Introduction

The era of global boiling follows the era of global warming, recording the hottest month in 2023. Furthermore, given that the rise in global temperature is definitely due to greenhouse gas (GHG) emissions, even the hotter months await us if the GHG emissions keep increasing. Thus, to mitigate the global boiling by reducing GHG emissions, various technical efforts have been made for industrial sectors especially the energy sector which is the majority of the global emissions. The main strategies for the energy sector include near-term technologies such as combining carbon capture into conventional plants, and long-term technologies such as electrification of plants, and alternating energy sources with new and renewable energies. As one of the representative new energies, hydrogen (H2) has been spotlighted given its high gravimetric energy density and clean combustion without carbon emissions. Even though the H2 does not emit GHG during combustion, its current production processes such as steam methane reforming (SMR) emit significant amounts of carbon dioxide making its life-cycle highly carbon-positive. Thus, cleaner production processes are required for H2 to become a future sustainable energy source and one of the possible processes for cleaner production of H2 suggested so far is water electrolysis with renewable electricity which produces green H2. Here, the most important thing for green H2 to be stably produced is the stable and sufficient supply of renewable electricity. However, the capacity of renewable energy is significantly varied by global region, so several countries can produce more H2 than their domestic demands while other countries cannot meet their domestic demands by their own production. Thus, it is clearly considered that the international trade of green H2 will be necessary in the future for H2 to become a major energy source worldwide and various possible projects have been announced so far, mainly in several major countries including Korea, Japan, Australia, to name a few, as presented in Table 1.

Table 1 Announced projects for international trade of H2
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Among the various projects presented in Table 1, Australia, Japan, and the Republic of Korea are the majorities preparing international trade of green H2 for compensating the imbalance of their capacity and demand. Currently, the Korean Ministry of Trade announced a report for the H2 economy in 2021 containing detailed targets related to the production amount of H2 in the future as presented in the Fig. 1 [17]. According to the report, the Republic of Korea is planning to produce domestic clean H2 of more than 1 million tons annually by 2030 and 5 million tons by 2050 and import overseas clean H2 of about 2 million tons annually by 2030 and 23 million tons by 2050.

Fig. 1
figure 1

Announced national targets related to the production amount of H2 in the Republic of Korea

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At the same time, numerous large-scale renewable energy generation sites are under construction and even already powered on in Australia to utilize abundant renewable energy sources which are sufficient to fulfill domestic demands and export yield energy as well. Renewable energy capacities of each state and territory are presented in Fig. 2a and it is clear that most of the large-scale generation sites are in Eastern Australia including Queensland, New South Wales, and Victoria accounting for more than 80% of the total capacity of Australia [18]. Among the various projects for the generation of renewable energy in Eastern Australia, three representatives including Sun Metals solar farm, Macintyre wind farm, and Collinsville wind farm are considered in this study as presented in Fig. 2b [19,20,21]. Here, a H2 hub named ‘SunHQ’ is under construction at the site near the Sun Metals solar farm in Townsville so this hub is considered for the production of green H2 with renewable energy [22].

Fig. 2
figure 2

Australia Nation’s renewable energy a industry powered on in 2022 and b some representative projects in Eastern states

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In line with the trends, the economics and sustainability of the green H2 supply pathway between Australia and Korea are analyzed in this study, with unit cost and GHG emission of supplied H2 by currently suggested representative pathways. As Fig. 3 presents, the scope of consideration for the pathways includes renewable electricity generation with both solar photovoltaic (PV) and wind power, water electrolysis H2 production, H2 transmission from production site to exporting port, synthesis of ammonia (NH3) which is considered to as a H2 carrier, NH3 storage in both exporting and importing port, NH3 ship transportation, reformation of NH3 to H2 with cracking, and the final storage of H2 in Korea.

Fig. 3
figure 3

Overall schematic diagram of the considered pathway for supplying green H2 from Australia to Korea

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Methods

Before estimating the expenditures and emissions from the whole supply chain of green H2 trade pathways, a detailed scope with supposed technologies for each process and real conditions of project sites are required to be structured. Thus, the structured scope of the whole project pathway is demonstrated in Fig. 4. Two representative cases are considered with a base scenario for the first case and a more optimistic scenario for another case. First, the capacity of renewable electricity mixed with solar PV and wind energy is assumed to be 600 MW and different percentages of each renewable energy are considered for the two cases. Also, the Macintyre wind farm which is about 1500 km away from the H2 production hub is considered for case 1, while another wind farm named Collinsville about 200 km far from the hub is considered for case 2. For the water electrolysis base production of green H2, there are three representatives of the electrolyzer type including alkaline electrolyzer, proton-exchange membrane (PEM) electrolyzer, and solid-oxide electrolyzer [23]. Among the types, the PEM electrolyzer is considered in this study, given that it currently reached a commercialization level, operates at a comparatively higher pressure and current density resulting in high efficiency and purity, and also can be smoothly linked to renewable energy due to its short start-up time [23]. Of the renewable power produced at a total scale of 600 MW, 500 MW is assumed to be used to produce green H2 and the rest energy to other required processes in Australia including H2 transmission, NH3 synthesis, and storage. Thus, green H2 is produced about 88,000 tons annually in Australia, so the corresponding NH3 production is about 497,000 tons annually. The produced H2 at the production site is required to be transmitted to the exporting port in Australia, and the existing Townsville port is considered in this study. For the transmission, the H2 pipeline is considered to be used due to the large amount (88,000 tonH2 y−1) and short distance (15 km) between the site and port. Before the transportation of H2 from Townsville in Australia to the port of Korea, it is commonly required for H2 to be conditioned into the form of liquid-state carriers such as liquid H2 (LH2), liquid organic H2 carrier (LOHC), and NH3, given that the gaseous H2 itself has a significantly low volumetric energy density making its transportation economically uncompetitive and unstable [24]. As Table 1 presents, most of the current projects are considering NH3 as a feasible H2 carrier for their supply pathways, and it is due to its appropriate H2 contents (~ 17 wt%), and ease of storage compared to the other types of carrier, so NH3 is considered to as the H2 carrier in this study as well. Here, numerous researches have been conducted to develop a new technique for synthesizing NH3 rather than the conventional Haber–Bosch (H–B) process which emits significant amounts of GHG, however, there is no industrial-scale alternative yet [25], so the currently possible H-B process is considered, remaining the possibility of emission reduction through alternation of this process in the future. The synthesized NH3 will be stored near the Townsville port followed by transportation to Korea with a conventional vessel which is fueled by marine diesel. Thus, additional emission reduction may be expected in this transportation process by considering other eco-friendly vessels such as LNG-fueled, H2-powered, and to name a few. The existing Ulsan port is considered the port in Korea for importing overseas H2, given that a green H2 logistics hub is under construction in Ulsan port intended to be completed by 2030 and it will feature facilities for green NH3 import and NH3 cracking as well [26]. After the transportation, some of the imported green NH3 will be stored and others will be reformed back to H2 by cracking at the facility featured in the port. Through the considered NH3 cracking process with a recovery rate of 84%, some amount of the supplied NH3 will be lost, and eventually, about 74,000 tons of H2 will be supplied in the final. Finally, the supplied green H2 will be stored in an H2 storage tank for further distribution to end-users in Korea.

Fig. 4
figure 4

Detailed scope for each process and conditions of the considered project in this study

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Economic Analysis

Basically, economic analysis is commonly conducted by estimation of total expenditure (TOTEX) which is the sum of capital expenditure (CAPEX) and operating expenditure (OPEX). The CAPEX of a process includes all the expenditures associated with construction and modifications of required plants for the process, while the OPEX of a process includes all the expenditures associated with consumption of required raw materials, electricity, labor, maintenance, and to name a few. The exact cost of required equipment can be directly provided by a current price quote from a vendor or obtained cost data can be used with several adjustments for considering the effects of capacity and time with the following Eqs. (1) and (2), respectively.

$$\frac{{C}_{a}}{{C}_{b}}={\left(\frac{{A}_{a}}{{A}_{b}}\right)}^{n}$$
(1)
$${C}_{2}={C}_{1}\cdot \left(\frac{{I}_{2}}{{I}_{1}}\right)$$
(2)

where A, C, I, and n refer to equipment cost attribute, purchased cost, cost index, and cost exponent, respectively. Subscripts a and b refer to equipment with the required attribute and base attribute, respectively, and 1 and 2 refer to the base time when the cost is known and the time when the cost is desired, respectively.

To analyze the annual expenses of the process together with annually expensed OPEX, the initially expensed costs of required equipment can be annualized by multiplication of capital recovery factor (CRF) which can be calculated by Eq. (3) considering the lifetime of the equipment and discount rate. In this study, the discount rate of 4.5% is assumed for the estimation of all the required processes, and different lifetimes are considered for the respective process.

$$\text{CRF}=\frac{i{\left(1+i\right)}^{N}}{{\left(1+i\right)}^{N}-1}$$
(3)

where i refers to discount rate (%) and N can refer to lifetime/project year/economic analysis period/the number of annuities received.

With the basic logic for the estimation of economics, expenditure from each process can be individually calculated. First, for the electricity generation with solar energy at the Sun Metals solar farm, energy generated by each PV panel can be calculated with the following Eq. (4) using the panel area, yield, and global horizontal irradiation value of the desired production site, and performance ratio.

$$E=A\times r\times H\times \text{PR}$$
(4)

where E, A, r, H, and PR refer to energy generated by a panel (kWh y−1), total solar panel area (m2), solar panel yield, global horizontal irradiation (kWh m−2 y−1), and performance ratio. Here, a 10 m2 size panel with 19.8% yield and 10% loss is considered, and the global horizontal irradiation of Townsville in Australia is found to be about 2120 kWh m−2y−1 [27].

For the electricity generation with wind energy at the both Macintyre and Collinsville wind farms, power generated by each turbine can be calculated with the following Eqs. (5)–(6) using the air density, wind speed, blade size, efficiency, and possible losses from various parts.

$${P}_{\text{Turbine}}=0.5\cdot {\rho }_{\text{air}}\cdot {v}_{\text{Wind}}^{3}\cdot (\pi {l}_{\text{Blade}}^{2})\cdot \mu$$
(5)
$$\mu =(1-{k}_{\text{m}})\cdot (1-{k}_{\text{e}})\cdot (1-{k}_{\text{t}})\cdot (1-{k}_{\text{w}})\cdot {C}_{\text{P}}$$
(6)

where \({P}_{\text{Turbine}}\) (VA) refers to the real output power of a wind turbine considering the total efficiency, \({\rho }_{\text{air}}\), \({v}_{\text{Wind}}\), \({l}_{\text{Blade}}\) are air density (1.225 kg m−3), wind speed (m s−1), and blade length of the turbine (81.5 m), respectively. Here the wind speed of the considered wind farms is found to be about 9.5 m s−1 [28]. \(\mu\) is the efficiency of the turbine which can be calculated by Eq. (6) with losses. \({k}_{\text{m}}\), \({k}_{\text{e}}\), \({k}_{\text{t}}\), \({k}_{\text{w}}\), \({C}_{\text{P}}\) are mechanical losses of blades and gearbox (0.3%), electrical losses of the turbine (0%), time out of order (3%), wake losses (10%), and turbine efficiency (40%), respectively.

Here, the electrical losses of the turbine are assumed to be 0% in this equation and losses occurred from the long-distance transmission of electricity are separately estimated for consideration by Eq. (7) with specific resistance of copper cable (16.8 nΩ⋅m), distance, current (A), and cross-sectional area of considered cable (800 mm2). Associated capital and operating costs required for the solar farm are organized in Table 2 and correlation equations for estimating costs related to wind farms are presented in Eqs. (8)–(13).

Table 2 Capital and operating costs associated with a solar farm
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$$\text{Loss}(\text{MW})={\text{Current}}^{2}\cdot {R}_{\text{Cu}}\cdot \frac{{L}_{\text{Cable}}}{{A}_{\text{Cable}}}$$
(7)

Ref. [31]

$${C}_{\text{Turbine}}(\$ {\text{EA}}^{-1})=191\cdot {10}^{3}\cdot {P}_{\text{Turbine}}$$
(8)

Ref. [32]

$${C}_{\text{Support}}(\$ {\text{EA}}^{-1})=1.373\cdot {{10}^{-3}\cdot P}_{\text{Turbine}}\cdot (1+0.8\cdot {10}^{-6}\cdot {(h}_{\text{hub}}\cdot {l}_{\text{Blade}}^{2}-{10}^{5}))$$
(9)

Ref. [33]

$${C}_{\text{Transformer} \,\left(\text{LV}-\text{MV}\right)}\left(\$ {\text{EA}}^{-1}\right)=-\text{170,000}+\text{145,000}\cdot {\left({V}_{\text{Cable}}\cdot {I}_{\text{Cable}}\right)}^{0.4473}$$
(10)

Ref. [33]

$${C}_{\text{Transformer}\,\left(\text{MV}-\text{HV}\right)}\left(\$ {\text{EA}}^{-1}\right)=-\text{47,397}\cdot {\left({V}_{\text{Cable}}\cdot {I}_{\text{Cable}}\right)}^{0.7513}$$
(11)

Ref. [32]

$${C}_{\text{Cable},66\text{kV}}\left(\$ {\text{km}}^{-1}\right)=\text{96,700}+\text{87,912}\cdot {e}^{234.35\cdot {I}_{\text{Cable}}\cdot {10}^{-5}}$$
(12)

Ref. [32]

$${C}_{\text{Substation}}\left(\$ {\text{EA}}^{-1}\right)=0.98\cdot \text{55,500}\cdot {P}_{\text{Wind}}$$
(13)

where Current, RCu, LCable, and ACable refer to the current of the considered cable (A), the resistance of copper (Ω∙m), length (m), and cross-sectional area (mm2) of the considered cable, respectively. \({h}_{\text{hub}}\), \({V}_{\text{Cable}}\), \({I}_{\text{Cable}}\), \({P}_{\text{Wind}}\) refer to the height of a wind turbine (m), cable voltage level (MV), cable ampacity (A), and installed wind power capacity (MVA), respectively.

With the calculated energy generated by each panel or wind turbine and investigated expenditures for construction and operation of equipment for the farm, the levelized cost of electricity (LCOE) generated by the considered electricity generation farm can be calculated with a related Eq. (14).

$$\text{LCOE}=\frac{{\sum }_{t=1}^{n}\frac{{I}_{t}+{M}_{t}+{F}_{t}}{{\left(1+r\right)}^{t}}}{{\sum }_{t=1}^{n}\frac{{E}_{t}}{{\left(1+r\right)}^{t}}}$$
(14)

where It, Mt, Ft, Et refer to investment expenditures, operations and maintenance expenditures, fuel expenditures, and electrical energy generated in a considered year t, respectively. r refers to the discount rate, and n is the expected lifetime of the system or power station.

For the production of green H2 by water electrolysis, PEM electrolyzer cell is considered in this study as aforementioned, and specifications of the electrolyzer are based on the product of Plug Power (EX-4250D) and organized in Table 3 [34]. In addition, the cost data according to the system scale are obtained from the International Renewable Energy Agency (IRENA) report and utilized in curve fitting for identifying a correlation equation between cost and scale of the system presented in Eq. (15) [35].

Table 3 Specifications of the considered Plug Power’s PEM electrolyzer cell
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$${C}_{\text{Stack}}\left(\$\text{ k}{\text{W}}^{-1}\right)=1081.35025\cdot {\text{Scale}}_{\text{Stack}}{\left(\text{MW}\right)}^{-0.17465}$$
(15)

Given that the distance between SunHQ H2 hub and Townsville port is about 15 km, transmission of the produced H2 from the production site to the exporting port is required. Thus, the H2 transmission by pipelines is considered and related costs can be estimated using following equations from (Eq 16) to (Eq 22) which are reconfigured with proper unit operation based on provided relational expressions for estimating appropriate diameter of pipelines, required material costs, required labor costs, and to name a few, in a previous study [36].

$${D}_{\text{Pipe}}=\left({\left({\left(\frac{{r}_{{\text{H}}_{2}}}{\text{21,024}}\right)}^{0.9091}\cdot {d}_{\text{Pipe}}^{0.5}\cdot 4.524\right)}^{0.415}\right)\cdot 0.025$$
(16)
$${M}_{\text{Pipe}}=1869\cdot {\left(\frac{{D}_{\text{Pipe}}}{0.025}\right)}^{2}$$
(17)
$${L}_{\text{Pipe}}=\left({\left(343\cdot {D}_{\text{Pipe}}\cdot 39.37\right)}^{2}+2074\cdot \left({D}_{\text{Pipe}}\cdot 39.37\right)+\text{170,013}\right)\cdot \left({d}_{\text{Pipe}}\cdot 1.609\right)+\text{185,000})$$
(18)
$${E}_{\text{Comp}}=820\cdot {r}_{{\text{H}}_{2}}$$
(19)
$${C}_{\text{Comp}}=\text{1,455,000}\cdot {r}_{{\text{H}}_{2}}$$
(20)
$${C}_{\text{Pipe}}=\left(\text{IR}+{M}_{\text{Pipe}}\right)\cdot {d}_{\text{Pipe}}\cdot \text{CRF}+{C}_{\text{Comp}}$$
(21)
$${O}_{\text{Pipe}}={L}_{\text{Pipe}}\cdot \text{CRF}+{C}_{\text{Pipe}}\cdot 5\%+{E}_{\text{Comp}}$$
(22)

where D, M, L, E, and IR refer to the diameter of pipelines, material cost for manufacturing pipelines, labor cost required for construction of pipelines, electricity cost for powering pipelines by compressors, and installation and right-of-way costs for pipelines, respectively. \({d}_{\text{Pipe}}\), \({C}_{\text{Pipe}}\), and \({O}_{\text{Pipe}}\) refer to the distance of required pipeline construction in kilometers, CAPEX, and OPEX of the constructed pipelines, respectively. Here, the IR, and lifetime of pipelines are assumed to be 600,000 $ km−1 and 50 years, respectively, in this study.

Next, the produced and transmitted green H2 requires a conditioning process for it to be stored and transported in the form of an H2 carrier and a reconditioning process for the carrier to discharge the stored H2 as well. Because the NH3 is considered to be the H2 carrier in this study, analysis of Haber–Bosch NH3 synthesis and cracking of NH3 are conducted and associated specifications of the processes are organized in Table 4. To estimate the variable OPEX associated with electricity usage, since NH3 synthesis takes place in Australia, the estimated Australian renewable energy-based electricity price was applied, while an assumed Korean electricity price of 0.06 $ kWh−1 was applied to NH3 cracking given that it takes place in Korea. For case 2 considered in this study, the required heat energy for cracking of NH3 is neglected given the possibility of heat integration with other processes, assuming the optimistic scenario.

Table 4 Specifications of the Haber–Bosch NH3 synthesis and NH3 cracking processes
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After the conditioning of H2, the synthesized green NH3 will be transported by ship from Australia to Korea. The conventional marine diesel-fueled ship is considered for the ship transportation process in this study and required specifications for the analysis are organized in Table 5. As the table presents, the ship with a max loading capacity of 50,400 tons of NH3, average speed of about 17 knots, and daily fuel consumption of 39 tons is considered for 7690 km of green NH3 transportation from Australia to Korea in this study.

Table 5 Specifications of the conventional diesel-fueled ship [39]
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Before the transportation of NH3 in Australia and both the imported green NH3 and H2 after the reconditioning of transported green NH3 in Korea will require some storage system at the port. For the H2 storage, though there are five types of tank according to the used components and structures, type III tank which is overwrapped by metal liner composite is considered for the storage process in this study, given that the tank can endure some high-pressure up to 700 bars and has a much more efficient capacity than commonly used type I tank, that is, a smaller and lighter tank can be used to store the same amount than the type I [40]. Even though the type III tank is the priciest of all the types so far due to the use of carbon fiber, a number of studies predict that its price could be lowered [40]. The specifications associated with storage tank for NH3 and H2 are organized in Table 6.

Table 6 Specifications of the storage system for NH3 and H2
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Sustainability Analysis

To identify the sustainability of the considered pathway for green H2 introduction from Australia in Korea, environmental impact analysis is conducted by estimating GHG emission amount with the ‘GREET’ model developed by the Argonne National Laboratory. Basically, there are various kinds of GHGs including the representative carbon dioxide (CO2), methane (CH4), and nitrous oxide (N2O), but only the three representatives are considered to as GHGs for the environmental impact analysis in this study. Global warming potential (GWP) is an index to measure how much infrared thermal radiation a GHG absorbs over a given time after it has been emitted to the atmosphere. It can be measured according to the strength of gas absorption, the rate of gas removal from the atmosphere, and the considered time frame. Among the several standards, a GWP over 100 years (GWP-100) of each is considered to be 1, 28, and 265 for CO2, CH4, and N2O, respectively, following the IPCC Fifth Assessment Report in 2014 (AR5) [42]. The functional unit is considered to be the GHG emission amount to supply 1 kg of H2. For the boundary condition of analysis, ‘cradle-to-gate’, which can consider the stages from material preparation to plant operation except for the end-of-life stage, is considered for each process of the pathway from electricity generation in Australia to the final storage in Korea as Fig. 5 describes. Amounts of all the required resources for each process of the overall pathway are based on numerous studies that have been published and all the used values are organized in supplementary information. The supply routes of each resource could be applied by using both default pathways and GREET and user-defined pathways as well.

Fig. 5
figure 5

Description of the boundary condition considered for environmental impact analysis in this study

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Results and Discussion

From the analyses on costs expensed and GHGs emitted by introducing green H2 from Australia to Korea, unit cost and sustainability of the introduced green H2 can be identified. The analyses are conducted on the two cases of pathway to indicate not only how much the costs and emissions are inevitable with conservatively considering all the required technologies, but also how much they can be reduced by considering optimistically improved technologies for several processes. First, results of unit H2 cost and GHG emission from the pathway with case 1 are presented in Figs. 6 and 7, respectively, with the form of a Sankey diagram for indicating the hot spots of each. In the case of unit H2 cost, the total is about 6.6 $ kgH2−1 and the majority of the total depends on PEM electrolysis H2 production with renewable energy generation which is presented as a variable OPEX of the electrolysis process. Here, among the total expenditure to generate renewable electricity, CAPEXs expensed for the related facilities are the majority. In addition to the H2 production, NH3 cracking and H2 storage processes account for large percentages of the total as well, especially the heat and electricity required for the NH3 cracking which is presented as a variable OPEX of the cracking process. In the case of GHG emission, the total is about 11.2 kgCO2-eq kgH2−1 and the majority of the total depends on NH3 cracking for regeneration of H2 due to its highly required heat and electricity and the use of conventional grid in Korea. Thus, some feasible alternatives such as heat integration for mitigation of heat usage and utilization of possible renewable energy sources in Korea for reducing the emission from electricity consumption may be considered. In addition to the NH3 cracking process, H2 storage, wind electricity generation, and NH3 synthesis also generate large amounts of GHGs more than 2 kgCO2-eq kgH2−1 from each of them. Electricity required to store H2 in Korea is the main cause that the H2 storage process becomes one of the emission-intensive processes and nitrogen from air separation unit (ASU) and silicon are the main cause of NH3 synthesis and wind electricity generation, respectively. Thus, the total unit cost and GHG emission from green H2 supply might be significantly reduced if some kinds of improvement and alternatives for the current technologies are used in the aforementioned majorities.

Fig. 6
figure 6

Unit H2 cost expensed for introducing green H2 from Australia to Korea by considered pathway with case 1

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Fig. 7
figure 7

GHG emissions for introducing green H2 from Australia to Korea by considered pathway with case 1

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Here, though the emission from wind electricity is much higher than the emission from solar PV electricity, the result is that the used electricity amount of wind-based is much higher than solar-based, that is, the comparison between those two kinds of process needs to be conducted with the same unit amount of electricity for both. From the analysis with the same unit amount, the solar PV and wind electricity emit 0.052 and 0.032 kgCO2-eq kWh−1, respectively. Thus, for solar PV energy to be competitive compared to wind energy, it is required for its process to reduce the use of the main cause of its emission, and the main cause is found to be the use of silicon for manufacturing panels.

As abovementioned, the total unit H2 cost and emissions from the supply pathway can be reduced by possible reduction of material uses, utilization of new technologies, and conditions of the pathway. Thus, with several assumptions mentioned in the methodology section, case 2 is also considered to be analyzed in this study for comparison with case 1. To recap assumptions for case 2, first, the ratio of used renewable energy is the same for both wind and solar-based energy, while those are 90% and 10% for case 1. Second, given that the loss occurred from the transmission of wind energy from Macintyre farm which is 1500 km far apart from the H2 hub is very high, the Collinsville farm which is 200 km from the hub is considered for case 2. Third, CAPEXs of wind turbines, solar PV modules, and PEM electrolyzer systems, H2 storage tanks are assumed to be lower than case 1, and grid electricity price in Korea is considered to be 50 $ MWh−1 while it is 60 for case 1. Fourth, the heat energy required to crack NH3 into H2 is neglected considering the possibility of heat integration for the process. Fifth, the usage of emission-intensive materials such as platinum for manufacturing PEM electrolyzer cells, and silicon for wind turbines and solar panels are considered to be half of the consumption considered in case 1. Last, the percentage of wind energy used for electricity in Korea is assumed to be increased from 4% to 30% decreasing the percentage of coal-based energy generation from 40% to 14%.

The results of the analysis on case 2 can be found in Fig. 8 compared with the results of case 1. As Fig. 8 presents, the cost of generating renewable electricity, producing H2 by electrolysis, and cracking of NH3 can be significantly reduced by assuming different shares of solar and wind energy, the optimal CAPEXs of renewable farms and electrolyzer cells, and energy consumption. Here, the price reduction of renewable energy consequently reduces the cost of energy consumption required throughout the entire process in Australia. With the considerable reduction in several major processes, the total unit H2 cost of the supplied green H2 can be reduced to 3.161 $ kgH2−1 which is lower than half of the cost of green H2 supplied with case 1. Not only the cost reduction but also the GHG emission reduction can be realized by considering case 2 for the pathway. The lower usage of several emission-intensive materials, increased percentage of wind energy for electricity used in Korea, and heat energy integration could reduce emissions from several processes such as renewable electricity generation, NH3 cracking, and H2 storage. Considering case 2, the total GHG emission for supplying green H2 can be reduced to 6.408 kgCO2-eq kgH2−1 while the emission is 11.167 kgCO2-eq kgH2−1 with case 1. Comparing the unit H2 cost with the Korean national target cost of H2 in 2030 and GHG emission with the clean H2 certification standard in Korea [43, 44], both cost and emission of the pathway with case 1 are not yet in competitive ranges. Moreover, the GHG emission of the pathway cannot be competitive even considering case 2. Therefore, for the supplied H2 to be certified as the clean H2 in Korea, additional strategies would be necessary, such as improved technologies for renewable energy, alternative technology for synthesis of NH3, use of more environmentally friendly vessels for transportation, an increasing percentage of renewable energy for electricity use in Korea, to name a few.

Fig. 8
figure 8

Comparative results of a unit H2 cost and b GHG emission from green H2 supply pathway with case 1 and case 2

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More detailed results of estimated costs and emissions from the major processes of the pathway with both cases are presented in Figs. 9 and 10. In the case of unit H2 costs presented in Fig. 9, PEM water electrolysis with renewable energy accounts for the most percentage of the total cost mainly due to the variable OPEX which includes the renewable electricity price. Thus, several assumptions for possible cost reduction are considered including the cheaper CAPEXs, a closer wind farm, and different percentages of renewable energies, and the results of case 2 show significantly reduced variable OPEX which is approximately one-third of case 1. The variable OPEX of the NH3 cracking process includes the cost for providing heat energy by NG indicating quite a high cost and emission as well, so an assumption that the heat integration for providing the required heat is considered for case 2, given the possibility of heat integration for the process. With the assumption, the considerable reduction of variable OPEX and emission from NG in the process can be found in Figs. 9b and 10e. As mentioned before, a significant reduction in several processes can be found due to the reduced use of resources like silicon and electricity, however, the emissions from providing electricity for all the presented processes, and nitrogen gas for NH3 synthesis are still high making the supplied H2 not feasible get certified as a clean H2. Therefore, in addition to the efforts for the realization of technological assumptions in the case 2 scenario, the considerable emission reductions in electricity generation and air separation units are necessary for the green H2 supplied by the suggested pathway to achieve at least the certification standard of clean H2 in Korea.

Fig. 9
figure 9

Detailed results of estimated unit H2 costs from cost-intensive processes. a PEM water electrolysis, b NH3 cracking, and c H2 storage account for the highest percentages of the total cost of green H2 supply pathway

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Fig. 10
figure 10

Detailed results of estimated GHG emissions from emission-intensive processes. (a) and (b) indicate the emissions from renewable energy generation on the same scale given that electricity accounts for the most parts of each process. Other subgraphs from (c) to (f) indicate the emissions from the major processes from H2 production to H2 storage on the same scale and the processes in Australia (electrolysis and NH3 synthesis) include emissions from using renewable electricity as well

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Conclusions

Though green H2 which is produced by water electrolysis coupled with renewable energy is currently considered to as a feasible alternative energy source, the capacity of its production heavily depends on the renewable energy capacity causing the regional deviation globally. Thus, the international trading of green H2 is considered as the possible solution for mitigating the deviation and several projects have been announced and proceeding for realization of trading so far. This study aims to verify the economics and sustainability of one of the projects between Australia and Korea by covering the overall pathway of the project from green H2 production in Australia to storage in Korea. The pathway is analyzed for two cases with the first case considering all the technologies conservatively and the second case considering several possible improved technologies and reduced resource usage.

The results from the analysis on case 1 indicate the total unit H2 cost of 6.6 $ kgH2−1 and the GHG emission of 11.167 kgCO2-eq kgH2−1. In the total unit H2 cost of the supplied H2, the majority is from the process of renewable energy-based PEM electrolysis H2 production which accounts for about 65% of the total cost. Among the costs that emerged from renewable energy generation, CAPEXs for construction of the required facilities such as panels and turbines account for significant portions. In addition to the renewable energy generation and PEM electrolysis processes, NH3 cracking and H2 storage in Korea are majorities of the total cost as well due to their high energy consumption. In the GHG emission from the H2 supply pathway, the majority of the total is NH3 cracking due to its heat and electricity consumption and the associated use of natural gas and conventional grid in Korea. Similar to the cost-intensive processes, H2 storage, wind energy generation, and NH3 synthesis also account for a significant portion of the total more than 2 kgCO2-eq kgH2−1 from each process. The H2 storage process emits significant GHGs due to its high consumption of electricity from the Korean grid, wind energy is due to the use of silicon, and NH3 synthesis is due to the additional process to produce the required nitrogen by ASU.

The results from the analysis on case 2 indicate much lower unit H2 cost and GHG emission, which are 3.161 $ kgH2−1 and 6.408 kgCO2-eq kgH2−1, respectively. Significant reduction is mainly due to the reductions from the processes of renewable energy generation, NH3 cracking, and H2 storage. However, considering that the Korean national target cost of H2 supply in 2030 is 3.1 $ kgH2−1 and the clean H2 certification standard in Korea is 4 kgCO2-eq kgH2−1, both estimated cost and emission from the pathway for supplying green H2 with case 1 are not feasible yet and even with case 2 are uncertain to clearly achieve the national criteria. Therefore, additional strategies would be required especially in the electricity generation, electrolysis, NH3 synthesis, cracking, and H2 storage processes as are hot spots presented in Fig. 11. For the electricity generation, recycling silicon which is required to manufacture wind turbines and solar PV panel may generate the most considerable reduction in GHG emission from the process. For the PEM water electrolysis H2 production, increasing plant size and reducing or replacing the required rare elements may generate the most reduction in cost expensed from the process. Last, for the H2 storage in Korea, increasing the share of renewable energy for electricity will be the most necessary thing to reduce both cost and emission from the process. In addition to the strategies for the hot spots, others including the use of more environmentally friendly vessels for transportation of NH3 and increasing the percentage of renewable energy for electricity use in Korea, to name a few, may be possible to be considered in the future for reduction in GHG emissions from the pathway.

Fig. 11
figure 11

Verified hot spots of cost and GHG emission in the analyzed green H2 pathway

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In this study, most of the incidental processes including pipeline transmission, NH3 synthesis, ship transportation, and storage are considered with conventional technologies like the HB process, conventional marine diesel-fueled vessels, use of conventional grid in Korea, and to name a few. Those conservative considerations might present realistic and stable guidelines for people to materialize the green H2 introduction with the suggested pathway, however, several improved technologies like electrified HB, and NG-fueled vessels, that are quite possible to be considered may be analyzed in future work. Also, for the assessment of GHG emissions from each process of the pathway, most of the scope 1 and 2 emissions could be considered while most of the scope 3 emissions could not be considered except for the emissions from manufacturing the required equipment and facilities. Thus, a more comprehensive and expanded analysis of the environmental impact of the process will be required to present more realistic and reliable results in future work.