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Achieving Zero Pathway to a Zero Carbon Electricity System in Northern Ireland

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Charley Rattan's picture
World Hydrogen Leader Charley Rattan Associates

UK based offshore wind & hydrogen business advisor and trainer; Faculty member World Hydrogen Leaders. Delivering global offshore wind business advice, problem solving and training: ...

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Key findings

Increasing the renewable electricity generation (RES-E) in Northern Ireland from around 45% today to a target of greater than 80% is very achievable by 2030, using the same approach required to achieve a less ambitious 70% target, and implementing more of existing and proven technologies.

The SONI TESNI 2020 Accelerated Ambition scenario renewable capacity targets should be adopted for 2030; 2.5 GW of onshore wind, 500 MW of offshore wind and 1.2 GW of solar PV.

This target can be achieved at a lower cost to the end consumer in Northern Ireland, compared to delivery of a less ambitious 70% RES-E target.

A zero-carbon power system is possible, and is an achievable target in the early 2030s. Realising this target requires incremental investment in a suite of technologies new to Northern Ireland, and the implementation of a carbon price floor in the I-SEM

 

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Green hydrogen In the ‘Green Hydrogen’ and ‘Zero Carbon’ scenarios we have assumed that 1,600 MW of electrolyser capacity has commissioned throughout I-SEM by 2030. This capacity is split into NI and ROI on a demand-weighted basis; 310 MW in NI and 1,290 MW in ROI. These electrolysers are configured to produce hydrogen when day-ahead prices fall below 45 £/MWh.

At this price, the marginal molecule of hydrogen retains approximate price parity with that of fossil gas under an ETS carbon price of 90 £/tCO2, assuming some insulation from transport charges from strategic locational deployment of electrolysers, with the average molecule of hydrogen being considerably lower in cost than the fossil.

 The electrolyser capacity is assumed to have a power-to-hydrogen efficiency of 70%, i.e. 100 MWh of electricity can produce 70 MWh of hydrogen. We assume that the hydrogen produced is utilised in hydrogen-ready fossil gas-fired generation assets built before 2030, retrofitted to become hydrogen-fired. In the ‘Green Hydrogen’ scenario we consider 300 MW of retrofitted fossil gas-fired capacity in NI and 900 MW in ROI. In the ‘Zero Carbon’ scenario we model a complete retrofit of the remaining I-SEM fossil gas-fired fleet; 1,600 MW of hydrogen-fired generation capacity in NI, and 4,380 MW in ROI.

Retrofitting the I-SEM fossil gas fleet is considered technically achievable according to suppliers such as GE49, Siemens50 and Mitsubishi51. It should be noted however that all gas customers, as well as the gas transmission and distribution system, would need to convert to a hydrogen blend (or 100% hydrogen) at the same time.

It is outside the scope of this study to determine the feasibility, economics or timing of such a change. The volume of hydrogen produced by the electrolysers during the model horizon is assigned to hours of highest to lowest price, with hydrogen offtake limited in each hour by the installed retrofitted capacity in each jurisdiction. Fossil gas offtake is displaced in these hours, until the hydrogen volume is consumed. This calculation has been performed in Excel, using the hourly results of the PLEXOS market model. To allow this flexible and targeted hydrogen offtake, we have assumed that storage volumes are not a limiting factor in these scenarios, with 1.0 and 3.0 TWh of hydrogen storage available in NI and ROI respectively in the ‘Green Hydrogen’ scenario, and 4.5 TWh of storage deployed throughout I-SEM in the ‘Zero Carbon’ scenario (0.5 TWh more than in the ‘Green Hydrogen’ scenario).

Hydrogen can be stored cryogenically or in high pressure tanks, or more economically, in underground caverns where the geology permits. This methodology assumes that suitable cavern locations are employed for storage of hydrogen. Without these sites the available storage volume may become a limiting factor in the deployment of green hydrogen infrastructure in I-SEM. This would result in a ‘less targeted’ use of hydrogen offtake for generation, in hours of lower emission intensity. In both scenarios, we assume that an equal volume of hydrogen is used in hydrogen-fired generation capacity within the power sector as is produced by the modelled electrolysers, i.e. the power sector hydrogen use is net neutral in 2030. This does not assume that the hydrogen infrastructure in the power sector is isolated, only that there is no net gain/loss of hydrogen within it in 2030.

Green hydrogen could alternatively be used to decarbonise the heating, industrial, or transport sectors, sometimes known as ‘sector coupling’52 . Hydrogen can also be used as a raw material step in the production of ‘electrofuels’ such as ammonia, methanol, electromethane, ‘e-petrol’ and ‘e-diesel’. These fuels may have applications in shipping and aviation, both domestically and for export to other markets. The infrastructure required to produce and store hydrogen could be shared between the electricity system and these end-uses, with resulting economies of scale, but evaluation of the interactions between sectors is outside the scope of this study. 

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