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Search indexed NASA NTRS and DOE OSTI research on propulsion, heat transfer, battery materials and energy systems. Follow report and document links to the original sources.
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Palo Alto Research Center (PARC) and its partners will explore a targeted molten metal as a catalyst in a methane pyrolysis mist reactor to convert natural gas into hydrogen and solid carbon at a low cost without carbon dioxide emissions. The technology could augment or replace current H 2 production methods, while simultaneously sequestering carbon in high value materials.
The feasibility and component cost of hydrogen rail refueling infrastructure is examined. Example reference stations can inform future studies on components and systems specifically for hydrogen rail refueling facilities. All of the 5 designs considered assumed the bulk storage of liquid hydrogen on-site, from which either gaseous or liquid hydrogen would be dispensed. The first design was estimated to refuel 10 multiple unit trains per day, each train containing 260 kg of gaseous hydrogen at 350 bar on-board. The second base design targeted the refueling of 50 passenger locomotives, each with 400 kg of gaseous hydrogen on-board at 350 bar. Variations from this basic design were made to consider the effect of two different filling times, two different hydrogen compression methods, and two different station design approaches. For each design variation, components were sized, approximate costs were estimated for major components, and physical layouts were created. For both gaseous hydrogen-dispensing base designs, the design of direct-fill using a cryopump design was the lowest cost due to the high cost of the cascade storage system and gas compressor. The last three base designs all assumed that liquid hydrogen was dispensed into tender cars for freight locomotives that required 7,500 kg of liquid hydrogen, and the three different designs assumed that 5, 50, or 200 tender cars were refueled every day. The total component costs are very different for each design, because each design has a very different dispensing capacity. The total component cost for these three designs are driven by the cost of the liquid hydrogen tank; additionally, delivering that much liquid hydrogen to the refueling facility may not be practical. Many of the designs needed the use of multiple evaporators, compressors, and cryopumps operating in parallel to meet required flow rates. In the future, the components identified here can be improved and scaled-up to better fit the needs of heavy-duty refueling facilities. This study provides basic feasibility and first-order design guidance for hydrogen refueling facilities serving emerging rail applications.
A technoeconomic analysis of grid to low temperature electrolysis (Grid-LTE), photovoltaic to low temperature electrolysis (PV-LTE), concentrating solar power to high temperature electrolysis (CSP-HTSE) and a concentrating solar power with PV to high temperature electrolysis (CSP-PV-HTSE) centralized hydrogen production systems are analyzed to assess the economics of system and to provide a baseline for comparing these technologies against hydrogen production cost targets. A framework integrating the system advisor model (SAM) and US Department of Energy hydrogen production models (H2A) is developed to assess these systems. The hydrogen levelized cost given current and future assumptions for technology cost and performance is evaluated at optimal system configurations. The framework described in this report integrates SAM with H2A electrolyzer technologies and provides analysts a detailed technoeconomic method to analyze concentrating and photovoltaic solar technologies to produce energy that are directly coupled to LTE and HTSEs that use that energy to split water into hydrogen and oxygen. The baseline hydrogen levelized cost (HLCs) for the GRID-LTE, PV-LTE, CSP-HTSE, and CSP-PV-HTSE systems in Daggett, CA are 2.82, 3.86, 3.68, and 2.90 $\$$USD 2016/kg H2 and 2.50, 2.13, 2.84, 2.15 $\$$USD 2016/kg H2 in the 2020 and 2050 scenarios respectively. To achieve the $\$$2/kg H2 target in locations with excellent solar resources, cost parameters values aligned with aggressive R&D targets will need to be achieved for all the systems configurations. In Daggett, PV costs of $\$$0.68 /Wac or moderate ATB PV CAPEX projections result in HLCs of $\$$2 /kg H2. Similarly for PV-MSALT-HTSE systems, $\$$0.60 /Wac result in $\$$2/kg H2. For the MSALT-HTSE systems, better than aggressive 2050 ATB salt tower CAPEX projections would be needed to reach $\$$2/kg H2. Molten salt tower capital costs of $\$$2400/kW would enable $\$$2/kg H2 in 2050.
Presentation at the 9th ELAEE (Latin American Energy Economics Meeting) July 28th – 30th, 2024 in PUC-Rio, Rio de Janeiro, Brazil. The presentation highlights the FECM/NETL Hydrogen Pipeline Cost Model (H2_P_COM). The model estimates costs for transporting gaseous hydrogen in a pipeline from a source, such as a hydrogen production facility, to a final destination which may be a user of the hydrogen or a distribution center where hydrogen in the pipeline is diverted to multiple end users.
A hydrogen fuel cell propelled electric aircraft can compete with incumbent turbofan technologies for single-aisle regional aircraft by coupling design of stack, air handling, thermal management, propulsion, and airframe to optimize performance. The stack operates at 95°C to facilitate heat rejection during take-off and below 75°C during cruise to extend lifetime and is oversized to satisfy power requirements at end of life. A multi-stage turbocompressor with a compression ratio >10 is selected to reach high stack power density at 11,300-m cruise altitude. The propulsion system is configured to accommodate air handling within the core duct, an inclined heat exchanger in the outer duct to limit the nacelle size, and variable area nozzles to independently control mass flows through the core and bypass ducts. The airframe is modified for maximum lift coefficient and longer balanced field length for dramatically reduced thrust during take-off, and the fuselage is stretched by 20% to store liquid hydrogen (LH 2 ). Modularization of power systems promotes safety in one engine inoperative scenarios and allows reaching specific power metrics for stack, balance-of-plant and fuel cell system (FCS), necessary for acceptable take-off weight. In conclusion, cost parity requires increase in FCS lifetime, LH 2 cost reduction, and improved FCS specific power.
Cost-effective and reliable hydrogen compression remains a challenging barrier in the widespread adoption of hydrogen as an energy carrier. The prevailing technology of mechanical compression suffers from several drawbacks, some of which can be addressed by nonmechanical compression strategies (e.g., electrochemical or metal hydride-based thermal compression). Thermally driven metal hydride compression strategies typically rely on multistage metal hydride-based compressors; however, discovering or optimizing low-stability metal hydrides that can pressurize hydrogen upward of 1000 bar is difficult, both with respect to computational predictions and experimental validation. Here, in this study, we (1) demonstrate that simple machine learning-derived design rules can inform the rational design of alloying strategies yielding low-stability hydrides, (2) validate their experimental pressure–composition–temperature (PCT) isotherms up to 875 bar, and (3) utilize a dynamic system-level model of a metal hydride compressor design to evaluate their performance under realistic operating conditions. Importantly, this analysis yields predicted operational efficiencies of both 2-stage (90–875 bar) and 3-stage (20–875 bar) metal hydride compressors to enable further evaluation of this technology and its techno-economic outlook.
This project made advancements in developing lower cost steel alloys with novel microstructural design for use in hydrogen refueling infrastructure such as storage, compressors, and dispensing components, and utilizing accelerated test methods to efficiently evaluate variations in alloy and microstructure design. The project specifically sought to design alloys with lower nickel contents to reduce alloy cost, which was accomplished through substituting manganese for nickel along with other alloy additions to control deformation characteristics known to be important for hydrogen embrittlement resistance. Through Mn substitutions for nickel, austenitic and duplex austenite-ferrite steels were successfully developed with lower cost than currently available commercial stainless steel products that are employed for hydrogen refueling infrastructure. The steels were processed to achieve comparable strength and toughness in hydrogen environments as the commercially available steels containing high Ni contents. To evaluate mechanical performance in hydrogen, a testing methodology was employed to compare ubiquitous laboratory testing using electrochemical hydrogen charging in a liquid electrolyte to less accessible high pressure gaseous testing. While the application of these steels is in high pressure gaseous environments, the electrochemical hydrogen charging tests produced comparable results. Additionally, the Los Alamos Neutron Scatting Center enabled characterization of deformation mechanisms of the steel alloys in the presence of hydrogen, which has been associated with steel alloy characteristics associated with hydrogen embrittlement. Finally, a fracture mechanics based test bed model was developed to predict the influence of hydrogen gas pressure and fatigue conditions on fatigue lifetimes of pressure vessel steels. Together, these developments can be employed to enable lower cost hydrogen fueling infrastructure and more reliable prediction of steel alloy components in hydrogen service conditions. In particular, the newly alloys have the potential to replace stainless steels, having demonstrated comparable performance at substantially reduced cost.
Hydrogen fuel cell electric vehicles (FCEVs) have been proposed as an option for lowering carbon dioxide (CO 2 ) and pollutants emissions from the transportation sector, when implemented in combination with green hydrogen production methods such as water electrolysis powered by renewable electricity. FCEVs also have the added advantages of high specific energy density and rapid refueling, two important challenges that battery electric vehicles have not yet fully overcome. Moreover, flexible operation of electrolysis could support the grid and lower electricity costs. In this paper, we simulate time-varying FCEV hydrogen refueling demand for light, medium- and heavy-duty vehicles met using electrolysis systems distributed throughout the Western U.S. power system. We find that by oversizing electrolyzers the resulting load flexibility results in different hydrogen generation temporal profiles, average electricity costs, renewable curtailment levels, and CO2 emissions. Our results indicate that increasing hydrogen production flexibility lowers hydrogen and electricity generation cost and CO 2 emissions, but there is a tradeoff between lowering operational cost and increasing electrolyzer capital cost, yielding a minimum total system cost at a size corresponding to between 80% and 90% annual capacity factor assuming a future electrolyzer cost of $300/kW.
Low-cost green hydrogen can be achieved by integrating utility-scale wind farms to an electrolyzer. The power produced by a wind farm depends on spatial and temporal changes in the wind, and this variability can affect the electrolyzer's performance. This study examines the trade-offs between two electrolyzer configurations: a large centralized electrolyzer connected to the wind farm versus several smaller distributed electrolyzers connected directly to each wind turbine. The results show that a centralized configuration generates more hydrogen because turbines that are waked and produce less power are compensated but other un-waked turbines.
Presently, the steam reforming process is the largest industrial source of hydrogen. Improving its efficiency can help to reduce associated carbon emissions and hydrogen production costs. Intensifying the water-gas shift reaction using microreactors with integrated cooling is one way of achieving this. In this study, a 2-D computational model of one of these microreactors is developed, validated with experimental data, and then used to demonstrate how microreactors can enhance the conversion of the water-gas shift reaction beyond what can be achieved using conventional packed bed reactors. These results are then generalized into a full system model of the steam reforming process to demonstrate how microreactors can reduce hydrogen production costs. The results suggest that microreactors can significantly reduce the required reactor volume and catalyst loading for the water-gas shift reaction and can similarly reduce the hydrogen production costs associated with the steam reforming process.
NETL's Strategic Systems Analysis & Engineering (SSAE) is developing a reference study for fossil-based, commercial scale hydrogen production with a levelized cost of hydrogen (2018 $/kg) as the figure of merit. Coal/biomass gasification as well as natural gas-based technology routes (steam-methane reforming & autothermal reforming) are featured as technologies to be assessed. The final report is expected to be completed in August, 2021 -- this presentation describes the study's design in more detail as well as reports on its progress.
Abstract Producing inexpensive hydrogen using electricity to split water or to extract hydrogen from hydrocarbon compounds is a two-sided coin: one side is obtaining and exploiting low-cost, emissions-free energy sources while the opposite side is establishing low-cost robust, durable, and efficient materials for the conversion processes. This article explores the materials needed for water splitting electrolysis, electrochemical abstraction of hydrogen from light alkanes, and looping thermal-chemical reaction processes that typically form and then dissociate an acid compound in a two- or three-step process. The focus is on the R&D needs of materials that are used for high-temperature electrochemistry, focusing on solid-oxide, ion-conducting cell materials sets (SOECs). To exploit the availability of low-cost electricity, these materials must stand up to cyclic operations. They also must be durable for years of service to reduce operating and maintenance costs, and they must achieve high conversion efficiencies to avoid large, energy-intensive recycle loops. Graphical abstract
To help meet the need for inexpensive green fuels, we are working on wind turbine design optimization specifically for hydrogen production. We have thus far achieved a 1.53% decrease in LCOH as compared to a turbine optimized for LCOE using the same code, design variables, and models. We accomplished this by optimizing some components of the wind turbine tower, rotor, and drivetrain design with hydrogen production and costs in the design loop.
Hydrogen represents a major pathway to decarbonize and stabilize the national and international energy industry and select manufacturing markets. To facilitate the development of hydrogen markets, the US Department of Energy initiated H2@Scale to bring together stakeholders to advance affordable hydrogen production, transport, storage, and utilization to increase revenue opportunities in multiple energy sectors. One major impediment to hydrogen implementation is cost. To expedite the use of hydrogen in energy and other markets, the United States announced in 2021 the Hydrogen Shot, which seeks to reduce the cost of clean hydrogen by 80% to $1 per 1 kilogram in 1 decade ("1 1 1"). As the cost of hydrogen drops, new applications will emerge that will require unique configurations of existing equipment and infrastructure, and eventually lead to advances in the generation and utilization of hydrogen. As the hydrogen economy expands, sensors and detection methods will need to adapt to changing infrastructure demands to address the primary targets of health & safety, emissions monitoring, and process control. The NREL Sensor Laboratory is playing a pivotal role in advancing the use of hydrogen sensors and detection methodologies in each of these categories to support DOE's mission for safe and efficient utilization in emerging markets. Health & safety monitors are required to ensure that operators and facilities can react to unintended hydrogen releases, either as GH2, LH2, or as a constituent of blends (e.g., natural gas or ammonia). Current detection methodologies focus on safety applications to detect near its lower flammable limit (4 vol %), and typically include point sensors in applications such as fixed or mobile detectors (e.g., personal gas monitors). Methodologies amenable for area detection include acoustic, emerging optical imaging methods, and flame detectors. Comparable detection strategies can be utilized for emissions monitoring and quantization, however few methods can simultaneously cover both low (emissions) and high (health & safety) levels. Deployment of emission level detectors will be required to 1) reduce product loss through small but potentially significant leaks from an environmental or cost perspective, 2) reduce downtime of high demand systems by early identification of eminent system failures (leaks through pump or compressor seals indicative of impending failure), and 3) address potential emission monitoring requirements that may be set by regulating bodies. The first two points should be adopted by industry to reduce the cost-of-goods-sold. The third main category for hydrogen detection relates to process control and may be advantageous for many existing applications. Two main applications are emerging. For example, the purity requirements for hydrogen that is dispensed from refueling systems for hydrogen fuel cell electric vehicles (FCEV) is rigorously regulated by the Standard SAE J2719, which prescribes maximum allowable levels of multiple impurities in the hydrogen fuel and must be verified by a regulatory body. Hydrogen contaminant detectors (HCD) integrated to the fueling station can assure this compliance. HCDs must be able operate in 100% H2 backgrounds and be able to distinguish between multiple contaminants at low ppm to low ppb levels. Secondly, as a strategy to decarbonize the natural gas grid, there are proposals to blend hydrogen with natural gas. This blending will affect transport applications (pipeline infrastructure), stationary combustion systems (turbines), and consumer and commercial appliances. In the short-term, hydrogen levels up to 20% are proposed. Variations in the hydrogen level can have dramatic impact on the combustion process and on the potential response of safety sensors. These mixtures may be regulated so that the concentration at a delivery point must be monitored with high precision. However, routine maintenance may introduce background gases such as ambient air (with water) or maintenance gases (introduced with welding processes or adhesive outgassing.) Therefore, the detection methodology must be robust enough to recover or respond to various contaminants. Several reviews can be found in literature addressing sensing and detection technologies, including their limitations and applications. However, for most applications, limitations can be alleviated by combining various detection techniques either through system integration or implementation of machine learning methods (artificial intelligence). In this presentation, we will discuss several applications, highlight their current approach for hydrogen detection, and suggest detection strategies to supplement their limitations.
Here this study focuses on the production and consumption of solar-powered green hydrogen in Belgium by comparing the costs of domestic production with those of imports from Morocco and Namibia. The levelized cost of hydrogen (LCOH) is determined via a techno-economic assessment considering various parameters including, power connectivity, electrolyzer types, location factors, and risk premium. The results show that the lowest LCOH can be achieved by on-grid Proton exchange membrane electrolyzers (PEMEL). LCOH of production in Belgium, Morocco, and Namibia with a PEMEL on-grid system are 5.64, 6.32 and 5.13 euro/kg H 2 , respectively. Thus, importing hydrogen from Namibia to Belgium is more competitive than domestic production. The sensitivity analysis suggests that a target LCOH of 3 euro/kg H 2 is achievable by importing from Namibia through various cost combinations. One of these combinations involves reducing the cost of PV panels to 222.3 euro/kW (70% reduction) and electrolyzers to 363.3 euro/kW (25% reduction).
The objective of this study is to establish a detailed techno-economic analysis to assess the effectiveness of incremental technology improvements needed for solid oxide electrolysis cell (SOEC) technology to achieve the U.S. DOE’s Hydrogen Shot goal of hydrogen production at less than $1 per kilogram. The pathway considers incremental technology improvements to key system parameters, with system performance and cost assessed for each pathway step. Briefly, the steps include cell voltage degradation rate improvements, operational current density increases, operating temperature reduction, improved steam utilization, increased system capacity factor, and reduced cell/stack capital costs. Each step is assessed at both atmospheric and pressurized (8 bar) operating conditions. To supplement assessment at each of these discrete stepwise improvements, sensitivity studies are conducted to understand the relative impact of each parameter and identify avenues for additional cost reductions. System efficiency and levelized costs of hydrogen (LCOH) for each case are presented. For the end-of-pathway case, which includes all the incremental research and development improvements, the cost of hydrogen produced is reduced by 50 percent from the state-of-the-art case.
The societal energy system is evolving rapidly as the impacts of our existing energy system are better appreciated and technological advances have dramatically decreased the cost of renewable resources. Simultaneously, the importance of energy transfer across timeframes and the difficulty of decarbonizing the industrial loads and transportation demands using electricity are being recognized. At the center of this need is achieving low-cost clean hydrogen. The U.S. Department of Energy launched the Hydrogen Energy EarthShot which seeks to reduce the cost of clean hydrogen to $1 per 1 kilogram in one decade. Reaching the $1/kg goal is dependent on the evolution of the electrical energy system to increase renewable energy deployment and low electricity costs; advances in electrolysis technology and manufacturing readiness; and infrastructure build-out and hydrogen market establishment that results in the ability to make, move, store, and use clean hydrogen economically while spurring job creation.
Water electrolysis is gaining traction in large-scale applications, with production of multiple technologies scaling to hundreds and thousands of megawatts of new electrolyzer capacity annually. Low-temperature electrolysis has dominated the electrolyzer market for decades, but still only represents a small amount of the overall hydrogen market, due to the higher production costs versus hydrogen derived from fossil fuels. Advances are needed in capital cost and efficiency to close the cost gap, especially for energy applications. Similarly, while high-temperature electrolyzers can operate more efficiently, reducing the operating cost, they still need further scale-up and cost reduction to compete in these markets. Understanding the recent advances in each and the priority research directions is important to focus and accelerate innovation, and will be discussed in this article. The different advantages and disadvantages of each of these technologies will also be reviewed; there will likely be applications for each in the overall deployment of renewable hydrogen.