Comprehending the efficiency and economics of ammonia-based hydrogen transport is crucial and requires a detailed techno-economic analysis to benchmark the cost of hydrogen delivery via ammonia carrier against conventional pathways. This study presents a techno-economic analysis of the entire ammonia supply chain, including its production, transport (road, pipeline, & marine pathways), and decomposition processes. Over short distances, truck-trailers are the most cost-effective mode while, pipeline transport becomes economically viable over longer distances and higher throughputs. Additionally, overseas transport of ammonia using ocean tankers offers cost savings over liquid hydrogen shipping, primarily due to ammonia's higher payload capacity and the boil-off losses associated with liquid hydrogen transport. This study highlights that the economics of hydrogen delivery in pure form versus using ammonia as a carrier primarily hinges on factors such as delivefry volume, distance, the chosen mode of transport, and the specific hydrogen end-use application (i.e., industrial or vehicle fueling).

Ammonia is an important chemical product and a promising carbon-free energy carrier for future energy systems. As the Haber-Bosch (H-B) process is increasingly integrated with renewable and nuclear energy sources, there is a need to reassess traditional operating pressures and reactor designs. This study develops an Aspen Plus-Python optimization framework to investigate the impact of operating pressure on ammonia synthesis performance. Four design pressures (125, 180, 240, and 292 bar) were evaluated using validated ammonia synthesis kinetics and optimized reactor inlet temperatures and bedsizes.Several design criteria, including constant conversion yield, constant reactor size, targeted percentage toward equilibrium, and reactor pressure drop effects, were examined in both open-loop and closed-loop H-B systems. Results show that optimal reactor inlet temperatures increase with pressure. Reactor sizing based on a fixed percentage toward equilibrium provides a more consistent design approach than maintaining a constant conversion yieldacross different pressures. When pressure drop is considered, low-pressure systems experience the greatest performance penalty. In contrast, intermediate pressures of 180–240 bar generally provide lower electricity consumption per tonne of ammonia while maintaining reasonable reactor bed sizes. Higher pressures improve single-pass conversion and allow higher ammonia production capacities. Overall, the results indicate that intermediate-pressure Haber-Bosch systems offer a favorable balance between energy efficiency, reactor size and production performance.

Steam methane reforming of natural gas is the primary method of producing hydrogen in the United States, accounting for 95% of all hydrogen produced there. Methane pyrolysis, an alternative production pathway that decomposes natural gas into solid carbon and hydrogen, both eliminates CO2 emissions associated with methane reforming and allows for additional income from carbon black. A life-cycle inventory of this process has been developed using ASPEN Plus to model the methane pyrolysis (plasma arc) process. From well to gate, hydrogen production via methane pyrolysis produces 2.78 kg CO(2)e/kg H-2 of greenhouse gas emissions using mass allocation of emissions between hydrogen and carbon black coproducts. The well-to-gate emissions are mainly driven by electricity consumption (similar to 38 kW h/kg H-2), which accounts for 81% of the emissions; if renewable electricity is used, well-to-gate emissions can be reduced to -0.448 kg CO(2)e/kg H-2.

Synthetic fuels produced from CO2 and electricity-so-called electrofuels (e-fuels)-are drop-in blendstocks for petroleum fuels. Nuclear energy is an attractive energy source for e-fuel production because it is able to provide steady heat and power with low carbon footprint. We modeled and evaluated the cost and environmental footprint of e-fuel production in the distillate range (jet fuel and diesel) for three nuclear power scales-100, 500, and 1000 MWe-via methanol and olefins intermediates leveraging commercial or high technology readiness level (TRL) processes. Compared to the commonly studied e-fuels from the Fischer-Tropsch process that often has a distillate yield of <70%, with the rest being low-value naphtha, the proposed process via a methanol intermediate increases the product selectivity, yielding 96% distillate and only 4% naphtha. The modeled process has a carbon conversion ratio of 98%, and a process energy efficiency of 56% relative to the total equivalent nuclear electricity input. The e-fuel plant economics and GHG emissions were estimated by considering CO2 collected from ethanol plants adjacent to nuclear power plants. The estimated minimum fuel selling price (MFSP) of e-fuel is in the range of $5.5-$8.9/gal depending on e-fuel plant scale, electricity cost, and CO2 transportation distance. The corresponding e-fuels life cycle GHG emissions are estimated to be in the range of 5-6 gCO(2)e/MJ of liquid fuel using the R&D Greenhouse gases, Regulated Emissions, and Energy use in Technologies (R&D GREET) model.

This study presents a multilevel analysis of electrochemically mediated methanolysis as a promising method for reducing the environmental impacts of plastic recycling, with a focus on depolymerizing poly(ethylene terephthalate) (PET) into dimethyl terephthalate (DMT). Instead of conventional chemical PET depolymerization, this electrochemical approach provides distinct technical advantages in process control and efficiency. At the process level, key operational parameters, including applied current and reaction time, were systematically investigated to optimize PET conversion and DMT selectivity. The electrochemical approach was directly compared to equivalent chemical methanolysis systems and demonstrated superior performance in terms of PET conversion and DMT selectivity. Building on these findings, a technoeconomic assessment identified the current economic bottlenecks and revealed that improvements in process design, DMT selectivity, PET conversion, and energy efficiency are key to reducing the overall process cost and enabling future implementation. While further optimization is required for market competitiveness, these results establish a performance baseline for the electrochemically mediated PET methanolysis process and underscore the importance of combining process-level innovation with systems-level evaluation in the development of sustainable recycling technologies.

Hydrogen is considered a key energy carrier for which interest has grown over recent years. Chlor-alkali plants in the United States (U.S.) can potentially recover and supply the by-product hydrogen at scale. However, there is a scarcity of standard analysis for energy use and emissions associated with products from chlor-alkali plants owing to lack of data and variations in chlor-alkali plant technology and operation. A rigorous life cycle analysis (LCA) is needed to quantify the emissions of by-product hydrogen and other products from chlor-alkali plants. In this study, we performed well-to-gate (WTG) emissions analysis of chlor-alkali products based on U.S. plant operating data gathered from the U.S. Environmental Protection Agency’s (EPA’s) Chemical Data Reporting database, the U.S. Energy Information Administration survey EIA-923 form, and the EPA’s Greenhouse Gas Reporting Program. We performed process-level mass allocation to allocate energy use and emissions to the chlor-alkali products. This study shows that the by-product hydrogen has WTG CO2 emissions of 1.3–1.9 kgCO2/kg H2 for plants without combined heat and power (non-CHP) and 1.5–2.4 kgCO2/kg H2 for plants with combined heat and power (CHP). Furthermore, we identified that electricity upstream emissions are the key driver affecting the emissions of by-product hydrogen from non-CHP plants, while CHP emissions can be reduced by electricity export to grids with higher carbon intensity (CI). Finally, the study shows that chlor-alkali plants in the U.S. can potentially meet up to 320 kilotons of hydrogen demand (approximately 3% of total demand) annually.

Under the 2022 Inflation Reduction Act, tax credits of up to $3/kgH(2) are available to hydrogen producers if they generate emissions at levels below 0.45 kgCO(2)e/kgH(2), spurring producers to explore how hydrogen production via electrolysis using electricity generated by nuclear power may qualify for such tax credits. With uranium as a primary fuel for nuclear power plants (NPPs) and no on-site emissions, the upstream emissions associated with nuclear fuel supply chains largely determine the carbon intensity of nuclear energy. Using the GREET (Greenhouse gases, Regulated Emissions, and Energy use in Technologies) model, we evaluated the life-cycle greenhouse gas (GHG) emissions of uranium production and the use of uranium to generate electricity in light water reactor (LWR) NPPs. We evaluated the process chemicals and energy inputs throughout the nuclear fuel supply chain to identify the major contributors to nuclear fuel cycle GHG emissions. Such emissions are estimated at 3.0 gCO(2)e/kWh at NPPs in the United States. The greatest share of nuclear fuel cycle GHG emissions-comprising 53% of total emissions-are associated with electricity consumption throughout the fuel supply chain. We extended the analysis to include an evaluation of the carbon intensity of H-2 production via electrolysis using nuclear power from LWRs. Finally, we examined the impact of future (2035 and 2050) electricity supply chain scenarios on nuclear fuel cycle GHG emissions. Our analysis revealed a decrease of 33% (2035) and 46% (2050) in the carbon intensity of nuclear electricity relative to current nuclear fuel cycle GHG emissions.

Low-carbon hydrogen can play a key role in decarbonizing steel and ammonia production. Here, we report a techno-economic and life-cycle emissions analysis of different hydrogen production routes for steelmaking via direct reduced iron-electric arc furnace and ammonia synthesis for five locations with estimated technological progress through 2035 and considering a range of Inflation Reduction Act (IRA) tax credits. Our results show that these credits can make off-grid renewable-driven electrolytic hydrogen production competitive with fossil-based routes for decarbonizing steel and ammonia in several locations within the current decade and that off-grid electrolytic hydrogen production could potentially be cost competitive with fossil-based routes in Texas and Minnesota by 2035 even without incentives. Furthermore, with maximum IRA tax incentives, off-grid electrolytic hydrogen production is competitive with fossil-based hydrogen production routes with current technology costs. Strong renewable energy resources, access to low-cost hydrogen storage, and proximity of process feedstocks are all critical for enabling these decarbonization opportunities.

Ammonia is an essential nitrogen source for crop growth and a promising hydrogen carrier due to its lower storage and transport costs compared to hydrogen. In this study, we developed the Hydrogen Carrier Scenario Analysis Model (HCSAM) to estimate the levelized cost and well-to-gate greenhouse gas (GHG) emissions of the ammonia supply chain. We evaluated the costs and GHG emissions across various ammonia production, delivery, and decomposition scenarios.

Biowastes are produced daily. These wastes are rich in organic components with high potential to produce valuable products such as BioH 2 and CO 2 . This study explores wastes converted into low-cost BioH 2 through integrated processes.

Hydrogen is a zero-carbon energy carrier with potential to decarbonize industrial and transportation sectors, but its life-cycle greenhouse gas (GHG) emissions depend on its energy supply chain and carbon management measures (e.g., carbon capture and storage). Global support for clean hydrogen production and use has recently intensified. In the United States, Congress passed several laws that incentivize the production and use of renewable and low-carbon hydrogen, such as the Bipartisan Infrastructure Law (BIL) in 2021 and the Inflation Reduction Act (IRA) in 2022, which provides tax credits of up to $3/kg depending on the carbon intensity of the produced hydrogen. A comprehensive life-cycle accounting of GHG emissions associated with hydrogen production is needed to determine the carbon intensity of hydrogen throughout its value chain. In the United States, Argonne’s R&D GREET® (Greenhouse Gases, Regulated emissions, and Energy use in Technologies) model has been widely used for hydrogen carbon intensity calculations. This paper describes the major hydrogen technology pathways considered in the United States and provides data sources and carbon intensity results for each of the hydrogen production and delivery pathways using consistent system boundaries and most recent technology performance and supply chain data.

Hydrogen (H2) is considered an alternative energy carrier to reduce greenhouse gas (GHG) emissions related to power and heat generation. A quantitative analysis was conducted to estimate the energy intensity and GHG emissions associated with the transportation of NG/H2 mixture in high-pressure transmission pipeline, considering blending ratios up to 100% of low-carbon H2. The life cycle emissions were obtained by including upstream supply chain emissions, compression and transportation emissions, and end use combustion emissions of the NG/H2 blend. This study accounts for global warming potential of fugitive methane and H2 emissions associated with pipeline transportation of the blend in the life cycle analysis. A significant reduction in the overall life cycle GHG emissions can be achieved when delivering the same volume throughput but at a reduced energy flow to end users. However, to maintain the nominal energy throughput of the pipeline regardless of the H2 mole fraction, a maximum reduction of about 6% is obtained as the H2 mole fraction in the blend will be practically limited to approximately 30% H2 when the pipeline operates at capacity.

Abstract Recently, a subsurface technology of in-situ hydrogen production using electromagnetic (EM) heating shows great potential for extracting clean hydrogen directly from natural gas reservoirs. However, critical knowledge gaps persist, particularly in technical assessments. This study addresses these gaps by evaluating energy efficiency, techno-economic viability, and greenhouse gas (GHG) emissions throughout the process. We analyze the system energy efficiency under various experimental conditions using sandstone and synthetic catalysts. The results highlight the potential for field improvements through the optimization of catalysts and methane flow rates. Techno-economic analysis (TEA), based on a developed reservoir-scale model, indicates hydrogen production cost can be potentially as low as $0.86/kg with the integration of renewable energy. Key cost drivers include membrane expenses and EM-heating electricity for hydrogen production. Life cycle assessment (LCA) indicates that methane pyrolysis in gas reservoirs does not generate GHG emissions throughout its life cycle. However, GHG emissions associated with electricity use (i.e., EM heating) in the process should be considered. Moreover, the technology's eligibility for Section 45 V of Inflation Reduction Act (IRA 45 V) clean hydrogen credits is contingent upon the source of electricity used. And the qualification for the credits depends on the proportion of renewable energy in the electricity consumption mix. This study provides insights into efficiency optimization, cost competitiveness, and environmental considerations for in-situ hydrogen production from gas reservoirs using EM heating.

Synthetic natural gas (SNG) is of great interest in reducing fossil energy consumption while maintaining compatibility with existing NG infrastructure and end-use applications equipment. SNG can be produced using clean H2 generated from renewable or nuclear energy and CO2 captured from stationary sources or the atmosphere. In this study, we develop an engineering process model of SNG production using Aspen Plus® and production scales reported by the industry. We examine the levelized cost and life cycle greenhouse gas (GHG) emissions of SNG production under various CO2 supply scenarios. Considering the higher cost of H2 transportation compared with CO2 transportation, we assume that CO2 feedstock is transported via pipeline to the H2 production location, which is collocated with the SNG plant. We also evaluate the cost of CO2 captured from the atmosphere, assuming the direct air capture process can occur near the SNG facility. Depending on the CO2 supply chain, the levelized cost of SNG is estimated to be in the range of $45–76 per million British thermal units (MMBtu) on a higher heating value (HHV) basis. The SNG production cost may be reduced to $27–57/MMBtu-HHV by applying a tax credit available in the United States for low-carbon H2 production (45 V). With a lower electricity price of 3ȼ/kWh for water electrolysis and accounting for a 45 V tax credit, the SNG cost reaches parity with the cost of fossil NG. Depending on the CO2 supply chain, SNG can reduce life cycle GHG emissions by 52–88 % compared with fossil NG.

Electricity generated using nuclear power accounted for 18.9% of all electricity consumed in the United States in 2021, putting it in third place behind natural gas (38%) and coal (22%) power plants. Nuclear power plants boast a significantly higher uptime or capacity factor—90% and above—compared to 49.1% for coal fired power plants and 56.6% for natural gas power plants. Renewable energy sources, such as solar photovoltaic (PV) and wind electricity, have lower capacity factors: 24.9% and 36.3%, respectively. In addition, nuclear power is cleaner than both coal and natural gas fired power plants. With the passing of the 2022 Inflation Reduction Act, significant tax credits will be claimed by producers of hydrogen with well-to-gate greenhouse gas (GHG) emissions below 0.45 kg CO2e/kg H2. This has sparked interest in using clean sources of electricity, including nuclear power, to generate H2 via water electrolysis. As uranium is a primary fuel for modern nuclear power plants, the upstream emissions from nuclear fuel production greatly impact the GHG emissions related to all nuclear power end use. Therefore, it is important to accurately determine the upstream emissions associated with the nuclear fuel cycle of nuclear power production in the United States. In this analysis, the nuclear fuel cycle was separated into distinct steps to allow better understanding of the chemical and energy inputs at each step of the fuel cycle. This also provides details of the GHG emissions at each step in the nuclear fuel cycle. The transportation distance for each step of the fuel cycle was updated to account for the locations of uranium processing facilities along the supply chain of the current U.S. nuclear power plants. Finally, all the updated values were incorporated into Argonne National Laboratory's Greenhouse Gases, Regulated Emissions, and Energy Use in Technologies (GREET) model.

In 2019, U.S. petroleum refineries emitted 196 million metric tons (MT) of CO2, while the well-to-gate and the full life cycle CO2 emissions were significantly higher, reaching 419 and 2843 million MT of CO2, respectively. This analysis examines decarbonization opportunities for U.S. refineries and the cost to achieve both refinery-level and complete life-cycle CO2 emission reductions. We used 2019 life-cycle CO2 emissions from U.S. refineries as a baseline and identified three categories of decarbonization opportunity: (1) switching refinery energy inputs from fossil to renewable sources (e.g., switch hydrogen source); (2) carbon capture and storage of CO2 from various refining units; and (3) changing the feedstock from petroleum crude to biocrude using various blending levels. While all three options can reduce CO2 emissions from refineries, only the third can reduce emissions throughout the life cycle of refinery products, including the combustion of fuels (e.g., gasoline and diesel) during end use applications. A decarbonization approach that combines strategies 1, 2, and 3 can achieve negative life-cycle CO2 emissions, with an average CO2 avoidance cost of $113-$477/MT CO2, or $54-$227/bbl of processed crude; these costs are driven primarily by the high cost of biocrude feedstock.

Electrofuels, or e-fuels, are synthetic liquid hydrocarbon fuels which may be produced using carbon dioxide (CO2) and low carbon hydrogen (H2) as feedstock. They are of great interest because they have much lower carbon intensity compared to the conventional petroleum fuels and can utilize the existing fuel infrastructure owing to their ability to blend with or replace existing fuels. We modeled an e-fuel production process to produce low carbon jet, diesel, and naphtha using a reverse water gas shift process to produce synthesis gas, followed by a Fischer-Tropsch (FT) synthesis process. Nuclear energy is considered for e-fuel production due to its steady energy supply, near-zero carbon emissions, capability to produce hydrogen with high efficiency via high tem-perature electrolysis, and proximity to biogenic CO2 sources from nearby corn-ethanol plants in the United States. The modeled FT process achieved a high carbon conversion ratio of 99% by recycling CO2 and the use of oxy-combustion, and a process energy efficiency of approximately 70%. The life cycle greenhouse gases emis-sions are estimated to be 7 and-25 gCO2e/MJ, without and with steam coproduct credit, respectively, by using the Greenhouse gases, Regulated Emissions, and Energy use in Technologies (GREET (R)) model. Additionally, the process economics were evaluated for three scales corresponding to nuclear power plant capacities of 100, 400, and 1000 MWe, estimating a minimum fuel selling price (MFSP) of $3.61/gal ($0.95/L), $2.82/gal ($0.74/L), and $2.66/gal ($0.70/L) of FT fuel mix, respectively, by considering $3/kg of H2 tax credit prescribed in the recent Inflation Reduction Act.