Combined electrolyser-HRS and Power-to-Gas system

Topic description

Specific Challenge:

The business case for renewable hydrogen projects is frequently hindered by low utilisation of the equipment. This is caused by the combination of a variable renewable energy supply and a still emerging demand for renewable hydrogen in the mobility sector (e.g. from fuel cell vehicles). Projects are thus often limited to specific niches where non-monetary benefits compensate for idle excess capacity. New business models are therefore required to facilitate the future rollout of hydrogen infrastructure.

The ability to inject hydrogen into the European gas infrastructure via the power-to-gas approach would allow selling surplus hydrogen as a green gas to natural gas distribution networks and reduce the variability on the demand side. This will create a supplementary revenue stream from the gas market, improve electrolyser readiness for providing electricity grid services on demand, and reduce the investment risk by overcoming low plant/HRS utilisation.

The challenge for this topic is to reduce the financial risk of hydrogen supply at a refuelling station by optimising the operating condition of the electrolyser under varying power prices, grid services regimes and changing customer demand, using the low pressure gas distribution network as a hydrogen sink for achieving a secondary income stream, and electricity grid services as a tertiary income stream.

This topic calls for assessment and demonstration of an electrolyser and gas network injection equipment at a refuelling station where hydrogen demand for mobility is expected to increase over time. The mobility demand may come from passenger cars, or any other type of hydrogen vehicle including buses, trucks and trains. Although co-location of a station with the gas distribution network is not a conventional siting criterion, it is a pre-requisite for achieving a combined electrolyser-HRS and Power-to-Gas system.
The following equipment could be used for the project and be directly connected at a single site:

• A hydrogen refuelling station with a capacity of dispensing at least 200 kg/day that is expected to experience under-utilisation during most (or all) of the demonstration period (demand build-up period);
• An electrolyser of at least 600 kg/day generation capacity, with sufficient flexibility to optimise hydrogen production cost as a function of electricity prices, grid balancing activities and gas network feed-in tariffs;
• A gas grid admixture and injection system, including the development of appropriate mixing and concentration monitoring technology, which is capable of injecting hydrogen admixtures at flow rates of up to 100% of the electrolyser capacity while maintaining the transient concentration at the grid injection point within specified limits.

It is expected that potential project would:

• Create and publish a model that optimises for total cost of ownership the operation of the components above as a function of power prices, grid services payments, hydrogen mobility revenue and hydrogen injection revenue (including injection fee where applicable). Consideration should be given to diurnal and seasonal variations in operating strategy, to the expected transition from low to high numbers of hydrogen vehicles using the station and to any variations in the value of hydrogen to gas networks as they decarbonise. It is important that any costs for the gas network in a regulatory context (e.g. regulatory sandbox) are included in the analysis and the model should consider existing, planned and new stations that are in close proximity to gas distribution pipelines. Preferred operating strategies should be identified by the project, which must be comprehensive enough that others can repeat the work and adopt the identified business models;
• Build and operate the equipment to validate the model with real life data, including comparing the Total Cost of Ownership (TCO) of the refuelling station without gas grid injection (no CAPEX, OPEX or revenue from the injection system) to that with a grid injection facility. Hydrogen cost targets for stations with and without gas grid injection should be compared for a range of operating variables and rates of HRS deployment across the period 2020-2030. The demonstration should last for at least 2 years, with the expectation that all of the equipment remains in use afterwards. The duration of need for the network injection facility is a key parameter (demand build-up period);
• Liaise with the similar topics of this call (topic FCH-02-5-2019: Systematic validation of the ability to inject hydrogen at various admixture level into high-pressure gas networks in operational conditions and topic FCH-04-3-2019: Hydrogen admixtures in natural gas domestic and commercial end uses) to ensure the latest understanding of the impacts of admixtures upon end use equipment and any variations across EU inform the chosen concentration limit and concentration ranges to be applied at the HRS site;
• Obtain an exemption from existing regulations and a permit as required from the gas network regulating authority to inject admixtures at the site of the refuelling station. Because flow rates in gas distribution networks tend to be low outside of the heating season, especially overnight, it is important for the system to be able to inject admixtures of up to the highest acceptable concentration if the annual electrolyser utilisation is to be maximised, rather than remain within the limits of existing regulations;
• Assess the challenges and propose solutions for injecting hydrogen admixtures into gas distribution networks with respect to: identifying appropriate sites where refuelling stations can feasibly be located close to gas distribution pipelines while ensuring all downstream gas applications are compatible with the admixture concentration under consideration; obtaining any required permits and exemptions; network connection costs and hydrogen concentration measurement at the entry point; and the associated impacts on HRS footprint and site maintenance;
• Report any differences with initial assumptions, for example related (but not limited) to electrolyser hydrogen yield, product losses, switching times, injection curtailment due to low gas grid flow rates or transient situations, the primary/secondary/tertiary revenue streams, and the cost and regulatory context for the grid injection equipment;
• Provide a conclusion around the impact of hydrogen admixture injection into the gas distribution grid upon the business case of an electrolyser-HRS and identify the cost reduction potential of adding gas grid injection to an electrolyser-HRS.

TRL at start: 6 and TRL at end: 8.

Any safety-related event that may occur during execution of the project shall be reported to the European Commission's Joint Research Centre (JRC) dedicated mailbox JRC-PTT-H2SAFETY@ec.europa.eu, which manages the European hydrogen safety reference database, HIAD and the Hydrogen Event and Lessons LEarNed database, HELLEN.

Test activities should collaborate and use the protocols developed by the JRC Harmonisation Roadmap (see section 3.2.B "Collaboration with JRC – Rolling Plan 2019"), in order to benchmark performance of components and allow for comparison across different projects.

The HRS, electrolyser, gas mixing and injection equipment, and related activities are considered within the scope of the project, while consortium is encouraged to make use of existing infrastructure or equipment where possible and focus on the demonstration, generating and communicating learnings.

“CertifHy Green H2“ guarantees of origin should be used through the CertifHy platform to ensure that the hydrogen produced, dispensed at the HRS and injected in the natural gas grid is of renewable nature.

The maximum FCH 2 JU contribution that may be requested is EUR 5 million. This is an eligibility criterion – proposals requesting FCH 2 JU contributions above this amount will not be evaluated.

A maximum of 1 project may be funded under this topic.

Expected duration: 4 years.

The project should deliver substantiated information on the optimisation potential and optimisation schemes for electrolysers at HRS operated on variably priced power and receiving revenues from FCEV refuelling, the gas market thanks to admixture injection, and the delivery of electricity grid services.

Via a validated model, the results should be applicable to different settings where the actual demonstration takes place, for example other EU countries.

It is expected that the project would:

• Combine a hydrogen refuelling station and a power-to-gas system compactly at one site using one electrolyser;
• Ensure more efficient use of renewable power and increase the amount of renewable gas in the gas grid;
• Enable lower cost on-site hydrogen supply from renewable power sources, reducing the hydrogen price at the pump. This would also increase the amount of decentralised hydrogen production and thus decrease distribution requirements;
• Provide a blueprint for HRS bankability at initial stages of operation when vehicle concentration is low, facilitating a more economic and faster roll-out of an HRS network across Europe;
• Demonstrate efficient sectoral integration between the electricity, gas and mobility sectors;
• Improve understanding of the impacts of admixtures upon grid and end use equipment, in collaboration with the other two relevant topics of the call (see above under Scope).

Type of action: Innovation Action

The conditions related to this topic are provided in the chapter 3.3 and in the General Annexes to the Horizon 2020 Work Programme 2018– 2020 which apply mutatis mutandis.