Canadian Energy Research Institute
Emission Abatement Potential for the Alberta Oil Sands Industry and Carbon Capture and Storage (CCS) Applicability to Coal-Fired Electricity Generation and Oil Sands Zoey Walden
Study No. 126
October 2011
Relevant • Independent • Objective
EMISSION ABATEMENT POTENTIAL FOR THE ALBERTA OIL SANDS INDUSTRY AND CARBON CAPTURE AND STORAGE (CCS) APPLICABILITY TO COAL-FIRED ELECTRICITY GENERATION AND OIL SANDS
Emission Abatement Potential for the Alberta Oil Sands Industry and Carbon Capture and Storage (CCS) Applicability to Coal-Fired Electricity Generation and Oil Sands
Copyright © Canadian Energy Research Institute, 2011 Sections of this study may be reproduced in magazines and newspapers with acknowledgement to the Canadian Energy Research Institute
ISBN 1-927037-03-4
Author:
Zoey Walden
Acknowledgements: The author of this report would like to extend thanks and gratitude to everyone involved in the production and editing of the material, including, but not limited to Carlos Murillo, Afshin Honarvar, Dinara Millington, Jon Rozhon, Thorn Walden, Peter Howard and most notably Megan Murphy.
CANADIAN ENERGY RESEARCH INSTITUTE 150, 3512 – 33 Street NW Calgary, Alberta T2L 2A6 Canada www.ceri.ca
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Table of Contents LIST OF FIGURES ..............................................................................................................................
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LIST OF TABLES ................................................................................................................................
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LIST OF ABBREVIATIONS.................................................................................................
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EXECUTIVE SUMMARY ....................................................................................................................
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CHAPTER 1 INTRODUCTION ....................................................................................................... Oil Sands ...................................................................................................................................... Electricity Generation .....................................................................................................................
1 1 2
CHAPTER 2
GREENHOUSE GASES, ABATEMENT TECHNOLOGIES AND OPPORTUNITIES IN THE OIL SANDS INDUSTRY ........................................................ Introduction.................................................................................................................................... Thermal Operations, Steam Requirements and Challenges ........................................................... Geology: The Carbonate versus Sandstone Story ......................................................................... Applicability of Oil Sands Technologies .......................................................................................... Methodology ..................................................................................................................................
5 5 9 17 21 24
CHAPTER 3 CARBON CAPTURE AND STORAGE ........................................................................... Introduction.................................................................................................................................... Capture Processes .......................................................................................................................... Advantages and Disadvantages of the Carbon Capture Process .................................................... Compression and Transportation ................................................................................................... Storage ...................................................................................................................................... Oil Sands CCS Potential .................................................................................................................. Electricity Generation in Alberta .................................................................................................... Coal-Fired Generation .................................................................................................................... Electricity Generation and Brief Overview of Coal in Saskatchewan ............................................. Gasification ..................................................................................................................................... In Situ Coal Gasification vs. Integrated Gasification Combined Cycle ............................................ Gasification of Coke and the Oil Sands ........................................................................................... Methodology .................................................................................................................................. Power Requirements for Carbon Capture as Calculated for Electricity Generation by Coal.......... Capital Costs Associated with CCS and Other Electricity Generating Technologies ....................... Concluding Remarks .......................................................................................................................
31 31 32 36 38 39 39 40 44 46 46 48 49 50 51 54 54
CHAPTER 4 EMISSION ABATEMENT POTENTIALS ....................................................................... Reference Case for Oil Sands.......................................................................................................... Electricity Generation .....................................................................................................................
55 55 59
CHAPTER 5
CONCLUDING REMARKS ..........................................................................................
61
APPENDIX A
TECHNICAL COMPONENTS OF EQUATIONS OF PROCESSES AND METHODOLOGIES .........................................................................
63
GLOSSARY ................................................................................................................. REFERENCES .................................................................................................................
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List of Figures Figure E.1 Figure 1.1 Figure 1.2 Figure 2.1 Figure 2.2 Figure 2.3
Reference Case Projection of Emissions from the Oil Sands............................................ Alberta Oil Sands Areas .................................................................................................... Capacity Breakdown of Electricity.................................................................................... Canada’s Overall Emissions .............................................................................................. Alberta, Electricity Generation and Oil Sands Emissions ................................................. Percentage Change of Emissions and Production Since 1990 Levels for Mining, Extracting and Upgrading of the Oil Sands ......................................................... Figure 2.4 Bitumen Viscosity versus Temperature ........................................................................... Figure 2.5 In Situ Recovery Methods ................................................................................................ Figure 2.6 Oil Sands Projects and Different Formations in the Athabasca Region ........................... Figure 2.7 The Athabasca-Wabiskaw Formation .............................................................................. Figure 2.8 Major Formations ............................................................................................................ Figure 2.9 Natural Gas Requirements for Varying Boiler Feed Water and Steam-to-Oil Requirements ............................................................................................. Figure 2.10 Natural Gas Requirements for Varying Pressure and Steam-to-Oil Requirements ......... Figure 3.1 Block Representations of the Different Processes ........................................................... Figure 3.2 Partial Pressure CO2 Concentrations from Various Industrial Sources ............................ Figure 3.3 Project Additions Between 1998-2015 as Provided by AESO .......................................... Figure 3.4 Summation of Proposed Project Additions Each Year Between 1998-2015 .................... Figure 3.5 AESO’s 2009-2029 Long-Term Energy Outlook Generation Mix for 2010 and 2020 ....... Figure 3.6 Forecasted Electricity Demand Between 2009-2029 ....................................................... Figure 3.7 IGCC Plant ........................................................................................................................ Figure 4.1 Realistic Scenario of CERI Production on a Total Raw Bitumen Produced Basis, 2008-2035 .............................................................................................. Figure 4.2 Reference Case Projection of Emissions from the Oil Sands, 2008-2035 ........................
xi 2 3 5 6 7 10 11 18 19 20 27 28 32 36 41 42 42 43 48 55 56
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List of Tables Table E.1 Table E.2 Table E.3 Table 2.1 Table 2.2 Table 2.3 Table 2.4 Table 2.5 Table 2.6 Table 2.7 Table 2.8 Table 3.1 Table 3.2 Table 3.3 Table 3.4 Table 3.5 Table 3.6 Table 3.7 Table 3.8 Table 3.9 Table 4.1 Table 4.2 Table 4.3 Table A.1 Table A.2
Emissions of the Oil Sands Sectors for the Years 2009, 2020 and 2035 Using CERI’s Realistic Scenario Projection Estimates ....................................................... Comparison of Emission Factors for Gasification of Coke and Asphaltenes .................... CCS Technology for Supercritical Power Plants and IGCC ................................................ 2008 Greenhouse Gas Emissions from the National Inventory Report 2010 by National Inventory Category ....................................................................................... Breakdown of Greenhouse Gas Emissions by Potential Oil Sands Sources ..................... Oil Sands Technology Roadmap ....................................................................................... Solvent Projects at the Commercial Stage ....................................................................... Applicability of Different Production Methods ................................................................ Emission Factors for Various Oil Sands Operations ......................................................... Emission Factors Calculated from CERI Methodology ..................................................... Emission Factors for Emerging Technologies ................................................................... CO2 Concentrations from Various Flue Gases from Oil Sands Operations ....................... Advantages and Disadvantages of Carbon Capture Processes ........................................ Summary of Factors Affecting Different CCS Technological Processes ............................ Advantages and Disadvantages of Physical and Chemical Solvent Systems and Membranes ................................................................................................. Retiring Electrical Generation Plants by 2027 in Alberta ................................................. Gasification Process, Environmental Controls and Products ........................................... Comparison of Emission Factors for Gasification of Coke and Asphaltenes .................... Comparison of Chemical Solvents on Power for Coal, Post-Combustion ........................ Efficiencies as Modified by the NETL 2011 Study to Reflect a 450 MW Gross Output Plant ............................................................................................ Emissions of the Oil Sands Sectors for the Years 2009, 2020 and 2035 Using CERI’s Realistic Scenario Projection Estimates ....................................................... Comparison of Emission Factors for Gasification of Coke and Asphaltenes .................... Possible Abatement Potentials for the Year 2035 if Energy Efficient Technologies and Some CCS are Utilized Between 2011-2035 .............................................................. Chemical Composition of Syncrude and Suncor Coke...................................................... Dry Mole Percentage Composition ..................................................................................
xii xiii xiii 6 8 9 14 22 29 29 30 35 37 37 38 41 47 50 52 53 57 58 59 66 66
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List of Abbreviations Air Separation Unit Alberta Bitumen Link Alberta Geological Society Alkaline-Surfactant-Polymer Barrels per day Boiler Feed Water Carbon Capture and Storage (Sequestration) Carbon Dioxide Equivalent Catalyst-Upgrading Process In Situ Centipoise Chemical Looping Combustion Chemical Looping Gasification Combustion Overhead Gravity Drainage Criteria Air Contaminant Cumulative Steam-to-Oil Ratio Cyclic Steam Simulation Dimethyl Ether Electromagnetic Radiation Electric Submersible Pump Electric Thermal Dynamic Striping Process Emission Factor Energy Resources Conservation Board Enhanced Oil Recovery Enhanced Solvent Extraction Incorporating Electromagnetic Heating Enthalpy Entropy Expanding Solvent Steam Assisted Gravity Drainage Global Warming Potential Greenhouse Gas Heat Recovery Steam Generator Horizontal Cyclic Steam Simulation In Situ Coal Gasification In Situ Combustion Instantaneous Steam-to-Oil Ratio Integrated Gasification Combined Cycle International Panel on Climate Change Ionic Liquid Kelvin Low Pressure Steam Assisted Gravity Drainage Megatonne Megawatt Electric Megawatt Thermal Mercury Metal Organic Framework Metric Tonne
ASU ABL AGS ASP BPD BFW CCS CO2eq CAPRI cP CLC CLG COGD CAC CSOR CSS DME EM ESP ET-DSP EF ERCB EOR ESEIEH H S ES-SAGD GWP GHG HRSG HCS ISCG ISC ISOR IGCC IPCC IL K LP-SAGD Mt MWe MWth Hg MOF t
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Microbial Enhanced Oil Recovery Mobile Oil Zone Monoethanolamine National Energy Technology Laboratory Natural Gas Combined Cycle National Inventory Report National Petroleum Council Nitrous Oxides Once Through Steam Generator Pascal Pressure Swing Absorption Sensible Heat Capacity Skin Electric Current Tracing Solvent Aided Process Steam Alternating Solvent Steam Assisted Gravity Drainage Steam Methane Reforming Steam-to-Oil Ratio Sulphur Oxides Sulphur Recovery Unit Synthetic Crude Oil Supercritical Pulverised Coal Thermal Assisted Gravity Drainage Toe-to-Heel Air Injection Tonne Underground Coal Gasification Vertical Steam Drainage Water Gas Shift Western Canadian Sedimentary Basin
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MEOR MOZ MEA NETL NGCC NIR NPC NOx OTSG Pa PSA c SECT SAP SAS SAGD SMR SOR SOx SRU SCO SCPC TAGD THAI t UCG VSD WGS WCSB
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Executive Summary In an increasingly greenhouse gas (GHG) conscious environment, Alberta has faced criticism for its heavy emissions within the oil sands industry and its utilization of coal-fired generation. The Alberta oil sands are the third largest oil deposit in the world and have experienced a rapid increase in production and consequently emissions. Furthermore, Alberta primarily utilizes coal for base load generation with coal traditionally making up approximately 50 percent of the electrical generation capacity and almost two-thirds of electricity output. The oil sands are economically viable at current oil prices, and Alberta has an abundance of coal reserves. This study projects emissions using CERI’s 2010 Supply Model Realistic Scenario1 and examines abatement opportunities within the oil sands and the role that Carbon Capture and Storage (CCS) can have in the advancement of “clean-coal” technologies. Figure E.1: Reference Case Projection of Emissions from the Oil Sands 160
140
120
ET-DSP COGD THAI
100
SAGD/ES-SAGD
CO2eq in MT
SAGD
LP-SAGD 80
HCS Vertical Steam Drive (VSD) / CSS CSS/SAGD
60
CSS, LASER & CSP CSS
Mining 40
Int Upgrader In Situ Int Upgrader Non-IntUpgrader
20
2035
2034
2033
2032
2031
2030
2029
2028
2027
2026
2025
2024
2023
2022
2021
2020
2019
2018
2017
2016
2015
2014
2013
2012
2011
2010
2009
2008
0
Year
Source: CERI
1
Realistic Scenario is from CERI Study No. 122, “Canadian Oil Sands Supply Costs and Development Projects (20102044) which can be downloaded from the CERI website.
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Figure E.1 shows the growth in emissions by technology over time within the oil sands industry that would occur without CCS. Following CERI’s realistic scenario, in the year 2035 the oil sands could be emitting as much as 127 Mt of CO2eq for that year, which is a 232 percent increase from 2009 (39.3 Mt CO2eq) emissions. Under the Copenhagen Accord of 2009, Canada’s total emissions for the year 2020 need to be 607 Mt CO2eq or lower. According to the projection, the total emissions from the oil sands would equal 88 Mt CO2eq in 2020, which amounts to 14 percent of the total targeted emissions of Canada for that year. Table E.1 summarizes the emissions in each sector for the years 2009, 2020 and 2035. Table E.1: Emissions of the Oil Sands Sectors for the Years 2009, 2020 and 2035 Using CERI’s Realistic Scenario Projection Estimates Sector Stand-Alone Upgrading Integrated Mining and Upgrading Integrated Upgrading In Situ Stand-alone Mining Stand-alone In Situ Projects Total
2009 10 11
Emissions CO2eq (Mt) 2020 2035 11 15 27 30
4
15
22
2 12
14 22
14 47
39
89
128
Source: CERI In situ is the most rapidly growing area for emissions as it is experiencing a growth spurt in production from the advent of steam extraction and is, unsurprisingly, a significant contributor to emissions growth. Moreover, in situ extraction is more energy-intensive than mining, generating higher emissions per barrel and therefore causative to the acceleration of emissions from the 2009 levels. If production is to continue at this pace, technologies capable of making deep and long-term reductions in emissions are needed; they must be implemented prior to 2020 to avoid accelerating emissions growth. From the CERI 2010 production estimate, projects that are part of the classic in situ technologies make up approximately 44 Mt of the 47 Mt CO2eq from stand-alone in situ projects in the year 2035. This creates, at most, approximately 20 Mt CO2eq of abatement potential from converting to less energy intensive technologies (e.g., solvents). CCS is both expensive and energy-intensive. Consequently, in light of low natural gas prices, it is problematic to finance CCS without significant financial incentives to build and invest in the equipment. Also, the public needs to be on board with CCS, and safety is a key priority towards gaining trust. Currently, for upgraders not utilizing gasification, the easiest CO2 capture process is at the hydrogen production plants, which could reduce their emissions by approximately 0.03 t CO2eq/bbl. Gasification of oil sands by-products and coal may also be a source of hydrogen but without CCS it is more GHG intensive than the current steam reforming of natural gas. Table October 2011
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E.2 summarizes emissions from the utilization of different fuel sources for gasification, with and without CCS, as well as the current emissions from upgraders. Table E.2: Comparison of Emission Factors for Gasification of Coke and Asphaltenes Project Type
Stand alone Upgrader Integrated Upgrader Integrated Upgrader In Situ
0.06
Coke gasification no CCS (t CO2eq/bbl) 0.1
EF (Emission Factor) Asphaltene H2 Plant w/ gasification CCS no CCS (t (tCO2eq/bbl) CO2eq/bbl) 0.09 0.03
Coke gasification w/CCS (t CO2eq/bbl) 0.01
Asphaltene gasification w/ CCS (t CO2eq/bbl) 0.009
0.09
0.16
0.14
0.06
0.016
0.014
--
0.22
0.2
--
0.022
0.02
Natural gas (t CO2eq/bbl)
Source: CERI In situ is currently considered uneconomic for the application of CCS. CERI’s estimate is that without extensive utilization of CCS in the in situ portion of the oil sands, the total abatement potential for emissions by the year 2035 is approximately 60 Mt. Power loss is significant for power plants utilizing CCS. Table E.3 summarizes the power loss from implementing CCS on a supercritical power plant and for IGCC. Table E.3: CCS Technology for Supercritical Power Plants and IGCC
Power no CCS (MWe) CO2 emitted no CCS (Mt/yr) CO2 captured (Mt/yr) Efficiency Plant after Capture Efficiency Plant after Compression Power output CCS (MWe)
Base SCPC 450 3.1 -0.385 --
MEA SCPC 450 3.1 2.8 0.24 0.21
KS-1 SCPC 450 3.1 2.8 0.27 0.24
Chilled Ammonia SCPC2 450 3.1 2.8 0.29 0.27
IGCC3
450
255
287
311
304
450 2.1 1.9 0.32 --
Source: CERI and various other sources
2
The chilled ammonia process is highly uncertain and the numbers for this should be treated with some reservation. 3 Compression requirements are not included for the IGCC calculation.
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The financial and energy barriers to CCS result in coal facing a largely uncertain future as more stringent GHG controls are put into effect. Natural gas is a reliable alternative to coal but will eventually face GHG restrictions itself. Investment in CCS could be beneficial and could promote a renaissance of clean coal technologies; it could revive the utilization of Alberta and Saskatchewan’s abundant coal reserves. Moving from subcritical to supercritical or ultrasupercritical coal plants results in decreased emissions (~10-20 percent for Supercritical, ~30 percent for Ultra-supercritical) but these emissions are still higher than the newest generation of combined cycle technologies using natural gas (more than 50 percent lower). Also, it is easier to implement CCS on new coal plants designed for such a process, which could result in greater emission reductions (more than 85 percent from baseline coal plant emissions without CCS). While there has been a push towards renewables, large-scale implementation of wind or solar is subject to the variability of weather conditions and would require increases in electricity prices to support the elevated regulated reserve required to ramp up and down as conditions change. All-in-all, CCS remains in the forefront of the technologies capable of achieving longterm significant reductions in GHG emissions, within both the power and oil sands industries, because of its large applicability to virtually everything.
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Chapter 1 Introduction This report seeks to acquaint the general reader with the major sources of greenhouse gas (GHG) emissions from the oil sands and electricity industries in Alberta. It provides an overview of promising technologies to decrease emissions and assesses their advantages and disadvantages. Kyoto, Copenhagen and the Intergovernmental Panel on Climate Change are all widely known reports/accords on the sources of GHG emissions and the actions needed to mitigate them as climate change is a possible global threat. Consequently, this has resulted in increasing scrutiny by numerous parties over the key sources and potential abatement of GHG. Alberta in particular has faced criticism for its heavy emissions, particularly within the oil sands and within its abundance of coal powered generation.
Oil Sands Currently, the production of bitumen4 is economic at existing oil prices despite the reduced profit margin and high risks (i.e., labour shortages, long pay back periods, etc. As well, conventional resources have been on the decline5 (ERCB 2011). This has motivated companies to invest heavily within the oil sands, with the Canadian Energy Research Institute’s (CERI) Realistic forecast predicting over 4 million barrels per day (BPD) being produced after 2030 – up from approximately 1.5 BPD in 2010 (ERCB 2011). Natural gas is the fuel of choice to run oil sands operations and is utilized as a source of hydrogen, steam/hot water requirements and, occasionally electricity. Coke, coal and asphaltenes could be utilized as alternative fuels but would result in increased CO2 from their combustion. Figure 1.1 depicts the 3 oil sands areas.
4
For a more comprehensive review of the oil sands and current reserves and production, one can refer to the CAPP website, the ERCB and Alberta Energy. Electricity statistics can also be found under AESO or Alberta Energy. 5 There has been an increase in conventional oil reserves recently due to increased enhanced oil recovery (EOR) and application of horizontal drilling techniques with multi-well fracturing.
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Figure 1.1: Alberta Oil Sands Areas
The Government of Canada and Alberta have sponsored numerous research and development activities for many decades, which have promoted the advancement of technologies within the oil sands. These advances in technology have the potential to mitigate the immediate concern of carbon emissions and, less directly, other environmental problems (i.e., land reclamation, tailings ponds, water usage, etc.). Lastly, there are long-term benefits of improved recovery factors, and decreased manpower requirements, depending on the success and proliferation of promising technologies.
Electricity Generation Alberta primarily utilizes coal for base load generation with coal traditionally making up approximately 50 percent of the electrical generation capacity and almost two-thirds of electricity output. As coal plants retire, there has been a shift towards natural gas and renewables. Moreover, more industrial sites are opting for onsite cogeneration. However, since Alberta has an abundance of coal reserves, it is advantageous to see how coal compares to its alternatives and to examine the role that CCS can have in the advancement of “clean-coal” technologies. Figure 1.2 shows the mix of generating capacities for the year 2010.
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Figure 1.2: Capacity Breakdown of Electricity
Wind Hydro 6% 7%
Other 2%
Coal 46% Natural Gas 39%
Source: (Hu 2011).
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Chapter 2 Greenhouse Gases, Abatement Technologies and Opportunities in the Oil Sands Industry Introduction Until recently, Canada’s emissions have been on the rise, and Alberta’s emissions have continued to rise. Canada is committed to reducing emissions below 607 Mt CO2eq a year by its ratification of the Copenhagen Accord. Tables 2.1 and Figures 2.1-2.3 give a historical impression of the quantity of GHG emissions in the past. Canada’s GHG emissions have been decreasing from 2007 to 2009 as a result of the economic recession. Alberta’s emissions have been on the rise, partially driven by the rapidly expanding oil sands industry, and as Figure 2.3 depicts, emissions have been relatively proportional to the growth in the industry. Figure 2.2 compares the oil sands emissions to Alberta’s total emissions. Figure 2.1: Canada’s Overall Emissions 800
700 600
MT CO2eq
500 400 300
200 100 0 1990
1995
2000
2005
2006
2007
2008
2009
Year
Source: (Environment Canada 2010)
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Figure 2.2: Alberta, Electricity Generation and Oil Sands Emissions 300
250
200 Alberta Total Emissions 150
Electricity Generation Emissions Oil Sands Emissions
100
50
0 1990
2005
2006
2007
Source: (Environment Canada 2010) Table 2.1: 2008 Greenhouse Gas Emissions from the National Inventory Report 2010 by National Inventory Category in Mt of CO2eq National Inventory Category
Oil Sands (Mining, In Situ, Upgrading) Total
Oil Sands Total 37.2 Energy Fuel 29.2 Combustion Stationary Energy Fuel 0.6 Combustion Transportation Energy Fugitive 2.0 Unintentional Energy Fugitive Flaring 1.4 Energy Fugitive 4.0 Venting Source: (Environment Canada 2010)
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Oil Sands Mining, Extraction and Upgrading 24.9 18.2
Oil Sands In Situ Bitumen
0.6
--
2.0
0.0
1.0 3.2
0.5 0.8
12.2 11.0
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Figure 2.3: Percentage Change of Emissions and Production Since 1990 Levels for Mining, Extracting and Upgrading of the Oil Sands 350% 300% 250% 200%
% Growth Production since 1990
150%
% Growth Emissions since 1990
100% 50% 0% 2000 2004 2005 2006 2007 2008 2009 Source: (Environment Canada 2010) Alberta has vast reserves of crude oil in the form of bitumen, making the oil sands the third largest oil deposit in the world. However, in contrast to deposits within most OPEC countries, bitumen is highly viscous and does not flow freely within the reservoir without additional energy input. Consequently, specialized and highly energy-intensive techniques are employed to recover the bitumen and transform it into synthetic crude oil (SCO). Extraction in this manner consumes large amounts of fossil fuels, primarily natural gas, and as such oil sands production emits immense quantities of greenhouse gases. While there may be a high degree of variation on the source and composition of GHG (i.e., facility based, reservoir based, etc.), in general, emissions can be traced to 5 primary arenas: combustion of fossil fuels to drive the processes, venting and flaring, fugitive emissions, storage losses and accidental releases due to spills. The processes outlined above are direct emissions. Indirect emissions are typically associated with electricity or other energy consuming usages not directly applicable to the operation.6 Table 2.2 is a breakdown of direct emissions by source.
6
This is true for facilities that have no cogeneration capabilities on site. In the case of cogeneration, some of the natural gas combusted goes both towards steam and electrical generation with the surplus (deficit) sold (bought) from the electrical system.
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Table 2.2: Breakdown of Greenhouse Gas Emissions by Potential Oil Sands Sources Primary Emission Source Fossil Fuel Combustion
Activity Description
Natural gas withdrawn/purchased for steam/electricity/other energy requirements Diesel combustion (mining operations) Process gas or off spec product combustion Natural gas compressor or processing stations Natural gas for hydrogen formation Venting/Flaring Venting of gas operated devices Reboiler/processing vents Depressurisation activities (equipment, inspection, etc.) Venting/flaring to relieve pressure Glycol dehydrator offgas Fugitive Emissions Loss of hydrocarbon gases and liquids to the atmosphere due to inefficiencies/leaking from equipment (i.e., valves) Loading/unloading losses Storage losses Evaporative losses from storage Accidental Releases Releases due to spills and equipment failures Source: (Nyboer and Tu 2008) Greenhouse gas emissions may be affected by a variety of drivers which influence the intensity of emissions for the sector. In general, companies strive to reduce emissions by improving the energy efficiency of the operation and by the implementation of lower carbon intensity inputs. For the oil sands industry, a variety of techniques are being investigated to improve extraction efficiency or lower the carbon intensity of the input. An opposing tendency, however, is the replacement of natural gas by oil sands coke or asphaltenes. Table 2.3 summarizes some of the potential emission mitigation measures.
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Table 2.3: Oil Sands Technology Roadmap Mitigation Measure Extraction Efficiency Improvements
Technology Sector In Situ Extraction Technologies
Mining Extraction Technologies Lower Carbon Intensity of Energy Inputs
CCS
Alternative Fuels
Technologies Available Steam processes efficiency (i.e., well placement configuration, efficient heat transfers by insulating wells, etc.) Solvents (ranges from pure solvent to hybrid steam/solvent/air combinations) in situ combustion (i.e., THAI/CAPRI) Chemicals (polymers, alkalines, colloidal gels, ionic solvents, supercritical fluids, surfactants, additives) Biological Non-condensing gases (N2, CO2, CH4, etc.) Electric heating (current, ultrasonics, microwaves) Operation changes (shift to lower emitting vehicles) Chemical changes Combustion/gasification of fossil fuels (asphaltenes, coke) Capture/storage of CO2 and CO2 for enhanced oil recovery (EOR) Nuclear Biomass Syngas Geothermal
Source: Various sources and CERI Indirectly, drivers of emissions may be attributed to the following:
Supply/demand and price of oil and other hydrocarbon products Ability to transport commodities and mode of transportation Political dynamics encompassing local/provincial/national/international levels Exploration/technological advancement beyond the above mentioned category Clear Air Acts/EcoEnergy initiatives and other policies governing emission standards Public perception of the industry and acceptance of alternative emission reduction strategies (especially nuclear)
Thermal Operations, Steam Requirements and Challenges Bitumen viscosity is high at reservoir temperatures resulting in solid-like rather than fluid-like behaviour. Furthermore, depending on the heterogeneity of the reservoir, lateral movement of steam may be difficult, resulting in losses to the surrounding areas (Flach 1984). Consequently, thermal projects vary considerably in terms of their requirements for steam. This component is
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largely dependent on how easy it is to get the oil out of the reservoir and how much oil is being produced at a given moment in time. In general, steam is injected to form a steam chamber at approximately the steam saturation temperature for a given pressure (generally over 200°C). The steam flows towards the perimeter, and condenses in the periphery and heat is transferred via thermal conduction to the surrounding reservoir (Al-Bahlani and Babadagli 2009). As the oil heats up from the conduction process, it becomes less viscous. Strategies that improve this heat transfer ultimately decrease the amount of steam required and, consequently, also reduce fuel requirements thus lowering emissions. Figure 2.4 depicts the trend of viscosity versus temperature (higher values for centipoises (cP) denote greater viscosities). Figure 2.4: Bitumen Viscosity versus Temperature
Athabasca Bitumen, Canada (8.6oAPI) 10000000
Oil Viscosity (cp)
1000000 100000 10000 1000 100 10 1 0
50
100
150
200
250
300
Temperature (oC) Source: http://www.heavyoilinfo.com/blog-posts/bitumen_viscosity.ppt/view, June 23, 2011 The desired steam characteristics are determined by the characteristics of the reservoir (i.e., depth, porosity, viscosity, saturation, etc.). Moreover, steam pressure is limited by the fracture pressure of the formation (Bersak and Kadak 2007). Consequently, depending on the reservoir and the fracture pressures allowed, a variety of steam pressures and temperatures may be injected for oil sands projects with similar extraction methods (i.e., SAGD). According to CAPP’s greenhouse gas study (CAPP 2004), for a thermal heavy crude oil battery, 99.3 percent of fuel burned goes into steam boilers with the remaining 0.7 percent attributed to reciprocating engines. Consequently, emissions for a thermal oil sands project that do not
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have onsite cogeneration can be reasonably approximated using the estimated natural gas requirements to generate steam at a given pressure and temperature from the combustion emission factors for marketable and non-marketable natural gas in the province of Alberta.
Oil Sands Technologies Figure 2.5: In Situ Recovery Methods
Electric Heating SAGD Thermal
Steam CSS
In Situ Recovery
Solvent
Combustion
Other EOR Methods Source: (CERI) There are a variety of paths one can take for in situ recovery of oil, and Figure 2.5 is a simplified flow diagram of the options available. Following are in-depth descriptions of each of the above processes with additional technologies discussed that are not portrayed in Figure 2.5. Steam Processes Efficiency One way to reduce natural gas usage and improve recoveries is to improve the transfer of heat from steam to bitumen and to find the most effective way of drilling to allow that transfer of heat. In general, physical improvements are made with steam boiler efficiencies but, more recently, proposals have been made for a new way of drilling. These two ways are known respectively as Cross and Fast SAGD. For Cross SAGD, the wells are drilled in a manner that creates a mesh of injection and production wells. Cross SAGD was used to overcome low pressure (LP) SAGD problems. It has the advantage of achieving better thermal efficiencies but is only effective at establishing a steam chamber at the points where the wells cross instead of along the length of the well, as there are operational challenges and capital costs to plugging and drilling the wells (Al-Bahlani and Babadagli 2009). Fast SAGD utilizes an additional horizontal well to improve the steam chamber growth rate and to create a pressure sink to counteract the steam’s tendency to rise; it results in higher oil recoveries (Al-Bahlani and October 2011
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Babadagli 2009). Another example of well placement is Cenovus’ application of “wedge wells” which extracts bitumen in the space between two horizontal well spaces (Jaremko 2009). Lastly, another way to impede heat loss into the surrounding reservoir is through the use of an insulating tube. ConocoPhillips is experimenting with a vacuum insulated tube for its Surmont project (ConocoPhillips). Lower steam pressures are both advantageous and disadvantageous. The advantages are lower steam pressure and temperatures reduce reservoir heat content, reduce heat loss to the surroundings and increase the latent heat of the steam (higher enthalpy) towards the reservoir, creating better heat transfer between the steam and bitumen. The disadvantages are that reduced pressure means lower temperatures, resulting in less steam chamber growth which ultimately reduces the overall production of the well and possibly requires more wells to be drilled. Despite the lowered production, each well pair consumes less steam thus decreasing the steam-to-oil ratio (SOR) of the project, which makes production more economical for a longer period of time and ultimately increases recovery (Cenovus 2010). Low pressure operations typically use Electric Submersible Pumps (ESP) which generate a reservoir pressure of 1-3 MPa – in contrast to gas push mechanisms which typically require reservoir pressures of 4.5-6 MPa. Solvents A large amount of research has been devoted to the addition of solvents to steam or injection of pure solvents into an oil sands reservoir. Typically bitumen is recovered by reducing viscosity via heating (i.e., steam). In a solvent-assisted process the bitumen viscosity is reduced by dissolving and mixing solvent into the bitumen. Success of the project is measured by the ability to recover the costly solvent, lower the SOR, and increase the miscibility of the solvent into the oil (Flach 1984). In order for the solvent to mix, it must stay vaporized in the central portion while condensing along the periphery. This is accomplished due to the wellhead having a temperature similar to the saturation steam temperature and the periphery having temperatures similar to the native reservoir temperature. Consequently, an ideal solvent must exhibit the following (Pattinson 2009): 1. Be readily miscible with bitumen 2. Be a vapour at the wellhead 3. Condense in the periphery of the steam chamber Potential benefits of solvent co-injection are summarized as follows (Orr 2009): 1. 2. 3. 4. 5. 6.
Potentially decreased SOR Increased recoveries of bitumen Reduced bitumen viscosity Use in reservoirs not typically suited for SAGD, such as those with lean zones Vaporization of lighter components of solvents to create a solution-gas drive mechanism Solvents travel more quickly to the chamber extremities as well as extend out more laterally then typical SAGD operations
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7. Industrial waste streams used as solvents (i.e., carbon disulphide, organonitrogen thiocarbonates, hydrogen sulphide) Since a wide variety of solvents can be used and could potentially have benefits including, but not limited to, reduced greenhouse gas emissions, numerous companies are exploring the possibilities of enhancing and improving the extraction of bitumen from oil sands reservoirs through solvent usage. However, there seems to be conflicting results on the applicability and success of solvent projects (Orr 2009). Nenniger (N-Solv) argues that part of the lack of success of previous expanding solvent projects (i.e., Suncor’s Firebag, EnCana’s Christina Lake) was due to a lack of proper accounting of materials balance. This results in accumulation of vapour in the steam trap which hinders heat transfers. Nenniger argues that the bubble and dew points of solvent/steam mixes must be well established with a proper materials balance (Nenniger and Gunnewie). In contrast to the disappointing results at Firebag and Christina Lake, Imperial Oil reported success with their LASER pilot with a 30 percent increase in production rates and a 32 percent decrease in their SOR value (Orr 2009). In many cases, there is deviation from simulations to actual field results, resulting in a variety of interpretations over success and applicability. These differences can be generally attributed to differences in heat and mass transfer assumptions in simulations and artificial compensations of some of the coefficients such as the coefficient of diffusion (Orr 2009). The point of emphasis is that depending on the characteristics of the reservoir, and the numerous solvent possibilities, solvents may aid or hinder a great deal depending on the retention of solvent within the reservoir and the degree to which it emulates the aforementioned ideal solvent properties. This has created several ways of doing solvent injections including expanding solvent SAGD (ES-SAGD), steam alternating solvent (SAS), liquid addition to steam enhanced recovery (LASER), solvent aided process (SAP) and other hybrid SAGD processes. Some of the projects and solvents utilized are shown in Table 2.4.
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Table 2.4: Solvent Projects at the Commercial Stage Company Completed Pilots7 Suncor Suncor EnCana EnCana Imperial Oil Nexen Proposed Pilots Cenovus Laricina Researching ConocoPhillips
Project
Solvents
Year
Firebag Firebag Senlac Christina Lake LASER Long Lake
Propane Naphtha Butane Propane, Butane Diluent Jet B
2004 2006 2002 2005
Narrows Lake Saleski
Butane, xylene Propane, Diluent
2017 2011
Alberta Oil Sands Inc. Devon
Pilot Fort Mac. Jackfish 3
2006
Naphtha, Diluent, Other light HC’s Gas-condensate
Source: (CERI, various ERCB and company applications) While the widely used solvents have been propane, butane, pentane, diluents and naphtha, a novel concept that has arisen is the use of dimethyl ether (DME) as a solvent. DME has found its use through an initiative known as the Alberta Bitumen Link (ABL). DME may be synthesized from a coal gasification process. Benefits of utilizing DME are the elimination of tailings, and condensate use, and possibly the elimination of the use of natural gas. Since there have been disappointing results from injecting cold solvents into reservoirs, it is proposed that reservoirs be heated with a downhole electrical system called skin electric current tracing (SECT). Although still in its testing phase, application of such a system could revolutionize the way in situ oil sands operations are conducted (Stastny 2011). In Situ Combustion In situ combustion has a long history in conventional reservoirs, with the first pilot in 1920 by the US and since then it has resulted in over 100 other commercial pilots worldwide and at least 19 commercial operations (Turta and others 2007). In situ combustion requires that air be injected into the well and that part of the oil be burned. Mechanisms driving the oil towards the producer well are reduced viscosity from partial upgrading, and enhanced push by CO2, steam and distilled oil fractions. Coke may serve as a fuel source as the combustion front advances. The combustion can also be done in reverse by starting at the producer well. Water may also be injected with the air and become vaporized, carrying latent heat to the rest of the formation. Oil sands pilots of in situ combustion have been met with limited success due to the differing characteristics of oil sands versus conventional heavy oil reservoirs. In heavy oil reservoirs the 7
While some of these operations are still operating, “completed” denotes that the pilot has been done with either further application or dismissal of the technique.
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fluids are able to stay ahead of the combustion front allowing for burning of a larger area. Oil sands however, do not allow the movement of hot fluids through the impermeable cold reservoir which results in a lack of communication between the injector and the producer. This problem can be solved if the burn can happen through a fracture between the producer and injector allowing for the movement of fluids and the burn front (Flach 1984). At their Whitesands pilot in 2006, Petrobank recently patented a process known as Toe-to-Heel-AirInjection or THAI™ and Catalyst-Upgrading Process In Situ or CAPRI™. The combustion process has the added benefit of upgrading the oil via thermal cracking within the reservoir (Shah and others 2010). For an in-depth description of the THAI™ process, please refer to CERI Study 122. Chemicals This class includes substances that aid in the extraction process of oil from the underground reservoir and include polymers, surfactants, alkalines, colloidal gels, ionic solvents, and supercritical fluids. Polymers In 2005, CNRL began polymer injection at its Pelican Lake site with the co-injection of water and polyacrylamide or polyacrylamide with brine (CNRL 2011a). This pilot was a success and showed that polymer/water combinations were more effective than waterfloods alone. The reason for this was that polymer/water combinations were more viscous and thus resulted in less fingering and break-through in the reservoir. CNRL believes that this method will result in a 20 percent recovery factor at a relatively low cost (CNRL 2011a). Polymer flooding is considered a mature technology in sandstone reservoirs, with several projects worldwide, and also has seen some success in carbonate formations (Alvarado and Manrique 2010). Polymer is advantageous in shallower reservoirs or reservoirs where permeability is lower than that required for thermal production (Shah and others 2010). Surfactant Flooding Surfactant flooding uses compounds such as petroleum sulfonates with alcohol and salt to lower the interfacial tension between oil and water. It has not taken off due to excessive surfactant loss and treatment of emulsions being problematic (Shah and others 2010). CNRL will be testing a surfactant pilot in 2011. Alkaline Flooding Alkaline flooding involves the injection of an alkaline solution such as sodium hydroxide, sodium carbonate or sodium orthosilicate. The alkaline solution reacts with the acidic components of crude oil and generates a surfactant in situ that can help to mobilize the crude oil. This technique is not applicable in carbonate formations due to the abundance of calcium, which react chemically and may cause precipitation into the solution (Shah and others 2010). Alkaline-Surfactant-Polymer (ASP) Flooding ASP reduces interfacial tension and improves the recovery factor to approximately 25-30 percent. It takes advantage of the above-mentioned chemical methods by trying to find an
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optimum in recovery while lowering injection costs (Shah and others 2010). CNRL has been using ASP flooding at its Grand Forks reservoir, claiming that the surfactants reduce the amount of oil left behind in the reservoir and the polymers improve the flood’s sweep. All of this has resulted in improved oil recovery (CNRL 2011b). Colloidal Gels, Ionic Solvents, and Supercritical Fluids Colloidal Dispersion Gels are an alternative polymer technology designed to improve the sweep efficiency in reservoirs with high permeability variation and an abundance of thief zones. Ionic solvents is a method still in the research phase in which ionic liquids (IL) are used to separate the bitumen from the sand. An organic solvent that is miscible with bitumen but not the IL can be used, and it produces a separation of bitumen, sand and solvent (Painter, Williams, Mannebach 2010). Supercritical fluids are injected as a dissolving agent for improved extraction. Electromagnetic Heating/Ultrasonics/Microwaves While steam has been a widely used method of heating the reservoir and thereby reducing bitumen viscosity, its applicability is limited by the availability of the steam to penetrate the reservoir and enhance production sufficiently to warrant its injection into the reservoir. Thin pay zones, low injectivity and heterogeneity can hinder the performance of steam injection. Alternatives include heating the reservoir through the use of electromagnetic heating, or heating through the frequency of electromagnetic radiation (i.e., infrared for microwaves). This application is geared towards the following situations (Sahni, Kumar, Knapp 2000): a) A deep formation where the heating losses between the surface and the wellbore could be significant, resulting in low quality steam. b) Thin pay zones, where heat losses to the surrounding non-oil bearing rock are significant. c) Low permeability, which inhibits the flow of fluid into the reservoir. d) Heterogeneity, where fractures or caverns can trap the steam thereby reducing sweep efficiency. e) Other situations where injecting the steam may cause environmental concern or is uneconomical for reasons not mentioned above. Electromagnetic heating can be done in a variety of ways depending on the frequency of the electromagnetic radiation. High frequency usually results in dielectric heating, where molecules align with the electric field and alteration of the field induces rotational movement. The result is significant heating similar to that of microwaves. Low frequency uses alternating current where resistive heating is dominant (ohmic I2R). Lastly, alternating current may cause inductive heating where secondary currents induced by a magnetic field cause circulation for heat generation (Sahni, Kumar, Knapp 2000). Currently, AOSC is experimenting with electric heating assisted recovery with their thermal assisted gravity drainage (TAGD) process.
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Biological Microbial enhanced oil recovery (MEOR) represents the use of microorganisms to enhance the recovery of oil. Microbial products include the following (Lazar, Petrisor, Yen 2007): a) b) c) d) e) f) g)
Gases (H2, N2, CH4, CO2) for non-condensing gas extraction Acids (primarily low molecular weight fatty acids) Solvents (alcohols and ketones) Biosurfactants Biopolymers Biomass (selective plugging) Alkanes and alkenes produced by anaerobic degradation (Mbadinga and others 2011)
The last point of anaerobic degradation has become of greater interest recently because of its potential to upgrade oil within the reservoir as well as to bioremediate oil-contaminated environments. The points above primarily use products of the microorganisms’ metabolic process to create compounds that will either decrease the viscosity of the oil or physically push out the oil by selective plugging. Advantages of the MEOR process are all of the components are inexpensive, easy to obtain and handle, and can be attractive for fields prior to shutdown as it can be used as a tertiary enhanced oil recovery mechanism (Lazar, Petrisor, Yen 2007). Catalysts Catalysts are considered with ISC as a way of upgrading the oil downhole. Catalysts can aid in breaking of the oil bonds with less heat being applied to the system. Catalysts can be problematic because they tend to be de-activated in the presence of heavy metals, of which there is abundance in the oil sands (Shah and others 2010). Alternative Fuels Coal, coke and asphaltenes could be used to replace burning of natural gas but direct combustion increases CO2 emissions. Since carbon taxation is most likely to increase in the future, so will the associated compliance costs. Gasification could provide hydrogen and energy and is discussed in more detail in the CCS section in Chapter 3. Nuclear power could provide energy and hydrogen as well, but in light of Fukushima public resistance is highly likely and therefore will not be considered in this report.
Geology: The Carbonate versus Sandstone Story Most heavy oil deposits in the world and within Alberta are within quartzite sandstone formations. The quality of oil sands reserves is generally measured by the degree of saturation of bitumen (typically 30 percent or higher), the thickness of the reservoir, the presence of shale/clay content (decreases bitumen saturation), the porosity of the rock, and the volume of water within the reservoir (ERCB 2011). A majority of projects sit within the Athabasca/Wabiskaw and Grand Rapids/Clear Water deposits that are primarily sandstone structures. Figures 2.6 and 2.7 show the locations of projects in relation to bitumen thickness. As one can see, a majority of the areas that are most economical to oil sands development have
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been leased for one project or another. Typically projects have a permeability of approximately 1-10 darcies, 70-85 percent oil saturation, porosities of 30 percent, a net pay zone thickness of greater than 10m and reservoir temperatures around 12-20°C.8 Figure 2.6: Oil Sands Projects and Different Formations in the Athabasca Region
Source: (Alberta Energy and ERCB)
8
These statistics come from a variety of ERCB applications showing the geology of the projects.
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Figure 2.7: The Athabasca-Wabiskaw Formation
Source: ERCB ST-98 2010 An area of remarkable lack of development is the Grosmont carbonates. Carbonate formations also hold extensive oil reserves but generally are not produced due to the complexity of carbonates. The Grosmont formation contains approximately 64.5 x 10 9 m^3 (405 billion bbls) of bitumen with an API gravity typically around 5-9° (Buschkuehle, Hein, Grobe 2007)(ERCB 2011). The formation is an extensive upper Devonian formation spanning an approximately 500 x 150 km wide platform in the northern region of Alberta. While the reservoir is extremely
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variable, a variety of pilots have been performed between 1975 and 1987. Initial pilots were conducted in the upper eastern portion of the Grosmont formation for in situ thermal recovery and included techniques such as injecting hot water, steam, firefloods, and lastly, solvent extraction. These pilots had mixed results and were largely disbanded as a result of unfavourable economic conditions (Buschkuehle, Hein, Grobe 2007; Roche 2006). Furthermore, there are other oil bearing carbonates within the region such as the Ireton and Winterburn formations within the Nisku (10.3 x 10^9 m^3), carbonates under the Peace River formation (Shunda and Missipian Debolt 10.3 x 10^9 m^3) and the Pekisko and Elk Point formations (ERCB 2011). Altogether, the carbonates hold a vast amount of potential oil reserves. Figure 2.8 gives a cross-sectional view of the major formations. Figure 2.8: Major Formations
Source: Adapted from Buschkuehle et al. and from the Alberta Geologic Society (AGS) (Buschkuehle, Hein, Grobe 2007) Recently, there has been a resurgence of interest in the carbonates with Husky, Shell, Laricina, OSUM and ASOC all acquiring leases and beginning pilots. Shell paid $464.7 million for 88,576 hectares in 2005, showing that the carbonates may become the next frontier in development of the oil sands region (Roche 2006). Previously, there had been a degree of negativity towards the development of the carbonates due to the highly heterogeneous nature of the formation.
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However, the high degree of saturation (70-100 percent bitumen) and the highly karsted9 nature of parts of the formation make the carbonates amenable to thermal recovery methods. The lower formations (A,B) as well as the western end tend not to be as porous or bitumen saturated as the upper formations and, consequently, a majority of the drilling will take place in the eastern end of the formation. Average porosity of the formation is also decreased, typically at around 20 percent. For thermal operations, the main challenge is the variability of the formation in that processes that work in one area may not work a short distance away. However, karsted formations have fissures, tunnels and caverns which crumble to a point where the formation can behave like sandstone. The denser limestones have very low permeability which makes extraction very difficult and may need techniques similar to the extraction of oil shale. Thermal recovery may result in heat lost to the formation but the bitumen pay zones in the eastern area exceed 30m thick and can still result in economical and successful production (Edmunds and others 2009; Roche 2006). Lastly, the Grosmont formation is in a remote area and infrastructure would need to be built to access a large part of it. As the oil sands become developed, the gains in decreased energy intensity may be offset by the fact that more difficult resources will become developed. This is counteracted by the development of technologies that are capable of dealing with the progression from one type of reservoir to the other. When referring to technologies, it is important to keep in mind the formations and types of crude oil since technologies applied as one process in one pool may not be successful in another.
Applicability of Oil Sands Technologies Applicability has been determined from looking at references and following a paper by the National Petroleum Council (NPC) on applicability and status (Clark and others 2007). Table 2.5 summarizes the applicability of techniques within different reservoirs and if the technique is close to the commercial stage or if the technique is still primarily within the research stage.
9
Karst is limestone where erosion has degraded sections by dissolution producing a crumbly mix of fissures, tunnels and caverns.
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Table 2.5: Applicability of Different Production Methods Production method of resource: Status Shallowest (1000m)
No
Carbonates Thin beds (
