Emission Abatement Potential for the Alberta Oil …Emission Abatement Potential for the Alberta Oil Sands Industry and Carbon Capture vii and Storage (CCS) Applicability to Coal-Fired

Relevant • Independent • Objective

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

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 October 2011 Printed in Canada

http://www.ceri.ca/

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Table of Contents LIST OF FIGURES .............................................................................................................................. v

LIST OF TABLES ................................................................................................................................ vii

LIST OF ABBREVIATIONS ................................................................................................. ix

EXECUTIVE SUMMARY .................................................................................................................... xi

CHAPTER 1 INTRODUCTION ....................................................................................................... 1 Oil Sands ...................................................................................................................................... 1 Electricity Generation ..................................................................................................................... 2

CHAPTER 2 GREENHOUSE GASES, ABATEMENT TECHNOLOGIES AND OPPORTUNITIES IN THE OIL SANDS INDUSTRY ........................................................ 5 Introduction.................................................................................................................................... 5 Thermal Operations, Steam Requirements and Challenges ........................................................... 9 Geology: The Carbonate versus Sandstone Story ......................................................................... 17 Applicability of Oil Sands Technologies .......................................................................................... 21 Methodology .................................................................................................................................. 24

CHAPTER 3 CARBON CAPTURE AND STORAGE ........................................................................... 31 Introduction.................................................................................................................................... 31 Capture Processes .......................................................................................................................... 32 Advantages and Disadvantages of the Carbon Capture Process .................................................... 36 Compression and Transportation ................................................................................................... 38 Storage ...................................................................................................................................... 39 Oil Sands CCS Potential .................................................................................................................. 39 Electricity Generation in Alberta .................................................................................................... 40 Coal-Fired Generation .................................................................................................................... 44 Electricity Generation and Brief Overview of Coal in Saskatchewan ............................................. 46 Gasification ..................................................................................................................................... 46 In Situ Coal Gasification vs. Integrated Gasification Combined Cycle ............................................ 48 Gasification of Coke and the Oil Sands ........................................................................................... 49 Methodology .................................................................................................................................. 50 Power Requirements for Carbon Capture as Calculated for Electricity Generation by Coal.......... 51 Capital Costs Associated with CCS and Other Electricity Generating Technologies ....................... 54 Concluding Remarks ....................................................................................................................... 54

CHAPTER 4 EMISSION ABATEMENT POTENTIALS ....................................................................... 55 Reference Case for Oil Sands.......................................................................................................... 55 Electricity Generation ..................................................................................................................... 59

CHAPTER 5 CONCLUDING REMARKS .......................................................................................... 61

APPENDIX A TECHNICAL COMPONENTS OF EQUATIONS OF PROCESSES AND METHODOLOGIES ......................................................................... 63

GLOSSARY ................................................................................................................. 69

REFERENCES ................................................................................................................. 71

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Emission Abatement Potential for the Alberta Oil Sands Industry and Carbon Capture v and Storage (CCS) Applicability to Coal-Fired Electricity Generation and Oil Sands

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List of Figures Figure E.1 Reference Case Projection of Emissions from the Oil Sands............................................ xi Figure 1.1 Alberta Oil Sands Areas .................................................................................................... 2 Figure 1.2 Capacity Breakdown of Electricity.................................................................................... 3 Figure 2.1 Canada’s Overall Emissions .............................................................................................. 5 Figure 2.2 Alberta, Electricity Generation and Oil Sands Emissions ................................................. 6 Figure 2.3 Percentage Change of Emissions and Production Since 1990 Levels for Mining, Extracting and Upgrading of the Oil Sands ......................................................... 7 Figure 2.4 Bitumen Viscosity versus Temperature ........................................................................... 10 Figure 2.5 In Situ Recovery Methods ................................................................................................ 11 Figure 2.6 Oil Sands Projects and Different Formations in the Athabasca Region ........................... 18 Figure 2.7 The Athabasca-Wabiskaw Formation .............................................................................. 19 Figure 2.8 Major Formations ............................................................................................................ 20 Figure 2.9 Natural Gas Requirements for Varying Boiler Feed Water and

Steam-to-Oil Requirements ............................................................................................. 27 Figure 2.10 Natural Gas Requirements for Varying Pressure and Steam-to-Oil Requirements ......... 28 Figure 3.1 Block Representations of the Different Processes ........................................................... 32 Figure 3.2 Partial Pressure CO2 Concentrations from Various Industrial Sources ............................ 36 Figure 3.3 Project Additions Between 1998-2015 as Provided by AESO .......................................... 41 Figure 3.4 Summation of Proposed Project Additions Each Year Between 1998-2015 .................... 42 Figure 3.5 AESO’s 2009-2029 Long-Term Energy Outlook Generation Mix for 2010 and 2020 ....... 42 Figure 3.6 Forecasted Electricity Demand Between 2009-2029 ....................................................... 43 Figure 3.7 IGCC Plant ........................................................................................................................ 48 Figure 4.1 Realistic Scenario of CERI Production on a Total Raw Bitumen

Produced Basis, 2008-2035 .............................................................................................. 55 Figure 4.2 Reference Case Projection of Emissions from the Oil Sands, 2008-2035 ........................ 56

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Emission Abatement Potential for the Alberta Oil Sands Industry and Carbon Capture vii and Storage (CCS) Applicability to Coal-Fired Electricity Generation and Oil Sands

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List of Tables Table E.1 Emissions of the Oil Sands Sectors for the Years 2009, 2020 and 2035 Using CERI’s Realistic Scenario Projection Estimates ....................................................... xii Table E.2 Comparison of Emission Factors for Gasification of Coke and Asphaltenes .................... xiii Table E.3 CCS Technology for Supercritical Power Plants and IGCC ................................................ xiii Table 2.1 2008 Greenhouse Gas Emissions from the National Inventory Report 2010 by National Inventory Category ....................................................................................... 6 Table 2.2 Breakdown of Greenhouse Gas Emissions by Potential Oil Sands Sources ..................... 8 Table 2.3 Oil Sands Technology Roadmap ....................................................................................... 9 Table 2.4 Solvent Projects at the Commercial Stage ....................................................................... 14 Table 2.5 Applicability of Different Production Methods ................................................................ 22 Table 2.6 Emission Factors for Various Oil Sands Operations ......................................................... 29 Table 2.7 Emission Factors Calculated from CERI Methodology ..................................................... 29 Table 2.8 Emission Factors for Emerging Technologies ................................................................... 30 Table 3.1 CO2 Concentrations from Various Flue Gases from Oil Sands Operations ....................... 35 Table 3.2 Advantages and Disadvantages of Carbon Capture Processes ........................................ 37 Table 3.3 Summary of Factors Affecting Different CCS Technological Processes ............................ 37 Table 3.4 Advantages and Disadvantages of Physical and Chemical Solvent

Systems and Membranes ................................................................................................. 38 Table 3.5 Retiring Electrical Generation Plants by 2027 in Alberta ................................................. 41 Table 3.6 Gasification Process, Environmental Controls and Products ........................................... 47 Table 3.7 Comparison of Emission Factors for Gasification of Coke and Asphaltenes .................... 50 Table 3.8 Comparison of Chemical Solvents on Power for Coal, Post-Combustion ........................ 52 Table 3.9 Efficiencies as Modified by the NETL 2011 Study to Reflect a

450 MW Gross Output Plant ............................................................................................ 53 Table 4.1 Emissions of the Oil Sands Sectors for the Years 2009, 2020 and 2035

Using CERI’s Realistic Scenario Projection Estimates ....................................................... 57 Table 4.2 Comparison of Emission Factors for Gasification of Coke and Asphaltenes .................... 58 Table 4.3 Possible Abatement Potentials for the Year 2035 if Energy Efficient Technologies

and Some CCS are Utilized Between 2011-2035 .............................................................. 59 Table A.1 Chemical Composition of Syncrude and Suncor Coke...................................................... 66 Table A.2 Dry Mole Percentage Composition .................................................................................. 66

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Emission Abatement Potential for the Alberta Oil Sands Industry and Carbon Capture ix and Storage (CCS) Applicability to Coal-Fired Electricity Generation and Oil Sands

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List of Abbreviations Air Separation Unit ASU Alberta Bitumen Link ABL Alberta Geological Society AGS Alkaline-Surfactant-Polymer ASP Barrels per day BPD Boiler Feed Water BFW Carbon Capture and Storage (Sequestration) CCS Carbon Dioxide Equivalent CO2eq Catalyst-Upgrading Process In Situ CAPRI Centipoise cP Chemical Looping Combustion CLC Chemical Looping Gasification CLG Combustion Overhead Gravity Drainage COGD Criteria Air Contaminant CAC Cumulative Steam-to-Oil Ratio CSOR Cyclic Steam Simulation CSS Dimethyl Ether DME Electromagnetic Radiation EM Electric Submersible Pump ESP Electric Thermal Dynamic Striping Process ET-DSP Emission Factor EF Energy Resources Conservation Board ERCB Enhanced Oil Recovery EOR Enhanced Solvent Extraction Incorporating Electromagnetic Heating ESEIEH Enthalpy H Entropy S Expanding Solvent Steam Assisted Gravity Drainage ES-SAGD Global Warming Potential GWP Greenhouse Gas GHG Heat Recovery Steam Generator HRSG Horizontal Cyclic Steam Simulation HCS In Situ Coal Gasification ISCG In Situ Combustion ISC Instantaneous Steam-to-Oil Ratio ISOR Integrated Gasification Combined Cycle IGCC International Panel on Climate Change IPCC Ionic Liquid IL Kelvin K Low Pressure Steam Assisted Gravity Drainage LP-SAGD Megatonne Mt Megawatt Electric MWe Megawatt Thermal MWth Mercury Hg Metal Organic Framework MOF Metric Tonne t

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Microbial Enhanced Oil Recovery MEOR Mobile Oil Zone MOZ Monoethanolamine MEA National Energy Technology Laboratory NETL Natural Gas Combined Cycle NGCC National Inventory Report NIR National Petroleum Council NPC Nitrous Oxides NOx Once Through Steam Generator OTSG Pascal Pa Pressure Swing Absorption PSA Sensible Heat Capacity c Skin Electric Current Tracing SECT Solvent Aided Process SAP Steam Alternating Solvent SAS Steam Assisted Gravity Drainage SAGD Steam Methane Reforming SMR Steam-to-Oil Ratio SOR Sulphur Oxides SOx Sulphur Recovery Unit SRU Synthetic Crude Oil SCO Supercritical Pulverised Coal SCPC Thermal Assisted Gravity Drainage TAGD Toe-to-Heel Air Injection THAI Tonne t Underground Coal Gasification UCG Vertical Steam Drainage VSD Water Gas Shift WGS Western Canadian Sedimentary Basin 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

Source: CERI

1Realistic Scenario is from CERI Study No. 122, “Canadian Oil Sands Supply Costs and Development Projects (2010-

2044) 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 Emissions CO2eq (Mt)

2009 2020 2035

Stand-Alone Upgrading 10 11 15

Integrated Mining and Upgrading

11 27 30

Integrated Upgrading In Situ

4 15 22

Stand-alone Mining 2 14 14

Stand-alone In Situ Projects

12 22 47

Total 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

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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

EF (Emission Factor)

Natural gas (t CO2eq/bbl)

Coke gasification no CCS (t CO2eq/bbl)

Asphaltene gasification no CCS (tCO2eq/bbl)

H2 Plant w/ CCS (t CO2eq/bbl)

Coke gasification w/CCS (t CO2eq/bbl)

Asphaltene gasification w/ CCS (t CO2eq/bbl)

Stand alone Upgrader

0.06 0.1 0.09 0.03 0.01 0.009

Integrated Upgrader

0.09 0.16 0.14 0.06 0.016 0.014

Integrated Upgrader In Situ

-- 0.22 0.2 -- 0.022 0.02

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

Base SCPC

MEA SCPC

KS-1 SCPC

Chilled Ammonia SCPC2

IGCC3

Power no CCS (MWe) 450 450 450 450 450

CO2 emitted no CCS (Mt/yr) 3.1 3.1 3.1 3.1 2.1

CO2 captured (Mt/yr) -- 2.8 2.8 2.8 1.9

Efficiency Plant after Capture 0.385 0.24 0.27 0.29 0.32

Efficiency Plant after Compression

-- 0.21 0.24 0.27 --

Power output CCS (MWe) 450 255 287 311 304

Source: CERI and various other sources

2The chilled ammonia process is highly uncertain and the numbers for this should be treated with some

reservation. 3Compression 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 ultra-supercritical 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 long-term 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.

4For 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. 5There 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

Source: (Hu 2011).

Coal 46%

Natural Gas 39%

Hydro 7%

Wind 6%

Other 2%


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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

Source: (Environment Canada 2010)

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Figure 2.2: Alberta, Electricity Generation and Oil Sands Emissions


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 Mining, Extraction and Upgrading

Oil Sands In Situ Bitumen

Oil Sands Total 37.2 24.9 12.2

Energy Fuel Combustion Stationary

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Energy Fuel Combustion Transportation

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Energy Fugitive Unintentional

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Energy Fugitive Flaring 1.4 1.0 0.5

Energy Fugitive Venting

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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


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.

6This 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

Activity Description

Fossil Fuel Combustion 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 Technology Sector Technologies Available

Extraction Efficiency Improvements

In Situ Extraction Technologies

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)

Mining Extraction Technologies

Operation changes (shift to lower emitting vehicles) Chemical changes

Lower Carbon Intensity of Energy Inputs

CCS Combustion/gasification of fossil fuels (asphaltenes, coke) Capture/storage of CO2 and CO2 for enhanced oil recovery (EOR)

Alternative Fuels 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

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

Athabasca Bitumen, Canada (8.6oAPI)

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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

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

In Situ Recovery

Thermal

Electric Heating

Steam

SAGD

CSS

Combustion Solvent

Other EOR Methods


October 2011

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. Potentially decreased SOR 2. Increased recoveries of bitumen 3. Reduced bitumen viscosity 4. Use in reservoirs not typically suited for SAGD, such as those with lean zones

5. Vaporization of lighter components of solvents to create a solution-gas drive mechanism 6. Solvents travel more quickly to the chamber extremities as well as extend out more

laterally then typical SAGD operations


October 2011

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.


October 2011

Table 2.4: Solvent Projects at the Commercial Stage

Company Project Solvents Year

Completed Pilots7

Suncor Firebag Propane 2004

Suncor Firebag Naphtha 2006

EnCana Senlac Butane 2002

EnCana Christina Lake Propane, Butane 2005

Imperial Oil LASER Diluent

Nexen Long Lake Jet B 2006

Proposed Pilots

Cenovus Narrows Lake Butane, xylene 2017

Laricina Saleski Propane, Diluent 2011

Researching

ConocoPhillips Naphtha, Diluent, Other light HC’s

Alberta Oil Sands Inc. Pilot Fort Mac. Gas-condensate

Devon Jackfish 3

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

7While some of these operations are still operating, “completed” denotes that the pilot has been done with either

further application or dismissal of the technique.


October 2011

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-Air-Injection 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


October 2011

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.


October 2011

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) Gases (H2, N2, CH4, CO2) for non-condensing gas extraction b) Acids (primarily low molecular weight fatty acids) c) Solvents (alcohols and ketones) d) Biosurfactants e) Biopolymers f) Biomass (selective plugging)

g) 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


October 2011

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)

8These statistics come from a variety of ERCB applications showing the geology of the projects.


October 2011

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 109 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


October 2011

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.


October 2011

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.

9Karst is limestone where erosion has degraded sections by dissolution producing a crumbly mix of fissures,

tunnels and caverns.


October 2011

Table 2.5: Applicability of Different Production Methods

Production method of resource:

Open-pit mining

CHOPS10 Waterflood11 CSS12 SAGD13

Status Commercial Commercial Commercial Commercial Commercial

Shallowest (<50m) Only solution No No No No

Shallow (50-100m) Possible if economically viable

No No No No

Medium depth (100-300m)

No Unlikely 16 API or greater, unlikely unless very low viscosity and high permeability14

No unless there is a good sealing caprock to prevent blow outs

No unless there is a good sealing caprock to prevent blow outs

Intermediate depth (300-1000m)

No Yes but requires unconsolidated sandstone formation and solution gas

16 API or greater, low viscosity and/or high formation temperature

Yes but deeper zones require greater pressures and temperatures

Yes but deeper zones require greater pressures and temperatures

Deep (>1000m) No Unlikely, needs unconsolidated formations

Low viscosity and/or high formation temperature

No, too much heat loss to overburden

No, too much heat loss to overburden

Carbonates No No No Possible Possible

Thin beds (<10m thick)

No Yes Maybe Possible with horizontal wells

No

10

CHOPS is the method of choice within the Lloydminster region for oil production and good for thin reservoir beds where steaming would be ineffective (Peachey 2010). 11

(Peachey 2010) 12

Need at least 10-15 m net pay zone as well to be economically viable (Flach 1984). CSS is not applicable to areas with thick bottom water or top gas but can handle heterogeneities better than SAGD. 13

Ibid 14

The ERCB defines Bitumen as “A thick, stick, naturally occurring viscous mixture of hydrocarbons that may contain sulphur compounds and that, in its naturally occurring state, is not recoverable at a commercial scale through a well.” Bitumen could be predominantly defined as crude oils having a dead-oil viscosity of greater than 10,000 cp and sometimes may refer to oils with an API of less than 10 degrees (Clark and others 2007). This makes CHOPS, waterfloods, most non-condensing and miscible solvents largely inapplicable to oil sands reservoirs. Cenovus has used co-injection of methane (non-condensing gas) at its Christina Lake project with moderate success. It is believed that the methane insulates against heat loss.


October 2011

Table 2.5: Applicability of Technologies (continued)


Solvent with heat

Solvent without heat

Vertical well combustion

THAI/CAPRI Polymers

Status Commercial /Pilot

Pilot Commercial Commercial/Pilot Commercial/Pilot

Shallowest (<50m)

No No No No No

Shallow (50-100m)

Unknown Possible if economically viable

No No Unknown


Needs good vertical and horizontal permeability. Initial results are conflicting on applicability

Unproven, needs good vertical and horizontal permeability

Possible but discouraging results from 70/80’s pilots for Bitumen

Possible Possible


Needs good vertical and horizontal permeability. Initial results are conflicting on applicability. CO2 as a miscible solvent may be more successful for lighter oils.15

Unproven, needs good vertical and horizontal permeability. Winter tests for cold solvent injection in oil sands required heating.

Possible but discouraging results from 70/80’s pilots for bitumen. Successful results elsewhere for less viscous oil reservoirs.

Petrobank reports success for its pilot and has continued to commercial demonstration

Yes

Deep (>1000m)

Unknown Unknown Possible Possible but unproven

Unknown

Carbonates Success with Laricina’s pilot Saleski but largely unknown potential

Possible but unproven

Unknown Unknown Maybe




Unknown Unlikely Unknown

15

(Peachey 2010) CO2 for immiscible flooding may be more successful for heavier oils but is largely unproven for bitumen resources.


October 2011

Table 2.5: Applicability of Technologies (continued)


Surfactants Other chemicals

Electric induction, ultrasonics

Supercritical Fluids

Biotechnology

Status Pilot/Research Research Pilot/Research Experimental Research

Shallowest (<50m)

No No No No Unknown

Shallow (50-100m)

Unknown Unknown Possible, ETS reports success on their pilot

No, needs high reservoir pressure

Unknown


Possible Unknown Possible, limited successes in isolated cases.


Unknown


Yes Unknown Possible but unproven


Unknown

Deep (>1000m)

Unknown Unknown Possible but unproven

Weyburn/ Midale project a success and shows miscible interaction of the CO2

16

Unknown

Carbonates Unknown Unknown Limited success in Grosmont formation

Maybe Unknown


Unknown Unknown Possible but unproven

Possible with horizontal wells

Unknown

Source: (Various sources and the NPC)

Methodology

There is no universally agreed method for calculating GHG emissions; the Federal government

suggests that the procedure as outlined from the United Nations Framework Convention on Climate Change be utilized. Since there is inadequate information to perform a Tier 3 comprehensive materials/energy balance, the International Panel on Climate Change (IPCC) Tier 1 default emission factors for stationary combustion of fuels were utilized to calculate the CO2, CH4, and N2O emissions of an oil sands project except the CO2 content of natural gas. Carbon dioxide was calculated from Environment Canada’s emission factors for marketable natural gas in Alberta, where a heat content of 1.06 GJ/Mcf was utilized. Emission factors are based on the higher heating value of the fuels.

All natural gas was assumed to follow the emission factors for boiler and combined cycle utility

source emissions. The exceptions to the IPCC default was for N2O for boiler emissions, as the

16

(Godin 2007)


October 2011

reported values were lower than was calculated with the default; therefore, a lower emission factor was used. Cogeneration was calculated on the assumption that all natural gas purchased was run through either a boiler or a combined cycle turbine with a heat recovery unit. The lower heating value of methane is 34 MJ/m3 (0.965 MJ/cf), but natural gas streams have varying amounts of liquids which could raise the heat content, and there is some variability depending on the location the natural gas came from. For cases where fuel consumption could be established for projects, the emission factor (EF) was applied directly. For cases where offspec SCO was utilized, it was assumed the fuel was diesel. Venting of natural gas was assumed to be composed of 100 percent methane, which is an overstatement.17 Depending on the GWP and composition of the natural gas stream used this could create differences in terms

of the true CO2eq emission factor. Flared gas was assumed to have the same EF as stationary combustion of natural gas. Energy contents were obtained from the NEB and ERCB ST-98 report. The following GWP and factors were utilized:

Chemical GWP Emission Factors (EF)

Natural gas combustion (kg/GJ)

Process Gas (kg/GJ)

Diesel (kg/GJ)

Naphtha (kg/GJ)

Coke (kg/GJ)

CO2 1 54.3 57.6 74.1 73.3 97.5

CH4 21 0.001 Boiler/Combined Cycle

0.001 0.003 0.003 0.003

N2O 310 0.0001 Boiler 0.003 Combined Cycle

0.0001 0.0006 0.0006 0.0006

Source: (IPCC, ERCB, NEB)

Emissions were calculated from the following formula:

Correction factors for potential diesel and transportation emissions as well as miscellaneous venting emissions were then added to the above result. The 2008 National Inventory Report

17

Hydrocarbons other than methane have a much lower GWP than methane. For example, GWPs of 3 and 3.3 have been reported for propane and isobutene, respectively.


October 2011

(NIR) reported that approximately 2.4 percent of emissions came from transportation, while the Alberta Energy GHG report had closer to 8 percent emissions coming from transportation. The Ordorica-Garcia coefficient of 2L/bbl diesel for mining operations was used to estimate the emissions using Environment Canada’s emission factor for diesel from refineries since no better substitute was available. Venting emissions were estimated from the ERCB’s ST-60 report applying the ratio of venting emissions from the NIR 2008 report. Other sources of information were the ST-39 and ST-53 reports from the ERCB.

The emissions for mining were checked from the reported values of the 2008 National Inventory Report (NIR) inflated linearly to match the 2010 production. The rough estimate was

around 31 Mt, and the calculated value from the above process was between 31-34 Mt. The numbers were also checked between calculated values and reported 2009 values from Environment Canada’s facility greenhouse gas reports. There was some discrepancy in the values, which was to be expected as emission factors for natural gas can vary depending on the liquids content, and there is considerable variation in composition of process gas and naphtha. Thermodynamics of reported gas consumption values versus energy requirements for steam generation suggest that the natural gas heat content might be closer to 1.1 GJ/Mcf, which signifies higher liquids content then the national average.

Calculated upgrading emissions were higher than the reported values, and it is assumed there is

some discrepancy in the energy inputs in the methodology. All process gas was assumed to be combusted while in reality some process gas may be recycled and the hydrogen extracted for further hydrotreating. Based on Total’s Environmental Assessment of its proposed upgrader, it is believed that the default value should be around 0.05-0.06 T CO2eq/bbl with approximately 0.5 Mcf/bbl for natural gas usage and 0.5 Mcf/bbl for process gas usage, giving a range of 0.06-0.08 T CO2eq/bbl. This is still slightly higher than the reported value but seems adequate for the purposes of this report.

Natural Gas Requirements for Differing Operating Conditions

In situ emissions may vary depending on the amount of steam to successfully extract bitumen.

Different pressure, steam, and temperature requirements cause the natural gas usage to vary

because the energy requirements vary. While a default value has been picked for the emission factors, natural gas usage for varying SOR’s and temperature, pressure requirements have been calculated based on the theoretical energy requirements for generating steam at different conditions. The steam was assumed to be produced at 80 percent quality within a system that was 94 percent efficient at transferring energy from natural gas combustion to steam generation.

The general calculation was as follows:


October 2011

Natural Gas Heat Content was assumed to be 38.9 MJ/m^3 (1.1 GJ/Mcf) which is on the higher end of heat contents as it was assumed Alberta natural gas has a higher than average liquids content as well as solution gas is expected to have a higher than average liquids content. It is possible that this number is closer to (1.05 GJ/Mcf). A more in-depth description of the equations is given in the appendix.

Figure 2.9 is an indicator of the natural gas requirements for different SORS as boiler feed water (BFW) temperatures are varying for steam requirements at 11 megaPascals (MPa).18 The intercept is 0, which is not realistic as a boiler would utilize some water for its own use, giving a non-zero value for a steam to oil ratio of 0.

Figure 2.9: Natural Gas Requirements for Varying Boiler Feed Water and Steam-to-Oil Requirements

Source: CERI

18

Note that a BFW of 40°C is unlikely to happen and this calculation is to show how much the energy increases when one has to preheat the water as well.

y = 0.3958x + 1E-15

y = 0.4134x + 4E-15

y = 0.5374x + 5E-15

0

1

2

3

4

5

6

0 2 4 6 8 10

Nat

ura

l Gas

Mcf

/bb

l

DRY SOR

BFW 175 Theoretical Basic Heat Requirement NG mcf/b




October 2011

Figure 2.10 shows the natural gas requirements if the temperature requirements are allowed to

remain the same as pressure and SOR vary.

Figure 2.10: Natural Gas Requirements for Varying Pressure and Steam-to-Oil Requirements

Source: CERI

0

0.5

1

1.5

2

2.5

0 1 2 3 4 5 6

Nat

ura

l Gas

Mcf

/bb

l

Dry SOR

Pressure @ 10 bar Theoretical Calculation Natural Gas




Pressure @50 bar Theoretical Calculation Natural Gas







October 2011

Emission Factor Ranges

Table 2.6: Emission Factors for Various Oil Sands Operations

Operation Calculated Emission Factor Range* (tCO2eq/bbl)19

Literature Range (tCOeq/bbl)

Mining 0.022-0.042 0.025-0.05

Integrated Mining & Upgrading 0.09-0.15 --

Upgrading w/o gasification 0.056-0.09 0.038-0.09

Upgrading w/ gasification -- 0.074-0.083

Integrated In Situ & Upgrading 0.2 --

In Situ w/o Cogen SAGD 0.038-0.116 0.065-0.115

In Situ w/ Cogen SAGD 0.087-0.11 --

In Situ CSS20 0.06-0.12 0.08-0.12

Source: (Various sources, CERI) *Venting, Fugitive and Transportation are largely estimated values, which accounts for part of the range.

Default Emission Factors

Table 2.7: Emission Factors Calculated from CERI Methodology

Operation Calculated Emission Factor Range* (tCO2eq/bbl)

Mining 0.03

Integrated Mining & Upgrading 0.09

Upgrading w/o gasification 0.056

Upgrading w/ gasification 0.08

Integrated In Situ & Upgrading 0.2

In Situ w/o Cogen SAGD 0.06

In Situ w/ Cogen SAGD 0.09

In Situ CSS 0.08

In Situ SC-SAGD Carbonate 0.0421

In Situ SAGD Co-injection 0.0522

Source: (CERI)

*SAGD based on an SOR of 3 and CSS based on a CSOR of 3.5

19

tCO2eq/bbl includes the total emissions from the facility, which includes cogeneration capabilities if the facility of interest has a cogeneration unit. The barrel designation has not been differentiated between emissions associated with the production and export of electricity and emissions directly associated with the barrel of oil produced. Barrels were assumed to be on per barrel of raw bitumen produced or received by the facility; therefore, upgrading is not per barrel of SCO but per barrel of received/processed raw bitumen. 20

CSS Calculations were not reported and TIAX’s LCA report values for the energy inputs had to be utilized. For literature values, values supplied by the CanOils database were utilized. 21

As calculated for reported SOR of Laricina Saleski Carbonate reservoir 22

As calculated for reported SOR of Cenovus Christina Lake


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The numbers for EF for the classic examples of in situ are on the lower end because, as novel techniques proliferate throughout the industry, the energy intensity per barrel of output is expected to decrease. Moreover, while the specific relationship cannot be quantitatively deduced, CERI believes that the overall emission factor will be lower than the approximately 0.1 t CO2eq/bbl historical average. Lastly, as reservoirs become depleted and less desirable resources are extracted, the energy intensity may increase. However, exploration of this possibility is beyond the scope of this study and virtually incalculable due to the heterogeneous nature of such a prediction.

Emerging Technologies Emission Factors

This mix includes possible technologies that are either in the pilot stages with little data, estimated from company reports, or from other literature sources. The estimation is based either on the predicted SOR or from a percentage value given (i.e., 30 percent reduction of energy or GHG). Most technologies were not included for this study as they are still largely in the research phase. Consequently, only technologies that were in the pilot to commercial stage and were deemed possible for application in oil sands reservoirs were considered for abatement reduction. This largely limits technologies to solvent combinations, combustion, and electric heating.

Table 2.8: Emission Factors for Emerging Technologies

Process EF T CO2eq/bbl

CSS, LASER & CSP 0.05

HCS (horizontal CSS) 0.05

Vertical Steam Drive (VSD) / CSS 0.03

LP-SAGD 0.07

SAGD/ES-SAGD 0.03

SAGD/SAP 0.04

SAGD/SC-SAGD 0.05

SAP or SAGD 0.03

SAS (steam alternating solvent) Unknown

Enhanced solvent extraction incorporating electromagnetic heating (ESEIEH)

0.02

N-Solv 0.01

VAPEX 0.01

Combustion Overheard Gravity Drainage (COGD)

0.02

THAI 0.02

TAGD Unknown

ET-DSP 0.03

Source: (CERI)


October 2011

Chapter 3 Carbon Capture and Storage Introduction

Historically, as an economy expands and develops, there has been an increase in total energy consumption, and while energy intensity decreases over time the net result has been the release of carbon-based compounds into the atmosphere at a rate greater than can be sequestered back into the Earth. Furthermore, there is a growing consensus that anthropogenic

emissions have affected the global climate by unprecedented amounts and therefore steps must be taken to significantly reduce GHG, primarily from fossil fuel combustion, into the atmosphere. The ways of decreasing emissions are by further decreasing energy intensity,

switching to non-carbon fuels, and finding suitable artificial and permanent sinks for the carbon. Since fossil fuels provide a majority of the world’s energy needs, it is unlikely in the short-term that significant reductions in energy intensity or non-carbon fuels will come into the forefront; therefore, artificial sinks of carbon are becoming of increasing interest and priority (Bachu 2003). Accordingly, governments are investing in technologies that promote carbon capture and storage (CCS) as a promising venue to make significant reductions (Figueroa and others 2008).

In 2008, the Alberta government developed its climate change strategy which called for the reduction of 200 Mt of CO2 by the year 2050. One of the key reduction strategies proposed was CCS targeted for a 70 percent reduction. Since then Alberta has released $2 billion in CCS funding through its 2010 Carbon Capture and Storage Grant to promote the advancement of CCS technologies (Alberta Energy 2011).

Currently, CCS technologies are expensive to deploy and considerable advancements in research are needed to successfully install commercial CCS projects in a cost-effective manner. The focus for CCS establishment has usually been large point source emitters such as power

generation units. Coal-fired generation makes up a significant portion of the emissions, but

there has also been focus on retrofitting oil sands upgraders with carbon capture units.

CCS has 4 stages: CO2 capture, compression, transport, and storage. Consequently, CCS can be considered a lifecycle process of controlling emissions and will be an effective means of reducing emissions if it can be applied without significantly restricting economic growth. The major categories of capture technologies at the forefront are pre-combustion, post-combustion and oxy-combustion which will be described in more detail later. Pre-combustion can be applied to gasification processes while post- and oxy-combustion may be retrofitted to current point-source emitters (Ciferno, Litynski, Plasynski 2010).


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Capture Processes

While there are a number of processes that are capable of removing CO2, there have been numerous constraints which have impeded the commercialization of a majority of these processes. The primary impediment is the dilute CO2 concentrations in flue gas streams from sources of interest. This is because the vast majority of sources are from combustion processes that generate a high-volume but dilute stream of CO2 at low pressures. A majority of the capture processes operate more efficiently at higher pressures and/or lower temperatures and therefore an energy penalty is incurred to bring the process into the ideal operating range. Consequently, for abatement potential of a process, the amount captured must be corrected for the excess amount emitted. Figure 3.1 is a simplified block diagram representation of the

different processes. Pre-combustion processes may vary depending on the desired output required for the process.

Figure 3.1: Block Representation of the Different Processes

Source: (CERI and various sources)


October 2011

Pre-combustion Capture

Classic Technologies

Pre-combustion capture is mainly applicable to gasification plants. Gasification is the process of converting any fuel with carbon in it (biomass, waste, coal, asphaltenes, coke, etc.) to gaseous substances by applying steam, pressure and sub-stoichiometric quantities of oxygen (O2). The rate of combustion is controlled by restricting the O2 so that only the amount of heat necessary to decompose the fuel into syngas (a mixture of carbon monoxide (CO), hydrogen gas (H2) and other minor gas constituents) is applied. Syngas can be further processed by means of a water

gas shift (WGS) reactor to produce additional quantities of CO, CO2 and more H2. The advantage of this system is that the CO2 emitted is at a high partial pressure making it easier to catch utilizing organic or physical solvents. An acid gas removal system can remove the CO2; the produced H2 can be transported for utilization in the generation of electricity or in other industrial processes that require H2. Currently, the most advanced technologies are glycol based Selexol™ (a mixture of di-methyl ethers of polyethylene glycol) an organic solvent, Purisol™ (N-methyl-2-pyrrolidone), Fluor Solvent™ (propylene carbonate) and the physical solvent of methanol-based Rectisol™. All of these utilize physical solvents to capture by preferential adsorption of CO2 from the syngas stream (Ciferno, Litynski, Plasynski 2010)(Ordorica-Garcia and others 2010). Rectisol™ is employed in the Weyburn EOR process.

Emerging Technologies

Issues with physical solvents involve a loss of pressure during regeneration, a requirement for the cooling of the syngas and then reheating of the turbine. Solid sorbents, H2/CO2 membranes, and improved WGS reactors are being considered to help keep the process at an elevated temperature. Solid sorbents work from the principle that certain gaseous components are more strongly adsorbed than others. The capacity of the sorbent to adsorb the gas depends on the operating pressure and conditions, and thus a pressure swing cycle can be utilized to preferential adsorb and then release the CO2. The advantage of solid sorbents is that no water is needed, eliminating the sensible heat and stripping requirements. Membranes allow for the

selective permeability of CO2 molecules and use partial pressure differences as the driving force for separation. There are many different types of membranes available including polymeric, porous inorganic, palladium, and zeolite. The improved WGS reaction is to use a CO2/H2 selective membrane in conjunction with the WGS reactor. Adsorption-enhanced WGS is also another way to improve this system (Ciferno, Litynski, Plasynski 2010).

Post-combustion Capture


Post-combustion is usually applied to conventional power plants but may be utilized for gasification plants and combined-cycle natural gas turbines. Post-combustion sequesters CO2 from the flue gases of the boiler reaction primarily by means of a solvent with selectivity for


October 2011

CO2. Chemical extraction usually requires large amounts of steam diverted from the power plant in order to regenerate the solvent due to the reversal of the heat of reaction and absorption enthalpies for release. There are also challenges in treating the large volumes of flue gas that are emitted from the stacks in a typical power plant. Typically clean up of CO2 is similar to acid gas removal in gas processing plants; capture is by preferential absorption of CO2 from amine-based chemical solvents. The most commonly utilized solvent is monoethanolamine (MEA), the same solvent which is used to clean up natural gas streams. Despite low partial pressure of CO2 in the stream, MEA can still trap a large amount of CO2 to form carbamates, but this results in steam from the turbine needing to be diverted to regenerate the solvent again and in degeneration of the expensive amine solvent (Ciferno, Litynski, Plasynski 2010). Recently

however, more advanced forms of solvents are being utilized through a process known as hindered amine absorption. Even though these solvents are less reactive, they have lower circulation rates and can achieve higher rates of regeneration at lower temperatures. This ultimately decreases energy penalties and solvent losses. Currently Mitsubishi Heavy Industries has the KS-1 and KP-1. KS-1 has all the properties of amines while KP-1 reduces the pressure drop across the absorber, decreasing power consumption (Figueroa and others 2008). Lastly, chilled ammonia can be used to capture the CO2 to form ammonium bicarbonate, which is then subsequently released in a regeneration process (Alstom).


There are numerous issues surrounding chemical solvents despite their long successful history as industrial solvents. Some of these issues include large volumes of water needed and vast amounts of energy consumed. Technologies focus on improving regeneration, reaction kinetics, low-cost and non-corrosive solvents, and solvents that are resistive to degradation. Ionic liquids (IL) are being investigated as a physical solvent for capturing CO2 and are considered cost-effective due to their high thermal stability and low volatility. However, IL’s are highly viscous, which could result in pumping problems. Solid sorbents are also being investigated for post-combustion processes as are sodium and potassium oxides, zeolites, carbonates, amine-enriched sorbents and metal-organic frameworks (MOF). Membranes are also being utilized for

CO2 selectivity through the use of semi-permeable and permeable membranes. However, research so far has not come far enough to keep unwanted contaminants out at the concentrations needed for transportation specifications (Ciferno, Litynski, Plasynski 2010).

Oxy-Combustion


OxyFuel Combustion relies on combusting fuel with a pure stream of O2 with dilute amounts of CO2 in it and has the potential of capturing 100 percent of the CO2. The advantage of this over post-combustion is that the primary products are water and CO2 without nitrogen which results

in the creation of a highly concentrated CO2 stream that can be easily captured. CO2 is released by the cooling and condensing of the associated water vapour and is easier to concentrate for storage and transportation specifications. While it may be cheaper to sequester the CO2, there


October 2011

are capital costs associated with the equipment required for this process – these capital costs are concentrated within the cryogenic air separation unit and the boiler air filtration unit which dilutes flue gas with N2 and O2 contained in the concentrated CO2 stream (Ciferno, Litynski, Plasynski 2010).


Burning coal in an oxygen rich environment is not without its technical challenges, resulting in a call for more research in understanding flame characteristics, burner and feed design and the oxy-combustion products. One of the main concerns is that the fuel burns hotter and thus the

high temperatures may degrade the boiler materials. Also, an excess of NOx, SOx and N2 and O2 could dilute the CO2 flue stream and may require additional filtering to meet transportation specifications. An ion transport membrane is in development to address this. In addition, chemical looping combustion (CLC) is being investigated. The use of a metal oxide or any compound capable of acting as an O2 carrier transfers O2 from the combustion air to the fuel resulting in CO2 and H2O to be isolated from the combustion reaction. This splits the combustion into oxidation (air unit) and reduction (fuel unit) reactions. The metal is recycled back to be regenerated by air. Possible candidates for the O2 carrier are iron, nickel, copper and manganese. This design allows the disadvantages of oxyfuel combustion to be eliminated by removing the need for the cryogenic unit. A modification of this design is chemical looping

gasification (CLG) where the O2 is utilized for the combustion and gasification of coal, a second loop carries CO and reacts in a WGS reactor to produce H2 and CO2. The CO2 is released in a calcinations step for transport ready CO2 (Ciferno, Litynski, Plasynski 2010).

CO2 Concentration

Estimates in determining abatement potential of various CCS projects are variable due to the heterogeneous costs associated with capturing CO2 from a variety of sources. Capturing concentrated CO2 streams is less costly than dilute streams due to the significant decreases in operating costs. This is because less volume of gas needs to be processed with a highly concentrated stream leading to reduced energy and solvent demands. Consequently, it is

preferable to capture CO2 containing streams that have a high concentration of CO2 within

them. Table 3.1 summarizes the concentration of CO2 as reported by Ordorica-Garcia et al(Ordorica-Garcia, Wong, Faltinson 2011) and Figure 3.2, as shown by Kaarstad et al, gives CO2 partial pressures for a variety of industrial streams(Kaarstad, Berger, Berg 2011):

Table 3.1: CO2 Concentrations from Various Flue Gases from Oil Sands Operations

CO2 % in Flue Gas(mol % dry basis)

Diesel Hot Water

Steam Power Process Fuel

Hydrogen

Typical Range 10-15% 0-10% 0-10% 10-15% 0-10% 15-55%

Source: (Ordorica-Garcia and others 2011)


October 2011

Figure 3.2: Partial Pressure CO2 Concentrations from Various Industrial Sources

Source: (Kaarstad & Berg 2011)

Advantages and Disadvantages of the Carbon Capture Process

The National Energy Technology Laboratory (NETL) published a paper in 2008 reviewing CCS and displayed the following table of some of the advantages and disadvantages of doing the different processes (Figueroa and others 2008). Tables 3.2 to 3.4 summarize the advantages

and disadvantages of each process and the factors that affect all of them.


October 2011

Table 3.2: Advantages and Disadvantages of Carbon Capture Processes

Process Advantages Disadvantages

Pre-Combustion Synthesis Gas is highly concentrated in CO2 which creates a high partial pressure for CO2. This creates a high driving force for CO2 separation, allows for more technologies to be enabled and may lower compression costs/loads

Applicable mainly to new plants as there are not many gasification plants. There is a high cost of equipment, availability issues, and extensive supporting systems required

Post-Combustion Applicable to majority of existing power plants and has the possibility to be retrofitted on.

Flue gas is dilute in CO2 concentration which requires higher volumes to be processed for significant capture levels as well as CO2 is produced at low pressure compared to sequestration requirements.

Oxy Combustion High CO2 concentration in flue gas and has retrofitting and repowering technology options

Cryogenic O2 production is costly and need to have cooled CO2 recycle to maintain lower temperatures within limits of combustion materials which decreases the process efficiency

Source: (Figueroa and others 2008)

Table 3.3: Summary of Factors Affecting Different CCS Technological Processes

Solvent Absorption Physical Adsorption Membrane

Operating Pressure & Temperature Solvent Working Capacity Heats of Absorption & Reaction Mass Transfer & Chemical Reaction Rates CO2 Selectivity Regeneration Energy Co-solvent concentrations Contamination Resistance

Surface Area Working Capacity Heat of Absorption Crush Strength Cycle Time Number of Expected Cycles Sorbent Costs

Permeance Selectivity Pressure Ratio Packing Density Contaminants

Source: (Ciferno, Litynski, Plasynski 2010)

Table 3.3 summarizes different factors affecting the major processes. Physical and chemical solvents behave differently. Physical solvents are driven by Henry’s Law where the solubility of

the acid gas (H2S or CO2) increases linearly with its partial pressure. Hence, high pressures are ideal for physical solvent systems. Consequently, physical solvents require less energy to regenerate as the acid gas is released by pressure reduction (Strube and Manfrida). Chemical


October 2011

solvents require low acid gas pressures and, as mentioned above, require energy to break the acid-solvent link in order to regenerate the solvent. Advantages and disadvantages of physical and chemical solvents and membranes are summarized in Table 3.4 (Kidnay and Parrish 2006).

Table 3.4: Advantages and Disadvantages of Physical and Chemical Solvent Systems and Membranes

Process Advantages Disadvantages

Chemical Solvents Can reduce H2S and CO2 to ppm levels and largely insensitive to them

Large energy requirements Amines in water solution and hence the treated gas is saturated with water

Physical Solvents Easily regenerated with low energy penalty Selective between H2S and CO2

Sensitive to acid gas partial pressure Process is dry Heavy hydrocarbons strongly absorb.

Membranes Low capital investment. Easy to install No chemicals needed.

Little economy of scale Need a clean feed: Pre-treatment to remove particulates and liquids Gas compression: Pressure difference is needed for membrane separation and hence there are recompression requirements.

Source: (CERI & Kidnay and Parrish 2006)

Compression and Transportation

CO2 must be compressed in order to be cost-effectively transported and is generally in a supercritical state when transported and injected for storage. Compressors or

refrigeration/pumping are utilized to get CO2 into a supercritical state. Pipelines are then used to transport the CO2 to its storage location or to an EOR site. The energy requirements to compress takes away from the overall power plant output. DOE/NETL have estimated that about a 30 percent power output loss would occur to meet the capture and compression energy requirements and that an additional unit may be needed to make up the lost power (Ciferno, Litynski, Plasynski 2010). Moreover, due to the high pressures required, conventional pipelines for transporting oil and gas are not suitable and, hence, CO2 transportation requires a network of its own. Lastly, compression and transportation require significant volumes of water to cool all of the components as well as the flue gas (Ciferno, Litynski, Plasynski 2010).

Compression requires huge amounts of power from the power plant, the NETL has estimated that about 7.5 percent of the gross power output of a coal-fired plant is needed for compression (Ciferno, Litynski, Plasynski 2010). CO2 is generally transported at its supercritical


October 2011

state since the power requirements for transporting the liquid are less than transporting the compressed gas. Semi-isothermal compression may reduce power requirements by using an internal cooling jacket. A second concept is the use of refrigeration to liquefy CO2 so that its pressure can be increased using a cryogenic pump. This is because most of the power requirements are for the initial compression (Ciferno, Litynski, Plasynski 2010).

Storage

Ocean disposal has been considered for CO2 by injecting CO2 at depths that will form hydrates or heavier-than-water substances that will sink. Since the physical and chemical processes of this are not well understood and ocean disposal is not relevant for Alberta’s emissions, this

form of disposal will not be further addressed. Geological storage is the more sought after disposal method and involves the injection of CO2 into underground formations that have the potential to permanently and securely store CO2 for long periods of time. Methods of storage are as follows: entrapment in depleted oil and gas reservoirs, solubility trapping in aquifers or water in oil and gas reservoirs, adsorption onto coal or other mediums that attract CO2, injection into salt caverns, and lastly immobilization through mineralization. All of these CO2

sinks may result in storage from a few months to millions of years depending on the process and the flow path. Even though enhanced oil recovery (EOR) results in CO2 breaking through the wellhead, it is the most likely form that will be utilized first due to its economic benefits of additional fossil fuel production. Sedimentary basins are the only suitable sites for geologic

storage; the Western Canadian Sedimentary Basin (WCSB) holds a vast amount of potential storage space for geological storage as well as numerous possibilities for EOR (Bachu 2003). Potential storage sites were explored in detail in CERI’s 2010 Green Bitumen23 report and Bachu’s report with the conclusion that the south western region of Alberta is the most suitable for geological storage. However, underground aquifers such as the Redwater aquifer are going to be utilized in the near future (Shell’s Quest) for storage. Out of all the stages, storage injection is probably the cheapest and the least technological. Risk assessment of the potential storage sites must be thoroughly evaluated before a large scale project can come on stream, and public perception and acceptance is needed before injection can commence.

Oil Sands CCS Potential

Mining

Energy requirements for mining are primarily for electricity and thermal energy for hot water/steam production in the separation process. The last energy requirement is for diesel in the transportation. Carbon capture and storage is only possible on electricity and hot water production units. Ordorica-Garcia et al. examined the feasibility of the different capture processes on mining operations and determined that post-combustion technologies may be the most practical (Ordorica-Garcia and others 2010).

23

CERI Study No. 119, “Green Bitumen: the Role of Nuclear, Gasification and CCS in Alberta’s oil Sands”, David McColl. Available for download off CERI’s website at www.ceri.ca.


October 2011

Upgrading

Upgrading is a very energy-intensive process with the energy requirements primarily being the generation of H2 from SMR and for steam/heat for cracking processes. Post-combustion and gasification of its by-products for pre-combustion are two possible candidates for carbon capture.

SAGD/CSS

Most of the energy requirements are for steam generation in a SAGD operation. The same study by Ordocira-Garcia et al determined that oxyfuel or CLC was optimal (Ordorica-Garcia and others 2010). This works best if the amount captured warrants the cost of the equipment as

well as if it is feasible to access a CO2 transport network from many of the remote SAGD locations. Furthermore, because a majority of the resource is extractable by in situ, in situ operations such as SAGD will continue to produce more oil and therefore will become a significant emitter in the future. For the purposes of this report, CCS is considered uneconomic for in situ operations for the following reasons:

1) Total recently completed an OxyFuel pilot which served to estimate the costs and future potential in SAGD operations in Lacq France by injecting CO2 into a depleted natural gas reservoir. This project cost $72 million to retrofit an old natural gas boiler and captured 120,000 tonnes. The investment per tonne of CO2 captured does not even account for

20 tonnes of emissions released for every 100 tonnes abated and unquestionably costs over $200 dollars a tonne (Le Hir 2010). While further application of this technology will significantly reduce costs, it can be surmised that retrofitting natural gas boilers with an oxyfuel system is in all probability too expensive to be adapted on a widespread basis for the oil sands anytime in the near future.

2) Total’s project was a success but the reservoir was close to the site of capture and most geologically suitable sites in Alberta are in the south-western region, requiring at least 400 km transportation distance to reach them adding significantly to the overall cost. Furthermore, most SAGD projects are in remote locations, and a significant gathering pipeline would be needed to transport the CO2.

Electricity Generation in Alberta

Alberta’s electricity mix is composed of coal, natural gas, hydroelectric and a minor portion of renewables (biomass, wind). A majority of the natural gas capacity is from cogeneration in industrial sources. In 2009 the electricity mix was 60 percent coal, 33 percent natural gas, 2 percent hydro with the remainder to others. Since 2009, Alberta has built a couple of natural gas peaking plants, and it is forecasted that by 2019 natural gas capacity will be approximately 7,100 MW, making up 46 percent of the total supply. The coal-fired Wabumun plant site was fully decommissioned in 2010 but is expected to be replaced by the Keephills Unit. It is forecasted by the ERCB that in 2019 coal will still make up about 52 percent of the electricity

share in the province (ERCB 2010). Table 3.5 is a summary of retiring electricity capacity by 2027 as forecasted by AESO (Wabumun has not been included as it is already retired)(AESO


October 2011

2009). Figures 3.3 to 3.6 give an idea of the type and magnitude of electrical generating capacity being added onto the grid.

Table 3.5: Retiring Electrical Generation Plants by 2027 in Alberta

Station Type Capacity (MW)

Rossdale 8,9,10 Simple Cycle Gas Turbine 209

Rainbow 1,2,3 Simple Cycle Gas Turbine 87

Sturgeon 1,2 Simple Cycle Gas Turbine 18

Battle River 3,4,5 Coal-Fired 664

Sheerness 1,2 Coal-Fired 756

H.R. Milner Maxim Coal-Fired 143

Source: (AESO 2009)

Figure 3.3: Project Additions Between 1998-2015 as Provided by AESO24

Source: (AESO 2011, CERI)

24

For the years 2011 to 2015, these are proposed projects and not every project approved or proposed may go forward. These numbers are included to give the reader a sense of the shift from coal and fossil fuels towards renewables.

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Figure 3.4: Summation of Proposed Project Additions Each Year Between 1998-2015

Source: (AESO, CERI and Alberta Energy)

Figure 3.5: AESO’s 2009-2029 Long-Term Energy Outlook Generation Mix for 2010 and 2020

Source: (AESO 2010)

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Figure 3.6: Forecasted Electricity Demand Between 2009-2029 (MWe)

Source: (AESO 2010, CERI)

From the proposed additions, one can see that there is a shift towards meeting future demand with renewable and natural gas-fired generation. There is a discrepancy between wind additions (approximately 6,000 MW) between the years of 2011-2015 and forecasted wind capacity for 2020 (approximately 2,500 MW). This is due to the fact that all proposed projects may not necessarily go forward; a certain amount of electricity of one mix ends up being contracted even if multiple projects have been approved. Furthermore, while there has been a

push towards renewables, 1 MW from wind generation is not equivalent to 1 MW from coal

generation because the former, at a 30 percent capacity factor, will generate 2.6 GWh yearly while the latter, at an 85 percent capacity factor, will generate 7.4 GWh yearly. Lastly, the more wind that is included in the mix, the more costly it is to generate electricity. Wind tends to have an approximately 15 percent error between estimates and forecasts, making it difficult to determine when wind should be in the mix. It is possible to include more wind by increasing system flexibility (i.e., regulate more reserve or ramping capacity). However, more coordination between wind and the purchasing of other generators to put wind into the mix can be complicated, and as mentioned previously, more costly (i.e., electricity must be purchased from make-up generators at the market pool price and those generators will run less frequently as they give priority to wind)(Hu 2011). Lastly, ramping up capability largely comes in the form of

natural gas turbines as coal is typically a base load generator, also promoting a shift from coal to natural gas. A comprehensive discussion of wind power into electrical grids and the

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associated electricity cost is given in CERI Study No. 116, The Economics of Significant Wind Power Development in Canada, August 2007.

However, despite the trend towards increased natural gas usage and a shift to renewables, there is still a large piece of the puzzle that is left unresolved in terms of supply and demand. As CCS technologies become cheaper, and more commercially available, it is entirely possible that there could be a renaissance of “clean coal” technologies to make up the base-load. Less probable is the resurgence of nuclear.

Coal-Fired Generation

Coal-fired generation has many advantages for electricity generation in that it is both cheap and abundant within Canada (especially Alberta), and it is a reliable, mature technology that is well understood. Also, many of the current coal-powered plants within Alberta and Saskatchewan are adjacent to coal mines, ensuring a secure, long term supply of coal. Furthermore, coal prices remain relatively stable compared to oil or natural gas prices (Chandler 2011). Historically, coal is best suited for base load generation as it cannot be easily adjusted like hydro or natural gas generation to meet fluctuating demands in electricity. In the past, acid rain from coal-fired generation was a concern, but advanced burner controls have significantly reduced the amount of NOx and SOx emitted through the use of precipitators and scrubbers. Alberta generally has relatively low sulphur coal and alkaline soils, therefore acid rain has not

been an issue in Alberta unlike in the East. Nonetheless, in light of a push towards a low carbon future, emissions from coal power plants have become of increasing concern. Noticeably, the higher greenhouse gas emissions (50-100 percent higher) than its natural gas turbine counterparts as well as the high mercury content from the ashes that transform into the biomagnifying agent methyl mercury have generated criticism and opposition towards coal-fired plants (National Energy Board 2008).

Federally, Canada has committed towards reducing greenhouse gas emissions through the Kyoto Accord. Currently, the federal government plan is that coal-fired generation must have

the same or lower emissions to the equivalent natural gas plant or face retirement. In addition,

plants in operation over 45 years must retire if technological improvements cannot substantially reduce emissions. The deadline to meet these requirements is 2015 (Fekete 2011). Furthermore, there have been radical provincial reforms, namely the phasing out of coal by the Ontario government. In light of increasing political restrictions over coal powered generation as well as the potential of a tax on carbon, many investors have been discouraged from building new coal-fired power plants until technology has economically reached a point where a coal plant emits a similar amount to natural gas.

Despite these dispiriting factors, “clean coal” technology has emerged and continues to advance offering many options for a lower emitting and thus “clean” source of coal-fired generation; this enables the continued usage of coal-fired generation. Most notably are the

advancements within Alberta and Saskatchewan. Alberta built the Genesse 3 unit in Edmonton that was the first in Canada to utilize supercritical-pressure pulverised coal technology.


October 2011

Supercritical pulverized coal (SCPC) reduces fuel consumption by increasing the efficiency of the boiler from the utilization of supercritical water. Alberta will follow Genesse 3 in 2011 with the new Keephills 3 unit (450 MW) using the same technology. Keephills 3 will be retrofitted with chilled ammonia flue scrubbers and commencing in 2015 will transport approximately 1 Mt of CO2 per annum for enhanced oil recovery and permanent sequestration (Chandler 2011). Another major coal generation technology at the forefront is Integrated Gasification Combined Cycle (IGCC) systems (National Energy Board 2008). Deployment of the Swanhills Synfuels In-Situ Coal gasification (ISCG) and Sagitawah power project will produce 300 MW of low emitting fuel for power generation to Albertans and combined CCS with gasification (Swanhills Synfuels 2011). Lastly, in promotion of coal powered generation, Saskatchewan is pursuing CCS by

building an amine post-combustion CO2 capture plant at one 100 MW Unit at the Boundary Dam power plant (National Energy Board 2008).

Coal in Alberta

Alberta coal ranges from lignite through sub-bituminous and bituminous to sub-anthracite,25 with the large majority of it being sub-bituminous. These coals are found in three principle regions: the Mountains, Foothills and Plains. The Plains hold lignite and the large majority of the sub-bituminous coal with the mountains holding the rare sub-anthracite portions, mainly by the town of Canmore (Stephenson, Cameron, Odegaard 2003). Coal (bituminous thermal or metallurgical) from the Mountains and Foothills regions are usually cleaned and exported or

used for industrial purposes such as steel making. Plains coal, which is lower in energy content, is used primarily for electricity generation. It is estimated that about 33.4 GT of coal is remaining. The production of coal in Alberta in 2009 was 78 percent sub-bituminous, 9.3 percent bituminous metallurgical, and 12 percent thermal bituminous. Thermal bituminous has a higher heat content than sub-bituminous and is more economic to transport whereas sub-bituminous coal is utilized for coal-fired generation within Alberta and is an abundant and cheap resource to draw upon (ERCB 2010). Most of the coal is extracted by strip mining but a majority of the coal is too deep for surface mining and may require in situ gasification to be economically extractable.

Disadvantages

While carbon capture and storage has been successfully implemented for projects such as the Weyburn EOR project in Saskatchewan, there has been resistance to CCS on coal powered plants. The main reasons are as follows (Ciferno, Litynski, Plasynski 2010):

1) CCS has not been successfully demonstrated on a conventional power plant 2) Substantial amounts of steam and power are needed to operate the CCS system, which

significantly decreases the power output 3) It is not currently cost-effective to put into operation on power plants

25

Since there are many compositional differences in coals around the world, coal is ranked from the characteristics of heat content, volatile matter, moisture, ash and fixed carbon. In a basic sense the order of ranking from highest to lowest respectively is anthracite, bituminous, sub-bituminous and lignite. These rankings matter because higher ranked coal generally commands a higher market value than lower ranked.


October 2011

However, meeting energy demand without coal could be challenging and some key reasons are as follows:

1) Renewables are a clean source of energy but the current and forecasted capacity is unlikely to meet growing demand

2) Nuclear could meet forecasted demand and would need to be widely proliferated but is within a politically charged arena

3) Natural gas is a cleaner burning fuel but is still a hydrocarbon; furthermore, is there enough of it?

Electricity Generation and Brief Overview of Coal in Saskatchewan

Most of Saskatchewan’s coal is lignite from the Ravenscrag formation with 90 percent used for electricity generation. The remainder is shipped to Ontario and Manitoba for electricity generation. The Boundary Dam mine supplies coal to the Boundary Dam (1973) and Shand (1992) generating stations. The Shand mine also supplies the Shand generating station. The Poplar River mine supplies the Poplar generating station and Bienfait mine supplies coal to the Ontario Power Authority. Coal is also used to make char for barbeque briquettes (Mackenzie 2003).

Electricity Generating Station

Saskatchewan has 3 coal generating stations, 7 natural gas turbines and the remaining generation is composed of wind and hydro. Coal generation capacity makes up 1,664 MW out of the total 3,717 MW installed capacity. Boundary Dam is the largest coal-fired generating station at 824 MW (Canadian Center for Energy Information 2009).

Gasification

Gasification is a mature technology and has garnered attention due to the variety of materials that can be gasified, including but not limited to biomass, asphaltenes, coke, coal, etc. Gasification produces CO, H2, CO2, H2O and CH4, with the composition varying by fuel and by the type of technology used (i.e., water gas shift reactor). One of the most advantageous points

about gasification is that the environmental performance is improved by removal of contaminants which are usually present from the direct combustion of any of the aforementioned fuels. However, the gasification environment is a reducing environment, so any sulphur present within the fuel becomes converted to H2S or carbonyl sulfyl COS species which must be later cleaned out of the syngas. The DOE/NETL has a summary of gasification fuels, processes and their expected products which is summarized in Table 3.6.


October 2011

Table 3.6: Gasification Process, Environmental Controls and Products

Resource Gasifiers Environmental Control

Energy Conversion

Products

Air/Oxygen Coal Biomass Coke Heavy Oil Refinery waste Municipal Solid Waste Orimulsion Other wastes

Oxygen Blown - Entrained Flow - Fluidized Bed - Moving Bed -Transport Reactor Air Blown - Fluidized Bed - Sprouting Bed - Entrained Flow -Transport Reactor

Particulate removal and scrubbers Chloride and Alkali removal Acid gas removal COS hydrolysis Sulphur recovery Water treatment Tail gas treatment Turbine NOx control Syngas mercury capture Syngas CO2 capture

Gas turbine HRSG Steam turbine Boiler Syngas conversion to Fuels and Chemicals Catalytic conversion Shift conversion Fischer-Tropsch Fuel Cell H2 Turbine

Steam Electric Power Liquid Fuels Chemicals Methanol Hydrogen Ammonia/Fertilizers Slag Sulphur/Sulfuric Acid

Source: (Ratafia-Brown and others 2002)

The selection of product and the type of fuel will determine the composition of the gas stream.

For example, hydrogen production will have WGS to convert the CO to CO2 and more H2.

Integrated coal gasification combined cycle (IGCC) has emerged as an alternative to pulverized coal (PC) for power generation. IGCC is the process by which coal is gasified to create syngas to generate electricity or hydrogen. IGCC is more efficient than pulverized coal plants, it can efficiently clean up the gas (particulates, mercury, etc.), has flexibility in fuel use, an ability to clean up CO2 more cheaply and efficiently, can produce pure H2 if needed, and has substantial water consumption reduction (Stiegel, Ramezan, McIlvried). IGCC had taken a back seat because of cheap prices of natural gas but as execution of a low-carbon economy becomes more imminent, IGCC may proliferate. If CO2 capture and storage technologies are employed,

IGCC is one of the most promising and cost-effective companion technologies.


October 2011

Figure 3.7: IGCC Plant


IGCC is not a new technology but there is limited commercial penetration in the market. According to Ordorica-Garcia et al, retrofitting existing gasification plants may be problematic if the plant was not originally designed to support CCS. Required additions would be a WGS to shift the CO to CO2 + H2, an additional Selexol™ unit for CO2 removal, CO2 drying and compression facilities, modifications to the turbine to operate on H2 instead of synfuel, the addition of air compression capacity for an ASU plant, and additional auxiliary load

requirements for plant utilities (Ordorica-Garcia and others 2009).

In Situ Coal Gasification vs. Integrated Gasification Combined Cycle For underground (or in situ) coal gasification (UCG or ISCG), coal is gasified underground by the injection of the steam; in comparison, entrained flow gasifiers require the coal to be mined and fed to an above-ground gasifier. Underground gasification is generating interest because it can take otherwise unrecoverable coal reserves and turn them into the useful product syngas, which, as mentioned above, can be utilized for a wide variety of products. Furthermore, underground coal seams tend to be in close proximity to oil reservoirs and saline aquifers, making transport and storage of CO2 economically attractive (Friedmann, Upadhye, Kong 2009).

The pressure and temperature at which UCG syngas exits the reservoir are similar to that of IGCC gasifiers; consequently, methodologies for power generation and pre-combustion capture are comparable. Some of the contaminants, particularly SOx and Hg, may be precipitated


October 2011

underground but the clean-up of the syngas is similar to that of an entrained flow gasifier in an IGCC plant. The advantage of UCG is that there is a lower auxiliary load requirement on the ASU, which results in a higher net capacity of the turbine; however, for CCS systems the process and energy requirements remain similar (Shaigec 2011).

Lastly, a theoretical advantage of UCG is within deep coal seams (greater than 800m) where the surface pressure of the syngas may exceed that of an IGCC plant. This could be used to drive high pressure processes (i.e.,, methanol generation), or reduce the compression requirements for CO2 transport (Friedmann, Upadhye, Kong 2009). Whether these higher pressures are utilized to generate chemicals, such as methanol, would depend on the demand for such

chemicals as well as the economics of building such a plant.

Gasification of Coke and the Oil Sands

Coke gasification has been examined as a potential fuel source for the oil sands as Syncrude and Suncor both produce and utilize coke from their oil sands operations. Over the years, this stockpile of coke has become significantly large, so processes that can utilize coke in an environmentally acceptable manner are becoming of greater interest. Most of Syncrude’s coke is stockpiled, but Suncor utilizes some coke for steam production in their boilers. Coke has a high carbon content, making it a valuable source of energy for gasification. Like coal gasification, coke gasification could be used for the creation of both electricity and hydrogen.

The high carbon content of the coke makes burning it akin to burning anthracite, except for sizeable sulphur emissions, as coke generally has 5-7 percent sulphur content compared with 1-3 percent for coal (Furimsky 1998). Furthermore, as sulphur is removed by use of a solvent or catalyst, the H2 and CO concentrations and CO2 content decreases (Watkinson, Cheng, Fung 1989).

Coke is not the only by-product of oil sands production: another high carbon product without commercial value is asphaltenes. Currently, Opti-Nexen has constructed a fully integrated in situ and upgrading facility which is fueled by the gasification of asphaltenes. Gasification is used

to create hydrogen for upgrading and synfuel for power and steam production. Currently, there

is a sulphur recovery unit (SRU) that utilizes Selexol™ and a pressure swing absorption (PSA) unit. The PSA is utilized to recover hydrogen for upgrading; the remaining syngas is used as fuel for the operation with no shift reaction to convert the CO to H2. Since CO and H2 have similar heating values, the variation in composition does not affect the injection into the turbine. Ordorica-Garcia et al recommend that a future CCS unit be placed after the sulphur clean up unit to prevent larger gas flows into the SRU (Ordorica-Garcia and others 2009). Table 3.7 compares the emissions associated with gasifying different sources for upgraders within the oil sands.


October 2011

Table 3.7: Comparison of Emission Factors for Gasification of Coke and Asphaltenes

Project Type Emission Factor (EF)

natural gas (T CO2eq/bbl)

coke gasification no CCS (T CO2eq/bbl)

asphaltene gasification no CCS (T CO2eq/bbl)

Non-integrated Upgrader

0.06 0.1 0.09

Integrated Upgrader 0.09 0.16 0.14


-- 0.22 0.2

Source: (CERI)

Methodology

There are numerous possibilities to explore in CCS and for this study the focus is on MEA, KS-1 and chilled ammonia for chemical solvents. Selexol™ was selected to represent physical solvents. These processes were selected because of their widespread applicability as well as they are the most commonly investigated processes worldwide. MEA was given only a cursory review as several more efficient processes are on the forefront. Chilled ammonia was included because it was the solvent of choice for installing a post-combustion unit by TransAlta at

Keephills 3 (TransAlta 2009). KS-1 was selected as it represents hindered amines as well as is becoming a solvent of choice to replace MEA systems. KS-1 is also represented in a previous CERI study (SNC Lavalin 2002). The 2002 numbers were updated from the Mitsubishi Heavy Industries website on the KS-1 process to reflect efficiency gains since that time. If the reboiler requirements per tonne captured were available for the process, the energy for regeneration of the solvent was directly calculated. Compression power requirements were calculated for a stream, assuming 99.9 percent CO2 from equations present in the appendix.

In most cases there is not enough data to properly estimate additional auxiliary load requirements and power consumption from the CCS plant, so default values were assigned after evaluation of papers with simulated coal plants with CCS that possessed similarities to the

unit of interest. There were several reasons for estimating this. The most important reason was that it is difficult to estimate the loading factor of the solvent since the solubility of CO2 varies with the composition of the solution, temperature and partial pressure of CO2. Therefore, without proper simulation of the operating characteristics, it is difficult to determine how much fluid needs to be pumped through the system and to estimate the associated heating/cooling requirements. However, it cannot be stressed enough how much the efficiency of the system depends on reducing regeneration energy and pumping less solvent solution through the system (i.e., faster and better rates of transfer).

The chemical solvents are compared first and then the KS-1 solvent is used for abatement

potential calculations. KS-1 is utilized because it is more efficient than MEA and has the most


October 2011

data attributed to it. Chilled ammonia processes seem promising but there is no consistent data on which to base the calculations.

Power Requirements for Carbon Capture as Calculated for Electricity Generation by Coal

Chemical Solvents

Table 3.8 is a summary of the power requirements to run sub- and super-critical coal-fired

generation.


October 2011

Table 3.8: Comparison of Chemical Solvents on Power for Coal, Post-Combustion

Base SCPC

MEA SubCPC

26

MEA SubCPC

27

MEA SCPC

28

KS-1 SCPC

Chilled Ammonia SCPC

29

Chilled Ammonia SCPC

30

Power no CCS (MWe) 450 798 450 450 450 500 450

Auxiliary power load31

(MWe)

47 25 25 25 2632

2533

Reboiler (GJ/tonne CO2 captured)

3.6 3.6 3.6 2.8 N/A 2.05

CO2 emitted no CCS (Mt/yr)

3.1 N/A 3.5 3.1 3.1 N/A 3.1

CO2 captured (Mt/yr) -- N/A 3.1 2.8 2.8 N/A 2.8

Regeneration Power lost (MWe)

-- 335 172 172 109 N/A 111

Utility Consumption (MWe)

34

-- 8.7 6 6 6 N/A 6

Efficiency Plant after Capture

0.385 0.2006 0.21 0.24 0.27 N/A 0.29

Compression Power Requirements (kWhe/tonne captured)

-- 73.1 75 75 75 N/A 75

Efficiency Plant after compression

-- 0.1767 0.19 0.21 0.24 N/A 0.27

Power output CCS (MWe) 450 454 247 255 287 415 311


Note: Sub-bituminous coal is assumed except for Rhudy et al., for the chilled ammonia process which is unknown. It is assumed that coal plants operate 315 days of the year.

26

(Sanpasertparnich and others 2010) 27

Procedure for sub-critical plant to estimate how well methodology is holding up to reported values. 28

Results as estimated from using equations from KS-1 process for a 450 MWe plant supercritical pulverized coal plant. 29

(Rhudy and Black 2007) 30

(Darde and others 2009) 31

Auxiliary load in this case refers to estimated additional power requirements based on papers revealing approximately a 5 percent increase in plant use power, and this number does not include power requirements for amine pumps and the capture unit specifically. 32

As reported from their presentation. 33

Darde et al. only provided a regeneration energy capability and do not take into account effects of refrigeration. CERI estimates that the process which increases pressure, thus reducing final compression requirements, is offset by mechanical requirements of compression for refrigeration of the flue gas and ammonia. Mathias et al. (Mathias, Reddy, O’Connell 2010)suggest that the energy requirements for refrigeration exceed the energy bonus from reduced final compression requirements. Furthermore, depending on the composition of the rich-CO2 loading component and the composition of the ammonia solution the regeneration energy may vary considerably. The regeneration value utilized is 2.05 GJ/tonne CO2 captured which is for a solution of 28 percent mass ammonia fraction and a rich-CO2 loading factor of 0.67. Consequently, the number may be an under(over)estimation of the true losses in efficiencies since the additional mechanical requirements cannot be accounted for and was the best that could be done with the available data. 34

Utilized 6 MWe for the KS-1 as this is the number reported in CERI’s 2002 report.


October 2011

Physical Solvents

Physical solvents require higher pressures and the aforementioned IGCC and gasification plants are the major candidates for applicability. Given the variability in gasification technologies, studies done by the NETL were utilized for parameters on CCS abatement potential. Maurstad et al. determine that coal rank matters for slurry-feed technologies but not for dry-feed entrained flow. This is because the high moisture content and lower heating value in lower ranked coals require more auxiliary power to run the slurry feed. In contrast, the drying procedure in dry-feed results in almost no effect between coal rank and output and associated emissions. Consequently, the Shell IGCC system is utilized as representative for IGCC technologies and the data from the NETL 2011 paper on IGCC for low rank sub-bituminous coal

is used. Table 3.9 summarizes the results for power requirements on an IGCC system with and without CCS.

Table 3.9: Efficiencies as Modified by the NETL 2011 Study to Reflect a 450 MW Gross Output

Plant

Plant Shell IGCC Shell IGCC Shell IGCC

Technology Entrained-Flow Entrained-Flow Entrained-Flow

Type Dry-Feed Dry-Feed Dry-Feed

Fuel Lignite Sub-bituminous Bituminous

Heating value w/o CCS (kJ/kWh)

8605 8563 8719.5

Heating value w/ CCS (kJ/kWh)

11365 11227 11207.7

Steam turbine output (MWe) w/o CCS

269 273 280

Gas turbine (MWe) w/o CCS

181 176 171

Steam turbine output (MWe) w/ CCS

273 278 279

Gas turbine (MWe) w/ CCS

153 150 138

Gross Power w/o CCS 450 450 450

Gross Power w/ CCS 427 429 417

Net Power w/o CCS 369 370 382

Net power w/ CCS 299 304 311

Efficiency w/o CCS 0.418 0.42 0.411

Efficiency w/ CCS 0.317 0.321 0.32

Mt CO2/year w/o CCS 2.26 2.13 2.21

Mt CO2/year w/ CCS 0.226 0.213 0.221

EF w/o CCS T/MWh 0.87 0.83 0.83

EF w/ CCS T/MWh 0.11 0.10 0.10

Source: (CERI and NETL 2011)


October 2011

Capital Costs Associated with CCS and Other Electricity Generating Technologies There is no doubt that the deployment of CCS is on the high-end of electricity cost whether one goes down the post-combustion capture route for coal or through gasification. In 2009 the Portlands Energy Center was built in Toronto and was a natural gas cogeneration plant for 550 MW that cost $733 million dollars (Anonymous). In contrast, SaskPower is proposing to retrofit approximately 100 MW on its boundary dam plant at a cost of $1.5 billion over 7 years (MIT 2011). For IGCC without CCS, Duke Energy is commissioning a 618 MW plant at a cost of $2.88 billion, of which $460 million was awarded from the government (Duke Energy). It is currently significantly more expensive to deploy CCS and this will likely act as a barrier for uptake of CCS

until costs at a commercial scale are considerably lowered.

Concluding Remarks The high capital and energy costs of deploying CCS create a significant barrier to its. A majority of oil sands emissions in the future are a result of in situ operations which are the hardest to capture and sequester, not just from a technical stand-point, but also from an economic one. For power generation, there are still significant energy losses (~30 percent loss) to the capture and compression process. CERI believes that significant investment in research to improve and perfect the CCS process is needed before it can be implemented on a widespread commercial scale. Since hydrogen plants supply the most concentrated form of CO2 in oil sands operations,

upgraders seem like a reasonable candidate to begin to refine and improve the CCS process. Lastly, CERI believes that CCS is needed to create long-term reductions in emissions as efficiencies in hydrocarbon based machinery are thermodynamically limited. Research is needed to improve OxyFuel based systems, to develop lower energy intensity solvents, to reduce the energy requirements of compression and lastly, if possible, to determine if capture from mobile sources, such as vehicles, are possible. Moreover, CCS must be viewed as competing with efficiency-improving strategies as the enormous capital investment for commercial scale CCS systems favours efficiency enhancement and fuel substitution (i.e.,

natural gas turbines over SCPC units with CCS). Further study is needed to determine feasibility

and what conditions favour CCS over alternative technologies.


October 2011

Chapter 4 Emission Abatement Potentials Reference Case for Oil Sands

The reference case was generated by multiplying the Chapter 2 emission factors with the barrels of raw bitumen produced from the CERI 2010 Oil Sands Report realistic scenario which was broken down by technology type. There is some variability in the values of the EF depending on the assumptions made about the composition of the fuel combusted. As stated

previously, most IPCC default values were utilized; however, depending on the carbon content and the liquids content for natural gas, the variability could be as high as 20 percent. Since the projection is extremely sensitive to the EF it is possible that the true value may be lower or

higher than the above-mentioned coefficients. Furthermore, some of the projects coming online in 10-15 years may or may not proceed and therefore the uncertainty of the projection increases with time.

Figure 4.1: Realistic Scenario of CERI Production on a Total Raw Bitumen Produced Basis, 2008-2035

Source: (CERI 2010 Oil Sands Supply Outlook)

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

5,000

2008 2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030 2032 2034

Pro

du

ctio

n (

00

0 b

bl/

d)

Year

In Situ

Mining


Int Upgrader


October 2011

Figure 4.2: Reference Case Projection of Emissions from the Oil Sands, 2008-2035

Source: (CERI)

The jump in production from 2009 and 2010 reflects the change from the use of historical to the beginning of CERI’s forecast period. Historically, for the year 2010, certain projects did not proceed at full capacity due to various mechanical problems (i.e., boiler breakdowns, etc.). These are not reflected in the model as the model assumes all projects are fully operational.

Furthermore, two major mining projects came online which added significant capacity.

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. Integrated Upgrading In Situ is a high value (22 Mt) because gasification of heavier hydrocarbons emits almost double the CO2eq unit of output compared to what natural gas combustion emits; without carbon capture and storage (CCS), gasification becomes a significant emitter over time as production increases. Table 4.1 summarizes the emissions in each sector for the years 2009, 2020 and 2035.

0

20

40

60

80

100

120

140 C

O2

eq

in M

T

Year

ET-DSP

COGD

THAI

SAGD/ES-SAGD

SAGD

LP-SAGD

HCS

Vertical Steam Drive (VSD) / CSS

CSS/SAGD

CSS, LASER & CSP

CSS

Mining


Int Upgrader

Non-IntUpgrader


October 2011

Table 4.1: Emissions of the Oil Sands Sectors for the Years 2009, 2020 and 2035 Using CERI’s Realistic Scenario Projection Estimates

Sector Emissions CO2eq (Mt)

200935 2020 2035

Stand-Alone Upgrading 10 11 15

Integrated Upgrading 11 27 30

Integrated Upgrading In Situ

4 15 22

Mining36 2 14 14

All In Situ Projects 12 22 47

Source: (CERI)

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. 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 the 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 as oil sands production is enlarged. Lastly, these technologies must still be affordable to implement as the oil sands is already a riskier venture with a lower profit margin than conventional oil production.

In situ is seeing decreasing energy intensity per barrel of bitumen produced (CAPP reports a 39 percent decrease in energy intensity since 1990). Contemporary technologies/drilling methods have reported emission factors as low as 0.03 T CO2eq/bbl compared to historical values around 0.06-0.1 T CO2eq/bbl; therefore, as long as extraction of oil from reservoirs does not

become increasingly difficult, there is a potential to decrease more than half of the total emissions on a per barrel basis for in situ operations from the oil sands region. From the CERI 2010 production estimate, projects that are part of the classic technologies make up approximately 44 Mt of the 47 Mt CO2eq for the year 2035. This creates at most approximately 20 Mt CO2eq of abatement potential by converting to less energy intensive technologies. However, this amount of abatement by technology switching alone would not be sufficient to reduce GHG emissions below 2005 levels because the oil sands industry is a rapidly growing arena with production expected to potentially triple within the next 20 years. Also, it is unlikely

35

These values are not the NIR values but the calculated values from the CERI emission factor coefficients and therefore some discrepancy is expected. 36

Mining for this table are for stand-alone mining projects with the remainder incorporated in Integrated Upgrading.


October 2011

without a lower-emitting way to produce the thermal energy required for viscosity reduction that this full potential will be realized as more viscous, or lower-net-pay zone, reservoirs are produced. Gasification could potentially supply an alternative fuel source but it must be retrofitted with CCS technology in order to have lower emissions than natural gas usage. CCS also has potential for applying OxyFuel combustion to natural gas boilers but so far is expensive to deploy. Significant incentives would be needed to implement CCS.

Mining and upgrading have the potential to decrease energy intensity through improved solvent usage and improved conversion techniques. Hydrogen production from the Benfield process is a cheap yet effective way of capturing carbon as steam methane reforming produces

steam and CO2, of which the steam needs to be condensed; consequently the highly pure CO2 is ready for transportation. PSA for hydrogen production is another easy way to capture CO2 provided it is not costly to build the plant. Gasification also has potential in this arena for energy and hydrogen requirements, but like in situ, must be installed with CCS equipment in order to be a lower-emitting alternative to steam-reforming of natural gas. Gasification also has benefits because low ranked fuels (coke, asphaltenes, etc.) can be utilized and the process can clean up impurities and hazardous substances that would significantly reduce emissions of criteria air contaminants (CAC) compared to direct combustion of these fuels. 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.

Table 4.2 summarizes emissions from the utilization of different fuel sources for gasification and how they compare to a CCS emission and the current emissions from upgraders.

Table 4.2: Comparison of Emission Factors for Gasification of Coke and Asphaltenes

Project Type

EF (Emission Factor)

Natural gas (T CO2eq/bbl)

Coke gasification no CCS (T CO2eq/bbl)

Asphaltene gasification no CCS (T CO2eq/bbl)

H2 Plant w/ CCS (T CO2eq/bbl)

Coke gasification w/CCS (T CO2eq/bbl)

Asphaltene gasification w/ CCS (T CO2eq/bbl)

Stand alone Upgrader

0.06 0.1 0.09 0.03 0.01 0.009

Integrated Upgrader

0.09 0.16 0.14 0.06 0.016 0.014


-- 0.22 0.2 -- 0.022 0.02

Source: (CERI)


October 2011

Table 4.3: Possible Abatement Potentials for the Year 2035 if Energy Efficient Technologies and Some CCS are Utilized Between 2011-2035

Project Type Reference 2035 Emission (Mt CO2eq)

Emissions with extensive proliferation of technologies in 2035 (Mt CO2eq)

Abatement amount 2035 (Mt CO2eq)

Stand alone Upgrader 15 7 8

Integrated Upgrader 30 20 10


22 2 20

Mining 14 14 0

In Situ 47 3037 17

Source: (CERI)

Table 4.3 summarizes the possible emissions if widespread utilization of lower emitting technologies, excluding CCS, that are at least within the pilot stage are utilized. Without extensive utilization of CCS in the in situ, the total abatement potential for emissions within the year 2035 is approximately 60 Mt. This still results in emissions above the 2005 targeted level, and although this abatement estimate has a high degree of uncertainty, it does demonstrate a potential to reduce emissions significantly within the oil sands industry.

Electricity Generation

Coal faces a largely uncertain future as more stringent GHG controls are put into effect. However, there are also difficulties in installing large amounts of wind and CCS controls. Natural gas is a reliable alternative to coal but will eventually face GHG restrictions itself. Investment into CCS could be beneficial and promote a renaissance of clean coal technologies; in the process it would utilize Alberta and Saskatchewan’s abundant coal reserves. Building supercritical to ultra-supercritical coal plants results in decreased emissions (~10-20 percent Supercritical, ~30 percent Ultra-supercritical), but these emissions are still higher than the newest generation of combined cycle technologies using natural gas (more than 50 percent

lower). However, it is easier to implement CCS on coal plants, which could result in greater emission reductions (more than 85 percent). 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 result in increases in electricity prices to support the elevated regulated reserve required to ramp up and down as conditions change.

37

The value is different from the 26 Mt reported earlier as 26 was the maximum and in this case we have not assumed that all projects were capable of meeting this emission amount. Also CCS for boilers has not been included in this abatement amount but could significantly contribute to the reduction.


October 2011


October 2011

Chapter 5 Concluding Remarks Reduction of GHG is a complex area involving technical expertise with a need for social acceptance of alternatives and political support/incentives to promote lower emitting technologies. The oil sands industry has significantly decreased energy intensity in recent years and has the potential to decrease energy inputs further but is still unlikely to meet a below-2005 target for 2020 GHG emissions.

For CCS it is preferable to capture highly concentrated CO2 streams at high pressures, and there is a potential to perfect the technology on easy-to-capture sources prior to large scale implementation on power plants. Moreover, CCS is expensive both financially and in energy utilization. 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, public acceptance is required for CCS, with safety being a key priority towards gaining trust. Nevertheless, CCS remains at the forefront of technologies capable of achieving long-term significant reductions in GHG emissions.

Most studies examine the power loss and cost for a maximum abatement of CO2 for CCS equipment. However, partial loads of CO2 capture (i.e., 70 percent rather than 90 percent) may prove to be a more economically viable alternative. This could be coupled with ramping up capability of CCS as taxation or GHG reduction criteria are met.

Advancements in technology have the added benefit of decreasing other hazardous air contaminants (i.e., clean-up for gasification of coke and asphaltene). Lastly, there is an abundance of technological options to improve energy intensity and decrease emissions.


October 2011


October 2011

Appendix A Technical Components of Equations of Processes and Methodologies The projects used to estimate the default emission factors are:

Operation Projects

Mining Shell Albian Sands, Shell Jackpine, Syncrude Aurora

Integrated Mining & Upgrading CNRL Horizon, Syncrude Mildred Lake, Suncor OSG

Upgrading w/o gasification Total’s EIA application

Upgrading w/ gasification North West Upgrading’s EIA Application

Integrated In Situ & Upgrading Nexen/Opti Long Lake 2010 values

In Situ w/o Cogen SAGD Suncor Firebag, Cenovus Christina Lake, Cenovus Foster Creek, Conoco Phillips Surmont

In Situ w/ Cogen SAGD Suncor Firebag

In Situ CSS Imperial Cold lake, CNRL Primrose

Source: (Various sources of company and ERCB applications)

The Equation for Total Energy Requirement for the SOR’s was as follows:

Equation 138:

Equation 2:

38

The kg in this equation is per kg of steam which was then later converted to barrels


October 2011

Equation 3:

Equation 4:

Equation 5:

Equation 6:

=

Equation 7:

Amine Reaction Mechanisms (Kidnay and Parrish 2006):

CO2 + H2O <-> H2CO3 (carbonic acid)

H2CO3 <-> H+ + HCO3- (bicarbonate)

H+ + R1R2R3N <-> R1R2R3NH+

CO2 + H2O + R1R2R3N <-> R1R2R3NH+ HCO3-

Or

CO2 + R1R2NH <-> R1R2NH2+HCOO-

R1R2N+H COO- + R1R2NH <-> R1R2NCOO-+ R1R2NH+

CO2 + 2 R1R2NH <-> R1R2NH+ R1R2NCOO-


October 2011

The second reaction mechanism is the carbamate formation reaction which only occurs with

primary and secondary amines and is faster than the first reaction mechanism of hydrolysis.39

Ammonia Reactions (Sherrick and others 2008):

CO2 (g)<-> CO2 (aq) (1)

(NH4)2CO3 (aq) + CO2 (aq) + H2O (l) <-> 2(NH4)HCO3 (aq)

(NH4)2CO3 (aq) <-> (NH4)HCO3 (s)

(NH4)2CO3 (aq) <-> (NH4)NH2CO2 (aq) + H2O (l)

The ammonia process is hindered by the fact that the hydrolysis of CO2 is a slow reaction. This

problem can be overcome by increased turbulence of the liquid portion to increase the

efficiency of absorption (Kohl and Nielsen 1997).

IGCC Equations and Enthalpies (Stiegel, Ramezan, McIlvried )40:

C + O2 CO2 ΔHr = -393.4 MJ/kmol (1)

C + ½ O2 CO ΔHr = -111.4 MJ/kmol (2)

C + H2O H2 + CO ΔHr = 130.5 MJ/kmol (3)

C + CO2 <-> ↔ 2CO ΔHr = 170.7 MJ/kmol (4)

CO + H2O ↔ H2 + CO2 ΔHr = -40.2 MJ/kmol (5)

C + 2H2 CH4 ΔHr = -74.7 MJ/kmol (6)

39

In reality the chilled ammonia process actually has quite a complicated equilibrium and phase system. There is the equilibrium for speciation, the vapour-liquid equilibrium, and lastly the liquid-solid equilibrium. The equations presented above are a generalized version of this system. 40

The gasification chemistry is quite complex and these equations are representative of the major reactions that take place.


October 2011

Table A.1 Chemical Composition of Syncrude and Suncor Coke41

Element Syncrude Suncor Coal Lignite North Dakota

Coal Sub-Bituminous Montana

Coal Bituminous Illinois

Coal Anthracite Ruhr Germany

Carbon 83.74 84.90 71 76.4 78.4 91.8

Hydrogen 1.77 3.93 4.3 5.6 5.4 3.6

H/C 0.25 0.55 -- -- -- --

Nitrogen 2.03 1.32 1.1 1.7 1.4 1.4

Sulphur 6.52 6.02 0.4 1.4 4.9 0.7

Oxygen 0.88 0.73 23.2 14.9 9.9 2.4

Source: (Furimsky 1998).

*Note: Mass percentage of coal calculated on analysis of the coal ignoring water content.

Table A.2: Dry Mole Percentage Composition

Stream Raw Syngas

Sweet Syngas

Shifted Syngas

Clean Syngas

Fuel Syngas

Fuel Syngas no Shift

H2 38.6 39.8 59.2 87.8 82.2 13.8

CO 51.4 52.9 3.6 4.8 7.0 75.7

CO2 7.1 5.7 36.1 5.6 8.1 8.1

H2S 1.6 0.5 0.3 0.5 0.7 0.7

Ar 1.0 1.0 0.7 1.1 1.6 1.5

CH4 0.2 0.2 0.1 0.2 0.3 0.3

Source: (Ordorica-Garcia et al. 2011)

Compression Equations:

Isothermal Work done on an ideal gas (it is assumed there is a cooling system to take away the

heat of compression in order to prevent adiabatic expansion):

Ws = -RT ln (P1/P2)/MW

R is the ideal gas constant

T is the temperature

P is the pressure

MW is the molecular weight of the gas.

41

Coal statistics taken from book Gasification (Higman and van )


October 2011

The general equation of power requirements for centrifugal compressors:

Power = mhis/ƞis where h is the isentropic head given by h= -zavgws

ƞ is the isentropic efficiency which was assumed to be 75%

z is the average compression factor for CO2 for the change in Pressure

m is the flow rate of the gas.

Power mechanical losses: (Power calculated)^0.4


October 2011


October 2011

Glossary Benfield Process: The utilization of hot potassium carbonate (K2CO3) to remove CO2 and H2S

and was developed by the United States Bureau of Mines.

Carbon Capture and Sequestration/Storage (CCS): A system of capturing and storing carbon

emissions and is a means of mitigating emissions that contribute to global warming.

Carbon Dioxide Equivalent (CO2eq): A measurement of the magnitude of global warming

potential a greenhouse gas may have as expressed as the equivalent amount of CO2 emissions.

Criteria Air Contaminant (CAC): The class of air pollutants that cause smog, acid rain, and are

hazardous to health.

Enthalpy (Latent Heat): A thermodynamic equivalent referring to the total heat content with a

system.

Entropy: A thermodynamic equivalent of the randomness of a system.

Fingering: The occurrence of injected fluids by-passing the sections of the reservoir resulting in

no-contact between the fluids and the reservoir.

Global Warming Potential (GWP): Is a relative measure of how much a given mass of

greenhouse gas contributes to heating of the earth.

Greenhouse Gas (GHG): A gas that can absorb infrared radiation and thus has the potential to

warm up the earth via the greenhouse effect.

Head Pressure: The vertical lift in height (usually measured in units of water), which resists a

pumps ability to move the fluid to the point that the pump can no longer exert enough pressure

to move the fluid.

Heat Content: A thermodynamic quantity that expresses the internal energy of a system times

the pressure and volume of that system.

Karst Formation: An area where erosion has produced irregular limestone that is quite uneven

and soluble and abundant in sinkholes or other cavernous features.

Megawatt Electric (MWe): The electric power capability of a plant.

Megawatt Thermal (MWth): The thermal power capability of a plant (i.e., steam that is then

used in a turbine to generate MWe).


October 2011

Pressure Swing Absorption (PSA): A technology that separates gases by exploiting their

preferential adsorption to materials at different pressures.

Sensible Heat: Energy exchanged within a system as a result of changing temperatures but the

phase remains the same.

Solvent: A solid, liquid or gas that dissolves another solid, liquid or gas to create a solution.

Steam Methane Reforming (SMR): A process that produces hydrogen by reacting steam with

fossil fuels at high temperatures.

Supercritical Fluid: A fluid that is above its critical point in temperature and pressure.

Water Gas Shift Reaction (WGS): A chemical reaction of carbon monoxide with water to

produce carbon dioxide and hydrogen.


October 2011

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