Study No. 143 July 2014
CANADIAN ENERGY OIL SANDS ENVIRONMENTAL RESEARCH IMPACTS INSTITUTE
Canadian Energy Research Institute | Relevant • Independent • Objective
OIL SANDS ENVIRONMENTAL IMPACTS
Oil Sands Environmental Impacts
Copyright © Canadian Energy Research Institute, 2014 Sections of this study may be reproduced in magazines and newspapers with acknowledgement to the Canadian Energy Research Institute
ISBN 1-927037-27-0
Authors: Rob McWhinney
Acknowledgements: The author of this report would like to extend his thanks and sincere gratitude to all CERI staff that provided insightful comments and essential data inputs required for the completion of this report, as well as those involved in the production, reviewing, and editing of the material, including but not limited to Peter Howard and Megan Murphy
CANADIAN ENERGY RESEARCH INSTITUTE 150, 3512 – 33 Street NW Calgary, Alberta T2L 2A6 Canada www.ceri.ca
July 2014 Printed in Canada
Front Cover Photo Courtesy of https://www.flickr.com/photos/suncorenergy/5014474029/in/photostream/
July 2014 Oil Sands Environmental Impacts iii
Table of Contents
LIST OF FIGURES ...... v LIST OF TABLES ...... vii CHAPTER 1 INTRODUCTION ...... 1 Oil Sands ...... 1 Mining ...... 3 In Situ ...... 5 Scope ...... 6 CHAPTER 2 GREENHOUSE GAS EMISSIONS...... 7 Introduction ...... 7 Oil Sands Emissions in a Global and Canadian Context ...... 8 Current Trends in Oil Sands Greenhouse Gas Emissions ...... 10 Mining and Upgrading ...... 11 In Situ ...... 15 Life-Cycle GHG Emissions of Oil Sands Fuels ...... 20 Highlights of WTW Results for Oil Sands Fuels ...... 23 Specified Gas Emitters Regulation ...... 27 CCEMC Projects ...... 29 CHAPTER 3 AIR EMISSIONS ...... 31 Introduction ...... 31 Reported Emissions – NPRI ...... 31 Criteria Air Contaminants ...... 32 Heavy Metals and Polycyclic Aromatic Hydrocarbons ...... 36 Soil and Lake Acidification ...... 37 Other Emissions and Air Quality Observations ...... 40 CHAPTER 4 WATER AND TAILINGS ...... 43 Water Use ...... 43 Mining ...... 43 In Situ ...... 45 In Situ Water Regulations ...... 47 CHAPTER 5 LAND USE AND BIODIVERSITY...... 49 Introduction ...... 49 Land Disturbance in the Oil Sands Region ...... 49 Biodiversity Impacts ...... 52 Biodiversity Intactness ...... 52 Non-Native Plants ...... 53 Woodland Caribou...... 54 Reclamation ...... 56
July 2014 iv Canadian Energy Research Institute
CHAPTER 6 MONITORING ...... 59 Current Monitoring Programs ...... 59 AEMERA ...... 61 CHAPTER 7 CONCLUSIONS ...... 63 LIST OF ABBREVIATIONS ...... 65
July 2014 Oil Sands Environmental Impacts v
List of Figures
1.1 Oil Sands Regions in Alberta ...... 2 2.1 2010 World, Canadian and Oil Sands GHG Emissions ...... 8 2.2 Canadian GHG Emissions by Sector, 1990-2020 With 2020 Emissions Forecast ...... 9 2.3 Breakdown of 2005, 2011 and Forecast 2020 Oil and Gas Emissions in Canada ...... 10 2.4 Absolute GHG Emissions and GHG Emission Intensities for Oil Sands Mining and Upgrading Projects, 2004-2012 ...... 11 2.5 Absolute GHG Emissions and GHG Emission Intensities for Oil Sands Mining and Upgrading Projects, Broken Down by Individual Project, 2004-2012 ...... 12 2.6 Shell GHG Emissions by Facility, 2004-2012 ...... 15 2.7 Absolute GHG Emissions and GHG Emission Intensities for Oil Sands In Situ Projects, 2004-2012 ...... 16 2.8 GHG Emissions Intensities for all Thermal In Situ Producers Reporting as of 2004 ...... 17 2.9 GHG Emissions Intensities for all Thermal In Situ Producers Reporting Later than 2004 ...... 18 2.10 2012 GHG Emissions Intensity as a Function of Steam-Oil Ratio for Thermal In Situ Projects ...... 19 2.11 Range of GHG Emissions Intensities for Dilbit, Synbit, and SCO from Coking and Hydrocracking for Bitumen Obtained from SAGD, CSS, and Surface Mining ...... 24 2.12 Refining and Upgrading Emissions for SCO Produced by Either Coker or Hydrocracking (Eb-Bed), Bitumen, or Dilbit ...... 25 3.1 Receptor Acid Sensitivity Map of Alberta ...... 39 3.2 Modeled Acid Deposition as a Percentage of the Monitoring Load, 2006 and Projected for 2020 ...... 39 4.1 Fresh Water Usage by Oil Sands Mining Operations, 2005-2013 ...... 43 4.2 Fresh and Brackish Water Use by In Situ Oil Sands Producers ...... 46 5.1 Land Disturbance in the Oil Sands Regions...... 50 5.2 Human Footprint in the Oil Sands Regions of Alberta ...... 51 5.3 Caribou Ranges in Alberta...... 55 5.4 Land Disturbance and Reclamation Status of Oil Sands Projects as of December 31, 2012 ...... 57
July 2014 vi Canadian Energy Research Institute
July 2014 Oil Sands Environmental Impacts vii
List of Tables
1.1 Mineable and In Situ Bitumen Reserves and Production ...... 3 2.1 WTW GHG Emission Ranges for Conventional Crude Oil, Mined and Upgraded Bitumen, and In Situ Dilbit for Production of European Diesel Fuel ...... 26 2.2 SGER Compliance Information for In Situ Oil Sands Producers ...... 28 2.3 SGER Compliance Information for Mining and Upgrading Oil Sands Producers ...... 29 3.1 Canada-wide 2012 CAC Emissions from Oil Sands and Other Sectors ...... 33 3.2 Percentage Contribution of Oil Sands to Total Industrial and Anthropogenic Canadian Emissions in 2012 ...... 34 3.3 Ratio of Absolute Emissions and Emissions Intensity in 2011-2012 to Emissions Intensity in 2004-2005 for Criteria Air Contaminants ...... 35 3.4 Critical, Target, and Monitoring Loads for High, Moderate, and Low Sensitivity Regions in Alberta...... 38 4.1 Required Fines Disposal Under Directive 74 and Mine Performance ...... 45 4.2 IL 89-5 Based Recycle Rates and Directive 81 Based Disposal Limits and Rates ...... 47 4.3 Disposal Factors for Thermal In Situ Oil Sands Producers ...... 48 5.1 Selected non-Native Plants in the Athabasca Oil Sands Region in 2010 and Across all Oil Sands Regions in 2012 ...... 54
July 2014 viii Canadian Energy Research Institute
July 2014 Oil Sands Environmental Impacts 1
Chapter 1: Introduction
This report aims to provide the reader with an overview of the current environmental impacts of development of the oil sands resource in the province of Alberta. Current expansion plans have come under increasing scrutiny both domestically and internationally, with concerns ranging from greenhouse gas emissions, water and land impacts, air and water contamination, and effects on biodiversity. Oil Sands The Canadian oil sands resource is primarily located in northeastern Alberta. The resource consists of three main deposits: the Athabasca, Peace River, and Cold Lake deposits, shown in Figure 1.1. Unlike conventional oil deposits, oil sands contain bitumen, a heavy, viscous (that is, highly resistant to flow) petroleum resource. The high viscosity of the substance means that, unlike conventional oil reserves that can be pumped directly from the ground, oil sands must undergo more advanced production methods. And, while this is more technically demanding than conventional oil production, high oil prices and the sheer size of the oil sands deposits (167 billion barrels of remaining reserves as of 2013, compared to 1.8 billion barrels for conventional oil), oil sands production is now the largest oil source in Alberta at 761 million barrels in 2013 (compared to 213 million barrels for crude oil).1
1 Alberta Energy Regulator ST98 (2014). Alberta’s Energy Reserves 2013 and Supply/Demand Outlook 2014-2023. http://www.aer.ca/documents/sts/ST98/ST98-2014.pdf
July 2014 2 Canadian Energy Research Institute
Figure 1.1: Oil Sands Regions in Alberta
Source: Government of Alberta
There are two major methods of bitumen extraction. Mining of bitumen involves the open-face mining of oil sands ore. Ore is transported to a central processing plant, where the bitumen is separated from the sand and subsequently upgraded to synthetic crude oil. Mining can only be effective for bitumen deposits located sufficiently close to the surface (up to roughly 75 metres in depth below the surface). In situ bitumen extraction refers to the extraction of bitumen directly from the ground. As the bitumen does not flow naturally at the reservoir temperature, the viscosity of the bitumen must first be lowered to allow the bitumen to be pumped out of the ground. This is typically achieved by injecting steam into a well, which heats the bitumen, reducing its viscosity and allowing it to be pumped from the well.
July 2014 Oil Sands Environmental Impacts 3
While mining is a more mature production method, it has been surpassed by in situ extraction. As of 2013, 430 million barrels of bitumen are produced by in situ projects and 359 million barrels are produced by mining projects (see Table 1.1). The large reserves of in situ bitumen mean that in situ is likely to continue to remain the dominant form of extraction. The two production methods are different and unique, and result in different potentials for environmental impacts.
Table 1.1: Mineable and In Situ Bitumen Reserves and Production (billions of barrels, 2013)
Mining In Situ Total Initial Established Reserves 38.7 138.0 176.7 Cumulative Production 5.9 3.4 9.2 Remaining Established Reserves 32.9 134.2 167.1 Current Annual Production 0.36 0.40 0.76 Source: AER ST98
Mining Mining was established considerably before in situ production became commonplace, as there were fewer technical hurdles to clear. To mine bitumen, the oil sands ore is first cleared of overburden (the earth located above the productive bitumen resource; overburden is typically stored on site to be reused to fill in the pit left from when the mine area is reclaimed). The ore is then excavated and transported to a central ore processing site. Traditionally this was accomplished using bucket wheels, draglines and conveyors. Recently, this has been replaced using shovel-and-truck excavation and hydro transport. The process of hydro transport mixes the ore with warm water and sodium hydroxide, generating an ore-and-water slurry that is piped to the extraction plant. The process is less energy-intensive than the conveyor method, and has the added benefit of pre-conditioning the ore prior to froth treatment.
At the central extraction plant, the slurry is mixed with a hydrocarbon solvent and the mixture is heated and agitated, generating a bitumen froth that floats to the top of the water mixture and can be skimmed off the surface. The water and solids left behind, known as tailings, are sent for secondary treatment to remove residual bitumen and solvent. After the bitumen has been removed, the tailings are either sent to fine tailings treatment (to be discussed in Chapter 4) or are pumped to large holding ponds, known as tailings ponds. Water that is sufficiently free of solids can be reused for bitumen froth treatment, and the remainder is left until the solids settle enough that they can be used for land reclamation. However, as will be discussed in more detail in a later chapter, this process can take several decades due to the nature of the solid clay particles in the mine tailings.
After separation, the hydrocarbon solvent (commonly referred to as diluent) is recovered for reuse in froth treatment, and the bitumen is sent to an upgrader. The process of upgrading can be thought of as a preliminary refining process, converting bitumen to lighter fractions with fewer contaminants. To obtain light hydrocarbons, the basic hydrocarbon molecules need to be made smaller in average size, and this requires increasing the hydrogen-to-carbon ratio of the oil. This
July 2014 4 Canadian Energy Research Institute
typically involves sending the bitumen to either a coker or hydrotreating unit. The former operates by removing carbon in the form of petroleum coke, while the latter adds hydrogen to the molecules, which increases the overall yield of SCO.
Upgrading the oil to a synthetic crude oil is required in order to transport the bitumen via pipeline, as the bitumen contains residual water and solids from the froth treatment process in addition to corrosive impurities within the oil, including sulphur and heavy metals. Requirements for upgrading can vary depending on the froth treatment technique used. If naphtha is used for the hydrocarbon solvent, as is the most common technique, the upgrading requirements are more substantial. If paraffinic solvent is used instead, the upgrading requirements can be lower or even eliminated, as asphaltenes, one of the heaviest, lowest-value fractions of the bitumen, do not readily dissolve in paraffinic solvents, making them easier to separate.
Throughout the mining process, there are a number of potential areas for environmental concern. These include:
Land use change and reclamation: the mining region contains a high number of natural wetlands, which are important habitats and very difficult to restore to their natural condition. In addition, some mine features, such as tailings ponds, are difficult to reclaim. Energy use and greenhouse gas emissions: the mining process consumes considerable energy. Fuel is required for the mining vehicles, for heating the water for hydro transport and bitumen extraction, and for the upgrading of bitumen to synthetic crude oil. This energy is typically derived from the burning of fossil fuels, which releases greenhouse gases that contribute to climate change. Air pollutant emissions: exhaust from mining vehicles and stack emissions from the processing plants and upgraders can contribute to local air pollution. Exposed mine surfaces can release volatile organic compounds and dust, while contaminated tailings ponds can release pollutants as well through direct evaporation or activity of microorganisms. Water use: a substantial amount of water is required for the separation of bitumen from the oil sands ore, which must be obtained from local fresh water sources such as the Athabasca River. As some extraction water is tied up in tailings, new water must be used on a regular basis, which removes it from the local fresh water systems. Water pollution: tailings pond water contains several contaminants from the oil sands extraction process, some of which are toxic to aquatic life. There is concern about tailings water entering the water system and the effect this might have on aquatic life, and wildlife entering the ponds themselves can be adversely affected.
Current commercial mining projects include projects by Suncor, Syncrude (Mildred Lake and Aurora Mines), Shell (Muskeg River and Jackpine Mines, as well as the Scotford Upgrader located in Alberta’s Industrial Heartland near Fort Saskatchewan), and CNRL Horizon. The Suncor Fort Hills and Imperial Kearl Lake mines are under development.
July 2014 Oil Sands Environmental Impacts 5
In Situ The in situ process as it currently operates commercially uses steam to heat the bitumen within the reservoir until it has a sufficient flow rate that it can be pumped to the surface. Two distinct techniques are currently used. The oldest but less common technique is known as cyclic steam stimulation, or CSS. As the name suggests, CSS is a cyclic technique using a single well. The first stage in the process is to inject high-pressure steam into the reservoir, which is allowed to soak for a time to allow for heat transfer, followed by pumping the heated bitumen back through the same well. The newer, but more common technique is known as steam assisted gravity drainage, or SAGD. In this process, horizontal wells are drilled in pairs. The top well is an injection well, where high-quality steam is continuously injected into the well to heat the surrounding bitumen. Approximately 5 metres below this well is the producing well, where heated bitumen and condensed water are collected and pumped out of the well.
In situ extraction is a simpler process in comparison to mining. Most in situ projects do not make use of upgraders (although currently the CNOOC/Nexen Long Lake project does make use of an integrated upgrading process, and two Suncor operated in situ projects, MacKay River and Firebag, currently send produced bitumen to the Suncor mine for upgrading), and instead mix produced bitumen with a hydrocarbon solvent diluent to produce what is known as dilbit for transport to refineries. Most of the above-ground portion of an in situ plant is devoted to water treatment and steam generation, particularly due to regulations in place that encourage reuse of produced water from the well and use of high-salinity groundwater rather than freshwater. Since the generation of the steam is the primary user of energy for thermal in situ projects, the steam- oil ratio (SOR; the volume of cold water needed to produce steam for a unit volume of bitumen) is a key performance driver. Lower SOR means less water and natural gas requirements, and thus lower production costs and environmental impacts.
In situ projects have their own unique potential for environmental impacts, including:
Energy usage and greenhouse gases: the process of generating high pressure and high quality steam is very energy-intensive and uses natural gas to operate, which leads to greenhouse gas emissions. Water use: the generation of steam of course requires water, which can come from surface water or groundwater. This leads to concerns of disrupting local surface and groundwater supplies, particularly if produced water is not sufficiently recycled. Surface blowout and groundwater contamination: in situ requires that the oil sands formation be deep enough and the cap rock above the formation be strong enough that the steam stays within the reservoir. This is of particular concern for CSS operations, which allow injected steam to soak in the reservoir over time before bitumen extraction. Land disturbance: since the extraction process takes place mostly underground, the surface footprint of in situ projects is considerably smaller than for surface mines. However, to characterize the reservoir, seismic lines are cut above ground, and these linear disturbances can affect animal habitat.
July 2014 6 Canadian Energy Research Institute
Air emissions: although in situ primarily uses cleaner-burning natural gas a fuel source, there are still air pollutant emissions that arise from operation beyond greenhouse gases. Scope This particular report will be focusing on the overview of environmental impacts of mining, upgrading, and thermal in situ projects (there are a number of primary and enhanced recovery projects located within the three oil sands areas). Due to availability and consistency of data, the discussion will also be limited to those projects within Alberta, although there are thermal in situ projects as well as an upgrader located in Saskatchewan. The effects discussed will be related to greenhouse gases, air pollutant emissions, water use, water quality, land disturbance, and impacts on biodiversity.
In addition, in discussing in situ projects, the CNOOC/Nexen Long Lake project will in most cases not be included in the discussion for the sector as a whole, particularly in the case of greenhouse gas emissions. This project produces synthetic crude oil rather than bitumen through a proprietary OrCrude process, which removes asphaltenes.2 The asphaltenes are then gasified to produce syngas (a mixture of carbon monoxide and hydrogen); a portion of the hydrogen is sent to a hydrocracker, which upgrades the bitumen into lighter fractions and removes sulphur impurities. The process is quite energy-intensive and, as will be discussed later, results in much high greenhouse gas emissions per barrel of produced synthetic crude oil. The operations of Long Lake are not a typical setup, and unless otherwise specified, this particular operation is not included when the in situ sector is discussed as a whole.
2 CNOOC-Nexen: How Long Lake Works. http://www.nexencnoocltd.com/en/Operations/OilSands/HowLongLakeWorks.aspx
July 2014 Oil Sands Environmental Impacts 7
Chapter 2: Greenhouse Gas Emissions
Introduction Greenhouse gases (GHG) are a class of gases in the earth’s atmosphere that play a key role in establishing the average surface temperature by altering the amount of heat radiation that is emitted from the earth into space. This process, known as the greenhouse effect, occurs naturally in the absence of human activity through the presence of such gases as carbon dioxide (CO2), methane (CH4), and water vapour. In the absence of an atmosphere containing GHGs, the average temperature of the earth’s surface would be approximately -18 degrees Celsius to be in balance with the light energy it receives from the sun.1 GHGs trap some of this outgoing infrared radiation at the surface of the earth, however, resulting in average temperatures about 33 degrees higher than in the absence of the greenhouse effect.
Anthropogenic (i.e., human produced) emissions of GHGs have been steadily increasing since the start of the industrial revolution. The main driver behind this increase is through the burning of carbon-containing fossil fuels such as coal, oil, and natural gas. Combustion of fossil fuels liberates a great amount of useful energy, but simultaneously oxidizes the carbon within the fuel to generate CO2. Prior to industrialization, CO2 concentrations in the atmosphere were approximately 270 parts per million (ppm) based on ice core data. In 2013, average 2 concentrations of CO2 at the Mauna Loa Observatory in Hawaii were approximately 396 ppm. The Fifth Assessment Report of the Intergovernmental Panel on Climate Change, the main international authority producing climate change assessments, states that human activity, including the release of anthropogenic GHGs, is extremely likely (with more than 95 percent certainty) to be the cause of observed warming since the mid-twentieth century.3 As outlined by a recent report from the Climate Change Impacts and Adaptation Division of Natural Resources Canada, Canadian temperatures have increased at approximately double the rate of the global average, and climate change is expected to have broad effects on weather, industry, the environment, and health.4 The effects range from adverse to beneficial, but all require some degree of planning and investment to adapt to in the future.
As such, there is an ongoing global effort through a number of processes to reduce anthropogenic GHG emissions in order to keep potential problems associated with climate change to a minimum. One mechanism aimed at reducing emissions is the use of international agreements under which countries commit to reducing GHG emissions. Canada committed in 2009 (during the United Nations Framework Convention on Climate Change [UNFCCC] 15th Conference of
1 Jacob (1999). Introduction to Atmospheric Chemistry. Princeton University Press. http://acmg.seas.harvard.edu/publications/jacobbook/index.html 2 Data from National Oceanic & Atmospheric Administration Earth System Research Laboratory: http://www.esrl.noaa.gov/gmd/obop/mlo/ 3 http://www.ipcc.ch/report/ar5/index.shtml 4 Canada in a Changing Climate: Sector Perspectives on Impacts and Adaptation (2014), Natural Resources Canada, Cat. No. M174-2/2014E-PDF. http://www.nrcan.gc.ca/environment/resources/publications/impacts- adaptation/reports/assessments/2014/16309
July 2014 8 Canadian Energy Research Institute
Parties in Copenhagen5) to reduce the country’s GHG emissions to 17 percent below 2005 levels as of 2020. Emissions as of 2005 were 736 megatonnes (Mt) of carbon dioxide equivalents (CO2e; non-CO2 GHGs are converted to an equivalent emission of CO2 to ease comparison), making the target under the Copenhagen Accord 611 Mt CO2e in 2020.6 Oil Sands Emissions in a Global and Canadian Context Direct emissions from the oil sands themselves contribute a small amount to global anthropogenic GHG emissions, as illustrated in Figure 2.1. Global estimates of total emissions are uncertain. The most recent estimate of global GHG emissions in the Fifth Assessment Report is 7 for 2010, where approximately 49 Gt CO2e were emitted. Canada’s 2014 National Inventory Report submitted that 699 Mt were emitted in 2010 with 52 Mt coming from oil sands activity, 8.7 percent of Canadian GHG emissions. Although this is a sizeable contribution to Canada’s GHG emissions, Canada is a small contributor to total global emissions (about 1.4 percent). At approximately 0.1% of total global emissions in 2010, even a drastic decrease in the emissions from the oil sands sector will do relatively little to reduce world GHG emissions in the absence of reduction efforts from other countries and industries.
Figure 2.1: 2010 World, Canadian and Oil Sands GHG Emissions
World Canada Oil Sands
Source: IPCC Fifth Assessment Report on Climate Change; Environment Canada 2014 National Inventory Report
However, while oil sands emissions are small in a global context, the relative importance is larger in the context of Canadian emissions and national commitments to GHG abatement. In the most recent GHG inventory submission to the UNFCCC, Canada reported emissions of 699 Mt CO2e for the 2012 reporting year. This represents a 5 percent reduction from 2005 emissions, with the majority of the reduction coming from a combination of slowed economic growth from the 2008
5 For more information on the Copenhagen Climate Change Conference: http://unfccc.int/meetings/copenhagen_dec_2009/meeting/6295.php 6 National Inventory Report 1990–2012: Greenhouse Gas Sources and Sinks in Canada. Environment Canada. http://unfccc.int/files/national_reports/annex_i_ghg_inventories/national_inventories_submissions/application/zip/can-2014- nir-11apr.zip 7 IPCC (2014). Intergovernmental Panel on Climate Change Working Group III – Mitigation of Climate Change. Technical Summary: Working Group III Contribution to the IPCC Fifth Assessment Report. http://report.mitigation2014.org/drafts/final- draft-postplenary/ipcc_wg3_ar5_final-draft_postplenary_technical-summary.pdf
July 2014 Oil Sands Environmental Impacts 9
recession, the phase-out of coal-fired electricity generation in Ontario, and reduction of emissions from emission-intensive industries such as cement, smelting, and pulp and paper.
While overall emissions have fallen, the oil and gas sector has grown by 9 percent from 159 to 173 Mt CO2e between 2005 and 2012, and are projected to total 200 Mt CO2e by year 2020 (Figure 2.2). The largest contributor to this increase is from further oil sands developments; the Alberta Energy Regulator has projected a 151 percent increase in mined bitumen and a 372 percent increase in bitumen from in situ extraction between 2005 and 2020. 8 As a result, Environment Canada projects GHG emissions to increase from 34 Mt CO2e in 2005 to 101 Mt CO2e in 2020, eventually contributing to more than half of total oil and gas emissions (Figure 2.3). If considered as a separate economic sector, the magnitude of emissions will be second only to transportation by 2020. Environment Canada currently estimates that emissions in 2020 will only be 0.4 percent below 2005 levels, compared to 9.5 percent below 2005 in the absence of GHG emissions growth in the oil sands sector. Increasing production in this sector makes the meeting of international commitments increasingly difficult to meet, and thus there is interest in reducing the amount of GHGs emitted to extract bitumen from the oil sands and generate synthetic crude oil.
Figure 2.2: Canadian GHG Emissions by Sector, 1990-2012 with 2020 Emissions Forecast
900
800
700 e)
2 Waste and Others 600 Agriculture 500 Buildings EITEI 400 Transportation 300 Electricity
GHG Emissions GHGEmissions (Mt CO Oil and Gas 200
100
0 1990 2000 2005 2008 2009 2010 2011 2012 2020
Source: Environment Canada (2014 National Inventory Report)
8 ST98: Alberta’s Energy Reserves & Supply/Demand Outlook. Alberta Energy Regulator. http://www.aer.ca/data-and- publications/statistical-reports/st98
July 2014 10 Canadian Energy Research Institute
Figure 2.3: Breakdown of 2005, 2011 and Forecast 2020 Oil and Gas Emissions in Canada
250 LNG Production
200 Downstream Oil and Gas e) 2 Transmission 150 Oil Sands Upgrading
Oil Sands Mining 100
Oil Sands In Situ GHG Emissions GHGEmissions (Mt CO
50 Conventional Oil Production Natural Gas Production 0 and Processing 2005 2012 2020
Source: Environment Canada (2013 Emissions Trends, 2014 National Inventory Report) Current Trends in Oil Sands Greenhouse Gas Emissions When discussing greenhouse gas emissions of oil sands projects, it is useful to examine two metrics. The first is absolute emissions, which is the total mass of GHGs emitted by the industry. This is the most environmentally relevant metric to look at, as the climate response depends solely on how much gas is emitted to the atmosphere. However, since the amount of energy used (and thus the amount of GHG emitted) depends highly on the amount of production, the efficacy of emissions reductions efforts can be lost if production at a given project increases. An alternative to examining absolute GHG emissions is to look at emissions intensity, where the amount of GHG emitted is normalized to the volume of bitumen or SCO produced. While increases in production can easily overshadow the benefits of emission reduction, looking at the emissions intensity of a project allows one to determine if efforts to increase the efficiency of the bitumen or SCO production process are effective.
GHG data discussed hereafter is from the Environment Canada greenhouse gas reporting system9 and is available from years 2004 to 2012, while production data is obtained from the ERCB/AER statistical reports for mining and in situ oil sands production (ST3910 and ST5311, respectively). Since facility reporting is only available from 2004 onward, earlier progress in reducing emission intensity cannot be observed from this data. From Environment Canada’s most recent National Inventory Report to the UNFCCC, absolute emissions from the oil sands have roughly quadrupled
9 Facility Greenhouse Gas Reporting, Environment Canada. http://www.ec.gc.ca/ges-ghg/default.asp?lang=En&n=040E378D-1 10 http://www.aer.ca/data-and-publications/statistical-reports/st39 11 http://www.aer.ca/data-and-publications/statistical-reports/st53
July 2014 Oil Sands Environmental Impacts 11
from 15 Mt in 1990 to 61 Mt in 2012. Emission intensity of the sector, however, has fallen by 28 percent from 121 kg CO2e per barrel in 1990 to 87 kg CO2e per barrel in 2012.
Mining and Upgrading Emissions for the mining of bitumen and upgrading to synthetic crude oil (SCO) are shown in Figure 2.4. Between 2004 and 2012, reported GHG emissions rose from 21.6 to 31.1 Mt CO2 at an average rate of 1.2 Mt per year, or about 5.6 percent per year based on 2004 emissions.
Figure 2.4: Absolute GHG Emissions and GHG Emission Intensities for Oil Sands Mining and Upgrading Projects, 2004-2012
35 140
30 120
e)
2 e/bbl SCO)e/bbl
25 100 2
20 80
15 60
10 40 Total Total GHGemissions (Mt CO
5 20 GHG emission GHGemission intensity (kg CO
0 0 2004 2005 2006 2007 2008 2009 2010 2011 2012
Emissions Emission intensity
Source: Environment Canada Facility GHG Reporting; Alberta Energy Regulator ST39
However, production of mining operations has increased during this period, from about 219 million barrels of SCO in 2004 to 370 million barrels in 2012. Over this time, the GHG emission intensity has remained relatively constant; emission intensity in 2004 was about 99 kg CO2e per barrel of SCO and about 97 kg CO2e per barrel in 2012. A linear fit of the emission intensity reveals a slight decrease of approximately 0.6 percent per year on average, although this is indistinguishable from the year-to-year variability in emissions intensity (the relative standard deviation of which is about 3 percent). There appears to be a very slight downward trend in emissions intensity from 2008 through 2012; linear regression yields a decrease of about 1.3 kg CO2e per barrel per year, although this trend is not statistically significant.
The data in Figure 2.4 are not entirely restricted to mining and upgrading emissions due to a change in reporting methods from Suncor in 2009. Between 2004 and 2008, GHG emission
July 2014 12 Canadian Energy Research Institute
submissions to Environment Canada for the Suncor mine include the Firebag SAGD project, and SCO produced by Suncor comes from both mined bitumen and Firebag in situ bitumen. During this time period, bitumen from Firebag contributed between 4 and 13 percent, and since the SAGD process is generally more energy-intensive than mining extraction, the intensity calculated for Suncor is likely slightly overestimated during this time period.
As of 2009, two changes occurred: first, Firebag began reporting emissions to Environment Canada as a separate project from the base mine; and second, bitumen from the MacKay River project began being included in upgraded product from the Suncor base mine. As a result, although SCO production rates depended on input from the mine and the two in situ projects, reported GHG emissions excluded the production of in situ bitumen, which was 21 to 33 percent of the total bitumen processed by the upgrader. As a result, the Suncor mine emissions intensities during this time period are likely underestimated.
This becomes quite clear when looking at emissions on a mine-by-mine basis as illustrated in Figure 2.5. The integrated mine emissions intensity (the dark blue line in Figure 2.5) falls considerably in the years after 2009; if the emissions intensity is recalculated to include the emissions required to extract the SAGD bitumen (the red line in Figure 2.5), the fall in emissions intensity is no longer evident (although, again, this is likely an overestimate of the true mining and upgrading intensity due to the energy-intensive nature of SAGD extraction).
Figure 2.5: Absolute GHG Emissions and GHG Emission Intensities for Oil Sands Mining and Upgrading Projects, Broken Down by Individual Project, 2004-2012
35 160
30 140 e/bbl)
120 2 e)
2 25
100 20 80 15 60
10
GHG Emissions GHGEmissions (Mt CO 40
5 20 GHGemission intensity (kg CO
0 0 2004 2005 2006 2007 2008 2009 2010 2011 2012
Suncor (incl. SAGD) Suncor Syncrude Shell CNRL Horizon
Source: Environment Canada Facility GHG Reporting; Alberta Energy Regulator ST39
July 2014 Oil Sands Environmental Impacts 13
There are two notable observations that can be made when comparing the different mining projects. First, there is no fall in emissions intensity in any of the projects during the time period between 2004 and 2012; Shell (as the combined emissions from mining, cogeneration, and the Scotford upgrader), in fact, increases emissions intensity over this time period by a rate of about 2.3 kg CO2e/bbl per year. Second, although the difference has narrowed somewhat since 2004, Shell has consistently lower emissions intensity than the other projects.
One major reason for the difference in emissions intensity of Shell versus Suncor, Syncrude, and CNRL Horizon is the froth treatment employed at each facility to extract bitumen from the oil sands ore. The former makes use of a paraffinic froth treatment to extract bitumen, while the latter three use naphthenic froth treatment.12 The prime difference between the two techniques is the solvent used to aid in froth generation.
In naphthenic froth treatment, naphtha, a mixture of light hydrocarbons, is mixed with the oil sand slurry. Naphtha typically contains considerable fraction of aromatic solvents, and is advantageous in that it has quite high bitumen recovery rates during the hot water extraction process. This includes asphaltenes, which leads to two conditions that increase the overall energy intensity of the extraction process. First, asphaltenes tend to act as surfactants. What this means for froth treatment is they tend to sit at the interface between water and the water-repellant bitumen, forming small water droplets within the bitumen that do not settle through buoyancy. This requires additional energy to separate the water and bitumen through processes such as centrifugation, and the final bitumen extracted contains roughly 1 to 2 percent water and 0.5 percent solids. Second, in addition to the need to remove water and solids, asphaltenes tend to have high levels of inorganic and non-hydrocarbon contaminants, which require additional upgrading to SCO before the bitumen can be shipped by pipeline.
Paraffinic froth treatment, as the name implies, instead uses a paraffinic solvent. This type of solvent is comprised mostly of saturated hydrocarbons and has low aromatic content. While this process has lower bitumen recovery yields and requires the use of higher volumes of solvent, asphaltenes do not readily dissolve in paraffinic solvent. There are fewer suspended water droplets in the bitumen froth as a result, reducing the required energy to separate the froth from the water. Consequently, there are very low levels of water and solid contamination in the bitumen froth, and the rejection of asphaltenes, while reducing the amount of hydrocarbons recovered, reduces the required upgrading prior to pipeline transport. In the case of Imperial Oil- and Exxon-owned Kearl Lake mine, the proprietary paraffinic froth treatment will not include any upgrading and will instead produce dilbit. Removing the requirement of upgrading, a very energy- intensive process has the potential to drastically reduce the emissions intensity of a mining project. For example, more than half of Shell’s emissions from 2004 through 2012 were a result of emissions from the Scotford upgrader (Shell is the only project of the three to report upgrader emissions separately from mine emissions).
12 Rao and Liu (2013). Froth Treatment in Athabasca Oil Sands Bitumen Recovery Process: A Review. Energy and Fuels 27, 7199- 7207.
July 2014 14 Canadian Energy Research Institute
The extraction process for obtaining bitumen from oil sands ore is relatively mature, and as such, there have been many practices already adopted to decrease the amount of energy used, and thus the amount of greenhouse gases emitted. The use of hydro transport has reduced the amount of energy required to transport mined ore to the central processing facilities, and over time the temperature required for the Clark hot water extraction process used to separate bitumen from the oil sands ore has fallen, reducing the amount of energy required for heating extraction water. The solvent used for bitumen froth treatment can also affect energy requirements. Using paraffinic solvents rather than the typical naphtha allows separation of contaminants such as asphaltenes during the froth treatment, which reduces or eliminates the requirement for energy-intensive upgrading prior to pipeline shipment.
Further reductions in emissions are expected as the Shell Quest carbon capture and storage (CCS)13 project comes online. The project is expected to capture up to 35 percent of the Shell Scotford upgrader emissions (more than 1 Mt of CO2) to be stored permanently underground. With current mining and upgrading emissions of over 30 Mt per year and growing, this is a modest reduction. Further efforts will need to be undertaken to make more significant progress in reducing emissions.
Although it would require significant changes in operations at most sites, the upgrading process is one large target for reducing emissions. Upgrading itself, as will be discussed later in this chapter, it a very energy-intensive process. While most sites do not break down emissions by mining and upgrading operations, Shell, with the standalone Scotford upgrader, contributes a substantial portion of the total GHGs emitted from the Shell mining and upgrading facilities (Figure 2.6), contributing just over half of total emissions in 2012.
13 Details on the Quest CSS project may be found at http://www.shell.ca/en/aboutshell/our-business-tpkg/upstream/oil- sands/quest.html
July 2014 Oil Sands Environmental Impacts 15
Figure 2.6: Shell GHG Emissions by Facility, 2004-2012
7
6
5
4
3
2 GHG emissions GHGemissions (Mt CO2e)
1
0 2004 2005 2006 2007 2008 2009 2010 2011 2012
Muskeg River Mine Jackpine Mine Expansion Scotford Upgrader Muskeg River Cogeneration Plant
Source: Environment Canada Facility GHG Reporting
Eliminating the upgrading process, as Imperial’s Kearl Mine is set to do by using a paraffinic froth treatment, is one way to offset some of these emissions. However, it should be stressed that while this will offset emissions coming directly from the mine, the advantage is somewhat diminished due to the fact that bitumen is more energy-intensive to refine than synthetic crude oil. However, the upgrading-refining route does tend to be more energy-intensive than direct refining of bitumen, overall emissions for the life-cycle may be lowered if upgrading is not included in the bitumen life-cycle.
In Situ Emissions from in situ oil sands projects are shown in Figure 2.7. Note that the data shown do not include emissions from the Nexen/CNOOC Long Lake integrated in situ extraction and upgrading project. The technology used at Long Lake differs significantly from that used by other in situ projects and is significantly more emissions intensive than the average in situ producer; between 2010 and 2012, Long Lake averaged 336 kg CO2e per barrel of SCO produced compared to an average of 77 kg CO2e per barrel of bitumen for other commercial in situ projects.
July 2014 16 Canadian Energy Research Institute
Figure 2.7: Absolute GHG Emissions and GHG Emission Intensities for Oil Sands In Situ Projects, 2004-2012
20 125 e)
2 16 100
12 75 e/bbl bitumen)
8 50 2
(kg (kg CO GHG emission GHGemission intensity
4 25 Total Total GHGemissions (Mt CO
0 0 2004 2005 2006 2007 2008 2009 2010 2011 2012
Emissions Emission intensity
Source: AER ST53; Environment Canada Facility GHG Reporting
Reported greenhouse gas emissions for commercial in situ bitumen have risen, on average, by about 1.5 Mt CO2e per year between 2004 and 2012, or about 20 percent per year based on 2004 emissions. Emissions intensity, however, fell during this time by an average of 1.9 kg CO2e per barrel of bitumen extracted each year, or 2 percent per year based on 2004 emission intensity.
Much of the reduction in GHG emissions intensity has come during the 2009 through 2011 period. During this time period, many new commercial SAGD projects started to come online. Typically, new projects have relatively high GHG emissions intensities since the steam added at the beginning of a new project tends not to produce bitumen right away. However, they also tend to have relatively low amounts of steam and production in early stages of operation, which leads to less impact on overall emissions. During this period, emissions intensities for old (production commencing prior to the beginning of GHG reporting in 2004) and new (production commencing after 2004) projects are quite similar, indicating that the drop in emissions intensity is a general trend and not the result of new, lower-emissions projects coming online. The annual emissions intensities of old and new projects are shown in Figure 2.8 and Figure 2.9, respectively.
July 2014 Oil Sands Environmental Impacts 17
Figure 2.8: GHG Emissions Intensities for all Thermal In Situ Producers, Reporting as of 2004
200.0
180.0
160.0
140.0
120.0 e per barrel per e barrel of bitumen) 2 100.0
80.0
60.0
40.0
20.0
0.0 2004 2005 2006 2007 2008 2009 2010 2011 2012
GHG Emissions GHGEmissions Intensity (kg CO Cenovus Christina Lake Imperial Cold Lake Cenovus Foster Creek JACOS Hangingstone Suncor MacKay River Shell Peace River CNRL Wolf Lake/Primrose Weighted Average
Note: Black marked line shows the production weighted average Source: AER ST53; Environment Canada Facility GHG Reporting
July 2014 18 Canadian Energy Research Institute
Figure 2.9: GHG Emissions intensities for all Thermal In Situ Producers, Reporting Later than 2004
300.0
250.0
200.0 per barrle barrle per of bitumen)
2 150.0
100.0
50.0
0.0 2008 2009 2010 2011 2012
GHG emission GHGemission intensity (kg CO Husky Tucker Connacher Great Divide Devon Jackfish Shell Orion ConocoPhillips Surmont MEG Christina Lake Connacher Algar Statoil Leismer Weighted Average
Note: Black marked line shows the production weighted average Source: AER ST53; Environment Canada Facility GHG Reporting
A wide range of emissions intensities can be observed for different in situ projects. Emissions intensities in 2012 ranged from a low of 42.9 kg CO2e per barrel of bitumen for Cenovus’ Christina Lake project to a high of 168 kg CO2e per barrel of bitumen for Husky’s Tucker project. While there is some variability in the emissions intensity-to-SOR ratio, the SOR is really the prime driver of emissions intensity, as illustrated in Figure 2.10; GHG emissions for in situ projects arise primarily from fuel burning to generate steam for the thermal extraction process. Thus, any action that reduces the SOR will serve to reduce the emissions intensity of the project. The recent drop in GHG emissions intensities has been accompanied by a fall in the average SOR of all commercial in situ projects; the production-weighted average SOR was 3.5 in 2008 compared to 3.1 in 2012. Much of what determines SOR is simply a matter of finding a high quality reservoir, but changes in the extraction technologies have also aimed to either reduce steam requirements or increase oil recovery.
July 2014 Oil Sands Environmental Impacts 19
Figure 2.10: 2012 GHG Emissions Intensity as a Function of Steam-Oil Ratio for Thermal In Situ Projects
180.0
160.0
140.0
e/bbl bitumen) e/bbl 120.0 2
100.0
80.0
60.0
40.0
20.0 GHG emission GHGemission intensity (kg CO 0.0 0 1 2 3 4 5 6 7 Steam-Oil Ratio
Source: AER ST53; Environment Canada Facility GHG Reporting
Vapour extraction (VAPEX) and solvent-assisted SAGD make the use of low-viscosity solvents miscible with bitumen to increase the flow rate of in situ bitumen, eliminating or reducing the need for steam. This technique has been shown to be effective in some cases, such as test wells used at Cenovus’ Christina Lake project, but there are currently few solid examples of the efficacy of using solvents in the SAGD process. Whether or not it becomes commercially viable depends heavily on factors such as solvent cost and recovery of the solvent from the reservoir. Another Cenovus technique, the use of wedge wells, uses additional recovery wells located in between producing well pairs to increase the area of oil recovery and thus increase the amount if bitumen recovered from the same amount of steam injection. Other methods have been piloted, but results suggest these techniques are far from being reliable enough for commercial applications at this point. One such method, toe-to-heel air injection or THAI, planned to use in situ combustion of bitumen within the reservoir to both heat the bitumen and partially upgrade it in place, but control of the combustion front has so far proven elusive.
While step-changes in extraction methods are likely necessary for a drastic reduction in GHG emissions (some possible extraction techniques are discussed at the end of this chapter), more efficient use of energy within the existing SAGD process can reduce emissions in the short term. One common method is the use of cogeneration at in situ projects. Cogeneration involves using natural gas to both generate electricity to be used onsite and heat for steam generation.
July 2014 20 Canadian Energy Research Institute
Cogeneration facilities can generate electricity and heat more efficiently than separate generator and steam facilities. In addition, it reduces demand for electricity from the Alberta grid, which relies heavily on carbon-intensive coal-fired generators. It should also be noted that using cogeneration will effectively increase the direct GHG emission intensity for a project as calculated in this report; extra natural gas is necessary to produce electricity alongside steam. However, once external emissions of GHG from electricity generation are factored in, the overall emissions intensity will be lower. Canada’s Oil Sands Innovation Alliance (COSIA) also reports the testing of gas-turbine once-through steam generators, which generate electricity and steam more efficiently than cogeneration facilities.14 Life-Cycle GHG Emissions of Oil Sands Fuels There is pressure on the oil sands sector to improve GHG emissions performance, both to reduce fuel use and based on how those emissions contribute to Canada’s emission totals and how this affects the ability to meet commitments to international agreements on emissions reduction, such as the Copenhagen Accord. This perspective is reflective of accounting emissions at their point of source. Another approach to looking at emissions is through a life-cycle perspective. Life- cycle analysis, or LCA, allocates emissions throughout the production cycle of a particular product, and assigns emissions through each stage of production through to the end use of a finished product. Such an analysis allows for comparison of two similar products in terms of their environmental footprint and for a choice to be made for the least impactful product, taking into account a holistic view of its production process.
Taking into account the full production cycle of fuel from oil sands bitumen is important, as the impact of GHGs does not depend on the location in which they are emitted. For example, Alberta could conceivably reduce GHG emissions by shipping crude oil outside of the province to refineries and repurchasing that refined oil back as fuel, rather than refining oil within the province. The refining emissions are now attributed to an external region, but provided that all refining processes are the same, overall global GHG emissions will increase due to the additional pipeline transmission required under this hypothetical setup. For supply chains that span over several countries, this is an important consideration in order to reduce GHGs in an effective way, rather than simply outsourcing emissions to another area of the globe.
From the perspective of hydrocarbon fuels, LCA is also known as a well-to-wheels (WTW) analysis. GHGs resulting from oil extraction, transport and refining of crude oil, and transport and end use of a refined fuel are all embodied into the final fuel product, usually as a function of the energy contained in the product. As it stands, this type of analysis has no bearing on Canada’s GHG emission targets; that is, GHGs resulting from oil sands production are counted as Canadian emissions, regardless of whether or not the bitumen or SCO is used in Canada or elsewhere in the world. However, there has been recent interest in life-cycle analysis of the oil sands fuel life- cycle. This is due, in part, to the advent of fuel standards aiming at reducing the overall footprint of vehicle fuels. Examples include California’s Low Carbon Fuel Standard15 and British Columbia’s
14 http://www.cosia.ca/initiatives/greenhouse_gases/gas-turbine-once-through-steam-generator 15 http://www.energy.ca.gov/low_carbon_fuel_standard/
July 2014 Oil Sands Environmental Impacts 21
Renewable and Low Carbon Fuel Requirements Regulation,16 both of which aim to reduce the GHG intensity of fuels by 10 percent by 2020, and the proposed European Union Fuel Quality Directive.17 Beyond this, however, life-cycle analysis also allows for the examination of individual steps in the extraction and upgrading process, identifying the most effective targets for emissions reduction.
Several studies performing WTW analysis of oil sands-derived fuels have been carried out to date, some looking at solely oil sands processes, and some as a comparative study to fuels from other crude oil sources. As a numerical model, the quality of WTW analysis is highly dependent on the quality of the numbers used for the model, the assumptions that were made in developing the model, and the boundaries placed on the analysis. In LCA, boundaries refer to which types of processes GHG emissions are calculated and accounted for in the final fuel product, and which are not. For oil sands WTW analysis, these processes typically include:
Mining or extraction processes, such as GHGs from truck-and-shovel extraction, hydro transport, steam generation, and water treatment; Upgrading of bitumen to SCO; Transport of bitumen, dilbit, or SCO to a refinery; Refining of bitumen, dilbit, or SCO to final fuel products; Transport of fuel to retail stations; and Burning of fuel in the tank of a vehicle.
While GHGs are produced in the manufacture of facilities required for oil treatment, these are generally not included in the LCA.
The quality of the data going into the LCA determines how useful the final output of the model is, particularly when attempting to compare fuels from different crude oil sources. Analysis usually involves modeling a particular process within the supply chain and determining the emissions using an emission factor. Using in situ production as an example, modeling the emissions from a once-through steam generator requires one to know the energy requirements for natural gas for producing a unit of high-quality steam, the amount of GHG produced for each unit of natural gas used (i.e., the natural gas emission factor), and the amount of steam required to produce each unit of bitumen. As these numbers become more certain, the output of the LCA becomes higher quality and more reliable.
Some examples of recent publications on oil sands fuel LCA include:
The OSOM (Oil Sands Operation Model), a 2007 paper18 which examines SCO production from mining and in situ projects and bitumen production from in situ projects based on
16 http://www.empr.gov.bc.ca/RET/RLCFRR/Pages/default.aspx 17 http://ec.europa.eu/environment/air/transport/fuel.htm 18 Ondorica-Garcia et al. (2007). Modeling the energy demands and greenhouse gas emissions of the Canadian oil sands industry. Energy & Fuels 21, 2098-2111.
July 2014 22 Canadian Energy Research Institute
2003 production, and compares to anticipated emissions in 2012 and 2030 using the Oil Sands Technology Roadmap.19 The development of the GHOST (GreenHouse gas emissions of current Oil Sands Technologies) model by researchers at the University of Calgary.20,21 GHOST can be used to model a number of different oil sands project configurations, and has the advantage of being based off of actual operating data obtained from oil sands producers via non- disclosure agreements. The most recent publication includes both mining, CSS and SAGD data. Recently, PRELIM (Petroleum Refinery Life-cycle Inventory Model) has been developed to expand the model to include more detailed refining emissions.22
A consulting report from TIAX prepared for the Alberta Energy Research Institute looked at the life-cycle GHG emissions of various North American and imported crudes in the context of low carbon fuel standards.23
Two Jacobs consulting reports, prepared for the Alberta Energy Research Institute24 and the Alberta Petroleum Marketing Commission,25 examining the difference between WTW analysis of oil sands crude and other global crudes in the context of low carbon fuel standards.
IHS CERA carried out a meta-analysis in 2012 of several different crude oil WTW emissions for fuels refined in the United States, normalizing several studies in an effort to compare numerical results with different boundaries and assumptions.26
This list is not exhaustive, but these references provide a reasonable overview of the current state of LCA and highlight some of the differences between methods of oil sands production and different global crude sources. It should be kept in mind that while these studies all examine the life cycle emissions of oil sands related products, comparison of the results of different studies is difficult. Some processes may be included or excluded in some studies and not others, the level of detail examined in modeling processes may differ, and different assumptions are often used in differing studies. As such, in most cases it is advisable to examine each study individually and
19 Alberta Chamber of Resources (2004). Oil Sands Technology Roadmap: Unlocking the Potential. http://www.strategywest.com/downloads/ACR200401.pdf 20 Charpentier et al. (2011). Life cycle greenhouse gas emissions of current oil sands technologies: GHOST model development and illustrative application. Environmental Science and Technology 45, 9393 – 9404. 21 Bergerson et al. (2012). Life cycle greenhouse gas emissions of current oil sands technologies: surface mining and in situ applications. Environmental Science and Technology 46, 7865 – 7874. 22 Abella and Bergerson (2012). Model to investigate energy and greenhouse gas emissions implications of refining petroleum: impacts of crude quality and refinery configuration. Environmental Science and Technology 46. 13037 – 13047. 23 TIAX LLC and MathPro Inc. (2009). Comparison of North American and imported crude oil lifecycle GHG emissions. Prepared for Alberta Energy Research Institute. 24 Jacobs Consultancy (2009). Life cycle assessment comparison of North American and Imported Crudes. Prepared for Alberta Energy Research Institute. 25 Jacobs Consultancy (2012). EU pathway study: life cycle assessment of crude oils in a European context. Prepared for Alberta Petroleum Marketing Commission. 26 IHS CERA (2012). Oil Sands, Greenhouse Gases, and US Oil Supply: Getting the Numbers Right—2012 Update. Available from http://www.ihs.com/products/cera/energy-industry/oil-sands-dialogue.aspx
July 2014 Oil Sands Environmental Impacts 23
focus on the relative differences in fuel life cycles within one study, as the different techniques and assumptions used by each LCA will result in variations in final numerical results.
Highlights of WTW Results for Oil Sands Fuels OSOM examined only GHG emissions from the bitumen/SCO production process, rather than a full well-to-wheels analysis. The model found that although production of SAGD bitumen is more GHG-intensive than mining, the overall process is less GHG-intensive due to the lack of upgrading. Upgrading was the most GHG-intensive process, and the GHG intensity per barrel of SCO changed slightly if the refining configuration changed. The study found that a combination of fluid coking and hydrocracking led to the lowest GHG emissions overall, followed by delayed coking, and finally hydrocracking. However, the differences overall were small, and SCO from mining was modeled to produce 80.8 – 87.3 kg CO2e per barrel of SCO, compared to 37.4 kg CO2e per barrel of SAGD bitumen. It should be noted that both of these emission intensities are below those actually observed from reported values discussed previously, and highlight that, while useful for making comparisons, LCA results should be used with caution when looking at absolute value of the results.
In the more detailed analysis using the GHOST model, a range of possible emissions representing the range of typical operating conditions were calculated for dilbit, synbit (a diluted bitumen where SCO rather than diluent is used to prepare for pipeline transport at about 1:1 volume ratio), and SCO (produced by either delayed coking or hydrocracking) from SAGD, CSS, or mining projects. The results, illustrated in Figure 2.11, show that, for similar products, mining has the lowest greenhouse gas emissions on average, although the range of potential emissions has a great deal of overlap; actual emissions can vary from project-to-project. Although the in situ extraction methods are more energy-intensive than surface mining, the simple fact that in situ projects tend to ship bitumen as dilbit rather than SCO puts in situ dilbit at a slightly lower emissions intensity range compared to mining SCO.
July 2014 24 Canadian Energy Research Institute
Figure 2.11: Range of GHG Emissions Intensities for Dilbit, Synbit, and SCO from Coking and Hydrocracking for Bitumen Obtained from SAGD, CSS, and Surface Mining
50 46.3 44.7 45 40.9
39.2 e/MJ) 2 40 32.4 35 30.7
30 26.2 23.8 25 22.4 19.9 18.5 20 19 12.7 15 18.1 18.6 17.6
10 12.6 12.4 11.6 10.6 5 8.7 8.4 9.2
3.5
GHG emission GHGemission intensity CO (g 0
Source: Charpentier, et al. (2011) and Bergerson, et al. (2012)
The stages of processing described in the GHOST model are well-to-refinery gate emissions intensities, and do not include emissions from refining or fuel use. The three consultant reports mentioned previously do include refining emissions. The TIAX study examines modeled emissions for average PADD II (American Midwest), PADD III (Gulf Coast) and California refineries. The Jacobs 2009 study models a high-conversion refinery located in PADD II. The Jacobs 2012 study, since it looked at the context of the potential EU fuel standards, looked at five refinery configurations: two fluid catalytic cracking refineries, one with a visbreaking (thermal cracking) unit (based on a configuration in France) and the other with a coker (based on a configuration in Germany); an Italian hydrocracking and visbreaking-based refinery; a high-conversion fluid catalytic cracking and coking refinery on the US Gulf Coast; and a low-conversion hydroskimming refinery in Russia.
Both reports by Jacobs show that for bitumen upgraded to SCO, the emissions intensity of the refining process is lower than that for dilbit or bitumen (in the case that diluent used for transport is returned). However, the overall combination of upgrading and refining emissions means that the total GHG emissions intensity is slightly higher for SCO compared to dilbit or bitumen produced from the same extraction method. This is illustrated in Figure 2.12 for modeled results for ultra-low sulphur diesel produced at a PADD II high-conversion refinery. Refining of bitumen is about 15 percent lower overall than upgrading to SCO using a coking unit followed by refining, and the advantage is slightly higher if hydrocracking is used to generate SCO. Overall, there is a
July 2014 Oil Sands Environmental Impacts 25
small advantage emission intensity-wise, to remove the upgrading step from the oil sands fuel cycle.
Figure 2.12: Refining and Upgrading Emissions for SCO Produced by Either Coker or Hydrocracking (Eb-Bed), Bitumen, or Dilbit
25
20
e/MJ) 2 15 Refining
10 Upgrading
GHG Intensity GHGIntensity (g CO 5
0 SCO Coker SCO Eb-Bed Bitumen Dilbit
Note: Refining based on production of ultra-low sulphur diesel at a high conversion PADD II refinery. Source: Jacobs 2009
For total WTW life-cycle, the largest source of GHG emissions is the final burning of the fuel in the tank, which is approximately 73 to 74 g CO2e per MJ of fuel, depending on the type of fuel burned. The Jacobs 2012 EU study covers the widest range of fuels and refinery configurations, and total fuel intensities for diesel fuels range from 84 to 99 g CO2e per MJ of fuel for conventional crude oil sources (making the final burning of the fuel 75 to 89 percent of the total life-cycle greenhouse gas emissions). Mined bitumen diesel fuel ranged from 105 to 111 CO2e per MJ of fuel depending on whether the mine was high or low efficiency; the modeled low efficiency mine did not include heat recovery for heating process water, which is no longer a common practice at operating mines. The WTW emissions for in situ dilbit was slightly lower, from 100 CO2e per MJ of fuel for CHOPS (cold heavy oil production with sand, a non-thermal extraction technique) and 104 CO2e per MJ of fuel for SAGD produced dilbit at a steam-oil ratio of 3. These emissions are briefly summarized in Table 2.1. While CHOPS is considerably lower energy than thermal oil production, much of this advantage is lost due to higher levels of methane venting from this production method. It should also be noted that modeled methane emissions from tailings ponds were a significant fraction of the emissions from mines, nearly equaling the production emissions intensity for a high efficiency mine.
July 2014 26 Canadian Energy Research Institute
Table 2.1: WTW GHG Emission Ranges for Conventional Crude Oil, Mined and Upgraded Bitumen, and In Situ Dilbit for Production of European Diesel Fuel
Crude Type Low (g CO2e/MJ) / Source High (g CO2e/MJ) / Source Conventional 84 / North Sea 99 / Venezuela Surface Mining 105 / High efficiency mine 111 / Low efficiency Mine In Situ (dilbit) 100 / CHOPS 104 / SAGD, SOR 3.0 Source: Jacobs 2012
One potential method of reducing emissions intensities on a WTW basis is through the use of cogeneration. The Jacobs 2009 study notes that if credit is given for the emissions offset by using cogeneration of electricity, which is both more energy efficient than separate electricity and steam generation and less carbon-intensive than Alberta’s predominantly coal-fired grid, the effective emissions intensity for oil sands crude on a WTW basis can fall within or below the range of conventional crudes within the study.
There are several key points to be learned from this WTW life-cycle analysis:
The WTW emissions intensities of fuels produced from oil sands derived crude are not substantially higher than the ranges of other conventional crudes. The values for European diesel, for example, are 1 to 12 percent higher than the highest conventional crude, which is Venezuela heavy oil. A substantial fraction of the greenhouse gas emissions is from the end use of fuel, which inherently cannot be reduced; the amount of carbon in diesel fuel per unit energy cannot be substantially changed. For low carbon fuel standards, this means that upstream and downstream petroleum processing emissions must be reduced. When neglecting the carbon contained within the fuel, the difference between conventional and oil sands crude increases; the lowest in situ method, CHOPS, produces 4 percent more emissions than the highest conventional crude, while the highest mining produced cycle produces almost 50 percent more GHG than the highest conventional crude, and is almost 4 times more emissions-intensive than the lowest energy crude from the North Sea. If an emissions intensity reduction of 5 percent of the previous average fuel emissions intensity is imposed, it will take considerably more effort for high intensity crudes to meet this standard. The midpoint of the emissions intensities is about 92 g CO2e per MJ of fuel, representing about 18 g CO2e per MJ of upstream and downstream processing emissions. A 5 percent reduction to 87 g CO2e per MJ requires about 14 g CO2e per MJ of production, transport, and refining emissions, which is about 25 percent less than the median of conventional crudes and about 50 percent less than the least carbon-intensive crude.
The meta-analysis conducted by IHS CERA concluded that, when examining a broad range of global crudes, oil sands produced oil had, on average, 11 percent higher WTW emissions than the average barrel of crude refined in the US (14 percent higher if the boundaries are expanded to include off-site emissions from natural gas and electricity production). The authors caution,
July 2014 Oil Sands Environmental Impacts 27
however, that some of the lower-emission crudes come from jurisdictions with lower requirements for transparency in emissions reporting, which leads to the potential of underestimating emissions from these crudes. Estimates for emissions for some crudes varied by about 30 percent, which highlights the need for accurate emissions data when constructing a policy such as a low carbon fuel standard, so that the goals of the legislation are met.
This is not to say that oil sands crude is fundamentally incompatible with low carbon fuel standards; certainly, it can make up part of the mix of crudes, especially if being co-refined with low emissions intensity crudes. However, since the reduction relies on the comparatively small upstream and downstream processing numbers, it would be unsurprising if oil sands crude became less appealing to refineries trying to meet fuel carbon standards, particularly in the absence of substantial changes in emissions from the oil sands sector. Equally important in establishing fuel standards based on life cycle emissions of fuel production is ensuring that the upstream extraction emissions are based on reliable information, as not all crude-producing jurisdictions have similar requirements for emissions reporting. This is something that will need to be kept in mind as regulations change in countries that import oil sands crude. Specified Gas Emitters Regulation Alberta is one of the few North American jurisdictions with a carbon pricing regulation. The regulation, called the Specified Gas Emitters Regulation (SGER),27 was established as of July 2007 and requires large emitters of over 100,000 tonnes of CO2 equivalents to reduce their greenhouse gas emission intensities by 12 percent below a baseline.28
The baseline emissions level is determined based on the age of the project. Facilities that began operation prior to year 2000 use the years 2003 through 2005 as the baseline. New projects must start reducing emissions intensity in their fourth year of operation at a rate of 2 percent per year, with the baseline determined in the third year of operation until years 3 through 5 can be used to establish a 3-year baseline. There are four options to meet the regulation:
Improve the energy efficiency of the facility to meet the required emission intensity improvement. Pay $15 per tonne emitted in excess of the twelve percent reduction into the Climate Change and Emissions Management Fund (CCEMF), which acts as a resource for GHG emission reduction and climate change mitigation. Purchase offset credits from projects that lie outside of the SGER. Purchase credits from facilities that exceed the emission reduction requirements of the SGER.
27 Alberta Regulation 139/2007. Climate Change and Emissions Management Act: Specified Gas Emitters Regulation. http://www.qp.alberta.ca/documents/Regs/2007_139.pdf 28 Government of Alberta (2012): Annual Summary of Specified Gas Emitters Regulation: 2009. http://esrd.alberta.ca/focus/alberta-and-climate-change/regulating-greenhouse-gas-emissions/greenhouse-gas-reduction- program/documents/8644.pdf
July 2014 28 Canadian Energy Research Institute
It should be noted that the SGER is not a $15 per tonne carbon tax, as the cost only applies to emissions above the 12 percent-above-baseline threshold. If a facility maintains a constant emission intensity and chooses to pay into the CCEMF to meet the regulation, this results in an effective price of $1.80 per tonne of CO2 equivalents released.
There has not been an annual summary report for the SGER since the 2009 report, released in 2012, in addition to the first 2007-2008 annual report.29 As such, there is currently little available information on how the SGER was met by oil sands producers past year 2009. The breakdown of how in situ producers met the SGER requirements is listed in Table 2.2 while the mining and upgrading sector is listed in Table 2.3. In the tables, the “Tonnes Owed” column should equal the sum of the EPC submitted, the number of CCEMF credits purchased, and the number of offset credits submitted (rounding in the Alberta Government reports means that these numbers do not add up evenly). The total contribution to the CCEMF equals the number of credits purchased at a cost of $15 per credit. In all cases, one credit is equivalent to one tonne of GHG in CO2 equivalents.
Table 2.2: SGER Compliance Information for In Situ Oil Sands Producers (units in tonnes CO2e except for total CCEMF contribution)
Year Emissions Tonnes EPC EPC CCEMF Total CCEMF Offsets Owed Generated Submitted Credits Contribution Submitted 2007* 5,210,000 138,000 121,000 850 137,000 $2,050,000 -- 2008 10,200,000 704,000 178,000 42,000 607,000 $9,105,000 54,900 2009 11,100,000 1,150,000 104,000 84,500 1,030,000 $15,450,000 34,600 Total 26,510,000 1,992,000 403,000 127,350 1,774,000 $26,605,000 89,500 *Only includes July – December 2007 Source: Government of Alberta SGER Annual Summary Reports
In situ projects were in excess of the emissions performance by 2.0 Mt over the first two-and-a- half years of the SGER (the “Tonnes Owed” column of Table 2.2). Overall, in situ projects were more successful at generating emission performance credits (EPC) than mining and upgrading. During this time, Cenovus’ Christina Lake and Foster Creek, and Suncor’s MacKay River and Firebag all achieved emissions lower than the regulated intensity levels, with a total of about 0.40 Mt CO2 equivalents generated by all projects. CCEMF contributions corresponding to 1.77 Mt CO2e ($26.6 million) were the largest form of compliance, followed by submission of purchased or saved EPCs (0.13 Mt CO2e) and emissions offset purchases (0.09 Mt CO2e).
29 Government of Alberta (2011). Annual Summary of Specified Gas Emitters Regulation: 2007 – 2008. http://esrd.alberta.ca/focus/alberta-and-climate-change/regulating-greenhouse-gas-emissions/greenhouse-gas-reduction- program/documents/SGER_Summary_Report_2007-2008.pdf
July 2014 Oil Sands Environmental Impacts 29
Table 2.3: SGER Compliance Information for Mining and Upgrading Oil Sands Producers (units in tonnes CO2e except for total CCEMF contribution) Year Emissions Tonnes EPC EPC CCEMF Total CCEMF Offsets Owed Generated Submitted Credits Contribution Submitted 2007* 10,300,000 384,120 -- 94,200 269,000 $4,035,000 20,900 2008 17,700,000 963,000 -- 364,000 444,000 $6,660,000 154,000 2009 18,800,000 1,180,000 -- 566,000 303,000 $4,545,000 311,000 Total 46,800,000 2,527,120 -- 1,024,200 1,016,000 $15,240,000 485,900 *Only includes July – December 2007 Source: Government of Alberta SGER Annual Summary Reports
Mining and upgrading projects were in excess of the SGER emissions limits by a total of 2.5 Mt CO2e over the first two-and-a-half years of the regulation (the “Tonnes Owed” column of Table 2.3). No EPCs were generated during this time. EPCs purchased from other facilities and CCEMF credits were the largest compliance methods (1.02 Mt CO2e each; $15.2 million contributed to the CCEMF), with 0.49 Mt CO2e of offset credits purchased as well.
Beyond 2009, there is little information about the SGER beyond annual summaries, which do not include compliance data on a sector-by-sector basis. This was recently identified as a shortcoming by the province’s Auditor General, who highlighted the need for further analysis of the efficacy of the regulation.30 The regulation is set to expire at the end of 2014, and so a path forward will soon need to be examined.
CCEMC Projects The money contributed to the CCEMF is managed by the Climate Change and Emissions Management Corporation (CCEMC). 31 Several funded projects 32 are related to emissions reductions at the oil sands.
Several CCS projects funded by the CCEMC relate to the oil sands. The Devon Jackfish plant successfully pilot-tested a 1,000 tonne per day CO2 capture plant that can capture carbon dioxide at an estimated total cost (capital and operating) of under $70 per tonne. Projects in development include an enzymatic system for low cost capture of oil sands CO2, and an oxy-fuel demonstration project for once-through steam generators, which allows for more efficient CO2 capture.
New extraction techniques are being piloted in part from CCEMC funding. E-T Energy received funding to field test an Electro-Thermal Dynamic Stripping Process (ET-DSP)33 at its Poplar Creek site. Previously used as a method for reclamation of contaminated soils, this is a novel thermal in situ technique that uses electrode wells to induce current in groundwater. The groundwater is heated through this process, heating bitumen in the oil sands deposit to increase flow rate, and
30 Report of the Auditor General of Alberta, July 2014. http://www.oag.ab.ca/webfiles/reports/AGJuly2014Report.pdf 31 For more information, see the CCEMC website: http://ccemc.ca/about/ 32 Information for projects described here is found at http://ccemc.ca/projects/ 33 ET-DSP Technology: http://www.e-tenergy.com/technology/et-dsp-technology.html
July 2014 30 Canadian Energy Research Institute
the bitumen is pumped out of interspersed wells in the formation. The process, if successful, uses no steam, requires substantially less water, and requires minimal use of natural gas. Moreover, the technique could be used in formations too deep for surface mining, but too shallow for the pressures required for steam thermal techniques. The funded project is completed and the final report to the CCEMC is forthcoming.
The enhance solvent extraction incorporating electromagnetic heating (ESEIEH) method is being tested by the Harris Corporation of Melbourne, Florida, Laricina Energy, Nexen, and Suncor. The technique uses solvent dilution and heating of bitumen using radio-frequency waves to thermally produce bitumen in situ. The process, if successful, does not require steam and may reduce GHG emissions intensity by up to 80 percent in comparison to SAGD.
Saltworks is testing at a Vancouver facility a desalination technique that operates using waste heat. Thermal in situ projects require a considerable amount of clean water, which is currently produced using energy-intensive techniques such as warm lime softening or evaporators. Low energy desalination could improve the energy efficiency of SAGD or CSS projects.
July 2014 Oil Sands Environmental Impacts 31
Chapter 3: Air Emissions
Introduction Greenhouse gases from the oil sands, which are mostly in the form of carbon dioxide, are important for their overall contribution to global emissions. However, it does not act like a classical pollutant; carbon dioxide is already naturally occurring and relatively inert, and remains in the atmosphere for a considerable time once emitted. As an emission, it has importance, but has little direct impact on the environment surrounding the oil sands.
Greenhouse gases, though, are not the only substance emitted to the air from oil sands activities. Oil sands developments also result in the release of air pollutants to the atmosphere, including sulphur dioxide (SO2), nitrogen oxides (NOx), volatile organic compounds (VOCs), and particulate matter (PM). Some of these arise in concert with GHGs from fossil fuel burning, but there are additional sources as well, such as emissions arising from mine faces or tailings ponds.
Many of these pollutants are comparatively short-lived in the atmosphere and are removed in the order of hours, days, or weeks either by deposition to the earth’s surface or by chemical conversion. As such, the impacts of these emissions tend to be more regional in nature. Air emissions can lead to a number of concerns such as acute toxicity to humans or animals, acid rain and soil acidification, and deposition of toxic pollutants in remote areas. This chapter will discuss some of the air emissions and what their impacts are in the oil sands region. Reported Emissions – NPRI The National Pollutant Release Inventory (NPRI) is a publicly available database operated by Environment Canada and contains industry-reported pollutant releases to air, water, and land, either through direct emissions, disposal, or transfer. Industries that release certain substances above a defined threshold must report these releases. These data are available to the public through the NPRI website1 and are made public to incentivize emissions reductions.
There are several things to bear in mind when interpreting data from the NPRI. First of all, the report of a pollutant release does not necessarily signify that there is a particular environmental problem with that release. Not all pollutants are equally harmful, and small releases of some pollutants can have little impact on the surrounding environment. Second, the NPRI is not an exhaustive list of pollutant releases. Smaller industries that do not reach a reporting threshold are not included in the industry-reported data; some industries, such as agriculture, are not included in reporting requirements; and the reported emissions omit non-industrial sources, such as mobile sources (i.e., motor vehicle emissions) and residential emissions. The NPRI does, however, annually estimate emissions on a country-wide basis from all sources for a subset of pollutants including criteria air contaminants, some heavy metals, and some polycyclic aromatic hydrocarbons (PAHs). Finally, there can be inconsistencies between concurrent reporting years
1 http://www.ec.gc.ca/inrp-npri/default.asp?lang=En&n=4A577BB9-1
July 2014 32 Canadian Energy Research Institute
in the method of calculating releases, which can result in step changes in reported releases that reflect reporting methods rather than actual changes in pollutant release.
Criteria Air Contaminants Criteria air contaminants, or CACs, are the primary constituents of air pollution that lead to the most common, broad-scale air quality issues such as smog and acid rain. These include the following primary (i.e., directly emitted) pollutants:2
Sulphur oxides (SOx): emitted primarily in the form of sulphur dioxide (SO2), sulphur oxides are formed when fossil fuels containing sulphur impurities are combusted. Sulphur oxides are transformed by oxidizing in the atmosphere to form sulphuric acid, which forms particles and contributes to acid rain. As a gas, SO2 itself can have toxic effects by inhalation if in high enough concentrations.
Nitrogen oxides (NOx): emitted primarily as nitric oxide (NO), but rapidly and reversibly converted to nitrogen dioxide (NO2), NOx is formed during high-temperature combustion in the presence of nitrogen gas. In the presence of sunlight and volatile organic compounds, NOx leads to the formation of ground-level ozone (O3), a gas that leads to part of the toxicity of smog. Additionally, NOx can be further oxidized to nitric acid in the atmosphere, which, like sulphuric acid, contributes to particle formation and acid rain. Finally, NO2 itself can be toxic by inhalation if present at high enough concentrations.
Particulate matter (PM): PM refers to small solid or liquid particles suspended in the atmosphere. Primary PM can arise from combustion or through mechanical generation, such as dust from brake pads or wind-blown dust from exposed surfaces. When inhaled, PM can deposit in the airways or lungs and exhibits toxicity. Because the toxicity of PM and how deep PM can penetrate the airway is dependent on size (smaller particles tend to be more toxic and more likely to reach deeper parts of the airway), particles tend to be broken down into three categories. Total PM (TPM) refers to all suspended particles up to approximately 100 micrometres (0.1 mm) in diameter; PM less than 10 micrometres in diameter (PM10), sometimes referred to as coarse PM when excluding particles less than 2.5 micrometres; and PM less than 2.5 micrometres in diameter (PM2.5), sometimes referred to as fine PM.
Volatile organic compounds (VOC): these carbon- and hydrogen-containing organic gases and vapours (excluding the relatively non-reactive methane) are reactive in the atmosphere and, in the presence of sunlight and NOx, produce ground-level ozone. Some chemicals formed through the oxidation of VOCs can also form substantial amounts of PM, making VOCs an important precursor to smog. Sources of VOCs can include evaporation of organics (such as fumes from gasoline or solvents) or from unburned fuel in exhaust from fossil fuel combustion. In addition to
2 Criteria air contaminants and related pollutants. Environment Canada. https://www.ec.gc.ca/air/default.asp?lang=En&n=7C43740B-1
July 2014 Oil Sands Environmental Impacts 33
their reactivity, some specific VOCs can also be toxic by inhalation when present at sufficiently high concentrations.
Carbon monoxide (CO): formed during incomplete combustion of carbon-containing fuels, CO displaces oxygen in the bloodstream and can be highly toxic by inhalation.
Ammonia (NH3): ammonia is a pungent gas that is toxic at high concentrations. Additionally, it reacts with acids in the atmosphere such as sulphuric and nitric acid to produce PM2.5. It is primarily emitted from agricultural sectors and from fertilizer production.
Secondary pollutants, which form through reactions in the atmosphere rather than through direct emissions, include ozone and secondary PM, the two major components of smog. These are often important in related discussions since they are formed through sunlight-initiated reactions of precursor CACs.
Table 3.1: Canada-wide 2012 CAC Emissions from Oil Sands and Other Sectors
TPM PM10 PM2.5 SOx NOx VOC CO NH3 (t) (t) (t) (t) (t) (t) (t) (t) Mining 751 372 199 2,885 3,826 18,947 3,461 162 In Situ 686 671 670 9,433 14,397 1,947 13,498 -- Heavy oil and bitumen upgrading 4,379 2,638 1,256 99,545 26,445 24,819 14,201 1,197 Other Industry 473,446 172,719 92,389 739,183 568,217 711,264 1,368,440 15,088
All Industry 479,262 176,400 94,514 851,046 612,885 756,977 1,399,600 16,447 Non-Industry 129,676 114,972 109,772 314,730 240,774 151,136 732,440 1,956 Incineration 254 157 129 2,564 2,217 1,030 4,129 371 Miscellaneous 9,630 9,467 9,365 0 23 405,277 3,907 1,768 Mobile 62,980 62,424 55,501 96,818 994,232 440,325 6,022,566 24,038 Open Sources 22,049,942 6,717,647 1,099,044 22,504 11,587 271,929 91,486 450,942
Total Anthropogenic* 22,731,744 7,081,067 1,368,325 1,287,662 1,861,718 2,026,674 8,254,128 495,522 Natural Sources 118,430 23,032,699 *Total Anthropogenic includes all non-natural CAC sources Source: Environment Canada, Pollutant Inventories and Reporting Division, 2014
July 2014 34 Canadian Energy Research Institute
Table 3.2: Percentage Contribution of Oil Sands to Total Industrial and Total Anthropogenic Canadian Emissions in 2012
TPM PM10 PM2.5 SOx NOx VOC CO NH3 (t) (t) (t) (t) (t) (t) (t) (t) Mining vs. Industrial 0.2% 0.2% 0.2% 0.3% 0.6% 2.5% 0.2% 1.0% In Situ vs. Industrial 0.1% 0.4% 0.7% 1.1% 2.3% 0.3% 1.0% 0.0% Upgrading vs. Industrial 0.9% 1.5% 1.3% 11.7% 4.3% 3.3% 1.0% 7.3%
All oil sands vs. Industrial 1.2% 2.1% 2.2% 13.1% 7.3% 6.0% 2.2% 8.3% Mining vs. Total 0.00% 0.01% 0.01% 0.22% 0.21% 0.93% 0.04% 0.03% In Situ vs. Total 0.00% 0.01% 0.05% 0.73% 0.77% 0.10% 0.16% 0.00% Upgrading vs. Total 0.02% 0.04% 0.09% 7.73% 1.42% 1.22% 0.17% 0.24%
All oil sands vs. total 0.03% 0.05% 0.16% 8.69% 2.40% 2.26% 0.38% 0.27% Source: Environment Canada, Pollutant Inventories and Reporting Division, 2014
Total CAC emissions from all sectors in Canada for 2012 are shown in Table 3.1. To clarify the comparative size of emissions, the percentage contribution of the three oil sands activities (namely mining, in situ extraction, and bitumen and heavy oil upgrading) to total industrial and non-natural emissions is given in Table 3.2. The oil sands and heavy oil upgrading sectors are large contributors of total industrial emissions for certain CACs, including SOx (13.1 percent of industrial SOx emissions), NOx (7.3 percent of industrial NOx emissions), VOC (6.0 percent of industrial VOC emissions), and ammonia (8.3 percent of industrial ammonia emissions). When expanding the contribution to all non-natural sources of CACs, the contribution of the oil sands drops for three of these substances. Relative emissions of ammonia drop substantially due to the large contribution of agriculture to ammonia emissions, and NOx and VOC contributions drop slightly (to 2.4 and 2.3 percent of non-natural emissions, respectively) due to sizable emissions from power generation, mobile sources, and, in the case of VOCs, solvent use. Relative emissions of SOx drop only slightly to 8.7 percent of Canada-wide emissions, primarily due to additional emissions from power generation not included in the industrial numbers.
The extraction processes, both mining and in situ, are relatively minor contributors to total CAC, with the exception of mining VOC emissions, which were about 2.5 percent of all Canadian industrial VOC emissions, and in situ SOx and NOx emissions, which were 1.1 and 2.3 percent of total industrial emissions, respectively. For mining, VOCs can be emitted rather readily from both open mine faces, tailings ponds, and from evaporation of solvents required for the froth
July 2014 Oil Sands Environmental Impacts 35
extraction process. The amount of energy required for steam generation leads to the relatively high emissions of NOx and SOx in the in situ field.
Upgrading, on the other hand, is a comparatively large source of CACs, with heavy oil and bitumen upgrading contributing anywhere from 0.9 percent (TPM) to 11.7 percent (SOx) of total emissions. The sector is a significant industrial source of SOx, NOx, and VOCs; it is also a reasonably large industrial source of ammonia, although it is a small source compared to agriculture. Emissions of NOx and SOx are of considerable interest due to the acid sensitivity of a number of lakes in the region, and will be discussed later in this chapter.
While the oil sands sector is a significant source of several CACs, there has been progress, in some cases substantial, in reducing emissions produced per barrel of bitumen or SCO. For both mining/upgrading and in situ projects, emissions intensities of all CACs for the 2011-2012 period were significantly lower than in 2004-2005 (see Table 3.3 for details). For the mining and upgrading projects in Alberta, average emission intensities in 2011 through 2012 were anywhere from 81 percent (TPM) to 26 percent (carbon monoxide) of the 2004 though 2005 emission intensity. Additionally, despite a nearly 50 percent increase in SCO production over this time period, absolute reported emissions of SOx, VOCs, carbon monoxide and ammonia actually fell by about 16, 14, 61, and 30 percent, respectively. Emissions of NOx and PM rose, but at lower rates than SCO production.
Table 3.3: Ratio of Absolute Emissions and Emissions Intensity in 2011-2012 to Emissions Intensity in 2004-2005 for Criteria Air Contaminants
Emission Ratio (2011-12/2004-05) Intensity Ratio (2011-12/2004-05) CAC Mining In Situ Mining In Situ TPM 1.21 2.01 0.81 0.76 PM10 1.09 1.81 0.73 0.68 PM2.5 1.00 1.81 0.67 0.68 SOx 0.84 0.58 0.56 0.22 NOx 1.17 1.36 0.79 0.51 VOC 0.86 0.82 0.58 0.30 CO 0.39 1.72 0.26 0.64 NH3 0.70 N/A 0.47 N/A Source: NPRI Facility Report Data; AER ST39/ST53
In situ emissions intensities in 2011-2012 ranged from 76 percent (TPM) to 22 percent (SOx) of 2004-2005 values. Since production of bitumen in 2011-2012 was about 2.7 times that in 2004- 2005, most of the reported CAC emissions increased during this time. However, both VOC and SOx emissions declined during this time period by 18 and 62 percent, respectively.
For comparison, average mining and upgrading GHG emission intensities only fell by about 4 percent over the same time period, while in situ GHG emissions intensities fell by 14 percent,
July 2014 36 Canadian Energy Research Institute
highlighting the greater relative difficulty of emissions controls on GHGs compared to CACs. This is due in part because emissions controls technology is more mature for several CACs, but also due to regulatory efforts that aim at limiting the emissions of CACs, particularly in the case of acid rain precursors.
Heavy Metals and Polycyclic Aromatic Hydrocarbons The NPRI also provides estimates for Canada-wide emissions of the heavy metals lead, cadmium, and mercury; dioxins and furans; four polycyclic aromatic hydrocarbons (PAHs); and hexachlorobenzene (HCB). The oil sands are small overall contributors to the three heavy metals; in 2012, they accounted for 0.4 percent of air emissions of lead, 1.3 percent of air emissions of cadmium, and 1.6 percent of air emissions of mercury. According to NPRI estimates, they are insignificant contributors of dioxins, furans, PAHs and HCB.
Although total emissions are relatively low in comparison to total anthropogenic sources, the oil sands are located in a relatively remote area, and thus may be a substantially larger source than other regional emission sources. And when compounds are emitted to the air, they may be carried downwind and deposited in areas farther afield from the source, either by depositing to ground or water directly from the air or by being bound to particles that can settle out of the air. In a region with relatively few large anthropogenic sources, regional effects from point sources can be significant.
There is evidence of higher-than-expected background PAHs in the region surrounding the oil sands that cannot be explained by what is currently understood to be the PAH emission rates from regional sources, including the oil sands. One study attempted to model concentrations of three PAHs – phenanthrene, pyrene, and benzo[a]pyrene – using reported NPRI air emissions.3 When the model only included direct air emissions as they are reported to the NPRI, the modeled concentrations were considerably lower than those actually observed in the oil sands region. An indirect air emissions source was added; PAHs contained in tailings ponds water were allowed to volatilize (that is, allowed to move from the water to the air). With this additional indirect source, which was much larger in magnitude than direct air emissions, modeled PAH concentrations were much closer to observations. Benzo[a]pyrene, which is particularly resistant to volatilizing, was still modeled at lower concentrations than those observed, which may have been due to an additional source from blowing dust from mine surfaces. Thus, while reported emissions were not technically incorrect, the direct values reported to the NPRI are incomplete when it comes to describing the fate of releasing PAHs to the environment, and highlights the need to better characterize emissions and their sources in the oil sands. This is particularly important for large surface sources such as the exposed mine surface and tailings ponds, where emissions are particularly difficult to measure and characterize.
3 Parajulee and Wania (2014). Evaluating officially reported polycyclic aromatic hydrocarbon emissions in the Athabasca oil sands region with a multimedia fate model. Proceedings of the National Academy of Sciences 111, 3344 – 3349.
July 2014 Oil Sands Environmental Impacts 37
The deposition of PAHs has likewise been indirectly measured in lake sediments in the region.4 Sediment cores were collected from six lakes, five of which were within a 35 km radius of the major upgrading facilities, and one of which was a remote lake northeast of the major mining region. PAH concentrations in the sediments started to increase in sediments deposited around 1966 while a related class of sulphur containing molecules called dibenzothiophenes (DBTs) started to increase shortly thereafter, around 1972. PAH concentrations in current-day sediments were enhanced anywhere from 2.5 to 23 times that of background levels before the oil sands development, while DBTs where 2.6 to 57 times higher than background concentrations. The PAHs were dominated by what are known as alkylated PAHs; these PAHs have additional carbon side chains off the main PAH molecule and, along with DBTs, are prominent components of bitumen. Despite the significant increase in PAHs in the sediments, the study did not find evidence of changes in abundance of Daphnia, a species that is sensitive to the toxicity of PAHs. However, there was definite evidence of impacts of emissions of PAHs to remote lakes within the region. Soil and Lake Acidification The adverse effects of acid precipitation are well known; the effects of sulphur dioxide emissions and subsequent acid rain that results was one of the main drivers behind a transboundary agreement on air emissions between Canada and the United States established in 1991.5
When entering the atmosphere, sulphur dioxide and nitrogen oxides are oxidized to sulphuric and nitric acids, respectively. These water-soluble acids can be removed from the atmosphere through acid precipitation or by directly depositing to the earth’s surface. The effect acid deposition has on soil is highly dependent on soil chemistry. Sulphate and nitrate ions that are formed when these acids dissolve in water move readily through the soil. As they do so, these negatively charged species can pair with positively charged ions and leach them from the soil. This most readily occurs with what are known as base cations, which includes sodium, potassium, calcium and magnesium ions. As the base cations are depleted, toxic ions, notably aluminum, begin to mobilize and affect the health of vegetation.6
The sensitivity of soils and lakes to the effects of acid deposition depends on the capacity of soil minerals to neutralize the acid, known as the buffering capacity. This depends on the amount of base cations in the soil, how readily the minerals in the soil can weather and release additional buffering capacity, and how much additional buffering capacity is added to the system through deposition. The sensitivity of soils and lakes is typically measured using a critical load; this is the maximum deposition rate of acids that can be buffered by soil without leading to long-term harm.
4 Kurek et al. (2013). Legacy of a half century of Athabasca oil sands development recorded by lake ecosystems. Proceedings of the National Academy of Science 110, 1761 – 1766. 5 International Joint Commission: Agreement Between the Government of Canada and the Government of the United States of America on Air Quality. http://www.ijc.org/rel/agree/air.html 6 For an overview of soil acidification, see the United Kingdom Air Pollution Information System’s discussion at: http://www.apis.ac.uk/overview/pollutants/overview_Acid_deposition.htm
July 2014 38 Canadian Energy Research Institute
Many areas of northern Alberta are sensitive to acid deposition. Alberta Environment and Sustainable Resource Development has in place an acid deposition management framework for addressing the potential effects of acid deposition in the province.7 Within the framework there are three acid sensitivities defined. Each has three distinct trigger levels: the monitoring load, which is a level of predicted deposition that leads to further monitoring and research; the target load, which is the level of deposition that is aimed to be practically achieved; and the critical load, which as mentioned earlier is the highest load that will not lead to long-term harm. The loads for low, moderate, and high sensitivity regions are listed in Table 3.4.
Table 3.4: Critical, Target, and Monitoring Loads (kiloequivalents of H+ per hectare per year) for High, Moderate, and Low Sensitivity Regions in Alberta Sensitivity Level Critical Load Target Load Monitoring Load High 0.25 0.22 0.17 Moderate 0.50 0.45 0.35 Low 1.00 0.90 0.70 Source: Alberta Environment and Sustainable Resource Development
In July 2014, the 2011 Acid Deposition Assessment for Alberta was released.8 The most recent map of acid deposition sensitivities from this report is shown in Figure 3.1. Much of northeastern Alberta is of high acid sensitivity, although currently models show that acid deposition is only approaching the monitoring load, which is the lower acid deposition mode designed to trigger more intensive monitoring, by year 2020 (see Figure 3.2). However, the region near Fort McMurray is projected to be the only region near this threshold by 2020, and so the potential for acid deposition should still be monitored as oil sands development continues to grow.
7 Details of the acid deposition management framework may be found at http://esrd.alberta.ca/air/management- frameworks/acid-deposition-management-framework/default.aspx 8 Government of Alberta (2014). 2011 Acid Deposition Assessment for Alberta: a Report of the Acid Deposition Assessment Group. http://esrd.alberta.ca/air/management-frameworks/acid-deposition-management- framework/documents/2011AcidDepositionAssessment-Jul2014.pdf
July 2014 Oil Sands Environmental Impacts 39
Figure 3.1: Receptor Acid Sensitivity Map of Alberta
Source: Alberta Environment and Sustainable Resource Development
Figure 3.2: Modeled Acid Deposition as a Percentage of the Monitoring Load, 2006 and Projected for 2020
Source: Alberta Environment and Sustainable Resource Development
July 2014 40 Canadian Energy Research Institute
There is a range of opinions in the scientific literature about the state of soil acidification in the oil sands region. One study suggested that between 34 and 63 percent of acid sensitive soils experience acid deposition rates greater than the critical load.9 This is a less typical finding, however. Modeling of lake sensitivity to acidification showed that out of 50 lakes, only one would reach a critical threshold defined in the emissions management framework. 10 Models of 11 locations with highly acid sensitive soils showed that under 2006 conditions, 2 to 3 of the sites are expected to reach a critical threshold in 15 to 30 years, respectively, increasing to 7 sites if sulphur deposition is doubled, though the authors state that the effects of acid deposition are likely to be limited throughout the region.11 A more recent study found that soils in the region are currently in the process of recovering from previous acidification.12
Particularly in light of the downward trend in sulphur dioxide emissions, soil acidification is not an immediate concern; however, the situation should continue to be monitored to ensure that acid sensitive soils and lakes are not adversely affected in the future. Other Emissions and Air Quality Observations Routine monitoring of air quality in the oil sands region is primarily carried out by the Wood Buffalo Environmental Association (WBEA). Continuous and passive air monitoring are carried out at several monitoring locations throughout the Athabasca Oil Sands Area.
In 2010, the WBEA released a report on decade-long air quality trends in the region.13 The report examined trends in nitrogen dioxide, sulphur dioxide, fine PM, ozone, carbon monoxide, and total reduced sulphur for the 1998 to 2007 period. Although the oil sands underwent considerable expansion during this time period, the effect on air quality at Fort McMurray, Fort Chipewyan, and Fort MacKay (the closest community to the oil sands mines) was relatively small. Both Fort McKay and Fort McMurray saw a small increase in nitrogen dioxide concentrations. Total reduced sulphur increased slightly over the time period in Fort MacKay to concentrations that may result in odor issues if trends continue into the future. All three communities saw a decline in the amount of fine particulate matter.
Part of the mandate of the WBEA is to determine if air quality objectives are being met. Air quality objectives are maximum desirable concentrations of given air pollution components to prevent issues such as health impacts or odors. Two pollutants were found to exceed ambient guidelines on a somewhat regular basis in 2012. 14 Hydrogen sulphide exceeded the Alberta 1-hour
9 Whitfield et al. (2010). Estimating the sensitivity of forest soils to acid deposition in the Athabasca Oil Sands Region, Alberta. Journal of Limnology 69(S1), 201 – 208. 10 Whitfield et al. (2010). Modeling catchment response to acid deposition: a regional dual application of the MAGIC model to soils and lakes in the Athabasca Oil Sands Region, Alberta. Journal of Limnology 69(S1), 147 – 160. 11 Whitfield et al. (2009). Modeling soil acidification in the Athabasca Oil Sands Region, Alberta, Canada. Environmental Science and Technology 43, 5844 – 5850. 12 Jung et al. (2013). Critical loads and H+ budgets of forest soils affected by air pollution from oil sands mining in Alberta, Canada. Atmospheric Environment 69, 56 – 64. 13 Kindzierski (2010). Ten-Year Trends in Regional Air Quality for Criteria Pollutants in the Athabasca Oil Sands Region. Wood Buffalo Environmental Association. http://www.wbea.org/library/ambient-air-monitoring-reports 14 WBEA (2014). Wood Buffalo Environmental Association Annual Report 2012. http://www.wbea.org/library/annual-reports
July 2014 Oil Sands Environmental Impacts 41
guidelines of 10 ppb a total of 182 times in 2012; this is a vast improvement from 2010 and 2009 where the threshold was exceeded 614 and 1,625 times, respectively. The most frequent exceedances were observed at industry-located sites Mannix and Mildred Lake. Alberta’s 24-hour guideline of 3 ppb for hydrogen sulphide was exceeded 31 times in 2012, which, again, was an improvement from 2010 (118 exceedances) and 2009 (252 exceedances). Environmental Protection Orders were issued in 2009 by Alberta Environment and Sustainable Resource Development to reduce high levels of hydrogen sulphide,15 and the measures taken thus far appear to be improving the ambient levels of hydrogen sulphide in the oil sands area. Of other air pollutants, fine PM also exceeded guidelines of 30 micrograms per cubic metre of air over a 24-hour period; guidelines were exceeded 65 times in 2012 over the 11 sites measuring PM.
15 Alberta ESRD (2014). Hydrogen Sulphide Levels. http://esrd.alberta.ca/focus/state-of-the-environment/air/condition- indicators/hydrogen-sulphide-levels.aspx
July 2014 42 Canadian Energy Research Institute
July 2014 Oil Sands Environmental Impacts 43
Chapter 4: Water and Tailings
Water Use Both mining and in situ oil sands projects rely on water for the extraction of bitumen. The different processes used lead to unique challenges in fluid management. While oil sands mining water management is primarily concerned with the treatment of solid tailings, in situ water management is primarily an issue of water treatment for feed to steam generators. Water usage data is obtained from Alberta Environment and Sustainable Resource Development 1 and production data is obtained from AER ST39 and ST53.
Mining The process of extracting bitumen from raw oil sands ore requires a substantial amount of water. Although water used in processing bitumen ore can be recycled, loss of water through evaporation and non-reusable water associated with some mine tailings lead to a requirement for fresh water use. Based on reported water consumption from all oil sands mines and reported synthetic crude oil production rates, shown in Figure 4.1, an average of 3.2 barrels of fresh water were consumed for every barrel of synthetic crude oil produced between 2005 and 2013.
Figure 4.1: Fresh Water Usage by Oil Sands Mining Operations, 2005-2013
4.00 5.00
3.00 3.75
2.00 2.50
1.00 1.25
Water Water use intensity (bbl/bbl) Fresh water Fresh water (millionuse bbl per day)
0.00 0.00 2005 2006 2007 2008 2009 2010 2011 2012 2013
Fresh water usage Water use intensity
Source: AER ST39; Alberta Environment and Sustainable Resource Development
1 Oil Sands Operators: Water Use History, Alberta Environment and Sustainable Resource Development. http://environment.alberta.ca/apps/OSIPDL/Dataset/Details/56
July 2014 44 Canadian Energy Research Institute
The amount of water that can be recycled in mining operations is related to the management of fluid tailings. Tailings are the spent water mixture that results from the bitumen extraction process, and consists of a mixture of water, sand, fine clay particles, and residual oil and organic matter from the bitumen. The extraction process results in the formation of fine clay particles with high negative surface charges. Fine clay particles tend to settle very slowly initially due to their small size, and tend to stop settling and compacting over time due to electrostatic repulsion of like charges on the surface of the particles.2 As a result, when tailings are discharged to ponds, large sand particles tend to settle to the bottom relatively quickly, while clay particles tend to form a sludge-like mixture referred to as mature fine tailings or MFT.3 Around 1.5 barrels of MFT are generated for each barrel of bitumen produced.4
MFT present an important environmental management issue from the perspectives of water usage, land usage, and land reclamation. The time period from the initial formation of MFT to total consolidation is estimated to be in the range of several decades or longer. In addition to the water contained within these tailings, a large water cap is needed to prevent the tailings from being disturbed in the event of mixing from winds. As of 2013, according to tailings management plans, approximately 950 million cubic metres (about 6 billion barrels) of MFT are present in tailings ponds, containing a large volume of water that could otherwise be recycled back into the extraction process. Furthermore, the consistency of MFT is such that they lack the physical strength to support capping by sand or soil, which prevents dry reclamation of land covered with fluid tailings. The longer it takes for fluid tailings to consolidate into a form that can be reclaimed, the more land will be needed to be covered with tailings ponds to contain the volume of fines and water prior to final reclamation.
The Alberta Energy Regulator or AER (formerly known as the ERCB) put forth Directive 74 (Tailings Performance Criteria and Requirements for Oil Sands Mining Schemes) 5 in 2009 to address tailings management by oil sands mines. The directive requires oil sands mines to form designated disposal areas for the capture of fine tailings and reduce the amount of fines (defined as solids less than 44 micrometres in diameter) released to tailings ponds. Captured fines are required to be trafficable; that is, the fines must be sufficiently load-bearing to support eventual dry reclamation. Required fines capture rates were 20 percent in the July 2010 – June 2011 period, increasing to 30 percent for the July 2011 – June 2012 period and 50 percent annually thereafter. The techniques or technologies used to meet the directive are decided by the individual operators. Annual reports are to be submitted to the regulator to determine compliance.
2 Taylor M. L. et al. (2002). Kinetics of adsorption of high molecular weight anionic polyacrylamide onto kaolinite: the flocculation process. Journal of Colloid and Interface Science 250, 28-36. 3 Allen E. W. (2008). Process water treatment in Canada’s oil sands industry: I. Target Pollutants and treatment objectives. Journal of Environmental Engineering and Science 7, 123-138. 4 Tailings, a Lasting Oil Sands Legacy (2010), WWF Canada. http://awsassets.wwf.no/downloads/tailings__a_lasting_oil_sands_legacy___wwf.pdf 5 http://www.aer.ca/rules-and-regulations/directives/directive-074
July 2014 Oil Sands Environmental Impacts 45
The AER released an update assessing the performance of Directive 74 in 2013.6 For the first two reporting periods, four mining projects were required to capture fines. Three projects were allowed reduced targets as tailings management was implemented. Table 4.1 summarizes the tailings reduction performance for the first two reporting periods.
Table 4.1: Required Fines Disposal Under Directive 74 and Mine Performance (percent)
Project July 2010 – June 2011 July 2011 – June 2012 Requirement Performance Requirement Performance Suncor 20.0 10.7 30.0 8.5 Syncrude Mildred Lake 9.2 17.7 12.0 8.8 Shell Muskeg River 8.5 1.9 23.5 8.8 Shell Jackpine 9.5 0.0 15.5 0.0 Source: AER
With the exception of the first reporting period for Syncrude Mildred Lake, all mines have significantly underperformed in comparison to the required fines capture rates at this time. The report notes some of the issues that the industry has come across at this point and has opted not to utilize enforcement measures until the success of mitigating measures can be assessed. The next report on tailings management from the AER is expected in 2015, at which point the regulator notes that enforcement options will be examined if fines capture continues to underperform.
Directive 74 does not prescribe any particular method for fines capture, and as such there are multiple methods by which mines have gone about achieving these directives. Consolidated or composite tailings (CT) mixes mature fine tailings with sand from extracted ore and gypsum, which speeds up the release of water and the thickening of fine tailings, and is used at Syncrude, Shell Muskeg River, and previously by Suncor. Polymer flocculants (agents that cause fine clay particles to aggregate) are also used, such as Suncor’s Tailings Reduction Operation (TRO) and Shell Muskeg River’s atmospheric fines drying (AFD). The polymer flocculants thicken the fine clay particles, allowing the tailings to be dried using thin lifts. Shell Jackpine uses a thickened tailings (TT) process, using a thickening agent before disposing of fine tailings. Large-scale centrifuges are also used to mechanically thicken MFT; this process is in use at Syncrude and Shell Muskeg River.
In Situ In situ oil sands extraction relies on the use of steam to heat bitumen in the reservoir, decreasing its viscosity to the point that it can be pumped to the surface. The amount of water required for the extraction process is dictated by the steam-to-oil ratio; the weighted average from 2004 through 2011 for in situ commercial projects is about 3.4 barrels of cold water equivalents in steam for every barrel of bitumen produced. The source water for steam production has three
6 2012 Tailings Management Assessment Report: Oil Sands Mining Industry (2013), Energy Resources Conservation Board. http://www.aer.ca/documents/oilsands/tailings-plans/TailingsManagementAssessmentReport2011-2012.pdf
July 2014 46 Canadian Energy Research Institute
primary sources: fresh water, which may be taken from surface water or groundwater sources; brackish water, which is saline groundwater with total dissolved solids (TDS) higher than 4,000 milligrams per litre; and produced water, which is water extracted from the oil production well that is a combination of condensed steam and existing groundwater in the oil reservoir. As produced water can be recycled, the actual makeup water required from fresh and brackish sources is considerably less than the amount of steam required. As tailings are not an issue for in situ extraction, the amount of process water that can be recycled is also higher than for mining, reducing the amount of required makeup water. Between 2002 and 2013, an average of 0.93 barrels of makeup water were used for every barrel of bitumen produced by commercial SAGD and CSS operations. As with GHG emissions, the discussion of in situ water usage will exclude data from the Nexen/CNOOC Long Lake project due to the different production techniques used at that facility and focus on non-integrated commercial bitumen production.
Makeup water usage is shown in Figure 4.2. Although bitumen production by in situ methods was roughly 4.5 times higher in 2013 than in 2002 (the first year that water usage is reported by Alberta Environment), total makeup water usage was only 2.2 times higher in 2013 compared to 2002. Most of this increase in makeup water has come from a greater reliance on brackish water, as fresh water use was only 1.1 times higher in 2013 compared to 2002. While almost all makeup water was fresh in 2002, brackish water now accounts for about half of the total makeup water used for in situ projects.
Figure 4.2: Fresh and Brackish Water Use by In Situ Oil Sands Producers
500 1.25
400 1.00
300 0.75
200 0.50
100 0.25
Makeup water Makeup water use intensity (bbl/bbl) Makeup water Makeup water usage (thousands bbl per day) 0 0.00 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013
Fresh used Brackish Used Fresh intensity Brackish intensity
Source: AER ST53; Alberta Environment and Sustainable Resource Development
July 2014 Oil Sands Environmental Impacts 47
In addition to increased reliance on brackish water, the overall use of makeup water has dropped considerably for each barrel of bitumen produced. In 2013, 0.53 barrels of makeup water were required to extract one barrel of bitumen, down from a maximum of 1.23 barrels of makeup water during the 2002-2013 period.
In Situ Water Regulations The AER (and the former ERCB) have sought to encourage the reduction of water use, and in particular the amount of fresh water required for steam generation at in situ sites. In previous years, recycling of process water was required through IL 89-5 for in situ producers requiring more than 500,000 m3 of fresh water per year. Water recycle rates were determined based on the amount of produced water and fresh makeup water used compared to the total steam injected into the well. The recycle rate was calculated using the following formula:7
Steam injected − Fresh water Recycle rate = × 100 Produced water
Recycle rates can be calculated using publicly available data as of 2009 when the then-ERCB started reporting produced water and steam volumes with the statistical report ST 53 (Alberta Crude Bitumen In Situ Production Monthly Statistics), combined with fresh water use from Alberta Environment. Recycle rates, shown in Table 4.2 have fallen slightly from 96 percent in 2009 to 94 percent in 2012.
Table 4.2: IL 89-5 Based Recycle Rates and Directive 81 Based Disposal Limits and Rates (data incomplete for 2012-2013 disposal rates)
Year Recycle Rate Disposal Limit Overall Disposal Rate (%) (%) (%) 2009 96.1 10.7 8.9 2010 94.8 10.6 9.3 2011 92.2 10.3 10.9 2012 93.7 10.8 -- 2013 93.6 10.4 -- Source: AER ST53, AER in situ annual updates
Currently, regulations to curb the use of makeup water (that is, additional surface or groundwater to generate steam beyond recycled produced water) take the form of a water disposal limit. Water usage is addressed in Directive 81: Water Disposal Limits and Reporting Requirements for Thermal In Situ Oil Sands Schemes.8 This directive sets a limit on the volume of liquid disposal based on the amount of fresh, brackish, and produced water used by a facility. The disposal limit is calculated from the following formula:
7 Formula obtained from http://www.pembina.org/pub/612 8 http://www.aer.ca/rules-and-regulations/directives/directive-081
July 2014 48 Canadian Energy Research Institute
Fresh In × Df + Brackish In × Db + Produced In × Dp Disposal Limit = × 100 Fresh In + Brackish In + Produced In
Df, Db, and Dp are disposal factors given for fresh, brackish, and produced water, respectively. Disposal factors are specified for SAGD and CSS operations and are listed in Table 4.3. Produced water recycle requirements for SAGD are slightly less stringent than for CSS since the former uses dry steam for well injection (that is, steam free of liquid water). Since blowdown water, the term for liquid water that remains after steam production, must be recycled by SAGD operators and contains relatively high concentrations of dissolved solids, the disposal requirements for produced water are set lower than for CSS operators.
Table 4.3: Disposal Factors for Thermal In Situ Oil Sands Producers
Disposal Factor Water Type SAGD CSS
Df Fresh water 0.03 0.03 Db Brackish water 0.35 0.35 Dp Produced water 0.10 0.07 Source: AER
The actual disposal rate is calculated by dividing the volume of water disposed by the total fresh, brackish, and produced water input into a facility. The directive applies only to operations requiring greater than 500,000 cubic metres of makeup water per year in absence of produced water recycle, as to exclude pilot projects. Although Directive 81 does not mandate an overall disposal rate for in situ producers, for the interest of this discussion the average disposal limit and disposal rate are shown in Table 4.2. Disposal rates are calculated using data obtained from in situ annual progress reports.9 In 2011, the actual disposal rate slightly exceeded the limit determined using the Directive 81 formula.
The calls for both higher water recycling rates and increased use of brackish water have led to a change in the steam and water treatment and steam generation processes. Water treatment was typically accomplished using warm-lime softening, followed by steam generation using once- through steam generators (OTSGs). OTSGs are typically used in conjunction with warm lime softening as they can handle the higher solids content in the water characteristic of this treatment process. However, the higher solids content also leads to a greater amount of high- solids wastewater, and thus lower water recycle rates. Recycle rates can be higher when treating water using an evaporator, which produces cleaner distilled feedwater for steam generation. An additional advantage is that feedwater from an evaporator has a low enough solids content to be used in conventional drum boilers, which can significantly lower the capital cost of SAGD operations. While the evaporator-boiler setup can increase water recycle rates, it does have the tradeoff of being more energy-intensive than warm lime softening and OTSGs, and thus will have adverse effects on GHG emissions in SAGD operations.
9 http://www.aer.ca/data-and-publications/activity-and-data/in-situ-performance-presentations
July 2014 Oil Sands Environmental Impacts 49
Chapter 5: Land Use and Biodiversity
Introduction While human health can be impacted by industrial development, a function of ecosystems may also be altered by human activity. Altering of natural habitat for human development, such as for oil and gas extraction, forestry, or agriculture, can alter the makeup of organisms within an ecosystem by either decreasing the populations of sensitive species or increasing the populations of species well suited to areas with high human activity. The variety of species living in a particular environment is referred to as biodiversity. While a degree of biodiversity preservation stems from an ideal of leaving nature untouched by human activity, there are many tangible benefits from preserving ecosystems as they function. Ecosystem services include climate regulation, water regulation, soil formation and erosion control, pollination, food production, provision of raw materials, and cultural and recreational services; in 1997, ecosystem services were estimated at about $33 trillion US dollars per year globally (1994 dollars).1 Knowing the impacts of human activity on biodiversity and ecosystem function is crucial for both mitigating effects of current development and for responsible planning of future development.
In 2007, the Alberta Biodiversity Monitoring Institute was formed.2 A non-profit organization at arms-length from government and industry, the ABMI is tasked with monitoring the state and detecting changes in biodiversity in Alberta. The monitoring activities of ABMI are performed in collaboration with the University of Alberta, Alberta Innovates, the Royal Alberta Museum, and the Alberta Conservation Association, and their activity is reviewed by an independent science committee consisting of global experts. They are currently the only group that performs regular, province-wide biodiversity monitoring with publicly available data, performed at sites on a province-wide, 20 km by 20 km grid.
The ABMI has released two preliminary assessment reports on the state of biodiversity in the oil sands region. In 2013, “The Status of Biodiversity in the Athabasca Oil Sands Region”3 focused on the largest of the three regions, while in 2014, “The Status of Biodiversity in the Oil Sands Region of Alberta”4 included the Cold Lake and Peace River oil sands regions as well. The findings of these reports will be discussed in this chapter. Land Disturbance in the Oil Sands Region The human footprint was assessed by ABMI using a combination of externally sourced data such as cities, roads, industrial sites, cutlines, human-made water bodies, cultivated land, and
1 Costanza et al. (1997). The value of the world’s ecosystem services and natural capital. Nature 387, 253 – 260. 2 The Alberta Biodiversity Monitoring Institute. http://www.abmi.ca 3 The Alberta Biodiversity Monitoring Institute (2013). The Status of Biodiversity in the Athabasca Oil Sands Area: Preliminary Assessment. ABMI, Alberta, Canada. Available at www.abmi.ca 4 The Alberta Biodiversity Monitoring Institute (2014). The Status of Biodiversity in the Oil Sands Region of Alberta: Preliminary Assessment. ABMI, Alberta, Canada. Available at www.abmi.ca
July 2014 50 Canadian Energy Research Institute
managed forests. These data were supplemented with aerial photography and satellite imagery to establish the degree of land disturbed in the oil sands regions.
As shown in Figure 5.1, the total human footprint in the three oil sands region increased from 11.3 to 13.8 percent between 1999 and 2012. More than half of the disturbed land is from agricultural development, which accounts for more than 7 percent of the total land area. Most of the agricultural development occurs in the Peace River and Cold Lake Regions, with less than 1 percent of the Athabasca Oil Sands Region containing agricultural development. Energy and mining, which includes the oil sands, has the third largest land footprint at 2.3 percent of the land area, behind forestry, covering 3.1 percent of the land area. Protected areas make up 6.2 percent of the region.
Figure 5.1: Land Disturbance in the Oil Sands Regions
16.0
14.0
12.0
10.0
8.0
6.0
4.0 Total Total footprint land (%) 2.0
0.0 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 Agriculture Commercial/Industrial Energy and Mining Forestry Residential/Recreation Transportation
Source: ABMI
The report covering only the Athabasca Oil Sands Region highlights the difference between the development footprints of mining and in situ projects. Energy and mining has a land disturbance of 2.5 percent of the region in 2010. The sub-region with active in situ projects had a slightly higher footprint, with 4.2 percent of the land disturbed by energy projects, while the mineable oil sands region had a footprint of 16.8 percent. Overall human footprints are 6.8 percent in the entire Athabasca oil sands region, 7.7 percent in areas with active in situ development, and 20.8 percent in the active minable region.
While oil sands development has a relatively small land disturbance, the nature of the resource means that the impact is much less compact than other industries. Minor footprints from linear disturbances, mainly from seismic lines used to determine reservoir properties, are observable
July 2014 Oil Sands Environmental Impacts 51
over a large portion of the oil sands regions, while a much larger proportion of the region is undisturbed by agriculture and forestry (Figure 5.2). Based on 2012 observations, while 86 percent of the land is unaltered, only 67 percent is more than 50 metres away from land altered by human activity. When this buffer zone is increased to 200 metres, only 37 percent of the land area is unaffected, and only 3 percent is 2 km from altered land. As such, while the overall footprint is relatively small, these linear disturbances could disproportionately affect species that require their habitat to have a large buffer zone from areas impacted by human activity.
Figure 5.2: Human Footprint in the Oil Sands Regions of Alberta Top Left – All Activities; Top Right – Agriculture; Bottom Left – Forestry; Bottom Right – Energy and Mining
Source: ABMI
July 2014 52 Canadian Energy Research Institute
Biodiversity Impacts Biodiversity Intactness The ABMI reports the status of 425 native species in the oil sands regions using a Biodiversity Intactness Index. Species counts are combined with the human footprint in a statistical model that predicts current abundance of each species in quarter-section-sized areas and compares that to the expected abundance in the absence of human impact. The Biodiversity Intactness Index is presented as a percentage, with 100 percent representing a quarter-section area where current abundance equals the expected species abundance. For species that have declined in numbers, the index is calculated as:
퐶푢푟푟푒푛푡 퐴푏푢푛푑푎푛푐푒 퐵푖표푑푖푣푒푟푠푖푡푦 퐼푛푡푎푐푡푛푒푠푠 퐼푛푑푒푥 = × 100% 푅푒푓푒푟푒푛푐푒 퐴푏푢푛푑푎푛푐푒
For species that have increased in numbers, the index is calculated as:
푅푒푓푒푟푒푛푐푒 퐴푏푢푛푑푎푛푐푒 퐵푖표푑푖푣푒푟푠푖푡푦 퐼푛푡푎푐푡푛푒푠푠 퐼푛푑푒푥 = × 100% 퐶푢푟푟푒푛푡 퐴푏푢푛푑푎푛푐푒
Biodiversity intactness was calculated across five ecosystem components: native birds, winter- active mammals, armoured mites, native vascular plants, and moss and liverworts. Overall, intactness averaged 88 percent over the oil sands regions in 2012. The Peace River and Cold Lake regions, which are more heavily impacted by agriculture, average 85 and 72 percent intactness, while the Athabasca region is, on average, 94 percent intact for the species measured by the ABMI.
Native birds were overall the most impacted class of species measured by the ABMI in 2012, with overall intactness of 80 percent among 80 species observed. ABMI notes that of the 10 species that were lower in abundance than expected, 8 species required old forest habitat, with the black-throated green warbler about 50 percent less abundant than expected. Another 10 species were found in higher abundance than expected. These species, such as the American crow and the black-billed magpies, are well adapted to live in human-impacted environments.
This ABMI report had expanded the birds observed compared to the previous report focusing on the Athabasca region, which looked at 20 species of old forest birds. In the Athabasca study, bird species were 93 percent intact on average, with 91 and 88 percent intactness in the active in situ regions and active minable regions, respectively, in 2010. However, since the latest report notes that the greatest effect on bird populations is from the over-abundance of species that thrive in human environments, which the Athabasca report did not provide data for, it cannot be said with any certainty whether the bird impacts tend to be worse when the Peace River and Cold Lake regions are included in observations.
Winter-active mammals are important both for ecological reasons, such as roles as predators in the case of the grey wolf or the Canada lynx, and for economic purposes due to hunting and
July 2014 Oil Sands Environmental Impacts 53
trapping. Overall, 10 observed species were 91 percent intact as of 2012. Small coniferous forest- dwelling mammals, including the marten, the fisher, and the red squirrel, were less abundant than expected, while the coyote was more abundant than expected due to its ability to adapt to human environments. The Athabasca region in 2010 was not substantially different in impacts, with 10 species being 95 percent intact on average. In the minable oil sands region, all but two species were less abundant than expected, although even the most impacted species were 87 percent intact.
Armoured mites, which are important decomposers in soil ecosystems, were about 90 percent intact over the three oil sands regions for 62 studied species. The ABMI notes that prior to these monitoring efforts, little was known about armoured mites in the oil sands ecosystem and what habitats and ecological niches they fill. As such, these observations form an important baseline study of this class of organisms. Similar intactness was observed in 2010 in the Athabasca region, with species found to be 95 percent intact on average. Impacts were slightly larger in the in situ (91 percent intact) and mining (88 percent intact) areas.
Vascular plants in the region were on average 88 percent intact over 183 species. A number of species were much less abundant than expected; the 10 most negatively affected plant species were 56 to 78 percent less abundant than reference conditions, and represent species from both young deciduous and older coniferous forests. Grasses and sedges were among the species found in higher-than-expected abundance, as these plants are usually the first to grow in disturbed areas. Red fescue, a native grass, was more than three times more abundant than expected in the oil sands regions.
The report on the Athabasca region only reported observations on berry-producing plants, which are important food sources for wildlife and serve dietary and medicinal purposes for locals. These plants were 97 percent intact, although most species were negatively impacted, although species such as the wild red raspberry, which grows readily in disturbed areas, were more abundant. The minable region was substantially more impacted, with berry-producing plants only 87 percent intact.
Finally, ABMI measured 85 moss species to be 91 percent intact on average. Negatively impacted species include long-forked moss, which is noted to play a role in peatland formation, and several of the more abundance mosses are known to grow well in disturbed areas.
These studies primarily represent preliminary assessment of biodiversity intactness in the oil sands region. ABMI will continue to carry out assessment of these species as the oil sands are developed, which will allow for action to be taken if there is an observed negative effect as a result of development.
Non-Native Plants The ABMI also reports the frequency by which non-native plants are found at monitoring sites. Non-native plants are introduced into a landscape via human activity, intentionally or not, and can occasionally have a detrimental effect on plant biodiversity by out-competing local plants.
July 2014 54 Canadian Energy Research Institute
A selection of more common non-native plants is shown in Table 5.1. For the most part, the observed non-native plants are similar between the entire oil sands region from 2012 observations and the Athabasca oil sands region in 2010. The common dandelion, alsike clover, Timothy, and Kentucky bluegrass are the four most commonly observed species. Four species observed – perennial sow-thistle, creeping thistle, tall buttercup, and scentless chamomile (not in Table 5.1; observed at fewer than 1 percent of sites in the 2012 all-region study) – are listed as noxious weeds in the Alberta Weed Control Act (2010).
Table 5.1: Selected non-Native Plants in the Athabasca Oil Sands Region in 2010 and Across all Oil Sands Regions in 2012
Species Athabasca All Oil Sands (2010) (2012) Common Dandelion 25 30 Alsike Clover 15 14 Timothy 14 9 Kentucky Bluegrass 12 18 Common Plantain 8 5 Yellow Sweet-clover 8 2 Annual Hawk’s Beard 8 7 White Sweet-clover 8 1 Perennial Sow-thistle* 6 3 Red Clover 6 2 Awnless Brome 6 7 Creeping Thistle* 5 6 Tall Buttercup* 3 3 *Classified as noxious weeds Source: ABMI 2013 and 2014
Woodland Caribou The population of caribou in the oil sands region is sufficiently small that the ABMI does not observe the species as part of its monitoring program. As a species at risk under the federal Species at Risk Act,5 Alberta Environment and Sustainable Resource Development carries out monitoring for caribou throughout the Province of Alberta, and released a report in 2010 updating their status.6
Woodland caribou in Alberta were listed as endangered in 1987, with their status changed to threatened when the risk category was created in 1997. Sixteen populations of caribou exist in
5 Government of Canada. Species at Risk Public Registry – Species Profile (Woodland Caribou). http://www.sararegistry.gc.ca/species/speciesDetails_e.cfm?sid=636 6 Alberta Sustainable Resource Development and Alberta Conservation Association. 2010. Status of the Woodland Caribou (Rangifer tarandus caribou) in Alberta: Update 2010. Alberta Sustainable Resource Development. Wildlife Status Report No. 30 (Update 2010). Edmonton, AB. 88 pp. http://esrd.alberta.ca/fish-wildlife/species-at-risk/species-at-risk-publications-web- resources/mammals/documents/SAR-StatusWoodlandCaribouAlberta-Jul2010.pdf
July 2014 Oil Sands Environmental Impacts 55
the province, with several living in the boreal forest of northeastern Alberta where the oil sands are located (Figure 5.3). Populations overlapping with at least part of the three oil sands regions are Cold Lake, Nipisi, Red Earth, Richardson, East-side Athabasca, and West-side Athabasca (a seventh population, the Chinchaga, has a very small overlap on the western edge of the Peace River oil sands region).
Figure 5.3: Caribou Ranges in Alberta
Note: The Red Earth, West Side and East Side Athabasca River, Cold Lake, Richardson and Nipisi ranges overlap with the oil sands regions Source: Alberta Conservation Association; Government of Alberta
July 2014 56 Canadian Energy Research Institute
Most populations of caribou are in decline. Between 1993 and 2002, a study of 6 caribou populations in northeastern Alberta found that four populations were in decline (the east side of the Athabasca River, Red Earth, the Cold Lake Air Weapons Range in Saskatchewan, and the Caribou Mountains), three of which were declining rapidly enough to decrease to half their size within three generations.7 The populations in the west side of the Athabasca River and the Cold Lake Air Weapons Range in Alberta were stable over this time period. A longer study looked at 14 populations for periods ranging from 3 to 17 years between 1994 and 2012.8 Of these caribou, only three populations did not show clear signs of decline (one of these, the Richardson range, overlaps with the northeast portion of the Athabasca oil sands region). Across Alberta, caribou populations were declining rapidly at a rate of about 50 percent every 8 years.
Both studies attribute the loss to increased mortality of mature caribou and calves due to increased predation rates. Human disturbance of habitat can increase predation rates in a number of ways. For example, land disturbances and an increase in the population of prey species, such as deer and moose (both of which have been found in increased abundance by ABMI), which in turn can increase the population density of wolves, the primary predator of caribou. Similarly, climate change can result in northern migration of other prey species with the same end outcome. Perhaps of most concern for oil sands specifically, linear disturbances, such as the seismic lines cut for in situ developments, can likewise increase the efficiency by which wolves can hunt caribou.
It should be stressed that while oil sands developments can adversely affect caribou populations, the decline is not unique to the oil sands; human impacts are causing decline in the caribou and reindeer population globally. 9 Preventing loss of this species requires intervention in development patterns, both in the energy industry and in other industries and potentially human-influenced habitat alterations such as forest fires. Reclamation Oil sands projects are required to reclaim disturbed land once a project has been decommissioned. The process of reclamation involves returning the land to an ecologically functional area, ideally as close to the original function of the disturbed land. As of the end of 2012, of the approximately 85,000 hectares of land affected by oil sands development, 5,042 hectares have been fully reclaimed, and only 104 hectares have been certified as such.10 More than 90 percent of total land affected by development is currently either classified as disturbed or cleared of vegetation at this point and not at the point of being ready for reclamation. Total disturbed and reclaimed land is summarized in Figure 5.4. At this stage in development, much of the affected land is still under active development, and more reclamation efforts will occur in future years.
7 McLoughlin et al. (2003). Declines in populations of woodland caribou. Journal of Wildlife Management 67, 755 – 761. 8 Hervieux et al. (2013). Widespread declines in woodland caribou (Rangifer tarandus caribou) continue in Alberta. Canadian Journal of Zoology 91, 872 – 882. 9 Vors and Boyce (2009). Global declines of caribou and reindeer. Global Change Biology 15, 2626 – 2633. 10 Government of Alberta. Alberta’s Oil Sands: Reclamation. http://www.oilsands.alberta.ca/reclamation.html
July 2014 Oil Sands Environmental Impacts 57
Figure 5.4: Land Disturbance and Reclamation Status of Oil Sands Projects as of December 31, 2012
90
80
70 Cleared
60 Disturbed Ready for Reclamation 50 Soils Placed 40 Temporary Reclaimed 30 Permanent Reclaimed
Thousands of Hectares 20 Certified Reclaimed
10
0
Source: Government of Alberta
One particularly difficult area of the landscape to reclaim is natural wetlands. Covering about half of the oil sands area, wetlands are a highly important habitat and serve many environmental functions, such as water treatment, flood control, carbon storage, stabilization of shorelines, and regulation of local groundwater, and this complexity makes it difficult to restore an equivalent ecological function of wetlands.11 Success in final reclamation will be partially dictated by how well oil sands mine operators in particular are able to restore the original ecological functioning of displaced wetlands.
11 Guideline for Wetland Establishment on Reclaimed Oil Sands Leases (2007). Wetlands and Aquatics Subgroup, Reclamation Working Group, Cumulative Environmental Management Association – Wood Buffalo Region. http://environment.gov.ab.ca/info/library/8105.pdf
July 2014 58 Canadian Energy Research Institute
July 2014 Oil Sands Environmental Impacts 59
Chapter 6: Monitoring
Current Monitoring Programs Environmental effects monitoring has been a somewhat contentious issue in the oil sands region. Monitoring has been carried out by a number of different entities, including the Cumulative Effects Management Association (CEMA), the Wood Buffalo Environmental Association (WBEA), and the Regional Aquatic Monitoring Program (RAMP). Monitoring under CEMA has typically taken the form of short-term sponsored studies to support environmental management frameworks in the region, while WBEA and RAMP have supported long-term monitoring of air and water in the region, respectively.
Criticisms of the state of monitoring, particularly in the case of RAMP,1 have led to the recent agreement between the provincial and federal governments to coordinate efforts. The Joint Oil Sands Monitoring (JOSM) implementation plan was announced in February 2012 and is to be fully implemented by 2015. The JOSM has its roots in a December 2010 report to the federal Minister of the Environment from an Oil Sands Advisory Panel charged with examining the state of environmental monitoring in the Lower Athabasca River Basin. 2 The Panel reported that significant monitoring activities were carried out in the region for the purpose of studying air quality, water quality, land disturbance and biodiversity. However, the activity was substantially lower than previous large scale monitoring efforts such as the effects of acid deposition in eastern Canada, and that existing monitoring failed to create any consensus on the degree of environmental impact in the region. Their recommendation was to create a management framework for the coordination of monitoring activities with “aligned priorities, policies and programs” that is integrated across environmental media, time, and agencies.
Detailed documents outlining the scope of the expanded monitoring program were released in 2011. The first, the Lower Athabasca Water Quality Monitoring plan,3 outlines plans with respect to the monitoring of surface and groundwater quantity and quality. This was followed by the Integrated Oil Sands Monitoring Plan,4 which includes components on expansion of the water monitoring program, aquatic effects and biodiversity, and acid sensitive lakes, 5 air quality monitoring, 6 and terrestrial biodiversity. 7 These documents outline the future scope of the
1 RAMP 2010 Scientific Peer Review. http://www.ramp-alberta.org/ramp/results/ramp+2010+scientific+peer+review.aspx 2 A Foundation for the Future: Building an Environmental Monitoring System for the Oil Sands (2010). Oil Sands Advisory Panel, Environment Canada, Cat. No. EN4-148/2010E-PDF. http://publications.gc.ca/site/eng/392384/publication.html 3 Lower Athabasca Water Quality Monitoring Plan Phase 1 (2011), Environment Canada, Cat. No. EN14-42/2011E-PDF. http://publications.gc.ca/site/eng/390667/publication.html 4 An Integrated Oil Sands Monitoring Plan (2011), Environment Canada, Cat. No. EN14-47/2011E-PDF. http://publications.gc.ca/site/eng/396679/publication.html 5 Integrated Monitoring Plan for the Oil Sands: Expanded Geographic Extent for Water Quality and Quantity, Aquatic Biodiversity and Effects, and Acid Sensitive Lake Component (2011), Environment Canada, Cat. No. EN14-49/2011E-PDF. http://publications.gc.ca/site/eng/396888/publication.html 6 Integrated Monitoring Plan for the Oil Sands: Air Quality Component (2011), Environment Canada, Cat. No. EN14-45/2011E- PDF. http://publications.gc.ca/site/eng/394253/publication.html 7 Integrated Monitoring Plan for the Oil Sands: Terrestrial Biodiversity Component (2011), Environment Canada, Cat. No. EN14- 48/2011E-PDF. http://publications.gc.ca/site/eng/396865/publication.html
July 2014 60 Canadian Energy Research Institute
adaptive monitoring program such as sampling sites, physical and chemical measurements needed, and intensive monitoring campaigns required to expand current knowledge. The program is designed to integrate different environmental media together during monitoring and is designed to meet three core results: assessment of accumulated environmental conditions; assessment of the relationship between environmental response and drivers within the system; and assessment of cumulative ecological and environmental effects. The documents were written and reviewed by an extensive list of scientists from government, academia, and monitoring agencies, and are quite detailed in scope.
In 2012, the governments of Alberta and Canada released the Joint Canada-Alberta Implementation Plan for Oil Sands Monitoring.8 In the document, a three-year timeline outlining the establishment of the integrated plan is detailed, with full implementation to be achieved by 2015. The agencies responsible for the particular monitoring projects are unclear in the document, but overall current and developing monitoring arrangements were to be co-led by the provincial and federal governments. Annual reports were to be published about the status of the implementation process, with a peer review to occur after implementation is complete.
The integrated monitoring plan itself is detailed and comprehensive, and the status of implementation as it stands was reported on in 2014 with the first annual report on the monitoring program.9 Most of the commitments for the 2012-2013 implementation period were met or initiated by the monitoring program. Highlights of the implementation process include:
A preliminary funding structure was established, collecting approximately $13.2 million from industry for monitoring activities. Multi-stakeholder engagement processes were held with Aboriginal groups, the Governments of Saskatchewan and Northwest Territories, environmental non- governmental organizations, industry, and existing monitoring agencies. Development of the Portal website for future inclusion of monitoring data and analysis.
Key findings of the monitoring program during the 2012-2013 period are also highlighted in the report, including data on acidifying gases, polycyclic aromatic hydrocarbons and compounds, heavy metals, and ecosystem and biodiversity impacts.
A data portal has been established for the program,10 although as the data management system is still being established, there is currently little data available. News releases on the data portal include announcements of a Queen’s University/Environment Canada study finding increasing
8 Joint Canada-Alberta Implementation Plan for Oil Sands Monitoring (2012), Government of Canada and Government of Alberta. http://www.jointoilsandsmonitoring.ca/default.asp?lang=En&n=D876B1A8-1 9 The Joint Canada-Alberta Implementation Plan for Oil Sands Monitoring First Annual Report: 2012-2013 (2014), Government of Canada and Government of Alberta. http://www.jointoilsandsmonitoring.ca/074F3CAC-CC77-460E-8B72- 33DC06DDFC80/2012-2013%20JOSM%20Annual%20Report-FINAL%20EN.pdf 10 www.jointoilsandsmonitoring.ca
July 2014 Oil Sands Environmental Impacts 61
lake contamination in the oil sands region,11 announcement of the data portal itself,12 and an intensive ground- and aircraft-based air monitoring study in August-September 2013 as part of the air quality component of the plan.13
The information portal includes an interactive map14 that shows monitoring sites established under the program and, as the program continues to be implemented, should link to data collected at each site. Certainly, a number of sites related to water, sediments, benthic invertebrates, fish monitoring, biological contamination, and air quality have been established since 2011, and there are a number of sites listed as planned on the map as well. The first annual update indicates that a number of these new monitoring sites have been established as was committed in the 2012-2013 time period.
One recent area of progress for the JOSM has been the establishment of a funding mechanism with the passing of Bill 21: the Environmental Protection and Enhancement Amendment Act in 2013. The bill allows for the provincial government to collect from industry the $50 million per year required for the initial expansion of monitoring in the region.
AEMERA In March 2012, the Alberta government formed the Alberta Environmental Monitoring Working Group to provide recommendations for the governance and funding of a new provincial environmental monitoring, evaluation and reporting system. The report 15 recommended the establishment of a science-based, neutral, and arm’s length provincial agency charged with establishing province-wide environmental monitoring under Alberta’s Land Use Framework. The arm’s length model was recommended based on the potential for the greatest amount of legitimacy, credibility, and stakeholder support. The working group made twelve recommendations for the monitoring system, including its mandate, values and principles, arm’s length structure, funding, and implementation.
To carry out the provincial portion of the monitoring activities, the Alberta Environmental Monitoring, Evaluation and Reporting Agency (AEMERA) was established. The agency came into existence by the passing of Bill 31: Protecting Alberta’s Environment Act, which came into effect in April 2014. The current status of AEMERA is that it has been officially established and a Board of Directors has been appointed. The success of the implementation will need to be examined as the agency establishes itself and takes over monitoring activities from the Ministry of Environment and Sustainable Resource Development.
11 Kurek et al. (2013). Legacy of a half century of Athabasca oil sands development recorded by lake ecosystems. Proceedings of the National Academy of Science 110, 1761 – 1766. 12 http://www.ec.gc.ca/default.asp?lang=En&n=714D9AAE-1&news=859F236E-422D-4678-9067-FE4C31CFC856 13 http://www.ec.gc.ca/default.asp?lang=En&n=714D9AAE-1&news=D1490330-B65A-4711-8A89-DE917ACCBD29 14 http://www.jointoilsandsmonitoring.ca/flex/index.html 15 Implementing a World Class Environmental Monitoring, Evaluation and Reporting System for Alberta: Report of the Working Group on Environmental Monitoring, Evaluation and Reporting (2012), Alberta Environmental Monitoring Working Group. http://environment.gov.ab.ca/info/library/8699.pdf
July 2014 62 Canadian Energy Research Institute
July 2014 Oil Sands Environmental Impacts 63
Chapter 7: Conclusions
There are a number of points that can be taken from this discussion of oil sands environmental impacts.
Greenhouse gas emissions from the oil sands, while small on a global scale, are rising in absolute terms for both mining and in situ production. This comes despite progress made in reducing the emissions intensity of bitumen production. Continued development of the oil sands, in the absence of drastic changes in technology leading to greatly reduced emissions, will make it challenging for Canada to achieve its international GHG emissions reductions commitments. Emissions intensities of criteria air contaminants have decreased significantly since 2004- 2005, and some CACs, including sulphur dioxide, have seen reductions in absolute emissions despite high growth in oil sands production. Currently, air quality does not appear to be substantially worsening in the region, but evidence of deposition of potentially toxic contaminants such as PAHs highlight the need for continued monitoring in the region. The region is sensitive to acid deposition, and current observations suggest that while soil acidification is unlikely to be a widespread problem, continued monitoring of the region should be carried out, particularly in areas likely to be highly impacted by acid deposition. Water usage per barrel of SCO by mines has remained relatively unchanged since 2005, although higher production rates mean fresh water use has increased over time. Tailings reduction regulations have been implemented, although the full impact has yet to be established. In situ fresh water usage has remained steady over time despite large increases in produced bitumen, in part due to an increased reliance on saline groundwater and increased rates of recycling of produced water. Total land impact for the oil sands is most evident for mining projects, although linear disturbances from seismic lines for in situ projects mean that there is widespread, low- level land disturbance throughout the oil sands region. Preliminary biodiversity monitoring has noted some changes in the ecology of the oil sands region, although the impacts region-wide are due to both oil sands development and other human activities, such as agriculture and urbanization. Reclamation progress in the region, so far, is minimal, and will be an important area of concern in the future as oil sands areas begin to be decommissioned. Monitoring of air, water, and land has seen mixed levels of success thus far, with notable issues arising from water monitoring in particular. Some progress has been made in implementing a Joint Oil Sands Monitoring program at this time. The establishment of an arm’s length provincial monitoring agency aims to address further shortcomings, although the recent establishment of this agency means that its performance is yet to be seen. High quality monitoring will be necessary both to foster confidence in environmental performance and detect environmental change early enough to mediate adverse environmental effects.
July 2014 64 Canadian Energy Research Institute
July 2014 Oil Sands Environmental Impacts 65
List of Abbreviations
ABMI Alberta Biodiversity Monitoring Institute AER Alberta Energy Regulator AEMERA Alberta Environmental Monitoring Working Group AFD atmospheric fines drying bbl barrel CAC criteria air contaminant CCEMC Climate Change and Emissions Management Corporation CCEMF Climate Change and Emissions Management Fund CCS carbon capture and storage CEMA Cumulative Effects Management Association
CH4 methane CHOPS cold heavy oil production with sand CNOOC China National Offshore Oil Corporation CNRL Canadian Natural Resources Ltd. CO carbon monoxide
CO2 carbon dioxide
CO2e carbon dioxide equivalent COSIA Canada’s Oil Sands Innovation Alliance CSS cyclic steam stimulation CT composite tailings DBT dibenzothiophene Dilbit diluted bitumen EITEI emission intensive and trade exposed industry EPC emission performance credit ERCB Energy Resources Conservation Board GHG greenhouse gas GHOST GreenHouse gas emissions of current Oil Sands Technologies HCB hexachlorobenzene JOSM Joint Oil Sands Monitoring LCA life cycle analysis MFT mature fine tailings MJ megajoule
July 2014 66 Canadian Energy Research Institute
Mt megatonne
NH3 ammonia
NO/NO2/NOx nitric oxide/nitrogen dioxide/nitrogen oxides NPRI National Pollutant Release Inventory
O3 ozone OSA oil sands area OSOM Oil Sands Operation Model OTSG once-through steam generator PADD Petroleum Administration for Defense Districts PAH polycyclic aromatic hydrocarbon
PM/PM2.5/PM10 particulate matter/PM less than 2.5/10 microns in diameter ppm parts per million PRELIM Petroleum Refinery Life-cycle Inventory Model RAMP Regional Aquatic Monitoring Program SAGD steam assisted gravity drainage SCO synthetic crude oil SGER Specified Gas Emitters Regulation
SO2/SOx sulphur dioxide/sulphur oxides SOR steam-oil ratio Synbit synthetic crude oil-diluted bitumen TDS total dissolved solids THAI toe-to-heel air injection TPM total particulate matter TRO Tailings Reduction Operation TT thickened tailings UNFCCC United Nations Framework Convention on Climate Change VAPEX vapour extraction VOC volatile organic compound WBEA Wood Buffalo Environmental Association WTW well-to-wheels
July 2014