Environmental Considerations
1. Emissions profile, including life-cycle assessment (LCA)
Current IMO regulations address only emissions occurring on ships, but there is growing pressure for a full LCA methodology to assess Well to Wake (WtW) emissions. These would take into account both direct emissions from the ship (Tank to Wake, or TtW), and emissions from the production and distribution of fuels (Well to Tank or WtT).
Hydrogen has very low TtW emissions, and could be a zero-emission fuel if consumed in a fuel cell, or a single fuel Internal Combustion Engine (ICE). It could also could significantly reduce emissions when used in a dual fuel engine.
WtT emissions, meanwhile, are variable and largely dependent on the method of hydrogen production. From an LCA perspective, the production of hydrogen accounts for the majority of WtW emissions.
There are typically four types of hydrogen production pathways:
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Brown hydrogen, produced from the processing of coal
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Grey hydrogen, produced from the processing of natural gas or other fossil fuels
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Blue hydrogen, produced from the processing of fossil fuels accompanied with emission control technologies, including carbon capture, utilization and storage (CCUS) methods
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Green hydrogen, produced from renewable energy sources, typically via electrolysis using water. Sources of electricity can include solar or wind power to provide net-zero carbon hydrogen production
Carbon Release from Hydrogen Production With and Without Using CCUS Compared to Marine Gas Oil (MGO) as Baseline
2. Environmental factors (in particular those affecting coastal and port communities):
Hydrogen will dissipate quickly when exposed to an open environment due to its low boiling point and very low density in comparison to air.
Hydrogen is considered non-toxic but is highly explosive both in its liquid and gas form.
3. Expected savings in GHG emissions and how is it verified/recorded:
As in previous diagram, certificates of origin could be used however nothing has been mandated by IMO.
4. Energy content:
120.2 MJ/kg, however due to lower volumetric energy density liquid hydrogen may require four times more space than MGO.
Technology for Production of the Fuel
1. Most advanced projects underway:
Most advanced Projects underway and over the horizon for green hydrogen appear to be the HyDeal ambition project, however update on project status is required. It was listed in February 2021 that they would start hydrogen production in 2022 but it remains unclear if the pandemic has impacted this.
2. Investment projections (costs and capital expenditure needed):
There is not much available on project costs and expenditure, but the Saudi Arabian Hellos project is receiving an investment of USD5 billion and it only represents 15% of HyDeal electrolyser capacity, so a figure more than USD20 billion may be in order.
Technology as Marine Fuel use
1. Quality parameters to be met (basic properties, flammability, toxicity considerations):
Due to its molecular simplicity, unless the hydrogen is contaminated, its physical properties are very predictable, as unlike most marine fuels it has a very large flammable range (4% to 75% in air) and is not toxic. The “burning velocity” and the energy required for ignition vary considerably with the ratio of hydrogen to air which has implications for safety with any leaks. At 20% Hydrogen to air it requires only 10% of the ignition energy of methane at 10% methane to air.
2. Technology development status: Current status of engine development, fuel cell systems for using alternative fuels:
As of 2021 the two principal applications of hydrogen as fuel were in Otto cycle engines (gasoline engines) and in fuel cells. In both applications it is used in road transport, but the complexities of storage limit the overall size and power output. One manufacturer has a 200-kW engine running now and scheduled for customer trials in 2022. Most of the current developments are focused on using a mix of hydrogen with natural gas in stationary applications. Hydrogen can be used as a single fuel in Otto cycle engines and together with a pilot fuel in a Diesel cycle engine. We will not know the degree of modification needed in dual fuel engines for at least the next 3 years.
Rederi AB Gotland announced in December 2021 that they plan on building a Swedish ferry before 2030 which will utilise multi-fuel turbines including hydrogen for propulsion.
There has been considerable research into storage of hydrogen on board. The most likely scenarios are storing as a cryogenic liquid at -253° C or as a compressed gas at between 350 and 700 bar. There are alternatives under examination and one such technology, Liquid Organic Hydrogen Carriers or LOHC’s looks encouraging. This requires the carrier molecule to be hydrogenated prior to storage and dehydrogenated prior to use. Work continues into this area, and it may yield practical solutions in the medium term. It permits the storage on board at normal temperature and pressures. The research into cryogenic storage comes from the US space programme and this shows that there are technical hurdles to be overcome in materials, heat flux and bunker transfer.
3. Types of vessels using technology/ best suited for technology:
It is probable that the first practical marine applications will be in small vessels – work boats, small ferries etc. and that they are likely to have hybrid power systems (internal combustion engines, fuel cells and battery systems). Fuel storage will initially be as compressed gas.
4. Engine modifications and current technological status (including dual fuel engines):
As stated before, modifications for pure gas engines (Otto cycle) will be minimal and related to safety issues and engine control. For dual fuel (Diesel cycle) engines the degree of modification may make retrofit impractical, but we will not know for some years.
5. Retrofit requirements, timelines, and costs:
At this stage, other than vessels already using gas fuelled Otto cycle engines, retrofit seems very unlikely. Using fuel cells should be a simple transition for pressurised hydrogen fuel storage. The major cost for retrofitting a vessel already using Otto cycle gas engines will be the installation of suitable hydrogen storage and handling equipment and we are unlikely to be able to estimate the time or cost in the near term.
6. Considerations for an onboard fuel transition:
As stated previously, hydrogen fuel does not lend itself to engines routinely changing from one fuel to another. Vessels burning methane (stored as LNG or CNG) may be able to burn a blend of methane and hydrogen with very little modification other than to the fuel storage and handling systems. Changing between pure methane and pure hydrogen is a different matter as the control of ignition and combustion will need to be quite different to reflect the different flammable range and flame speed.
7. Safety issues. Managing the hazards and associated risks related to the shipboard application. What are some of the appropriate safeguards that can be put in place onboard?
At this time, most Class Societies will base their rules for hydrogen-fuelled vessels on the requirements for low flash point gas storage and use as laid down in the IGC and IGF codes. These cover the prevention of leakage of cryogenic liquid, the gaseous fuel and leakage of nitrogen where it is used as an inerting medium. The rules also cover the prevention of accumulation of flammable vapour in storage spaces and machinery spaces, the detection of flammable vapour and the controlled shut down of the fuel system in case of detection of leakage in enclosed spaces or extraction ventilation ducts. These precautions will involve double walled fuel pipes, permanent flammable gas detection systems and detection of nitrogen gas. The key principle is to prevent the presence of fuel vapour and air in the same space at the same time. The bunker station must be designed as a zone 0 during fuel bunkering operations, but reverts to zone 2 on completion.
According to hazard definitions Zone 0 is an area in which an explosive gas is present continuously or for long periods whereas zone 2 is for shorter periods, if at all. The pressure wave risks from a hydrogen leak / fire will require some blast screening for protection of personnel.
Emergency shut down devices (ESD’s) have been in use for the safe transfer of LNG and LPG for some time so we may see their use on hydrogen fuelled vessels. ESD systems ashore and on the ship are interlinked so they can shut down and isolate for a number of reasons including but not limited to manual trip, auto trip, power fail, fire detection, tank overfill and loss of containment.
Please see below a typical system component which link ship and shore by a hard-wired connection.
Credit Trelleborg
8. Operational issues (e.g. extra lubricants, higher MT/Hour equivalent consumption to traditional fuel -and alternatives-, adding/exchanging spare parts, software or subscriptions in order to record and report verifiable emissions savings):
Until we have operational experience, most of the above topics are “unknowns”. The lubrication requirements are unlikely to be a significant issue. The mt/hour consumption will be much lower than conventional fuels due to the high energy density of hydrogen. Emission reporting will only become significant when we include “well to wake” as it will require knowledge of the production method of the hydrogen. It is likely that there will be a significant degree of training required for vessel staff for hydrogen fuelled vessels. This will need coordination via the STCW convention and will be more stringent than the requirements for the current IGF code.
9. Differentiation between short and deep-sea shipping:
The answer here is as expressed in item 3). Short sea shipping with power in the 200 kW to 4 MW range is likely to be the first sector to adopt hydrogen and will also initially use compressed gas storage. Heat leakage and boil off of liquid with lower powered vessels, and smaller tanks may present problems. This could be managed for short sea voyages where a base load is used for auxiliary power take-off.
Laws and Regulations
1. Current legislation and policies (IMO, EU, national and regional regulations)
IMO currently does not have specific regulations for the use of hydrogen as marine fuel. However, the IGF Code provides a general regulatory framework for low-flashpoint fuels. The work to include fuel cells in the IGF Code is already completed and awaits formal adoption by the IMO, however the bunkering, storage, and handling of hydrogen as fuel is currently not included. The only IMO regulation related to hydrogen is MSC.420(97) Interim recommendations for carriage of liquefied hydrogen in bulk which handles hydrogen as cargo rather than a fuel.
2. Industry guidance currently available:
Industry guidance on hydrogen as marine fuel is given mainly by the classification societies ABS, DNV, LR and NKK.
3. ISO /ASTM Specifications currently available:
ISO has technical committee TC197 for Hydrogen technologies. The TC 197 has published 18 standards and 16 standards are under development. Most of the developed standards are for land vehicles for fuel quality, fuelling stations, fuel tanks, and hydrogen generators. There are no marine specific hydrogen standards yet.
ASTM has subcommittee (SC) D0314 on hydrogen and fuel cells engaged in developing fuel quality standards for hydrogen fuel cell vehicles. Currently SC has developed 9 ASTM methods to support the commercialization of hydrogen as a vehicle fuel.
Demand / Supply
1. Current production levels and locations:
The majority of hydrogen is currently produced from fossil fuels. It is estimated that 90 Mt hydrogen was produced worldwide. Hydrogen is produced locally near the consumption location as pipelines and storage facilities are rare.
Hydrogen production in 2020
2. Production restrictions (such as biofuels requirement for farming area):
Hydrogen can be produced by fossil fuels which is inevitably not zero emission, and from electrolysis which can be truly zero emission if renewable energy is used. The production restrictions are from renewable energy availability and use of hydrogen as feedstock for other fuels such as ammonia.
3. Plans of localized production so to minimize the emissions outlet during production and transportation to the end user:
Plans exists for electrolysers as follows, most of the plans are local facilities:
4. 5 years and 10 years production levels scenarios:
Three scenarios were developed as “Stated Policies Scenario” (STEP), “Announced Pledges Scenario” (APES), “Net Zero Emissions by 2050 Scenario” (NZE).
5. Green production levels:
In 2020, 30 kt of H2 was produced from electrolysis (0.03 %) and 0.7 Mt H2 was produced from natural gas using Carbon capture utilisation and storage (CCUS).
6. Current feedstock availability:
There is no feedstock availability problem as fossil fuels or water is required as feedstock. However, production of hydrogen is an energy intensive process, hence availability of energy is the main concern.
7. 5 years and 10 years feedstock availability scenarios:
Same as above.
8. Current retail supply availability:
Hydrogen is produced according to demand as storage and transportation facilities are rare, hence supply infrastructure is very limited. 400 bcm global gas storage is reported in 2020 equivalent to 10 % of the yearly consumption.
9. Potential future retail supply availability – 5 years scenario, 10 years scenario:
Not enough information is available as storage of hydrogen is problematic. An estimated 50 Mt (550 bcm) storage is required by 2050 to keep same storage ratio as estimated demand for 2050 is 530 Mt.
10. Demand from other industrial sectors:
Hydrogen is required for many essential chemical processes such as oil refining (40 Mt H2 in 2020), and industry (50 Mt H2 in 2020) for the production of ammonia and methanol (45 Mt H2 in 2020), iron and steel making (5 Mt in 2020). In addition, it is used as a fuel in land transportation.
Distribution
1. Bunkering infrastructure (potential fuelling sites, distribution, storage, carriage):
Hydrogen is a very low-density gas which results in slow fuelling/bunkering in the form of compressed gas. In current automotive refuelling, storage for compressed hydrogen is usually in type II vessels (up to 200 bar) which are made of a combination of a polymer liner wrapped around a metallic tank, but with the polymer liner only wrapped around the cylindrical part of the vessel or type III tanks (700 bar), built on the type II vessels with the addition of a metallic liner fully wrapped with the composite fibre for support. The filling rate for compressed hydrogen in automotive practice is limited to 1kg per minute and the gas is precooled to -40⁰C to counter the heating effect of the operation. This is clearly unworkable for anything other than small ferries or workboats. Some automotive applications have opted for liquid hydrogen on board storage but the size of the tanks and the control of “boil off “are problematic. The vehicles have a driving range of about 300 km but can only contain the liquid fuel for about 5 days. This should not be a significant issue for shore bunkering facilities or large ships as they will have frequent or continuous offtake of product from the tanks.
Design of hydrogen bunker stations will need to take particular care over the possibility of a significant leak infighting as the flame speed will generate an explosive pressure wave far greater than would be seen from LNG. The low density of hydrogen does have some advantage in that smaller leaks will dissipate in the atmosphere very quickly.
To date, no ships have been designed/produced for bulk transportation of liquid hydrogen. All current distribution is via pipeline or by road tankers.
2. Projected bunkering infrastructure – 5 years scenario, 10 years scenario:
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The infrastructure growth will depend on 3 elements:
- The expected demand (especially the split between pure hydrogen fuel and hydrogen blends with natural gas).
- The development of bulk liquid hydrogen storage at hub ports.
- The development of liquid hydrogen carriers (gas tankers) for distribution and bunkering.
The first and second elements will be largely based on economics and governmental policy incentives as the core technology should not be problematic. The third element is more difficult to read as there is no current model to use as a baseline.
If hydrogen remains limited to short sea and predominantly compressed gas, then it is unlikely to develop significantly in volume in the next 10 years. If early adopters can encourage the development of liquid hydrogen bunkering, even if limited to a few ports, then there is the potential to see a demand of 5 to 10% of global bunker demand within 10 to 15 years.
The prospects for other hydrogen-based fuels (synthetic fuels) are much better as they will avoid the complexities of cryogenic storage, liquid hydrogen bunker operations and the issues of risk and hazards of hydrogen use.
3. Fuel storage volume and weight requirements, location of storage, storage requirements (pressure and temperature) for both existing vessels and new buildings:
Liquid hydrogen will require approximately 4.6 times the storage tank volume of VLSFO for the same steaming range. There will be an additional volume penalty to cover the void spaces, cold box and valve rooms required for the cryogenic tanks, which will be comparable to that required for LNG, thus increasing the overall storage space requirement from 4.6 up to about 6 times the volume required for VLSFO. There is no mass penalty as the energy per unit mass of hydrogen is so high. Initial studies indicate tank locations for liquid hydrogen will be like those for LNG. The liquid will be stored at -253°C and pressure of less than 10 bar. Gaseous hydrogen will be stored at atmospheric temperature and a pressure of about 700 bar or at a lower temperature and a pressure of about 200 bar. The above conditions will almost certainly preclude the retrofit of existing vessels to use hydrogen fuel except for natural gas fuelled vessels using a blend of natural gas and hydrogen.
Pricing
1. What factors needs to be taken into consideration when pricing hydrogen:
- Presently hydrogen produced from fossil fuels is more competitively priced than from renewable energy, however we expect this to shift in the opposite direction by 2030 according to IRENA (International Renewable Energy Agency).
- IMO Decision on well to wake emissions will be used for analysis.
- EU ETS, FuelEU Maritime and other Regional GHG reduction systems
- CO2 pricing
- Carbon levies and carbon trading
- Capital expenditure
- Fuel costs
- Transmission and distribution costs
- Infrastructure
- Tax incentives – for example the EU Energy Tax Directive (ETD)
2. Impact of rebates (if any) on pricing:
- Tax incentives will reduce cost of green hydrogen but not black hydrogen.
- It’s hard to say how much positive impact rebates will have until more is decided regionally and globally.
3. Renewable power pricing:
- According to IRENA renewable energy dropped in cost by as much as 85% between 2010 & 2020. This is driven by economies of scale, better supply chains and improving developer experience. Heavy investments past 2030 will see an increase in renewable energy production as well as green hydrogen. However, this may depend on regional systems such as ETS, other industry initiatives and levels of Government funding.
4. What is the current USD/MT equivalent? (calorific value adjusted):
- For green hydrogen it is presently USD6/ kg
5. Projection of Forward Prices:
Hydrogen production costs are expected to decrease by 50% between now and 2030. Green hydrogen may be around USD2-2.5/ kg by 2030 and may head closer to USD1.5/ kg by 2050 dependant on several variables.
References
Hydrogen as a Marine Fuel Whitepaper – ABS
International Renewable Energy Agency
https://interestingengineering.com/the-worlds-top-green-hydrogen-projects
https://www.eqmagpro.com/over-540mw-of-green-hydrogen-capacity-announced-in-spain-during/
https://www.eqmagpro.com/woodmac-on-green-hydrogen-its-going-to-happen-faster-than-anyone-expects/
https://www.csis.org/analysis/hydrogen-key-decarbonizing-global-shipping-industry |