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Recent concerns surrounding climate change and the contribution of fossil fuels to greenhouse gas (GHG) emissions have sparked interest and advancements in renewable energy sources including wind, solar, and hydroelectricity. These energy sources, often referred to as “clean energy”, generate no operational onsite GHG emissions. They also offer the potential for clean hydrogen production through water electrolysis, presenting a viable solution to create an environmentally friendly alternative energy carrier with the potential to decarbonize industrial processes reliant on hydrogen. To conduct a full life cycle analysis, it is crucial to account for the embodied emissions associated with renewable and nuclear power generation plants as they can significantly impact the GHG emissions linked to hydrogen production and its derived products. In this work, we conducted a comprehensive analysis of the embodied emissions associated with solar photovoltaic (PV), wind, hydro, and nuclear electricity. We investigated the implications of including plant-embodied emissions in the overall emission estimates of electrolysis hydrogen production and subsequently on the production of synthetic ammonia, methanol, and Fischer–Tropsch (FT) fuels. Results show that average embodied GHG emissions of solar PV, wind, hydro, and nuclear electricity generation in the United States (U.S.) were estimated to be 37, 9.8, 7.2, and 0.3 g CO2e/kWh, respectively. Life cycle GHG emissions of electrolytic hydrogen produced from solar PV, wind, and hydroelectricity were estimated as 2.1, 0.6, and 0.4 kg of CO2e/kg of H2, respectively, in contrast to the zero-emissions often used when the embodied emissions in their construction were excluded. Average life cycle emission estimates (CO2e/kg) of synthetic ammonia, methanol, and FT-fuel from solar PV electricity are increased by 5.5, 16, and 49 times, respectively, compared to the case when embodied emissions are excluded. This change also depends on the local irradiance for solar power, which can result in a further increase of GHG emissions by 35–41% in areas of low irradiance or reduce GHG emissions by 21–25% in areas with higher irradiance.

The Northwestern University Freight Rail Infrastructure & Energy Network Decarbonization (NUFRIEND) framework is a comprehensive industry-oriented tool for simulating the deployment of new energy technologies including biofuels, e-fuels, battery-electric, and hydrogen locomotives. By classifying fuel types into two categories based on deployment requirements, the associated optimal charging/fueling facility location and sizing problem are solved with a five-step framework. Life-cycle analysis (LCA) and techno-economic analysis (TEA) are used to estimate carbon reduction, capital investments, cost of carbon reduction, and operational impacts, enabling sensitivity analysis with operational and technological parameters. The framework is illustrated on lower-carbon drop-in fuels as well as battery-electric technology deployments for the US Eastern and Western Class I railroad networks. Drop-in fuel deployments are modeled as admixtures with diesel in existing locomotives, while battery-electric deployments are shown for varying technology penetration levels and locomotive ranges. When mixed in a 50% ratio with diesel, results show biodiesel’s capacity to reduce emissions at 36% with a cost of $ 0.13 per kilogram of CO2reduced, while e-fuels offer a potential reduction of 50% of emissions at a cost of $ 0.22 per kilogram of CO2reduced. Battery-electric results for 50% deployment over all ton-miles highlight the value of future innovations in battery energy densities as scenarios assuming 800-mi range locomotives show an estimated emissions reduction of 46% with a cost of $ 0.06 per kilogram of CO2reduced, compared with 16% emissions reduction at a cost of $ 0.11 per kilogram of CO2reduced for 400-mi range locomotives. The NUFRIEND framework provides a systematic method for comparing different alternative energy technologies and identifying potential challenges and benefits in their future deployments.

Captured CO2is a potential feedstock to produce fuel/chemicals using renewable electricity as the energy source. We explored resource availability and synergies by region in the United States and conducted cost and environmental analysis to identify unique opportunities in each region to inform possible regional and national actions for carbon capture and utilization development. This study estimated production cost of synthetic methanol and Fischer–Tropsch (FT) fuels by using CO2captured from the waste streams emitted from six industrial [ethanol, ammonia, natural gas (NG) processing, hydrogen, cement, and iron/steel production plants] and two power generation (coal and NG) processes across the United States. The results showed that a total of 1594 million metric ton per year of waste CO2can be captured and converted into 85 and 319 billion gallons of FT fuels and methanol, respectively. FT fuels can potentially substitute for 36% of the total petroleum fuels used in the transportation sector in 2018. Technoeconomic analysis shows that the minimum selling prices for synthetic FT fuels and methanol are 1.8–2.8 times the price of petroleum fuel/chemicals, but the total CO2reduction potential is 935–1777 MMT/year.

China has implemented strong incentives to promote the market penetration of plug-in electric vehicles (PEVs). In this study, we compare the well-to-wheels (WTW) greenhouse gas (GHG) emission intensities of PEVs with those of gasoline vehicles at the provincial level in the year 2017 by considering the heterogeneity in the consumption-based electricity mix and climate impacts on vehicle fuel economy. Results show a high variation of provincial WTW GHG emission intensities for battery electric vehicles (BEVs, 22–293 g CO2eq/km) and plug-in hybrid electric vehicles (PHEVs, 82–298 g CO2eq/km) in contrast to gasoline internal combustion engine vehicles (ICEVs, 227–245 g CO2eq/km) and gasoline hybrid electric vehicles (HEVs, 141–164 g CO2eq/km). Due to the GHG-intensive coal-based electricity and cold weather, WTW GHG emission intensities of BEVs and PHEVs are higher than those of gasoline ICEVs in seven and ten northern provinces in China, respectively. WTW GHG emission intensities of gasoline HEVs, on the other hand, are lower in 18 and 26 provinces than those of BEVs and PHEVs, respectively. The analysis suggests that province-specific PEV and electric grid development policies should be considered for GHG emission reductions of on-road transportation in China.

Electrofuels from renewable H2and waste CO2streams are of increasing interest because of their CO2emissions reduction potentials compared to fossil counterparts. This study evaluated the well-to-wheel (WTW) greenhouse gas (GHG) emissions of Fischer–Tropsch (FT) fuels from various electrolytic H2pathways and CO2sources, using various process designs (i.e., with and without H2recycle) and system boundaries. Two systems with different boundaries were considered: a stand-alone plant (with CO2from any source) and an integrated plant with corn ethanol production (supplying CO2). The FT fuel synthesis process was modeled using Aspen Plus, which showed that 45% of the carbon in CO2can be fixed in the FT fuel, with a fuel production energy efficiency of 58%. Using nuclear or solar/wind electricity, the stand-alone FT fuel production from various plant designs can reduce WTW GHG emissions by 90–108%, relative to petroleum fuels. When integrating the FT fuel production process with corn ethanol production, the WTW GHG emissions of FT fuels are 57–65% lower compared to petroleum counterparts. This study highlights the sensitivity of the carbon intensity of FT fuels to the system boundary selection (i.e., stand-alone vs integrated), which has different implications under various GHG emission credit frameworks.

Conventional diesel medium- and heavy-duty vehicles (MHDVs) create large amount of air emissions. With the advancement in technology and reduction in the cost of batteries, plug-in battery electric vehicles (BEVs) are increasingly attractive options for improving energy efficiency and reducing air emissions of MHDVs. In this paper, we compared the well-to-wheels (WTW) greenhouse gases (GHGs) and criteria air pollutant emissions of MHD BEVs with their conventional diesel counterparts across weight classes and vocations. We expanded the Greenhouse gases, Regulated Emissions, and Energy use in Technologies (GREET) model to conduct the WTW analysis of MHDVs. The fuel economy for a wide range of MHDV weight classes and vocations, over various driving cycles, was evaluated using a high-fidelity vehicle dynamic simulation software (Autonomie). The environmental impacts of MHD BEVs are sensitive to the source of electricity used to recharge their batteries. The WTW results show that MHD BEVs significantly improve environmental sustainability of MHDVs by providing deep reductions in WTW GHGs, nitrogen oxides, volatile organic compounds, and carbon monoxide emissions, compared to conventional diesel counterparts. Increasing shares of renewable and natural gas technologies in future national and regional electricity generation are expected to reduce WTW particulate matters and sulfur oxide emissions for further improvement of the environmental performance of MHD BEVs.

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 H2generated from renewable or nuclear energy and CO2captured 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 CO2supply scenarios. Considering the higher cost of H2transportation compared with CO2transportation, we assume that CO2feedstock is transported via pipeline to the H2production location, which is collocated with the SNG plant. We also evaluate the cost of CO2captured from the atmosphere, assuming the direct air capture process can occur near the SNG facility. Depending on the CO2supply 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 H2production (45V). With a lower electricity price of 3ȼ/kWh for water electrolysis and accounting for a 45V tax credit, the SNG cost reaches parity with the cost of fossil NG. Depending on the CO2supply chain, SNG can reduce life cycle GHG emissions by 52–88% compared with fossil NG.

The global and U.S. domestic effort to develop a clean energy economy and curb environmental pollution incentivizes the use of hydrogen as a transportation fuel, owing to its zero tailpipe pollutant emissions and high fuel efficiency in fuel cell electric vehicles (FCEVs). However, the hydrogen production process is not emissions free. Conventional hydrogen production via steam methane reforming (SMR) is energy intensive, coproduces carbon dioxide, and emits air pollutants. Thus, it is necessary to quantify the environmental impacts of SMR hydrogen production alongside the use-phase of FCEVs. This study fills the information gap, analyzing the greenhouse gas (GHG) and criteria air pollutant (CAP) emissions associated with hydrogen production in U.S. SMR facilities by compiling and matching the facility-reported GHG and CAP emissions data with facilities’ hydrogen production data. The actual amounts of hydrogen produced at U.S. SMR facilities are often confidential. Thus, we have developed four approaches to estimate the hydrogen production amounts. The resultant GHG and CAP emissions per MJ of hydrogen produced in individual facilities were aggregated to develop emission values for both a national median and a California state median. This study also investigates the breakdown of facility emissions into combustion emissions and noncombustion emissions.

Using Greenhouse Gas Reporting Program data (GHGRP) and National Emissions Inventory data from 2014, we investigate U.S. refinery greenhouse gas (GHG) emissions (CO2, CH4, and N2O) and criteria air pollutant (CAP) emissions (VOC, CO, NOx, SO2, PM10, and PM2.5). The study derives (1) combustion emission factors (EFs) of refinery fuels (e.g., refinery catalyst coke and refinery combined gas), (2) U.S. refinery GHG emissions and CAP emissions per crude throughput at the national and regional levels, and (3) GHG and CAP emissions attributable to U.S. refinery products. The latter two emissions were further itemized by source: combustion emission, process emission, and facility-wide emission. We estimated U.S. refinery product GHG and CAP emissions via energy allocation at the refinery process unit level. The unit energy demand and unit flow information were adopted from the Petroleum Refinery Life Cycle Inventory Model (PRELIM version 1.1) by fitting individual U.S. refineries. This study fills an important information gap because it (1) evaluates refinery CAP emissions along with GHG emissions and (2) provides CAP and GHG emissions not only for refinery main products (gasoline, diesel, jet fuel, etc.) but also for refinery secondary products (asphalt, lubricant, wax, light olefins, etc.).

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 temperature electrolysis, and proximity to biogenic CO2sources from nearby corn-ethanol plants in the United States. The modeled FT process achieved a high carbon conversion ratio of 99% by recycling CO2and the use of oxy-combustion, and a process energy efficiency of approximately 70%. The life cycle greenhouse gases emissions 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®) 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 H2tax credit prescribed in the recent Inflation Reduction Act.

In 2019, U.S. petroleum refineries emitted 196 million metric tons (MT) of CO2, while the well-to-gate and the full life cycle CO2emissions 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 CO2emission reductions. We used 2019 life-cycle CO2emissions 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 CO2from various refining units; and (3) changing the feedstock from petroleum crude to biocrude using various blending levels. While all three options can reduce CO2emissions 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 CO2emissions, with an average CO2avoidance 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.

Electro-fuels (e-fuels) are examples of carbon capture and utilization (CCU) hydrocarbon products that are derived from captured carbon dioxide (CO2), while using renewable electricity as the energy feedstock. The environmental impacts of CCU products (e.g., e-fuel) are systematically quantified through life-cycle analysis (LCA). Previous studies evaluating LCA of e-fuels proposed frameworks with an expanded system boundary approach that included the entire supply chain of the production process generating the CO2for CCU, in addition to the supply chain of the CCU product. This expanded system boundary approach evaluates two system boundaries, and uses deduction methods to calculate the carbon intensity (CI) of the CCU product (e-fuel). This paper proposes a simpler system boundary using an incremental approach that can calculate identical CI of the CCU product (e-fuel), while avoiding the extensive calculations in the expanded system boundary framework. The proposed incremental approach allocates the burdens of the CO2capturing process to the CO2feedstock supplying the CCU production process (e.g., e-fuel production). The CI of the captured CO2supplied to CCU process is determined by the energy and material requirements for the CO2capturing process and transportation to the CCU plant. Thus, the CI of CO2supplied to CCU process can be directly linked to the CI of e-fuel without the need to conduct LCA of the preceding process that generates the CO2for CCU.

This study systematically examined the potential impacts of recharging scenarios for multiple plug-in hybrid electric vehicles (PHEVs) in the western United States—in particular, the service area of the Western Electricity Coordinating Council (WECC)—in 2030. The goal of the study was twofold: to examine the impact of scenarios for market penetration and charging of PHEVs on the electric utilities and transmission grid and to estimate the potential reductions in petroleum use and greenhouse gas (GHG) emissions attributable to PHEV miles traveled on primarily grid electricity. Three charging scenarios for PHEVS were examined: (a) begin recharging upon arrival at home at the end of the last daily trip, (b) complete recharging of batteries just before the start of the first daily trip, and (c) any additional charging opportunity during the daytime. The three charging scenarios produced distinct hourly electric load profiles, with the opportunity-charging scenario resulting in a significant increase in load during the daytime. However, when the utility dispatch simulations were run for these charging scenarios in the WECC area, they all exhibited similar marginal-generation mixes (dominated by the natural gas combined-cycle technology) to satisfy the PHEV load, and GHG emissions were within 2% of each other. A well-to-wheel analysis revealed that the marginal-generation mixes produced 40% to 45% lower GHG emissions by PHEVs than did conventional gasoline internal combustion engine vehicles.

Over the past century gasoline fueling has evolved from being performed by a variety of informal, diverse methods to being performed through the use of a standardized, highly automated system that exploits the fuel's benefits and mitigates its hazards. Any effort to transition to another fuel with different properties—with both advantages and disadvantages— must make similar adjustments. This paper discusses the existing gaso-line refueling infrastructure and its evolution. It then describes the hydrogen delivery scenario analysis model, an Excel-based tool that calculates the levelized cost of delivering hydrogen from a central production facility to a vehicle by the use of currently available technologies and a typical profile of vehicle use and fueling demand. The results are shown for a status quo, or gasoline-centric case, in which demand reflects the current gasoline-based system and supply responds accordingly, and a hydrogen-centric case, in which some of those patterns are altered. The paper highlights fueling requirements that are particularly problematic for hydrogen and concludes with a discussion of alternative fueling paradigms.

Over the past century gasoline fueling has evolved from being performed by a variety of informal, diverse methods to being performed through the use of a standardized, highly automated system that exploits the fuel's benefits and mitigates its hazards. Any effort to transition to another fuel with different properties–-with both advantages and disadvantages–- must make similar adjustments. This paper discusses the existing gasoline refueling infrastructure and its evolution. It then describes the hydrogen delivery scenario analysis model, an Excel-based tool that calculates the levelized cost of delivering hydrogen from a central production facility to a vehicle by the use of currently available technologies and a typical profile of vehicle use and fueling demand. The results are shown for a status quo, or gasoline-centric case, in which demand reflects the current gasoline-based system and supply responds accordingly, and a hydrogen-centric case, in which some of those patterns are altered. The paper highlights fueling requirements that are particularly problematic for hydrogen and concludes with a discussion of alternative fueling paradigms.

As with the distribution of any commodity, distribution of hydrogen depends on how the hydrogen is packaged, how far it must travel, and how much must be delivered. Few would argue that transporting a high-pressure gas is markedly different from transporting a cryogenic liquid—or even a liquid at standard temperature and pressure. Packaging affects not only density (weight/volume) but also the operation of potential delivery modes and onboard storage, a problem that has been called the grand challenge of the hydrogen economy. These three factors—packaging (which in turn affects shipment size and modal attributes), delivery distance, and demand—affect both the structure of potential delivery systems and their contribution to unit costs. This paper describes the hydrogen delivery scenario analysis model, a generalized model of hydrogen delivery that can be used to analyze the economic feasibility of various options for hydrogen distribution to markets of different sizes and types. Inputs may be user defined, or default values developed for the U.S. Department of Energy's Hydrogen Analysis project may be used. This paper describes the model's structure and capabilities, presents initial results, and discusses ongoing enhancements.

As with the distribution of any commodity, distribution of hydrogen depends on how the hydrogen is packaged, how far it must travel, and how much must be delivered. Few would argue that transporting a high-pressure gas is markedly different from transporting a cryogenic liquid— or even a liquid at standard temperature and pressure. Packaging affects not only density (weight/volume) but also the operation of potential delivery modes and onboard storage, a problem that has been called the grand challenge of the hydrogen economy. These three factors—packaging (which in turn affects shipment size and modal attributes), delivery distance, and demand—affect both the structure of potential delivery systems and their contribution to unit costs. This paper describes the hydrogen delivery scenario analysis model, a generalized model of hydrogen delivery that can be used to analyze the economic feasibility of various options for hydrogen distribution to markets of different sizes and types. Inputs may be user defined, or default values developed for the U.S. Department of Energy's Hydrogen Analysis project may be used. This paper describes the model's structure and capabilities, presents initial results, and discusses ongoing enhancements.

CO2capture and utilization provides an alternative pathway for low-carbon hydrocarbon production. Given the ample supply of high-purity CO2emitted from ethanol and ammonia plants, this study conducted technoeconomic analysis and environmental life cycle analysis of several systems: integrated methanol–ethanol coproduction, integrated methanol–ammonia coproduction, and stand-alone methanol production systems, using CO2feedstock from ethanol plants, ammonia plants, and general market CO2supply. The cradle-to-grave greenhouse gas emissions of methanol produced from the stand-alone methanol, integrated methanol–ethanol, and integrated methanol–ammonia systems are 13.6, 37.9, and 84.6 g CO2-equiv/MJ, respectively, compared to 91.5 g CO2-equiv/MJ of conventional methanol produced from natural gas. The minimum fuel selling price (MFSP) of methanol ($0.61–0.64/kg) is 61–68% higher than the average market methanol price of $0.38/kg, when using a Department of Energy target renewable hydrogen production price of $2.0/kg. The methanol price increases to $1.24–1.28/kg when the hydrogen price is $5.0/kg. Without CO2abatement credits, the H2price needs to be within $0.77–0.95/kg for the MFSP of methanol to equal the average methanol market price. With a CO2credit of $35/MT according to tax credit per metric ton of CO2captured and used, the methanol price is reduced to $0.56–0.59/kg.