preprint to be published in the proceedings of the 11th International Energy Conference, May 30-31, Tehran, Iran
Renewable Energy-based Synthetic Fuels Export Options for Iran in a Net Zero Emissions World Mahdi Fasihi, Dmitrii Bogdanov and Christian Breyer Lappeenranta University of Technology, Lappeenranta (Finland) E-mail:
[email protected],
[email protected]
Abstract With growing demand for LNG and transportation fuels such as diesel, and concerns about climate change and emission cost, this paper introduces new value chain design for LNG and transportation fuels and respective business cases for Iran, taking into account hybrid PV-Wind power plants. The value chains are based on renewable electricity (RE) converted by power-to-gas (PtG) or power-to-liquids (PtL) facilities into SNG (which is finally liquefied into LNG) or synthetic liquid fuels, mainly diesel, respectively. The RE-LNG or RE-diesel can be shipped to everywhere in the world. The calculations for the hybrid PV-Wind power plants, electrolysis, methanation (H2tSNG) and hydrogen-to-liquids (H2tL) are done based on both annual full load hours (FLh) and hourly analysis. Results show that the proposed RE-LNG or RE-diesel value chains are competitive for crude oil prices within a minimum price range of about 118 - 187 USD/barrel (24 – 31 USD/MBtu of LNG production cost) and 102 - 168 USD/barrel (0.68 – 0.86 €/l of diesel production cost), depending on the chosen specific value chain and assumptions for cost of capital, available oxygen sales and CO 2 emission costs. RE-LNG or RE-diesel could become competitive to conventional fuels from an economic perspective, while removing environmental concerns. The RE-PtX value chain needs to be located at the best complementing solar and wind sites in the world combined with a de-risking strategy. This could be an opportunity for Iran to use its abundant source of solar and wind and the available conventional fossil fuel transportation infrastructure to export carbon neutral hydrocarbons around the world where the environmental limitations on conventional hydrocarbons is getting tighter and tighter. Keywords: hybrid PV-Wind, Power-to-Gas (PtG), Gas-to-Liquids (GtL), Powerto-Liquids (PtL), Liquefied Natural Gas (LNG), economics, fuel-parity, Iran
1. Introduction Our planet is facing a dramatic climate change problem (IPCC, 2014) and fossil fuel-based CO2 emissions would be a limiting constraint for usage of fossil fuels in the long-term (Carbon Tracker, 2013; 2015). In the past years, voluntary and mandatory regulations have been set to limit fossil fuel emissions at different levels. Currently we see a starting phase-out of coal on a global level, for new investments but also for existing assets. For example, Ontario in Canada shuttered all its coal power plants by 2014 (Marshall, 2013) and the New York government aims to phase out coal by 2020 (Henry D., 2016). Vietnam stopped all new investments into coal (Nhu, 2016), international financial institutions set coal on par with child labour (King, 2016) and the largest coal producing company fell into bankruptcy (Kary et al., 2016). The phase-out of oil has also already prepared. For instance, Norway is considering banning the sale of new cars that are not electric from 2025 onwards (Morris, 2016). The phase-out of natural gas (NG) would be the next step.
Based on the COP21 Paris agreement, some certain countries, if not all, have to aim to reach a net zero emissions system by 2050 (UNFCCC, 2015). This means, in these countries, fossil fuel consumption could be completely banned, in particular since natural negative emissions such as growing forests are very limited and carbon capture and storage (CCS) technology is high in cost and risky. In addition, the unacceptably high costs of climate change may soon overshadow the desire for fossil fuels in the eyes of consumers worldwide, no matter how cheap they are. At the very least, this will result in drastic reductions in the consumption of fossil fuels, something that will result in serious challenges to exporting countries. To reach the goal of net zero emissions, fossil fuel-based energy demand could be mainly replaced by renewable electricity. The transition to 100% renewable energy systems for the power sector on national and regional levels has been already started all around the world, as indicated by a fast increase of renewable energy installed capacities (Farfan and Breyer, 2016). The financially beneficial projections for Iran and the MENA region for 100% renewables despite abundant fossil-based resources have been studied by
Aghahosseini et al. (2016a; 2016b). However, there are sectors such as aviation, shipping, heavy transportation and non-energetic application of fossil fuels where hydrocarbons cannot be replaced by electricity easily, or physically not at all. Biofuel production is faced with resource limitations and conflicts with food production and, therefore, no substantial substitute (Koizumi, 2015; Tomei and Helliwell, 2016). Net zero emissions could be achieved by a recarbonization of the energy system, whereby carbon from fossil sources is replaced by that which is created synthetically and sustainably, by the aid of renewable electricity (RE). These RE-based fuels are carbon neutral and can be used in the current fossil fuel-based infrastructure. As such, expertise in hydrocarbon refining may be highly advantageous. Thus, this may present new opportunities for countries that have traditionally relied on income from fossil fuel exports, such as Iran.
There are regions in the world, such as Europe and Japan, which do not have the RE-based power potential to answer this demand or the final production cost could be too expensive. Iran, with a high potential of solar energy and, to a lesser degree, wind power, can act as a carbon neutral oil well which can export a wide range of carbon neutral hydrocarbons. These can be also used domestically to satisfy local emission regulations and to overcome the environmental issues the country is facing (Naddafi, 2012).
There are several technical options to produce hydrocarbon fuels based on hybrid PV-Wind plants for the transport and mobility sector: mainly RE-PtG (Breyer et al., 2015), liquefied natural gas (LNG) based on RE-PtG (Fasihi et al., 2015a), RE-PtG-GtL (Fasihi et al., 2015b) and RE-PtL (Fasihi et al., 2016). All options can be used to buffer and store intermittent renewable electricity. Figure 1 illustrates a very simplified version of these value chains.
Figure 1: The PtX value chains. PtG-LNG (top), PtG-GtL (middle) and PtL (bottom).
Figures 2 to 4 show the simplified value chains of the whole process for these three technologies. The RE-PtG-LNG value chain is illustrated in Figure 2. 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.
Figure 2: 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.
Figure 3 shows the RE-PtG-GtL value chain. The main components are: hybrid PV-Wind plants, electrolyser and methanation plants, CO2 from air scrubbing
units, syngas production unit, Fischer-Tropsch (FT) plant, product upgrading plant and fuel shipping. The integrated system introduces some potentials for the utilization of waste energy and by-products. This will also result in the elimination of some sub-components of the integrated system, such as gas treatment facilities and oxygen production units, which will increase the overall efficiency and will decrease the costs.
Figure 3: The hybrid PV-Wind-PtG-GtL value chain. The main components are: hybrid PV-Wind plants, electrolyser and methanation units, CO2 from air scrubbing units, syngas production unit, Fischer-Tropsch unit, products upgrading unit and fuels shipping.
Figure 4 delineates the RE-PtL value chain. The main components are: hybrid PV-Wind plants, electrolyser and reverse water gas shift (RWGS) plants, CO2 from air scrubbing units, Fischer-Tropsch plant, product upgrading unit and fuel shipping. The integrated system introduces some potentials for the utilization of waste energy which will increase the overall efficiency and will decrease the costs.
This paper investigates the final product and production potential of these three different technologies and the corresponding cost based on Iran’s solar and wind potential. The paper is structured in a methodology section, results for an annual basis model and an hourly basis model, discussion and conclusions.
Figure 4: The hybrid PV-Wind-PtL value chain. The main components are: hybrid PVWind plants, AEC, RWGS units, CO2 from air scrubbing units, FT unit, products upgrading unit and fuels shipping.
2. Methodology The RE-Power-to-X (PtX) production system consists of three main parts: a, Renewable electricity production b, CO2 capturing and water desalination c, PtG, LNG, PtL and GtL value chain.
Two models are used to describe the power, CO2, H2 and SNG production for considerations on an annual, but also on an hourly basis. With the aid of storage technologies for electricity, H2, SNG and CO2, the rest of the corresponding value chains mentioned in section ‘c,’ can always run on a base load, leading to a reduction in cost for the final product. Thus, there would be only annual calculations for them. 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 for all PtX technologies. 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. No water or electricity transmission cost has been included in this model. The estimate on an annual FLh basis can be surprisingly accurate if applied carefully (Breyer et al., 2011a; Pleßmann et al., 2014). An important piece of information is the level of curtailment, or so-called critical 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 for Iran is 2-3% (Gerlach et al., 2011) and may be in cost optimized operation around 5% (Caldera, 2016a). This model will give a rough estimation of a system working with equal PV and wind power capacity.
The Hourly Basis Model uses the optimized 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-SNG or RE-diesel. In case of PtG, electrolyser and methanation plants are coupled and will work simultaneously and with a SNG storage system, the liquefaction or GtL plants can run on a base load. In case of PtL, hydrogen and CO2 storage systems will guarantee the feedstock for operation of the RWGS plant and subsequently the Fischer-Tropsch 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 combusted to produce electricity via a gas turbine as a backup system for the constant electricity demand of the RWGS unit.
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, η, annuity factor, crf, weighted average cost of capital, WACC, lifetime, N, performance ration, PR, overlap FLh, overlap.
𝐿𝐶𝑂𝐸𝑖 = crf =
𝐶𝑎𝑝𝑒𝑥𝑖 ∙crf+𝑂𝑝𝑒𝑥𝑖,𝑓𝑖𝑥 𝐹𝐿ℎ𝑖
WACC∙(1+WACC)N (1+WACC)N −1
+ 𝑂𝑝𝑒𝑥𝑖,𝑣𝑎𝑟 +
fuel 𝜂𝑖
(1) (2)
𝐹𝐿ℎ𝑃𝑉,𝑒𝑙 = 𝑃𝑉𝑖𝑟𝑟𝑎𝑑𝑖𝑎𝑡𝑖𝑜𝑛 ∙ 𝑃𝑅 𝐿𝐶𝑂𝐸𝑔𝑟𝑜𝑠𝑠 =
𝑊𝑖𝑛𝑑𝐹𝐿ℎ ×𝑊𝑖𝑛𝑑𝐿𝐶𝑂𝐸 +𝑃𝑉𝐹𝐿ℎ ×𝑃𝑉𝐿𝐶𝑂𝐸 (𝑊𝑖𝑛𝑑𝐹𝐿ℎ +𝑃𝑉𝐹𝐿ℎ )
𝐿𝐶𝑂𝐸𝑔𝑟𝑜𝑠𝑠
𝐿𝐶𝑂𝐸𝑛𝑒𝑡 = 1−overlap
(3) (4) (5)
2.1. Common sections 2.1.1. Hybrid PV-Wind power plant and battery In this research, hybrid PV-Wind power plants are taken into account as the source for renewable electricity. The hybrid PV-Wind power plants should be located in the regions of very high FLh to reduce the LCOE of power production and subsequently the LCOE of electrolysis. Figure 5 shows the FLh for hybrid PV-wind power plant sites in Iran, where the best sites are indicated by a red colour coding (Breyer, 2011b; Stackhouse, 2008). With about 6000 FLh, South Khorasan (S.K.) shows the highest potential of solar and wind in Iran. In this study, the study case plant for annual calculation is located on the border between Sistan and Baluchestan (S.&B.) and Kerman (K.) provinces, which is among the best places in Iran for solar and wind resources and close to the coast to make the power transmission cost and the power generation cost in total as low as possible. The produced RE-based hydrocarbons are assumed to be shipped to Japan or Rotterdam in the European Union. The general and Iranian hybrid PV-Wind plant specification can be seen in Tables 1 and 2.
Figure 5: Iran’s hybrid PV-Wind power plant FLh map.
Table 1: Hybrid PV-Wind power plant specification. Unit Amount PV fixed-tilted Wind energy Capex €/kWp 500 Capex Opex % of capex p.a. 1.5 Opex Lifetime years 35 Lifetime PV single-axis tracking Capex €/kWp Opex % of capex p.a. Lifetime years
Unit
Amount
€/kW % of capex p.a. years
1000 2 25
€/kWhel % of capex p.a. years %
150 6 15 90
Battery 550 1.5 35
Capex Opex Lifetime Cycle efficiency
Table 2: Iran’s hybrid PV-Wind power plant specification for the annual analysis scenario (case study) Unit Amount Unit Amount 2 Irradiation (single-axis) kWh/(m ∙a) 2410 PV single-axis h 2000 FLh PV performance ratio % 83 Wind FLh h 3700 (PR) PV yield kWh/kWp 2000 PV and Wind % 8 overlap Hybrid PV-Wind h 5244 FLh Installed capacities PV single-axis installed GWp 5 capacity Wind installed capacity GW 5
2.1.2. CO2 from ambient air scrubber To have a sustainable energy system with carbon neutral products, CO 2 needs to be obtained from a sustainable CO2 source. In this work, ambient air is the source of CO2, which is independent of the location, thus carbon supply would not restrict the best places for the PtX plant. The CO2 capture from ambient air approach from Climeworks (Climeworks, 2015a) 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 (Wurzbacher, 2014). In this case the output heat of the electrolysis and methanation or FT process 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 methanation or FT plant, utilized 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 13001700 kWhth of thermal energy at 100-110°C and 200-250 kWhel electricity (Climeworks, 2015b). The average numbers which have been used in calculations can be seen in Table 3. In case of a lack of internal heat, the heat from heat pumps could be used to deliver the heat needed for the CO 2 capture plant.
Table 3: CO2 capture plant specification Unit
Amount
Capex
€/(tCO2∙a)
356
Opex
% of capex p.a.
4
years
30
Electricity demand
kWhel/tCO2
225
Heat demand
kWhth/tCO2
1500
Lifetime
2.1.3. Water desalination The output water from the methanation or RWGS and Fischer-Tropsch 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 electrolysis has to be supplied from an external source. Due to high level of water stress in Iran (Caldera, 2016a), there might not be enough clean water available for electrolysis. The plant is located along the sea shore in the south of Iran, thus seawater reverse osmosis (SWRO) desalination could be used. Water desalination plant specifications can be found in Table 4. More details on RE-powered SWRO desalination plants are provided by Caldera et al. (2016b).
The PtX plants are built along the sea shore and electricity from the hybrid PVWind 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 fuel transportation cost to the port will be minimized as well. Table 4: Water desalination and storage plants’ specification (Caldera et al., 2016b) SWRO Desalination Capex Opex Lifetime Electricity consumption Water extraction efficiency
Unit
Amount
€/(m3∙a)
2.23
Unit Water storage Capex €/(m3∙a)
% of capex p.a. years kWh/m3 %
4.3
Opex
30 3.0 45
Lifetime
% of capex p.a.
Amount 0.0074 1.5 50
2.1. Power-to-Gas
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 6. Water and electricity are the inputs for the electrolysis plant, while electrical power converts water to H 2 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 (Bandi, 1995; Specht, 2009; Sterner, 2009).
Figure 6: Power-to-Gas (electrolysis and methanation) process.
Electrolysis: E + 2H2O → 2H2 + O2 + Q
(6)
Methanation: CO2 + 4H2 → CH4 + 2H2O + Q
(7)
Hydrogen can be produced by different types of electrolysers. The alkaline electrolysis cell (AEC) is well-known and a mature technology for water electrolysis (Millet and Grigoriev, 2013), while the proton exchange membrane electrolysis cell (PEMEC) (Millet and Grigoriev, 2013; Millet, 2015) and the solid oxide electrolysis cell (SOEC) (Millet and Grigoriev, 2013; Elder et al., 2015) are technologies in the commercialization phase or still under development. The reported costs for PEMEC and SOEC are higher and in a wider range than those for AEC in 2030 (Table 5). Alkaline high pressure electrolysis has been used in our model, as the lower capex for AEC is very important in achieving optimized SNG cost. A more detailed comparison for this selection can be found in Fasihi et al. (2015a) Table 5: Electrolysers’ specification Capex Opex Lifetime EtH2 eff. (HHV) Heat demand
Unit
AEC
PEMEC
SOEC
€/kW el
319
250-1270
625-100
% of capex p.a. years % % of inlet E
3 30 86.3 -
2-5 20 74-89 -
2-5 20 91-109 18-20
Methanation specification can be found in Table 6. Table 6: Methantion’s specification. Capex Opex Lifetime Efficiency
Unit
Amount
€/kWhgas
234
% of capex p.a. years %
2.14 30 77.9
2.2. Liquefied Natural Gas (LNG)
For distances of more than 2000 km, LNG transportation is cheaper than NG pipelines (Mokhatab, 2014). In this research, Japan, which has the highest LNG demand and price in the world (BP, 2015), has been chosen as the target market. Due to the large distance between Iran and Japan (approx. 12,000 km), NG
transportation via pipeline is not considered. Thus, LNG shipping and therefore a LNG value chain is required.
Figure 7 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. Then, it can be shipped to the destination by LNG carriers. At destination, LNG is heated up in regasification plants (Mokhatab, 2014) 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 (Canis, 2014).
Figure 7: RE-LNG value chain.
2.2.1 SNG liquefaction Generally, NG liquefaction efficiency is around 70-80% (Kotzot, 2007), 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 (Lewis, 2014). The gas treatment needed for the NG depends on the quality of each NG reserve. Figure 8 shows the maximum gas treatment process needed in LNG production from NG. Besides the increase in the energy efficiency and the elimination of these gas treating devices result in lower cost in comparison to NG liquefaction process. The cost distribution of a typical liquefaction plant is shown in Table 7 (Mokhatab, 2014).
Figure 8: Maximum gas treatment for LNG production from NG (Kotzot, 2007)
Table 7: Cost distribution of a typical liquefaction plant (Mokhatab, 2014) Gas treatment Liquefaction Fractionation Utilities and off-sites LNG storage and loading
Unit % % % % %
Amount 12 32 5 27 24
There is an increase in the cost of new liquefaction plants becoming operational in the next 5 years (Songhurst, 2014). The reason has been analyzed by Fasihi et al. (2015a) and the results show that the SNG-based liquefaction cost will remain at today’s level.
2.2.2 LNG shipping With today’s technology there are LNG carriers up to 200,000 m 3 capacity, but the common capacity for LNG carriers is 138,000 m 3 LNG (Kotzot, 2007; Bahadori, 2014a). 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 (Bahadori, 2014a). The assumed ship’s specifications can be seen in Table 8.
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 its simpler structure, a regasification plant has lower capital cost and higher lifetime and efficiency in comparison to liquefaction. The LNG value chain specification has been shown in Table 8 and the data have been gathered from Lochner and Bothe (2009), Castillo and Dorao (2010), Vanem et al. (2008), Khalilpour and Karimi (2012), Maxwell and Zhu (2011), Bahadori (2014b), and Neto and Sauer (2006). Cold energy out of regasification can be used in
cryogenic oxygen production. This could be an extra benefit from the system which can increase the competitiveness of the final product’s cost. In this analysis it is not taken into account.
Table 8: LNG value chain specification. 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 Lifetime years 25 Efficiency % 93 Capacity Mmtpa Shipping Availability Ship size Capex Opex Lifetime Boil-off gas Speed Charge & discharge time total Marine Distance LNG ships required
% m LNG m€/ship % of capex per annum years %/day knots days km -
Regasification plant Availability Capex Opex Lifetime Efficiency
% k€/mcm/a SNG % of capex per annum years %
3
95 138 151 25 0.1 20 2 17,5 2.huhti
95 74 30 98.5
2.3. Power-to-Liquids 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. 2.3.1. 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. 8), which are shown in Figure 9. CO2 obtained from ambient air by CO2 capture plants and H2 from electrolyser units are used in the endothermic process of RWGS (Kaiser et al., 2015) to produce carbon monoxide. A level of 800-900 ºC is a common temperature to operate the RWGS plant (König et al., 2015). Due to the high temperatures needed in this process, the energy demand for this process is supplied by electricity. In our model, hydrogen is stored in a hydrogen storage to get the RWGS plant operating on base load, thus batteries or an H2tG-GtP system is needed to supply this demand in the absence of fluctuating RE. The hydrogen storage capex is 0.015 €/kWhgas (König et al., 2015) and the gas turbine efficiency in 2030 is assumed to be 58%. The overall carbon conversion can be considered more than 95%, as in Sunfire’s approach (Sunfire, 2013).
Figure 9: Power-to-Syngas (electrolysis and RWGS) process.
Electrolysis: E + 2H2O → 2H2 + O2 + Q RWGS: CO2 + H2 → CO + H2O
(6) ∆H0 = 41 kJ/mol
(8)
RWGS with extra H2: CO2 + 3H2 → CO + 2H2 + H2O ∆H0 = 41 kJ/mol
(9)
Identical to the PtG section, based on costs and applications, the alkaline high pressure electrolysis has been taken into account in the used model for water electrolysis in the PtL system. A detailed comparison between different types of electrolysers and their applications in the PtL system can be found in Fasihi et al. (2016).
2.3.2. 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 (FT) and products upgrading (Wood et al., 2012).
The Fischer-Tropsch process converts syngas to different chains of synthetic hydrocarbons (-CH2-)n, which is also known as syncrude (Eq. 10). This reaction is highly exothermic (Graves et al., 2011). 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. More information about the characteristics of different types of FT synthesis are explained by Fasihi et al. (2015b). FT: n CO + 2n H2 → (-CH2-)n + n H2O
∆Hº = -209 kJ/mol
(10)
The syncrude contains hydrocarbons of different lengths. By adding hydrogen and hydrocracking of long chain syncrude, the hydrocarbons with a desired range of length can be produced in the upgrading unit. Equation 11 shows the simplified reaction at this step. If needed, the hydrogen used in this step can be supplied from storage. Products upgrade: (-CH2-)n + H2 → CnH2n+2
(11)
Starting from the syngas, the FT and syncrude hydrocracking are the common and last loops in both the GtL and PtL value chains. Thus, the final products of PtL are basically the same as for GtL plant products. Hydrocracked FT products in some publications are shown in Table 9.
Aiming for the maximum middle distillates share, the numbers provided by (FVV, 2013) 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 (Jensen et al., 2013), 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 (Glebova, 2013). Table 9: FT’s hydrocracked final product composition (vol. %). Abbreviations: liquefied petroleum gas, LPG. Middle distillates Lubes Source LPG Naphtha & Comment Jet fuel / Diesel Kerosene Wax Fleisch et al. (2002) 15-25 65-85 0-30 Brown (2013) 5 20 75 typical GtL Velocys (2015) 20 80 Chedida et al. 6 26 68 (2007) NPC (2007) 25 70 5 Khalilpour, Karimi 5 20 75 (2012) Bao (2010) 3 30 67 15 25 60 Diesel mode FVV (2013) 25 50 25 Kerosene mode
Table 10 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 specifications have been calculated by combining the technologies and cost breakdowns presented by Maitlis and Klerk (2013), König et al. (2015) and Fasihi et al. (2015b).
Table 10: 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 % 71 naphtha % 15 jet fuel % 25 Products diesel % 60
2.3.3. 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. These ships can carry a weight of approximately 90% of their DW (EIA, 2014). The shipping specifications are shown in Table 11, assuming shipping from Iran to Rotterdam. The data have been taken from Konovessis (2012), MAN (2013), Sea distances (2015), UNCTAD (2009) and Khalilpour (2012).
Table 11: Shipping specification Unit Capex m€/ship Opex % of capex p.a. Lifetime years Availability % Ship type large range 2 (LR2) Ship size ton (deadweight) Speed knots Charge and discharge time days total Marine distance km
Amount 48 3 25 95 100,000 14 2 12,000
2.3. Gas-to-Liquids
The GtL process provides the opportunity to convert NG or SNG to liquid fuels through a series of chemical reactions. The GtL process consists of three main steps: syngas production, Fischer-Tropsch (FT) and products upgrading (Wood et al., 2012). The last two steps and the shipping of the products are the same as PtL process. However, the syngas production in this model is different and is explained below.
SNG, as the output of the PtG plant, is the feedstock for the GtL plant. In the first step, SNG needs to be converted to syngas (mixture of CO and H 2) as the feedstock for the FT section. The desired CO:H2 ratio for the FT process is 1:2. There are different reforming technologies to produce syngas from natural gas, explained by Fasihi et al. (2015b).
Catalytic partial oxidation (CPO) (Eq. 12), provides the syngas with the desired CO:H2 ratio for the FT process, but air separation units (ASU) are needed to produce the required oxygen for this reaction. The cost of an air separation unit is reported to be at least 8% of the capital cost of GtL facilities (Maitlis and Klerk, 2013). CPO: CH4 + 0.5 O2 → CO + 2H2
∆H0 = -38 kJ/mol
(12)
In our model, pure oxygen is already available as the by-product of electrolysis in the PtG plants. Thus, partial oxidation is the technology that makes the most sense for syngas production within the approach of this paper. The real model would not be this simple and efficient. CO2 would be produced in the following side reaction: CH4 + 2 O2 → CO2 + 2 H2O
(13)
This technology is used by the Shell middle distillates synthesis (SMDS) plant in Bintulu, Malaysia, and the carbon to CO conversion is reported to be 94% (Hoek, 2006). The CPO reaction happens at high temperatures, about 1000 °C, and the released heat in this reaction is used to keep it in an autothermal mode (Al-Sayari, 2013) and cannot be used for other purposes.
As mentioned earlier, the rest of the GtL value chain is the same as for the PtL system. Table 12 shows all the assumptions for the specifications of the GtL plant in the model used in this paper. Table 12: GtL capital expenditures breakdown (Maitlis and Klerk, 2013) Capex Opex Lifetime Availability Efficiency
Unit k€/bpd % of capex p.a. years % %
Amount 60 3 30 95 71
capital expenditures breakdown Air Separation Unit Syngas Unit Hydrogen Unit FT Unit Upgrading Units Water Disposal Unit Utilities Offsites
% 8 18 6 24 5 3 16 20
3. Results 3.1. Annual basis model
3.1.1. Energy and material flow Integrating all the system’s elements offers some chances to increase the overall efficiency. Figure 10-12 show the Sankey diagrams of the entire system, depicting the energy and material flows within the entire RE-PtG-LNG, RE-PtGGtL and RE-PtL value chains, respectively. The figures are the example of a system with 1 MWhel specific electricity input.
As can be seen in Figure 10, the electrolyser, at 97%, is the main electricity consumer in the PtG-LNG value chain, while the excess heat out of the electrolyser and the methanation plant is the main source of energy for the CO 2 capture plant. In total, 58.1% of inlet electricity would be delivered in Japan or Rotterdam as SNG (HHV).
Figure 10: RE-PtG-LNG energy and material flow diagram.
Figure 11 shows the energy and mass flow for the PtG-GtL value chain. As can be seen, the alkaline electrolyser, at 97%, is the main electricity consuming element, while the excess heat by-product of the electrolyser and the methanation plant is the main source of energy for the CO2 capture plant. The heat released in the FT process accounts for 14% of initial electricity and 22% of
the energy content of inlet SNG to the GtL system. The overall PtG-GtL efficiency of this system, without FT heat utilization, would be 42.5%, while 65% of inlet SNG is converted to liquid fuels in the GtL 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.
Figure 11: RE-PtG-GtL energy and material flow diagram.
Figure 12 illustrates the energy and mass flow for the PtG-PtL value chain. 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.
Figure 12: RE-PtL energy and material flow diagram.
3.1.2. Production cost The production cost of each value chain has been broken down into different steps. Calculations are done based on cost numbers explained in the methodology section. All the general assumptions in the calculations of the base case can be found in Table 13.
Table 13: General assumptions in base case calculations WACC Exchange rate Brent crude oil price FLh of all sectors
Unit % USD/€ USD/bbl h
Amount 7 1.35 80 5244
Figure 13 shows the levelized costs in the RE-PtG-LNG value chain with two scenarios for the weighted average cost of capital (WACC) of 7% and 5%. The RE-PtG-LNG cost distribution as a share of the total is not dependent on the WACC. Methanation and hybrid PV-Wind power plants have the highest share (47% and 35%, respectively) of the total cost. At 18%, the 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 5% and 3%, respectively.
Figure 13: RE-PtG-LNG value chain cost breakdown for WACC of 5% (top) and 7% (bottom).
Water and CO2 costs are included in the 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 37% of the cost of this process. At 9.38 €/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 CO 2 scrubbing process (Figure 10). With the base scenario, the final cost of RE-SNG in Japan would be 84.5 €/MWhth,gas, which is equal to 192 USD/bbl or 33 USD/MMBtu.
Figure 14 shows the levelized costs in the RE-PtG-GtL value chain. GtL and methanation have the highest share (43.4% and 31.7%, respectively) in the total cost. At 1%, shipping has the lowest share in this process.
Figure 14: RE-PtG-GtL value chain cost breakdown for WACC of 5% (top) and 7% (bottom).
The water cost in the PtG-GtL process is 40% less than for the PtG-LNG value chain. This is due to additional recycled water from FT in the GtL system. (Figure 11). For the assumptions of the base case scenario, the final cost of RE-diesel in Rotterdam would be 125 €/MWhth, which is equal to 284 USD/bbl, 49 USD/MMBtu or 1.2 €/l of diesel.
Figure 15 shows the levelized costs in the RE-PtL value chain. H2tL and the hybrid PV-Wind plant have the highest share (50.8% and 33.8%, 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. Electrolysis represents 14.2% of the final product’s cost, while at 7.8 €/MWhth,H2, the share of the electrolysis plant itself in the final cost of hydrogen production is 62%, and energy losses in electrolysis account for 37.6% of the cost of this process.
Figure 15: RE-PtL value chain cost breakdown for WACC of 5% (top) and 7% (bottom).
Water cost is also included in the hydrogen production (electrolysis) section of the value chain. At 0.06 €/MWhth,H2, the cost of water is almost negligible. At 13.8 €/MWhth,fuel, the cost of CO2 has a 30.6% 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 (Figure 12). At 16.63 €/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 88.45 €/MWhth, which is equal to 200 USD/bbl, 34.6 USD/MMBtu or 0.86 €/l of diesel.
A summary of all production costs for the base scenario can be found in Table 14. RE-diesel based on RE-PtG-GtL is 42% more expensive than RE-diesel based on the PtL chain. Thus, PtL based fuels are preferred and GtL results will not be further analyzed in this paper.
Table 14: Production cost in the base scenario Renewable Electricity (RE) CO2 Desalinated water
Unit €/MWhel €/tCO2 €/m3
Amount 29.85 52.73 0.65
RE-H2 RE-SNG RE-LNG at production site Regasified RE-SNG at destination
€/MWhth €/MWhth €/MWhth €/MWhth
42.44 69.58 78.25 84.54
RE-PtG-GtL average product at production site RE-based FT-diesel at destination
€/MWhth €/MWhth
123.76 124.98
RE-PtL average product at production site RE-based FT-diesel at destination
€/MWhth €/MWhth
87.41 88.45
3.1.3. Business case and cost drivers for reaching fuel-parity As discussed in the introduction, by 2030 there would be countries which may only demand carbon neutral hydrocarbons. However, in general the SNG and RE-diesel should compete with NG and conventional diesel in the market, taking into account additional costs for environmental and health-related damages. Crude oil price, weighted average capital cost (WACC), CO2 emission cost and the benefit from oxygen can effect this competitiveness. The health-related costs of fossil fuels are not taken into consideration for this analysis.
The price of NG and conventional diesel is a function of the crude oil price and in the case of diesel, also a function of refining cost. The 30 year average ratio of LNG price in Japan to crude oil price is 102.3% (Fasihi et al. 2015a) and the 13 year average ratio of one barrel of diesel cost (crude oil consumption and refinery cost) to crude oil price is 118.76% (Fasihi et al., 2015b). For a WACC of 7% in the base scenario, the cost of debt and return on equity are 5% and 12%, respectively, with 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.
CO2 emission cost for fossil fuels can have a significant impact on the competitiveness of RE-SNG or RE-diesel, and NG or conventional diesel, as it increases the total cost of fossil fuels. The NG and conventional diesel carbon emissions are 15.3 and 20.2 tC/TJ (ton carbon per tera joule) (IPCC, 1996), which are equal to 56.07 and 74.02 tCO2/TJ, respectively (201.8 and 266.5 kgCO2/MWhth, respectively). The effect of the additional cost of CO2 emissions with a maximum price of 50 €/tCO2 on the NG and conventional diesel price have been considered in this paper. It has to be noted that the real cost of CO2 emissions are 70-80 €/tCO2 (Agora Energiewende, 2016), therefore the difference has still to be accounted as a subsidy paid by societies for using fossil fuels. RE-based synthetic fuels do not induce such subsidies.
In the case of a potential market, oxygen as a byproduct of the electrolysis can also have a very important role in the final cost of produced synthetic fuels. The market price of oxygen for industrial purposes can be up to 80 €/tO2 (Breyer et al., 2015). However, 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 utilization in the base scenario. The projection of a maximum 20 €/t O2 benefit from oxygen utilization is assumed in this study.
In summary, an increase in crude oil price or CO2 emission cost will increase the cost of NG and conventional diesel, while a profitable business case for O 2 or a reliable business case at a de-risked 5% WACC level can lead to lower cost for RE-synthetic fuels. The effects of all these potential game changers have been summarised in Figure 15. The price of diesel in the EU is based on:
the global crude oil price as depicted in Figure 15 for a price range of 60 – 200 USD/barrel,
two scenarios for CO2 emission cost,
two scenarios for benefits from O2 sales, and
the cost of delivered RE-SNG or RE-diesel based on two different WACC levels
All projections are for the year 2030.
Figure 16: Different scenarios for the RE-SNG price in Japan and RE-diesel in the EU based on the production costs in Iran. 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 cost), while the RE-diesel cost varies from 65 – 88 €/MWhth (depending on WACC and O2 benefit), i.e. for 103 USD/bbl, 50 €/tCO2, 5% WACC and 20 €/tO2 the RE-diesel is competitive to the conventional one without any further assumptions.
With 85 €/MWhth, RE-SNG has a lower production cost in comparison to 89 €/MWhth for RE-diesel. On the other hand, the market price of diesel per unit of energy is higher than natural gas. Moreover, CO2 emissions of diesel per unit of energy are more than NG, thus CO2 emission cost would have a greater impact on the price of conventional diesel. Thus, in total, RE-diesel can reach market parity at lower crude oil prices. This market party can be also called fuel-parity, since for the applied assumptions the fossil and RE-based fuels result in the same cost in the target markets. The fuel-parity concept and its impacts are further explained by Breyer et al. (2011c). 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 103 USD/bbl. While RE-diesel produced under the base case (WACC of 7%, no CO2 emission cost and no O2 sales) can reach fuel-parity with conventional diesel whenever the crude oil price is higher than about 164 USD/bbl. In the case of RE- SNG the first breakeven point can be expected for a crude oil price of 118 USD/bbl and for the base scenario, it can compete with conventional diesel whenever the crude oil price is higher than about 187 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 (OECD, 2013).
3.2. Hourly basis model Iran’s carbon neutral SNG, LNG and synthetic liquid fuel generation potentials have 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 PtG plant is located along a sea shore, thus the cost of power lines from hybrid PV-Wind plants to a PtX plant and the loss of power along the transmission lines are included in the model. The sample models are designed for a PtG and a PtL system with a specific constant synthetic fuel output (with the aid of SNG or liquid fuel storage). 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.
3.2.1. Hybrid PV-Wind FLh FLh have a major role in the final product cost. 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 17. With up to 4600 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. Single-axis tracking PV systems have higher FLh in comparison to fixed tilted solar systems, which makes it more competitive in sunny regions, despite of higher capex.
The PV FLh show an almost even level in most parts of the country, with a slightly
better potential in the southern part. On the other hand, there is a wider range in minimum and maximum FLh of wind in Iran. With 3000 FLh, the regions located in the Alborz or Zagros Mountains have a relatively high wind potential, while the best wind potential is available in the eastern part of Iran. The cumulative FLh of PV and wind reaches 6000 FLh in the eastern part of Iran, along the border with Afghanistan, which seems a perfect place for power generation. But the long distance to the sea and the corresponding transmission line cost could have a negative effect on that.
Figure 17: PV fixed tilted FLh (top, left), PV single-axis tracking FLh (top, right), wind FLh (bottom, left) and hybrid PV-Wind cumulative FLh (bottom, right) for the cost year 2030.
3.2.2. Levelized cost of electricity Besides FLh, the levelized cost of electricity (LCOE) has a key role in the cost of synthetic fuels. Figure 18 shows Iran’s electricity production cost of fixed tilted
and single-axis tracking PV systems and wind energy in 2030. Single-axis tracking PV generates cheaper electricity and as shown in Figure 17, as it has higher FLh. Thus, only single-axis tracking PV system has been installed in our model. The minimum wind electricity generation cost with 2030 technology and cost would be 24 €/MWh, but unlike PV, it is limited to certain regions such as the eastern part of Iran and the mountainous regions in the north.
Figure 18: Levelized cost of wind electricity (top), PV fixed tilted (bottom, left) and PV single-axis tracking FLh (bottom, right) for the cost year 2030.
3.2.3. Cost optimised hybrid PV-Wind plants and LCOE Although PV is the cheaper option in most regions, an optimal capacity of wind would also be installed in each node to increase the FLh of delivered electricity to the PtX plants, in order to minimize the cost of the final synthetic fuels, by
maximizing the operating time of the costly PtX plants. A different configuration of PtG and PtL plant results in a slightly different optimal combination of PV and Wind for these two systems, but the FLh of electrolysers as the main consumer of electricity in the PtX systems, show a slightly higher difference for the PtG and PtL configuration. Figure 19, shows the share of installed capacity of single-axis tracking PV and wind plants, in the optimal hybrid PV-Wind power plant configuration and the corresponding FLh of electrolysers for the PtG and PtL system. The figure indicates that PV would be the dominating installed technology in the cost optimal system, while, by 40%, wind would have its maximum share in the north-east and the eastern part of Iran.
Figure 19: Ratio of PV to hybrid PV-Wind plant installed capacity (top), FLh of electrolysers in the PtG system (bottom, left) and FLh of electrolysers in the PtL system (bottom, right) for the cost year 2030.
Figure 19 also shows that the FLh of electrolysers for the PtG system are about 500 hours higher than the FLh of electrolysers for the PtL system. This is because in the PtG system, electrolysers and methanation units are handled as coupled units and this represents a device with higher capex in comparison to the independent electrolysers in the PtL system, which are decoupled from the rest of the system by hydrogen storage. Thus, in the PtG system, it is more cost efficient to keep the electrolysers running for a longer time. The FLh of electrolysers are significantly higher in regions with a relatively high share of wind capacity.
The optimal combination of PV (single-axis tracking) and wind (Fig. 19) and their corresponding LCOE results in the LCOE of the hybrid system, shown in Figure 20. Least cost sites of the hybrid system which are mainly dominated by PV have an LCOE of 22-24 €/MWh. But the transmission line cost and the level of overlap and curtailment affect the price and amount of delivered electricity to the coast in the southern part of Iran. For an optimal hybrid PV-Wind power plant located in central Iran, the percentage of excess electricity transmitted to the coast for PtG and PtL systems would be about 9% and 7%, respectively. The higher curtailment of electricity for PtG is due to the demand for higher FLh of electrolysers in the PtG system as shown in Figure 19. To provide higher FLh of electricity for electrolysers in the PtG system, a higher level of curtailment would be applied to the fluctuating renewable electricity, in order to balance it with the transmission line cost. On the other hand, up to 2% of the hybrid PV-Wind power plant’s annual generation would be stored in batteries (mainly in regions with a higher share of installed PV) for the PtL system. This is the other reason for lower excess electricity in the PtL system. No significant amount of batteries is installed for the PtG system. The farthest site in Iran to the southern coast is about 1200 km and the transmission line cost in most regions with a distance of up to 1000 km would not exceed 10-12 €/MWhel. Finally the cost of delivered electricity to the PtG and PtL systems on the coast would be about 30-45 €/MWhel, with a slightly lower delivery cost for the PtL system.
Figure 20: Levelized cost of electricity of hybrid PV-Wind (top), excess electricity in percentage of generation for the PtG system (center, left) and the PtL system (center, right) and levelized cost of electricity delivered for the PtG system (bottom, left) and the PtL system (bottom, right) for the cost year 2030.
3.2.4. Levelized cost of synthetic fuels The price and FLh of delivered electricity to the PtG plants will result in the SNG production cost illustrated in Figure 21. The generated SNG can be stored in a methane storage tanker. Thus, with a constant SNG flow, the downstream liquefaction plant can work on base load. The cost of produced LNG and the regasified SNG in Japan is also shown in Figure 21. The cost difference between LNG and regasified LNG stands for LNG shipping and regasification. With a minimum production cost of 100 €/MWhth,fuel, RE-diesel production cost is about 10% higher than SNG, but it would be cheaper than regasified LNG in Japan per unit of energy.
Figure 21: Cost of SNG (top, left), cost of LNG (top, right), cost of regasified SNG in Japan (bottom, left) and cost of synthetic liquid fuels (bottom, right) for the cost year 2030.
3.2.5. Optimal RE-PtG and RE-PtL installed capacities The sample case can be scaled up to generate more electricity and synthetic fuels. A maximum 10% of land is allowed for PV and wind installation. Figure 22 illustrates the optimal installed capacity potential of hybrid PV-Wind, PtG and PtL plants. The optimal installed capacity potential of hybrid PV-Wind for the PtL system is about 5% more than hybrid PV-Wind for the PtG system. This is due to the slightly higher share of PV in the PtL system which reaches its installation area limit at higher capacities in comparison to wind. On the other hand, with 1308 GW output, the optimal installed capacity potential of PtL is only 38% of the optimal PtG installation potential. Because, with the aid of hydrogen storage, the downstream part of PtL system (RWGS and FT) would be operated on base load, while in the PtG system it is directly connected to the source of power, thus the operating time of the system is shorter, but at a higher level of capacities.
Figure 22: Optimal hybrid PV-Wind FLh installed capacity potential for PtG (top, left), optimal hybrid PV-Wind FLh installed capacity potential for PtL (top, right), optimal PtG installed capacity potential (bottom, left), and optimal PtL installed capacity potential (bottom, right) for the cost year 2030.
3.2.6. Optimal Hybrid PV-Wind, RE-PtG and RE-PtL annual generation potential The installed capacities mentioned in Figure 22, result in the production potential of electricity, SNG and RE-diesel illustrated in Figure 23. As can be seen, the higher installed capacity of hybrid PV-Wind for PtL, results in higher production of electricity. However, the 11,455 TWh of the annual production of synthetic liquid fuels would be lower than the 12,294 TWh of the SNG production. This is due to lower efficiency of the PtL chain in comparison to the PtG system. Taking into account the efficiency of the LNG value chain, the delivered product in the target market would be 10,924 TWh, which is lower than the PtL production.
Figure 23: Optimal hybrid PV-Wind FLh annual generation potential, for PtG (top, left), for PtL (top, right), optimal PtG annual generation potential (bottom, left), and optimal PtL 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 24 presents the optimal annual PtG and PtL production volume sorted in order of the specific generation cost. The minimum PtG and PtL production cost are 90 and 101 €/MWhth,fuel. A maximum of 11,000 TWhth SNG and 7,000 TWhth synthetic fuels can be produced for costs less than 120 €/MWhth,fuel in Iran. Obviously, to boost the volume of cheap fuel production, desirable nodes can be completely covered by solar PV plants or wind farms, if their site is outside of a residential region.
Figure 24: PtG and PtL industrial cost curve for cost optimized production based on hybrid PV-Wind power in a cumulative (up) and a spectral (bottom) distribution for the cost year 2030.
4. Discussion and conclusion There is no place for fossil fuels in a fully sustainable energy system, due to their emissions (UNFCCC, 2015). 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, shipping, heavy vehicles in all cases and in particular in some industries for non-energetic use. Thus, renewable electricity based fuels are essential to fulfill this demand. PtG and PtL plants can convert RE to RE-SNG or RE-diesel and other fuels into a liquid phase. To have a carbon neutral product, CO2 needed for this process should be captured from ambient air, and water desalination should be applied whenever there is a certain level of water stress in the region. Using AEC, all the technologies for these energy systems, except RWGS, already exist on a commercial scale and they can become operational whenever investors decide to go for it (Dimitriou et al., 2015). However, the system cannot run if the final product is not cost competitive.
This study shows that, for the base scenario for the case study, RE-diesel produced in Iran in 2030 can reach fuel-parity with RE-diesel in the EU for a crude oil price of 168 USD/bbl and RE-SNG produced in Iran can compete with regasified NG in Japan whenever the crude oil price is more than 187 USD/bbl. These are more than the prices of conventional fossil diesel or NG in today’s markets. There are different factors which can improve the competitiveness of RE-diesel with conventional fossil diesel in the long-term and not all of these factors are internal issues related to this energy system.
-
The 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.
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Environmental problems and fuel quality will put additional costs on the conventional fossil diesel price. A 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 sulphur-free SNG and synthetic diesel can be considered as one of the main substitutions, also for a production cost 50-100% higher than conventional fossil diesel.
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The by-products of the RE-PtX value chain can play a significant role in some regional cases, if not globally. A RE-PtX plant located in a region with a high demand for oxygen can decrease the production cost of diesel by about 20%. For this matter, a study on oxygen demand in Iran is essential.
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The 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%. Iran is one of the most stable countries in the region. Further improvement of this strength will encourage investors to choose Iran for their investment in this sector.
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The production cost of synthetic fuels is not the only factor to choose one as the best option. Preference also depends on each one’s application and the corresponding demand. The simple question would be that if the production cost were the same, which one would be chosen by the end consumer?
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On the other hand, when it comes to competition with conventional fuels, the situation is clearer. Historically, NG and diesel prices have been a function of the crude oil price. And diesel has a higher price per unit of energy in comparison to NG, thus the first business cases depend on both production cost of synthetic fuels and also the market price of conventional
fuels. Currently, the cost of delivered LNG in Japan (produced in Iran), is 4 €/MWhth cheaper than RE-diesel. But the market price of conventional diesel is 6.5 €/MWhth more expensive than NG. Thus, even with a higher production cost, RE-diesel can reach fuel-parity sooner. Applying CO2 emission cost would also be more effective for the RE-diesel case because the CO2 emission from 1 MWhth diesel is more than that from 1 MWhth NG. Thus, in the presence of CO2 emission cost regulation, RE-diesel can reach the fuel-parity even faster. On the other hand, despite the common application of NG and diesel, each one could also have its own application or preferred role. For example, gas turbines have a higher efficiency, which can result in a cheaper electricity production.
Thus, we see a decent market potential for both SNG and RE-diesel in 2030, which Iran can address and gain a significant share. For a least cost combination with maximum 10% land usage for PV and wind, Iran can produce annually about 8000 TWhth of synthetic liquid fuels (from that 4800 TWhth RE-diesel) or 9000 TWhth of SNG with the price range of 105 – 150 €/MWhth or 92 – 140 €/MWhth, respectively. For good sites located in desert areas, the installation can easily go beyond 10% of land usage to boost the low cost production. The optimal hybrid PV-Wind installed capacity potential for PtG and PtL systems in Iran is about 7980 GW and 8460 GW, respectively. Due to lower LCOE generated by PV, it has the main share of installed capacity. For instance, for the PtL system, the potential installed capacities of PV and wind would be 7700 GW and 760 GW, respectively. For regions with lower FLh of wind, such as the southern part of Iran, PV is the only installed option. The best regions for PtX plants depend not only on the cost and FLh of generated electricity, but also on the distance to the coast. The southern part of Iran with an approximate maximum of 500 km from the coast, Isfahan and South Khorasan providence represent the best regions for the minimum production cost. As discussed in the Introduction, the world’s energy system will become mainly electrified in future, thus the market size for hydrocarbons would shrink to mainly aviation, heavy vehicles, and non-energetic industrial applications. Even for these matters, there would be more and more restrictions on fossil-based hydrocarbons
due to environmental issues and emissions cost, in particular due to the global net zero agreement at the COP21 in Paris. Iran, with huge reserves of oil and NG and a high dependency on fossil fuel-based exports, should get ready for this change in the global energy markets as soon as possible. For this matter, Norway could be the best example and role model for Iran. Iran should increase its oil and gas export as much and as fast as possible, because there would not be much demand in some decades. At the same time, Iran should start decarbonizing its energy system as fast and as much as possible. The extra profit from boosted fossil fuel exports can be used to finance the investments for the recarbonization of Iran’s energy system and to finance the PtX projects. This source of capital is what many countries with high potential of solar and wind are missing to run this dense capital expenditure project. Following such a pathway, Iran can also meet its commitment to the COP21 agreement and also can remain a hydrocarbon exporter, using the exciting infrastructure. In addition, this transition and the investment in RE technologies can make Iran a forerunner and exporter in the growing market of RE-based technologies. Otherwise, in some decades, Iran may lose its main source of income and can turn from an energy exporter to REtechnology importer to run RE-based power plants. In sum, renewable electricity and RE-synthetic fuels will have the main roles in the world’s future energy system. Iran, with abundant solar potential and substantial earnings in today’s fossil fuel business to be used for RE and PtX project financing, has a great potential to be a main player in this transition.
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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