Integrated Solar Power Plants (ISCC)

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Energy 29 (2004) 947959

www.elsevier.com/locate/energy

Trough integration into power plantsa study on theperformance and economy of integrated solar combined

cycle systems

Jurgen Dersch a,, Michael Geyer b, Ulf Herrmann b, Scott A. Jones c,Bruce Kelly d, Rainer Kistner e, Winfried Ortmanns a, Robert Pitz-Paal a,

Henry Price f

a Solare Energietechnik, German Aerospace Center (DLR), D-51170 Koln, Germanyb FLABEG Solar International, Muhlengasse 7, D-50667 Koln, Germany

c Sandia National Laboratories, Albuquerque, NM 87185-0703, USAd Nexant Inc., 44 Montgomery, Suite 4100, San Francisco, CA 94104-4814, USAe Milenio Solar S.A., Avda. de la Paz 41, E-04720 Aguadulce (Almeria), Spain

f National Renewable Energy Laboratory, 1617 Cole Blvd., Golden, CO 80401-3393, USA

Abstract

Parabolic trough solar technology has been proven at nine commercial Solar Electric Generating Sys-tems (SEGS) power plants that are operating in the California Mojave desert. These plants utilize steamRankine cycle power plants, and as a result, most people associate parabolic trough solar technologywith steam Rankine cycle power plant technology. Although these plants are clearly optimized for theirparticular application, other power cycle designs may be appropriate in other situations. Of particularinterest is the integration of parabolic trough solar technology with combined cycle power plant tech-nology. This configuration is referred to as integrated solar combined cycle systems (ISCCS). Four poten-tial projects in India, Egypt, Morocco, and Mexico are considering the ISCCS type solar power cycleconfigurations. The key questions are when is the ISCCS configuration preferred over the SEGS powercycle configuration and how is the ISCCS plant designed to optimize the integration of the solar field andthe power cycle. This paper reviews the results of a collaborative effort under the International Energy

Agency SolarPACES organization to address these questions and it shows the potential environmentaland economic benefits of each configuration.# 2003 Elsevier Ltd. All rights reserved.

Corresponding author. Tel.: +49-2203-6012219.E-mail address: [email protected] (J. Dersch).

0360-5442/$ - see front matter#

2003 Elsevier Ltd. All rights reserved.doi:10.1016/S0360-5442(03)00199-3


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1. Introduction

Integrated solar combined cycle systems (ISCCS) are modern combined cycle power plants

with gas and steam turbines and additional thermal input of solar energy from a field of para-

bolic troughs. The plant concept was initially proposed by Luz Solar International[1]. Since this

time, the subject has been discussed in several publications (e.g.[2,3]). Due to the decision of the

Global Environment Facility to provide grants for four ISCCS power plants in India, Egypt,

Morocco and Mexico, interest in this kind of power plants increased again [4,5].Today, solar thermal power plants based on parabolic troughs represent the only solar power

plant technology tested on a commercial basis. Therefore, they are promising candidates in pro-

viding a significant contribution to carbon dioxide mitigation.The aim of this paper is to show the advantages and disadvantages of ISCCS compared to

SEGS type solar power plants and to conventional combined cycle (CC) power plants. A base

solar field size of 270,320 m2 was used for the performance calculations, because this would be

the design size for a 50 MWe SEGS plant at sites like Barstow, California.Whereas the evaluation of fossil fired CC plants can be performed by using the mean values

of ambient temperature, load and full load hours, ISCCS are considerably more affected by

ambient conditions and load profiles. Therefore, it is essential to use annual performance calcu-

lations for ISCCS plant analysis.

Nomenclature

Eanngen

annual electricity output, kW h/a

FannPV present value of annual fixed cost, $fcr fixed charge rateItotPV present value of total investment cost, $

LEC levelized energy cost, $LHV lower heating value of fuel, kJ/kg_mmfuel fuel mass flow rate, kg/s

OMannPV present value of operating and maintenance cost, $/aPel,net net electrical output, kWPth,solar thermal input from solar field, kWss annual solar sharexnet_elec_solar instantaneous net electrical solar fraction

Greek symbols

gnet_incr_solar net incremental solar efficiencygref net efficiency of the reference power plant

J. Dersch et al. / Energy 29 (2004) 947959948


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2. Integrated solar combined cycle systems

Most commercial CC plants use a multiple-pressure, reheat steam turbine to improve

efficiency, but a simplified single-pressure system will be discussed now to illustrate the issuesrelated to the ISCCS.

Fig. 1 shows an example of an ISCCS with a single-pressure, reheat steam turbine and heat

recovery steam generator (HRSG). Preheated feed water is drawn from the high pressure pre-

heater, evaporated and slightly superheated in the solar steam generator, returned to the

HRSG, and together with the steam from the conventional evaporator, finally superheated to

the live steam temperature. Steam turbine, preheater, superheater and condenser of an ISCCS

have to be larger than the corresponding parts of a CC plant using the same gas turbine type

because of the increased steam mass flow for the integrated plant.In comparison to existing Rankine cycle power plants with parabolic trough technology

(SEGS)[6], ISCCS plants offer three principal advantages: First, solar energy can be converted

to electric energy at a higher efficiency. Second, the incremental costs for a larger steam turbine

are less than the overall unit cost in a solar-only plant. Third, an integrated plant does not suf-

fer from the thermal inefficiencies associated with the daily start-up and shutdown of the steam

turbine.

Fig. 1. Scheme of an ISCCS power plant with a single-pressure-reheat steam cycle and the use of solar energy toreplace latent heat of evaporation.

949J. Dersch et al. / Energy 29 (2004) 947959


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3. Integration issues

From a thermodynamic point of view, the solar heat input should be used for the replace-

ment of latent heat and at the highest possible temperature level. The temperature of the heattransfer fluid is limited to 400 v

C to avoid decomposition; therefore, maximum solar steam tem-peratures of about 380

v

C are possible. Analysis was performed in several steps: plant design,annual performance evaluation, economic and environmental analysis.

Since this was a general study not focussing on one specific project, the infinite analysis spacewas limited as follows:

. Heat balance calculations were carried out to compare CC, ISCCS, and SEGS plants.

. Proven parabolic trough technology using oil as a heat transfer fluid to collect the solarenergy was used.

. Solar field size was set by the requirements of a 50 MWe SEGS plant. However, this provided

a solar share for the ISCCS case very close to the maximum solar share that could be inte-grated while still maintaining the live steam temperature and pressure requirements for mostday and night operation.

. Maximum plant output was held constant for CC and ISCCS cases to insure they were com-pared on an equal basis.

. Natural gas, the most common fuel in combined cycle power plants, was used.

. A high-efficiency, triple-pressure, single-reheat steam turbine (565 v

C=125 bar) and HRSGwere used.

. The solar heat was used at the highest pressure level to make optimal use of the solar powerinput.

. The influence of a 2-tank molten salt thermal energy storage (TES) system and of duct firingin the heat recovery boiler was considered.

. Performance analyses were conducted for two sites, one with a high solar irradiation(Barstow, California) and one with a somewhat lower irradiation (Tabernas, Spain).

During the first step of the investigation process, several plant designs and cycle balance cal-culations were performed using the commercial computer codes, GateCycle2 [7]and IPSEpro2

[8]. Steady state performance for different load cases was calculated. The electrical output fromthe gas turbine was only influenced by ambient temperatures. Supplementary firing and thermalstorage were considered, because the power plants should be able to follow a load curve even in

times of low or without insolation.In the present paper, five figures of merit are used to evaluate the different cycles and loadcases. The first figure of merit is called net incremental solar efficiency and is used as a measurefor the fuel saved by the solar part of the plant:

gnet incr solarPel;net gref _mmfuelLHV

Pth;solar(1)

Here grefis the overall net electric efficiency of the combined cycle (CC) reference plant at thesame ambient temperature. This is an optimized conventional CC plant using the same gas tur-bine, but has no solar heat input. Since an ISCCS power plant without solar heat input operates



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in part load, the overall net efficiency of a CC reference plant will be higher than the efficiencyof the ISCCS without solar heat input. Thus, the second term in the numerator of Eq. (1) maybe considered as the net electrical output of an optimized CC power plant burning the same

amount of fuel as the ISCCS.The second figure of merit, called instantaneous net electrical solar fraction, is based on the

net incremental solar efficiency:

xnet elec solargnet incr solarPth;solar

Pel;net(2)

Using the net incremental solar efficiency and the instantaneous net electrical solar fraction,defined as shown above, gives lower values for these figures of merit than defining them basedon the electrical output of an ISSC plant without solar radiation. This was the intention of theauthors, because it prevents the choice of an ISCCS which produces more carbon dioxide emis-

sions than an optimized CC plant.Fig. 2 shows some results of the cycle balance calculations. The fuel based net electricefficiency in this diagram is defined as net electric output of the plant divided by fuel mass flowtimes LHV. Therefore, the net electric efficiency increases up to 68.4% for the ISCCS at designsolar input. The steam cycle efficiency is defined as electrical power output of the steam turbinegenerator divided by the overall thermal input to the steam cycle from HRSG and solar field.This figure of merit may be used as a measure for the process improvement by the integration ofsolar steam. Looking at the steam cycle efficiency solely, the highest value is provided by theISCCS with full supplementary firing. But, this operation mode has by far the lowest netincremental solar efficiency (0%) and thus the highest carbon dioxide emissions per kW h elec-tricity.

Fig. 2. Instantaneous efficiencies and solar fraction for an ISCCS power plant in different operation modes and forthe CC reference plant at 25

v

C ambient temperature.



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The results of the steady state calculations were used to generate plant characteristics for theannual performance simulations. Solar radiation and ambient conditions for the specific site aremodeled by using a typical meteorological year (TMY) at this site. As main output, the per-

formance calculation delivers annual values such as net electricity production, fuel consumption,annual solar share, dumped solar energy and CO2 emissions. The annual solar share, ss, used inthe next chapter was calculated with the following equation:

ss 1 annual fuel consumption per kWhISCCS or SEGSannual fuel consumption per kWh CC reference plant

(3)

In contrast to the instantaneous net electric solar fraction from Eq. (2), the annual solar shareconsiders the predefined load curve as well as start-up and turn down losses, thermal storagecharge state, and scheduled and unscheduled outages. Therefore, it will be considerably lowerthan the instantaneous net electric solar fraction.

4. Annual performance results

This paper focuses on the results for an ISCCS plant in comparison to a SEGS plant and apure combined cycle. For each integration approach, a configuration without TES and anotherwith TES are presented. Table 1 shows the main technical parameters of the discussed config-urations. A base solar field size of 270,320 m2 was used, because this would be the design sizefor a 50 MWe SEGS plant at sites like Barstow, California.

The nominal electricity output is the same in all ISCCS and CC configurations. The SEGSplants have a relatively lower electricity output as the corresponding ISCCS with the same solarfield size. A back-up system is integrated with the ISCCS and SEGS which allows supplemen-tary firing in periods when no solar energy is available but nominal plant output is required. Inaddition, two of the configurations have a thermal energy storage, which reduces the use of theduct burner during non-solar periods. For these configurations, the solar field has to be

Table 1Main design parameter for some of the investigated configurations

Plant type SEGS SEGS withTES

ISCCS ISCCS withTES

CC

Nominal power (MWe, net) 50 50 310 310 310Solar field size (m2) 270,320 427,280 270,320 427,280 0Fuel type Natural gas Natural gas Natural gas Natural gas Natural gasThermal energy storage (MWht) 0 839 0 839 0Fossil back-up system Boiler Boiler Duct Burner Duct Burner BU thermal output (MWt) 139 139 139 139 0Gas turbine power (MWe, gr) 0.0 0.0 162.0 162.0 201.0Steam turbine power (MWe, gr) 50.0 50.0 148.0 148.0 109.0Plant efficiency, net 34.7% 32.6% 68.6% 68.1% 56.5%Total parasitics (MWe) 3.77 6.54 6.14 8.61 3.77Cooling system Wet Wet Wet Wet Wet



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enlarged to collect enough solar energy to charge the storage. This, of course, increases invest-

ment cost, but leads to higher solar fractions. The output of the reference CC in Table 1 refers

to scaled power plant in order to compare the fuel consumption of the plant to the fuel con-

sumption of the ISCCS.InFig. 2, the efficiencies for different loads and operation modes are presented. However, to

assess the overall performance of an ISCCS, it is necessary to analyse how many hours per year

the plant will operate in the design point and how often at part load. The performance analysis

over the whole year provides the solar fraction of the produced electricity and the annual CO2

Fig. 3. Load curves used for the annual performance calculation.



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emissions. The solar fraction, of course, depends on the local weather conditions. Therefore, fora detailed annual performance analysis, the direct normal irradiation (DNI) at the site wherethe power plant should be built has to be known. In this study, we conducted our analysis for

two sites, one with high solar irradiation, Barstow in California (2717 kW h/m2a), and one witha somewhat lower irradiation, Tabernas in Spain (2023 kW h/m2a). A TMY data set has beenused, which contains hourly values for the DNI, ambient temperature and wind speed for onecomplete year. Hence, the annual performance calculation are also carried out in hourly steps.However, only the annual sums are presented below.

For a daily and annual performance calculation also the operation strategy of the powerplant has to be stipulated. Two strategies are investigated here: a solar dispatching and a sched-uled load operation mode. In the scheduled load mode, the plant operation follows a fixeddemand curve. The used load curves are shown inFig. 3.

The scheduled load curve follows a demand profile, which is typical for many countries. The

electricity demand is high during the day and during the evening. During night hours, thedemand is somewhat lower. Therefore, the plants operate 16 h at full load and 8 h at 80%. If nosolar energy is available to fulfil the load curve, the fossil back-up is used.

In the solar dispatching mode, no specific load profile is prescribed. The gas turbine operatesat full load for 24 h. The output of the gas turbine then depends only on the ambient tempera-ture and the site elevation. If solar energy is available, the steam turbine is boosted and the totalplant output increases. No back-up burner is used in this mode.

Fig. 4 shows the results of the annual performance calculation for the ISCCS cases and theCC. The figure gives the annual electricity output and the solar share. For each case, runs wereperformed for the two sites, California and Spain, and for the load profiles presented above.

In scheduled load operation mode, the annual electricity production is the same for all config-urations, while in solar dispatching operation, the electricity production is affected by the plant

Fig. 4. Results of annual performance calculation for ISCCS and CC.



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configuration and the local weather condition. The output of the CC is the highest in this mode,because the plant operates at full load for 24 h. The ISCCS configurations operate at full loadonly, when thermal energy is available from the solar field or the thermal storage.

In California, where the solar radiation is higher than in Spain, the output and the solarshare of the ISCCS are higher.

Also, it can be observed that the solar share is higher in solar dispatching mode than inscheduled load. The scheduled load configuration requires periodic use of the duct burner,which increases the fossil fuel consumption and thereby decreases the solar share. Also, thesolar share is higher for configurations with thermal storage than those without TES. In Cal-ifornia, solar shares of nearly 10% can be achieved. For a pure combined cycle, the solar shareis, of course, 0%.

Fig. 5 shows specific carbon dioxide emissions for ISCCS in comparison to SEGS and CCplants for different sites, configurations, operation modes and solar field areas. All ISCCS con-

figurations show lower carbon dioxide emissions than the corresponding CC reference plants.FromFig. 2, it becomes evident that SEGS plants offer the opportunity of solar-only operationwith almost no carbon dioxide emissions if they are operated in solar dispatching mode.Although a small amount of fossil fuel is used for start-up and warming during non-sunshinehours at these plants, the value is beyond the plotting scale ofFig. 2.

If 24-h operation is required, SEGS plants without storage would be a very bad solution, atleast in Spain, because they would need a lot of supplementary firing with low efficiency com-pared to an optimized CC. Increasing the solar field size leads to lower specific carbon dioxide

Fig. 5. Specific CO2emissions for different sites, plant configurations, operation modes and solar field areas.



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emissions for all cases, but because of the high costs of this part, it is not useful to build anarbitrarily large solar field. Economic details are discussed in the next section. In California andunder the load profile used here, SEGS and ISCCS plants have very similar specific CO2 emis-

sions if they are built without a storage. Adding a thermal storage would decrease the specificcarbon dioxide emissions of SEGS plants in the scheduled load operation mode.

5. Economic analysis

The driving force for the integration of parabolic troughs into conventional power cycles is toreplace some of the fossil fuel by renewable sources and thus reduce the greenhouse gas emis-sion (GHG) of a combined cycle power plant. However, power generation from renewableresources is normally associated with higher initial investment costs and lower operation costs.The objective of this economic analysis is to assess the cost efficiency of ISCCS power plants,

determine the economics of different solar integration alternatives and compare it with conven-tional power generation systems. For the comparative assessment, two levelized energy costs(LEC) were used as the figures of merit. The LEC is the present value of the life-cycle costs con-verted into a stream of equal payments. As an advantage, the LEC cost figure allows an econ-omic evaluation of different power generating technologies with varying capacities, full loadhours, lifetime, etc. The computed LEC values for power generation systems can be significantlyinfluenced by the methodology and assumptions employed. A widespread methodology for theLEC calculation is the approach outlined in [9]. The methodology applied here is based on thatapproach but is slightly modified. The goal of this study is a project independent assessment ofdifferent integration options; thus, any project-specific data (e.g. tax influences, depreciation,

etc.) should be disregarded. The LEC values have been calculated according to the followingequation:

LEC ItotPV fcrOM

annPV F

annPV

Eanngen

(4)

Beside the methodology, the determination of realistic input assumptions has a significantinfluence on the LEC results. The general parameters and assumptions used in the economicanalysis are summarized inTable 2.

The annual O&M costs, i.e. all operation and maintenance expenses other than fuel expenses,had to be determined from case to case since it contains a fixed component and an output-dependent component. The annual values fluctuate for the ISCCS between 6.6 million US$ peryear and 7.5 million US$ per year.

LEC calculations for an ISCCS plant with and without thermal storage for a project site inBarstow (California) and one in Tabernas (Spain) were performed. The LEC increase for caseswith a higher solar share but the calculated values are very similar for all ISCCS plants inves-tigated here (from 3.9 to 4.2). This is due to the fact that the LEC are dominated by the fossilpart of the plants.

In order to determine the costs of a solar generated kWh, the LEC of the ISCCS plant hasto be divided into a solar LEC and a conventional LEC. The last named corresponds to thepower generating costs of reference CC (LECref.CC) with the same capacity and the same load



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profile. By means of the solar share,ss, the solar LEC can be calculated according to the follow-ing equation:

LECsolarLECISCCS or SEGS 1 ss LECref:CC

ss(5)

InFig. 6, solar LEC are plotted. The results show that ISCCS plants will have lower solarLEC than SEGS plants at the same site and the same operating scheme. This difference becomes

Table 2General parameters for LEC calculation (base case scenario)

Item Parameter Units

Constant value real discount rate 6.5 %Lifetime of ISCCS plant and reference plant 25.0 yearsFuel price (Gas) 11.1 US/m3

1.26 US/kWhthAnnual fuel price escalation rate 2.0 %Annual inflation rate 2.5 %Spec. investment costs for solar fieldHTF system 220.0 US$/m2

Spec. investment costs for conventional CC 550.0 US$/kWSpec. investment costs for conventional components of ISCCS 600.0 US$/kWSpec. investment costs for thermal storage 35.0 US$/kWhthBase year for discounting 2002

Fig. 6. Solar LEC for different sites, plant configurations, operation modes and solar field areas.



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more significant for the scheduled load operation mode. Furthermore, solar LEC are lower forISCCS in scheduled load operation than in solar dispatching operation mode in most of thecases. In Spain, without a thermal storage, this is only valid for the largest solar field size inves-

tigated. In contrast to this, SEGS solar LEC are higher in scheduled load than in solar dis-patching mode. This is due to the large amount of fossil fuel which has to be used with lowefficiency during night times when SEGS plants are operated 24 h a day. The investment on athermal storage for ISCCS plants seems to be useful, because the solar LEC are about 10%15% lower with a thermal storage.

6. Conclusions

ISCCS provide an interesting way of solar electricity generation. If properly designed andoperated in the design manner, ISCCS plants show lower specific CO2emissions than optimized

CC plants at the same site and under the same operating conditions. ISCCS provide a bettersolution than SEGS plants, if 24-h operation a day is required. This is valid if both types haveno thermal storage.

If the ISCCS plants are supposed to have high efficiencies at times without solar energy input,the fraction of solar thermal input is limited. In this study, a triple-pressure single-reheat cyclewas used with an instantaneous net electrical solar fraction of 17.5% at design point. Underexcellent solar conditions as in the Californian Mojave desert, this results in an annual solarshare of 5.6% without and 9.4% with a thermal storage. These values are valid for solar dis-patching operation mode which means that the plant can use all incoming solar energy withoutany restrictions on load management. For sites with lower insulation or for scheduled load

operation, the solar share values are even lower.SEGS plants are able to deliver higher annual solar shares and they are suitable technology ifsolar-only plants are required and no load restrictions prevail. With thermal storage tech-nology available in a commercial scale, SEGS plants may even be used in load scheduling modewith considerable load demand during non-sunshine hours.

Acknowledgements

The authors wish to thank the International Energy Agency SolarPACES organization forsupporting this cooperative project. Sandia National Laboratories contributions were sup-

ported by the US Department of Energy under contract DE-AC04-94AL85000.

References

[1] Johansson TB, et al., editors. Renewable energy, sources for fuels and electricity. Washington, DC: Island Press;1993, p. 2345.

[2] Solar Thermal Electricity in the Mediterranean, EU Contract APAS-RENA CT94014, Final Report. EuropeanUnion, 1994.

[3] Allani Y, Favrat D, von Spakovsky MR. CO2 mitigation through the use of hybrid solar-combined cycles.Energy Conversion Manage 1997;38:S6617.



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[4] Rheinlander J, Horn M, Fuhring H. GuD-Kraftwerk mit integriertem Solarsystem. Brennstoff WarmeKraft 2001;53(6):558.

[5] Kelly B, Herrmann U, Hale MJ. Optimization studies for integrated solar combined cycles. Proceedings of SolarForum 2001; Solar Energy: The Power to Choose, Washington, DC, April 2125. 2001.

[6] KJC Operating Company. Boron, CA 93516. See also: http://www.kjcsolar.com/.[7] Heat balance and process simulation package IPSEpro: http://www.SimTechnology.com/.[8] Heat balance and process simulation package GateCycle: http://www.gepower.com/enter/.[9] International Energy Agency (IEA). Guidelines for the economic analysis of renewable energy technology appli-

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