Feasibility of Retrofitting a Conventional Vessel with Hydrogen Power Systems: A Case Study in Australia

Abstract

As the pursuit of greener energy solutions continues, industries worldwide are turning away from fossil fuels and exploring the development of sustainable alternatives to meet their energy requirements. As a signatory to the Paris Agreement, Australia has committed to reducing greenhouse gas emission by 43% by 2030 and reaching net-zero emissions by 2050. Australia’s domestic maritime sector should align with these targets. This paper aims to contribute to ongoing efforts to achieve these goals by examining the technical and commercial considerations involved in retrofitting conventional vessels with hydrogen power. This includes, but is not limited to, an analysis of cost, risk, and performance, and compliance with classification society rules, international codes, and Australian regulations. This study was conducted using a small domestic commercial vessel as a reference to explore the feasibility of implementation of hydrogen-fuelled vessels (HFVs) across Australia. The findings indicate that Australia’s existing hydrogen infrastructure requires significant development for HFVs to meet the cost, risk, and performance benchmarks of conventional vessels. The case study identifies key determining factors for feasible hydrogen retrofitting and provides recommendations for the success criteria.

1. Introduction

According to a 2020 study conducted by the International Maritime Organization (IMO), greenhouse gas (GHG) emissions from shipping have increased from 977 million tonnes in 2012 to 1.1 billion tonnes in 2018, representing a 9.6% rise [1]. In an effort to reach carbon neutrality, the IMO introduced the revised GHG Strategy during its Marine Environment Protection Committee (MEPC) 80 meeting, setting an enhanced common ambition to reach net-zero GHG emissions from international shipping by or around 2050 [2]. The strategy also includes a commitment to ensure the uptake of alternative zero and near-zero GHG emission fuels by 2030. Additionally, 195 parties have joined the Paris Agreement [3]. As part of the agreement, Australia has committed to reduce GHG emissions by 43% by 2030 and reach net-zero emissions by 2050. The Low Emissions Technology Statements (LETS) highlight Australia’s ambition to become a world-leading clean hydrogen producer and exporter, identifying clean hydrogen as one of the priority low emissions technologies [4].

In recent years, Australia’s domestic maritime GHG emissions have persisted at around 2 million tonnes annually, accounting for approximately 0.4% of the nation’s total annual emissions [5]. The Australian maritime fleet is predominantly composed of small domestic commercial vessels (DCVs), which are the largest contributors of GHG emissions from Australian vessels. Over 8700 vessels operating in Australian waters with valid certificates of survey are less than 50 m in length and more than 80% of these vessels have the potential to be replaced with zero-emission power systems in the next 10–20 years [5]. Zero-emission technologies for maritime vessels each have distinct strengths and weaknesses. Battery electric propulsion offers high efficiency but is limited by energy density and charging infrastructure [6,7]. Hydrogen power systems provide fast refuelling but face challenges in logistic, storage, and conversion efficiency [8,9,10]. Green ammonia and methanol power systems can leverage existing bunkering infrastructure but require advancements in supply chains and engine technology [7,11,12]. The maritime industry’s transition to zero-emission solutions will require a balanced approach that considers energy density, operational flexibility, and infrastructure readiness.

A study [13] concluded that fuel cell (FC) technology has the potential of being more efficient and cleaner than conventional internal combustion engines (ICEs) and gas turbines. However, nearly a decade later, the design and development of hydrogen-fuelled vessels (HFVs) remain complex, requiring solutions to numerous design challenges [8,9,10,14]. The most prominent challenges arise from the properties of hydrogen: it is a highly flammable gas prone to leaks and is deeply cryogenic in its liquid state. Combined with its relatively low volumetric energy density, these characteristics introduce complications regarding fuel storage, including storage methods, materials, space requirements, and locational constraints. Nonetheless, hydrogen is suitable for marine applications, as its risks and hazards are well understood [15]. The maritime use of FCs and compressed hydrogen (CH₂) high-pressure cylinders are now commercially available [5], and the cost of green hydrogen in Australia is projected to decrease to levels comparable to fossil fuels, with the Australian government setting a stretch goal of under AUD 2 per kg of H₂ [16].

This paper investigates the feasibility of retrofitting a conventionally fuelled vessel with hydrogen power systems. The research explores various design challenges with reference to classification society requirements and analyses the feasibility of such undertakings through an asset management (AM) approach.

2. Scope and Methodology

The retrofit design of a hydrogen-fuelled vessel (HFV) is dictated by various technical and commercial considerations, primarily established by regulatory bodies, and the assessment of cost, risk, and performance. Ideally, a retrofitted HFV should maintain the safety, capabilities, functionality, and economic viability of the benchmark conventional vessel. This includes, but is not limited to, considerations of the vessel’s mission statement, tank capacities, bunkering requirements, safety ratings, and hydrostatics. However, achieving these objectives is challenging in retrofit applications due to the unique design constraints associated with hydrogen power systems.

This paper examines these challenges through a detailed case study of a conventionally powered (marine diesel oil, MDO-fuelled), non-self-propelled aquaculture feed barge. The study provides theoretical yet pragmatic insights into the feasibility of retrofit applications within the Australian context. The retrofit specifications are evaluated in alignment with AM principles, design and system considerations, and the guidelines set forth by the relevant classification societies, international codes, and Australian regulations.

AM principles are the key methodology employed in conducting the feasibility studies. As stated in the literature [17], “Balancing cost, risk, and performance is the essence of value generation in any asset management system and forms an integral part of the decision-making process. Regardless of the approach, every decision in asset management should consider the elements of cost-effectiveness and risk moderation. Moreover, balancing cost, risk, and performance also depends upon the distinctiveness of the value. Applying one specific methodology to all scenarios is not practical”. The author of the publication [17] also postulates that “any AM activity, problem, issue, and/or solution from tactical to strategic level has cost, risk, and performance elements inherently embedded in it in a certain percentage composition; this is called Asset management Value (AMV) balance”. The empirical equations provided below define this balance [17].

$$Value=(Performance-Cost) @ Risk$$

(1)

The value can be tangible or intangible, financial or non-financial, and is measured either quantitatively or qualitatively with regard to the application and its intended objective. The international standard on risk management, ISO 31000 [18], indicates that risk has a negative effect on objectives. Cost is also considered a negative effect; thus, as depicted in Equation (1), value can be expressed as performance minus cost, considering the associated risks. In this study, the vessel’s performance is defined by its efficiency and ability to fulfil its mission. This refers to its fish feed capacity and the duration it can operate before returning to port or conducting bunkering operations. The cost and risk aspects refer to the commercial and technical considerations. Overall, the AM approach helps to identify the determining factors of the feasibility criteria and highlights the aspects that must be addressed to move toward a feasible application.

3. Overview of Hydrogen-Fuelled Vessels

Fundamentally, an HFV uses hydrogen fuel to generate electricity via FCs, powering onboard systems and storing energy in batteries for hybrid power generation and auxiliary power. These onboard systems have increased risks, higher overall costs, and relatively compromised performance compared to a conventional vessel. This is due to the major design challenges of a hydrogen power system, particularly considering the current state of technology and infrastructure in the maritime industry. The following subsections provide overviews of the three main systems that dictate and define the design of an HFV.

3.1. Fuel Hydrogen

The onboard storage of hydrogen presents a significant challenge that must be addressed in retrofit applications. Hydrogen’s low volumetric energy density compared to conventional diesel oil necessitates the use of larger tanks to achieve equivalent energy storage capacity. Regardless of vessel size, ensuring sufficient hydrogen storage space remains a fundamental challenge in ship design [19,20,21]. Additionally, its extremely low flashpoint imposes stringent requirements on the storage method, location, and area to ensure safety. Hydrogen’s low fluid density can lead to unfavourable changes in weight distribution, which may adversely impact the stability of a conventional MDO vessel in retrofitting applications. Furthermore, hydrogen’s small molecular size makes it susceptible to causing hydrogen embrittlement in storage tanks—a process where hydrogen atoms diffuse into metals, reducing ductility and compromising the structural integrity of the tanks [22]. To mitigate this phenomenon, industry-proven solutions include specially engineered alloys, protective coatings, and corrosion inhibitors. However, these measures increase both procurement and storage costs. In maritime applications, hydrogen is predominantly stored as CH₂ or liquid hydrogen (LH₂), each with its own set of technical and economic considerations.

LH₂ offers a relatively higher energy density but requires cryogenic storage at approximately −253 °C, necessitating insulated tanks and incurring significant storage and production demands [23,24]. Producing LH₂ also requires considerable energy to cool hydrogen below its critical point, contributing to higher production costs. CH₂, on the other hand, is stored in high-pressure tanks, typically ranging from 250 to 700 bar, which demands more storage space for an equivalent energy supply [23]. According to the literature [25], CH₂ is the most common storage method for hydrogen in mobility applications due to its technological maturity, wide availability, and cost-effectiveness. However, CH₂’s lower volumetric energy density necessitates more frequent bunkering compared to LH₂.

While LH₂ offers superior energy density and reduced storage volume requirements, its production, procurement, and storage are more expensive [26]. In contrast, CH₂ benefits from more established infrastructure and widespread adoption in both maritime and automotive industries, reducing overall costs and risks related to production, bunkering, and storage. Within the Australian context, the infrastructure for CH₂ production and bunkering is more developed than for LH₂ [27], making it a more suitable choice for domestic vessels. As such, CH₂ is selected for consideration in this study.

3.2. Prime Mover—Hydrogen Fuel Cells

Hydrogen power systems typically operate using FCs or ICEs. FCs convert hydrogen into electricity, while ICEs use hydrogen as a fuel to generate thermal energy. Hydrogen FCs are more efficient than ICEs in terms of the power output and GHG emissions. However, for small vessels, FCs and their associated systems can often occupy relatively more space for equivalent energy output and therefore prompt greater spatial requirements, which may compromise useful space on board. Hydrogen ICE technologies are currently not as developed and refined as FCs for maritime applications. Thus, at present, FCs are more favourable in the development of zero-emission hydrogen-powered vessels, especially as FC technology becomes more advanced and readily available, ultimately reducing cost and becoming more accessible. They are especially feasible in vessels that are unmanned and not self-propelled, which require less maintenance-intensive systems on board and a relatively less comprehensive approach to the design in terms of the onboard systems and crew safety considerations. This study considers Proton Exchange Membrane (PEM) FCs for the investigation in order to align with the goal of achieving net-zero emissions by 2050.

3.3. Energy Storage—Batteries

During routine operations, a vessel may be subject to several load variations, which cannot always be satisfied via FCs due to their longer response times. To satisfy the power demand in these conditions, HFVs are often fitted with an electrical energy storage system (ESS) such as batteries. These batteries provide a form of hybrid power system that addresses adverse energy gradients, powers auxiliary systems, and provides powering redundancy in the case of a single failure [8]. Excess electricity generated by FCs during lower power demands is stored in the batteries [28]. Lithium-ion (Li-ion) and lithium-polymer (LiPo) are the two most commonly used battery types in marine applications, which use a liquid and solid electrolyte, respectively. Li-ion batteries often have a relatively higher energy density; however, LiPo batteries are lighter, flexible, leak-resistant, and capable of being engineered into any shape, making them safer and more suitable for maritime applications [29]. Nonetheless, Li-ion batteries are more refined and readily available due to their widespread use across many industries, and thus incur reduced costs in comparison to LiPo batteries.

4. Design Considerations

The design of an HFV contains several systems which may not be found on conventional MDO vessels. The high-risk environment of an HFV prompts specific consideration to the onboard systems and special requirements for compliance with classification society rules and international codes [30]. Specific prescriptive IMO regulations are not yet in place for the use of hydrogen as a marine fuel; however, the International Convention for the Safety of Life at Sea (SOLAS) II-I opens the way for a structured design process based on risk assessments in cases where a ship is deviating from prescribed rules [31]. In terms of utilising FC, the IMO has issued the Interim Guidelines for the Safety of Ships Using FC Power Installations (MSC.1/Circ.1647) [32]. The main international code applicable to vessels using alternative fuels is the International Code of Safety for Ships Using Gases or Other Low-flashpoint Fuels (IGF Code) [33]. Currently, the IGF Code only provides requirments for liquified natural gas-fuelled vessels and refers to the alternative design approach for the approval of using hydrogen and other fuels. The approach requires a risk-based approval process to obtain an equivalent level of safety compared to a conventionally fuelled ship [34]. The IGF Code working group plans to completed drafting interim guidelines for hydrogen-fuelled ships until 2026 [35]. Many classification societies provide rules or guidelines for HFVs, such as ABS [36], BV [37], CCS [38], DNV [39], KR [40], LR [41], and RINA [42]. Some of them are appointed as Australian Maritime Safety Authority (AMSA)-recognised organisations [43]. This section provides an overview of the systematic considerations, which directly impact the vessel’s general arrangement design, with reference to class rules provided by BV [37].

4.1. Safety Assessment

Risk assessments, such as Hazard Identification (HAZID), Failure Modes, Effects, and Criticality Analysis (FMECA), and Hazard and Operability Studies (HAZOP), are required to ensure that any risks arising from the use of hydrogen affecting persons on board, the environment, the structural strength, and the integrity of the ship are addressed. These documents are highly technical and require extensive analysis of system interactions to assess the potential risks and propose mitigation measures. Nonetheless, the classification society rules set the basis for a safe design.

The high-risk environment of an HFV presents various areas of concern in terms of safety, leading to several limitations on the use of available space and accessible areas [44,45]. Therefore, the vessel design is majorly affected by the safety considerations. Nonetheless, these considerations can be eased on unmanned vessels, such as the barge considered in this paper, as they provide more opportunity to optimise the useful space onboard by having relatively higher allowable risks and hazardous areas in the absence of crew. Hydrogen bunkering is also considered a high-risk operation where classification societies define various rules. These considerations include, but are not limited to, the load on bunkering manifolds, hose material grades, locational constraints, piping routes and connections, monitoring and alarms, ventilation, redundancy, and emergency measures [8].

4.2. Arrangement on Board

The arrangement and location of spaces for hydrogen storage, distribution, and use should be designed to minimise the number and extent of hazardous areas. These spaces should be arranged to prevent the accumulation of hydrogen by having simple geometric shapes, sloping ceilings, and avoiding obstructing structure in the upper part. Additionally, several design restrictions should be applied to hazardous areas onboard, limiting accesses, outlets, inlets, and the overall general arrangement.

4.2.1. Hydrogen Fuel Location and Arrangement

Hydrogen fuel tanks should be located such that they are protected from external damage caused by a collision or grounding. The rules and regulations can vary across different classification societies; however, it is a common commandment to not locate hydrogen tanks within machinery spaces, cargo spaces, service spaces, or accommodation spaces. Generally, tanks are not to be installed in congested areas. This also includes tanks or equipment located on an open deck where sufficient natural ventilation should be warranted to prevent the accumulation of escaped hydrogen.

4.2.2. Compressed and Portable Hydrogen Tanks

CH₂ tanks are generally not allowed to be stored in enclosed spaces. However, this is subject to special consideration in accordance with the classification society requirements and risk assessments. As a minimum, CH₂ tanks in enclosed spaces must have adequate means to depressurise and avoid a hazardous atmosphere. Suitable protection must be provided on all surfaces within the enclosed space to protect against any lost high-pressure hydrogen gas unless the bulkheads are designed for the lowest temperature that can arise from hydrogen expansion leakage. A fire extinguishing system must be installed along with a mechanical forced ventilation system that is sufficient in diluting to an average gas concentration below 25% of the lower explosive limit (LEL) in all maximum probable leakage scenarios. Spaces used for the storage of CH₂ are not to be used for the storage of other combustibles, tools, or objects not part of the hydrogen distribution system. Sources of heat must be kept clear in these spaces. On open decks, cylinders are to be properly secured, and all valves, pressure regulators, and pipes leading from such cylinders are to be protected against mechanical damage. Portable hydrogen fuel tanks are to be located in dedicated spaces where if located in an enclosed space, that area is considered to be a tank connection space. Containerised fuel tanks on open deck may be considered as an enclosed or semi-enclosed space if the ventilation around the tank is not sufficient.

4.2.3. Tank Connection, Fuel Preparation, Machinery, and Gas Valve Unit Spaces

All tank connections, fittings, flanges, and tank valves are normally enclosed in a gastight tank connection space unless located on an open deck. The space is to safely contain leakage from the tank and ensure that the hull structure will not be exposed to unacceptable cooling in the case of leakage from the tank connections. The space must be designed to withstand the maximum pressure buildup during a leakage scenario or alternatively, pressure relief venting must to provided to a safe location. Access to the tank connection space is to be arranged as a bolted hatch or a gastight door and an airlock unless the space is independent and direct from the open deck. Fuel preparation rooms are required to accommodate the systems associated with LH₂ storage, whereas for CH₂ applications, all associated systems can be incorporated into the tank connection space. The machinery space is to be arranged to ensure that it is gas safe under all conditions. This infers that a single failure is to not lead to the release of hydrogen into the machinery space. Risk assessments are required to ensure acceptable safety ratings if the machinery space contains any engines, hydrogen-fuelled or not. Gas valve unit (GVU) spaces may be located in tank connection spaces, fuel preparation rooms, an enclosed space within the machinery room, or an independent space that fulfils the criteria of a fuel preparation room with respect to location, access, ventilation, and gas detection. Access to GVU rooms must be arranged through an airlock from gas-safe hydrogen consumer machinery spaces. To reduce the response time in case of load variation and to limit the amount of hydrogen released in the case of a leakage, GVUs are usually located within close proximity to hydrogen consumers.

4.2.4. Fuel Bunkering Station

The bunkering station should generally be located on open deck with sufficient natural ventilation. For closed or semi-closed bunkering stations, gas- and liquid-tight boundaries against enclosed spaces are normally required and are subject to special considerations based on risk assessment. The space must be arranged for the safe management of fuel spills and to prevent hull or deck structures from being exposed to excessive low temperatures in the event of any leakage.

4.3. Control of Atmosphere

The ventilation requirements of a space are usually determined by measures and estimations based on hydrogen leakage rate under normal operation. Ventilation capacity requirements are generally a function of the total volume of the room; however, an increased capacity may be necessary for rooms with complicated geometries. Some spaces may also utilise inert gas, such as nitrogen, to control the risky and hazardous nature of a given atmosphere. Nonetheless, gas or vapour detection devices are required to be fitted in any space containing hydrogen-related equipment, components, or piping. The number of detectors and their location are determined in accordance with the size, layout, and ventilation of the space.

Entry openings from non-hazardous to hazardous spaces must be arranged with airlocks. The ducting arrangement of hazardous spaces must be designed to eliminate the possibility of hydrogen accumulation, thus running continuously upward from the ventilated space up to the ventilation outlet without small radii of curvatures. The ducting for hazardous spaces is required to be separated from the ducting of non-hazardous spaces. Outlets from hazardous enclosed spaces must be located in an open area that, in the absence of the considered outlet, would be of the same or lesser hazard than the ventilated space.

Mechanical ventilation systems are required in spaces where hydrogen accumulation must be avoided. This generally consists of independent fans of a sufficient combined capacity to dilute the hydrogen concentration to an acceptable level even in the case of circuit failure. The fans are required to be of a non-sparking type that are approved by the society. As a general rule, the ventilation systems in tank connections spaces, fuel preparation rooms, machinery spaces, and gas valve unit spaces must be able to withstand the respective maximum pressure in case of hydrogen leakage. The space must provide a ventilation capacity sufficient to dilute the average gas or vapour concentration to below 25% of the LEL in all maximum probable leakage scenarios.

5. Feasibility of Achieving Equivalent Performance

Retrofitting conventional vessels with hydrogen fuel often results in reduced performance, higher costs, and increased risks compared to their conventional counterparts. To assess the cost, risk, and performance compromise, the following section analyses the feasibility of retrofitting an aquaculture feed barge—an Australian domestic commercial vessel—to hydrogen fuel.

5.1. Conventional Feed Barge Specifications

The vessel is an unmanned, stationary feed barge servicing fish feeding pens in Tasmania, Australia.

Table 1. Principal particulars of feed barge.

Principal Particular	Value	Unit	Capacity	Value	Unit
Length Overall	39.20	m	Feed	600.00	tonnes
Length WL	36.63	m	Fuel oil	28.60	m3
Moulded Breadth	12.00	m	Potable water	4.00	m3
Design Draft	3.90	m	Black water	3.27	m3
Installed Power	900.00	kW	Ensilage	57.50	m3
Frame Spacing	667.00	mm	Lube oil	0.24	m3
AMSA Class	NSCV3C	/	Acid tank	1.00	m3
Scantling	Lloyd’s	/	Mill tank	1.00	m3

presents the main particulars of the barge. It has an overall length of 39.20 m, a moulded breadth of 12.0 m, and a waterline length of 36.63 m at a 3.90 m design draft. The onboard systems supporting 600 tonnes of feed delivery to the pens are powered by 3 × 300 kW gensets, each weighing 2.5 tonnes. The vessel accommodates 28.6 m³ of fuel oil and undergoes bunkering operations every seven days.

5.2. Fuel Specifications

Table 2. Fuel specifications of barge.

Particular	Conventional Barge	Hydrogen-Fuelled Barge
Fuel Type	Marine Diesel Oil	H2 (350 bar)
Fluid Density (kg/m3)	920	23
Energy Density (MJ/m3)	38,000	2761
Bunkering Frequency (days)	7	7
Required Fuel Capacity (m3)	28.60	393.63
Fuel Weight (tonnes)	26.31	9.05

Note: The values presented in this table represent only the fuels (diesel and hydrogen) themselves and do not account for hydrogen cylinders. Based on a 450 L Type III 350 bar hydrogen cylinder specification (2160 mm length, 610 mm outer diameter, 202 kg weight), the estimated onboard volume and weight required for 9.05 tonnes of hydrogen are 526 m³ and 178 tonnes, respectively.

provides specifications for the HFV fuelling requirements (for equivalent performance) in comparison with the conventional feed barge specifications.

5.3. Hydrogen Availability

Hydrogen bunkering infrastructure remains underdeveloped in Australia, particularly in Tasmania [26]. The Metro Tasmania Mornington Bus Depot in Hobart, currently under construction, is the only hydrogen refuelling station in Tasmania [27]. This station will produce CH₂ at 350 bar, distributing it via CH₂ tube trailers. It will be commissioned for private use by Metro Tasmania for their hydrogen FC electric bus trial, with a designed dispensing and storage capacity of 150 kg/day and 185 kg, respectively. In this study, it is assumed that expanding the facility’s dispensing and storage capacity could meet the proposed vessel’s demand. The station is located approximately 60 km from the home port of the barge by road and 30 km by sea.

The Australian government is actively expanding Tasmania’s green hydrogen infrastructure, leveraging the state’s long history of renewable power generation [46]. In January 2024, the government announced a proposal for a new hydrogen hub in Bell Bay, Tasmania, capable of producing up to 45,000 tonnes of green hydrogen per year. Nonetheless, this hub is not primarily considered for this study as it is located 300 km away (by road and approximately 500 km by sea) from the home port, making it infeasible based on the bunkering frequency defined in Section 5.5.2, and the associated cost, risk, and performance compromise.

5.4. Determining Fuel Requirements

MDO and 350 bar CH₂ have a volumetric energy density of 38,000 MJ/m³ and 2761 MJ/m³, respectively. With a fuel capacity of 28.6 m³, the barge stores approximately 1086.8 GJ of energy. This requires approximately 394 m³ of 350 bar CH₂ to store 9.05 tonnes of hydrogen. Considering the CH₂ cylinders, the total estimated volume and weight increase to 526 m³ and 178 tonnes, respectively (see the note for Table 2), to achieve equivalent performance in terms of the bunkering requirements (to meet the energy demands). It prompts approximately 18.4 times the space demand and 6.8 times in weight compared to the conventional arrangement.

Accommodating this volume on the barge is infeasible due to spatial requirements along with the adverse effects on the vessel’s stability as a result of the drastic change in weight distribution. For simplicity, this study only focuses on the spatial requirements, assuming that stability challenges will be addressed by modifying the existing MDO fuel tanks to hold ballast. Referring to the theoretical tank dimensions provided in

Table 3. HFV tank capacity requirements.

Tank	Length (m)	Width (m)	Height (m)	Vertical Projected Area (m2)	Volume (m3)
Starboard (STBD)	14.80	7.00	2.54	103.60	263
Port	14.80	7.00	2.54	103.60	263
Combined	14.80	14	2.54	207.20	526

, Figure 1 provides a scaled visual representation of the hydrogen fuel tank area relative to the barge’s original design.

5.5. Feasibility Analysis of Fuel Requirements

Challenges associated with hydrogen storage stem primarily from hydrogen’s volumetric energy density. While the cylinders add weight, this can be effectively managed due to the fact that it is small compared to the weight of the barge. This section analyses the potential feasible solutions using the AM approach.

5.5.1. Altering Tank Arrangement

Although the fuel tank dimensions can be iterated and arranged in several ways, it is important to note that each method will have its own limitations. Ultimately, for the barge, the spatial requirements to accommodate the required fuel capacity (for equivalent performance) cannot be altered unless bunkering frequency is increased.

Table 4. Tank arrangement cases.

Case	Case Description	Advantage	Limitation
1	Distribute hydrogen into multiple smaller tanks strategically positioned across the open deck to maximise the utilisation of available space.	Tanks can be arranged within smaller available spaces, avoiding the need to modify the feed tank hatches or other existing structures and components.	More unusable restricted areas due to risk and safety considerations in accordance with class rules. This is not only due to the various tank locations, but also their respective components and piping distributed over a larger area.
2	Smaller tanks are strategically arranged throughout the vessel to maximise the utilisation of all available spaces.	Tanks can be arranged on the open deck as well as inside appropriate spaces below deck. This will allow for more space on the open deck and will not require many significant modifications to the structures and components on the open deck.	This prompts several special considerations and risk assessments in accordance with class rules. This can also compromise useful space on board due to structural modifications, safety, risks, and hazards considerations, and associated systems.
3	Maintain the segregation of tanks within a single designated location.	Minimises the area of hazardous spaces across the vessel. Bunkering operations are less complex and more time efficient. This will address the limitation of Cases 1 and 2.	Available tank capacity will be compromised, which will require more frequent bunkering and limit the time spent conducting feed operations.
4	Utilise portable tanks.	Potentially enables more efficient bunkering that can allow the vessel to spend more time conducting its intended operations. This will address the limitation of Case 3.	May not comply with the available space on the vessel and require several smaller portable tanks to obtain a feasible bunkering frequency. However, this will increase the area of hazardous spaces due to the vast number of tanks and their associated systems.
5	Utilise longer pressure vessels installed along the length and width of the open deck to optimise space and storage capacity.	The tank arrangement can be distributed more efficiently across the length and beam of the vessel (and in the spaces between the feed tank hatches). This will address some limitations of Case 4.	The long pressure vessels will have to be placed in various locations across the open deck, which will compromise useful space due to the safety and risk hazards. The longer pressure vessels will also have to be specially designed and engineered to suit the layout, which will increase cost and may not be supported by the dedicated bunkering station, and thus may prompt complications during bunkering operations.
6	Modify the feed tank spaces to accommodate portable CH2 tanks in the upper section, with feed storage retained in the lower section, separated by a removable hatch cover. This configuration can be complemented by fixed tanks installed on the open deck to maximise overall fuel capacity.	This will allow the vessel to carry more fuel, which will decrease the fuel bunkering frequency.	There will be immense design challenges presented in this due to the associated systems, and geometry of the fuel tanks and feed tanks. Bunkering operation will also become more complex and riskier due to the arrangement of the tanks and considerations for their associated systems. The logistics of feed and fuel bunkering will require significant considerations to address the bunkering plans of the portable tanks, fixed tanks, and the feed tanks. For the purposes of this study, it is assumed that these challenges can be addressed. The space occupied by the CH2 tanks will reduce the feed capacity, which will require more frequent bunkering for the feed. Thus, ultimately, the vessel will have to use the additional fuel to bunker for the feed, which will reduce the time it can conduct feed operations.
7	Maintain the CH2 tank capacity to align with the filling frequency of the feed tank, with fixed tanks located on the open deck and portable tanks integrated into the feed tanks.	This will ensure that feed filling and fuel bunkering are required at the same time, which will address the limitation of Case 6.	Feed filling and fuel bunkering cannot occur simultaneously due to clashes between systems/operations, which will greatly increase the bunkering time. This will result in the vessel spending less time undertaking feed operations.
8	Offset the CH2 bunkering frequency from the feed filling frequency, with fixed CH2 tanks located on the open deck and portable tanks integrated into the feed tanks.	This will enable alternating feed filling and fuel bunkering operations to address the limitations of Case 7.	Bunkering operations will be more complex and have a higher inherent risk. Feed filling will require the removal of a relatively full hydrogen tank, which will be a critical operation. The alternating schedules and different procedures could increase the complexity of bunkering operation and therefore demand more time.
9	Implement more frequent fuel bunkering without modifications to the feed tanks.	This will allow the vessel to undertake fuel bunkering operations periodically at the home port.	The vessel will spend more time bunkering for fuel than undertaking feed operations.
10	Implement more frequent bunkering using a floating bunkering platform near the operational zone, with either fixed or portable tanks.	Portable tanks can be placed on floating platforms near the operational zone. This will address the limitations of Case 9 as the vessel will spend relatively less time commuting to the bunkering facility. The feed filling and fuel bunkering (fixed tanks) can both also be accustomed to the floating platform.	This may not be ideal due to the higher costs and risks associated with the floating platform’s setup, operations, and maintenance, given its relatively compromised performance in terms of feed operations. See Section 5.5.3 for further discussion.

presents various onboard CH₂ storage cases.

5.5.2. Frequent Bunkering

Achieving the same seven-day bunkering frequency (for equivalent performance) is infeasible for the HFV. More frequent bunkering could mitigate spatial constraints. The barge consumes approximately 4 m³ of MDO per day (155.3 GJ/day). Assuming similar energy losses in the powering, auxiliary, and feed systems of the HFV [47], the HFV would require approximately 56 m³ (1.3 tons) of 350 bar CH₂ per day. This infers that the HFV would prompt almost double the fuel capacity (volume) requirement for a single day that the barge currently utilises for the entire seven-day bunkering schedule.

5.5.3. Cost Risk and Performance Compromise Due to Frequent Bunkering

Figure 2 and

Table 5. Fuel tank capacity requirements with reference to bunkering frequency.

Bunkering Fuel	Frequency (Days)	Required Tank Capacity (m3)	Weight (Tonnes)
MDO	1	4.09	3.76
	2	8.17	7.52
	3	12.26	11.28
	4	16.36	15.04
CH2 (350 bar)	1	56.23	1.29
	2	112.46	2.59
	3	168.70	3.88
	4	224.96	5.16

indicate that a bunkering frequency beyond three days is infeasible due to spatial constraints. Achieving a bunkering frequency beyond one to two days would prompt several considerations with regard to the redesign, extensive risk assessments, and class review for approval. Section 4 suggests that even a two-day bunkering schedule is highly unlikely due to risks associated with tank arrangements and associated systems.

Table 6. Cost, risk, and performance compromise for Cases 1, 3, and 10.

Case	Cost Compromise	Risk Compromise	Performance Compromise
1	Longer bunkering operations to address relatively more tanks, ultimately driving up costs. Retrofit costs will also increase as more piping, associated systems, and risk assessments will be required for the design and approval of the vessel. More maintenance and inspections will further contribute to higher operational costs.	The vessel will be at higher risks due to the following: More hazardous areas. More points of failure at the tanks, connections, and systems. High-risk bunkering operations as more tanks need to be fuelled.	The vessel’s efficiency will be impacted due to the following factors: Although bunkering frequency is relatively low, operations will take longer due to the increased number of tanks, reducing the time available for feed operations. Less useable and accessible spaces on open deck. More maintenance and inspections required, affecting operational times. Feed filling operations will be slower due to the inherent risks associated with CH₂ tanks on the open deck, requiring greater caution during operations.
3	The bunkering frequency would have to be further increased as larger tanks cannot be fitted into one single region. The available spaces are not large enough to accommodate big tanks; therefore, as per reasons defined in Case 1, the increased bunkering frequency would drive up the cost even further.	The vessel will have to undertake relatively more bunkering operations, which is a high-risk operation. Risk is also presented due to the commercial outputs of the barge as it is not efficient in conducting its intended operations, which will drive up cost at reduced performance.	The performance will be reduced due to the increased bunkering frequency, preventing the vessel from undertaking its intended operations.
10	The cost for the design, construction, operations, and maintenance of the floating platform will be relatively high. Additional costs will also be associated with the feed filling and fuel bunkering for the floating platform.	The floating platform is subject to motion, which can present a relatively riskier operation.	Environmental constraints may limit when and how often bunkering can take place, which may delay the vessel from undertaking feed operation.

provides a breakdown for the cost, risk, and performance compromise of the most feasible one- to two-day bunkering frequency scenarios (Cases 1, 3, and 10) from Table 4.

Among the defined cases, Case 10 is the most feasible option for hydrogen storage and bunkering. Although establishing a floating bunkering platform entails high costs, it is an adaptable solution to the evolving green hydrogen industry. Such a platform could serve other potential hydrogen-powered vessels in the region and can potentially store higher pressure CH₂ gas or even LH₂ as infrastructure develops. Additionally, the proposed Bell Bay H₂ hub could supplement supply, reducing reliance on the Mornington station, which would otherwise require significant expansion. Ultimately, the floating platform may provide a reasonable return on investment. The risk and performance limitations mainly stem from the environmental conditions, which can be address by utilising motion control and operating in areas with acceptable sea states. Overall, Case 10 presents a relatively positive asset management value balance with minimal cost and risk compromise while maximising performance output.

5.6. Fuel Cell System

Proton Exchange Membrane Fuel Cells (PEMFCs) are widely used in maritime applications due to their high technology readiness level [5] and are therefore considered in this investigation.

5.6.1. Determining Fuel Cell Requirements

It is assumed that the efficiency of the powering, auxiliary, and feed systems of the HFV are mostly equal to the conventional vessel [47]. Thus, the HFV requires an installed power of at least 900 kW to match the barge’s powering demands for systems such as feed distribution, barge-to-pen delivery, water circulation and aeration, lighting and environment control, and winches and cranes.

Table 7. Fuel cell specifications for varying models that operate on compressed hydrogen.

Manufacturer/Model	Dimensions (L × W × H)	Power	Power (10% Loss)	No. Installed	Power. Installed	Occupied Volume	Total Weight
	[m × m × m]	[kW]	[kW]		[kW]	[m3]	[kg]
TECO 2030 FCM 400 [48]	1.4 × 0.8 × 2.1	325	292.5	4	1170	9.33	5560
Ballard FC Wave [49]	1.2 × 0.7 × 2.2	200	180	5	900	9.83	5000
Nedstack MT-FCPI-120 [50]	2.0 × 1.1 × 2.1	120	108	9	972	41.59	22,500
Nedstack MT-FCPI-600 [51]	6.1 × 2.4 × 2.9	600	540	2	1080	85.76	30,000
Yanmar FC [52]	1.7 × 3.4 × 3.0	300	270	3	810	19.07	9000

provides specifications for suitable FC modules operating on CH₂ from four different manufacturers. To account for unideal operating conditions, a 10% loss in efficiency is considered for every module. The FCs are selected based on the power-to-weight and power-to-volume ratios to consider the most efficient power delivery system with regard to weight and spatial requirements.

As shown in Figure 3, the most optimal configuration consists of four TECO FCM 400 units, providing 1170 kW of power at an occupied volume of 9.33 m³. Although this exceeds the minimum power requirements, it is still considered suitable since it occupies less volume and has a relatively smaller deviation in weight from the barge. This will ensure that there are considerably less adverse effects on the vessel’s stability as a result of weight reduction/increase from the powering system. As per the classification requirements, a single failure of a FC power installation shall not lead to an unacceptable loss of power [39]; therefore, the additional power is considered favourable as it allows for greater redundancy. It should be noted that the Ballard FC Wave stack is also fit for purposes of this vessel in terms of the power, weight, and occupied volume. For additional power demands, the batteries can be employed to provide a hybrid power supply system.

5.6.2. Fuel Cell Availability

FC stacks need to be replaced several times throughout the vessel’s lifecycle. Therefore, it is important to account for this in the retrofit design and to consider the logistics of procuring the relevant parts and components. On average, each FC module shown in

Table 8. Specifications for electrical energy storage system.

Rated Energy	Rated Voltage	Rated Capacity	Dimensions (L × W × H)	No. Units Installed	Energy Installed	Occupied Volume	Total Weight
[kWh]	[V]	[Ah]	[m × m × m]		[kWh]	[m3]	[kg]
100	51.20	2000	1.1 × 0.5 × 1.4	3	300	2.34	1860

has a maximum lifetime of approximately 30,000 h. TECO 2030 and Nedstack are based in Europe, Ballard in North America and Yanmar in Japan. However, each manufacturer has suppliers based in Australia expect for Ballard. Nonetheless, the replacement of these FC stacks is not time-critical and allows for sufficient opportunity to plan the logistics of such undertakings well in advance. One of the biggest considerations in retrofitting from conventional ICEs to FCs is the replacement planning of the FC stack throughout the vessel’s lifecycle. It is crucial to develop an efficient method for replacing the FC stacks during the design stage of the retrofit to ensure that the compromise on cost, risk, and performance is minimised. A poorly designed replacement plan could incur additional costs due to extensive labour, extra materials, and additional time. This can also increase the risk of not meeting the vessel’s commercial goals amongst the risks that may be presented during replacement operations. The performance of the vessel is measured by its efficiency in undertaking its intended operations and meeting its commercial goals. Thus, the replacement process should be well planned to minimise the time that the vessel is out of service.

5.7. Battery Installation

Li-Po batteries offer exceptional safety and flexibility, making them quite desirable in maritime applications. Nevertheless, this study considers Li-ion batteries due to their relatively high depth of discharge, advanced technology, and availability at reduced costs.

5.7.1. Determining Energy Storage System Requirements

The estimate for the energy requirement of the ESS is obtained using the barge-to-pen feed delivery powering data of a similar vessel (refer to Figure 4). The power demand is at its highest during feed delivery operations, which occur twice a day for approximately four hours per cycle. The requirements for these operations can be satisfied using energy generated from FCs. However, the ESS stores additional energy generated by the FCs to provide hybrid power during load variations, powers some onboard auxiliary systems during bunkering operations, and/or meets the powering requirements in the case of a failure of the FC power installations. In accordance with the data provide in Figure 4 and the information establish in previous sections, the energy storage system was selected to have a rated energy of 300 kWh, which can cover two-hour barge-to-pen delivery operations.

5.7.2. ESS Availability

This study considers three units of the 100 kWh ESS from QH Technology, a high voltage battery producer. Table 8 presents the specifications of the ESS. These batteries are subject to replacement throughout the vessel’s lifecycle. Therefore, it is crucial to account for the replacement plans in the retrofit design and pay special consideration to the logistics of procurement and installation.

5.8. Powering Specifications

As justified in Section 5.6 and Section 5.7,

Table 9. Power specifications for barge.

Particular	Conventional Barge	Hydrogen-Fuelled Barge
		Fuel Cell	Battery	Fuel Cell + Battery (Total)
Installed Power	900 kW	1170 kW	300 kWh	-
Weight (kg)	7500	5560	1860	7420
Occupied (Vertical Projected) Area (m2)	7.56	4.39	1.70	6.09

provides specifications for the HFV powering requirements (for equivalent performance) in comparison with the conventional feed barge specifications.

6. Feasibility of Hydrogen Retrofitting in Australia

Significant costs are associated with retrofit design and production of boats/ships, as several systems within the vessel must be removed and replaced with HFV-associated systems. Depending upon the size of the vessel, the complexity of the systems, the available infrastructure in the operational region, and the design changes required for the retrofit, the cost can increase significantly, which may make retrofitting an unfeasible option. Ultimately, this can favour new builds, as they may provide a better asset management value balance.

The current Australian shipbuilding market does not encourage new-build vessels for commercial use due to the high labour costs compared to other countries. Australia is also relatively stricter with class certifications, as AMSA requires classification compliance for novel vessels operating in Australian waters [53]. In contrast, many other countries do not impose this requirement for vessels under 50 m in length. Extensive risk analysis is often required to acquire class approval, and with the relatively lower knowledge bandwidth of HFV design and production (as there is no established framework for the design and production of HFV), this can greatly increase costs, leading clients to avoid class certification where practicable.

To meet Australia’s commitment to the Paris Agreement, it is inevitable for considering retrofitting the existing fleet of vessels. The case study presented in Section 5 demonstrates that hydrogen retrofitting may not always be feasible on a case-by-case basis, from both a technical and commercial perspective. This is primarily due to the cost, risk, and performance compromise, particularly given the current infrastructure in Australia and the available technology. Nonetheless, it is important to note that this case study only provides one of many potential applications where a hydrogen retrofit may be considered. The approach utilised in this study can be adopted to identifying determining factors, and areas of improvement must be addressed to make hydrogen retrofitting feasible in Australia.

7. Conclusions

The case study identifies the determining factors for a feasible hydrogen retrofit application with respect to an asset management approach. It provides an overview of the challenges associated with the design, production, and operations of an HFV, defines considerations to classification society requirements, and analyses the feasibility of achieving equivalent performance. The main challenge in developing a retrofit design is achieving equivalent performance while minimising cost and risk. This is primarily due to the low volumetric energy density of hydrogen, which prompts more frequent bunkering, ultimately resulting in the vessel spending much less time conducting its intended operations and incurring higher associated costs and risks. A negative AMV balance is introduced as a result. However, these challenges can be overcome by developing more advanced hydrogen infrastructures in operational regions and setting standards for the use of hydrogen in maritime applications. For example, standardising a minimum of 700 bar CH₂ for CH₂ bunkering stations, as the volumetric energy density at 350 bar is too low for feasible maritime applications. Additionally, advancement in cryogenic CH₂ and LH₂ applications should also be pursued to standardise its use over current methods.

In conclusion, the feasibility of retrofitting conventional vessels with hydrogen power is heavily dependent on the infrastructure that is presented. The infrastructure must address the spatial challenges (explored throughout this paper) associated with the storage of hydrogen on vessels, by providing more energy-dense hydrogen fuels and developing standards and procedures to make bunkering operations more efficient (to minimise the time spent bunkering).

Table 10. Spatial requirements for hydrogen storage.

Fuel	Fluid Density	Volumetric Energy Density	Bunkering Frequency	Req Fuel Capacity	Weight
	[kg/m3]	[MJ/m3]	[Days]	[m3]	[Tonnes]
MDO	920	38,000	7	28.60	26.31
CH2 (350 bar)	23	2761		393.63	9.05
CH2 (700 bar)	42	5042		215.55
LH2 (4 bar)	65	7800		139.33
Cryo-CompressedH2 (300 bar)	88	10,560		102.92

presents a comparison of the spatial requirements for storing hydrogen of varying physical properties, which highlights the importance for further infrastructure developments required to make hydrogen retrofitting feasible. Nonetheless, it should be noted that cryogenic fuels may require additional space, such as fuel preparation rooms for associated systems. Ultimately, all vessels are purpose-built and differ from one another; therefore, the required infrastructure —in terms of the facilities and locations—must also be designed and developed to support these intended purposes. To put this in perspective, the case study presented in this paper would be considered much more feasible if there were an LH₂ or cryo-compressed H₂ [54] bunkering facility nearby, provided on a floating facility within the operational zone.

8. Limitations and Future Works

This paper does not consider the detailed design for the retrofit, including the extensive risk assessments required to justify design decisions such as the arrangement of tanks, FCs, batteries, and their associated systems. Thus, several technical aspects of a retrofit design are not discussed. A major example of this is the lack of consideration for the vessel’s stability. Hydrogen retrofitting would drastically reduce the initial fuel weight, while the MDO fuel tanks located on either side of the vessel will become voids. The resulting change in weight distribution will have adverse effects on the hydrostatics of the vessel, potentially leading to variations in the resistance curves, load lines, seakeeping, and most importantly, the stability. To address this, the fuel tanks may be used as seawater ballast (which is not ideal, as the vessel would effectively be carrying non-essential cargo, making it inefficient and perhaps less “green”) or converted into silos for the feed tanks. However, there are various technical considerations associated with this.

For hydrogen storage, this study focused on 350 bar CH₂. As advancements are made in various storage methods, including physical-, chemical- [55], and material-based methods [56], these hydrogen storage technologies can be compared to identify optimal solutions.

Individual case studies, such as the one provided in this paper, can be performed using an asset management approach to build a portfolio of feasibility studies, which could aid in developing feasibility criteria. This will help to identify the determining factors that need to be addressed for a given retrofit application. Additionally, hybrid power systems could be considered to investigate whether they can provide a more reasonable asset management value balance by reducing bunkering frequency.