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Economics of Global LNG Trading Based on Hybrid PV-Wind Power Plants

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With growing demand for liquefied natural gas (LNG) and concerns about climate change, this paper introduces a new value chain design for LNG 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 liquefied into LNG. This RE-LNG can be shipped everywhere in the world. The calculations for hybrid PV-Wind power plants, electrolysis and methanation are done based on both annual and hourly full load hours (FLh). To reach the minimum cost, the optimized combination of fixed-tilted and single-axis tracking PV, wind power, and battery capacities have been applied. Results show that the proposed RE-LNG value chain is competitive for Brent crude oil prices within a minimum price range of 87-145 USD/barrel, depending on assumptions for cost of capital, available oxygen sales and CO2 emission costs. RE-LNG is competitive with fossil LNG from an economic perspective, while removing environmental concerns. This range would be an upper limit for the fossil LNG price in the long-term and RE-LNG can become competitive whenever the fossil prices are higher than the level mentioned and the cost assumptions expected for the year 2030 are achieved. The substitution of fossil fuels by hybrid PV-Wind power plants could create a PV-wind market potential in the order of 9.5 terawatts.
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Economics of Global LNG Trading Based on Hybrid PV-Wind Power Plants
Mahdi Fasihi, Dmitrii Bogdanov and Christian Breyer
Lappeenranta University of Technology, Skinnarilankatu 34, 53850 Lappeenranta, Finland
E-mails: mahdi.fasihi@lut.fi, dmitrii.bogdanov@lut.fi, christian.breyer@lut.fi
ABSTRACT: With growing demand for liquefied natural gas (LNG) and concerns about climate change, this paper
introduces a new value chain design for LNG 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-to-gas (PtG) facilities into synthetic
natural gas (SNG), which is finally liquefied into LNG. This RE-LNG can be shipped everywhere in the world. The
calculations for hybrid PV-Wind power plants, electrolysis and methanation are done based on both annual and hourly full
load hours (FLh). To reach the minimum cost, the optimized combination of fixed-tilted and single-axis tracking PV, wind
power, and battery capacities have been applied. Results show that the proposed RE-LNG value chain is competitive for
Brent crude oil prices within a minimum price range of 87 - 145 USD/barrel, depending on assumptions for cost of capital,
available oxygen sales and CO2 emission costs. RE-LNG is competitive with fossil LNG from an economic perspective,
while removing environmental concerns. This range would be an upper limit for the fossil LNG price in the long-term and
RE-LNG can become competitive whenever the fossil prices are higher than the level mentioned and the cost assumptions
expected for the year 2030 are achieved. The substitution of fossil fuels by hybrid PV-Wind power plants could create a
PV-wind market potential in the order of 9.5 terawatts.
Keywords: Hybrid PV-Wind, Power-to-gas, SNG, LNG, Economics, business model, Argentina, Japan
1 INTRODUCTION
The demand for liquefied natural gas (LNG) is high in
the world and is growing [1]. By 2030, LNG will have the
same share as pipeline-based gas in gas consumption
globally, which is expected to reach 8600 TWhth,gas [2].
But fossil fuel resources are limited and it is not yet known
how much affordable natural gas (NG) will be available
for LNG in the long-term [3]. On the other hand, the planet
is facing a dramatic climate change problem [4]. Thus,
even with adequate reserves of fossil fuels, CO2 emissions
still would be a limiting constraint in the mid- to long-term,
in particular since it is already known that CO2 emissions
should be very close to zero by the middle of this century.
An increasing number of concerned investors are already
starting to put fossil activities on their sell list, due to the
CO2 emissions limitations and to avoid stranded assets in
their long-term investments [5, 6]. An economic substitute
for fossil LNG is required in order to use the existing
downstream LNG infrastructure in a sustainable energy
system. NG contains approximately 95% methane, and
methanation plants converting renewable electricity (RE)
into SNG already exist with power-to-gas (PtG)
technology on a commercial scale [7-11].
By using RE in these PtG plants, fossil-CO2 free
synthetic natural gas (SNG) and LNG can be produced to
overcome the constraints of resource limitation and CO2
emissions in the LNG value chain. Figure 1 shows the
simplified value chain of the whole process. The main
components are: hybrid PV-Wind plants, electrolyser and
methanation plants, CO2 from air scrubbing units,
liquefaction to LNG, LNG shipping, and regasification.
The integrated system introduces some potentials for
utilization of waste energy and by-products. This will also
result in the elimination of some sub-components of the
major components of the integrated system, which will
increase the overall efficiency and will decrease the costs.
The paper is structured in a methodology section,
results for an annual basis model and an hourly basis
model, and a conclusion.
Figure 1: The PtG-LNG value chain. The main components are: hybrid PV-Wind plants, electrolyser and methanation plants,
CO2 from air scrubbing units, liquefaction to LNG, LNG shipping and regasification.
2 METHODOLOGY
The RE-LNG system has been divided into two main
parts, RE-based SNG production and the LNG
downstream value chain. There are two models for SNG
production, annual and hourly basis.
The Annual Basis Model presents a hybrid PV-Wind
power plant with 5 GW capacity for both single-axis
tracking PV and Wind 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 in the system and the produced electricity and
respective calculations are based on annual full load hours
(FLh) of the hybrid PV-Wind plants, which can be seen in
Table I. The estimate on an hourly FLh basis is
surprisingly accurate if applied carefully [12, 13]. The
annual basis plants specification can be seen in Table II.
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
hybrid PV-Wind plants, a conservative estimate is 5%
[14]. This model will give a rough estimation of a system
working with equal PV and wind power capacity.
The Hourly Basis Model uses the best 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 cost of SNG. Low cost batteries are
added to harvest the excess electricity during overlap times
to increase the FLh whenever it is beneficial.
The full LNG value chain is only analyzed in the
annual basis model because with storage for output SNG,
the liquefaction plant can work at baseload conditions,
which is the cost optimal solution.
The equations below have been used to calculate the
LCOE of Hybrid PV-Wind power plants and the
subsequent value chain. Abbreviations: capital
expenditures, capex, operational expenditures, opex, full
load hours, FLh, fuel costs, fuel, efficiency, η, annuity
factor, crf, weighted average cost of capital, WACC,
lifetime, N, performance ration, PR, overlap FLh, overlap.


  
(Eq. 1)
 
 (Eq. 2)
 
  (Eq. 3)
 

 (Eq. 4)
 
 (Eq. 5)
2.1 Power-to-SNG
2.1.1 Hybrid PV-Wind power plant and battery
In this research, hybrid PV-Wind power plants are
taken into account as the resources 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 and methanation. Figure 2 shows the FLh for
the best sites in the world. In this study, the plant is located
in Patagonia, Argentina, which is among the best places in
the world for solar and wind resources. The demand is
assumed to be in Japan.
Figure 2: World’s hybrid PV-Wind FLh map. The
numbers refer to the place of RE-LNG production (1) and
LNG demand (2).
Table I: Hybrid PV-Wind power plants specification.
Abbreviations: capital expenditures, capex, and
operational expenditures, opex.
Unit Amount
PV fixed-tilted
Capex €/kWp 500
Opex % of capex per annum 1.5
Lifetime years 35
PV single-axis
Capex €/kWp 550
Opex % of capex per annum 1.5
Lifetime years 35
Wind energy
Capex €/kW 1000
Opex % of capex per annum 2
Lifetime years 25
Battery
Capex €/kWhel 150
Opex % of capex per annum 6
Lifetime years 10
Cycle efficiency % 90
Table II: Hybrid PV-Wind power plants specification for
annual analysis scenario
Unit Amount
PV irradiation (1-axis) kWh/(m2a) 2410
PV performance ratio (PR) % 83
PV yield kWh/kWp 2000
Installed capacities
PV 1-axis installed capacity GWp 5
Wind installed capacity GW 5
PV single-axis FLh h 2000
Wind FLh h 5200
PV and Wind overlap % 5
Hybrid PV-Wind FLh h 6840
2.1.2 Electrolysis and methanation
SNG production consists of two main steps, hydrogen
production (eq. 6) and methanation (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.
Generated H2 and CO2 from a CO2 capture plant are used
in the exothermic process of methanation based on a
Sabatier reaction to produce SNG [15-17].
Figure 3: Power-to-Gas (electrolysis and methanation)
process.
Electrolysis:        (6)
Methanation:        (7)
The alkaline electrolysis cell (AEC) is the well-known
and mature technology for water electrolysis [18], while
the proton exchange membrane electrolysis cell (PEMEC)
[18, 19] and solid oxide electrolysis cell (SOEC) [18, 20]
are the other technologies still under development.
PEMEC has slightly better efficiency and shorter start up
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 will offer the chance to replace a part of the
electricity needed for the reaction with heat. And the
produced hydrogen will be at high pressure, which will
decrease the energy and cost of compressing hydrogen for
the methanation process. But the startup time of SOEC is
higher than AEC and PEMEC. The reported costs for
PEMEC and SOEC are higher and in a wider range than
those for AEC in 2030 (Tab. III). In addition, there are
more uncertainties about the achievement of techno-
economic targets for 2030. On the other hand, in the
current RE-LNG system set-up the entire waste energy in
our system is already utilized for CO2 capturing from the
ambient air, thus there is no more excess heat to be used in
SOEC. Therefore, alkaline high pressure electrolysis has
been used in our model. Moreover, the lower capex for
AEC is very important in achieving optimized SNG cost.
Table III: Electrolyzers specification [21-26].
Abbreviations: electricity-to-hydrogen, EtH2, efficiency,
eff.
Unit
AEC
PEMEC
SOEC
Capex
€/kWel
319
250-1270
625-1000
Opex
% of capex
per annum
3
2-5
2-5
Lifetime
years
30
20
20
EtH2 eff.
%
86.3
74-89
91-109
Heat demand
% of inlet E
-
-
18-20
The Sabatier reaction is applied in the methanation
process and the methanation plant’s specification can be
seen in Table IV.
Table IV: Methanation process specification
Unit Amount
Capex €/kWH2 215
Opex % of capex per annum 3
Lifetime years 30
H2-to-SNG eff. (HHV) % 77.9
H2-to-Heat eff. (HHV) % 14
2.1.3 CO2 scrubber
CO2 can be supplied from different sources such as
large power plants, or ambient air. To have a sustainable
energy system with carbon neutral products, CO2 can be
from a sustainable CO2 source such as a biomass plant with
carbon capture and utilization (CCU) or it can be captured
from air, which is assumed in this work. The chosen CO2
source is independent of the location, thus carbon supply
would not restrict the best places for the PtG plant.
Climeworks CO2 capture plant has been used in our
energy system, since between 80-90% of energy needed
for this plant can be supplied by heat, rather than electricity
[27]. In this case the output heat of the system can be used
to fulfill this heat demand, which will increase the overall
efficiency of the system. The output heat of alkaline
electrolysis and methanation processes, 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 kWh of thermal energy at 100-
110°C and 200-250 kWh electricity [28]. The average
numbers which have been used in our calculations can be
seen in Table V. In case of a lack of internal heat, heat
pumps could be used to deliver the heat needed for the CO2
capture plant.
Table V: CO2 capture plant specification
Unit Amount
Capex 228 /(tCO2a) 356
Opex % of capex per annum 4
Lifetime years 30
Electricity demand kWhel/tCO2 225
Heat demand kWhth/tCO2 1500
2.1.4 Water desalination
The steam output of methanation goes through the heat
exchanger first, providing the heat for the CO2 capture
plant and the condensed water can be used in electrolysis,
but it cannot supply all the water needed for electrolysis.
Thus, a part of water needed for the electrolyzer 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 sea water
reverse osmosis (SWRO) desalination is used, whenever
clean water demand for any other activity in the region is
more than half of clean water available in the region (water
stress higher than 0.5). Water desalination plant
specifications can be seen in Table VI. More details on
RE-powered SWRO desalination plants are provided by
Caldera et al. [29].
PtG and liquefaction plants are built along the sea
shore and electricity from hybrid PV-Wind plants 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, LNG is produced just
beside the PtG plant and thus no SNG transportation cost
has to be taken into account and the LNG transportation
cost to the port will be minimized as well.
Table VI: Water desalination plant specification [29].
Unit Amount
SWRO Desalination
Capex €/(m3∙a) 2.23
Opex % of capex per annum 4.3
Lifetime years 30
Electricity consumption kWh/m3 3.0
Water efficiency % 45
Water storage
Capex €/(m3a) 0.0074
Opex % of capex per annum 1.5
Lifetime years 30
2.1.5 Oxygen
In case of a potential market, oxygen, as a byproduct
of electrolysis, can have a very important role in the final
cost of produced SNG. The market price of oxygen for
industrial purposes can be up to 80 €/tO2 [10]. It might be
too optimistic to assume that all the produced oxygen
would be sold for this price. Moreover, in case of a
potential market, oxygen storage and transportation costs
have to be applied. To have a rough assumption,
considering all these effects, there is no benefit from
oxygen in the base scenario. The projection of maximum
20 €/tO2 benefit from oxygen has been studied.
2.2 LNG VALUE CHAIN
Hybrid PV-Wind plants and PtG facilities need the
highest rate of FLh to minimize the levelized cost of
energy (LCOE) to produce SNG. There are limited places
in the world with such high FLh (see Fig. 2) which can act
as an interminable NG reserve. Like NG reserves, these
places are not always near consumption areas. For
distances of more than 2000 km, LNG transportation is
cheaper than NG pipelines [30]. In this research Japan,
which has the highest LNG demand and price in the world
[31], has been chosen as the target market. The selected
place of SNG production is Argentina (see Fig. 2). Due to
the large distance between these two countries (approx.
17,500 km) and the oceans between them, NG
transportation via pipeline is not beneficial, neither
practical; thus, LNG shipping and therefore a LNG value
chain is required.
Figure 4 shows the LNG value chain. First, NG is
cooled down to -162°C at atmospheric pressure in order to
change it to a liquid phase which has 600 times less volume
[30]. Then, it can be shipped to the destination by LNG
carriers [30]. At destination, LNG is heated up in
regasification plants [30] to change the phase to gas, so that
it can be used in the local gas grid. It is also possible to use
LNG directly as fuel in the transportation sector [32].
Figure 4: RE-LNG value chain.
2.2.1 SNG liquefaction
Generally, NG liquefaction efficiency is around 70-
80% [33], but SNG liquefaction efficiency is much higher
as it is pure methane and no gas treatment is required. Only
7-9% of feed gas is used as fuel in the liquefaction process
[34]. The gas treatment needed for the NG depends on the
quality of each NG reserve. Figure 5 shows the maximum
gas treatment process needed in LNG production from
NG. Besides the increase in the energy efficiency, the
elimination of these gas treating devices results in lower
cost in comparison to NG liquefaction process. The cost
distribution of a typical liquefaction plant is shown in
Table VII [30].
Figure 5: Maximum gas treatment for LNG production
from NG [33].
Table VII: Cost distribution of a typical liquefaction plant
[30]
Unit Amount
Gas treatment % 12
Liquefaction % 32
Fractionation % 5
Utilities and off-sites % 27
LNG storage and loading % 24
There is an increase in the cost of new liquefaction
plants becoming operational in the next 5 years [35]. These
plants are mostly located in Australia, and there are
regional reasons for the increase in the cost of a
liquefaction plant, such as higher labor cost, delay in
project and geographical nature, which makes it more
expensive. In addition, a liquefaction plant located in
industrialized regions with good infrastructure costs
almost half of those located in remote areas [35]. The
liquefaction plant in our model is located in Patagonia,
Argentina (see Fig. 2). With the easy and affordable ability
of electricity transmission, we can build the liquefaction
plant in the best location. Thus, for the liquefaction cost in
2030, the current price and specification have been used,
which can be found in Table VIII.
2.2.2 LNG shipping
With today’s technology there are LNG carriers up to
200,000 m3 capacity, but the common capacity for LNG
carriers is 138,000 m3 LNG [33, 36]. Approximately 0.1%
of the cargo will be evaporated each day (boil-off gas) and
needs to be evacuated from the LNG tanker to keep the
pressure constant, thus the efficiency of the ship would be
99.9% per day. The boil-off gas can be used in power
production or it can be liquefied again to keep the cargo
mass constant, but that needs a small scale liquefaction
plant, which will both cost and take some space in the ship
[36]. The assumed ship’s specifications can be seen in
Table VIII.
2.2.3 LNG regasification
The regasification plant, located in Japan, is the final
part of the LNG value chain. In this step, LNG is unloaded
from the ship to LNG storage. Then, it can be heated up by
seawater to be reconverted to NG, which can be delivered
to the gas grid or any other consumption destination. LNG
can be also used directly in the transportation sector. Due
to simpler structure, a regasification plant has lower capital
cost and higher lifetime and efficiency in comparison to
liquefaction (Tab. VIII).
Cold energy out of regasification can be used in
cryogenic oxygen production. This could be an extra
benefit out of the system which can increase the
competitiveness of the final product’s cost. In this analysis
it is not taken into account.
Table VIII: LNG value chain specification [37-44].
Abbreviations: million cubic meter, mcm, million ton per
annum, MMTPA.
Unit Amount
Liquefaction plant
Availability % 95
Capex k€/mcm/a SNG 196
Opex % of capex per annum 3.5
Lifetime years 25
Efficiency % 93
Capacity Mmtpa
Shipping
Availability % 95
Ship size m3 LNG 138,000
Capex m€/ship 151
Opex % of capex per annum 3.5
Lifetime years 25
Boil-off gas %/day 0.1
Speed knots 20
Charge & discharge time total days 2
Marine Distance km 17,500
LNG ships required - 2.4
Regasification plant
Availability % 95
Capex k€/mcm/a SNG 74
Opex % of capex per annum 3.5
Lifetime years 30
Efficiency % 98.5
3 RESULTS
Putting all the system’s elements together will offer some
chances of integration to increase the overall efficiency.
Figure 6 shows the so-called Sankey diagram of the whole
system, depicting the energy and material flows within the
entire RE-LNG value chain. The figure is the sample of a
system with 1 MWhel annual electricity input. As can be
seen, the electrolyzer, at 97%, is the main electricity
consumer, while the excess heat out of the electrolyzer and
the methanation plant is the main source of energy for the
CO2 capture plant.
All the general assumptions in calculations can be found
in Table IX.
Table IX: General assumptions in calculations
Unit Amount
WACC % 7
Exchange rate USD/€ 1.35
Brent crude oil price USD/bbl 80
Figure 6: RE-PtG-LNG energy and material flow diagram.
3.1 Annual Basis Model
The LCOE of wind and PV are 20.3 €/MWh and 25.36
€/MWh, respectively. The hybrid PV-Wind power plant of
5 GW produces 34,688 GWh of electricity per year and the
average cost is 22.58 €/MWh. Captured CO2 and
desalinated water will cost 5.08 €/tCO2 and 0.65 €/m3,
respectively. A summary of all production costs for the
base scenario can be found in Table X.
Table X: Production cost in base scenario
Unit Amount
Renewable Electricity (RE) €/MWhel 25.38
CO2 €/tCO2 5.08
Desalinated water €/m3 0.65
RE-SNG €/MWhth,gas 46.46
RE-SNG USD/MMBtu 18.17
RE-SNG USD/bbl 105.4
RE-SNG €/m3 0.488
LNG at production site €/MWhth,gas 52.68
RE-SNG at destination €/MWhth,gas 57.94
Figure 7 shows the levelized costs in the RE-LNG
value chain with two scenarios for the weighted average
cost of capital (WACC): 7% and 5%. RE-LNG cost
distribution as a share of total is not dependent on the
WACC. Methanation and hybrid PV-Wind power plants
have the highest share (46% and 35%, respectively) in the
total cost. At 19%, LNG value has the lowest share in this
process. The liquefaction plant has the highest share in the
LNG value chain and represents 10% of the final cost,
while LNG shipping and regasification plant shares are 6%
and 3%, respectively. Thus, it is more important to have
the plants in regions with highest solar and wind potential
than regions close to the target market in order to reduce
the final cost.
Figure 7: SNG production cost breakdown for WACC of 5% (top) and 7% (bottom).
Water and CO2 costs are included in electrolysis and
methanation. The share of the PtG plant itself in the final
cost of methanation is 39.5%, while energy losses in the
electrolysis and exothermic reaction of methanation are
36.6% of the cost of this process. At 7.19 €/MWhth,gas, the
cost of CO2 has only a 23.6% share in methanation plant
cost, which is due to internal heat utilization for the CO2
scrubbing process (Fig. 7).
With the base scenario, the final cost of RE-SNG in
Japan would be 65.61 €/MWhth,gas, which is equal to
148.86 USD/bbl or 25.67 USD/MMBtu. The LNG price in
Japan is a function of the crude oil price [31], thus the NG
price in Japan is a function of both crude oil price and
regasification cost which are shown is Figures 8 and 9.
Figure 8: Prices for LNG in Japan and crude oil in OECD
countries. Data are taken from [31].
Figure 9: Ratio of the LNG price in Japan to the crude oil
price in OECD countries. Data are taken from [31].
The long term (30 years) average ratio of LNG price
in Japan to OECD crude oil price, which is 102.3%, has
been used in this work. The described ratio for the year
2014 was 101.6%. With a Brent crude oil price of 80
USD/bbl, the price of NG (regasified LNG) in Japan would
be equivalent to 82.9 USD/bbl or 14.3 USD/MMBtu.
Thus, the base scenario, accounting for a RE-LNG-based
NG cost in Japan of 148.9 USD/bbl, is not competitive
with conventional NG, but there are some potential game
changers:
A) WACC: For the WACC of 7% in the base scenario,
the cost of debt and return on equity are 5% and 12%,
respectively. For a WACC of 5%, the corresponding
numbers are 4% and 7%, which could be realized for a
minimized risk of the business case. With this scenario the
cost of RE-SNG in Japan would decrease by 16.8% to 56.1
€/MWhth,gas, 22 USD/MMBtu or 127.4 USD/bbl
equivalent. Figure 10 shows the effect of WACC on the
final cost.
Figure 10: 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 huge impact on the competitiveness of
RE-SNG and NG, as it increases the total cost of fossil
fuels. The NG carbon emission is 15.3 tC/TJ (ton carbon
per tera joule) [45], which is equal to 56 tCO2/TJ. The
additional cost of CO2 emissions with a maximum price of
50 €/tCO2 on the NG price can be seen in Figure 11.
Figure 11: The additional cost of CO2 emission on NG
price for a CO2 price up to 50 €/tCO2 in absolute numbers
and relative for a basis NG price equivalent of 80 USD/bbl.
A CO2 price of up to 50 €/tCO2 is equivalent to a price
increase of NG in Japan of 10.2 €/MWhth,gas, 4
USD/MMBtu and 23.2 USD/bbl. Assuming a crude oil
price of 80 USD/bbl and 12.57 USD/MMBtu as the
corresponding price for NG in Japan as the base case, the
impact of CO2 emission cost on NG cost in percentage can
be also seen in Figure 11.
C) Oxygen: There is no financial benefit from oxygen
in the base scenario. The projection of a maximum average
benefit of 20 €/tO2 is shown in Figure 12. An oxygen price
of up to 20 €/tO2 is equivalent to a cost decrease of the RE-
LNG-based NG in Japan of 6.5 €/MWhth,gas, 2.55
USD/MMBtu and 17.74 USD/bbl, which is equal to a
10.4% decrease in the final cost.
Figure 12: Effect of oxygen benefit for an oxygen price of
up to 20 €/tO2 on RE-SNG cost in Japan in absolute
numbers and relative ones for the base scenario cost.
As a conclusion, an increase in crude oil price or CO2
emission cost will increase the cost of conventional NG,
while a profitable business case for O2 or a reliable
business case at a de-risked 5% of WACC level can lead
to lower cost for RE-SNG cost in Japan.
The effects of all these assumptions have been
summarised in Figure 13.
Figure 13: All possible scenarios for RE-SNG and NG price in Japan.
The price of NG in Japan is based on:
the global crude oil price as depicted in Figure 13 for a
price range of 40 160 USD/barrel,
three scenarios for CO2 emission cost,
three scenarios for benefit from O2 sales, and
the cost of delivered RE-methane based on two different
WACC levels
projected for the year 2030. To estimate the NG price in
Japan the cost of regasification is added to the LNG import
price in Japan [31]. The first breakeven can be expected
for produced RE-SNG with a WACC of 5%, CO2-
emission cost of 50 €/tCO2, accessible oxygen price of 20
€/tO2 and a crude oil price of 87 USD/bbl. While RE-SNG
produced under the base case (WACC of 7%, no CO2
emission cost and no O2 sales) can compete with
conventional NG whenever the crude oil price is higher
than 145 USD/bbl (which had been already the case for a
few days in the year 2008 for current currency values).
This is a very high difference and the base model 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 [46].
To have a better understanding about the scale of the
project, Table XI lists the physical and economic aspects
of the 5 GW model assumption.
Table XI: General assumptions in calculations.
Abbreviations: million ton per annum, MMTPA.
Unit Amount
PV 1-axis installed capacity GWp 5
Wind installed capacity GW 5
Hybrid PV-Wind, capex bn€ 7.8
Hybrid PV-Wind, generation GWhel 36,000
Hybrid PV-Wind, used GWhel 34,668
CO2 capture plant
Capacity MWel 131
Capex m€ 36
CO2 production MMTPA 4.032
External heat utilization GWhth 6896
Desalination plant
Capacity MWel 5
Capacity m3/h 505
Capex m€ 10
Water production mio m3 3.5
Electrolysis and methanation plants
Capacity GWel 4.87
Capex bn€ 2.43
SNG production GWhth 22,672
SNG production MMTPA 1.47
Liquefaction plant
Capacity mio m3/a NG 2272
Capex m€ 445
LNG production MMTPA 1.5
LNG shipping
Volume mio m3 LNG 3.31
Capex m€ 432
Regasification Plant
Capacity mio m3/a NG 2.05
Capex m€ 152
SNG production mio m3/a NG 1.92
RE-LNG value chain, capex bn€ 1.02
3.2 Hourly Basis Model
The Hourly Basis Model analysis has been used to find
the cost optimum combination of all elements described in
the methodology section. The results show that single-axis
tracking PV systems start to play an increasingly more
relevant role in the PV sector as they generate minimum
LCOE for a maximum of FLh, thus fixed tilted PV systems
are substituted more and more. In addition, for the whole
world with the exception of Tibet, the cost of batteries
would be too high to generate a financial benefit for a
reduction of curtailed electricity. As a result, battery
capacity is not installed. The PtG plant is located along a
sea shore, thus the cost of power lines from hybrid PV-
Wind plants to a PtG plant and the loss of power along the
transmission lines are included in the model.
FLh have a major role in the final cost of SNG. High
FLh of hybrid PV-Wind plants result in cost reduced
downstream processes such as PtG, water desalination and
CO2 scrubbing. The FLh of PV, wind and hybrid PV-Wind
Plant are shown in Figure 14. All the figures in this section
illustrate the FLh and the corresponding information for
areas with a minimum of 6000 FLh. As can be seen in the
figure, the sites of high hybrid PV-Wind FLh are
distributed across the world. With up to 6500 hours, wind
FLh are much higher than PV FLh due to 24h harvesting,
but a PV single-axis tracking system stays competitive due
to lower capex and comparable LCOE.
Figure 14 Hybrid PV-Wind FLh (top), PV (single-axis tracking) FLh (bottom, left) and wind FLh (bottom, right) for the cost
year 2030.
The LCOE of PV, wind and the hybrid PV-Wind
plants are shown in Figure 15. LCOE represents a major
contribution to the final cost of SNG. The most
competitive electricity is produced by PV plants in South
America in the range of 15-17 €/MWh, but it has a small
share on a global scale due to the small area with this
potential. In Africa and Oceania, single-axis tracking PV
plants generate lower cost electricity in the range of 20-
23 €/MWh, while in Patagonia wind is the dominating
low cost source of electricity with costs in the range of
16-21 €/MWh. The LCOE of PV plants in South America
shows the highest divergence, from 15 to 30 €/MWh. The
LCOE of the hybrid PV-Wind plant in each region is in a
range between the corresponding PV and wind LCOE,
closer to the one with a higher share in the capacity and
FLh of the hybrid system. As an example, the LCOE of
PV and wind plants in the southern part of Patagonia are
in the range of 27-30 and 18-20 €/MWh, respectively, and
the LCOE of the hybrid system is in the range of 20-23
€/MWh. These higher cost will be compensated by higher
FLh for the PtG plant, reducing the overall cost.
Figure 15: Hybrid PV-Wind LCOE (top), PV (single-axis tracking) LCOE (bottom, left) and wind LCOE (bottom, right) for
the cost year 2030.
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, PtG capacity will be optimized
as well. This might result in some further curtailment of
electricity (excess electricity). The excess electricity, the
levelized cost of net electricity used for the PtG process
and the cost of produced SNG is shown in Figure 16.
Excess electricity is a function of the overlap of PV and
wind FLh, PtG capacity, application of batteries, and water
desalination demand. Figure 16 shows that Patagonia,
with less than 4%, has the lowest rate of excess electricity
in the world. That means 96% of electricity produced by
the hybrid PV-Wind plant is converted into SNG in the
PtG plant, which will result in a lower SNG 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 PtG process. The LCOE
used in the PtG plant is in the range of 18 - 33 €/MWh,
with the exception of West Tibet, which has LCOE of 50
€/MWh. This is due to a very high rate of excess electricity
in Tibet, which can be up to 30%. The most attractive
regions for LCOE are in Patagonia, Tibet and Somalia with
LCOEs in the range of 20, 24 and 26 €/MWh respectively.
Considering the finally optimized combination of FLh,
LCOE, excess electricity and power transmission loss,
results in the least cost for SNG production, which is the
final objective. SNG production cost in Patagonia,
Somalia, southern Tibet and western part of Australia is
the lowest, which is in the range of 50-80 €/MWhth,gas. On
the other hand, SNG cost in western Tibet is in the range
of 160-200 €/MWhth,gas which is the highest in the world
(see Fig. 16).
Figure 16: Levelized cost of SNG (top), Levelized cost of electricity (bottom, left) and excess electricity in percentage of
generation (bottom, right) for the cost year 2030.
The maximum potential of installable capacity of
hybrid PV-Wind plants for at least 6000 FLh is shown in
Figure 17. This is the maximum possible installable
capacity at a 10% land usage limit for both PV and wind
energy, not taking into account a limit for the LCOE. With
respect to these constraints, the global installable capacity
would be about 50,865 GW. The capacity units indicated
by the color bar is for an area of 0.45ºx0.45º each, equal to
an area of 2,500 km2 (50x50 km) near the equator, but the
area is shrinking towards the poles. At 60º S or N latitude,
the area of the same 0.45ºx0.45º is halved. This is the main
reason for smaller capacities in northern and southern
regions. Thus, the numbers per node in these figures do not
necessarily represent the same values per square kilometer
(km2). This fact should be taken into account for all the
following figures related to capacity and generation on a
per node basis. Applying a 10% area limit for both PV and
wind energy, the maximum possible installable capacity in
the largest node is 20.85 GW, with 2.1 and 18.75 GW
shares for wind energy and PV, respectively. With about
13,970 (Africa), 12,370 (South America) and 12,260 GW
(Asia), these regions have the highest installable capacity
in the world, while Europe (970 GW) has the least
installable capacity.
Figure 17: Hybrid PV-Wind plant installable capacity assuming a 10% area limit.
The maximum capacities of about 50.8 TW in Figure
17, with respect to corresponding FLh of at least 6000 for
each node, can generate a maximum possible annual
electricity by PV and wind energy in the hybrid PV-Wind
plant, which is shown in Figure 18. With 100,460 TWhel,
the generation potential of the PV part of the hybrid plant
is almost 5 times higher than that of the wind part, which
is 22,760 TWhel. The hybrid system generation potential is
the sum of PV and wind generation potential, which is
123,220 TWhel. This results in a generation potential of
61,880 TWhth,gas. This is a very significant potential as the
global natural gas production in 2014 was 3461 billion
cubic meters, which is equal to 36,350 TWhth,gas [31].
Several regions, with about 17,560 (Africa), 15390
(Asia) and 14,890 TWhth,gas, (South America),
respectively, have major potential for SNG production,
while Europe (900 TWhth,gas), has the least potential. The
SNG production potential in North America (4,260 TWh
th,gas) is significantly less than that of South America
(14,890 TWhth,gas). With 5940 TWhel, South America has
the highest wind power generation potential, while Africa,
with 29,300 TWhel, is the continent with the highest
potential for PV power generation, which can be utilized
for SNG production.
Figure 18: Hybrid PV-Wind annual electricity generation potential (top), PV (single-axis tracking) annual electricity
generation potential (center, left), wind energy annual electricity generation potential (center, right) and SNG annual generation
potential (bottom) for the cost year 2030.
In order to obtain the least cost electricity and SNG
production, not all the possible capacity of PV and wind
energy would be installed. Figure 19 shows the optimized
installed capacities for hybrid PV-Wind and PtG plants.
The ratio of installed capacities is a function of LCOE and
FLh of PV and wind energy. In southern Patagonia, with
more than 90% installed capacity, wind is the dominating
sector, while it also plays the main role in southern Tibet
and east Africa, accounting for 80 and 60%, respectively.
Interestingly, even in some regions near the equator, wind
power is the more significant part of the hybrid PV-Wind
plant. Australia and North Africa show an even
(50%:50%) ratio of installed capacity of PV and wind
power plants. As can be seen, the amount of optimized
installed capacity in most regions is less than 5 GW per
node (0.45ºx0.45º). This is due to the fact that wind energy
has much higher FLh (see Fig. 14) than PV, which makes
it more attractive for PtG plants, even if the corresponding
LCOE were slightly higher than that of PV (see Fig. 15) in
a region. Thus, wind energy would be installed first. On
the other hand, as shown by Figure 17, wind energy
capacity in the same area is 9 times less than PV due to a
much better area efficiency of PV, thus it reaches to its’
upper limit sooner in a lower capacity. PV is installed in
parallel to increase the FLh and capacity, but in most
regions it is installed with almost the same capacity of
wind energy. This will result in the same capacity for
higher FLh for hybrid PV-Wind power plants and, as a
consequence, for PtG plants. Higher PV capacities
increase the capacity of the entire system, but for smaller
FLh. Such an unbalanced production is not suitable for PtG
plants. It would require a larger PtG plant operating for a
smaller plant utilization, which obviously increases the
levelized cost of produced SNG.
The global optimal installed capacity of hybrid PV-
Wind plants is 9495 GW, while Africa with 2630 GW has
the highest share. Europe, with 110 GW, stands for 1% of
global capacity potential, while Oceania, with 1,440 GW,
has more than 15% of global capacity potential.
Figure 19: Optimal hybrid PV-Wind plant installable capacity potential (top), ratio of PV to hybrid PV-Wind installable
capacity (center, left), ratio of wind to hybrid PV-Wind installable capacity (center, right) and optimal PtG plant installable
capacity potential (bottom) for the cost year 2030.
At the same time, there are regions with a significant
difference in the FLh of PV and wind energy (see Fig. 14),
which results in respective differences in the LCOE (see
Fig. 15). In these cases, the ratio of installed capacities is
more oriented to the one with better potential. 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 (see Fig. 15). In this region the LCOE of
PV is almost half of the LCOE of wind energy (see Fig.
15). This unique constraint results in installation of PV to
its’ maximum possible capacity, which would be 18 GWel
per node. This would result in a PtG capacity of more than
8 GW.
With respect to the optimal hybrid PV-Wind power
plants’ capacity, optimal PtG installed capacity would be
3045 GW globally (see Fig. 19). Although Africa, with
2630 GW, has the highest capacity for optimal hybrid
system, South America has the highest PtG optimized
capacity (880 GW) in the world and Africa stands in the
second place at 765 GW optimal capacity. This is due to
the minimum excess electricity in South America, shown
in Figure 16.
The optimized capacities shown in Figure 19, result in
the optimal production generation presented in Figure 20.
As can be seen in the figure, the optimal production rate in
most nodes is less than 20 TWhel. The generation potential
for PtG is less than the electricity generation, which is due
to the electricity consumption in the desalination and CO2
capture plant, and efficiency losses in the PtG plant and
power transmission lines. The global annual optimal
electricity and SNG production potential are 31,440 TWhel
and 17,560 TWhth,gas, respectively. More SNG could be
produced in South America (4,750 TWhth,gas), while hybrid
PV-Wind power plant generation in Africa (8,360 TWhel)
is comparable to the potential of South America (8170
TWhel). As mentioned for Figure 19, it is because of the
very small ratio of excess electricity in South America (see
Fig. 16). Europe has the lowest electricity and SNG
production, with 62.6%, but it has the highest electricity to
SNG conversion rate among all continents. With respect to
global production numbers in the figure, the average
electricity to SNG conversion rate can be estimated to be
about 56%.
Fig. 20: Optimal hybrid PV-Wind plant annual electricity generation potential (top) and optimal PtG plant annual SNG
generation potential (bottom) for the cost year 2030.
Most interesting is finally an industrial cost curve, i.e.
the SNG production cost as a function of volume. Figure
21 presents the optimal annual SNG production volume
sorted in order of the specific generation cost. Minimum
SNG production cost is 51 €/MWhth,gas. A maximum of
16,000 TWhth,gas SNG can be produced for costs less than
100 €/MWhth,gas at sites with at least 6000 FLh for hybrid
PV-Wind plants. For costs less than 70 €/MWhth,gas,
production of 2,000 TWhth,gas is achievable. A larger
volume could be produced for costs in the range of 70 to
90 €/MWhth,gas.
Figure 21: SNG cost curve, for cost optimized SNG generation in a cumulative (left) and a spectral (right)
representation.
4 CONCLUSION
Hybrid PV-Wind power plants can be used to harvest
RE in sites of very high FLh and to supply the power
needed for PtG plants in order to produce SNG. To have a
carbon neutral product, CO2 needed for this process is
captured from ambient air and water desalination is used
whenever the water stress in the region is more than 0.5.
The RE-SNG can be used in a LNG value chain to reach
Japan, the most attractive market. All the technologies for
this energy system already exist on a commercial scale and
it can become operational whenever investors decide to go
for it. This point in time may be reached when the
projected costs in this paper are achieved and the final cost
is competitive with the conventional NG price, including
cost for fossil CO2 emissions and income for byproducts,
such as O2.
The Annual Basis Model presents a rough assumption
for production cost and effecting factors in Patagonia,
Argentina. With WACC of 7%, the cost of produced SNG
would be 65.6 €/MWhth,gas, which is equal to 148.9
USD/bbl or 25.7 USD/MMBtu. At 46 and 35 %,
respectively, methanation and hybrid PV-Wind power
plants have the highest shares in the cost of the whole
value chain, while the share of LNG value chain is only
19% of the total cost. Thus, it perfectly makes sense to
build the plants in regions of best solar and wind energy
resources and to pay for the additional cost of the LNG
value chain, rather than building PtG plants in
consumption regions with considerably lower solar and
wind energy resource potentials, or limited area.
There are factors which improve the economics of the
RE-LNG value chain, such as income for byproducts or
emission costs for fossil NG. The conventional NG price
has historically shown to be a function of the crude oil
price and this will occur in future also for the CO2 emission
cost. The results of this paper show that for a CO2 emission
cost of 50 €/tCO2, an O2 benefit of 20 €/tO2 and a WACC of
5% for all value chain steps of RE-LNG, cost
competitiveness to conventional NG price is achieved
whenever the Brent crude oil price is 87 USD/barrel or
higher. A realistic breakeven may happen for crude oil
prices between 100 - 120 USD/bbl. 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
SNG cost in Japan throughout the entire value chain by
16%.
The Hourly Basis Model enables the financially
optimized combination of PV and Wind capacities for the
SNG production for all regions in the world with at least
6000 FLh for hybrid PV-Wind plants. Results show that
LCOE of hybrid PV-Wind plants at the best sites would be
in the range of 18-22 €/MWhel. With the impact of FLh,
excess electricity, water desalination demand and demand
for power transmission lines, this results in RE-SNG cost
in the range of 50-100 €/MWhth,gas.
The global possible capacity and corresponding
production potential for hybrid PV-Wind power plants,
applying the aforementioned constraints are about 50.9
TW and 123,220 TWhel, respectively. This can lead to an
annual generation of 61,880 TWhth,gas globally. For cost
optimized hybrid PV-Wind power plants, the global
capacity and corresponding generation potential of hybrid
PV-Wind plants and PtG plants would be about 9.5 TW,
3.0 TW and 31,440 TWhel, 17,560 TWhth,gas, respectively.
From this potential, approximately 2000 TWhth,gas can be
produced for costs less than 70 €/MWhth,gas, while larger
volumes can be produced in a cost range of 70 - 90
€/MWhth,gas.
These results have a significant impact on the
discussions of the energy transformation towards
sustainability ahead. The hybrid PV-Wind-RE-PtG-LNG
system could set an upper limit for fossil fuel prices,
globally. At that price level, the CO2 emission
disadvantage of fossil fuels could be fully eliminated.
It would also further increase the demand for solar PV
systems, wind turbines, water electrolyzers, methanation
plants and CO2 capture plants. This potentially huge
market itself would further reduce production costs and
increase research and development investments in the field
for more efficient technologies.
ACKNOWLEDGEMENTS
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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[46] OECD, 2013. Climate and Carbon: Aligning Prices
and Policies, OECD Environment Policy Papers,
No. 1, OECD Publishing, Paris, October 9
... A simple solution consists in harvesting renewable resources in remote areas where they are abundant, synthesising carbonneutral fuels or feedstocks using renewable electricity and transporting them back to demand centres (Fasihi and Bogdanov, 2015;Chapman et al., 2017;Heuser et al., 2019). However, two conditions must be satisfied for such an approach to be worth pursuing. ...
... Since renewable power generation technologies usually have very low operating costs, the higher the capacity factor, the lower the electricity cost. Regions with outstanding resources and vast technical potential include Patagonia (wind) (Heuser et al., 2019), North Africa (sun and wind) (Fasihi and Bogdanov, 2015), and Greenland (wind) (Radu et al., 2019). Providing an accurate quantitative assessment of the economics and efficiency of such remote renewable energy supply chains and pathways is critical to evaluate future sustainable energy supply options available to policy makers and society at large as well as to identify where to direct future research and development efforts. ...
... Production cost estimates for this route were found to be between 23.5 and 30.0 US$/GJ (which would roughly correspond to 74.1 and 94.6 e/MWh, using the 2020 average exchange rate of $1.142 for 1.0e). The production of carbon-neutral synthetic methane and liquid fuels in remote areas with abundant renewable resources has been considered in Fasihi and Bogdanov (2015) and Fasihi et al. (2017), respectively. In the first study, the authors estimate that the cost of producing synthetic methane from renewable electricity in North Africa (specifically in central and southern Algeria) and delivering it to Japan could be around 65-75 e/MWh by 2030 for a hybrid solar-wind system, assuming a uniform weighted average cost of capital (WACC) of 7%. ...
Article
Full-text available
This paper studies the economics of carbon-neutral synthetic fuel production from renewable electricity in remote areas where high-quality renewable resources are abundant. To this end, a graph-based optimisation modelling framework directly applicable to the strategic planning of remote renewable energy supply chains is proposed. More precisely, a hypergraph abstraction of planning problems is introduced, wherein nodes can be viewed as optimisation subproblems with their own parameters, variables, constraints and local objective. Nodes typically represent a subsystem such as a technology, a plant or a process. Hyperedges, on the other hand, express the connectivity between subsystems. The framework is leveraged to study the economics of carbon-neutral synthetic methane production from solar and wind energy in North Africa and its delivery to Northwestern European markets. The full supply chain is modelled in an integrated fashion, which makes it possible to accurately capture the interaction between various technologies on an hourly time scale. Results suggest that the cost of synthetic methane production and delivery would be slightly under 150 €/MWh (higher heating value) by 2030 for a system supplying 10 TWh annually and relying on a combination of solar photovoltaic and wind power plants, assuming a uniform weighted average cost of capital of 7%. A comprehensive sensitivity analysis is also carried out in order to assess the impact of various techno-economic parameters and assumptions on synthetic methane cost, including the availability of wind power plants, the investment costs of electrolysis, methanation and direct air capture plants, their operational flexibility, the energy consumption of direct air capture plants, and financing costs. The most expensive configuration (around 200 €/MWh) relies on solar photovoltaic power plants alone, while the cheapest configuration (around 88 €/MWh) makes use of a combination of solar PV and wind power plants and is obtained when financing costs are set to zero.
... A simple solution consists in harvesting renewable resources in remote areas where they are abundant, synthesising carbon-neutral fuels or feedstocks using renewable electricity and transporting them back to demand centres [12,13,14]. However, two conditions must be satisfied for such an approach to be worth pursuing. ...
... Since renewable power generation technologies usually have very low operating costs, the higher the capacity factor, the lower the electricity cost. Regions with outstanding resources and vast technical potential include Patagonia (wind) [14], North Africa (sun and wind) [12] and Greenland (wind) [15]. Providing an accurate quantitative assessment of the economics and efficiency of such remote renewable energy supply chains and pathways is critical to evaluate future sustainable energy supply options available to policy makers and society at large as well as to identify where to direct future research and innovation efforts. ...
... Production cost estimates for this route were found to be between 23.5 and 30.0 US$/GJ (which would roughly correspond to 74.1 and 94.6 e/MWh, using the 2020 average exchange rate of $1.142 for 1.0e). The production of carbon-neutral synthetic methane and liquid fuels in remote areas with abundant renewable resources has been considered in [12] and [22], respectively. In the first study, the authors estimate that the cost of producing synthetic methane from renewable electricity in the Maghreb and North Africa (specifically in central and southern Algeria) and delivering it to Japan could be around 65-75 e/MWh by 2030 for a hybrid solar-wind system, assuming a uniform weighted average cost of capital (WACC) of 7%. ...
Preprint
Full-text available
This paper studies the economics of carbon-neutral synthetic fuel production from renewable electricity in remote areas where high-quality renewable resources are abundant. To this end, a graph-based optimisation modelling framework directly applicable to the strategic planning of remote renewable energy supply chains is proposed. More precisely, a graph abstraction of planning problems is introduced, wherein nodes can be viewed as optimisation subproblems with their own parameters, variables, constraints and local objective, and typically represent a subsystem such as a technology, a plant or a process. Edges, on the other hand, express the connectivity between subsystems. The framework is leveraged to study the economics of carbon-neutral synthetic methane production from solar and wind energy in North Africa and its delivery to Northwestern European markets. The full supply chain is modelled in an integrated fashion, which makes it possible to accurately capture the interaction between various technologies on hourly time scales. Results suggest that the cost of synthetic methane production and delivery would be slightly under 200 \euro/MWh and 150 \euro/MWh by 2030 for a system supplying 100 TWh (higher heating value) annually that relies on solar photovoltaic plants alone and a combination of solar photovoltaic and wind power plants, respectively, assuming a uniform weighted average cost of capital of 7\%. The cost difference between these system configurations mostly stems from higher investments in technologies providing flexibility required to balance the system in the solar-driven configuration. Synthetic methane costs would drop to roughly 124 \euro/MWh and 87 \euro/MWh, respectively, if financing costs were zero and only technology costs were taken into account. Prospects for cost reductions are also discussed, and options that would enable such reductions are reviewed.
... 12,13 It is also increasingly better understood that the energy system in this century will be mainly based on electricity, finally due to high technical efficiency, comparable low cost, and the availability of respective power-to-X technologies. The power-to-X technologies include power-to-heat (electric heat pumps 14,15 ), power-to-water (reverse osmosis desalination 16 ), powerto-hydrocarbons (hydrogen, 17,18 methanation, [17][18][19][20] synthetic fuels, [20][21][22] and synthetic chemical feedstock [23][24][25][26], and a directly or indirectly electrified transport sector (battery electric vehicles, 27,28 marine, 29 and aviation 21 ). Decision makers increasingly require energy transition analyses with high spatial and temporal resolutions, so that the results can be discussed on a country or subcountry level in full hourly resolution and for demonstrating the feasibility of 100% RE systems. ...
... Gas turbines can be installed after 2015 due to lower carbon emissions and the possibility to accommodate synthetic natural gas or biomethane into the system. 19 The applied strong sustainability requirements do not allow new investments in nuclear energy, as mentioned, but the utilisation of the existing capacity till the end of its individual technical lifetime, so that a gradual phase out can be observed. Coalfired power plants are also not allowed to receive new investments; however, the existing capacities have to be amortised till the end of FIGURE 1 Main inputs and outputs of the LUT energy system model. ...
Article
The power sector is faced with strict requirements in reducing harmful emissions and substantially increasing the level of sustainability. Renewable energy (RE) in general and solar photovoltaic (PV) in particular can offer societally beneficial solutions. The LUT energy system transition model is used to simulate a cost-optimised transition pathway towards 100% RE in the power sector by 2050. The model is based on hourly resolution for an entire year, the world structured in 145 regions, high spatial resolution of the input RE resource data, and transition steps of 5-year periods. The global average solar PV electricity generation contribution is found to be about 69% in 2050, the highest ever reported. Detailed energy transition results are presented for representative countries in the world, namely, Poland, Britain and Ireland, Turkey, Saudi Arabia, Brazil, Ethiopia, and Indonesia. The global average energy system levelised cost of electricity gradually declines from 70 €/MWh in 2015 to 52 €/MWh in 2050 throughout the transition period, while deep decarbonisation of more than 95% around 2040, referenced to 2015, would be possible. The targets of the Paris Agreement can be well achieved in the power sector, while increasing societal welfare, given strong policy leadership.
... However the same paper could not confirm the benefits for cross-border exchange of electricity for the same exporting and importing regions. Fasihi et al. have shown substantial benefits of international trade of PtX products, as shown for liquefied SNG (Fasihi et al., 2015), Fischer-Tropsch liquid fuels (Fasihi et al., 2016), methanol and dimethyl ether , ammonia , and indicated similar characteristics for all hydrogen-based synthetic fuels and chemicals . All these examples utilize at least at some point the existing infrastructure. ...
Article
The discussion about the benefits of a global energy interconnection is gaining momentum in recent years. The techno-economic benefits of this integration are broadly discussed for the major regions around the world. While there has not been substantial research on the techno-economic benefits, however, some initial results of the global energy interconnection are presented in this paper. Benefits achieved on the global scale are lower than the interconnections within the national and sub-national level. The world is divided into 9 major regions and the major regions comprise of 23 regions. When all the considered regions are interconnected globally, the overall estimated levelized cost of electricity is 52.5 €/MWh for year 2030 assumptions, which is 4% lower than an isolated global energy system. Further, the required installed capacities decrease by 4% for the fully interconnected system. Nevertheless, a more holistic view on the entire energy system will progress research on global energy interconnection as, synthetic power-to-X fuels and chemicals emerge as an important feature of the future sustainable global energy system with strong interactions of the power system not only to the supply, in energy fuel and chemicals trading globally, but also to the demand side. Global energy interconnection will be part of the solution to achieve the targets of the Paris Agreement and more research will help to better understand its impact and additional value.
... Gas based power plants, CHP and boilers can be installed after 2015 due to lower GHG emissions and the possibility to accommodate synthetic natural gas (SNG) or bio-methane into the system [36]. ...
Article
Transition towards 100% renewable energy supply is a challenging aim for many regions in the world. Even in regions with excellent availability of wind and solar resources, such factors as limited availability of flexible renewable energy resources, low flexibility of demand, and high seasonality of energy supply and demand can impede the transition. All these factors can be found for the case of Kazakhstan, a mostly steppe country with harsh continental climate conditions and an energy intensive economy dominated by fossil fuels. Results of the simulation using the LUT Energy System Transition modelling tool show that even under these conditions, the power and heat supply system of Kazakhstan can transition towards 100% renewable energy by 2050. A renewable-based electricity only system will be lower in cost than the existing fossil-based system, with levelised cost of electricity of 54 €/MWh in 2050. The heat system transition requires installation of substantial storage capacities to compensate for seasonal heat demand variations. Electrical heating will become the main source of heat for both district and individual heating sectors with heat cost of about 45 €/MWh and electricity cost of around 56 €/MWh for integrated sectors in 2050. According to these results, transition towards a 100% renewable power and heat supply system is technically feasible and economically viable even in countries with harsh climatic conditions.
... Greenpeace [39] estimates that 560 TWh will be utilized for hydrogen generation and 790 TWh for synthetic liquid fuel generation intended for the transport sector. Fasihi et al. [33,32] conclude that renewable electricity based synthetic fuels are a real option for decarbonizing the energy system for the period of the year 2030 and beyond. The findings for the Sub-Saharan Africa 100% renewable resource-based energy system clearly show the potential of the region for RE generation and for a global climate change mitigation strategy. ...
Article
This paper determines a least cost electricity solution for Sub-Saharan Africa (SSA). The power system discussed in this study is hourly resolved and based on 100% Renewable Energy (RE) technologies. Sub-Saharan Africa was subdivided into 16 sub-regions. Four different scenarios were considered involving the setup of a high voltage direct current (HVDC) transmission grid. An integrated scenario that considers water desalination and industrial gas production was also analyzed. This study reveals that RE is sufficient to cover 866.4 TWh estimated electricity demand for 2030 and additional electricity needed to fulfill 319 million m3 of water desalination and 268 TWh LHV of synthetic natural gas demand. Existing hydro dams can be used as virtual batteries for solar PV and wind electricity storage, diminishing the role of other storage technologies. The results for total levelised cost of electricity (LCOE) decreases from 57.8 €/MWh for a highly decentralized to 54.7 €/MWh for a more centralized grid scenario. For the integrated scenario, including water desalination and synthetic natural gas demand, the levelised cost of gas and the levelised cost of water are 113.7 €/MWh LHV and 1.39 €/m3 , respectively. A reduction of 6% in total cost and 19% in electricity generation was realized as a result of integrating desalination and power-togas sectors into the system. A review of studies on the energy future of Sub-Saharan Africa provides the basis for a detailed discussion of the new results presented.
Article
The Paris Agreement sets a clear target for net zero greenhouse gas (GHG) emissions by the mid‐21st century. This implies that the transport sector has to reach zero GHG emissions mainly through direct and indirect electrification in the form of synthetic fuels, such as hydrogen and Fischer‐Tropsch (FT) fuels. The results of this research document that this very ambitious target is possible. This research analyses the global solar photovoltaics (PV) demand for achieving the Paris targets in the transport sector by the year 2050. The methodology is composed of the derivation of the transportation demand converted into final energy demand for direct electrification, hydrogen, methane, and FT‐fuels production. The power‐to‐gas (H2, CH4) and power‐to‐liquids (FT fuels) value chains are applied for the total electricity demand, which will be mostly fulfilled by PV, taking into account previous results concerning the renewable electricity share of the energy transition in the power sector for the world structured in 145 regions and results aggregated to nine major regions. The results show a continuous demand increase for all transportation modes till 2050. The total global PV capacity demand by 2050 for the transport sector is estimated to be about 19.1 TWp, thereof 35%, 25%, 7%, and 33% for direct electrification, hydrogen, synthetic natural gas, and FT fuels, respectively. PV will be the key enabler of a full defossilisation of the transport sector with a demand comparable with the power sector but a slightly later growth dynamic, leading to a combined annual PV capacity demand of about 1.8 TWp around 2050.
Article
Accordingly to the COP21 Paris Agreement a net zero greenhouse gas emission energy system must be built no later than 2050. Such a fast power system transition will be very challenging for the conditions of Northeast Asia, a region with a large and fast growing power demand. Power system transition modelling was performed in order to check the technical feasibility of such a transition. The results of the simulation show that the transition can be accomplished and a 100% renewable energy system is both technically feasible and economically viable in Northeast Asia with average electricity generation cost of around 55 €/MWh. Solar photovoltaic (PV) will become the major energy source in Northeast Asia with a generation share of more than 70%; wind energy will contribute to 18% of the generation. Decarbonisation of the system can be achieved quite fast: by 2035 CO 2eq emissions in the power sector will decrease by 95 and 99% by 2045, respectively.
Thesis
Full-text available
Burning of fossil fuels is one of the main drivers accelerating the climate change. COP21 agreement adopted at the United Nations Climate Change Conference has addressed the climate change. In order to comply with the targets the countries need to implement energy transition from fossil fuels towards renewable energy. Biofuels are one of the alternatives for fossil fuels in transportation. Though the constraints for their deployment include the low commercialization level, limited resource availability, uncertainty regarding cost competitiveness with fossil fuels, sustainability concerns and better alternatives in the future such as synthetic fuels. The objective of the thesis is to assess the biofuels contribution towards the global energy transition from the different perspectives such as technology, resources, economics, sustainability and alternative options. The work is based on secondary data, which was collected and analyzed. The cost calculations were done by means of levelized cost of fuel formula. The cost projections for biofuels were done based on the feedstock cost estimations for the future. The findings have shown that there are many types of biofuels but only conventional biofuels, which are generally associated with sustainability constraints, are commercially available. Nowadays the United States corn and Brazilian sugarcane ethanol are the major biofuels on the market. Sugarcane ethanol has excellent emission reduction, good energy return on energy investment as well as dramatically decreasing costs in the future. Whereas corn ethanol has average emission reduction performance and energy return on energy investment as well as its costs slightly grow in the future. Therefore it is clear that sugarcane ethanol will stay on the market long time in the future while corn ethanol will be extruded by a cheaper and more sustainable alternative. Biofuels cannot satisfy the global transportation demand alone so their contribution towards global energy transition is limited. Thus, there should be an energy mix of conventional and advanced biofuels, synthetic fuels and electrification of transport aimed at satisfying the demand of different transportation sectors.
Technical Report
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Technical Report "Global Energy System based on 100% Renewable Energy – Power Sector", published at the Global Renewable Energy Solutions Showcase event (GRESS), a side event of the COP23, Bonn, November 8, 2017 A global transition to 100% renewable electricity is feasible at every hour throughout the year and more cost effective than the existing system, which is largely based on fossil fuels and nuclear energy. Energy transition is no longer a question of technical feasibility or economic viability, but of political will. Existing renewable energy potential and technologies, including storage can generate sufficient and secure power to cover the entire global electricity demand by 2050 . The world population is expected to grow from 7.3 to 9.7 billion. The global electricity demand for the power sector is set to increase from 24,310 TWh in 2015 to around 48,800 TWh by 2050. Total levelised cost of electricity (LCOE) on a global average for 100% renewable electricity in 2050 is 52 €/MWh (including curtailment, storage and some grid costs), compared to 70 €/MWh in 2015. Solar PV and battery storage drive most of the 100% renewable electricity supply due to a significant decline in costs during the transition. Due to rapidly falling costs, solar PV and battery storage increasingly drive most of the electricity system, with solar PV reaching some 69%, wind energy 18%, hydropower 8% and bioenergy 2% of the total electricity mix in 2050 globally. Wind energy increases to 32% by 2030. Beyond 2030 solar PV becomes more competitive. Solar PV supply share increases from 37% in 2030 to about 69% in 2050. Batteries are the key supporting technology for solar PV. Storage output covers 31% of the total demand in 2050, 95% of which is covered by batteries alone. Battery storage provides mainly short-term (diurnal) storage, and renewable energy based gas provides seasonal storage. 100% renewables bring GHG emissions in the electricity sector down to zero, drastically reduce total losses in power generation and create 36 million jobs by 2050. Global greenhouse gas emissions significantly reduce from about 11 GtCO2eq in 2015 to zero emissions by 2050 or earlier, as the total LCOE of the power system declines. The global energy transition to a 100% renewable electricity system creates 36 million jobs by 2050 in comparison to 19 million jobs in the 2015 electricity system. Operation and maintenance jobs increase from 20% of the total direct energy jobs in 2015 to 48% of the total jobs in 2050 that implies more stable employment chances and economic growth globally. The total losses in a 100% renewable electricity system are around 26% of the total electricity demand, compared to the current system in which about 58% of the primary energy input is lost.
Article
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The increase in domestic supplies of natural gas has raised new interest in expanding its use in the transportation sector. This report considers issues related to wider use of natural gas as a fuel in passenger cars and commercial vehicles. The attractiveness of natural gas as a vehicle fuel is premised in large part on its low price (on an energy-equivalent basis) compared to gasoline and diesel fuel. When prices for gasoline and diesel are relatively low or natural gas prices are relatively high, natural-gas-based fuels lose much of their price advantage. While natural gas has other benefits-such as producing lower emissions than gasoline and diesel and protecting users of transportation fuels from the volatility of the international oil market-it is largely the cost advantage, if any, that will determine the future attractiveness of natural gas vehicles. There are a number of technology pathways that could lead to greater use of natural gas in transportation. Some require pressurized systems to use natural gas in a gaseous state, and others convert natural gas to a liquid. Two of the most widely discussed options use compressed natural gas (CNG) and liquefied natural gas (LNG). Other technological approaches use liquefied petroleum gas (LPG), propane, and hydrogen. In addition, natural gas can be used to generate electricity to power electric vehicles. Increasing the use of natural gas to fuel vehicles would require creation of an extensive nationwide refueling infrastructure. Although a small number of CNG vehicles have been on U.S. roads for more than 20 years, CNG use has been limited to vehicles that return to a central garage for refueling each day, such as refuse trucks, short-haul trucks, and city buses. LNG, on the other hand, requires large insulated tanks to keep the liquefied gas at a very low temperature and is therefore seen as more suitable for long-haul trucks. In both cases, the limited availability of refueling stations has limited the distances and routes these vehicles may travel. Congress has taken a strong interest in spurring production and use of natural gas vehicles. Legislation has been introduced on a wide range of proposals that would equalize the tax treatment of LNG and diesel fuels, provide tax credits for natural gas vehicles and refueling equipment, require the production of vehicles that could run on several different fuels (such as gasoline and CNG), increase federal research and development on natural gas vehicle tank and fuel line technologies, and revise vehicle emission regulations to encourage manufacturers to produce more CNG passenger cars. Legislation pending in the 113th Congress includes proposals that would extend expired tax credits for refueling property and fuel cell vehicles (S. 2260), authorize the use of energy savings performance contracts to support the use of natural gas and electric vehicles (S. 761), and require the U.S. Postal Service to study the feasibility of using natural gas and propane in long-haul trucks (S. 1486).
Article
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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.
Article
Natural gas is considered the dominant worldwide bridge between fossil fuels of today and future resources of tomorrow. Thanks to the recent shale boom in North America, natural gas is in a surplus and quickly becoming a major international commodity. Stay current with conventional and now unconventional gas standards and procedures with Natural Gas Processing: Technology and Engineering Design. Covering the entire natural gas process, Bahadoris must-have handbook provides everything you need to know about natural gas, including: Fundamental background on natural gas properties and single/multiphase flow factors How to pinpoint equipment selection criteria, such as US and international standards, codes, and critical design considerations A step-by-step simplification of the major gas processing procedures, like sweetening, dehydration, and sulfur recovery Detailed explanation on plant engineering and design steps for natural gas projects, helping managers and contractors understand how to schedule, plan, and manage a safe and efficient processing plant Covers both conventional and unconventional gas resources such as coal bed methane and shale gas Bridges natural gas processing with basic and advanced engineering design of natural gas projects including real world case studies Digs deeper with practical equipment sizing calculations for flare systems, safety relief valves, and control valves.
Chapter
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.
Chapter
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.
Conference Paper
Global water demand is increasing whilst the renewable water resource is diminishing. This has resulted in an increase in demand for seawater desalination, with reverse osmosis (RO) accounting for 65% of the 80.9 million m3/day of desalted water produced globally in 2013. A prevailing concern is high energy demand and availability of fossil fuel resources, resulting in the drive for renewable energy powered desalination systems. In the near future, the increasing desalination demand can be met through SWRO plants powered by hybrid PV-Wind-Battery and Power-to-Gas (PtG) power plants at a cost level competitive with current fossil fuel powered SWRO plants.Hybrid systems allow for higher full load hours and optimal utilization of the installed desalination capacity. 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. The levelized cost of water (LCOW), which includes water production, electricity, water transportation and water storage costs, ranges from 0.59 €/m3 – 2.81 €/m3 for the 2030 desalination demand. The global system required to meet the 2030 global water demand is found to cost about 9790 billion € of initial investments. It is possible to overcome the water supply limitations in a sustainable and financially competitive way.
Article
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.
Article
Further development of the North-East Asian energy system is at a crossroads due to severe limitations of the current conventional energy based system. For North-East Asia it is proposed that the excellent solar and wind resources of the Gobi desert could enable the transformation towards a 100% renewable energy system. An hourly resolved model describes an energy system for North-East Asia, subdivided into 14 regions interconnected by high voltage direct current (HVDC) transmission grids. Simulations are made for highly centralized, decentralized and countrywide grids scenarios. The results for total system levelized cost of electricity (LCOE) are 0.065 and 0.081 €/(kW&h) for the centralized and decentralized approaches for 2030 assumptions. The presented results for 100% renewable resources-based energy systems are lower in LCOE by about 30–40% than recent findings in Europe for conventional alternatives. This research clearly indicates that a 100% renewable resources based energy system is THE real policy option.
Chapter
The purpose of this chapter is to provide an overview of the different water electrolysis technologies. In the introduction section, the general characteristics of water electrolysis (thermodynamics, kinetics, efficiency) are described. Main electrolysis technologies used to produce hydrogen and oxygen of electrolytic grade are then described in the following sections. Alkaline water electrolysis is described in Section 2.2, proton-exchange membrane water electrolysis in Section 2.3 and high-temperature water electrolysis in Section 2.4. For each technology, state-of-the-art performances are analyzed, limitations are identified and some perspectives are discussed.