The CANiCAP Program
Planning Options for Technology and Knowledge Base Development for the Implementation of
Carbon Capture and Transportation Research, Development and Deployment in Canada
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Prepared by:
Bill Gunter, Alberta Research Council Inc.
Bob Mitchell, Inspired Value Inc.
Ian Potter, Alberta Research Council Inc.
Brent Lakeman, Alberta Research Council Inc.
Sam Wong, Alberta Research Council Inc.
With input from
Bill Pearson, Natural Resources Canada
Murlidhar Gupta, Natural Resources Canada
Doug Macdonald, SNC Lavalin Inc.
Copyright © April 2005
Planning Options and Concepts for the Evolution of Carbon Capture and Transport Research in Canada
NOTICE
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This Report was prepared as an account of work conducted at the Alberta Research Council
Inc. (“ARC”) on behalf of Alberta Environment (“AENV”). All reasonable efforts were made
to ensure that the work conforms to accepted scientific, engineering and environmental
practices, but ARC makes no other representation and gives no other warranty with respect to
the reliability, accuracy, validity or fitness of the information, analysis and conclusions
contained in this Report. Any and all implied or statutory warranties of merchantability or
fitness for any purpose are expressly excluded. AENV acknowledges that any use or
interpretation of the information, analysis or conclusions contained in this Report is at its own
risk. Reference herein to any specified commercial product, process or service by trade name,
trademark, manufacturer or otherwise does not constitute or imply an endorsement or
recommendation by ARC.
•
Any authorized copy of this Report distributed to a third party shall include an
acknowledgement that the Report was prepared by ARC and shall give appropriate credit to
ARC and the authors of the Report.
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Copyright ARC 2005. All rights reserved.
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Acknowledgements: This report was prepared after extensive discussions, one on one, with
industry and government. The opinions presented in this report reflects the authors viewpoint
based on these meetings but do not necessarily reflect the viewpoint of the people listed below
who were interviewed. Discussions were held with Bill Pearson & Murlidhar Gupta (NRCan);
Soheil Asgarpour (Alberta Energy); Doug Macdonald (SNC Lavalin); John Barrie (Fluor);
Jim Provias, Cal Coulter & Steven Kaufman (Suncor); Bob Stobbs (SaskPower); Malcolm
Wilson (University of Regina); David Keith (University of Calgary); Ken Brown (Geological
Storage Consulting); Bob Taylor (Infinite Scope Management); Ronnie Sadorra (Shell); Bill
Richards (Nova Scotia Power); Ron Steffan (Nova Chemicals); Eddy Isaacs & Duke
DuPlessis (AERI); Michelle Heath & Collin Heath (CO2hub); Keng Chung (Syncrude);
Elizabeth Siarkowski, Stephen Clark & Robert Craig (TCPL); Paul Clark, Don Wharton &
Ariel Goldenburg (TransAlta); Stefan Bachu (AEUB—AGS); Keith Rivers (Babcock and
Wilcox); Blair Seckington (OPG); Jim Bertram & Pat Greenaway (KeyEra); Rick Hyndman
(CAPP); Dave Podgurny, Bruno Sanelli and Dave LeBlanc (Air Liquide); Brad Anderson
(Alberta Chamber of Resources); Andre Plourde (University of Alberta); Alex Gorodetsky &
Robert Engler (Luscar); Gareth Crandall (Purvin & Gertz); David Hughes (Geological survey
of Canada); and Floyd Wist, Saskatchewan Industry and Resources.
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EXECUTIVE SUMMARY
CANiCAP has a double entendre. “CAN i CAPture CO2” is directed at the non-governmental (NGO)
community and is meant to address environmental issues and consequences. The “CANada innovation
(CO2) CAPture” program focuses on identification of technology systems that are or may be capable
of delivery of CO2 in a concentrated form that renders it readily useable, transportable and storeable;
and a business plan to put them in place. Both goals are embodied in CANiCAP.
The impetus for this document grew from the companion report CANiSTORE. Together, CANiCAP
and CANiSTORE are intended to be the two technology pillars that the Canadian Roadmap for CO2
Capture and Geological Storage rests on. The CANiSTORE report proposes a plan for the
implementation of Geological Storage in Canada (issued in April, 2004 and is available from the
website “www.co2network.gc.ca”). This CANiCAP report is a strategic document that proposes a plan
for the commercialization of CO2 Capture in Canada based on evolving technologies and technology
systems. The infrastructure of CANiCAP is based on the prediction of large industry evolution over
the next 30 years.
The document reported herein represents a culmination of both provincial, national and international
review documents, and valuable feedback from an initial Straw Dog on CO2 capture and transport
(based on discussions with over 25 companies from across Canada).
The main part of the report outlines a pathway for CO2 capture and transport research in Canada based
on research, piloting, commercial demonstrations and expanded commercial projects, and the
construction of a CO2 backbone pipeline connecting large CO2 emission hubs. This is driven by the
need for hydrogen for upgrading of the oil sands and the need for reduction in CO2 emissions across
Canada by CO2 Capture and Geological Storage (CCS). Financial projections and more detailed parts
of the plan are contained in the appendices (i.e. A: CO2 Emission hubs across Canada and the
Proximity of Geological Sinks; B: CO2 Capture Technologies and Capture Opportunities C:
Economics of CO2 Capture from Power Plants considering Near Term to Longer Term Breakthrough
Technologies; D: A Selection of International Activities Related to Carbon Capture; E: Opportunities
at Oil Sand and Heavy Oil CO2 Emission hubs; F: Opportunities at Electricity CO2 Emission hubs; G:
Opportunities at Petrochemical CO2 Emission hubs; H: Opportunities at Multi-Industrial CO2
Emission hubs; I: Off-Gas from Oil Refineries and Bitumen Upgrading; J: Opportunities for a CO2
Backbone Pipeline; J: A “BallPark” Financial Plan for Implementation of CCS in Canada).
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Table of Contents
NOTICE....................................................................................................................................................i
EXECUTIVE SUMMARY .....................................................................................................................ii
INTRODUCTION ................................................................................................................................... 1
Carbon Dioxide Capture in Canada..................................................................................................... 2
Objective of CANiCAP Report........................................................................................................... 2
CANiCAP Technology Goals and Co-Benefits .................................................................................. 3
CANiCAP Linkages............................................................................................................................ 4
Vision .................................................................................................................................................. 5
Mission ................................................................................................................................................ 5
Values.................................................................................................................................................. 6
Strategic Goals .................................................................................................................................... 6
Measures of Success............................................................................................................................ 6
Strategic Objectives............................................................................................................................. 7
The Opportunity .................................................................................................................................. 7
BUSINESS PATHWAYS ....................................................................................................................... 8
Relationship between CANiCAP and Industry ................................................................................. 10
Business Objectives and Guiding Principles..................................................................................... 11
Business Context and Critical Factors............................................................................................... 12
Strategic Themes ............................................................................................................................... 12
Risk Management Plan...................................................................................................................... 13
TECHNICAL PATHWAYS ................................................................................................................. 13
Research and Development ............................................................................................................... 14
Capture Technology Options and Time Frames for CO2 Capture ................................................ 14
Capture Systems............................................................................................................................ 15
Environmental Compliance........................................................................................................... 16
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Compression and Pipelining ......................................................................................................... 17
Hub Pilot and Demonstration Projects .............................................................................................. 17
Oil Sand/Heavy Oil Hubs ............................................................................................................. 19
Electricity Hubs ............................................................................................................................ 19
Post Combustion CO2 Capture ................................................................................................. 19
IGCC and Hydrogen Manufacture............................................................................................ 20
Oxy-Fuel................................................................................................................................... 21
Multi-Industry Hubs...................................................................................................................... 21
Petrochemical Hubs ...................................................................................................................... 22
Polygeneration Hubs ..................................................................................................................... 23
Pipelines........................................................................................................................................ 23
Education and Outreach .................................................................................................................... 24
CLOSING STATEMENT ..................................................................................................................... 24
RECENT COMPLIMENTARY INFORMATION SOURCES ............................................................ 25
APPENDIX A - CO2 EMISSION HUBS ACROSS CANADA AND PROXIMITY OF
GEOLOGICAL SINKS (ONSHORE AND OFFSHORE).................................................................... 27
Overview of CO2 Emissions Sources:............................................................................................... 27
Forecasted Emissions Growth....................................................................................................... 28
Facility Specific GHG Emissions ................................................................................................. 28
Continental Sources ...................................................................................................................... 31
Geologic Storage Opportunities ........................................................................................................ 32
Continental Opportunities for Geologic Storage........................................................................... 32
National Opportunities for Geologic Storage ............................................................................... 33
Provincial Opportunities for Geologic Storage............................................................................. 34
Conclusions ....................................................................................................................................... 35
APPENDIX B: CO2 CAPTURE TECHNOLOGIES AND CAPTURE OPPORTUNITIES ............... 37
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CO2 Capture Technologies................................................................................................................ 37
Absorption..................................................................................................................................... 38
Chemical absorption ................................................................................................................. 40
Physical absorption................................................................................................................... 44
Hybrid absorption processes..................................................................................................... 44
Technology development trends in solvent absorption ............................................................ 45
Adsorption..................................................................................................................................... 45
Membranes.................................................................................................................................... 46
Gas separation membranes ....................................................................................................... 47
Gas absorption membranes....................................................................................................... 49
Cryogenic (low temperature distillation) ...................................................................................... 51
CO2 Capture Opportunities in Canada .............................................................................................. 52
Electricity Generation ................................................................................................................... 52
CO2 capture opportunities in non power-sectors........................................................................... 53
Iron and steel production .......................................................................................................... 53
Cement production.................................................................................................................... 55
Hydrogen/Ammonia production ............................................................................................... 56
Natural gas processing.............................................................................................................. 57
Oil refining ............................................................................................................................... 58
CO2 capture costs for various sectors............................................................................................ 61
References ......................................................................................................................................... 62
APPENDIX C: ECONOMICS OF CO2 CAPTURE FROM POWER PLANTS CONSIDERING
NEAR TERM TO LONG TERM BREAKTHOUGH TECHNOLOGIES ........................................... 66
Near Term Technologies ................................................................................................................... 66
Medium Term Technologies ............................................................................................................. 66
Outlook for Longer Term Technologies on the Rise......................................................................... 68
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Novel Concepts ............................................................................................................................. 69
Cost Curve Frontier........................................................................................................................... 71
References ......................................................................................................................................... 74
APPENDIX D: A SELECTION OF NATIONAL AND INTERNATIONAL ACTIVITIES
RELATED TO CARBON CAPTURE .................................................................................................. 76
Overview ........................................................................................................................................... 76
National ............................................................................................................................................. 76
International Test Centre for CO2 Capture.................................................................................... 76
CANMET Energy Technology Centre.......................................................................................... 77
Oxy-fuel Combustion ............................................................................................................... 77
Coal Gasification ...................................................................................................................... 77
Looping Combustion ................................................................................................................ 78
Canadian Clean Power Coalition (CCPC) .................................................................................... 78
United States ..................................................................................................................................... 78
Future Gen .................................................................................................................................... 78
US Regional Partnerships ............................................................................................................. 80
International ...................................................................................................................................... 81
Intergovernmental Panel on Climate Change (IPCC) ................................................................... 81
Carbon Sequestration Leadership Forum (CSLF)......................................................................... 82
International Energy Agency (IEA) .............................................................................................. 84
Carbon Capture Project................................................................................................................. 85
Australian Cooperative Research Centre for Greenhouse Gas Technologies (CO2 CRC)........... 86
NorCap .......................................................................................................................................... 86
CASTOR....................................................................................................................................... 86
CO2Net ......................................................................................................................................... 86
APPENDIX E – OPPORTUNITIES AT OIL SANDS AND HEAVY OIL CO2 EMISSION HUBs... 88
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Fort McMurray.................................................................................................................................. 88
Opportunity Summary....................................................................................................................... 91
APPENDIX F - OPPORTUNITIES AT ELECTRICITY CO2 EMISSION HUBs............................... 92
Lake Wabamun ................................................................................................................................. 92
Opportunity Summary....................................................................................................................... 95
APPENDIX G - OPPORTUNITIES AT PETROCHEMICAL CO2 EMISSION HUBs ...................... 96
Joffre-Prentiss–Red Deer .................................................................................................................. 96
Nova Joffre.................................................................................................................................... 96
Dow Prentiss ................................................................................................................................. 97
Agrium Joffre................................................................................................................................ 98
Permolex Red Deer ....................................................................................................................... 99
Opportunity Summary....................................................................................................................... 99
APPENDIX H - OPPORTUNITIES AT MULTI-INDUSTRIAL CO2 EMISSION HUBs................ 100
Fort Saskatchewan........................................................................................................................... 100
Dow Chemical Canada................................................................................................................ 101
Shell Chemicals/Refinery/Upgrader ........................................................................................... 103
Agrium ........................................................................................................................................ 103
Air Liquide.................................................................................................................................. 104
Opportunity Summary..................................................................................................................... 105
APPENDIX I - OFF-GAS FROM OIL REFINERIES AND BITUMEN UPGRADING .................. 106
Alberta Oil Sands ............................................................................................................................ 106
Coking......................................................................................................................................... 106
Estimates of Off-Gas Volume from Oil Sands Upgrading in Alberta ........................................ 107
Off-Gases from Hydrogen Production ........................................................................................ 108
Conventional Refineries .................................................................................................................. 108
Catalytic Cracking....................................................................................................................... 108
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Estimates of Off-Gas Volumes from Conventional Petroleum Refineries in Canada ................ 108
The Opportunity .............................................................................................................................. 109
The Challenge ................................................................................................................................. 109
APPENDIX J - OPPORTUNITIES FOR A CO2 BACKBONE PIPELINE ...................................... 111
The CO2 Backbone Concept ....................................................................................................... 111
Why a Backbone? ....................................................................................................................... 111
International Considerations: ...................................................................................................... 112
Existing Infrastructure................................................................................................................. 112
CO2 Supply Considerations: ....................................................................................................... 113
Potential Business Arrangement to Keep Pipeline at Capacity................................................... 114
APPENDIX K – A “BALLPARK” FINANCIAL PLAN FOR IMPLEMENTATION OF CCS IN
CANADA ............................................................................................................................................ 116
CO2 Transportation Projects............................................................................................................ 116
Capture from Electricity Generation Facilities ............................................................................... 117
Capture from Petroleum and Petrochemical Sources...................................................................... 119
Research, Development and Demonstration Programs for CCS..................................................... 120
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INTRODUCTION
Fossil fuels will, on current trends, continue to be a major source of energy for Canada and worldwide,
well into the timeframe when substantial reductions in greenhouse gas emissions are required. Carbon
capture and geological storage (CCS) enables the continued use of fossil fuels while making major
cuts in greenhouse gas emissions, thus giving a longer timeframe to achieve a transition to fully
sustainable energy sources and energy utilization processes.
CCS or the geological sequestration process consists of “capture”, including purification, of site
specific anthropogenic CO2 emissions, “transport” of a concentrated CO2 waste stream and “storage”
of the CO2 by injection into deep geological media consisting of active and depleted oil, gas and
coalbed methane (CBM) reservoirs, saline aquifers and salt caverns.
The timing for the deployment of CCS depends on the target rate of reduction in greenhouse gas
emissions and the success of the full spectrum of measures including energy efficiency and renewable
energy. With the aggressive Federal Government reduction targets for greenhouse gases (GHG)
emissions in the Kyoto commitment period, large-scale deployment of CCS will be needed for
associated emissions from electricity generation and petroleum resource recovery. In addition, Canada
ranks second only to Saudi Arabia in oil reserves, and is blessed with large accumulations of natural
gas and coal. All of these are major CO2 sources when utilized.
In Canada’s favour is extensive access to substantial carbon dioxide storage capacity in the
sedimentary basins associated with coal seams, depleted oil and gas fields and deep saline aquifers.
The storage of CO2 derived from fossil fuels in the Western Canadian Sedimentary Basin (WCSB) has
the potential to become one of the new major industries developed which will allow Canada to
continue reap economic benefits from fossil fuel production and use without incurring GHG penalties.
In the short term, the storage of CO2 in depleted oil reservoirs combined with EOR will yield some
financial return to offset partially the cost of capture and transportation. In the longer term, further
technology development will be required to reduce the costs associated with CCS, and in particular the
cost of capture and the logistics of efficient transportation of CO2 between source and sink. Cost
reduction through innovation will be critical to the uptake and long-term viability of CCS technologies
and there is considerable scope for international collaboration to spread this effort. The IEA GHG
R&D Programme already plays a part in brokering international collaboration and could help extend
such activities. Canada should continue to participate in work by the IPCC, and opportunities for
developing further collaboration could be offered by the international Carbon Sequestration
Leadership Forum (CSLF), set up by the USA with membership including Canada, Australia, Brazil,
China, Colombia, India, Italy, Japan, Mexico, Norway, Russia, the UK and the European Commission.
Appendix D provides additional detail on these and other national and international mechanisms.
In March 2004, a technology framework was proposed and developed for a “Canadian Network of
Innovation in Carbon Geological Storage” (CANiSTORE). This report builds upon the CANiSTORE
report to provide a technology framework for carbon dioxide capture and transportation – CANiCAP.
CANiCAP has a double entendre. “CAN i CAPture CO2” is directed at the non-governmental (NGO)
community and is meant to address environmental issues and consequences. The “CANada innovation
(CO2) CAPture” program focuses on identification of technology systems that are or may be capable
of delivery of CO2 in a concentrated form that renders it readily useable, transportable and storable;
and a business plan to put them in place. Both goals are embodied in CANiCAP.
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CANiCAP will be a companion report to CANiSTORE. Together they are intended to be the two
technology pillars that the Canadian Roadmap for CO2 Capture and Geological Storage rests on. The
CANiSTORE report proposes a plan for the implementation of Geological Storage in Canada (issued
in April, 2004 and is available from the website “www.co2network.gc.ca”). The CANiCAP report is a
strategic document that will propose a plan for the commercialization of CO2 Capture in Canada. The
infrastructure of CANiCAP is based on the prediction of large industry evolution over the next 30
years.
Carbon Dioxide Capture in Canada
On the capture side of geological sequestration, Canada is well positioned. A Capture Centre has been
established in Saskatchewan at the International Test Centre at the University of Regina. In parallel,
NRCan at Bell’s Corner in Ottawa is operating enriched-oxygen combustion and gasification labs.
Industry has responded with the Canadian Clean Power Coalition (CCPC), a public-private partnership
that aims to demonstrate CO2 removal from an existing coal-fired power plant and from a new power
plant by 2012. As well, work is underway by the Zero Emission Carbon Alliance (ZECA), a
consortium formed to design a zero emissions coal-based power plant.
Carbon dioxide capture would be most efficiently applied to large “point sources” in order to gain
economies of scale both in the capture process itself and in subsequent transportation and storage.
Examples of such sources include fossil-fuelled power stations, oil refineries, petrochemical plants,
cement works and iron & steel plants. Because of the large quantities of gas involved (i.e. of the order
of 1 – 30 Mt/yr CO2 for a full scale scheme) transportation is most likely to be by pipeline in
preference to batch handling, although liquefied gas tankers have been suggested as an option for a
demonstration project. A range of storage options have been proposed, including injection into
depleted oil and/or gas reservoirs, geological aquifers, deep unminable coal seams and on or below the
deep ocean bed. Injection into oil/gas reservoirs and deep coal seams has the attraction of utilizing
geological formations with demonstrated storage capabilities. They also have potential to generate an
economic return through enhanced oil recovery (EOR), Enhanced Gas Recovery (EGR), or enhanced
coal-bed methane (ECBM) production. Appendix A provides details on large CO2 site specific final
emitters and appropriate geological sink locations.
Consequently capture and storage needs to be assessed as a major option for greenhouse gas
abatement for Canada. This investigation has focused on carbon dioxide capture from hydrocarbon
supply and consumption from utilities, refineries and petrochemical plexes.
Objective of CANiCAP Report
The document has been prepared directly for Alberta Environment, but it is intended to have a much
wider distribution and has been written to address numerous potential stakeholders, specifically:
•
The Canadian governments who will set the policy and legislative framework to steer
Canada’s development, and can invest in emerging technologies which are important to
improving Canada’s foundation as a world power. Specifically, the decision makers in the
Canada’s federal and provincial governments who drive the process of co-operative research
and development to meet Canada’s international and domestic environmental commitments
and objectives have to be engaged.
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The Canadian people who have to understand the capacity of CO2 geological storage and the
risks of CO2 capture and geological storage (CCS) in the context of the world’s energy
demands.
•
Canadian industry who have to commercialize CCS without impairing Canada’s industrial
competitiveness in world markets, and whose long term future depends on rapid, efficient and
effective development of CO2 Capture and Storage and other GHG mitigation technologies,
•
The scientific community that provides equipment, laboratories, knowledge and innovation to
facilitate the development process.
At present CCS technology has attracted little media interest in Canada, and as a consequence there is
little awareness amongst the general public of CCS as an option for CO2 abatement. It is important that
the facts about it be well understood and trust developed amongst the public and NGOs.
Overall, it is anticipated that the CANiCAP report (as well as the existing CANiSTORE report) will
become a partial blueprint for industry projects and future government programs that wish to
accelerate the uptake of new technology systems that address environmental issues and energy supply
in a sustainable manner for future generations.
CANiCAP Technology Goals and Co-Benefits
There are major questions of how the development of technology for carbon capture and storage
through innovation would impact the future potential GHG reductions, and how much investment
should be made in research, development and deployment (RD&D). While much is known about past
technological change, much less is known about future technological change. The uncertainties
include: where inventions will come from; what inventions will become successful; what any given
dollar of R&D will return; how much learning will occur; how quickly a particular product or process
will diffuse into wider use; or where the next big breakthrough will come. There is no evidence in the
literature that any single technology will provide society with the ability to control the cost of
emissions mitigation. However, evidence does suggest that a suite of new and improved technologies
will become available over time.
CANiCAP’s envisaged programs and activities would provide the following valuable return on
investment for the stakeholders:
Direct tonnes of CO2 separated from source and sequestered in the demonstration projects;
Lower operating costs through technology development, operational improvements and
reductions in energy consumption, resulting in strengthened industry viability;
Lowering costs and reductions/elimination of GHG emissions to improve the industry’s
competitiveness and solidify Canada’s place in the international market;
Number and strength of collaborative partnerships to optimize research investments and
provide scientific knowledge, new technologies and better practices for the industry as a
whole;
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Number of highly qualified personnel (HQP) that are trained in Universities/colleges as a
result of network operations; and
Size of leverage industry funds.
Other co-benefits include:
Addressing energy supply, demand and application, while bearing in mind the potential for
symbiotic interaction between energy sources.
Resolving the environmental, supply, and reliability constraints of producing and using energy
resources to provide Canadians with a stronger economy, healthier environment and more
secure future.
Creating linkages and opportunities for current industrial wastes from one industry sector as
resources in another.
Developing technologies and processes to address existing pollutants (NOx, SOx, particulates,
mercury). These pollutants could be significantly reduced, if not eliminated.
CANiCAP Linkages
This document provides an overview of the options and elements needed to guide Canada’s long-term
research effort into carbon dioxide capture and transportation. It is hoped that the document will guide
the coordinated efforts of the stakeholders participating in the Canadian CO2 Capture and
Sequestration Technology Network (CCCSTN). This document responds to:
The Energy Innovation Network (EnergyINet) program in CO2 management – established to
reduce greenhouse gas and other emissions by developing technology to capture, transport,
and use carbon dioxide to increase oil and gas recovery and inject into coal beds to release
methane.
The Canadian CO2 Capture and Storage Technology Network (CCCSTN) - established to
coordinate activities undertaken by various groups and/or entities working on research,
development and demonstration of national CO2 Capture and Storage (CCS) initiatives.
The Clean Coal Roadmap being prepared by Natural Resources Canada.
The Oil Sands Roadmap prepared by the Alberta Chamber of Resources
The Hydrogen Roadmap being prepared by Natural Resources Canada
The Carbon Capture and Storage Roadmap being prepared by Natural Resources Canada.
The relationship between EnergyINet & CCCSTN and the capture and storage initiatives underway in
Canada is illustrated in Figure 1. It is intended that this document provide input and pathways to aid in
the development of a detailed business plan that includes both governance, funding and technology
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issues, to be developed by a program director, a position administered by the Alberta Energy Research
Institute (AERI) and the EnergyINet program.
Figure 1: Relationship of CANiCAP with respect to programs/activities in Canada (Modified
from Bachu, AGS)
Vision
A concerted coordinated effort to push suites of CO2 capture and transport technologies and
strategies needed for evolving technology systems over the top from “developing” through
“commercially available” to “commercially attractive” in Canada within the next 10 to 20
years.
Mission
To enhance the knowledge, awareness, competency, and global competitiveness of Canada through
the:
Development, adoption, adaptation and demonstration of cost effective transitional
technologies in CO2 capture and transportation for geological storage.
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Implementation of technologies in Canada to significantly decrease CO2 emissions to the
atmosphere from major stationary CO2 sources.
Derivation of benefits from Canada’s abundant natural resources and existing industrial base.
The mission will be achieved through technology development and industrial focused capture and
transport investigations, and the continued implementation of Canadian commercial projects for CO2
capture, transportation and storage in geological media.
Values
The following core values and beliefs will contribute to CANiCAP’s success:
Commitment and Accountability to stakeholders
Leadership and Teamwork – in engaging and accelerating collaborative action, provincially,
nationally and international that supports the longer term vision
Passion for Innovation – believing that we can develop and effectively deploy technology into
the economy
Respect and Integrity - be honest and trustworthy in all relationships
Strategic Goals
CANiCAP will contribute to the following desired end-states:
Aid in focusing the skills of the appropriate Canadian research organizations on solving
technology barriers to implementation of CO2 capture and transportation
Increase the awareness and perception of the Canadian public in carbon capture and geological
storage as a safe solution for reducing greenhouse gas emissions
In collaboration with government and industry, establish carbon capture piloting activities
Accelerate the commercialization of carbon capture, transportation and geological storage
though successful piloting leading to commercial demonstration.
By developing knowledge with the aim of achieving these goals, CANiCAP will ensure that it
addresses the most important carbon capture and transportation issues. For each of the goals,
CANiCAP will prepare technology-based solutions that support government policy discussions and
decision-making and industry business initiatives.
Measures of Success
The development of realistic, quantifiable measures to give substance to the strategic goals and to
demonstrate progress in achieving them will be a key deliverable of the business plan to be developed
by the proposed CANiCAP program in concert with the overall governance direction provided by the
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EnergyINet and the Carbon Capture & Geological Storage Network. In the short term, the following
measure is representative of reasonable aspirations and targets for CANiCAP:
Accelerating the commercialization of geological capture and be indirectly responsible for the
storage of 25 megatonnes of CO2 in geological media by 2012.
Strategic Objectives
These key outputs support our vision, strategic goals and measures of success:
Meeting CO2 emission targets, yet maintaining low cost power derived from fossil fuels
Meeting CO2 emission targets, yet maintaining low cost hydrogen derived from fossil fuels
Avoiding the future need to purchase carbon credits internationally but being able to sell
Canadian geological storage credits internationally
Providing a sustainable future for major energy exports worth tens of billions of dollars
Developing new commercial opportunities via new technologies, and in the longer term
through integrated regional emission-free hubs, a precursor of a hydrogen economy
Establishment of a CO2 backbone pipeline connecting the major CO2 emission hubs
Decreasing CO2 emissions in an environmentally sustainable manner
Providing part of the solution to a major environmental problem, yet maintaining the social
benefits of economic growth
The Opportunity
Canada ranks second only to Saudi Arabia in oil reserves, and is blessed with large accumulations of
fossil fuels: natural gas, oil, oil sands and coal. All of these are major CO2 sources when produced,
processed and utilized.
Western Canadian Sedimentary Basin (WCSB): Canada has one of the world’s best regions for
geological storage in the depleted or underutilized pore space of the WCSB (located in northeastern
BC, Alberta, southern Saskatchewan and southwestern Manitoba), and a knowledge base in carbon
capture and storage second to none. Alberta is unique, in the sense that it not only requires geological
storage to reduce CO2 emissions, but it requires hydrogen to process its large bitumen resource (a
situation which could allow Canada to become a world leader in the transition to zero emission fuels
because of the potential synergies between CO2 storage and hydrogen production).
Maritime Basins: Nova Scotia and New Brunswick rely heavily on fossil-based coal, and oil for power
generation. CO2 Capture and Storage (CCS) infrastructure is in the early stage of development in this
region. In the Eastern Canadian Sedimentary Basins, opportunities exist for CCS for onshore enhanced
coalbed methane and also for offshore enhanced oil or gas recovery.
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Central Canada: Quebec has only a few small sedimentary basins along the St. Lawrence River.
Ontario has sedimentary basins on its southern borders, which are suitable for geological storage of
CO2, the largest portions of which are found in the US (e.g. Michigan Basin). Ontario also has
sedimentary basins along Hudson Bay, which is remote from large CO2 emission sources. CCS
technology offers Ontario a cost-effective alternative to the retirement of its coal-fired power plants by
2007, allowing the province to generate electricity from its existing coal-fired power plants and
virtually eliminate impacts on air and the atmosphere.
Storage of CO2 derived from fossil fuels has the potential to become a new major industry that will
allow Canada to continue to reap economic benefits from fossil fuel production and use, while
reducing the need to purchase international permits/credits or incur GHG penalties. Use of “home
based” technologies will keep jobs and economic development within Canada, something the purchase
of international permits/credits will not achieve.
BUSINESS PATHWAYS
The major business function of the CANiCAP will be the design of, development of, execution of and
participation in CO2 capture and transportation projects. To support the projects and to ensure that the
maximum amount of information beneficial to the early establishment of a CCS industry in Canada is
obtained from these projects, three core areas are proposed:
Program Management;
Research and Development Programs; and
Pilot and Demonstration Projects.
Figure 1 provides a general structure for the operation of the network. It is anticipated that achieving
the goals set for CANiCAP will require testing technology systems at the pilot scale at CO2 hubs
followed by demonstration projects. Equally important will be the collaboration of CANiCAP with
external projects. As shown in Figure 2, the program would be led by a program leader (who heads
the CO2 Management Program of EnergyINet; see Figure 1) with assistance for finance and
accounting functions. The Pilot and Demonstration Programs and the Research and Development
Programs would be lead by managers seconded to CANiCAP from AERI, AENV or NRCan,
individuals from associated research organizations and/or industry that are part of EnergyINet. The
scientific advisory committee advises both the governance board and the program management team
on technology decisions. The managers of pilot and demonstration projects and the research and
development programs must work closely together.
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CO 2 Capture & Storage
Technology Road Map
CANiCAP Organizational Chart
Governance Board
(Carbon Capture & Geologic Storage Network)
SCIENTIFIC
SCIENTIFIC
ADVISORY
ADVISORY
COMMITTEE
COMMITTEE
Program
ProgramLeader
Leader
Finance &
Administration
Finance &
Administration
Pilot
& Demonstration
DEMONSTRATION
DEMONSTRATION
PROJECT(S)
PROJECT(S)
Projects
GEOLOGICAL
STORAGE
GEOLOGICAL
STORAGE
Carbon
Capture
Research &
RESEARCH
RESEARCH&&DEVELOPMENT
DEVELOPMENT
PROGRAMS
Development
Programs
PROGRAMS
Capture
Captureand
andGeological
Geological
Storage
StorageProject
Project
2
(Ft.
(Ft.Saskatchewan)
Saskatchewan)
SCIENCE
Technology
&
SCIENCEand
and
TECHNOLOGY
TECHNOLOGY Systems
Technology
At CO Emission Hubs
External
Project
Liaisons
EXTERNAL
EXTERNAL
PROJECT
PROJECT
LIAISONS
LIAISONS
Post-Combustion
ENHANCED
ENHANCEDOIL
OIL
RECOVERY
RECOVERY
ENHANCED
ENHANCEDCOALBED
COALBED
METHANE
METHANERECOVERY
RECOVERY
Oxy-Combustion
SALINE
SALINE
Gasification
AQUIFER
AQUIFER
DEPLETED
DEPLETEDOIL/GAS
OIL/GAS
Industrial
Processes
RESERVOIR
RESERVOIR
Policy &
Performance
POLICY
POLICYand
and
PERFORMANCE
PERFORMANCE
REGULATION/
REGULATION/
OUTREACH
OUTREACH
Chemical Solvents
REGIONAL
REGIONAL
CHARACTERIZATION
CHARACTERIZATION
Regulation &
Outreach
RESERVOIR
RESERVOIR
CHARACTERIZATION
CHARACTERIZATION
LIFE
LIFECYCLE/
CYCLE/
ECONOMICS
ECONOMICS
EXISTING
EXISTINGWELL
WELL
CHARACTERIZATION
CHARACTERIZATION
Lifecycle &
Economics
RISK AND
PERFORMANCE
PERFORMANCE
Risk
& Performance
ASSESSMENT
ASSESSMENT
Assessment
Physical Solvents
Solid Adsorbents
Membranes
WELL
WELLTECHNOLOGY
TECHNOLOGY
PORE SPACE
ENGINEERING
Cryogenics
ENGINEERING
)(RES. & STORAGE ENGNG.)
MEASUREMENT,
MEASUREMENT,
MONITORING
MONITORING&&
VERIFICATION
VERIFICATION
Hybrid Processes
System Integration
Pipelines
Pipelines
Figure 2: General organization of CO2 Capture Programs undertaken by CANiCAP
The Research and Development Programs are of two types: Policy and Performance, and Capture
Technology and Technology Systems. Policy research and performance programs are split into
regulation and outreach, life cycle evaluation and economics, and risk and performance assessment
and have already been discussed in the CANiSTORE report. Capture technology is split into chemical
solvent scrubbing, physical solvent scrubbing, solid adsorption/desorption, membrane separation,
cryogenic separation, hybrid processes, system integration and pipelines. Technology systems are the
incorporation of the capture technologies into post-combustion, oxy-combustion, gasification and
industrial processes as part of system integration (Figures 2 and 3).
CANiCAP should aim to collaborate in all CO2 capture projects in Canada. Although it will initiate
some projects with industry as the operator at CO2 emission hubs, it will also invest in existing
projects (i.e. called external project liaisons in Figure 2). The information flow from these projects
will be aligned with and applied to the CANiCAP’s own CO2 Emission hub pilots to make maximum
use of the external data. This will also aid in ensuring the development of an integrated, holistic
framework for the CO2 capture industry in Canada, and will support the need for a CO2 backbone
pipeline connecting the major CO2 emission hubs in Canada.
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Industrial Processes
Raw
Materials
Process Carbon
Release
Process
stream
20-95 % CO2
Value Added Products
i.e. Ammonia, NG,
Transport Fuels,
Cement, Steel etc.
CO2
Capture
CO2
Post-combustion Capture
Air-Combustion
Power
& Heat
Flue gas
5-10 % CO2
CO2
Capture
CO2
Pre-combustion Capture
Coal/Coke
/NG/Fuel Oil/
Biomass
Gasification/
Reforming
Syngas
Carbon
Capture
20-40 % CO2
H2
Power
& Heat
Combustion
CO2
Compression
& Transport
for Storage
CO2
O2 /Steam
Oxy-fuel Combustion
Oxy-Combustion
Power
& Heat
Flue gas
>80 % CO2
CO
CO
2 2
Capture
CO2
Figure 3: Technology CO2 capture pathways in fossil fuel conversion and industrial
processes (Courtesy of Gupta and Pearson, NRCan)
Relationship between CANiCAP and Industry
Based on the significant role CANiCAP is envisaged to perform in assisting in the development of
capture technologies associated with the electrical generation and fossil fuel recovery industries, it will
be important that the organizational structure of CANiCAP be sufficiently robust to effectively
participate in the hub type pilot projects and meet the commitments for leading the research and
development programs. A path forward for a typical project is summarized below in point form:
CANiCAP has developed and acquired an array of capture technologies through its research
program.
A potential project is screened by CANiCAP based on a CO2 emission hub’s needs for CO2
capture or transport technology.
Negotiation takes place between CANiCAP and industry for the use of the appropriate
CANiCAP technology. Issues such as ownership, legal aspects, liability and outreach are
addressed.
CANiCAP and industry form a development team and prepare a design for the capture system
based on the capture technology.
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The capture technology is scaled up to a size appropriate for a capture pilot that results in a
budget, and industry seeks a permit from the appropriate regulatory agency for construction
and testing.
Once regulatory approval is received, a tendering process for all aspects of the pilot will be
made.
Strategic alliances will be sought with engineering firms and equipment suppliers.
The pilot will be built and commissioned.
During pilot execution, CANiCAP’s technology development and performance program teams
will be conducting measurements and doing assessments under the guidance of the operator.
The pilot program can be rated successfully based on two criteria, either:
o
A commercial success would lead to a commercial demonstration with or without
CANiCAP’s participation.
o
A technical success would lead to IP but because of the cost, a commercial
demonstration would not be warranted. However the technical success would produce
data, knowledge and experience that would be used to design future research.
An analysis of the success of the project would identify future needs and knowledge gaps.
These research drivers would allow the Scientific Advisory Committee (Figure 2) to make
recommendations to the CANiCAP board and to the managers of the Technology
Development and Performance Programs for future emphasis and refinement of screening
criteria for future projects.
Business Objectives and Guiding Principles
Establish a network of scientists and engineers for CO2 capture and transport in the technology
areas of chemical solvent scrubbing, physical solvent scrubbing, solid adsorption/desorption,
membrane separation, cryogenic separation, pipelines and system integration.
Provide advice for the legislative (i.e. regulatory/legal) framework for CO2 capture and
transport by engaging the appropriate bodies (e.g. Alberta Energy and Utility Board) with a
plan, in place within two years.
Conduct a comprehensive outreach program that is developed by government departments
within the first year.
Develop nationally and internationally accepted audit and verification procedures for CO2
capture and transport within three years.
Complete a feasibility study of a CO2 backbone pipeline connecting the major CO2 emission
hubs within one year.
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Construct the first stage of a CO2 backbone pipeline linking two CO2 emission hubs within
five years.
Tie all technology projects funded by CANiCAP into CO2 emission hubs.
Complete or put into operation, five CO2 capture projects at CO2 emission hubs.
Implement three commercial operations as a result of technology developed through
CANiCAP within seven years.
Business Context and Critical Factors
CANiCAP is being set up to accelerate a potential new global industry – that of reducing CO2
emissions to the atmosphere by capture and storage of CO2 in geological media.
Canada has the knowledge resource to develop and implement geological CCS, and has been
at the forefront of this technology development for several years.
The establishment of CANiSTORE and CANiCAP presupposes that the global community
will attach a dollar value to reducing CO2 emissions that will exceed $10 to $50 Cdn/tonne
CO2 avoided. If the CO2 were from coal-fired electrical power plants, the cost of coal-fired
electricity would be increased by approximately 20 to 40%, which is equivalent to $57/tonne
CO2 for each tonne of CO2 stored. Although this might seem to be a prohibitive cost, it will
lead indirectly to implementation of Clean Coal technologies that will have other
environmental benefits. This is the biggest uncertainty that the business faces.
Another important issue is the containment of the CO2 in geological media. Leakage from the
storage reservoir must be minimized and leakage that does occur must be identified and steps
taken to avoid any unsafe situations.
Strategic Themes
The focus of CANICAP is testing capture technology in the field at CO2 emission hubs. There are four
major generic hub types: multi-industry hubs, oil sands/heavy oil hubs, electricity hubs and
petrochemical hubs (Figure 4). Each hub type is composed primarily of a specific segment of industry
and is sited geographically based on access to feedstock materials, which results in a mix of primary
and parasitic industries being built there. In reality, a number of secondary factors such as energy
availability, transportation costs and access to skilled labour prescribe the industry mix. As
transportation becomes less of an issue (with construction of a CO2 backbone pipeline), and limitations
of the oil and gas supply are being felt globally, it is thought that the hubs will eventually evolve into
polygeneration hubs (Figure 4). At all the hubs, fossil fuels are being used for energy production or
for higher value products through combustion, gasification and industrial processes. These are the
systems (Figures 2 and 4) which need to be further developed or replaced by incorporation of more
efficient capture technologies into them.
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Figure 4: Merger of multi-industry hubs, oil sands/heavy oil hubs, electricity hubs and
petrochemical hubs into a polygeneration hub.
Risk Management Plan
The largest risk facing the development of the CANiCAP is government and industry support for
investment in technology development for carbon dioxide capture. To date, it would appear there has
been insufficient investment in such a technology development process and it is recommended that a
detailed research and development investment plan be prepared and approved. This should be
undertaken with full consultation with the EnergyINet Carbon Management Steering Committee.
TECHNICAL PATHWAYS
It is proposed that CANiCAP will operate three major programs:
1. Research and development
2. Hub Pilot and Demonstration Projects
3. Education and Outreach
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Research and Development
This component will be carried out by the universities and government research and technology
transfer organizations, and will be aligned with industry needs and linked directly to specific piloting
projects or it will not be funded. Both piloting (i.e. field pilots) and commercial projects are to be
initiated and operated by industry (In the case of geological storage, governments may have to be
involved much higher up in the “S” curve than would be the case for “economic development”
projects).
Capture Technology Options and Time Frames for CO2 Capture
CO2 waste streams from large final emitters (LFEs) can be split into three groups based on
concentration: streams that are greater than 80% pure (high), those that are between 20 and 80%
(intermediate) and those that are less than 20% (low) CO2. Each of these streams is representative of
certain industries and the separation or capture technologies depend on the composition, concentration
and pressure of the waste stream. Some of the industries require separation of the CO2 as part of the
process and these industries produce the high purity CO2 streams. Currently, the purest streams (i.e.
95+% CO2) come from the industries where a source of pure hydrogen is needed such as ammonia
plants. Attractive intermediate streams have resulted by the switch in the natural gas reforming from
separation technologies using chemical or physical solvents to separation technologies using solid
adsorbents through pressure swing adsorption (PSA). The largest dilute streams are associated with
combustion of coal to produce electricity (i.e. ~ 13% CO2); yet currently they are the largest emitters
of CO2. The largest cost of CO2 capture from LFEs is for those with the most dilute CO2 waste
streams, and capture is the most costly component of CCS. For example, in capturing CO2 from a post
combustion process of coal or natural gas, the high cost is dependent on the large amount of flue gas
that must be processed per unit of CO2 captured. Current technologies can reduce a power plant’s net
generation rate by as much as 40%. Furthermore, the actual volume abated and counted against a GHG
reduction “report card” is 1/3 less than the volume actually stored in the geological formation.
Therefore, in planning for a Canadian CCS program, the purest CO2 sources being the least expensive
and most efficient in terms of storage, would be utilized first. This observation allows for a technology
development time frame that is tied into industry.
There are five main technologies available for separating gases (Figure 2), with the choice depending
on the state (i.e. concentration, pressure, volume) of the CO2 to be captured:
•
Chemical solvent scrubbing
•
Physical solvent scrubbing
•
Solid adsorption/desorption
•
Membrane separation
•
Cryogenic separation.
•
Hybrid processes
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For low concentration and low-pressure CO2 streams, chemical solvents are favoured while high
concentration and/or high-pressure streams favour physical solvents, solid sorption or membrane
separation. A purer CO2 stream is prepared by utilizing cryogenic oxygen (in an oxyfuel process) in
place of air for combustion or gasification. Hybrid processes involve a combination of any of the
above in a two or more step separation process. Advancements in all these technologies are possible,
especially when incorporated into capture systems: Appendix B provide more details on each of these
capture technologies, and opportunities for their use by industry .
Capture Systems
In general, CO2 capture from anthropogenic CO2 emissions can be contained through four capture
pathways utilizing specific capture technologies:
Post Combustion: Application of chemical solvent separation technologies.
Oxy-Combustion: Cryogenic oxygen separation, resulting in concentrated CO2 stream from
combustion, possibly captured by membrane separation technologies
Gasification: Application of physical solvent and solid adsorbent separation technologies
Industrial Processes: Application of various separation technologies
CO2 is the end product from the combustion of any carbonaceous fuel. Post-combustion capture
systems (Figure 3) involve scrubbing CO2 out of flue gas after the fossil fuel is combusted.
Conventional air-fired process heaters and industrial utility boilers fit into this category. In these
systems, the fossil fuels are combusted in excess air, resulting in a flue gas stream that contains low
concentrations of CO2 (10-15 v/v% for modern coal fired power plants and 5-8 v/v% for natural gas
fired plants) and high concentrations of nitrogen. There are also small amounts of excess oxygen and
SOx and NOx. These factors increase the cost and energy requirements of post-combustion capture.
CO2 capture at these low CO2 concentrations and system pressure usually involves reversible chemical
reactions that require heat in order to regenerate and recycle the chemicals used to capture the CO2.
The most common technology used for capture uses a chemical amine solution to absorb the CO2. Net
loss in efficiency due to the capture process is in the order of 25%. Under the current state of
technology, only absorption and to some extent membranes are considered to be economically viable
technologies. Major players in the post combustion capture systems are Mitsubishi Heavy Industries
(MHI), Fluor Corporation and the International Test Centre at the University of Regina.
Oxy-combustion capture systems (Figure 3) use pure oxygen in place of air for combustion thereby
producing a flue gas of mostly CO2 and water vapour resulting in a high concentration at low system
pressure. The oxygen is obtained by separating it from air prior to using it to burn the fuel. The
removal of nitrogen (78%) from the oxidant stream produces highly concentrated flue gas streams
(>80 v/v% CO2) that can be easily concentrated further. Oxyfuel combustion is widely used in glass
and metal industries where very high temperatures are required for the process. Compared to the glass
and metal industries, oxy-fuel combustion for power generation and other large industrial boilers is a
relatively a new approach. In order to control the flame temperature, a portion of the flue gas can be
recycled to the furnace to keep the flame at moderate temperatures. Since nitrogen is eliminated from
the feed gas, the combustion takes place in an O2/CO2 environment. Net loss in efficiency due to the
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capture process is in the order of 25%. Key players are US, EU, Japan and Canada. The CANMETIndustry CO2 Consortium is carrying out a research and development program through a pilot scale
research facility and is pursuing an early demonstration of oxyfuel combustion systems in Canada.
The gasification or pre-combustion capture systems (Figure 3) basically involves de-carbonization
of carbonaceous fuels. The carbonaceous fuels are converted to syngas (pre-dominantly a mixture of
CO and H2) through gasification, partial oxidation or steam reforming. Subsequently, CO is converted
to CO2 through the shift conversion reaction producing a stream containing mainly H2 and CO2.
Oxygen is generally used in gasification systems, but compared to oxy-fuel combustion of coal, it
requires significantly less oxygen per unit of net power output. In electricity generation, the hydrogen
is combusted in a gas turbine and further efficiencies are gained by using waste heat to power a steam
turbine. The concentration of CO2 in this stream is around 25-40% and the total pressure is typically in
the range of 2.5-5 MPa. Thus the partial pressure of CO2 in the pre-combustion capture is very high
compared to post-combustion systems, making it much easier to separate through techniques such as
scrubbing through physical solvents. The CO2 is recovered in a dry condition, at moderate pressure
with little or no use of steam, significantly reducing the CO2 compression costs and power
requirements, and resulting in a noticeably smaller loss of net efficiency compared to oxy-fuel
combustion and post-combustion. The main product of a pre-combustion system is the decarbonized
energy carrier such as hydrogen or electricity for consumer applications giving it a strategic flexibility
for future energy requirements. The variants of precombustion capture systems include, integrated
gasification combined cycle (IGCC), integrated gasification hybrid cycle (IGHC) involving fuel cells
and polygeneration facilities. The 2nd generation IGCC has been demonstrated at commercial scale in
EU and US, however it did not include CO2 capture. As the experience from these plants is based on
high quality coals, extensive research is needed for adaptation of commercial IGCC in the Canadian
circumstance. CANMET Energy Technology Center is engaged in characterizing the low quality
Canadian coals through its pilot scale gasifier facility for an early deployment of IGCC plant in
Canada. The Canadian Clean Power Coalition plans to demonstrate an IGCC plant fired with
indigenous low value Canadian coals and with CO2 capture in the 2012 time frame. Appendix C
considers the timing and economics of these first three capture systems as applied to power plants.
Industrial Processes (Figure 3) that release large quantities of CO2 are chemical processes, such as
upstream natural gas conditioning, manufacturing of ammonia/urea and hydrogen which separate
nearly pure CO2 streams from the process. However in absence of any incentive, the unused CO2 is
vented to atmosphere. Other industrial processes, which are potential source of process related CO2
emissions, are cement and steel manufacturing where average concentration of CO2 in the flue gas is
greater than 20% (i.e. in cement kilns and blast furnaces where flue gases contain process-related CO2,
the CO2 concentration in the flue gases may vary from 14-33%).
Environmental Compliance
The cost of environmental compliance for other issues besides CO2 will also play a role on which
capture systems move forward. This favours gasification over combustion, as NOx, SOx, particulates
and mercury levels in the flue gas are lower.
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Compression and Pipelining
Additional compression is required to take the relatively low-pressure purified CO2 stream and
pressurize it for pipelining. Normally CO2 is transported in a liquid form which requires pressures of
approximately 1600 MPa be maintained. Next to capture, compression is the most expensive step of
the CCS process, requiring significant energy input, thereby reducing the amount of CO2 abated.
CO2 can be transported in gaseous, liquid or solid form. However, with the quantities to be handled (110Mt/yr) and distances involved (10-1,000 km) for any single full-scale capture and storage project in
Canada it is likely that pipeline transmission of “dense phase” CO2 will be the preferred option.
Most experience in pipeline transport of CO2 has been gained in the USA where the gas is used
extensively for Enhanced Oil Recovery (EOR). For EOR in West Texas, CO2 is derived from naturally
occurring geological sources in New Mexico and Colorado, and from amine scrubbing at four natural
gas processing plants. Around 22Mt CO2 is transported each year through a 3980 km pipeline system
to oilfields in the Permian Basin of West Texas. More recently a 330 km pipeline has been
commissioned to carry CO2 separated in the Great Plains Synfuels Plant in North Dakota to the
Weyburn EOR operation in Saskatchewan. This pipeline can carry up to 2Mt CO2 per year. This
practical experience shows that CO2 transport by pipeline is an established commercial technology.
An alternative would be to liquefy the carbon dioxide and use rail and ship transport. This could be
deployed for enhanced oil recovery options, and has the advantage of providing some “buffer”
capacity to handle shut downs of either the power plant or the injection well heads.
Pipelining will determine the siting of new industries. Pipelines have to be able to transmit multiple
commodities. Slurry pipelining may be used to transport two phases simultaneously (e.g. coal and
water, coal and CO2, coal and oil). CO2 may be used as a diluent for transport of bitumen if the
bitumen contains no water (if water is present, stainless steel would be needed for the pipeline) and the
CO2 does not cause asphaltene precipitation from the bitumen. If these two factors prove
insurmountable, slugging or batching of bitumen and liquid CO2 could be considered, or CO2 could be
used as a supercritical solvent to strip out the asphaltenes to achieve a partial upgrading before
pipelining. CO2 may be separated from natural gas or other gaseous streams at regional CO2 gas plants
rather than locally. Pipelining of hydrogen and oxygen is assumed to be minimized in preference to
the other phases, although pipelining of syngas is a possibility for production of electricity or
conversion to a pure hydrogen stream at sites distant from the solid carbon source (e.g. coal mines).
Strategically located depleted large oil or gas reservoirs may be used as a “giant surge” tank in a CO2
gathering and distribution network. Similarly, salt caverns can be used for temporary storage of CO2.
Presently, salt caverns are used in Western Canada (Saskatchewan and Alberta) for gas/liquids storage.
Hub Pilot and Demonstration Projects
CANiCAP will consider the options of commercial development taking place in sites with high
volumes of CO2 emissions (which could be purified now or in the future under the right economic
environment) from a number of sources in close proximity, which if connected together by a CO2
gathering system could become an emission 'hub' (Figure 5). An emission hub designation could also
be considered for a single source if there was a sufficient volume of CO2 emissions that could be
captured from it to put it on the scale of other hubs (for example, a coal-fired thermal generation
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facility) - granted no external gathering system would be strictly necessary for it to be designated a
hub. Isolated emissions sites could choose to join a hub without being physically connected to the
hub's gathering system if that remote location agrees to transport their CO2 to the hub by some other
means such as truck, rail or commingled with other products in a pipeline.
A CO2 hub could also be an important part of a more integrated industrial 'plex' where several
industrial sites are connected together to take advantage of by-product synergies (one plant's waste,
such as waste heat, is an important input into another's process). Plexes can evolve to poly-generation
consisting of integrated multi-product energy (e.g. steam, electricity and hydrogen) and/or chemical
complexes largely based on use of solid carbon forms (e.g. coal, bitumen and coke). Establishment of
new industry at a plex is strongly influenced by the relative costs of transporting of one plant's
product/by-product output to another plant as an input to their process.
Part of a CO2 Emission Hub
Flue Gas CO
2
Electricity
Plant
Flue
Gas
N2
CO2
Hydrogen
Plant
N2
Separation
Injection
Coal
Deep Coal bed
CO2
CH4
CH4
•Note: Pipelining may be required if reservoirs (e.g. coal, oil, gas or saline aquifers) are
not located directly under the hub.
Figure 5: Scenario for a CO2 Emission hub where the CO2 from a coal-fired power plant is
injected into a coalbed methane reservoir, the methane produced is reformed to hydrogen,
and the CO2 from the hydrogen plant is also injected in the coal bed to recover more methane
(Note that it takes two or more molecules of CO2 depending on the rank of the coal to
displace one methane molecule. Courtesy of ARC)
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Oil Sand/Heavy Oil Hubs
(e.g. Fort McMurray, Lloydminster – see Appendix E for more detail.)
For the case of Fort McMurray, in a world where long term oil price stabilizes at US $30-35/bbl and
North American gas price at $4 to $5/MCF (i.e. North American LNG terminal growth is not expected
to have a significant influence on prices or markets for Canadian natural gas below this price), oil
sands development in Alberta can be expected to continue at a stable pace. With this scenario,
gasification of bitumen upgrader residuals to make hydrogen will be viable and will soon be proven at
Opti-Nexen's Long Lake Project. Utilizing bitumen 'bottoms' in this way to make electricity, heat and
hydrogen will help alleviate the oil sands industry's exposure to the high price volatility of natural gas,
and will also help alleviate the anticipated shortage of natural gas, the traditional feedstock for
hydrogen production. However, oxygen requirements for the process are large. The Oil Sands
Roadmap states: “Gasification of abundant coal or oil sands residues (perhaps even coke) holds the
greatest promise at this time to generate hydrogen in the amounts needed, and replace natural gas for
this purpose. At the same time, energy and power are natural products. About 10% by weight of the
original oil sands production needs to be gasified to produce enough hydrogen to convert the
remaining 90% into high quality (40o API+) synthetic crude oil (SCO).”
The CO2 separation issues would be CO2/H2 separation, under hot temperatures and moderate pressure
conditions. Current physical absorption separation technologies can be applied (PSA, Benfield,
Selexol, Rectisol), but process improvements are required to demonstrate economic viability in a wide
range of applications. The high cost of oxygen is a major impediment to widespread implementation
of gasification with CCS. Improved air separation processes are needed. Water requirements will have
to be addressed. The timing of these activities is within the 2015 timeframe.
Although the high price of natural gas has resulted in a technology push, is it far enough? By
upgrading the bitumen to SCO and leaving a coke residue, the potential for higher value products is
limited. Stripping of the asphaltenes under supercritical conditions could leave a transportable product
and an asphaltene residual, both of which can be converted into a high value products for the
petrochemical and gasoline industries. Nova Chemicals has a vision of “petrochemicals from
Alberta’s oil sands”. The gap to be addressed is the “lack of technology and infrastructure for optimal
conversion of bitumen to high quality fuels and petrochemical feedstocks”. To accomplish this,
research is being supported in catalysis (aromatic ring opening) and separation technologies. The
timing of these activities maturing is in the 2015+ timeframe.
Electricity Hubs
(e.g. Alberta, Saskatchewan, Ontario, Nova Scotia – see Appendix F for more detail):
Post Combustion CO2 Capture
Current fossil-fired steam generation technology utilizes pulverized coal combustion in air in a subcritical steam cycle with a resultant flue gas containing 13 to 15% CO2 (dry basis). Advanced
technology options to reduce CO2 emissions are focused on increasing overall plant efficiency such as
pulverized coal supercritical steam cycles and to a lesser extent, pressurized fluidized bed combustion.
The efficiency goes up with the increasing temperature of the process and may be limited by the
temperature limitations of current boilers and steam turbines. Cogeneration (Combined Heat and
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Power) offers significant efficiency improvements, but is limited to a relatively few, large (>100MW
electrical) selected sites where steam users and hosts are collocated. To meet CO2 emission targets,
amine capture technologies can be added to new plants and existing plants with long expected lives, as
an end of the pipe solution.
To improve the economics of capture projects, these amine capture plants can offer additional
flexibility to operators as they may be run only during off-peak hours to maximize electricity
production during peaking. As with the CO2/H2 separation, these capture technologies require further
refinement to move them into widespread use.
If the capture system outlives the plant, there may be the potential for it to be deconstructed and
installed on either the replacement plant, or, more likely, moved to and installed at another plant of
similar vintage. Such relatively new but used capture systems could have a market value within both
the domestic and international market in a CO2 emissions-constrained world. These used capture
systems could potentially be installed on facilities in the developing world as a combination of aid and
earning CDM credits. A robust used market for capture systems that are in good working order could
improve the economics for Canadian plants that wish to ‘trade up’ as new and more effective capture
technology systems become available. Alternatively, these technology systems may be retired in a
CO2 emissions-constrained world as the current capital stock is retired (predicted to occur gradually
over a 35 year period) as more cost effective technology systems come on stream such as IGCC.
IGCC and Hydrogen Manufacture
For the power sector, IGCC (Integrated Gasification Combined Cycle) from coal or other solid fuels
has been in development and commercial demonstration for over two decades, but still has not seen
widespread application, likely due to somewhat higher power generation costs, and demonstrated
availabilities that are well below those of more conventional technologies. From some viewpoints, the
purpose of IGCC is to produce hydrogen; power is a “waste” product (possibly, a view of the future if
coal gasification is used as hydrogen source for upgrading of bitumen)! Moreover, IGCC may
contribute in the 2020s to the implementation of very high energy- efficient fuel cells for conversion to
electricity and/or hydrogen production for the transportation sector. Even further into the future,
possibly in the 2030s, near zero emission concepts such as “ZECA” will be available at ultra-high
efficiencies using advanced fuel cells. Gasification of the lower rank sub-bituminous and lignitic coals
requires more development work as the process is currently too expensive.
Improvements needed to assist IGCC’s advancement include:
•
Reducing the high cost to deliver oxygen to the gasifier, a major hurdle to the commercial
application of IGCC (and oxy-fuel, see below). Improvement on or a replacement
(perhaps membranes) for cryogenic air separation technologies is one possibility.
•
Synthetic gas clean-up technologies, including physical solvent absorption, physical
adsorption and new innovative methods for hot gas cleanup.
•
Improving gas turbines for higher temperature and (higher hydrogen concentration)
applications to achieve better efficiencies.
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Commercial coal IGCC should be available in significant numbers beginning in the 2015 timeframe.
Alternate uses for hydrogen such as upgrading and fertilizer production etc. will likely expedite this
development. This technology system will initially form an integral part of an industry plex.
CO2 capture from IGCC requires carrying out a “shift” reaction after the gasification step. Steam is
added to a shift converter at the right temperature. This converts the CO in the gasifier syngas to CO2
while producing more H2 from the syngas. The CO2 is in a concentrated form and can be fairly easily
captured. The hydrogen can be directed to a combined cycle, gas turbine (designed for hydrogen-rich
fuel) for electricity production or the hydrogen can be used in a downstream chemical processing
system.
Oxy-Fuel
An alternative technology to expedite CO2 capture is oxy-fuel combustion. Oxyfuel is already in
limited commercial service in the aluminium smelting industry. Two oxyfuel technology systems are
currently being considered; one using CO2 recycle to keep temperatures down; the other uses water
recycle. Oxy-fuel combustion with water recycle is in the piloting stage. This technology system is
derived from the rocket industry. In the prior case, paper studies and piloting tests on a 1.8 MW boiler
simulator demonstrate that oxyfuel with CO2 recycle may be retrofitted to existing power plants
without major technical hurdles.
The major components of the oxy-fuel combustion technology are commercially available; however, it
needs integration and commercial size demonstration. The immediate step is to find a demonstration
site. The issues are economics and the cost of oxygen. CO2 from oxy-fuel combustion can be of
relatively high purity. The major advantage is that CO2 separation is not a major hurdle; a significant
offset to oxygen production costs. This would be a plus where/when there is sufficient demand for
CO2 for EOR and ECBM applications. Further upside could be realized with lowering the cost of
oxygen production from air or water. However, optimization is needed for impurities removal and
cryogenic separation/condensation. Oxyfuel may have an advantage over IGCC when hydrogen is not
required for other applications. CO2 from oxy-fuel combustion may be available in the 2010 time
frame.
Gasification and oxyfuel are not necessarily in competition. Oxyfuel’s best opportunity may be where
there is no alternate use for a hydrogen stream but a pure CO2 stream is required. Gasification is more
suited to energy plexes where the hydrogen is already needed with the excess hydrogen being used for
generating electricity. Both require an enriched oxygen stream for the process.
Multi-Industry Hubs
(e.g. Fort Saskatchewan, Sarnia – see Appendix H for more detail)
The hub at Fort Saskatchewan (which includes Edmonton) consists of more than 40 industries ranging
from power to refineries and petrochemicals, which are becoming more integrated with time; and
consequently is poised to become a polygeneration hub in the future. In the interim, PSA off-gas from
hydrogen production could provide an attractive stream to demonstrate the oxy-fuel combustion
technology; or that separation of both hydrogen and CO2 from this off-gas stream is technically
feasible and needs commercial confirmation (See Appendix I).
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One of the challenges is whether to combine the streams from different processes and plants for
processing. A consideration is the variation in the off-gas composition from different sites (e.g. Shell’s
off-gas in Fort Saskatchewan, and Suncor and Syncrude’s off-gas in Fort McMurray might provide
good candidates as they are all generated during the upgrading of bitumen – see Appendix I). Another
advantage for sites such as Fort Saskatchewan is that enough pure CO2 can be amassed to justify a
shorter pipeline for EOR in the next 5-10 years (2200 t/d existing plus another 3000 t/d from PSA offgases at Fort Saskatchewan). This allows time to develop the longer Fort McMurray pipeline to deliver
CO2 south for EOR applications (pure CO2 of 5500 t/d plus another 4000 t/d available from PSA at
Fort McMurray).
The other opportunity with the CO2 hub at Fort Saskatchewan is the siting of future upgrading plants.
Integration of upgrading with existing refineries favours the Fort Saskatchewan-Edmonton Area. An
example is the Shell facility in Scotford. This might be appealing for skilled labour accessibility
reasons, in addition to an array of industrial infrastructures available at the hub (two very compelling
incentives). It is expected that, over time, more upgrading plants will be located there (e.g. note BA
Energy’s recent application to the AEUB). The Oil Sands Roadmap states “These projects will
succeed on the basis of close integration between the upgrader and the refinery capabilities, potentially
saving costs for broad quality uplift in central upgraders producing a single quality synthetic crude
oil.” The upgrader residuals can provide sources of hydrogen and power. Separation technology needs
are similar to Fort McMurray. Timing is similar to Fort McMurray, and depends on whether or not
there is a change in the balance of upgrading activities from Fort McMurray to Fort Saskatchewan.
Petrochemical Hubs
(e.g. Joffre, Montreal – see Appendix G for more detail)
For the case of Joffre, the petrochemical plex has been built on the basis of a sustainable supply of
ethane for polyethylene plastic manufacture. For the petrochemical sector, expansion into other
plastics such as polypropylene seems logical if ethane supplies diminish. This appears to be
happening. Due to the current limitation on ethane supplies (this could be alleviated by new sources of
supply such as from the Alaskan pipeline), current ethylene plants have started to supplement ethane
with propane thus making available a stream of propylene. In the meantime, recovering the propylene
from upgrading offgas makes sense to kick-start the propylene market in Alberta that could eventually
result in construction of world scale polypropylene plants. This could happen in Fort Saskatchewan
(where Williams Energy has started separating propylene from a stream from Fort McMurray).
However, the incremental CO2 emissions will be primarily low concentration combustion flue gas, and
will not be attractive for CCS. Production of high purity CO2 would remain at current levels.
For ammonia plants, not much more development is seen because of the high gas prices and the
existing alternatives for urea (fertilizer) manufacture. The situation is similar for methanol unless we
can identify another source of hydrogen. As with the heavy oil situation discussed above, one option
is gasification of coal or bitumen for hydrogen with CO2 capture. Existing physical absorption
technologies place this route just below widespread economic viability. Further down the road may be
extended processing of bitumen feedstocks (perhaps at Fort Saskatchewan where refineries are already
in place) to supplement the dwindling natural gas feedstocks to obtain ethane for polyethylene,
propane for polypropylene and benzene for polystyrene. Each of these process chains will have CO2
emissions associated with them that will have to be addressed. Currently, Nova Chemicals pipes
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excess gas-liquids to Fort Saskatchewan for storage in salt caverns until they are needed. In the future,
if shortages of these gas-liquids occur, the bitumen upgraders in Fort Saskatchewan may be modified
from producing SCO to produce this stream from bitumen, and the same pipeline used to move them
to Joffre.
If solutions like these aren’t found, the bitumen will be transported south to the US or west to Asia
where these higher value petrochemical products will be produced there. Larry Wall, Executive
Director of Alberta’s Industrial Heartland area northeast of Edmonton said in an interview with the
Edmonton Journal “It’s a symptom of a North American phenomenon, petrochemicals are under
siege” by Asian rivals and high natural gas costs. Canadian producers need to focus on higher value
products for export by utilizing their fossil fuel precursors more effectively.
Polygeneration Hubs
(e.g. Sasol Fischer - Tropsch Synfuels complex in South Africa, Great Plains - Synfuels plant in North
Dakota)
Simultaneous manufacture of hydrogen, natural gas, power generation, CO2 capture and petrochemical
products from coal-based syngas is in the 2015 to 2030 time frame and represents a future logical step.
Liquid fuels and petrochemicals could be produced by Fischer Tropsch processes or from methanol
synthesis plants. Electricity, heat, steam, hydrogen, synthetic natural gas or ammonia (for fertilizers)
are alternate products. The Clean Coal Roadmap concluded: “Gasification plants of the future can be
designed with dual downstream options helping to make coal competitive with oil or natural gas.
Power for the electricity grid would be generated during times of peak demand, but at times of low
power demand, hydrogen together with a variety of fuels and chemicals would also be produced.”
Currently, marketing chemicals and other streams of products is not appealing to the power sector.
Strategic alliances between the power and chemical sectors are required to make this work. However,
the chemical and refinery sectors have other options to generate electricity than from coal (residuals
and coke). They would potentially be in competition with the power sector as more excess electricity
would be available to the power grid.
All of the other hubs will evolve into some facet of polygeneration hubs over the next 50 years. The
example of such a process occurring to an electricity hub or a multi-industry hub was discussed above.
Perhaps oil sands are poised to trail blaze this path ahead of coal as they already are commercializing
gasification of bitumen residuals. If one looks at the value chain for bitumen, a 20 times multiplier is
expected if the product shipped out of Alberta is not bitumen, but derivatives consisting of
transportation fuels and petrochemical products.
Pipelines
Commercial projects leading to CO2 capture and geological storage are currently hampered by the
physical separation between industrial CO2 waste streams and suitable reservoirs for injection of CO2
(i.e. lack of pipelines for CO2 transport). The Alberta Government has identified this issue as a priority
and they are currently proposing new fiscal policies that would encourage the building of CO2
pipelines and CO2 storage demonstrations. These provide opportunities for technology development.
However, investment should be based on opportunities that access as wide a variety of storage
reservoir types as possible, such as a backbone CO2 backbone pipeline. A CO2 backbone pipeline
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connecting CO2 emission hubs could act as a manifold with a number of taps for injection and
withdrawal of CO2. Captured CO2 at the hub is compressed and injected into the pipeline temporarily
and transported in either direction to the withdrawal point for a geological storage project. Appendix J
contains a discussion and plan for a CO2 backbone pipeline for transporting CO2 in Canada.
Education and Outreach
The notion of capturing and sequestering carbon dioxide and other greenhouse gases is relatively new,
and many people are unaware of its role as a greenhouse gas reduction strategy. Increased education
and awareness are needed to achieve acceptance of carbon sequestration by the general public,
regulatory agencies, policy makers, and industry and, thus, enable future commercial deployments of
advanced technology. The following activities are recommended to highlight CANiCAP activities in
education and outreach:
•
CCS webpage
•
Monthly CCS newsletter
•
The CANiSTORE and CANiCAP Program Plans, revised annually
•
Educational curriculum on global climate change and GHG emissions mitigation options
In addition the CANiCAP stakeholders should actively participate in technical conferences and
workshops. These efforts expose professionals working in other fields to the technology challenges of
CCS and also enable examination of some of the more detailed issues underlying the technology.
As with any new technology, there are environmental issues associated with CCS that need to be
explored, understood, and addressed. The level of uncertainty is higher for some technology options
than for others. A portion of the CANiCAP Program's R&D portfolio should be aimed at an improved
understanding of potential environmental impacts. In concert with R&D, the CANiCAP Program
seeks to engage NGO's and federal, state, and local environmental regulators to raise awareness of
what the Program is doing in this area, and the priority it places on systems that preserve human and
ecosystem health.
CLOSING STATEMENT
It is important to be able to anticipate and adapt to future changes in the fossil fuel industry to allow
the selection of technologies to be improved and new technologies, which will be needed to
accomplish the goal of lowering CO2 emissions through CCS. From this discussion, two scenarios are
implied. Without the leadership of government (policy, regulatory and financial), industry will follow
a bottom-up economic approach looking at projects on an incremental basis. Infrastructure will be
created in a haphazard fashion. However, government can influence industry in a top-down approach
by putting in the necessary incentives to build the infrastructure (alone or in partnership with industry)
to accomplish more efficient long-term goals. One such top-down scenario is the building of a
pipeline backbone or corridor, which links the CO2 emission hubs/plexes and allows feeder
connections to appropriate geological sinks. The construction of a backbone would set the stage for
carbon capture and storage projects to contribute to nationally significant emission reductions. Siting
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of new industry will be influenced, leading to accelerated research, development and
commercialization of gasification of solid carbon sources (e.g. coal, coke and bitumen) as a
replacement for natural gas in upgrading and production of electricity, and implementation of
commercial CSS projects. A tentative plan to accomplish this for Canada is presented in a financial
spreadsheet in Appendix K.
RECENT COMPLIMENTARY INFORMATION SOURCES
Alberta Chamber of Resources (2004) Oil Sands Technology Roadmap, Alberta Chamber of
Resources, 82 pages.
Canadian Clean Power Coalition (2004) Clean Coal-Fired Power Plant Technology to Address
Climate Change Concerns, Confidential report
Carbon Sequestration Leadership Forum (2004) Final Draft Technology Roadmap, CSLF, 32 pages.
Cleaner Hydrocarbon Technology Futures Group (2003) Cleaner Hydrocarbons: Technology
Challenges and Opportunities for the Western Canadian Hydrocarbon Energy Sector, Alberta
Research Council, 63 pages
Cooperative Research Centre for Greenhouse Gas Technologies (2004) Carbon Dioxide Capture and
Storage: Research, Development & Demonstration in Australia, CO2CRC, 71 pages
Gunter, W.D. and R. J. Chalaturnyk (2004) The CANiSTORE Program: Planning Options for
Technology and Knowledge Base Development for the Implementation of Geological Storage
Research, Development and Deployment in Canada, Alberta Research Council, 94 pages.
Hughes, David (2005) Energy Supply/Demand Trends and Forecast: Implications for a Sustainable
Energy Future in Canada and the World, Geological Survey of Canada open File Report 1798, 70
pages.
International Energy Agency (2004) Energy Technology Analysis: Prospects for CO2 Capture and
Storage, OECD/IEA, IEA Publications, 249 pages.
International Panel for Climate Change (In preparation for a 2005 release) IPCC Special Report on
Carbon Dioxide Capture and Storage, IPCC, (100+ pages).
Heath and Associates, (2002) CO2 Pragmatic Business Solutions, Alberta Department of Energy, 44
pages.
Keith, David, (2002) Towards a Strategy for Implementing CO2 Capture and Storage in Canada,
Environment Canada Protection, EPS/2/IC/1-Dec. 2002, 23 pages.
McCann, T.J. and Associates (2002) Petrochemicals from Oil Sands. Confidential report. 112 pages
plus appendices)
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Natural Resources Canada (In preparation for a 2005 release) Clean Coal Technology Roadmap,
Natural Resources Canada (approx. 80 pages)
Natural Resources Canada (In preparation for a 2005 release) CO2 Capture and Storage Technology
Roadmap (approx. 80 pages)
Natural Resources Canada (In preparation for a 2005 release) Hydrogen Systems: A Canadian Strategy
for Greenhouse Gas reduction and Economic Growth, Natural Resources Canada (approx. 80 pages).
North American Energy Working Group (2005) North American Natural Gas Vision, Experts Group
on Natural Gas Trade and Interconnections, 117 pages.
SNC.Lavalin (2004) Impact of Impurities on CO2 Capture, Transport and Storage, IEA Greenhouse
Gas Research & Development Programme, Report Number PH4/32, 86 pages.
U.S. Department of Energy (2004) Carbon Sequestration Technology Roadmap and Program Plan –
2004, USDOE – National Energy Technology Laboratories, 24 pages
ZECA Corporation (2005) www.zeca.org
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APPENDIX A - CO2 EMISSION HUBS ACROSS CANADA AND
PROXIMITY OF GEOLOGICAL SINKS (ONSHORE AND
OFFSHORE)
By Brent Lakeman (Alberta Research Council Inc.)
Overview of CO2 Emissions Sources:
According to Canada’s 2000 greenhouse gas inventory, GHG emissions associated with large final
emitters (LFE) accounted for 342 Mt (or 46%) of Canadian greenhouse gas emissions in 2000. This 342
Mt is divided between three industry sub-sectors, with oil and gas accounting for 133 Mt (39% of the
industry total); the electricity sector accounting for 126 Mt (37%); and the mining and manufacturing
sector accounting for 82 Mt (24%). Figure A-1 provides an overview of Canada’s GHG emissions in
2000.
Figure A-1: Canadian GHG Emissions in 2000
While the sources of these greenhouse gas emissions are located across the nation, in some cases, there
are clustered around the locations of specific industries (e.g. oil sands, mining) or in specific geographic
“hubs” where large facilities have historically operated or around or near major population centres.
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Forecasted Emissions Growth
Natural Resources Canada (NRCan) forecasts that the greenhouse gas emissions within several key
sectors – including several industry sectors -- will experience significant growth over the coming 15
years. Table A-1, presents a “business as usual” scenario for greenhouse gas emissions growth.
Table A-1: Projected GHG Emissions Growth by Sector
Sector
1990
2000
2010
2020
(Mt/yr)
(Mt/yr)
(Mt/yr)
(Mt/yr)
Power
Generation
Industry
Residential &
Agriculture
Commercial
Fossil Fuel
Production
Transportation
Agroecosystems
Waste
Other
Total
95
130
127
135
136
46
142
48
152
45
168
47
26
75
32
107
34
147
35
154
146
59
20
2
605
180
60
24
3
726
194
76
25
9
809
224
81
26
17
887
Source: Natural Resources Canada, 2002
With respect to the large final emitting sectors, the oil and gas sector is forecast to see its greenhouse gas
emission grow by 44% between 2000 and 2020; the industry sector (which would include the mining and
manufacturing sector) sees an 18% increase in greenhouse emissions between 2000 and 2020; and the
power generation sectors sees a more modest 4% increase in GHG emissions over this same period.
While all parts of Canada are expected to experience GHG emissions growth during the coming 15 years,
these industry-related emission increases are likely to be concentrated in specific geographic regions of
the country. For example, northern Alberta will see a significant increase in GHG emissions associated
with the rapidly expanding oil sands sector. Manufacturing and mining related emissions are expected to
occur mainly in parts of British Columbia, Ontario and Quebec. The need to replace older electricity
generating facilities in provinces, such as Ontario, could result in increased GHG emissions depending
upon the technology selected.
Facility Specific GHG Emissions
At this point, Canada’s GHG inventory is developed in a “top down” manner, using aggregated sector
production data and applying conversion factors to estimate GHG emissions. While Canada’s inventory
provides a relatively accurate estimate of overall sector emissions, it provides little information on the
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specific sources of these emissions. The national GHG reporting system, to commence in 2005 will allow
for an improved understanding of the specific industry sources of Canadian GHG emissions (at least those
that are above the reporting threshold).
Using data submitted by companies to the Voluntary Challenge and Registry Inc., some organizations
have attempted to identify the companies with the largest overall GHG emissions 1 . While the VCR itself,
does not report GHG emissions at the facility level, corporate reports to VCR Inc. may detail facilityrelated emissions. For example, in its 2003 submission to VCR Inc., Ontario Power Generation (OPG)
reported the GHG emissions from its generation facilities 2 . They ranged from .889 Mt at Atikokan to
21.37 Mt at Nanticoke. Other companies from the electricity generation sector and from other sectors
have also provided facility-specific numbers to VCR Inc.
Some provincial data provides for a more detailed assessment of facility-level GHG emissions in Canada.
Alberta, for example, in developing its GHG reporting requirements, has had background studies
undertaken that identify the facilities with GHG emissions greater than 80 kt of CO2 equivalent. Table A2 details the largest point sources of GHG emissions in Alberta.
It is expected that Alberta’s GHG reporting structure will allow for further detail on the specific location
and nature of facilities whose GHG emissions are greater than 100 kilotonnes of CO2equivalent. Results
from the first year of reporting will be made available in the coming months.
Table A-2 does not make a distinction between those facilities whose CO2 emissions are of a relative pure
concentration (for example, CO2 concentrations for emissions associated with some forms of oil sands
upgrading are over 90 percent) and those whose concentrations are significant lower (for example, the
concentrations of CO2 emissions from the combustion of natural gas are generally around three percent).
For some facilities, CO2 emissions may comprise a range of different concentrations depending upon the
specific processes being used. For a more detailed discussion of the concentrations of specific processes,
see Appendices E, F, G and H, which outline CO2 Hubs in greater details.
Plotted on a map of the Western Canada Sedimentary Basin, GHG emissions within Alberta and
Saskatchewan are shown in Figure A-2.
1
Greenhouse Gas Emissions from Industrial Companies in Canada, 1998, by Matthew Bramley, Pembina Institute, October
2000.
2
Towards Sustainable Development, 2002 Progress Report, Ontario Power Generation
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Table A-2: Facility GHG Emissions in Alberta
Owner
Sector
Facility Name
CO2e
(kt in 2000)
Syncrude
TransAlta
Epcor
TransAlta
ATCO Power
Suncor
Atco Power
TransAlta
Imperial Oil Resources
Ltd.
TransAlta / Air Liquide
ATCO Power
EPCOR
Nova
ATCO Power
DOW
Imperial Oil
Petro-Canada
Celanese
Shell Canada
CNRL
Oil Sands
Power Plants
Power Plants
Power Plants
Power Plants
Oilsands
Power Plants
Power Plants
Gas/Heavy Oil Plants
Ft. McMurray
Sundance
Genesee
Keephills
Sheerness
Ft. McMurray
Battle River
Wabamun
Cold Lake
8700
16019
6128
5854
5850
4833
4430
3456
2817
Power Plants
Power Plants
Power Plants
Chemical
Power Plants
Chemical
Petroleum Refining
Petroleum Refining
Chemical
Petroleum Refining
Gas/Heavy Oil Plants
Ft. Saskatchewan
Poplar Hill
Clover Bar
Joffre
Rainbow Lake
Ft. Saskatchewan
Strathcona
Edmonton Refinery
Edmonton Cloverbar
Scotford
Primrose Wolf Lake
2627
1905
1900
1842
1734
1611
1408
1344
1151
1117
1018
Source: Alberta Environment, 2003
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Figure A-2: Major CO2 sources in the Western Canadian sedimentary Basin (Modified from
Bachu, AGS)
Figure A-2 identifies several key clusters of large point sources of CO2 emissions. For example, Fort
Saskatchewan, which is immediately northeast of Edmonton, contains several large point sources, as does
the Wabamum area, which is immediately West of Edmonton and Ft. McMurray in northeastern Alberta.
This map, however, does not make a distinction between facilities with high concentrations of CO2 and
those with lower concentrations.
Continental Sources
In addition to having an understanding of Canadian CO2 sources, it is important to remain aware of the
overall North American CO2 emission profile, particularly as it relates to the matching of CO2 sources and
geologic “sinks” for CO2 storage. In some cases, the most promising opportunities for the sequestration
of CO2 could involve the transboundary transport of CO2 to a satisfactory sink. The Weyburn Enhanced
Oil Recovery project, for example, relies on CO2 pipelined from North Dakota. There may be other
examples of US sources being transported to Canadian sinks, or alternatively, Canadian CO2 emissions
being transported to US sinks.
The US Regional Partnerships which the US Department of Energy has initiated represent an important
opportunity area for Canadian and US organizations to work together to better understand and capitalize
on GHG sources and sinks. While these partnerships are still in the process of developing baseline
information on CO2 sources and sinks, it will be important for Canadian organizations to remain engaged
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in the Regional Partnerships so that Canada has a comprehensive picture of the opportunities and
technologies available for carbon capture and storage.
Geologic Storage Opportunities
Continental Opportunities for Geologic Storage
A discussion of the potential for carbon capture and storage needs to consider opportunities within the
United States for carbon sequestration. As discussed above, the emerging US DOE Regional Partnerships
(seven in total) are each beginning to detail the potential for carbon sequestration in their regions.
The regional partnerships that potentially offer the greatest synergies for Canada are likely to be the
Plains and the Mid-West regional partnerships (see Figure A-3 and A-4). These partnerships are both
located in states adjacent to Canadian provinces and have varying capacity for CO2 storage in geologic
media. The Plains Partnership, for example, has emerged as one of the leading regional partnerships and
is undertaking detailed quantitative assessments of the sources and sinks within its regional boundaries. It
is noteworthy that several Canadian governments and agencies (e.g. Environment Canada, Alberta
Environment, Saskatchewan Industry and Resources, Manitoba Environment, Alberta Energy and
Utilities Board, Petroleum Technology Research Centre, SaskPower, and the University of Regina) are
members of this partnership.
Figure A-3: The Plains Partnership
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Figure A-4: the Mid-West Regional Partnership
National Opportunities for Geologic Storage
To date, efforts to assess the potential for the sequestration of CO2 in Canadian geology has occurred at
provincial levels, led by provincial geological surveys. Figure A-5, provides an overall snapshot of the
sites within Canada that are most suitable for the geologic storage of CO2.
Figure A-5: Canada’s Sedimentary Basins most Suitable for CO2 Storage (Modified from
Bachu, AGS)
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Federal and provincial governments have supported the development of an assessment of Canada’s CO2
storage potential through the development of the Energy Innovation Network (EnergyINet) CO2
Management Program. The framework of the CO2 Management Program is described in The
CANiSTORE Program: Planning Options for Technology and Knowledge Base Development for the
Implementation of Geological Storage Research, Development and Deployment in Canada 3 .
According to CANiSTORE (pages 19-22):
Canada’s sedimentary basins can be grouped into 12 groups based on type and geographic
distribution that are variously suited for CO2 storage…. Examination of sedimentary basins in
Canada and application of these regional-scale and general site selection criteria using a
parameterization and normalization method (Bachu, 2003) leads to a ranking of Canada’s
sedimentary basins in terms of suitability for CO2 geological sequestration that shows that the
Alberta and Williston basins are by far the best suited and with most potential for CO2 storage…
This cursory analysis indicates that the primary targets for CO2 sequestration in Canada should
be the Alberta and Williston basins (i.e. northeastern B.C., Alberta and Saskatchewan). Secondorder targets should be basins in Nova Scotia and the shallow edge of the Williston basin in
Manitoba. Third-order targets should be the sedimentary strata in southern Ontario and
southern Quebec. The intramontane basins in B.C., although ranked lower because of size and
possible faulting, may have significant potential for CO2 storage in coal beds. Because of this,
they are a second-order target. Beaufort-Mackenzie basins, although likely of great potential,
should be a third- or fourth-order target because they lack infrastructure and large CO2 sources.
However, if the gas resources in the Mackenzie Delta are developed, this situation may change.
As discussed earlier, an important aspect of these sedimentary basins is that the all extend south across the
Canadian – US borders (e.g. the Williston Basin into Montana and North Dakota; the shallow
sedimentary strata in southern Ontario extend into deeper sedimentary basins in Michigan and Ohio) and
are being considered as part of the US Regional Partnerships.
Provincial Opportunities for Geologic Storage
At the regional level, government agencies and research organizations have taken steps to identify CO2
sources and sinks that exist within the Alberta and Williston basins. Figure A-6 provides a snapshot of
the relationship between the most suitable CO2 sinks regions and some of the larger CO2 sources.
Some early specific source sink matches for Alberta are shown in Figure A-7 where the sources are
outlined by triangles and all of them contain high purity waste CO2 streams (with the available tons/day
of CO2 listed). The Fort McMurray, Ft. Saskatchewan and Joffre CO2 Emission hubs are shown in the
three triangles to the north. The four sources to the south are smaller and for the most part represent single
sources either from a fertilizer plant, a gas processing or a pipeline. The sinks are contained by ellipses
3
The CANiSTORE Program: Planning Options for Technology and Knowledge Base Development for the Implementation of
Geological Storage Research, Development and Deployment in Canada, Prepared by Bill Gunter, Alberta Research Council Inc.
and Rick Chalaturnyk, University of Alberta, with input from Stefan Bachu, Alberta Geological Survey, Don Lawton, University
of Calgary, Doug Macdonald, SNC Lavalin Inc., Ian Potter, Alberta Research Council Inc., Kelly Thambimuthu, NRCan,
Malcolm Wilson, University of Regina, and Michelle Heath, The CO2 Hub Inc., April 2004.
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(with the tons/day of CO2 uptake by the reservoirs listed in brackets) and represent depleted oil reservoirs.
Once these purer CO2 sources are being fully utilized, attention will be focused on the waste streams of
lower CO2 purity and other sinks will be identified. At this point, Alberta is the only province that has
evaluated the opportunities for CCS in this much detail. In the future, other provinces will do similar
studies.
Figure A-6: Major CO2 Sources and Sink Regions in the Western Canada Sedimentary Basin
(Alberta and Williston Sedimentary Basins. Modified from Bachu, AGS))
Conclusions
In CCS, provincial and national boundaries should not become barriers. Good CO2 source-sink
combinations may reside totally in one province such as Alberta but in some cases, better opportunities
may lie across provincial boundaries in BC or Saskatchewan. In the case of Ontario’s sources, the best
sinks lie on the other side of the US –Canadian border. In addition, even though the total site-specific CO2
emissions for Canada are fairly well known, total sedimentary basin sink capacity is poorly known and
must be more rigorously evaluated.
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Figure A-7: Sources and Storage Opportunities in Alberta
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APPENDIX B: CO2 CAPTURE TECHNOLOGIES AND
CAPTURE OPPORTUNITIES
By Murlidhar Gupta and Bill Pearson (Natural Resources Canada).
The objective of CO2 capture from large emission sources, is to produce a concentrated stream of CO2
which can be transported and sequestered underground or in deep oceans. The CO2 capture concept is not
new to industry. The capture processes have been widely applied in the natural gas processing and
chemical processing industries for over 60 years and existing practice is to vent the unused CO2 to
atmosphere. However, the concept of capture of CO2 from the fossil fuel usage for the purpose of
geological storage is relatively new.
In general CO2 capture from the anthropogenic CO2 emissions can be contained through four capture
pathways, namely, industrial processes, post-combustion capture systems, oxy-fuel combustion systems
and pre-combustion capture systems (which have been discussed previously). The capture systems are
facilitated by a variety of capture technologies such as membrane separation, absorption, adsorption and
cryogenic separation etc.
CO2 Capture Technologies
The CO2 capture technologies are the component of a capture system that facilitate or enable the
production of pure streams of CO2. In fact, many CO2 capture technologies have been in industrial
practice for over decades. Specialized chemical solvents were developed more than 60 years ago to
remove CO2 from impure natural gas, and these operations continue to be in use, even today. Also the
solvent scrubbing processes are currently widely used to separate CO2 from gas mixtures during the
production of hydrogen for petroleum refining, ammonia/urea production and in the chemical industries
(Anderson and Newell, 2003). In addition, several power plants and other industrial plants use the same or
similar solvents to recover pure CO2 from flue gases for applications in the food processing and chemical
industries.
The selection of a technology for a given capture system depends on many factors i.e. partial pressure of
CO2 in the gas stream, extent of CO2 recovery required, sensitivity to impurities (such as acid gases and
particulates), purity of the desired CO2 product stream, the cost of additives necessary to overcome fouling
and corrosion where applicable, the capital and operating costs of the process and the environmental
impacts (White et al., 2003).
The capture technologies can be broadly classified into the following categories (see Figure B-1):
•
Absorption
•
Adsorption
•
Membrane separation
•
Cryogenic separation
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Hindered
Amines
Organic
Solvents
PSA
TSA
ESA
Physical
Absorption
Inorganic
Solvents
Chemical
Absorption
Adsorption
Absorption
Gas
Absorption
Gas
Separation
Membrane
Separation
Cryogenics
CO2 Capture Technologies
PSA: Pressure Swing Adsorption; TSA: Temperature Swing Adsorption; ESA: Electrical Swing Adsorption; WGSMR: Water Gas Shift Membrane Reactor
Figure B-1: Strawman of CO2 capture technologies
Absorption
Chemical and or physical absorption processes are widely used in the petroleum, natural gas and chemical
industries for separation of CO2. The solvent capacity of an absorbed gas is a function of its partial
pressure in the absorption unit (Thambimuthu, 1993; Kohl and Nielsen, 1997). In physical absorption, the
solvent capacity or loading, which initially follows Henry’s law (for ideal non interacting gas mixtures),
assumes an almost linear dependence on the gas partial pressure. In chemical absorption, the solvent
loading assumes, a non-linear dependence on partial pressure and is higher at low partial pressures. At the
concentrations approaching the saturation loading of the solvent, chemical absorption decreases sharply.
Large increases in the partial pressure of the absorbed gas result in very little increase in the solvent
loading. This behaviour is caused by an effect akin to weak physical absorption and usually arises from
gas absorption in the aqueous component of the solvent used in the process. Thus, the retention capacity of
a chemical solvent in a chemical absorption process is much higher at low partial pressures, whereas the
converse is true for physical absorption (Thambimuthu, 1993). The primary method of regeneration in
physical absorption occurs by a simple pressure reduction in the system. In chemical absorption, heating
(reboiler) is necessary for solvent regeneration and may be cost effective if the process has large supply of
low cost and sufficiently high temperature heat (or steam) available to it.
Table B-1 lists the most common industrial CO2 scrubbing solvents and their respective process
conditions.
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Table B-1: Commercial CO2 scrubbing solvents used in chemical process industry
Absorption process
Solvent
Process conditions
Developer/ licensor
Rectisol
Methanol
-10/-70°C, >2 MPa
Lurgi and Linde, Germany; Lotepro Corporation, USA
Puisol
n-methyl-2-pyrolidone (NMP)
-20/+40°C,>2 MPa
Lurgi, Germany
Selexol
dimethyl ethers of polyethylene glycol
(DMPEG)
-40°C, 2-3 MPa
Union Carbide, USA
Fluor Solvent
Propylene carbonate
Below ambient temperatures,
3.1-6.9 MPa
Fluor, El Paso, USA
Physical Solvent
Chemical Solvent
Organic (Amine based)
MEA
Amine Guard (MEA)
Econamine (DGA)
ADIP (DIPA & MDEA)
2.5 n monoethanolamine and chemical
inhibitors
5 n monoethanolamine and chemical
inhibitors
6 n diglycolamine
2-4n diisopropanolamine
2n
methyldiethanolamine
MDEA
2 n methyldiethanolamine
Flexisorb/ KS-1, KS-2, KS-3
Hindered amine
~40°C, ambient-intermediate
pressures
~40°C, ambient-intermediate
pressures
80-120°C 6.3 MPa
35-40°C, >0.1 MPa
Dow Chemical, USA
Union Carbide, USA
SNEA version by Societe National Elf Aquitane, France
Shell, Netherlands
Exxon, USA; M.H.I., Japan
Inorganic
Benfield and versions
Potassium carbonate & catalysts Lurgi
and Catarcab with arsenic trioxide
70-120°C, 2.2-7 MPa
Lurgi, Germany; Eickmeyer and Associates, USA; Giammarco
Vetrocoke, Italy
>0.5 MPa
Shell, Netherlands
5/40°C, >1 MPa
Lurgi, Germany
Phys/Chem Solvents (Hybrid)
Sulfinol-D and Sulfinol-M
Amisol
Mixture of DIPA or MDEA, water and
tetrahydrothiopene (DIPAM) or
diethylamine
Mixture of methanol and MEA, DEA,
diisopropylamine (DIPAM) or
diethylamine
39
Chemical absorption
The chemical absorption process for separating CO2 from gas is based on the use of aqueous solutions
such as mono-, di- or tri-ethanol amines, di-isopropanol amine, sodium hydroxide, sodium carbonate and
potassium carbonate etc., which form weakly bonded intermediate compounds with CO2. They can be
classified as organic and inorganic solvents.
Organic solvents
The majority of chemical solvents are organic amine-based. Depending on the composition of the target
stream, these amines have different reaction rates, different equilibrium absorption characteristics,
different sensitivities with respect to solvent stability and corrosion factors. These amines can be divided
into three groups: (1) primary amines whose members include monoethanol amine (MEA), diglycolamine
(DGA); (2) secondary amines whose members include diethanolamine (DEA), di-isopropylamine (DIPA);
and (3) tertiary amines whose members include triethanolamine (TEA) and methyl-diethanolamine
(MDEA).
Extracted CO 2 to
dehydration and
compression
Condenser
Stripped gas
(Mainly N 2 and O2)
Reflux Drum
Stripper
Absorber
Steam
Reboiler
Cooled flue gas
CO 2
Regenerated
absorbed
solvent
solvent
Figure B-2: A typical amine absorption process for CO2 capture from flue gas
Figure B-2 shows a typical amine absorption process for CO2 recovery from a flue gas stream. Prior to
capture, the CO2 containing stream is cooled and particulates and other impurities are removed as much as
possible. It is then passed into an absorption vessel (plate or packed column) where it comes in contact
with the chemical solvent, which absorbs much of the CO2 by chemically reacting with it to form a loosely
bound compound. The CO2 rich solvent from the bottom of the absorber is passed into a parallel vessel
(stripper column) where it is heated with steam in the reboiler so as to reverse the CO2 absorption
reactions. CO2 released in the stripper passes through a condenser and is directed to a dehydration and
compression train for transport and storage. The CO2-free solvent from the stripper is recycled to the
absorption vessel. CO2 recovery rates from the chemical solvents can be as high as 98% and product
purity can be in excess of 99%.
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Among the primary amines, MEA has been the traditional solvent of choice for carbon dioxide absorption
and acid gas removal. MEA is the least expensive of the alkanolamines and has the lowest molecular
weight, so it possesses the highest theoretical absorption capacity for carbon dioxide. This theoretical
upper absorption capacity of MEA is not realized in practice due to corrosion problems. In addition,
MEA has the highest vapour pressure of any of the alkanolamines and high solvent carryover occurs
during carbon dioxide removal from the gas stream and in the regeneration step. To reduce solvent losses,
a water wash of the purified gas stream is usually required, which incurs on the additional cost of
operation. In addition, MEA reacts irreversibly with minor impurities such as COS and CS2 resulting in
solvent degradation. Foaming of the absorbing liquid MEA due to the build-up of impurities is also a
concern. For the current MEA absorber systems, the absorption and desorption rates are reasonably high.
However, the column packing and energy consumption causes a significant cost. In addition, the stripping
temperature is required to be strictly controlled as high temperature causes, dimerization of carbamate,
which deteriorates the sorption capability of MEA (Wong et al., 2002).
Secondary amines have advantage over primary amines - their heat of reaction with carbon dioxide is
lower, 1.90 MJ/kg versus 1.51 MJ/kg (see Table B-2). This means that the secondary amines require 20%
less heat in the regeneration step than primary amines. From an energy consumption point of view, this is
an important consideration when the primary objective is the capture of carbon dioxide from flue gas with
minimum penalty on the process efficiency.
Tertiary amines react slower with carbon dioxide than primary and secondary amines, requiring higher
circulation rates of liquid to remove the same amount of CO2 compared to primary and secondary amines.
However, the major advantage of tertiary amine is its significantly lower energy requirements for solvent
regeneration, approximately 30% less than MEA and 11% less than DEA (see Table B-2).
Table B-2: Heat of reaction between amines and CO2 (Wong et al., 2002)
Amines Primary (MEA)
Heat of reaction, ΔHr (MJ/kg)
Secondary (DEA)
1.90
1.51
Tertiary (MDEA)
1.34
In addition, tertiary amines show a lower tendency to degrade and show lower corrosion rates when
compared to primary and secondary amines
It should be noted that corrosion has been a serious issue in amine processes. In general, alkanolamines
themselves are not corrosive to carbon steel; rather the dissolved CO2 is the primary corroding agent. The
observed corrosivity of alkanolamines to carbon steel is generally in the order
Primary Amines
Secondary Amines
Tertiary Amines.
Specialty amines are also being formulated, for example, hindered amines. The hindered amine concept is
based on the reaction rates of the acid gases with different amine molecules. In the case of CO2 removal,
the capacity of the solvent is greatly enhanced if one of the intermediate reactions (i.e. the carbamate
formation) can be slowed down by providing steric hindrance to the reacting CO2. This hindrance effect is
achieved by attaching a bulky alkyl group on the amino group. As a consequence the reactivity is different
from alkalanolamines. In addition to slowing down the overall reaction, bulkier substitutes give rise to less
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stable carbamates. By making the amine carbamate unstable, one can theoretically double the capacity of
the solvent. Sterically hindered amines currently used in absorption processes are 2-amino-2-methyl-1propanol (AMP), 1,8-pmethanediamine (MDA) and 2piperidine ethanol (PE). They were originally
developed by Exxon (Veawab et al., 2002).
The advantage of sterically hindered amines over alkanolamines is that only 1 mol of the sterically
hindered amine, instead of 2 mol of alkanolamine, is required to react with 1 mol of CO2. Thermal
degradation occurs at temperatures higher than 478 K. Sterically hindered amine systems can have lower
heats of absorption/regeneration as compared with MEA. This makes these types of amines, potential
candidates for CO2 removal in power generation systems (White et. al, 2003).
Limitations of amine-based processes and plausible technological advances
Much of the amine scrubbing technology in the past has focused on the removal of hydrogen sulphide and
CO2 from gas plants and reformer flue gases, which corresponds to a reducing environment. However, for
the recovery of carbon dioxide from power plant flue gas, the scale of operations and the requirements are
completely different. Typically the size of the largest commercial plant based on amines is relatively small
(maximum 800 t/d), compared to that required for processing the flue gas from a standard size coal-fired
power plant(> 10,000 t CO2/d). A power plant flue gas does not contain hydrogen sulfide and many of the
other troublesome impurities such as hydrocarbons, pipeline gas additives etc., which are encountered in
conventional applications of amine scrubbing. However, the impurities such as oxygen, sulphur oxides,
nitrogen oxides and particulate matter in a power plant flue gas stream present a different set of
challenges.
The greatest limitation for CO2 recovery from flue gas is the low pressure of the flue gas. CO2 is absorbed
much more easily into solvents at high pressure. The only commercially available solvents that can
absorb a reasonable amount of CO2 from dilute atmospheric pressure gas are primary and sterically
hindered amines, such as MEA, DGA, AMP, and KS-1, KS-2 and KS-3 series of solvents However, this
results in high-energy requirements to regenerate the solvent. The only way, the energy penalty can be
reduced is, if the process can be fully integrated with a power plant where significant amount of low-grade
heat may be available.
The oxygen content of the flue gas is an issue that must be addressed. Most solvents applicable for flue
gas systems degrade to varying degrees in an oxidizing environment, which leads to either high solvent
losses or expensive reclaiming processes. Presence of oxygen also causes corrosion problems in the
process equipment, which can lead to failures and plant breakdowns or more expensive materials of
construction. The use of inhibitors in the solvent to reduce degradation and corrosion appears to work
well and is encouraging for power plant applications. Oxygen scavenging has been proposed but it has
not been commercially demonstrated with flue gases.
Sulfur oxides (SO2, SO3) react with MEA to form heat-stable corrosive salts that cannot be reclaimed. It
is generally accepted that installing a flue gas desulphurization unit before the absorber is the best way to
alleviate the problem. There is a myriad of technologies available for desulphurization, but that is beyond
the scope of this report.
Presence of NOx in a typical flue gas also poses a challenge. NOx generally consists of NO and NO2 in a
ratio of from 95:5 to 90:10. The main component, NO performs as inert gas and will not affect the solvent.
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However, NO2 partially leads to formation of a heat stable salt. Generally, some solvent degradation may
be acceptable in order to avoid the cost of removing the NO2.
Fly ash in the flue gas causes foaming and degradation of the solvent, and plugging and scaling of the
process equipment. This affects the plant performance. Installation of advance fly ash control options
such as a wash operation is considered as a solution to this problem, however, that adds to the cost of
capture.
In summary, the recovery of CO2 from combustion flue gas requires a significant amount of pre-treatment
processing in order to avoid any fouling in the amine absorption step. This will add to the cost of CO2.
However, significant improvements can be made in the amine absorption process in terms of optimizing
the compositions of the absorbing amines and the gas-liquid contactors.
Inorganic solvents
The inorganic chemical solvents include potassium carbonate, sodium carbonate and aqueous ammonia.
Among these, potassium carbonate has the dominant market share. The potassium carbonate process can
be used in various configurations. Generally these process configurations are accompanied by minor
changes in the solvent and catalytic additives used in the process. Overall the system uses an aqueous
solution of about 20-40% wt% of the potassium salt. The absorption of CO2 shows an equilibrium
behaviour that is favourable even at temperatures (typically 70-120oC) close to the atmospheric boiling
point of the solvent. Consequently, it is possible to operate the process with a relatively low incremental
heat input for solvent regeneration or gas desorption. This feature normally eliminates the use of the heat
exchangers used to cool the solvent flow between the regenerator and absorption column. The popular
Benfield process is a split flow version of the basic potassium carbonate process used at moderate gas
pressures of around 2.2 MPa.
Ammonia
Recently ammonia has been tested as a sorbent for CO2. It has been observed that the maximum CO2
removal efficiency by NH3 absorbent can reach 99% and the CO2 loading capacity can approach 1.2 kg
CO2 /kg NH3 (Yeh et al, 2002). On the other hand, the maximum CO2 removal efficiency and loading
capacity by MEA absorbents have been reported as 94% and 0.4 kg CO2 /kg MEA, respectively (White et.
al, 2003). At pH=11, and at an ammonium carbonate concentration of 0.1 M, and at an ammonia
equilibrium vapour pressure of 0.0034 atm, the CO2 removal efficiency has been observed to be 100%
from an initial 12% CO2 in flue gas (Huang and Chang, 2002).
However, the concerns with this technology include the highly volatile nature of ammonia. Also this
technology lacks in the regeneration of ammonia from its carbonate salts (Huang and Chang, 2002).
Capability of anion-exchange resins to regenerate ammonia from ammonium bicarbonate as well as the
feasibility for the regeneration of resin by heated water and collection of CO2 are being investigated.
Released ammonia reacts with the remaining ammonium bicarbonate to form ammonium carbonate,
which results in the resin’s inability to completely regenerate ammonia. A new scrubbing system has been
proposed where CO2 in flue gas, along with the acid gas pollutants, SO2, NOx, HCl and HF, could be
removed in a regenerable scheme (Yeh et al, 2002). The key advantage to the process is that the thermal
energy consumption for the CO2 regeneration is expected to be significantly less than the MEA process
(White et. al, 2003).
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The thermal energy requirement is approximately 50% less in a dual alkali system using ammonia to
absorb CO2 and anion-exchange resins to regenerate ammonia for reuse than using amine to absorb CO2
and steam stripping to dissociate the resulting carbamates. (Huang and Chang, 2001).
The major drawback of inorganic solvents lies in the fact that they may release Na, K and V in the product
gas that could promote deposition, erosion and corrosion in gas turbines, fuel cells and compression trains.
Others such as arsenic trioxide are potent chemicals hazardous to plant and animal life.
Physical absorption
The physical solvents are ideally suited for the removal of CO2 from fuel gases with high vapour pressure
and have been used in the industrial processes (mostly in the reducing environment). These solvents are
suitable for capturing CO2 from pre-combustion capture systems (i.e. IGCC) where the partial pressure of
CO2 is high in the downstream of the shift converter. These physical solvents combine less strongly with
CO2. The advantage of such solvents is that CO2 can be separated from them in the stripper mainly by
reducing the pressure or increasing the temperature, incurring low energy penalty. Table B-1 summarizes
the main physical solvents that could be used for CO2 capture. These are basically cold methanol (Rectisol
process), dimethylether of polyethylene glycol (Selexol process), propylene carbonate (Fluor process) and
n-methyl-2pyrollidone (NMP-purisol). Physical solvent scrubbing of CO2 is well established, e.g. in
ammonia production plants. The Rectisol process has mainly been used to treat syngas, hydrogen and
town gas streams. The coal gasification plant in North Dakota, USA uses a Rectisol process to capture
about 5000 t/d of high quality CO2 that is pipelined to Weyburn, Canada for EOR applications. The
majority of physical absorption solvents are based on organic solvents with high boiling points and low
vapour pressures. Other than methanol, most of these solvents can be used at near ambient temperatures
without appreciable vaporization losses, but may require special water washing stages to mitigate solvent
losses.
In general, all physical solvents must have an equilibrium capacity for absorbing CO2 several times that of
water and a lower capacity for removing other primary constituents of the gas stream. They must have
low viscosity, low or moderate hygroscopicity, and low vapour pressure at ambient temperature. They
must be non-corrosive to common metals as well as non reactive with all components in the gas stream.
(White et. al, 2003). The technology development needs for physical solvents are similar in principle to
those for chemical solvents.
Hybrid absorption processes
Hybrid absorption processes use solvents that offer a combination of chemical and physical absorption.
Processes currently used with coal syngas for removal of CO2 and sulphur compounds are the Shell
Sufinol® process and Amisol® process developed by Lurgi (Collot, 2003).
In its original form the shell Sufinol process uses sufolan (tetrahydroehiophene dioxide) as the organic
solvent and an amine solvent, DIPA (di-isopropanolamine) with 15% water. Shell has also developed MSufinol® in which the amine solvent is MDEA instead of DIPA. The main difference between the
Sulfinol® unit and an alkanolamine unit is that Sufinol® unit tolerates a much higher acid gas loading
(twice as much as the standard MEA unit) before becoming corrosive.
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The Amisol® process is based on a mixture of methanol and either MEA or DEA as the chemical
component and a small percentage of water. Another version that is particularly suited for the removal of
large quantities of CO2 uses MDEA as the chemical solvent component.
Technology development trends in solvent absorption
Considerable work is ongoing internationally to improve the solvent absorption technology for scale-up
and cost effective adaptation in various capture systems. Japan and Canada are pursuing strong research
initiatives to improve the amines and process for the specific task of CO2 capture.
Japanese researchers are developing a series of amine solvents designated as KS-1, KS-2 and KS-3. The
KS-1 solvent has been commercialized in Malaysia, where a flue gas containing 8 vol % CO2 is being
treated with 90% CO2 recovery. Corrosion problems have been reported to be negligible using this solvent
and also the solvent degradation during prolonged operation was significantly low. Experience has
indicated that amine consumption was about 2 kg/t of CO2 recovered. With the improved solvents
currently in the pilot scale phase, it is anticipated that solvent loss may be further reduced to 0.1 kg/t of
CO2 captured. KS-3 is projected as even better than KS-1 and KS-2 in terms of energy consumption for
solvent regeneration.
The International Test Center, Regina, Canada is developing a series of proprietary designer solvents
designated as PSR solvents (Veawab et al., 2002). The PSR solvents are targeting specifically for the
capture of CO2 from post-combustion capture systems. The PSR solvents are expected to have higher
amine concentration than conventional MEA solvents and at a higher loading of CO2. The key features
claimed for the PSR solvents are lower regeneration temperature, lower solvent circulation rate, lower
degradation rate and lower corrosion rate.
Another area that is being investigated for improved CO2 capture is the gas-liquid contractor. A lowpressure gas stream containing low (5-15%) quantities of CO2 means that the volume of the gas to be
processed is large for the quantity of recovered CO2. Improvements in the packing materials in the gas
liquid contact towers have been reported by Canadian as well as Japanese groups. The outcome of this
research will be smaller gas-liquid contactors for a given CO2 capture capacity, thus reducing the size of
unit suitable for a standard power plant application.
Adsorption
The intermolecular forces between gases such as CO2 and the surface of certain solid materials permit
separation by adsorption. Selective adsorption of the gases depends on temperature, partial pressures,
surface forces and adsorbent pore size. The solid adsorbents, such as activated carbon and molecular
sieves are normally arranged as packed beds of spherical particles. The process operates on a repeated
cycle with the basic steps being adsorption and desorption (regeneration). In the adsorption step, gas is
fed to a bed of solids that selectively adsorbs CO2 and allows the other gases to pass through. When a bed
becomes saturated with CO2, the feed gas is switched to another clean adsorption bed and the fully loaded
bed is regenerated to remove the CO2. The adsorption and desorption steps can be induced by changing
the physical parameters. For example, in pressure swing adsorption (PSA), the adsorbent is regenerated by
reducing pressure. In temperature swing adsorption (TSA), the adsorbent is regenerated by raising its
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temperature. Two other variants of adsorption technology are under development. These variants are
swing adsorption (ESA) where regeneration takes place by passing a low-voltage electric current through the
adsorbent and the vacuum swing adsorption (VSA) where the desorption is driven by vacuum.
PSA, TSA (as well VSA) are commercially available technologies and are widely used in commercial H2
production, bulk separation of O2 and in the removal of CO2 from natural gas (McKee, 2002). A
combination process of pressure and temperature swing adsorption (PTSA) has been tested at the bench
scale and pilot scale levels by Tokyo Electric Power Company (TEPCO) & Mitsubishi Heavy industries
respectively (Smith, 1999). Bench scale PTSA tests used an adsorbent zeolite Ca-X(ß) for having high
capacity and selectivity to CO2. Pilot-scale tests from a power station burning a coal/oil mix and a flue gas
with a concentration of 11% CO2 resulted in a 90% capture of CO2. Compared to a single PSA process,
the hybrid PTSA reduced the power consumption for capture by 11% (Smith, 1999).
ESA, which is commercially not ready, holds promise as a possible advanced CO2 separation technology
that will use less energy than other processes. The material used in ESA for separation of CO2 is basically
a carbon fiber composite molecular sieve (CFCMS). The Oak Ridge National Laboratory in USA is
developing a novel ESA process that adsorbs amongst the other gases CO2 from syngas from low
hydrogen-to-carbon ratio fuels on a carbon fiber molecular sieve with a monolithic structure. After
saturation of the carbon fibre adsorbent with CO2, immediate desorption of the adsorbed gas is
accomplished by applying a low voltage across the adsorbent. The ESA process for gas separation has
been studied at pressures up to 2 MPa and temperatures up to 100oC. A CO2 uptake of 45% (wt) has been
demonstrated at a pressure of 2 MPa and a temperature of 25oC (Klara and Srivastava, 2002; Collot,
2003).
Under the current state of technology, adsorption is yet not considered attractive for large-scale separation
of CO2 from flue gases because the capacity and CO2 selectivity of available adsorbents is low. However,
the simplicity of this technology is a major driving force for coherent research as this technology (ESA in
particular) holds the promise for a future where the compact solid state CO2 capture technologies will be
the most efficient way of CO2 capture from fossil fuel usages.
Membranes
A membrane is a barrier film that allows selective and specific permeation under conditions appropriate to
its function. Depending on the type of membrane and its state of development, the membrane technology
fits with all the capture systems. In oxy-fuel combustion, the membrane modules are strong contenders for
economic oxygen production. In gasification capture systems, membranes may help capture CO2 from the
downstream of shift converter without a high energy penalty. Whereas in post-combustion capture
systems, membranes may help capture CO2 from low concentration flue gases.
With regards to CO2 capture, two types of membranes are considered:
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Gas separation membranes
Gas separation membranes rely on differences in physical or chemical interactions between gases and a
membrane material, causing one component to pass through the membrane faster than another. Various
types of gas separation membranes are currently available, including ceramic, polymeric and a
combination of two (hybrid). The separation of the gases rely on diffusivity of the gas molecules in the
membrane - differences in the partial pressure from one side of the membrane to other acts as a driving
force for gas separation (see Figure B-3).
Gas Separation Membrane
Gas Absorption Membrane
Lean
Gas
Absorption
fluid
CO2
CO2
High
Pressure
Low
Pressure
Flue Gas
Figure B-3: Principles of gas separation and gas absorption membranes
Membranes for gas separation are usually formed as hollow fibers arranged in the tube-and-shell
configuration, or as flat sheets, which are typically packaged as spiral-wound modules. The membrane
process has been widely used on the commercial scale for hydrogen recovery from purge gases in
ammonia synthesis, refinery and natural gas dehydration, sour gas removal from natural gas, and nitrogen
production from air. Compared to absorption separation, the advantages of the membrane process are: 1) it
does not require a separating agent, thus no regeneration is required, 2) the systems are compact and
lightweight, and can be positioned either horizontally or vertically, which is especially suitable for
retrofitting applications, 3) modular design allows optimization of process arrangement by using multistage operation, and 4) low maintenance requirements because there are no moving parts in the membrane
unit. According to a market study, the membrane gas separation market is growing very rapidly and will
become the dominating non-cryogenic separation technology for certain applications (Wong et al., 2002).
A number of solid polymer membranes are commercially available for the separation of CO2 from gas
streams, primarily for natural gas sweetening. These membranes selectively transmit CO2 versus CH4.
The driving force for the separation is pressure differential across the membrane. As such, compression is
required for the feed gas in order to provide the driving force for permeation, and the separated CO2 is at
low pressure and requires additional compression to meet pipeline pressure requirements.
The energy required for gas compression is significant when a very high pressure is required. Figure B-4
shows the amount of CO2 generated for compressing a unit of CO2 in the flue gas as a function of
compression for using coal and natural gas as the compression fuels (Chakravarti et al., 2001). The
breakeven point is about 8.3 MPa (1200 psia) for coal fuel, beyond which the amount of CO2 produced in
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compressing the flue gas, will be more than the amount of CO2 captured from 10% CO2 flue gas.
However, for membrane separation, a moderate pressure 0.70 - 0.14 MPa (up to 100 ~ 200 psig) of feed
gas has been shown to be adequate. Clearly the objective is to maintain good separation performance at
moderate pressures. Compared to the amine absorption process, the membrane process may have a higher
compression cost, but it does not require any solvent regeneration. On the life cycle basis, the membrane
systems are likely to be very competitive with the amine process in terms of the overall energy
consumption.
Coal-Flue gas compression (10% CO2)
Coal-Amine absorption + CO2 compression
NG-Flue gas compression (10% CO2)
NG-Amine absorption + CO2 compression
Figure B-4: Amount of CO2 generated by compressing unit amount of CO2 as a function of
compression pressure
Los Alamos National Laboratory, USA is developing a high temperature polymeric membrane with better
separation performance by supporting a polybenzimidazole (PBI) film on a sintered metal support. The
PBI possesses excellent chemical resistance, a high glass transition temperature (450oC) and good
mechanical strength. This type of membrane is highly selective and is able to operate at flue gas
conditions (Klara and Srivastava, 2002).
Ion transport membranes
The high cost and energy penalty associated with O2 production is currently a major barrier to the
commercial application of oxyfuel combustion system and precombustion capture systems where oxygen
is a key component of the process. The current state of the art in commercial O2 production is cryogenic
air separation, which is relatively energy and cost intensive process.
As a consequence, new membrane based oxygen separation technologies are being developed. Ion
transport membranes (ITMs) are being developed for production of oxygen using high temperature mixed
oxide materials such as perovskites, which will simultaneously conduct electrons and oxygen ions (see
Figure B-5) when there is a difference in the activity such as a difference in oxygen partial pressure across
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the material. The ITM system may consist of flat square section hollow plates arranged sequentially on a
hollow collector tube and mounted in a pressure vessel through which heated air flows over the “fins”.
Oxygen diffuses through the membrane surfaces due to a pressure gradient and pure oxygen is collected,
cooled and compressed to delivery pressure.
Figure B-5: Ion transport membrane (ITM)
In two parallel programs, the EU and US-DOE are pursuing extensive work to develop commercial scale
technologies by 2010. The EU sponsored consortia at the forefront of the membrane development are led
by Air Products (developing ion transport membranes – ITMs), Praxair (developing oxygen transport
membrane-OTM) and Alstom/Norsk Hydro (developing mixed conducting membrane- MCMs). The goal
of the US DOE program is to demonstrate an ITM based O2 production technology at pre-commercial
scale and to achieve cost and energy saving targets that are approximately 33% lower than the
conventional cryogenic plants for O2 production.
Gas absorption membranes
Gas absorption membranes are micro-porous solid membranes that are used as contacting devices between
gas flow and liquid flow (see Figure B-3). The CO2 diffuses through the membrane and is removed by the
absorption liquid, which selectively removes certain components from a gas stream on the other side of
the membrane. In contrast to gas separation membranes it is the absorption liquid (not the membrane) that
gives the process its selectivity (McKee, 2002).
Micro-porous hollow fiber membranes are evolving as a new technology for CO2 separation using the
amine-based chemical absorption processes. Micro-porous membranes are used in the gas-liquid unit
where the amine solution is contacted with the CO2 containing flue gas. The principle advantage of the
micro-porous membrane is the reduction in the physical size and weight of the gas-liquid contacting unit.
Unlike conventional membrane separation, the micro-porous hollow fiber membrane separation is based
on reversible chemical reaction, and mass transfer occurs by diffusion of the gas through the gas/liquid
interface just as in the traditional contacting columns (Wong et al., 2002).
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The hollow fiber membrane itself does not contribute to the separation but instead acts as a contacting
medium between the gas and the liquid. There are a number of advantages to using the gas-liquid
membrane contactors, including:
•
High gas/liquid contact area due to the high packing density of the hollow fibers (500 to 1,500
m2/m3 versus 100~250 m2/m3 for a conventional column)
•
Foaming is eliminated because the gas flow does not impact the solvent and there is no connective
dispersion of gas in the liquid.
•
The membrane acts as a partition between the gas and liquid, and the gas/liquid flow rate ratio
may vary in a wide range without causing flooding problems.
•
The available gas/liquid contact area is not disturbed by variations in flow rates. This means the
process can tolerate a wider range of process condition variations.
•
Solvent degradation is minimized as oxygen (a degradation agent to amines) is prevented from
intimate contact with the solvents.
•
Unlike the absorption column that can only be operated vertically, the hollow fiber membrane
contactor may be operated in any orientation to suit the overall plant layout.
Three companies: Kvaerner (Norway), TNO (Netherlands), and the Alberta Research Council (Canada)
are the active players pursuing the micro-porous membrane contactors for flue gas treatment.
Very little technical details are available on both the Kvaerner and the TNO solvents or membranes. The
ARC research program is investigating following key technical issues in micro-porous membrane
technology:
•
Wetability of the membranes
•
Chemical stability of membrane
•
Geometry of the membrane
•
Alternative solvents
As mentioned in the above sections, several membranes with different characteristics may be required to
separate high-purity CO2 in the capture systems. Membranes could be used to separate CO2 at various
locations in the capture systems, for example from syngas gas in IGCC or during combustion in a gas
turbine. However membranes have not been optimized for the large volume of gas separation that is
required for CO2 capture. Membranes cannot usually achieve high degrees of separation, so multiple
stages and/or recycle of one of the streams is necessary. This leads to increased complexity, energy
consumption and costs.
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Cryogenic (low temperature distillation)
The critical temperature of CO2 is 31.1oC and its triple point is –56.6oC. Hence CO2 in a high
concentration stream can be selectively liquefied and distilled by careful manipulation of pressure and
temperature (refrigeration/heating). Cryogenic separation is widely used commercially for purification of
CO2 from streams that already have high CO2 concentrations (typically >70%). It is not suitable for dilute
CO2 streams such as flue gas from coal/natural gas fired boilers, as the amount of energy required for
refrigeration is uneconomic for the plant. Cryogenic separation has the advantage that it enables direct
production of liquid CO2, which is needed for economic transport, such as transport by ship or pipeline.
The most promising applications for cryogenics are expected to be for separation of CO2 from high partial
pressure gases, such as in pre-combustion capture systems, or oxyfuel combustion in which the input gas
contains a high concentration of CO2.
In conclusion, in terms of suitability of the capture systems, each capture technology discussed above has
different limitations and different applications. While chemical absorption suits low concentration (see
Table B-3) flue gases in a post-combustion system, the physical absorption and the membrane absorption
technologies are a better fit for capture of CO2 from syngas in precombustion and in industrial systems.
The natural choice of capture technology for oxyfuel combustion where the CO2 concentration in the flue
gas exceeds beyond 70%, would be cryogenic capture. It should be noted that these technologies may
have even better performance when used in combination i.e. hybrid technologies.
Table B-3: Suitability of separation processes to feed gas streams (Wong et al., 2002)
Capture Technology
Chemical
CO2
Concentration
(%)
Operating
Feed
Gas
Temperature
Pressure (MPa) o
( C)
Pre-treatment
>3
> 0.1
Required
50
Absorption
Low
Physical
> 20
>2
Required
-10
Adsorption
> 30
Moderate
Low to moderate
Required
Cryogenic
> 90
Moderate
Low
Required
Membrane
> 15
> 0.7
Feed temperature
Required
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CO2 Capture Opportunities in Canada
Electricity Generation
The coal-fired generators are part of NRCan’s Large Final Emitter’s (LFE) group, and projections show
that LFEs could be responsible for up to half of Canada's GHG emissions by 2010 (see Figure A-1). As a
result, companies under the LFE system are being asked to collectively reduce their emissions by 55 Mt/yr
CO2e by 2008 – 2012 (CCTRM, 2005). Although there may be some negotiations on this number,
industry will be expected to reduce emissions during the Kyoto and any subsequent commitment periods.
Electricity generation, which emits 17% of total Canadian GHGs, accounted for 40% of LFE emissions in
1997. Thermal power generation is the largest single industry sector source under the LFE, and coal-fired
facilities generate the majority of those emissions. Emissions reduction targets for all of the sectors under
LFE are being established through voluntary covenant agreements between government and industry,
which are based on regulatory compliance and financial penalties for non-compliance. The government
will have sector specific backstop targets in place in case covenant agreements are not reached. A series
of options have been discussed for power generation, including a national thermal intensity target,
provincial/territorial thermal intensity targets, and intensity targets for new and/or near end-of-life thermal
plants.
Fossil-fuel generators are important to these discussions because they are the sources from which
meaningful CO2 emissions reductions can be made, and coal is the most emissions-intensive of all fossil
fuels. Also, large stationary point sources (such as a thermal plant) are generally thought to be the best
places for retrofits, in terms of cost-effectiveness due to the scale of the facilities. As a result, the
Canadian Clean Coal Technology Roadmap (CCTRM) recognizes that the development and deployment
of CCTs is essential for reducing GHG emissions from coal. Carbon capture and storage (CCS) is an
important component of CCT, as it will enable the possibility of truly near-zero emissions from fossil fuel
power generation.
To meet the challenge, Canada’s electricity industry has suggested an emissions performance equivalency
standard (EPES) as a starting point for the discussions on new and near end-of-life plants, proposing that
coal-fired plants achieve an equivalent rate of emissions intensity to that of a natural gas combined cycle
(NGCC) plant. Elements of the proposed EPES include: new facilities meeting or exceeding the standard,
facilities 40 or more years old meeting or exceeding the standard, and facilities less than 40 years old
being exempt. Industry believes that applying this standard would lead to a more than 50% reduction in
net CO2 emissions intensity from coal-fired plants.
The Canadian Clean Power Coalition (CCPC) is handling the development of standards for existing
plants. The CCPC recently conducted an extensive study to evaluate the expected performance of near
term clean coal technologies. The CCPC study concluded that it would not be cost effective to retrofit
existing facilities for CO2 capture because of the large energy penalty involved and the cost of retrofits.
Therefore, industry is requesting that existing facilities be left in operation and be exempt from CO2
emissions reductions until they reach their 40 year economic life. Thus, it is proposed that GHG
emissions from power generation be dealt with solely through new coal-fired facilities and brown-field
installations on existing sites.
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Figure B-6 is a cumulative plot of Canada's coal-fired facilities that will require replacement (expressed in
MWe decommissioned) as they reach their 40-year life (CCCTRM, 2005). About half of the current
installed capacity is over 25 years old, 33 units will have reached economic maturity by 2015, and 61 will
need to be replaced by 2034. If Canada opted for the proposed EPES standard, all of Canada's coal-fired
facilities will be performing to the standard of an equivalent NGCC plant by 2035. The rate of change to
the higher performance standard is approximately 725 MWe/year, assuming a start date of 2005 and
continuing for the next 25 years. As the average emission intensity of a new CCT plant is approximately
1.5 times more than an NGCC plant (without CO2 capture), this target translates into cumulative addition
of coal fired plants having cumulative addition of capture capacity at the rate of 2 Mt CO2/y for next 25
years, capturing about total 50 Mt CO2/year from the all coal fired plants in the year 2035.
Figure B-6: Replacement schedule from Canadian coal-fired facilities
CCTRM envisages that variants of oxyfuel combustion/post-combustion capture system based on
pulverized coal (PC) and variants of pre-combustion capture systems such as IGCC, will be the base
technologies for meeting this target. As the 2020 – 2025 timeframe approaches, and if CO2 storage
conditions are proven suitable, clean coal plants may be able to deliver even better performance with nearzero emissions electricity (capturing total ≈135 Mt CO2/year in the year 2035).
CO2 capture opportunities in non power-sectors
Iron and steel production
About 60% of global steel production comes from primary integrated steel mills. However, these mills
account for over 80% of CO2 emissions from steel production (IEA GHG, 2000a). Due to process related
emissions, the concentration of CO2 from steel plants is higher than gas or coal fired plants. According to
recent estimates, using available capture technologies, this sector alone can help reduce global CO2
emissions by 4% (Gielen, 2003)
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The Canadian iron and steel sector is composed of four integrated steel plants with coke ovens, blast
furnaces, and basic oxygen furnaces, one non-integrated plant operating a basic oxygen furnace, and 11
non-integrated plants operating electric arc furnaces. Canada’s iron and steel sector was the 13th largest
steel producer in 2000 with production of 16.5 million tonnes or two percent of world production
(Environment Canada and CCME, 2002). It is interesting to note that Canadian steel industry has
responded positively to voluntary covenant agreements between government and industry, which are
based on regulatory compliance and financial penalties for non-compliance. This affirms the potential
opportunities of reducing CO2 emissions in this sector through capture and storage.
Iron ore and
Carbonaceous fuels
Blast furnace
O2
plant
Electricity
Steam
turbine
Off gas
CO, CO2, , H2, N2
Oxy-fired
Process
Heaters
To vent
(current practice)
Air-fired
Process
Heaters
Flue gas
Shift reaction
N2/H2
CO2 capture
Enriched
Membrane
H2
CO2
Compression
train
Expansion
turbine
Electricity
To
transport & storage
Figure B-7: CO2 capture from a conventional blast furnace ( … shows the capture options)
Direct GHG emissions from steel plants were 14.5 Mt in 1996 or 2% of Canada’s total GHG emissions.
Virtually all emissions were CO2 from the fossil fuels used in ore smelting/reduction and in combustion.
The two main sources of GHG emissions are the coal and natural gas used in iron and steel production.
Integrated steel producers are estimated to account for 85% of steel industry GHG emissions. The largest
sources of CO2 come from coke oven gas and blast furnace gas (Issue Table, 2000)
About 70% of the carbon input to an integrated steel mill is present in the blast furnace gas, which is used
as fuel gas within the steel mill. Blast furnace gas typically contains 20% by volume CO2 and 21% CO,
with the rest being mainly N2; its pressure is typically 2-3 bar. CO2 could be captured before or after
combustion of this gas. The CO2 concentration after combustion in air is about 27% by volume,
significantly higher than in the flue gas from power stations. The higher flue gas CO2 concentration can
reduce the energy penalty of capture depending on the type of CO2 capture technology deployed. Other
process streams within a steel mill may also be suitable candidates for CO2 capture, before or after
combustion, for example the off-gas from an oxygen-steel furnace contains typically 70% CO and 16%
CO2 (well suited for shift conversion followed by CO2 capture or oxyfuel combustion and CO2 capture).
Currently, blast furnace gas composition is changing because of increasing injection of coal, natural gas
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and plastic waste into existing furnaces (Gielen, 2003). As these fuels reduce the temperature in the blast
furnace, the effect is balanced by 50-75 kg of oxygen injection per ton of iron. The oxygen enrichment
decreases the N2 concentration in the off gas and concentrations of CO, CO2 and H2 increase which further
favours the cost effective capture (see Figure B-7).
In contrast to a blast furnace, CO2 capture is already widely applied in the iron and steel industry in the
production of Directly Reduced Iron (DRI) in order to enhance the flue gas quality. CO2 is removed from
the reduction gas and is vented to atmosphere while the reduction gas is recycled for DRI production. A
typical example of DRI process coupled with a gasifier is shown in Figure B-8.
Iron ore
Coal/Heavy fuel oil
/Pet coke/Naphtha
Recycle
Gas
Gas
cleaning
Shaft
Furnace
Gasifier
O2
O2
Plant
CO2
removal
S
c
r
u
b
b
e
r
To vent
(current practice)
CO2
Compression
and
Dehydration
To
transport
& storage
Gas
heater
DRI
Enriched
Recycle Gas
Fresh Reducing Gas
MIDREXTM
Direct Reduction Plant
Gasification Plant
Figure B-8: DRI process coupled with gasification and CO2 removal
Cement production
The annual capacity of the Canadian cement industry is over 14.5 million tonnes of cement. Total CO2
emissions are 8 Mt/yr. (Canadian Cement Council, 1994; Humphrey and Mahasenan, 2002)
Cement is made in two basic types of process: wet, in which the raw materials (limestone and silica) are
ground in water and fed to the kiln as a slurry; and dry, in which the raw materials are ground and fed into
the kiln as a dry powder where the calcinations process takes place:
CaCO3
+
heat
(limestone)
CaO
+
CO2
(quick lime)
Preheater and precalciner kilns are modem fuel-efficient refinements of the dry process where
considerable heat is recovered from the exhaust gases (Canadian Cement Council, 1994). The wet process
is less fuel-efficient and generates more CO2 emissions than the dry process because of the need to remove
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the added water from the raw mix. The Canadian cement industry is technologically advanced, and more
than 80% of its production capacity is of the energy efficient dry process and precalciner/preheater types.
As discussed above, the production of cement and lime requires two main ingredients, each of which
contributes to CO2 emissions. The first source of CO2 emissions is the combustion of fossil fuels to heat
the kilns. Currently a large section of Canadian cement manufacturers use natural gas in the kilns.
However because of the rising price of natural gas, cement plants intend to switch to coal and other solid
fuels as kiln fuel. The second source of CO2 is chemical reaction (as shown above), calcinations, that
occurs in the kiln. Process-related CO2 normally accounts for more than half of the total CO2 emissions
and this proportion is expected to increase in future due to energy efficiency improvements as well due to
increasing share of solid fuels. In the conventional coal-based cement manufacturing processes, the
concentration of CO2 in the flue gas stream may vary from 14 % (in heaters and boilers) to 33 % in the
calcinators. The CO2 concentration of flue gases in the cement industry is higher than in power generation
processes, so cement kilns offer a potential opportunity for CO2 capture. CO2 could be captured using
suitable solvent scrubbing (depending on the concentration) but the large quantities of low-grade heat
required for solvent regeneration are normally unavailable at cement works (Thambimuthu et al. 2002).
One option is to build a combined heat and power plant that would provide the required heat and power
for the energy intensive cement plants. It may be quite possible to use oxyfuel combustion in cement
kilns but the effects of a higher concentration of oxygen and CO2 in the flue gas on the process chemistry
would need to be assessed.
Hydrogen/Ammonia production
Large quantities of hydrogen are widely used in petroleum refining, ammonia synthesis and in the
upgrading of raw bitumen extracted from the oil sands in the Western Canadian Sedimentary Basin
(WCSB). Production of refined petroleum products from oil sand bitumen requires 5-10 times the amount
of hydrogen compared to conventional crude. With the projected expansion of oil sands operations in
WCSB, hydrogen demand for oil sand sector alone is likely to quadruple to 56 Mm3/day by 2010 (Keith,
2002; Thambimuthu, 2003). This will be equivalent to 20% of current world production of H2 for refining
applications. This scenario is likely to place in Alberta, the world’s largest concentration of hydrogen
plants, and possibly an attractive opportunity for low cost CO2 capture. Currently all commercial
hydrogen production in WCSB comes from steam methane reforming (SMR) of natural gas. According to
projected growth rates of hydrogen production, the SMR and water-gas-shift alone will produce around 13
Mt CO2/yr by 2010. However, the increasing price of natural gas is raising serious concerns on
sustainability of natural gas dependent oil sand operations. The new thinking is to replace natural gas with
the other low cost fuels such as coal or the petcoke for producing the heat, hydrogen and electricity
required for economic oil sands operations. According to the projections from Oil Sand Technology
Roadmap (OSTR, 2004; see Figure: B-9), the increasing production rates of oil sand operations when fuel
requirements are supplemented by solid fuels will result in the high CO2 emissions (225 Mt/y) by the year
2030. A major fraction of high conc. CO2 will come from increased demand for hydrogen for upgrading
the bitumen.
At present, Benfield and PSA processes are used for producing pure streams of hydrogen in SMR
operations. The Benfield process is a conventional process and involves high and low temperature shift
followed by CO2 removal through chemical absorption (Benfield solvent, see earlier sections), producing
a high purity hydrogen stream as shown in Figure B-10. The off gas contains basically 47% CO2 and 52%
water which can be easily removed through condensation followed by CO2 compression.
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Figure B-9: Greenhouse gas emissions from future oil sands projections
The Pressure Swing Adsorption (PSA) process which uses a PSA unit instead of a solvent to purify the
product hydrogen, is emerging as the process of choice as it involves only a high temperature shift
conversion and provides a very high purity (>99.5%) of H2 stream as shown in Figure B-10. Although the
off gas contains sufficiently high concentration of CO2 (46%), the presence of methane (20%), hydrogen
(23%) and CO (10%) makes CO2 capture a costly affair, if captured through conventional solvents. Under
the current practice, in PSA plants, for synergic reasons, the residual off gas stream is mixed with other
fuel gases and then combusted as fuel.
One possibility could be to use oxy-fuel combustion which will maintain the energy requirements of the
process but at the same time will produce nearly as high concentration of CO2 as in Benfield process
where CO2 can be capture through condensation followed by CO2 compression (see Figure B-10).
Natural gas processing
Raw natural gas varies widely in composition and is rarely suitable for pipeline transportation. Natural
gas (NG) may contain 0-30% CO2 by volume. In addition to this, raw natural gas may contain significant
amount of other impurities such as H2S and nitrogen In fact MEA solvents were developed 60 years ago
specifically for this purpose. The mean CO2 concentration of natural gas produced in Canada is currently
about 2.5%, implying that the total production of well CO2 is around 9 Mt CO2/year, equivalent to about
1.5% total Canadian CO2 emissions (Keith, 2002). Since NG production in Canada is likely to rise by 50%
by the next decade, the NG well CO2 production is likely to rise to 14 Mt CO2/year, which will be
equivalent to 2.3% of total CO2 emission in Canada (CEO, 1999). Under existing practice, while treating
natural gas to meet piping specifications, this CO2 is captured but is vented to atmosphere. Figure B-11
shows a typical process sheet for natural gas processing and the proposed route to capture CO2 for storage.
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Also the Figure shows the option of onsite acid gas injection (AGI) involving CO2 onsite sequestration
with the H2S removed from the gas, thus avoiding the cost of CO2 and H2S separation.
Product
Methanator
Benfield
Process
H2
Low Temp Shift
High Temp Shift
To vent
(current practice)
CO2 removal
through
absorption
Flue gas >90%CO2 (dry basis)
Compression
and
Dehydration
Methane
CH4
To transport
& storage
Catalytic
Reformer
Product
PSA Unit
Steam
H2
CO, CH4
H2 CO2
Air-fired
Process
Heaters
PSA
Process
To vent
(current practice)
Flue gas
High Temp Shift
Oxy-fired
Process
Heaters
Flue gas >90%CO2
Compression
and
Dehydration
To transport
& storage
Figure B-10: Hydrogen production from natural gas: Benfield and PSA processes (--- shows the
proposed CO2 capture possibilities)
Oil refining
The refinery is essentially a carbon/hydrogen manipulator, tailoring and reshaping molecules and boiling
ranges to meet the production needs of particular fuels. All emissions from the refinery itself originate
from the feedstocks used. These feedstocks are mainly crude oil(s) to be processed plus other imported
feedstocks such as natural gas for steam or hydrogen plants. Figure B-12 shows CO2 emissions profile for
two typical 100 000 bpsd refineries, one hydrocracking (HCK) based, the other fluid catalytic cracking
(FCC) based (Philips, 2002).
Figure B-12 indicates that emissions are dominated by those resulting from burning of fossil fuel fired
heaters, power production and utilities (80-84%). In practice, refineries have a large number of process
heaters scattered with in the plant area. These heaters emit flue gases with CO2 concentrations of 4-14%
depending upon the fuel used. This makes CO2 capture more difficult, extremely expensive or even
impractical. However, there is potential for capture of CO2 produced from power generation, hydrogen
production and utilities within the refinery complex, which represents approximately half the refinery CO2
emission.
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Raw natural gas
Acid Gas
Removal
Clean natural
gas to pipeline
H2S, CO2
Air
Thermal
Reaction
Chamber
To acid gas injection (AGI)
Sulphur
Condenser
H2S, CO2
H2O, S2, N2, SO2
H2S, CO2
Catalyzer
Condenser
H2O, N2, SO2
CO2, H2O,
N2, SO2
Sulphur
To vent
(current practice)
To transport
& storage
CO2
CO2 capture
CO2, H2O,
Incinerator
N2, SO2
Compression
and
Dehydration
Figure B-11: Natural gas processing plant with CO2 capture and sequestration
HCK
Utilities
23%
Hydrogen
Plant
20%
FCC
Process
Heaters
44%
Power@3
4%
13%
Utilities
16%
Hydrogen
Plant
16%
Process
Heaters
53%
Pow er@
34%
15%
Figure B-12: Distribution of CO2 emissions in refineries
The possible CO2 capture options in a refinery include:
•
Capture from fired heater flue gases using a regenerable amine solvent.
•
Use of oxygen produced in an air separation unit (ASU) to burn the heater fuel (oxy-fuel
combustion). Flue gas is re-circulated to control the combustion temperature. Another important
application of oxyfuel combustion could be the fluid catalytic cracking (FCC) units in the
refineries. Under existing practice, the spent catalyst is regenerated using combustion (in air) to
get rid of coke that collects on the catalyst during FCC process. The resulting flue gas contains
low concentration of CO2 (see Figure B-13). The use of pure oxygen in de-coking of the catalysts
will result in highly concentrated streams of CO2. However the effect of pure oxygen on the
catalyst activity needs to be assessed.
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•
Use of a hydrogen-rich fuel gas in the fired heaters. Depending on the carbon content of the
primary fuel, CO2 capture can be before or after the fuel is burnt. The H2-rich fuel gas is made
from the refinery-produced gases supplemented by natural gas
Gas (C4 + )
To vent
(current practice)
Heat
recovery
Reactor
Separation
Vessel
Gasoline
Flue gas
Light gas oil
CO2
Capture
Spent
Fractionator
Catalyst
Heavy gas oil
Regenerator
Compression
& Dehydration
Riser
Bottom
Recycle
To transport
& storage
Air/Oxy-fired
Regenerated
combustion
catalyst
Figure B-13: Fluid catalytic cracking (FCC) process
It is interesting to note that following issues greatly influence the above options;
•
Fuel replacement
•
The need for hydrogen
In the past, the driving force behind fuel replacement has been SO2 reduction. However, it can be seen
from Figure B-14 that fuel switching from heavy oil to natural gas has a relatively small impact on CO2
emissions (only 20% for Fuel Oil No. #6). However, it costs more when one uses natural gas, which can
be otherwise used as a raw material for hydrogen production for upgrading the refinery products.
According to conservative estimates, more than 12 tonnes of CO2 per tonne of hydrogen is produced
irrespective of the manufacturing process. Thus the use of hydrogen as a refinery fuel does not make much
sense.
Hence for process heating, refineries need to look for fuels other than hydrogen or natural gas and need to
install the appropriate CO2 capture technologies. Figure B-14 shows that the typical emission intensity for
a refinery fuel gas (RFG). RFG has the highest emissions among the given fuel options, a major portion of
this fuel gas is from the inherent CO2 present in the feed gas itself (see Figure B-14).
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110
Fuel inherent CO2
CO2 emission intensity (kg/GJ)
100
90
Fuel combustion CO2
44
80
70
60
50
40
30
53
62
59
NG
RFG*
LPG
74
68
20
10
0
Kerosene
Fuel Oil
Fuel molecular weight
*RFG: A typical hydrogen rich refinery fuel gas
Figure B-14: CO2 emission intensity - Impact of fuel switching in a refinery
CO2 capture costs for various sectors
Generally, the cost of CO2 capture and the concentration of CO2 in the capture stream have an inverse
relationship. High purity CO2 sources are by far the most attractive candidates for capture. However as
shown in Figure B-15 the bulk of the potential streams in the WCSB consist of relatively dilute CO2
concentrations, with only 5 % of CO2 available from relatively high purity sources. Capture from high
purity sources is equivalent to a capture capacity of around 7Mt CO2/yr.
The significant contribution of coal-fired power plants is reflected in the large 10-20 % CO2 concentration
category. Virtually all of the CO2 from the lean (<10% CO2) streams is associated with natural gas-fired
operations.
3%
2%
20%
(<10
%)
CO
2 concentration
(10-20 %)
(20-50 %)
(>50 %)
75%
Total emissions: 141 Mt/year
Figure B-15: Concentration based distribution of CO2 emissions in WCSB: (CERI, 2002)
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Figure B-16 shows the typical capture cost for various different capture systems as a function of CO2
concentration in the emission stream (inlet for CO2 capture plant). Higher concentrations of CO2 in the
flue gases in the Benfield, IGCC and Oxyfuel systems results in a reduced cost of CO2 capture. In general,
the overall cost of CO2 captured decreases with the increase in CO2 concentration. The low concentration
streams involving chemical solvent scrubbing (PC) exhibit higher orders of the cost compared to the high
concentration steams. However, as the largest fraction of the total CO2 emission streams is contained in
low concentration streams, it is important to either address them through suitable capture technology such
as amine scrubbing or through altering the process such that O2/CO2 recycle, so that the existing
infrastructure can produce high concentration CO2 streams which can economically be captured for
storage.
140
NGCC
120
$/Net ton CO2
100
PC
Gas
Proce s s in g
80
PSA
60
Ce m e nt
Tre nd
40
Oxyfue l
IGCC †
Be nfie ld
20
0
0
25
50
75
100
% CO2 in Inle t (Dry)
† Conc. in the downstream of shift reactor
Figure B-16: Typical CO2 capture cost vs % CO2 in the flue gas stream
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APPENDIX C: ECONOMICS OF CO2 CAPTURE FROM
POWER PLANTS CONSIDERING NEAR TERM TO LONG
TERM BREAKTHOUGH TECHNOLOGIES
By Sam Wong (Alberta Research Council Inc.)
All the technologies involved in CO2 capture from coal combustion involve three components: (1) cleanup of the flue gas to remove impurities, (2) separation of the CO2 from the gas, and (3) compression of the
purified CO2 to pipeline pressure. Current coal combustion technology produces huge volumes of flue
gas with low CO2 content, low total pressure and contaminated with impurities. These factors mean that
CO2 production costs from this source will remain high. If costs are to be reduced in a meaningful way,
CO2 feed streams with a higher concentration/pressure of CO2 will have to be exploited in the future.
Environmental concerns may require future coal fired power plants to reduce particulate and other
emissions to a much greater extent than is commonly practiced today. This may provide an incentive to
burn coal using different technologies resulting in a more efficient energy producing plant, and a cleaner
flue gas stream from which CO2 can be recovered in a more cost effective way.
Since a thorough review of capture technologies was carried out in Appendix B, please consult it for
additional information for more details of a specific capture technology.
Near Term Technologies
All near term technologies are based on amine separation with improvement of the capture solvents
and/or steam integration in the process. Some immediate benefits can be realized if the amine-based
process can be heat integrated with the CO2 source plant by energy management, for example, a power
plant where substantial low-grade heat is available. Also, improved solvents are expected to result in cost
reductions (Figure C-1). However, order of magnitude improvements are not expected, as substantial
progress has already been made. To this end, chemical absorption including solvent selection and
contactor design are being improved at the International Centre for CO2 Capture in Regina,
Saskatchewan.
Medium Term Technologies
Medium term technologies are focused on use of membranes, either as contactors or as semi-permeable
membranes (Figure C-1). To this end, work on hollow fiber membrane absorption is being carried out at
the Alberta Research Council in Edmonton with a fiber-making machine at the University of Waterloo.
O2/CO2 recycle combustion (producing concentrated flue gas CO2 streams as an integral part of the
process with O2 produced by cryogenic separation) with extension to natural gas fired steam turbines and
gas turbines is being piloted at the CANMET Energy Technology Centre in Ottawa.
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60
ESA
Cost Reduction Potential (%)
50
Adsorption
SETS
CO 2 Hydrates
40
Membranes
30
Improved
Contactors
Optimized
Process
Improved
Cryogenic
Steam Solvents
Separation
Integration
20
10
0
0
5
10
Delivery Time Scale (Years)
15
20
Figure C-1: Potential Cost Reduction of CO2 Production (Ovals Represent Amine-Based
Processes, Rectangles Represent Other Processes)
A number of key technical hurdles have been identified in the micro-porous membrane technology that
have to be overcome within the next 5 to 10 years:
•
Wetability of the membrane
•
Chemical stability of the membrane
•
Geometry of the membrane
•
Compatible solvent
Though the challenges seem tall, the payback is high. Micro-porous membranes offer the promise of gasliquid contact units of smaller size and lighter weight than conventional towers. This is an important
consideration for flue gas applications where large volumes of gas have to be treated. The nature of the
micro-porous membrane is such that contact between the liquid and gas takes place within the micropores of the membrane itself. This greatly reduces liquid foaming problems and the carryover of liquid
spray from contact units. Since the gas-liquid contact occurs within the membrane, the units are expected
to be more forgiving of changes of gas or liquid flow rates than are conventional towers, however, this
has yet to be demonstrated in practice.
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The cost of the micro-porous membrane modules may be an issue; however, this cost may be offset by the
smaller size of the absorbing units. The flue gas feed to the micro-porous membrane units will have to be
free of fine particulate matter or the pores may become clogged resulting in a reduced mass exchange
rate. Particulate matter removal is also a requirement for conventional amine absorbing units to reduce
degradation of the absorbing liquid. Finally, there is only limited pilot experience with micro-porous
membrane technology and many designs are at the laboratory stage.
Micro-porous fibers are only one variation on a theme of polymer membrane separation technology.
Most polymer membrane separation technology is based on solid membranes. In solid membrane
technology, the membrane selectively transmits one component of a mixture of gases. The driving force
for this separation is typically pressure. In a flue gas situation, low starting pressure (1 atmosphere) and
low (10-15%) CO2 content make the cost of compression prohibitive.
Outlook for Longer Term Technologies on the Rise
The US research program on CO2 capture is more diverse including basic research and technology
development. A major thrust of this program is directed to capturing CO2 from synthesis gas and reformer
gas, which ties in with the Vision 21 R&D Program. Capture cost is expected to be lower as we can take
advantage of the pressure available from the reactor beds. The following are selected projects funded
under the carbon sequestration program, which hopefully will give a sense of the kind of technologies
emerging from the US (see Figure C-1):
Absorption:
(a) Vortex Tube Contactor, [Basic/applied research, extension of the Ranque-Hilsch vortex tube
technology]
The project studies CO2-liquid absorption kinetics, solvent regeneration requirements and scaleup parameters for vortex contactors. In a vortex contactor, solvent and gas under high pressure
are injected into a tubular reactor where they expand and accelerate to create a cylindrical flow of
fine mist down the tube, enhancing capture of the gas in the solvent.
Performers: [Idaho National Engineering and Environmental laboratory, Pacific Gas and Electric,
Southern California Gas, BP-Amoco and Purdue University]
Adsorption:
(a) Dry Regenerable CO2 Sorbents [Applied research]
The project is to develop a CO2 separation technology that uses a regenerable, sodium based
sorbent to capture CO2 from flue gas. Thermodynamic analysis and preliminary laboratory tests
indicate that the technology is viable. Process data will be collected to assess the technical and
economic feasibility of the various process configurations.
Performers: [Research Triangle Institute, Church and Dwight Inc.]
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Membranes:
(a) Membrane Reactor [Applied research, reforming reactions]
The project is to develop an inorganic, palladium-based membrane device that can reform
hydrocarbon fuels to mixtures of hydrogen and CO2 and at the same time separates the high value
H2. The CO2 can be recovered in a compressed form.
Performer: [Research Triangle Institute]
(b) Thermally Optimized Membrane [Applied research, clean power]
Structurally altered polymeric membranes are being developed and optimized for high
temperature operation (100 to 400oC) to enhance integration with power generation and industrial
systems.
Performers: [Los Alamos National Laboratory, University of Colorado, Idaho National Energy
and Environmental Laboratory, Pall Corporation and Shell].
Novel Concepts
There are also three novel concepts being developed which could be the breakthrough technologies of the
future. CO2 hydrate separation is currently aimed at synthesis gas separation. Its application to
combustion flue gas has not been assessed. Electrical swing adsorption is a completely new technology of
separation. Its potential is tremendous. The Sorbent Energy Transfer System opens a new way of burning
fuels.
The following is a brief description of these three technologies:
(a) CO2 Hydrate Process for Gas Separation from Shifted Synthesis Gas
This process is developed by SIMTECHE (a California based company), based on initial experimental
studies conducted at the California Institute of Technology (Caltech) from 1993 to 1995. CO2 hydrate will
form at temperatures near 0oC and pressures from 10 to 70 atmospheres, depending on the other gases
present and the partial pressure of the CO2 in the gas stream. The SIMTECHE CO2 hydrate separation
process is a two-stage process. First, “nucleated water”, saturated with CO2 is formed in the first reactor,
where circulating ammonia provides the cooling. Shifted synthesis gas (CO2, H2 and other gases) enters
the second reactor together with the nucleated water, at pressures from 6 to 20 atmospheres; CO2 hydrates
form rapidly and fix all CO2 entering the reactor. H2 is collected as the off-gas. The process is a good fit
with future coal gasification systems where the shifted synthesis gas streams come out at pressures of 20
atmospheres or above, and CO2 partial pressure of 8 atmospheres or more, ideally meeting CO2 hydrate
forming requirements. In addition, H2S present in the synthesis gas is also absorbed in the “nucleated
water”, due to the high solubility of H2S in water. Therefore, there is no need for a H2S removal and
sulfur recovery system in this process.
Laboratory work by Los Alamos National Laboratory (LANL) validated the Caltech claim that hydrates
can be produced in a flow-through system. This demonstration is an essential first step for industrial
implementation of the SIMTECHE hydrate technology. Equilibrium experiments have established the
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benefits of gaseous and liquid CO2 hydrate promoters. The promoters lower the initial formation pressure
of the hydrate, thereby increasing scrubber efficiency and allow operation far from the freezing
temperature. This simplifies operation and reduces the cooling required which is a major cost of
operation. Since H2 is inert and does not form a hydrate, no H2 will be lost which is not the case with
other processes. Performance of greater than 97% H2 recovery and greater than 86% CO2 separation has
been achieved. Preliminary process evaluation shows that it has significant advantage over conventional
H2S and CO2 removal, stripping and CO2 compression processes from both energy efficiency and overall
cost perspectives. Preliminary economics show that CO2 separation and sequestration can be achieved in
the range of $10 to 11/tonne of CO2 (Spencer et al., 1999)
Potential barriers to this technology are: the ability to release CO2 from the hydrate in an energy efficient
manner; efficient capture of CO2; stable pre-hydrate; and trace contaminants interfere with hydrate
formation. Nexant, Inc. (a Bechtel Technology and Consulting firm) has assembled an experienced team
of scientists and engineers from LANL and SIMTECHE to carry out a more detailed engineering and
economic evaluation. Results are not available in the public literature.
(b) Electrical Swing Adsorption (ESA)
The ESA system developed by Oak Ridge National Laboratory uses a novel carbon-bonded activated
carbon fiber as the adsorption material (Burchell et al, 1997, Judkins et al., 2001). This material is called
carbon fiber composite molecular sieve (CFCMS). Activation conditions for the CFCMS can be varied to
increase or decrease pore size, pore volume and surface area to improve the effectiveness of the carbon
fiber as a CO2 adsorbent. The monolithic material is rigid and strong, resistant to attrition and dusting, and
because of its continuous carbon skeletal structure, is electrically conductive. An adsorbed gas may be
quickly and efficiently desorbed by the passage of an electric current, thereby allowing a low energy,
electrical swing system. The electrical energy required for desorption is approximately equal to the heat
of adsorption of the adsorbed gas. It is possible to regenerate the CFCMS in the absence of a temperature
increase, potentially reducing swing cycle time and improving separation efficiency. Several separations
have been demonstrated such as the separation of H2 from experimental gas mixtures containing H2 and
H2S or H2 and CO2; separation of CO2 from CH4; and the separation of CO2, CO, H2S and H2O from a
variety of gas mixtures. The technology is at an early stage of development. There is great need for R&D
focused specifically on CO2 separation and capture. For example, development of modified activation
procedures to render the CFCMS more or less selective for CO2, systematic study of CFCMS to
maximize its adsorptive capacity for CO2 and integration of CFCMS with sequestration technology.
(c) A Novel CO2 Separation System
TDA Research Inc. (TDA), which is based in Wheat Ridge, Colorado, is developing a novel CO2
separation system called Sorbent Energy Transfer System (SETS). SETS transfers the energy of the fuel
without bringing the carbon along. The SETS works by using the fossil fuel (gasified coal, petroleum
fuels or natural gas) in a pressurized fluidized bed to reduce a metal oxide, thereby producing a metal (or
lower valence metal oxide), CO2 and water. The water is condensed and its energy used to raise steam
leaving a stream of pure CO2 at 3-6 atmospheres that can be sequestered. The metal oxide is burned or reoxidized in air to produce heat and the metal oxide required for the reduction step.
Alberta Research Council Inc.
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SETS utilizes the full chemical potential of combustion of the fuel, even though the net reaction is carried
out in two steps. However, as a result of the two-step process, no additional energy is needed to separate
CO2 from the combustion products, and the concentrated CO2 stream produced can be further compressed
for sequestration with very little additional energy.
TDA has tested both iron - and nickel - based oxygen sorbents. The lower cost iron - based sorbents were
strong, attrition resistant, and had enough oxygen capacity to fully oxidize fuel to CO2 and steam.
Measurements of the attrition rate carried out at both TDA and Kellogg, Brown and Root Inc., showed
that the iron - based sorbents would last for more than 1,000,000 cycles. However, testing also
demonstrated that the iron-based sorbents could not be used for extended period at temperatures above
800oC because the iron sinters into larger, less reactive crystallites. This temperature limitation would not
allow the system to take advantage of modern, high efficiency gas turbines typically operating today. In
this aspect, the Ni - based sorbent fared better. It had excellent activity, strength, attrition resistance, and
the ability to fully oxidize fuel (CH4) to CO2 and steam at 1,050oC without sintering.
Because the sorbents developed by TDA have very high surface areas and are small and porous to reduce
mass transfer resistance, they can be fully oxidized in 3 seconds and reduced in less than 18 seconds.
Thus, the SETS process can be carried out in small, high throughput (transport and fluidized bed)
reactors. Because the reactors are small, internally insulated and do not require exotic materials the capital
cost of the system is very low.
SETS can capture CO2 for sequestration. Costs are on the order of US $10 – 20/ton for separation and
compression to pipeline pressures (Copeland et al., 2001).
Consequently, in the longer term, CO2 capture technologies would not be limited to amine-based
technologies. This concept is displayed in Figure C-1 along with other projections of future cost
reductions. Separation technologies such as hydrate formation, various membranes and many others that
are currently in the developmental stage, offer the promise of significantly reduced costs.
Commercialization of coal gasification is expected in this time frame.
Cost Curve Frontier
Using data from the literature, three sets of cost curves - the near-term (0-5 years), mid-term (5-10 years)
and long-term (10-15 years), were constructed (see Figure C-2). Also, the present cost of capture is
indicated by the MEA Reference point in Figure C-2.
Near Term (0-5 years)
In the near term, the Mitsubishi Heavy Industries/Kansai Electric Power (MHI/KEP) KS-1 solvent
absorption process including the KP-1 packing probably represents current best available technology,
although the Fluor Daniel ECONAMINE FG is also close. However, the MHI/KEP KS-1 process has
only limited commercial experience. The commercial plant in Malaysia has only been in operation from
October 1999. Feed gas for the Malaysia plant is based on a steam reformer off-gas with 8 vol.% CO2.
Plant performance so far has been excellent. Low-pressure steam consumption was 1.5 ton/ton of CO2
recovered and solvent loss was 0.35 kg/tonne CO2. Degradation of the KS-1 solvent was very slow. It was
reported that reclaiming operation was not required even after 5,700 hours of operation.
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One drawback of the MHI/KEP KS-1 process is the lack of large plant experience. The scale of the
Malaysia plant is 160 tonnes of CO2 per day, so the scale up of the plant to the 5,000 tonnes per day level
contemplated for recovering CO2 from coal-fired power plant flue gas may be suspect.
The curve labelled Current (KS-1) was generated using a spreadsheet model developed by SNC-Lavalin
for ARC. The spreadsheet model was used to develop cost estimates using MHI/KEP vendor data for
CO2 capture.
Capital cost for a 5,500 tonnes per day CO2 stand-alone plant was estimated at Canadian $ 348 million.
The cost of the CO2 recovered was $ 55.1/tonne, including a compression cost of $ 11.2/tonne. All costs
are in constant 2000 Canadian dollars. In this analysis natural gas price of $ 3.25 /GJ and electricity price
of $ 50 /MWh are used. Cooling water was assumed to be available at reasonable price across the fence
from the power plant.
The model was then re-run for different CO2 concentrations in the flue gas, from 3% to 50%. The costs of
CO2 recovered ranged from $41/tonne for 50% CO2 to $ 114/tonne for 3% CO2. It should be noted that
for the 3% CO2 case, it is based on a natural gas fuel, and desulfurization is probably not needed, our
estimate would likely be on the high side.
These costs of CO2 compared well with other estimates. Fluor Daniel has developed a cost of $63.34
/tonne CO2 using the ECONAMINE FG Process for a coal-fired power plant flue gas with 13% CO2. For
a gas turbine flue gas with 3% CO2, the cost of CO2 was $85.00 /tonne. The ECONAMINE FG process
was very similar to the MHI/KEP KS-1 process in terms of costs. The Canadian Energy Research
Institute (CERI) in its recent study provided an estimate of $ 71.00 /tonne CO2 for the 13% CO2 case.
However, even though the same model was used, the CERI study used a different financing structure and
higher energy costs.
As can be seen from the curve, the cost of CO2 capture using the KS-1 amine based process decreases
with increasing CO2 concentration in the feed gas. This lowering of the cost curve reflects a situation
where heat requirements for CO2 liberation from the solvent are a significant part of the operating costs.
As heating requirements are lowered for higher CO2 concentration, capture costs are lowered
significantly. Also shown from the curve, CO2 capture costs increase rapidly when the CO2 concentration
is lower than 10%.
Medium Term (5-10 Years)
In the medium term, application of hybrid membrane/amine technology will be quite robust.
Perhaps the most promising opportunity for reducing the cost of CO2 production is changes in combustion
technology. Combustion of coal in an oxygen enriched atmosphere allows higher efficiency and in the
mean time results in the production of a flue gas containing CO2 at concentrations and pressures above
that of conventional combustion technology.
A further 30% reduction from the MHI/KEP KS-1 capture cost is plausible in the medium term using
hollow fibre membrane technology. The curve frontier for a 13% CO2 flue gas case would be in the order
of $ 42 /tonne. Improvements would be limited by the regeneration energy requirement. This shift in costs
is represented as the Medium Term cost curve in Figure C-2.
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Unit CO2 Production Cost (CAD$/t CO2)
140
120
100
Reference
MEA
80
60
Current
(KS-1)
40
Medium Term
20
Long Term
0
0
10
20
30
Inlet CO2 Concentration (mol %)
40
50
Figure C-2: Cost Curve Frontiers
Long Term (10-15 years)
In the long term, new CO2 separation technologies such as the CO2 hydrate separation process and
Electrical Swing Adsorption (ESA) process which are small scale at present may be commercialized.
These technologies offer significant potential for cost reduction.
Long term processes by their nature are more speculative and unclear; however, the major CO2 cost
breakthrough will probably involve alternative coal combustion technology. Alternative separation
technologies associated with pre-combustion decarbonization may be further developed given the right
environment. These technologies have great potential for CO2 production cost reduction as an alternative
to the amine-based systems. They operate most efficiently at elevated CO2 concentration and/or pressure.
Pre-combustion decarbonization of coal/natural gas in an oxygen or oxygen-steam atmosphere
(gasification) results in a gas stream containing a high concentration of CO2 at elevated pressure. This
facilitates CO2 production by making alternative technologies viable, and may be expected to greatly
improve process economics.
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In Figure C-2 a cost curve is displayed and labelled Long Term. Given that the technologies, particularly
those with breakthrough potential are still at an early stage of development, economic data are lacking or
not available. However, preliminary economic analyses on some of the novel technologies given the
limited data indicate that CO2 capture can be achieved at a cost US $ 10 /ton ($ 11/tonne) for coal-fired
power plant flue gas. Perhaps, an ultimate cost curve boundary of US $ 16 – 33 /tonne range (including
compression), with poorer quality CO2 gas stream at the higher end of the cost curve is viable for this
period.
Novel technologies for fuel combustion such as the Sorbent Energy Transfer System (SETS) represent a
new approach to fuel combustion; however, this and similar technologies will require considerable
development before the economics can be assessed.
References
Appendix C is based on a portion of a report by: Wong, S., Payzant, J., Bioletti, R. and Feng, X.,
(2002). “CO2 Separation in Enhanced Oil Recovery: A State-of-the-Art Technical & Economic
Review”, Prepared by Alberta Research Council for Alberta Energy Research Institute, March. A
more comprehensive reference list can be found in this report. All the references below come from this
report.
Burchell, T.D., Judkins, R.R., Rogers, M.R. and Williams, A.M. (1997), “A Novel Process and Material
for the Separation of Carbon Dioxide and Hydrogen Sulfide Gas Mixtures”, Carbon, 35(9): 1279-94.
Chakma, A. and Tontiwachwuthikul, P. (2001), “Economics and Cost Studies of Designer Solvents for
Energy Efficient CO2 Separation from Flue Gas Streams”, Fifth International Conference on Greenhouse
Gas Control Technologies, Cairns, Australia.
Copeland, R.J., Alptekin, G., Cesario, M. and Gershanovich, Y. (2001), “A Novel CO2 Separation
System”, First National Conference on Carbon Sequestration, Washington, DC, May 15-17, 2001.
Iijima, M. (1998), “A Feasible New Flue gas CO2 Recovery Technology for Enhanced Oil Recovery”,
SPE paper 39686, Presented to1998 SPE/DOE Improved Oil Recovery Symposium, Tulsa, Oklahoma,
April 19-22, 1998.
Judkins, R.R. and Burchell, T.D. (2001), “CO2 Removal from Gas Streams Using a Carbon Fiber
Composite Molecular Sieve”, First National Conference on Carbon Sequestration, Washington, DC, May
15-17, 2001.
Mariz, C.L. (1998), “Carbon Dioxide Recovery: Large Scale Design Trends”, Journal of Canadian
Petroleum Technology, Vol. 37, 7, July 1998.
Mimura, T., Satsumi, S., Iijuma M., Mitsuoka S., (1999), “Development on Energy Saving Technology
for Flue Gas Carbon Dioxide Recovery by the Chemical Absorption Method and Steam System in Power
Plant”, Proceedings of the Fourth International Conference on Greenhouse Gas Control Technologies,
pp.71-76, Interlaken, Switzerland, 1999.
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Mimura, T., Matsumoto, K., Iijuma M., Mitsuoka S., (2001), “Development and Application of Flue Gas
Carbon Dioxide Recovery Technology”, Proceedings of the Fifth International Conference on
Greenhouse Gas Control Technologies, pp.138-142, Cairns, Australia, 2001.
Spencer, D.F. (1999), “Integration of an Advanced CO2 Sequestration Process with Methods for
Disposing of CO2 in Oceans and Terrestrial Aquifers”, Proceedings of 4th International Conference on
Greenhouse Gas Control Technologies, Riemer, P., Eliasson, B. and Wokaun, A., editors, 1999.
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APPENDIX D: A SELECTION OF NATIONAL AND
INTERNATIONAL ACTIVITIES RELATED TO CARBON
CAPTURE
By Brent Lakeman (Alberta Research Council Inc.)
Overview
While Canada has a significant opportunity to achieve significant CO2 emissions reductions through the
adoption of carbon capture and storage practices, Canada is not alone in advancing technology
development in this area. Currently, there are a range of regional, national and international partnership
activities related to CO2 capture and storage research and development and policy development. These
initiatives typically involve industry and other stakeholders. Many of these initiative have established
extensive research, development and demonstration budgets related to the goal of CO2 capture that are an
order of magnitude greater than Canadian governments and research organizations have dedicated
towards this issue. Canada has the opportunity to learn from these international initiatives and focus its
own research activities on specific gaps or unique conditions with Canada (e.g. climate, nature of energy
supply) and the Western Canada Sedimentary Basin in particular where the greatest opportunities over the
short-medium term appear to exist.
Following is a description of some of these national and international initiatives that are important to
Canada.
National
International Test Centre for CO2 Capture
(http://www.co2-research.ca/main.html)
The International Test Centre’s missions is to perform R&DD (Research, Development and
Demonstration) in select niche areas for which Canada has natural advantages over other nations and
develop technologies that will not only help Canada meet our CO emission reduction targets but will also
allow export of such technologies, thus providing a double dividend. The Test Centre brings researchers
and leaders from industry, universities, government agencies and laboratories together to perform targeted
and coordinated research activities that will yield short ( <10 years) and medium term ( <25 years)
technological solutions.
2
One of the Test Centre’s initiatives is a pilot-scale project (4 metric tons per day CO2 capture) located on
a flue gas slipstream of a lignite-fuelled power plant near Regina, Saskatchewan, Canada, that will
demonstrate CO2 capture using chemical solvents. Supporting activities include bench- and lab-scale units
that will be used to optimize the entire process using improved solvents and contactors, develop
fundamental knowledge of solvent stability, and minimize energy usage requirements. More than $5
million has so far been spent on construction of the pilot facility at the project site and another $3 million
on a pilot plant (1 metric ton per day CO2 capture) at the University of Regina where additional testing is
taking place. The goal of the project is to develop improved cost-effective technologies for separation and
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capture of CO2 from flue gas. Current research is demonstrating significantly reduced regeneration energy
requirements.
CANMET Energy Technology Centre
(www.nrcan.gc.ca/es/etb/cetc/)
Oxy-fuel Combustion
CETC has been conducting R&D in oxy-fuel combustion technologies for CO2 capture and storage for
more than ten years now under the umbrella of an international consortium. The Consortium was formed
in 1994, and at different points in time, the membership comprised Canada’s major Canadian coalfired
electric utilities, Canadian and US government agencies, and other international industrial partners. Under
this program, which is now in Phase 8, a capital investment of about $6 million has been invested in the
pilot scale research facilities and an additional $5 million has been invested in ongoing research and
development to support the consortium interest in combustion research in O2 enriched environments for
enhanced CO2 capture and storage. This pilot-scale facility has a rated capacity of 0.3 MWth and can
operate in a wide operational envelope, from normal combustion in air to combustion with high O2
concentration and flue gas recirculation. Since its formation, the CO2 consortium has generated a large
knowledge base in the area of oxy-fuel combustion for clean power generation through extensive testing
with fossil fuels, and development of tools and models for process and CFD simulations, low-NOx oxyfuel burners, advanced cycles, and zero-emissions micro gas turbines. The pilot scale facility has been
recently redesigned to enhance its capabilities for development of the 2nd generation advanced oxy-fuel
combustion systems, under the Climate Change Technology and Innovation (T&I) Program. Current
research aims to demonstrate:
New variants of advanced oxy-fuel cycles with CO2 capture that would lead to the development, with
lower or zero recycle flows, of a new generation of more compact, near-zero emission power plants;
and,
A novel CO2 compression unit for generating transport-ready CO2 streams by capturing, purifying,
and compressing CO2 from the stack flue gas of oxy-fuel combustion boilers.
CETC has also recently received funding for development and demonstration of oxy-fuel firing in a
CFBC (circulating fluidized bed combustion) boiler using its 1MWth CETC pilot-scale CFBC boiler to
test a range of Canadian fuels and to carry out process simulations and economic evaluation.
Coal Gasification
In addition to oxy-fuel combustion, CETC has been involved in coal gasification for over 20 years and
has played a leading role in the Canadian Coal Gasification Technical Committee. CETC has on-going
partnerships to develop gasification, syngas treatment, and hydrogen production technologies with
Instituto de Carboquimica in Spain and Cranfield University in the UK. It will also have access to IP
created under the EU project: “Innovative In Situ CO2 Capture Technology for Solid Fuel Gasification”.
The partnership includes 14 members from universities, government research facilities, and industry.
CETC’s entrained flow gasifier is the only small (0.35 MWth, 12.7 cm ID, operating at up to 1500 KPa
and 1600 oC) pilot-scale slagging gasifier accessible for R&D in North America. The system is capable of
running with dry feed or with a slurry feed. The reactor of this gasifier unit is sectional in design,
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allowing the addition or removal of sections to investigate alternate gasification geometries. The gas
treating section of the system has been designed to allow the integration of third-party technologies such
as advanced shift reactors, hot gas clean-up facilities, and fuel cells. CETC is currently focusing its
gasification research in two key areas:
Enabling gasification technology in Canada; and,
Developing advanced combined cycle gasification plants with integrated carbon dioxide capture.
Looping Combustion
CETC has been studying CO2 looping combustion for nearly four years and is investigating a number of
different fluidized bed process configurations at the pilot scale to capture CO2.
Canadian Clean Power Coalition (CCPC)
(www.canadiancleanpowercoalition.com)
The Canadian Clean Power Coalition (CCPC) is an association of leading Canadian coal and coal-fired
electricity producers and the California-based Electric Power Research Institute (EPRI). The CCPC
believes that coal, along with a diverse mix of fuels like hydro, natural gas, wind, solar and nuclear, will
play an important role in meeting the energy needs of the future. The CCPC’s goal is to secure a place for
coal-fired electricity generation within Canada's multi-fuelled electricity sector.
The CCPC's mandate is to research, develop and demonstrate commercially viable clean coal technology.
The coalition plans to build a full-scale, coal-fired demonstration plant in the next decade. The
demonstration plant, expected to be in operation by 2012, will be designed to remove greenhouse gas and
all other emissions of concern from a “Greenfield” facility.
The first phase was completed in early 2004. The technology gaps identified in the first phase are now
being addressed by additional studies. This work will be completed in 2005 allowing a site selection for
the demonstration plant. The CCPC estimates that it will cost over $1 billion dollars over the next ten
years to develop and construct a clean coal demonstration plant.
United States
Future Gen
(www.netl.doe.gov/coalpower/sequestration, www.fe.doe.gov/coal_power/sequestration)
FutureGen, the Integrated Sequestration and Hydrogen Research Initiative, is a $1 billion U.S.
industry/government partnership to design, build and operate a coal gasification-based, nearly emissionfree, electricity and hydrogen production plant. The 275-megawatt prototype plant will serve as a large
scale engineering laboratory for testing new clean power, carbon capture, and coal-to-hydrogen
technologies. According to the United States Department of Energy, it will be the cleanest fossil fuel-fired
power plant in the world. Virtually every aspect of the prototype plant will employ cutting-edge
technology. With respect to sequestration technologies, captured CO2 will be separated from the hydrogen
perhaps by novel membranes currently under development. It would then be permanently stored in a
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geologic formation. Candidate reservoir(s) could include depleted oil and gas reservoirs, unmineable coal
seams, deep saline aquifers, and basalt formations.
FutureGen has set out the following goals:
•
Design, construct, and operate a nominal 275-megawatt (net equivalent output) prototype plant
that produces electricity and hydrogen with near-zero emissions. The size of the plant is driven by
the need for producing commercially relevant data, including the requirement for producing one
million metric tons per year of CO2 to adequately validate the integrated operation of the
gasification plant and the receiving geologic formation.
•
Store at least 90 percent of CO2 emissions from the plant with the future potential to capture and
store nearly 100 percent.
•
Prove the effectiveness, safety, and permanence of CO2 storage.
•
Establish standardized technologies and protocols for CO2 measuring, monitoring, and
verification.
•
Validate the engineering, economic, and environmental viability of advanced coal-based, nearzero emission technologies that by 2020 will: (1) produce electricity with less than a 10%
increase in cost compared to non-CCS systems; (2) produce hydrogen at $4.00 per million Btus
(wholesale), equivalent to $0.48/gallon of gasoline, or $0.22/gallon less than today’s wholesale
price of gasoline. Figure D-1 outlines timelines, components and estimated costs of FutureGen.
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Figure D-1: Timelines, Components and Estimated Costs of FutureGen
US Regional Partnerships
(http://www.netl.doe.gov/coal/Carbon%20Sequestration/partnerships/index.html)
The U.S. Department of Energy has seven partnerships of state agencies, universities, and private
companies that will form the core of a nationwide network to help determine the best approaches for
capturing and permanently storing gases that can contribute to global climate change. The partnerships
include 216 organizations spanning 40 states, three Indian nations, and four Canadian provinces (B.C,
Alberta, Saskatchewan and Alberta as well as Environment Canada). In announcing the initiative, the
U.S. Secretary of Energy stated that the partnerships would become "the centerpiece" of expanded federal
efforts to investigate the potential for carbon sequestration. The partnerships are a key part of President
Bush's Global Climate Change Initiative (GCCI).
Regional Carbon Sequestration Partnerships are a government/industry effort to create a nationwide
network of partnerships to determine the most suitable technologies, regulations, and infrastructure needs
for carbon capture, storage and sequestration in different areas of the country. This initiative supports
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President Bush’s Global Climate Change Initiative (GCCI) goal of reducing greenhouse gas intensity by
18% by 2012 and will help ensure that a suite of commercially-ready sequestration technologies are
available for the 2012 technology assessment mandated by the GCCI. The geographical differences in
fossil fuel use and sequestration sinks across the United States dictates that regional approaches will be
required to address the sequestration of CO2. Figure D-2, prepared by the US DOE presents a map of the
various partnerships and the organizations involved in each of these partnerships
International
Intergovernmental Panel on Climate Change (IPCC)
(http://www.ipcc.ch/)
In 1988, the World Meteorological Organization and the United Nations established the
Intergovernmental Panel on Climate Change (IPCC) to provide advice to policy-makers on the state of
climate change science. The role of the IPCC is to assess on a comprehensive, objective, open and
transparent basis the scientific, technical and socio-economic information relevant to understanding the
scientific basis of risk of human-induced climate change, its potential impacts and options for adaptation
and mitigation. The IPCC does not carry out research nor does it monitor climate related data or other
relevant parameters. It bases its assessment mainly on peer reviewed and published scientific/technical
literature.
The United Nations Framework Convention on Climate Change (UNFCCC) at its Seventh Conference of
the Parties (COP) expressed its interest in carbon dioxide capture and storage by inviting the IPCC to
prepare a Technical Paper on geological carbon dioxide storage technologies and report on it for the
consideration of the 2nd COP/MOP. At its 19th session in Geneva, April 2002 the Panel therefore decided
to hold a workshop to consider the issues associated with geological and ocean carbon dioxide separation,
capture and storage and to advise to the Panel whether to develop a Special Report on this topic or to
incorporate the issue in the Fourth Assessment Report. The workshop held from 18-21 November 2002,
in Regina, Canada recommended a Special Report. The Panel at its 20th session (Paris, 19-21 February
2003) decided to prepare a Special report and approved the outline. The report is currently being prepared
by IPCC Working Group III and will be approved by the IPCC Working Group Three (WGIII) Session of
September 22nd - 24th, 2005, in Montreal, Canada. The report will be publicly available after the IPCC
Plenary meeting accepts it on September 26th, 2005.
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Partnership
States/Provinces
Represented
Partnership Lead
IN, KY, MI, MD, OH,
PA, WV
Midwest Regional Sequestration Partnership Battelle Memorial Institute
Illinois Basin
The Board of Trustees of the University of
Illinois, Illinois State Geological Survey
AL, AR, FL, GA, LA,
MS, NC, SC, TN, TX,
VA
Southeast Regional Carbon Sequestration
Southern States Energy Board
Partnership
Southwest Regional Partnership for Carbon New Mexico
Sequestration
Technology
Institute
of
West Coast Regional Carbon Sequestration State
of
Partnership
California Energy Commission
Mining
and AZ, CO, KS, NE, NM,
OK, TX, UT, WY
California, AK, AZ, CA, NV, OR,
WA, BC
Big Sky Regional Carbon Sequestration
Montana State University
Partnership
Plains CO2 Reduction Partnership
IL, IN, KY
University
North
Dakota
Energy & Environmental Research Center
ID, MT, SD, WY
-
IA, MO, MN, ND, NE,
MT, SD, WI, WY,
ALTA, SASK, MAN
Figure D-2: An Overview of US DOE Regional Partnerships
Carbon Sequestration Leadership Forum (CSLF)
(http://www.cslforum.org/)
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The Carbon Sequestration Leadership Forum is an international climate change initiative that is focused
on development of improved cost-effective technologies for the separation and capture of CO2 for its
transport and long-term safe storage. The purpose of the CSLF is to make these technologies broadly
available internationally; and to identify and address wider issues relating to carbon capture and storage.
This could include promoting the appropriate technical, political, and regulatory environments for the
development of such technology.
The first ministerial-level meeting took place in June 2003 in Virginia and was attended by delegations
from 16 countries and the European Commission. Representatives of 13 countries, including Canada, the
United States, Japan, Australia and the European Commission, signed the CSLF charter. Since then,
Germany, South Africa, and France have joined, bringing the total number of members to 17. The charter
will stay in effect for 10 years and establishes a broad outline for cooperation with the purpose of
facilitating development of cost-effective techniques for capture and safe long-term storage of CO2, while
making these technologies available internationally. While there are several large-scale international CO2
sequestration projects underway, this first-ever ministerial-level sequestration forum underscores the new
importance given to international cooperation.
The Second CSLF meeting was held in Rome, Italy in January 2004. One of the key outcomes was the
presentation of several projects for endorsement by the CSLF. These projects were reviewed and projects
were nominated for endorsement by the CSLF. The CSLF endorsed the following ten projects (four of
which Canada is a partner in) at its third CSLF meeting in Melbourne, Australia, September 13-15, 2004.
•
Enhanced Coal-Bed Methane Recovery Project (Canada, US, UK)
•
CANMET Energy Technology Centre (CETC) R&D Oxyfuel Combustion for CO2 Capture
(Canada and US)
•
CASTOR (European Commission, France and Norway)
•
CO2 Capture Project, Phase II (UK, Norway, Italy and US)
•
CO2 Separation from Pressurized Gas Stream (Japan and US)
•
CO2SINK (European Commission and Germany)
•
CO2STORE (Norway and European Commission)
•
Frio Project (US and Australia)
•
ITC CO2 Capture with Chemical Solvents (Canada and US)
•
Weyburn II CO2 Storage Project (US, Canada and Japan)
Other important accomplishments to come out of Australia include the adoption of the CSLF Technology
Roadmap and the establishment of three Technical Group task forces. The meeting in Melbourne was the
second CSLF Ministerial-level meeting with ministers from each of the 17 Members in attendance.
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The CSLF seeks to:
•
Identify key obstacles to achieving improved technological capacity
•
Identify potential areas of multilateral collaborations on carbon separation, capture, transport and
storage technologies
•
Foster collaborative research, development, and demonstration (RD&D) projects reflecting
Members' priorities
•
Identify potential issues relating to the treatment of intellectual property
•
Establish guidelines for the collaborations and reporting of their results
•
Assess regularly the progress of collaborative R&D projects and make recommendations on the
direction of such projects
•
Establish and regularly assess an inventory of the potential areas of needed research
•
Organize collaboration with all sectors of the international research community, including
industry, academia, government and non-government organizations; the CSLF is also intended to
complement ongoing international cooperation in this area
•
Develop strategies to address issues of public perception
•
Conduct such other activities to advance achievement of the CSLF's purpose as the Members may
determine
International Energy Agency (IEA)
(www.ieagreen.org.uk)
The International Energy Agency’s Greenhouse Gas Research and Development Programme is an
international collaboration which aims to (1) evaluate technologies for reducing emissions of greenhouse
gases; (2) disseminate the results of these studies; and (3) identify targets for research, development and
demonstration and promote the appropriate work. The IEA GHG R&D Programme operates under an
Implementing Agreement provided by the International Energy Agency (IEA); the Programme started in
November 1991 and the fourth phase began in November 2000. Its main activities concern methods of
reducing GHG emissions, particularly CO2 from fossil fuels. Much attention has been given to the option
of capture and storage or utilization of CO2.
Under the auspices of the IEA Greenhouse Gas Programme, the International Network for CO2 Capture
has been established to stimulate worldwide collaboration and encourage practical development of Post
Combustion CO2 capture technology. The focus is on the capture of CO2 using regenerable solvent-based
scrubbing systems that have the ability to remove CO2 from emissions although, use of membranes and
solid sorbents are increasingly being considered.
Network contributors have set themselves specific objectives and scope of work:
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"To develop more efficient and cost effective CO2 capture from flue gases, than is currently
available, through demonstration of a range of amine-based solvent scrubbing and similar
technologies. Over the long term it is important to achieve severe cuts in costs for the
technologies developed to be competitive with other options."
In the first four years, attention has focused on process simulation, process economic assessment and
innovation in laboratories and at pilot plant scale. The Network has held 7 workshops with delegates
from 12 countries have attended some or all of the workshops.
Carbon Capture Project
(www.co2captureproject.org)
The Carbon Capture Project (CCP) is an international public private R&D partnership that aims to
develop new breakthrough technologies to reduce the cost of carbon dioxide separation, capture,
transportation and storage from fossil fuel streams by 50% for existing energy facilities and by 75% for
new energy facilities compared to currently available alternatives. This is a pilot-scale project that will
continue the development of new technologies to reduce the cost of CO2 separation, capture, and geologic
storage from combustion sources such as turbines, heaters and boilers.
The primary objective of the CO2 Capture Project (CCP) is to develop new, breakthrough technologies to
reduce the cost of CO2 separation, capture, and geologic storage from combustion sources such as
turbines, heaters, and boilers. The CCP will accomplish this objective through he following functions:
•
International industry and government partners cooperatively direct and fund the development of
CO2 capture and storage technologies with the aim of advancing the science and expanding the
potential scope of implementation.
•
Identify and address critical issues around assurance of geological storage of CO2. Contribute to
global efforts to establish best practices for site characterization, process optimization,
monitoring/verification and risk assessment.
•
Identify and develop technologies to reduce the costs of capture of CO2 emissions by 60-80 %
from the 2000 baseline.
•
Expand economic / infrastructure scenarios for complete integration of the CO2 capture,
transportation and storage value chain.
•
Increase public acceptance and awareness of CO2 Capture and Storage.
One project under the CCP is a small-scale project that will evaluate processes and economics for CO2
separation from pressurized gas streams. Testing will utilize membranes developed in Japan at a test
facility near Pittsburgh, Pennsylvania, United States. The proposed project, which began in 2003 and is
scheduled for completion in 2006, will evaluate primary promising new membranes under atmospheric
pressure. The next stage is to improve the performance of the membranes for CO2 removal from the fuel
gas product of coal gasification and other gas streams under high pressure.
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Australian Cooperative Research Centre for Greenhouse Gas Technologies (CO2 CRC)
(http://www.co2crc.com.au/)
The Cooperative Research Centre for Greenhouse Gas Technologies (CO2CRC) researches the logistic,
technical, financial and environmental issues of storing industrial carbon dioxide emissions in deep
geological formations. The CRC also researches the capture and separation of carbon dioxide from
industrial systems.
CO2CRC is focusing its efforts on the development and application of technologies to more effectively
capture and geologically store carbon dioxide, and is acknowledged as one of the world's leading Centres
in the study of carbon dioxide capture and storage.
The CO2CRC’s Storage Program aims to research, develop and deploy technologies that can achieve
significant cuts in storage and/or usage costs and provide Australia with a research and education
capability to support industries using these technologies. CO2CRC is reviewing a range of storage options
and technologies and evaluating applications that might be used by the fossil fuel industry sectors. The
aim is to select those technologies most likely to allow significant reductions while still demonstrating
safety and security. An economic framework will be used to measure and validate research directions and
integrate both with energy production issues and capture infrastructure.
The CO2CRC Capture Program aims to research develop and deploy technologies that can achieve
significant cuts (75-80%) in capture cost. This will be achieved by reviewing a range of capture
technologies and applications that could be used by the fossil fuel industry and, after choosing those most
likely to provide significant reductions, targeting them for development. An economic framework will be
used to measure and evaluate research directions and integrate them with issues of energy production and
storage infrastructure.
NorCap
The NorCap Project is a joint venture between Norway’s Statoil and international partners. The objective
is to develop and test promising new technologies that can reduce the costs of separating, capturing,
transporting and storing CO2 from the combustion of fossil energy.
CASTOR
CASTOR, "CO2 from Capture to Storage", is a European initiative grouping 30 partners (industries,
research institutes, and universities) representing 11 European countries, including France and Norway.
The project is partially funded by another CSLF member, the European Commission, under the 6th
Framework Program. CASTOR`s overall goal is to develop and validate, in public/private partnerships,
all the innovative technologies needed to capture and store CO2 in a reliable and safe way.
CO2Net
(http://www.co2net.com/)
The CO2 Thematic Network provides information for future policies and advice towards best practice,
benchmarking and standardization, thereby facilitating the decision-making process. The Thematic
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Network seeks to increase awareness of research activities and results throughout Europe and world wide
through its international associations. The goal is to accelerate the developing technologies towards CO2
mitigation. For the EU and national governments, the Thematic Network will offer a think-tank on CO2
issues.
Public education and outreach is a key focus of CO2Net. Training materials will be developed and
educational activities with public meetings will be organized towards increased public awareness and
acceptability.
Building on existing knowledge and experience in gas storage, the Thematic Network will provide advice
to allow modification of existing natural gas standards for the safe handling and disposal of CO2.
Parameters for these need to be defined and verified in order to establish best practice. This will be
achieved through discussion and dissemination of the results generated by the associated projects to as
wide an audience as possible. This will enable informed decisions to be made on whether geological
storage of CO2 is a viable mitigation option capable of wide-scale application and will help to define best
practice.
The Thematic Network will bring together the researchers in the fields of carbon capture and storage to
benefit from the work of each other, help to define best practice and identify new research requirements.
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APPENDIX E – OPPORTUNITIES AT OIL SANDS AND
HEAVY OIL CO2 EMISSION HUBS
By Sam Wong (Alberta Research Council Inc.) and Bob Mitchell (Inspired Value Inc.)
The oil sands hubs are centered around Fort McMurray and the heavy oil hub is located at
Lloydminister.
Fort McMurray
The oil sands deposit in northern Alberta is huge, with a reserve estimate of more than 175 billion
barrels. Including the oil sands, Canada is ranked second only to Saudi Arabia in terms of proven
reserves. For the foreseeable future, the Alberta oil sands and bitumen reserves will increasingly be
called upon to supply the energy needs in both Canada and the U.S. Synthetic crude oil and bitumen
production is expected to increase from the current 1 million barrels per day (bpd) to 2 million bpd in
2012 and with a vision of 5 million bpd by 2030.
Of the approximately 1 million barrels bpd of current bitumen production, about 65% is from mined
production and the remaining 35% from in-situ or thermal production. All of the 650,000 bpd of
mined bitumen is upgraded. For the two earlier mining projects, Suncor and Syncrude convert their
bitumen production on-site to a light, sweet synthetic crude oil (SCO) and in the case of Suncor, other
sour variants. The third mining project, the Shell led Albian Sands mining project recovers the
bitumen and upgrades this off-site in the Shell refinery and upgrader complex at Scotford, Alberta. Of
the 350,000 bpd of in-situ bitumen production, some of it is upgraded to a SCO in Husky’s
Lloydminster, Saskatchewan upgrader. However, the majority is blended with a light diluent such as
gas condensate and shipped to refineries, primarily in the U.S. mid-west, which are suitably equipped
to handle the high residue content bitumen.
Bitumen production is highly energy intensive. Historically, oil sand projects depend heavily on the
cheap and abundant natural gas for steam and power (co-generation) and hydrogen production for
upgrading. In-situ project energy demand with to-day’s technology requires 1 – 1.2 MCF of natural
gas per barrel of bitumen recovered. Mining recovery demand is more modest at 0.25 MCF per barrel.
Upgraders need about 0.5 MCF of natural gas for every barrel of SCO produced for energy and
hydrogen today. However, this will climb, as SCO quality demand increases. Assuming that the vision
of 5 million bpd of bitumen and SCO production by 2030 is valid, this would require upwards of 5
BCF per day (1.8 TCF per year) of natural gas for the oil sands plants. Clearly, this demand of natural
gas is not sustainable in the long run. The challenge is to reduce the dependence on natural gas.
Typically upgrading can be considered as a two-step process – primary upgrading and secondary
hydrotreating. For the Suncor and Syncrude projects, primary upgrading is largely based on coking
(they use two different versions of coking). However, coking which is a severely thermally based
process produces a highly aromatic crude, with poor quality distillates – jet and diesel fuel components
– and gas oils which must be converted in the refinery to lighter gasoline and distillates. In addition,
coking produces a low value coke product, which must be utilized or disposed of. Alternatively,
special catalytic processes are being increasingly used for primary upgrading. Rather than carbon
rejection, the alternative ebullated bed process uses hydrogen addition. The ebullated bed
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hydroprocessing has two technical advantages: it operates at more moderate temperatures and with the
addition of hydrogen, produces a less aromatic liquid product. The primary step still leaves significant
amounts of sulphur and nitrogen compounds in the lighter products, and further secondary treating in
large hydrotreaters (with high hydrogen addition) is needed to produce a synthetic crude. For current
operations the hydrogen consumption is about 1,000 standard cubic feet per barrel. However this could
increase to as high as 1,800 standard cubic feet per barrel when a higher quality SCO is demanded.
Suncor and Syncrude, in their expansion plans to 2010-2012 will continue to use the same coking
process, covering some 1 million bpd of combined upgrading capacity by that time. Therefore, in the
immediate time frame to 2012, coking will remain the dominant process for primary upgrading.
Husky, at its upgrader at Lloydminster, currently processes about 60,000 bpd using ebullated bed
hydroprocessing, followed by coking of the unconverted residue. The Shell led upgrader at Scotford
uses ebullated bed hydroprocessing alone for primary upgrading. In their case, the unconverted residue
is shipped with the various synthetic crude streams for market sales or transferred to the owner’s
refineries for further processing.
It is clear that the oil sands and heavy oil CO2 emission hubs are a big consumer of hydrogen. Existing
oil sands plants such as Suncor and Syncrude use steam methane reforming to produce hydrogen.
Either a Benfield process or a pressure swing adsorption (PSA) process is used to separate the
hydrogen from the CO2. These represent immediate opportunities to capture the CO2. Benfield
produces a high purity CO2 (90+5%), which can be captured by simply dehydration and compression.
The PSA process produces a 40% CO2 fuel gas, which is currently consumed as plant fuel. To capture
this CO2 requires some further technical development and demonstration. Physical absorption and
oxy-fuel combustion are two feasible approaches.
The long-term vision of the oil sands industry sees internal resources being used for energy, hydrogen
and power. This will alleviate the dependence on natural gas. The technology is gasification (an
existing technology), which can be used to convert the least valuable residues of the bitumen barrel to
steam, power and hydrogen. Typically about 10% of the bitumen barrel is needed for the production of
hydrogen alone. For an in-situ thermal based process, which requires a large amount of steam for
injection, as much as 20-30% of the recovered bitumen is required to meet these needs. The
integration of hydrogen production and utilization of the bitumen residues have a beneficial impact on
upgrading process selection, because a disproportionate cost of upgrading today is devoted to
converting these least valuable residues to feedstocks suitable for producing upgraded products.
External resources such as coal and nuclear energy have also been considered. There is no significant
coal deposit near the Fort McMurray area. Therefore coal must be transported into the area. Nuclear
energy has its own environmental concerns. While coal gasification for hydrogen production is
possible, this option precludes the favourable synergies between bitumen residue use and primary
upgrading. A case in point is the Nexen/OPTI joint venture Steam Assisted Gravity Drainage (SAGD)
and upgrader project at Long Lake, Alberta.
The Nexen/OPTI project uses a SAGD process for in-situ bitumen production. The upgrader initial
capacity is 70,000 bpd. It uses new approaches to upgrading, including integrated residue gasification
for hydrogen, and steam and power production. The primary upgrading process it employs is its
proprietary ORMAT process, which is a combination of visbreaking and deasphalting. The
Nexen/OPTI project is potentially the first upgrader to move away from coking and ebullated bed
processes. The milder thermal and physical processes, such as ORMAT, can play one of two possible
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roles: as field upgraders to reduce or eliminate the need for diluent for transport or as primary
processes in future upgraders where some residue is removed and consumed in hydrogen production.
In the Nexen/OPTI project, the bitumen residue is gasified using the Shell gasification technology.
The hydrogen from the synthesis gas is separated and purified. The CO in the synthesis gas will not go
through a water shift reaction to produce more hydrogen and carbon dioxide, but rather the CO is
burned to produce steam and electric power for plant use. In this way, the plant is self sufficient in
energy without relying on external natural gas.
Figure E-1: Development stages of an oil sands CO2 emission hub
Deasphalting and visbreaking may play a role within the next decade, especially where residue use for
hydrogen and energy positively influences the primary upgrading process selection. Optimized use of
bitumen fractions to replace natural gas for steam, power and hydrogen will likely be an essential
characteristic of the industry during the next 25 years. It should be recognized, however, that a
bitumen residue based gasification scheme for hydrogen and steam would produce more greenhouse
gas emissions than a natural gas based scheme. For example, the mining based recovery process would
produce 40 kilograms of CO2E per barrel and about 60 kilograms CO2E for in-situ, in both cases with
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natural gas as feed. Burning residue for SAGD fuel will increase CO2E to around 80 kilograms per
barrel. At the high end of the spectrum, combining SAGD using residue as fuel and upgrading using
more residue for hydrogen will result in as much as 160 kilograms of CO2E emissions per barrel of
SCO. In this case as more oil sands plants are built in the near future based on gasification of the
bitumen residues or even coke, capturing the CO2 becomes more urgent if Canada is going to meet its
emission reduction targets.
Opportunity Summary
The Fort McMurray oil sands CO2 emission hub has many opportunities to capture the CO2, Figure E1 summarizes a view of the enabling conditions and the technology research that must be performed to
assist in these developments. As a first stage opportunity, the high purity CO2 sources (90+%) from
the Benfield units which use chemical solvents for hydrogen separation in the existing Suncor and
Syncrude plants would be relatively easy and inexpensive to capture, as all it requires is dehydration
and compression. Daily capacity is about 5,500 metric tonnes per day. No new capture technology is
needed and this capture can be carried out in the 2005 present time frame. In addition, there are also
large quantities of high CO2 concentration off gas (~ 40% CO2) from the PSA units for hydrogen
separation in the two existing plants of Suncor and Syncrude. Daily capacity from these PSA units is
about 3,900 metric tonnes per day. Physical absorption and oxy-fuel combustion may be two viable
approaches for such application. These technologies must be further developed and demonstrated. This
can happen in the second stage in the 2010 - 2015 time frame. CO2 from gasifying bitumen residue
and CO2 from PSA for hydrogen production for new plants are also potential sources farther into the
future. To capture CO2 from this source will require technologies that need further research and
development in order to make the capture economically attractive. Technologies that can be applied to
this CO2 capture include solid sorbents, physical solvents, membranes and hybrid processes. Gasifier
tag-on research is also an option. The likely time frame for this capture is in the 2013 – 2020 time
period. The third stage opportunity is in the CO2 capture for gasifying petroleum coke, and the time
frame is in the 2020 and beyond. The long term CO2 capture is in the combustion flue gas where the
CO2 concentration is low, in the range of 3 to 15%, with a range of other impurities as well. The time
frame is in the 2030 and beyond. Inexpensive pipeline transportation for all of these purified CO2
streams to geological sinks is required.
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APPENDIX F - OPPORTUNITIES AT ELECTRICITY CO2
EMISSION HUBS
By Sam Wong (Alberta Research Council Inc.) and Bob Mitchell (Inspired Value Inc.)
The burning of fossil fuels to produce electricity emits greenhouse gases (GHG), predominantly CO2.
Coal accounts for the largest share of GHG emissions for the electricity generation sector (~ 85%),
followed by natural gas and fuel oil. In terms of emissions per kilowatt-hours, coal emits more CO2 than
oil or natural gas. Hydro and wind power do not produce much CO2.
Most of the coal-fired power plants in Canada are concentrated in Alberta, Saskatchewan, Ontario and
Nova Scotia. Take, for example, the electricity CO2 emission hub at Lake Wabamun, Alberta. There are
four coal-fired electric power plants in this hub, with a total generating capacity of 4,300 MW. They are
all based on local low sulfur sub-bituminous coal from open cast mining close-by. Total CO2 emissions
amounts to 34 million tonnes per year.
Lake Wabamun
The four electric power plants around Lake Wabumun are:
1. Wabamun Power Plant –owned by TransAlta
Currently one unit (#4) operating (due to be retired in 2010)
Capacity is 279 MW
CO2 generation ~ 2300 kt/y
2. Sundance Power Plant – owned by TransAlta
Six units ranging from 280 MW to 366 MW; Total power ~ 2020 MW
CO2 generation ~ 16200 kt/y
3. Keephills Power Plant
Keephills #1 and #2 owned by TransAlta, Capacities 383 MW each or 766 MW
CO2 generation ~ 3077 kt/y/unit or 6154 kt/y
4. Genesee Power Plant
Genesee #1 and #2 owned by Epcor ~ 386 MW each or 772 MW
Genesee #3 owned jointly by Epcor and TransAlta ~ 450 MW
CO2 generation ~ 9400 kt/y
______________________________________________________________
Total Generating Capacity ~ 4300 MW
Total estimated CO2 generation ~ 34050 kt/y
Genesee #3 is a supercritical unit and produces CO2 at about 88% of the sub-critical units.
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These four plants are very large CO2 emitters, and each can be considered as individual hub in their own
right. The CO2 concentration in these power plant flues gases ranges from 13 – 15% (on a dry basis), plus
a number of other contaminants such as SOx and NOx. As shown in Appendix B, chemical absorption is
the only viable technology to capture CO2 from this low CO2 concentration, low pressure combustion flue
gas. It would also require extensive pre-treatment to remove the SOx, NOx and particulates to a very low
level in order not to foul up the chemical absorption process. This adds to the capture costs. In Appendix
C, it is shown that the cost of CO2 capture for a 15% CO2 combustion flue gas using the current state-ofthe-art technology such as the Mitsubishi Heavy Industries/Kansai Electric Power SK-1 solvent is about
$55/tonne. This is prohibitively expensive under current conditions. The recently completed Canadian
Clean Power Coalition study came to the same conclusion: it would not be cost effective to retrofit
existing facilities for CO2 capture because of the large energy penalty involved and the cost of retrofits.
Therefore, even though these are very large CO2 sources, the opportunity for CO2 capture is limited in the
present 2005 time frame.
In the time frame 2010 - 2035, the electric power sector faces a very robust capacity development cycle.
This development is fuelled by two premises: (1) old plants that would be retired and replaced by new
plants or new retrofits (averaging some 700 MW a year); and (2) new capacities that must be added to
meet the increased demand over this time frame (see Appendix B). A number of opportunities arise from
this scenario and include:
•
Building new coal fired power stations that integrate carbon capture
•
Building new integrated coal gasification combined cycle (IGCC) power stations that integrate
carbon capture
•
Building new oxy-fuel combustion power plants with CO2 capture
•
Refurbishing existing coal-fired power stations with gasifiers or oxy-fuel combustion boilers and
fitting capture equipment
Both IGCC and oxy-fuel combustion are the key technology pathways to achieve the reduced emission
targets.
In IGCC, the coal is gasified in oxygen to produce a syngas. CO2 can be separated from the syngas and
the hydrogen is used as fuel in a gas turbine combined cycle plant. The advantage of IGCC is that it
produces a smaller volume of flue gas for treatment, which is richer in CO2 and at high pressure. This
reduces the size of the gas separation plant thus reducing capital costs. Also the higher concentration of
CO2 and higher pressure enables less selective gas separation techniques to be used (e.g. physical
solvents, solid adsorption/ desorption) that require less energy to operate.
Oxy-fuel combustion involves burning fuel in an oxygen/CO2 mixture or oxygen water mixture rather
than air to produce a CO2-rich flue gas. Generally the oxygen is generated from an air separation unit, and
the oxygen/CO2 mixture is produced by recirculating some of the flue gas back to the combustor. The
oxygen/CO2 mixture is needed to control flame temperature, which would be too high if combustion takes
place in pure oxygen. The advantage of oxy-fuel combustion is that it produces a highly CO2-enriched
flue gas (80+%) that allows simple and low-cost CO2 purification methods to be used. In addition, there is
benefit of reduced NOx and SOx production in the boiler. However, the disadvantage is that it requires an
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air separation plant, which is expensive and requires a considerable amount of energy to operate. At
present there is less operational experience with oxy-fuel combustion, and there are operational questions
that must be addressed before the technology can be taken to full commercial deployment in the power
industry.
All of the above approaches could be applied to new plant or retrofitted to existing facilities. A new build
has the advantage of allowing maximum integration of the capture facilities into the power generation
plant, which will benefit overall generation efficiency. It also avoids any space limitations associated with
fitting new equipment to an existing facility, and could permit the plant to be located closer to the storage
facility thus reducing transport costs. A retrofit is likely to have a lower capital cost, although this
advantage is reduced if appreciable refurbishment is needed to extend the operating life of the plant.
Figure F-1: Development stages of a electricity CO2 emission hub
The immediate need for capturing CO2 in the electricity CO2 emission hub is an orderly demonstration of
the oxy-fuel combustion and IGCC technologies. Therefore, in the 2008 – 2012 time frame, an oxy-fuel
demonstration project should be planned and if successful should move forward to a commercial
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demonstration. In the same time frame, a commercial demonstration of an IGCC plant should also be
planned. This plant could be fuelled by coal or petroleum coke.
Opportunity Summary
Figure F-1 summarizes a view of the enabling conditions and the technology research that must be
performed to assist in these developments at CO2 electricity hubs. A first stage opportunity is for CO2
capture from an oxy-fuel combustion demonstration unit. Oxy-fuel combustion is at a stage where
demonstration in a pilot scale operation is required. The time frame for this to happen is likely during the
2008-2012 period. The second stage opportunity lies in the CO2 capture from a demo gasifier (IGCC) of
coal or petroleum coke. If the first stage of oxy-fuel demo is successful, the next stage of development
would be CO2 capture from a commercial oxy-fuel retrofit plant. The third stage opportunity is CO2
capture from commercial gasifiers (IGCC) in the time frame 2020 and beyond. The long-term opportunity
is CO2 capture from highly diluted streams of combustion flue gases. Inexpensive pipeline transportation
for all of these purified CO2 streams to geological sinks is required.
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APPENDIX G - OPPORTUNITIES AT PETROCHEMICAL CO2
EMISSION HUBS
By Sam Wong (Alberta Research Council Inc.) and Bob Mitchell (Inspired Value Inc.)
The major petrochemical complexes in Canada are located in Montreal, Sarnia, Fort Saskatchewan and
Joffre-Prentiss. The petrochemical complex in Alberta is different than that in eastern Canada. While
petrochemical plants in eastern Canada are oil or naphtha based, those in Alberta are natural gas or ethane
based. Hence, the range of products they produce is different. One of the characteristics of the
petrochemical complex is the significant integration between the feedstock providers, the primary
petrochemical plants and the derivative plants. Take, for example, the petrochemical manufacturing
facilities at Joffre-Prentiss, Alberta. The main products are ethylene and ethylene derivatives such as
polyethylene, ethylene oxide/ethylene glycol and linear alpha olefin. Ethylene from Nova is moved to
supply feedstock for the polyethylene plants, the ethylene oxide plants and the linear alpha olefin plant.
Excess hydrogen from the ethylene plants is moved to another plant to produce ammonia.
Joffre-Prentiss–Red Deer
The following major plants are located in the Joffre-Prentiss-Red Deer area:
•
Nova Joffre: 3 world scale ethylene plants, 2 polyethylene plants, 1 co-generation plant
•
Dow Prentiss: 2 ethylene oxide /ethylene glycol plants
•
BP Canada Chemicals Joffre – 1 linear alpha olefin plant (in the Nova Joffre site)
•
Agrium Joffre – 1 ammonia plant (manufacture with hydrogen imported from ethylene plant, so
no major CO2 emissions)
•
Permolex Red Deer – 1 ethanol plant manufactured from the fermentation of wheat
Nova Joffre
The Nova Joffre plant is the world’s largest single site ethylene complex. It uses ethane as feedstock
(recovered from natural gas processing plants) to produce, from three cracking units, 2,720 kt/year of
ethylene for use on site and export. The ethylene feeds two polyethylene units on site with a combined
capacity of 930 kt/year and two ethylene oxide plants and a polyethylene plant located nearby that are
operated by Dow Chemical. The ethylene also is the feedstock for a linear alpha olefin (LAO) plant on
site operated by BP Canada Chemicals. The CO2 sources in the plant are three CO2-rich streams from the
three feed gas processing units for the ethylene crackers, and combustion sources, the largest of which are
the exhaust streams from the three cracking furnaces and the exhaust from the 450 MW cogeneration
plant.
In 2003, Nova Joffre emitted 3,013 kt of CO2e, of which 2,087 kt CO2e was direct emissions from
chemical manufacture and 926 kt CO2e was emissions from the cogeneration units. On average, the Joffre
cogeneration facility only operated at 52% of its rated capacity in 2003. This was lower than 2002.
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(a)
Feed Gas (Ethane) Processing Units
The Nova Joffre plant receives ethane extracted from natural gas in straddle plants, using a “deep-cut”
ethane extraction process. This is carried out by condensing all of the heavier components (gas liquids) of
the raw gas and separating them by distillation into different boiling ranges for shipment. The CO2
reports with the ethane because of their similar boiling points. The ethane supply to Nova contains
significant quantities of carbon dioxide recovered with the ethane. To provide a suitable ethane stock for
cracking, Nova removes the CO2 by absorption in amine solution. The amine is dissolved in water for the
absorption. In the process, the ‘rich’ amine solution stream, which has absorbed CO2, is transferred to a
stripping tower in which the CO2 is recovered by steam injection (or gas injection) to regenerate the
amine solution. The CO2 source is at the stripper exhaust. The CO2 content of the exhaust stream is 99
%+ on a dry basis. The temperature and pressure of the CO2 is 150oC and 400 kPa, respectively.
The CO2 outputs for the three plants (E1, E2 and E3) are, respectively, 60 kt/year, 70 kt/year and 130
kt/year for a total of 260 kt/year. This is less than 10% of the total CO2 emissions at Joffre. The output of
E1 is contracted out to an EOR operator. Only the outputs from E2 and E3 are available (totalling 200
kt/year).
Capturing CO2 from this high purity source is straight forward, requiring simply dehydration and
compression. However, this exhaust stream contains minor amount of H2S, which must be removed prior
to CO2 capture. The H2S can be oxidized into SO2 by incinerating in furnaces at the petrochemical
complex.
(b)
Combustion Units
The other major CO2 sources in the Nova Joffre plant are combustion sources – the three ethane cracking
furnaces and the cogeneration plant are probably the largest potential sources of CO2, although much
lower in concentration than the feed gas processing source.
Nova fuels the cracking furnaces with natural gas and with process-derived fuel. Thermal cracking of
ethane for ethylene production in the Nova plant is carried out with light hydrocarbon crackers with steam
added. The CO2 concentration is about 9.2%, on a dry basis.
The cogeneration plant at Nova Joffre is a 450-megawatt plant jointly owned by Nova, Atco Power and
EPCOR. The plant comprises two natural gas turbines, each with a Heat Recovery Steam Generator
(HRSG) and a steam turbine to produce additional electric power. The plant produces 530 t/h of steam.
Atco Power is the cogeneration plant operator. The co-generation plant exhaust contains 3.3% CO2,
15.2% O2 and the rest being N2 (dry basis).
As shown in Appendix C, capturing CO2 from these sources would be prohibitively expensive, under
current technology and economic conditions.
Dow Prentiss
The only source of CO2 considered in the Dow Prentiss plant is the CO2-rich stream from ethylene oxide
production. The CO2 generated in the production of ethylene oxide is absorbed with a potassium
carbonate solution that is subsequently regenerated by steam stripping. The absorption takes place in
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packed towers. Catalyst efficiency (percent of conversion to ethylene oxide) decreases from 82% with
fresh catalyst to 76% with aged catalyst. Catalyst efficiency is independent of plant operating rate (i.e. to
65% turndown, at least). At present, Dow vents the CO2 removed from the regeneration of the carbonate
absorbent. The vent streams are essentially water saturated and have only minor amounts of other
contaminants. CO2 concentration is 99+% on a dry basis. The vent gas is recovered from one regenerator
at atmospheric pressure (EGP1) and at approximately 185 kPa from the other (EGP2). Temperature of
the recovered gas is about 90°C. The total quantity of CO2 in the vent gas stream is about 283 kt/year.
Capturing CO2 from this high purity source is simply by dehydration and compression. There is no H2S in
this stream. However, the water content is significant.
Figure G-1: Development stages of a petrochemical CO2 emission hub
Agrium Joffre
Agrium produces ammonia using import hydrogen. So there is no CO2 emissions related to the production
of hydrogen.
However, under a gas price scenario of $ 4 – 5 /MCF, the ammonia industry need to find alternatives to
produce hydrogen. Gasification of coal or bitumen residues to produce hydrogen may be a viable
approach in Alberta. Associated with this will be opportunities to capture CO2, should new plants be built
in Alberta in the near future.
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Permolex Red Deer
The Permolex plant uses the fermentation of grains to produce ethanol. The fermentation process is
generally not a source of large amounts of CO2, however, the CO2 is high purity (99+%). The plant
produces about 50 tonnes per day of CO2. To capture this CO2 requires simply dehydration and
compression.
The plant also produces two other streams of exhaust gas – the flue gas from the auxiliary boilers used for
the generation of steam (6.8% CO2) and the flue gas from a co-generation unit which provides electric
power to the plant and to the Alberta electrical grid (less than 3% CO2). Again these sources of CO2
would be prohibitively expensive to capture under current conditions.
Opportunity Summary
Figure G-1 summarizes a view of the enabling conditions and the technology research that must be
performed to assist in the commercial development of capture for the various CO2 streams from
petrochemical hubs. The petrochemical plants at Joffre-Prentiss produce some high purity CO2 exhaust
gases (99+%) from the ethane feed processing, ethylene oxide and ethanol manufacture. Total capacity
amounts to some 1,300 metric tonnes per day. These high purity sources do not require any new capture
technology. All it requires is dehydration and compression. This CO2 can be recovered economically in
the present time frame of 2005 (see Figure G-1). There are also potential opportunities to capture CO2
from new plants. The new plants would likely be built based on bitumen feedstock. Hydrogen would be
produced from the gasification of coal or bitumen residues. The time frame for this development would
be 2015 and beyond. The petrochemical plants also produce streams of combustion flue gases, which
range in CO2 concentration from 10% (cracking furnace flue gas) to 4% (cogeneration turbine flue gas).
To recover CO2 from these flue gases would require further technology development in the area of solid
sorbets, oxy-fuel cycles, physical solvents, membranes and hybrid processes. These technologies
probably cannot be deployed economically until the long term in the 2030 and beyond time frame.
Inexpensive pipeline transportation for all of these purified CO2 streams to geological sinks is required.
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APPENDIX H - OPPORTUNITIES AT MULTI-INDUSTRIAL
CO2 EMISSION HUBS
By Sam Wong (Alberta Research Council Inc.) and Bob Mitchell Iinspired Value Inc.)
Examples of multi-industrial emission hubs in Canada are Sarnia in Ontario and Fort Saskatchewan in
Alberta. For the case of Sarnia, development started after local oil discoveries prompted the need for
refineries, followed by access to a major oil pipeline and easy access to the US markets as a natural
advantage. The pipeline provides the crude for the refineries, which in turn provide the feedstock for the
petrochemical plants. Then the downstream chemical plants follow. The pattern in Fort Saskatchewan is
similar. The access to major pipelines provides the crude and natural gas necessary to support a refining
and a gas based petrochemical industry in the area. Government also plays a role by setting
comprehensive policies to encourage industries to follow. Then the downstream manufacturing plants
come. It then drives the need for steam, power and hydrogen. Because of the access to existing
infrastructures and pool of skilled labor, it attracts upgraders to be located there. It opens up more
opportunities. The hub may eventually evolve into a polygeneration CO2 emission hub, where
manufacture of hydrogen, petroleum liquids, synthetic natural gas, electric power, petrochemicals and
CO2 capture and storage all occur at one location. One important aspect is that the multi-industrial hub
must facilitate integration across industries.
Fort Saskatchewan
Take the Fort Saskatchewan area (including Edmonton) in Alberta as an example where over 40 major
industrial commercial operations are situated. This area is known as the “Alberta’s Industrial Heartland”.
Figure H-1 details the industries that have operations within this region.
A subset of representative companies which are CO2 producers is:
•
Dow Chemicals Canada
•
Shell Canada Chemicals /Refinery /Upgrader
•
Agrium
•
Air Liquide
•
Praxair
The industries they represent include petrochemical, fertilizer, refineries, bitumen upgrading, cogeneration and gas processing. Another company is proposing to build a second bitumen upgrader there.
A gasification pilot is also planned in the area. As the hub continues to grow, more opportunities become
available. The following are some details of the activities of these companies in the Fort Saskatchewan
hub.
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Figure H-1: Companies operating within Alberta’s Industrial Heartland
Dow Chemical Canada
The Dow Chemical Complex at Fort Saskatchewan has a number of manufacturing plants:
•
An Ethylene plant;
•
An Ethylene Oxide/Ethylene Glycol plant;
•
A Chlor-Alkali unit which produces chlorine, caustic soda and hydrogen chloride as well as
hydrogen;
•
A Polyethylene plant which produces polymer from a portion of the ethylene produced;
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•
An Ethylene Dichloride (EDC)/Vinyl Chloride Monomer (VCM) plant which combines the two
intermediates, chlorine and ethylene, to produce the basic monomer for polyvinyl chloride (PVC)
manufacture;
•
A Styrofoam plant which manufactures polystyrene foam for insulation and construction; and
•
A cogeneration plant.
The cogeneration plant at Dow comprises three natural gas turbines, each with a Heat Recovery Steam
Generator (HRSG) and a steam turbine to produce additional electric power. Dow originally installed two
gas/steam turbine units with a joint capacity of 180 MW and subsequently installed, with TransAlta
Energy and Air Liquide, a third unit with a capacity of 140 MW. Dow is the operator of the three
cogeneration units.
For the Dow plant, the CO2 streams include:
•
CO2-rich stream from processing of feed natural gas liquids (206 kt/yr)
•
CO2-rich stream from ethylene oxide production (129 kt/yr)
•
Exhaust combustion gas from ethane cracker furnace (922 kt/yr)
•
Exhaust combustion gas from cogeneration unit (863 kt/yr)
Acid gases removed from the processing of the feed ethane are absorbed with an amine solution and
recovered by steam stripping the rich solution to regenerate the amine. The absorption system comprises
of two trains. The produced CO2 is high purity – just over 99% on a dry basis – and is currently
undergoing expansion in capacity. The CO2 stream currently is directed either to incineration or to flare
to eliminate the H2S and then vented.
The CO2 generated in production of ethylene oxide is absorbed with a potassium carbonate solution that is
subsequently regenerated by steam stripping. The absorption takes place in two packed towers. Catalyst
efficiency (percent of conversion to ethylene oxide) decreases from 82% with fresh catalyst to 76% with
aged catalyst. Catalyst efficiency is independent of plant operating rate (i.e. to 65% turndown, at least).
At present, Dow sends 30-40% of this stream to Praxair to recover the CO2 and the balance is vented.
To capture CO2 from these two high purity streams is straight forward, by simply dehydration and
compression. Praxair already recovers some of the CO2.
The cracking furnace that converts ethane to ethylene is one of the large heat sinks of the Dow plant. In
the current configuration of the plant, this furnace is fired by excess hydrogen from the chlor-alkali and
ethylene plants. However, some of this hydrogen will be transmitted to the Shell upgrader at Scotford,
and the cracker will revert to natural gas firing which will significantly increase the CO2 generated. The
exhaust gas generated will be a conventional flue gas from combustion with a moisture content of about
18.5%.
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The cogeneration unit at Dow consists of three gas turbine/steam turbine assemblies with a capacity of
320 MWe of combined cycle power. These three units generate approximately 25% more power than the
plant requires at present but will soon be fully utilized.
Capturing CO2 from the combustion flue gases is expensive using current technologies. It would require
further development in the area of solid sorbents, oxy-fuel cycles, physical solvents, membranes and
hybrid processes.
Shell Chemicals/Refinery/Upgrader
Shell Canada has operated the Scotford Refinery since 1984, processing synthetic crude into
transportation fuels and feedstock for polymer manufacture. The refinery is based upon hydrocracking of
feedstock and includes a 1.5 106m3/d hydrogen plant. The Upgrader is more recent, becoming fully
operational in the spring of 2003, receiving diluted bitumen from the Muskeg River Mine owned by Shell
with partners Chevron Canada and Western Oil Sands and hydrocracking the recovered bitumen to
produce a synthetic crude oil for the neighboring Refinery and for export to other refineries. The
hydrogen plant at the Upgrader has a daily production of about 3.0 106m3/d.
Both hydrogen plants depend upon PSA technology for separation of the hydrogen from the co-product
fuel gas. The CO2 concentration in two offgas streams from the PSA ranges from 38 to 44%. Total
quantities of CO2 amount to 1,200 kt/year, with the upgrader offgas containing twice as much CO2 as the
refinery off gas stream.
CO2 recovery can be accomplished by physical absorption of the CO2 and its subsequent recovery for
storage. The balance of the exhaust gases can be put back to the plant for fuel uses (the current method is
for fuel use and applies to the entire PSA exhaust gas). The alternative approach of oxy-fuel combustion,
accomplishes a similar result by combusting the exhaust gases with oxygen, producing additional CO2
and water that can be condensed out of the gas stream prior to injection for storage.
In the Shell Complex, the Chemicals Unit has an ethylene oxide plant. The CO2 in the exhaust is extracted
and shipped across the fence to Air Liquide for liquefaction and sold as merchant CO2.
Agrium
Agrium has two operating ammonia plants in this area for fertilizer production, one at Redwater and the
other at Fort Saskatchewan. For the Agrium Redwater plant, there are two CO2 streams:
1. The CO2 recovered from the potassium carbonate absorption in the Agrium Redwater plant is
>98.5% purity on a dry basis. The CO2 is recovered by steam stripping of rich solvent from the
CO2 absorber. The CO2 is water saturated (at the stripper temperature of 97ºC), but otherwise
reasonably pure as the H2 and CO impurities report with the synthesis gas. At the Agrium
Redwater plant, about 63% of the CO2 produced is transported to the urea manufacturing plant
where it is combined with ammonia to produce urea. The remaining CO2 is vented at present.
However, this stream can be recovered by simple dehydration and compression.
2. The flue gas from the reformer furnace is exhaust gas from conventional natural gas combustion
and has relatively low CO2 content and appreciable oxygen content. In the plant, the flue gas is
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used as a heat source for energy conservation and would be available at a suitable temperature
from the feed lines to the main stack.
Figure H-2: Development stages of a multi-industrial CO2 emission hub
These two streams are very different, both in their compositions and in the volumes of gas involved. The
reformer exhaust gas after hydrogen recovery contains greater than 98.5% CO2 (dry basis), while the flue
gas from the reformer furnace is conventional combustion gas with a low CO2 content (about 7%), and a
significant oxygen content (about 3%). The volumes of gas produced are also markedly different.
Air Liquide
Air Liquide operates a CO2 liquefaction plant, an oxygen plant and a cogeneration plant in Fort
Saskatchewan. It is the cogeneration plant that is considered here. This cogeneration plant provides steam
and electricity to the Shell Plant at Scotford and is rated at 80 MW. Natural gas is the fuel for the
combustion turbine and for auxiliary firing in the Heat Recovery Steam Generator (HRSG). Based upon
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stack gas analysis, the concentration of CO2 in the exhaust gas is about 3.3% and the total quantity of CO2
generated is 521 kt/y. This total will change somewhat as the requirements for electricity and steam vary.
Opportunity Summary
Figure H-2 summarizes a view of the enabling conditions and the technology research that must be
performed to assist in the commercial development stages of a multi-industrial CO2 emission hub for
capture of the various CO2 streams. In the Fort Saskatchewan hub, significant amounts of high purity CO2
are available from feed gas processing, ethylene oxide production, and from hydrogen production in the
ammonia plant. Total CO2 amounts to 2,500 tonnes per day. The first stage opportunity is to capture CO2
from these high purity sources by dehydration and compression. This can happen in the present time
frame of 2005. Air Liquide and Praxair already have plants in the hub recovering the CO2 for sales. The
second stage opportunity is the capture of CO2 from the PSA off-gas from hydrogen production. The CO2
concentration in the two off-gas streams from the Shell Upgrader PSA ranges from 38 to 44%. Total
quantities of CO2 amount to 3,300 tonnes per day. CO2 recovery can be accomplished by physical
absorption of the CO2 and its subsequent recovery for disposal. The balance of the exhaust gases can be
put back to the plant for fuel uses (the current method is for fuel use and applies to the entire PSA exhaust
gas). The alternative approach of oxy-fuel combustion, accomplishes a similar result by combusting the
exhaust gases with oxygen, producing additional CO2 and water that can be condensed out of the gas
stream prior to injection for storage. Physical absorption techniques and oxy-fuel combustion must be
demonstrated before commercial deployment can take place. Another opportunity is in the CO2 capture
from gasification of coal or petroleum coke either with hydrogen production or IGCC. A pilot scheme has
been proposed. Physical solvent, sold sorbents, membranes and hybrid processes are some of the
technologies to try to capture the CO2. Gasifier tag-on research should also be investigated. The time
frame for this development would be in the 2012-2015 period. Another opportunity would be in the CO2
capture from PSA for hydrogen production at new plants. The third stage would be CO2 capture from
commercial gasifers. The time frame for this would be in the period 2020 and beyond, after the
technologies are successfully demonstrated at the second stage opportunity. The hub produces large
amount of combustion flue gases. The long-term opportunity is in the capture of this highly diluted CO2
in the combustion flue gas stream. This requires significant R&D. The time frame for commercial
deployment would be in the 2030 and beyond. Inexpensive pipeline transportation for all these purified
CO2 streams to geological sinks is required.
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APPENDIX I - OFF-GAS FROM OIL REFINERIES AND
BITUMEN UPGRADING
By John Payzant and John Zhou (Alberta Research Council Inc.)
Off-gas may be roughly defined as the C3 and lower boiling gaseous materials produced by the upgrading
of petroleum during thermal treatment operations. Off-gas is principally generated in petroleum
upgrading operations such as catalytic cracking and coking. In these upgrading operations the feedstock
is heated sufficiently hot to cause the interatomic bonds in the molecules to break, converting nondistilling or high boiling materials into more desirable, lower boiling materials. Every effort is made in
petroleum refining to maximize the yield of distillable liquid, as liquid transportation fuel is the most
desirable product.
The off-gas from these operations is typically a mixture of hydrogen, methane, ethane and ethylene,
propane and propylene with varying amounts of other gases such as nitrogen, carbon oxides and hydrogen
sulfide. Typically, the off-gas is subjected to an amine scrubbing operation to remove hydrogen sulfide
and/or carbon dioxide etc. prior to use as fuel. C4 and higher boiling materials are recovered for use in
transportation fuels and other products. The CO2 content of the off-gas varies from 0 to 40%. In most
refineries the off-gas is burned for process heat requirements which produces a CO2-rich flue gas.
The value of the individual components in off-gas is considerably more than the value of the mixture as
heating fuel. The hydrogen and olefins contained in off-gas are much more valuable than say methane,
but the challenge lies in the economic separation of the valuable components from the mixture. The
economics of the separation is dependent on identifying appropriate markets for the separated
components and, most importantly, the quantity of off-gas available. It is this last component, the scale of
the operation, which has limited the use of off-gas to fuel. At many oil refineries, the quantity of off-gas
produced is too small to justify the capital cost of a separation train; however, in Alberta, the quantity of
off-gas produced in bitumen upgrading operations is sufficiently large to justify the recovery of individual
components.
James G. Speight has authored texts on Petroleum including The Chemistry and Technology of Petroleum
(1990) and Fuel Science and Technology Handbook (1991). In Fuel Science and Technology Handbook,
p. 249, the author indicates that the yield of off-gas in catalytic cracking operations is in the 5-wt% to 10wt% range of process feed. In delayed coking and fluid coking, the yield of off-gas is again in the 5-wt%
to 10-wt% range of process feed, being somewhat higher in fluid coking than in delayed coking.
Alberta Oil Sands
Coking
In Alberta, the bitumen upgrading plants employ a coking operation as a primary upgrading step.
Because coking is the primary upgrading operation, large quantities of off-gas are produced. Data are
available indicating the quantity and composition of the off-gas from Syncrude and Suncor.
Unfortunately, such data is not readily available for petroleum refineries in the Edmonton area.
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Estimates of Off-Gas Volume from Oil Sands Upgrading in Alberta
Estimating the quantity of off-gas available for further processing in Alberta is difficult. The major
bitumen upgrading facilities in Ft. McMurray generate 5-wt% to 10-wt% of process feed as off-gas. At
present, this off-gas is mainly consumed on site as process fuel. Suncor recovers the C3 fraction from its
off-gas, which is sent to the Williams Energy plant in the Edmonton area where propylene is recovered.
The scale of bitumen upgrading operations in Alberta is considerably larger than the refining capacity for
conventional petroleum. This trend is expected to continue in the future as conventional petroleum
reserves decline, and production from the oil sands increases. Each of the oil sands plants in Ft.
McMurray processes several hundred thousand barrels of bitumen per day. Much of this bitumen is
subjected to a coking or hydrocracking operation, and off-gas is generated from these operations.
An attempt is made to estimate the volume of off-gas from Alberta’s oil sands plants (Table I-1). Off-gas
volume is estimated based on following assumptions: 8% for fluid coking process, 6% for delayed coking
process, 3% for hydroprocessing, and. 5% for future projects with various upgrading process. Based on
the information we have, these assumptions should be reasonable.
Table I-1: Estimate of Off-gas Production from Bitumen Upgrading
Project
Capacity
(bpd)
Upgrading
*Off-gas
Process
(bpd)
Fluid Coking
Delayed coking
Hydroprocessing
17,600
13,200
3,900
Current Production
Syncrude
Suncor
Albian Sands
220,000
220,000
130,000
Estimated Future Production up to 2012
Combined future projects
Total Capacity
1,800,000
2,460,000
Various
90,000
124,700
Source: Compiled from Oil Sands Industry Update, Alberta
Economic Development, March 2004
*Off-gas volume is estimated based on following assumptions:
8% for fluid coking process, 6% for delayed coking process, 3%
for hydroprocessing, and. 5% for future projects with various
upgrading process.
According to National Energy Board (2001) prediction, the amount of C2/C2= entrained in bitumen
upgrading off-gas will be 7,900 m3/d of liquid equivalent by 2012.
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Table I-2: Example of Composition of off-gas from a Bitumen Coking Operation
Component
Mol %
H2
16.3
CH4
29.0
C2/C2=,
27.3
C3/C3=
29.3
C4+
~2.0
CO, N2, Others
Balance
Off-Gases from Hydrogen Production
Large quantities of natural gas are currently re-formed with steam for hydrogen production. The
hydrogen is used for upgrading of bitumen into transportation fuels. The final purification of the
hydrogen from the steam re-former is done using PSA (pressure swing adsorption). The exhaust gas from
the PSA unit is typically 40% CO2, 35% H2, 30% CH4 and is consumed as fuel. The carbon dioxide and
hydrogen could be recovered from this mixture with the hydrogen being used on site and the carbon
dioxide sent for other uses or disposal.
Conventional Refineries
Catalytic Cracking
The quantity of off-gas produced as a wt% of feedstock depends on the nature of the feedstock and design
of the processing conditions. In the conventional petroleum refinery, only a minor portion of total
refinery feedstock is subjected to catalytic cracking. Conventional petroleum is distilled to recover as
much liquid as possible in the boiling point range of transportation fuels. Heavier, or higher boiling
fractions, are hydrotreated to remove heteroatoms, and then sent to a catalytic cracker where, in the
presence of catalyst, the heavier fractions are broken down into lower boiling materials which are then
further upgraded into transportation fuels. Off-gas, in the 5-wt% to 10-wt% range of feed to the
operation, is produced.
The total quantity of off-gas produced from a catalytic cracking in Alberta is difficult to estimate. In
refining a conventional petroleum, the proportion of the total feed that goes to the a catalytic cracker will
depend on the API gravity of the feed and the ratio of various components that is desired by the refiner.
A rough estimate is that the equivalent of 20-wt% to 30-wt% of the conventional crude petroleum
feedstock to the refinery goes to the catalytic cracker. The off-gas from this operation is consumed at the
refinery for process heat requirements.
Estimates of Off-Gas Volumes from Conventional Petroleum Refineries in Canada
By contrast, in conventional petroleum refineries, only a portion of the feedstock is subjected to catalytic
cracking or coking. Table I-3 is an estimate of off-gas volume from all refineries in Canada. We have
assumed that on average, 20% of oil going through the refinery will be catalytically cracked, and that
10% of catalytically cracked material will be converted to off-gas. We have less information to verify
this assumption. We do not have the actual composition of off-gas from these refineries.
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Table I-3: Canadian Refinery Capacity and Estimated Off-Gas Volume
Refinery
Refining Come-by-Chance
Irving Oil Saint John
Shell Canada Montreal
Shell Canada Scotford
Imperial Oil Dartmouth
Imperial Oil Nanticoke
Imperial Oil Sarnia
Imperial Oil Strathcona
PetroCanada Montreal
PetroCanada Oakville
PetroCanada Strathcona
Suncor Sarnia
Ultramar Jean Gaudin
Consumers Co-op
Chevron Canada Burnaby
Total Nameplate Capacity
Province
NF
NB
QC
ON
NS
ON
ON
AB
QC
ON
AB
ON
QC
SK
BC
Capacity (bpd)
105,000
250,000
130,203
71,706
97,495
118,000
119,000
195,000
105,043
83,028
125,171
70,000
215,000
40,000
52,000
1,865,646
Source: Future Fuels, Oilweek, February 2, 2004
Estimated Off-gas from Canadian Refineries
Total Refinery Capacity
Bpd
1,865,646
Catalytic Cracked Portion
20%
373,129
Total Off-gas from Cdn Refineries
10%
73,129
The Opportunity
The quantity of off-gas ether being generated, or projected to be generated, from bitumen upgrading in
Alberta is large. It contains more than enough petrochemicals to act as feedstock for a world-scale olefin
polymerizing plant. This represents a tremendous economic opportunity.
The Challenge
The challenge is to identify, and/or develop technologies to recover petrochemicals from the coking and
refinery off-gas, and where significant CO2 is generated – capture it. The off-gas is a complex mixture of
petrochemicals. Technologies are well known for the separation of these petrochemicals from feeds that
are principally one component; however, off-gas is a mixture of several valuable petrochemicals, and
therein lays the challenge.
It is anticipated that the best efficiency will be gained through hybrid systems involving a membrane as
one component. Currently, PSA (pressure swing adsorption) is used to separate hydrogen in steam
reforming. However, PSA is not suitable for H2 recovery from off-gas due to the relatively low content of
H2. A membrane separator can effectively separate H2 from off-gas, but the product may not have the
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sufficient purity for hydrotreating application. It is very likely a hybrid system of PSA and membrane
will be the most economical for H2 recovery.
Such a hybrid separation system has been found to be effective in other situations (Doshi et al., 1989,
“Integration of Membrane and PSA System for the Purification of Hydrogen and Production of OxoAlcohol Syngas,” AIChE Symposium Series No. 272, V85). The major tasks here are membrane selection,
confirmation of performance, system design, and modeling of process efficiency.
For olefin separation, a combination of cryogenic distillation and membrane separator may be attractive.
The best off-gas CO2 source is from hydrogen production of bitumen as discussed in Appendices E and
H. Even though the off-gases from coking and catalytic cracking contain very low CO2, they are part of
the overall system and cannot be neglected in any integrated CCS strategy.
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APPENDIX J - OPPORTUNITIES FOR A CO2 BACKBONE
PIPELINE
By Bob Mitchell (Inspired Value Inc.) and Bill Gunter (Alberta Research Council Inc.)
The CO2 Backbone Concept
Plexes in Canada are large consumers of energy. Since most plexes in Canada derive most of their energy
from fossil fuel consumption and are large CO2 emitters, they are also CO2 emission hubs. Based on
current day economics, some CO2 Enhanced Oil Recovery Projects may go ahead if low cost sources of
CO2 (i.e. pure CO2 by-product steams) are available. However, the CO2 needs to be transported from the
capture site to the sink site and transportation of CO2 by road and rail can be cost prohibitive, so a
pipeline is necessary if large amounts of CO2 are required over an extended period of time. Governments
have recognized the technology risk and the high cost of CO2 are substantial barriers to the utilization and
storage of CO2 so they have established fiscal programs to catalyze industry action. The Alberta
Government has established a $30 million royalty relief program for CO2 Enhanced Oil, Gas and/or
Coalbed Methane projects. The federal government has also established the CO2 Capture and Storage
Incentive Program that is providing $15 million to six projects during fiscal 2004-2005 and 2005-2006.
At the time of writing, five pilot projects have been approved under the Alberta program.
Why a Backbone?
Government-industry partnerships, such as this, are required to accelerate the uptake of CCS, but could
result in small feeder pipelines being built from the closest CO2 hubs or single large CO2 industrial source
to the geological sinks. This approach does not lead to the kind of orderly development of a CO2
transportation infrastructure that would facilitate the widespread deployment of CO2 utilization and the
long-term geological storage of substantial tonnage of CO2. Therefore if this ad hoc one-off approach is
taken to the development of the CO2 transportation infrastructure, the practice of CO2 capture and
geological storage may stall-out in Western Canada long before its full potential is realized. Fort
McMurray is the emission hub with the largest pure CO2 stream available and since it is a substantial
distance from good value-added long-term storage sites, that CO2 is unlikely to be captured and stored
without the construction of a large diameter CO2 backbone from Ft. McMurray to areas with good
potential for the utilization and long-term storage of CO2.
While a pipeline from the Ft. McMurray area to an area with good storage potential may appear, on the
surface, to be advisable, an alternative strategy would be to build a large diameter backbone pipeline
connecting the CO2 emission hubs (i.e. the sites of the major industrial plexes) and thereby assure
potential customers that a ready, robust and assured supply of CO2 will be available over the long-term.
The establishment of a CO2 backbone would reduce the supply and price risk to the CO2 buyer of relying
on a single supplier.
The development of a CO2 backbone could be done in stages – the obvious first stage being a leg from
Fort McMurray through Fort Saskatchewan (both having large pure CO2 waste streams) to Joffre and then
perhaps extending into Saskatchewan by way of Empress (Figure J-1). Sarnia is an isolated hub in Eastern
Canada, which can utilize geological sinks extending south from Canada into the US (Figure J-2) as the
Canadian portion of these geological sinks are fairly shallow and of limited capacity. A pipeline corridor
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which already exists between Montreal and Sarnia may be utilized at a later date to transport CO2 through
Sarnia to the US. A backbone to the Maritime Provinces from Sarnia may be attractive as an alternative
when the Maritime offshore gas reservoirs have been fully exploited and the depleted pools become
available for storing CO2. Note that coal- and gas-fired power plants such as those around Lake Wabamun
in Alberta, the Boundary Dam plant in Saskatchewan, the Nanticoke plant in Ontario and in Nova Scotia
will also have to be a part of this pipeline strategy in the future, when more efficient and less expensive
capture technologies have been developed for their dilute CO2 waste streams and/or when newer more
efficient clean thermal generating technologies that provide a more concentrated stream of CO2.
CO2 backbone pipelines could conceivably be used for shipping other commodities, and thus can play a
role in the efficient siting of new industry (e.g. such as regional upgraders). Finally, backbone
connections between the east and west have to be considered for transporting CO2, coal, bitumen and/or
gas. What makes sense will have to be based on economic and environmental evaluation. It seems
reasonable that the first segment of the backbone be built in Western Canada where significant emission
sources are found in close proximity to value-added storage sites. In addition, a CO2 distribution system
could perhaps even utilize existing pipeline and gas plant infrastructure.
International Considerations:
Market forces outside of Canada also play an important role. The expansion of the oil sands stirs up the
debate on what petroleum products should be exported from Canada (i.e. bitumen through
petrochemicals). Regardless of the product, new pipe capacity is needed to the US as well as to the west
coast to access the Asian markets. The planned Mackenzie and Alaskan pipelines from the large Arctic
gas fields will likely pass through Alberta on their way to markets in the US, and offer an opportunity for
buying and stripping the associated gas-liquids for the petrochemical industry. The CO2 backbone could
be a factor in this decision. The backbone could be designed as a prebuild for these northern pipelines
where a 42 inch large diameter pipe could be used to transport CO2 in the gaseous phase along with the
natural gas. Compression costs for the CO2 would be minimal as only blowers would be required to
move the CO2. Final compression of the CO2 would take place at the feeder lines off the backbone to the
depleted oil and gas fields and saline aquifers where the CO2 is stored.
Existing Infrastructure
A precursor for the backbone in Western Canada already exists in bitumen pipelines connecting the Oil
Sands Hub at Fort McMurray to the upgraders in the Multi-Industry Hub at Fort Saskatchewan; and both
gas and product pipelines connecting Fort Saskatchewan to the Petrochemical Hub at Joffre. These
connections would be upgraded in any scheme to build a CO2 backbone, and will depend on where crucial
processing is to take place in Alberta in order to climb up the fossil fuel commodity value chain. The
electricity hub at Wabamun is connected to the other three by power lines, a different form of an energy
carrier. New or revised fiscal policies centered on government investment (subsidies should be avoided if
possible) could play a role in encouraging a move by industry interest in this direction.
Feeder pipelines to the depleted oil and gas fields from the backbone may already exist, as pipelines were
built in the past for production from the same fields that are the targets for storage. These abandoned
pipelines could be connected with new short pipe segments to the backbone for CO2 delivery. The
backbone can flow in either direction depending on the need and in this sense the backbone can be
regarded as a pressurized supply manifold.
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Figure J-1: CO2 backbone for the Western Canadian Sedimentary Basin
CO2 Supply Considerations:
The issue of over or under supply of CO2 for the backbone is addressed by the concept of using a giant
“surge” tank. The largest such geological tanks in Western Canada are found in the shale rebound area of
the WCSB where rebound of the crust in the mountains is causing giant shale formations to act as a
sponge and causing deep saline aquifers to flow towards the Rockies where these fluids will be
hydrodynamically trapped in deep formations for geological time (presumably until the next ice age when
new glaciers may recompress these deep formations). The overflow of CO2 for the backbone would be
injected into the aquifers of the rebound zone, and could be recovered as needed when the backbone is
experiencing underflow (tonnes extracted from backbone exceed tonnes inputted). This surge capacity
will help to maintain pressure in the backbone. In terms of economics, this could be considered as a bank.
When the CO2 is injected into the rebound zone, it is considered stored and GHG credits can be earned.
When the CO2 is retrieved from the surge tank, emission credits will need to be purchased. The federal
government’s cap on the compliance cost of CO2 could act as a leveller for the CO2 backbone.
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Figure J-2: A CO2 backbone scheme for Canada. Canada’s sedimentary basins are those
areas of Canada that appear in grey stripping. Note a backbone between Sarnia and the
Maritime Provinces may be justifiable in the future, once the Maritime gas and oil industry
matures and depleted pools become available..
Potential Business Arrangement to Keep Pipeline at Capacity
The business arrangement might be something like the following. The CO2 backbone could be built to
operate more like a manifold (electricity grid) than a pipeline because the flow would not have to be in a
particular direction. A CO2 source could input its pipeline spec CO2 (i.e., of a specific purity and
pressure) into the system at any injection point on the system. There would be tolls charged by the
backbone system on a carefully thought out basis (e.g. would have to be some toll for inputting CO2 but
tolls might not be impacted by the distance it is transported, and tolls for taking delivery of CO2 from the
system could be small). The customer (of the CO2 supplier that has input CO2 into the backbone) could
take delivery of its CO2 at any outlet along its length (likely to a lateral supply pipeline).
If the inputs to the system were greater than the takes, the system could be pressure-balanced by injecting
CO2 in the following priority order:
1) temporarily store in salt caverns;
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2) temporarily store in depleted oil or gas pools;
3) permanent storage in one of the research pilot test strata (at an injection rate appropriate for
the research project being done);
4) permanent storage in a deep saline aquifer, and
5) if absolutely necessary, vent to the atmosphere – this would be a safety valve only. Any
emissions fees associated with venting would be allocated back to anyone who injected more CO2
into the backbone than they sold.
When the tonnes extracted are more than those inputted, we would expect to balance pressure in the
system by drawing CO2 from 1 and 2. If a company inputs more CO2 than it sells, it loses the right to
revenues arising from the sale of that excess CO2 it put into the system, although it would have to share in
any emissions charges if the system has to vent (5). The backbone system operator may also have some
of its own staff trying to sell some of the excess CO2 on a spot basis before we go to steps 4 and/or 5.
This would earn income for the backbone system operator. If the system has the excess CO2 to
permanently store it (i.e., either 3 or 4), then the government could pay something like $15 per tonne
injected for permanent storage (This should be a much preferred alternative to buying offshore credits).
The revenues from permanent storage would go towards the operation of the backbone and the field test
and injection centre in some proportion.
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APPENDIX K – A “BALLPARK” FINANCIAL PLAN FOR
IMPLEMENTATION OF CCS IN CANADA
By Bob Mitchell (Inspired Value Inc.) with advice and input from Ken Brown (GSCI), Bob Stobbs
(EnergyINet & Canadian Clean Power Coalition) and Bill Pearson (NRCan-CANMET)
Table K-1 at the end of this appendix was prepared to provide an indication of rough ballpark costs for
some important capture and geological storage project opportunities in Canada. These will be refined in
the future. Nineteen project opportunities are listed: 11 in the Western Canada Sedimentary Basin (6 of
those in Alberta, 4 in Saskatchewan and 1 in both provinces), 3 in the Maritime Provinces, 3 in Ontario
and Quebec, and 2 in all regions of Canada. Where it is deemed necessary for Governments to invest to
stimulate appropriate development, the additional costs have been proportioned into thirds, split equally
between the federal government, the provincial government and industry. The cost estimates are divided
into two periods: 2008 – 2012 (5 years); and 2013 – 2020 (8 years). The two governments’ investments
are shown in a separate column of the spreadsheet; and total over three billion dollars in the first
commitment period and over two billion dollars in the second commitment period.
CO2 Transportation Projects
Projects 1, 8, 12 and 15 are all CO2 backbone pipeline infrastructure projects in Alberta, Saskatchewan,
the Maritimes and Ontario-Quebec. The size of the backbone pipeline will vary depending on the
proximity of the geological sinks to the CO2 sources and the injectivities into the sinks and the size of the
sources. The capital costs, for the purposes of this worksheet are assumed to be incurred over a twelveyear period on a flat line basis for a 12 to 14 inch diameter pipeline capable of carrying 5000 tonnes/day
of CO2. In cases where higher loads of CO2 are anticipated, the cost will increase appropriately (e.g. the
cost will double if the diameter of the pipeline is increased to 24 inches and the pipeline would be capable
of carrying 30,000 tonnes/day of CO2). At its peak, it is predicted that between 50,000 and 100,000
tonnes/day of CO2 will be stored in geological media. Of course any specific segment of the pipeline will
only be carrying a fraction of this amount. Value-added storage opportunities are available at present in
the Western Canada Sedimentary Basin in reasonable proximity to large point source emitters and/or
proposed emission hubs, so this spreadsheet assumes that the pipeline infrastructure would be developed
there in the first period and expanded in the second.
Project 1 2008 – 2012 (Alberta)
The costs included in the initial pipeline leg in Alberta are for a large diameter backbone pipeline
joining the locations in Alberta with more than 1,000 tonnes of high purity CO2 (i.e., greater than
80% pure). Those locations are Ft. McMurray, Ft. Saskatchewan and Joffre (near Red Deer).
The initial phase of the project is also assumed to include supply laterals running from the
pipeline backbone to both the Pembina and Swan Hills oil fields. Wherever possible, the supply
laterals would utilize existing and underutilized oil and gas pipelines that are already in place.
Project 1 2013 – 2020 (Alberta & BC)
This second phase of the pipeline is assumed to involve the extension of the large diameter CO2
backbone pipeline south from Joffre to Taber (near Lethbridge) and west from Ft. Saskatchewan
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to link in the large gas plants and storage opportunities in the area around Ft. St. John, BC.
Project 8 2008 – 2012 (Saskatchewan)
The costs for the initial Saskatchewan leg of the large diameter CO2 backbone pipeline assumes
that it will connect an emission hub in Regina with the sources in the Belle Plaine area, the
storage opportunities around Weyburn and Midale and the existing CO2 pipeline from Dakota
Electric that is supplying CO2 to the EnCana Weyburn project.
Project 8 2013 – 2020 (Saskatchewan & Alberta)
The cost in the spreadsheet assumes that the Saskatchewan leg of the CO2 backbone pipeline will
be extended west to pick up other emission sources in Saskatchewan and then on to Taber,
Alberta where it will join the Alberta leg of the backbone. (An alternative route for the link to the
Alberta leg of the backbone is northeast from Regina-Belle Plaine through Lloydminster and on
to Ft. Saskatchewan. For the purposes of this spreadsheet, the cost of either extension west can
be assumed to be about the same.
Project 12 2013 – 2020 (Maritime Provinces)
The cost estimate for this project assumes that the initial leg of the Maritime leg of a CO2
backbone pipeline would connect emission sources in St. John, New Brunswick with Halifax and
Sydney, Nova Scotia sources. Supply laterals for storage projects are assumed to be short and
inexpensive since the initial storage opportunities are expected to be deep onshore coal seams
underlying much of the area through which this leg of the pipeline would run. A study should be
undertaken in the 2008 – 2012 timeframe to determine the main CO2 emission sources in the area,
the precise locations of the optimal onshore storage locations as well as offshore storage
opportunities that could be developed in a subsequent time period.
Project 15 2013 – 2020 (Ontario-Quebec)
The cost estimate for Project 15 assumes a leg of the CO2 backbone pipeline linking the main
emissions sources and/or hubs in the Sarnia, Hamilton, Toronto, Kingston and Montreal areas. A
detailed review of potential source and storage sites should be undertaken to inform the plans for
this route. Since the best geological storage potential in this region of the country are in the
sedimentary basins sites in the Lake Huron, Lake Erie and Lake Ontario areas, it will be
important to work cooperatively with the US in developing the storage potential of the region. In
a subsequent period, the technology to capture CO2 in serpentinite rock (a rock that is broadly
available in the St. Lawrence-Great Lakes corridor) may be commercially available and the CO2
backbone could supply serpentinite as well as geological storage projects.
Capture from Electricity Generation Facilities
Projects 4, 5, 9, 10, 11, 13 and 16 all involve capturing CO2 from existing and new electricity generation
facilities. Projects 4 and 10 are for construction of next generation coal-fired power demonstration plants
with CO2 recovery. The costs in the table for these two projects reflect only the incremental costs of
those power plants over and above the cost of constructing a proven commercial super-critical pulverized
coal power plant. The incremental cost in each case is assumed to be about 50% of the cost of the
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conventional plant.
Project 4 2008 – 2012 (Alberta)
A new 400 megawatt commercial demonstration of an Integrated Gasification Combined Cycle
plant is expected to be built in Alberta and include equipment for CO2 capture. This plant could
be fuelled by coal or petroleum coke. The plant could be expected to be built in close proximity
to a ready supply of the chosen fuel, so if it is built to run on petroleum coke, it would likely be
built in the Ft. McMurray area and be linked into the CO2 backbone pipeline there. Otherwise, it
would likely be built near both an appropriate coal deposit and the CO2 backbone. The total cost
of $565 million cost ($113 million per year for 5 years), as mentioned above, is really only the
incremental cost above a conventional modern super-critical coal combustion facility. These
incremental cost are assumed to be shared equally among the province, the federal government
and industry. Government involvement in funding the project is assumed to be appropriate since
the capital cost and risks of a demonstration project are substantially higher than for a commercial
project. If governments want to help cause a technology breakthrough they can help finance the
demonstration project.
Project 5 2013 – 2020 (Alberta)
In the second period, about 6500 megawatts of next generation electricity facilities are expected
to be required in the province. The spreadsheet assumes some government financial involvement
in those facilities but if the technologies have been proven, government financial involvement
should not be necessary.
Project 9 2008 – 2012 (Saskatchewan)
An oxy-fuel demonstration project, retrofitting part of an existing pulverized coal plant with oxyfiring, could be developed by SaskPower to generate 60 megawatts of power. The $75 million
total cost is assumed to be shared between SaskPower, the province and the federal government
in the first five years of the plant’s operation.
Project 10 2008 – 2012 (Saskatchewan)
In this time period, SaskPower may also be interested in developing a commercial demonstration
(i.e., about 300 megawatts) of a new oxyfuel generation facility fired by low rank Saskatchewan
coal. In addition to sharing the technology risk, government financial involvement can help to
defray the high cost of oxygen over the first five years of the project’s operation.
Project 11 2013-2030 (Saskatchewan)
As with Alberta (see Project 5 above), Saskatchewan is expected to need 1200 megawatts of
generation facilities within this time frame to both replace old plants that are scheduled to be
retired and also to meet the expected demand growth. The CO2 capture costs and the technology
risks should drop during the first period (i.e., 2008 – 2012) so the need for government financial
involvement should be reassessed after the first period.
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Project 13 2008 – 2012 (Maritimes)
800 megawatts of new clean coal electricity generation is likely to be added in this time period.
As for Projects 5 and 11, the need for government financial involvement should be reassessed in
light of the prevailing technology risk at the time.
Project 16 2008 – 2012 (Ontario)
Clean coal technology is expected to be proven sufficiently by 2012 for Ontario to consider this
as a desirable electricity generation source. About 10,000 megawatts of new coal, natural gas
and/or bio-fuel fired generation with CO2 capture could be required to replace retiring nuclear and
thermal generation plants as well as to meet the expected growth in demand for electricity. The
CO2 could be stored in deep saline aquifers that run under the eastern Great Lakes. The need for
government financial involvement should be reassessed at the beginning of the period in light of
the prevailing technology risk at that time.
Capture from Petroleum and Petrochemical Sources
Projects 2, 3, 6, 14 and 17 primarily involve the capture of CO2 from refineries, natural gas and
petrochemical plants and oil sands upgraders. CO2 capture at other facilities like cement and ethanol
facilities could also be included.
Project 2 2008 – 2012 (Alberta)
There are more than 5000 tonnes per day of high purity CO2 (i.e., >80% CO2) available in the Ft.
McMurray area from Benfield hydrogen production plants. There are more than 2200 tonnes per
day of high purity CO2 available from petrochemical, fertilizer and upgrading facilities in the Ft.
Saskatchewan area (north of Edmonton). A further 1100 tonnes per day of high purity CO2 is
also available in the Joffre area. At present, a small amount of CO2 from the Joffre area is being
captured and sold for CO2 enhanced oil recovery. The existing Alberta and federal fiscal
programs to encourage the utilization of CO2 in oil and coalbed methane recovery will likely
cause more tonnes to be captured at any of the locations but it is not yet apparent that the demand
for CO2 for projects stimulated by these programs will be sufficient to cause widespread capture
and/or the development of a gathering system of CO2 from these sources in these emission hubs.
Government financial participation in the development of capture capacity and gathering systems
for these emission hubs may be required, although if Project 1 – the initial Alberta leg of the CO2
backbone pipeline – is developed, there may be no need for government financial involvement in
Project 2.
Project 3 2008 – 2012 (Alberta)
In addition to the high purity CO2 streams mentioned above, Ft. McMurray and Ft. Saskatchewan
respectively have about 3800 and 1600 tonnes per day of medium purity CO2 available at this
time. That volume is expected to grow apace with the substantial industrial growth anticipated in
those regions as well as new medium purity sources in the Joffre-Red Deer area. It is more costly
to capture CO2 from medium purity sources than for the high purity sources so government
financial involvement may be required initially to cause these emitters to begin capturing their
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CO2 to supply the storage industry. The amount of financial involvement required will be
reduced by the development of the pipeline backbone, reductions in the cost of CO2 and the
development of emission hubs.
Project 6 2013 – 2020 (Alberta)
Opti-Nexen’s Long Lake Project is going to be gasifying the heavy end of a bitumen barrel to
produce heat and hydrogen for their project. The project plans do not currently include
equipment to capture and compress CO2. This project is expected to demonstrate the commercial
potential to gasify these heavy ends and then others will follow their example as a way of
weaning themselves from high and volatile natural prices. Governments may need to get
involved in the initial cost of installing capture technologies in these facilities and ensuring that
they are tied into the CO2 transportation backbone. The amount of financial involvement
required will be reduced by the development of the pipeline backbone, reductions in the cost of
CO2 and the development of emission hubs.
Project 14 2013 – 2020 (Maritimes) and Project 17 2013 – 2020 (Ontario-Quebec)
There will be some substantial costs associated with retrofitting refineries and large fossil
industries in the Maritimes, Ontario and Quebec. The federal and provincial governments may
have to share financially in this cost of CO2 capture facilities and gathering systems. Like
Projects 2, 3 and 6, the amount of financial involvement required will be reduced by the
development of the pipeline backbone, reductions in the cost of CO2 and the development of
emission hubs.
Research, Development and Demonstration Programs for CCS
Project 18 2008 – 2012 and 2013 – 2020 (All Regions)
Project 18 relates to the ongoing financial investment by the federal government in encouraging
the research and development necessary to reduce the cost and improve the performance of CO2
capture, transport and storage technologies. This cost to the federal government assumes that this
investment in technology will be matched by equal contributions from the province and industrial
partners (perhaps on a basis that could be negotiated through the Energy Innovation Network).
Project 7 (SK & AB) and Project 19 (All Regions) 2008 – 2012 and 2013 -- 2020
Both these projects involve the ongoing measurement, monitoring and verification of CO2 that
has been or will be geologically stored as part of demonstration projects. Government
participation in the funding of measurement, monitoring and verification of CO2 injected and
stored in demonstration projects is necessary because the information collected will inform policy
and also help to allay any potential public concerns. Like the research and development project
above, this row of the spreadsheet only includes the combined federal government and provincial
government costs and it is assumed that this investment in measurement, monitoring and
verification will be matched by industry (i.e. contributing 1/3 of the total cost).
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Table K-1: A “ballpark” budget for CO2 Capture and Storage Initiatives
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