The corresponding life cycle GHG emissions from producing jet fuel from Canadian oil sands are shown in Table 20. Recall that the low emissions value represents the low case for surface mining while the high emissions value represents the high case for in-situ recovery.
Table 20: Summary of result for jet fuel from Canadian oil sands
Low Baseline High
Life Cycle CO2 Emissions by Stage
Recovery of feedstock (gCO2/MJ) 14.6 19.7 54.4
Transportation of feedstock (gCO2/MJ) 1.3 1.3 1.7 Processing of feedstock to fuel (gCO2/MJ) 5.5 5.5 5.5 Transportation of jet fuel (gCO2/MJ) 0.5 0.5 0.7
Combustion CO2 (gCO2/MJ) 73.2 73.2 73.2
WTT GHG Emissions by Species
WTT CO2 emissions (gCO2/MJ) 21.9 27.1 62.3
WTT CH4 emissions (gCO2e/MJ) 2.7 3.0 3.3
WTT N2O emissions (gCO2e/MJ) 0.1 0.1 0.2
Total WTW GHG Emissions (gCO2e/MJ) 97.9 103.4 139.0 Life Cycle GHG Emissions Relative to
Baseline Conventional Jet Fuel 1.12 1.18 1.59
The life cycle GHG emissions of the production and use of jet fuel from Canadian oil sands range from 1.12 to 1.59 times higher than those from the production and use of conventional jet fuel.
This analysis has only considered the use of natural gas as a process fuel and source of hydrogen. Although natural gas is currently the main source of energy for oil sands production, its use may not be sustainable in the long term. To reduce dependence on natural gas, coal and asphaltene (a bitumen residue) were considered as an alternative energy sources. Though abundant, the use of coal and bitumen upgrading residues can result in greater GHG emissions compared to the use of natural gas. Specifically, using coal energy to power bitumen production and asphaltene gasification to provide hydrogen for bitumen upgrading, the life cycle GHG emissions from surface-mining and in-situ production are 1.3 times and 1.6 times greater than those of conventional jet fuel, respectively. Even when carbon capture is used to reduce emissions from the gasification of asphaltene, the life cycle GHG emissions from surface-mining and in-situ production are still about 1.2 times and 1.5 times greater than those of conventional jet fuel, respectively.
of oil shale to shale oil and shale gas on the surface takes place at higher temperatures than the in situ technique. The higher temperatures could result in the decomposition of the carbonate minerals contained within the oil shale, potentially releasing considerably more CO2 than the Shell ICP process.17
5.2.1 Analysis Methodology
The pathway for the extraction of shale oil from oil shale using the Shell ICP is not available in GREET and was analyzed based on incorporating information available from the literature into the GREET framework. Specifically, the process energy for the production of shale oil from oil shale, as well as the yield of oil and gas products using the Shell ICP, were adopted from Brandt’s analysis of the Green River Formation in Colorado, Utah, and Wyoming (Brandt, 2008).
This analysis was specifically focused on the Green River Formation; however, many other oil shale resources are dispersed around the world.18
Only major process energy demands, namely the in situ heating energy and the energy to maintain the frozen wall (about one order of magnitude less than the in situ heating energy) were considered.19 The effects of different amounts and sources of in-situ heating energy on the overall GHG emissions of this pathway were explored with the low emissions, baseline and high emissions scenarios. The low and baseline cases assumed that 25% of the in situ heating energy needed was provided through the recycling of waste heat (as was assumed in the low carbon case in Brandt’s analysis), while no recycling of waste heat was assumed in the high case. As a large amount of electrical energy is needed to provide in-situ heating for the Shell ICP, dedicated coal-based power generation facilities were assumed to be near the extraction site due to the vast abundance of coal resources in the Green River Formation. The locality of electricity was assumed to reduce transmission losses to 5% from the GREET default value of 8%. For the low case, the use of coal IGCC electricity with carbon capture (90% efficiency) was assumed;20 while the baseline and high cases employ traditional pulverized coal-fired electricity without carbon capture.
Brandt (2008) provided low and high estimates of the electrical energy required for in situ heating, the amount of shale oil output and the amount of shale gas co-produced. There is no natural gas consumption within the process; therefore, energy and emission credits were given to the natural gas co-produced using the displacement method.21 The low emissions scenario used the low value for in situ heating energy with high values for shale oil and shale gas production; the baseline scenario used mean values; and the high emissions scenario used high value for in situ heating energy with low values for shale oil and shale gas production. In addition, shale oil is much lighter and contains almost no heavy ends compared to traditional crude oil; hence, the
17 Typical oil shale from the Green River Formation is composed of 23% dolomite (calcium-magnesium bicarbonate) and 16% calcite (calcium carbonate). Surface conversion processes require up to 750°C while the decomposition of dolomite and calcite occur around 575°C and 650°C, respectively. The Shell ICP process takes place at temperatures between 340°C and 400°C. Because of this increased temperature, production of shale oil using surface retorting could result in between 1.2 to 3 times more GHG emissions than if the production had been performed using the Shell ICP process.
(Hileman et al., 2009)
18 There are known oil shale formations in Australia, Brazil, Canada, China, Estonia, Israel, Jordan, Morocco, Russia, Sweden, Syria, Thailand, Turkey and the United States (Geology.com, 2009)
19 Other minor process energy requirements like drilling and pumping energy (< 1% of retorting energy), as well as energy needed for infrastructural construction, are ignored in this study.
20 From Deutch and Moniz (2007), the estimated efficiency of an IGCC plant with 90% carbon capture is 31.2% (HHV) or about 34% (31.2+3) on a LHV basis. The efficiency of 34% (LHV) was adopted in this study.
21 The displacement (system expansion) method was used to account for energy and emission credits to natural gas, i.e., the natural gas produced was assumed to displace the recovery and processing of conventional petroleum based natural gas in a separate, independent facility.
refining efficiency of processing shale oil to jet fuel was assumed to be higher (~2-3%) than that of refining traditional crude oil.22
The key processes and assumptions involved in the production of jet fuel from oil shale using the Shell ICP are summarized in Table 21.
Table 21: Input assumptions for the production of jet fuel from oil shale for low emissions, baseline and high emissions cases
Low Baseline High
Process conditions
Use 25% recycled heat for retorting; use
coal IGCC electricity with CCS; capture
efficiency of 90%
Use 25% recycled heat for retorting;
use 100% coal- fired electricity; no
carbon capture
No recycled heat used; 100%
coal-fired electricity; no carbon capture Electrical energy input
(J/MJ shale oil produced) 134600 148100 211900
Natural gas co-produced (J/MJ shale oil produced) (LHV)
223700 189600 152500
Refining efficiency (LHV) 96% 96% 96%
5.2.2 Oil Shale to Jet Fuel Results
The GHG emissions from the production and use of jet fuel from oil shale using the Shell ICP are shown in Table 22.
Table 22: Summary of results for jet fuel from in situ oil shale pathway
Low Baseline High
Life Cycle CO2 Emissions by Stage
Recovery of feedstock (gCO2/MJ) 3.6 41.2 59.7
Transportation of feedstock (gCO2/MJ) 0.5 0.6 0.7 Processing of feedstock to fuel (gCO2/MJ) 3.3 3.3 3.3 Transportation of jet fuel (gCO2/MJ) 0.5 0.6 0.7
Combustion CO2 (gCO2/MJ) 73.2 73.2 73.2
WTT GHG Emissions by Species
WTT CO2 emissions (gCO2/MJ) 7.8 45.8 64.4
WTT CH4 emissions (gCO2e/MJ) 2.4 2.5 3.2
WTT N2O emissions (gCO2e/MJ) 0.6 0.2 0.2
Total WTW GHG Emissions (gCO2e/MJ) 84.1 121.6 141.0 Life Cycle GHG Emissions Relative to
Baseline Conventional Jet Fuel 0.96 1.39 1.61
With carbon capture (low emissions case), the life cycle GHG emissions of jet fuel from oil shale are reduced to slightly less than baseline conventional jet fuel. Without the capture of carbon dioxide from coal-based electricity plants providing the in situ heating energy, the production of jet fuel from oil shale produces life cycle GHG emissions 1.4 to 1.6 times greater than baseline conventional jet fuel.
In addition to increased GHG emissions, oil shale development also presents other adverse impacts to the environment. Though less intrusive to the surface topography than ex situ processes and not requiring the disposal of spent shale, in-situ conversion will still cause displacement of all other land uses in the area and disruptions to the local ecological community
22 Jim Bartis, interview with Hsin Min Wong, July 16, 2007.
(Bartis et al., 2005). In situ methods also have the potential to cause ground water contamination.
Though the freeze wall protects groundwater during production, contamination may occur post- production. As the Green River formation lies within the Colorado River drainage basin, water contamination could impact millions of downstream users (Gruenwald, 2006).
6 Fischer-Tropsch Jet Fuel
The Fischer Tropsch (F-T) process first involves the steam reforming or gasification of any carbon containing feedstock (e.g. natural gas, coal or biomass) to synthesis gas (syngas), which is a mixture of hydrogen and carbon monoxide. The syngas is subsequently converted to paraffinic hydrocarbons in the presence of an iron- or cobalt-based catalyst (Fischer-Tropsch synthesis). A third upgrading step cracks the longer hydrocarbon chains to maximize the production of synthetic paraffinic liquid fuels like diesel and jet fuel. Syngas must be cleaned before Fischer- Tropsch synthesis step to remove contaminants, particularly sulfur, to avoid poisoning the catalyst. Hence, the resultant Fischer-Tropsch liquid fuels are virtually free of contaminants and the jet fuel fraction of the product slate falls into the category of synthetic paraffinic fuels.
All jet fuels produced using F-T synthesis have similar characteristics, independent of feedstock type. Any small variations in fuel properties are primarily associated with the operating conditions (e.g., catalyst, temperature, and pressure) within the synthesis reactors and how the direct products of the synthesis are treated and processed. All jet fuels produced using the F-T process share common characteristics with regard to compatibility with existing infrastructure and aircraft, combustion emissions, and their relative merit for use in aviation. Feedstock choice, however, does have a strong influence on fuel production capacity, production cost, life cycle greenhouse gas emissions, and technology readiness (Hileman et al., 2009).
Fischer-Tropsch fuels created from natural gas, coal, biomass and combinations of coal and biomass were analyzed in this work. Gas-to-Liquid (GTL) production is currently limited to Malaysia where Shell has been producing approximately 15,000 bbl/day since 1993. Sasol as well as Shell in collaboration with Qatar Petroleum are both constructing GTL facilities in Qatar with design capacities of 34,000 bbl/day and 140,000 bbl/day, respectively. Existing coal-to- liquids (CTL) capacity is limited to Sasol in South Africa where a production capacity of 160,000 bbl/day of oil equivalent has been consistently maintained. There is no commercial scale production of F-T fuels using biomass as the feedstock (BTL). This technology is still in the development phase; however, a German firm, CHOREN, began start-up operations of a 300 bbl/day facility in 2008 and Solena Group, with Rentech, announced plans for a 1,800 bbl/day BTL facility located in Gilroy, California. Experience with simultaneously gasifying a combination of coal and biomass in a single gasifier is presently limited to successful tests at an IGCC plant in the Netherlands (Hileman et al., 2009). The analysis of F-T jet fuel from coal and natural gas was conducted using GREET version 1.8a while F-T jet fuel from biomass and the combination of coal and biomass was considered using GREET version 1.8b.