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The cost of hydrogen delivery for transportation accounts for most of the current H2 selling price; delivery also requires substantial amounts of energy. We developed harmonized techno-economic and life-cycle emissions models of current and future H2 production and delivery pathways. Our techno-economic analysis of dispensed H2 costs guided our selection of pathways for the life-cycle analysis. In this paper, we present the results of market expansion scenarios using existing capabilities (for example, those that use H2 from steam methane reforming, chlor-alkali, and natural gas liquid cracker plants), as well as results for future electrolysis plants that use nuclear, solar, and hydroelectric power. Reductions in greenhouse gas emissions for fuel cell electric vehicles compared to conventional gasoline pathways vary from 40% reduction for fossil-derived H2 to 20-fold for clean H2. Supplemental tables with greenhouse gas emissions data for each step in the H2 pathways enable readers to evaluate additional scenarios.

Captured CO2 is 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 CO2 captured 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 CO2 can 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 CO2 reduction 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.

CO2 capture and utilization provides an alternative pathway for low-carbon hydrocarbon production. Given the ample supply of high-purity CO2 emitted 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 CO2 feedstock from ethanol plants, ammonia plants, and general market CO2 supply. 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 CO2 abatement credits, the H2 price needs to be within $0.77-0.95/kg for the MFSP of methanol to equal the average methanol market price. With a CO2 credit of $35/MT according to tax credit per metric ton of CO2 captured and used, the methanol price is reduced to $0.56-0.59/kg.

Conventionally, ammonia is produced from natural gas via steam methane reforming (SMR), water-gas shift reaction, and the Haber–Bosch process. The process uses fossil natural gas, which leads to 2.6 metric tons of life cycle greenhouse gas (GHG) emissions per metric ton of ammonia produced. With ammonia being the second most produced chemical in the world, its production accounts for approximately 2% of worldwide fossil energy use and generates over 420 million tons of CO2 annually. To reduce its carbon intensity, ammonia synthesis relying on renewable energy or utilizing by-products from industrial processes is of interest. We conduct a life cycle analysis of conventional and alternative ammonia production pathways by tracking energy use and emissions in all conversion stages, from the primary material and energy resources to the ammonia plant gates. Of all the alternative pathways, obtaining N2 from cryogenic distillation and H2 from low-temperature electrolysis using renewable electricity has the lowest cradle-to-plant-gate GHG emissions, representing a 91% decrease from the conventional SMR pathway.

This paper presents an in-depth laboratory technology assessment of a 2016 Toyota Mirai Fuel Cell (FC) vehicle based on chassis dynamometer testing. The 114.6 kW FC stack has a high dynamic response, which makes this powertrain a FC-dominant hybrid electric vehicle. The measured peak efficiency is 66.0% FC stack and 63.7% FC system with an idle hydrogen flow rate of 4.39 g/hr. The high FC system efficiencies at low loads match typical vehicle power spectrums, resulting in a high average vehicle efficiency of 62% compared to 45% and 23% for a hybrid electric vehicle and a conventional vehicle, respectively. An energy breakdown accounts for the FC stack losses, FC system losses, air compressor loads, and heater loads for different drive cycles and different thermal conditions. The cold-start North American city drive cycle (UDDS) energy consumption values are, respectively, 758, 581, 226, and 321 Wh/km at ambient conditions of −18 °C, −7 °C, 25 °C and 35 °C with 850 W/m2 of solar loading. The FC system shutdown and startup processes at temperatures below the freezing point contribute to the increased hydrogen consumption. The raw test data files are available for download, thus providing the research community with a public reference data on a modern production automotive FC system.

The operation of hydrogen fuel cell electric vehicles (HFCEVs) is more efficient than that of gasoline conventional internal combustion engine vehicles (ICEVs), and produces zero tailpipe pollutant emissions. However, the production, transportation, and refueling of hydrogen are more energy- and emissions-intensive compared to gasoline. A well-to-wheels (WTW) energy use and emissions analysis was conducted to compare a HFCEV (Toyota Mirai) with a gasoline conventional ICEV (Mazda 3). Two sets of specific fuel consumption data were used for each vehicle: (1) fuel consumption derived from the U.S. Environmental Protection Agency's (EPA's) window-sticker fuel economy figure, and (2) weight-averaged fuel consumption based on physical vehicle testing with a chassis dynamometer on EPA's five standard driving cycles. The WTW results show that a HFCEV, even fueled by hydrogen from a fossil-based production pathway (via steam methane reforming of natural gas), uses 5%–33% less WTW fossil energy and has 15%–45% lower WTW greenhouse gas emissions compared to a gasoline conventional ICEV. The WTW results are sensitive to the source of electricity used for hydrogen compression or liquefaction.

Light-duty battery electric vehicles (BEVs) can reduce both greenhouse gas (GHG) and criteria air pollutant (CAPs) emissions, when compared to gasoline vehicles. However, research has found that while today’s BEVs typically reduce GHGs, they can increase certain CAPs, though with significant regional variability based on the electric grid mix. In addition, the environmental performance of electric and gasoline vehicles is not static, as key factors driving emissions have undergone significant changes recently and are expected to continue to evolve. In this study, we perform a cradle-to-grave life cycle analysis using state-level generation mix and vehicle operation emission data. We generated state-level emission factors using a projection from 2020 to 2050 for three light-duty vehicle types. We found that BEVs currently provide GHG benefits in nearly every state, with the median state’s benefit being between approximately 50% to 60% lower than gasoline counterparts. However, gasoline vehicles currently have lower total NOx, urban NOx, total PM2.5, and urban PM2.5 in 33%, 15%, 70%, and 10% of states, respectively. BEV emissions will decrease in 2050 due to a cleaner grid, but the relative benefits when compared to gasoline vehicles do not change significantly, as gasoline vehicles are also improving over this time.

Refueling costs account for much of the fuel cost for light-duty hydrogen fuel-cell electric vehicles. We estimate cost savings for hydrogen dispensing if metal hydride (MH) storage tanks are used on board instead of 700-bar tanks. We consider a low-temperature, low-enthalpy scenario and a high-temperature, high-enthalpy scenario to bracket the design space. The refueling costs are insensitive to most uncertainties. Uncertainties associated with the cooling duty, coolant pump pressure, heat exchanger (HX) fan, and HX operating time have little effect on cost. The largest sensitivities are to tank pressure and station labor. The cost of a full-service attendant, if the refueling interconnect were to prevent self-service, is the single largest cost uncertainty. MH scenarios achieve $0.71–$0.75/kg-H2 savings by reducing compressor costs without incurring the cryogenics costs associated with cold-storage alternatives. Practical refueling station considerations are likely to affect the choice of the MH and tank design.

Hydrogen fuel cell electric vehicle technology is emerging as a promising option for the electrification of school or transit buses. For fuel cell electric transit buses, the U.S. government has set the fuel economy target at 8 miles per diesel gallon equivalent (MPDGE). However, life-cycle environmental implications of the 8 MPDGE target are currently lacking in the literature. In addition, no comparable target exists for fuel cell electric school buses. This study shows that achieving the fuel economy target (8 MPDGE) for fuel cell electric transit buses is likely to result in reductions of overall energy consumption and air emissions on a well-to-wheel basis, in comparison with diesel buses. For fuel cell electric school buses, 13 MPDGE fuel economy is expected to bring comparable benefits to those of their transit bus counterparts, in terms of well-to-wheel energy use and air emissions reductions. When it comes to the life-cycle environmental performance of fuel cell electric school/transit buses, it is critical to acknowledge that results can vary significantly depending on duty cycles, geographical factors, hydrogen fuel production pathways, and regional electric grids. All of these factors introduce nested (multilayered) variations in comparisons of diesel and fuel cell electric buses.

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.

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.

Steam crackers convert hydrocarbon feedstock (e.g., natural gas liquids) to light olefins via thermal cracking and produce hydrogen as a by-product during the process. Benefiting from the shale gas boom in recent years, the overall production capacity of U.S. steam crackers, as well as the potential of by-product hydrogen production, is continuously growing. We estimate that 3.5 million tonne/year of by-product hydrogen can be produced from steam crackers, almost doubling the size of the existing U.S. merchant hydrogen market. We also find that producing hydrogen from steam crackers creates less (15%–91%) life-cycle greenhouse gas emissions than the conventional centralized steam methane reforming (SMR) pathway. For criteria air pollutants, life-cycle emissions reduction benefits vary greatly (−75% – +85%), depending on the co-product treatment scenario (substitution or allocation) and air pollutant type. The substitution scenario generally results in an increase of criteria air pollutants emissions, mainly due to the requirement of substitutive natural gas fuel. We estimate that the cost of purified by-product hydrogen fuel from steam crackers is $0.9–1.1/kg, reducing hydrogen production costs by 30% compared to the conventional central SMR pathway. Furthermore, using by-product hydrogen from steam crackers can generate credits of $1.8–2.5/kg under California's low-carbon fuel standard.

This study provides a comprehensive and up-to-date life-cycle comparison of hydrogen fuel cell electric trucks (FCETs) and their conventional diesel counterparts in terms of energy use and air emissions, based on the ensemble of well-established methods, high-fidelity vehicle dynamic simulations, and real-world vehicle test data. For the centralized steam methane reforming (SMR) pathway, hydrogen FCETs reduce life-cycle or well-to-wheel (WTW) petroleum energy use by more than 98% compared to their diesel counterparts. The reduction in WTW air emissions for gaseous hydrogen (G.H2) FCETs ranges from 20 to 45% for greenhouse gases, 37–65% for VOC, 49–77% for CO, 62–83% for NOx, 19–43% for PM10, and 27–44% for PM2.5, depending on vehicle weight classes and truck types. With the current U.S. average electricity generation mix, FCETs tend to create more WTW SOx emissions than their diesel counterparts, mainly because of the upstream emissions related to electricity use for hydrogen compression/liquefaction. Compared to G.H2, liquid hydrogen (L.H2) FCETs generally provide smaller WTW emissions reductions. For both G.H2 and L.H2 pathways for FCETs, because of electricity consumption for compression and liquefaction, spatio-temporal variations of electricity generation can affect the WTW results. FCETs retain the WTW emission reduction benefits, even when considering aggressive diesel engine efficiency improvement.

Increasing stress on the global water supply necessitates the measurement of water consumption as a sustainability metric to evaluate energy production, including the production of transportation fuels (gasoline, diesel, jet fuel) at petroleum refineries. This study estimated refinery water consumption for petroleum fuels by considering three typical refinery configurations (cracking, light coking, and heavy coking) that process different crude qualities (e.g., American Petroleum Institute Gravity (API) gravity and sulfur content). The results showed that refinery water consumption was 0.34, 0.44, and 0.47 bbl water/bbl crude (L water/L crude) for cracking, light coking, and heavy coking configurations, respectively. The water consumption for a specific refinery product was estimated using an energy allocation approach at the process unit level. The results indicated that gasoline production consumes the largest amount of water, 0.60–0.71 gal water/gal gasoline (0.60–0.71 L water/L gasoline), due to the energy-intensive (and thus water-intensive) processing of gasoline components (mainly sourced from alkylation, reformer, and fluid catalytic cracking units). In contrast, jet fuel production consumes the least water, 0.09 gal water/gal jet fuel, for all three refinery configurations, because it is sourced directly from the crude distillation unit with minimal post-treating. The consumption of diesel is most sensitive to refinery configuration with 0.20, 0.30, and 0.40 gal water/gal diesel (L water/L diesel) for cracking, light coking and heavy coking configurations, respectively. This is mainly because as configuration complexity increases to process heavier and sourer crudes, a sizable burden of hydrogen production from steam methane reforming unit is allocated to diesel fuel production (including diesel sulfur removal). The trend of water consumption associated with these refinery products is consistent with the energy consumption for their production.

By-product hydrogen from chlor-alkali processes can help meet the increasing demand for hydrogen fuel in early fuel cell electric vehicle markets (e.g., California) in the U.S. Hydrogen produced from chlor-alkali plants is typically combusted for process heat on site, vented to the atmosphere (i.e., wasted), or sold to the external merchant hydrogen market. Whether it is combusted, vented, or sold as a commodity, relevant information is lacking as to the life-cycle environmental benefits or trade-offs of using by-product hydrogen from chlor-alkali plants. A life-cycle analysis framework was employed to evaluate well-to-gate greenhouse gas (GHG) emissions associated with by-product hydrogen from chlor-alkali processes in comparison with hydrogen from the conventional centralized natural gas steam methane reforming (central SMR) pathway. U.S.-specific, plant-by-plant, and up-to-date chlor-alkali production characteristics were incorporated into the analysis. In addition to the venting and combustion scenarios, to deal with the multi-functionality of the chlor-alkali processes that simultaneously produce chlorine, sodium hydroxide, and hydrogen, two different co-product allocation strategies were adopted—mass allocation and market value allocation. It was estimated that by-product hydrogen production from chlor-alkali processes creates 1.3–9.8 kg CO2e/kg H2 of life-cycle GHG emissions on average, which is 20–90% less than the conventional central SMR pathway. The results vary with co-product treatment scenarios, regional electric grid characteristics, on-site power generation, product prices, and hydrogen yield. Despite the variations in the results, it was concluded that the life-cycle GHG emission reduction benefits of using by-product hydrogen from chlor-alkali processes are robust. With a diverse set of scenario analyses, the study developed a comprehensive and detailed life-cycle GHG emissions inventory of the chlor-alkali by-product hydrogen pathway and quantified sensitivity indices in the context of different assumptions and input parameter values.

Transporting compressed gaseous hydrogen in tube trailers to hydrogen refueling stations (HRSs) is an attractive economic option in early fuel cell electric vehicle (FCEV) markets. This study examines conventional (Type I, steel) and advanced (Type IV, composite) high-pressure tube trailer configurations to identify those that offer maximum payload and lowest cost per unit of deliverable payload under United States Department of Transportation (DOT) size and weight constraints. The study also evaluates the impacts of various tube trailer configurations and payloads on the transportation and refueling cost of hydrogen under various transportation distance and HRS capacity scenarios. Composite tube trailers can transport large hydrogen payloads, up to 1100 kg at 7300 psi (500 bar) working pressure, while steel tube trailer configurations are limited by DOT weight regulations and may transport a maximum hydrogen payload of approximately 270 kg. Using steel pressure vessels to transport hydrogen at high pressure is counterproductive because of the rapid increase in vessel weight with wall thickness. The most economic composite tube trailer configuration includes 30-inch-diameter vessels packed in a 3 × 3 array. A linear relationship between the deliverable payload and the capital cost of a composite tube trailer has been developed for configurations with the lowest cost-per-unit payload. The capital cost is approximately $1100 per kg of deliverable hydrogen payload. Considering the entire delivery pathway (including refueling), tube trailer configurations with smaller vessels packed in greater numbers enable higher payload delivery and lower delivery cost in terms of $/kg H2, when delivering hydrogen over longer distances to large stations. Selection of the appropriate tube trailer configuration and corresponding hydrogen payload can reduce hydrogen delivery cost by up to 16%.

An operation strategy known as two-tier “pressure consolidation” of delivered tube-trailers (or equivalent supply storage) has been developed to maximize the throughput at gaseous hydrogen refueling stations (HRSs) for fuel cell electric vehicles (FCEVs). The high capital costs of HRSs and the consequent high investment risk are deterring growth of the infrastructure needed to promote the deployment of FCEVs. Stations supplied by gaseous hydrogen will be necessary for FCEV deployment in both the near and long term. The two-tier pressure consolidation method enhances gaseous HRSs in the following ways: (1) reduces the capital cost compared with conventional stations, as well as those operating according to the original pressure consolidation approach described by Elgowainy et al. (2014) [1], (2) minimizes pressure cycling of HRS supply storage relative to the original pressure consolidation approach; and (3) increases use of the station's supply storage (or delivered tube-trailers) while maintaining higher state-of-charge vehicle fills.

We conducted a techno-economic and thermodynamic analysis of precooling units (PCUs) at hydrogen refueling stations and developed a cost-minimizing design algorithm for the PCU observing the SAE J2601 refueling protocol for T40 stations (requiring −40 ° C precooling temperature). In so doing, we identified major factors that affect PCU cost and energy use. The hydrogen precooling energy intensity depends strongly on the station utilization rate, but approaches 0.3 kWh e /kg-H 2 at full utilization. In early fuel cell electric vehicle markets where utilization of the refueling capacity is low, the overhead cooling load (to keep the heat exchanger cold at −40 °C) results in significantly high PCU energy intensity because only a small amount of hydrogen is being dispensed. We developed a parameterized precooling energy intensity prediction formula as a function of the ambient temperature and station utilization rate. We also found that the Joule-Thomson effect of the flow control device introduces a significant increase in temperature upstream of the PCU's heat exchanger (HX), which impacts the PCU design capacity. An optimal PCU (per dispenser, at 35 °C HX inlet temperature) consists of a 13-kW refrigerator and a HX with 1400 kg of thermal mass (aluminum), which currently costs $70,000 (uninstalled). The total (installed) capital and operation cost of PCU at a fully utilized hydrogen refueling station adds $0.50/kg-H 2 .

The cost of hydrogen in early fuel cell electric vehicle (FCEV) markets is dominated by the cost of refueling stations, mainly due to the high cost of refueling equipment, small station capacities, lack of economies of scale, and low utilization of the installed refueling capacity. Using the hydrogen delivery scenario analysis model (HDSAM), this study estimates the impacts of these factors on the refueling cost for different refueling technologies and configurations, and quantifies the potential reduction in future hydrogen refueling cost compared to today's cost in the United States. The current hydrogen refueling station levelized cost, for a 200 kg/day dispensing capacity, is in the range of $6–$8/kg H2 when supplied with gaseous hydrogen, and $8–$9/kg H2 for stations supplied with liquid hydrogen. After adding the cost of hydrogen production, packaging, and transportation to the station's levelized cost, the current cost of hydrogen at dispensers for FCEVs in California is in the range of $13–$15/kg H2. The refueling station capacity utilization strongly influences the hydrogen refueling cost. The underutilization of station capacity in early FCEV markets, such as in California, results in a levelized station cost that is approximately 40% higher than it would be in a scenario where the station had been fully utilized since it began operating. In future mature hydrogen FCEV markets, with a large demand for hydrogen, the refueling station's levelized cost can be reduced to $2/kg H2 as a result of improved capacity utilization and reduced equipment cost via learning and economies of scale.

Hydrogen fuel cell electric vehicles (HFCEVs) are zero-emission vehicles (ZEVs) that can provide drivers a similar experience to conventional internal combustion engine vehicles (ICEVs), in terms of fueling time and performance (i.e. power and driving range). The Society of Automotive Engineers (SAE) developed fueling protocol J2601 for light-duty HFCEVs to ensure safe vehicle fills while maximizing fueling performance. This study employs a physical model that simulates and compares the fueling performance of two fueling methods, known as the “lookup table” method and the “MC formula” method, within the SAE J2601 protocol. Both the fueling methods provide fast fueling of HFCEVs within minutes, but the MC formula method takes advantage of active measurement of precooling temperature to dynamically control the fueling process, and thereby provides faster vehicle fills. The MC formula method greatly reduces fueling time compared to the lookup table method at higher ambient temperatures, as well as when the precooling temperature falls on the colder side of the expected temperature window for all station types. Although the SAE J2601 lookup table method is the currently implemented standard for refueling hydrogen fuel cell vehicles, the MC formula method provides significant fueling time advantages in certain conditions; these warrant its implementation in future hydrogen refueling stations for better customer satisfaction with fueling experience of HFCEVs.

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, NO x, 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.).

Electro-fuels can be produced from concentrated sources of carbon dioxide and hydrogen using electricity generated from renewable sources; this process enables energy storage at high volumetric energy density. Among the electro-fuels options, FT (Fischer-Tropsch) fuel is attractive for heavy-duty trucks and non-road transportation applications. The present study conducts a techno-economic analysis of FT liquid fuel production from H2 and CO2 using a detailed performance analysis. Minimum fuel selling price is estimated for a broad range of H2 and CO2 prices and for a range of potential CO2 credits. The analysis indicates that H2 price has the largest impact on the minimum selling price of FT fuel. FT fuel production with a CO2 price of $17.3/metric ton requires an H2 price of $0.8/kg to be cost-competitive with the pre-tax petroleum diesel price of $3.1/gal in 2050 (before the application of any CO2 credits). When the H2 price is $2.0/kg from central water electrolysis (2020 target), the minimum selling price of the FT fuel is $5.4–5.9/gal. A sensitivity analysis shows that future system optimization of FT fuel production could focus on improving the H2 and CO2 recycle contributions and FT fuel conversion ratio. The analysis results can be combined with various upstream systems for H2 and CO2 production.

This article presents a cradle-to-grave (C2G) assessment of greenhouse gas (GHG) emissions and costs for current (2015) and future (2025–2030) light-duty vehicles. The analysis addressed both fuel cycle and vehicle manufacturing cycle for the following vehicle types: gasoline and diesel internal combustion engine vehicles (ICEVs), flex fuel vehicles, compressed natural gas (CNG) vehicles, hybrid electric vehicles (HEVs), hydrogen fuel cell electric vehicles (FCEVs), battery electric vehicles (BEVs), and plug-in hybrid electric vehicles (PHEVs). Gasoline ICEVs using current technology have C2G emissions of ∼450 gCO2e/mi (grams of carbon dioxide equivalents per mile), while C2G emissions from HEVs, PHEVs, H2 FCEVs, and BEVs range from 300–350 gCO2e/mi. Future vehicle efficiency gains are expected to reduce emissions to ∼350 gCO2/mi for ICEVs and ∼250 gCO2e/mi for HEVs, PHEVs, FCEVs, and BEVs. Utilizing low-carbon fuel pathways yields GHG reductions more than double those achieved by vehicle efficiency gains...

Because of increasing environmental and energy security concerns, a detailed understanding of energy efficiency and greenhouse gas (GHG) emissions in the petroleum refining industry is critical for fair and equitable energy and environmental policies. To date, this has proved challenging due in part to the complex nature and variability within refineries. In an effort to simplify energy and emissions refinery analysis, we delineated LP modeling results from 60 large refineries from the US and EU into broad categories based on crude density (API gravity) and heavy product (HP) yields. Product-specific efficiencies and process fuel shares derived from this study were incorporated in Argonne National Laboratory's GREET life-cycle model, along with regional upstream GHG intensities of crude, natural gas and electricity specific to the US and EU regions. The modeling results suggest that refineries that process relatively heavier crude inputs and have lower yields of HPs generally have lower energy efficiencies and higher GHG emissions than refineries that run lighter crudes with lower yields of HPs. The former types of refineries tend to utilize energy-intensive units which are significant consumers of utilities (heat and electricity) and hydrogen. Among the three groups of refineries studied, the major difference in the energy intensitiesmore » is due to the amount of purchased natural gas for utilities and hydrogen, while the sum of refinery feed inputs are generally constant. These results highlight the GHG emissions cost a refiner pays to process deep into the barrel to produce more of the desirable fuels with low carbon to hydrogen ratio. (c) 2015 Argonne National Laboratory. Published by Elsevier Ltd.« less

The energy intensity and fugitive emissions of oil sands extraction are modeled using detailed public data sets to provide more accurate estimates of energy use. Facility-level energy consumption and environmental emission data are collected on a monthly basis for 24 operating oil sands projects (7 mining projects and 17 in situ projects) over the periods of 2005–2012 (for mining projects) and 2009–2012 (for in situ projects). This is the most detailed data set used to date for greenhouse gas (GHG) assessment from the oil sands and relies entirely on data from government data sets. Monthly facility-level data are aggregated into four pathways, depending upon the mode of primary extraction (i.e., mining or in situ) and the type of product exported [i.e., bitumen or synthetic crude oil (SCO)]. Large variability is found among pathways and between projects within each pathway. Energy intensity ranges from 0.1 GJ/GJ of bitumen for mining projects to 0.4 GJ/GJ of SCO for in situ projects. Month-to-month variab...

Hydrogen refueling stations require high capital investment, with compression and storage comprising more than half of the installed cost of refueling equipment. Refueling station configurations and operation strategies can reduce capital investment while improving equipment utilization. Argonne National Laboratory developed a refueling model to evaluate the impact of various refueling compression and storage configurations and tube trailer operating strategies on the cost of hydrogen refueling. The modeling results revealed that a number of strategies can be employed to reduce fueling costs. Proper sizing of the high-pressure buffer storage reduces the compression requirement considerably, thus reducing refueling costs. Employing a tube trailer to initially fill the vehicle's tank also reduces the compression and storage requirements, further reducing refueling costs. Reducing the cut-off pressure of the tube trailer for initial vehicle fills can also significantly reduce the refueling costs. Finally, increasing the trailer's return pressure can cut refueling costs, especially for delivery distances less than 100 km, and in early markets, when refueling stations will be grossly underutilized.

Algae biomass is an attractive biofuel feedstock when grown with high productivity on marginal land. Hydrothermal liquefaction (HTL) produces more oil from algae than lipid extraction (LE) does because protein and carbohydrates are converted, in part, to oil. Since nitrogen in the algae biomass is incorporated into the HTL oil, and since lipid extracted algae for generating heat and electricity are not co-produced by HTL, there are questions regarding implications for emissions and energy use. We studied the HTL and LE pathways for renewable diesel (RD) production by modeling all essential operations from nutrient manufacturing through fuel use. Our objective was to identify the key relationships affecting HTL energy consumption and emissions. LE, with identical upstream growth model and consistent hydroprocessing model, served as reference. HTL used 1.8 fold less algae than did LE but required 5.2 times more ammonia when nitrogen incorporated in the HTL oil was treated as lost. HTL RD had life cycle emissions of 31,000 gCO2 equivalent (gCO2e) compared to 21,500 gCO2e for LE based RD per million BTU of RD produced. Greenhouse gas (GHG) emissions increased when yields exceeded 0.4 g HTL oil/g algae because insufficient carbon was left for biogas generation. Key variables in the analysis were the HTL oil yield, the hydrogen demand during upgrading, and the nitrogen content of the HTL oil. Future work requires better data for upgrading renewable oils to RD and requires consideration of nitrogen recycling during upgrading.

Forklift propulsion systems and distributed power generation are identified as potential fuel cell applications for near-term markets. This analysis examines fuel cell forklifts and distributed power generators, and addresses the potential energy and environmental implications of substituting fuel-cell systems for existing technologies based on fossil fuels and grid electricity. Performance data and the Greenhouse gases, Regulated Emissions, and Energy use in Transportation (GREET) model are used to estimate full fuel-cycle emissions and use of primary energy sources. The greenhouse gas (GHG) impacts of fuel-cell forklifts using hydrogen from steam reforming of natural gas are considerably lower than those using electricity from the average U.S. grid. Fuel cell generators produce lower GHG emissions than those associated with the U.S. grid electricity and alternative distributed combustion technologies. If fuel-cell generation technologies approach or exceed the target efficiency of 40%, they offer significant reduction in energy use and GHG emissions compared to alternative combustion technologies.

As the global population and economy continue to grow, demand for energy will continue to grow. The transportation sector has been relying solely on petroleum, consuming more than 50 % of the global world oil production. The United States is the top oil-importer country. Two major issues facing the transportation sector in the U.S. and other major countries are energy security and environmental sustainability. Improvements in the energy efficiency of vehicles and the substitution of petroleum fuels with alternative fuels can help slow the growth in the demand for petroleum oil and mitigate the increase in greenhouse gas emissions. Biofuels and electricity are being promoted for their potential reduction of petroleum use and greenhouse gas emissions. This chapter examines the potential reduction of life-cycle energy use and greenhouse gas emissions associated with the use of biofuels in internal combustion engine vehicles and electricity in plug-in hybrid electric vehicles and battery-powered electric vehicles.

Use of ethanol as a transportation fuel in the United States has grown from 76 dam 3 in 1980 to over 40.1 hm 3 in 2009 — and virtually all of it has been produced from corn. It has been debated whether using corn ethanol results in any energy and greenhouse gas benefits. This issue has been especially critical in the past several years, when indirect effects, such as indirect land use changes, associated with U.S. corn ethanol production are considered in evaluation. In the past three years, modeling of direct and indirect land use changes related to the production of corn ethanol has advanced significantly. Meanwhile, technology improvements in key stages of the ethanol life cycle (such as corn farming and ethanol production) have been made. With updated simulation results of direct and indirect land use changes and observed technology improvements in the past several years, we conducted a life-cycle analysis of ethanol and show that at present and in the near future, using corn ethanol reduces greenhouse gas emission by more than 20%, relative to those of petroleum gasoline. On the other hand, second-generation ethanol could achieve much higher reductions in greenhouse gas emissions. In a broader sense, sound evaluation of U.S. biofuel policies should account for both unanticipated consequences and technology potentials. We maintain that the usefulness of such evaluations is to provide insight into how to prevent unanticipated consequences and how to promote efficient technologies with policy intervention.

Globally, bioethanol is the largest volume biofuel used in the transportation sector, with corn-based ethanol production occurring mostly in the US and sugarcane-based ethanol production occurring mostly in Brazil. Advances in technology and the resulting improved productivity in corn and sugarcane farming and ethanol conversion, together with biofuel policies, have contributed to the significant expansion of ethanol production in the past 20 years. These improvements have increased the energy and greenhouse gas (GHG) benefits of using bioethanol as opposed to using petroleum gasoline. This article presents results from our most recently updated simulations of energy use and GHG emissions that result from using bioethanol made from several feedstocks. The results were generated with the GREET (Greenhouse gases, Regulated Emissions, and Energy use in Transportation) model. In particular, based on a consistent and systematic model platform, we estimate life-cycle energy consumption and GHG emissions from using ethanol produced from five feedstocks: corn, sugarcane, corn stover, switchgrass and miscanthus. We quantitatively address the impacts of a few critical factors that affect life-cycle GHG emissions from bioethanol. Even when the highly debated land use change GHG emissions are included, changing from corn to sugarcane and then to cellulosic biomass helps to significantly increase the reductions in energy use and GHG emissions from using bioethanol. Relative to petroleum gasoline, ethanol from corn, sugarcane, corn stover, switchgrass and miscanthus can reduce life-cycle GHG emissions by 19‐48%, 40‐62%, 90‐103%, 77‐97% and 101‐115%, respectively. Similar trends have been found with regard to fossil energy benefits for the five bioethanol pathways.

Researchers around the world are developing sustainable plant-based liquid transportation fuels (biofuels) to reduce petroleum consumption and greenhouse gas emissions. Algae are attractive because they promise large yields per acre compared to grasses, grains and trees, and because they produce oils that might be converted to diesel and gasoline equivalents. It takes considerable energy to produce algal biofuels with current technology; thus, the potential benefits of algal biofuels compared to petroleum fuels must be quantified. To this end, we identified key parameters for algal biofuel production using GREET, a tool for the life-cycle analysis of energy use and emissions in transportation systems. The baseline scenario produced 55 400 g CO2 equivalent per million BTU of biodiesel compared to 101 000 g for low-sulfur petroleum diesel. The analysis considered the potential for greenhouse gas emissions from anaerobic digestion processes commonly used in algal biofuel models. The work also studied alternative scenarios, e.g., catalytic hydrothermal gasification, that may reduce these emissions. The analysis of the nitrogen recovery step from lipid-extracted algae (residues) highlighted the importance of considering the fate of the unrecovered nitrogen fraction, especially that which produces N2O, a potent greenhouse gas with global warming potential 298 times that of CO2.