Climate Impact and Economic Feasibility of Solar Thermochemical

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Climate impact and economic feasibility of solar thermochemical jet fuel production Christoph Falter, Valentin Batteiger, and Andreas Sizmann Environ. Sci. Technol., Just Accepted Manuscript • DOI: 10.1021/acs.est.5b03515 • Publication Date (Web): 07 Dec 2015 Downloaded from http://pubs.acs.org on December 8, 2015

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Environmental Science & Technology

Falter et al.

Environmental Science and Technology

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Climate impact and economic feasibility of solar thermochemical jet

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fuel production

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Christoph Falter*1, Valentin Batteiger1, Andreas Sizmann1

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1

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*

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85521 Ottobrunn, Germany, Phone: +49-89-307484939, Fax: +49-89-307484920

Bauhaus Luftfahrt e.V., Willy-Messerschmitt-Straße 1, 85521 Ottobrunn, Germany

Corresponding author: [email protected], Willy-Messerschmitt-Str. 1,

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TOC art

CO2,H2O STL CxHy

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Abstract

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Solar thermochemistry presents a promising option for the efficient conversion of H2O and CO2

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into liquid hydrocarbon fuels using concentrated solar energy. In order to explore the potential of

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this fuel production pathway, the climate impact and economic performance are analyzed. Key

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drivers for the economic and ecological performance are thermochemical energy conversion

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efficiency, the level of solar irradiation, operation and maintenance, and the initial investment in

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the fuel production plant. For the baseline case of a solar tower concentrator with CO2 capture

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from air, jet fuel production costs of 2.23 €/L and life cycle greenhouse gas (LC GHG) emissions

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of 0.49 kgCO2-eq./L are estimated.

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Capturing CO2 from a natural gas combined cycle power plant instead of the air reduces the

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production costs by 15% but leads to higher LC GHG emissions than conventional jet fuel.

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Favorable assumptions for all involved process steps (30% thermochemical energy conversion

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efficiency, 3000 kWh/(m² a) solar irradiation, low CO2 and heliostat costs) result in jet fuel

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production costs of 1.28 €/L at LC GHG emissions close to zero. Even lower production costs

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may be achieved if the commercial value of oxygen as a by-product is considered.

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1. Introduction

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Today, the transportation sector is almost exclusively dependent on fuels derived from crude oil.

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Limited resources and an increasing demand are likely to lead to higher fuel prices in the future

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unless alternatives can be introduced into the market. For the automotive sector, the

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electrification of the vehicle or the use of hydrogen fuel cells are viable alternatives. However, in

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the aviation sector, more stringent requirements for the energy carrier with respect to both 2 ACS Paragon Plus Environment

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specific energy and energy density, as well as power density are present.1 The electrification of

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the aircraft is limited by the specific energy of batteries2 and the introduction of the non-drop-in

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fuel hydrogen by the energy density. For the present and the near-term future, conventional jet

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fuel and its synthetic blends remain the exclusive option for commercial aviation and it may

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continue to be attractive for long-range air travel due to its favorable properties. Available

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alternative fuels for aviation based on the conversion of biomass (biofuels) have a wide range of

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life cycle GHG emissions, often not even reaching the limit of 35% reduction compared to

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conventional fuel set by the European Union3,4. Furthermore, large-scale substitution of jet fuel

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with biofuels could lead to competition for arable land for food and fodder production. It is

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therefore desirable to find renewable “drop-in”-capable non-biogenic alternatives that offer the

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perspective of competing favorably with the conventional fuel pathway. In order to identify and

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compare such alternatives, the climate impact and economic performance shall be used as

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indicators.

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The analyzed solar thermochemical fuel path is based on the high-temperature conversion of

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water and carbon dioxide into a mixture of hydrogen and carbon monoxide (synthesis gas or

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syngas) and oxygen mediated by ceria redox reactions.5,6 In order to reach the reduction

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temperatures of 1500°C and above that are usually required for redox reactions of metal oxides,

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solar energy is concentrated into the aperture of a thermochemical reactor. A solar tower or dish

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concentration system can deliver the required level of radiative flux. Solar syngas is further

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converted into liquid hydrocarbon fuels by the Fischer-Tropsch process. The produced synthetic

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paraffinic kerosene is certified for use in commercial aviation in mixtures with a share of up to

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50% with conventional jet fuel according to ASTM D7566.

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H2O

CO2 Sunlight Syngas FT

CxHy

H2O/CO2

O2

57 58

CO2/H2O capture/storage

Solar concentration

Thermochemistry

Gas storage

FischerTropsch

Combustion

59

60

Figure 1 Schematic of solar thermochemical fuel production path. H2O and CO2 are

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ubiquitous and can be captured from air. Direct solar radiation is concentrated by a field of

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heliostats and drives the high-temperature thermochemical conversion of H2O and CO2 to

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H2 and CO (syngas). The syngas is stored and finally converted into jet fuel via the FT

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process.

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Assuming carbon dioxide provision from industrial sources, all process steps involved in the

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production of solar jet fuel are fully developed and established in a commercial environment with

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the exception of the solar thermochemical production of syngas. This conversion step is currently

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subject to research and development campaigns in several research groups that work on different

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reactor concepts to include new materials7, heat recuperation8–11, and vacuum generation9 to

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improve the experimentally demonstrated efficiency of currently about 2%6,12 towards 20%13


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which is well within the thermodynamic potential and which is expected to be required for the

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economic operation of a fuel production plant.

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The analysis of the environmental performance of processes using concentrated solar energy in

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the literature comprises CSP plants for electricity production14–16, the production of zinc and

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syngas17, of hydrogen18,19, and of solar fuels based on thermochemical conversion of water and

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carbon dioxide mediated by redox reactions of a metal oxide.20 Kim et al.20 examine a process

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path similar to the one suggested in this manuscript and include flue gas scrubbing from a fossil

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power plant for the provision of carbon dioxide. Counting the CO2 capture from the fossil power

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plant as negative emissions, the authors show that a lower environmental burden is associated to

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the production and use of solar gasoline than for gasoline derived from crude oil.

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Economic analyses of solar fuels in the literature comprise methanol production21, hydrogen

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generation22,23, and fuels based on solar thermochemistry13,24. However, concerning the fuel

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production path shown in Figure 1, the number of publications for an economic and

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environmental analysis is small. Kim et al. assume a conversion efficiency of 20% from

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unconcentrated sunlight to syngas and arrive at well-to-tank GHG emissions of -1.58 kg CO2-eq.

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per liter of gasoline (which corresponds to well-to-wake emissions of 0.74 kg/L) and a minimum

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selling price of about 1.50 € per liter of gasoline equivalent.20,24 So far, the analyses have mostly

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focused on either the economics or the ecology of the production processes. This paper

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complements these analyses with respect to the combined investigation of economic and climate

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impact drivers and their trade-offs.

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For the derivation of drivers of climate impact and economic performance, both a life cycle

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analysis of GHG emissions and an economic model are used. The results presented in this paper

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apply to the following baseline case with a plant size of 1000 bpd of jet fuel production. As a co-

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product, 865 bpd of naphtha are produced from the same facility. The publicly supported solar-

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stand alone facility, i.e. without external sources of heat or electricity, is located in a region with

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2500 kWh/(m² a) of direct normal irradiation, where the concentration facility is a tower system.

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Thermochemical conversion efficiency is 20%. CO2 is supplied by an air capture unit located at

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the plant site and H2O by a seawater desalination unit located at 500 km distance and 500 m

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altitude difference. Transportation of the fuel is assumed to be carried out over 500 km via

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pipeline.

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2. Methods: Life cycle analysis

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2.1 Goal and scope

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The fundamental steps in a life cycle analysis, as outlined in ISO 14040, are goal and scope

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definition, inventory analysis, impact assessment, and interpretation. The goal of the life cycle

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analysis here is the estimation of the global warming potential associated to the production and

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use of solar jet fuel and naphtha. The functional unit is chosen to be 1 L of jet fuel, while 0.87 L

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naphtha is produced as a by-product in the same process.25 A well-to-wake boundary is thus

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chosen which includes the resource provision, concentration of solar energy, thermochemistry,

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and Fischer-Tropsch conversion, as well as the final combustion of the fuel. The life cycle phases

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of construction, manufacturing and disassembly are taken into account for the plant components.

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A cut-off criterion of 1% of the total GHG emissions is used and all contributions below this 6 ACS Paragon Plus Environment

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threshold are neglected, e.g. the construction of the seawater desalination plant.26 As the process

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of carbon dioxide air capture is energy-intensive, the expected contribution of the infrastructure is

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likely to be small. Due to the low technology readiness level, the infrastructure requirement for

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the capture plant could not be estimated with a high level of fidelity and is not included in the

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analysis. In case of the FT unit, the GHG emission associated to the construction of the facility

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was estimated based on a large-scale GtL plant in Qatar and it was found that the contribution

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was well below the 1% cut-off limit. Assuming that the transport of the material to the plant

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location and the deconstruction do not exceed the manufacturing, the total contribution of the FT

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infrastructure can be neglected.

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The direct normal solar irradiation (DNI) at the location of the fuel production plant is assumed

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to be 2500 kWh/(m² a), a value which is common for example in the Middle East and North

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Africa region, Australia, Chile, the Southwest of the US, or Southern Africa.

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Seawater 0.1 MJe

Return water

H2O desalination 13.4 L H2O

0.5 MJe

Option C: CO2 capture from power plant

Atm. air

30.3 MJ

H2O transport

CO2 capture Return air 13.4 L H2O

Solar energy

Thermochemical conversion

Solar-to-heat 494.2 MJ 1033.4 MJ 184.1 MJ

1217.5 MJ

5.6 kg CO2 2.1 L H2O

267.7 mol H2 127.5 mol CO

33.8 MJe 2.3 MJe

Fischer-Tropsch conversion

Solar-to-electricity 1.9 MJe Option B: Grid electricity

13.3 mol H2

0.3 MJe

Hydrocracking and distillation

CHP 1.9 MJ 0.15 kg C1-C4

1.00 0.87 0.15

1.2 MJ

L Jet fuel L Naphtha kg C1-C4

System boundary 1.00 0.87

L Jet fuel L Naphtha

Figure 2 Energy and mass balance of fuel production plant for baseline case


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2.2 System description and inventory analysis

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In the following, the energy and mass balance referenced to the functional unit is described for

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the baseline case of the fuel plant (Figure 2). As input to the FT unit, 395.2 mol syngas are

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needed, which in turn requires 267.7 mol of hydrogen and additionally 13.3 mol of hydrogen for

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hydrocracking. Assuming a complete conversion of water into hydrogen and oxygen, 5.1 L of

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water have to be supplied to the thermochemical reaction. In total, 13.4 L of water are required

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for the production of one functional unit, 6.5 of which are for cleaning the mirrors, 3.9 for the

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supply of CSP electricity, and the remaining amount is for the thermochemical conversion where

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through the recycling of water produced in the FT process (2.1 L), the required amount of water

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for the latter is reduced. For cleaning the mirrors, the value of 58.0 L/(m² y) derived by Whitaker

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et al.27 is used as a reference. Water consumption of the Ivanpah CSP plant in the United States

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reaches similar values, however for the whole plant operation.28 Fresh water for the process is

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provided through seawater desalination and subsequent transport of the water over 500 km

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distance and 500 m altitude difference to the fuel plant. The desalination plant operates with

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reverse osmosis at an energy requirement of 3 kWh/m³.29 The energy requirements for pipeline

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transport of the water to the fuel plant are calculated after Milnes.30

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Carbon dioxide in the baseline plant layout is assumed to be captured from the atmosphere by

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chemical absorption31–33 to an amine-functionalized solid sorbent with an energy requirement of

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1500 kWh of heat and 200 kWh of electricity per ton.34 The energy is predominantly required in

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the form of low-temperature heat for desorption of CO2 from the sorbent, an energy which is

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oftentimes available as waste heat in industry. The capture of carbon dioxide from the

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atmosphere is located at the plant site, obviating long-distance CO2 transport. 5.6 kg of CO2 are

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required for the production of the functional unit which are supplied to the thermochemical

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reaction at ambient pressure. 9 ACS Paragon Plus Environment


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The thermochemical cycle operates under a temperature-pressure-swing5,35, where the achieved

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nonstoichiometry of ceria per cycle is 0.1 and the number of cycles per day is 16. While the

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former represents an improvement of presently achieved values in experiments6,12,35, a decrease

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of the cycle time could reduce the required nonstoichiometry per cycle. In fact, the cycle time has

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been reduced considerably in recent experiments.35 Ceria has been shown to be very stable over a

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large number of cycles35,36, however, a degradation process is expected that requires the

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remodeling of the structure to be used in the reactors. As on the other hand, ceria is not consumed

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in the reactions, it does not have to be physically replaced by new material. The efforts for the

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remodeling of the ceria structure are neglected. The thermochemical reaction is assumed to

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proceed at an energy efficiency of 20%, where the definition of efficiency is the HHV of syngas

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divided by the energy inputs for its production, i.e. the thermal energy for heating of gases and

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ceria, for the reduction reaction, for inert gas purification, and separation of the CO/CO2 mixture.

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The energy efficiency is thus based on thermal energy, where electrical energy is provided with

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an efficiency of 40% by conversion of solar heat. Inert gas is assumed to be purified at 16 kJel per

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mol37 at an amount of ten times the evolved oxygen from the metal oxide.38 The gas separation of

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CO and CO2 is required as an excess amount of CO2 is supplied to the oxidation for kinetic and

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thermodynamic reasons, where the assumed excess factor with respect to the stoichiometric

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amount is two. The gas separation, i.e. CO2 removal from syngas, has been shown to work with

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amine sorbents39 and is thus based on chemical absorption of CO2 to the liquid sorbent K-1with a

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separation energy of 132 kJ of heat and 9 kJ of electricity.40 A carbon efficiency of 90% for the

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Fischer-Tropsch conversion from syngas to hydrocarbons and a loss of the remaining 10% CO

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feed as CO2 is assumed. As the FT conversion operates at a pressure of 30 bar, the syngas coming

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from the solar reactor has to be pressurized to this level which requires 4.2 MJ of electricity, 2.3

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MJ of which are supplied by conversion of solar primary energy and 1.9 MJ are supplied from 10 ACS Paragon Plus Environment

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internal conversion of intermediate products.

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The hydrocracking and distillation step which reduces the chain lengths of the hydrocarbons to

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the desired ranges and separates the products, has an energy demand of 0.3 MJ of electricity and

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of 1.9 MJ of heat41, both of which are supplied from the combined heat and power unit which

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combusts the light hydrocarbon fraction from the FT conversion. Alternatively, the light

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hydrocarbon fraction could be reformed into syngas and cycled back to the FT unit. However, in

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the baseline case, the conversion of the light hydrocarbons in a CHP plant is assumed as this is

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also close to the current practice of GtL plants.

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Overall, 1.22 GJ of solar primary energy are captured and converted into heat and electricity with

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efficiencies of 51.7% and 20.0%, respectively. The overall energy conversion efficiency based on

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the LHV of jet fuel and naphtha is thus 5.0%. This value includes the provision of heat and

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electricity used in the process. While in other publications higher numbers are mentioned for the

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overall efficiency, our more conservative estimate is based on a thermochemical efficiency of

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20% which is well below the thermodynamic limit. At experimental values which are at about

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2% today5,6,12,35, the achievement of 20% seems to be an ambitious but realistic target for the

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mid-term future and was therefore selected here.

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In the solar stand-alone configuration (i.e. without external electricity and heat sources), the

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required amount of solar primary energy and the level of solar irradiation at the chosen plant

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location are used to calculate the size of the mirror field. In the baseline case, a solar tower

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system is assumed with a concentration efficiency of 51.7%.42 For the estimation of

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environmental burdens of the heliostat field, emissions of 132.8 kgCO₂-eq. per square meter of

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heliostat area are assumed.27 For the tower, building and streets required, 28.0 kgCO₂-eq. per m² are

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added, where both values are for the construction and decommissioning phases combined.27 The 11 ACS Paragon Plus Environment


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material requirement for the thermochemical reactors is estimated based on experimental

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equipment12 and multiplied with the respective emission factors.43 The fuel products are assumed

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to be transported via pipeline over a distance of 500 km and the corresponding emissions are

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taken from the Gemis software.43

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3. Methods: Economic assessment

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For the calculation of jet fuel production costs from the baseline plant, investment costs (I) and

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operation and maintenance costs (O&M) are estimated. The largest part of the investment costs is

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due to the solar concentrating facility, where costs of 100 € per m² of reflective area have been

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assumed which covers also the installation, engineering and other associated costs such as piping

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or wiring. Currently, the cost of heliostats for solar tower plants is estimated in the range of 130-

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200 $/m² 44,45, while the future cost target is 75-100 $/m². 44,46 The chosen value of 100 €/m² thus

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represents a realistic target. The cost of the tower which consists of a supporting structure and a

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receiver for the solar radiation coming from the heliostat field, is assumed with 20 € per kWth.45

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The solar thermochemical reactors are comprised of the reactive material ceria, insulation

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material, a supporting structure, and a window. For the estimation of the cost, data from Kim et

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al.21 are used, where a similar reactor system was analyzed. Ceria is included with a cost of 5

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€/kg, slightly higher than the current market price47 but lower than recent price peaks, wherethe

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required amount is calculated to be 7000 metric tons at an assumed nonstoichiometry of 0.1 and

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16 cycles per day. An increase in either of these two factors would lead to a higher utilization of

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the material and thus to reduced costs.


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For the conversion of syngas to fuels, a Fischer-Tropsch plant is expected to have a minimum

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economic size of 1000 bpd.48 Its investment costs are taken to be 23000 € per barrel per day of

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nominal output.48 and that of the CHP plant 1050 €/kWel installed.49 Two centrifugal compressors

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at a unit cost of 1.54 million € compress the syngas coming from the reactors to 30 bar for the FT

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conversion.50 Buildings which are required for the process controls and the syngas conversion,

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besides others, are estimated to have an area of about 22000 m² at a cost of 600 €/m².23 The

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investment costs for the CSP plant are included in the unit price of CSP electricity.

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The total investment costs are thus 8.8 × 108 € for the fuel production plant with a capacity of

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1000 bpd jet fuel and 865 bpd naphtha.

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Operation and maintenance costs are comprised of the following elements. Water is derived from

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seawater desalination and has a unit cost of 0.5 € per m³51 and CO2 of 100 € per ton if supplied by

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air capture on site. For the latter, the chosen technology of air capture is currently in a

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demonstration stage which makes a detailed estimate of investment costs and O&M costs very

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difficult. It is therefore chosen to assume unit costs which incorporate all involved cost

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contributions. Operation and maintenance of the solar concentration facility including the

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heliostat field and the tower are assumed to be similar to a CSP plant at 35 € per kWel and

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year.45,52–54 Accordingly, for an assumed CSP efficiency of 20%, this analysis uses specific O&M

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costs of 7 €/(m2 a) for the heliostats and the tower. The produced electricity by CSP has a cost of

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0.060 € per kWhel which corresponds to the goal of the SunShot Vision Study of the US

240

Department of Energy.54 An annual renewal of 0.20% of the heliostat field due to degradation is

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taken into account.55 For the FT unit, O&M costs are 4 € per barrel per day of liquid product48

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and 0.008 €/kWhel and 9.8 €/(kW a) for the CHP plant49, respectively.

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The overall annual O&M costs are thus 1.2 × 108 €. An overview of the cost items and

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assumptions are given in the supporting information. 13 ACS Paragon Plus Environment


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The annuity method is used for the derivation of production costs of jet fuel. Firstly, the present

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value (PV) of the O&M costs is the annual O&M costs CO&M multiplied with the annuity factor

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A, where the O&M costs are assumed in constant currency and the annuity factor is calculated

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with the real interest rate. Naphtha is assumed to be sold at a fixed price of 80% with respect to

249

the production costs of jet fuel. This value was derived by comparing the current naphtha and jet

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fuel prices and acknowledging the fact that both prices are highly correlated and follow the crude

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oil market price closely. The interest rate is comprised of the weighted interest rates for equity

252

and debt, where the latter is reduced by the tax rate. The total life cycle costs (TLCC) of the plant

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are derived by subtracting the present value of depreciation (PVDEP) and adding the present value

254

of the O&M costs (PVO&M) to the investment costs, and taking into account the tax rate (T).

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Finally the cost per unit jet fuel produced is calculated through dividing by the produced annual

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amount of jet fuel Q multiplied by the annuity factor. A lifetime of ݊=25 years and an interest

257

rate ݅ of nominal 6% for the baseline case of a publicly supported production plant is assumed.

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PV୓&ெ

=

C୓&୑ × ‫ܣ‬

(1)

A

=

1 − ሺ1 + ݅ሻି௡ ݅

(2)

TLCC

=

I − ሺT × PVୈ୉୔ ሻ + ሺ1 − TሻPV୓&୑ 1−T

(3)

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260

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=

TLCC Q×A

(4)

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4. Results

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4.1 Life cycle greenhouse gas emissions for baseline case

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Life cycle emissions and costs associated to the production of one liter of jet fuel are derived for

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the baseline case of the fuel production plant. The amount of CO2 in the atmosphere is reduced

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by the capture process which counts negatively in the overall CO2 balance. The plant operates in

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a solar stand-alone configuration, i.e. all heat and electricity requirements are covered by the

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local conversion of solar primary energy. Life cycle greenhouse gas emissions are 0.49 kgCO₂-eq.

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per liter jet fuel and 0.55 kgCO₂-eq. per liter naphtha, where the different results for both fuels are

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due to their different energy densities and combustion emission factors. The largest influences on

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the positive emissions are fuel combustion with 65%, the FT conversion with 16%, and the

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construction, use and decommissioning of the solar concentration facility with 12% (see graphs

276

in supporting information). Emissions of the FT conversion are due to the combustion of the light

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hydrocarbon fraction in the CHP plant and fugitive emissions, where the latter stem from the

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incomplete use of carbon entering the FT process (90% carbon efficiency). The 10% carbon loss

279

is assumed to occur as CO2. Emissions of the solar concentrating facility are almost completely

280

associated to the construction and deconstruction of the heliostats and tower, while its use

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accounts for only a small fraction. The thermochemical reactors, electricity, and fuel

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transportation only have minor contributions. Compared to conventional jet fuel derived from

283

crude oil with an overall emission of 3.03 kgCO₂-eq. per liter4, over 80% of greenhouse gas

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emissions could be saved through the use of solar jet fuel. This represents a significant savings

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potential which is also well below the threshold of currently 35% and even the more stringent

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emissions reductions set by the European Union for the use of biofuels.

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The solar stand-alone configuration leads to low greenhouse gas emissions, as the heat and 16 ACS Paragon Plus Environment

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electricity requirements are satisfied by conversion of solar primary energy, while grid electricity,

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which is at least partly based on fossil energy carriers, is not used. Also the capture of carbon

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dioxide from the atmosphere leads to a significant reduction of the emissions compared to the

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capture from industrial (fossil) sources if the fossil emissions are included into the boundaries of

292

the assumption. On the other hand, the combustion of the light fraction of the produced

293

hydrocarbons from the FT unit in a combined heat and power plant leads to considerable but not

294

prohibitive emissions. A different plant configuration is possible, where also the heat and power

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from the CHP plant is supplied by renewable energy conversion. This is further analyzed in

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section 5.3 of this article.

297

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4.2 Production costs for baseline case

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The baseline case of a publicly financed facility assumes that the fuel production plant is

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supported by the public. This could be the case if such a facility is supported by the government

301

in order to secure supply security of liquid hydrocarbon fuels. The nominal interest rate is

302

assumed to be 6% and the production plant to be exempt from taxes, simplifying the equation (3)

303

for the total life cycle costs to the sum of investment costs and the present value of the O&M

304

costs. Production costs of 2.23 € per liter of jet fuel are estimated. For the assumptions made, the

305

economics of the plant are dominated by the accumulated O&M costs which have about twice the

306

impact of the investment costs. However, the plant economics are also strongly driven by the

307

investment costs, as the concentration of the solar resource requires an expensive infrastructure.

308

The investment costs are comprised of 74% for the heliostat field, 11% for the thermochemical

309

reactors including the reactive material ceria, 8% for the solar tower and minor contributions for

310

the FT unit, buildings and other components. The O&M costs on the other hand are comprised of 17 ACS Paragon Plus Environment


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37% for the operation of the heliostat field and the tower, 27% for the supply of carbon dioxide,

312

32% for the generation of solar electricity, and minor contributions due to the operation of the FT

313

unit, mirror renewal, and others. The O&M costs are dominated by the operation of the solar field

314

which includes labor cost, mirror cleaning, insurance, and others.

315

316

4.3 Sensitivity study for life cycle greenhouse gas emissions

317

In order to analyze the influence of important variables on the life cycle greenhouse gas

318

emissions and the economics of the fuel plant, a sensitivity study is performed on the baseline

319

case, in which selected variables are varied by ±10% at constant output of the plant. The chosen

320

variables are solar irradiation level, thermochemical efficiency, lifetime of the plant, and

321

emissions from the construction, use and deconstruction of the concentration infrastructure

322

(Figure 3). Results show that a variation of the plant lifetime, of thermochemical efficiency, or of

323

solar irradiation has a similar influence on the GHG emissions: a decrease of 10% of the

324

variables increases the GHG emissions by 10-12%, while a 10% larger value decreases the costs

325

by 8-10%. In case of the lifetime, the reason for the change in emissions is that the environmental

326

burdens associated with the infrastructure and operation of the plant are distributed over a varied

327

number of years and thus the specific emissions per unit fuel produced changes. The level of

328

solar irradiation and thermochemical efficiency directly influence the required area of mirrors

329

and thus the emissions associated with their production. The large number of heliostats required

330

for the concentration of sunlight has an important impact also through the associated emission

331

factor per unit of mirror area. If this emission factor is varied by ±10%, the life cycle GHG

332

emissions change by ±8.6%. This highlights the possible improvement through a decrease of the

333

material intensity of the heliostats, a topic which is also interesting for economic reasons. 18 ACS Paragon Plus Environment

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The fact that GHG emissions vary in proportion with these variables reflects the near direct or

335

inverse proportional scaling of the emissions with the single variables for the chosen

336

assumptions, especially the solar stand-alone configuration. If CO2 capture from fossil sources is

337

introduced, it will dominate the emission behavior and show a different sensitivity with respect to

338

the chosen variables. The climate impact of solar jet fuel production could therefore be reduced

339

through the choice of a highly irradiated plant location, the enhancement of the thermochemical

340

conversion step, a prolongation of the lifetime of the plant components, and a reduction of the

341

material intensity of the mirrors and the solar tower.

LC GHG emissions relative to baseline case

342

15%

Thermochemical efficiency

10%

Solar irradiation

5% 0%

Life time of plant -5% -10% -15% -10%

Emission factor (Concentration infrastructure) -5% 0% 5% Variation of variable

10%

343 344

Figure 3 Sensitivity of LC GHG emissions for a variation of ±10% of selected variables,

345

efficiency of thermochemical syngas production, annual amount of direct normal solar



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irradiation, life time of the plant, and emission factor for the solar concentration

347

infrastructure, assuming a constant output of 1000 bpd of jet fuel

348 349

4.4 Sensitivity study for production costs

350

The selected variables for the economic sensitivity study are level of solar irradiation,

351

thermochemical efficiency, life time of the plant, specific investment costs of reflective area, and

352

costs of CO2 provision (Figure 4). An altered plant location which increases the level of solar

353

irradiation by 10% decreases the production costs by 4.7%. Equally, a decrease in solar

354

irradiation by 10% leads to 5.8% higher production costs. These values are not the same because

355

the 10%-increase in solar irradiation leads to a smaller heliostat field by 9%, while its decrease

356

requires a larger reflective surface area of 11%. A similar effect is found for the variation of

357

thermochemical efficiency which directly influences the required size of the heliostat field: an

358

increase of efficiency by 10% reduces the production costs by 6.1%, while a similar drop in

359

efficiency leads to an increase of 7.5%. As the concentration of the dilute solar energy requires a

360

large field of mirrors, investment costs for the solar concentration step play a major role. A

361

variation by ±10% of the unit cost of heliostat area shows a variation in production costs by

362

±2.4%. A change in O&M costs for the solar concentration has a similar effect and is not shown

363

in the graph. The 10%-reduction in lifetime of the plant leads to increased costs of 5.0%, while a

364

10% longer lifetime reduces the costs by 4.0%. The reason for the asymmetry is the nonlinearity

365

of the annuity factor. Finally, the CO2 costs have the smallest influence of ±1.8% on the

366

production costs. Solar irradiation, thermochemical efficiency, and plant lifetime are thus found

367

to have the largest impact on plant economics and are thus the main cost drivers of the process.


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Production costs relative to baseline case

10% Thermochemical efficiency 5%

Solar irradiation Lifetime of plant

0%

Investment costs reflective area

-5%

-10% -10%

CO₂ costs -5% 0% 5% Variation of variable

10%

368 369

Figure 4 Sensitivity of production costs for a variation of ±10% of selected variables,

370


371

irradiation, lifetime of the plant, investment costs of the solar concentration facility,

372

and CO2 provision costs, assuming a constant output of 1000 bpd of jet fuel

373 374

5 Scenario analyses

375

5.1 Scenario of grid electricity use

376

Up to this point, in the baseline case, the electricity requirements in the plant were assumed to be

377

covered by concentrated solar power. This solar stand-alone configuration of the plant reduces

378

the climate impact as it avoids the use of grid electricity which is likely to be at least partly based

379

on fossil primary energy and thus net emissions of greenhouse gases. For the derivation of 21 ACS Paragon Plus Environment


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380

production costs, electricity generation costs of 0.060 €/kWhel were assumed and the associated

381

emissions were taken into account for the calculation of life cycle GHG emissions. However,

382

electricity can also be taken from the local grid which reduces the number of heliostats but

383

introduces emissions depending on the fossil contribution to the national electricity production.

384

In the following, the use of grid electricity instead of solar electricity generation at the plant site

385

is assumed and the consequences for the economic performance and climate impact are analyzed.

386

As a reference plant site, Morocco is chosen, as it offers the assumed level of solar irradiation and

387

proximity to the European fuel market. The emission factor of the local grid electricity today is

388

0.729 kgCO₂-eq./kWhel56 at a cost of 0.072 €/kWhel57 in 2014. As the solar fuel plant is assumed to

389

operate in the mid-term future, these values may be subject to substantial change. They are

390

therefore adjusted to 0.480 kgCO₂-eq./kWhel and 0.060 €/kWhel for comparison, assuming 42% of

391

the electricity production to be based on renewable energy, following the strategy of the national

392

energy plan in 2020.58

393

If the electricity were taken from the grid at the conditions prevalent today, the production costs

394

would rise to 2.33 € and the life cycle GHG emissions to 4.92 kgCO₂-eq. per liter jet fuel when

395

compared with the baseline case in the future. The rise in costs is explained via the assumption of

396

low solar electricity costs in the future for the baseline case, while grid electricity today is slightly

397

more expensive. This assumption is motivated by the SunShot target for solar electricity and by

398

the fact that in some cases, already today, renewable sources represent the cheapest form of

399

electricity production. is the use of grid electricity results in only a slight increase in production

400

costs but a dramatic increase in climate impact to a value 60% higher than that of conventional jet

401

fuel today.4 If the adjusted values for the future grid are assumed, the production costs at 2.23 €

402

remain the same as for the baseline case and the GHG emissions rise to 3.36 kgCO₂-eq. per liter jet

403

fuel. This represents an increase in GHG emissions of about 10% with respect to conventional jet 22 ACS Paragon Plus Environment

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fuel today. Here, it should be noted that assumptions about the electricity production costs in the

405

future are inherently difficult to make and therefore the comparison with respect to production

406

costs should be treated with caution. Nevertheless, the production costs only change marginally

407

from one scenario to the other as electricity costs do not dominate the plant economics.

408

The analysis of the use of grid electricity shows that production costs are only negligibly affected

409

but life cycle GHG emissions are significantly increased. This is due to the fact that for the

410

production of 1 L jet fuel and 0.87 L naphtha, 11.4 kWh of electricity are required, or about 70%

411

of the LHV. The largest share of this electricity need is due to the inert gas purification for the

412

thermochemical reaction. The compression of syngas has a smaller but also an important

413

influence. Different reactor concepts using less electricity are thus expected to have a large

414

impact on the environmental performance of the fuel path in case grid electricity is used.

415

In the power-to-liquid path, hydrogen is produced by electrolysis at a much larger amount of

416

electricity than the value shown here. Nevertheless, depending on the emission intensity of the

417

local electricity supply, the climate impact of solar thermochemical jet fuel production may be

418

considerably deteriorated. This underlines the importance of providing the energy inputs from

419

renewable sources in order to produce fuels with a low level of GHG emissions.

420

421

5.2 CO2 capture from natural gas plant

422

A frequently discussed option of CO2 supply is the capture from fossil sources, e.g. carbon

423

capture from coal or natural gas power plants. In the following scenario, CO2 is captured with an

424

efficiency of 86% from a modern natural gas combined cycle power plant (NGCC).59 The capture

425

process introduces energy penalties which reduce the plant efficiency to 48%59 and increase the

426

specific electricity cost to 0.071 €/kWhel.60 With respect to the baseline case, the plant 23 ACS Paragon Plus Environment


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427

configuration is changed such that the required CO2 and electricity (the part which is not

428

provided by the CHP unit) for the plant is supplied not by conversion of solar primary energy but

429

by the NGCC plant. The size of the fossil plant was chosen to provide the necessary amount of

430

CO2. The amount of electricity produced then exceeds the demand of the solar plant, where the

431

surplus electricity is assumed to be sold at the market price of 0.072 €/kWhel. For the production

432

of 1000 bpd of jet fuel and 865 bpd of naphtha, 892.0 t of CO2 have to be supplied per day from

433

the capture unit of the NGCC plant. As 14% of the CO2 in the flue gas stream are lost to the

434

environment, 145.2 tCO₂ are emitted daily from the fossil plant. The electricity production of the

435

NGCC plant is 99.0 MWel, 75.0 MWel of which are used in the solar fuel plant, while the

436

remaining share is fed to the local grid. Costs associated to the NGCC plant are estimated with

437

the specific electricity production cost multiplied with the amount of produced electricity, while

438

revenue is created by the sale of electrical energy. Life cycle emissions are adjusted by the

439

decreased size of the heliostat field and the direct emissions from the fossil plant. The total

440

emissions are then allocated to the three products jet fuel, naphtha, and electricity on an energy

441

basis. Under the given assumptions, the production costs are 1.91 € at life cycle emissions of 3.67

442

kgCO₂-eq. per liter jet fuel. The use of CO2 and electricity from a NGCC power plant reduces the

443

costs of jet fuel production as the unit cost for CO2 provision is lower compared to air capture,

444

however, it considerably increases the life cycle GHG emissions due to the fossil origin of CO2

445

used for the fuel synthesis. Emissions of the production process and of fuel combustion can thus

446

not be counterbalanced by negative emissions of CO2 as in the baseline case using CO2 capture

447

from the atmosphere. The production of solar thermochemical fuels presents only a viable option

448

over conventional fuels if the CO2 is captured from renewable sources such as the atmosphere

449

and not from flue gases of a fossil power plant. This result is consistent with the analysis of Van

450

der Giesen et al.61 where the authors arrive at the same conclusion for the production of solar 24 ACS Paragon Plus Environment

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451

electrochemical fuels. More information including an overview of the contributions to the overall

452

emissions for the different scenarios analyzed here is given in the supporting information.

453

454

5.3 Potential for reductions of costs and GHG emissions

455

Considering favorable assumptions of a publicly financed plant in a sunny region with 3000

456

kWh/(m² a) of direct normal irradiation, a thermochemical efficiency of 30% (including inert gas

457

purification and gas separation), a reduction of the CO2 capture costs to 50 €/t, and a replacement

458

of the CHP plant by solar heat and electricity, production costs of 1.28 €/L jet fuel are estimated

459

at life cycle GHG emissions of 0.10 kgCO₂-eq. per liter jet fuel. Even more favorable conditions are

460

possible, e.g. the thermochemical efficiency has a thermodynamic limit above 50%62, the best

461

locations for concentrated solar technologies surpass the assumed 3000 kWh/(m² a), and more

462

cost effective sources of CO2 are available59 (possibly at higher specific emissions). However,

463

overly optimistic assumptions will deliver an unrealistic estimate for the ecologic and economic

464

performance which is why the baseline case has been chosen with partly ambitious but well

465

achievable boundary conditions.

466

467

Acknowledgments

468

The authors gratefully acknowledge the contribution of Hans Geerlings, Arne Roth and Christoph

469

Jeßberger, and Robert Pitz-Paal. The research leading to these results has received funding from

470

the European Union Seventh Framework Program (FP7/2007-2013) under grant agreement no.

471

285098 − Project SOLAR-JET.



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472

473

Supporting Information

474

Additional results, assumptions and figures are given in the supporting information which is

475

available free of charge via the Internet at http://pubs.acs.org.


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1

H2O

CO2 Sunlight

Syngas FT

CxHy

H2O/CO2

O2

2 3

CO2/H2O capture/storage

Solar concentration

Thermochemistry

Gas storage

FischerTropsch

Combustion

4

5

Figure 1 Schematic of solar thermochemical fuel production path. H2O and CO2 are

6

ubiquitous and can be captured from air. Direct solar radiation is concentrated by a field of

7

heliostats and drives the high-temperature thermochemical conversion of H2O and CO2 to

8

H2 and CO (syngas). The syngas is stored and finally converted into jet fuel via the FT

9

process.

1

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1

Seawater 0.1 MJe

Return water

H2O desalination 13.4 L H2O

0.5 MJe

Option C: CO2 capture from power plant

Atm. air

30.3 MJ

H2O transport

CO2 capture Return air 13.4 L H2O

Solar energy

Thermochemical conversion

Solar-to-heat 494.2 MJ 1033.4 MJ 184.1 MJ

1217.5 MJ

5.6 kg CO2 2.1 L H2O

267.7 mol H2 127.5 mol CO

33.8 MJe 2.3 MJe

Fischer-Tropsch conversion

Solar-to-electricity 1.9 MJe Option B: Grid electricity

13.3 mol H2

0.3 MJe

Hydrocracking and distillation

CHP 1.9 MJ 0.15 kg C1-C4

1.00 0.87 0.15

1.2 MJ

L Jet fuel L Naphtha kg C1-C4

System boundary 1.00 0.87

L Jet fuel L Naphtha

Figure 2 Energy and mass balance of fuel production plant for baseline case

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Falter et al.

Page 34 of 35


LC GHG emissions relative to baseline case

1

15%

Thermochemical efficiency

10%

Solar irradiation

5% 0%

Life time of plant -5% -10% -15% -10%

Emission factor (Concentration infrastructure) -5% 0% 5% Variation of variable

10%

2 3

Figure 3 Sensitivity of LC GHG emissions for a variation of ±10% of selected variables,

4


5

irradiation, life time of the plant, and emission factor for the solar concentration

6

infrastructure, assuming a constant output of 1000 bpd of jet fuel

7 8

1


Page 35 of 35


Falter et al.


1

Production costs relative to baseline case

10% Thermochemical efficiency 5%

Solar irradiation Lifetime of plant

0%

Investment costs reflective area

-5%

-10% -10%

CO₂ costs

-5% 0% 5% Variation of variable

10%

2 3

Figure 4 Sensitivity of production costs for a variation of ±10% of selected variables,

4


5

irradiation, lifetime of the plant, investment costs of the solar concentration facility,

6

and CO2 provision costs, assuming a constant output of 1000 bpd of jet fuel

7 8

1


Climate Impact and Economic Feasibility of Solar Thermochemical

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