Applications & Pathways

The use of green hydrogen can support the decarbonization of sectors which are difficult to electrify such as industry or heavy transport. Yet the wider power sector effects of providing green hydrogen are not well understood so far. We use an open-source electricity sector model to investigate potential power sector interactions of three alternative supply chains for green hydrogen in Germany in the year 2030. We distinguish between model settings in which Germany is modeled as an electric island versus embedded in an interconnected system with its neighboring countries as well as settings with and without technology-specific capacity bounds on wind energy. The findings suggest that large-scale hydrogen storage can provide valuable flexibility to the power system in settings with high renewable energy shares. These benefits are more pronounced in the absence of flexibility from geographical balancing. We further find that the effects of green hydrogen production on the optimal generation portfolio strongly depend on the model assumptions regarding capacity expansion potentials. We also identify a potential distributional effect of green hydrogen production at the expense of other electricity consumers of which policy makers should be aware.

Low-carbon ammonia has recently received interest as alternative fuel for the maritime sector. This paper presents a techno-economic analysis of the total cost of ownership (TCO) of a Post-Panamax vessel powered by low-carbon ammonia. We also calculate the annual increase in carbon tax needed to compensate for the increment in TCO compared to a vessel powered by very low sulfur fuel oil. The increment in TCO is calculated as function of propulsion efficiency to account for uncertainties in the thermodynamics of ammonia combustion for three different cost scenarios of low-carbon ammonia. We evaluate the benefits and drawbacks of hydrogen and diesel as dual fuel for three types of propulsion systems: a compression ignition engine a spark-ignition engine and a combination of a solid oxide fuel cell (SOFC) system and a spark-ignition engine. We incorporate three different cost levels for ammonia and a variable engine efficiency ranging from 35% to 55%. If the ammonia engine has the efficiency of a conventional marine engine the increment in TCO is 25% in the most optimistic cost scenario. SOFCs can reach a better efficiency and yield no pollutant emissions but the reduction in fuel expenses in comparison to conventional combustion engines only offsets their high investment costs at either low engine efficiency or high fuel prices. The increment in TCO and reduction in GHG emissions depend on whether high combustion efficiencies small dual fuel fractions and low NOx N2O and NH3 emissions can be simultaneously achieved.

Aviation is one of the most challenging sectors to electrify directly due to its high energy density demands. Hydrogen offers a pathway for indirect electrification in such sectors enabling sustainable aviation fuels (SAF) production when combined with a carbon source. SAF produced via methanol or Fischer-Tropsch (FT) synthesis (e-SAF) has higher volumetric density than hydrogen remains liquid under standard conditions and can be used as a direct drop-in fuel. Certain FT-based e-SAF pathways are already certified for use in blends enhancing their appeal for sustainable aviation. This study evaluates e-SAF pathways in terms of resource efficiency and costs for different carbon sources. The results from both a standalone and system-level perspective indicate that biomass gasification-sourced carbon is the most energy-efficient pathway given biomass availability. For point-source and direct air capture pathways electricity costs for renewable hydrogen dominate the overall costs comprising about 70 % of total e-SAF costs. Given cheap renewable electricity and by-product revenues e-SAF can achieve price levels of 0.5–1.1 €/litre which is cost-competitive with their fossil-based counterparts. A breakeven electricity price of 9–29 €/MWh is needed for e-SAF made via a point source-based CO2 pathway compared with a moderate aviation fossil fuel price of 0.5 €/litre.

Ammonia production currently contributesalmost 11% of global industrial carbon dioxide emissions or1.3% of global emissions. In the context of global emissiontargets and growing demand decarbonization of this processis highly desirable. We present a method to calculate a firstestimate for the optimum size of an ammonia productionplant (at the process level) the required renewable energy(RE) supply and the levelized cost of ammonia (LCOA) forislanded operation with a hydrogen buffer. A model wasdeveloped to quantitatively identify the key variables thatimpact the LCOA (relative to a ±10 GBP/tonne change inLCOA): levelized cost of electricity (±0.89 GBP/MWh) electrolyzer capital expenditure (±65 GBP/kW) minimum Haber−Bosch (HB) load (±12% of rated power) maximum rate of HB load ramping and RE supply mix. Using 2025/2030 estimatesresults in a LCOA of 588 GBP/tonne for Lerwick Scotland. The application of the model will facilitate and improve theproduction of carbon-free ammonia in the future.

The integration of renewable energy resources (RES) into microgrids (MGs) poses significant challenges due to the intermittent nature of generation and the increasing complexity of multi-energy scheduling. To enhance operational flexibility and reliability this paper proposes an intelligent energy management system (EMS) for MGs incorporating a hybrid hydrogen-battery energy storage system (HHB-ESS). The system model jointly considers the complementary characteristics of short-term and long-term storage technologies. Three conflicting objectives are defined: economic cost (EC) system response stability and battery life loss (BLO). To address the challenges of multi-objective trade-offs and heterogeneous storage coordination a novel deep-reinforcement-learning (DRL) algorithm termed MOATD3 is developed based on a dynamic reward adjustment mechanism (DRAM). Simulation results under various operational scenarios demonstrate that the proposed method significantly outperforms baseline methods achieving a maximum improvement of 31.4% in SRS and a reduction of 46.7% in BLO.

Financing sizing operating or upgrading a hydrogen refueling station (HRS) is challenging and may be complex much more so in today's rapidly changing and growing hydrogen industry. There is a significant information gap regarding experimental hydrogen station activities. A high-level perspective on such data and information may facilitate the transition between present and future HRS operations. To address the need for such high-level perspective this paper presents a comprehensive data set on the performance of the California State University Los Angeles Hydrogen Research and Fueling Facility based on multi-year operational data. The analysis of over 4500 refueling events and over 8800 kg of hydrogen dispensed as well as the operation of the facility electrolyzer and of both storage and refueling compressors from 2016 to 2020 reveals a comprehensive picture of HRS energy performance and the identification of useful key performance indicators. In 2016 the station's energy efficiency was 25% but in 2017 and the first three quarters of 2018 it dropped to 15%. Station-specific energy consumption increased during these quarters. The 2020 first quarter energy consumption was between 70 and 80 kWh/kg. At this time the energy efficiency of the station reached 40%.<br/>This research is based on an unprecedented and unique dataset of an HRS operating under real-world conditions with an approach that can be informative for modeling the performance of other stations providing a dataset that HRS designers operators and investors may utilize to make data-driven choices regarding HRS components and their specs and size as well as operating strategies.

With the deepening electrification of transportation hydrogen fuel cell electric vehicles (FCEVs) are emerging as a vital component of clean and electrified transportation systems. Nonetheless renewable-based hydrogen production–refueling stations (HPRSs) for FCEVs still need solid models for accurate simulations and a practical capacity optimization method for cost reduction. To address this gap this study leverages real operation data from China’s largest HPRS to establish and validate a comprehensive model integrating hydrogen production storage renewables FCEVs and the power grid. Building on this validated model a novel capacity optimization framework is proposed incorporating an improved Jellyfish Search Algorithm (JSA) to minimize the initial investment cost operating cost and levelized cost of hydrogen (LCOH). The results demonstrate the framework’s significant innovations and effectiveness: It achieves the maximum reductions of 29.31% in the initial investment 100% in the annual operational cost and 44.19% in LCOH while meeting FCEV demand. Simultaneously it reduces peak grid load by up to 43.80% and enables renewable energy to cover up to 89.30% of transportation hydrogen demand. This study contributes to enhancing economic performance and optimizing the design and planning of HPRS for FCEVs as well as promoting sustainable transportation electrification.

Civil aviation provides an essential transportation network that connects the world and supports global economic growth. To maintain these benefits while meeting environmental goals next-generation aircraft must have drastically reduced climate impacts. Hydrogen-powered aircraft have the potential to fly existing routes with no carbon emissions and reduce or eliminate other emissions. This paper is a comprehensive guide to hydrogen-powered aircraft that explains the fundamental physics and reviews current technologies. We discuss the impact of these technologies on aircraft design cost certification and environment. In the long term hydrogen aircraft appear to be the most compelling alternative to today’s kerosene-powered aircraft. Using hydrogen also enables novel technologies such as fuel cells and superconducting electronics which could lead to aircraft concepts that are not feasible with kerosene. Hydrogen-powered aircraft are technologically feasible but require significant research and development. Lightweight liquid hydrogen tanks and their integration with the airframe is one of the critical technologies. Fuel cells can eliminate in-flight emissions but must become lighter more powerful and more durable to make large fuel cell-powered transport aircraft feasible. Hydrogen turbofans already have these desirable characteristics but produce some emissions albeit much less damaging than kerosene turbofans. Beyond airframe and propulsion technologies the viability of hydrogen aircraft hinges on low-cost green hydrogen production which requires massive investments in the energy infrastructure.

This paper evaluates the potential impacts of introducing low-carbon intensity hydrogen technologies in two oil refineries with different complexity levels emphasizing the role of hydrogen production in reducing CO2 emissions. The novelty of this work lies in three key aspects: Comprehensive system analysis of refinery complexity using real site data integration of low-carbon Hydrogen technologies long-term and short-term strategies. Two Colombian refineries serve as case studies with technological solutions adapted to their complexity levels. The methodology involves evaluating different options for hydrogen production accounting for improvement in technological efficiency over time.<br/>The refinery systems were evaluated in a cost-optimization model built in Linny-r. Three different scenarios were considered Business-As-Usual (BAU) high and low-ambitions decarbonization scenarios focusing on the time horizons of 2030 and 2050.<br/>When comparing the two case studies the preferred decarbonization strategy for both facilities involves the substitution of SMR technology with water electrolyzers powered by renewable electricity. Post-2030 biomass-based hydrogen technology is still a costly alternative; however to achieve CO2 neutrality negative emissions storage of biogenic CO2 emerges as an achievable alternative.<br/>Our results indicate the achievability of CO2 reduction objectives in both refineries. Our results show that achieving long-term CO2 neutrality requires both refineries to increase renewable electricity production by 5 to 6 times for powering water electrolyzers steam production by 2 to 2.5 times for CO2 capture and supply of dry biomass by 2.6 to 4.5 kt/d.<br/>The two most significant factors influencing the refining net margin in the decarbonization scenarios are primarily the CO2 and the renewable electricity prices. The short-term horizon emerges as the pivotal period particularly within the high-ambition decarbonization scenarios. In this context the medium complexity refinery demonstrates economic viability until a CO2 price of 140 €/t CO2 while the high complexity refinery endures up to 205 €/t CO2.<br/>The high complexity refinery is better prepared to face the challenges of decarbonization and the impacts generated on the refining margin. Compared to the BAU scenario the high complexity refinery shows a negative impact on the net margin that corresponds to a 40% and 5% reduction in the short and long term respectively. Meanwhile for the medium complexity refinery the impact on net margin amounts to a 52% reduction in the short term and a 27% improvement in the long term.<br/>Furthermore our research highlights the significant potential for reducing CO2 emissions by fully eliminating the use of refinery gas as fuel providing alternative applications for it beyond combustion.

Electrofuels fuels produced from electricity water and carbon or nitrogen are of interest as substitutes for fossil fuels in all energy and chemical sectors. This paper focuses on electrofuels for transportation where some can be used in existing vehicle/vessel/aircraft fleets and fueling infrastructure. The aim of this study is to review publications on electrofuels and summarize costs and environmental performance. A special case denoted as bio-electrofuels involves hydrogen supplementing existing biomethane production (e.g. anaerobic digestion) to generate additional or different fuels. We use costs identified in the literature to calculate harmonized production costs for a range of electrofuels and bio-electrofuels. Results from the harmonized calculations show that bio-electrofuels generally have lower costs than electrofuels produced using captured carbon. Lowest costs are found for liquefied bio-electro-methane bio-electro-methanol and bio-electro-dimethyl ether. The highest cost is for electro-jet fuel. All analyzed fuels have the potential for long-term production costs in the range 90–160 € MWh−1 . Dominant factors impacting production costs are electrolyzer and electricity costs the latter connected to capacity factors (CFs) and cost for hydrogen storage. Electrofuel production costs also depend on regional conditions for renewable electricity generation which are analyzed in sensitivity analyses using corresponding CFs in four European regions. Results show a production cost range for electro-methanol of 76–118 € MWh−1 depending on scenario and region assuming an electrolyzer CAPEX of 300–450 € kWelec −1 and CFs of 45%–65%. Lowest production costs are found in regions with good conditions for renewable electricity such as Ireland and western Spain. The choice of system boundary has a large impact on the environmental assessments. The literature is not consistent regarding the environmental impact from different CO2 sources. The literature however points to the fact that renewable energy sources are required to achieve low global warming impact over the electrofuel life cycle.