Ireland

Dedicated offshore wind farms for hydrogen production are a promising option to unlock the full potential of offshore wind energy attain decarbonisation and energy security targets in electricity and other sectors and cope with grid expansion constraints. Current knowledge on these systems is limited particularly the economic aspects. Therefore a new integrated and analytical model for viability assessment of hydrogen production from dedicated offshore wind farms is developed in this paper. This includes the formulae for calculating wind power output electrolysis plant size and hydrogen production from time-varying wind speed. All the costs are projected to a specified time using both Discounted Payback (DPB) and Net Present Value (NPV) to consider the value of capital over time. A case study considers a hypothetical wind farm of 101.3 MW situated in a potential offshore wind development pipeline off the East Coast of Ireland. All the costs of the wind farm and the electrolysis plant are for 2030 based on reference costs in the literature. Proton exchange membrane electrolysers and underground storage of hydrogen are used. The analysis shows that the DPB and NPV flows for several scenarios of storage are in good agreement and that the viability model performs well. The offshore wind farm – hydrogen production system is found to be profitable in 2030 at a hydrogen price of €5/kg and underground storage capacities ranging from 2 days to 45 days of hydrogen production. The model is helpful for rapid assessment or optimisation of both economics and feasibility of dedicated offshore wind farm – hydrogen production systems.

Decarbonising economies and improving environment can be enhanced through circular economy energy and environmental systems integrating electricity water and gas utilities. Hydrogen production can facilitate intermittent renewable electricity through reduced curtailment of electricity in periods of over production. Positioning an electrolyser at a wastewater treatment plant with existing sludge digesters offers significant advantages over stand-alone facilities. This paper proposes co-locating electrolysis and biological methanation technologies at a wastewater treatment plant. Electrolysis can produce oxygen for use in pure or enhanced oxygen aeration offering a 40% reduction in emissions and power demand at the treatment facility. The hydrogen may be used in a novel biological methanation system upgrading carbon dioxide (CO2)in biogas from sludge digestion yielding a 54% increase in biomethane production. A 10MW electrolyser operating at 80% capacity would be capable of supplying the oxygen demand for a 426400 population equivalent wastewater treatment plant producing 8500 tDS/a of sludge. Digesting the sludge could generate 1409000 m 3 CH4/a and 776000 m 3 CO2/a. Upgrading the CO2 to methane would consume 22.2% of the electrolyser generated hydrogen and capture 1.534 ktCO2e/a. Hydrogen and methane are viable advanced transport fuels that can be utilised in decarbonising heavy transport. In the proposed circular economy energy and environment system sufficient fuel would be generated annually for 94 compressed biomethane gas (CBG) heavy goods vehicles (HGV) and 296 compressed hydrogen gas fuel cell (CHG) HGVs. Replacement of the equivalent number of diesel HGVs would offset approximately 16.1 ktCO2e/a.

Ireland’s Climate Action Plan 2021 has set out ambitious targets for decarbonization across the energy transport heating and agriculture sectors. The Climate Action Plan followed the Climate Act 2021 which committed Ireland to a legally binding target of net-zero greenhouse gas emissions no later than 2050 and a reduction of 51% by 2030. Green hydrogen is recognized as one of the most promising technologies for enabling the decarbonization targets of economies across the globe but significant challenges remain to its large-scale adoption. This research systematically investigates the barriers and opportunities to establishing a green hydrogen economy by 2050 in Ireland by means of an analysis of the policies supporting the optimal development of an overall green hydrogen eco-system in the context of other decarbonizing technologies including green hydrogen production using renewable generation distribution and delivery and final consumption. The outcome of this analysis is a set of clear recommendations for the policymaker that will appropriately support the development of a green hydrogen market and eco-system in parallel with the development of other more mature low-carbon technologies. The analysis has been supplemented by an open “call for evidence” which gathered relevant information about the future policy and roles of hydrogen involving the most prominent stakeholders of hydrogen in Ireland. Furthermore the recommendations and conclusions from the research have been validated by this mechanism.

Renewable electricity can be converted into hydrogen via electrolysis also known as power-to-H2 (P2H) which when injected in the gas network pipelines provides a potential solution for the storage and transport of this green energy. Because of the variable renewable electricity production the electricity end-user’s demand for “power when required” distribution and transmission power grid constrains the availability of renewable energy for P2H can be difficult to predict. The evaluation of any potential P2H investment while taking into account this consideration should also examine the effects of incorporating the produced green hydrogen in the gas network. Parameters including pipeline pressure drop flowrate velocity and most importantly composition and calorific content are crucial for gas network management. A simplified representation of the Irish gas transmission network is created and used as a case study to investigate the impact on gas network operation of hydrogen generated from curtailed wind power. The variability in wind speed and gas network demands that occur over a 24 h period and with network location are all incorporated into a case study to determine how the inclusion of green hydrogen will affect gas network parameters. This work demonstrates that when using only curtailed renewable electricity during a period with excess renewable power generation despite using multiple injection points significant variation in gas quality can occur in the gas network. Hydrogen concentrations of up to 15.8% occur which exceed the recommended permitted limits for the blending of hydrogen in a natural gas network. These results highlight the importance of modelling both the gas and electricity systems when investigating any potential P2H installation. It is concluded that for gas networks that decarbonise through the inclusion of blended hydrogen active management of gas quality is required for all but the smallest of installations.

Future low-carbon systems with very high shares of variable renewable generation require complex models to optimise investments and operations which must capture high degrees of sector coupling contain high levels of operational and temporal detail and when considering seasonal storage be able to optimise both investments and operations over long durations. Standard energy system models often do not adequately address all these issues which are of great importance when considering investments in emerging energy carriers such as Hydrogen. An advanced energy system model of the Irish power system is built in SpineOpt which considers a number of future scenarios and explores different pathways to the wide-scale adoption of Hydrogen as a low-carbon energy carrier. The model contains a high degree of both temporal and operational detail sector coupling via Hydrogen is captured and the optimisation of both investments in and operation of large-scale underground Hydrogen storage is demonstrated. The results highlight the importance of model detail and demonstrate how over-investment in renewables occur when the flexibility needs of the system are not adequately captured. The case study shows that in 2030 investments in Hydrogen technologies are limited to scenarios with high fuel and carbon costs high levels of Hydrogen demand (in this case driven by heating demand facilitated by large Hydrogen networks) or when a breakthrough in electrolyser capital costs and efficiencies occurs. However high levels of investments in Hydrogen technologies occur by 2040 across all considered scenarios. As with the 2030 results the highest level of investments occur when demand for Hydrogen is high albeit at a significantly higher level than 2030 with increases in investments of large-scale electrolysers of 538%. Hydrogen fuelled compressed air energy storage emerges as a strong investment candidate across all scenarios facilitating cost effective power-to-Hydrogen-to-power conversions.

The high environmental impacts of transport mean that there is an increasing interest in utilising low-carbon alternative energy carriers and powertrains within the sector. While electricity has been mooted as the energy carrier of choice for passenger vehicles as the mass and range of the vehicle increases electrification becomes more difficult. This paper reviews the shipping aviation and haulage sectors and a range of low-carbon energy carriers (electricity biofuels hydrogen and electro fuels) that can be used to decarbonise them. Energy carriers were assessed based on their energy density specific energy cost lifecycle greenhouse gas emissions and land-use. In terms of haulage current battery electric vehicles may be technically feasible however the specific energy of current battery technology reduces the payload capacity and range when compared to diesel. To alleviate these issues biomethane represents a mature technology with potential co-benefits while hydrogen is close to competitiveness but requires significant infrastructure. Energy density issues preclude the use of batteries in shipping which requires energy dense liquids or compressed gaseous fuels that allow for retrofits/current hull designs with methanol being particularly appropriate here. Future shipping may be achieved with ammonia or hydrogen but hull design will need to be changed significantly. Regulations and aircraft design mean that commercial aviation is dependant on drop-in jet fuels for the foreseeable future with power-to-liquid fuels being deemed the most suitable option due to the scales required. Fuel costs and a lack of refuelling infrastructure were identified as key barriers facing the uptake of alternatives with policy and financial incentives required to encourage the uptake of low-carbon fuels.

In this paper a new isolated hybrid system is simulated and analyzed to obtain the optimal sizing and meet the electricity demand with cost improvement for servicing a small remote area with a peak load of 420 kW. The major configuration of this hybrid system is Photovoltaic (PV) modules Biomass gasifier (BG) Electrolyzer units Hydrogen Tank units (HT) and Fuel Cell (FC) system. A recent optimization algorithm namely Mayfly Optimization Algorithm (MOA) is utilized to ensure that all load demand is met at the lowest energy cost (EC) and minimize the greenhouse gas (GHG) emissions of the proposed system. The MOA is selected as it collects the main merits of swarm intelligence and evolutionary algorithms; hence it has good convergence characteristics. To ensure the superiority of the selected MOA the obtained results are compared with other well-known optimization algorithms namely Sooty Tern Optimization Algorithm (STOA) Whale Optimization Algorithm (WOA) and Sine Cosine Algorithm (SCA). The results reveal that the suggested MOA achieves the best system design achieving a stable convergence characteristic after 44 iterations. MOA yielded the best EC with 0.2106533 $/kWh the net present cost (NPC) with 6170134 $ the loss of power supply probability (LPSP) with 0.05993% and GHG with 792.534 t/y.

Understanding the system performance of different electrolyzers could aid potential investors achieve maximum return on their investment. To realize this system response characteristics to 4 different summarized data sets of curtailed renewable energy is obtained from the Irish network and was investigated using models of both a Low Temperature Electrolyzer (LTE) and a High Temperature Electrolyzer (HTE). The results indicate that statistical parameters intrinsic to the method of data extraction along with the thermal response time of the electrolyzers influence the hydrogen output. A maximum hydrogen production of 5.97 kTonne/year is generated by a 0.5 MW HTE when the electrical current is sent as a yearly average. Additionally the high thermal response time in a HTE causes a maximum change in the overall flowrate of 65.7% between the 4 scenarios when compared to 7.7% in the LTE. This evaluation of electrolyzer performance will aid investors in determining scenario specific application of P2G for maximizing hydrogen production.

The current research on green hydrogen can focus from the perspective of production but understanding the demand side is equally important to the initial creation of a hydrogen ecosystem in countries with low industrial activities that can utilise large amounts of hydrogen in the short term. Early movers in these countries must create a demand market in parallel with the green hydrogen plant commissioning. This paper presents research that explores the heavy-duty transport sector as a market-of-interest for early deployment of green hydrogen in Ireland. Conducting a survey-based market research amongst this sector indicate significant interest in hydrogen on the island of Ireland and the barriers the participants presented have been overcome in other jurisdictions. The study develops a model to estimate 1.) the annual hydrogen demand and 2.) the corresponding delivery cost to potential hydrogen consumers either directly or to central hydrogen fuelling hubs.

With a relatively high energy density hydrogen is attracting increasing attention in research commercial and political spheres specifically as a fuel for residential heating which is proving to be a difficult sector to decarbonise in some circumstances. Hydrogen production is dependent on the power system so any scale use of hydrogen for residential heating will impact various aspects of the power system including electricity prices and renewable generation curtailment (i.e. wind solar). Using a linearised optimal power flow model and the power infrastructure on the island of Ireland this paper examines least cost optimal investment in electrolysers in the presence of Ireland's 70% renewable electricity target by 2030. The introduction of electrolysers in the power system leads to an increase in emissions from power generation which is inconsistent with some definitions of green hydrogen. Electricity prices are marginally higher with electrolysers whereas the optimal location of electrolysers is driven by a combination of residential heating demand and potential surplus power supplies at electricity nodes.