Hydrogen pipelines offer a potential solution for high-volume, long-distance transport, and they have a lifespan of 30–80 years (IEA, 2019). This method ensures a reliable and low-loss hydrogen supply. However, the design of hydrogen pipelines requires careful consideration of material compatibility, leak prevention, and safety because of the reactive and flammable nature of hydrogen. Hydrogen embrittlement, the phenomenon in which hydrogen weakens metals, presents a significant challenge in pipeline construction (Raj et al., 2024). The dependency on a fixed route and the need to predict hydrogen production and consumption levels over a pipeline’s lifespan present further complexities (Dinh et al., 2024).

Hong et al. (2021) compared various hydrogen transport methods, including those for methylcyclohexane, liquid hydrogen, compressed hydrogen, and liquid ammonia, based on their energy efficiency, carbon emissions, and costs. That study concluded that the optimal transport method depended on the specific export location and intended use. In this case, the pipeline transportation of compressed hydrogen from neighboring countries was the most cost-effective option. Similarly, a study by Solomon et al. (2024) investigated the cost-effectiveness of compressed hydrogen gas transport via gas trailers and pipelines. The study found that the optimal transport method was primarily influenced by the hydrogen demand and distance. Pipelines are advantageous in high-demand, short-distance scenarios, whereas gas trailers are more cost-effective for lower demands and shorter distances. The United States and Europe have an established network of approximately 4,600 km of dedicated hydrogen pipelines (IRENA, 2022). In contrast, the Arctic lacks hydrogen pipeline infrastructure, despite the presence of the Trans-Alaska oil pipeline (Lanan et al., 2001). Extreme Arctic conditions, including permafrost and remote nature, present challenges for pipeline construction; therefore, further design considerations and mitigation strategies for hydrogen pipelines are required (DeGeer and Nessim, 2009).

Liquid-hydrogen transportation via tankers was the second method explored in this study. The existing and future development of port facilities further enhance the potential for shipping green hydrogen (Arctic Portal, n.d.). The low volumetric density of hydrogen renders it inefficient for large-scale transportation under ambient conditions (Niermann et al., 2021) but if liquefaction is employed, it can reduce the volume of hydrogen for storage and transportation. However, liquefaction is an energy-intensive process requiring cooling to −253 °C (Al-Breiki & Bicer, 2020), resulting in approximately one-third energy loss.

Liquid hydrogen has high specific energy consumption (SEC), low exergy efficiency, high total expenses, and boil-off gas (BOG) losses, which hinder its widespread use as an energy carrier (Ghorbani et al., 2023). However, various types of liquefaction cycles can be used depending on the specific requirements of the liquefaction process, its scale, efficiency, and type of liquefied gas (Lee et al., 2022). Although many studies have focused on hydrogen liquefaction cycles and methods to reduce SEC, studies tailored to Arctic conditions are not available, even though cold climate conditions may offer significant advantages by reducing the energy consumption for liquefaction and minimizing BOG losses.

At present, shipbuilding for liquid hydrogen transportation is a nascent field with no shipping trade. Only one liquid hydrogen tanker, the SUISO Frontier (Kawasaki Heavy Industries, 2019) has been constructed in Japan as a proof-of-concept, which has a volume of 1,250 m³. Niermann et al. comprehensively compared the cost of transporting hydrogen from Algeria to Germany via pipelines, high-voltage direct current (HVDC) electricity transmission, and shipping (both as liquid hydrogen and hydrogen carriers). The results showed that hydrogen carriers, specifically liquid organic hydrogen carriers (LOHCs), are more economical for distances exceeding 3,000 km and pipeline transport is generally preferred for distances less than 3,000 km (Niermann et al., 2021). Kamiya et al. supply chain analysis estimated the cost of transporting liquid hydrogen from Australia to Japan by ship to be 0.67 USD/kg (Kamiya et al., 2015). Ishimoto et al. reviewed the energy efficiency, carbon footprint, and cost of shipping liquid hydrogen (LH2) and ammonia from Northern Norway to Rotterdam and Japan (Ishimoto et al., 2020). They found similar supply chain costs for shipping LH2 and ammonia to Japan, although LH2 offered lower costs and had a smaller environmental impact than ammonia on the Rotterdam route. One of the few studies related to Arctic shipping was conducted by Dai et al. (2021), who compared the feasibility of transporting liquid natural gas (LNG) via the Northern Sea Route (NSR) with the traditional Suez Canal Route (SCR) (Dai et al., 2021). A critical gap is the absence of open-source models capable of estimating the cost of shipping for unique routes, while simultaneously considering the entire hydrogen supply chain.

Existing research has analyzed hydrogen transportation costs using pipelines and shipping; however, a unified methodology that encompasses the entire green hydrogen supply chain for green hydrogen production and transportation is limited. Therefore, this study aims to address the significant gap in green hydrogen supply chain analysis by developing a comprehensive methodology that combines procedures from a wide range of sources and integrates production, liquefaction, and transportation costs for both pipelines and shipping into a single framework. Although existing studies have focused on specific aspects of hydrogen transportation, a standardized approach for determining costs across diverse locations is lacking. By applying this unified methodology to Greenland as a case study, we conducted a techno-economic analysis to compare the viability and cost-effectiveness of hydrogen transportation methods under the Arctic region’s unique geographical and environmental conditions. This approach seeks to provide a more holistic understanding of green hydrogen supply chains and offers valuable insights for decision making in the emerging hydrogen economy.

A simplified capital cost model was used for the pipeline system that considered the major aspects of pipeline construction, piping, materials, and compressors. The reference model proposed two pipeline CAPEX variants in Eqs. (2) and (3) for distribution and transmission, respectively (Baufumé et al., 2013). CAPEX was expressed as a second-order polynomial function of the diameter.

The recompression cost reflects the difference between Eqs. (2) and (3). Eq. (3) includes the recompression cost, which was factored into the calculations used in this study. An offshore pipeline was assumed according to the Northstar Arctic pipeline design (Lanan et al., 2001) which has a pipe diameter of 200 mm, operating pressure of 10.2 MPa, and operating safety factor of 1.6. The cost of an offshore pipeline can be estimated based on the onshore pipeline cost multiplied by two, according to IRENA (2022).

The capital expenditure for the pipeline (CAPEXpipe) in Eqs. (2) and (3) is given in €/km but is converted to USD/km (1 USD = 1.09 EUR), and Dpipe is the pipeline diameter in meters (m). The diameter of a pipeline is a major driver of the cost of pipeline transportation systems. A sensitivity analysis of different pipeline diameters (D) was performed, and the minimum diameter used is 100 mm. The OPEX, which refers to the cost associated with energy, maintenance, repairs and labor, is inherently uncertain and requires careful consideration for accurate estimation. It typically accounts for approximately 2%–10% of the total costs (Molnar, 2022). The OPEX for the pipeline (OPEXpipe) was estimated to be 2% of the CAPEXpipe used in this study based on the recommendations of Dinh et al. (2024).

The hydrogen pipeline was assumed to operate at 10 MPa. Because hydrogen is typically produced at low pressures ranging from 2 to 3 MPa, an initial compression is necessary prior to transportation. Subsequent compression along the pipeline is required when the pressure drops to approximately 50% of its initial value (Solomon et al., 2024). According to the literature (Solomon et al., 2024), the Dracy–Weisbach equation was used to calculate the pressure drop within the pipeline in order to determine the necessary number of compressor stations required and their exact distance along the entire pipeline length. Solomon et al. (2024) calculated that the average distance the gas requires for recompression is 250–300 km.

The LCoT via shipping was calculated by adjusting the CAPEX and OPEX for liquefaction, shipping, and storage to the present value. The OPEX, which includes labor costs, port charges, maintenance, and miscellaneous expenses, is estimated based on the CAPEX. This is primarily due to the uncertainties arising from the lack of infrastructure and operational data in remote Arctic regions.

BOG is inevitably generated during the storage and transportation of liquefied hydrogen due to heat ingress. In this study, the BOG rate was kept low to the required quantity for propulsion owing to the high-performance insulation technology used, as in the case presented by Ishimoto et al. (2020).

The daily fuel consumption in tonnes was initially calculated to determine the fuel cost when utilizing boil-off hydrogen for propulsion purposes. Using Eqs. (6) and (7), the fuel cost was calculated, where MP is the market price and LHV is the lower heating value for LH2. Given a ship’s engine capacity of 30.5 MW and an assumed efficiency of 50%, the estimated fuel consumption was calculated to be 44 t/d. (Heuser et al., 2019; Raab et al., 2021).

The storage BOG cost and shipping BOG cost were calculated using Eqs. (8) and (9), respectively. Given the inherent uncertainties and extreme operating conditions in Greenland, a 20% OPEX estimate was adopted relative to the CAPEX as a preliminary approximation. This is due to the region’s unique geographical and environmental challenges, which may cause increased maintenance and operating conditions. These uncertainties and fluctuations require more precise OPEX calculations using region-specific data and in-depth analysis. Tables 3 and 4 present details of the shipping parameters used in this study.

The annual delivered hydrogen quantity depends on the ship’s annual trips, number of sailing days between the two terminals, and its capacity. This relates the distance between the production and demand to the quantity delivered, as shown in Eqs. (10)–(12). The ship was assumed to operate for 350 d at 9.23 m/s.

The total sailing time (d) considers the travel distance between the export and import terminals (back and forth) and the number of days spent loading and unloading at both terminals.

The annual CAPEX for the tanker and storage was calculated by multiplying the capital recovery factor (CRF), given by Eq. (13). The interest rate i, is 5% and the lifetime N is 20 years, as listed in Table 2.

The LCoT can be determined by summing the individual contributions of all CAPEX and OPEX components. The LCoT comprises capital costs for the ship and storage and operating costs for the ship, storage, fuel, and BOG from both shipping and storage.

A cost analysis of hydrogen transportation via pipeline was conducted using Eqs. (2) and (3) to calculate the LCoT. For a medium-scale demand of 10 t/d using a pipeline with a diameter of 100 mm over 200 km, the LCoT was 4.1 USD/kg. When scaled to 1000 t/d, the LCoT decreased significantly to 0.04 USD/kg. A sensitivity analysis comparing pipeline diameters of 100, 200, and 300 mm for both 10 and 1,000 t/d capacities across three different distances is illustrated in Figs. 2 and 3.

A comparison of the two cases demonstrates that the transportation costs increase with both distance and pipe diameter. This is attributable to the direct proportionality of the material, labor, and compression costs to the pipe diameter and length. The recompression costs contributed to a 62% increase in the LCoT over 500 km. The flow rate is another significant cost driver for pipeline transportation. The results show that a higher cost is obtained for low flow rates and long distances, whereas lower costs are associated with shorter distances and high flow rates (see Fig. 3). The transmission of higher capacities necessitates larger pipe diameters, which reduce the pressure drop and consequently lower the required recompression power. This leads to significant economies of scale in pipeline transportation. Costs below 1 USD/kgH₂ have also been suggested for large-scale, long-distance hydrogen pipelines (IRENA, 2022). This is consistent with Fig. 3, where this value increases for distances longer than 4,000 km.

The case of transporting liquefied hydrogen to Nuuk via shipping estimated a cost of 0.12 USD/kg using a tanker capacity of 160,000 m³. The time required for a round trip from the loading terminal in Paamuit to the receiving terminal in Nuuk, including loading and unloading, was calculated as 3.6 d. Assuming 350 operational days annually, the ship can make approximately 96.5 trips per year. The calculated quantity of hydrogen delivered was 3,000 t/d, equivalent to 1,098,372,413 kg/y. This value represents the storage and shipping costs, but excludes the cost of liquefaction. The amount of hydrogen delivered is influenced by the shipping distance owing to the BOG consumed for propulsion, which is factored into the cost model used.

The cost of LH2 shipping is significantly affected by high storage costs, low capacity, and a high BOG rate. This results in a reduced quantity delivered upon arrival at the destination, consequently increasing the LCoT. Furthermore, high ship and storage capital costs are due to the thermophysical properties of hydrogen, which require extremely low storage temperatures and substantial insulation.

The capital cost for a 160,000 m³ capacity ship is calculated as $216,784,000. A 10% increase in this capital cost was applied to account for the uncertainty associated with using the BOG for propulsion. Compared to LNG and methanol tankers, this cost is 10% and 44% lower, respectively. This was obtained from a study by Al-Breiki and Bicer (2020) who analyzed the cost of transporting LH2, ammonia, LNG, methanol, and LOHC (with dimethyl ether (DME) as the LOHC) between Qatar and Japan.

A comparison of our results with the data from Johnston et al. (2022 revealed a discrepancy of 0.03 USD/kg in the shipping transport cost of LH2, with our results being 2.16 USD/kg lower. This variation is attributed to differing operational costs given the scarcity of data on Arctic port infrastructure and operations.

Our model yielded a transportation cost of 1.3 USD/kg as shown in Fig. 4, more than double their reported cost of 0.45 USD/kg (Al-Breiki and Bicer, 2020). This significant discrepancy is likely due to overlooking the ship’s return journey and the use of BOG for propulsion. Additionally, methodologies for determining maritime routes and sailing times, which were not considered here, should be a focus area in the future.

Fig. 5 illustrates the impact of varying ship capacity on hydrogen transportation costs. The results indicate an inverse relationship between ship capacity and transportation costs, as ship capacity decreases and transportation costs increase. A 10% reduction in transportation cost was observed when ship capacity rose from 100,000 to 250,000 m³. Although larger ship volumes lead to an increased surface area and higher BOG rates, the overall effect yields a decrease in the levelized transportation cost. This is due to economies of scale; as the nominal storage capacity (double the ship capacity) increases, and annual BOG and associated costs also increase, the overall cost of hydrogen transport diminishes.