Canadian Oil Sands: Life-Cycle Assessments
of Greenhouse Gas Emissions
Richard K. Lattanzio
Analyst in Environmental Policy
May 15, 2012
Congressional Research Service
7-5700
www.crs.gov
R42537
CRS Report for Congress
Pr
epared for Members and Committees of Congress

Canadian Oil Sands: Life-Cycle Assessments of Greenhouse Gas Emissions

Summary
Canadian Oil Sands and Climate Change
Recent congressional interest in U.S. energy policy has focused in part on ways through which
the United States could secure more economical and reliable crude oil resources both
domestically and internationally. Many forecasters identify petroleum refined from Canadian oil
sands as one possible solution. Increased petroleum production from Canadian oil sands,
however, is not without controversy, as many have expressed concern over the potential
environmental impacts. These impacts may include increased water and natural gas use,
disturbance of mined land, effects on wildlife and water quality, trans-boundary air pollution, and
emissions of greenhouse gases (GHG) during extraction and processing. A number of key studies
in recent literature have expressed findings that GHG emissions from the production of Canadian
oil sands crudes may be higher than those of other crudes imported, refined, and consumed in the
United States. The studies identify two main reasons for the increase: (1) oil sands are heavier and
more viscous than lighter crude oil types on average, and thus require more energy- and resource-
intensive activities to extract; and (2) oil sands are compositionally deficient in hydrogen, and
have a higher carbon, sulfur, and heavy metal content than lighter crude oil types on average, and
thus require more processing to yield consumable fuels.
Selected Findings from the Primary Published Studies
CRS surveyed the available literature, including the U.S. Department of State-commissioned
study in the Environmental Impact Statement for the Keystone XL pipeline project. The literature
reveals the following:
• despite differences in the design and input assumptions of the various studies,
Canadian oil sands crudes are on average somewhat more GHG emission-intensive
than the crudes they would displace in the U.S. refineries, with a range of increase
from 14%-20% over the average Well-to-Wheel emissions of other imported crudes;
• discounting the final consumption phase of the life-cycle assessment (which can
contribute up to 70%-80% of Well-to-Wheel emissions), Well-to-Tank (i.e.,
production) emissions from Canadian oil sands crudes have a range of increase from
72%-111% over the average Well-to-Tank emissions of other imported crudes;
• Canadian oil sands crudes, on a Well-to-Wheel basis, range from 9%-19% more
emission-intensive than Middle Eastern Sour, 5%-13% more emission-intensive than
Mexican Maya, and 2%-18% more emission-intensive than various Venezuelan
crudes;
• the estimated effect of the proposed Keystone XL pipeline on the U.S. GHG footprint
would be an increase of 3 million to 21 million metric tons of GHG emissions
annually (equal to the annual GHG emissions from the combustion of fuels in
approximately 588,000 to 4,061,000 passenger vehicles); and
• the estimated effect of the Keystone XL pipeline on global GHG emissions remains
uncertain, as some speculate that its construction would encourage an expansion of
oil sands development, while others suggest that the project would not substantially
influence either the rate or magnitude of oil extraction activities in Canada or the
overall volume of crude oil transported to and refined in the United States.
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Canadian Oil Sands: Life-Cycle Assessments of Greenhouse Gas Emissions

Scope and Purpose of This Report
After discussing the basic methodology of life-cycle assessments and examining the choice of
boundaries, design features, and input assumptions, this report compares several of the publicly
available assessments of life-cycle emissions data for Canadian oil sands crudes against each
other and against those of other global reference crudes. Further, as congressional concern over
the environmental impacts of Canadian oil sands production may encompass both a broad
understanding of the global resource as well as a specific assessment of the proposed Keystone
XL pipeline, the report surveys both the general scientific literature as well as the individual
findings of the State Department’s Keystone XL Project Environmental Impact Statement.
Finally, as life-cycle assessments have become an influential—albeit developing—methodology
for collecting, analyzing, and comparing GHG emissions, the report concludes with a discussion
of some tools for policymakers who are interested in using these assessments to investigate the
potential impacts of U.S. energy policy choices on the environment.
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Canadian Oil Sands: Life-Cycle Assessments of Greenhouse Gas Emissions

Contents
Introduction...................................................................................................................................... 1
Life-Cycle Assessment Methodology.............................................................................................. 2
Results of Selected Life-Cycle Emissions Assessments.................................................................. 6
Life-Cycle Assessments of Canadian Oil Sands........................................................................ 6
Findings............................................................................................................................... 8
Design Factors and Input Assumptions for Canadian Oil Sands Assessments.................. 15
Life-Cycle Assessments of Canadian Oil Sands versus Other Reference Crudes................... 19
Findings............................................................................................................................. 19
Design Factors and Input Assumptions for Reference Crudes Assessments..................... 21
Life-Cycle Assessments of Canadian Oil Sands versus Other Fuel Resources....................... 22
U.S. Carbon Footprint for the Keystone XL Pipeline.................................................................... 23
Further Considerations................................................................................................................... 24

Figures
Figure 1. Crude Oil Life-Cycle Schematic ...................................................................................... 3
Figure 2. Well-to-Wheel GHG Emissions Estimates for Canadian Oil Sands Crudes .................... 9
Figure 3. Well-to-Wheel GHG Emissions Estimates for Global Crude Resources ....................... 20
Figure 4. Life-Cycle GHG Emissions Estimates for Selected Fuel Resources.............................. 23

Tables
Table 1. Life-Cycle Assessments of Canadian Oil Sands ................................................................ 7
Table 2. Reported Findings of Well-to-Wheel GHG Emissions Estimates in the
Life-Cycle Assessments of Canadian Oil Sands Crudes ............................................................ 10
Table 3. Potential GHG Mitigation Activities in Canadian Oil Sands Production ........................ 25

Contacts
Author Contact Information........................................................................................................... 26
Acknowledgments ......................................................................................................................... 26

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Canadian Oil Sands: Life-Cycle Assessments of Greenhouse Gas Emissions

Introduction
Recent congressional interest in U.S. energy policy has focused in part on ways through which
the United States could secure more economical and reliable crude oil resources both
domestically and internationally. Many forecasters identify petroleum products refined from
Canadian oil sands1 crude as one possible solution. Canadian oil sands account for about 46% of
Canada’s total oil production, and that number is expected to rise from its current level of 1.2
million barrels per day (mbd) to 2.8 mbd by 2015.2 Further, the infrastructure to produce,
upgrade, refine, and transport the resource from Canadian oil sand reserves to the United States is
in place, and additional infrastructure projects—such as the Keystone XL pipeline—have been
proposed.3 Increased oil production from Canadian oil sands, however, is not without controversy,
as many have expressed concern over the potential environmental impacts. These impacts may
include increased water and natural gas use, disturbance of mined land, effects on wildlife and
water quality, trans-boundary air pollution, and emissions of greenhouse gases (GHG) during
extraction and processing.
A number of key studies in recent literature have expressed findings that GHG emissions from the
production of Canadian oil sands crudes may be higher than those of other crudes imported,
refined, and consumed in the United States.4 While GHG emissions and other air quality issues
originating in the upstream sectors of Canada’s petroleum industry do not directly impact U.S.
National Emissions Inventories or U.S. GHG reporting per se, many environmental stakeholders
and policymakers have noted that the increased use of more emission-intensive resources in the
United States may have negative consequences for both U.S. and global energy policy and
environmental compliance.
The U.S. Department of State (DOS), in response to comments on the draft Environmental
Impact Statement (EIS) for the Keystone XL pipeline project (which would connect oil sands
production facilities in the Western Canadian Sedimentary Basin with refinery facilities in the
United States), commissioned a contractor’s study on the GHG life-cycle emissions associated
with these resources in comparison to other reference crudes.5 DOS presented this analysis in the
Final EIS as a “matter of policy,” and noted that neither the National Environmental Policy Act
(NEPA) nor DOS regulations (22 C.F.R. 161.12) nor Executive Orders 13337 and 12114
(Environmental Effects Abroad of Major Federal Activities) legally require that an EIS include an
assessment of environmental activities outside the United States. In the Final EIS, DOS supported
the claim that while the proposed Keystone XL pipeline project may contribute to certain trans-
boundary and continental scale environmental impacts, it may not substantially influence either

1 The resource has been referred to by several terms, including oil sands, tar sands, and, most technically, bituminous
sands. Because of its widespread use in academic literature, the term “oil sands” is used in this report.
2 For more information on oil sands resources, see CRS Report RL34258, North American Oil Sands: History of
Development, Prospects for the Future, by Marc Humphries.
3 For a full analysis of TransCanada’s Keystone XL Pipeline project, see CRS Report R41668, Keystone XL Pipeline
Project: Key Issues, by Paul W. Parfomak et al., and CRS Report R42124, Proposed Keystone XL Pipeline: Legal
Issues, by Adam Vann et al.
4 A list of studies surveyed in this report can be found in Table 1; an account of the finding can be found in Table 2.
5 The full report by the State Department’s contractor, IFC International LLC, is found in U.S. Department of State,
Keystone XL Project, Final Environmental Impact Statement, Appendix V, “Life-Cycle Greenhouse Gas Emissions of
Petroleum Products from WCSB Oil Sands Crudes Compared with Reference Crudes,” July 13, 2011, at
http://www.keystonepipeline-xl.state.gov/.
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the rate or magnitude of oil extraction activities in Canada or the overall volume of crude oil
transported to and refined in the United States.6
This report presents a summary of a range of life-cycle emissions assessments of Canadian oil
sands crudes and provides an analysis of their respective findings. The first section of the report,
“Life-Cycle Assessment Methodology,” discusses the basic methodology of life-cycle
assessments and examines the choice of boundaries, design features, and input assumptions. The
second section of the report, “Results of Selected Life-Cycle Emissions Assessments,” compares
several of the publicly available assessments of life-cycle GHG emissions data for Canadian oil
sands crudes against each other, against those of other global reference crudes, and against those
of other fossil fuel resources. The third section, “U.S. Carbon Footprint for the Keystone XL
Pipeline,” examines some of the specific findings of the Department of State’s commissioned
study for the Keystone XL pipeline. The report concludes with a discussion of some tools for
policymakers who are interested in using these assessments to investigate the potential impacts of
U.S. energy policy choices on the environment.
Life-Cycle Assessment Methodology
Life-cycle assessment (LCA) is an analytic method used for evaluating and comparing the
environmental impacts of various products (in this case, the climate change implications of
hydrocarbon resources). LCAs can be used in this way to identify, quantify, and track emissions
of carbon dioxide and other GHG emissions arising from the development of these hydrocarbon
resources, and to express them in a single, universal metric of carbon dioxide equivalent (CO2e)
GHG emissions per unit of fuel or fuel use.7 The results of an LCA can be used to evaluate the
GHG emissions intensity of various stages of the fuel’s life cycle, as well as to compare the
emissions intensity of one type of fuel or method of production to another.
GHG emissions profiles modeled by most LCAs are based on a set of boundaries commonly
referred to as “cradle-to-grave,” or, in the case of transportation fuels such as petroleum, “Well-
to-Wheel” (WTW). WTW assessments for petroleum-based transportation fuels focus on the
emissions associated with the entire life cycle of the fuel, from extraction, transport, and refining
of crude oil, to the distribution of refined product (e.g., gasoline, diesel, jet fuel) to retail markets,
to the combustion of the fuel in end-use vehicles. Other LCAs (e.g., Well-to-Tank (WTT) or Well-
to-Refinery Gate (WTR)) establish different (i.e., more specific) life-cycle boundaries to evaluate
emissions (see Figure 1). Inclusion of the final combustion phase allows for the most complete
picture of crude oil’s impact on GHG emissions, as this phase can contribute up to 70%-80% of
WTW emissions. However, other LCAs can be used to highlight the differences in upstream
emissions associated with particular stages as well as experiment with certain boundary

6 Several of the studies, however, question this finding, and in particular, whether the production of Canadian oil sands
crude would be economically viable if not exported through pipelines to the United States. See, for example, Natural
Resources Defense Council, “Say No to Tar Sands Pipeline,” March 2011, at http://www.nrdc.org/land/files/
TarSandsPipeline4pgr.pdf.
7 Greenhouse gases include carbon dioxide (CO2), methane (CH4), nitrous oxide (N2O), hydrofluorocarbons (HFCs),
perfluorocarbons (PFCs), and sulfur hexafluoride (SF6), among many others. In order to compare and aggregate
different greenhouse gases, various techniques have been developed to index the effect each greenhouse gas has to that
of carbon dioxide, where the effect of CO2 equals one. When the various gases are indexed and aggregated, their
combined quantity is described as the CO2-equivalent. In other words, the CO2-equivalent quantity would have the
same effect on, say, radiative forcing of the climate, as the same quantity of CO2.
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assumptions. The choice of boundaries is an important component to any LCA: the more specific
a study draws the bounds of its assessment, the more amplified the differences may appear across
resources.8
Because of the complex life cycle of hydrocarbon fuels and the large number of analytical design
features that are needed to model their emissions, LCAs must negotiate many variables and
uncertainties in available data. Key factors that influence the results of an LCA include (1)
composition of the resource that is modeled, (2) extraction process of the resource that is
modeled, (3) design factors chosen for the assessment, and (4) assumptions made in the input data
for the assessment.
Figure 1. Crude Oil Life-Cycle Schematic

Source: Jacobs Consultancy, Life Cycle Assessment Comparison of North American and Imported Crudes, Alberta
Energy Research Institute and Jacobs Consultancy, 2009.
Crude Oil Types. Oil sands are a type of unconventional petroleum deposit. They are commonly
loose sand or partially consolidated sandstone containing naturally occurring mixtures of sand,
clay, and water, as well as a dense and extremely viscous form of petroleum technically referred
to as bitumen.9 Most LCAs do not include an assessment of raw bitumen, because it is near solid
at ambient temperature and cannot be transported in pipelines or processed in conventional
refineries. Thus, bitumen is often diluted with liquid hydrocarbons or converted into a synthetic
light crude oil to produce the resource known as oil sands crude. Several kinds of crude-like

8 A study’s choice of boundaries is responsible for many of the vastly differing values for GHG emissions that are
currently being reported in published studies of the Canadian oil sands relative to other reference crudes. For example,
when expressed on a WTT basis rather than on a WTW basis, GHG emissions from Canadian oil sands crudes may
show values that are significantly higher than reference crudes due to the technical omission of combustion from the
calculation (see the reported findings in subsequent sections for examples).
9 For more technical information on bitumen, see CRS Report RL34258, North American Oil Sands: History of
Development, Prospects for the Future, by Marc Humphries; and, for example, National Petroleum Council, Heavy Oil,
Topic Paper #22, July 18, 2007, at http://www.npc.org/study_topic_papers/22-ttg-heavy-oil.pdf.
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products can be generated from bitumen, and their properties differ in some respects from
conventional light crude. They include:
• Upgraded Bitumen, or Synthetic Crude Oil (SCO). SCO is produced from
bitumen through an upgrading process that turns the very heavy hydrocarbons
into lighter fractions. Since the upgrading process begins at the production
facility for SCO, the allocation of GHG emissions is weighted more heavily
upstream than other crude types.
• Diluted Bitumen (Dilbit). Dilbit is bitumen mixed with diluents—typically
natural gas liquids such as condensate—to create a lighter, less viscous, and more
easily transportable product. Mixing bitumen with less carbon-intensive diluents
lessens the GHG emissions impact per barrel of dilbit in relation to bitumen or
SCO. Some refineries need modifications to process large quantities of dilbit
feedstock, since it requires more heavy oil conversion capacity than conventional
crudes. Increased processing in refineries shifts GHG emissions downstream,
potentially intensifying the downstream GHG emission impact of dilbit in
relation to SCO or other crudes (e.g., if dilbit is transported from Canada to the
United States via a pipeline, the need for increased refining downstream would
shift the potential for emissions to the United States).
• Synthetic Bitumen (Synbit). Synbit is typically a combination of bitumen and
SCO. The properties of each kind of synbit blend vary significantly, but blending
the lighter SCO with the heavier bitumen results in a product that more closely
resembles conventional crude oil. Refining emissions from synbit occur both
upstream and downstream, depending upon a variety of factors.
Extraction Process. Two types of methods for extracting bitumen from the reservoir are
currently used in the Canadian oil sands. They include:
• Mining. Oil sands deposits that are less than approximately 75 meters below the
surface can readily be removed using conventional strip-mining methods. An
estimated 20% of currently recoverable reserves are close enough to be mined.
The strip-mining process includes removal of the overburden (i.e., primary soils
and vegetation), excavation of the resource, and transportation to a processing
facility. Mining accounts for slightly more than 50% of current production, and is
expected to remain 40%-50% through 2030.10
• In-Situ. Oil sands deposits that are deeper than approximately 75 meters are
recovered using in-situ methods. Most in-situ recovery methods currently in
operation involve injecting steam into an oil sands reservoir to heat—and thus
decrease the viscosity of—the bitumen, enabling it to flow out of the reservoir to
collection wells. Steam is injected using cyclic steam stimulation (CSS), where
the same well cycles both the steam and the bitumen, or by steam-assisted gravity
drainage (SAGD), where a top well is used for steam injection and the bottom
well is used for bitumen recovery. Because significant amounts of energy are
currently required to create steam, in-situ methods are generally more GHG-

10 Predictions range from 50% in IHS CERA, Oil Sands, Greenhouse Gases, and U.S. Oil Supply: Getting the Numbers
Right, IHS Cambridge Energy Research Associates, Inc., 2010, to 40% in Canadian Association of Petroleum
Producers, “Crude Oil Forecast,” June 2011.
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intensive than conventional mining (excluding land use impacts). With over 80%
of recoverable reserves situated too deep for conventional mining techniques, it is
assumed that the industry will eventually move toward an increased use of the in-
situ extraction process in some form.
Study Design Factors. Design factors relate to how the GHG comparison is structured in each
study and which parameters are included. These factors may include:
• overall purpose and goal of the study,
• time frame for the inputs and the results,
• life-cycle boundaries that are established for comparison,
• units and metrics used for comparison,
• GHG global-warming potential used for comparison,11
• treatment of co-products during refining (e.g., asphalt, petroleum coke, liquid
gases, lubricants),
• treatment of secondary emission flows (e.g., capital infrastructure, land-use
changes),12
• treatment of power co-generation at the facilities, and
• treatment of flaring, venting, and fugitive emissions.
Input Assumptions. Input assumptions can impact life-cycle results at each stage of the
assessment. Studies often use simplified assumptions to model GHG emissions due to limited
data availability and the complexity of and variability in the practices used to extract, process,
refine, and transport crude oil, diluted crude, or refined product. Key input assumptions for
Canadian oil sands crude may include:
• percentage contribution of each type of crude and each type of extraction process
in the final transported product,
• type of upgrading or refining processes,
• amount of petroleum coke produced, stored, combusted, or sold,
• steam-to-oil ratio for in-situ extraction,
• bitumen-to-diluents ratio for dilbit, and
• energy efficiency of steam generation and other production processes.

11 Global-warming potential (GWP) is a relative measure of how much heat a greenhouse gas traps in the atmosphere.
It compares the amount of heat trapped by a certain mass of the gas in question to the amount of heat trapped by a
similar mass of carbon dioxide. A GWP is calculated over a specific time interval, commonly 20, 100, or 500 years. All
data included in this report use a 100-year time interval.
12 LCAs often characterize emissions into primary and secondary flows. Primary flows are associated with the various
stages in the hydrocarbon life cycle, from extraction of the resource to the combustion of the final refined fuel. Primary
flows are generally well understood and included in most LCAs. Secondary flows are associated with activities not
directly related to the conversion of the hydrocarbon resource into useful product (e.g., local and indirect land-use
changes, construction emissions, etc.). Because these flows are outside the primary operations, they are often
characterized differently across studies or excluded from LCAs altogether.
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Results of Selected Life-Cycle Emissions
Assessments
Life-Cycle Assessments of Canadian Oil Sands
Greenhouse gases, primarily in the form of carbon dioxide and methane, are emitted during a
variety of stages in oil sands production (see text box below for a summary).13 A number of
published and publicly available studies have attempted to assess the life-cycle GHG emissions
data for Canadian oil sands crudes. This report examines the life-cycle assessments analyzed by
the U.S. Department of State (DOS)—in conjunction with the consultancy firm IFC International
LLC (IFC)—in the Keystone XL Project’s Final Environmental Impact Statement (Final EIS).
The studies were selected by IFC using several criteria: (1) they evaluated Canadian oil sands
crudes in comparison to other reference crude oils, (2) they focused on GHG emissions impacts
throughout the entire crude oil life-cycle, (3) they were published within the past 10 years, and (4)
they represented the perspectives of a range of stakeholders.
Table 1 provides a list of the studies referenced by the IFC analysis. While the type, boundaries,
and design features vary across all studies, DOS and IFC determined the data and results from
AERI/Jacobs 2009, AERI/TIAX 2009, NETL 2008, and NETL 2009 to be sufficiently robust for
inclusion in the Final EIS. Reasons against the inclusion of the remaining studies are presented
briefly in the table, and outlined in more detail in the Final EIS.

Summary of the Potential Sources of GHG Emissions in Oil Sands Development
•
land use changes (emissions from the removal of vegetation and trees, soil, and peatland for mining or facilities),
•
capital equipment (emissions from the construction of facilities, machinery, or other infrastructure),
•
upstream fuels (emissions from the upstream production of fuel or electricity that is imported to the facility to
be used as process heat or power for machinery),
•
extraction (emissions from the bitumen extraction process, including equipment for mining and steam generation
for artificial lifting),
•
upgrading (emissions from the bitumen upgrading process and the combustion of co-products),
•
crude product transportation (emissions from the transportation of crude products and co-products),
•
refining (emissions from the crude oil refining process and the combustion of co-products),
•
fugitives (emissions from the venting or flaring of methane, or fugitive leaks at any stage of production),
•
refined product transportation (emissions from the transportation of final refined products and co-products),
•
combustion (emissions from the end-use combustion of the refined fuel and co-products).

13 For a discussion of the role and effects of greenhouse gases in climate change, see CRS Report RL34266, Climate
Change: Science Highlights, by Jane A. Leggett.
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Table 1. Life-Cycle Assessments of Canadian Oil Sands
As evaluated by DOS/IFC for inclusion in the Keystone XL Project Final EIS
Reference
Study
Years Type
Boundaries Design
Factors
Primary LCAs, the data from which are included in the Final EIS
AERI/Jacobs 2009
2000s
LCA
WTW
Al crudes
AERI/TIAX 2009
2007-2009
LCA
WTW
Al crudes
NETL 2008
2005
LCA
WTW
Al crudes
NETL 2009
2005
LCA
WTW
Al crudes
Other studies, the data from which are not included in the Final EIS
Charpentier 2009
1999-2008
Meta-analysis
WTW
Dilbit not analyzed
GREET 2010
Current
Model
WTW
SCO and dilbit unspecified
ICCT 2010
2009
Partial LCA
WTT
Only average mix of imports to
Europe analyzed
IEA 2010
2005-2009
Meta-analysis
WTW
Crude type not specified, results
compared on a per barrel basis
IHS CERA 2010
2005-2030
Meta-analysis
WTW
Al crudes, results compared on a per
barrel basis
McCann 2001
2007
LCA
WTW
SCO only, results compared on a per
liter basis
McCul och/Pembina
2002-2005
Partial LCA
WTR
SCO only, results compared on a per
2006
barrel basis
NRCan 2008
2008
LCA
WTW
Bitumen only, dilbit not analyzed
NRDC 2010
2006-2010
Meta-analysis
WTW
Al crudes
Pembina 2005
2000, 2004
Partial LCA
WTR
Crude composition not specified
RAND 2008
2000s
LCA
WTR
SCO only
Sources: Jacobs Consultancy, Life Cycle Assessment Comparison of North American and Imported Crudes, Alberta
Energy Research Institute and Jacobs Consultancy, 2009; TIAX LLC, Comparison of North American and Imported
Crude Oil Lifecycle GHG Emissions, Alberta Energy Research Institute and TIAX LLC, 2009; NETL, Development of
Baseline Data and Assessment of Life Cycle Greenhouse Gas Emissions of Petroleum-Based Fuels, National Energy
Technology Laboratory, November 26, 2008; NETL, An Evaluation of the Extraction, Transport and Refining of
Imported Crude Oils and the Impact of Life Cycle Greenhouse Gas Emissions, National Energy Technology Laboratory,
March 27, 2009; Charpentier, A.D., et al., “Understanding the Canadian Oil Sands Industry’s Greenhouse Gas
Emissions,” Environmental Research Letters, Vol. 4, January 20, 2009; GREET, Greenhouse Gases, Regulated Emissions,
and Energy Use in Transportation Model, Version 1.8d.1, Argonne National Laboratory, 2010; ICCT, Carbon
Intensity of Crude Oil in Europe Crude, International Council on Clean Transportation, 2010; IEA, World Energy
Outlook 2010, International Energy Agency, 2010; IHS CERA, Oil Sands, Greenhouse Gases, and U.S. Oil Supply:
Getting the Numbers Right, IHS Cambridge Energy Research Associates, Inc., 2010; McCann and Associates, Typical
Heavy Crude and Bitumen Derivative Greenhouse Gas Life Cycles in 2007, Prepared for Regional Infrastructure
Working Group by T. J. McCann and Associates Ltd., November 16, 2001; McCulloch, M., et al., Carbon Neutral
2020: A Leadership Opportunity in Canada’s Oil Sands, Oil Sands Issue Paper No. 2, Pembina Institute, October
2006; NRCan/(S&T)2, 2008 GHGenius Update, (S&T)2 Consultants report on model results prepared for Natural
Resources Canada, August 15, 2008; NRDC, GHG Emission Factors for High Carbon Intensity Crude Oils, Ver. 2,
Natural Resources Defense Council, September 2010; Pembina Institute, Oil Sands Fever: The Environmental
Implications of Canada’s Oil Sands Rush, November 2005; RAND Corporation. Unconventional Fossil-Based Fuels:
Economic and Environmental Trade-Offs, The RAND Corporation, 2008; U.S. Department of State, Keystone XL
Project, Final Environmental Impact Statement, Appendix V, “Life-Cycle Greenhouse Gas Emissions of Petroleum
Products from WCSB Oil Sands Crudes Compared with Reference Crudes,” July 13, 2011.
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Notes: According to the DOS/IFC evaluation: “Type” is considered sufficient when the study is a unique,
original assessment, and is not a meta-analysis that summarizes and averages the results from other sources;
“Boundaries” is considered sufficient when the study evaluates the ful WTW GHG emissions life cycle; “Design
Factors” is considered sufficient when the study includes and evaluates all crude types likely to be transported by
the Keystone XL pipeline. See DOS Final EIS, p. 40, for more on the DOS evaluation of each study.
Findings
Using data from various studies, the DOS/IFC analysis in the Final EIS finds the following:
• Well-to-Wheel GHG emissions of 91 gCO2e/megajoule (MJ) lower heating value
(LHV)14 gasoline for the average of imported transportation fuels to the United
States in the reference year of 2005.15
• Well-to-Wheel GHG emissions of, on average, 104-109 gCO2e/MJ LHV gasoline
for the weighted average16 of Canadian oil sands crudes likely to be transported
in the proposed Keystone XL pipeline project in the near term.
• An increase in Well-to-Wheel GHG emissions of 14%-20% for Canadian oil
sands crude over the 2005 average for all imported transportation fuels to the
United States.
• An increase in Well-to-Tank (i.e., “production”) GHG emissions of 72%-111%
for Canadian oil sands crude over the 2005 average production emissions for
imported transportation fuels to the United States (18 gCO2e/MJ).
Individual estimates of WTW GHG emissions from Canadian oil sands crude types and processes
from the secondary studies listed in Table 1 range from increases of 1%-41% over the baseline.
Figure 2 presents a summary of the WTW GHG emissions estimates for various Canadian oil
sands crude types and production processes as reported by each study. Table 2 summarizes and
compares each study’s emissions estimates, data, and relevant input assumptions used to identify
the key drivers in the life-cycle GHG emissions. Variability among the estimates is the result of
each study’s differing design and input assumptions. A discussion of these assumptions—and
their estimated effects on GHG emissions impacts—follows in the next section.

14 The heating value or energy value of gasoline is the amount of heat released during the combustion of a specified
amount of it. The quantity known as higher heating value (HHV) is determined by bringing all the products of
combustion back to the original pre-combustion temperature, and in particular condensing any vapor produced. The
quantity known as lower heating value (LHV) assumes that the latent heat of vaporization of water in the fuel and the
reaction products is not recovered. LHV is useful in comparing transportation fuels because condensation of the
combustion products is not practical.
15 This baseline value is based on NETL 2008. It assesses the emissions from a weighted average of imported
transportation fuels to the United States in 2005. It does not, however, include emissions from some of the most
carbon-intensive imported crude oils (e.g., Venezuelan Heavy) due to modeling uncertainties. This baseline is
consistent with the definitions for “baseline life-cycle greenhouse gas emissions” as used in the Energy Independence
and Security Act (EISA) of 2007 and the U.S. Renewable Fuel Standards Program of 2010.
16 Weighted average computations refer to the assumed mix of crude types and production processes that make up the
bulk of the final transported product (e.g., mining versus in-situ, SCO versus dilbit). The assumptions are based on
reported industry practices, and are reported differently in each study.
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Figure 2. Well-to-Wheel GHG Emissions Estimates for Canadian Oil Sands Crudes

Source: CRS, from studies outlined in Table 1. Average U.S. petroleum baseline for 2005 provided by U.S.
Environmental Protection Agency (U.S. EPA), Renewable Fuel Standard Program (RFS2): Regulatory Impact Analysis,
February 2010, EPA-420-R-10-006, with data sourced from DOE/NETL, Development of Baseline Data and Analysis
of Life Cycle GHG Emissions of Petroleum Based Fuels, November 2008.
Notes: See section “Life-Cycle Assessment Methodology” for key to crude oil types and production processes.
U.S. EPA 2005 (U.S. average) assesses a weighted average of al imported transportation fuels to the United
States in 2005, including Canadian oil sands. It does not include emissions from some of the most carbon-
intensive imported crude oils (e.g., Venezuelan Heavy) due to modeling uncertainties.
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Table 2. Reported Findings of Well-to-Wheel GHG Emissions Estimates in the
Life-Cycle Assessments of Canadian Oil Sands Crudes
WTW
Increase
Production
Crude
GHG
over
Study
Method
Type
Emissions Baseline
Key Assumptions
LCAs analyzed by IFC 2011
WTW GHG emissions expressed in gCO2e/MJ LHV gasoline
U.S. EPA
Baseline
Varied
91
—
Baseline assesses the emissions from a
2005
weighted average of imported
transportation fuels to the United States in
2005, including Canadian oil sands. It does
not, however, include emissions from some
of the most carbon-intensive imported
crude oils (e.g., Venezuelan Heavy) due to
modeling uncertainties.
AERI/Jacobs
Mining +
SCO 108 19%
Units:
gCO2e/MJ reformulated gasoline;
2009
Upgrading
petroleum coke stored at upgrader,
allocated to other fuel products outside
LCA at refinery; accounting for upgrading
included in refinery emissions; emissions
from upstream fuel production included;
venting and flaring included; infrastructure
and land-use changes not specified or not
included.
AERI/Jacobs
Mining Dilbit 105 15%
Units:
gCO2e/MJ reformulated gasoline;
2009
diluents processed with bitumen at
refinery; emissions from upstream fuel
production included; venting and flaring
included; infrastructure and land-use
changes not specified or not included.
AERI/Jacobs In-Situ, SAGD +
SCO 119 31%
Units:
gCO2e/MJ reformulated gasoline;
2009
Upgrading
steam-to-oil ratio (SOR) of 3; petroleum
(Hydrocracking)
coke stored at upgrader, allocated to other
fuel products outside LCA at refinery;
cogeneration credits applied; accounting for
upgrading included in refinery emissions;
emissions from upstream fuel production
included; venting and flaring included;
infrastructure and land-use changes not
specified or not included.
AERI/Jacobs In-Situ, SAGD +
SCO 116 27%
Units:
gCO2e/MJ reformulated gasoline;
2009
Upgrading
SOR 3; petroleum coke stored at upgrader,
(Coker)
allocated to other fuel products outside
LCA at refinery; cogeneration credits
applied; accounting for upgrading included
in refinery emissions; emissions from
upstream fuel production included; venting
and flaring included; infrastructure and land-
use changes not specified or not included.
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WTW
Increase
Production
Crude
GHG
over
Study
Method
Type
Emissions Baseline Key
Assumptions
AERI/Jacobs
In-Situ, SAGD
Dilbit
105-113
15%-24% Units: gCO2e/MJ reformulated gasoline;
2009
SOR 3; cogeneration credits applied;
diluents processed with bitumen at
refinery; emissions from upstream fuel
production included; venting and flaring
included; infrastructure and land-use
changes not specified or not included.
AERI/TIAX
Mining +
SCO 102 12%
Units:
gCO2e/MJ reformulated gasoline;
2009
Upgrading
petroleum coke not combusted at
upgrader, al ocated to other fuel products
outside LCA at refinery; accounting for
upgrading included in refinery emissions;
emissions from upstream fuel production
included; venting, flaring, and fugitives
included; infrastructure and land-use
changes not specified or not included.
AERI/TIAX
In-Situ, SAGD +
SCO 112-128 23%-41%
Units:
gCO2e/MJ reformulated gasoline;
2009
Upgrading
SOR 2.5; petroleum coke not combusted at
upgrader, al ocated to other fuel products
outside LCA at refinery; cogeneration
credits applied using project specific data;
accounting for upgrading included in
refinery emissions; emissions from
upstream fuel production included; venting,
flaring, and fugitives included; infrastructure
and land-use changes not specified or not
included.
AERI/TIAX
In-Situ, SAGD
Synbit
105-108
15%-19% Units: gCO2e/MJ reformulated gasoline;
2009
SOR 2.5; cogeneration credits applied using
project specific data; emissions from
upstream fuel production included; venting,
flaring, and fugitives included; infrastructure
and land-use changes not specified or not
included.
AERI/TIAX
In-Situ, SAGD
Dilbit
101-105
11%-15% Units: gCO2e/MJ reformulated gasoline;
2009
SOR 2.5; cogeneration credits applied using
project specific data; diluents processed
with bitumen at refinery; emissions from
upstream fuel production included; venting,
flaring, and fugitives included; infrastructure
and land-use changes not specified or not
included.
AERI/TIAX
In-Situ, CSS
Synbit
109-112
20%-23% Units: gCO2e/MJ reformulated gasoline;
2009
SOR 3.4-4.8; cogeneration credits applied
using project specific data; emissions from
upstream fuel production included; venting,
flaring, and fugitives included; infrastructure
and land-use changes not specified or not
included.
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Canadian Oil Sands: Life-Cycle Assessments of Greenhouse Gas Emissions

WTW
Increase
Production
Crude
GHG
over
Study
Method
Type
Emissions Baseline Key
Assumptions
AERI/TIAX
In-Situ, CSS
Dilbit
107-112
18%-23% Units: gCO2e/MJ reformulated gasoline;
2009
SOR 3.4-4.8; cogeneration credits applied
using project specific data; diluents
processed with bitumen at refinery;
emissions from upstream fuel production
included; venting, flaring, and fugitives
included; infrastructure and land-use
changes not specified or not included.
NETL 2008
Mining +
SCO 101 11%
Units:
gCO2e/MMBtu gasoline, diesel, and
Upgrading
jet fuel; petroleum coke use unspecified at
upgrader, allocated outside LCA at refinery;
accounting for upgrading not included in
refinery emissions; emissions from
upstream fuel production included; venting,
flaring, and fugitives included; infrastructure
and land-use changes not specified or not
included.
NETL
2008 In-Situ,
CSS Dilbit 110
21% Units:
gCO2e/MMBtu gasoline, diesel, and
jet fuel; SOR not stated; cogeneration
unspecified; diluents unspecified; emissions
from upstream fuel production included;
venting, flaring, and fugitives included;
infrastructure and land-use changes not
specified or not included.
Additional LCAs analyzed by NRDC 2010
WTW GHG emissions expressed in gCO2e/MJ LHV gasoline
U.S. EPA
Baseline
Varied
93
—
Baseline assesses a weighted average of all
2005
imported transportation fuels to the United
States in 2005. Includes emissions from
higher carbon-intensity crude oils imported
or produced domestically.
GREET
Mining +
SCO 103 11%
Units:
gCO2e/mile; petroleum coke use
2010
Upgrading
unspecified; accounting for upgrading not
included in refinery emissions; emissions
from upstream fuel production not
specified; venting, flaring, and fugitives
included; infrastructure and land-use
changes not specified or not included.
GREET
In-Situ, SAGD +
SCO 108 16%
Units:
gCO2e/mile; SOR not stated;
2010
Upgrading
petroleum coke use unspecified;
cogeneration unspecified; accounting for
upgrading not included in refinery
emissions; emissions from upstream fuel
production not specified; venting, flaring,
and fugitives included; infrastructure and
land-use changes not specified or not
included.
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WTW
Increase
Production
Crude
GHG
over
Study
Method
Type
Emissions Baseline Key
Assumptions
McCulloch
Mining +
SCO 105-111 13%-19%
Units:
kgCO2e/bbl SCO; petroleum coke
2006
Upgrading
gasification at upgrader included in high
estimate, unspecified at the refinery;
accounting for upgrading not specified in
refinery emissions; emissions from
upstream fuel production not specified;
venting, flaring, and fugitives partial y
included; infrastructure and land-use
changes not specified or not included.
NRCan
Mining +
SCO 109 17%
Units:
gCO2e/MJ reformulated gasoline;
2008
Upgrading
petroleum coke used at the upgrader
contributes 15% of the energy requirement
for processing SCO and the remainder
offsets emissions from coal combustion at
electric generating units, not specified at
refinery; accounting for upgrading not
included in refinery emissions; emissions
from upstream fuel production included;
venting, flaring, and fugitives included;
infrastructure and land-use changes not
specified or not included.
NRCan
Mining Dilbit 108 16%
Units:
gCO2e/MJ reformulated gasoline;
2008
diluents unspecified; emissions from
upstream fuel production included; venting,
flaring, and fugitives included; infrastructure
and land-use changes not specified or not
included.
NRCan
In-Situ, SAGD +
SCO 119 28%
Units:
gCO2e/MJ reformulated gasoline;
2008
Upgrading
SOR 3.2; petroleum coke used at the
upgrader contributes 15% of the energy
requirement for processing SCO and the
remainder offsets emissions from coal
combustion at electric generating units, not
specified at refinery; cogeneration not
included; accounting for upgrading not
included in refinery emissions; emissions
from upstream fuel production included;
venting, flaring, and fugitives included;
infrastructure and land-use changes not
specified or not included.
NRCan
In-Situ, SAGD
Dilbit
116
25%
Units: gCO2e/MJ reformulated gasoline;
2008
SOR 3.2; cogeneration not included;
diluents unspecified; emissions from
upstream fuel production included; venting,
flaring, and fugitives included; infrastructure
and land-use changes not specified or not
included.
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WTW
Increase
Production
Crude
GHG
over
Study
Method
Type
Emissions Baseline Key
Assumptions
IHS CERA,
In-Situ, SAGD +
SCO 555 14%
Units:
kgCO2e per barrel of refined
2010
Upgrading
products; SOR 3; petroleum coke use
unspecified at the upgrader, al ocated
outside LCA at refinery; cogeneration
credits applied; accounting for upgrading
not specified in refinery emissions;
emissions from upstream fuel production
not included; venting, flaring, and fugitives
not specified; infrastructure and land-use
changes not specified or not included.
Sources: CRS, from studies outlined in Table 1. Average U.S. petroleum baseline for 2005 provided by U.S.
EPA, Renewable Fuel Standard Program (RFS2): Regulatory Impact Analysis, February 2010, EPA-420-R-10-006, with
data sourced from DOE/NETL, Development of Baseline Data and Analysis of Life Cycle GHG Emissions of Petroleum
Based Fuels, November 2008.
Notes: See section “Life-Cycle Assessment Methodology” for key to crude oil types and production processes.
IFC 2011 and the LCAs it reviewed, as wel as NRDC 2010, expressed functional units in GHG emissions per
megajoule (MJ) of gasoline, per MJ of diesel, and per MJ of jet fuel (the gasoline values are shown in this report).
IHS CERA 2010, in contrast, expressed GHG emissions in units of kilograms of carbon dioxide equivalent per
barrel of refined product produced, (kgCO2e per barrel of refined products). Refined products are defined by
IHS CERA as “the yield of gasoline, diesel, distillate, and gas liquids from each crude.” As a meta-analysis, IHS
CERA 2010 used the results of the existing and publicly available life-cycle assessments, including many of those
listed in Table 1; however, a demonstration of the unit conversions was not provided. Without detail of the
underlying allocation methods used to aggregate the gasoline, diesel, jet fuel, and other co-products, neither CRS
nor the DOS/IFC report was able to convert and directly compare IHS CERA’s functional units to the other
studies.
Design Factors and Input Assumptions for Canadian Oil Sands Assessments
Most published and publicly available studies on the life-cycle GHG emissions data for Canadian
oil sands identify two main factors contributing to the increase in emissions relative to other
reference crudes:
1. oil sands are heavier and more viscous than lighter crude oil types on average,
and thus require more energy- and resource-intensive activities to extract;
2. oil sands are compositionally deficient in hydrogen, and have a higher carbon,
sulfur, and heavy metal content than lighter crude oil types on average, and thus
require more processing to yield consumable fuels.
While most studies agree that Canadian oil sands crudes are on average “somewhat” more GHG-
intensive than the crudes they may displace in the U.S. refineries, the range of the reported
increase varies among assessments. Key design and input assumptions can significantly influence
results. These factors include:
• Metrics. Comparing results from various studies is complicated by each study’s
choice of functional units. While GHG emissions have been normalized by most
studies and reported as CO2-equivalents, the units they are expressed “over” vary
greatly. Some evaluate GHG emissions on the basis of a particular final fuel
product (e.g., gasoline, diesel, or jet fuel). Others evaluate emissions by an
averaged barrel of refined product. Some studies report emissions per unit of
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volume (e.g., millions of barrels (mbl)), and others by unit of energy produced
(e.g., British Thermal Units (Btus) or megajoules (MJ)). For example, NETL
2008, Jacobs 2009, and TIEX 2009 use functional units for energy produced
across the final products—MMBtus or MJs for gasoline, diesel, and/or jet fuel.
IHS CERA 2010 expresses GHG emissions “per barrel of refined product
produced”; while others, like Charpentier 2009 (not included in the reported
findings), by “kilometers driven.” The choice affects how the results are
presented and makes it challenging to compare across studies if the data or
conversion values are not fully published or transparent.
• Extraction Process. GHG emissions vary by the type of extraction process used
to recover bitumen. Due to the high energy demands of steam production, in-situ
methods are generally assumed to be more GHG-intensive than mining
operations. However, not all studies assess the difference to be the same. IHS
CERA 2010 estimates the increase of WTW GHG emissions from in-situ
extraction to be, on average, 7% greater than mining. NRDC 2010 estimates 9%.
Specific estimates in Jacobs 2009 show a 4% increase (for SAGD dilbit over
mining dilbit) and in NRCan 2008 an increase of 9% (for SAGD SCO over
mining SCO).
• In-Situ Steam-to-Oil (SOR) Ratio. The amount of steam injected into a
reservoir during in-situ processes to extract a unit volume of bitumen varies
across reservoirs and across extraction facilities. The resulting energy
consumption and GHG emissions estimates vary accordingly. Thus, the figure
used in LCAs to express this ratio may significantly impact GHG estimates.
NRCan 2008 reports SOR values from 2.5 to 5.0 across SAGD operations in
Canadian oil sands. NRDC 2010 reports a range from 1.94 to 7.26. IHS CERA
cites an industry average of 3. Charpentier 2009 demonstrates that GHG
emissions at the production phase are very sensitive to SOR, estimating that
every 0.5 increase in the ratio corresponds to an increase of 10 kgCO2e GHG
emissions per barrel of bitumen produced.
• Upgrading Process. Bitumen needs pre-processing in order to lower its viscosity
and remove impurities before it is fit for conventional refineries. This pre-
processing is called “upgrading,” the key components of which include (1)
removal of water, sand, physical waste, and lighter products; (2) catalytic
purification (i.e., the process of removing excess sulfur, oxygen, nitrogen, and
metals), and (3) hydrogenation through either carbon rejection or catalytic
hydrocracking (i.e., the process of removing or breaking down the heaviest
fraction of the oil residuum by either vacuum distillation and precipitation or by
adding hydrogen in a “hydrocracking process that breaks long-chain
hydrocarbons into shorter, more useful ones). The residuum can be further
refined in a “coking” process to produce gasoline, distillate, and petroleum coke.
The resulting product is synthetic crude oil (SCO) and numerous co-products,
including water, sand, waste, sulfur, oxygen, nitrogen, distillate, and petroleum
coke, among others. Some of the co-products from the upgrading process contain
carbon and other potential GHG emission sources. Thus, a consistent and
comprehensive accounting of the GHG emission from all co-products would be
necessary for a full life-cycle assessment of oil sands crude—or any
hydrocarbon—production.
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• Treatment of Petroleum Coke. Petroleum coke (an excess source of carbon) is a
co-product of bitumen production at both the upgrader and the refinery. Roughly
5%-10% of a barrel of crude ends up as coke; and the heavier the crude, the
greater the percentage of coke. Dilbit refining produces about 50% more coke
than the average conventional crude. The treatment of coke is a primary driver
behind the results of any WTW GHG oil sands assessment. If coke is combusted
(i.e., for process heat, electricity, or hydrogen production at the upgrader in lieu
of natural gas combustion), WTW GHG emissions may increase anywhere from
14% (TIAX 2009) to 50% (McCulloch 2006) over lighter crudes. If it is stored,
sold, and/or combusted elsewhere, its potential emissions may not be factored
into the LCA. The main concern for modeling is ensuring that coke produced at
the upgrader (for SCO) is treated consistently with coke produced at the refinery
(for dilbit or other imported crudes). Based on the studies analyzed in this report,
petroleum coke at the upgrader is either (1) combusted (increase in WTW GHG
emissions), (2) stored (unspecified change in WTW GHG emissions), or (3) sold
as a fuel for combustion (increase in WTW GHG emission if allocated to coke
production (as in TIAX 2009)). In contrast, petroleum coke at the refinery is
either (1) used as an offset credit to back out coal combustion for electricity
generation (decrease in WTW GHG emissions), or (2) allocated outside the life-
cycle assessment (effect not included in WTW GHG emissions). These
inconsistent methodologies make comparisons problematic. Coke produced at
U.S. refineries has a low domestic demand, and is therefore often shipped to
overseas markets for use as a replacement fuel for coal combustion or steel
production (most studies include neither the overseas transportation nor the
combustion emissions of coke in WTW GHG emissions assessments).
• Cogeneration. Cogeneration facilities use both steam and electricity generated
from the steam to achieve higher energy efficiencies. In-situ extraction facilities
often have steam requirements much greater than electricity requirements, thus
leaving excess capacity for electricity generation that can be exported back into
the grid for use elsewhere. Offset credits given to exported electricity in LCAs
can have a substantial impact on WTW GHG emissions. Cogeneration
assumptions vary across the studies of Canadian oil sands crudes in two ways:
(1) whether cogeneration credits are included, and (2) if so, what source of
electricity is offset (e.g., coal-fired generation, oil, or natural gas). Some
estimates show that applying credits from oil sands facilities to offset coal-fired
electricity generation could reduce WTW GHG emission to within the range of
conventional crudes. Many studies currently do not consider offset credits
because the practice is not in widespread use among producers.
• Upgrading and Refinery Emissions. Because SCO delivered to a refinery has
already been processed at the upgrader, the energy consumption at the refinery—
and therefore the GHG emissions at the refinery—will be lower than the refinery
emissions of dilbit or other crudes. Accounting for the reduced emissions from
SCO has a modest effect on WTW GHG emissions, as refinery emissions are
commonly around 5%-15% of the total. Many studies do not mention this
accounting, and it is unclear if the reductions for SCO at the refinery are
incorporated into many of the LCAs.
• Diluents. Because the viscosity of raw bitumen is too high to be transported via
pipeline, diluting bitumen with lighter hydrocarbons to assist in its transport has
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become a common industry practice. Accounting for the effects of diluting
bitumen is an important component in emission estimates, because producing and
refining the diluents into finished products may result in a lower WTW GHG
emissions estimate per barrel of dilbit in comparison to a barrel of raw bitumen.
LCAs that report emissions for dilbit on a per barrel of refined product basis
(e.g., IHS CERA 2010) are thus reporting the emissions from a combination of
both oil sands bitumen and the supplemental hydrocarbons. Additionally, diluting
raw bitumen with light hydrocarbons creates a crude product that is more
difficult and energy-intensive to refine than other crude oils, thus producing less
premium refined product per barrel after the refinery stage.17 The extent to which
this difference in yield is accounted for across the various studies is unclear. The
IHS CERA 2010 estimates for crude production of SAGD dilbit do not show an
adjustment for the difference. TIAX 2009 and Jacobs 2009 both show slightly
higher refinery emissions for dilbit compared to other crudes, but the reasons for
the increase are not specified.
• Upstream Production Fuels. Some studies include the GHG emissions
associated with the upstream production of purchased electricity that is imported
to provide process heat and to power machinery throughout crude production.
The upstream GHG emissions for natural gas fuel and electricity generation used
in the production of oil sands can be significant. Jacobs 2009 demonstrates that
the GHG emissions associated with the upstream fuel cycle account for roughly
4%-5% of the total WTW GHG emissions for average Canadian oil sands. IHS
CERA 2010 indicates that although its study excludes upstream fuel and
electricity GHG emissions, the inclusion of them would add 3% to WTW GHG
emissions per barrel of refined product.
• Flared, Vented, and Fugitive Emissions. Emissions associated with flaring and
venting can be a significant source of GHG emissions. The TIAX 2009 study
indicates that including venting and flaring emissions associated with oil sands
production (particularly for mining extraction techniques) may contribute up to
4% of total WTW GHG emissions. Further, methane emissions from fugitive
leaks throughout the oil sands production process can potentially contribute up to
1% of GHG emissions.18 Methane emissions from oil sands mining and tailings
ponds may have an even larger impact, contributing from 0%-9% of total GHG
emissions.19 TIAX 2009, McCulloch 2006, and NRCan 2008 state that they
include emissions from these sources. IHS CERA 2010 excludes emissions from
methane released from tailings ponds but recognizes there is considerable
uncertainty and variance in quantifying these emissions. Other studies do not
specify.

17 As described in IFC 2011, diluting raw bitumen with light hydrocarbons creates what is referred to as a “dumbbell”
blend, since it contains high fractions of both the heavy residuum and the light ends, with relatively low fractions of
hydrocarbons in the middle that can be easily refined into premium fuel products. As a result, producing one barrel of
premium fuel products (i.e., gasoline, diesel, and jet fuel) requires more dilbit input and produces more light ends and
petroleum coke than refining one barrel of premium fuel products from other crudes and SCO. This results in additional
energy use and GHG emissions from refining the dilbit, and producing, distributing, and combusting the light- and
heavy-end co-products.
18 Environment Canada, National Inventory Report: 1990-2008 Greenhouse Gas Sources and Sinks in Canada, 2010.
19 Yeh, S., et al., “Land Use Greenhouse Gas Emissions from Conventional Oil Production and Oil Sands,” Environ.
Sci. Technol., 2010, 44 (22), pp. 8766–8772.
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• Infrastructure/Construction Emissions. None of the existing studies include
the GHG impacts associated with capital equipment and the construction of
facilities, machinery, and infrastructure needed to produce oil sands. According
to Bergerson and Keith 2006,20 the relative percentage increase to WTW GHG
emissions from incorporating capital equipment can be between 9% and 11%.
Charpentier 2009 discusses the need to more fully investigate and include these
potentially significant supply chain infrastructure GHG emissions in future oil
sands life-cycle studies.
• Local and Indirect Land-Use Change Emissions. Emissions associated with
changes in biological carbon stocks from the removal of vegetation, trees, and
soil during oil sands mining operations may be significant, albeit temporary. Yeh
2010 estimates that surface mining of oil sands results in a 0.9%-2.5% increase in
the WTW emissions versus the baseline (2005 average U.S. gasoline). The range
was highly dependent on the type of lands displaced and reclamation practices
used, with the removal of peatland having the largest impact. None of the life-
cycle studies reviewed, however, include land-use change GHG emissions in the
WTW life-cycle assessment. Several recent studies have begun to assess the
effects.21
Life-Cycle Assessments of Canadian Oil Sands versus Other
Reference Crudes
To compare the life-cycle GHG emissions from Canadian oil sands crudes against those of other
crude oils imported into the United States, many of the published studies conduct reference
assessments of other global resources.
Findings
Figure 3 presents the results of one of the more comprehensive studies (NETL 2009), which
compares Well-to-Wheel GHG emissions of reformulated gasoline across various crude oil
feedstocks (a review of the NETL 2009 input assumptions is included in the figure’s “Notes”
section). The NETL findings show the following:
• Well-to-Wheel GHG emissions from gasoline produced from a weighted average
of Canadian oil sands crudes imported to the United States are approximately
17% higher than that from gasoline derived from the average mix of crudes
imported to the United States in 2005. This corresponds to an increase in Well-to-
Tank (i.e., “production”) GHG emissions of 80% over the 2005 average
production emissions for imported transportation fuels to the United States (18
gCO2e/MJ).

20 Bergerson, J. & Keith, D., Life Cycle Assessment of Oil Sands Technologies, Paper No. 11 of the Alberta Energy
Futures Project, University of Calgary, 2006; J. Bergerson, The Impact of LCFS on Oil Sands Development: Hybrid
LCA Methods, Presentation at the InLCA/LCM Conference, October 2, 2007, University of Calgary.
21 See, for example, Rooney, R., et al., Oil Sands Mining and Reclamation Cause Massive Loss of Peatland and Stored
Carbon, PNAS, at http://www.pnas.org/cgi/doi/10.1073/pnas.1117693108.
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• Well-to-Wheel GHG emissions from gasoline produced from a weighted average
of Canadian oil sands crudes are 19%, 12%, and 18% higher than the life-cycle
emissions from Middle Eastern Sour, Mexican Maya, and Venezuelan
Conventional crudes, respectively.22 This corresponds to an increase in Well-to-
Tank (i.e., “production”) GHG emissions of 102%, 53%, and 92% higher than
the production emissions from Middle Eastern Sour, Mexican Maya, and
Venezuelan Conventional crudes, respectively.
Individual estimates of WTW GHG emissions from Canadian oil sands crudes from the primary
studies listed in Table 1 range from 9%-19% more GHG-intensive than Middle Eastern Sour,
5%-13% more GHG-intensive than Mexican Maya, and 2%-18% more GHG-intensive than
various Venezuelan crudes (including Venezuelan Conventional and Bachaquero).
Figure 3. Well-to-Wheel GHG Emissions Estimates for Global Crude Resources

Source: CRS, from NETL, An Evaluation of the Extraction, Transport and Refining of Imported Crude Oils and the
Impact of Life Cycle Greenhouse Gas Emissions, National Energy Technology Laboratory, March 27, 2009

22 NETL 2009 assumes the production of these specific reference crudes could be affected most by an increase in
Canadian oil sands production. See next section “Design Factors and Input Assumptions for Reference Crudes
Assessments.”
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Notes: NETL’s value for the final fuel consumption stage is 72.6 kgCO2e/MJ for al crude resources. U.S. EPA
2005 (U.S. average) assesses a weighted average of all imported transportation fuels to the United States in 2005,
including Canadian oil sands. It does not include emissions from some of the most carbon-intensive imported
crude oils (e.g., Venezuelan Heavy) due to modeling uncertainties. NETL values converted from kgCO2e/MMBtu
using conversion factors of 1,055 MJ/MMBtu and 1,000 g/kg. NETL input assumptions are as fol ows: (1) assumes
a weighted average of Canadian oil sands extraction at 43% raw bitumen (not accounting for blending with
diluents to form dilbit) from CSS in-situ production and 57% SCO from mining production in the years 2005 and
2006; (2) allocates refinery emissions from co-products other than the gasoline, diesel, and jet fuel to the co-
products themselves, including petroleum coke, and thus outside the boundaries of the LCA (unless combusted
at refinery); (3) uses linear relationships to relate GHG emissions from refining operations based on API gravity
and sulfur content, thus failing to fully account for the various produced residuum ranges of bitumen blends and
SCO; (4) does not fully evaluate the impact of pre-refining SCO at the upgrader prior to the refinery; (5) does
not account for the transportation emissions of co-products; and (6) bounds the GHG emissions estimates for
Venezuela’s ultra-heavy oil/bitumen using uncertainty analysis due to the limited availability of public data.
Further, as noted in Table 2, NETL 2009 study assumptions do not state SOR, do not include upstream fuel
production, do not include infrastructure or land-use changes, and do not specify cogeneration, but do include
emissions from venting, flaring, and fugitives.
Design Factors and Input Assumptions for Reference Crudes Assessments
Similar to the LCAs conducted on Canadian oil sands crudes, assessments on other global
resources present many variables and uncertainties in the available data. Likewise, these
assessments are bounded by specific design factors and input assumptions that can affect the
quality of the results. These factors include:
• Choice of Reference Crudes Studied. Crude oil resources around the world
vary significantly in regard to resource quality and production methods. Thus, the
comparison of the GHG emissions intensity for Canadian oil sands crudes against
a reference crude could vary significantly, depending upon the choice of
reference.
• Choice of Reference Crudes Presumed Displaced in U.S. Refineries. If an
increased volume of Canadian crude is imported into the United States, and if
U.S. refineries continue using the same input mix of heavy crudes as they
currently use, it is assumed by some of the studies that resources like Venezuelan
Bachaquero or Mexican Maya would likely be the first displaced. However, to
the extent that a crude like Saudi Light (i.e., Middle Eastern Sour) is the world’s
balancing crude, some analysts believe that it may ultimately be the resource that
is backed out of the global market by increased Canadian oil sands production.23
• Assumptions Regarding Artificial Lift. Comparisons of reference crudes are
further complicated by the choice of production phase, and thus the
determination of the crude’s recovery method. While primary resource recovery
relies only upon the internal pressure of the well to lift the resource, the use of
injected water or gas in subsequent phases of recovery, or the use of steam or
CO2 in the final phases, can significantly increase the emissions intensity of
crude recovery.

23 Many factors—from economics, to geopolitics, to trade issues—would influence the balance of global petroleum
production. An analysis of how incremental production of Canadian crudes would affect the production levels of other
global crudes, and which of those crudes would be backed out of U.S. refineries and/or global production, is beyond the
scope of this report. For more detail on global oil markets, see CRS Report R41765, U.S. Oil Imports: Context and
Considerations, by Neelesh Nerurkar.
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Canadian Oil Sands: Life-Cycle Assessments of Greenhouse Gas Emissions

• Sensitivity to Water-Oil and Gas-Oil Ratios. These ratios describe the fraction
of the flow from a well that is oil, water, and gas. Due to the complex nature of
production systems and resource reservoirs, studies often use ratios to develop
simplified relationships between energy use and GHG emissions. Venting or
flaring of associated gas, and fugitive emissions from produced water, can also
have moderate to significant impacts on GHG emissions intensities.
• Treatment of Petroleum Coke at the Refinery. Much like the end-use
determination—and consequent GHG emissions—for petroleum coke at
Canadian upgrading facilities, the treatment of coke and its associated emissions
at the refinery is a primary driver behind the results of any WTW GHG
assessment of reference crudes.
• Transportation Emissions. LCAs must account for the contribution of
transportation in WTW GHG emissions estimates, including the distance and
mode of transportation from oil field to export terminal, and from producer to
refiner, as well as the final transportation emissions of all co-products.
Life-Cycle Assessments of Canadian Oil Sands versus Other
Fuel Resources
Figure 4 offers a comparison of the life-cycle GHG emissions estimates of petroleum products
from Canadian oil sands crudes with estimates from other unconventional petroleum products,
natural gas, and coal. These data are drawn from several different studies employing many
different design features and input assumptions, not the least of which are different methods of
combusting the final fuel products. Further, it should be noted that different and non-substitutable
end uses for the fuel products (e.g., the different end uses for coal and petroleum combustion)
make a full comparison of their emissions impacts problematic. The figure presents an average
value for each fuel; the original source materials provide a full description of each study’s design
characteristics as well as a presentation of each estimate’s uncertainty analysis.
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Figure 4. Life-Cycle GHG Emissions Estimates for Selected Fuel Resources

Source: CRS, from NETL, Development of Baseline Data and Assessment of Life Cycle Greenhouse Gas Emissions of
Petroleum-Based Fuels, National Energy Technology Laboratory, November 26, 2008; Brandt, A.R. and A.E. Farrell,
“Scraping the Bottom of the Barrel: Greenhouse Gas Emission Consequences of a Transition to Low-quality and
Synthetic Petroleum Resources,” Climatic Change, Vol. 84, 2007, pp. 241-263; and Burnham, A., et al., “Life-Cycle
Greenhouse Gas Emissions of Shale Gas, Natural Gas, Coal, and Petroleum,” Environmental Science and
Technology, Vol. 46, 2012, pp. 619–627.
Notes: NETL values converted from kgCO2e/MMBtu using conversion factors of 1,055 MJ/MMBtu and 1,000
g/kg; Brandt values converted from gCe/MJ using conversion factor of 3.667 Ce/CO2e.
U.S. Carbon Footprint for the Keystone XL Pipeline
In response to comments on the draft Environmental Impact Statement (EIS) for the Keystone XL
pipeline project and as a “matter of policy,” the DOS/IFC study provides estimates for the
incremental GHG emissions resulting in the production of Canadian oil sands crudes likely to be
transported by the Keystone XL pipeline project (i.e., the U.S. GHG emissions footprint).24
Incremental GHG emissions are determined by the following:
1. the presumed throughput of the pipeline,
2. the mix of oil sands crude types imported through the pipeline, and
3. the GHG emission intensity of the crudes in the pipeline compared to the crudes
they displace.

24 DOS, Final EIS, 3.14.52-56.
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For illustrative purposes, the Final EIS uses the emissions assessment data from Jacobs 2009,
TIAX 2009, and NETL 2009 to develop weighted averages of Canadian crudes and other
reference crudes for the purposes of the carbon footprint analysis. DOS/IFC assumes the near-
term initial throughput of the proposed Keystone XL pipeline to be 700,000 barrels of crude per
day, with a potential capacity of 830,000 barrels per day. Using the Jacobs 2009 and TIAX 2009
assessments, DOS/IFC estimates that the throughput for the pipeline would be 50% SCO and
50% dilbit, with all dilbit produced using in-situ methods and 12% of SCO produced using in-situ
methods, yielding a final mix of 50% in-situ produced dilbit, 44% mining produced SCO, and 6%
in-situ produced SCO. Using the NETL 2009 assessment, DOS/IFC calculates a mix of 43%
crude bitumen and 57% SCO. Incremental GHG emissions for Canadian crudes are computed
against four different reference crudes: Middle Eastern Sour (with the assumption that as the
world’s balancing crude, it may ultimately be the crude that is backed out of the world market by
increased production of Canadian crudes), Mexican Maya and Venezuelan Bachaquero (with the
assumption that as the heavy crudes currently in the input mix at U.S. refineries, they are likely to
be the first displaced by an increased production of Canadian crudes), and a reference crude based
on the average mix imported and refined in the United States in 2005.
The analysis found that the potential range of incremental GHG emissions contributed by the
pipeline would be 3-17 MMTCO2e annually at the near-term initial throughput and 4-21
MMTCO2e annually at the potential throughput. As the United States reported a total domestic
GHG inventory of 6,865.5 MMTCO2e in 2010,25 the incremental pipeline emissions would
represent an increase of 0.06%-0.3% in total annual GHG emissions for the United States. This
overall range is equivalent to annual GHG emissions from the combustion of fuels in
approximately 588,000 to 4,061,000 passenger vehicles, or the CO2 emissions from combusting
fuels used to provide the energy consumed by approximately 255,000 to 1,796,000 homes for one
year.26
Further Considerations
Life-cycle assessment has emerged as an influential methodology for collecting, analyzing, and
comparing the GHG emissions and climate change implications of various hydrocarbon
resources. However, because of the complex life cycle of hydrocarbon fuels and the large number
of analytical design features that are needed to model their emissions, LCAs retain many
variables and uncertainties. These uncertainties often make comparing results across resources or
production methods problematic. Hence, the usefulness of LCA as an analytical tool for
policymakers may lie less in its capacity to generate comparative rankings, or “scores,” between
one source and another, and more in its ability to highlight “areas of concern,” or “hot spots,” in
the production of a given hydrocarbon fuel. In this way, LCA can serve to direct policymakers’
attention to those areas in resource development that present the greatest challenges to GHG
emissions control, and hence, the biggest potential benefits if adequately managed.
Table 3 summarizes the GHG emissions impacts of the various stages of Canadian oil sands
production and presents examples of mitigation strategies that have been offered by industry,
academia, and other stakeholders.

25 See 2012 Draft U.S. Greenhouse Gas Inventory Report, Table-ES-2, at http://epa.gov/climatechange/emissions/
downloads12/Executive%20Summary.pdf.
26 Final EIS, 3.14-55.
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Table 3. Potential GHG Mitigation Activities in Canadian Oil Sands Production
Magnitude of
Source’s GHG
Impact
Source of GHG
Mitigation Activity
Significant
Upstream Fuels for Production
Energy-efficiency measures.
Use of natural gas or bio-based fuels such as biodiesel
or bioethanol in mining and trucking fleets and
equipment.

Extraction
In-situ extraction improvements such as improved wel
configuration and placement, low-pressure SAGD, flue
gas reservoir re-pressurization, new artificial lift
pumping technologies, use of electric submersible
pumps, and overall improvements in energy efficiency
that can reduce the steam-to-oil ratios (SOR) of in-situ
production processes.
Steam solvent processes, which use solvents to reduce
the steam required for bitumen extraction. These
include solvent-assisted processes (SAP), expanding
solvent steam-assisted gravity drainage (ES-SAGD), and
liquid addition to steam for enhanced recovery (LASER).
Electrothermal extraction, where electrodes are used
to heat the bitumen in the reservoir.
Use of lower-temperature water to separate bitumen
from sand during extraction to reduce the energy
required.
In-situ combustion, where the heavy portion of
petroleum is combusted underground.

Upgrading and Refining
Expanded use of cogeneration to produce electricity
and steam during the upgrading stages of oil sands
production, particularly for in-situ production.
Bio-upgrading technology in development that includes
the use of microbes to remove sulfur compounds and
impurities.
Use of co-products (e.g., petroleum coke) as
replacement fuels for coal-fired power generation.

Storage
Carbon capture and storage (CCS) technologies to
store CO2 produced from point sources.

Vented Emissions
Vapor recovery units where possible, flares otherwise.
Moderate Land-Use
Changes
Reclamation.

Capital Equipment and
Energy-efficiency measures.
Infrastructure
Small Transportation
Energy-efficiency
measures.

Fugitive Emissions
Leak detection and repair.
Source: CRS, from studies outlined in Table 1.
Notes: Significant = greater than approximately 3% change in WTW emissions. Moderate = approximately 1%–
3% change in WTW emissions. Small = less than approximately 1% change in WTW emissions.

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Author Contact Information

Richard K. Lattanzio

Analyst in Environmental Policy
rlattanzio@crs.loc.gov, 7-1754

Acknowledgments
Thanks to Amber Wilhelm of CRS for her help with graphics, and to Bryan Sinquefield of CRS for his help
with editing.

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