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.

This study evaluates the feasibility of repurposing produced water—an abundant byproduct of hydrocarbon extraction—for green hydrogen production in Wyoming USA. Analysis of geospatial distribution and production volumes reveals that there are over 1 billion barrels of produced water annually from key basins with a general total of dissolved solids (TDS) ranging from 35000 to 150000 ppm though Wyoming’s sources are often at the lower end of this spectrum. Optimal locations for hydrogen production hubs have been identified particularly in high-yield areas like the Powder River Basin where the top 2% of fields contribute over 80% of the state’s produced water. Detailed water-quality analysis indicates that virtually all of the examined sources exceed direct electrolyzer feed requirements (e.g. 10% LCOH) are notable electricity pricing (50–70% LCOH) and electrolyzer CAPEX (20–40% LCOH) are dominant cost factors. While leveraging produced water could reduce freshwater consumption and enhance hydrogen production sustainability further research is required to optimize treatment processes and assess economic viability under real-world conditions. This study emphasizes the need for integrated approaches combining water treatment renewable energy and policy incentives to advance a circular economy model for hydrogen production.

This research models a 20 MW PEM hydrogen plant. PEM units operate in the 60 to 80 ◦C range based on their location and size. This study aims to recover the waste heat from PEM modules to enhance the efficiency of the plant. In order to recover the heat two systems are implemented: (a) recovering the waste heat from each PEM module; (b) recovering the heat from hot water to produce electricity utilizing an organic refrigerant cycle (ORC). The model is made by ASPEN® V14. After modeling the plant and utilizing the ORC the module is optimized using Python to maximize the electricity produced by the turbine therefore enhancing the efficiency. The system is a closed-loop cycle operating at 25 ◦C and ambient pressure. The 20 MW PEM electrolyzer plant produces 363 kg/hr of hydrogen and 2877 kg/hr of oxygen. Based on the higher heating value of hydrogen the plant produces 14302.2 kWh of hydrogen energy equivalents. The ORC is maximized by increasing the electricity output from the turbine and reducing the pump work while maintaining energy conservation and mass balance. The results show that the electricity power output reaches 555.88 kW and the pump power reaches 23.47 kW.

The increasing global energy demand and the transition toward sustainable energy systems have highlighted the importance of energy storage technologies by ensuring efficiency reliability and decarbonization. This study reviews chemical and thermal energy storage technologies focusing on how they integrate with renewable energy sources industrial applications and emerging challenges. Chemical Energy Storage systems including hydrogen storage and power-to-fuel strategies enable long-term energy retention and efficient use while thermal energy storage technologies facilitate waste heat recovery and grid stability. Key contributions to this work are the exploration of emerging technologies challenges in large-scale implementation and the role of artificial intelligence in optimizing Energy Storage Systems through predictive analytics real-time monitoring and advanced control strategies. This study also addresses regulatory and economic barriers that hinder widespread adoption emphasizing the need for policy incentives and interdisciplinary collaboration. The findings suggest that energy storage will be a fundamental pillar of the sustainable energy transition. Future research should focus on improving material stability enhancing operational efficiency and integrating intelligent management systems to maximize the benefits of these technologies for a resilient and low-carbon energy infrastructure.

In this work a new modeling tool called DECAL (DEcarbonize CALifornia) is developed and used to evaluate what it will take to reach California’s climate mandate of net-zero emissions by 2045. DECAL is a scenario-based model that projects emissions society-wide costs and resource consumption in response to user-defined inputs. DECAL has sufficient detail to model true net-zero pathways and reveal fine-grain technology insights. Using DECAL we find the State can achieve 52 % of the emissions abatement needed to meet net-zero by 2045 using technologies that are already commercially available such as electric vehicles heat pumps and renewable electricity & storage. While these technologies are mature the speed and scale of deployment required will still pose significant practical challenges if not technical ones. In addition we find that 25 % of emissions abatement will come from technologies currently at early-stage deployment and 23 % from technologies at research scale motivating the continued research & development of these technologies including zero-emission heavy-duty vehicles carbon capture & sequestration clean industrial heating low global warming potential refrigerants and direct air capture. Significant carbon dioxide removal will also be needed for California to meet its net-zero target on time at least 45 Mt/yr and more likely up to 75 Mt/yr by 2045. Accelerating deployment of mature technologies can further reduce the need for carbon removal nevertheless establishing enforceable carbon removal targets and conducting policy planning to make said goals a reality will be needed if California is to meet its net-zero by 2045 goal.

This week the EAH team discusses LIFTE H2’s plans for the future and discusses the challenges in hydrogen markets expansion and rollout the need for resiliency for offtakers and how to build consumer confidence.

The podcast can be found on their website.

Hydrogen fueling stations are critical infrastructure for deploying zero emission hydrogen fuel cell electric vehicles (FCEV). Stations with greater dispensing capacities and higher energy efficiency are needed and cryogenic liquid hydrogen (LH2) has the potential to meet these needs. It is necessary to ensure that hazards and risks are appropriately identified and managed. This paper presents a Quantitative Risk Assessment (QRA) methodology for high-capacity (dispensing >1000 kg/day) hydrogen fueling stations with liquid hydrogen storage and presents the application of that methodology by presenting a Failure Mode and Effect Analysis (FMEA) and data curation for the design developed for this study. This methodology offers a basis for risk and reliability evaluation of these systems as their designs evolve and as operational data becomes available. We developed a generic station design and process flow diagram for a high-capacity hydrogen fueling station with LH2 storage. Following the system description is hazard identification done from FMEA to identify the causes of hydrogen releases and the critical components causing the releases. Finally data collection and curation is discussed including challenges stemming from the limited public availability of reliability data on components used in liquid hydrogen systems. This paper acts as an introduction to the full QRA presented in its companion paper Schaad et al. [1].

This review paper presents an overview of fuel cell electrochemical systems that can be used for clean large-scale power generation and energy storage as global energy concerns regarding emissions and greenhouse gases escalate. The fundamental thermochemical and operational principles of fuel cell power generation and electrolyzer technologies are discussed with a focus on high-temperature solid oxide fuel cells (SOFCs) and solid oxide electrolysis cells (SOECs) that are best suited for grid scale energy generation. SOFCs and SOECs share similar promising characteristics and have the potential to revolutionize energy conversion and storage due to improved energy efficiency and reduced carbon emissions. Electrochemical and thermodynamic foundations are presented while exploring energy conversion mechanisms electric parameters and efficiency in comparison with conventional power generation systems. Methods of converting hydrocarbon fuels to chemicals that can serve as fuel cell fuels are also presented. Key fuel cell challenges are also discussed including degradation thermal cycling and long-term stability. The latest advancements including in materials selection research design and manufacturing methods are also presented as they are essential for unlocking the full potential of these technologies and achieving a sustainable near zero-emission energy future.

Hydrogen is a promising carbon-free energy carrier for large-scale applications yet its adoption faces unique safety challenges. Microscopic physicochemical properties such as high diffusivity low ignition energy and distinct chemical pathways alter the safety of hydrogen systems. Analyzing the HIAD 2.0 incident database an occurrence-based review of past hydrogen incidents shows that 59% arise from general industrial failures common to other hydrocarbon carrier systems. Of the remaining 41% only 15% are unequivocally linked to the fuel’s unique properties. This study systematically isolates hazards driven by hydrogen’s intrinsic properties by filtering out confounding factors and provides an original clear characterization of the different failure mechanisms of hydrogen systems. These hydrogen-specific cases are often poorly described limiting their contribution to safety strategies and regulations improvement. A case study on pipeline failures illustrates how distinguishing hydrogen-specific hazards supports targeted risk mitigation. The findings highlight the need for evidence-based regulation over broadly precautionary approaches.

Green hydrogen plays a pivotal role in decarbonizing our energy system and achieving the Net-Zero Emissions goal by 2050. Offshore wind farms (OWFs) dedicated to green hydrogen production are currently recognized as the most feasible solution for scaling up the production of cost-effective electrolytic hydrogen. However the cost associated with distribution and transmission systems constitute a significant portion of the total cost in the large-scale wind-hydrogen system. This study pioneers the simultaneous optimization of the inter-array cable routing of OWFs and the location and capacity of offshore hydrogen production platforms (OHPPs) aiming to minimize the total cost of distribution and transmission systems. Considering the characteristics of hydrogen production efficiency this paper constructs a novel mathematical model for OHPPs across diverse wind scenarios. Subsequently we formulate the joint planning problem as a relaxed mixed-integer second-order cone programming (MISOCP) model and employ the Benders decomposition algorithm for the solution introducing three valid inequalities to expedite convergence. Through validation on real-world large-scale OWFs we demonstrate the validity and rapid convergence of our approach. Moreover we identify hydrogen production efficiency as a major bottleneck cost factor for the joint planning problem it decreases by 1.01% of total cost for every 1% increase in hydrogen production efficiency.

This study experimentally investigates the effect of hydrogen addition on combustion and thermal characteristics of impinging non-premixed jet flames for low-heating values gases (LHVGs). We evaluate the flame morphology and stability using a concentric non-premixed combustor with an impingement plate. OH radicals are visualized using the OH* chemiluminescence and OH-planar laser-induced fluorescence (OH-PLIF) system. Emission characteristics are investigated by calculating CO and NOx emission indices. The results show that the flame stability region narrows as the heating value decreases but expands as hydrogen has been added. The low-OH radical intensity of LHVGs increases with the hydrogen addition. EICO and EINOx decrease with the reduction of heating values. EICO rapidly declines near the lifted flame limit due to the premixing of fuel and air downstream of the flame region. The effect of the hydrogen addition on EINOx is insignificant and shows very low emissions. The heat transfer rate into cooling water indicates a linear tendency with thermal power regardless of the fuel type. These findings show that LHVGs can be employed in existing-impinging flame systems so long as they remain within flame sta bility regions. Furthermore hydrogen addition positively affects the expansion of flame stability enhancing the utility of LHVGs.

The future is bright for hydrogen as a clean mobile energy source to replace petroleum products. This paper examines new and emerging technologies for hydrogen production storage and conversion and highlights recent commercialization efforts to realize its potential. Also the paper presents selected notable patents issued within the last few years. There is no shortage of inventions and innovations in hydrogen technologies in both academia and industry. While metal hydrides and functionalized carbon-based materials have improved tremendously as hydrogen storage materials over the years storing gaseous hydrogen in underground salt caverns has also become feasible in many commercial projects. Production of “blue hydrogen” is rising as a method of producing hydrogen in large quantities economically. Although electric/battery powered vehicles are dominating the green transport today innovative hydrogen fuel cell technologies are knocking at the door because of their lower refueling time compared to EV charging time. However the highest impact of hydrogen technologies in trans portation might be seen in the aviation industry. Hydrogen is expected to play a key role and provides hope in transforming aviation into a zero-carbon emission transportation over the next few decades.

Hydrogen energy is valued for its diverse sources and clean low-carbon nature and is a promising secondary energy source with wide-ranging applications and a significant role in the global energy transition. Nonetheless hydrogen’s low energy density makes its largescale storage and transport challenging. Liquid hydrogen with its high energy density and easier transport offers a practical solution. This study examines the global hydrogen liquefaction methods with a particular emphasis on the liquid nitrogen pre-cooling Claude cycle process. It also examines the factors in the helium refrigeration cycle—such as the helium compressor inlet temperature outlet pressure and mass—that affect energy consumption in this process. Using HYSYS software the hydrogen liquefaction process is simulated and a complete process system is developed. Based on theoretical principles this study explores the pre-cooling refrigeration and normal-to-secondary hydrogen conversion processes. By calculating and analyzing the process’s energy consumption an optimized flow scheme for hydrogen liquefaction is proposed to reduce the total power used by energy equipment. The study shows that the hydrogen mass flow rate and key helium cycle parameters—like the compressor inlet temperature outlet pressure and flow rate—mainly affect energy consumption. By optimizing these parameters notable decreases in both the total and specific energy consumption were attained. The total energy consumption dropped by 7.266% from the initial 714.3 kW and the specific energy consumption was reduced by 11.94% from 11.338 kWh/kg.

Methane pyrolysis produces hydrogen (H2) with solid carbon black as a co-product eliminating direct CO2 emissions and enabling a low-carbon supply when combined with renewable or low-carbon heat sources. In this study we propose a hybrid geothermal pyrolysis configuration in which an enhanced geothermal system (EGS) provides baseload preheating and isothermal holding while either electrical or solar–thermal input supplies the final temperature rise to the catalytic set-point. The work addresses four main objectives: (i) integrating field-scale geothermal operating envelopes to define heatintegration targets and duty splits; (ii) assessing scalability through high-pressure reactor design thermal management and carbon separation strategies that preserve co-product value; (iii) developing a techno-economic analysis (TEA) framework that lists CAPEX and OPEX incorporates carbon pricing and credits and evaluates dual-product economics for hydrogen and carbon black; and (iv) reorganizing state-of-the-art advances chronologically linking molten media demonstrations catalyst development and integration studies. The process synthesis shows that allocating geothermal heat to the largest heat-capacity streams (feed recycle and melt/salt hold) reduces electric top-up demand and stabilizes reactor operation thereby mitigating coking sintering and broad particle size distributions. Highpressure operation improves the hydrogen yield and equipment compactness but it also requires corrosion-resistant materials and careful thermal-stress management. The TEA indicates that the levelized cost of hydrogen is primarily influenced by two factors: (a) electric duty and the carbon intensity of power and (b) the achievable price and specifications of the carbon co-product. Secondary drivers include the methane price geothermal capacity factor and overall conversion and selectivity. Overall geothermal-assisted methane pyrolysis emerges as a practical pathway to turquoise hydrogen if the carbon quality is maintained and heat integration is optimized. The study offers design principles and reporting guidelines intended to accelerate pilot-scale deployment.

Developing cleaner processes via newer technologies will accelerate advancement toward more sustainable energy systems. Hydrogen is an energy carrier and an intermediate molecule in chemical processes. This research investigates an innovative hydrogen production process utilizing a non-thermal Cold Atmospheric Pressure Plasma-based Reformer (CAPR). Exploring environmentally friendly and economically viable pathways for hydrogen production is crucial for addressing climate change and reducing the carbon footprint of industrial processes. The study investigates the conversion of natural gas to hydrogen at ambient temperature and pressure highlighting the ability of plasma-based technology to operate without direct CO2 emissions.<br/>Initially through experimental studies natural gas was passed through the CAPR where the plasma's energetic discharges initiate the reforming process. Subsequently the produced hydrogen along with other light hydrocarbons enters the separation system for producing purified hydrogen. The research focuses on techno-economic analyses and sensitivity assessments to determine the levelized cost of producing hydrogen via a nanosecond plasma-based refining plant and benchmark technologies. Sensitivity analyses identify two primary factors that significantly affect the levelized cost of hydrogen production in a plasma-based reforming system.<br/>The research suggests that instead of producing carbon dioxide and capturing the emitted CO2 utilize processes that do not emit direct CO2. CAPR shows potential for cost competitiveness with conventional hydrogen production methods including steam methane reforming (SMR) and electrolysis. The findings underscore the need for further research to optimize the system's performance and cost-effectiveness positioning CAPR as a potentially transformative technology for the chemical process industry.

Hydrogen is an attractive energy carrier which could play a role in decarbonizing process heat power or transport applications. Though the U.S. already produces about 10 million metric tons of H2 (over 1 quadrillion BTUs or 1% of the U.S. primary energy consumption) production technologies primarily use fossil fuels that release CO2 and the deployment of other cleaner H2 production technologies is still in the very early stages in the U.S. This study explores (1) the level of current U.S. hydrogen production and demand (2) the importance of hydrogen to accelerate a net-zero CO2 future and (3) the challenges that must be overcome to make hydrogen an important part of the U.S. energy system. The study discusses four scenarios and hydrogen production has been shown to increase in the future but this growth is not enough to establish a hydrogen economy. In this study the characteristics of hydrogen technologies and their deployments in the long-term future are investigated using energy system model MARKAL. The effects of strong carbon constraints do not cause higher hydrogen demand but show a decrease in comparison to the business-as-usual scenario. Further according to our modeling results hydrogen grows only as a fuel for hard-to-decarbonize heavy-duty vehicles and is less competitive than other decarbonization solutions in the U.S. Without improvements in reducing the cost of electrolysis and increasing the performance of near-zero carbon technologies for hydrogen production hydrogen will remain a niche player in the U.S. energy system in the long-term future. This article provides the reader with a comprehensive understanding of the role of hydrogen in the U.S. energy system thereby explaining the long-term future projections.