• Energy Research

To achieve the Net-Zero Emissions goal by 2050, a major upscale in green hydrogen needs to be achieved; this will also facilitate use of renewable electricity as a source of decarbonised fuel in hard-to-abate sectors such as industry and transport. Nearly 80% of the world's offshore wind resource is in waters deeper than 60 m, where bottom-fixed wind turbines are not feasible. This creates a significant opportunity to couple the high capacity factor floating offshore wind and green hydrogen. In this paper we consider dedicated large-scale floating offshore wind farms for hydrogen production with three coupling typologies; (i) centralised onshore electrolysis, (ii) decentralised offshore electrolysis, and (iii) centralised offshore electrolysis. The typology design is based on variables including for: electrolyser technology; floating wind platform; and energy transmission vector (electrical power or offshore hydrogen pipelines). Offshore hydrogen pipelines are assessed as economical for large and distant farms. The decentralised offshore typology, employing a semi-submersible platform could accommodate a proton exchange membrane electrolyser on deck; this would negate the need for an additional separate structure or hydrogen export compression and enhance dynamic operational ability. It is flexible; if one electrolyser (or turbine) fails, hydrogen production can easily continue on the other turbines. It also facilities flexibility in further expansion as it is very much a modular system. Alternatively, less complexity is associated with the centralised offshore typology, which may employ the electrolysis facility on a separate offshore platform and be associated with a farm of spar-buoy platforms in significant water depth locations.

Abstract The suitability of existing sources of CO2 in a region (Ireland) for use in power to gas systems was determined using multi criteria decision analysis. The main sources of CO2 were from the combustion of fossil fuels, cement production, alcohol production, and wastewater treatment plants. The criteria used to assess the suitability of CO2 sources were: annual quantity of CO2 emitted; concentration of CO2 in the gas; CO2 source; distance to the electricity network; and distance to the gas network. The most suitable sources of CO2 were found to be distilleries, and wastewater treatment plants with anaerobic digesters. The most suitable source of CO2, a large distillery, could be used to convert 461 GWh/a of electricity into 258 GWh/a of methane. The total electricity requirement of this system is larger than the 348 GWh of renewable electricity dispatched down in Ireland in 2015. This could allow for the conversion of electricity that would be curtailed into a valuable energy vector. The resulting methane could fuel 729 compressed natural gas fuelled buses per annum. Synergies in integrating power to gas at a wastewater treatment plant include use of oxygen in the wastewater treatment process.

Biomethane is a flexible energy vector that can be used as a renewable fuel for both the heat and transport sectors. Recent EU legislation encourages the production and use of advanced, third generation biofuels with improved sustainability for future energy systems. The integration of technologies such as anaerobic digestion, gasification, and power to gas, along with advanced feedstocks such as algae will be at the forefront in meeting future sustainability criteria and achieving a green gas supply for the gas grid. This paper explores the relevant pathways in which an integrated biomethane industry could potentially materialise and identifies and discusses the latest biotechnological advances in the production of renewable gas. Three scenarios of cascading biomethane systems are developed.

Abstract Accommodating renewables on the electricity grid may hinder development opportunities for offshore wind farms (OWFs) as they begin to experience significant curtailment or constraint. However, there is potential to combine investment in OWFs with Power-to-Gas (PtG), converting electricity to hydrogen via electrolysis for an alternative/complementary revenue. Using historic wind speed and simulated system marginal costs data this work models the electricity generated and potential revenues of a 504 MW OWF. Three configurations are analysed; (1) all electricity is sold to the grid, (2) all electricity is converted to hydrogen and sold, and (3) a hybrid system where power is converted to hydrogen when curtailment occurs and/or when the system marginal cost is low, with the effect of curtailment analysed in each scenario. These represent the status quo, a potential future configuration, and an innovative business model respectively. The willingness of an investor to build PtG are determined by changes to the net present value (NPV) of a project. Results suggest that configuration (1) is most profitable and that curtailment mitigation alone is not sufficient to secure investment in PtG. By acting as an artificial floor in the electricity price, a hybrid configuration (3) is promising and increases NPV for all hydrogen values greater than €4.2/kgH2. Hybrid system attractiveness increases with curtailment only if the hydrogen value is significantly above the levelised cost of €3.77/kgH2. In order for an investor to choose to pursue configuration (2), the offshore wind farm would have to anticipate 8.5% curtailment and be able to receive €4.5/kgH2, or 25% curtailment and receive €4/kgH2. The capital costs and discount rates are the most sensitive parameters and ambitious combinations of technology improvements could produce a levelised cost of €3/kgH2.

Abstract Variable renewable electricity (VRE) decarbonises the electricity grid, but its intermittency leads to variations in price, carbon intensity, and curtailment over time. This has led to interest in utilising difficult to manage electricity to produce electrofuels (such as hydrogen via water electrolysis) for transport. The vast majority of the environmental impact of electrofuels is contained in the electricity they consume however, only consuming otherwise curtailed electricity (produced when supply exceeds demand) leads to prohibitively expensive hydrogen due to low run hours. Using a model which bids for wholesale electricity, two operational strategies (controls) aimed at increasing sustainability without requiring policy changes were tested in electricity system models of 40–60% renewable electricity penetration. (1) Bid price control set a maximum price the plant will pay for electricity. (2) Wind forecast control dictated that the plant may only run when a minimum forecast VRE production is met. It was shown that sourcing electricity at times of low cost or high forecast wind power can lead to more decarbonised hydrogen production (up to 56% more) at a lower cost (up to 57% less). When economically optimised (minimising levelised costs) the bid price control reduced the carbon intensity of the electrofuel produced by 5–25%, and the wind forecast control by 14–38%, compared to the grid average. Both controls demonstrated a high proclivity to utilising otherwise curtailed electricity and can be said to aid grid balancing. The bid price control also greatly reduced the average cost of electricity to the plant. The positive impacts increased with renewables penetration, and significant synergies between economic and environmentally conscious operation of the plants were noted. The operational strategies tested in this paper allow for transport fuels to be produced from grid electricity, without exacerbating the mismatch of supply and demand. Future decentralised quasi-storage using these operating strategies may economically produce transport fuel, and aid grid balancing.

Abstract The operation of power-to-X systems requires measures to control the cost and sustainability of electricity purchased from spot markets. This study investigated different bidding strategies for the day-ahead market with a special focus on Sweden. A price independent order (PIO) strategy was developed assisted by forecasting electricity prices with an artificial neural network. For comparison, a price dependent order (PDO) with fixed bid price was used. The bidding strategies were used to simulate H2 production with both alkaline and proton exchange membrane electrolysers in different years and technological scenarios. Results showed that using PIO to control H2 production helped to avoid the purchase of expensive and carbon intense electricity during peak loads, but it also reduced the total number of operating hours compared to PDO. For this reason, under optimal conditions for both bidding strategies, PDO resulted in an average of 10.9% lower levelised cost of H2, and more attractive cash flows and net present values than PIO. Nevertheless, PIO showed to be a useful strategy to control costs in years with unexpected hourly price behaviour such as 2018. Furthermore, PIO could be successfully demonstrated in a practical case study to fulfil the on-demand requirement of an industrial captive customer.

Abstract Power to gas (P2G) has been mooted as a means of producing advanced renewable gaseous transport fuel, whilst providing ancillary services to the electricity grid through decentralised small scale (10 MW) energy storage. This study uses a discounted cash flow model to determine the levelised cost of energy (LCOE) of the gaseous fuel from non-biological origin in the form of renewable methane for various cost scenarios in 2020, 2030, and 2040. The composition and sensitivity of these costs are investigated as well as the effects of incentives and supplementary incomes. The LCOE was found to be €107-143/MWh (base value €124) in 2020, €89-121/MWh (base value €105) in 2030, and €81-103/MWh (base value €93) in 2040. The costs were found to be dominated by electricity charges in all scenarios (56%), with the total capital expenditure the next largest contributor (33%). Electricity costs and capacity factor were the most sensitive parameters followed by total capital expenditure, project discount rate, and fixed operation and maintenance. For the 2020 base scenario should electricity be available at zero cost the LCOE would fall from €124/MWh to €55/MWh. Valorisation of the produced oxygen (€0.1/Nm3 profit) would generate an LCOE of €105/MWh. A payment for ancillary services to the electricity grid of €15/MWe for 8500 h p.a would lower the LCOE to €87/MWh. Price parity with diesel, exclusive of sales tax, is achieved with an incentive of €19/MWh.

Abstract Power-to-Gas (P2G) is a technology that converts electricity to gas and is termed gaseous fuel from non-biological origin. It has been mooted as a means of utilising low-cost or otherwise curtailed electricity to produce an advanced transport fuel, whilst facilitating intermittent renewable electricity through grid balancing measures and decentralised storage of electricity. This paper investigates the interaction of a 10MWe P2G facility with an island electricity grid with limited interconnection, through modelling electricity purchase. Three models are tested; 2016 at 25% renewable electricity penetration and 2030 at both 40% and 60% penetration levels. The relationships between electricity bid price, average cost of electricity and run hours were established whilst the levelised cost of energy (LCOE) was evaluated for the gaseous fuel produced. Bidding for electricity above the average marginal cost of generation in the system (€35–50/MWeh) was found to minimise the LCOE in all three scenarios. The frequency of low-cost and high-costs hours, analogous to balancing issues, increased with increasing shares of variable renewable electricity generation. However, basing P2G systems on low-cost (less than €10/MWeh) hours alone (999 h in 2030 at 60% renewable penetration) is not the path to financial optimisation; it is preferential to increase the run hours to a level that amortises the capital expenditure.