United States

Hydrogen produced from electrolysis is an attractive carbon-free fuel and feedstock but potential benefits depend on the carbon intensity of electricity production. This study uses technoeconomic modeling to analyze the benefits of producing zero-carbon hydrogen through dynamically operated polymer electrolyte membrane electrolyzers connected to photovoltaic and wind variable renewable energy (VRE) sources. Dynamic operation is considered for current densities between 0 and 6 A cm2 and compared to a constant current density of 2 A cm2 for different combinations of VRE to electrolysis (VRE:E) capacity ratios and compositions of photovoltaic and wind energy in four locations across the United States. For optimal VRE:E and wind:photovoltaic capacity ratios dynamic operation is found to reduce the levelized cost of hydrogen by 5%–9% while increasing hydrogen production by 134%–173% and decreasing excess electrical power by 82%–95%. The framework herein may be used to determine the optimal VRE:E capacity and VRE mix for dynamically operated green hydrogen systems.

This work addresses the energy efficiency of hydrogen refueling stations (HRS) using a first principles model and optimal control methods to find minimal entropy production operating paths. The HRS model shows good agreement with experimental data achieving maximum state of charge and temperature discrepancies of 1 and 7% respectively. Model solution and optimization is achieved at a relatively low computational time (40 s) when compared to models of the same degree of accuracy. The entropy production mapping indicates the flow control valve as the main source of irreversibility accounting for 85% of the total entropy production in the process. The minimal entropy production refueling path achieves energy savings from 20 to 27% with respect to the SAE J2601 protocol depending on the ambient temperature. Finally the proposed method under nearreversible refueling conditions shows a theoretical reduction of 43% in the energy demand with respect to the SAE J2601 protocol.

Fluid dispersion directly influences the transport mixing and efficiency of hydrogen storage in depleted gas reservoirs. Pore structure parameters such as pore size throat geometry and connectivity influence the complexity of flow pathways and the interplay between advective and diffusive transport mechanisms. Hence these factors are critical for predicting and controlling flow behavior in the reservoirs. Despite its importance the relationship between pore structure and dispersion remains poorly quantified particularly under elevated flow conditions. To address this gap this study employs pore network modeling (PNM) to investigate the influence of sandstone and carbonate structures on fluid flow properties at the micro-scale. Eleven rock samples comprising seven sandstone and four carbonate were analyzed. Pore network extraction from CT images was used to obtain detailed pore structure parameters and their statistical measures. Pore-scale simulations were conducted across 60 scenarios with varying average interstitial velocities and water as the injected fluid. Effluent hydrogen concentrations were measured to generate elution curves as a function of injected pore volumes (PV). This approach enables the assessment of the relationship between the dispersion coefficient and pore structure parameters across all rock samples at consistent average interstitial velocities. Additionally dispersivity and n-exponent values were calculated and correlated with pore structure parameters.

Increasing penetrations of renewable-based generation have led to a decrease in the bulk power system inertia and an increase in intermittency and uncertainty in generation. Energy storage is considered to be an important factor to help manage renewable energy generation at greater penetrations. Hydrogen is a viable long-term storage alternative. This paper analyzes and presents use cases for leveraging electrolyzer-based power-to-gas systems for electric grid support. The paper also discusses some grid services that may favor the use of hydrogenbased storage over other forms such as battery energy storage. Real-time controls are developed implemented and demonstrated using a power-hardware-in-the-loop(PHIL) setup with a 225-kW proton-exchange-membrane electrolyzer stack. These controls demonstrate frequency and voltage support for the grid for different levels of renewable penetration (0% 25% and 50%). A comparison of the results shows the changes in respective frequencies and voltages as seen as different buses as a result of support from the electrolyzers and notes the impact on hydrogen production as a result of grid support. Finally the paper discusses the practical nuances of implementing the tests with physical hardware such as inverter/electrolyzer efficiency as well as the related constraints and opportunities.

This paper presents a comparative analysis of two hydrogen station configurations during the refueling process: the conventional “directly pressurized refueling process” and the innovative “cascade refueling process.” The objective of the cascade process is to refuel vehicles without the need for booster compressors. The experiments were conducted at the Hydrogen Research and Fueling Facility located at California State University Los Angeles. In the cascade refueling process the facility buffer tanks were utilized as high-pressure storage enabling the refueling operation. Three different scenarios were tested: one involving the cascade refueling process and two involving compressor-driven refueling processes. On average each refueling event delivered 1.6 kg of hydrogen. Although the cascade refueling process using the high-pressure buffer tanks did not achieve the pressure target it resulted in a notable improvement in the nozzle outlet temperature trend reducing it by approximately 8 ◦C. Moreover the overall hydrogen chiller load for the two directly pressurized refuelings was 66 Wh/kg and 62 Wh/kg respectively whereas the cascading process only required 55 Wh/kg. This represents a 20% and 12% reduction in energy consumption compared to the scenarios involving booster compressors during fueling. The observed refueling range of 150–350 bar showed that the cascade process consistently required 12–20% less energy for hydrogen chilling. Additionally the nozzle outlet temperature demonstrated an approximate 8 ◦C improvement within this pressure range. These findings indicate that further improvements can be expected in the high-pressure region specifically above 350 bar. This research suggests the potential for significant improvements in the high-pressure range emphasizing the viability of the cascade refueling process as a promising alternative to the direct compression approach.

To reduce carbon emissions generation of electricity from combustion systems is being replaced by renewable resources. However the most abundant renewable sources – solar and wind – are not dispatchable vary diurnally and are subject to intermittency and produce electricity at times in excess of demand (excess production). To manage this variability and capture the excess renewable energy energy storage technologies are being developed and deployed such as battery energy storage (BES) hydrogen production with electrolyzers (ELY) paired with hydrogen energy storage (HES) and fuel cells (FCs) and renewable natural gas (RNG) production. While BES may be better suited for short duration storage hydrogen is suited for long duration storage and RNG can decarbonize the natural gas system. California Senate Bill 100 (SB100) sets a goal that all retail electricity sold in the State must be sourced from renewable and zero-carbon resources by 2045 raising the questions of which set of technologies and in what proportion are required to meet the 2045 target in the required timeframe as well as the role of the natural gas infrastructure if any. To address these questions this study combines electric grid dispatch modeling and optimization to identify the energy storage and dispatchable technologies in 5-year increments from 2030 to 2045 required to transition from a 60% renewable electric grid in 2035 to a 100% renewable electric grid in 2045. The results show that by utilizing the established natural gas system to store and transmit hydrogen and RNG the deployment of battery energy storage is dramatically reduced. The required capacity for BES in 2045 for example is 40 times lower by leveraging the natural gas infrastructure with a concomitant reduction in cost and associated challenges to transform the electric grid.

There is a pressing need to rapidly and massively scale up negative carbon strategies such as carbon capture and storage (CCS). At the same time large-scale CCS can enable ramp-up of large-scale hydrogen production a key component of decarbonized energy systems. We argue here that the safest and most practical strategy for dramatically increasing CO2 storage in the subsurface is to focus on regions where there are multiple partially depleted oil and gas reservoirs. Many of these reservoirs have adequate storage capacity are geologically and hydrodynamically well understood and are less prone to injection-induced seismicity than saline aquifers. Once a CO2 storage facility is up and running it can be used to store CO2 from multiple sources. Integration of CCS with hydrogen production appears to be an economically viable strategy for dramatically reducing greenhouse gas emissions over the next decade particularly in oil- and gas-producing countries where there are numerous depleted reservoirs that are potentially suitable for large-scale carbon storage.

The role of hydrogen in energy system decarbonization is being actively examined by the research and policy communities. We evaluate the potential “hydrogen economy” in global climate change mitigation scenarios using the Global Change Analysis Model (GCAM). We consider major hydrogen production methods in conjunction with delivery options to understand how hydrogen infrastructure affects its deployment. We also consider a rich set of hydrogen end-use technologies and vary their costs to understand how demand technologies affect deployment. We find that the availability of hydrogen transmission and distribution infrastructure primarily affects the hydrogen production mix particularly the share produced centrally versus on-site whereas assumptions about end-use technology primarily affect the scale of hydrogen deployment. In effect hydrogen can be a source of distributed energy enabled by on-site renewable electrolysis and to a lesser extent by on-site production at industrial facilities using natural gas with carbon capture and storage (CCS). While the share of hydrogen in final energy is small relative to the share of other major energy carriers in our scenarios hydrogen enables decarbonization in difficult-to-electrify end uses such as industrial high-temperature heat. Hydrogen deployment and in turn its contribution to greenhouse gas mitigation increases as the climate objective is tightened.

Growing imbalances between electricity demand and supply from variable renewable energy sources (VREs) create increasingly large swings in electricity prices. Polymer electrolyte membrane (PEM) electrolyzers can help to buffer against these imbalances and minimize the levelized cost of hydrogen (LCOH) by ramping up production of hydrogen through high-current-density operation when low-cost electricity is abundant and ramping down current density to operate efficiently when electricity prices are high. We introduce a technoeconomic model that optimizes current density profiles for dynamically operated electrolyzers while accounting for the potential of increased degradation rates to minimize LCOH for any given time-of-use (TOU) electricity pricing. This model is used to predict LCOH from different methods of operating a PEM electrolyzer for historical and projected electricity prices in California and Texas which were chosen due to their high penetration of VREs. Results reveal that dynamic operation could enable reductions in LCOH ranging from 2% to 63% for historical 2020 pricing and 1% to 53% for projected 2030 pricing. Moreover high-current-density operation above 2.5 A cm2 is increasingly justified at electricity prices below $0.03 kWh1 . These findings suggest an actionable means of lowering LCOH and guide PEM electrolyzer development toward devices that can operate efficiently at a range of current densities.

Hydrogen-powered aviation is gaining momentum as a sustainable alternative to fossil-fueled flight yet the field faces complex technological and operational challenges. To better understand commercial innovation pathways this study analyzes the claims sections of 166 hydrogen aviation patents issued between 2018 and 2024. Unlike prior studies that focused on patent titles or abstracts this approach reveals the protected technical content driving commercialization. The study classifies innovations into seven domains: fuel storage fuel delivery fuel management turbine enhancement fuel cell integration hybrid propulsion and safety enhancement. Thematic word clouds and term co-occurrence networks based on natural language processing techniques validate these classifications and highlight core technical themes. Scientometric analyses uncover rapid patent growth rising international participation and strong engagement from both established aerospace firms and young companies. The findings provide stakeholders with a structured view of the innovation landscape helping to identify technological gaps emerging trends and areas for strategic investment and policymaking. This claims-based method offers a scalable framework to track progress in hydrogen aviation and is adaptable to other emerging technologies.