Canadian Oil Sands: Life-Cycle Assessments
of Greenhouse Gas Emissions
Richard K. Lattanzio
Analyst in Environmental Policy
March 10, 2014
Congressional Research Service
7-5700
www.crs.gov
R42537
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 petroleum resources both
domestically and internationally. Many forecasters identify petroleum products refined from
Canadian oil sands as one possible solution. Increased production from Canadian oil sands,
however, is not without controversy, as many have expressed concern over the potential
environmental impacts. These impacts include emissions of greenhouse gases (GHG) during
resource extraction and processing. A number of key studies in recent literature have expressed
findings that GHG emissions per unit of energy produced from Canadian oil sands crudes are
higher than those of other crudes imported, refined, and consumed in the United States. The
studies identify two main reasons for the difference: (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 chemically 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 by U.S. standards.
Selected Findings from the Primary Published Studies
CRS surveyed the published literature, including the U.S. State Department-commissioned study
for the Keystone XL pipeline project in both the 2011 Final Environmental Impact Statement and
the 2014 Final Supplementary Environmental Impact Statement. The primary literature reveals
the following:
• Canadian oil sands crudes are generally more GHG emission-intensive than other
crudes they may displace in U.S. refineries, and emit an estimated 17% more
GHGs on a life-cycle basis than the average barrel of crude oil refined in the
United States;
• compared to selected imports, Well-to-Wheels GHG emissions for Canadian oil
sands crudes range from 9% to 19% more emission-intensive than Middle
Eastern Sour, 5% to 13% more emission-intensive than Mexican Maya, and 2%
to 18% more emission-intensive than various Venezuelan crudes;
• compared to selected energy- and resource-intensive crudes, Well-to-Wheels
GHG emissions for Canadian oil sands crudes are within range of heavier crudes
such as Venezuelan Bachaquero and Californian Kern River, as well as lighter
crudes that are produced from operations that flare associated gas (e.g., Nigerian
Bonny Light);
• discounting the final consumption phase of the life-cycle assessment (which can
contribute up to 70%-80% of Well-to-Wheels emissions), Well-to-Tank (i.e.,
“production”) GHG emissions for Canadian oil sands crudes are 9%-102%
higher than for selected imports;
• 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 investment and development, while others suggest that the
project would not substantially influence either the rate or magnitude of oil
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Canadian Oil Sands: Life-Cycle Assessments of Greenhouse Gas Emissions
extraction activities in Canada or the overall volume of crude oil transported to
and refined in the United States.
Scope and Purpose of This Report
Congressional interest in the GHG emissions attributable to Canadian oil sands crudes has
encompassed both a broad understanding of the resource as well as a specific assessment of the
proposed Keystone XL pipeline. This report discusses the basic methodology of life-cycle
assessments and compares several of the publicly available studies of GHG emissions data for
Canadian oil sands crudes against each other and against those of other global reference crudes.
For a detailed analysis of the GHG emissions attributable to the proposed Keystone XL pipeline,
and the findings from the State Department’s Final Environmental Impact Statement, see CRS
Report R43415, Keystone XL: Greenhouse Gas Emissions Assessments in the Final
Environmental Impact Statement, by Richard K. Lattanzio.
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Contents
Introduction ...................................................................................................................................... 1
Scope and Purpose of This Report ............................................................................................ 2
Life-Cycle Assessment Methodology .............................................................................................. 3
Key Factors in the Assessment of Canadian Oil Sands Crudes ................................................. 4
Results of Selected Life-Cycle Emissions Assessments .................................................................. 7
Life-Cycle Assessments of Canadian Oil Sands Crudes ........................................................... 7
Findings ............................................................................................................................... 9
Design Factors and Input Assumptions for Life-Cycle Assessments of Canadian
Oil Sands Crudes ............................................................................................................ 18
Life-Cycle Assessments of Canadian Oil Sands Crudes versus Other Reference
Crudes ................................................................................................................................... 22
Findings ............................................................................................................................. 22
Design Factors and Input Assumptions for Life-Cycle Assessments of Reference
Crudes ............................................................................................................................ 23
Life-Cycle Assessments of Canadian Oil Sands Crudes versus Other Fuel Resources ........... 26
Further Considerations ................................................................................................................... 27
Figures
Figure 1. Crude Oil Life-Cycle Schematic ...................................................................................... 4
Figure 2. Well-to-Wheels GHG Emissions Estimates for Canadian Oil Sands Crudes ................. 11
Figure 3. Well-to-Wheels GHG Emissions Estimates for Global Crude Resources ...................... 25
Figure 4. Life-Cycle GHG Emissions Estimates for Selected Fuel Resources.............................. 26
Tables
Table 1. Life-Cycle Assessments of Canadian Oil Sands Crudes .................................................... 8
Table 2. Reported Findings of Well-to-Wheels GHG Emissions Estimates in the
Life-Cycle Assessments of Canadian Oil Sands Crudes ............................................................ 12
Table 3. Potential GHG Mitigation Activities in Canadian Oil Sands Production ........................ 27
Contacts
Author Contact Information........................................................................................................... 28
Acknowledgments ......................................................................................................................... 28
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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 petroleum resources both
domestically and internationally. Many forecasters identify petroleum products refined from
Canadian oil sands1 as one possible solution. Canadian oil sands account for about 56% of
Canada’s total crude oil production, and that number is expected to rise from its current level of
1.8 million barrels per day (mbd) in 2012 to 5.2 mbd by 2030.2 Further, the infrastructure to
produce, upgrade, refine, and transport the resource from Canadian oil sands reserves to the
United States is in place, and additional infrastructure projects—such as the Keystone XL
pipeline—have been proposed.3 Increased 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.4
A number of key studies in recent literature have expressed findings that GHG emissions per unit
of energy produced from Canadian oil sands crudes are higher than those of other crudes
imported, refined, and consumed in the United States.5 While GHG emissions and other air
quality issues originating in the upstream sectors of Canada’s petroleum industry may 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
and environmental policy.
The U.S. Department of State (DOS), in response to comments on the 2010 Draft Supplementary
Environmental Impact Statement (2010 Draft EIS)6 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 to analyze the life-cycle GHG
emissions associated with these resources in comparison to other reference crudes.7 DOS
presented this analysis in the 2011 Final Environmental Impact Statement (2011 Final EIS)
released on August 26, 2011, as a “matter of policy,” but noted that neither the National
Environmental Policy Act (NEPA) nor DOS regulations (22 C.F.R. 161.12) nor Executive Orders
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 Canadian Association of Petroleum Producers market outlooks,
http://www.capp.ca/aboutUs/mediaCentre/NewsReleases/Pages/2013-OilForecast.aspx.
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, Kristina Alexander, and Kenneth R. Thomas.
4 For more discussion on environmental impacts beyond GHG emissions, see CRS Report R42611, Oil Sands and the
Keystone XL Pipeline: Background and Selected Environmental Issues, coordinated by Jonathan L. Ramseur.
5 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.
6 For all project documents, see the State Department’s website: http://www.keystonepipeline-xl.state.gov/.
7 The most recent full report by the State Department’s contractor is found in U.S. Department of State, Keystone XL
Project, Final Supplementary Environmental Impact Statement, Appendix U, “Life-Cycle Greenhouse Gas Emissions
of Petroleum Products from WCSB Oil Sands Crudes Compared with Reference Crudes,” January 31, 2014.
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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.
The initial permit for the Keystone XL Project was denied due to insufficient time to prepare a
rigorous, thorough, and transparent review of the pipeline’s proposed routes through Nebraska. In
May 2012, Keystone filed a new permit application for a revised route, implementing a new
national interest determination. In accordance with this process, DOS released a revised Draft
Supplementary EIS (Draft EIS) for the revised project on March 1, 2013, and a revised Final
Supplementary EIS (Final EIS) on January 31, 2014, including an assessment of the indirect
cumulative impacts and life-cycle GHG emissions of Canadian oil sands crudes.8 While DOS
commissioned a different contractor to assist with the EIS,9 the data used to determine the GHG
life-cycle emissions associated with the resource, as well as the market analysis used for supply
and demand projections, remained largely unchanged. Hence, the 2014 Final EIS made similar
findings to the 2011 Final EIS, including the following:
1. Canadian oil sands crudes “are more GHG-intensive than the other heavy crudes
they would replace or displace in U.S. refineries, and emit an estimated 17%
more GHGs on a life-cycle basis than the average barrel of crude oil refined in
the United States in 2005,”10 and
2. “Approval or denial of any one crude oil transport project, including the
proposed Project, is unlikely to significantly impact the rate of extraction in the
oil sands or the continued demand for heavy crude oil at refineries in the United
States.”11
Opponents of the pipeline, however, are critical of this impact assessment. They contend that the
lack of transport infrastructure and the price discount it occasions has already affected production
of the oil sands and, if continued, would further depress investment and development in the
region.12
Scope and Purpose of This Report
This report presents a summary 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
8 Hereinafter in this report, CRS refers to the “supplementary” documents as the Draft Environmental Impact Statement
(Draft EIS) and the Final Environmental Impact Statement (Final EIS), as the submission of a new permit application
is understood to reinitiate the National Environmental Policy Act process. For further explanation, see CRS Report
R41668, Keystone XL Pipeline Project: Key Issues, by Paul W. Parfomak et al.
9 The first EIS was contracted to Cardno Entrix, with assistance on the GHG analysis from ICF International; the
second EIS was contracted to Environmental Resources Management (ERM).
10 Final EIS, op cit., p. ES-15.
11 Final EIS, op cit., p. ES-16.
12 See, for example, Natural Resources Defense Council, “Say No to Tar Sands Pipeline,” March 2011, at
http://www.nrdc.org/land/files/TarSandsPipeline4pgr.pdf.
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fuel resources. 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. For a specific analysis of the GHG emissions attributable to the
proposed Keystone XL pipeline, see CRS Report R43415, Keystone XL: Greenhouse Gas
Emissions Assessments in the Final Environmental Impact Statement, by Richard K. Lattanzio.
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.13 This figure is commonly referred to as the
“emissions intensity” of the fuel. 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-Wheels” (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 petroleum’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 emissions
associated with particular stages as well as experiment with certain boundary assumptions. The
choice of boundaries is an important component to any LCA and can lead to vastly differing
reported results.14
13 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.
14 A study’s choice of boundaries is responsible for many of the vastly differing values for GHG emissions intensities
that are currently being reported in published studies of the Canadian oil sands crudes relative to other reference crudes.
For example, when expressed on a WTT basis rather than on a WTW basis, GHG emissions intensities 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).
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Figure 1. Crude Oil Life-Cycle Schematic
Source: CRS.
Key Factors in the Assessment of Canadian Oil Sands Crudes
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. Some of these factors with respect to Canadian oil sands crudes are as
follows:
Crude Oil Types. Oil sands are a type of unconventional petroleum deposit. They are commonly
formations of loose sand or 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.15 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-derived crude” or simply
“oil sands crude.” Several kinds of crude-like products can be generated from bitumen, and their
properties differ in some respects from conventional light crude. They include the following:
• 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
15 For more technical information on bitumen, see, 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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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 the following:
• 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. Higher intensities of GHG emissions may result from increased land use
changes during strip-mining. Mining accounts for slightly more than 50% of
current production, and is expected to remain between 40% and 50% through
2030.16 Currently, a significant portion of mined bitumen is upgraded to SCO.
• 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-
intensive than conventional mining (excluding land use impacts). With more
than 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.
16 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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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,17
• 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),18
• 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 crudes 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;
• ratios for bitumen-to-diluents, steam-to-oil, gas-to-oil, water-to-oil; and
• energy efficiencies for steam generation and other production processes.
17 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.
18 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 Crudes
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).19 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 ICF International LLC
(ICF)—in the Keystone XL Project’s August 2011 Final Environmental Impact Statement (2011
Final EIS). The studies were selected by ICF 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. The use of these
studies was replicated in the 2014 Final Environmental Impact Statement (2014 Final EIS)
conducted by DOS and the contractor Environmental Resources Management.
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),
and
•
combustion (emissions from the end-use combustion of the refined fuel and co-products).
Table 1 provides a list of the studies referenced by the DOS analysis. While the type, boundaries,
and design features vary across all studies, DOS 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 2011 Final EIS as well as the 2014 Final EIS. Reasons against the inclusion of the
remaining studies are presented briefly in the table, and outlined in more detail in the EIS.
19 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 Crudes
As evaluated by DOS/ICF 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 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: Alberta Energy Research Institute/Jacobs Consultancy, Life Cycle Assessment Comparison of North
American and Imported Crudes, 2009; Alberta Energy Research Institute/TIAX LLC, Comparison of North American
and Imported Crude Oil Lifecycle GHG Emissions, 2009; National Energy Technology Laboratory, Development of
Baseline Data and Assessment of Life Cycle Greenhouse Gas Emissions of Petroleum-Based Fuels, November 26, 2008;
National Energy Technology Laboratory, An Evaluation of the Extraction, Transport and Refining of Imported Crude
Oils and the Impact of Life Cycle Greenhouse Gas Emissions, March 27, 2009; Charpentier, A., 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; International Council on Clean Transportation, Carbon Intensity of Crude Oil
in Europe Crude, 2010; International Energy Agency, World Energy Outlook, 2010; IHS Cambridge Energy
Research Associates, Inc., Oil Sands, Greenhouse Gases, and U.S. Oil Supply: Getting the Numbers Right, 2010; T. J.
McCann and Associates Ltd., Typical Heavy Crude and Bitumen Derivative Greenhouse Gas Life Cycles in 2007,
Prepared for Regional Infrastructure Working Group, 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; Natural Resources Canada /(S&T)2 Consultants, 2008 GHGenius Update, August 15, 2008; Natural
Resources Defense Council, GHG Emission Factors for High Carbon Intensity Crude Oils, Ver. 2, 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, 2008.
Notes: According to the DOS/ICF 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 Final EIS, Appendix U, pp. 5-7, for more on the DOS evaluation of each study.
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The 2014 Final EIS mentioned several other studies published after the release of the 2011 Final
EIS. These studies include Jacobs Consultancy, EU Pathway Study: Life Cycle Assessment of
Crude Oils in a European Context, 2012; IHS CERA, Oil Sands, Greenhouse Gases, and U.S. Oil
Supply Getting the Numbers Right—2012 Update; Adam Brandt, Upstream GHG Emissions from
Canadian Oil Sands as a Feedstock for European Refineries, 2011; and Joule Bergerson et al.,
Life Cycle Greenhouse Gas Emissions of Current Oil Sands Technologies: Surface Mining and In
Situ Applications, 2012. The Final EIS, however, retained a focus on the data and results from
AERI/Jacobs 2009, AERI/TIAX 2009, NETL 2008, and NETL 2009.
Findings
The primary studies—as well as the DOS/ICF meta-analysis—report the following findings:
• Comparisons across the published studies of GHG life-cycle emissions intensities
for fuels derived from different sources are sensitive to each study’s choice of
boundaries and input parameters.
• As reported in the studies, Well-to-Wheels GHG emissions for the full range of
Canadian oil sands crudes and production processes are valued between 101-120
gCO2e/MJ lower heating value (LHV)20 gasoline.
• As reported in NETL 2008, Well-to-Wheels GHG emissions for a select range of
Canadian oil sands crudes and production processes are valued between 101-110
gCO2e/MJ LHV gasoline.
• As reported in NETL 2008, Well-to-Wheels GHG emissions for the weighted
average21 of transportation fuels sold or distributed in the United States (in
reference year 2005) are valued at 91 gCO2e/megajoule (MJ) LHV gasoline.22
• As reported in NETL 2008, Canadian oil sands crudes emit an estimated 17%
more GHGs on a life-cycle basis than the weighted average of transportation
fuels sold or distributed in the United States (in reference year 2005).
• As reported in NETL 2008, discounting the final consumption phase of the life-
cycle assessment (which can contribute up to 70%-80% of Well-to-Wheels
20 The heating value of gasoline is the amount of heat released during the combustion of a specified amount. The
quantity known as higher heating value (HHV) is determined by bringing all the products of combustion back to the
original pre-combustion temperature, thus 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.
21 Weighted average computations refer to the assumed mix of crude types and production processes that make up the
bulk of a final product. The assumptions are based on reported industry practices, and are modeled differently in each
study. For example, calculations for the weighted average for “transportation fuels sold or distributed in the United
States” in 2005 can be found in NETL 2008. IHS CERA 2010 assumes an average 55% dilbit and 45% SCO for oil
sands crudes imported to United States, and NETL 2008 assumes 57% SCO and 43% crude bitumen.
22 This baseline is from NETL 2008. It assesses “the average life cycle GHG profile for transportation fuels sold or
distributed in the United States in 2005 [and] is determined based on the weighted average of fuels produced in the U.S.
plus fuels imported into the U.S. minus fuels produced in the U.S. but exported to other countries for use” (NETL
2008, p. ES-5). It includes Canadian oil sands crudes, but does not include emissions from some of the most carbon-
intensive imported crude oils (e.g., Venezuelan Heavy) due to modeling uncertainties (NETL 2008, p. ES-7; NETL
2009, p. ES-2). The baseline value 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.
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emissions), Canadian oil sands emit an estimated 80% more GHGs on a Well-to-
Tank (i.e., “production”) basis than the weighted average of transportation fuels
sold or distributed in the United States (in reference year 2005).
These numbers serve as averages, and are intended to reflect the range of estimates from the
primary studies. Conversely, individual estimates reported by each of the studies listed in Table
1—both primary and secondary—for various Canadian oil sands crude types and production
processes can be found in Figure 2 and Table 2.
Figure 2 illustrates the WTW GHG emissions estimates as reported by each of the studies for
various Canadian oil sands crude types and production processes. Table 2 summarizes and
compares each study’s emissions estimates, data, and relevant input assumptions. Variability
among the estimates is, in part, the result of each study’s differing design and input assumptions.
A discussion of these assumptions—and their estimated impacts on GHG emissions—follows in
the next section.
Several life-cycle GHG emissions assessments have been published since the release of the 2011
Final EIS. These studies include Jacobs 2012, IHS CERA 2012, Brandt 2011, and Bergerson
2012, among others. IHS CERA 2012 found that transportation fuels produced from oil sands
crudes result in average WTW GHG emissions that are 14% higher than the average crude refined
in the United States (results range from 5%-23% higher). Jacobs 2012 found that WTW GHG
intensities of transportation fuels produced from oil sands crudes are within 7%-12% of the
“upper range” of the WTW intensity of conventional crudes. Bergerson 2012 reported that
“although a high degree of variability exists in Well-to-Wheels emissions due to differences in
technologies employed, operating conditions, and product characteristics, the surface mining
dilbit and the in situ SCO pathways have the lowest and highest emissions, 88 and 120 g
CO2eq/MJ reformulated gasoline,” and that the lower values for certain oil sands production
activities “overlap with emissions in literature for conventional crude oil.”
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Figure 2. Well-to-Wheels 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 “the average life cycle GHG profile for transportation fuels sold or
distributed in the United States in 2005 [and] is determined based on the weighted average of fuels produced in
the U.S. plus fuels imported into the U.S. minus fuels produced in the U.S. but exported to other countries for
use” (NETL 2008, p. ES-5). This baseline includes Canadian oil sands crudes, but does not include emissions from
some of the most carbon-intensive imported crude oils (e.g., Venezuelan Heavy) due to modeling uncertainties
(NETL 2008, p. ES-7; NETL 2009, p. ES-2). The baseline number is internal y consistent only with the other
NETL findings reported in the figure.
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Table 2. Reported Findings of Well-to-Wheels GHG Emissions Estimates in the
Life-Cycle Assessments of Canadian Oil Sands Crudes
WTW
Production
Crude
GHG
Study
Method
Type
Emissions
Key Assumptions
LCAs analyzed in the Final EIS
WTW GHG emissions expressed in gCO2e/MJ LHV gasoline
U.S. EPA
Baseline
Varied
91
Baseline assesses “the average life cycle
2005/NETL
GHG profile for transportation fuels sold
2008
or distributed in the United States in 2005
[and] is determined based on the weighted
average of fuels produced in the U.S. plus
fuels imported into the U.S. minus fuels
produced in the U.S. but exported to other
countries for use" (NETL 2008, p. ES-5).
This baseline includes Canadian oil sands
crudes, but does not include emissions
from some of the most carbon-intensive
imported crude oils (e.g., Venezuelan
Heavy) due to modeling uncertainties
(NETL 2008, p. ES-7; NETL 2009, p. ES-2).
AERI/Jacobs
Mining +
SCO 108 Units:
gCO2e/MJ reformulated gasoline;
2009
Upgrading
petroleum coke stored at upgrader;
petroleum coke production emissions at
the refinery allocated to the premium fuel
products and sold as a substitute for coal in
electricity generation; 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
Units:
gCO2e/MJ reformulated gasoline;
2009
diluents processed with bitumen at
refinery; petroleum coke production
emissions at the refinery allocated to the
premium fuel products and sold as a
substitute for coal in electricity generation;
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 Units:
gCO2e/MJ reformulated gasoline;
2009
Upgrading
steam-to-oil ratio (SOR) of 3; petroleum
(Hydrocracking)
coke stored at upgrader; petroleum coke
production emissions at the refinery
allocated to the premium fuel products and
sold as a substitute for coal in electricity
generation; 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
Production
Crude
GHG
Study
Method
Type
Emissions Key
Assumptions
AERI/Jacobs In Situ, SAGD +
SCO 116 Units:
gCO2e/MJ reformulated gasoline;
2009
Upgrading
SOR 3; petroleum coke stored at upgrader;
(Coker)
petroleum coke production emissions at
the refinery allocated to the premium fuel
products and sold as a substitute for coal in
electricity generation; 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
Dilbit
105-113
Units: gCO2e/MJ reformulated gasoline;
2009
SOR 3; cogeneration credits applied;
diluents processed with bitumen at
refinery; petroleum coke production
emissions at the refinery allocated to the
premium fuel products and sold as a
substitute for coal in electricity generation;
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 Units:
gCO2e/MJ reformulated gasoline;
2009
Upgrading
petroleum coke production emissions at
upgrader allocated in part to the coke and
outside LCA; petroleum coke combustion
emissions at upgrader not included;
petroleum coke production emissions at
the refinery allocated to the premium fuel
products; petroleum coke combustion
emissions at refinery not included;
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 Units:
gCO2e/MJ reformulated gasoline;
2009
Upgrading
SOR 2.5; petroleum coke production
emissions at upgrader allocated in part to
the coke and outside LCA; petroleum coke
combustion emissions at upgrader not
included; cogeneration credits applied using
project specific data; petroleum coke
production emissions at the refinery
allocated to the premium fuel products;
petroleum coke combustion emissions at
refinery not included; 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.
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Canadian Oil Sands: Life-Cycle Assessments of Greenhouse Gas Emissions
WTW
Production
Crude
GHG
Study
Method
Type
Emissions Key
Assumptions
AERI/TIAX
In Situ, SAGD
Synbit
105-108
Units: gCO2e/MJ reformulated gasoline;
2009
SOR 2.5; cogeneration credits applied using
project specific data; petroleum coke
production emissions at the refinery
allocated to the premium fuel products;
petroleum coke combustion emissions at
refinery not included; 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
Units: gCO2e/MJ reformulated gasoline;
2009
SOR 2.5; cogeneration credits applied using
project specific data; diluents processed
with bitumen at refinery; petroleum coke
production emissions at the refinery
allocated to the premium fuel products;
petroleum coke combustion emissions at
refinery not included; 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
Units: gCO2e/MJ reformulated gasoline;
2009
SOR 3.4-4.8; cogeneration credits applied
using project specific data; petroleum coke
production emissions at the refinery
allocated to the premium fuel products;
petroleum coke combustion emissions at
refinery not included; 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
Dilbit
107-112
Units: gCO2e/MJ reformulated gasoline;
2009
SOR 3.4-4.8; cogeneration credits applied
using project specific data; diluents
processed with bitumen at refinery;
petroleum coke production emissions at
the refinery allocated to the premium fuel
products; petroleum coke combustion
emissions at refinery not included;
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
Production
Crude
GHG
Study
Method
Type
Emissions Key
Assumptions
NETL 2008
Mining +
SCO 101 Units:
gCO2e/MMBtu gasoline, diesel, and
Upgrading
jet fuel; petroleum coke use unspecified at
upgrader, petroleum coke production
emissions at refinery allocated outside
LCA; petroleum coke combustion
emissions at refinery allocated only if
combusted on site; 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
Units: gCO2e/MMBtu gasoline, diesel, and
jet fuel; SOR not stated; cogeneration
unspecified; diluents unspecified; petroleum
coke production emissions at refinery
allocated outside LCA; petroleum coke
combustion emissions at refinery allocated
only if combusted on site; 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 “the average life cycle
2005/NETL
GHG profile for transportation fuels sold
2008
or distributed in the United States in 2005
[and] is determined based on the weighted
average of fuels produced in the U.S. plus
fuels imported into the U.S. minus fuels
produced in the U.S. but exported to other
countries for use" (NETL 2008, p. ES-5).
Includes emissions from higher carbon-
intensity crude oils imported or produced
domestically.
GREET
Mining +
SCO 103 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 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
Production
Crude
GHG
Study
Method
Type
Emissions Key
Assumptions
McCulloch
Mining +
SCO 105-111 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 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
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 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
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
Production
Crude
GHG
Study
Method
Type
Emissions Key
Assumptions
NRCan
In Situ, CSS +
SCO 117 Units:
gCO2e/MJ reformulated gasoline;
2008
Upgrading
SOR not stated; 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, CSS
Dilbit
113
Units: gCO2e/MJ reformulated gasoline;
2008
SOR not stated; 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.
Additional LCAs analyzed by IHS CERA 2010
WTW GHG emissions expressed in KgCO2e/barrel of refined product (see notes below)
IHS CERA,
Average US
Varied
487
As modeled by IHS CERA from data
2010
Barrel
sourced from NETL 2008.
Consumed
IHS CERA,
Mining Dilbit 488
Units:
kgCO2e per barrel of refined
2010
products; diluents processed with bitumen
at refinery; emissions from upstream fuel
production not included; venting, flaring,
and fugitives not specified; infrastructure
and land-use changes not specified or not
included.
IHS CERA,
Mining +
SCO 518 Units:
kgCO2e per barrel of refined
2010
Upgrading
products; petroleum coke use unspecified
(Coker)
at the upgrader, allocated outside LCA at
refinery; 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.
IHS CERA,
In Situ, SAGD
Dilbit
512
Units: kgCO2e per barrel of refined
2010
products; SOR 3; cogeneration credits
applied; diluents processed with bitumen at
refinery; emissions from upstream fuel
production not included; venting, flaring,
and fugitives not specified; infrastructure
and land-use changes not specified or not
included.
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WTW
Production
Crude
GHG
Study
Method
Type
Emissions Key
Assumptions
IHS CERA,
In Situ, SAGD +
SCO 555 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.
The Final EIS 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 Final EIS was able to convert and directly compare IHS CERA’s functional units to the other studies.
(Author’s note: IHS CERA has since converted its calculations in the update to its report.)
Design Factors and Input Assumptions for Life-Cycle Assessments
of Canadian Oil Sands Crudes
Most published and publicly available studies on the life-cycle GHG emissions data for Canadian
oil sands crudes identify two main factors contributing to the difference in emissions intensity
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; and
2. oil sands are chemically 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 by U.S. standards.
While most studies agree that Canadian oil sands crudes are, on average, 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, but are not limited to, the following:
• 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
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averaged barrel of refined product. Some studies report emissions per unit of
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,” among others. 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 crudes—or any
hydrocarbon—production.
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• Treatment of Petroleum Coke. Petroleum coke (a source of excess 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. Bitumen refining can produce 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 crudes 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) consumed (for process
heat, electricity, or hydrogen production); (2) stored; or (3) sold as a fuel for
combustion. In contrast, the studies assume that petroleum coke produced at the
refinery that is not consumed by the refinery itself is either (1) used to back out
coal combustion for electricity generation; or (2) allocated outside of the LCA.23
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
incremental 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—may 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
23 Jacobs 2009 assumed that all coke is stockpiled, noting that “the practice of storing coke is typical” and that “the
transport costs of marketing the material from Alberta exceed its value” (p. 4-10). In contrast, TIAX 2009 examines
three scenarios where petroleum coke at upgraders is either used as a fuel, sold as a product, or buried. In comments to
TIAX’s report, Suncor Energy noted that 34% of the coke generated by upgrading bitumen is consumed in the
production of SCO and that the rest is sold or stockpiled (p. G-3).
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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
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 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.24 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 crudes 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 crudes. 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.25 Methane emissions from oil sands mining and tailings
ponds may have an even larger impact, contributing from 0% to 9% of total GHG
24 As described in the Final EIS, 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.
25 Environment Canada, National Inventory Report: 1990-2008 Greenhouse Gas Sources and Sinks in Canada, 2010.
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Canadian Oil Sands: Life-Cycle Assessments of Greenhouse Gas Emissions
emissions.26 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.
• 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. Charpentier
2009 discusses the need to more fully investigate and include these potentially
significant supply chain infrastructure GHG emissions in future life-cycle studies
of oil sands crudes.
• 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 in
some cases, and highly dependent upon the reclamation activities employed after
use. 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 U.S. average). The
range was dependent on the type of lands displaced, with the removal of peatland
having the largest impact and certain in situ facilities having the least impact.
None of the life-cycle studies reviewed, however, includes land-use change GHG
emissions in the WTW life-cycle assessment.27 Some recent studies, including
the 2014 Final EIS, have begun to assess the effects.28
Life-Cycle Assessments of Canadian Oil Sands Crudes
versus Other Reference Crudes
To compare the life-cycle GHG emissions intensities 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
compared Well-to-Wheels 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). NETL 2009 reported the following:
• Well-to-Wheels GHG emissions from gasoline produced from a weighted
average of Canadian oil sands crudes imported to the United States are
26 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.
27 For a more detailed description of how land-use changes can be modeled into LCAs, see CRS Report R40460,
Calculation of Lifecycle Greenhouse Gas Emissions for the Renewable Fuel Standard (RFS), by Brent D. Yacobucci
and Kelsi Bracmort.
28 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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approximately 17% higher than those from gasoline derived from the weighted
average of transportation fuels sold or distributed in the United States in the
reference year 2005. This corresponds to an increase in Well-to-Tank (i.e.,
“production”) GHG emissions of 80% over the weighted average of
transportation fuels sold or distributed in the United States in the reference year
2005 (18 gCO2e/MJ).
• Compared to a few selected imports, Well-to-Wheels 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.29 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.
• Compared to selected energy- and resource-intensive crudes, Well-to-Wheels
GHG emissions from gasoline produced from a weighted average of Canadian oil
sands crudes are found to be “within range” of those produced from heavier
crudes such as Venezuelan Bachaquero and Californian Kern River, as well as
lighter crudes that are produced from operations that flare associated gas (e.g.,
Nigerian Bonny Light).
Individual estimates of WTW GHG emissions from Canadian oil sands crudes from the primary
studies listed in Table 1 range from 9% to 19% more GHG-intensive than Middle Eastern Sour,
5% to 13% more GHG-intensive than Mexican Maya, and 2% to 18% more GHG-intensive than
various Venezuelan crudes (including both Venezuelan Conventional and Bachaquero).
Design Factors and Input Assumptions for Life-Cycle Assessments
of Reference Crudes
Similar to LCAs conducted on Canadian oil sands crudes, assessments of other global crude
resources confront many variables and uncertainties in available data. Likewise, these
assessments are bounded by specific design factors and input assumptions that can affect the
quality of the results. Conditions that may impact the results include the following:
• Choice of Reference Crudes Studied. Crude oil resources around the world
vary significantly in regard to resource quality and production methods. Thus,
GHG emissions intensities may also vary significantly. The results of
comparisons between Canadian oil sands crudes and other global crudes may
depend on which crudes are used as a reference and/or which crudes are
evaluated to determine a baseline. Some studies suggest that GHG emissions
intensities of Canadian oil sands crudes should be measured against a global
average in order to assess the full environmental impacts of the resource. Others
believe they should be measured against an average of all crudes consumed in a
given marketplace (e.g., a particular country or region, like the United States or
the European Union). Still others argue that Canadian oil sands crudes should be
29 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 Life-Cycle Assessments
of Reference Crudes.”
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measured against a representative basket of crudes they may displace in
production (e.g., crudes potentially displaced by Canadian oil sands crudes at
U.S. PADD III refineries; or, more specifically, only “heavy” crudes potentially
displaced at U.S. PADD III refineries).30
• Sensitivity to Water-Oil and Gas-Oil Ratios. Due to the complex nature of
crude oil production systems and resource reservoirs, studies often use ratios to
describe the fraction of the flow from a well that is oil, water, and gas. The use of
ratios simplifies the relationship between energy use and GHG emissions and
may fail to accurately report the variability across differing resources. Further,
assumptions regarding venting or flaring of associated gas, and fugitive
emissions from produced water, may further impact GHG emissions intensities.
• Transportation Emissions. Assumptions regarding how LCAs account for the
contribution of transportation may impact WTW GHG emissions estimates to a
small degree. These include 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.
• Uncertainty Analysis. Accurately measuring GHG emissions intensities is
highly uncertain. Few of the studies listed in Table 1 fully consider associated
uncertainty, and none of them rigorously treat underlying uncertainties in data
inputs and models. Most calculate averages from a wide range of values and
develop point estimates without providing statistical bounds. These bounds may
prove to be important if their ranges are shown to overlap with other results.
• Data Transparency. The quality of the data and the transparency in presentation
vary considerably by study. Most studies do not provide complete transparency in
their methodologies, assumptions, or data sources. This is partially a function of
the difficulty in accessing necessary data elements from the field. Data on the
Canadian oil sands are more robust than some global resources and less robust
than others. Lack of transparency impedes the ability to make meaningful
comparisons of the results for oil sands crudes and reference crudes.
30 Each of the studies listed in Table 1 makes different assumptions regarding reference crudes and baselines. NETL
2009 assumes that resources from Venezuela or Mexico may likely be the first displaced by Canadian oil sands crudes
in U.S. refineries. However, to the extent that a crude like Saudi Light (i.e., Middle Eastern Sour) is the world’s
balancing crude, NETL also suggests that it may ultimately be the resource backed out of the global market by
increased Canadian oil sands production. 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 R42465, U.S. Oil Imports and Exports, by Robert Pirog.
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Figure 3. Well-to-Wheels 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.
Notes: U.S. EPA 2005 (U.S. Average) assesses “the average life cycle GHG profile for transportation fuels sold
or distributed in the United States in 2005 [and] is determined based on the weighted average of fuels produced
in the U.S. plus fuels imported into the U.S. minus fuels produced in the U.S. but exported to other countries for
use” (NETL 2008, p. ES-5). This baseline includes Canadian oil sands crudes, but does not include emissions from
some of the most carbon-intensive imported crude oils (e.g., Venezuelan Heavy) due to modeling uncertainties
(NETL 2008, p. ES-7; NETL 2009, p. ES-2). 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.
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Life-Cycle Assessments of Canadian Oil Sands Crudes
versus Other Fuel Resources
Figure 4 offers a comparison of the life-cycle GHG emissions intensities 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.
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.
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Canadian Oil Sands: Life-Cycle Assessments of Greenhouse Gas Emissions
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
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.
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 well
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.
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Magnitude of
Source’s GHG
Impact
Source of GHG
Mitigation Activity
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.
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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