Conference Agenda

Overview and details of the sessions of this conference. Please select a date or location to show only sessions at that day or location. Please select a single session for detailed view (with abstracts and downloads if available).

 
Session Overview
Session
E&S-8: Transportation fuels and other energy systems
Time:
Thursday, 27/Jun/2019:
10:30am - 12:00pm

Session Chair: Troy R Hawkins
Location: Hawthorne/Sellwood

Presentations
10:30am - 10:50am

Evaluation of Variability in Well-to-Wheel Greenhouse Gas Emissions Intensities of Oil Sands Mining and In Situ Pathways

Sylvia Sleep1, John Guo1, Andrea Orellana1, Ian J. Laurenzi2, Joule A. Bergerson1, Heather L. MacLean3

1Department of Chemical and Petroleum Engineering, University of Calgary; 2ExxonMobil Research and Engineering Company; 3Department of Civil and Mineral Engineering, University of Toronto

The techniques employed for producing oil sands bitumen (i.e., mining or in situ) and how the crude is processed (either upgraded to synthetic crude oil, SCO, or diluted with condensate to produce dilbit) result in a range of crude properties with distinct downstream emissions. In previous work, we developed a statistically-enhanced version of the Greenhouse gas emissions of current Oil Sands Technologies (GHOST-SE) model that characterizes variability in upstream (bitumen production and upgrading/dilution) greenhouse gas (GHG) intensities of oil sands mining [1] and in situ [2] techniques on a project basis. In this work, we explicitly characterize variability in GHG intensities of oil sands pathways across the full well-to-wheel (WTW), accounting for variability in upstream and downstream (crude transport and refining) life cycle stages, which has not been done in previous studies. A WTW approach enables a comparison of projects and production pathways that produce crudes with distinct properties on a common functional unit. Additionally, extending the boundary across the WTW prevents incentivizing decisions that reduce upstream emissions but increase WTW emissions by increasing emissions downstream.

GHOST-SE is integrated with statistically-enhanced versions of crude pipeline (Crude Oil Pipeline Transportation Emissions Model) and refinery (Petroleum Refinery Life cycle Inventory Model) models to account for WTW variability. Statistical distributions of WTW GHG intensities are compared for individual projects to identify sources of variability within projects employing the same production technique (i.e., mining or in situ) as well as across representative oil sands pathways (i.e., SCO or dilbit produced via mining or in situ). GHG intensity distributions are also disaggregated by life cycle stage to identify the contribution of each stage to WTW variability and drivers of variability within each stage.

The range of WTW GHG intensities across all pathways range from of P10 to P90 of 93-123 g CO2eq/MJ gasoline (mining) 98-133 g CO2eq/MJ gasoline (in situ). For all bitumen production methods, dilbit pathways have narrower GHG intensity distributions with lower median GHG intensities (96 and 102 g CO-2eq/MJ gasoline for mining and in situ, respectively) than their respective SCO pathways (112 and 119 g CO2eq/MJ gasoline). Within individual pathways, WTW variability is driven in approximately equal proportions by the upstream and refinery stages, although the relative contribution of upstream and refining stages varies across pathways. Refinery emissions are driven primarily by refinery configuration and the properties of crude refined.

Compared to previous WTW studies that have modeled a single SCO refining pathway, we quantify refinery emissions for the distinct SCO produced by each upgrader and find that SCO refinery GHG intensities range from 48-70 kg CO2eq/bbl SCO. Additionally, across all crudes and refinery configurations modeled, the lowest-API gravity crude with the lowest sulfur content does not always have the lowest refinery emissions. The results of this study can inform about key drivers of variability and the technologies, operating decisions, and downstream conditions that can result in the lowest GHG intensity across the WTW. This approach could be extended to other fuel production pathways to identify opportunities for reducing WTW GHG intensities across a range of pathways.

[1] Sleep et al. Environ. Sci. Technol. 2018

[2] Orellana et al. Environ. Sci. Technol. 2018



10:50am - 11:10am

Projections of Low and Midlevel Ethanol Blends for the Canadian Light-Duty Vehicle Fleet and Greenhouse Gas Emission Implications

Alexandre Milovanoff, Heather L. MacLean

Department of Civil & Mineral Engineering, University of Toronto

Biofuels, such as ethanol, can substitute for petroleum fuels in light-duty vehicles to reduce greenhouse gas (GHG) emissions. However, ethanol currently accounts for only 6% of gasoline blends by volume in Canada and increasing ethanol volumes requires the use of higher blends, such as mid-level ethanol blends (i.e., blends with more than 15% but less than 30% of ethanol by volume). Mid-level ethanol blends have effects on engine operations and no study has assessed the effects of their deployment on gasoline and ethanol volumes and GHG emissions in the Canadian context.

The aim of our work is to quantify the changes in ethanol and gasoline volumes of mid-level ethanol blend deployment in Canada from 2018 to 2030 and to assess the well-to-wheel (WTW) GHG emissions of gasoline/ethanol blends in the Canadian light-duty fleet from 2018 to 2030 under several mid-level ethanol blend deployment scenarios. To that end, we develop a Canadian light-duty vehicle fleet model to explore scenarios that estimates the number of vehicles by vehicle technology and production year from 2015 to 2030, and their fuel blend compatibility. Then, we estimate the annual fuel use by fuel blend considering the effects of ethanol level on vehicle fuel consumption. We develop three hypothetical scenarios regarding the deployment of three fuel blends: E10, E15 and E25. Finally, we calculate the associated WTW GHG emissions of gasoline and ethanol from emission factors of GHGenius v5.0a simulated from 2015 to 2030.

First, we estimate that the Canadian light-duty fleet will increase from 23 million vehicles in 2018 to 28 million vehicles in 2030 and will still be dominated by internal combustion engine vehicles using gasoline (at 88% in 2030). We find that the deployment of E10 across the entire Canadian fleet beyond the current (2018) average of E7, would result in an increase in the annual ethanol volume of 1.3 billion liters, a decrease in gasoline blendstock volume by 1.1 billion liters and a reduction in annual GHG emissions by 2.1 megatonnes carbon dioxide equivalent (Mt CO2 eq.) in 2030. The penetration of E15 and E25 compatible vehicles and the deployment of E15 and E25 blends starting in 2020 could provide 2.7 and 0.3 Mt CO2 eq. in annual GHG emission reductions in 2030, respectively. The small contribution to the reductions from the use of E25 relates largely to the timing of its introduction and assumed relatively modest penetration, even by 2030. Currently, only flex fuel vehicles (representing 2.2 million vehicles in 2018) can use E25 blends. The deployment of E10, E15 and E25 as per the three scenarios could reduce the annual Canadian fleet GHG emissions from gasoline and (grain-derived) ethanol from 99.8 to 94.7 Mt CO2 eq. in 2030 (or 5%) and the cumulative GHG emissions from 2018 to 2030 from 1.80 to 1.76 Gt CO2 eq. (i.e., 37.7 Mt CO2 eq. reductions or 3%). We conduct sensitivity analysis on the parameters evaluated as sensitive and outline the range of reductions from 46 to 33 Mt CO2 eq. reductions in cumulative GHG emissions.

Our study offers insights on the role of ethanol to meet the GHG emission target of Canada and outline the potential challenges faced by mid-level ethanol blends.



11:10am - 11:30am

Life Cycle Greenhouse Gas and Criteria Air Pollutant Emissions from Alternative Marine Fuels

Troy R Hawkins1, Uisung Lee1, Michael Q Wang1, Tom Thompson2

1Argonne National Laboratory, U.S. Dept of Energy; 2Maritime Administration, U.S. Dept of Transportation

The marine transportation industry is poised to make significant decisions regarding how to respond to fuel sulfur limits set by the International Maritime Organization (IMO) which become effective in 2020. At present, most marine transportation is fueled by heavy fuel oil with a sulfur content of up to 3.5% with marine gas oil comprising a smaller share of the total. The new IMO rules limit marine fuel sulfur content to 0.5% beginning January 1, 2020. This level puts considerable pressure on refineries producing heavy fuel oil for marine markets due to the cost associated with reducing sulfur content.

The sulfur limits present an opportunity for alternative marine fuels and drivetrains moving forward. Our project was motivated by the desire to consider biofuels for marine applications due to their naturally low sulfur content and their potential to reduce greenhouse gas and criteria pollutant emissions. While the sulfur limits will provide significant benefits in terms of air quality and human health, they have the unfortunate side effect of causing a slight increase in global warming effect. This is due to the interaction between sulfur dioxide and aerosols which directly reflect sunlight.

This study considers straight soybean oil, Fischer-Tropsch diesel, and biodiesel produced from hydrotreated vegetable oil, liquefied natural gas, and compares these fuels to conventional and low-sulfur heavy fuel oil and marine gas oil. The scope of the study includes the full life cycle of each fuel, from feedstock production, through conversion, distribution, and use. This presentation will focus on preliminary results for emissions of greenhouse gases and criteria air pollutants. Marine fuels are an interesting case for life cycle assessment. They differ from transportation fuels for cars and trucks which are more typically the subject of LCA studies due to differences in distribution, the extremely large scale of the engines in which they are used, and because of the low price of the residual HFO which currently provides the largest share of fuel for marine transportation. Our preliminary results find that biofuels have lower life cycle GHG and SOx emissions (6-33% and 0.4-1.9% respectively) compared to those of conventional heavy fuel oil. The findings of this work are planned for incorporation in a new marine fuels module in the Greenhouse Gases, Regulated Emissions, and Energy Use in Transportation (GREET) to be released next fall.



11:30am - 11:50am

Recycling of almond residues via gasification for almond processing and preservation

Jin Wook Ro, Alissa Kendall, Edward Spang

University of California, Davis, United States of America

California produces about 80% of the global commercial almond supply, making it the largest almond producer in the United States and in the world. Almond orchards produce four different types of products; almond kernels, hulls, shells, and other woody biomass. Among these products, only kernels are consumed as food, and the others are considered to be co-products, by-products, or wastes. However, the quantity of these products, particularly hulls and shells, are not negligible. The whole almond fruit consists of 27 percent kernel, 54 percent hull, and 19 percent shell by mass. Almond hulls, which are the ‘fruit’ portion of almonds, are frequently used as dairy feed, but this market is shrinking. Shells, which are the ‘woody’ portion of almonds, are used in very low value functions, such as livestock bedding material. For these reasons, almond hulls and shells may be available for other uses with higher values such as energy production. Meanwhile, the almond supply chain requires considerable energy in forms of electricity, steam, and heat for manufacturing processes. The typical almond supply chain consists of three main components; orchard cultivation, hulling and shelling sites, and processors. Once harvested from the orchard, almonds go to hulling and shelling sites, and then are transported to processors where almonds are packaged and distributed as raw, or processed by roasting, blanching, slicing, or milling. In between, cold storage is often used to maintain the quality of almonds. Thus, if utilization of almond hulls and shells could generate enough energy for the almond supply chain, they could potentially contribute to lower environmental impacts and improved profits.

This study considers two scenarios for repurposing almond hulls and shells as feedstocks for gasification; one using both almond hulls and shells and one using only almond shells. The two major differences between these scenarios are the total amount available and the composition of feedstock including moisture content and volatile matter. Utilization of both almond hulls and shells showed higher potential electricity generated per year due to the larger available amount of feedstock. Using only almond shells showed higher yield of electricity per mass of feedstock due to the lower moisture content and more volatile matter. From the techno-economic assessment, the results suggest that almond shells have a great potential for cost-effective electricity generation as well as reduced environmental impacts. If the total almond shells generated in California were converted to electricity via a gasification process, they could generate about three times the amount of electricity than current electricity consumption of statewide almond processing and would reduce statewide greenhouse gas emissions by more than 165,000 tonnes of carbon dioxide equivalent.