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Techno-Economic Assessment of Power-to-Liquids (PtL) Fuels Production and Global Trading Based on Hybrid PV-Wind Power Plants


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This paper introduces a value chain design for transportation fuels and a respective business case taking into account hybrid PV-Wind power plants, electrolysis and hydrogen-to-liquids (H2tL) based on hourly resolved full load hours (FLh). The value chain is based on renewable electricity (RE) converted by power-to-liquids (PtL) facilities into synthetic fuels, mainly diesel. Results show that the proposed RE-diesel value chains are competitive for crude oil prices within a minimum price range of about 79 - 135 USD/barrel (0.44 – 0.75 €/l of diesel production cost), depending on the chosen specific value chain and assumptions for cost of capital, available oxygen sales and CO2 emission costs. A sensitivity analysis indicates that the RE-PtL value chain needs to be located at the best complementing solar and wind sites in the world combined with a de-risking strategy and a special focus on mid to long-term electrolyser and H2tL efficiency improvements. The substitution of fossil fuels by hybrid PV-Wind power plants could create a PV-wind market potential in the order of terawatts.
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1876-6102 © 2016 The Authors. Published by Elsevier Ltd. This is an open access article under the CC BY-NC-ND license
Peer-review under responsibility of EUROSOLAR - The European Association for Renewable Energy
doi: 10.1016/j.egypro.2016.10.115
Energy Procedia 99 ( 2016 ) 243 268
10th International Renewable Energy Storage Conference, IRES 2016, 15-17 March 2016,
Düsseldorf, Germany
Techno-Economic Assessment of Power-to-Liquids (PtL) Fuels
Production and Global Trading Based on Hybrid PV-Wind Power Plants
Mahdi Fasihi*, Dmitrii Bogdanov, Christian Breyer
Lappeenranta University of Technology, Skinnarilankatu 34, 53850 Lappeenranta, Finland
This paper introduces a value chain design for transportation fuels and a respective business case taking into account hybrid PV-
Wind power plants, electrolysis and hydrogen-to-liquids (H2tL) based on hourly resolved full load hours (FLh). The value chain
is based on renewable electricity (RE) converted by power-to-liquids (PtL) facilities into synthetic fuels, mainly diesel. Results
show that the proposed RE-diesel value chains are competitive for crude oil prices within a minimum price range of about 79 -
135 USD/barrel (0.44 – 0.75 €/l of diesel production cost), depending on the chosen specific value chain and assumptions for cost
of capital, available oxygen sales and CO2 emission costs. A sensitivity analysis indicates that the RE-PtL value chain needs to be
located at the best complementing solar and wind sites in the world combined with a de-risking strategy and a special focus on
mid to long-term electrolyser and H2tL efficiency improvements. The substitution of fossil fuels by hybrid PV-Wind power
plants could create a PV-wind market potential in the order of terawatts.
© 2016 The Authors. Published by Elsevier Ltd.
Peer-review under responsibility of EUROSOLAR - The European Association for Renewable Energy.
Keywords: hybrid PV-Wind; Power-to-Liquids (PtL); power-based fuels; economics; business model; Argentina
1. Introduction
The demand for transportation fuels is high in the world and it is growing [1], but fossil fuel resources are limited
and we do not know how much affordable crude oil is available for transportation fuels in the long term [2]. Besides,
* Corresponding author. Tel.: +358-449123345
E-mail address:
Available online at
© 2016 The Authors. Published by Elsevier Ltd. This is an open access article under the CC BY-NC-ND license
Peer-review under responsibility of EUROSOLAR - The European Association for Renewable Energy
244 Mahdi Fasihi et al. / Energy Procedia 99 ( 2016 ) 243 – 268
it is still impossible to use electricity directly in some transport sectors, like aviation. On the other hand, our planet is
facing a dramatic climate change problem [3], thus even with adequate fossil fuel reserves, CO2 emissions still
would be a limiting constraint in the long term [4, 5]. Power-to-Gas (PtG) plants based on electroysis and
methanation [6] converting electricity into synthetic natural gas (SNG) and Gas-to-Liquids (GtL) plants [7]
converting natural gas (NG) to liquid fuels (with higher heating value and easier transportation) already exist on a
commercial scale. In addition, Power-to-Liquids (PtL) [8] plants converting electricity directly into synthetic liquid
fuels (as a rather new concept to increase the efficiency and to decrease the final production cost) have been
developed on a laboratory scale and are ready to enter the commercialization phase [9]. By using solar photovoltaic
(PV) and wind energy based renewable electricity (RE) as the source of primary energy, RE-based fuels, such as
RE-diesel can be produced to overcome the constraints of resource limitation and CO2 emissions in the conventional
value chain.
There are several technical options to produce hydrocarbon fuels based on hybrid PV-wind plants for the
transport and mobility sector: mainly RE-PtG [6], liquefied natural gas (LNG) based on RE-PtG [10], RE-PtG-GtL
[11] and RE-PtL. All options can be used to buffer and store intermittent renewable electricity. This paper is focused
on the RE-PtL option. Some mobility sectors such as aviation, maritime transportation or heavy vehicles cannot be
easily operated by batteries or synthetic natural gas (SNG). Thus, even in the long term, liquid hydrocarbon fuels
will have a high demand. PtL is the technology to produce liquid fuels directly from renewable electricity, water and
CO2, but this technology is still under development and the best approach and final product is still under discussion.
This paper is an attempt to investigate the costs of one of the major PtL value chain options.
Figure 1 shows the simplified value chain of the whole process for a chain with alkaline electrolyser or solid
oxide co-electrolyser. In the first diagram (Fig. 1, top), the main components are: hybrid PV-Wind plants,
electrolyser and reverse water gas shift (RWGS) plants, CO2 from air scrubbing units, Fischer-Tropsch synthesis
plant, products upgrading (hydrocracker) unit and fuels shipping. The integrated system introduces some potentials
for utilization of waste energy which will increase the overall efficiency and will decrease the costs. In the second
diagram (Fig. 1 bottom), the main components are mainly the same, while a separate RWGS plant is eliminated due
to co-electrolysis of water and CO2 in a high temperature solid oxide electrolyser. This integration will increase the
overall efficiency and in long term might lead to a decrease in costs.
2. Methodology
The RE-diesel production system consists of two main parts: syngas (mixture of CO and H2) production and the
conventional Fischer-Tropsch (FT) downstream value chain. In this paper, two main routes are presented for
describing the syngas production, followed by a regular FT unit. On the other hand, two models are used for
describing the hydrogen production for considerations on an annual, but also on an hourly, basis.
The Annual Basis Model represents a hybrid PV-Wind power plant with 5 GW capacity for both PV single-axis
tracking and Wind onshore energy. The cost assumptions are based on expected 2030 values and that highly cost
competitive components can be sourced for such very large-scale investments. No fixed tilted PV or battery is
considered to be part of the plant and the produced electricity and respective calculations are based on annual full
load hours (FLh) of the hybrid PV-Wind plant, which can be seen in Table 1. The estimate on an annual FLh basis
can be surprisingly accurate if applied carefully [12, 13]. An important piece of information is the level of
curtailment, or so-called overlap FLh, i.e. an equivalent of energy which cannot be used. For the special case of a
hybrid PV-Wind plant, a conservative estimate is 5% [14]. This model will give a rough estimation of a system
working with equal PV and wind power capacity.
Mahdi Fasihi et al. / Energy Procedia 99 ( 2016 ) 243 – 268 245
Fig. 1. The hybrid PV-Wind-PtL value chain with alkaline electrolysers and RWGS units (top) and solid oxide co-electrolyser (bottom).
246 Mahdi Fasihi et al. / Energy Procedia 99 ( 2016 ) 243 – 268
Table 1. Hybrid PV-Wind power plant specification for annual analysis scenario.
Unit Amount Unit Amount
Irradiation (single-axis) kWh/(m2·a) 2410 PV single-axis FLh h 2000
PV performance ratio (PR) % 83 Wind FLh h 5200
PV yield kWh/kWp 2000 PV and Wind overlap % 5
Hybrid PV-Wind FLh h 6840
Installed capacities
PV single-axis installed capacity GWp 5
Wind installed capacity GWp 5
The Hourly Basis Model uses the optimised combination of PV (fixed-tilted or single-axis tracking), wind power
and battery capacity based on an hourly availability of the solar and wind resources to minimize the levelized cost of
electricity (LCOE) and RE-diesel. Hydrogen and CO2 storage systems will guarantee the feedstock for operation of
the reverse water gas shift (RWGS) plant and subsequently the Fischer-Tropsch (FT) plant on a base load. In
addition, low cost batteries are added to harvest the excess electricity during overlap times to increase the FLh
whenever it is beneficial. SNG is produced in a methanation plant which will be burnt to produce electricity via a
gas turbine.
The equations below have been used to calculate the LCOE of a hybrid PV-Wind power plant and the subsequent
value chain. Abbreviations: capital expenditures, capex, operational expenditures, opex, full load hours, FLh, fuel
costs, fuel, efficiency, Ș, annuity factor, crf, weighted average cost of capital, WACC, lifetime, N, performance
ration, PR, overlap FLh, overlap.
Capex crf Opex
crf WACC
,PV el irradiation
gross FLh FLh
Wind Wind PV PV
LCOE overlap
2.1. Power-to-Syngas
2.1.1 Hybrid PV-Wind power plant and battery
In this research, hybrid PV-Wind power plants are taken into account as the resource of renewable electricity.
The hybrid PV-Wind power plants should be located in the regions of very high FLh to reduce LCOE of power
production and subsequently the LCOE of electrolysis. Figure 2 shows the FLh for hybrid PV-wind power plant
sites in the world, where the best sites are indicated by a red color coding. In this study, the plant is located in
Mahdi Fasihi et al. / Energy Procedia 99 ( 2016 ) 243 – 268 247
Patagonia, Argentina, which is among the best places in the world for solar and wind resources. The produced RE-
based hydrocarbons are assumed to be shipped to Rotterdam in the European Union.
Fig. 2. World’s hybrid PV-Wind power plant FLh map. The numbers refer to the place of RE-diesel production (1) and diesel demand (2).
The specification of the hybrid PV-Wind power plant and the storage options can be seen in Table 2.
Table 2. Hybrid PV-Wind power plant and storage options specification. Abbreviations: capital expenditures, capex, and operational
expenditures, opex.
Unit Amount Unit Amount
PV fixed-tilted Battery
Capex €/kWp 500 Capex €/kWhel 150
Opex % of capex p.a. 1.5 Opex % of capex p.a. 6
Lifetime years 35 Lifetime years 15
Cycle efficiency 90
PV single-axis tracking
Capex €/kWp 550 Methanation (H2tG)
Opex % of capex p.a. 1.5 Capex €/kWhgas 234
Lifetime years 35 Opex % of capex p.a. 2.14
Lifetime years 30
Wind energy Efficiency % 77.9
Capex €/kWp 1000
Opex % of capex p.a. 2 Gas turbine
Lifetime years 25 Efficiency % 58
Hydrogen storage
Capex €/kWhgas 0.015
248 Mahdi Fasihi et al. / Energy Procedia 99 ( 2016 ) 243 – 268
2.1.2. Syngas production
In this method, syngas production consists of two main steps: hydrogen production by water electrolysis (Eq. 6)
and carbon monoxide hydrogenation by RWGS reaction (Eq. 7), which are shown in Figure 3. Water and electricity
are the inputs for the electrolysis plant, while electrical power converts water to H2 and O2 as products of this
endothermic process. CO2 obtained from ambient air by CO2 capture plants and H2 are used in the endothermic
process of RWGS [15] to produce carbon monoxide. The reaction rate is low and beside CO and H2O, the products
include unconverted CO2 and H2. Some actions can be done to increase the reaction rate. The first thing to do is to
increase the temperature of the RWGS reaction environment. A minimum temperature of 400 ºC is needed to get the
reaction started, while increasing the temperature up to 1600 ºC will result in higher reaction rates. A level of 800-
900 ºC is a common temperature to operate the RWGS plant [8]. Due to the high temperatures needed in this
process, the energy demand for this process is supplied by electricity. In our model, the RWGS plant is operating on
a base load, thus batteries or a H2tG-GtP system is needed to supply this demand in the absence of fluctuating RE.
On the other hand, a catalyst-based reaction (iron-chrome as an example) results in a higher reaction rate at lower
temperatures [16]. The third method is to increase the portion of H2 or CO2 to more than its nominal ratio. Applying
a H2:CO2 ratio of 3:1 is a common practice to boost the reaction rate. The extra hydrogen can be recycled and used
in the reaction again. But in our model, the recycling system is not needed, as that extra H2 is needed to form a
syngas with a H2:CO ratio of 2:1 (Eq. 8). Steam removal is also needed to increase the reaction rate and purity of
produced carbon monoxide [16]. In any case, the unreacted CO2 can be recycled in the system, thus the overall
carbon conversion can be considered more than 95%, as in Sunfire’s model [17].
Fig. 3. Power-to-Syngas (electrolysis and RWGS) process.
Electrolysis: 222
RWGS: 22 2
CO H CO H Oo (¨H0 = 41 kJ/mol) (7)
RWGS with extra hydrogen: 22 22
32CO H CO H H Oo (¨H0 = 41 kJ/mol) (8)
Hydrogen can be produced by different types of electrolysers. The alkaline electrolysis cell (AEC) is well-known
and a mature technology for water electrolysis [18], while the proton exchange membrane electrolysis cell (PEMEC)
[18, 19] and the solid oxide electrolysis cell (SOEC) [18, 20] are technologies in the commercialization phase or still
under development. PEMEC shows a slightly better efficiency and shorter startup time in comparison to AEC,
which is an advantage while using fluctuating RE as a source of power. SOEC operates at higher temperatures and
pressure. The higher temperature offers the chance to replace a part of the electricity needed for the reaction by heat,
which can be supplied by the outlet steam of the FT plant. The higher temperature of produced hydrogen by SOE
will result in a higher CO2 conversion rate in the RWGS plant, or can decrease the heat demand for a fixed reaction
Mahdi Fasihi et al. / Energy Procedia 99 ( 2016 ) 243 – 268 249
temperature. Furthermore, co-electrolysis of water and carbon dioxide is possible at that high temperature. This
results in the elimination of the RWGS plant, which can decrease the costs. However, the startup time of SOEC is
higher than for AEC and PEMEC. On the other hand, the structure of the used energy model in addition to the
application of fluctuating RE can question the application of this type of electrolyser. The SOEC needs to be kept
warm even in non-operating periods, when RE is not available. This can increase the overall energy demand,
complexity and cost of the system. On the other hand, most publications count on FT outlet heat to cover this heat
demand, while in the used model this heat is used in the atmospheric CO2 capture plant. Thus, there is no extra heat
available to be used for SOEC in this system. Moreover, the co-electrolysis of water and carbon dioxide by
fluctuating electricity will result in intermittent syngas production that would need a syngas storage system for
which no data had been found. The other solution would be to apply batteries to provide electricity on a base load,
which would increase the cost significantly. The reported costs for PEMEC and SOEC are higher and in a wider
range than those for AEC in 2030, while the lower capex for AEC is very important in achieving optimized SNG
cost. The projected specifications for these three types of electrolysers are shown in Table 3 [6, 21 – 25]. In addition,
there are more uncertainties about the achievement of techno-economic targets for PEMEC and SOEC for 2030.
Thus, based on costs and applications, the alkaline high pressure electrolysis has been taken into account in the used
Table 3. Electrolysers’ specification. Abbreviations: electricity-to-hydrogen, EtH2, efficiency, eff.
Capex €/kWel 319 250-1270 625-100
Opex % of capex p.a. 3 2-5 2-5
Lifetime years 30 20 20
EtH2 eff. (HHV) % 86.3 74-89 91-109
Heat demand % of inlet E - - 18-20
2.1.3. CO2 from ambient air scrubber
To have a sustainable energy system with carbon neutral products, CO2 needs to be obtained from a sustainable
CO2 source such as a biomass plant with carbon capture and utilization (CCU) [26] or it can be captured from
ambient air, which is assumed in this work. In the second case, the chosen CO2 source is independent of the
location, thus carbon supply would not restrict the best places for the PtL plant.
The CO2 capture from ambient air approach from Climeworks [27] has been used for the energy system in this
work, since between 80-90% of energy needed for this plant can be supplied by heat, rather than electricity [28]. In
this case the output heat of the electrolysis and FT can be used to fulfill this heat demand, which will increase the
overall efficiency of the system. The output heat of the alkaline electrolysis and FT plant, via a heat exchanger with
90% efficiency, perfectly matches the heat demand of the CO2 capture plant of the required capacity. To capture 1
ton of carbon dioxide out of ambient air, this system requires 1300-1700 kWhth of thermal energy at 100-110°C and
200-250 kWhel electricity [29]. The average numbers which have been used in our calculations can be seen in Table
4. In case of a lack of internal heat, the heat from heat pumps could be used to deliver the heat needed for the CO2
capture plant.
Table 4. CO2 capture plant specification.
Unit Amount
Capex €/(tCO2·a) 228
Opex % of capex p.a. 4
Lifetime years 30
Electricity demand kWhel/tCO2 225
Heat demand kWhth/tCO2 1500
250 Mahdi Fasihi et al. / Energy Procedia 99 ( 2016 ) 243 – 268
2.1.4. Water desalination
The output water from the RWGS and Fischer-Tropsch (FT) processes can be recycled and reused in electrolysis,
but these water sources are not enough to supply all the water needed for electrolysis. Thus, a part of the water
needed for the electrolyser has to be supplied from an external source. In some regions there might not be enough
clean water available for electrolysis. The plant is located along a sea shore, thus seawater reverse osmosis (SWRO)
desalination could be used. Water desalination plant specifications can be found in Table 5. More details on RE-
powered SWRO desalination plants are provided by Caldera et al. [30].
The syngas production plant is built along the sea shore and electricity from the hybrid PV-Wind plant is
transmitted to the site. In this case, there would be no cost for water piping and pumping from the coast, where the
seawater is desalinated. In addition, the FT plant is located just beside the syngas plant and thus no syngas
transportation cost has to be taken into account and the liquid fuels transportation cost to the port will be minimized
as well.
Table 5. Water desalination and storage plants’ specification [30].
Unit Amount Unit Amount
SWRO Desalination Water storage
Capex €/(m3·a) 2.23 Capex €/m3 65
Opex % of capex p.a. 4.3 Opex % of capex p.a. 1.5
Lifetime years 30 Lifetime 50
Electricity consumption kWh/m3 3.0
Water extraction efficiency % 45
2.1.5. Oxygen
In case of a potential market oxygen, as a byproduct of electrolysis, can also have a very important role in the
final cost of produced hydrogen or synthetic fuels. The market price of oxygen for industrial purposes can be up to
80 €/tO2 [6]. It might be too optimistic to assume that all the produced oxygen could be sold for this price. Moreover,
in case of a potential market, oxygen storage and transportation costs have to be applied. To make a rough
assumption, considering all these effects, there is no benefit from oxygen utilisation in the base scenario. The
projection of a maximum 20 €/tO2 benefit from oxygen utilisation is assumed in another study for RE-PtG-LNG
[10], when all the produced oxygen was for sale. The same is assumed in this study, while 5% less oxygen is
produced in the PtL chain with AEC.
2.2. Syngas-to-Liquids
The Syngas-to-Liquids process provides the opportunity to convert syngas to liquid fuels through a series of
chemical reactions. This process consists of two main steps: Fischer-Tropsch Synthesis (FTS) and products
upgrading [7]. Although these process steps are well-known, at the same time, the combined technology is complex
and well-protected by limited companies developing them.
2.2.1. Fischer-Tropsch synthesis
The Fischer-Tropsch process converts syngas to different chains of synthetic hydrocarbons (-CH2-)n, which is
also known as syncrude (Eq. 9). This reaction is highly exothermic [31]. In our model, the water produced in this
reaction is recycled and reused in the water electrolysis section. Also, the released heat is used in the atmospheric
CO2 capture plant through a heat exchanger. In case of the SOEC application, the steam out of the FT unit can be
Mahdi Fasihi et al. / Energy Procedia 99 ( 2016 ) 243 – 268 251
directly used in the SOEC. More details on the characteristics of different types of FT synthesis are described by
Fasihi et al. [11].
Fischer-Tropsch Synthesis (FTS):
2nCO nH CH nH Oo ¨H0 = -209 kJ/mol (9)
2.2.2. Products upgrade
The syncrude contains hydrocarbons of different lengths. By adding hydrogen and hydrocracking of long chain
syncrude, the hydrocarbons with a desired length can be produced as products in the upgrading unit. Equation 10
shows the simplified reaction at this step. If needed, the hydrogen used in this step can be supplied from the storage.
Products upgrade:
22 22nn
o (10)
The final products can include up to 30% wax. Maximizing wax configuration in the output improves the total
cost structure, but the demand for wax is much less than diesel. Thus, in a global model, the aim is to maximize the
diesel share in the output.
Starting from the syngas, the FT and syncrude hydrocracking are the common and the last loops in both the GtL
and PtL value chains. Thus, the final products of PtL are basically the same as for GtL plants’ products. GtL
products in some publications are shown in Table 6.
Table 6. GtL final products composition (vol%). Abbreviations: liquefied petroleum gas, LPG.
LPG Naphtha Middle distillates Lubes & Wax Comment
Jet fuel /
Kerosene Diesel
Fleisch et al. [32] 15-25 65-85 0-30
Brown [33] 5 20 75 typical GtL
Velocys [34] 20 80
Chedid et al. [35] 6 26 68
NPC [36] 25 70 5
Khalilpour, Karimi [37] 5 20 75
Bao [38] 3 30 67
FVV [39] 15 25 60 Diesel mode
25 50 25 Kerosene mode
Aiming for the maximum middle distillates share, the numbers provided by [39] have been used for the model of
this paper, and represent naphtha, jet fuel and diesel with a share of 15%, 25% and 60%, respectively. Considering
diesel and jet fuel as the target products of this process, the potential revenue of sold by-products from the total costs
and therefore the levelized cost of fuel (LCOF) of the target products in the value chain should be investigated.
Paraffin wax, as a potential product of the FT process has a higher financial value than crude oil [40], but it is not in
the slot of final products in the used model. The price of all products is a function of the crude oil price, as they
compete with refinery products of crude oil. Naphtha has approximately the same market value as crude oil, thus it
has no additional effect than the crude oil price on the results [41].
Table 7 shows all the assumptions for the specifications of the hydrogen to liquids (H2tL) plant in the model used
in this paper. In the absence of solid numbers for H2tL plant in the literature review, the specification have been
calculated by combining the technologies and cost breakdowns presented by Maitlis and Klerk [42], König et al. [8]
and Fasihi et al. [11].
252 Mahdi Fasihi et al. / Energy Procedia 99 ( 2016 ) 243 – 268
Table 7. Base case specification of a hypothetical H2tL (RWGS, FT and hydrocracking) plant assumed for this paper.
Unit Amount
Capex k€/bpd 60
Opex % of capex p.a. 3
Lifetime years 30
Availability % 95
Energy efficiency % 65
naphtha %
Products jet fuel
2.3. Products shipping
PtL products can be shipped by a product tanker fleet. The deadweight (DW) of large range vessels (LR2) is
between 80,000 to 120,000 tons. The ship can carry a weight of approximately 90% of its DW [43]. The shipping
specifications are shown in Table 8, assuming shipping from Patagonia to Rotterdam. The data have been taken
from Konovessis [44], MAN [45], Sea distances [46], UNCTAD [47] and Khalilpour [37].
Table 8. Shipping specification.
Unit Amount
Capex m€/ship 48
Opex % of capex p.a. 3
Lifetime years 25
Availability % 95
Ship type large range 2 (LR2) -
Ship size ton (deadweight) 100,000
Speed knots 14
Charge and discharge time total days 2
Marine distance km 13,400
3. Results
3.1. RE-PtL case study, annual basis model
Integrating all the system’s elements offers some chances to increase the overall efficiency. Figure 4 shows the
Sankey diagram of the entire system with AEC, depicting the energy and material flows within the entire RE-PtL
value chain. The figure is the sample of a system with 1 MWhel specific annual electricity input. As can be seen, the
alkaline electrolyser, at 93%, is the main electricity consuming element, while the excess heat by-product of the
electrolyser and the FT plant is the main source of energy for the CO2 capture plant. The heat released in the FT
process accounts for 19% of initial electricity and 24% of energy content of inlet H2 to the system. The overall PtL
efficiency of this system, would be 57.5%, while 71.8% of inlet hydrogen is converted to liquid fuels in the H2tL
plant. The 15% naphtha share is finally not available for transport fuels. However, this is no financial burden since it
can be sold on the market for an attractive value which should be cost neutral.
Mahdi Fasihi et al. / Energy Procedia 99 ( 2016 ) 243 – 268 253
Fig. 4. RE-PtL energy and material flow diagram.
RE-diesel production cost can be a function of crude oil price if there are by-products for selling in the market.
All the general assumptions in the calculations of the base case can be found in Table 9.
Table 9. General assumptions in base case calculations.
Unit Amount
WACC % 7
Exchange rate USD/€ 1.35
Brent crude oil price USD/bbl 80
The diesel produced in the FT-process has different characteristics than the conventional diesel produced by a
petroleum refinery. The term "FT-diesel" is used to emphasize the quality of the final product. Although the quality
of FT-diesel can differ from plant to plant, in this paper the density (at 20 ºC) and higher heating value (HHV) of
FT-diesel are assumed to be 766 kg/m3 and 45.471 MJ/kg, respectively [41, 48]. On the other hand, the term RE-
diesel is used to emphasize the source of primary energy (PE) in diesel production, while referring to the same
The LCOE of wind energy and solar PV are 20.35 €/MWh and 25.36 €/MWh, respectively. The hybrid PV-Wind
power plant of 5 GW produces about 34,700 GWh of electricity per year and the weighted average cost is 22.89
€/MWh. The CO2 captured from ambient air and the desalinated water cost 40.42 €/tCO2 and 0.52 €/m3, respectively.
A summary of all production costs for the base scenario can be found in Table 10.
254 Mahdi Fasihi et al. / Energy Procedia 99 ( 2016 ) 243 – 268
Table 10. Production cost in base scenario.
Unit Amount
Renewable Electricity (RE) €/MWhel 22.89
CO2 €/tCO2 40.42
Desalinated water €/m3 0.52
RE-H2 €/MWhth,H2 32.54
RE-PtL average product at production site €/MWhth 69.94
FT-diesel at destination €/MWhth 70.49
FT-diesel at destination USD/MMBtu 27.57
FT-diesel at destination €/l 0.69
Figure 5 shows the levelized costs in the RE-diesel value chain with two scenarios for two weighted average
costs of capital (WACC): 7% and 5%. The RE-diesel cost distribution as a share of the total is not dependent on the
WACC. H2tL and the hybrid PV-Wind plant have the highest share (52.8% and 32.3%, respectively) in the total
cost. The H2tL plant includes the CO2 capture plant, RWGS, FT and hydrocracking plants. At 1.3%, shipping has
the lowest share in this process. Thus, it is more important to have the plants located in regions of the highest solar
and wind potential than in regions close to the target market in order to reduce the final cost.
Fig. 5. RE-diesel production cost breakdown for WACC of 5% (top) and 7% (bottom).
Mahdi Fasihi et al. / Energy Procedia 99 ( 2016 ) 243 – 268 255
Electrolysis represents 13.6% of the final product’s cost, while at 5.98 €/MWhth,H2, the share of the electrolysis
plant itself in the final cost of hydrogen production is 62%, and energy losses in electrolysis accounts for 37.6% of
the cost of this process. Water cost is also included in the hydrogen production (electrolysis) section of the value
chain. At 0.04 €/MWhth,H2, the cost of water is almost negligible. At 10.56 €/MWhth,fuel, the cost of CO2 has a 28.2%
share in the H2tL plant cost. This includes the direct electricity used in the CO2 capturing process, and the heat
demand is supplied by internal heat, which is considered free of charge (Fig. 5). At 12.75 €/MWhth,fuel the cost of
energy loss in the H2tL plant is slightly more than the cost of the plant itself, which is 12.54 €/MWhth,fuel.
For the assumptions of the base case scenario, the final cost of RE-diesel in Rotterdam would be 70.89 €/MWhth,
which is equal to 160.85 USD/bbl, 27.73 USD/MMBtu or 0.69 €/l of diesel. The conventional diesel cost is a
function of the crude oil price and refining cost. Figure 6 shows the historical trends for the crude oil price, refining
cost, diesel cost and crude oil cost to diesel price ratio in percentage.
Fig. 6. Crude oil price, diesel refining cost and ratio diesel cost to crude oil price. Data taken from EIA [49].
The long term (13 year) average ratio of one barrel diesel cost (crude oil consumption and refinery cost) to crude
oil price is 118.76% and has been taken in this work. The ratio for the full year 2014 was 113.5%. With a crude oil
price of 80 USD/bbl, the cost of conventional diesel would be equivalent to 95 USD/bbl, 16.38 USD/MMBtu or
0.44 €/l. Thus, the base scenario, accounting for a RE-diesel of 160.85 USD/bbl, is not directly competitive to the
conventional diesel price, but there are some potential game changers:
A) WACC: For a WACC of 7% in the base scenario, the cost of debt and return on equity are 5% and 12%,
respectively, for a debt to equity ratio of 70:30. For a WACC of 5%, the corresponding numbers would be 4% and
7%, which could be realized for a risk minimized business case. With this scenario the cost of RE-diesel in
Rotterdam could be decreased by 14.5% to 60.6 €/MWhth, 23.71 USD/MMBtu, 137.5 USD/bbl or 0.593 €/l of diesel
equivalent. Figure 7 shows the effect of WACC on the final cost.
256 Mahdi Fasihi et al. / Energy Procedia 99 ( 2016 ) 243 – 268
Fig. 7. Effect of WACC on final product’s cost in comparison to base case scenario.
B) CO2 emission cost: CO2 emission cost for fossil fuels can have a significant impact on the competitiveness of
RE-diesel and conventional diesel, as it increases the total cost of fossil fuels. The conventional diesel carbon
emissions are 20.2 tC/TJ (ton carbon per tera joule) [50], which is equal to 74.02 tCO2/TJ. The additional cost of CO2
emissions with a maximum price of 50 €/tCO2 on the conventional diesel price can be seen in Figure 8. Assuming a
crude oil price of 80 USD/bbl and 101.44 USD/bbl as the corresponding price for diesel for the base case (including
the cost of refining), a CO2 price of up to 50 €/tCO2 is equivalent to a price increase of the diesel of 13.48 €/MWhth,
5.27 USD/MMBtu, 30.57 USD/bbl and 0.14 €/l.
Fig. 8. The additional cost of CO2 emissions on the conventional diesel price for a CO2 price of up to 50 €/tCO2 in absolute numbers and
relative for a basis crude oil price of 80 USD/bbl.
C) Oxygen: There is no financial benefit assumed from the oxygen produced in the base scenario. The projection
of a maximum average benefit of 20 €/tO2 is shown in Figure 9. An oxygen price of up to 20 €/tO2 is equivalent to a
cost decrease of the RE-diesel of 5.64 €/MWhth, 2.2 USD/MMBtu, 12.79 USD/bbl and 0.06 €/l of diesel, which is
equal to a 7.95% decrease in the final cost.
Mahdi Fasihi et al. / Energy Procedia 99 ( 2016 ) 243 – 268 257
Fig. 9. Effect of oxygen benefit for an oxygen price of up to 20 €/tO2 on RE-diesel in absolute numbers and relative ones for the base
scenario cost.
In summary, an increase in crude oil price or CO2 emission cost will increase the cost of conventional diesel,
while a profitable business case for O2 or a reliable business case at a de-risked 5% WACC level can lead to lower
cost for RE-diesel cost. The effects of all these potential game changers have been summarised in Figure 10. The
price of diesel in the EU is based on:
xthe global crude oil price as depicted in Figure 10 for a price range of 40 – 170 USD/barrel,
xthree scenarios for CO2 emission cost,
xthree scenarios for benefits from O2 sales, and
xthe cost of delivered RE-diesel based on two different WACC levels
All projections are for the year 2030.
Fig. 10. Different scenarios for the RE-diesel price in the EU based on the production costs in Patagonia. Reading example: For a crude
oil price of 100 USD/bbl the conventional diesel price varies from 52 – 66 €/MWhth (depending on the CO2 emission costs), while the
RE-diesel cost varies from 55 – 71 €/MWhth (depending on WACC and O2 benefit), i.e. for 80 USD/bbl, 50 €/tCO2, 5% WACC and 20
€/tO2 the RE-diesel is competitive to the conventional one without any further assumptions.
The first breakeven point can be expected for a produced RE-diesel with a WACC of 5%, CO2 emission cost of
50 €/tCO2, accessible oxygen price of 20 €/tO2 and a crude oil price of about 80 USD/bbl. While RE-diesel produced
258 Mahdi Fasihi et al. / Energy Procedia 99 ( 2016 ) 243 – 268
under the base case (WACC of 7%, no CO2 emission cost and no O2 sales) can compete with conventional diesel
whenever the crude oil price is higher than about 136 USD/bbl. This represents a very high difference and the base
case may not easily match with market prices. But the additional assumptions are not far from reality, since a CO2
emission cost is already applied in some countries [51].
To have a better understanding about the scale of the project, Table 11 lists the physical and economic aspects of
the 5 GW case assumption. In addition, the capital expenditure breakdown of the total value chain is shown in
Figure 11. The total capital cost is 13.07 bn€, while the electricity generation solely requires 59% of the capital
expenditure. With 0.8% and 0.04% respectively, the capital expenditures of ships and the desalination plant are
almost negligible.
Table 11. The annual consumption/ production and economic aspects of the 5 GW case assumption. Abbreviations: million ton per annum,
MMTPA, barrel per day, bpd.
Unit Amount Unit Amount
Hybrid PV-Wind power plant H2tL plant
PV single-axis installed capacity GWp 5 Capacity bpd PtL 31,170
Wind installed capacity GW 5 Capital expenditure bn€ 2.23
Capital expenditure bn€ 7.8 Diesel production bbl/year 7,733,500
Hybrid PV-Wind, generation GWhel 36,000 Jet fuel/ Kerosene production bbl/year 1,442,000
Hybrid PV-Wind, used GWhel 34,670 Naphtha production bbl/year 1,933,400
CO2 capture plant Electrolysis plant
Capacity MWhel 170 Capacity GWhel 4.64
Capital expenditure m 1500 Capital expenditure bn€ 1.48
CO2 production MMTPA 5.140 H2 production GWhth 27,360
External heat utilization GWhth 6610 H2 production MMTPA 0.694
Desalination plant Shipping
Capacity MWhel 10 Shipping volume bbl/year 12,889,200
Capacity m3/houtlet 340 number of ships - 2.11
Capital expenditure m 7 Capital expenditure m€ 100
Water production mio m3 2.3
Fig. 11. The capital expenditure breakdown of the hybrid PV-Wind-PtL value chain.
Mahdi Fasihi et al. / Energy Procedia 99 ( 2016 ) 243 – 268 259
To have an overview on the data available to the public, one should take into consideration that the real values for
2030 could be different from those explained above. In addition, geographical position of hybrid PV-Wind plants
will change the FLh and the input power to the system. Moreover, PtL plants can be designed for a desired range of
outputs and the corresponding costs could be quite different case by case. In response to these uncertainties, a series
of sensitivity analyses has been done for ±10% change in the capex, efficiency and other inputs of major elements.
Figure 12 illustrate these analyses in the categories of economic changes, geographical changes and changes in plant
Fig. 12. Sensitivity analysis of input data based on economic changes (top, left), change in plants’ opex (top, right), geographical
changes (bottom, left) and plants’ energy efficiency (bottom, right).
The economic changes graph illustrates that a 10% decrease in the capex of a hybrid PV-Wind power plant will
result in a 5.5% decrease in the final leveliced cost of fuel (LCOF) of diesel, which is 2.5 times more than the effect
of changes in the capex of the electrolysis or H2tL plant. On the other hand, changes in opex show that no single
plant can cause more than a 1% change in the final production cost if the opex divergence is up to 10%. The
geographical changes graph shows that a 10% decrease in the FLh of hybrid PV-Wind plant will increase the final
LCOF by 9%, while a 10% increase in the efficiency will just result in a 7.5% decrease in the final products’ cost. A
10% change in the amount of overlap is a very small number and it does not bring any significant change to the
system. As it is expected, plants’ energy efficiency analysis shows that a 10% increase in the efficiency of
electrolysis and H2tL plants would decrease diesel production cost by 7% each. Summing up, the three final RE-
diesel LCOF influencing factors are the full load hours of the hybrid PV-Wind power plant, the electrolyser and
260 Mahdi Fasihi et al. / Energy Procedia 99 ( 2016 ) 243 – 268
H2tL efficiency and WACC for the entire investment. As a consequence, the RE-PtL value chain needs to be located
at the best complemented solar and wind sites in the world combined with a de-risking strategy and a special focus
on mid to long term electrolyser and H2tL efficiency improvements.
3.2. Optimal RE-PtL global potential, hourly basis model
The global RE-PtL generation potential has been studied on an hourly basis. The hourly model enables the best
combination of PV (fixed-tilted or single-axis tracking), wind energy, H2tG-GtP and battery capacities based on an
hourly availability of the solar and wind resources to minimize the levelized cost of electricity (LCOE) and the cost
of produced hydrogen. Low cost batteries are added to harvest the excess electricity during overlap times to increase
the FLh whenever it is beneficial. The sample model is designed for a PtL system with specific 2 MW synthetic
fuels output. Then the system has been scaled up in each node (an area of 0.45ºx0.45º) with the optimal
configuration of components to reach the minimum cost, with a maximum area usage of 10% for PV and wind
power plants in each node.
The PtL plant (means H2tLplant) needs to operate on base load, thus CO2 and hydrogen storage are needed to
store extra hydrogen and CO2 production, which will be used during the shortage of RE. Applying this approach to
all regions in the world with a minimum of 6000 FLh for hybrid PV-Wind power plants and setting an upper
limitation of maximum 10% area use by both PV and wind power plants, the following global maps have been
generated. The same method has been applied by Fasihi et al. [10] for RE-PtG production, which can be used to
understand the configuration of the upstream value chain, such as the share of PV (fixed-tilted or single-axis
tracking) and wind and the corresponding FLh.
As mentioned before, the best combination of PV and wind power plants is required to minimize the cost of the
system. In addition to that, the electrolyser capacity will be optimized. This might result in some further curtailment
of electricity (excess electricity). The excess electricity, the levelized cost of net electricity used and the cost of
produced synthetic fuels are shown in Figure 13. Excess electricity is a function of the overlap of PV and wind FLh,
H2tL electricity demand, electrolyser capacity, application of batteries, and water desalination demand. Figure 13
shows that Patagonia, with less than 3%, has the lowest rate of excess electricity in the world. That means 97% of
the electricity produced by the hybrid PV-Wind plant is utilized by conversion into hydrogen in the electrolysers,
atmospheric CO2 capture or RWGS, which will result in a lower hydrogen production cost. Thus, it can be more
affordable than other sites with even higher FLh and lower LCOE of the hybrid system, but higher excess electricity.
In most other regions the excess electricity is in the range of 7-12%. The electricity loss, besides the loss in
transmission lines to the shore, increases the LCOE used in the PtL process. The LCOE used in the PtL plant is in
the range of 25 - 50 €/MWh, with the exception of West Tibet, which has LCOE of more than 60 €/MWh. This is
due to a very high rate of excess electricity in Tibet, which can be up to 30%. The most attractive regions in terms of
LCOE are located in Patagonia, Tibet and Somalia with LCOEs in the range of 20-30 €/MWh. Considering the
finally optimized combination of FLh, LCOE, excess electricity and power transmission loss, results in the least cost
for PtL production, which is the final objective. PtL production cost in Patagonia, Natal, Somalia, southern Tibet
and western part of Australia is the lowest, which is in the range of 70-90 €/MWhth,fuel. On the other hand, synthetic
fuels cost in western Tibet is in the range of 200-250 €/MWhth,fuel which is the highest in the world (see Fig. 13).
Mahdi Fasihi et al. / Energy Procedia 99 ( 2016 ) 243 – 268 261
Fig. 13. Levelised cost of synthetic fuels (top), Levelised cost of electricity (bottom, left) and excess electricity in percentage of
generation (bottom, right) for the cost year 2030.
Figure 14 illustrates the optimized installed capacities for different components of the system. As can be seen, the
amount of optimized hybrid PV-Wind plant installed capacity in most regions is less than 4 GW per node
(0.45ºx0.45º), with the exception of western Tibet and the Atacama Desert with very high potential of PV. Higher
PV capacities increase the capacity of the entire system, but for smaller FLh. Such an unbalanced production is not
suitable for electroyser plants. It would require a larger electrolysis plant operating for a smaller plant utilization,
which obviously increases the levelized cost of produced hydrogen.
The global optimal installed capacity of hybrid PV-Wind plants is about 10,060 GW, while Africa at 2980 GW
has the highest share. Europe, at 100 GW, stands for 1% of global capacity potential, while Oceania, at 1,430 GW,
has 14% share of global capacity potential.
At the same time, there are regions with a significant difference in the FLh of PV and wind energy. As an
example, the Atacama Desert in Chile has the highest PV FLh and the lowest wind FLh among all areas of at least
6000 FLh for the hybrid PV-Wind plant, both in the range of 3,000 hours. In this region the LCOE of PV is almost
half of the LCOE of wind energy [10]. This unique constraint results in an installation of PV to its’ maximum
possible capacity, which would be 18 GWel per node, which is almost 9 times larger than the commonly installed
capacity. This would result in a higher PtL capacity, up to 3.5 GW, which is approximately 7 times more than the
common PtL capacity of 0.7 GW. This is due to the least cost hydrogen storage, which can balance the system.
With respect to the optimal hybrid PV-Wind power plants’ capacity and the corresponding hydrogen production,
the optimal PtL installed capacity would be about 1960 GW globally (see Fig. 14). Although Africa, at about 2980
GW, has the highest capacity for optimal hybrid PV-Wind systems, South America has almost the same PtL
262 Mahdi Fasihi et al. / Energy Procedia 99 ( 2016 ) 243 – 268
optimized capacity (540 and 536 GW, respectively). This is due to the minimum excess electricity in South
America, shown in Figure 13. At 134 GW and 47 GW, considerable capacities of batteries are only installed in Asia
(mainly west Tibet) and South America (mainly the Atacama Desert), respectively, due to the high share of PV in
these regions.
Fig. 14. Optimal PtL installed capacity potential (top), optimal hybrid PV-Wind FLh installed capacity potential (bottom, left), and
optimal battery installed capacity potential (bottom, right) for the cost year 2030.
As discussed before, the H2tL plant works on a base load assumption, while the power supply is fluctuating
during the year. Thus hydrogen and carbon dioxide storage are used to supply the feedstock for the RWGS plant
during the whole year. In addition, the RWGS plant needs electricity on a base load. The results show that the
RWGS plant is in priority to the electrolyser plant to receive direct electricity. In the absolute lack of electricity,
batteries and gas turbines could be applied to cover this constant electricity demand. The gas for this process is
produced on a base load through a methanation (H2tG) plant, supplied by H2 and CO2 from H2 and CO2 storage
tanks. Figure 14 shows that batteries are not the main source of this electricity demand in most regions. Figure 15
illustrates that the methanation plant is installed globally to cover this demand, while batteries are only installed in
specific regions with a very high hybrid PV-wind installed capacity, due to a high installation of PV. The global
methanation capacity is approximately 7 GWgas, and it produces 61 TWh of SNG by operating on base load through
the year. Comparing methanation installed capacities (Fig. 15) with the corresponding PtL capacities (Fig. 14)
shows that Oceania has the minimum ratio of methanation to PtL capacity (0.00243). This means the times with
absolute lack of electricity production or a production less than the RWGS plant requires in Oceania is less than
anywhere else in the world, and for covering generation deficits for the RWGS plant only 180 FLh equivalent from
gas turbines are needed.
The graph at the bottom of Figure 15 shows the SNG level in a SNG storage tank for the whole year for a random
node. As mentioned, the production continues at a constant rate and the reductions in the SNG level represent the
Mahdi Fasihi et al. / Energy Procedia 99 ( 2016 ) 243 – 268 263
moments when the hybrid PV-Wind power plant’s electricity generation is less than RWGS consumption. An almost
4 MWhth,gas initial level of stored gas is needed in the tank to keep the system operating through the year, which is a
boundary condition of the model, since the storage levels at the start and end of the year needs to be equal.
Fig. 15. Optimal methanation installed capacity potential (top, left), optimal SNG generation potential (top, right), SNG level in gas
storage tank in a sample node (bottom) for the cost year 2030.
After PtL and H2tG hydrogen consumption, the surplus hydrogen needs to be stored in a tank for the hours of a
lack of hydrogen, to keep the system running. Figure 16 shows the optimal hydrogen storage capacity and the annual
amount of stored hydrogen. A maximum of about 1980 TWh capacity is installed globally, while at 540 TWh, Asia
needs the highest storage capacity in the world, while Africa and South America have the highest PtL plants’
capacity. This shows that there is a better match between hydrogen production and consumption rate on these two
continents. In total, 6830 TWh of hydrogen will be stored globally, which is 3.45 times the global capacity. That
means that the hydrogen tank mainly acts as a seasonal storage.
The graph in the bottom of Figure 16 shows the level of hydrogen in the storage tank in the same node as the one
in Figure 15. About 5% of the tank should be filled to keep the hydrogen level positive during the whole year. At
hour 8000, the hydrogen storage tank would be almost empty. This means there has been a shortage of electricity
and consequently hydrogen production prior to that. Figure 15 shows that electricity production during that time is
not even enough to cover the RWGS electricity demand, thus the gas turbine would start to generate electricity by
using available gas. This might be a good potential time for regular maintenance.
264 Mahdi Fasihi et al. / Energy Procedia 99 ( 2016 ) 243 – 268
Fig. 16. Optimal hydrogen storage capacity (top, left), optimal amount of stored hydrogen (top, right), and hydrogen level in storage tank
in a sample node (bottom) for the cost year 2030.
Figure 17 illustrates that the generation potential for PtL is almost half of the electricity generation. This includes
the electricity consumption in desalination, RWGS and CO2 capture plant, and efficiency losses in the electrolysis
and PtL plant and power transmission lines. The global annual optimal electricity and synthetic fuels production
potentials are about 33,240 TWhel and 16,970 TWhth,fuel, respectively. Almost the same amount of synthetic fuels
could be produced in South America (4700 TWhth,fuel) and Africa (4730 TWhth,fuel), while the hybrid PV-Wind
power plant generation in Africa (9250 TWhel) is slightly higher than the potential of South America (8910 TWhel).
Europe has the lowest electricity and synthetic fuels production potential. But with 56%, it has the highest electricity
to synthetic fuels conversion rate among all continents. With respect to global production numbers in the figure, the
average electricity to synthetic fuels conversion rate can be estimated to be about 51%, while Asia, at 49.2%, has the
lowest conversion rate. This is due to the significant excess electricity there, which also results is the highest battery
installation of 37 TWhel in Asia.
Mahdi Fasihi et al. / Energy Procedia 99 ( 2016 ) 243 – 268 265
Fig. 17. Optimal PtL annual generation potential (top), optimal hybrid PV-Wind annual generation potential (bottom, left), and optimal
battery annual generation potential (bottom, right) for the cost year 2030.
Most interesting is finally an industrial cost curve, i.e. the PtL production cost as a function of volume. Figure 18
presents the optimal annual PtL production volume sorted in order of the specific generation cost. The minimum PtL
production cost is 65 €/MWhth,fuel. A maximum of 16,000 TWhth synthetic fuels can be produced for costs less than
125 €/MWhth,fuel at sites with at least 6000 FLh for hybrid PV-Wind plants. For costs less than 90 €/MWhth,fuel,
production of 4,000 TWhth,fuel is achievable. A larger volume could be produced for costs in the range of 85 to 100
Fig. 18. PtL industrial cost curve for cost optimized PtL production based on hybrid PV-Wind power in a cumulative (left) and a spectral
(right) distribution for the cost year 2030.
266 Mahdi Fasihi et al. / Energy Procedia 99 ( 2016 ) 243 – 268
4. Discussion
There is no place for fossil fuels in a fully sustainable energy system, due to their emissions [52]. On the other
hand, a full substitution of hydrocarbons by renewable electricity is not possible, as electricity cannot be directly
used in some sectors such as aviation or heavy vehicles in all cases. Thus, renewable electricity based fuels are
essential to fulfill this demand. PtL plants can convert RE to RE-diesel and other fuels in a liquid phase. Modelling
an energy system without fossil fuels, the carbon source of this process cannot be from the flue gas of power plants
fired by fossil fuels. Moreover, on a global scale, the carbon source should be accessible wherever the renewable
power is available. To have a carbon neutral product, CO2 needed for this process should be captured from ambient
air, since biomass-based CCU options may be too limited, and water desalination should be applied whenever there
is a certain level of water stress in the region. Using AEC, all the technologies for this energy system, except
RWGS, already exist on a commercial scale and it can become operational whenever investors decide to go for it
[53]. However, the system cannot run if the final product is not cost competitive.
This study shows that, with about 135 USD per oil equivalent barrel, RE-diesel, produced in the RE-PtL chain,
costs more than conventional fossil diesel in today’s markets. There are different factors which can improve the
competitiveness of RE-diesel to conventional fossil diesel in the long term and not all of these factors are internal
issues related to this energy system.
xThe crude oil price is the very first factor. The long-term change in the crude oil price is a function of
production cost, production and consumption rate, reserves and political issues. On the other hand, in the
short term and as long as production cost of RE-diesel is higher than the production cost of conventional
fossil diesel, RE-diesel can be kept away from the market if the crude oil price is set less than RE-diesel
production cost. But in the long term, when the crude oil reserves are not sufficient to cover the demand,
then the market is likely to follow the RE-diesel production cost.
xEnvironmental concerns and fuel quality will put additional costs on the conventional fossil diesel price.
CO2 emission cost has been already set in some countries. Moreover, the standards for fuel quality may rise
to a limit at which conventional diesel cannot be produced at that quality anymore. In that case, carbon-
neutral and sulphur-free RE-diesel can be considered as one of the main substitutions, also for a production
cost 50-100% higher than conventional fossil diesel.
xThe by-products of the RE-PtL value chain can play a significant role in some regional cases, if not
globally. A RE-PtL plant located in a region with a high demand for oxygen can decrease the production
cost of diesel by about 20%. Thus, this system can still run for some special cases, if not globally.
xThe other regional effect would be the risk of investment. The impact of de-risking measures have been
found to be of high relevance for the economics, since reduced risks which could decrease the WACC from
7% to 5% would reduce the production cost throughout the entire value chain by about 14.5%.
xThe released heat in the FT process can be used in a CO2 capture plant or high temperature SOEC. The CO2
capture plant may be in priority as long as no other heat source is available for that.
5. Conclusion
External factors can have a strong impact on the competitiveness of the RE-PtL system and in a beneficial
combination they can reduce the cost of RE-diesel from the aforementioned 135 USD per oil equivalent barrel to
about 79 USD, which had been a crude oil price level for already some years in the recent past [54]. These results
have a significant impact on the discussions of the energy transformation towards sustainability ahead. If not
concurring with the market, the hybrid PV-Wind-PtL system could set an upper limit for fossil fuel prices, globally.
Mahdi Fasihi et al. / Energy Procedia 99 ( 2016 ) 243 – 268 267
It would also further increase the demand for solar PV systems, wind turbines, water electrolysers, RWGS plants
and CO2 capture plants. The additional market for solar PV and wind energy can be estimated to be in the terawatt
scale. This potentially huge market itself would further reduce production costs and increase research and
development investments in the field for more efficient technologies.
The authors gratefully acknowledge the public financing of Tekes, the Finnish Funding Agency for Innovation,
for the ‘Neo-Carbon Energy’ project under the number 40101/14. The first author thanks the Gas Fund for the
valuable scholarship. We also thank Michael Child for proofreading.
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... 2 Consideration of e-fuels and e-chemicals in highly renewable energy transition scenarios As discussed in Khalili and Breyer (2022), studies that focused on energy system analyses with high RE shares of over 95% in at least one of the major energy sectors are reviewed for the role of renewable electricity based e-fuels and e-chemicals. The focus was, in particular, on CO 2 -to-X conversion for e-methane (Blanco and Faaij, 2018;Sterner, 2009), e-kerosene jet fuel (Drünert et al., 2020;Fasihi et al., 2016), and e-methanol Lonis et al., 2021) in 100% RE systems. The non-hydrocarbon e-fuel, hydrogen Quarton et al., 2019) and the e-chemical, e-ammonia (Fasihi et al., 2021;Osman et al., 2020) are further discussed. ...
... J o u r n a l P r e -p r o o f Table 5. Electricity demand for e-fuels and e-chemicals (Fasihi et al., 2021(Fasihi et al., , 2016 (Table S1). Total demand for all fuels and chemicals (fossil, bio, electro) during the same period can be found in the Supplementary Material (Table S2). Figure 3. ...
... Our results have shown that sub-Saharan Africa in particular experiences strong growth in supply of CO 2 from cement mills that account for almost half of CO 2 from sustainable or unavoidable point sources in 2050, thus potentially turning the region into one of the major exporters of e-fuels and e-chemicals. However, despite potential reduction in costs of producing e-fuels and e-chemicals enabled by CO 2 availability from point sources, the same may not be true for other regions, as other studies have shown that cost of producing e-fuels and e-chemicals may vary significantly from one region to another as part of comprehensive energy system analyses (Bogdanov et al., 2021b), or the production of e-ammonia (Fasihi et al., 2021), e-FTL (Fasihi et al., 2016), e-methanol , and hydrogen . Europe and Eurasia may not become major exporters due to higher production costs, whereas in South America and parts of the MENA region costs are extremely low driven by low-cost wind energy and solar PV . ...
Defossilisation of the current fossil fuels dominated global energy system is one of the key goals in the upcoming decades to mitigate climate change. Sharp reduction in the costs of solar photovoltaics, wind power, and battery technologies enables a rapid transition of the power and some segments of the transport sectors to sustainable energy resources. However, renewable electricity-based fuels and chemicals are required for the defossilisation of hard-to-abate segments of transport and industry. The global demand for carbon dioxide as raw material for the production of e-fuels and e-chemicals during a global energy transition to 100% renewable energy is analysed in this research. Carbon dioxide capture and utilisation potentials from key industrial point sources, including cement mills, pulp and paper mills, and waste incinerators, are evaluated. According to this study's estimates, the demand for carbon dioxide increases from 0.6 in 2030 to 6.1 gigatonnes in 2050. Key industrial point sources can potentially supply 2.1 gigatonnes of carbon dioxide and thus meet the majority of the demand in the 2030s. By 2050, however, direct air capture is expected to supply the majority of the demand, contributing 3.8 gigatonnes of carbon dioxide annually. Sustainable and unavoidable industrial point sources and direct air capture are vital technologies which may help the world to achieve ambitious climate goals.
... A promising opportunity for developing multi-energy systems (MES) [1,2] with a holistic approach [3] is integrating electricity, gas, transportation and/or industrial sectors with power-to-X (P2X) technologies [4]. Among these, power-to-hydrogen (P2H) for green hydrogen production is already well-known and thoroughly discussed in the literature [5,6], and its further extensions towards developing power-to-methane (P2M) [7,8], power-to-liquid (P2L) [9,10] or even carbon capture, utilization or storage (CCUS) [11,12] value chains have been explored. From the aspect of power grid operators, these processes could relieve the burden of grid-balancing and maintenance if they convert renewable electricity into other energy carriers [13]. ...
... For example, P2M technologies convert H2 and CO2 into CH4 by biological or thermochemical processes [11], which leads to the opportunity of coupling electricity and natural gas sectors and long-term (seasonal) energy storage [30]. In contrast, P2L technologies focus on the production of diesel, kerosene or other liquid hydrocarbons by adapting Fischer-Tropsch or methanol synthesis processes [9], occasionally with high-temperature solid-oxide electrolysis (SOEC) or reversed water gas shift (RWGS) reaction to produce CO from CO2 [34]. The need for carbon dioxide links P2G directly to decarbonization; thus, the integration with CCU technologies has been recently proposed. ...
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As renewable electricity integration generates grid-balancing challenges for network operators, new ways of grid resilience receive significant attention from the energy research community. Power-to-gas (P2G) applications could produce and use green hydrogen. Thus, they enable the integration of more renewable energy into the energy system. Meanwhile, Internet-of-things (IoT) solutions could optimize renewable energy applications in decentralized systems. Despite the strategic importance of both technologies in renewable-rich grid developments, opportunities for P2G advancements based on IoT and related solutions have not come to the forefront of renewable energy research. To fill in this research gap, this study presents a hybrid (thematic and critical) systematic literature review to explore how strategic co-specialization opportunities appear in recent publications. Findings suggest that P2G and IoT could be fundamentally linked within the proposed frameworks of multi-energy systems and energy internet, but further empirical research is needed regarding their operative and strategic integration (e.g., cost reduction, risk management and policy incentives).
... Although solar-wind hybrids enable an uninterrupted power supply even at the wind and solar peak hours, several setbacks make developers and researchers question the feasibility of the market for specific large-scale applications [28]. Figure 9 shows a heatmap describing the world's PV-wind hybrid power plant on full load hours [29]. the feasibility of the market for specific large-scale applications [28]. ...
... the feasibility of the market for specific large-scale applications [28]. Figure 9 shows a heatmap describing the world's PV-wind hybrid power plant on full load hours [29]. Figure 9. Heatmap describing the global PV and wind power full load hours [30]. ...
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Solar and wind power systems have been prime solutions to the challenges centered on reliable power supply, sustainability, and energy costs for several years. However, there are still various challenges in these renewable industries, especially regarding limited peak periods. Solar–wind hybrid technology introduced to mitigate these setbacks has significant drawbacks and suffers from low adoption rates in many geographies. Hence, it is essential to investigate the challenges faced with these technologies and analyze the viable solutions proposed. This work examined solar–wind hybrid plants’ economic and technical opportunities and challenges. In the present work, the pressing challenges solar–wind hybrids face were detailed through extensive case studies, the case study of enabling policies in India, and overproduction in Germany. Presently, the principal challenges of solar–wind hybrids are overproduction, enabling policies, and electricity storage. This review highlights specific, viable, proposed solutions to these problems. As already recorded in the literature, it was discovered that academic research in this space focuses majorly on the techno-economic and seemingly theoretical aspects of these hybrid systems. In contrast, reports and publications from original equipment manufacturers (OEMs) and engineering, procurement, and construction engineers (EPCs) are more rounded, featuring real-life application and implementation.
... In addition, the rate of improvements in building renovation rates increase efficiency across applications and drive down the primary energy further. Lastly, the rate of adoption of synthetic fuels that are primarily based on renewable electricity 43 . The development of primary energy consumption 11 across the three scenarios, from an energy carrier perspective is shown in Figure 5. 11 Primary energy consumption does not include ambient heat from heat pumps and geothermal technologies. ...
Technical Report
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While the detrimental impacts of climate change are unraveling around the world, a geopolitical crisis at the heart of Europe has brought to the forefront another dimension to the complexities of the energy transition. Energy security and energy independence have preceded to shape future energy decisions, not only in Europe but across the world. Europe has been at the forefront in driving the transition towards sustainable energy adoption as well as enhancing climate mitigation. The energy transition towards higher shares of renewable energy is already well underway in many European countries, particularly in the power sector. The European Commission has envisaged a long-term climate neutrality vision with the European Green Deal. However, compounding crises including the Russian invasion of Ukraine have accentuated the cost to the European economy that is coupled with a centralised energy system highly dependent on imported fossil fuels. In this context, accelerating the energy transition across the European Union (EU) is essential for enhancing energy security, ensuring long-term price stability and mitigating climate change. Amidst the current gloom and doom, there is a long-term opportunity for Europe to emerge as a global leader with an accelerated transition towards a highly efficient energy system based on 100% renewables, which will enable a range of benefits, not only for its economy but also for other economies around the world.
... Additionally, we assume that electrolysis runs at 5,000 full-load hours, equivalent to a capacity factor of 57%. Such full-load hours could be realized, for example, by hybrid solar-wind power plants in several world regions 62 . Furthermore, this assumption is in harmony with the range of 3,000-6,000 full-load hours regarded as cost-minimizing using grid electricity 61 . ...
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Green hydrogen and derived electrofuels are attractive replacements for fossil fuels in applications where direct electrification is infeasible. While this makes them crucial for climate neutrality, rapidly scaling up supply is critical and challenging. Here we show that even if electrolysis capacity grows as fast as wind and solar power have done, green hydrogen supply will remain scarce in the short term and uncertain in the long term. Despite initial exponential growth, green hydrogen likely (≥75%) supplies <1% of final energy until 2030 in the European Union and 2035 globally. By 2040, a breakthrough to higher shares is more likely, but large uncertainties prevail with an interquartile range of 3.2–11.2% (EU) and 0.7–3.3% (globally). Both short-term scarcity and long-term uncertainty impede investment in hydrogen end uses and infrastructure, reducing green hydrogen’s potential and jeopardizing climate targets. However, historic analogues suggest that emergency-like policy measures could foster substantially higher growth rates, expediting the breakthrough and increasing the likelihood of future hydrogen availability.
... To perform the process, it is needed a continuous feedstock of syngas and CO 2 (Grim et al., 2019). The production of e-fuels generated by renewable sources in regions with high Flh of wind -as is the case of the ROI-, would decrease the associated economic costs and GHGs emissions (Fasihi et al., 2016;Soler, 2019). Efuels could play a vital role in establishing an artificial carbon cycle however, the high cost to produce them at the moment remains an obstacle. ...
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Global temperature will surpass the threshold of 1.5 • C in the next decade. The implementation and the development of modern technologies, such as Direct Air Capture (DAC) will play a key role in mitigating climate change. The article exhibits the most updated information to emphasise the importance of expanding its commercialisation and social acceptance in the Republic of Ireland. This literature review provides background on the energy demand and the emissions related to the consumption across the country. The study highlights the methods to remove permanently the CO 2 from the atmosphere and its uses for sectors that find difficulties to decarbonise. The Republic of Ireland set an ambitious plan to finish its dependence on fossil fuels. Yet, its emissions will remain constant regardless of the measures taken. Thus, there is a strong reliance on fossil fuels from specific sectors that will keep polluting in the near future. Certain countries and business are funding projects to remove the CO 2 from the atmosphere. Meanwhile, the Republic of Ireland is putting aside these alternatives. The time scheduled to switch towards a free carbon economy is tight. Hence, could the Republic of Ireland meet its climate goals without DAC? Overall, we conclude that there are numerous gaps to fill only with renewables and ignoring alternatives such as DAC can be counterproductive. Therefore, the information provided aims to assess the current state of the technology, as well as show the benefits of investing in DAC. Future studies should focus on the viability of implementing DAC in the Republic of Ireland.
... 15 Liu et al. studied the environmental implications of using direct air capture CO 2 in FT e-fuel, finding that its climate change impact was way below that of fossil diesel considering its final combustion (28−12 g CO 2 -eq/MJ e-fuel vs 104 g CO 2 -eq/MJ diesel). 16 Finally, the synthesis of FT e-diesel from direct aircaptured CO 2 and a hybrid wind/solar electricity fueled alkaline electrolyzer (AEC) for H 2 production was studied by Fasihi et al., 11 who by considering O 2 valorization, managed to reach production costs as low as 0.69 €/L of e-diesel. ...
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Electro-fuels are seen as a promising alternative to curb carbon emissions in the transport sector due to their appealing properties, similar to those of their fossil counterparts, allowing them to use current infrastructure and state-of-the-art automotive technologies. However, their broad implications beyond climate change remain unclear as previous studies mainly focused on analyzing their carbon footprint. To fill this gap, here, we evaluated the environmental and economic impact of Fischer-Tropsch electro-diesel (FT e-diesel) synthesized from electrolytic H2 and captured CO2. We consider various power (wind, solar, nuclear, or the current mix) and carbon sources (capture from the air (DAC) or a coal power plant) while covering a range of impacts on human health, ecosystems, and resources. Applying process simulation and life cycle assessment (LCA), we found that producing e-diesel from wind and nuclear H2 combined with DAC CO2 could reduce the carbon footprint relative to fossil diesel, leading to burden-shifting in human health and ecosystems. Also, it would incur prohibitive costs, even when considering externalities (i.e., indirect costs of environmental impacts). Overall, this work highlights the need to embrace environmental impacts beyond climate change in the analysis of alternative fuels and raises concerns about the environmental appeal of electro-fuels.
Technical Report
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In 2019, the commercial aviation sector produced approximately 2.5% of total global anthropogenic CO2 emissions. Sectoral demand for commercial aviation is expected to at least double by 2050 compared to 2019, leading – if there are no adjustments to the fuel mix – to increasing CO2 emissions. The main aim of this work is to quantify the volumes, cost, area demand and potential renewable energy competition in the United States and the EU-27 for synthetic kerosene jet fuel produced from renewable electricity-based hydrogen (e-kerosene) and CO2 from direct air capture (DAC-kerosene). E-kerosene is a low-lifecycle CO2 emission alternative to fossil-based kerosene jet fuel. We carry out a cost-optimised scenario analysis with the main boundary condition of a net-zero energy system in 2050.
Europe and North America have numerous studies on 100% renewable power systems. South America, however, lacks research on zero-carbon energy systems, especially understanding South America as an interconnected region, despite its great renewable energy sources, increasing population, and economic productivity. This work extends the cost-optimization energy planning model LEELO and applies it to South America. This results in the to-date most complete model for planning South America’s power sector, with a high temporal (8760 time steps per year) and spatial (over 40 nodes) resolution, and 30 technologies involved. Besides the base case, we study how varying spatial resolution for South America impacted investment results (43, 30, 16, 1 node). Finally, we also evaluate green hydrogen export scenarios, from 0% to 20% on top of the electricity demand. Our study reveals that South America’s energy transition will rely, in decreasing order, on solar photovoltaic, wind, gas as bridging technology, and also on some concentrated solar power. Storage technologies equal to about 10% of the total installed power capacity would be required, aided by the existing hydropower fleet. Not only is the transition to renewables technically possible, but it is also the most cost-efficient solution: electricity costs are expected to reach 32 €/MWh from the year 2035 onwards without the need for further fossil fuels. Varying the spatial resolution, the most-resolved model (43 nodes) reveals 11% and 6% more costs than the one-node and one-node-per-country (16) models, respectively, with large differences in investment recommendations, especially in concentrated solar and wind power. The difference between 43 and 30 nodes is negligible in terms of total costs, energy storage, and technology mix, indicating that 30 nodes are an adequate resolution for this region. We then use the 30-node model to analyze hydrogen export scenarios. The electricity costs drop, as hydrogen is not only a load but also a flexibility provider. Most green hydrogen is produced in Chile, Argentina, and northeast Brazil. For future work, we propose to do an integrated energy plan, including transport and heat, for the region, as well as modeling local hydrogen demands. This work aims to inform policymakers of sustainable transitions, and the energy community.
Large energy companies and energy startups are increasingly focusing their resources to build new businesses concerning smart energy systems (SES). The development and integration of related innovative technologies for green transformation with traditional business models are often hampered, however, by the challenge of parallel management of exploitation of current business areas, and the exploration of new business areas with breakthrough innovation. While knowledge management could be key in this balancing strategy and shifting the organization to a more sustainable future, little is known about the challenges in the context of the energy sector. Applying a comparative case study method at a large energy company and a small energy startup, path dependency is reflected in KMS design in both cases, which could result in a slower shift to new technologies in case of the incumbent, and slower exploitation of the technological innovation in case of the startup. If a partnership is not an option for simulating structural ambidexterity, energy companies could speed up green transformation individually with smart knowledge management systems (SKMS) that support the development of contextual ambidexterity and SES.
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Poster on the occasion of the 4th Conference on Carbon Dioxide as Feedstock for Fuels, Chemistry and Polymers in Essen, Germany, on September 29 - 30, 2015.
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The Power-to-Gas (PtG) process chain could play a significant role in the future energy system. Renewable electric energy can be transformed into storable methane via electrolysis and subsequent methanation. This article compares the available electrolysis and methanation technologies with respect to the stringent requirements of the PtG chain such as low CAPEX, high efficiency, and high flexibility. Three water electrolysis technologies are considered: alkaline electrolysis, PEM electrolysis, and solid oxide electrolysis. Alkaline electrolysis is currently the cheapest technology; however, in the future PEM electrolysis could be better suited for the PtG process chain. Solid oxide electrolysis could also be an option in future, especially if heat sources are available. Several different reactor concepts can be used for the methanation reaction. For catalytic methanation, typically fixed-bed reactors are used; however, novel reactor concepts such as three-phase methanation and micro reactors are currently under development. Another approach is the biochemical conversion. The bioprocess takes place in aqueous solutions and close to ambient temperatures. Finally, the whole process chain is discussed. Critical aspects of the PtG process are the availability of CO2 sources, the dynamic behaviour of the individual process steps, and especially the economics as well as the efficiency.
This study demonstrates how seawater reverse osmosis (SWRO) plants, necessary to meet increasing future global water demand, can be powered solely through renewable energy. Hybrid PV–wind–battery and power-to-gas (PtG) power plants allow for optimal utilisation of the installed desalination capacity, resulting in water production costs competitive with that of existing fossil fuel powered SWRO plants. In this paper, we provide a global estimate of the water production cost for the 2030 desalination demand with renewable electricity generation costs for 2030 for an optimised local system configuration based on an hourly temporal and 0.45° × 0.45° spatial resolution. The SWRO desalination capacity required to meet the 2030 global water demand is estimated to about 2374 million m3/day. The levelised cost of water (LCOW), which includes water production, electricity, water transportation and water storage costs, for regions of desalination demand in 2030, is found to lie between 0.59 €/m3–2.81 €/m3, depending on renewable resource availability and cost of water transport to demand sites. The global system required to meet the 2030 global water demand is estimated to cost 9790 billion € of initial investments. It is possible to overcome the water supply limitations in a sustainable and financially competitive way.
Conference Paper
With growing demand for transportation fuels such as diesel and concerns about climate change, this paper introduces a new value chain design for transportation fuels and a respective business case taking into account hybrid PV-Wind power plants. The value chain is based on renewable electricity (RE) converted by power-togas (PtG) facilities into synthetic natural gas (SNG), which is finally converted to mainly diesel in gas-to-liquid (GtL) facilities. This RE-diesel can be shipped to everywhere in the world. The calculations for the hybrid PV-Wind power plants, electrolysis and methanation are done based on annual full load hours (FLh). A combination of 5 GWp single-axis tracking PV and wind power have been applied. Results show that the proposed RE-diesel value chain is competitive for crude oil prices within a minimum price range of about 121-191 USD/barrel (0.67 – 1.06 €/l of diesel production cost), depending on assumptions for cost of capital, available oxygen sales and CO2 emission costs. RE-diesel is competitive with conventional diesel from an economic perspective, while removing environmental concerns. The cost range would be an upper limit for the conventional diesel price in the long-term and RE-diesel can become competitive whenever the fossil fuel prices are higher than the level mentioned and the cost assumptions expected for the year 2030 are achieved. A sensitivity analysis indicates that the RE-PtG-GtL value chain needs to be located at the best complemented solar and wind sites in the world combined with a de-risking strategy and a special focus on mid to long term electrolyzer efficiency improvements. The substitution of fossil fuels by hybrid PV-Wind power plants could create a PV-wind market potential in the order of terawatts.
High temperature electrolysis of carbon dioxide, or co-electrolysis of carbon dioxide and steam, has a great potential for carbon dioxide utilisation. A solid oxide electrolysis cell (SOEC), operating between 500 and 900. °C, is used to reduce carbon dioxide to carbon monoxide. If steam is also input to the cell then hydrogen is produced giving syngas. This syngas can then be further reacted to form hydrocarbon fuels and chemicals. Operating at high temperature gives much higher efficiencies than can be achieved with low temperature electrolysis. Current state of the art SOECs utilise a dense electrolyte, commonly yttria-stabilised-zirconia (YSZ), with porous fuel and oxygen side electrodes. The electrodes must be both electron and oxide ion conducting, and maximising the active surface area is essential for efficient operation. For the fuel electrode a cermet of nickel and YSZ is often used, whereas a lanthanum strontium manganite - YSZ mix is utilised for the oxygen electrode. Long term durability and performance are key for commercialisation of SOEC technology. To date, experimental tests of 1000. h on electrolysis stacks operated at low current density have shown little or no degradation when inlet gas cleaning is employed; however, operation at higher current density leads to cell degradation, which still needs to be overcome. Advances in materials and morphology are needed to further decrease cell degradation.
The aim of this chapter is to provide an overview of polymer electrolyte membrane (PEM) water electrolysis, from basic principles to technological developments. After a general introduction on water electrolysis based on some general considerations, thermodynamics of the water-splitting reaction are analyzed in Section 9.2, highlighting the effects of operating temperature and pressure on electrolysis voltages. In Section 9.3, general principles of PEM water electrolysis are introduced. The structure of PEM water electrolyzers (from materials to membrane–electrode assemblies, PEM cells, stacks, and balance of plant) is described. Individual cell components are presented. Conventional and some alternative designs are also described. In Section 9.4, advantages and disadvantages of PEM water electrolysis technology are compared with those of other water electrolysis technologies. Finally, in the last section, the potential of PEM water electrolysis technology to reach higher performance (operating current density, efficiency, and operating pressure) is evaluated and some future development trends are discussed.
Power-to-gas (PtG) technology has received considerable attention in recent years. However, it has been rather difficult to find profitable business models and niche markets so far. PtG systems can be applied in a broad variety of input and output conditions, mainly determined by prices for electricity, hydrogen, oxygen, heat, natural gas, bio-methane, fossil CO2 emissions, bio-CO2 and grid services, but also full load hours and industrial scaling. Optimized business models are based on an integrated value chain approach for a most beneficial combination of input and output parameters. The financial success is evaluated by a standard annualized profit and loss calculation and a subsequent return on equity consideration. Two cases of PtG integration into an existing pulp mill as well as a nearby bio-diesel plant are taken into account. Commercially available PtG technology is found to be profitable in case of a flexible operation mode offering electricity grid services. Next generation technology, available at the end of the 2010s, in combination with renewables certificates for the transportation sector could generate a return on equity of up to 100% for optimized conditions in an integrated value chain approach. This outstanding high profitability clearly indicates the potential for major PtG markets to be developed rather in the transportation sector and chemical industry than in the electricity sector as seasonal storage option as often proposed.
A review on the status of gas-to-liquids (GTL) industry covers global commercialization activities, e.g., the Shell Middle Distillate plant in Bintulu that converts natural gas into high-quality synthetic oil products and specialty chemicals, Sasol's coal-derived synthesis gas, and Sasol and Qatar Petroleum's plans to build a GTL plant in Ras Laffan Industrial City, Qatar, to convert 330 million scf/day into 24,000 bpd fuel, 9000 bpd naphtha, and 1000 bpd LPG; the technologies that are likely to be implemented in future projects, e.g., advanced gas-conversion technology Fischer-Tropsch (FT) hydrocarbon synthesis process, Shell's use of a tubular fixed bed reactor containing a proprietary Co-based catalyst with mild recycle, and Syntroleum's proprietary highly active Co-based FT catalysts to convert synthesis gas from a proprietary air-fed autothermal reactor; manufactured GTL products (35,000 bpd) from commercial gas-based plants; GTL as a significant alternative for monetizing natural gas in the 21st century; GTL drivers and definition; GTL products, e.g., premium fuels, petrochemical naphtha, waxes, and lubricant basestocks , which are all sulfur-free; and economics for GTL projects.