Learnings

Outcomes

SUMMARY
This work has explored the viability of non-pipeline hydrogen transportation to understand arising opportunities for a gas network in a transitionary state, where natural gas and hydrogen both play a role, but where widespread hydrogen infrastructure is still being established. This has been done through detailed techno-economic analysis to develop a Levelised Cost of Hydrogen (LCOH) for hydrogen transportation through three distinct mediums:

• Compressed Hydrogen
• Liquid Organic Hydrogen Carriers (LOHC)
• Ammonia (NH3)

The work has found that, when compared to compressed hydrogen, the LCOH varies less for LOHC and ammonia over longer distances and could be as low as £2/kg over a 300 mile journey. However, the choice between these mediums will depend on the demand-side ability to process LOHC and cracked or partly-cracked ammonia. Compressed hydrogen mostly overcomes these demand-side issues, but needs to accommodate higher pressures to be competitive.

The capital cost (CAPEX) constitutes the highest proportion of the LCOH in all scenarios. It is therefore likely that developments in technology, standardisation, and scalability will play a large role in reducing the CAPEX of non-pipeline hydrogen transportation. This could make the LCOH of LOHC and ammonia equally competitive as compressed hydrogen over shorter 50–100-mile distances.

The work has also undertaken a review of hydrogen production costs, considering both electrolytic and Steam Methane Reformation (SMR) technologies. This highlights the benefits of electrolytic production, but also a need for further R&D investment to reduce the LCOH of electrolytic hydrogen to a level where it is competitive with SMR.

Hydrogen Distribution By Road
Forms of hydrogen storage and transportation by road, with potential for short term deployment were reviewed, with following options identified as being the most likely to be feasible and cost effective selected for further evaluation: 

• Compressed Hydrogen. Compression and transport in pressurised tube trailers based on two options:
  • 300 kg of hydrogen per load at 230 barg in ASME Type I steel tanks; and
  • 1240 kg of hydrogen at 520 barg in ASME Type IV tanks.  

ASME Type I tube trailers are conventional and currently used in the UK for the transport of hydrogen. Tube trailers using ASME Type IV composite vessels are commercially available and at an early deployment stage in demonstration schemes.

• Liquid Organic Hydrogen Carriers (LOHC). Catalytic hydrogenation, transport and thermal catalytic dehydrogenation of Dibenzyltoluene (DBT) for release of hydrogen at the user’s site and return of the dehydrogenated form to complete the cycle. Transport is in conventional road tankers used for oil-based products, with a trailer payload basis of 1340 kg of hydrogen equivalent.
• Ammonia (NH3). The scheme consists of catalytic synthesis of ammonia, transport, thermal catalytic cracking to release hydrogen and purification at the user’s site. There is potential to use ammonia directly as fuel which eliminates cracking and purification costs. Transport is in liquid form in pressurised tankers, which are conventional for ammonia, potentially being able to reuse LPG infrastructure. Trailer payload basis is 3700 kg of equivalent hydrogen.

The Levelised Cost of Hydrogen (LCOH) was estimated over a lifetime of 10 years (chosen as a nominal timeframe where projected costs of hydrogen production could be assumed with reasonable confidence) for the forms of hydrogen transport selected and the range of plant capacities and transport distances. The costs include capital costs for the conversion, transport, reconversion and lifecycle operating costs for the above supply chain. Costs are only for the hydrogen supply chain and exclude hydrogen production costs and purification for final delivery of fuel cell grade hydrogen (if applicable).

LCOH for hydrogen delivery in conventional tube trailers (at nominal 230 barg) is estimated in the range £1.3 to £5 per kg H2 for individual user’s demand in the order of 1-3 tpd, and as high as £4 to £8 per kg H2 for the delivery of hydrogen to users with a small scale, nominally assumed 100 kg/day as representative. A very steep increase of costs with transport distance is shown for transport of compressed hydrogen in 230 barg trailers, which makes it unattractive not only for long distances in a UK wide distribution scheme, but even for regional distribution due to the relatively small payload carried by current tube trailers.

The use of high-pressure tube trailers (at nominal 520 barg) allows 4 times more hydrogen to be transported per trailer, halving LCOH to the approximate range £0.9 to 2.4 per kg H2 for delivery to users with demand in the order of 1-3 tpd. For small scale users with demand in the order of 100 kg/d, LCOH was estimated in the approximate range £7 to 8 per kg H2.

Estimated hydrogen distribution cost for LOHC (DBT) is in the range £2 to £3.3 per kg H2 to supply users with a demand in the order of 1-3 tpd. For small scale demand users with representative hydrogen consumption 100 kg/day, distribution costs are in the approximate range £5 to £6 per kg H2.

LOHC (DBT) may show some potential for regional distribution with LCOH in the range £1 to 3 per kg H2 realised by cost reductions including utilisation of hydrogenation heat, and for supply to a small number of users with relatively large individual demand using standardised modular dehydrogenation skids.  

Costs of ammonia synthesis and cracking are generally high compared to other alternatives, in the range £4 to 5.6 per kg H2 for users with a demand in the range 1-3 tpd and up to around £8 per kg H2 (or more) to supply small scale users with an indicative demand of 100 kg per day. The higher costs compared to other options is mainly due to the significant energy requirements and processing for ammonia cracking to release and purify hydrogen. This factor is likely to prevent ammonia being considered to be cost competitive for the regional distribution of hydrogen, on the basis that reconversion to hydrogen is required (see below for delivery for use of ammonia as fuel).

For regional distribution, delivery and reconversion of LOHC and ammonia were not found to be competitive against the simpler option of delivering compressed hydrogen due to high costs associated to LOHC dehydrogenation or ammonia cracking. However, LOHC and ammonia could be targeted and deemed attractive for supply of hydrogen over long distances and for large capacities, generally one plant supplying a single user or a small number of high demand users. 

The delivery of blue ammonia as a final product makes ammonia an attractive option, with LCOH being competitive against the other options evaluated for regional distribution at about £1.4 to £2.6 per kg H2. The LCOH of ammonia delivered as final product is potentially the lowest for national transport, for distances above 300 miles. Blue ammonia as fuel has potential to support decarbonisation of areas such as off-grid heat and power generation and particularly as a fuel for shipping.

Development of cost-effective solutions to supply relatively low demand to individual users, in the order of 100 kg/day (and lower), is anticipated to be challenging due to the required CAPEX to install storage and reconversion infrastructure at multiple user’s sites. Even for the case of compressed hydrogen, LOHC is estimated in the order of £4 to 8 per kg H2 mainly given the assumption that a tube trailer remains on site to be used as storage, which represents a high CAPEX option. This indicates that compressed gas could become competitive if alternative low-cost storage options are available for high pressure storage at the point of use. For relatively short distances below 50 miles, compressed hydrogen in 230 barg tube trailers gives the lowest LCOH.

The use of LOHC is anticipated to be more attractive for the supply of small individual user’s demand on the basis that standardised self-contained skids can be installed at a relatively low cost with minimum operator intervention as assumed. For regional distribution for small scale individual user’s demand, ammonia as final product has the lowest LCOH regardless of the transportation distance.

Local Hydrogen Generation
The main options for local hydrogen generation (on-site, at the point of use) include electrolysis, especially if electricity is supplied from renewable sources and small-scale SMR.

Electrolysis modules can produce very pure hydrogen suited for fuel cell electric vehicles (FCEV), only producing oxygen (vented locally) as by product. It is expected that local generation by electrolysis will be particularly applicable to generation of hydrogen for transport, with generation plants adjacent to HRS coupled with buffer storage of hydrogen at high pressure.

Costs for electrolysis for HRS have been widely developed and reported, so this option could potentially become the technology of choice for localised generation in the short to medium term, with determination of technical and economic feasibility largely dependent on the cost and reliability for electricity supply.  The use of power generation from renewables to produce hydrogen would be more favourable if the intermittency of the sources of electricity production could be balanced with either the supply of other low carbon electricity and/or cost-effective local electricity and/or hydrogen storage facilities.

SMR is a niche technology with applications to date limited to small scale demonstration units. SMR produces CO2 (after separation from hydrogen) so is only applicable option for net zero if used alongside CCS. Something which is considered to be unlikely, especially for early adoption transition projects.

The use of SMR technology for hydrogen production purposes has therefore been ruled out due to the local release of CO2, unless the produced CO2 could also be compressed, conditioned, and transported to storage - incurring in additional costs.

One application where SMR is most likely to be used would be where biomethane was used as feedstock, which has the potential to be negative-emission technology with CCUS. .  Such costs could also potentially be justified and considered attractive if part of a negative emissions scheme, depending on costs of emissions. 

Costs for a biomethane feedstock hydrogen production plant using SMR could be competitive, dependent on the supply of low CAPEX standardised modules. Cost reported by the HyValue project are in the order of £5/kg. 

Deployment of Market Accelerating Hydrogen Distribution Options
The evaluation of hydrogen delivery by road has been based on delivery of hydrogen to individual users with a nominal average demand in the order of 1 tpd of hydrogen, likely to be industrial for heat and power generation or other off-grid users currently supplied with LPG, petroleum derived fuels or coal. The analysis performed can also be applied to other end-users including HRS for vehicle fuel (although this would require additional purification and compression). Other alternative applications could include the transportation of hydrogen by road for injection into an isolated section of the gas distribution network.

A large proportion of on-site hydrogen generation from electrolysis is expected to serve hydrogen for transport since it can produce FCEV grade hydrogen with minimal additional purification requirements compared to the production of hydrogen from gas reforming.

There may be a particular opportunity to consider local generation of hydrogen from small scale SMR with biomethane sites where the ability to declare net zero emissions means that limited access to CO2 transport and storage infrastructure in the short to medium term presents less of a barrier to deployment. Hydrogen produced from SMR is also a potential application for users currently using biomethane e.g. Combined heat and power (CHP) plants and injection into the grid.

Biomethane is already considered to be a green fuel produced from renewable sources of energy, so conversion to hydrogen may not be favoured as this will introduce energy inefficiencies and costs associated to the transformation. Therefore, conversion to hydrogen is only anticipated to take place where a specific end-use benefit has been identified – e.g. to serve FCEV applications as a backup for green hydrogen for intermittent generation from renewable power such as solar and wind.

Hydrogen transport by road and/or local hydrogen generation may be considered to support the phased conversion of the gas network to transport hydrogen blends, in advance of transition to a fully decarbonised 100% hydrogen network. Hydrogen transported by road also has potential to support transition of sections of the gas network to hydrogen duty. As demand for this scenario may be too large to be supported by supply in tube trailers, at this scale it may be more appropriate for LOHC or ammonia to be used to reduce the fleet size and traffic movements.

 The TRL of project moved from 2 - 3

Lessons Learnt

An ambitious scope of work for the study was initially developed to support the investigation into the role of the gas network as part of the South Wales Industrial Cluster (SWIC) deployment project. The initial scope of work document was used to support the funding application for the SWIC Deployment Programme Phase 2 from the Industrial Strategy Challenge Fund (ISCF). As the SWIC scope is evolving, the initial scope of work for this study was indicative of the expected work that would provide value as the first study of its kind by WWU as a SWIC stakeholder.

A close collaboration was established between the WWU net zero and network operation team and the Costain decarbonisation consultancy team via frequent (weekly) progress meetings to:

1. Refine the scope of work based oon:
   • The status of the SWIC project at the beginning of the study, the knowledge of SWIC projects and the interdependency for integration into the cluster plan
   • The availability of data, methods and tools
   • The assessment of the work that would provide more value at the early feasibility stage, aligned to the overall objectives of the study
2. Review study progress, provide feedback/input and agree basis and methods
   • Incorporate views, opinions and encourage knowledge sharing from study stakeholders including technical consultants, network operations team, net zero project management and other SWIC stakeholders
   • Agree on assumptions and methods, with stakeholders fully aware of outcomes at the first opportunity

This collaborative approach allowed the project to tailor the study scope, based on trustworthy discussions which provided significant benefits to gain maximum value. The study was a first of a kind piece of work, examining the potential role for gas network in the SWIC deployment plan, whilst considering practical considerations including network configuration and operation (particularly with regards to security of supply) and quantification of likely hydrogen demand aligned with SWIC ambitions for hydrogen production and roll-out.