Alternatives for Transport, Storage in Port and Bunkering Systems for Offshore Energy to Green Hydrogen

Abstract

Offshore electricity production, mainly by wind turbines, and, eventually, floating PV, is expected to increase renewable energy generation and their dispatchability. In this sense, a significant part of this offshore electricity would be directly used for hydrogen generation. The integration of offshore energy production into the hydrogen economy is of paramount importance for both the techno-economic viability of offshore energy generation and the hydrogen economy. An analysis of this integration is presented. The analysis includes a discussion about the current state of the art of hydrogen pipelines and subsea cables, as well as the storage and bunkering system that is needed on shore to deliver hydrogen and derivatives. This analysis extends the scope of most of the previous works that consider port-to-port transport, while we report offshore to port. Such storage and bunkering will allow access to local and continental energy networks, as well as to integrate offshore facilities for the delivery of decarbonized fuel for the maritime sector. The results of such state of the art suggest that the main options for the transport of offshore energy for the production of hydrogen and hydrogenated vectors are through direct electricity transport by subsea cables to produce hydrogen onshore, or hydrogen transport by subsea pipeline. A parametric analysis of both alternatives, focused on cost estimates of each infrastructure (cable/pipeline) and shipping has been carried out versus the total amount of energy to transport and distance to shore. For low capacity (100 GWh/y), an electric subsea cable is the best option. For high-capacity renewable offshore plants (TWh/y), pipelines start to be competitive for distances above approx. 750 km. Cost is highly dependent on the distance to land, ranging from 35 to 200 USD/MWh.

1. Introduction

There is an urgent need for decarbonization of the energy system to tackle dramatic climate changes as a result of anthropogenic activity. The development of hydrogen-related technologies is expected to have a key role in such energy system transition towards a deep reduction of greenhouse gas emissions [1]. The integration of hydrogen into society requires improvements from the technological side, as well as the development of a market to reduce costs. Apart from the efficiency and specific cost of equipment, such as electrolyzers, fuel cells, or storage tanks, a rational analysis of the integration of renewable sources and hydrogen generation is needed. The levelized cost of hydrogen (LCOH) currently depends on, and is expected to do more in the future with, electricity costs due to the huge efforts to reduce capital costs. The cost of the hydrogen to deliver to off-takers depends on the generation costs, as well as the distribution costs. Such hydrogen delivery costs to the off-takers will be key to enabling renewable-based hydrogen to substitute fossil-based hydrogen generation. For the case of renewable electricity production far from hydrogen delivery and consumption, energy transport in the form of electricity or hydrogen between both sites has to be carefully optimized.

In recent years, the public and private support for the development of hydrogen technologies has been enormous, being a pillar of the R&D and innovation programs around the world, and, in particular, at the Green Deal of the European Union [2,3]. One of the targets is the combination of hydrogen production technologies with renewable energy generation as a net-zero emission energy solution. Such a combination decoupled renewable intermittent electricity production from the demand, reducing curtailment of wind and PV production [4] by the accumulation of their production in excess into the hydrogen vector [5]. One of the most important issues affecting the techno-economic viability of offshore electricity production is its transport to the energy networks, which is highly dependent on the distance to shore [6]. Such networks may be electric, or molecular, which has brought attention to the production of offshore hydrogen [7,8]. Some authors reported that hydrogen transport by ship or pipeline may be competitive with subsea cables for long distances, high power and low electricity price [9].

Such an addition of offshore energy generation will support the decarbonization of hard-to-abate sectors such as aviation and shipping [10,11]. There are a number of future alternatives [12] for hydrogen carriers, including ammonia, synthetic natural gas, or other organic compounds, that would play a role as multipurpose vectors for transportation and use. Such alternatives are directly affecting the sustainability of ports and global economic growth [13].

Most of the research reported on offshore electricity production [6], including the use of hydrogen as an energy vector [9], mainly considers offshore hydrogen production and its transport to ports, or hydrogen transport port to port [14]. We will focus on the transport of electricity production offshore to a multi-sectorial energy hub on shore, providing a levelized cost of energy transport (LCOET) as a key performance indicator for the comparison, to take apart other costs depending on the specific generation technology that should be added for the evaluation of the full energy value chain, as the LCOE (levelized cost of energy generation) or the LCOS (levelized cost of storage).

In this paper, different alternatives for the integration of offshore plants for the delivery of hydrogen on shore are evaluated to assess their cost depending on distance and energy transport capacity. It comprises the transport from offshore generation sites to a connecting node on shore and the alternatives for its delivery from the port to the off-takers. This analysis is based on the current cost of the technology. It is expected to reduce the cost of some hydrogen-related equipment [15] as electrolyzers, affecting the global levelized cost of hydrogen (LCOH). Nevertheless, for the case of the LCOET, such cost is based on mature technologies, such as subsea cables, that have lower uncertainties and lower potential for cost reduction in the short term. For the case of hydrogen transport, compressed H₂ and liquid H₂ and pipeline are considered. Such transport means are based on existing mature technologies such as cryogenics, high-pressure equipment and dedicated ships, with costs that are not expected to evolve. Section 2 introduces the steps that will be considered for the analysis of offshore-to-port energy transport and its integration into hydrogen networks. There are some differences with respect to the port-to-port hydrogen transport that is considered in previous works [16] or hydrogen transport on land [16,17]. Section 3 and Section 4 describe the framework for energy transport by subsea cable, pipeline and ship, a brief description of the storage requirements, and the fuel bunkering at ports. Section 5 develops the cost analysis of the selected alternatives. Finally, Section 6 discusses the conclusions of this work.

2. Materials and Methods

The delivery of hydrogen production offshore to the land transport and distribution networks includes the implementation of the following infrastructures: the transport to the shore, likely to a port or similar, the bunkering and the hydrogen storage. Such infrastructure should be compatible with the needs of the off-takers, such as ships or a distribution network for local consumers, as well as an inland transport pipeline. Moreover, hydrogen production and conditioning for transport should be included in the full scope of the techno-economic viability evaluation.

2.1. Transport to Shore

There are multiple options for the delivery of energy production offshore to the demand at the coast. Such options may be the transport of hydrogen or a hydrogenated compound, either by a pipeline, a vessel or electricity, for its optional conversion into hydrogen onshore [18]. There are a few reported analyses with a direct comparison between offshore cables and offshore hydrogen pipelines [16]. Cost structures in both cases depend on several items of different nature. In particular, transmission efficiency in terms of energy is higher in pipelines, but O&M (Operation and Maintenance) costs are much lower for cables. In the particular case of hydrogen pipelines, materials must be chosen carefully, both to minimize diffusion leakage and to improve resistance to hydrogen embrittlement (HE). The current number of specific hydrogen pipes have been made on low-grade steels [19] operating at relatively low pressure, less than 10 MPa. Nevertheless, high-capacity hydrogen pipelines require high strength and high pressure, which is a challenge in current demo projects worldwide. The matter still requires some R&D [20], including the consideration and tests of high-density polyethylene pipes.

For the case of hydrogen transportation by ship, some authors have analyzed alternatives based on the use of compressed hydrogen (cH₂), liquid hydrogen (LH₂), ammonia (NH₃), and light organic compounds (LOHC) [21]. Those analyses are mainly devoted to long-distance transport, mainly for hydrogen logistics from port to port.

2.2. Hydrogen Bunkering and Distribution

Ports are one of the critical infrastructures in the energy transition as transportation hubs for international commerce. They are energy hubs [22] of their pivotal role related to the import/export of energy products, such as LNG (liquified natural gas), coal or oil. In the energy product list, hydrogen and its derivatives are called to be another asset, not only as fuel to feed transportation vessels into a decarbonized marine sector [23], but also as a link of continental energy transport networks with offshore energy generation facilities. Moreover, harbor infrastructures must be ready to operate in an uncertain context regarding the type of energy vector that will be used in a net-zero scheme by the international shipping fleet, or even to adapt to a multiple-fuel fleet [24] demanding ammonia, hydrogen and methanol.

Hydrogen bunkering at ports is also facing regulation issues. The maritime sector is regulated by the international safety code for ships using gases or other low-flashpoint fuels (IGF Code). This code contains mandatory standards for the disposal, installation, control and monitoring of equipment and systems using low-flash point fuels, as is the case of hydrogen with a flash point below 60 °C. The code is mandatory under the International Convention for the Safety of Life at Sea (SOLAS), but it has been elaborated focused on LNG [25]. On the other hand, SAE J2601 standards establish safety limits and performance requirements for gaseous hydrogen fuel dispensers. Criteria include maximum fuel temperature at the dispenser nozzle, maximum fuel flow rate, maximum pressure rise rate, and other performance criteria, but limited to heavy and light-duty road vehicles. For ships, consolidated standards are not available and a new regulation should be issued in view of the efforts for maritime transport decarbonization. Currently, one of the options for hydrogen bunkering is in the form of ammonia, but it might depend on the choice of maritime fuel (or combinations of fuels) finally adopted.

Another important issue is the connection with onshore networks, currently under development and implementation by several H₂ clusters and valleys. Such networks are mostly relying on the capacity of the existing natural gas networks for the transport of blended natural gas/hydrogen admixtures [26]. In that case, hydrogen produced offshore may be directly injected into the existing gas backbone.

2.3. Hydrogen Storage

There are plenty of options for hydrogen storage already available or under development, such as compressed and liquid hydrogen, hydrates, metal hydrides, adsorption and chemical formation of hydrogenated molecules [27]. Hydrogen storage at ports should be aligned with their role as fuel exchange hub connecting fuel bunkering for ships, clean energy delivery from offshore production and clean fuel distribution on land. Liquid hydrogen and ammonia are the two main options that have been proposed to store hydrogen at ports, as well as for decarbonizing shipping. Some works have been reported with techno-economical comparisons between liquid hydrogen, ammonia and LNG taking into account their environmental and economic impact [12]. One of the main key performance parameters is the fuel boil-off during transportation and storage, which is several times higher in the case of liquid hydrogen than ammonia as a consequence of a much lower boiling temperature (−253 °C vs. −33 °C at standard pressure).

Regarding the alternatives for decarbonizing maritime transport, it is an open issue that will be the most suitable fuel [28] in the future. Either hydrogen, ammonia or other vectors such as dimethyl ether (DME), or methanol, have their own pros and cons. Ammonia is a very interesting option due to the existence of plenty of infrastructures and a consolidated market worldwide. The hydrogen storage at ports in the form of ammonia will depend on the practical utilization of such substances as marine fuel.

3. Hydrogen Transport

3.1. Hydrogen Transport by Pipelines

The design of subsea gas pipelines is influenced by multiple factors, some of the most important being performance, pressure rating, pressure drop and depth [29]. In the case of transporting hydrogen through pipes, materials must be chosen carefully, both to minimize diffusion leakage and to improve resistance to hydrogen embrittlement (HE). Hydrogen embrittlement is a deterioration mechanism of the mechanical properties of materials (mainly in steel pipes). In this mechanism, the atomic hydrogen diffuses into the material, and it is deposited in the reticular structure of the metal, being able to create cracks and cause fractures [30]. The implementation of dedicated hydrogen pipelines, especially at subsea levels, requires a reliable verification of HE avoidance and a deep understanding of such phenomena in high-pressure pipelines. The severity of hydrogen embrittlement depends on the amount of hydrogen diffused in the structural material, the mechanical stress and the microstructural defects of the material. Hydrogen diffusion and penetration will depend on hydrogen partial pressure and cyclic stress by static loads during operation. Blended hydrogen mixtures with natural gas or carbon dioxide inhibited hydrogen embrittlement [31], but such mixtures are hardly likely for the transportation of hydrogen produced offshore, as natural gas or CO₂ will likely not be available. Such circumstances make it difficult to reuse existing subsea pipelines for gas transport to carry offshore hydrogen to land, as it should be needed a lot of pending research and understanding about the degradation of current gas steel pipes for hydrogen transportation [32].

In existing hydrogen infrastructures, low-alloy steel tubes are preferred for hydrogen pipes, such as X42 and X52 steel pipes recommended by ASME B31.12 standards. Some recent scenario analyses for hydrogen logistics follow this recommendation [33]. The use of higher-grade steels, X65, X70 and higher, for hydrogen transport is being investigated [34,35], which may imply a review of ASME standards, as the main reference for gas transmission and distribution piping systems. Non-metallic flexible pipes undergo a considerable reduction in installation and maintenance costs. Due to the current limitations of diameters and admissible pressures for flexible hydrogen pipes, as is the case of high-density polyethylene (HDPE) pipes, their use would be mostly applicable to low-pressure, low-transmission capacity. Plastic lines with higher diameters and operating pressures are expected to be developed in the following years. Currently, they are applied for low-pressure and short distances [34].

In respect of cost estimates for hydrogen pipelines, according to a report provided by the transmission system operators (TSOs) for the European Hydrogen Backbone [36], it is reported between 0.17 and 0.32 EUR/kg/1000 km for new pipes with a diameter between 500 and 1200 mm.

3.2. Hydrogen Transport by Ship

The alternatives for hydrogen transport by ship depends on the storage options that would be available, namely compressed hydrogen (cH₂), liquified hydrogen (LH₂), ammonia (NH₃), other hydrogenated compound as light organic hydrocarbons (LOHC) or methanol. Such facilities are expected to be available onshore, and, in particular, in the vicinity of ports, and they might play a role as energy hubs [22]. The available reports about long-distance hydrogen transport show how shipping is a sensible alternative between ports [9,23] with suitable infrastructures.

In the case of the production of any energy vector rather than electricity offshore, it is important to consider the feasibility of the transformation processes from electricity to hydrogen and any other chemical vector. In most of the cases, it is considered the offshore production of hydrogen by electrolysis. The addition of a hydrogen liquefaction plant or an ammonia synthesis facility for its loading in transportation ships makes much more complex the structure and equipment to be installed and operated in an aggressive environment, as is the case of the deep sea. In that sense, the liquefaction of hydrogen or its conversion offshore into a vector as ammonia or any other synthetic seems to be handicapped with respect to the transport of compressed hydrogen.

3.3. Hydrogen Transport by Truck

The most mature transportation means for hydrogen is trucks, which are the preferred option for short distances within the delivery capacity of such vehicles. In the case of compressed hydrogen in tube trailers, their capacity is relatively small, around 300 kg/truck [37]. Liquid hydrogen trucks are able to transport on the order of 5000 kg of hydrogen per vehicle. In this report, this option is not going to be considered, except as one of the pathways to distribute hydrogen stored directly at ports to local consumers.

4. Hydrogen Storage, Bunkering and Distribution

The alternatives for hydrogen storage at ports depend on the type of hydrogenated vectors that would be finally adopted for sustainable maritime transport. The compatibility between low-carbon fuel bunkering, storage at port, and the hydrogenated compound to transport offshore production to port should be granted, either by an easy physical exchange or by an efficient transformation between energy vectors (electricity–hydrogen, hydrogen–ammonia, gasification, liquefaction). There are already a lot of uncertainties about which will be the preferred onboard fuel for shipping. Liquid hydrogen is one of the options [38], as well as ammonia [10]. In particular, both seem more suitable for long-range transport with respect to compressed hydrogen due to the higher energy density onboard [39].

Hydrogen stored onshore will be distributed for its consumption in a variety of applications that may include industrial off-takers, refueling stations, injection into local transport networks, ship bunkering or any other delivery option. For such distribution, there are two main options: by existing or new pipelines, or by truck. The choice will depend on the transport capacity required, the distance and other regulated aspects. For high capacity, pipes are the most cost-effective option, either by a new brand pipe for distribution (>10 tons/day) or by using hydrogen admixtures in existing natural gas pipelines (>100 t/day) [40]. On the contrary, urban and local hydrogen distribution, with capacities lower than 10 t/day, will be more cost-effective with compressed gaseous hydrogen at a cost of around 0.65–1.63 EUR/kgH₂. The vessel bunkering system will depend on the infrastructure that will be needed to fuel the maritime fleet.

5. Cost Analysis

There are perspectives of cost reduction on every level of the hydrogen value chain as a consequence of the huge investment effort into development and innovation. The current cost analysis may be conducted according to the current state of the art, including cost reduction for the near future. Nevertheless, the economic viability and competitiveness of each alternative may be obviously affected by the expected lifetime and retrofitting cost of infrastructures, especially when CAPEX (capital expenditure) cost is dominant.

The realistic alternatives for the delivery of energy produced offshore and its integration into a hydrogen system onshore are the direct transport of electricity by subsea cables, hydrogen subsea pipelines or liquid/compressed hydrogen vessels. Figure 1 shows the different pathways to transport offshore energy generation to a port on land. The more viable alternatives are linked by the red paths and arrows. Ammonia synthesis is discarded in this analysis of the levelized cost of energy transport from the offshore platform to the port due to the additional complexity and cost of the ammonia synthesis plant. The electrolysis facility for the production of hydrogen might be installed either at the offshore platform or onshore. If the storage and bunkering are carried out in the form of ammonia or LOHC, additional transformation costs should be added. Hydrogen compression or gasification facilities have been excluded from the analysis for their additional cost. The scenarios with direct bunkering of the transported energy vector (LH₂, cH₂ or NH₃) are considered.

The levelized cost of the energy transport (LCOET) from an offshore location to shore has been evaluated from the classical definition, considering CAPEX, operational expenditure (OPEX) of each transport technology, a 25-year lifetime (N), and an annual capacity factor of 60% to account for the total amount of energy to be transported from the offshore plant and an average interest rate of 2% (r). The main input data is shown in

Table 1. Main data and uncertainties for the evaluation of LCOET for the transport by H₂ pipeline.

Parameter	Value	Uncert.	Unit	Ref.
Transmission capacity	0.1		kgH2/s
P max	35		bar
P min	15		bar
Hydrogen losses	483	10%	kg/km/y	[9]
CAPEX	0.12	5%	MUSD/GW/km	[36]
OPEX	0.8	10%	%CAPEX/y	[36]
Lifetime	25		y
Interest rate	2	10%	%

,

Table 2. Main data for the evaluation of LCOET for the transport of compressed H₂.

Parameter	Value	Uncert.	Unit	Ref.
Vessel capacity	50		tons	[9]
H2 consumed	0.06	15%	kg/s
Vessel life cycle	1513	10%	Journeys
CAPEX	22	5%	MUSD/GW/km	[40]
OPEX	0.8	10%	%CAPEX/y	[40]
Lifetime	25		y
Interest rate	2	10%	%

,

Table 3. Main data for the evaluation of LCOET for the transport of liquid H₂.

Parameter	Value	Uncert.	Unit	Ref.
Vessel capacity	12,760		tons	[9]
H2 consumed	0.06	15%	kg/s
Vessel velocity	0.96		m/s
Vessel life cycle	186	10%	journeys
Liquefaction plant cost	580	5%	MUSD
Offshore LH2 tank cost	1190	15%	MUSD
CAPEX Ship	26,200	5%	MUSD	[40]
OPEX	3	10%	%CAPEX/y	[40]
Lifetime	25		y
Interest rate	2	10%	%

and

Table 4. Main data for the evaluation of LCOET by subsea electric cable.

Parameter	Value	Uncert.	Unit	Ref.
Transmission capacity (max)	2		GW
Nominal trans. capacity	200		MW
Energy loss coefficient	1.37	15%	TJ/km/y	[41]
CAPEX	1.19	5%	MUSD/GW/km	[42]
OPEX	0.67	5%	%CAPEX/y	[43]
Lifetime	25		y
Interest rate	2	10%	%

for the cases that we have considered. The output is provided by the equation:

$$\mathrm{LCOET} \left[\frac{\mathrm{USD}}{\mathrm{MWh}}\right]=\frac{\mathrm{CAPEX}+{\sum }_{\mathrm{n}}^{\mathrm{N}}\frac{\mathrm{OPEX}}{{\left(1+\mathrm{r}\right)}^{\mathrm{n}}}}{{\sum }_{\mathrm{n}}^{\mathrm{N}}\frac{\mathrm{Energy} \mathrm{transported} - \mathrm{Energy} \mathrm{losses}}{{\left(1+\mathrm{r}\right)}^{\mathrm{n}}}}$$

(1)

Being the CAPEX linearly dependent on the distance and capacity, and the yearly OPEX is a fraction of the capital cost according to the references on the input data tables. Energy losses are neglected for the case of pipes, as pumping is included in the OPEX, and compressed hydrogen.

Regarding electric subsea cables, the infrastructure cost has three different components: the branch cost which represents the cost associated with the cable between both end stations, the onshore station cost, and the offshore station cost. The annual O&M (OPEX) is estimated at 0.67% of the installation cost. The CAPEX for the cost evaluation of a dedicated hydrogen pipeline is divided into costs of materials, costs of construction (survey, pipe laying and other labor costs) and costs associated with engineering, project management, inspection, repair, etc. The total O&M costs, excluding electricity, are estimated around 0.8% of the total costs of the pipeline. In the case of liquid H₂ ships, the CAPEX includes the infrastructure cost of the liquefaction plant, the costs of the storage tanks and the costs associated with the operation of the ships. In this model, it has been considered the option of time charter, because it seems to be the most appropriate charter type for this context. The OPEX is estimated around 3% of the cost of the liquefaction plant and 3% of the storage tanks [9]. For the case of the compressed H₂ ship, the CAPEX includes the costs of the compression plant, the storage tanks and the ship charter. Like in the LH₂, the considered option is time charter. The annual O&M will be estimated as 6% of the cost of the compression plant [9] and the O&M cost of 2000 USD/year per storage module in the compression plant.

The sizing and unitary costs of each hydrogen transport system depend on the amount of energy to deliver and the distance, which depends on the power capacity of the offshore plant. Two scenarios have been evaluated: a low-scale scenario as a typical case for a small 21-MW offshore wind farm, and a high-scale scenario with a 1-GW wind park. Those evaluations are shown in Figure 2 and Figure 3. Both scenarios, with an annual capacity factor of 60%, transport, respectively, 108 and 5160 GWh/year.

The cost of the alternatives for offshore hydrogen transport to shore is highly dependent on the scale. This is similar to onshore, where the main alternative for short distances and capacity is compressed hydrogen by truck. In the case of an offshore facility, this option is not available. From the cost analysis, there is a dramatic impact on the amount of yearly energy to transport, especially for hydrogen transportation.

Liquid hydrogen has the lowest sensitivity to the transport distance, as the costs of the liquefaction plant and offshore storage tank are the main expenditures. The capacity of liquid H₂ vessels is also much higher. Direct electric transport to the coast by a subsea cable is the more viable option for a wide range of distances and transmission capacities, with LCOET below 10 USD/MWh.

For distances below approx. 1500 km, liquid hydrogen is less competitive for the low-scale scenario, but it is more competitive than compressed hydrogen when a high transport capacity is demanded, being comparable with subsea cables and pipeline transport for long distances (1500 km and above). For the high capacity scenario, hydrogen transport by pipeline is estimated to be competitive above 900 km, with a levelized cost of transport between 10 and 20 USD/MWh.

6. Conclusions

The introduction of hydrogen is key for the decarbonization of multiple sectors of the economy. It has been shown an analysis of the alternatives for the particular case of producing offshore renewable electricity and its transformation into hydrogen for shore distribution, including their implementation for maritime transport and port decarbonization. Among the different options analyzed for producing hydrogen from offshore renewable energy, the most technically and economically viable option is transporting the renewable electricity generated offshore by subsea cable to land where the hydrogen production plant is located. The generation and transport of renewable electricity is a mature and well-known technology, as well as a lower cost and higher maturity than the facilities to produce hydrogen on shore. The analysis is based on the concept of LCOET (levelized cost of energy transport) to take apart the costs associated with energy generation (LCOE) dependent on the generation technology and the LCOS (levelized cost of storage). The LCOET depends mainly on the type of transport system and energy. In this case, electricity and hydrogen are the energy vectors that have been considered. The types of transport are adapted to the energy vector. The results have been presented to show the impact of the two main parameters affecting LCOET: distance between the energy generation site and the coast, and the energy capacity to transport (power/production) defining low and high-scale scenarios.

In the case of direct hydrogen generation offshore, an alternative option for the transport of green hydrogen produced to land is compressed gaseous hydrogen using subsea pipelines. The use of low alloy steels is preferred for hydrogen transport by pipelines. The ASME B31.12-2019 standard recommends the use of X42 and X52 steel pipes. However, some experts consider that higher-grade steels such as X70 steel could be used in the future. Steel pipes, although valid for the transport and distribution of hydrogen blended with natural gas, require a more detailed study for working with 100% hydrogen, mainly caused by the embrittlement effect on the material. Flexible (HDPE) pipes undergo a considerable reduction in installation and maintenance costs; they have not been considered in the analysis, as it was intended for a sensitivity analysis based on ASME materials as reference technical standard, and high capacity, long transport range, but its consideration should be carried out if confirmed they are suitable for subsea H₂ transportation tubes. In any case, regulations and standards are much less developed than for other cases, such as electric subsea cables.

Hydrogen transport by ship is intended for long distances, mainly port-to-port. The transport by means of compressed hydrogen is easier, but it is limited by the small amount of energy that can be transported. Ammonia and LOHC offshore facilities are not recommended due to their complexity and extra costs derived from construction and O&M. This analysis sheds some light and novelty on the comparative viability estimation offshore to port, being critical the cost and viability of the hydrogen synthesis offshore, more complex than at ports.

Regarding the LCOET comparison between hydrogen transportation by pipeline and by ship, the cost of compressed hydrogen transported by ship is lower than liquid hydrogen for the same capacity scenario. According to the LCOET, pipelines are the best solution for distances above 450 km for a high-scale scenario delivering the order of TWh/year. In opposition to the low-scale scenario, liquid hydrogen by ships is more competitive than compressed hydrogen when the energy transport to port is on the order of TWh/year, as the scale of liquid hydrogen transportation vessels is much higher.

Regarding hydrogen bunkering at ports, currently, the most viable option is through compressed gaseous hydrogen. Other options such as ammonia or methanol are still under development. In the short term, direct hydrogen application in maritime applications seems to be suitable for low and medium size vessels where energy consumption is moderate and weight is not a very important factor, as well as on short journeys in which stops in ports are made daily or with a similar frequency. They may also be applicable for ships for navigation in inland or port waters. Liquid hydrogen might be considered when hydrogen consumption grows to transport and deliver hydrogen for high-capacity vessels.