Carbon Capture: A Technology Assessment
Peter Folger, Coordinator
Specialist in Energy and Natural Resources Policy
October 21, 2013
Congressional Research Service
7-5700
www.crs.gov
R41325
CRS Report for Congress
Pr
epared for Members and Committees of Congress
Carbon Capture: A Technology Assessment
Summary
Carbon capture and sequestration (CCS) is widely seen as a critical strategy for limiting
atmospheric emissions of carbon dioxide (CO2)—the principal “greenhouse gas” linked to global
climate change—from power plants and other large industrial sources. This report focuses on the
first component of a CCS system, the CO2 capture process. Unlike the other two components of
CCS, transportation and geologic storage, the CO2 capture component of CCS is heavily
technology-dependent. For CCS to succeed at reducing CO2 emissions from a significant fraction
of large sources in the United States, CO2 capture technologies would need to be deployed
widely. Widespread commercial deployment will likely depend, in part, on the cost of the
technology deployed to capture CO2. This report assesses prospects for improved, lower-cost
technologies for each of the three current approaches to CO2 capture: post-combustion capture;
pre-combustion capture; and oxy-combustion capture.
While all three approaches are capable of high capture efficiencies (typically about 90%), the
major drawbacks of current processes are their high cost and the large energy requirements for
operation. Another drawback is that at present there are still no full-scale applications of CO2
capture on a coal-fired or gas-fired power plant. However, a number of large-scale demonstration
projects at both coal combustion and gasification-based power plants are planned or underway in
the United States and elsewhere. Substantial research and development (R&D) activities are also
underway in the United States and elsewhere to develop and commercialize lower-cost capture
systems with smaller energy penalties. Current R&D activities include development and testing
of new or improved solvents that can lower the cost of current post-combustion and pre-
combustion capture, as well as research on a variety of potential “breakthrough technologies”
such as novel solvents, sorbents, membranes, and oxyfuel systems that hold promise for even
lower-cost capture systems.
The future use of coal in the United States will likely depend on whether and how CCS is
deployed if legislative or regulatory actions curtail future CO2 emissions. Congressional interest
in CCS was renewed when the U.S. Environmental Protection Agency (EPA) re-proposed
standards for carbon dioxide (CO2) from new fossil-fueled power plants on September 20, 2013.
These re-proposed standards would not apply to existing power plants. As re-proposed, the
standards would limit emissions of CO2 to no more than 1,100 pounds per megawatt-hour of
production from new coal-fired power plants and between 1,000 and 1,100 for new natural gas-
fired plants. According to EPA, new natural gas-fired stationary power plants should be able to
meet the proposed standards. However, new coal-fired plants only would be able to meet the
standards by installing CCS technology, which could add significant capital costs.
In general, the focus of most current R&D activities is on cost reduction rather than additional
gains in the efficiency of CO2 capture. Key questions regarding the outcomes from these R&D
efforts are when advanced CO2 capture systems will be available for commercial rollout, and how
much cheaper they will be compared to current technology. “Technology roadmaps” developed
by governmental and private-sector organizations in the United States and elsewhere anticipate
that CO2 capture will be available for commercial deployment at power plants by 2020. A number
of roadmaps also project that some novel, lower-cost technologies will be commercial in the 2020
time frame. Such projections acknowledge, however, that this will require aggressive and
sustained efforts to advance promising concepts to commercial reality.
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Carbon Capture: A Technology Assessment
Achieving significant cost reductions will likely require not only a vigorous and sustained level of
R&D, but also a significant market for CO2 capture technologies to generate a substantial level of
commercial deployment. At present such a market does not yet exist. While various types of
incentive programs can accelerate the development and deployment of CO2 capture technology,
actions that significantly limit emissions of CO2 to the atmosphere ultimately are needed to
realize substantial and sustained reductions in the future cost of CO2 capture.
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Contents
Introduction ...................................................................................................................................... 1
Structure of the Report .............................................................................................................. 2
Other CRS Reports on CCS ...................................................................................................... 2
Technology Assessment Authorship .......................................................................................... 2
Acknowledgment ....................................................................................................................... 3
Chapter 1: Executive Summary ....................................................................................................... 3
Background................................................................................................................................ 3
Current Research and Development (R&D) Activities ............................................................. 3
Future Outlook........................................................................................................................... 5
Chapter 2: Background and Scope of Report .................................................................................. 7
Introduction ............................................................................................................................... 7
Report Objectives and Scope ..................................................................................................... 8
Organization of This Report ...................................................................................................... 9
Chapter 3: Overview of CO2 Capture Technologies ...................................................................... 10
Introduction ............................................................................................................................. 10
Post-Combustion Processes ..................................................................................................... 11
Pre-Combustion Processes ...................................................................................................... 13
Oxy-Combustion Systems ....................................................................................................... 15
Capture System Energy Penalty .............................................................................................. 16
Current Cost of CO2 Capture ................................................................................................... 17
Costs for New Power Plants .............................................................................................. 17
Retrofit Costs for Existing Power Plants ........................................................................... 19
Costs for Other Industrial Processes ................................................................................. 19
Important Caveat Concerning Costs.................................................................................. 20
Chapter 4: Stages of Technology Development ............................................................................. 21
Introduction ............................................................................................................................. 21
The Process of Technological Change ..................................................................................... 21
Technology Readiness Levels (TRLs) ..................................................................................... 22
Technology Maturity Levels Used in this Study ..................................................................... 24
Commercial Process .......................................................................................................... 24
Full-Scale Demonstration Plant......................................................................................... 24
Pilot Plant Scale ................................................................................................................ 25
Laboratory or Bench Scale ................................................................................................ 25
Conceptual Design ............................................................................................................ 25
Current Status of CO2 Capture Technologies .......................................................................... 25
Chapter 5: Status of Post-Combustion Capture ............................................................................. 26
Introduction ............................................................................................................................. 26
Commercial Processes ............................................................................................................. 26
Full-Scale Demonstration Plants ............................................................................................. 29
Pilot Plant Projects .................................................................................................................. 31
Amine-Based Capture Processes ....................................................................................... 32
Ammonia-Based Capture Processes .................................................................................. 33
The Alstom Chilled Ammonia Process ............................................................................. 33
The Powerspan ECO2 Capture Process ............................................................................. 34
Laboratory- or Bench-Scale Processes .................................................................................... 35
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Liquid Solvent-Based Approaches .................................................................................... 35
Solid Sorbent-Based Approaches ...................................................................................... 37
Membrane-Based Approaches ........................................................................................... 40
Conceptual Design Stage ......................................................................................................... 41
Novel Sorbents .................................................................................................................. 41
Hybrid Capture Systems .................................................................................................... 42
Novel Regeneration Methods ............................................................................................ 42
System Studies .................................................................................................................. 44
Conclusion ............................................................................................................................... 44
Chapter 6: Status of Pre-Combustion Capture ............................................................................... 46
Introduction ............................................................................................................................. 46
Commercial Processes ............................................................................................................. 46
Full-Scale Demonstration Plants ............................................................................................. 47
Pilot Plant Projects .................................................................................................................. 49
Laboratory- or Bench-Scale Developments............................................................................. 50
Solvent-Based Capture Processes ..................................................................................... 50
Sorbent-Based Capture Processes ..................................................................................... 51
Membrane-Based Capture Processes ................................................................................ 52
Enhanced Water Gas Shift Reactors .................................................................................. 54
Conceptual Design Stage ......................................................................................................... 55
Conclusion ............................................................................................................................... 56
Chapter 7: Status of Oxy-Combustion Capture ............................................................................. 57
Introduction ............................................................................................................................. 57
Commercial Processes ............................................................................................................. 57
Full-Scale Demonstration Plants ............................................................................................. 57
Pilot Plant Projects .................................................................................................................. 58
Laboratory- or Bench-Scale Developments............................................................................. 60
Advanced Oxygen Production Methods ............................................................................ 61
Chemical Looping Combustion ........................................................................................ 62
Conceptual Design Stage ......................................................................................................... 63
Conclusion ............................................................................................................................... 64
Chapter 8: Cost and Deployment Outlook for Advanced Capture Systems .................................. 65
Introduction ............................................................................................................................. 65
Projected Cost Reductions for CO2 Capture ............................................................................ 65
Results from Engineering-Economic Analyses ................................................................. 66
Results from Experience Curve Analyses ......................................................................... 68
Roadmaps for Capture Technology Commercialization .......................................................... 69
The DOE Roadmap ........................................................................................................... 70
The CSLF Roadmap .......................................................................................................... 73
Other Roadmaps and Milestones ....................................................................................... 73
Scenarios for CCS Deployment ............................................................................................... 74
Conclusion ............................................................................................................................... 75
Chapter 9: Lessons from Past Experience ..................................................................................... 76
Introduction ............................................................................................................................. 76
Case Studies of Novel Capture Technology Development ...................................................... 76
The Copper Oxide Process ................................................................................................ 77
The Electron Beam Process ............................................................................................... 78
The NOXSO Process ......................................................................................................... 79
The Furnace Limestone Injection Process ......................................................................... 80
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The Duct Sorbent Injection Process .................................................................................. 81
Implications for Advanced Carbon Capture Systems ........................................................ 82
The Pace of Capture Technology Deployment ........................................................................ 83
Rates of Performance and Cost Improvements ....................................................................... 84
The Critical Role of Government Actions ............................................................................... 86
Conclusion ............................................................................................................................... 88
Chapter 10: Discussion and Conclusions ....................................................................................... 89
Figures
Figure 1. Schematic of a CCS System, Consisting of CO2 Capture, Transport, and Storage .......... 8
Figure 2. Technical Options for CO2 Capture ................................................................................ 10
Figure 3. Schematic of a Coal-Fired Power Plant with Post-Combustion CO2 Capture
Using an Amine Scrubber System .............................................................................................. 11
Figure 4. Details of Flue Gas and Sorbent Flows for an Amine-Based Post-Combustion
CO2 Capture System ................................................................................................................... 12
Figure 5. Schematic of an Amine-Based Post-Combustion CO2 Capture System Applied
to a Natural Gas Combined Cycle (NGCC) Power Plant ........................................................... 13
Figure 6. Schematic of an Integrated Gasification Combined Cycle (IGCC) Coal Power
Plant with Pre-Combustion CO2 Capture Using a Water-Gas Shift Reactor and a
Selexol CO2 Separation System .................................................................................................. 13
Figure 7. Details of the Fuel Gas and Sorbent Flows for Pre-Combustion CO2 Capture .............. 14
Figure 8. Schematic of a Coal-Fired Power Plant Using Oxy-Combustion .................................. 15
Figure 9. Cost of Electricity Generation (2007 US$/MWh) as a Function
of the CO2 Emission Rate (tonnes CO2/MWh) for New Power Plants
Burning Bituminous Coal or Natural Gas .................................................................................. 18
Figure 10. Stages of Technological Change and Their Interactions .............................................. 22
Figure 11. Descriptions of Technology Readiness Levels (TRLs) ................................................ 23
Figure 12. A Department of Energy View of Technology Development Stages
and Their Corresponding TRLs .................................................................................................. 24
Figure 13. An Amine-Based CO2 Capture System Used to Purify Natural Gas at BP’s In
Salah Plant in Algeria ................................................................................................................. 28
Figure 14. Amine-Based Post-Combustion CO2 Capture Systems Treating a Portion of the
Flue Gas from a Coal-Fired Power Plant in Oklahoma, USA (left), and a Natural Gas
Combined Cycle (NGCC) Plant in Massachusetts, USA (right) ................................................ 29
Figure 15. Schematic of the Chilled Ammonia Process for CO2 Capture (left) and the 20
MW Pilot Plant at the AEP Mountaineer Station in West Virginia (right) .................................. 34
Figure 16. Schematic of CO2 Adsorption on the Surfaces of a Solid Sorbent ............................... 38
Figure 17. Schematic of a Process Concept Using Electrodialysis to Capture
and Regenerate CO2, While Generating Hydrogen and Oxygen as By-Products ....................... 43
Figure 18. Technical Readiness Levels (TRLs) of Projects Developing Post-Combustion
Capture Technologies Using Different Approaches.................................................................... 44
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Figure 19. A Pre-Combustion CO2 Capture System Is Used to Produce Hydrogen from
Gasified Petcoke at the Farmlands Plant in Kansas (left) and Synthetic Natural Gas
from Coal at the Dakota Gasification Plant in North Dakota (right) .......................................... 47
Figure 20. Schematic of Pre-Combustion CO2 Capture Using a Membrane to Separate
CO2 and H2 in the Gas Stream of an IGCC Power Plant ............................................................ 53
Figure 21. Projected Cost Reductions for IGCC Systems
Employing Advanced Technologies ........................................................................................... 55
Figure 22. Oxy-Combustion Pilot Plant Capturing CO2 from the Flue Gas of a Coal-Fired
Boiler at the Schwarze Pumpe Power Station in Germany ......................................................... 59
Figure 23. The Ion Transport Membrane (ITM) Oxygen Production Technology
Being Developed by Air Products .............................................................................................. 60
Figure 24. Schematic of a Chemical Looping Combustion System .............................................. 62
Figure 25. A Proposed Oxygen-Mixed Conduction Membrane Reactor Design for a
Natural Gas-Fired Power Plant ................................................................................................... 64
Figure 26. Typical Trend in Cost Estimates for a New Technology as It Develops
from a Research Concept to Commercial Maturity .................................................................... 66
Figure 27. Cost of Electricity (COE) Increases for Power Plants with CO2 Capture and
Storage Using Current Technology (column A) and Various Advanced Technologies
(columns B to G) ........................................................................................................................ 67
Figure 28. Current Cost of Electricity (COE) for IGCC and PC Power Plants with and
without CO2 Capture and Storage (CCS), Plus Future Costs with
Advanced Technologies from R&D ........................................................................................... 68
Figure 29. Projected Cost Reductions for Four Types of Power Plants with CO2 Capture
Based on Experience Curves for Major Plant Components ....................................................... 69
Figure 30. The DOE Carbon Sequestration Program Roadmap from 2012 to 2022 ..................... 70
Figure 31. DOE’s Timeline from R&D to Commercial Deployment of Advanced Post-
Combustion Capture Technologies for Existing Power Plants ................................................... 71
Figure 32. Steps in Technology Validation and Scale-Up Projects to Meet CURC-EPRI
Roadmap Goals for Advanced Coal Technologies with CCS ..................................................... 72
Figure 33. EPRI Projections of Capture Technology Development Based on Technology
Readiness Levels (TRLs) ............................................................................................................ 72
Figure 34. Key Milestones in the CSLF Technology Roadmap .................................................... 73
Figure 35. Capture System R&D Needs in the CCS Roadmap for Canada ................................... 74
Figure 36. Projected U.S. Energy Mix in 2050 for Two GHG Reduction Scenarios .................... 75
Figure 37. Development History of the Copper Oxide Process for Post-Combustion SO2
and NOx Capture ......................................................................................................................... 78
Figure 38. Development History of the Electron Beam Process for Post-Combustion SO2
and NOx Capture ......................................................................................................................... 79
Figure 39. Development History of the NOXSO Process for Post-Combustion SO2 and
NOx Capture ............................................................................................................................... 80
Figure 40. Development History of the Furnace Limestone Injection Process
for SO2 Capture........................................................................................................................... 81
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Figure 41. Development History of the Duct Sorbent Injection Process for SO2 Capture ............ 82
Figure 42. Historical Deployment Trends for Post-Combustion SO2 and NOx Capture
Systems (FGD and SCR Technologies) ...................................................................................... 84
Figure 43. Improvements in SO2 Removal Efficiency of Commercial Lime and
Limestone FGD Systems Coming Online in a Given Year, as a Function of Cumulative
Installed FGD Capacity in the United States .............................................................................. 85
Figure 44. Capital Cost Trends for Post-Combustion Capture of SO2 and NOx
at a New Coal-Fired Power Plant ............................................................................................... 86
Figure 45. Trend in U.S. Patenting Activity for SO2 Removal Technologies ................................ 87
Figure 46. Trend in U.S. Patenting Activity for Post-Combustion
NOx Removal Technologies ........................................................................................................ 88
Tables
Table 1. Post-Combustion Capture Approaches Being Developed
at Laboratory or Bench Scale ....................................................................................................... 4
Table 2. Representative Values of Current Power Plant Efficiencies
and CCS Energy Penalties .......................................................................................................... 16
Table 3. Breakdown of the Energy Penalty for CO2 Capture at Supercritical PC and IGCC
Power Plants ............................................................................................................................... 17
Table 4. Range of CO2 Capture Costs for Several Types of Industrial Processes .......................... 20
Table 5. Commercial Post-Combustion Capture Processes at Power Plants and Selected
Industrial Facilities ..................................................................................................................... 27
Table 6. Planned Demonstration Projects at Power Plants with
Full-Scale Post-Combustion Capture ......................................................................................... 30
Table 7. Pilot Plant Processes and Projects for Post-Combustion CO2 Capture ............................ 31
Table 8. Post-Combustion Capture Approaches Being Developed at the Laboratory or
Bench Scale ................................................................................................................................ 35
Table 9. Technical Advantages and Challenges for Post-Combustion Solvents ............................ 36
Table 10. Technical Advantages and Challenges for Solid Sorbent Approaches to Post-
Combustion CO2 Capture ........................................................................................................... 39
Table 11. Technical Advantages and Challenges for Membrane-Based Approaches
to Post-Combustion CO2 Capture ............................................................................................... 41
Table 12. Planned Demonstration Projects with Full-Scale Pre-Combustion Capture .................. 48
Table 13. Pilot Plant Projects for Pre-Combustion CO2 Capture at IGCC Power Plants .............. 50
Table 14. Key Advantages and Challenges of Physical Solvents for Pre-Combustion CO2
Capture........................................................................................................................................ 51
Table 15. Key Advantages and Challenges of Solid Sorbents for
Pre-Combustion CO2 Capture ..................................................................................................... 52
Table 16. Key Advantages and Challenges of Membrane Separation Systems for
Pre-Combustion CO2 Capture ..................................................................................................... 53
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Table 17. Planned Large-Scale Demonstrations of Oxy-Combustion CO2 Capture ...................... 58
Table 18. Pilot Plant Projects with Oxy-Combustion CO2 Capture ............................................... 59
Contacts
Author Contact Information........................................................................................................... 91
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Introduction
Congressional interest in carbon capture and sequestration (or carbon capture and storage, CCS)
has been renewed since the U.S. Environmental Protection Agency (EPA) re-proposed standards
for carbon dioxide (CO2) from new fossil-fueled power plants on September 20, 2013. As re-
proposed, the standards would limit emissions of CO2 to no more than 1,100 pounds per
megawatt-hour of production from new coal-fired power plants and between 1,000 and 1,100
(depending on size of the plant) for new natural gas-fired plants. The standards would not apply
to existing facilities. EPA proposed the standard under Section 111 of the Clean Air Act.1
According to EPA, new natural gas-fired stationary power plants should be able to meet the
proposed standards without additional cost and the need for add-on control technology. However,
new coal-fired plants only would be able to meet the standards by installing carbon capture and
sequestration (CCS) technology. The proposed standard allows a seven-year compliance period
for coal-fired plants but would require a more stringent standard for those plants that limit CO2
emissions to an average of 1,000-1,050 pounds per megawatt-hour over the seven-year period.
The promise of CCS lies in the potential for technology to capture CO2 emitted from large,
industrial sources, thus significantly decreasing CO2 emissions without drastically changing U.S.
dependence on fossil fuels, particularly coal, for electricity generation. The future use of coal—a
significant component of the U.S. energy portfolio—in the United States will likely depend on
whether and how CCS is deployed if legislative or regulatory actions curtail future CO2
emissions. The September 20 proposed rule for limiting CO2 emissions from new fossil-fueled
power plants is one such action. In addition, Section 111 of the Clean Air Act requires that EPA
develop guidelines for greenhouse gas emissions for existing plants whenever it promulgates
standards for new power plants. In a June 25, 2013, memorandum, President Obama directed the
EPA to issue proposed guidelines for existing plants by June 1, 2014, and to issue final guidelines
a year later.2 These proposed actions will likely draw additional congressional scrutiny of the
viability of large-scale CCS as the primary technology for mitigating CO2 emissions from coal-
fired power plants.
Unlike the other two components of CCS, transportation and geologic storage, the first
component of CCS—CO2 capture—is almost entirely technology-dependent. For CCS to succeed
at reducing CO2 emissions from a significant fraction of large sources in the United States, CO2
capture technology would need to deployed widely. Widespread commercial deployment will
likely depend on the cost of capturing CO2. This report examines the factors underlying the cost
of currently available CO2 capture technologies and advanced capture systems. This report also
examines efforts to commercialize other advanced technologies, namely sulfur dioxide (SO2) and
nitrogen oxide (NOx) capture technologies to reduce air pollution, to glean insights that could be
useful for assessing the prospects for improved, lower-cost CO2 capture systems.
1 Since 2009, EPA has begun to address emissions of greenhouse gases from both mobile and stationary sources, using
broad regulatory authority provided by Congress decades ago in the Clean Air Act. Although Congress has never
specifically directed EPA to regulate emissions of greenhouse gases, the Clean Air Act as enacted in 1970 and as
amended in 1977 and 1990 gave the agency authority to identify air pollutants and promulgate regulations to limit their
emission. For more information see CRS Report R43127, EPA Standards for Greenhouse Gas Emissions from Power
Plants: Many Questions, Some Answers, by James E. McCarthy.
2 Office of the Press Secretary, The White House, “Power Sector Carbon Pollution Standards,” Memorandum for the
Administrator of the Environmental Protection Agency, June 25, 2013, http://www.whitehouse.gov/the-press-office/
2013/06/25/presidential-memorandum-power-sector-carbon-pollution-standards.
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The transportation and storage components of CCS are not nearly as technology-dependent as the
capture component. Nonetheless, transportation and sequestration costs, while generally much
smaller than capture costs, could be very high in some cases. They would depend, in part, on how
long it would take to reach an agreement on a regulatory framework to guide long-term CO2
injection and storage, and on what those regulations would require. CCS deployment would also
depend on the degree of public acceptance of a large-scale CCS enterprise. CRS has several
reports (see below) addressing these policy issues of CO2 transportation and storage. This report
provides a “snapshot” of current technological development, but is both prospective and
retrospective in that it also examines emerging or advanced technologies that may affect future
CCS deployment, and looks at lessons from past experience with large-scale technological
development and deployment as guidelines that could be used to shape energy policy.
Structure of the Report
The bulk of the report consists of 10 chapters, together with figures and tables. Each chapter can
be read independently; however, “Chapter 1: Executive Summary,” “Chapter 2: Background and
Scope of Report,” and “Chapter 3: Overview of CO2 Capture Technologies” provide the reader
with background and context for a more complete understanding of some of the more
technologically focused discussions in other chapters.
Other CRS Reports on CCS
CRS has written a suite of products on different aspects of CCS that complement this assessment
of carbon capture technologies. These include
CRS Report R42532, Carbon Capture and Sequestration (CCS): A Primer, by Peter Folger; CRS
Report R42496, Carbon Capture and Sequestration: Research, Development, and Demonstration
at the U.S. Department of Energy, by Peter Folger; CRS Report R43028, FutureGen: A Brief
History and Issues for Congress, by Peter Folger; CRS Report R42950, Prospects for Coal in
Electric Power and Industry, by Richard J. Campbell, Peter Folger, and Phillip Brown; CRS
Report RL33971, Carbon Dioxide (CO2) Pipelines for Carbon Sequestration: Emerging Policy
Issues, by Paul W. Parfomak, Peter Folger, and Adam Vann; CRS Report R40103, Carbon
Control in the U.S. Electricity Sector: Key Implementation Uncertainties, by Paul W. Parfomak;
CRS Report RL34316, Pipelines for Carbon Dioxide (CO2) Control: Network Needs and Cost
Uncertainties, by Paul W. Parfomak and Peter Folger; CRS Report RL34307, Legal Issues
Associated with the Development of Carbon Dioxide Sequestration Technology, by Adam Vann
and Paul W. Parfomak; CRS Report RL34601, Community Acceptance of Carbon Capture and
Sequestration Infrastructure: Siting Challenges, by Paul W. Parfomak; CRS Report R43127, EPA
Standards for Greenhouse Gas Emissions from Power Plants: Many Questions, Some Answers,
by James E. McCarthy.
Technology Assessment Authorship
This technology assessment and report was undertaken by Carnegie Mellon University,
Department of Engineering and Public Policy, under the leadership of Edward S. Rubin, together
with Aaron Marks, Hari Mantripragada, Peter Versteeg, and John Kitchin. The work was
performed under contract to CRS, and is part of a multiyear CRS project to examine different
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Carbon Capture: A Technology Assessment
aspects of U.S. energy policy. Peter Folger, CRS Specialist in Energy and Natural Resources
Policy, served as the CRS project coordinator.
Acknowledgment
This report was funded, in part, by a grant from the Joyce Foundation.
Chapter 1: Executive Summary
Background
Carbon capture and storage (CCS) is widely seen as a critical technology for limiting atmospheric
emissions of carbon dioxide (CO2)—the principal “greenhouse gas” linked to global climate
change—from power plants and other large industrial sources. This report focuses on the first
component of a CCS system, namely, the CO2 capture process. The goal of the report is to
provide a realistic assessment of prospects for improved, lower-cost technologies for each of the
three current approaches to CO2 capture, namely, post-combustion capture from power plant flue
gases using amine-based solvents such as monoethanolamine (MEA) and ammonia; pre-
combustion capture (also via chemical solvents) from the synthesis gas produced in an integrated
coal gasification combined cycle (IGCC) power plant; and oxy-combustion capture, in which
high-purity oxygen rather than air is used for combustion in a pulverized coal (PC) power plant to
produce a flue gas with a high concentration of CO2 amenable to capture without a post-
combustion chemical process.
Currently, post-combustion and pre-combustion capture technologies are commercial and widely
used for gas stream purification in a variety of industrial processes. Several small-scale
installations also capture CO2 from power plant flue gases to produce CO2 for sale as an industrial
commodity. Oxy-combustion capture, however, is still under development and is not currently
commercial.
The advantages and limitations of each of these three methods are discussed in this report, along
with plans for their continued development. While all three approaches are capable of high CO2
capture efficiencies (typically about 90%), the major drawbacks of current processes are their
high cost and the large energy requirement for operation (which significantly reduces the net
plant capacity and contributes to the high cost of capture). Another drawback in terms of their
availability for greenhouse gas mitigation is that at present, there are still no applications of CO2
capture on a coal-fired or gas-fired power plant at full scale (i.e., a scale of several hundred
megawatts of plant capacity).
Current Research and Development (R&D) Activities
To address the current lack of demonstrated capabilities for full-scale CO2 capture at power
plants, a number of large-scale demonstration projects at both coal combustion and gasification-
based power plants are planned or underway in the United States and elsewhere. The current
status of these projects and the technologies they plan to employ are summarized in the body of
this report. Most of these demonstrations are expected to begin operation in 2014 or 2015.
Planned projects for other types of industrial facilities also are discussed.
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Also elaborated in this report are the substantial R&D activities underway in the United States
and elsewhere to develop and commercialize lower-cost capture systems with smaller energy
penalties. To characterize the status of capture technologies and the prospects for their
commercial availability, five stages of development are defined in this report: conceptual designs;
laboratory or bench scale; pilot plant scale; full-scale demonstration plants; and commercial
processes. Current activities at each of these stages are reviewed for each of the three major
capture routes.
Current R&D activities include development and testing of new or improved solvents that can
lower the cost of current post-combustion and pre-combustion capture, as well as research on a
variety of potential “breakthrough technologies” such as novel solvents, sorbents, membranes,
and oxyfuel systems that hold promise for even lower-cost capture systems. Most of the latter
processes, however, are still in the early stages of research and development (i.e., conceptual
designs and laboratory- or bench-scale processes), so that credible estimates of their performance
and (especially) cost are lacking at this time. Table 1 lists the major approaches being pursued for
post-combustion capture, although many of these approaches apply to pre-combustion and oxy-
combustion capture as well.
Table 1. Post-Combustion Capture Approaches Being Developed
at Laboratory or Bench Scale
Liquid Solvents
Solid Adsorbents
Membranes
Advanced amines
Supported amines
Polymeric
Potassium carbonate
Carbon-based
Amine-doped
Advanced mixtures
Sodium carbonate
Integrated with absorption
Ionic liquids
Crystalline materials
Biomimetic-based
Source: Edward S. Rubin, Aaron Marks, Hari Mantripragada, Peter Versteeg, and John Kitchin, Carnegie Mel on
University, Department of Engineering and Public Policy.
Processes under development at the more advanced pilot plant scale are, for the most part, new or
improved solvent formulations (such as ammonia and advanced amines) that are undergoing
testing and evaluation. These advanced solvents could be available for commercial use within
several years if subsequent full-scale testing confirms their overall benefit. Pilot-scale oxy-
combustion processes also are currently being tested and evaluated for planned scale-up, while
two IGCC power plants in Europe are installing pilot plants to evaluate pre-combustion capture
options.
In general, the focus of most current R&D activities is on cost reduction rather than additional
gains in the efficiency of CO2 capture (which can result in cost increases rather than decreases). A
number of R&D programs emphasize the need for lower-cost retrofit technologies suitable for
existing power plants. As a practical matter, however, most technologies being pursued to reduce
capture costs for new plants also apply to existing plants. Indeed, as the fleet of existing coal-fired
power plants continues to age, the size of the potential U.S. retrofit market for CO2 capture will
continue to shrink, as older plants may not be economic to retrofit (although the situation in other
countries, especially China, may be quite different).
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Carbon Capture: A Technology Assessment
Future Outlook
Whether for new power plants or existing ones, the key questions are the same: When will
advanced CO2 capture systems be available for commercial rollout, and how much cheaper will
they be compared to current technology?
To address the first question, this report reviews a variety of “technology roadmaps” developed
by governmental and private-sector organizations in the United States and elsewhere. All of these
roadmaps anticipate that CO2 capture will be available for commercial deployment at power
plants by 2020. Current commercial technologies like post-combustion amine systems could be
available sooner. A number of roadmaps also project that novel, lower-cost technologies like solid
sorbent systems for post-combustion capture will be commercial in the 2020 time frame. Such
projections acknowledge, however, that this will require aggressive and sustained efforts to
advance promising concepts to commercial reality.
That caveat is strongly supported by a review of experience from other recent R&D programs to
develop lower-cost technologies for post-combustion SO2 and NOx capture at coal-fired power
plants. Those efforts typically took two decades or more to bring new concepts (like combined
SO2 and NOx capture processes) to commercial availability. By then, however, the cost
advantages initially foreseen for these novel systems had largely evaporated in most cases: the
advanced technologies tended to get more expensive as their development progressed (consistent
with “textbook” descriptions of the innovation process), while the cost of formerly “high-cost”
commercial technologies gradually declined over time. The absence of a significant market for
the novel technologies put them at a further disadvantage. This is similar to the situation for CO2
capture systems today. Thus, the development of advanced CO2 capture technologies is not
without risks.
With regard to future cost reductions, the good news based on past experience is that the costs of
environmental technologies that succeed in the marketplace tend to fall over time. For example,
after an initial rise during the early commercialization period, the cost of post-combustion SO2
and NOx capture systems declined by 50% or more after about two decades of deployment at
coal-fired power plants. This trend is consistent with the “learning curve” behavior seen for many
other classes of technology. It thus appears reasonable to expect a similar trend for future CO2
capture costs once these technologies become widely deployed. Note, too, that the cost of CO2
capture also depends on other aspects of power plant design, financing, and operation—not solely
on the cost of the CO2 capture unit. Future improvements in net power plant efficiency, for
example, will tend to lower the unit cost of CO2 capture.
Other cost estimates for advanced CO2 capture systems are based on engineering-economic
analysis of proposed system designs. For example, recent studies by the U.S. Department of
Energy (DOE) foresee the cost of advanced PC and IGCC power plants with CO2 capture falling
by 27% and 31%, respectively, relative to current costs as a result of successful R&D programs.
No estimates are provided, however, as to when the various improvements described are expected
be commercially available. In general, however, the farther away a technology is from
commercial reality, the lower its estimated cost tends to be. Thus, there is considerable
uncertainty in cost estimates for technologies that are not yet commercial, especially those that
exist only as conceptual designs.
More reliable estimates of future technology costs typically are linked to projections of their
expected level of commercial deployment in a given time frame (i.e., a measure of their market
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Carbon Capture: A Technology Assessment
size). For power plant technologies like CO2 capture systems, this is commonly expressed as total
installed capacity. However, as with other technologies whose sole purpose is to reduce
environmental emissions, there is no significant market for power plant CO2 capture systems
absent government actions or policies that effectively create such markets—either through
regulations that limit CO2 emissions, or through voluntary incentives such as tax credits or direct
financial subsidies. The technical literature and historical evidence examined in this report
strongly link future cost reductions for CO2 capture systems to their level of commercial
deployment. In widely used models based on empirical “experience curves,” the latter measure
serves as a surrogate for the many factors that influence future technology costs, including the
level of R&D expenditures and the new knowledge gained through learning-by-doing (related to
manufacturing) and learning-by-using (related to technology use).
Based on such models, published estimates project the future cost of electricity from power plants
with CO2 capture to fall by as much as 30% below current values after roughly 100,000
megawatts (MW) of capture plant capacity is installed and operated worldwide. That estimate is
in line with the DOE projects noted above. If achieved, it would represent a significant decrease
from current costs—one that would bring the cost and efficiency of future power plants with CO2
capture close to that of current plants without capture. For reference, it took approximately 20
years following passage of the 1970 Clean Air Act Amendments to achieve a comparable level of
technology deployment for SO2 capture systems at coal-fired power plants.
Uncertainty estimates for these projections, however, indicate that future cost reductions for CO2
capture also could be much smaller than indicated above. Thus, whether future cost reductions
will meet, exceed, or fall short of current estimates will only be known with hindsight.
In the context of this report, the key insight governing prospects for improved carbon capture
technology is that achieving significant cost reductions will require not only a vigorous and
sustained level of R&D, but also a substantial level of commercial deployment. That will
necessitate a significant market for CO2 capture technologies, which can only be established by
government actions. At present such a market does not yet exist. While various types of incentive
programs can accelerate the development and deployment of CO2 capture technology, actions that
significantly limit emissions of CO2 to the atmosphere ultimately are needed to realize substantial
and sustained reductions in the future cost of CO2 capture.
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Carbon Capture: A Technology Assessment
Chapter 2: Background and Scope of Report
Introduction
Global climate change is an issue of major international concern and the focus of proposed
mitigation policy measures in the United States and elsewhere. In this context, the technology of
carbon capture and storage (CCS) has received increasing attention over the past decade as a
potential method of limiting atmospheric emissions of carbon dioxide (CO2)—the principal
“greenhouse gas” linked to climate change.
Worldwide interest in CCS stems principally from three factors. First is a growing consensus that
large reductions in global CO2 emissions are needed to avoid serious climate change impacts.3
Because electric power plants are a major source of GHG emissions, their emissions must be
significantly curtailed.
Second is the realization that large emission reductions cannot be achieved easily or quickly
simply by using less energy or by replacing fossil fuels with alternative energy sources that emit
little or no CO2. The reality is that the world (and the United States itself) today relies on fossil
fuels for over 85% of its energy use. Changing that picture dramatically will take time. CCS thus
offers a way to get large CO2 reductions from power plants and other industrial sources until
cleaner, sustainable technologies can be widely deployed.
Finally, energy-economic models show that adding CCS to the suite of other GHG reduction
measures significantly lowers the cost of mitigating climate change. Studies also have affirmed
that by 2030 and beyond, CCS is a major component of a cost-effective portfolio of emission
reduction strategies.4
Figure 1 depicts the overall CCS process applied to a power plant or other industrial process. The
CO2 produced from carbon in the fossil fuels or biomass feedstock is first captured, then
compressed to a dense liquid to facilitate its transport and storage. The main storage option is
underground injection into a suitable geological formation.
At the present time, CCS is not yet commercially proven in the primary large-scale application
for which it is envisioned—electric power plants fueled by coal or natural gas. Furthermore, the
cost of CCS today is relatively high, due mainly to the high cost of CO2 capture (which includes
the cost of CO2 compression needed for transport and storage). This has prompted a variety of
governmental and private-sector research programs in the United States and elsewhere to develop
more cost-effective methods of CO2 capture.
3 National Research Council, America’s Climate Choices: Limiting the Magnitude of Future Climate Change, The
National Academies Press, Washington, DC, May 2010; S. Solomon et al., eds., Climate Change 2007: The Physical
Science Basis, Contribution of Working Group I to the Fourth Assessment Report of the Intergovernmental Panel on
Climate Change. Cambridge University Press, Cambridge, UK and New York, NY, 2007.
4 J. Edmonds, “The Potential Role of CCS in Climate Stabilization,” Proc. 9th International Conference on Greenhouse
Gas Control Technologies, 2008, Washington, DC; B. Metz, et al., eds., Climate Change 2007: Mitigation.
Contribution of Working Group III to the Fourth Assessment Report of the Intergovernmental Panel on Climate
Change Cambridge University Press, Cambridge, United Kingdom and New York, NY, USA.
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Carbon Capture: A Technology Assessment
Figure 1. Schematic of a CCS System, Consisting of CO2 Capture,
Transport, and Storage
Fos
Fo si
s l Fu
l
el
e s
l ;
Air or
o
Biom
o ass
m
Oxyg
y en
Powe
w r
e Plan
a t
ant
CO
t
ant
CO
2
CO
CO
CO Sto
St rag
a e
g
e
2
CO
CO Storag
or In
or In
or I du
or In st
s ri
r a
i l
2
Capture &
2
2
al
a
re &
r
Transp
s ort
(Se
(S q
e ues
ue t
s ra
r t
a i
t on
o )
Pro
Pr ce
c s
e s
Comp
m ress
s
re
- Po
P st-
t c
- ombustiton
o
- Pipe
P
lin
ipe e
lin
- Depl
D
et
epl ed o
ed i
o l/gas
ga fiel
fie ds
USEF
U
UL
SEF
- Pre
r -c
- ombu
b st
s ion
- Tanker
- Deep
D
sa
eep
line
sa
for
line
m
for at
a ions
n
PRODUCTS
- Oxyfuel c
x
o
yfuel c mb
m us
u tion
- Un
U mi
m neab
e le
ab coal
co se
s ams
m
(e
( .g., e
.g
l
., e ectricit
r
y,
y fuels
fu
,
- Deep
D
Oc
eep
ea
Oc
n
,
chem
ch
icals
ic
,
als hydroge
y
n
droge )
- Miner
e aliza
z tion
)
- Reus
R
e
eus
Source: E. S. Rubin, “Will Carbon Capture and Storage be Available in Time?,” American Academy for the
Advancement of Science, Annual Meeting, San Diego, CA, February 18-22, 2010.
Notes: Carbon inputs may include fossil fuels and biomass. Technical options are listed below each stage. Those
in italics are not yet available or implemented at a commercial scale.
Report Objectives and Scope
The present report seeks to assist the Congressional Research Service (CRS) in providing analysis
and information to the U.S. Congress related to national policy on climate change. More
specifically, the objective is to provide a realistic assessment of prospects for improved, lower-
cost CO2 capture systems for use at power plants and in other industrial processes. Issues and
technologies associated with CO2 transport and storage are thus outside the scope of this report.
The tasks in the statement of work for this study were to:
• Discuss the advantages, as well as the possible limitations, on continued
development and commercial deployment of each of the three current approaches
to CO2 capture, namely (1) post-combustion chemical treatment and capture of
flue gas CO2 with amines, such as monoethanolamine (MEA) and ammonia; (2)
pre-combustion chemical removal of CO2 from the synthesis gas produced from
coal in an integrated gasification combined cycle (IGCC) plant; and (3) oxyfuel
combustion, in which pure oxygen replaces the air normally used in coal
combustion to produce a flue gas containing mainly water vapor and
concentrated CO2, which is amenable to capture without a post-combustion
chemical process.
• Investigate research in the United States and elsewhere to assess (1) the evolution
of current technologies, especially whether significant gains in the efficiency of
CO2 capture, and thus cost reductions, can be reasonably expected for the
technologies discussed above, along with reasonable estimates of the commercial
rollout schedules for retrofit and new plant use; and (2) the potential of emerging
and “breakthrough technologies” such as advanced catalysts for CO2 conversion,
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Carbon Capture: A Technology Assessment
novel solvents, sorbents, membranes, and thin films for gas separation. This part
of the study describes where such technologies currently are in the R&D process
(e.g., concept, laboratory, pilot scale and so on), in order to provide Congress
with an understanding of whether the research focus is on engineering and
technology development of new processes whose physics and chemistry are well
understood, as distinguished from projects whose research focus is on first
principles and conceptual design, with the engineering of an actual device still
many years in the future.
Organization of This Report
Consistent with the above objectives, this report’s “Chapter 3: Overview of CO2 Capture
Technologies” first gives an overview of CO2 capture technologies and their application to new
and existing facilities. The current costs of CO2 capture also are presented. “Chapter 4: Stages of
Technology Development” then discusses the process of technological change and defines the
five stages of technological development used in this report to describe the status of CO2 capture
technologies. “Chapter 5: Status of Post-Combustion Capture,” “Chapter 6: Status of Pre-
Combustion Capture,” and “Chapter 7: Status of Oxy-Combustion Capture” elaborate on each of
the three major categories of CO2 capture systems, namely, post-combustion, pre-combustion, and
oxy-combustion capture, respectively. For each category, the current status of technology in each
stage of development is described along with the technical challenges that must be overcome to
move forward. “Chapter 8: Cost and Deployment Outlook for Advanced Capture Systems” then
discusses the prospects for improved, lower-cost capture technologies and the timetables for
commercialization projected by governmental and private-sector organizations involved in
capture technology R&D. For perspective, “Chapter 9: Lessons from Past Experience” looks
retrospectively at recent experience on the pace of technology innovation and deployment to
control other power plant pollutants. It also discusses some of the key drivers of technology
innovation that influence future prospects for carbon capture systems. Finally, “Chapter 10:
Discussion and Conclusions” discusses the key findings and conclusions from this study.
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Carbon Capture: A Technology Assessment
Chapter 3: Overview of CO2 Capture Technologies
Introduction
A variety of technologies for separating (capturing) CO2 from a mixture of gases are
commercially available and widely used today, typically as a purification step in an industrial
process. Figure 2 illustrates the variety of technical approaches available. The choice of
technology depends on the requirements for product purity and on the conditions of the gas
stream being treated (such as its temperature, pressure, and CO2 concentration). Common
applications for CO2 capture systems include the removal of CO2 impurities in natural gas
treatment and the production of hydrogen, ammonia, and other industrial chemicals. In most
cases, the captured CO2 stream is simply vented to the atmosphere. In a few cases it is used in the
manufacture of other chemicals.5
Figure 2. Technical Options for CO2 Capture
CO2 Separation and Capture
Absorption
Adsorption
Cryogenics
Membranes
Microbial/Algal
Systems
Chemical
Adsorber
Gas
Beds
Separation
MEA
Alumina
Polyphenyleneoxide
Caustic
Zeolite
Polydimethylsiloxane
Other
Activated C
Gas
Physical
Regeneration
Absorption
Method
Polypropelene
Selexol
Pressure Swing
Ceramic Based
Rectisol
Temperature Swing
Systems
Other
Washing
Source: A. B. Rao and E. S. Rubin, “A Technical, Economic and Environmental Assessment of Amine-Based CO2
Capture Technology for Power Plant Greenhouse Gas Control,” Environmental Science & Technology, vol. 36, no.
20 (2002), pp. 4467-4475.
Notes: The choice of method depends strongly on the particular application.
CO2 also has been captured from a portion of the flue gases produced at power plants burning
coal or natural gas. Here, the captured CO2 is sold as a commodity to nearby industries such as
food processing plants. Globally, however, only a small amount of CO2 is utilized to manufacture
industrial products and nearly all of it is soon emitted to the atmosphere (for example, from
carbonated drinks).
5 B. Metz et al., eds., Special Report on Carbon Dioxide Capture and Storage, Prepared by Working Group III of the
Intergovernmental Panel on Climate Change. Cambridge University Press, Cambridge, UK and New York, NY, p 442,
2005.
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Since most anthropogenic CO2 is a by-product of the combustion of fossil fuels, CO2 capture
technologies, when discussed in the context of CCS, are commonly classified as either pre-
combustion or post-combustion systems, depending on whether carbon (in the form of CO2) is
removed before or after a fuel is burned. A third approach, called oxyfuel or oxy-combustion,
does not require a CO2 capture device. This concept is still under development and is not yet
commercial. Other industrial processes that do not involve combustion employ the same types of
CO2 capture systems that would be employed at power plants.
In all cases, the aim is to produce a stream of pure CO2 that can be permanently stored or
sequestered, typically in a geological formation. This requires high pressures to inject CO2 deep
underground. Thus, captured CO2 is first compressed to a dense “supercritical” state, where it
behaves as a liquid that can be readily transported via pipeline and injected into a suitable
geological formation. However, the CO2 compression step is commonly included as part of the
capture system, since it is usually located at the industrial plant site where CO2 is captured.
Post-Combustion Processes
As the name implies, these systems capture CO2 from the flue gases produced after fossil fuels or
other carbonaceous materials (such as biomass) are burned. Combustion-based power plants
provide most of the world’s electricity today. In a modern coal-fired power plant, pulverized coal
(PC) is mixed with air and burned in a furnace or boiler. The heat released by combustion
generates steam, which drives a turbine-generator (Figure 3). The hot combustion gases exiting
the boiler consist mainly of nitrogen (from air) plus smaller concentrations of water vapor and
CO2 formed from the hydrogen and carbon in the fuel. Additional products formed during
combustion from impurities in coal include sulfur dioxide, nitrogen oxides, and particulate matter
(fly ash). These regulated air pollutants, as well as other trace species such as mercury, must be
removed to meet applicable emission standards. In some cases, additional removal of pollutants
(especially SO2) is required to provide a sufficiently clean gas stream for subsequent CO2 capture.
Figure 3. Schematic of a Coal-Fired Power Plant with Post-Combustion
CO2 Capture Using an Amine Scrubber System
Stea
e m
Fl
F ue ga
ue
s
m
ga
Elec
e trirci
c ty
t
to a
to t
a m
t os
o p
s he
h r
e e
Turb
Tur ine
e
Genera
r to
a r
r
Stea
e m
a
Coal
a
Air Pollution
k
Co
C ntro
r l Syst
y ems
m
CO Ca
C pture
PC Boiler
Mostly
s
re
PC Boiler
Most
Air
2
r
N
(NO , PM,
, PM S
, O )
2
Stac
)
x
2
Amine
n
Amine
n /
e CO
C 2
CO2 to
CO2
storag
r e
Amine/CO
Amine/C 2
CO2
Sepa
p ra
r t
a ion
Compression
o
Source: E. S. Rubin, “CO2 Capture and Transport,” Elements, vol. 4 (2008), pp. 311-317.
Notes: Other major air pollutants (nitrogen oxides, particulate matter, and sulfur dioxide) are removed from
the flue gas prior to CO2 capture.
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Carbon Capture: A Technology Assessment
With current technology, the most effective method of CO2 capture from the flue gas of a PC
plant is by chemical reaction with an organic solvent such as monoethanolamine (MEA), one of a
family of amine compounds. In a vessel called an absorber, the flue gas is “scrubbed” with an
amine solution, typically capturing 85% to 90% of the CO2. The CO2-laden solvent is then
pumped to a second vessel, called a regenerator, where heat is applied (in the form of steam) to
release the CO2. The resulting stream of concentrated CO2 is then compressed and piped to a
storage site, while the depleted solvent is recycled back to the absorber. Figure 4 shows details of
a post-combustion capture system design.
Figure 4. Details of Flue Gas and Sorbent Flows for an Amine-Based
Post-Combustion CO2 Capture System
(absorber is shown on the left, and regenerator on the right)
Source: Metz, Special Report.
The same post-combustion capture technology that would be used at a PC plant also would be
used for post-combustion CO2 capture at a natural gas-fired boiler or combined cycle (NGCC)
power plant (see Figure 5). Although the flue gas CO2 concentration is more dilute than in coal
plants, high removal efficiencies can still be achieved with amine-based capture systems. The
absence of impurities in natural gas also results in a clean flue gas stream, so that no additional
cleanup is needed for effective CO2 capture. Further details on the design, performance, and
operation of amine-based capture technologies can be found in the technical literature.6
6 A. B. Rao and E. S. Rubin, “A Technical, Economic and Environmental Assessment of Amine-Based CO2 Capture
Technology for Power Plant Greenhouse Gas Control,” Environmental Science & Technology, vol. 36 (2002), pp.
4467-4475; Metz, Special Report. U.S. Department of Energy (DOE), Cost and Performance Baseline for Fossil
Energy Plants. Volume 1: Bituminous Coal and Natural Gas to Electricity Final Report, National Energy Technology
Laboratory, Pittsburgh, PA, August 2007.
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Carbon Capture: A Technology Assessment
Figure 5. Schematic of an Amine-Based Post-Combustion CO2 Capture System
Applied to a Natural Gas Combined Cycle (NGCC) Power Plant
El
E ec
e t
c ric
r it
ic y
it
Stea
e m
Fl
F ue ga
ue
s
ga
s
Turbin
Turbi e-
to a
to t
a mo
t
s
mo p
s h
p e
h r
e e
-
Gene
Ge
ra
r tor
a
St
S eam
Heat
Natural
Gas
CO Capture
r
2
Mostly
Reco
c ve
v ry
r
Comb
m u
b stor
o
ack
Gas
Combustor
Gas
Ga
Turbin
Turbi e
System
N2
Stea
e m Ge
m
n
N
Gen
Ge
St
Amine
n
Amine/
n CO
C 2
Air
CO2 to
Air
CO2
stor
o a
r g
a e
Com
Co p
m ress
p
or
ress
Amine/CO
g
Amine/CO
Amine/C
Amine/
2
CO2
Sepa
Sep ra
r t
a ion
Comp
m re
r ssio
s n
io
Source: Rubin, “CO2 Capture.”
Pre-Combustion Processes
To remove carbon from fuel prior to combustion, it must first be converted to a form amenable to
capture. For coal-fueled plants, this is accomplished by reacting coal with steam and oxygen at
high temperature and pressure, a process called partial oxidation, or gasification. The result is a
gaseous fuel consisting mainly of carbon monoxide and hydrogen—a mixture known as synthesis
gas, or syngas—which can be burned to generate electricity in a combined cycle power plant
similar to the NGCC plant described above. This approach is known as integrated gasification
combined cycle (IGCC) power generation. After particulate impurities are removed from the
syngas, a two-stage “shift reactor” converts the carbon monoxide to CO2 via a reaction with
steam (H2O). The result is a mixture of CO2 and hydrogen. A chemical solvent, such as the widely
used commercial product Selexol (which employs a glycol-based solvent), then captures the CO2,
leaving a stream of nearly pure hydrogen that is burned in a combined cycle power plant to
generate electricity, as depicted in Figure 6.
Figure 6. Schematic of an Integrated Gasification Combined Cycle (IGCC) Coal
Power Plant with Pre-Combustion CO2 Capture Using a Water-Gas Shift Reactor
and a Selexol CO2 Separation System
Fl
F ue ga
ue
s
ga
Elec
e t
c ri
r ci
c ty
to a
to t
a m
t osp
s h
p er
e e
Air
Ai
ty
r
Air Sepa
p ra
r ti
a o
ti n
Unit
H
Air
2
H O
O2
Coal
H
Gas T
s u
T rb
r ine
ck
Shifit
2
H2
Quench
t
Sulf
Sul ur
CO Ca
C pture
ur
Quench
a
2
Combined
Gasifier
r
e
St
H
Syst
s em
Removal
2O
Reactor
Remova CO
2O
Reactor
2
Cy
C cle Pl
l
an
e Pl
t
an
Sel
Se ex
e o
x l
o
Se
S le
e x
le o
x l/
o CO
C 2
CO2 to
Sulflur
Selexol/CO
CO2
CO
st
s orage
2
CO
Re
R covery
2
covery
Sepa
p ra
r ti
a on
Compressi
s on
o
Source: Rubin, “CO2 Capture.”
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Carbon Capture: A Technology Assessment
Although the fuel conversion steps of an IGCC plant are more elaborate and costly than
traditional coal combustion plants, CO2 separation is much easier and cheaper because of the high
operating pressure and high CO2 concentration of this design. Thus, rather than requiring a
chemical reaction to capture CO2 (as with amine systems in post-combustion capture), the
mechanism employed in pre-combustion capture involves physical adsorption onto the surface of
a solvent, followed by release of the CO2 when the sorbent pressure is dropped, typically in
several stages, as depicted in Figure 7.
Figure 7. Details of the Fuel Gas and Sorbent Flows for
Pre-Combustion CO2 Capture
H Fuel Gas
Ga
2
CO
(t
( o Powe
w r Block)
2 to Storage
)
2 to Storag
)
2 to Stora
Absor
o ber
COM
CO P3
er
P
er
Shi
Sh ft
f ed
e
COM
CO P2
P
Syn
Sy g
n as
COM
CO P1
P
CO
CO
2
2
CO
2
2
Rich
h
Recycle
Solvent
FL
F AS
L
H1
vent
v
Gas
FL
F AS
L
H2
FL
F A
L S
A H
S 3
Gas
H
Gas
Lean
TURB1
T
SUM
SU P
TURB2
T
Solvent
v
Cooler
Pum
Pu p
Source: Adapted from C. Chen, “A Technical and Economic Assessment of CO2 Capture Technology for IGCC
Power Plants”(Ph.D. thesis, Carnegie Mel on University, Pittsburgh, PA, 2005).
Pre-combustion capture also can be applied to power plants using natural gas. As with coal, the
raw gaseous fuel is first converted to syngas via reactions with oxygen and steam—a process
called reforming. This is again followed by a shift reactor and CO2 separation, yielding streams of
concentrated CO2 (suitable for storage) and hydrogen. This is the dominant method used today to
manufacture hydrogen. If the hydrogen is burned to generate electricity, as in an IGCC plant, we
have pre-combustion capture. While pre-combustion CO2 capture is usually more costly than
post-combustion capture for natural gas-fired plants, some power plants of this type have been
proposed.7 Further details regarding the design, performance, and operation of pre-combustion
capture systems can be found in the literature.8
7 Scottish and Southern Energy, “SSE, BP and Partners Plan Clean Energy Plant in Scotland,” at http://www.scottish-
southern.co.uk/SSEInternet/index.aspx?id=894&TierSlicer1_TSMenuTargetID=444&
TierSlicer1_TSMenuTargetType=1&TierSlicer1_TSMenuID=6.
8 Metz, Special Report. C. Chen and E. S. Rubin, “CO2 Control Technology Effects on IGCC Plant Performance and
Cost,” Energy Policy, vol. 37, no. 3 (2009), pp. 915-924.
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Carbon Capture: A Technology Assessment
Oxy-Combustion Systems
Oxy-combustion (or oxyfuel) systems are being developed as an alternative to post-combustion
CO2 capture for conventional coal-fired power plants. Here, pure oxygen rather than air is used
for combustion. This eliminates the large amount of nitrogen in the flue-gas stream. After the
particulate matter (fly ash) is removed, the flue gas consists only of water vapor and CO2, plus
smaller amounts of pollutants such as sulfur dioxide (SO2) and nitrogen oxides (NOx). The water
vapor is easily removed by cooling and compressing the flue gas. Additional removal of air
pollutants leaves a nearly pure CO2 stream that can be sent directly to storage, as depicted in
Figure 8.
Figure 8. Schematic of a Coal-Fired Power Plant Using Oxy-Combustion
Flue gas
ue
to a
to t
a m
t os
o p
s h
p er
e e
Ste
St a
e m
m
El
E ec
e tr
c ic
tr it
ic y
it
Turbine
e
ack
Gener
Ge
a
ner t
a or
t
or
St
Stea
Ste m
a
CO2 to
Coal
Air
Ai Pol
r
l
Pol u
l tito
i n
Coal
o
CO
storage
2
Dist
Di illation
n
storag
PC Boi
PC
l
Boi er
r
Co
C nt
n ro
r l Syste
l Sy
ms
m
CO2
2
s H2
H O
2
System
2O
Syste
( PM,
M SO
S
)
Comp
m ression
)
ssio
2
O2
Flue gas
ue
gas r
ecy
e cl
c e
H2
H O
Air
Ai
r
Sepa
Sep ra
r t
a iton
i
Air
Unit
Source: Rubin, “CO2 Capture.”
The principal attraction of oxy-combustion is that it avoids the need for a costly post-combustion
CO2 capture system. Instead, however, it requires an air separation unit (ASU) to generate the
relatively pure (95%-99%) oxygen needed for combustion. Roughly three times more oxygen is
needed for oxyfuel systems than for an IGCC plant of comparable size, so the ASU adds
significantly to the cost. Typically, additional flue gas processing also is needed to reduce the
concentration of conventional air pollutants, so as to comply with applicable environmental
standards, or to prevent the undesirable buildup of a substance in the flue gas recycle loop, or to
achieve pipeline CO2 purity specifications (whichever requirement is the most stringent). Because
combustion temperatures with pure oxygen are much higher than with air, oxy-combustion also
requires a large portion (roughly 70%) of the inert flue gas stream to be recycled back to the
boiler in order to maintain normal operating temperatures. To avoid unacceptable levels of
oxygen and nitrogen in the flue gas, the system also has to be carefully sealed to prevent any
leakage of air into the flue gas. This is a challenge since such leakage commonly occurs at
existing power plants at flanges and joints along the flue gas ducts, especially as plants age.
As a CO2 capture method, oxy-combustion has been studied theoretically and in experimental
laboratory and pilot plant facilities, but not yet at a commercial scale. Thus, a variety of designs
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have been proposed for commercial systems.9 Although in principle oxyfuel systems can capture
all of the CO2 produced, the need for additional gas treatment systems decreases the capture
efficiency to about 90% in most current designs.
In principle, oxy-combustion also can be applied to simple cycle and combined cycle power
plants fueled by natural gas or distillate oil. These conceptual designs are discussed more fully in
“Chapter 7: Status of Oxy-Combustion Capture.” As a practical matter, however, they would
require significant and costly modifications to the design of current gas turbines and other plant
equipment, with relatively limited market potential for greenhouse gas abatement. Thus, the
current focus of oxy-combustion development is on coal-fired power plant applications.
Capture System Energy Penalty
The energy requirements of current CO2 capture systems are roughly 10 to 100 times greater than
those of other environmental control systems employed at a modern electric power plant. This
energy “penalty” lowers the overall (net) plant efficiency and significantly increases the net cost
of CO2 capture. Table 2 shows that of the three CO2 capture approaches discussed earlier, post-
combustion capture on PC plants is the most energy-intensive, requiring nearly twice the energy
per net unit of electricity output as pre-combustion capture on an IGCC plant.
Table 2. Representative Values of Current Power Plant Efficiencies
and CCS Energy Penalties
Energy penalty: Added
Power plant type, and
Net plant efficiency
Net plant efficiency
fuel input (%) per net
capture system type
(%) without CCS
(%) with CCS
kWh output
Existing subcritical PC, post-
33 23
40%
combustion capture
New supercritical PC, post-
40 31
30%
combustion capture
New supercritical PC, oxy-
40 32
25%
combustion capture
New IGCC (bituminous coal),
40 34
19%
pre-combustion capture
New natural gas combined
cycle, post-combustion
50 43
16%
capture
Sources: Metz, Special Report; Massachusetts Institute of Technology (MIT), The Future of Coal (Cambridge, MA:
MIT, 2007); Carnegie Mel on University, Integrated Environmental Control Model (IECM), December 2009.
a. All efficiency values are based on the higher heating value (HHV) of fuel.
Notes: For each plant type, there is a range of efficiencies around the representative values shown here.
Lower plant efficiency means that more fuel is needed to generate electricity relative to a similar
plant without CO2 capture. For coal combustion plants, this means that proportionally more solid
waste is produced and more chemicals, such as ammonia and limestone, are needed (per unit of
9 Metz, Special Report.
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Carbon Capture: A Technology Assessment
electrical output) to control NOx and SO2 emissions. Plant water use also increases significantly
because of the additional cooling water needed for current amine capture systems. Because of the
efficiency loss, a capture system that removes 90% of the CO2 from the plant flue gas winds up
reducing the net (avoided) emissions per kilowatt-hour (kWh) by a smaller amount, typically 85%
to 88%.
In general, the higher the power plant efficiency, the smaller is the energy penalty and its
associated impacts. For this reason, replacing or repowering an old, inefficient plant with a new,
more efficient unit with CO2 capture can still yield a net efficiency gain that decreases all plant
emissions and resource consumption. Thus, the net impact of the CO2 capture energy penalty
must be assessed in the context of a particular situation or strategy for reducing CO2 emissions.
Innovations that raise the efficiency of power generation also can reduce the impacts and cost of
carbon capture. Table 3 shows that the overall energy requirements for PC and IGCC plants is
divided between electricity needed to operate fans, pumps, and CO2 compressors, plus thermal
energy requirements (or losses) for solvent regeneration (PC plants) and the water-gas shift
reaction (IGCC plants). Thermal energy requirements are clearly the largest source of net power
losses and the priority area for research to reduce those losses. For oxy-combustion systems, the
electrical energy required for oxygen production is the biggest contributor to the energy penalty.
Table 3. Breakdown of the Energy Penalty for CO2 Capture at Supercritical PC and
IGCC Power Plants
Approximate % of Total
Energy Type and Function
Energy Penalty
Thermal energy for amine solvent regeneration (post-combustion) or loss in water-
gas shift reaction (pre-combustion); or, electricity for oxygen production (oxy-
~60%
combustion)
Electricity for CO2 compression
~30%
Electricity for pumps, fans, etc.
~10%
Sources: MIT, “Future of Coal”; Carnegie Mel on, “IECM.”
Current Cost of CO2 Capture
To gauge the potential benefits of advances in carbon capture technology, it is useful to first
benchmark the cost of current systems. This section reviews recent cost estimates for power
plants and other industrial processes.
Costs for New Power Plants
Figure 9 displays the cost of generating electricity from new power plants with and without CCS,
as reported in recent studies based on current commercial post-combustion and pre-combustion
capture processes. All plants capture and sequester 90% of the CO2 in deep geologic formations.
The total cost of electricity generation (COE), in dollars per megawatt-hour ($/MWh), is shown
as a function of the CO2 emission rate (tonnes CO2/MWh) for power plants burning bituminous
coal or natural gas. The COE includes the costs of CO2 transport and storage, but most of the cost
(80% to 90%) is for capture (including compression).
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Figure 9. Cost of Electricity Generation (2007 US$/MWh) as a Function
of the CO2 Emission Rate (tonnes CO2/MWh) for New Power Plants
Burning Bituminous Coal or Natural Gas
h)
SCP
SC C
P
120
W 12
W
New
New
New
M
New
Natu
t ral
a
M
Ad
A vanced Subcr
ubc i
r tical
tica
100
10
Pla
Pl n
a ts
t
Ga
G s-
a Fi
s- re
r d
e
Coal Plant
t
Coal Plant
CC
Plan
a t
t
07$ /
with
07$ /
NG
IGCC
80
CCS
80
y (20
it 60
IGCC
NGCC
tric
SCPC
SC
PC
ec 40
El
t of 20
Cos
0
0
0.1
0.2
0.3
0.4
0.5
0.6
0.7
0
0.8
0.9
1.0
CO2
CO Emission Rate (tonnes / MWh)
2 Emission Rate (tonnes / MW
2 Emission Rate (tonnes / M
2 Emission Rate (tonnes /
Source: Adapted from E. S. Rubin, “CO2 Capture and Transport,” Elements, vol. 4, no. 5 (2008), pp. 311-317.
Notes: PC = subcritical pulverized coal units; SCPC = supercritical pulverized coal; IGCC = integrated
gasification combined cycle; NGCC = natural gas combined cycle). Ranges reflect differences in technical and
economic parameters affecting plant cost, based on data from DOE, “Cost and Performance”; N. Holt, “CO2
Capture & Storage—EPRI CoalFleet Program,” PacificCorp Energy IGCC/Climate Change Working Group,
January 25, 2007, Electric Power Research Institute, Palo Alto, CA; MIT, 2007; E. S. Rubin, C. Chen, and A. B.
Rao, “Cost and Performance of Fossil Fuel Power Plants with CO2 Capture and Storage,” Energy Policy, vol. 35,
no. 9 (2007), pp. 4444-4454; and Metz, ‘Special Report.’
The dominant factors responsible for the broad range of costs for each plant type in Figure 9 are
assumptions about the design, operation, and financing of the power plant to which the capture
technology is applied. For example, higher plant efficiency, larger plant size, higher fuel quality,
lower fuel cost, higher annual hours of operation, longer operating life, and lower cost of capital
all reduce both the cost of electricity and the unit cost of CO2 capture. Assumptions about the CO2
capture system design and operation also contribute to variations in the overall cost. Assumptions
vary across the set of studies cited. Since no single set of assumptions applies to all situations or
all parts of the world, there is no single estimate for the cost of CO2 capture. Indeed, the cost
ranges would be even broader if other factors such as a larger range of boiler efficiencies or coal
types were considered.
On a relative basis, CCS is estimated to increase the cost of generating electricity by
approximately 60% to 80% at new coal combustion plants and by about 30% to 50% at new coal
gasification plants. On an absolute basis, the increased cost translates to roughly $40-$70/MWh
for supercritical (SCPC) coal plants and $30-$50/MWh for IGCC plants using bituminous coal.
As noted earlier, the CO2 capture step (which includes CO2 compression) accounts for 80% to
90% of this cost.
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Figure 9 also can be used to calculate the cost per tonne of CO2 avoided for a plant with capture
relative to one without. This cost is equivalent to the “carbon price” or CO2 emissions tax above
which the CCS plant is more economical than the plant without capture. For new supercritical
coal plants this is currently about $60-$80/tonne CO2. For IGCC plants with and without CCS,
the avoidance cost is smaller, about $30-$50/tonne CO2. Since the cost of CO2 avoided depends
on the choice of “reference plant” with no CCS, it is also useful to compare an IGCC plant with
capture to a SCPC reference plant without capture. In this case, the cost of CO2 avoided is
roughly $40-$60/tonne CO2. In all cases, costs are lower if the CO2 can be sold for enhanced oil
recovery (EOR) with subsequent geological storage. For plants using low-rank coals (i.e.,
subbituminous coal or lignite), the avoidance cost may be slightly higher.10
Retrofit Costs for Existing Power Plants
For existing power plants, the feasibility and cost of retrofitting a CO2 capture system depend
heavily on site-specific factors such as the plant size, age, efficiency, type and design of existing
air pollution control systems, and availability of space to accommodate a capture unit.11 In
general, the added cost of electricity generation is higher than for a new supercritical plant. A
major contributing factor is the lower thermal efficiency typical of existing (subcritical) power
plants, which results in a larger energy penalty and higher capital cost per unit of capacity. Other
factors include the added capital costs due to physical constraints and site access difficulties
during construction of a retrofit project, plus the likely need for upgrades or installation of
additional equipment, such as more efficient SO2 scrubbers. The cost per ton of CO2 avoided also
increases as a result of these higher costs.
Studies also indicate that for many existing plants the most cost-effective strategy for plants that
have suitable access to geological storage areas is to combine CO2 capture with a major plant
upgrade, commonly called repowering. Here, an existing subcritical unit is replaced either by a
high-efficiency (supercritical) boiler and steam turbine system, or by a gasification combined
cycle system.12 In such cases, the cost of CO2 capture approaches that of a new plant, with some
potential savings from the use of existing plant components and infrastructure, as well as from
fewer operating permit requirements relative to a new greenfield site.
Costs for Other Industrial Processes
There have been a limited number of studies of CO2 capture costs for industrial processes other
than power plants. Table 4 summarizes the reported cost ranges.13 In general, the incremental cost
of capture is lowest for processes where CO2 is already separated as part of the normal process
operations, such as in the production of hydrogen or the purification of natural gas. In these cases,
10 U.S. Department of Energy, Assessment of Power Plants That Meet Proposed Greenhouse Gas Emission
Performance Standards DOE/NETL-401/110509, National Energy Technology Laboratory, Pittsburgh, PA, November
5, 2009; E. S. Rubin, C. Chen, and A. B. Rao, “Cost and Performance of Fossil Fuel Power Plants with CO2 Capture
and Storage,” Energy Policy, vol. 35, no. 9 (2007), pp. 4444-4454.
11 Rao and Rubin, “Technical, Economic.”
12 C. Chen, A. B. Rao, and E. S. Rubin, “Comparative Assessment of CO2 Capture Options for Existing Coal-Fired
Power Plants,” Proc. Second National Conference on Carbon Sequestration, May 5-8, 2003, Alexandria, VA.; D.
Simbeck, “The carbon capture technology landscape,” Proc. Energy Frontiers International Emerging Energy
Technology Forum, SFA Pacific, Inc., February, 2008, Mountain View, CA.
13 Metz, Special Report.
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the added cost is simply for CO2 compression. For other industrial processes, capture costs are
highly variable and depend strongly on site-specific factors, both technical and economic.
Table 4. Range of CO2 Capture Costs for Several Types of Industrial Processes
(2007$/tonne CO2)
Industrial Process
Capture Cost Range
Fossil fuel power plants
$20-$95/t CO2 net captured
Hydrogen and ammonia production, or a natural gas processing plant
$5-$70/t CO2 net captured
Al other industrial processes
$30-$145/t CO2 net captured
Source: Based on Metz, Special Report data, adjusted to 2007 cost basis.
Important Caveat Concerning Costs
Construction costs for power plants and industrial equipment escalated dramatically from about
2004 to 2008, as did fuel prices, especially natural gas. Most prices then stabilized or receded
during the subsequent economic recession. Uncertainty about future cost trends, together with the
absence of full-scale projects, further clouds the “true” cost of facilities with or without CCS. For
power plants, the relative costs of PC and IGCC plants also can change with coal type, operating
hours, cost of capital, and many other factors.14 Experience with IGCC power plants is still quite
limited, and neither PC nor IGCC plants with CCS have yet been built and operated at full scale.
Thus, neither the absolute nor the relative costs of these systems can be stated with a high degree
of confidence at this time.
14 Rubin et al., “Cost and Performance.”
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Carbon Capture: A Technology Assessment
Chapter 4: Stages of Technology Development
Introduction
The stages of technological development or maturity of carbon capture systems span a broad
spectrum. At one end of the spectrum are the current commercial systems described in the
previous chapter. At the opposite end are new concepts or processes that exist only on paper, or
perhaps as a small-scale device or experiment in a research laboratory. New or “advanced”
technologies commonly seek (and often boast of) higher effectiveness and/or lower cost than
current commercial systems—attributes that are highly desired in the marketplace. At the same
time, claims about the cost or performance of processes in the early stages of development are
inherently uncertain and subject to change as the technology advances toward commercialization.
This chapter discusses a number of ways to characterize the level of technological development
of CO2 capture systems. The aim is to provide a clear understanding of the steps that are needed
to bring a promising new technology to commercial reality. To begin, however, this section
briefly describes the general process of technological change in order to provide context for a
closer examination of innovations in carbon capture technologies.
The Process of Technological Change
Innovations in carbon capture technology and the commercial adoption of such systems are
examples of the general process of technological change. While a variety of terms are used to
describe that process, four commonly defined stages are:
• Invention—discovery; creation of knowledge; new prototypes
• Innovation—creation of a new commercial product or process
• Adoption—deployment and initial use of the new technology
• Diffusion—increasing adoption and use of the technology
The first stage is driven by R&D, including both basic and applied research. The second stage—
innovation—is a term often used colloquially to describe the overall process of technological
change. As used here, however, it refers only to the creation of a product or process that is
commercially offered; it does not mean the product will be adopted or become widely used. That
happens only if the product succeeds in the final two stages—adoption and diffusion, which
reflect the commercial success of a technology innovation.
Studies also show that rather than being a simple linear process, the four stages of technological
change are highly interactive, as depicted in Figure 10. Thus, innovation is stimulated not only
by support for R&D, but also by the experience of early adopters, plus added knowledge gained
as a technology diffuses more widely into the marketplace. The reductions in product cost that are
often observed as a technology matures—commonly characterized as a “learning curve”—reflect
the combined impacts of sustained R&D plus the benefits derived from “learning by doing”
(economies in the manufacture of a product) and “learning by using” (economies in the operating
costs of a product).
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Carbon Capture: A Technology Assessment
Figure 10. Stages of Technological Change and Their Interactions
Innovatio
i n
Adopti
A
o
dopti n
o
Diffu
ff si
s on
Inve
Inv ntion
e
(ne
(n w or better
(e
( arly u
ly s
u e)
)
(imp
m ro
p ved
pr
p odu
r
c
odu t
c )
t
technolo
l gy)
Learn
Le
ing
n
Learn
L
ing
R&D
By Doing
By Us
U ing
Source: E. S. Rubin, “The Government Role in Technology Innovation: Lessons for the Climate Change Policy
Agenda,” Institute of Transportation Studies, 10th Biennial Conference on Transportation Energy and
Environmental Policy, University of California, Davis, CA (August 2005).
This report deals only with the first two stages of Figure 10 in the context of carbon capture
systems at different levels of development or maturity. The goal is to characterize the current
status of capture technologies and the outlook for future commercial systems. Later, “Chapter 9:
Lessons from Past Experience” discusses the influence of the last two stages (adoption and
diffusion) on the pace of innovation and the prospects for lower-cost capture technologies.
Technology Readiness Levels (TRLs)
One method of describing the maturity of a technology or system is the scale of technology
readiness levels (TRLs) depicted in Figure 11. First developed for the National Aeronautics and
Space Administration (NASA), TRLs were subsequently adopted by the U.S. Department of
Defense, as well as by other organizations involved in developing and deploying complex
technologies or systems, both in the United States and abroad. Recently, researchers at the
Electric Power Research Institute (EPRI) also adopted TRLs to describe the status of new post-
combustion carbon capture technologies,15 discussed later in “Chapter 5: Status of Post-
Combustion Capture.”
15 Electric Power Research Institute, Program on Technology Innovation: Post-Combustion CO2 Capture Technology
Development, Report No. 1016995, Prepared by A. S. Bhown and B. Freeman, Palo Alto, CA, December 2008.
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Figure 11. Descriptions of Technology Readiness Levels (TRLs)
Source: National Aeronautics and Space Administration, “Definition of Technology Readiness Levels,” at
http://esto.nasa.gov/files/TRL_definitions.pdf.
The TRL scale has nine levels. At TRL 1 a technology consists only of basic principles, while at
TRL 9 it has evolved into a system that has been used successfully in its actual operating
environment. TRLs are used to assess the maturity of a technology and the risks of placing it into
service for a given mission. Studies by the U.S. Government Accountability Office (GAO) found
that commercial firms typically do not introduce new technology into a commercial product until
it is at the equivalent of TRL 8 or TRL 9, where the technology has been fully integrated and
validated in its working environment. The GAO also found that a number of government projects
it examined tended to be further behind schedule and over budget where unproven technologies
were employed, compared to projects designed with more mature technologies.16
DOE’s Office of Management also recently published a Technology Readiness Assessment Guide
to provide general guidance as to how critical technologies should be developed before and
during their integration into engineered systems.17 The modified definitions of TRLs employ four
scales of development called lab scale, bench scale, engineering scale and full scale (Figure 12).
A technology is considered to be lab scale at TRLs 2 and 3 and bench scale at TRL 4. The latter is
typically a complete system, whereas lab scale involves proof-of-concept for a subsystem or
component. A technology at the engineering scale corresponds to TRLs 5 and 6. At TRL 7 and
beyond the system is full scale. Variants of these four categories are used in this report to describe
the development stages of carbon capture technologies, as explained below.
16 U.S. General Accounting Office, Better Management of Technology Development Can Improve Weapon System
Outcomes, GAO/NSIAD-99-162, Washington, DC (July 1999); Government Accountability Office, Major
Construction Projects Need a Consistent Approach for Assessing Technology Readiness to Help Avoid Cost Increases
and Delays, Washington, DC (July 2007).
17 U.S. Department of Energy, Technology Readiness Assessment Guide, at http://www.directives.doe.gov/directives/
current-directives/413.3-EGuide-04/view?searchterm=None.
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Carbon Capture: A Technology Assessment
Figure 12. A Department of Energy View of Technology Development Stages
and Their Corresponding TRLs
Source: DOE, “Technology Readiness.”
Technology Maturity Levels Used in this Study
While the nine-level TRL scale is a useful way to describe and compare the status of technologies
being considered for deployment in a particular mission or complex system, for purposes of this
study, a simpler set of five categories is used to describe the maturity of carbon capture
technologies. The five stages reflect not only different levels of maturity but also differences in
the physical size and complexity of a technology at different points in its development.
Significant increases in the level of financial commitments also are needed to advance along this
five-stage journey, which not all processes survive. This representation of “what’s in the pipeline”
is possibly the most effective way to convey to Congress and others the prospects, time
requirements, and level of financial resources needed to bring improved CO2 capture systems to
the marketplace.
Commercial Process
A commercial carbon capture technology or process is one that is available for routine use in a
particular application such as a power plant or industrial process. The capture technology is
offered for sale by one or more reliable vendors with standard commercial guarantees. As defined
here, a commercial technology corresponds to TRL 9, the highest level on the TRL scale. This is
the maturity level that electric utility companies normally will require before installing a carbon
capture system at a U.S. power plant.
Full-Scale Demonstration Plant
The full-scale demonstration stage corresponds to levels 7 and 8 on the TRL scale. It represents
the stage at which a CO2 capture technology is integrated into a full-size system in order to
demonstrate its viability and commercial readiness in a particular application. For power plants,
such applications might include pulverized coal combustion systems employing oxy-combustion
or post-combustion CO2 capture, as well as IGCC plants employing pre-combustion capture.
While there is flexibility in the definition of “full-scale,” in general a full-scale demonstration
would correspond to a gross power plant size of approximately 250 MW, with a corresponding
CO2 capture rate of roughly 1-2 million tonnes per year for a coal-fired plant. For reference, the
median size of U.S. coal-burning power plants today is approximately 650 MW (gross or
nameplate capacity). For gas-fired power plants or other industrial applications a full-scale
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Carbon Capture: A Technology Assessment
demonstration may have smaller annual quantities of CO2 captured because of smaller plant sizes
and/or lower fuel carbon content.
Pilot Plant Scale
The pilot plant stage is where a process or technology is tested in a realistic environment, but at a
scale that is typically one to two orders of magnitude smaller than the full-scale demonstration.
For carbon capture processes, a pilot plant might be built as a stand-alone facility, or as a unit
capturing CO2 from the slipstream of an adjoining full-size power plant. Pilot plants represent an
initial demonstration stage corresponding to levels 6 and 7 on the TRL scale. At this stage data are
gathered to refine and further develop a process, or to design a full-size (or intermediate size)
demonstration plant.
Laboratory or Bench Scale
The laboratory and bench scales represent the early stage of process development in which an
apparatus or process is first successfully constructed and operated in a controlled environment,
often using materials and test gases to simulate a commercial process or stream (such as a flue
gas stream). A bench-scale apparatus is typically built as a complete representation of a process or
system, whereas laboratory-scale experiments typically seek to validate or obtain data for specific
components of a system. Laboratory- and bench-scale processes correspond to levels 3, 4 and 5
on the TRL scale.
Conceptual Design
The conceptual design stage of a CO2 capture process is one for which the basic science has been
developed, but no physical prototypes yet exist. Conceptual designs are often developed and
tested with computer models before any laboratory work is done. This allows for confirmation
that the design principles are sound, plus some degree of process optimization before progressing
to the more expensive laboratory or bench-scale stage. The conceptual design stage corresponds
to levels 1 and 2 on the TRL scale.
Current Status of CO2 Capture Technologies
Consistent with the objectives of this study, the next three chapters characterize the current status
of carbon capture technologies with respect to the five stages of development outlined above.
Each chapter addresses one of the three main avenues for CO2 capture—post-combustion, pre-
combustion, and oxy-combustion systems. The subsequent chapter then discusses the cost
reductions expected from advanced capture systems and the projected timetables for their
commercialization.
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Chapter 5: Status of Post-Combustion Capture
Introduction
This chapter summarizes the status of post-combustion CO2 capture technologies at various
stages of development. The most advanced systems today employ amine-based solvents, while
processes at the earliest stages of development employ a variety of novel solvents, solid sorbents,
and membranes for CO2 capture or separation. The chapter begins with a summary of current
commercial processes and then describes technologies at each of the four other stages of
development defined in “Chapter 4: Stages of Technology Development.”
In recent years, carbon capture R&D programs have expanded rapidly throughout the world; thus,
any summary of “current” activities and projects is soon out of date. For this reason, this report
does not attempt to cover capture-related R&D activities comprehensively. Rather, it attempts to
synthesize key findings from our own investigations and from the work of others who also track
and report on the status of CO2 capture technology developments. It draws also upon a set of
publicly available databases and CCS project status reports maintained by organizations including
DOE’s National Energy Technology Laboratory (DOE/NETL), the International Energy Agency’s
Greenhouse Gas Control Programme (IEAGHG), the Massachusetts Institute of Technology
(MIT) Carbon Sequestration Program, and the recently formed Global Carbon Capture and
Storage Institute (GCCSI).18 In some cases, the information from these public databases has been
supplemented by data from websites of companies involved in capture technology development.
In each of the sections below, the objective is to summarize not only the current status of post-
combustion capture technology developments (as of March 2010), but also the potential
advantages of each new technology, as well as the key technical barriers and challenges that must
be overcome to advance the method. Brief descriptions of new processes or capture methods not
previously discussed in “Chapter 3: Overview of CO2 Capture Technologies” also are provided.
Commercial Processes
As noted in “Chapter 3: Overview of CO2 Capture Technologies,” post-combustion CO2 capture
systems have been in use commercially for many decades, mainly in industrial processes for
purifying gas streams other than combustion products. The use of amines to capture CO2 was first
patented 80 years ago and since then has been used to meet CO2 product specifications in
industries ranging from natural gas production to the food and beverage industry.19 A number of
vendors currently offer commercial amine-based processes, including the Fluor Daniel
Econamine FG Plus process, the Mitsubishi Heavy Industries KM-CDR process, the Lummus
Kerr-McGee process, the Aker Clean Carbon Just Catch process, the Cansolv CO2 capture
system, and the HTC Purenergy Process.20
18U.S. Department of Energy, “NETL Carbon Capture and Storage Database,” http://www.netl.doe.gov/technologies/
carbon_seq/database/index.html; International Energy Agency Greenhouse Gas R&D Programme (IEAGHG), “CO2
Capture and Storage.” http://www.co2captureandstorage.info/co2db.php; MIT Energy Initiative, “Carbon Capture and
Sequestration Technologies at MIT,” http://sequestration.mit.edu; Global Carbon Capture and Storage Institute
(GCCSI), Strategic Analysis of the Global Status of Carbon Capture and Storage, WorleyParsons, 2009,
http://www.globalccsinstitute.com/downloads/Status-of-CCS-WorleyParsons-Report-Synthesis.pdf.
19 G. Rochelle, “Amine Scrubbing for CO2 Capture,” Science, vol. 325 (2009), pp. 1652-1654.
20 Clean Air Task Force & Consortium for Science, Policy and Outcomes, “Innovation Policy for Climate Change,”
Proc. National Commission on Energy Policy, Washington, DC.
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Carbon Capture: A Technology Assessment
The hundreds of commercial aqueous amine systems currently in operation typically vent the
captured CO2 to the atmosphere. Of the projects listed in Table 5, three are at natural gas
treatment plants (two in Norway, one in Algeria) in which the captured CO2 is sequestered in deep
geological formations to prevent its release to the atmosphere. One of these projects, the Statoil
natural gas production facility at Sleipner in the North Sea, has been operating since 1996. This is
the longest-running commercial CCS project. Figure 13 shows a photograph of the amine-based
CO2 capture unit installed more recently at a natural gas treatment plant in Algeria. That unit is
part of an integrated CCS system that includes CO2 capture, pipeline transport, and sequestration
in a nearby geological formation.
Table 5. Commercial Post-Combustion Capture Processes at Power Plants
and Selected Industrial Facilities
Approx.
Capture
CO2 Captured
Plant and
Year of Capture Plant System Type
(106
Project Name and Location
Fuel Type
Startup Capacity
(Vendor)
tonnes/yr)
United States
IMC Global Inc. Soda Ash Plant
Coal and
1978 43
MW Amine
0.29
(Trona, CA)
petroleum coke-
(Lummus)
fired boilers
AES Shady Point Power Plant
Coal-fired power
1991 9
MW Amine
0.06
(Panama City, OK)
plant
(Lummus)
Bellingham Cogeneration Facility Natural gas-fired
1991 17
MW Amine
(Fluor)
0.11
(Bellingham, MA)
power plant
Warrior Run Power
Coal-fired
2000 8
MW Amine
0.05
Plant (Cumberland, MD)
power plant
(Lummus)
Outside the United States
Soda Ash Botswana Sua Pan
Coal-fired
1991 17
MW Amine
0.11
Plant (Botswana)
power plant
(Lummus)
Sumitomo Chemicals
Gas & coal boilers
1994
8 MW
Amine (Fluor)
0.05
Plant (Japan)
Statoil Sleipner West Gas Field
Natural gas
1996 N/A
Amine
(Aker) 1.0
(North Sea, Norway)
separation
Petronas Gas Processing Plant
Natural gas-fired
1999 10
MW Amine
(MHI)
0.07
(Kuala Lumpur, Malaysia)
power plant
BP Gas Processing Plant
Natural gas
2004 N/A
Amine
1.0
(In Salah, Algeria)
separation
(Multiple)
Mitsubishi Chemical Kurosaki
Natural gas-fired
2005 18
MW Amine
(MHI)
0.12
Plant (Kurosaki, Japan)
power plant
Snøhvit Field LNG and CO2
Natural gas
2008 N/A
Amine
(Aker) 0.7
Storage Project
separation
(North Sea, Norway)
Huaneng Co-Generation Power
Coal-fired
2008 0.5
MW
Amine
0.003
Plant (Beijing, China)
power plant
(Huaneng)
Sources: DOE, “NETL Carbon”; IEAGHG, “CO2 Capture”; MIT, “Carbon Capture”; GCCSI, “Strategic
Analysis.”
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Carbon Capture: A Technology Assessment
Figure 13. An Amine-Based CO2 Capture System Used to Purify Natural Gas
at BP’s In Salah Plant in Algeria
Source: Photo courtesy of IEA Greenhouse Gas Programme.
As shown in Table 5, CO2 is also captured at several coal-fired and gas-fired power plants where
a portion of the flue gas stream is fitted with a CO2 capture system. Figure 14 shows the amine
systems installed at two U.S. power plants, one burning coal, the other natural gas. The CO2
captured at these plants is sold to nearby food processing facilities, which use it to make dry ice
or carbonated beverages. The oldest and largest commercial CO2 capture system operating on flue
gases is the IMC Global soda ash plant in California. Here, the mineral trona is mined locally and
combined with CO2 to produce sodium carbonate (soda ash), a widely used industrial chemical.21
All these products soon release the CO2 to the atmosphere (e.g., through carbonated beverages).
To date, only ABB Lummus (now CB&I Lummus) has commercial flue gas CO2 capture units
operating at coal-fired power plants, while both Fluor Daniel and MHI have commercial
installations at gas-fired plants (see Table 5). Both Fluor and MHI now also offer commercial
guarantees for post-combustion capture at coal-fired power plants.
These vendors (and others) use amine-based solvents for CO2 capture. In most cases the exact
composition of the solvent is proprietary. The currently operating Lummus systems employ a
solution of 20% MEA in water, while the Fluor systems use a solvent with a 30% amine
concentration.22 Higher amine concentrations are beneficial in reducing the large energy penalty
of CO2 capture, since there is less water in the solution that needs to be pumped and heated in the
regeneration process. Capital cost is also less, since higher amine concentrations lead to smaller
equipment sizes. On the other hand, amines such as MEA are highly corrosive, so higher amine
concentrations require chemical additives or more costly construction materials to prevent
corrosion. Tradeoffs among these factors underlie some of the differences in capture system
designs offered by different vendors. The systems and solvents currently offered commercially by
Fluor (Econamine FG+) and MHI (KS-1) boast of reductions of roughly 25% in capture energy
requirements relative to older system designs using MEA, which lowers the overall cost.
21 IEAGHG, “CO2 Capture.”
22 P. H. M. Feron, “Progress in SP2 CO2 Post-combustion Capture,” Presentation at ENCAP/CASTOR Seminar, March
2006. J. N. Jensen and J. N. Knudsen, “Experience with the CASTOR/CESAR Pilot Plant,” presentation at the
Workshop on Operating Flexibility of Power Plants with CCS, November 2009.
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Carbon Capture: A Technology Assessment
Figure 14. Amine-Based Post-Combustion CO2 Capture Systems Treating a Portion
of the Flue Gas from a Coal-Fired Power Plant in Oklahoma, USA (left), and a
Natural Gas Combined Cycle (NGCC) Plant in Massachusetts, USA (right)
Source: Photos courtesy of ABB Lummus, Fluor Daniels, and Chevron.
Full-Scale Demonstration Plants
Although several CO2 capture systems have operated commercially for nearly two decades on a
portion of power plant flue gases, no capture units have yet been applied to the full flue gas
stream of a modern coal-fired or gas-fired power plant. Thus, one or more demonstrations of
post-combustion CO2 capture at full scale are widely regarded as crucial for gaining the
acceptance of this technology by electric utility companies, as well as by the institutions that
finance and regulate power plant construction and operation. Several years ago, for example, the
European Union called for 12 such demonstrations in Europe, while in the United States there
have been calls for at least 6 to 10 full-scale projects.23
To date, however, no such demonstrations have yet occurred, nor (as best we can tell) has full
financing yet been guaranteed for any of the full-scale demonstration projects that have been
announced. One reason is the high cost of each project, estimated at roughly $1 billion for CO2
capture at a 400 MW unit operating for five years.24 Several previously announced
demonstrations of full-scale power plant capture and storage systems have been canceled or
delayed due to sharp escalations in construction costs prior to 2008. Even more recently, a 160
MW demonstration project in the United States was canceled not long after being announced.25
23 European Technology Platform for Zero Emission Fossil Fuel Power Plants, “EU Demonstration Programme for CO2
Capture and Storage (CCS),” November 2008, http://www.zeroemissionsplatform.eu/index; MIT, ‘Future of Coal.’
V.A. Kuuskraa, “A Program to Accelerate the Deployment of CO2 Capture and Storage (CCS): Rationale, Objectives
and Costs,” Paper prepared for the Coal Initiative Reports’ Series of the Pew Center on Global Climate Change,
Arlington, VA, October 2007.
24 Kuuskraa, “Accelerate Deployment.”
25 Sourcewatch, “Southern Company abandons carbon capture and storage project,” 2010, http://www.sourcewatch.org/
index.php?title=Southern_Company#cite_note-11.
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Carbon Capture: A Technology Assessment
Nevertheless, it appears reasonable to assume that at least some of the large-scale projects
currently planned for post-combustion CO2 capture in the United States and other countries will
materialize over the next several years, with costs shared between the public and private sectors.
Table 6 lists the features and locations of major announced demonstration projects at power
plants in the United States and other countries. Most of these CO2 capture systems would be
installed at existing coal-fired plants, with the captured CO2 transported via pipeline to a
geological storage site (often in conjunction with enhanced oil recovery to reduce project costs).
Table 6. Planned Demonstration Projects at Power Plants with
Full-Scale Post-Combustion Capture
Approx.
Capture
Current
Plant
Capture
System
Annual CO2
Status
Project Name
and Fuel
Year of
Plant
Type
Captured
(March
and Location
Type
Startup
Capacity
(Vendor)
(106 tonnes)
2010)
United States
Basin Electric Antelope
Coal-fired
2012 120
MW
Amine
1.0 Site
Valley Station (Beulah,
power
(HTC)
Selection
ND)
plant
Tenaska Trailblazer
Coal-fired
2014 600
MW
Amine
4.3 Permitting
Energy Center
power
(Fluor)
(Sweetwater, TX)
plant
American Electric
Coal-fired
2015
235 MW
Chilled
1.5 Scoping
Power Mountaineer
power
Ammonia
Plant (New Haven,
plant
(Alstom)
WV)
Outside the United States
SaskPower
Coal-fired
2014 115
MW
Amine
1.0 Plant
Design
power
(Cansolv)
Boundary Dam Polygon plant
(Estevan, Canada)
E.ON Kingsnorth
Coal-fired
2014 300
MWa Amine
(Fluor
1.9 Plant
Design
Ruhrgas UK Post-
power
& MHI)
Combustion Project
plant
(Kent, United Kingdom)
TransAlta Project
Coal-fired
2015 200
MW
Chilled
1.0 Plant
Design
Pioneer Keephills 3
power
Ammonia
Power Plant
plant
(Alstom)
(Wabamun, Canada)
Vattenfall Janschwalde
Coal-fired
2015
125 MW
Amine (TBD)
—
Permitting
(Janschwalde, Germany) power
plant
Porto Tolle (Rovigo,
Coal-fired
2015 200
MWa Amine
(TBD)
1.0
Scoping
Italy)
power
plant
Source: DOE, “NETL Carbon’”; IEAGHG, “CO2 Capture”; MIT, “Carbon Capture”; GCCSI, “Strategic
Analysis.”
a. Estimated from other reported data.
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Carbon Capture: A Technology Assessment
Note that while most of the projects in Table 6 plan to employ amine-based capture systems, a
few propose to use an ammonia-based process. Two such capture processes are currently at the
pilot plant stage and are described in more detail in the next section of this report. Plans for scale-
up to a demonstration project are predicated on successful operation of the smaller-scale pilot
plants.
Note too that most of the planned demonstration projects have expected startup dates of 2014 or
later. This means that such projects are currently in the early stages of detailed design and that
final commitments of full funding for construction have not yet been made. Similarly, it is still
too early to know the details of capture system designs and the extent to which they might be
expected to achieve further improvements in CO2 capture efficiency and/or reductions in cost
relative to current commercial systems.
In addition to the power plant projects in Table 6, DOE plans to support at least four
demonstration projects of CO2 capture at industrial facilities. Eleven candidates were selected for
further study in late 2009, with down-selections expected in mid-2010.
Pilot Plant Projects
Table 7 lists pilot-scale post-combustion CO2 capture projects that are currently operating or are
in the design or construction stage. Most of these projects are testing and developing new or
improved amine-based solvents. Several others are testing and developing ammonia-based
capture processes.
Table 7. Pilot Plant Processes and Projects for Post-Combustion CO2 Capture
Approx.
Capture
Capture
Annual CO2
Project Name
Plant and
Year of
Plant
System Type
Captured (106
and Location
Fuel Type Startup
Capacity
(Vendor)
tonnes)
United States
First Energy R.E. Burger Plant
Coal-fired
2008 1
MW
Ammonia
0.007
(Shadyside, OH)
power
(Powerspan)
plant
American Electric Power
Coal-fired
2009 20
MW
Chilled
0.1
Mountaineer Plant
power
Ammonia
(New Haven, WV)
plant
(Alstom)
Dow Chemicals South
Coal-fired
2009 0.5
MWa Amines
(Dow/ 0.002
Charleston Plant
power
Alstom)
(Charleston, WV)
plant
NRG Energy WA Parish Plant
Coal-fired
2012 60
MW
Amine
(Fluor)
0.5
(Houston, TX)
power
plant
Outside the United States
Nanko Natural Gas Pilot
Gas-fired
1991
0.1 MW
Amine (MHI)
0.001
Plant (Osaka, Japan)
power
plant
Matsushima Coal Plant
Coal-fired
2006 0.8
MWa Amine
(MHI) 0.004
(Nagasaki, Japan)
power
plant
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Carbon Capture: A Technology Assessment
Approx.
Capture
Capture
Annual CO2
Project Name
Plant and
Year of
Plant
System Type
Captured (106
and Location
Fuel Type Startup
Capacity
(Vendor)
tonnes)
Munmorah Pilot Plant
Coal-fired
2008 1
MWa Ammonia
(Delta
0.005
(Lake Munmorah, Australia)
power
& CSIRO)
plant
Tarong Power Station
Coal-fired
2008 0.5
MWa Amine
(Tarong 0.0015
(Nanango, Australia)
power
& CSIRO)
plant
Hazelwood Carbon Capture
Coal-fired
2008
2 MW
Amine (Process
0.01
(Morewell, Australia)
power
Group)
plant
CASTOR CO2 from Capture
Coal-fired
2008
3 MW
Amine (Multiple)
0.008
to Storage (Esbjerg,
power
Denmark)
plant
Eni and Enel Federico II
Coal-fired
2009
1.5 MW
Amine (Enel)
0.008
Brindisi Power Plant
power
(Brindisi, Italy)
plant
CATO-2 CO2 Catcher
Coal-fired
2008
0.4 MW
Amine (Multiple)
0.002
(Rotterdam, Netherlands)
power
plant
Statoil Mongstad
Natural
2010 15
MWa Chilled
NH3
0.08
Cogeneration Pilot
gas-fired
(Alstom)
(Mongstad, Norway)
power
plant
7 MWa Amine
(Various)
0.02
Sources: DOE, “NETL Carbon”; IEAGHG, “CO2 Capture”; MIT, “Carbon Capture”; GCCSI, “Strategic
Analysis.”
a. Estimated from other reported data.
Amine-Based Capture Processes
The class of solvents called amines (more properly, alkanolamines) are a family of organic
compounds that are derivatives of alkanols (commonly called the alcohols group) that contain an
“amino” (NH2) group in their chemical structures. Because of this complexity, there are multiple
classifications of amines, each of which has different characteristics relevant to CO2 capture.26
For example, MEA reacts strongly with acid gases like CO2 and has a fast reaction time and an
ability to remove high percentages of CO2, even at the low CO2 concentrations found in flue gas
streams. Other properties of MEA, however, are undesirable, such as its high corrosivity and
regeneration energy requirement. Various research groups are involved in synthesizing and testing
a variety of amine mixtures and “designer” amines to achieve a more desirable set of overall
properties for use in CO2 capture systems. One major focus is on lowering the energy required for
solvent regeneration, which has a major impact on process costs. Often, however, there are
tradeoffs to consider. For example, the energy required for regeneration is typically related to the
driving forces for achieving high capture capacities. Thus, reducing the regeneration energy can
lower the driving force and thereby increase the amount of solvent and size of absorber needed to
capture a given amount of CO2—thus increasing the capital cost. A higher cost of manufacturing
26 A. L. Kohl and R. B. Nielsen, Gas Purification, 5th ed. (Houston, TX: Gulf Publishing Company, 1997).
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Carbon Capture: A Technology Assessment
a new solvent also may detract from its benefits. Pilot plant projects are acquiring the data needed
to assess such tradeoffs and optimize the overall process.
Ammonia-Based Capture Processes
A 2005 study by DOE/NETL found that post-combustion CO2 capture using ammonia appeared
very promising. It suggested that if a number of engineering challenges could be overcome, the
overall cost of an ammonia-based system would be substantially less than an amine-based system
for CO2 capture. Since ammonia potentially could capture multiple pollutants simultaneously
(including CO2, SO2, NOx, and Hg), the overall plant cost could be reduced even further.27
Ammonia-based systems are attractive in part because ammonia is inexpensive, but also because
an ammonia-based process potentially could operate with a fraction of the energy penalty of
amines. Less compressor power also would be required, since CO2 can be regenerated at higher
pressure. These considerations led to early estimates that the overall energy penalty of an
ammonia-based system could be reduced to about half that of a conventional amine system—
claims not substantiated in subsequent testing. Ammonia also has a higher volatility than MEA
and thus is more easily released into the flue gas stream during the absorption step (a process
called “ammonia slip”). Controlling ammonia slip to acceptable levels is one of the major
engineering challenges, since a need for subsequent cleanup would add considerably to the cost.28
The development of ammonia-based capture technology has advanced to the pilot plant stage,
with the intent of soon scaling up to commercial sizes. The two major companies involved in
ammonia-based capture, a description of the pilot plants they have constructed, and the
announced plans for this technology are described below.
The Alstom Chilled Ammonia Process
In the chilled ammonia process being developed by Alstom, the flue gas and CO2 absorber are
cooled to about 20°C (68°F), a temperature that prevents large amounts of ammonia slip from
exiting the absorber with the cleaned flue gas stream. In the absorber, ammonium carbonate is
used to capture the CO2. As with amine system designs, the CO2-“rich” stream is then sent to a
stripper column where heat is added (using steam extracted from the power plant steam turbine)
to strip CO2 from the solution. This leaves a nearly pure CO2 stream that can be cleaned, dried,
and compressed for transport to a geological storage site. The CO2-“lean” stream is then
recirculated back to the absorber (Figure 15).
The energy required to regenerate the ammonia-based solvent is believed to be much smaller than
for amine systems, which would considerably reduce the overall process cost. However, there is
also an important tradeoff between the energy required to cool the process and the additional
equipment and energy costs of reducing ammonia slip to acceptable levels. Thus, the overall
process design must be optimized to achieve the best performance at minimum cost. Since details
of the Alstom process remain proprietary, rigorous cost and performance comparisons with other
processes are currently unavailable.
27 U.S. Department of Energy, An Economic Scoping Study for CO2 Capture Using Aqueous Ammonia, prepared by
J. P. Ciferno, P. DiPietro, and T. Tarka, National Energy Technology Laboratory, Pittsburgh, PA (2005);
http://www.transactionsmagazine.com/ArgonneLabCommonSense.pdf.
28 D. Figueroa et al., “Advances in CO2 capture technology—The U.S. Department of Energy’s Carbon Sequestration
Program,” International Journal of Greenhouse Gas Control, vol 2 (2008), pp. 9-20.
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Carbon Capture: A Technology Assessment
Figure 15. Schematic of the Chilled Ammonia Process for CO2 Capture (left) and
the 20 MW Pilot Plant at the AEP Mountaineer Station in West Virginia (right)
Source: Photo courtesy of AEP.
Alstom is currently operating two pilot plants using their chilled ammonia process—one in the
United States and one in Norway (see Table 7). The most recent is the pilot plant at the American
Electric Power (AEP) Mountaineer power station in West Virginia, a 1300 MW coal-fired plant,
where a flue gas slip stream equivalent to about 20 MW has been fitted with the Alstom process
(see Figure 15). This is the first successful integration of CO2 capture, transport and geological
sequestration at a coal-fired power plant. Data from this pilot plant will provide the basis for the
proposed demonstration plant listed in Table 6.
The Powerspan ECO2 Capture Process
Powerspan has developed a technology called the ECO process, which uses ammonia to capture
SO2 and NOx from power plant flue gas streams in lieu of separate flue gas desulfurization and
selective catalytic reduction systems. In 2005, Powerspan expanded the ECO process to also
capture CO2. This process, called ECO2, is similar to the Alstom chilled ammonia process in that
it also uses ammonium carbonate to capture CO2, though the process operates at a higher
temperature. Ammonium sulfate from the ECO process is used to control ammonia slip so that
ammonia is not consumed in the process. Thus, while amine-based systems must severely limit
exposure of the solvent to acid gases like SO2 and NO2 to prevent solvent loss and degradation,
ammonia does not degrade in the presence of these gases; instead, it forms ammonium sulfate and
nitrate, which have value as fertilizer by-products.29 Powerspan is currently testing its ECO2
process at a 1 MW pilot plant at First Energy’s R. E. Burger plant, as indicated in Table 7.
29 Clean Air Task Force, “Coal without Carbon.”
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Carbon Capture: A Technology Assessment
Laboratory- or Bench-Scale Processes
A large number of new processes and materials for post-combustion CO2 capture are currently at
the laboratory- or bench-scale stage of development.30 These can be grouped into three general
categories: (1) liquid solvents (absorbents) that capture CO2 via chemical or physical
mechanisms; (2) solid adsorbents that capture CO2 via physical mechanisms; and (3) membranes
that selectively separate CO2 from other gaseous species. Within each category, a number of
approaches are being pursued, as summarized in Table 8.
Table 8. Post-Combustion Capture Approaches Being Developed
at the Laboratory or Bench Scale
Liquid Solvents
Solid Adsorbents
Membranes
Advanced amines
Supported amines
Polymeric
Potassium carbonate
Carbon-based
Amine-doped
Advanced mixtures
Sodium carbonate
Integrated with absorption
Ionic liquids
Crystalline materials
Biomimetic-based
Source: Edward S. Rubin, Aaron Marks, Hari Mantripragada, Peter Versteeg, and John Kitchin, Carnegie Mel on
University, Department of Engineering and Public Policy.
Each of the approaches in Table 8 has some potential to reduce the cost and/or improve the
efficiency of CO2 capture relative to current commercial systems. At this early stage of
development, however, it is difficult or impossible to reliably quantify the potential benefits or the
likelihood of success in advancing to a commercial process. Indeed, at this stage, many of the
approaches being investigated consist solely of a novel or advanced material that holds promise
for CO2 capture, but which remains to be developed into an engineered process that can properly
be called a capture technology. Thus, even if a new material succeeds in capturing CO2 more
efficiently or with a lower energy penalty, substantial challenges remain in incorporating such
materials into a viable and scalable technology that is more economical than current CO2 capture
systems.31 While some of the approaches in Table 8 may later advance to pilot-scale testing,
others may not move past the bench scale. The sections below describe in greater detail the
promise and challenges for each of these options.
Liquid Solvent-Based Approaches
Liquid solvents (typically a mixture of a base and water) selectively absorb CO2 through direct
contact between the chemical solvent and the flue gas stream. Regeneration of the solvent and
release of CO2 then takes place in a separate vessel (the regenerator) through a change of process
conditions, such as a swing in temperature or pressure.
In general, the aim of solvent research is to identify or create new solvents or solvent mixtures
that have more desirable characteristics than currently available solvents. Such properties include
increases in CO2 capture capacity, reaction rates, thermal stability, and oxidative stability, along
with decreases in regeneration energy, corrosivity, viscosity, volatility, and chemical reactivity
30 U.S. Department of Energy, Proceedings of 1st Existing Plant Program Annual Meeting, National Energy
Technology Laboratory, Pittsburgh, PA, March 2008.
31 Electric Power Research Institute (EPRI), Post-Combustion CO2 Capture Technology Development, Report No.
10117644, Technical Update, Palo Alto, CA, December 2009.
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Carbon Capture: A Technology Assessment
with flue gas impurities. All of these attributes tend to lower the cost of CO2 capture compared to
current solvents.
Unfortunately, most real solvents exhibit a combination of desirable and undesirable properties.
Laboratory- and bench-scale research thus seeks new solvents that yield a more optimal blend of
properties. Table 9 summarizes the main advantages and challenges associated with liquid
solvent-based approaches to post-combustion CO2 capture.
Table 9. Technical Advantages and Challenges for Post-Combustion Solvents
Description Advantages Challenges
Solvent reacts reversibly with CO2,
Chemical solvents provide fast
The large amount of steam required
often forming a salt. The solvent is
kinetics to al ow capture from
for solvent regeneration de-rates the
regenerated by heating
streams with low CO2 partial
power plant significantly.
(temperature swing), which
pressure.
reverses the absorption reaction
Energy required to heat, cool, and
(normally exothermic). Solvent is
Wet scrubbing al ows good heat
pump non-reactive carrier liquid
often alkaline.
integration and ease of heat
(usually water) is often significant.
management (useful for exothermic
absorption reactions).
Vacuum stripping can reduce
regeneration steam requirements but is
expensive; bad economy of scale.
Multiple stages and recycle stream may
be required.
Source: U.S. Department of Energy, DOE/NETL Carbon Dioxide Capture R&D Annual Technology Update, Draft,
National Energy Technology Laboratory, Pittsburgh, PA, April 2010; hereafter “DOE, Carbon Dioxide Capture.”
Examples of promising solvents include new amine formulations, carbonates, certain blends of
amines and carbonates, and ionic liquids. For example, a promising new amines now receiving
attention is piperazine. This solvent, currently being studied at the University of Texas and
elsewhere, has been shown to have faster kinetics, lower thermal degradation and lower
regeneration energy requirements than MEA in experiments thus far.32 Further characterization
studies are in progress.
Potassium carbonate solvents, which have been used successfully in other gas purification
applications, are now being investigated for bulk CO2 capture from flue gases.33 Potassium
carbonate absorbs CO2 through a relatively low-energy reaction, but the process is slow.
Researchers are attempting to speed up absorption by blending potassium carbonate with various
amines, with promising results.34 Modeling of piperazine-promoted blends, for example, has
suggested that due to improved kinetics and low regeneration energy requirements, such systems
could have smaller equipment sizes and be less energy intensive than MEA-based systems.35
32 Rochelle, “Amine Scrubbing”; S. A. Freeman, J. Davis, and G. T. Rochelle, “Degradation of aqueous piperazine in
carbon dioxide capture,” International Journal of Greenhouse Gas Control, 2010.
33 D. G. Chapel, C. L. Mariz, and J. Ernest, “Recovery of CO2 from Flue Gases: Commercial Trends,” Proc. Canadian
Society of Chemical Engineers Annual Meeting October 4-6, 1999, Saskatoon, Saskatchewan, Canada. D. Wappel et
al., “The Effect of SO2 on CO2 Absorption in an Aqueous Potassium Carbonate Solvent,” Energy Procedia, vol. 1, no.
1 (2009), pp. 125-131. H. Knuutila, H. F. Svendsen, and O. Juliussen, “Kinetics of Carbonate-Based CO2 Capture
Systems,” Energy Procedia, vol. 1 (2009), pp. 1011-1018.
34 DOE, “Carbon Dioxide Capture”; J. T. Cullinane and G. T. Rochelle, “Carbon Dioxide Absorption with Aqueous
Potassium Carbonate Promoted by Piperazine,” Chemical Engineering Science, vol. 59 (2004), pp. 3619-3630.
35 J. Oexmann, C. Hensel, and A. Kather, “Post-combustion CO2-capture from Coal-fired Power Plants: Preliminary
Evaluation of an Integrated Chemical Absorption Process with Piperazine-promoted Potassium Carbonate,”
(continued...)
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Carbon Capture: A Technology Assessment
Ionic liquids are liquid salts with low vapor pressure (hence, low flue gas losses) that potentially
can absorb CO2 at high temperatures with relatively low regeneration energy requirements.36
Researchers at the University of Notre Dame have shown that ionic liquids can capture SO2 as
well as CO2, leading to the possibility that they can be used in a multi-pollutant capture system.37
In a separate line of investigation, Georgia Tech Research Corporation is developing a class of
solvents called reversible ionic liquids that chemically react with CO2 to make other ionic liquids
that further absorb CO2.38 One challenge for ionic liquids is that they can become highly viscous
when absorbing CO2, thus increasing the energy required for solvent pumping and the potential
for mass transfer problems and operational difficulties in engineered processes.39
Solid Sorbent-Based Approaches
Solid sorbents capture (adsorb) CO2 on their surfaces, as shown in Figure 16. They then release
the CO2 through a subsequent temperature or pressure change, thus regenerating the original
sorbent. Solid sorbents have the potential for significant energy savings over liquid solvents, in
part because they avoid the need for the large quantities of water that must be repeatedly heated
and cooled to regenerate the solvent solution.40 Sorbent materials also have lower heat capacity
than solvents and thus require less regeneration energy to change their temperature.
A challenge, however, is how to efficiently get heat into and out of a solid sorbent material. More
complicated solids handling equipment also is required compared to solvent solutions, which
simply require pumps. In this regard, resistance to physical attrition and deterioration over time is
another important property for most solid sorbent applications. Finally, it is not yet clear which of
several different absorber designs that can utilize solid sorbents (e.g., fluidized beds, packed bed
reactors, transport reactors, or other systems) will be most effective in reducing overall cost.
In general, the aim of solid sorbent research is to reduce the cost of CO2 capture by designing
durable sorbents with efficient materials handling schemes, increased CO2 carrying capacity,
lower regeneration energy requirements, faster reaction rates and minimum pressure drops.41 The
CO2 carrying capacity is a key sorbent parameter that depends on the total microscopic surface
area of the material. Researchers are thus attempting to identify and design sorbents with very
high surface area for CO2 capture.42 The capture mechanism can be either a chemical or physical
surface interaction. Solid sorbents that rely on chemical mechanisms are similar to liquid
solvents. They include amines supported on the surface of other materials (called supported
amines), as well as carbonates such as calcium carbonate (limestone) and sodium carbonate (soda
ash). Sorbents that rely on physical surface interactions include materials such as activated
carbon, zeolites, and metal organic frameworks (MOFs).
(...continued)
International Journal of Greenhouse Gas Control, vol. 2 (2008), pp. 539-552.
36 GCCSI, “Strategic Analysis.” DOE, “Carbon Dioxide Capture.”
37 Figueroa et al., “Advances CO2 Capture.”
38 U.S. Department of Energy, CO2 Capture Technology Sheets, report prepared by Leonardo Technologies Inc. for
Existing Plants, Emissions and Capture Program, National Energy Technology Laboratory, Pittsburgh, PA, 2009.
39 Clean Air Task Force, “Coal without Carbon.”
40 Figueroa et al., “Advances CO2 Capture”; U.S. Department of Energy, “Carbon Dioxide Capture from Flue Gas
using Dry Regenerable Sorbents,” Project Facts, National Energy Technology Laboratory, Pittsburgh, PA, 2008.
41 DOE, “Carbon Dioxide Capture.”
42 GCCSI, “Strategic Analysis.”
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Figure 16. Schematic of CO2 Adsorption on the Surfaces of a Solid Sorbent
Source: Edward S. Rubin, Aaron Marks, Hari Mantripragada, Peter Versteeg, and John Kitchin, Carnegie Mel on
University, Department of Engineering and Public Policy.
Notes: The simplified flue gas composition is represented as a mixture of CO2 and nitrogen (N2), the principal
flue gas constituent.
Supported amines share the benefits of liquid amine solvents but require less energy to regenerate
because there is no water solution.43 The amine sorbent can be physically supported by a number
of different materials, including relatively inexpensive activated carbon.44 Such sorbents have
been shown to have high CO2 carrying capacities compared to other solid sorbents.45 Current
research is focused on issues of thermal stability and fouling, as these sorbents have a tendency to
break down over time and degrade in the presence of SO2.46
Sodium carbonate-based sorbents also have been recognized for their CO2 capture potential,47
although their performance is degraded by contaminants in flue gas.48 Among the promising
activities in this field is a CO2 capture system using a sodium carbonate-based sorbent for use at
coal or gas-fired power plants.49
43 M. L. Gray et al., “Performance of Immobilized Tertiary Amine Solid Sorbents for the Capture of Carbon Dioxide,”
International Journal of Greenhouse Gas Control, vol. 2 (2008), pp. 3-8.
44 M. G. Plaza et al., “CO2 Capture by Adsorption with Nitrogen Enriched Carbons,” Fuel, vol. 86 (2007), pp.
2204-2212.
45 S. Sjostrom and H. Krutka, “Evaluation of Solid Sorbents as a Retrofit Technology for CO2 Capture,” Fuel, vol. 89
(2010), pp. 1298-1306.
46 DOE, “Technology Sheets.”
47 Y. Liang et al., “Carbon Dioxide Capture Using Dry Sodium-Based Sorbent,” Energy & Fuels, vol. 18 (2004), pp.
569-575.
48 GCCSI, “Strategic Analysis.”
49 Figueroa et al., “Advances CO2 Capture.”
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Carbon Capture: A Technology Assessment
Carbon-based adsorbents such as activated carbon and charcoal also are attractive because they
are relatively inexpensive and have large surface areas that can readily adsorb CO2. Researchers
at the University of Wyoming, for example, claim that their Carbon Filter Process potentially can
capture 90% of flue gas CO2 and regenerate it with at least 90% CO2 purity at a lower cost than
amine-based processes.50 They also can provide a support material for amines or other solid
sorbents.
Metal organic frameworks and zeolites are crystalline sorbents that are also receiving attention for
post-combustion CO2 capture. MOFs consist of a matrix structure of metallic and organic
molecules that contain void spaces that can potentially be used to absorb large amounts of CO2
with low regeneration energy requirements and cost. Zeolites are porous alumino-silicate
materials that have high selectivity, but low carrying capacity for CO2 and are subject to
performance degradation in the presence of water.51 Researchers at the University of Akron are
investigating an approach combining zeolites with amines to improve overall performance.52
Table 10 summarizes the key advantages and challenges of solid sorbent-based approaches to
post-combustion CO2 capture. Although such systems have the potential to offer better
performance than current amine systems, the need to handle large amounts of solids tends to
make this approach more complex and more difficult to scale up than an equivalent liquid solvent
system. Sorbents also must have high selectivity for CO2 and be relatively insensitivity to trace
impurities in the flue gas. Because CO2 bonding to sorbents is not as strong as with chemical
interactions, multiple contacting stages also may be required to achieve high CO2 capture
efficiencies, which would increase process costs.53 Current R&D programs are attempting to
address these challenges.
Table 10. Technical Advantages and Challenges for Solid Sorbent Approaches
to Post-Combustion CO2 Capture
Description Advantages
Challenges
When sorbent pel ets are contacted
Chemical sites provide large
Heat required to reverse chemical
with flue gas, CO2 is absorbed onto
capacities and fast kinetics, enabling
reaction (although general y less than
chemically reactive sites on the pellet. capture from streams with low CO2 for wet-scrubbing).
Pellets are then regenerated by a
partial pressure.
temperature swing, which reverses
Heat management in solid systems is
the absorption reaction.
Higher capacities on a per mass or
difficult. This can limit capacity and/or
volume basis than similar wet-
create operational issues for
scrubbing chemicals.
exothermic absorption reactions.
Lower heating requirements than
Pressure drop can be large in flue gas
wet-scrubbing in many cases (CO2
applications.
and heat capacity dependent).
Sorbent attrition may be high.
Source: DOE, “Carbon Dioxide Capture.”
50 M. Radosz et al., “Flue-Gas Carbon Capture on Carbonaceous Sorbents: Toward a Low-Cost Multifunctional Carbon
Filter for ‘Green’ Energy Producers,” Industrial & Engineering Chemistry Research, vol. 47 (2008), pp. 3784-3794;
EPRI, ‘Post-Combustion.’
51 Clean Air Task Force, “Coal without Carbon.”
52 Figueroa et al., “Advances CO2 Capture.”
53 Clean Air Task Force, “Coal without Carbon”; GCCSI, “Strategic Analysis.”
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Carbon Capture: A Technology Assessment
Membrane-Based Approaches
Membranes are porous materials that can be used to selectively separate CO2 from other
components of a gas stream. They effectively act as a filter, allowing only CO2 to pass through
the material. The driving force for this separation process is a pressure differential across a
membrane, which can be created either by compressing the gas on one side of the material or by
creating a vacuum on the opposite side.
Membranes have been used for gas purification in a number of industrial applications since the
1980s.54 Two important physical parameters of a membrane are its selectivity and permeability.
Selectivity reflects the extent to which a membrane allows some molecules to be transported
across the material, but not others. For post-combustion CO2 capture, the selectivity to CO2 over
N2 (the main constituent of flue gas) determines the purity of the captured CO2 stream. The
permeability of a membrane reflects the amount of a given substance that can be transported for a
given pressure difference.55 This determines the membrane surface area needed to separate and
capture a given amount of CO2.
Among the current laboratory- and bench-scale developments in this area, researchers at the
University of Mexico are attempting to incorporate amine functional groups into membrane
materials—a development that could help raise the selectivity of CO2.56 Another active research
area is gas absorption membranes.57 Here, CO2-laden flue gases contact one side of a membrane
while a liquid solvent (such as an amine-based solvent) contacts the other side. As CO2 and other
gases pass through the membrane, the CO2 is selectively absorbed by the liquid solvent.58 This
approach holds potential for better performance than conventional absorber and stripper
configurations.59
Yet another approach employs membranes with biomimetric components, seeking to employ
processes found in nature. One such process uses the enzyme carbonic anhydrase, which
facilitates the transport of CO2 in the respiratory system of mammals.60 One effort to exploit this
process is a liquid membrane system catalyzed by carbonic anhydrase being developed by
Carbozyme Inc.61 While preliminary results show potential for significant decreases in energy
penalty and cost compared to amine-based systems, the significant challenges that remain include
the problems of membrane fouling and scale-up to power plant applications.
Table 11 summarizes the potential benefits and technical challenges of membrane-based
technologies for post-combustion CO2 capture. By most accounts, membranes today do not have
the selectivity needed to be economically competitive with amine-based post-combustion CO2
54 J. Kotowicz, T. Chmielniak, and K. Janusz-Szymańska, “The Influence of Membrane CO2 Separation on the
Efficiency of a Coal-fired Power Plant,” Energy, vol. 35 (2010), pp. 841-850. E. Favre, R. Bounaceur, and D. Roizard,
“Biogas, Membranes and Carbon Dioxide Capture,” Journal of Membrane Science, vol. 328, no. 1-2 (2009), pp. 11-14.
55 L. Zhao et al., “Multi-stage Gas Separation Membrane Processes used in Post-Combustion Capture: Energetic and
Economic Analyses,” Journal of Membrane Science, Article in Press, pp. 1-13.
56 Figueroa et al., “Advances CO2 Capture”; Clean Air Task Force, “Coal without Carbon.”
57 EPRI, “Post-Combustion.”
58 GCCSI, “Strategic Analysis.”
59 Clean Air Task Force, “Coal without Carbon.”
60 E. Hand, “The Power Player,” Nature, vol. 462 (2009), pp. 978-983.
61 Figueroa et al., “Advances CO2 Capture.”
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Carbon Capture: A Technology Assessment
capture.62 Additional challenges include the need for large surface areas to process power plant
flue gases, limited temperature ranges for operation, low tolerance to flue gas impurities (or
requirements for additional equipment to remove those impurities) and high parasitic energy
requirements to create a pressure differential across the membrane.63
Table 11. Technical Advantages and Challenges for Membrane-Based Approaches
to Post-Combustion CO2 Capture
Description Advantages
Challenges
Uses permeable or semi-permeable
No steam load.
Membranes tend to be more suitable for
materials that allow for the
high-pressure processes such as IGCC.
selective transport and separation
No chemicals needed.
of CO
Tradeoff between recovery rate and product
2 from flue gas.
purity (difficulty to meet both at same time).
Requires high selectivity (due to CO2
concentration and low pressure ratio).
Good pre-treatment.
Poor economies of scale.
Multiple stages and recycle streams may be
required.
Source: DOE, “Carbon Dioxide Capture.”
Despite these issues, there are strong proponents of membranes for post-combustion CO2 capture.
For example, Favre (2007) asserts that many of the challenges for membrane technology are
amenable to engineering solutions. He also notes that membranes could be more competitive with
amines in applications with higher CO2 concentrations, such as in the cement and steel industries.
A power plant boiler fired by oxygen-enriched air also would increase the CO2 concentration of
the flue gas, making membrane-based separation more competitive.64
Conceptual Design Stage
This stage of development typically involves engineering analyses or computer-based modeling
studies of novel capture technology concepts or systems whose fundamental principles are
usually well understood, but that lack the experimental data needed to test or verify the merits of
the idea. This section briefly discusses three classes of novel but untested approaches to carbon
capture: novel sorbents, hybrid systems, and novel regeneration methods.
Novel Sorbents
A number of research groups are investigating the development of ultra-high surface area porous
materials for CO2 capture. These materials are known as metal organic frameworks (MOFs,
discussed earlier), zeolytic imidizolate frameworks, and porous organic polymers. These
62 Clean Air Task Force, “Coal without Carbon.”
63 C. E. Powell and G. G. Qiao, “Polymeric CO2/N2 Gas Separation Membranes for the Capture of Carbon Dioxide
from Power Plant Flue Gases,” Journal of Membrane Science, vol. 279 (2006), pp. 1-49.
64 Favre, “Biogas, Membranes.”
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Carbon Capture: A Technology Assessment
materials have pore sizes, surface areas, and chemistries that are highly “tunable,” meaning that
molecules can, in principle, be designed and fabricated by chemists and materials scientists to
maximize CO2 capture performance. Because CO2 capture research in this area is relatively new,
very little work has yet been done to assess these materials under realistic capture conditions or to
incorporate them into workable capture technologies.
Hybrid Capture Systems
Hybrid approaches to new solvents and sorbents attempt to combine the best features of two or
more components to mitigate the undesirable properties of one component. For example, a typical
problem with some CO2 capture solvents is that they become highly viscous when interacting
with CO2. Hybrid approaches to solving this problem are to support the solvent on either a
membrane or a solid sorbent. In these cases, viscosity is no longer an issue since no liquids are
flowing.
For solid sorbents, one of the key problems is how to get heat into the sorbent during
regeneration, since heat transfer in gas-solid systems is not as efficient as in liquid systems. One
proposed solution is to immobilize the sorbents on a membrane or other solid support material
that allows heat to be transferred more efficiently between two solids in direct contact.
Some examples of these hybrid approaches have advanced to the laboratory or bench scale, while
others are being studied at the concept stage. It is uncertain, however, how the cost of these
systems will compare to that of a single-component system whose active capture agent is now
“diluted” by the other component. In general, one expects that the capital cost will be higher for a
hybrid system, so its CO2 capture performance must be substantially improved to offset the cost.
Novel Regeneration Methods
The two most common ways of regenerating CO2 capture solvents or sorbents are application of
heat (temperature swing) or a vacuum (pressure swing), both of which are energy-intensive and
costly. Researchers are examining alternative approaches that could be more efficient and less
costly.
One alternative (and theoretically more efficient) approach to regeneration is based in
electrochemistry. A flow of electrons (electricity) is used to facilitate both the capture and
regeneration steps. Of the several concepts that have been studied, the most promising applies
electrochemistry to carbonate materials to make separate acid and base solutions (so-called pH
swing systems), with one solution used as a solvent to capture CO2 and the other used to
regenerate the solvent.65 This technology is similar to a fuel cell in that it requires electrodes and
specialized membranes to selectively separate particular species, such as protons and hydroxide
ions. Figure 17 illustrates one of the conceptual designs.
65 M. D. Eisaman, “CO2 concentration using bipolar membrane electrodialysis,” Proc. Gordon Research Conference on
Electrochemistry, 2010.
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Carbon Capture: A Technology Assessment
Figure 17. Schematic of a Process Concept Using Electrodialysis to Capture
and Regenerate CO2, While Generating Hydrogen and Oxygen as By-Products
Clean
Re
R cove
cov red (l
red e
(l a
e n)
n) s
olven
lv t
en
Flue Gas
(mainl
ain y N2
y N )
2
CO
O
2
H
O2
2
2
(to storage)
(b
( y
b produc
p
t)
(byp
(by roduc
p
t)
)
K+
K
CO
+
K+
+
K
2
-
H+
OH-
H
OH-
HCO -
scrubber
scru
HCO
scrubber
scru
3
H+
H
OH-
OH
CO -r
- ich solve
lv n
e t
Electrodia
Electr
l
odia ys
y is
t
2
So
S lv
l ent Recov
v
er
ent Recov y
CO - laden
2
Flue Gas
Fl
Source: Edward S. Rubin, Aaron Marks, Hari Mantripragada, Peter Versteeg, and John Kitchin, Carnegie Mel on
University, Department of Engineering and Public Policy.
There are two variations of the pH swing concept, electrolysis and electrodialysis. The energy
required for electrolysis is high and similar to that required for electrolysis of water. However,
besides capturing CO2 the process also generates hydrogen and oxygen, which have additional
economic value. Electrodialysis is a more efficient process, but no valuable gases such as
hydrogen are produced. Electrodialysis has been used commercially to desalinate water, but is
only just being studied for application to CO2 capture.66
A third electrochemical approach employs membranes to separate gases such as hydrogen,
oxygen and CO2. This approach is theoretically the most efficient, but high efficiencies have not
been obtained in practice due to the limitations of existing materials.67 While the fundamentals of
electrochemical approaches to CO2 capture have been proven at the bench scale, complete
process designs are still only conceptual at this time.
Other concepts for regenerating CO2 sorbents or solvents employ photochemical processes or
electromagnetic radiation such as microwave heating.68 At this point, however, it is unlikely that
such approaches will soon (if ever) move out of the conceptual stage because of either technical
or economic limitations.
66 Advanced Research Projects Agency—Energy, “Energy Efficient Capture of CO2 from Coal Flue Gas,” at
http://arpae.energy.gov/LinkClick.aspx?fileticket=CoktKdXJd6U%3d&tabid=90.
67 H. W. Pennline et al., “Separation of CO2 from flue gas using electrochemical cells,” Fuel, vol. 89 (2010), pp. 1307-
1314.
68 Advanced Research Projects Agency—Energy, “ARPA-E’s 37 Projects Selected from Funding Opportunity
Announcement #1,” http://arpa-e.energy.gov/LinkClick.aspx?fileticket=b-7jzmW97W0%3d&tabid=90.
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System Studies
In addition to component-level studies of advanced CO2 capture technologies, a variety of
systems studies have been undertaken to analyze ways of improving the overall efficiency of
power plants with CCS. One of the most promising methods is improved heat integration between
the power plant and the CO2 capture unit.69 As noted in “Chapter 3: Overview of CO2 Capture
Technologies,” measures that increase plant efficiency can also reduce the cost of CO2 capture,
provided that they do not introduce new costs that offset the efficiency benefits. Implementation
of such measures must await the construction of large-scale demonstration plants or fully
integrated pilot plants where the feasibility of such designs can be evaluated in greater detail.
Conclusion
This chapter has reviewed and summarized the major R&D activities aimed at reducing the cost
of post-combustion CO2 capture. While such activities have increased substantially in recent
years, most current efforts are still at the early stages of technology development. This is seen
clearly in Figure 18, which shows the results of a study by the Electric Power Research Institute
that reviewed over 100 active projects in this field and ranked them on the TRL scale described
earlier in “Chapter 4: Stages of Technology Development.”70 That study found that all but a few
of the post-combustion capture projects were between TRLs 1 and 5, which corresponds to the
conceptual design and laboratory-bench scale categories used in this report. Only a small number
of projects were ranked at TRL 6, corresponding to the pilot plant stage in this report.
Figure 18. Technical Readiness Levels (TRLs) of Projects Developing Post-
Combustion Capture Technologies Using Different Approaches
Source: Bhown and Freeman, “Assessment Post-Combustion.”
Notes: The y-axis is not scaled explicitly but corresponds to the relative number of processes of a given type.
Also, the approach labeled “Mineralization & Bio” is considered in the present report to be a sequestration
method rather than a post-combustion capture method since it typical y requires a stream of concentrated CO2
that has already been captured.
69 David C. Thomas, ed., The CO2 Capture and Storage Project (CCP) for Carbon Dioxide Storage in Deep Geologic
Formations for Climate Change Mitigation, Volume 1—Capture and Separation of Carbon Dioxide from Combustion
Sources (London: Elsevier, 2004); Rubin, ‘Cost and Performance.’
70 Bhown and Freeman, “Assessment Post-Combustion.”
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The EPRI study also shows that most of the new processes under development employ absorption
methods (i.e., solvents) for post-combustion capture of CO2. Fewer new processes and concepts
utilize membranes or solid sorbents (adsorption) for CO2 capture—a reflection of the greater
challenges facing those approaches.
Key questions that remain are: What are the prospects for any of these projects to result in a
viable new process for CO2 capture? How much improvement in performance or reduction in cost
can be expected relative to current or near-term options? How long will it take to see these
improvements? Such questions are addressed later in “Chapter 7: Status of Oxy-Combustion
Capture” and “Chapter 8: Cost and Deployment Outlook for Advanced Capture Systems,”
following a status report on the two other major approaches to CO2 capture.
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Chapter 6: Status of Pre-Combustion Capture
Introduction
This chapter summarizes the status of current and emerging pre-combustion CO2 capture
technologies at various stages of development. Pre-combustion CO2 capture can be used both in
power plants and in other industrial processes where CO2 separation is required, such as in
synthetic fuels production. The more advanced capture systems include chemical solvents such as
SelexolTM and Rectisol®, which are used widely in natural gas and synthesis gas applications.
Processes at the earliest stages of development employ novel methods such as solid sorbents or
membranes for CO2 capture. The chapter begins with a discussion of commercial processes and
then describes technologies at the less advanced stages of development outlined in “Chapter 4:
Stages of Technology Development.”
As noted previously, carbon capture research and development programs throughout the world
have expanded rapidly in recent years; thus any summary of “current” activities and projects soon
grows out of date. For this reason, there is no attempt in this report to be comprehensive in the
coverage of capture-related R&D activities. Rather, this report attempts to synthesize key findings
from our own investigations and from the work of others who also track and report on the status
of CO2 capture technology developments. This report draws too upon a set of publicly available
databases and CCS project status reports maintained by the U.S. Department of Energy (DOE),
the International Energy Agency’s Greenhouse Gas Control Programme (IEAGHG), the
Massachusetts Institute of Technology carbon sequestration program (MIT), and the Global
Carbon Capture and Storage Institute (GCCSI).
In each of the sections below, the objective is to summarize not only the current status of
technological developments (as of March 2010), but also the key technical barriers that must be
overcome to advance pre-combustion capture methods, along with the potential payoffs in terms
of improved performance and/or reduced costs. Brief descriptions of new capture methods or
processes not previously discussed in “Chapter 3: Overview of CO2 Capture Technologies” also
are provided.
Commercial Processes
Currently there are no commercial applications of pre-combustion CO2 capture at electric power
plants. However, the SelexolTM and Rectisol® processes that would be used in an IGCC power
plant are already widely used in other commercial applications, mainly for removing
contaminants such as sulfur and nitrogen compounds from syngas mixtures, as well as for
capturing CO2 present in syngas. Two examples are cited here to illustrate the scale at which pre-
combustion capture technologies are currently used commercially.
The Farmlands chemical plant in Coffeyville, Kansas, shown in Figure 19, uses the Selexol
system to separate and capture CO2 from a hydrogen-CO2 gas mixture produced by the
gasification of petroleum coke (petcoke) followed by a water-gas shift reactor—the same
processes depicted earlier in Figure 6 for an IGCC with pre-combustion CO2 capture. At the
Coffeyville plant, more than 93% of the CO2 is captured, amounting to about 0.2 million tons of
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CO2 per year.71 A portion of this CO2 is used to manufacture urea and the remainder is vented to
the atmosphere. The separated stream of nearly pure hydrogen is used to manufacture ammonia
(rather than burned to generate electricity, as in an IGCC plant), with the ammonia subsequently
used to produce fertilizers. This project has been in operation since 2000 and is similar to other
industrial applications that use the Selexol process for CO2 capture.
The Great Plains synfuels plant in North Dakota operated by the Dakota Gasification Company,
also shown in Figure 19, employs coal gasification to produce synthetic natural gas. In that
process, the plant captures approximately 3 million tons/year of CO2 using the methanol-based
Rectisol process. Previously, the CO2 was vented to the atmosphere. Now the CO2 is compressed
and transported via a 205-mile pipeline to a Canadian oil field, where it is used for EOR and
sequestered in the depleted oil reservoir.
Figure 19. A Pre-Combustion CO2 Capture System Is Used to Produce Hydrogen
from Gasified Petcoke at the Farmlands Plant in Kansas (left) and Synthetic Natural
Gas from Coal at the Dakota Gasification Plant in North Dakota (right)
Source: Photos courtesy of UOP and IPCC.
These two examples illustrate current commercial applications of pre-combustion CO2 capture
technologies that would be employed at gasification-based power plants. The choice of solvent or
process would depend on the conditions of a particular project or application. The following
section discusses current plans for full-scale demonstrations of pre-combustion capture at power
plants.
Full-Scale Demonstration Plants
As with post-combustion capture, to date there have been no full-scale demonstrations of pre-
combustion CO2 capture at an IGCC power plant, although a number of full-scale projects have
been announced and one (in China) is currently under construction. Several other previously
announced IGCC-CCS projects in different parts of the world have been canceled or delayed in
71 D. Heaven et al., “Synthesis Gas Purification in Gasification to Ammonia/Urea Plants,” Gasification Technologies
Conference, October, 2004, Washington, DC, Gasification Technologies Council, San Francisco, CA.
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recent years, including the highly publicized FutureGen project proposed for construction in
Mattoon, Illinois. The fate of this jointly funded government-industry venture is still being
negotiated as of this writing.72 Nevertheless, it appears reasonable that at least some of the large-
scale projects currently planned for pre-combustion CO2 capture in the United States and other
countries will indeed materialize over the next several years, with costs shared between the public
and private sectors.
Table 12 lists the features and locations of major announced demonstration of pre-combustion
CO2 capture. They include fuels production plants and IGCC power plants.
Table 12. Planned Demonstration Projects with Full-Scale Pre-Combustion Capture
Expected
CO2
Annual CO2
Plant and
Year of
Plant Size or Capture
Captured
Project Name and Location Fuel Type
Startup
Capacity
System
(106 tonnes)
United States
Baard Energy Clean Fuels
Coal+biomass
2013 53,000
Rectisol N/A
(Wellsville, Ohio)
to liquids
barrels/day
DKRW Energy (Medicine Bow,
Coal to liquids
2014
20,000
Selexol N/A
Wyoming)
barrels/day
Summit Power (Penwell, Texas)
Coal IGCC
2014
400 MWg Selexol
3.0
Taylorvil e Energy Center
Coal IGCC
2014
602 MW
N/A
N/A
(Taylorville, Illinois)
Mississippi Power, Kemper
Lignite IGCC
2014
584 MW
N/A
N/A
County IGCC (Mississippi)
Wallula IGCC (Walla Walla
Coal IGCC
2014
600-700 MW
N/A
N/A
County, Washington)
Hydrogen Energy
Petcoke IGCC
2015
250 MW
N/A
N/A
(Kern County, California)
Southern California Edison
Coal IGCC
2017
500 MW
Selexol
3.5
IGCC (Utah)
FutureGen Alliance
Coal IGCC
>2012a
275 MW
N/A
N/A
(Mattoon, Illinois)a
Outside the United States
GreenGen (Tianji Binhai, China)
Coal IGCC and
2011
250 MW
N/A
N/A
poly-generation
(stage I)
Eston Grange IGCC
Coal IGCC
2012
800 MW
N/A
5
(Teesside, UK)
Hartfield IGCC (Hartfield, UK)
Coal IGCC
2014
900 MW
Selexol
4.5
Genesee IGCC
Coal IGCC
2015
270 MW
N/A
1.2
(Edmonton, Canada)
RWE Goldenbergwerk
Lignite IGCC
2015b 360
MW N/A
2.3
(Hurth, Germany)
72 Air Products, “Air Products and EPRI Working Together on ITM Oxygen Technology for Use in Advanced Clean
Power Generation Systems,” at http://www.airproducts.com.
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Expected
CO2
Annual CO2
Plant and
Year of
Plant Size or Capture
Captured
Project Name and Location Fuel Type
Startup
Capacity
System
(106 tonnes)
Kedzierzyn Zero Emission
Coal-biomass
2015 309
MW N/A
2.4
Power and Chemicals (Opole,
IGCC and
Poland)
polygen
Nuon Magnumc
Multi-fuel IGCC
2015
1200 MWg N/A
N/A
(Eeemshaven, Netherlands)
ZeroGen (Rockhampton,
Coal IGCC
2015
530 MWg MHI
N/A
Australia)
FuturGas (Kingston, Australia)
Lignite to liquids
2016
10,000
N/A 1.6
barrels/day
Sources: DOE, “NETL Carbon”; IEAGHG, “CO2 Capture”; MIT, “Carbon Capture”; GCCSI, “Strategic
Analysis.”
Note: MW = net electrical megawatts output; MWg = gross electrical megawatts output.
a. Final decision still pending as of May 2010.
b. Depends on outcome of the Carbon Storage Law.
c. Depends on performance of the Buggenum pilot plant (see Table 13).
Most of the projects in Table 12 would not begin operation until 2014 or later. In most cases the
captured CO2 would be sequestered in a depleted oil reservoir in conjunction with EOR. The
percentage of CO2 captured varies widely across the projects, from 50% to 90% of the carbon in
the feedstock. Table 12 shows that Selexol is the preferred technology for pre-combustion
capture at projects that have announced their selection. However, for most of the projects listed
the choice of solvent or capture technology is not yet known. China’s GreenGen project is on
track to become the first full-scale IGCC plant with CO2 capture to become operational, with
construction begun in 2009. Construction has not yet started on any of the other proposed
projects.
Given the extensive commercial experience and scale of CO2 capture in industrial processes with
gas streams nearly identical to an IGCC plant, most of the large-scale projects in Table 12 will
serve to demonstrate other aspects of IGCC technology. In particular, the reliability of gasifier
operations and the large-scale use of hydrogen to power the gas turbine following CO2 capture are
key technical issues that remain to be demonstrated in the electric utility environment. The plant
startup schedules in Table 12 indicate that it will be at least five years before significant
operational data begins to accrue at most of the planned demonstration projects. As before, the
possibility also remains that some of these planned projects may not materialize for economic or
other reasons.
Pilot Plant Projects
In general there is relatively little current development of pre-combustion CO2 capture at the pilot
plant scale. However, two projects under construction at IGCC plants in Europe—Nuon’s
Buggenum plant in the Netherlands and Elcogas’s Puertollano plant in Spain—are significant
developments because they will be the first applications of CO2 capture at operating IGCC
facilities, albeit at a small scale treating only a portion of the syngas stream. These projects are
expected to begin operation in the late 2010 and 2011 time frames, as shown in Table 13.
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Table 13. Pilot Plant Projects for Pre-Combustion CO2 Capture
at IGCC Power Plants
Expected
Annual CO2
Project Name
Plant and
Year of
Plant Size
CO2 Capture
Captured (106
and Location
Fuel Type Startup
or Capacity
System
tonnes)
Nuon Buggenum
Coal and
2010 N/A
Different
physical 0.010
(Buggenum,
biomass
and chemical
Netherlands)
IGCC
solvents
Elcogas Puertol ano
Coal and
2011 14
MWth
Different
0.035
(Puertol ano, Spain)
petcoke
(~5 MW)
commercial
IGCC
solvents
Sources: DOE, “NETL Carbon”; IEAGHG, “CO2 Capture”; MIT, “Carbon Capture”; GCCSI, “Strategic
Analysis.”
Note: MW = net electrical megawatts output; MWth = gross thermal energy input (megawatts).
The Nuon Buggenum project is aimed at testing pre-combustion CO2 capture in order to better
select, design, and optimize a capture system after some operating experience is gained. Both the
water gas shift reactors and the CO2 capture process will be optimized for their performance
efficiency and different physical and chemical solvents will be tested. The main aim of this pilot
plant is to gain operational experience that can be used at the much bigger Nuon Magnum IGCC
power plant listed in Table 12.73
Laboratory- or Bench-Scale Developments
Although pre-combustion CO2 capture has a lower energy penalty and lower cost than post-
combustion capture processes performing similar duty, there is scope for further improvements
that can reduce costs. With this aim, current research is focused mainly on improving the capture
efficiency so that the size and cost of equipment can be lowered. Current research is focused on
the same three approaches discussed in “Chapter 5: Status of Post-Combustion Capture” for post-
combustion capture technologies, namely, liquid solvents, which separate CO2 from a gas stream
by absorption; solid sorbents, which separate CO2 from by adsorption onto the solid surface; and
membranes, which separate CO2 by selective permeation through thin layers of solid materials.
Solvent-Based Capture Processes
As noted previously, current pre-combustion CO2 capture systems employ solvents that
selectively absorb CO2 (and other acid gases) from a gas stream via the mechanism of physical
absorption into the solvent. Physical absorption is characterized by weak binding forces between
gas molecules and the solvent molecules. Research on physical solvents is aimed at improving the
CO2 carrying capacity and reducing the heat of absorption. Higher carrying capacity means that
more CO2 is captured in every pass through the absorption tower, thus lowering costs. Solvents
with a low heat of absorption require less energy to strip CO2 during the regeneration step, which
also lowers cost. Of the two properties, the main focus is on improving the CO2 carrying capacity,
since the heat of absorption already is low for most physical solvents (which is also why a
73 Nuon, “Towards 2nd Generation IGCC Plants, Nuon Magnum Multi-Fuel Power Plant,” Proc. Future of Coal and
Biomass in a Carbon-Constrained World, November 2, 2009, Fargo, ND.
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pressure-swing method can be used to strip captured CO2 from the solvent, unlike chemical
solvents, where heat is needed).
The CO2 carrying capacity of a solvent depends on a number of factors, including certain
properties of the solvent, the partial pressure of CO2 in the gas stream, and the temperature of the
process. Usually, the carrying capacity increases at higher pressure and lower temperature. A
practical problem with liquid solvents is their ability to corrode equipment materials. Any novel
solvent must therefore have low corrosive properties. Table 14 summarizes the advantages of
physical solvents and the challenges in improving their properties.
Table 14. Key Advantages and Challenges of Physical Solvents for
Pre-Combustion CO2 Capture
Description Advantages
Challenges
Solvent readily dissolves CO2. Solubility is
CO2 recovery does not require
CO2 pressure is lost during flash
directly proportional to CO2 partial
heat to reverse a chemical reaction.
recovery.
pressure and inversely proportional to
temperature, making physical solvents
Common for same solvent to have
Must cool synthesis gas for CO2
more applicable to low temperature, high
high H2S solubility, al owing for
capture, then heat and humidify
pressure applications (cooled syngas).
combined CO2/H2S removal.
again for firing in gas turbine.
Regeneration normal y occurs by pressure System concepts that recover CO2
Low solubility can require
swing.
with some steam stripping rather
circulating large volumes of
than flashed, with delivery at a
solvent, which increases energy
higher pressure, may optimize
needs for pumping.
processes for power systems.
Some H2 may be lost with the
captured CO2.
Source: DOE, “Carbon Dioxide Capture.”
Current research on new or improved solvents for pre-combustion capture seeks to develop
solvents that allow CO2 to be captured at higher pressures and temperatures. Currently, syngas
from the gasifier must be cooled to near room temperature before entering the solvent-based CO2
capture unit. After capture, the syngas must be reheated to prepare it for downstream processes.
New solvents that can capture CO2 at higher temperatures can therefore increase overall plant
efficiency and potentially reduce the equipment needs and cost of CO2 capture. In this context,
ionic liquids, discussed earlier in “Chapter 5: Status of Post-Combustion Capture,” are also being
studied as potential solvents for CO2 capture in pre-combustion applications.
As also noted in “Chapter 5: Status of Post-Combustion Capture,” ionic liquids are salts that are
liquid at room temperature. They have high CO2 absorption potential and do not evaporate at
temperatures as high as 250oC. In an IGCC system, this could allow separation of CO2 without
cooling the syngas, thereby reducing equipment size and cost. This is also one of the approaches
being pursued to develop new physical absorption solvents for pre-combustion capture.74
Sorbent-Based Capture Processes
Solid sorbents are another class of material that potentially could be used for pre-combustion CO2
capture as well as for post-combustion capture (see “Chapter 5: Status of Post-Combustion
74 DOE, “Carbon Dioxide Capture.”
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Capture”). The primary advantage of solid sorbent systems over solvents in pre-combustion
applications is their ability to operate at high temperatures. This avoids the additional equipment
for syngas cooling, thus reducing cost. However, the handling of solids is generally more difficult
than the handling of liquid-based systems. This offsets some of the advantages of solids and can
be an important factor in the choice (and overall cost) between solvent and sorbent-based capture
technology in large-scale applications.
Solid sorbent-based systems are used commercially today in a variety of applications, such as in
hydrogen purification processes employing pressure swing adsorption. With some changes, that
system has the scope to be adapted to capture CO2. Lehigh University, RTI International, TDA
Research, the University of North Dakota Energy & Environmental Research Center, and the
URS Group are among the organizations currently working on development of solid sorbents.75
The work is primarily focused on identifying the most promising sorbent materials and
conducting bench-scale experiments. Table 15 summarizes the key advantages and challenges of
using solid sorbents for pre-combustion CO2 capture.
Table 15. Key Advantages and Challenges of Solid Sorbents for
Pre-Combustion CO2 Capture
Description Advantages
Challenges
When sorbent pel ets are contacted with
CO2 recovery does not require heat to Solids handling is more
syngas, CO2 is physically adsorbed onto
reverse a reaction.
difficult than liquid-gas
sites and/or dissolves into the pore
systems.
structure of the solid. Rate and capacity
Common for H2S to also have high
are directly proportional to CO
solubility in the same sorbent, meaning
CO2 capture with sorbents is
2 partial
pressure, making these sorbents more
CO2 and H2S capture can be combined. a novel concept though other
applicable to high pressure applications.
gas purification processes use
System concepts in which CO2 is
Regeneration normal y occurs by pressure
adsorption techniques.
recovered with some steam stripping
swing.
rather than flashed and delivered at a
higher pressure may optimize
processes for power systems.
Source: DOE, ‘Carbon Dioxide Capture.’
Membrane-Based Capture Processes
As described in “Chapter 5: Status of Post-Combustion Capture,” membrane-based capture
processes operate by selectively allowing a gas to permeate through the membrane material.
Membranes for CO2 capture are made of micro-porous metallic, polymeric, or ceramic materials.
For effective CO2 capture in pre-combustion applications, they should not only have high
permeability and selectivity to CO2 but also be able to operate at the high pressures and
temperatures characteristic of IGCC systems.
Figure 20 shows a schematic of a membrane separation process for CO2 capture in an IGCC
application, where CO2 is preferentially separated from hydrogen in the gas stream following the
water-gas shift and sulfur removal steps illustrated earlier in Figure 6. Because the separation is
seldom perfect, several stages are typically needed to increase the purity of the separated
components.
75 DOE, ‘Carbon Dioxide Capture.’
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Figure 20. Schematic of Pre-Combustion CO2 Capture Using a Membrane
to Separate CO2 and H2 in the Gas Stream of an IGCC Power Plant
Source: DOE, “Carbon Dioxide Capture.”
To date, membrane technology has been used commercially for gas purification and CO2 removal
in the production of hydrogen, but it has not been used specifically for pre-combustion CO2
capture in IGCC plants or related industrial processes that require a high CO2 recovery rate with
high CO2 purity. Applications to IGCC are of interest since the mixture of CO2 and H2 following
the shift reactor is already at high pressure, unlike post-combustion applications, which require
additional energy to create a pressure differential across the membrane.
Table 16 summarizes the key advantages and challenges of membrane separation systems for pre-
combustion capture applications. Many of the challenges discussed earlier for post-combustion
applications also apply here, such as limited temperature ranges for operation and low tolerance
to impurities. Because of their modular nature and the need for relatively large surface areas,
membrane systems again do not have the economies of scale with plant size found in other types
of capture systems. Thus, they must have substantially superior performance and/or lower unit
cost to compensate for this disadvantage. These are the major hurdles that current research is
attempting to overcome.
Table 16. Key Advantages and Challenges of Membrane Separation Systems for
Pre-Combustion CO2 Capture
Membrane Description Advantages
Challenges
Type
H2-CO2
A membrane material
H2 or CO2 Permeable
Membrane separation of H2 and CO2
membranes which selectively allows
Membrane:
is more challenging than the
either H2 or CO2 to
No steam load or chemical
difference in molecular weights
permeate through the
losses.
implies.
material; potential use in
gasification processes with
H2 Permeable Membrane Only:
Due to decreasing partial pressure
streams of concentrated
Can deliver CO2 at high-
differentials, some H2 will be lost
H
pressure, greatly reducing
with the CO2.
2 and CO2.
compression costs.
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Membrane Description Advantages
Challenges
Type
H2 permeation can drive the
In H2-selective membranes, H2
CO shift reaction toward
compression is required and offsets
completion, potentially
the gains of delivering CO2 at
achieving the shift at lower
pressure. In CO2 selective
cost/higher temperatures.
membranes, CO2 is generated at low
pressure, thus requiring added
compression.
Membrane-
Flue gas is contacted with
The membrane shields the
Capital cost associated with the
Liquid
a membrane and a solvent
solvent from flue gas
membrane.
Solvent
on the permeate side
contaminants, reducing losses
Hybrids
absorbs CO
Membranes may not keep out al
2 and creates a
and allowing higher loading
partial pressure differential differentials between lean and
unwanted contaminants.
to draw CO2 across the
rich solvent streams.
Does not address CO2 compression
membrane.
costs.
Source: DOE, “Carbon Dioxide Capture.”
Enhanced Water Gas Shift Reactors
As noted in “Chapter 3: Overview of CO2 Capture Technologies,” in an IGCC plant with CCS,
the syngas exiting the gasifier is subjected to a water-gas shift (WGS) reaction to increase the
concentration of CO2 in the gas stream. This process is needed for efficient CO2 capture in a
subsequent step. It also provides additional hydrogen (H2) for power generation. The WGS
reaction between carbon monoxide (CO) in the syngas and steam (H2O) that is added is:
CO + H2O Ù CO2 + H2
The thermodynamics of chemical reactions dictates that the speed and efficiency of this reaction
is limited by the presence of the reaction products (CO2 and H2) in the reactor vessel. Thus, to get
high conversion efficiency of CO to CO2, a catalyst is used and the WGS reaction is
accomplished in two stages (and two vessels), with intermittent cooling of the syngas to help
speed the reaction. This additional equipment and the associated energy penalty of the WGS
process add to the cost of CO2 capture.
To reduce this cost, researchers are developing sorbents and membranes that can be used within a
WGS reactor so that the shift reaction occurs with simultaneous capture of CO2. Thus, in a
sorbent-enhanced water gas shift, the WGS catalyst is mixed with a CO2 capture sorbent in a
single reactor vessel. The sorbent removes CO2 as soon as it is formed, which allows increased
conversion of CO to CO2. In this way, CO2 capture is achieved simultaneously with an efficient
WGS reaction, which can lower the overall capital cost of the system.76 As with other sorbent-
based capture schemes, however, the development of enhanced WGS reactors also requires a
practical method of handling and regenerating the solid sorbent materials. This too is a topic of
ongoing research.
A similar concept for simultaneous WGS and CO2 capture employs a membrane reactor in which
either CO2 or H2 is separated as soon as it is formed. Again, the removal of reaction products
76 Van Dijk et al., “Performance of water-gas shift catalysts under sorption-enhanced water-gas shift conditions,”
Energy Procedia, vol. 1 (2009), pp. 639-646.
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improves the effectiveness and speed of the WGS reaction. The possibility of using liquid
solvents together with membranes also is being studied as a means of increasing the overall
capture efficiency.77
Conceptual Design Stage
At the conceptual design stage, most of the work related to pre-combustion capture is focused on
improving the efficiency of the overall power plant, which in turn lowers the cost of CO2 capture
(see “Chapter 3: Overview of CO2 Capture Technologies”). Thus, improvements in all major
IGCC system components—especially the air separation unit (ASU), gasifier and gas turbine—
also are of interest for CO2 capture. So too are studies of improved heat integration to reduce
energy losses; advanced plant designs that integrate components such as the ASU and gas turbine
air compressor; gasifier improvements that increase plant utilization; and advanced design
concepts such as an IGCC system coupled with a solid oxide fuel cell. Examples of such studies
can be found in several recent studies.78
Figure 21 shows an example of the cost reductions projected by the U.S. Department of Energy
for conceptual designs of IGGC systems employing a variety of advanced technologies. These
advances also would reduce the incremental cost of CO2 capture. Substantial R&D efforts would
be needed, however, to bring such designs to commercial reality.
Figure 21. Projected Cost Reductions for IGCC Systems
Employing Advanced Technologies
Source: Klara and Plunkett, “Potential Advanced.”
Notes: These improvements also reduce the cost of CO2 capture. Terms not defined previously: CF = capacity
factor; WGCU = warm gas cleanup; AHT = advanced hydrogen-fired turbines (designs 1 and 2); ITM = ion
transport membrane (for O2 production); SOFC = solid oxide fuel cell (integrated with gasifier).
77 DOE, “Carbon Dioxide Capture.”
78 Chen and Rubin, ‘CO2 Control Technology.’ J. M. Klara and J. E. Plunkett, “The potential of advanced technologies
to reduce carbon capture costs in future IGCC power plants,” International Journal of Greenhouse Gas Control,
Special Issue, Elsevier, March 2010.
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Conclusion
This chapter has reviewed and summarized the major research and development activities aimed
at reducing the cost of pre-combustion CO2 capture. Many of these activities are similar in nature
to those for post-combustion capture insofar as they involve the same basic concepts for new or
improved capture processes. Improvements also are being sought in a variety of other IGCC plant
components that also affect CO2 capture costs, such as the air separation unit, gasifier, water-gas
shift reactor, and gas turbines. At the conceptual level, advanced plant designs employing new
plant integration concepts and advanced technologies such as solid oxide fuel cells also are being
actively investigated. The most promising concepts, however, are likely to be decades away from
commercial reality.
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Chapter 7: Status of Oxy-Combustion Capture
Introduction
In contrast to post-combustion and pre-combustion CO2 capture technologies, which are
commercial and widely used in a variety of industrial applications, oxy-combustion capture is a
potential option that is still under development and not yet commercial. This chapter summarizes
the current status of oxy-combustion CO2 capture technology. The chapter again utilizes publicly
available databases and project status reports maintained by the U.S. Department of Energy
(DOE), the International Energy Agency’s Greenhouse Gas Control Programme (IEAGHG), the
Massachusetts Institute of Technology carbon sequestration program (MIT), and the Global
Carbon Capture and Storage Institute (GCCSI).
In each of the sections below, the objective is to summarize not only the current status of
technological developments (as of March 2010), but also the key technical barriers that must be
overcome to advance oxy-combustion capture and the potential payoffs in terms of improved
capture efficiency and/or reduced capture costs. Brief descriptions of new capture methods or
processes not previously discussed in “Chapter 3: Overview of CO2 Capture Technologies” also
are provided.
Commercial Processes
As noted above, there are currently no oxy-combustion carbon capture systems in commercial
operation. However, the critical technology of oxygen production is mature and widely used in a
variety of industrial settings. The combustion of oxygen in furnaces also is practiced in industries
such as glass manufacturing.
Most commercial air separation units (ASUs) employ a low-temperature cryogenic process to
separate oxygen from other constituents of air (principally nitrogen and argon). The process can
be scaled up or deployed in multiple trains to deliver the quantities of oxygen required for a
typical coal-fired power plant. A key drawback of current ASU technology, however, is its high
energy requirements, which increase with the level of oxygen purity.79 For a typical oxyfuel plant
design with 95% oxygen purity, Table 3 earlier showed that the energy penalty for oxygen
production is comparable to the penalty for amine solvent regeneration in post-combustion
capture systems. Thus, for oxy-combustion carbon capture to be more economical, air separation
methods are needed that are less energy-intensive than current cryogenic systems.
Full-Scale Demonstration Plants
As with post- and pre-combustion capture, to date there have been no full-scale demonstrations of
oxy-combustion CO2 capture at a power plant, nor were any oxyfuel projects selected for U.S.
government support under the recent (2009) DOE Clean Coal Technology Initiatives program. A
planned oxy-combustion demonstration project at a Canadian power plant also was canceled in
recent years due to escalating construction costs. However, several full-scale oxy-combustion
79 E. S. Rubin et al., “Estimating Future Trends in the Cost of CO2 Capture Technologies,” Report No. 2006/5, IEA
Greenhouse Gas R&D Programme, Cheltenham, UK, 2006/5, January 2006.
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demonstrations are still being planned outside the United States (Table 17), with costs to be
shared between the public and private sectors. It is thus expected (but not certain) that one or
more large-scale demonstrations of this technology will materialize over the next several years.
Table 17. Planned Large-Scale Demonstrations of Oxy-Combustion CO2 Capture
Plant and Expected
Annual CO2
Project Name
Fuel
Year of
Plant Size or Captured
Current Status
and Location
Type
Startup
Capacity
(106 tonnes)
(March 2010)
CS Energy
Coal boiler
2011
120 MW
N/A
Under
(Australia)
Construction
Boundary Dam
Coal boiler
2015
100 MW
1.0
Preliminary
(Canada)
Engineering
Vattenfall
Coal boiler
2015
500 MW
N/A
Feasibility Studies
Jänschwalde
(Germany)
Sources: DOE, “NETL Carbon”; IEAGHG, “CO2 Capture”; MIT, “Carbon Capture”; GCCSI, “Strategic
Analysis.”
Table 17 shows that one demonstration project now under construction in Australia could begin
operation as soon as next year, while two other projects would not begin operating until 2015.
These oxy-combustion designs would employ a conventional ASU as the oxygen source, along
with conventional flue gas cleanup systems. Potentially, a flue gas desulfurization system may be
omitted to reduce costs if it is determined that sulfur oxides can be safely co-sequestered with
CO2 without compromising either the boiler or pipeline operation.
A key test for these demonstrations will be the integration of conventional ASUs to meet the
oxygen needs of a large coal-fired boiler with substantial amounts of flue gas recirculation needed
to control furnace temperatures. Note, too, that all of the currently planned demonstration projects
are less than 200 MW in size, requiring only a single ASU train. Larger plants requiring more
than 5,000 tons per day of oxygen would need multiple ASUs, adding to the complexity and cost
of the oxygen delivery system.
Pilot Plant Projects
Table 18 lists one planned and two current pilot plants for testing oxy-combustion capture in an
integrated system design. The two European plants currently in operation each capture over 200
tons of CO2 per day. Vattenfall’s pilot plant at the Schwarze Pumpe power station in Germany
(Figure 22) is expected to provide critical performance data needed to design the planned
demonstration plant listed earlier in Table 17. The oxyfuel pilot plant operated by Total in Lacq,
France, is of comparable size to the Vattenfall unit. The third project in Table 18 would supply
CO2 for a geological storage project in California as part of DOE’s WESTCARB Regional
Partnership. One of the two candidate sources of CO2 is an oxy-combustion process currently
under development that employs a combustor based on rocket engine technology rather than a
conventional boiler system. The combustor uses a clean gaseous or liquid fuel to produce steam
and CO2 at high pressure.80 A final decision on the availability and use of this process for the
WESTCARB project is still pending as of this writing.
80 Clean Energy Systems, “Zero-Emission Power Plants (ZEPP),” Clean Energy Systems,
(continued...)
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Table 18. Pilot Plant Projects with Oxy-Combustion CO2 Capture
Expected
Annual CO2
Project Name
Plant and Fuel
Year of
Plant Size
Captured
Current Status
and Location
Type
Startup
or Capacity
(106 tonnes)
(March 2010)
Schwarze Pumpe
Coal Boiler
2008
30 MWth
0.075 Operational
(Germany)
(~10 MW)
Total Lacq
Natural Gas
2009 30
MWth
0.075 Operational
(France)
Boiler
(~10 MW)
WESTCARBa
Gaseous or
2012 ~50
MW
0.25
Preliminary
(California)
liquid fueled
Engineering
combustora
Sources: DOE, “NETL Carbon”; IEAGHG, “CO2 Capture”; MIT, “Carbon Capture”; GCCSI, “Strategic
Analysis.”
Note: MW = net electrical megawatts output; MWth = gross thermal energy input (megawatts).
a. One of two proposed CO2 sources for this project; final decision expected mid-2010.
Figure 22. Oxy-Combustion Pilot Plant Capturing CO2 from the Flue Gas of a
Coal-Fired Boiler at the Schwarze Pumpe Power Station in Germany
Source: Photo courtesy of Vattenfall.
Not included in Table 18 are other pilot-scale facilities around the world that are also used to test
various components of an oxy-combustion system, such as the 30 MWth Clean Energy
Development Facility of Babcock and Wilcox.81 Similarly, Air Products is operating a pilot plant
in Maryland that uses an experimental ion transport membrane (ITM) system for oxygen
(...continued)
http://www.cleanenergysystems.com/technology.html.
81 K. J. McCauley et al., “Commercialization of Oxy-Coal Combustion: Applying the Results of a Large 30MWth Pilot
Project,” Proc. 9th International Conference on Greenhouse Gas Control Technologies, Nov 16-20, 2008, Washington,
DC. Note: MWth = gross thermal energy input (megawatts).
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production, rather than a conventional cryogenic ASU.82 That system, depicted in Figure 23, is
one of several new technologies under development that promise to deliver lower-cost oxygen.
While not a CO2 capture technology, oxygen production is nonetheless the major cost and energy
penalty item of an oxy-combustion system. For that reason, advanced methods of oxygen
production are discussed in the following section on laboratory- and bench-scale developments.
Figure 23. The Ion Transport Membrane (ITM) Oxygen Production Technology
Being Developed by Air Products
Source: P. A. Armstrong et al., “ITM Oxygen for Gasification,” Gasification Technologies Council, Gasification
Technologies Conference, Washington, DC, October 3-6, 2004.
Laboratory- or Bench-Scale Developments
Laboratory- and bench-scale R&D related to oxy-combustion is found worldwide and is currently
focused mainly in the following areas:
• understanding oxy-combustion burner and boiler characteristics and their
interactions with the overall system;
• design of innovative oxy-combustion burners for new and retrofit applications;
• development of improved flue gas purification technologies for oxy-fired
systems;
• development of lower-cost, high-efficiency oxygen production units; and
• development of novel concepts such as chemical looping combustion.
82 Process Worldwide, “Rising Demand is Shaking up the Staid Business of Air Separation,” http://www.process-
worldwide.com/.
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Topics of study include investigations into the fundamental mechanisms that affect the
performance and design of oxygen-fired boiler systems, such as studies of oxy-combustion flame
characteristics, burner design, and fuel injection systems. Because of the high temperatures
associated with oxygen combustion, the development of advanced boiler materials is another
focus of research. In a number of areas, small-scale experiments are coupled with computational
fluid dynamic (CFD) modeling studies of oxy-combustion processes.
The development of advanced flue gas purification systems also is being pursued to find better,
lower-cost ways to remove contaminants such as sulfur oxides, nitrogen oxides, and trace
elements such mercury. The ability to remove such pollutants during the CO2 compression
process is one of the promising recently reported innovations being studied.83
There is a large body of technical literature that discusses and documents in detail the range of
laboratory- and bench-scale R&D activities and challenges in oxy-combustion CO2 capture.84 The
remainder of this section elaborates briefly on the two areas believed to offer the greatest promise
for lower-cost capture.
Advanced Oxygen Production Methods
Current commercial technology uses low-temperature (cryogenic) separation methods to produce
high-purity oxygen. An alternative that promises a lower energy penalty and lower cost is the ion
transport membranes (ITM) system mentioned earlier. Here, thin nonporous membranes are used
to separate oxygen from air at high temperature and pressure, as seen in Figure 23. As with other
membrane-based systems, the separation works on the principle of an oxygen pressure difference
on either side of the membrane. The higher the pressure difference, the better the separation. The
goal of R&D at Air Products, Inc., is to produce ITM oxygen at one-third the cost and energy
requirement of current cryogenic ASUs.85 IGCC systems and other gasification-based processes
are currently the most attractive applications for ITM oxygen, since these processes already
operate at the high pressures required by ITM technology. Oxy-combustion applications,
however, would require the development of pressurized combustion systems in order to take full
advantage of ITM oxygen production.
Unlike ITMs, which separate oxygen based on a pressure differential, the oxygen transport
membrane (OTM) concept utilizes the chemical potential of oxygen as the driving force. The
potential advantage of this approach is that it can be integrated directly into a boiler, with air on
one side of the membrane and fuel combustion on the other side. Combustion decreases the
oxygen concentration, which increases the chemical potential difference that drives O2 through
the membrane. This process is still in the early stages of development.86
83 K. White et al., “Purification of Oxyfuel-Derived CO2,” International Journal of Greenhouse Gas Control, vol. 4,
no. 2 (2010), pp. 137-142.
84 R. Allam, “Carbon Dioxide Capture Using Oxyfuel Systems,” Carbon Capture-Beyond 2020, U.S. Department of
Energy, Office of Basic Energy Research, March 4-5, 2010, Gaithersburg, MD; International Energy Agency
Greenhouse Gas R&D Programme, “Oxy-fuel Combustion Network,” at http://www.co2captureandstorage.info/
networks/oxyfuel.htm.
85 P. A. Armstrong et al., “ITM Oxygen.”
86 DOE, “Carbon Dioxide Capture.”
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Other new oxygen production methods being investigated use solid sorbents to absorb O2 from
air. The sorbent material is then transferred to another vessel where it is heated, releasing the O2.
This is fundamentally the same approach discussed in “Chapter 5: Status of Post-Combustion
Capture” and “Chapter 6: Status of Pre-Combustion Capture” for CO2 capture using solid
sorbents. For O2 production the sorbent material and process conditions are different. The process
called ceramic autothermal recovery uses the mineral perovskite. It releases heat while adsorbing
O2 from air, which potentially could be used along with heat from power plant flue gases to
reduce the overall energy penalty of oxygen production. Another sorbent being investigated is
manganese oxide, which absorbs O2 from high pressure air passed over the sorbent. This
technology is potentially easier to build and lower in cost.87 Until a larger-scale process is
developed and tested, however, cost estimates remain highly uncertain.
Chemical Looping Combustion
Another novel oxy-combustion technology being developed is called chemical looping
combustion (CLC). This is similar to the sorbent-based O2 production method discussed above.
Here, however, the O2-carrying sorbent—typically a metal oxide—is contacted with a fuel, so that
combustion occurs rather than a simple release of oxygen. The resulting exhaust stream contains
only carbon dioxide and water vapor, as in other oxy-combustion schemes. A schematic of this
concept is shown in Figure 24.
Figure 24. Schematic of a Chemical Looping Combustion System
Source: DOE, “Carbon Dioxide Capture.”
87 DOE, “Carbon Dioxide Capture.”
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Chemical looping has the potential to make carbon capture significantly cheaper than current
systems, but is still at an early stage of development, with challenges in materials handling and
oxygen carrier selection that have not yet been solved. Currently the largest chemical looping
combustor is a 120-kilowatt unit being tested in Austria.88 Projects funded by the U.S.
Department of Energy include two chemical looping tests, one by Alstom using calcium
compounds as an oxygen carrier, the other by Ohio State University using an iron oxide carrier.
Alstom currently has a 65 kW test reactor and plans to have a 3 MW pilot plant online in late
2010.89
Conceptual Design Stage
As with pre-combustion CO2 capture systems, a substantial amount of current activity on oxy-
combustion capture is still at the conceptual design stage, positing and analyzing alternative
system configurations that maximize overall efficiency and minimize estimated cost. Conceptual
designs encompass a broad range of fuels and power systems. Many of these designs include
advanced component technologies and heat integration schemes that do not currently exist, but
which illustrate the potential for process improvements.
For example, a proposed novel oxy-combustion cycle for natural gas-fired power plants combines
an oxygen transport membrane with advanced heat integration in a reactor design (Figure 25)
that theoretically achieves 85% to 100% CO2 capture with a plant efficiency much higher than a
current NGCC plant with CO2 capture.90 Other oxy-combustion designs for combined cycle
power plants utilize CO2 instead of air to generate power from advanced gas turbines, or employ
ITM technology to achieve high-efficiency power generation with high CO2 capture.91 All of
these advanced concepts, however, require the (costly) development and integration of advanced
technologies that do not yet exist and which may have only limited market potential. Thus,
despite their theoretical advantages, it appears unlikely that such concepts will advance to the
later stages of technology development any time soon.
Other conceptual designs for coal-fired power plants92 seek improved methods of heat and
process integration to improve overall plant efficiency using conventional technology for power
generation and oxygen production. More advanced concepts envision pressured combustion with
oxygen as a preferred approach for achieving high efficiency along with lower-cost CO2 capture.
These analyses based on thermodynamics and optimization methods are useful for identifying the
most promising concepts to consider for further development.
88 P. Kolbitsch et al., “Operating Experience with Chemical Looping Combustion in a 120 kW Dual Circulating
Fluidized Bed (DCFB) Unit,” Energy Procedia, vol. 1 (2009), pp. 1465 -1472.
89 H. E. Andrus et al., “Alstom’s Calcium Oxide Chemical Looping Combustion Coal Power Technology
Development” Proc. 34th International Technical Conference on Clean Coal & Fuel Systems, May 31-June 4, 2009,
Clearwater, FL.
90 R. Anantharaman, O. Bolland, and K. I. Asen, “Novel Cycles for Power Generation with CO2 Capture using OMCM
Technology,” Energy Procedia, vol. 1, no. 1 (2009), pp. 335-342.
91 Metz, “Special Report.” O. Bolland, “Outlook for Advanced Capture Technology,” presented at The 9th International
Conference on Greenhouse Gas Control Technologies, November, 16-20, 2008, Washington, DC.
92 K. E. Zanganeh and A. Shafeen, “A Novel Process Integration, Optimization and Design Approach for Large-Scale
Implementation of Oxy-Fired Coal Power Plants with CO2 Capture,” International Journal of Greenhouse Gas
Control, vol. 1 (2007), pp. 47-54l; Allam, “Oxyfuel Systems.”
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Figure 25. A Proposed Oxygen-Mixed Conduction Membrane Reactor Design for a
Natural Gas-Fired Power Plant
Source: R. Anantharaman, O. Bolland, and K. I. Asen, “Novel Cycles for Power Generation with CO2 Capture
using OMCM Technology,” Energy Procedia, vol. 1, no. 1 (2009), pp. 335-342.
Conclusion
This chapter has reviewed and summarized a range of R&D activities underway to develop oxy-
combustion CO2 capture as an alternative to post-combustion capture, especially for coal-fired
boilers. Some of these activities are similar in nature to those for post-combustion and pre-
combustion capture insofar as they involve the same basic concepts, such as the use of membrane
separation processes. In the context of oxy-combustion systems, however, the most compelling
need—and a major focus of R&D—is for improved, lower-cost processes to deliver large
quantities of high-purity oxygen, the major cost item in current oxyfuel schemes. To the extent
that oxy-combustion systems are able to transport and sequester multi-pollutant gas streams,
including pollutants like SO2 and NOx, costs can be further reduced by avoiding the need for
additional gas cleaning equipment to remove such pollutants. At the conceptual level, advanced
plant designs employing new plant integration concepts and advanced technologies such as
chemical looping combustion are also being actively investigated and many appear promising.
Because they are at the earliest stages of development, however, it remains to be seen which if
any of these concepts eventually develops into a viable commercial technology.
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Chapter 8: Cost and Deployment Outlook for
Advanced Capture Systems
Introduction
This chapter addresses two key questions not addressed in the previous chapters: (1) How much
cost reduction and performance improvement is expected from the CO2 capture technologies now
under development? and (2) When will these technologies be available for commercial use? To
address the first question, this chapter shows results from recent studies by DOE and others of
projected cost reductions for power plants with advanced capture systems. To address the second
question, this chapter presents a set of technology roadmaps and deployment scenarios developed
by governmental and private organizations involved in CO2 capture technology R&D. “Chapter 9:
Lessons from Past Experience” reviews past experience in other R&D programs to develop
advanced capture technologies for power plant emissions.
Projected Cost Reductions for CO2 Capture
Table 4 earlier summarized the range of cost estimates for power plants using current technology
for CO2 capture and storage. Other sources discuss in detail the many factors that affect such
estimates.93 In the context of the present report, it is especially important to emphasize the
uncertainty inherent in any cost estimate for a technology that has not yet been built, operated,
and replicated at a commercial scale. In general, the farther away a technology is from
commercial reality, the cheaper it tends to look. This is illustrated graphically in Figure 26, which
depicts the typical trend in cost estimates for a technology as it advances from concept to
commercial deployment.
Keeping in mind this uncertainty, this section summarizes the results of several recent studies that
estimated potential cost reductions from technology innovations both in CO2 capture processes
and in other power plant components that influence CO2 capture cost. These studies employ two
conceptually different methods of estimating future costs. The “bottom up” method uses
engineering analysis and costing to estimate the total cost of a specified advanced power plant
design. In contrast, the “top down” method uses learning curves derived from past experience
with similar technologies to estimate the future cost of a new technology based on its projected
installed capacity at some future time. The latter parameter represents the combined effect of all
factors that influence historically observed cost reductions (including R&D expenditures,
learning-by-doing, and learning-by-using).
93 Metz, “Special Report.” E. S. Rubin et al., The Effect of Government Actions on Environmental Technology
Innovation: Applications to the Integrated Assessment of Carbon Sequestration Technologies, report from Carnegie
Mellon University, Pittsburgh, PA, to U.S. Department of Energy, Germantown, MD, p. 153, January 2004.
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Carbon Capture: A Technology Assessment
Figure 26. Typical Trend in Cost Estimates for a New Technology as It Develops
from a Research Concept to Commercial Maturity
ty
aci
Cap
t of
Uni
per
l Cost
ta
pi
a
C
Researc
ar h
Devel
e opmen
opme t Demons
t
n Demonstr
t
t Demons r
trat
a ion
o
De
D pl
Depl
p
Deploy
o ment
ment
m
Mat
a ure
u
T
re T
re e
T c
e hnology
og
Time
m or
Cu
or
m
Cu u
m lativ
i e
v Capaci
Ca
t
paci y
t
Source: Adapted from S. Dalton, “CO2 Capture at Coal Fired Power Plants—Status and Outlook,” The 9th
International Conference on Greenhouse Gas Control Technologies, Washington, DC, November, 16-20, 2008.
Results from Engineering-Economic Analyses
Figure 27 shows the results of a 2006 analysis by DOE of potential advances in the major CO2
capture routes. Results are shown for pulverized coal (PC) plants and integrated gasification
combined cycle (IGCC) plants. The bars in Figure 27 show the percent increase in the total cost
of electricity (COE) compared to the same plant type without CO2 capture. As more advanced
technologies are implemented, the incremental cost is reduced significantly. On an absolute basis,
the total cost of electricity generation falls by 19% for the IGCC cases and by 28% for the PC
cases. The biggest cost reductions come in the final steps for each plant type. However, the
technologies in those cases are still in the early stages of development, including advanced solid
sorbents for CO2 capture membrane systems for water-gas shift reactors and chemical looping for
oxygen transport. As suggested earlier in Figure 26, cost estimates for these cases are the least
reliable and most likely to escalate as the technology approaches commercialization.
The 2006 DOE analysis also included four oxy-combustion cases (not shown in Figure 27) in
which the COE for an advanced system fell by 19% (from a 50% increase in COE for a current
supercritical PC plant, to a 21% increase for advanced SCPC with ITM oxygen production).
Because oxy-combustion systems are still under development and not yet demonstrated at a
commercial scale, assumed plant configurations and cost estimates for these systems are more
uncertain and variable than for current pre- and post-combustion systems. For example, while
some studies show oxy-combustion for new power plants to be somewhat lower in cost than post-
combustion capture,94 others report it to be higher in cost.95 There is general agreement, however,
that continued R&D can reduce the future cost of these systems.
94 U.S. Department of Energy, Pulverized Coal Oxycombustion Power Plants: Volume 1, Bituminous Coal to
Electricity, Report No. DOE/NETL-2007/1291, National Energy Technology Laboratory, Pittsburgh, PA, August 2008.
95 Metz, ‘Special Report.’
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Figure 27. Cost of Electricity (COE) Increases for Power Plants with CO2
Capture and Storage Using Current Technology (column A) and
Various Advanced Technologies (columns B to G)
80
SC w
C
/
w Am
A ine
SC w/
C
Ammonia
Scr
Sc u
r bb
b in
i g
80
CO Scr
Sc u
r bb
b in
i g
8.77
PC Plants
8.72
2
PC Plant
8.72
2
(c/k
(c W
/k h)
h
70
(c/k
(c W
/k h)
h
SC w
SC
/
w Econ
Ec
am
a in
i e
70
SC w/
w Mu
M ltip
lt o
ip llu
l ta
t n
a t
E
Scru
Scr bb
b in
i g
Ammo
m nia S
a cr
c u
r bb
b in
i g
E
USC w/Amine
O
70
69
60
8.00
(Bypro
B
du
d ct
c Cr
C ed
r
i
ed t)
69
00
Scru
Scr bb
b in
i g
USC w
C
/
w Ad
A vanced
60
(c/kW
k h)
h
7.84
7.74
Am
A in
m e S
e cr
c u
r b
u bin
b g
in
(c/k
(c W
/k h)
C
h
C
(c/k
(c W
/k h)
n
h
n 50
7.48
50
4
55
(c/kW
k h)
55
h
50
52
50
ease i 40
45
cr
RT
R I Re
R gener
e
a
gener bl
a e
cr
n 30
Sorb
Sor en
e t
6.30
30
`
t I
(c/k
(c W
/k h)
t I
h
20
rcen
22
e
P 10
0
A
B
C
D
E
F
G
40
Selex
e o
x l
IGCC Plants
Ad
A vanced
IGCC Plan
Ad
A vanced
Sel
Se exo
x l
o
35
7.13
35
(c/
(c k
/ W
k h)
E
h
E
7.01
Ad
A vanced
O 30
(c/
(c k
/ W
k h)
h
Se
S l
e exo
e
l
xo w/
l
co-
co
C 30
C
Seq
Se ue
u st
s r
t a
r t
a ion
o
n
e i 25
Adva
Ad nc
n e
c d
6.52
Se
S l
e ex
e o
x l w/IT
l w
M
(c/
(c k
/ W
k h)
h
& co-
o Se
S q
e ue
u str
st a
r t
a i
t on
o
31
reas 20
c
28
WGS M
S
em
e b
m ra
r n
a e
28
6.14
& Co-S
- e
S qu
q estra
r t
a i
t o
i n
t In 15
6.14
(c/k
/ W
k h)
15
h
6.03
WGS M
WGS e
M m
e b
m ra
r ne
n
e Chem
e i
m ca
c l
a Loop
Lo
i
op ng
n
19
WGS M
WGS e
M m
e b
m ra
r ne
n
e
(c/k
/ W
k h)
19
h
w/ITM &
M
Co
C -
& Co
& C -
en
c 10
Seques
que t
s rat
ra i
t on
Se
S q
e uestr
u
a
estr tion
o
10
5.75
5.75
12
10
(c/
(c k
/ W
k h)
h
(c/
(c k
/ W
k h)
h
Per
10
Per
5
5
5
0
A
B
C
D
E
F
G
Source: U.S. Department of Energy, “CO2 Capture Developments,” presentation by S.M. Klara, National Energy
Technology Center and Office of Fossil Energy, Strategic Initiatives for Coal, Queenstown, MD, December 2006.
Notes: The value of total COE appears at the top of each column. Abbreviations: SC = supercritical; USC =
ultrasupercritical; RTI = Research Triangle Institute; ITM = ion transport membrane; WGS = water gas shift.
Figure 28 shows a more recent (2010) DOE analysis of potential reductions in capture cost from
sustained R&D. Here, the total cost of a new supercritical PC plant with CCS declines by 27%
while the IGCC plant cost falls by 31%. Thus, the future IGCC plant with CCS costs 7% less than
the current plant without capture. For the PC plant the CCS cost penalty falls by about half in this
analysis.
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Figure 28. Current Cost of Electricity (COE) for IGCC and PC Power Plants
with and without CO2 Capture and Storage (CCS), Plus Future Costs with
Advanced Technologies from R&D
175
IGCC
G
Tec
e h
c nologies
e
Pul
u ve
v r
e ized
e C
d oa
o l
a lTec
Te hn
h ol
o ogies
gie
155
135
29
2 %
9 above
%
7% b
7% el
e ow
o
)
no CC
no
S
CC
115
no C
no C
C S
C
09
20
$
95
h (
W
75
M
$/
55
No
CCS
CC
CCS
CC
No
CCS
CCS
CCS
CC
with
wi
th
with
wi
th
CCS
CC
with
h
with
wi
th
35
No
R&D
R&
No
R&D
R&D
R&
R&D
15
-5
IGCC
C
C
IGCC w/
G
CCS
IGCC w/
G
CCS
Sup
u erc
e ritical
a PC
C Sup
u erc
e ritical
a PC
C Adv Combu
b s
u tion
o
31%
31 re
r d
e u
d cti
ct on
o
27%
27 redu
red ct
u i
ct on n
on
o
Toda
T
y
oda
Toda
T
y
oda
with R&
R D
Toda
T
y
oda
w/ CCS
CC «
w/ CCS
CC «
Source: U.S. Department of Energy, “Carbon Dioxide Capture and Storage (CCS),” CCS Briefing to Senate
Energy and Natural Resources Committee, by S. M. Klara, National Energy Technology Center and Office of
Fossil Energy, Washington, DC, March 5, 2010.
Since many of the components assumed in the DOE analysis are still at early stages of
development, cost estimates for these advanced technologies are again highly uncertain.
Nonetheless, these estimates can be taken as a rough (perhaps optimistic) indication of the
potential cost savings that may be realized. Other organizations have estimated similar cost
reductions for other advanced plant designs with CCS.96
Typically missing from engineering-based cost estimates such as these is an indication of the time
frame in which advanced technologies are expected to be in commercial use. This is especially
problematic for environmental technologies like CO2 capture processes, since the market for such
systems depends mainly on government policies that require or incentivize their use. An
alternative approach to forecasting technology costs, based on learning or experience curves,
comes closer to providing a temporal dimension together with cost estimates, as discussed below.
Results from Experience Curve Analyses
As noted earlier, the “top down” approach to cost estimation models the future cost of power
plants with CCS as a function of the total installed capacity of such plants. While time is not an
explicit variable, it is implied by the choice of CCS plant capacity that is projected. The future
cost reductions shown in Figure 29 are from a detailed analysis that applied historical learning
rates for selected technologies to the components of four types of power plants with CO2 capture
(PC, NGCC, IGCC, and oxyfuel).97 The component costs were then summed to estimate the
96 E.g., Metz, “Special Report.”
97 E. S. Rubin et al., “Use of Experience Curves to Estimate the Future Cost of Power Plants with CO2 Capture,”
International Journal of Greenhouse Gas Control, vol. 1, no. 2 (2007), pp. 188-197.
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Carbon Capture: A Technology Assessment
future cost of the overall power plant as a function of new plant capacity. The analysis also
considered uncertainties in key parameters, including potential increases in cost during early
commercialization.
Figure 29. Projected Cost Reductions for Four Types of Power Plants with
CO2 Capture Based on Experience Curves for Major Plant Components
30
E 25
CO
Ranges of %
Ra
COE
COE
in 20
n
reductio
t n bas
a ed on
io
ct
100 GW
0 G o
f
o
u 15
d
e
cum
cu ul
u ati
a v
ti e
v CCS
e
S
t R
capa
cap cit
ci y w
y o
w rld
rl wide
n 10
Perce 5
0
NG
N C
G C
C
C P
C
P I
C G
I CC
C O
C
x
O yf
y u
f el
e
Source: E. S. Rubin et al., “Use of Experience Curves to Estimate the Future Cost of Power Plants with CO2
Capture,” International Journal of Greenhouse Gas Control, vol. 1, no. 2 (2007), pp. 188-197.
Figure 29 shows the resulting ranges of cost reduction estimated for each of the four types of
power plants with CO2 capture after an assumed deployment of 100,000 MW for each system
worldwide (100,000 MW was the total installed capacity of flue gas desulfurization systems
approximately 20 years after that technology was first introduced at U.S. power plants). Note that
these results reflect the maturity of each plant type as well as the CO2 capture system. Thus, the
IGCC plant—whose principal cost components are less mature than those of combustion-based
plants—shows the largest potential for overall cost reductions. The combustion-based plants
show a smaller potential, since most of their components are already mature and widely deployed.
In all cases, however, the incremental cost of CO2 capture system falls more rapidly than the cost
of the overall plant.
Note that the high end of the cost reduction ranges in Figure 29 is similar to DOE’s “bottom up”
estimates shown in Figure 27. The low end of the ranges, however, is smaller by factors of two to
three. That result suggests a more gradual rate of cost reductions from continual improvements to
capture technologies as CCS is more widely deployed.
Roadmaps for Capture Technology Commercialization
This section looks at estimated timetables for the development and commercialization of CO2
capture systems. Such “roadmaps” have been developed by a number of governmental and
private organizations involved in CO2 capture technology R&D. They provide a useful
perspective on the time frame in which improved or lower-cost capture systems are expected to
become commercial and available for use at power plants and other industrial facilities.
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The DOE Roadmap
As part of its Carbon Sequestration Program, the U.S. Department of Energy (DOE) has
developed and periodically updates a roadmap displaying the projected timetable for major
program elements, including CO2 capture technology development. Figure 30 shows an excerpt
from the most recent DOE roadmap published in 2007. Figure 31 shows a more detailed timeline
for advanced CO2 capture technologies applied to existing plants.
Figure 30. The DOE Carbon Sequestration Program Roadmap from 2012 to 2022
Source: U.S. Department of Energy, Carbon Sequestration Technology Roadmap and Program Plan, National Energy
Technology Laboratory, Pittsburgh, PA, 2007.
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Carbon Capture: A Technology Assessment
Figure 31. DOE’s Timeline from R&D to Commercial Deployment of Advanced Post-
Combustion Capture Technologies for Existing Power Plants
Co
C m
o m
m ercial
Depl
p oym
y en
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Large De
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onstr
n
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(C
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0+ MW
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20
2010
2012
20
2016
20
2020
20
2024
Source: Ciferno, “DOE/NETLs Existing Plants.”
The 2007 DOE roadmap has milestones extending to 2022. The more recent roadmap for
advanced post-combustion capture systems in Figure 31 extends beyond 2024. It anticipates
commercial deployment of advanced technologies in 2020, with full-scale demonstrations
beginning four years earlier, in 2016.98 Laboratory- and bench-scale R&D would, on average,
advance to pilot-scale testing after about two years, with subsequent pilot plant testing and scale-
up prior to large-scale demonstrations.
The Electric Power Research Institute (EPRI) carries out R&D on behalf of member utility
companies. EPRI-supported projects include development and testing of advanced carbon capture
technologies. Figure 32 shows a roadmap developed jointly between EPRI and the Coal
Utilization Research Council (CURC), an industry advocacy group that promotes the efficient
and environmentally sound use of coal. Recent updates to this roadmap call for four
demonstrations of IGCC with CCS by 2025, including the FutureGen project (noted earlier in
“Chapter 6: Status of Pre-Combustion Capture”), plus nine demonstrations of combustion with
CCS by 2025.99 Like the DOE plan, the CURC-EPRI roadmap expects CO2 capture systems for
power plants to be commercial by 2020. That roadmap, however, shows a heavier reliance on
continued improvements to technologies that are already at the advanced stages of development.
EPRI researchers also have put forth a timeline for carbon capture developments based on the
Technology Readiness Levels (TRLs) described earlier in “Chapter 4: Stages of Technology
Development.” This timeline, shown in Figure 33, characterizes most systems being developed
today at TRLs 5 through 7. It shows activity at TRL 8 (equivalent to large-scale demonstration
projects) beginning in 2010, with commercial-scale plants (TRL 9) coming online by 2018. This
98 J. P. Ciferno, “DOE/NETLs Existing Plants CO2 Capture R&D Program,” Proc. Carbon Capture 2020 Workshop,
October 5-6, 2009, College Park, MD.
99 Coal Utilization Research Council (CURC), Clean Coal Technology Roadmap, Washington, DC (2009).
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implies a 10- to 15-year development schedule from concept to commercialization. EPRI
acknowledges, however, that this schedule represents an aggressive and well-funded program of
research, development, and deployment.
Figure 32. Steps in Technology Validation and Scale-Up Projects to Meet CURC-EPRI
Roadmap Goals for Advanced Coal Technologies with CCS
Source: CURC, “Clean Coal.”
Figure 33. EPRI Projections of Capture Technology Development Based on
Technology Readiness Levels (TRLs)
Source: Bhown and Freeman, “Assessment of Post-Combustion.”
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The CSLF Roadmap
The Carbon Sequestration Leadership Forum (CSLF) is an international climate change initiative
(at the ministerial level) focused on the development of improved cost-effective technologies for
CO2 capture and storage. Its mission is to facilitate the development and deployment of such
technologies via collaborative efforts.
The CSLF roadmap in Figure 34 sets out development goals in three time periods: 2009-2013,
2014-2020, and 2020 and beyond. For CO2 capture, the goal for the first stage is “development of
low-cost and scalable carbon capture technologies.” Goals for the second stage involve full-scale
demonstrations of these technologies, while the goal for 2020 and beyond is to have these
technologies deployed commercially.100 The roadmap also lays out goals for CO2 transport and
storage and for the development of integrated full-scale CCS projects by 2013. As an
international organization, the CSLF does not itself provide funding for CO2 capture R&D, but
rather relies on country-level support for such projects.
Figure 34. Key Milestones in the CSLF Technology Roadmap
Source: Carbon Sequestration Leadership Forum, “Carbon Sequestration Leadership Forum Technology
Roadmap: A Global Response to the Challenge of Climate Change,” http://www.cslforum.org/publications/
documents/CSLF_Techology_Roadmap.pdf.
Other Roadmaps and Milestones
Several other international groups and organizations have set goals and targets for the
demonstration, commercialization, and deployment of CO2 capture and storage systems. At its
2008 summit meeting in Japan, the Group of Eight (G8)—representing the governments of
Canada, France, Germany, Italy, Japan, Russia, the United Kingdom, and the United States—
committed to “strongly support the launching of 20 large-scale CCS demonstration projects
globally by 2010, ... with a view to beginning broad deployment of CCS by 2020.”101 This action
was based on recommendations of the CSLF and the International Energy Agency (IEA).
In conjunction with its global energy modeling activities, IEA also has published a CCS roadmap
calling for increasing numbers of pilot and demonstration plants worldwide through 2035.102 To
100 Carbon Sequestration Leadership Forum, “Technology Roadmap.”
101 Group of Eight 2008, G8 Summits Hokkaido Official Documents—Environment and Climate,
http://www.g7.utoronto.ca/summit/2008hokkaido/2008-climate.html.
102 International Energy Agency, “Technology Roadmap: Carbon Capture and Storage,” http://www.iea.org/papers/
2009/CCS_Roadmap.pdf.
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support the commercialization of CCS globally, the IEA sees a requirement for about 30 such
new-build pilot and demonstration projects in the 2020-2025 time frame, an additional 100
projects in 2025-2030, and about 40 more in 2030-2035. A majority of early large-scale projects
would take place in OECD countries, but after 2030 non-OECD countries would take the lead in
commercializing CCS plants.
A number of countries also have developed national plans or projections for CCS. Figure 35
shows the R&D needs and timetable for CO2 capture systems identified in a CCS roadmap for
Canada.
Figure 35. Capture System R&D Needs in the CCS Roadmap for Canada
Source: Natural Resources Canada, Canada’s Carbon Dioxide Capture and Storage Technology Roadmap,
March 2006.
Scenarios for CCS Deployment
Recent studies include a wide range of scenarios modeled by different groups to predict the
consequences of national and international policies to mitigate global climate change.103 These
studies typically assume that CCS is available for deployment at power plants and other industrial
facilities by at least 2020. While the future cost of CCS assumed in different models is not readily
available, the scenario results indicate widely differing projections of CCS deployment.
For example, Figure 36 shows results from five different models used to project the U.S. energy
mix in 2050 in response to policy scenarios requiring national reductions in greenhouse gas
103 National Research Council, “America’s Climate Choices.” Metz, “Climate Change 2007.”
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emission of 50% to 80% below 1990 levels.104 Results for the five models for the year 2035 show
deployment of CCS ranging from zero to 120 GW for the 50% GHG reduction case and 30-230
gigawatts (GW) for the 80% reduction scenario. While these results indicate the potential
importance of CCS as a cost-effective mitigation option for achieving climate goals by mid-
century, they also illustrate the large uncertainties in the future demand for CO2 capture
technology and the time frame for its widespread commercial use.
Figure 36. Projected U.S. Energy Mix in 2050 for Two GHG Reduction Scenarios
50
5 %
0 GHG redu
GHG red cti
u
on
o
80% GHG redu
GHG red ct
u i
ct on
160
160
140
140
120
120
100
100
yr 80
yr 80
EJ/
EJ/
60
60
40
40
20
20
0
0
00
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00
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G
M
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00
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00
20
AG
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20
EP
NE
20
AG
R
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AG
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EPPA
AD
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NE
AD
niC
Mi
N-
AD
ME
R
Mi
N-
R
M
M
Oil w/
il w o C
o C
C S
C
Oil w/
il w CC
C S
C
Coa
Co l w/
w o C
o C
C S
C
Coa
Co l w/CCS
CC
Gas w/
w o C
o C
C S
C
Gas w/
w CC
C S
C
Bi
B oen
oe er
e g
r y w/
w o CC
o C S
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Bioe
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e er
e g
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w CC
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o
Source: National Research Council, “America’s Climate Choices.”
Notes: The cross-hatched areas indicate facilities with CCS.
Conclusion
Current roadmaps and scenarios for carbon capture technology commercialization and
deployment envision that improved, lower-cost capture systems will be generally available for
use at power plants and other industrial facilities by 2020. At the same time, public and private-
sector research organizations alike acknowledge that a sustained R&D effort will be required over
the next decade to achieve that goal, especially for many of the promising new processes that are
still in the early stages of development. The magnitude of future cost reductions also is likely to
depend on the pace of CCS technology deployment as well as on continued R&D support. The
next chapter looks at past experience with other power plant environmental technologies to
provide additional perspectives on the pace of new technology development, deployment,
performance improvements, and cost reductions.
104 National Research Council, “America’s Climate Choices.”
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Chapter 9: Lessons from Past Experience
Introduction
This chapter looks retrospectively at a number of other recent efforts to develop and
commercialize advanced technologies to improve the effectiveness and lower the cost of air
pollutant capture at coal-fired power plants. The purpose of this analysis is to glean insights that
are useful for assessing the prospects for improved, lower-cost CO2 capture systems. First this
chapter presents several case studies of prior DOE-supported efforts to develop novel, lower-cost
systems to capture power plant sulfur dioxide (SO2) and nitrogen oxide (NOx) emissions. These
past efforts bear a number of similarities to current efforts for CO2 capture systems. Thus, they
provide some historical benchmarks for the time required to bring a new process from concept to
commercialization and the factors that influence the probability of success.
Following this, the chapter presents some historical data on the rates of technology deployment,
performance improvements, and cost reductions for post-combustion capture systems of SO2 and
NOx. Again, the purpose is to provide benchmarks for assessing current projections for CO2
capture systems. The critical role of government policies in establishing markets for
environmental technologies also is discussed and illustrated with examples drawn from past
experience with post-combustion SO2 and NOx capture technologies.
Case Studies of Novel Capture Technology Development
Current efforts to develop new or improved carbon capture systems are in many respects similar
to efforts that began in the late 1970s to develop improved, lower-cost technologies for power
plant SO2 and NOx controls. Those activities followed passage of the 1970 Clean Air Act
Amendments (CAAA) and the adoption of federal New Source Performance Standards (NSPS)
requiring “best available control technology” for major new sources of air pollution, including
fossil fuel power plants. Although SO2 capture technology had been used commercially since the
early 20th century on various industrial processes (such as metal smelters), it had seldom been
used to desulfurize power plant flue gases. The same was true of post-combustion NOx capture
technologies.
By the late 1970s, the most widely used technology for post-combustion SO2 control (in response
to NSPS and CAAA requirements) was a flue gas desulfurization (FGD) system or “scrubber”
that used a slurry of water and limestone to capture SO2 via chemical reactions (analogous to
today’s CO2 scrubbers that employ amine-based solutions). These early “wet FGD” systems had
high capture efficiencies (up to about 90%), but were widely regarded as being very expensive,
being difficult to operate reliably, and having a high energy penalty.105 In the case of nitrogen
oxides, post-combustion capture systems such as selective catalytic reduction (SCR) were
deemed too costly and unavailable in the 1970s to be required under the NSPS; instead, a less
105 M. R. Taylor, The Influence of Government Actions on Innovative Activities in the Development of Environmental
Technologies to Control Sulfur Dioxide Emissions from Stationary Sources, Ph.D. Thesis, Carnegie Mellon University,
Pittsburgh, PA, January 2001.
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stringent requirement was imposed that did not require post-combustion capture, but instead
could be met using only low-NOx burners.106
By the 1980s, U.S. coal-fired power plants were being targeted for further reductions in SO2 and
NOx emissions to curtail the growing problem of acid deposition (acid rain). In response, DOE
launched major initiatives to develop “high risk, high payoff” technologies that promised
significant cost-effective reductions in power plant SO2 and NOx emissions compared to the
prevailing FGD and SCR technologies.
Five new technologies supported under the DOE Clean Coal Technology program are briefly
described below. Three of the novel processes involved post-combustion SO2 and NOx capture in
a single process rather than in separate units. The other two processes sought more cost-effective
SO2 capture by injecting solid sorbents directly into the power plant furnace or flue gas duct. Of
particular relevance to the present report are the time required to develop each process and its
ultimate fate in the commercial marketplace.
The Copper Oxide Process
The use of copper oxide as a sorbent for sulfur removal was first investigated at the laboratory
scale by the U.S. Bureau of Mines in 1961.107 Pilot-scale tests were performed in the mid-1960s
and by 1973 the process saw industrial use for sulfur removal at a refinery in Japan.108 DOE
continued to develop the process as a lower-cost way to remove both SO2 and NOx from power
plant flue gases, while producing sulfur or sulfuric acid as a byproduct in lieu of solid waste.109
Figure 37 shows several milestones in the process development.
After a series of design changes following pilot plant tests in the 1970s and 1980s, DOE began
developing designs for a 500 MW power plant in the 1990s and planned a new 10 MW pilot plant
as part of its Low Emission Boiler System project.110 However, by the time the environmental
impact statement for that project was completed, the copper oxide process had been replaced by a
conventional wet FGD system.111 Although the process never developed into a commercial
technology for combined SO2 and NOx capture, research on copper oxide sorbents continues.112
106 S. Yeh et al., “Technology Innovations and Experience Curves for Nitrogen Oxides Control Technologies,” Journal
of the Air & Waste Management Association, vol. 55, no. 2 (Dec. 2005), pp. 1827-1838.
107 D. H. McCrea, A. J. Forney, and J. G. Myers, “Recovery of Sulfur from Flue Gases Using a Copper Oxide
Absorbent,” Journal of the Air Pollution Control Association, vol. 20 (1970), pp. 819-824.
108 Kohl, “Gas Purification.”
109 H. C. Frey and E. S. Rubin, “Probabilistic Evaluation of Advanced SO2/NOx Control Technology,” Journal of Air &
Waste Management Association, vol. 41, no. 12 (Dec. 1991), pp. 1585-1593.
110 U.S. Department of Energy, Fluidized Bed Copper Oxide Process Phase IV: Conceptual Design and Economic
Evaluation, Report from A. E. Roberts and Associates, Inc., to National Energy Technology Laboratory, Pittsburgh,
PA, 1994.
111 U.S. Department of Energy, “Environmental Impact Statement for the Low Emission Boiler System Proof-of-
Concept, Elkbart, Logan County, IL,” http://www.netl.doe.gov/technologies/coalpower/cctc/cctdp/bibliography/misc/
pdfs/hipps/000001B3.pdf.
112 J. Abbasian and V. S. Gavaskar, “Dry Regenerable Metal Oxide Sorbents for SO2 Removal from Flue Gases. 2.
Modeling of the Sulfation Reaction Involving Copper Oxide Sorbents,” Industrial & Engineering Chemical Research,
vol. 46, no. 4 (2007), pp. 1161-1166. T. Benko and P. Mizsey, “Comparison of Flue Gas Desulfurization Processes
Based On Lifecycle Assessment,” Chemical Engineering, vol. 51, no. 2 (2007), pp. 19-27.
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Figure 37. Development History of the Copper Oxide Process for Post-
Combustion SO2 and NOx Capture
1999: 10 MW
1975: DOE
1967: Pilot-
1984:
pilot planned
conducts test of
Scale Testing
Continued pilot
2006: Most
by DOE
fluidized bed
begins.
testing with 500
recent paper
system
lb/hr feed
published
1971: Test
1983: Rockwell
conducted in
contracted to
Netherlands
improve system
1996: DOE
continues
lifecycle
testing
1965
1970
1975
1980
1985
1990
1995
2000
2005
1979: Pilot-scale
1961:
testing conducted in
1992: DOE
Process
1970: Results of
Florida
contracts
described by
testing published.
design and
2002: Paper
Bureau of
modeling for
published at
Mines
1973: Used in
500MW plant
NETL
commercial refinery
symposium
in Japan
Source: Edward S. Rubin, Aaron Marks, Hari Mantripragada, Peter Versteeg, and John Kitchin, Carnegie Mel on
University, Department of Engineering and Public Policy.
The Electron Beam Process
The electron beam process for flue gas treatment was first introduced by the Ebara Corporation of
Japan in 1970.113 The concept was that energy from the electron beam would excite chemicals in
the flue gas, causing them to break down and form other stable compounds. The process was
promoted as a more cost-effective way to simultaneously capture both SO2 and NOx with high
(~90%) efficiency. Figure 38 shows the history of key process developments.
By 1977, Ebara’s testing moved to the pilot plant scale and in 1985 their subsidiaries in the
United States and Germany opened two more pilot plants, one in Indiana and one in Germany.114
DOE provided partial funding for the U.S. facility. Continued R&D led to the first commercial
plant in China in 1998, followed by three more plants built between 1999 and 2005, one in
Poland, the other two in China.115 The overall cost of this system is highly dependent on the
market value of the ammonium sulfate and ammonium nitrate byproducts that are produced, as
well as on the cost of ammonia, the key reagent for the process. The need for these byproduct
chemicals may help explain the adoption of this process in China. There have been no
commercial installations of the electron beam process in the United States.
113 Kohl, “Gas Purification.”
114 V. Markovic, “Electron Beam Processing of Combustion Flue Gases,” IAEA Bulletin, No. 3, International Atomic
Energy Agency, 1987, Vienna, Austria.
115 I. Calinescu et al., “Electron Beam Technologies for Reducing SO2 and NOx Emissions from Thermal Power
Plants,” Proc. World Energy Council Regional Energy Forum, 2008, Neptun, Romania.
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Figure 38. Development History of the Electron Beam Process for Post-Combustion
SO2 and NOx Capture
2005: Process
used in plant in
Hangzhou,
China
2002: Process
1998: Process
used in plant in
1970: Ebara
used in plant
Beijing, China
Corporation
in Chengdu,
begins lab scale
China
testing.
1965
1970
1975
1980
1985
1990
1995
2000
2005
1985: Pilots
initiated in U.S.
1977: Ebara
and Germany
begins pilot-
scale testing
1999:
Process used
at plant in
Poland
2008: Paper on process
presented at WEC forum in
Romania
Source: Edward S. Rubin, Aaron Marks, Hari Mantripragada, Peter Versteeg, and John Kitchin, Carnegie Mel on
University, Department of Engineering and Public Policy.
The NOXSO Process
The NOXSO process was another concept for post-combustion capture of both SO2 and NOx
from power plant flue gases. It used a solid sorbent of sodium carbonate supported on alumina
beads. The sorbent chemistry was based on an alkalized alumina process developed by the US
Bureau of Mines in the 1960s. A novel feature the NOXSO process was the use of a fluidized bed
reactor for sorbent regeneration. Figure 39 shows the process development timeline, which began
in 1979 with funding from DOE.
Pilot plant and life cycle testing were carried out from 1982 to 1993. In 1991 the NOXSO
Corporation received a DOE contract to build a commercial-scale demonstration plant.116
However, a number of administrative problems ensued, leading to several changes in the project
site location. A legal dispute with the owner of the final project site culminated in the bankruptcy
and subsequent liquidation of the NOXSO Corporation.117
116 U.S. Department of Energy, “Comprehensive Report to Congress: Commercial Demonstration of the NOXSO
SO2/NOx Removal Flue Gas Cleanup System,” 1991, Washington, DC.
117 Chemical Week, “NOXSO Sues Olin Over SO2 Agreement,” 1997, vol. 159.
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Figure 39. Development History of the NOXSO Process for Post-
Combustion SO2 and NOx Capture
1996:
2000: Noxso
Construction of
process cited in ACS
full scale test
paper, Last NOXSO
1985: DOE
begins
patent awarded
conducts
lifecycle testing.
1979:
1997: Noxso
Development of
Corporation
process begins
declares bankruptcy
1965
1970
1975
1980
1985
1990
1995
2000
2005
1982: Pilot-
scale tests
1993: Pilot-scale
carried out in
testing complete
Kentucky
1991: Noxso
1998: Noxso
Corporation
Corporation
receives DOE
liquidated. Project
contract
terminated.
Source: Edward S. Rubin, Aaron Marks, Hari Mantripragada, Peter Versteeg, and John Kitchin, Carnegie Mel on
University, Department of Engineering and Public Policy.
The Furnace Limestone Injection Process
In the early 1980s, the prospect of new restrictions on SO2 emissions to control acid rain
prompted interest in sulfur removal methods that were more cost-effective than FGD (post-
combustion capture) systems, especially for existing power plants. The furnace limestone
injection process promised to be such a technology. Limestone sorbent would be injected directly
into the furnace and react with sulfur oxides to achieve only moderate removal efficiencies, but at
very low cost. The method was first tested by Wisconsin Power in 1967.118 In the 1980s and
1990s, DOE supported two methods of furnace sorbent injection (called LIFAC and LIMB), as
seen in Figure 40.
The LIFAC process combined limestone injection with a humidification system to capture SO2.
First developed by the Tampella Company in 1983, it was later tested at a commercial scale in
Finland. DOE supported demonstrations in the United States starting in 1990, achieving 70% to
80% sulfur removal rates.119 The LIMB (limestone injection with multi-stage burners) process
was first developed by the U.S. Environmental Protection Agency. It achieved fairly low
(approximately 50%) SO2 removal using limestone, with somewhat higher capture efficiencies
using more expensive lime sorbents. Testing of both processes encountered failures of the
electrostatic precipitator at the test plants due to the larger volume of solids being collected.
118 W. A. Pollock et al., Mechanical Engineering, American Society of Mechanical Engineers, New York, NY, 1967.
119 U.S. Department of Energy, LIFAC Sorbent Injection Desulfurization Demonstration Project: A DOE Assessment,
National Energy Technology Laboratory, Pittsburgh, PA, 2001.
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Technical solutions added to the cost. 120 The LIFAC process was eventually used commercially at
nine facilities outside the United States, but neither LIFAC nor LIMB was adopted commercially
for SO2 control in the United States following the large-scale demonstrations.
Figure 40. Development History of the Furnace Limestone Injection Process
for SO2 Capture
1989: LIFAC
1990: LIFAC
system built in
System built in
Finland.
Canada, DOE
begins LIFAC
testing
1986: First full-
scale test of
1967: Wisconsin
LIFAC in
1995: LIFAC
Power tests
Finland
System built in
Furnace Limestone
China
Injection (FLI)
1984: LIMB
demonstration
Initiated
1965
1970
1975
1980
1985
1990
1995
2000
2005
1983: Tampella
1992: LIFAC
begins LIFAC
System built in
development
Canada
1988: LIFAC
1987: LIMB
system built in
testing
Finland
extended
1994: LIFAC System
built in Russia, DOE
begins long-term
LIFAC testing
Source: Edward S. Rubin, Aaron Marks, Hari Mantripragada, Peter Versteeg, and John Kitchin, Carnegie Mel on
University, Department of Engineering and Public Policy.
The Duct Sorbent Injection Process
Duct sorbent injection (DSI) is another post-combustion SO2 capture concept similar to furnace
limestone injection, except that the sorbent is injected into the flue gas duct after the boiler where
temperatures are lower and physical access is generally easier. This was proposed as a simpler
and more cost-effective method of achieving modest SO2 reductions at existing power plants.
Figure 41 shows the process development timeline.
120 Southern Research Institute, Analysis of Whitewater Valley Unit 2 ESP Problems during Operation of the LIFAC
SO2 Control Process, Report SRI-ENV-93-953-7945-I, Prepared for Southern Company Services by Southern
Research Institute, Birmingham, AL, August 1993. Babcock and Wilcox, LIMB Demonstration Project Extension and
Coolside Demonstration, Report No. DOE/PC/7979-T27 to the U.S. Department of Energy, Pittsburgh Energy
Technology Center, Prepared by T.R Goots et al., The Babcock & Wilcox Company, Barberton, OH, October 1992.
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Figure 41. Development History of the Duct Sorbent Injection Process
for SO2 Capture
1996: DOE initiates test
of duct sorbent injection
1985: Coolside
for mercury control
process piloted
1993: DOE tests dry
1980: B&W begins
duct sorbent injection
development of SOx-
2001: Testing
in Colorado
NOx-Rox-Box system
begins at NETL.
1965
1970
1975
1980
1985
1990
1995
2000
2005
2003: Testing of
TOXECON system
1990: DOE tests Duct
in Wisconsin
Injection System using CaOH
1991: Coolside process
1992: DOE begins
tested in Ohio
testing of the SOx-
NOx-Rox-Box system
Source: Edward S. Rubin, Aaron Marks, Hari Mantripragada, Peter Versteeg, and John Kitchin, Carnegie Mel on
University, Department of Engineering and Public Policy.
Babcock and Wilcox began work on a DSI system in 1980 for their SOx-NOx-ROx-BOx (SNRB)
combined pollutant control system, which DOE tested 12 years later. Pilot and demonstration
projects of DSI for SO2 capture during the 1980s and early 1990s achieved capture rates rarely
exceeding 40% with calcium-based sorbents. Costs and technical complexity were similar to the
more effective furnace injection systems.121 Subsequent process modifications improved the SO2
capture efficiency, but at a higher cost. There were no commercial adoptions of DSI following the
DOE test programs.
In 1996, DSI was retooled for use in mercury control. It developed into the TOXECON process,
which was tested at full scale in 2003, achieving 90% capture of flue gas mercury.122 Duct sorbent
injection for mercury control is now offered commercially but has not been widely adopted in
light of continuing uncertainty over final national power plant mercury emissions regulations.
Implications for Advanced Carbon Capture Systems
Several lessons can be gleaned from the case studies above that are relevant to current efforts to
develop lower-cost carbon capture systems for power plants. The first is the importance of
markets for these environmental technologies. Just as with advanced CO2 capture systems today,
121 T. Hunt et al., “Performance of the Integrated Dry NOx/SO2 Emissions Control System,” U.S. Department of
Energy, Fourth Annual Clean Coal Technology Conference, September 1995, Denver, CO.
122 ADA Environmental Solutions, TOXECON Retrofit for Multi-Pollutant Control on Three 90-MW Coal Fired
Boilers, Report to U.S. Department of Energy, National Energy Technology Laboratory, prepared by ADA
Environmental Solutions (2008).
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at the time they were being developed there were no requirements for (hence, no significant
markets for) high-efficiency combined SO2-NOx capture systems, or moderately efficient SO2
removal systems. This factor alone posed high risks for their commercial success. While that was
consistent with the DOE mission to pursue high-risk, high-payoff technologies, the high payoffs
that were projected never materialized—in large part because the markets for these technologies
failed to develop as expected. Similar risks face advanced carbon capture technologies today.
As shown in the figures above, the time required to develop a novel capture process from concept
to large-scale demonstration was typically two decades or more. During this period the projected
economic benefits of the advanced technologies tended to shrink. Not only did their cost tend to
rise during the development process (as suggested earlier in Figure 26), but the cost of competing
options also fell. Thus, the continual deployment and improvement of commercial FGD systems
(mainly in the United States) and SCR systems (in Japan and Germany) during the 1980s made it
increasingly difficult for combined SO2-NOx capture technologies to enter and compete in the
marketplace. Indeed, in the United States, there was no market for post-combustion NOx capture
at coal-burning plants until the mid-1990s.123 In the case of furnace and duct sorbent injection
processes for moderate levels of SO2 capture, the anticipated market for such an option did
materialize in the United States with passage of the acid rain provisions of the 1990 Clean Air Act
Amendments. However, switching to low-sulfur coal proved to be an easier and more economical
choice than sorbent injection, especially as low-sulfur western coals entered the marketplace.
In terms of additional lessons learned, the above discussion suggests that the lengthy time
historically required to develop advanced environmental technologies tends to diminish the
probability of commercial success, as more mature technologies gain initial market share
(assuming the existence of a market). Thus, any efforts that can accelerate the development
process can help reduce the commercial risks. Apropos of that, another lesson drawn from this
experience is that current commercial technologies do not “stand still” (as is often assumed by
proponents of new technologies). Advancements in current systems also must be anticipated to
more realistically assess the prospects and potential payoffs of advanced technologies that are still
under development.
The Pace of Capture Technology Deployment
Historical rates of deployment for other power plant environmental technologies can serve as a
useful guide for realistically assessing current projections for CCS technologies.
Figure 42 shows the trends in deployment of post-combustion capture systems for SO2 and NOx
from 1970 to 2000. For FGD systems, the maximum rate of deployment in response to new
environmental policy requirements over this period was approximately 15 GW per year (in
Germany), with an average rate of about 8 GW per year worldwide. For SCR systems, the
maximum rate was about 10 GW per year (again in Germany), with an average global
deployment rate of about 5 GW per year. These results suggests that deployment scenarios for
CO2 capture systems that significantly exceed these rate may be unrealistic or will require
aggressive new efforts and measures to achieve.
123 Yeh et al., “Technology Innovations.”
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Figure 42. Historical Deployment Trends for Post-Combustion SO2 and NOx Capture
Systems (FGD and SCR Technologies)
(a) Deployment of FGD systems
100
90
US
80
ty of
Japan
70
s (GWe)
Germany
60
apaci
em
Other
50
Syst
40
D
lative C
30
u
m
t FG
20
u
C
We
10
0
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0
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4
6
8
197
197
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198
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199
199
199
199
Year FGD System In Service
(b) Deployment of SCR systems
100
R
C
90
Japan
f S
80
Germany
o
ty
e) 70
Others
aci
W 60
US
ap
s (G 50
em 40
ve C
yst 30
lati
S
u
20
m
u
10
C
0
1978
1980
1982
1984
1986
1988
1990
1992
1994
1996
1998
2000
Year SCR System In Service
Source: E. S. Rubin et al., “Use of Experience Curves to Estimate the Future Cost of Power Plants with CO2
Capture,” International Journal of Greenhouse Gas Control, vol. 1, no. 2 (2007), pp. 188-197.
Rates of Performance and Cost Improvements
Studies also have documented the historical rates of improvement in the performance (capture
efficiency) of power plant emission control systems and their rates of cost reduction following
commercialization.124 For example, Figure 43 shows the trend in average SO2 capture efficiency
for power plant FGD systems coming online from 1969 to 1995. Capture efficiencies increased
from about 70% to 95% over that period due to the combined effects of technology improvements
and regulatory requirements. Since that time the performance of wet FGD systems has continued
to improve, with new systems today capturing 98% to 99% or more of the SO2. These deep levels
of sulfur removal now can facilitate post-combustion CO2 capture systems, which require inlet
124 J. Longwell, E. S. Rubin, and J. Wilson, “Coal: Energy for the Future,” Progress in Energy and Combustion
Science, vol. 21 (1995), pp. 269-360; Rubin et al., “Use of Experience Curves.”
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SO2 concentrations as low as one part per million for some commercial amine-based systems.125
These data, as well as other historical trends of increasing capture efficiencies for power plant
particulates and SO2 and NOx emissions126 suggest the potential for future improvements in
commercial CO2 capture systems as well.
Figure 43. Improvements in SO2 Removal Efficiency of Commercial Lime and
Limestone FGD Systems Coming Online in a Given Year, as a Function
of Cumulative Installed FGD Capacity in the United States
100%
1980
oved 90%
1976
1995
em
1990
80%
ioxide R 70% 1969
60%
ulfur D
t S
en 50%
erc
P 40%
0
10
20
30
40
50
60
70
Cumulative Wet FGD Installed Capacity, US (GW)
Source: E. S. Rubin et al., The Effect of Government Actions on Environmental Technology Innovation: Applications to
the Integrated Assessment of Carbon Sequestration Technologies, report from Carnegie Mellon University, Pittsburgh,
PA, to U.S. Department of Energy, Germantown, MD, January 2004, p. 153.
Figure 44 shows the historical trends in capital costs for FGD and SCR systems on standardized
coal-fired power plants in the United States. In both cases, the actual or estimated capital cost (as
well as O&M costs) increased during the early commercialization of these technologies in order
to achieve the levels of availability and performance required for utility operations. Subsequently,
costs declined considerably with increasing deployment. On average, the capital cost of these
technologies fell by 13% for each doubling of total installed capacity.127 This “learning rate” was
also assumed for future CO2 capture systems in the plant-level cost projections shown earlier in
Figure 29.
125 Mitsubishi Heavy Industries, “KM-CDR Post-Combustion CO2 Capture with KS-1 Advanced Solvent,” Eighth
Annual Conference on Carbon Capture and Sequestration, May 4-7, 2009, Pittsburgh, PA, Exchange Monitor
Publications, Washington, DC.
126 Longwell et al., “Coal: Energy.”
127 Rubin et al., “Cost and Performance.”
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Figure 44. Capital Cost Trends for Post-Combustion Capture of SO2 and NOx
at a New Coal-Fired Power Plant
300
120
1980←First Japan commercial installation on a
1976
7$
110
1980
97$
250
1983← First German commercial installa on
1982
199
, 19 100
1989
) in 200
W
90
1990
$/kW)
1979
/k
$ 150
1995
sts ( 80
s (
o
1978
1975
st
o
70
↓ First US commercial
100
ital C
installation
1974
ital C
1977
1993
ap
p
1972 (1000 MW, eff =80-90%)
C 60
a
R
1995
C 50
1968 (200 MW, eff =87%)
2000
SC 50
0
40
0
10
20
30
40
50
60
70
80
90 100
-20 -10
0
10
20
30
40
50
60
70
80
Cumulative World Wet FGD Installed
Cumulative World SCR Installed Capacity (GW)
Capacity (GW)
Source: Rubin et al., “Use of Experience Curves.”
Notes: On the left, capital cost trend for a wet limestone FGD system at a standardized new power plant (500
MW, 3.5% sulfur coal, 90% SO2 removal, except where noted); on the right, capital cost trend for a SCR system
at a new plant (500 MW, medium sulfur coal, 80% NOx removal). Solid diamond symbols are studies based on
low-sulfur coal plants. Open circles are studies prior to SCR use on coal-fired power plants.
The Critical Role of Government Actions
In the U.S. economy, the existence of a market (or demand) for a product is critical to its adoption
and widespread use. This is true as well for CO2 capture technologies. The adoption and diffusion
of a technology also are key elements of the innovation process that improves performance of a
product and reduces its cost over time, as depicted earlier in Figure 10. R&D plays a critical role
in this process. But R&D alone is not sufficient without a market for the technology.
For environmental technologies such as CO2 capture and storage systems, few if any markets
exist in the absence of government actions and policies. What electric utility company, for
example, would want to spend a large sum of money to install CCS—even with an improved
lower-cost capture process—if there is no requirement or incentive to reduce CO2 emissions? A
costly action such as this provides little or no economic value to the company—indeed, the added
cost and energy penalty of CO2 capture increase the cost of operation. Only if a government
action either required CO2 capture and storage, or made it financially worthwhile to reduce CO2
emissions, would a sizeable market be created for technologies that enable such reductions.
Thus, as with other environmental emissions that affect the public welfare, government actions
are needed to create or enhance markets for CO2 emission-reducing technologies.
Different policy measures influence markets in different ways. Measures such as government loan
guarantees, tax credits, direct financial subsides, and R&D funding can help create markets by
providing incentives for technology development, deployment, and diffusion. Voluntary
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incentives such as these are commonly referred to as “technology policy” measures.128 In
contrast, regulatory policies such as an emissions cap, emissions tax, or performance standards
that limit emissions to specified levels are mandatory, not voluntary. These policies create or
expand markets for lower-emission technologies by imposing requirements that can be met
only—or most economically—by the use of a low-emission technology.
Through their influence on markets for environmental technologies (like CO2 capture and storage
systems), government actions also are a critical element of the technological innovation process.
Studies of past measures to reduce sulfur dioxide and nitrogen oxide emissions from U.S. power
plants have documented the ability of regulatory policies to influence both the magnitude and
direction of efforts to develop new or improved capture technologies.129 Figure 45 and Figure
46, for example, show the century-scale trends in U.S. patenting activity for SO2 reduction
technologies and post-combustion NOx capture systems, respectively. In both cases, the number
of new patents filed—a measure of “inventive activity”—increased dramatically when new
environmental regulations that required or incentivized the use of these technologies came into
force. (In the case of NOx control, such regulations for coal plants came first in Japan and
Germany; U.S. regulations lagged by more than a decade.) The subsequent reduction in cost that
accompanied the increased deployment of these technologies (Figure 46) is evidence of the
influence of government actions on technology innovations in this domain.
Figure 45. Trend in U.S. Patenting Activity for SO2 Removal Technologies
No Fed
e eral R&D
R&
Some
m
e
CA
C A Re
A
gs +
gs R&D
+
120
Federal
e
110
R&D
R&
led
100
90
80
nts Fi
te
70
U.
U.
U S. Cl
S.
S C
. l
S. Clean Ai
ean A
n i
ean Air
60
All Me
M t
e hods of
f Pa
Act
Ac of
t o f
of 1
9
1 7
9 0
7
50
Act of 1970
50
SO Remo
Re
v
mo a
v l
2
40
ber o
30
um
20
N
10
0
1880
1890
1900
1910
1920
1930
1940
1950
1960
1970
1980
1990
2000
Ye
Y ar P
ar ate
t nt
n
t Filed
Source: Adapted from Taylor et al., “Control of SO2.”
128 J. A. Alic, D. S. Mowery, and E. S. Rubin, U.S. Technology and Innovation Policies: Lessons for Climate Change,
Pew Center on Global Climate Change, 2003.
129 M. R. Taylor, E. S. Rubin, and D. A. Hounshell, “Control of SO2 Emissions from Power Plants: A Case of Induced
Technological Innovation in the U.S.,” Technological Forecasting and Social Change, vol. 72, no. 6 (July 2005), pp.
697-718. Yeh, “Technology Innovations.”
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Figure 46. Trend in U.S. Patenting Activity for Post-Combustion
NOx Removal Technologies
120
U.S.
U.
110
Reg
Re s
g
100
iled
Ger
Ge man
a
F 90
Regs
80
Japane
n s
e e
atents 70
Post-Combus
u tio
t n
Reg
Re s
g
f P 60
NO Remova
v l
50
x
50
ber o 40
30
Num 20
10
0
188
8 0
189
8 0
190
9 0
1910
1920
1930
194
9 0
1950
1960
1970
198
9 0
1990
200
0 0
Year
a Pat
Pa e
t nt
n s
t Fi
le
Fi d
Source: Yeh, et al., “Technology Innovations.”
Conclusion
This chapter has examined recent historical experience in the development of advanced
technologies for post-combustion capture of sulfur dioxide and nitrogen oxide emissions at coal-
fired power plants, seeking lessons and insights relevant to current programs to develop
improved, lower-cost technologies for CO2 capture. The analysis revealed that several decades
were commonly required to develop a new process from concept to a commercial-scale
demonstration. It also illustrated the risks inherent in developing new environmental technologies
for which there is not yet a significant market. Benchmark rates of capture technology
deployment and long-term cost reductions also were derived from United States and global
experience with FGD systems (for SO2 capture) and SCR systems (for NOx capture). These
historical data underscore the challenging nature of current plans and roadmaps for the
commercialization of advanced CO2 capture processes.
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Chapter 10: Discussion and Conclusions
This report has sought to provide a realistic assessment of prospects for improved, lower-cost
CO2 capture systems for use at power plants and other industrial facilities in order to mitigate
emissions of greenhouse gases linked to global climate change. Toward that end, the report first
described each of the three current approaches to CO2 capture, namely, post-combustion capture
from power plant flue gases using amine-based solvents such as monoethanolamine (MEA); pre-
combustion capture (also via chemical solvents) from the synthesis gas produced in an integrated
coal gasification combined cycle power plant; and oxy-combustion capture, in which high-purity
oxygen is used for combustion to produce a flue gas with high CO2 concentration amenable to
capture without a post-combustion chemical process.
Currently, post-combustion and pre-combustion capture technologies are commercial and widely
used for gas stream purification in a variety of industrial processes, including several small-scale
installations on power plant flue gases that produce commodity CO2 for sale. Oxy-combustion
capture is still under development and is not currently commercial. The advantages and
limitations of each of these three methods are discussed in this report, along with plans for their
continued development and demonstration in large-scale power plant applications.
While all three approaches are capable of high CO2 capture efficiencies (typically about 90%),
major drawbacks of current processes are their high cost and large energy requirements for
operation (which contribute significantly to the high cost). This is especially true for the
combustion-based capture processes, which have the highest incremental cost relative to a similar
plant without CO2 capture.
Also discussed in this report are the substantial R&D activities underway in the United States and
elsewhere to develop and commercialize improved solvents that can lower the cost of current
post-combustion capture processes, as well as research on a variety of potential “breakthrough
technologies” such as novel solvents, sorbents, membranes, and oxyfuel systems that hold
promise for lower-cost capture systems. Most of these processes, however, are still in the early
stages of research and development (i.e., conceptual designs and laboratory- or bench-scale
processes), so that credible estimates of their performance and (especially) cost are lacking at this
time. Even with an aggressive development schedule, the commercial availability of these
technologies, should they prove successful, is at least a decade away based on past experience.
Processes at the more advanced pilot plant scale are, for the most part, new or improved solvent
formulations (such as ammonia and advanced amines) that are undergoing testing and evaluation.
These advanced solvents could be available for commercial use within several years if subsequent
full-scale testing confirms their overall benefit. Pilot-scale oxy-combustion processes also are
currently being tested and evaluated for planned scale-up, while in Europe two IGCC plants are
installing pilot plants to evaluate pre-combustion capture options.
At the moment, however, there are still no full-scale applications of CO2 capture at a coal-based
power plant, although a number of demonstration projects are planned or underway in the United
States and other countries. Capture projects for other types of industrial facilities also are planned.
In general, the focus of most current R&D activities is on cost reduction rather than additional
gains in the efficiency of CO2 capture (which can often result in higher overall cost). While a
number of programs emphasize the need for lower-cost retrofit technologies suitable for existing
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power plants, as a practical matter these same technologies are being pursued to reduce capture
costs for new plant applications as well. Indeed, as the fleet of existing coal-fired power plants
continues to age, the size of the potential U.S retrofit market for CO2 capture will continue to
shrink, as older plants may not be economic to retrofit (although the situation in other countries,
especially China, may be quite different).
Whether for new power plants or existing ones, the key questions are, when will advanced CO2
capture systems be available for commercial rollout, and how much cheaper will they be
compared to current technology?
All of the technology roadmaps reviewed in this report anticipate that CO2 capture will be
available for commercial deployment at power plants by 2020. For current commercial
technologies like post-combustion amine systems, this is a conservative estimate, since the key
requirement is for scale-up and demonstration at a full-size power plant—achievable well before
2020. A number of roadmaps also project that novel, lower-cost technologies like solid sorbent
systems for post-combustion capture also will be commercial in the 2020 time frame. Such
projections acknowledge, however, that this will require aggressive and sustained efforts to
advance promising concepts to commercial reality.
That caveat is strongly supported by our review of recent experience from R&D programs to
develop lower-cost technologies for post-combustion SO2 and NOx capture at coal-fired power
plants. Those efforts typically took two decades or more to bring a new concept (like combined
SO2 and NOx capture systems) to commercial availability. By then, the cost advantage initially
foreseen had largely evaporated: advanced technologies tended to get more expensive as the
development process progressed (consistent with “textbook” descriptions of the innovation
process), while the cost of formerly “high-cost” commercial options gradually declined over time.
In a number of cases, the absence of a market for the advanced technology (as is currently the
case for CO2 capture systems) put it at a further disadvantage.
The good news based on past experience is that the costs of environmental technologies that
succeed in the marketplace tend to fall over time. For example, after an initial rise during the
early commercialization period, the cost of post-combustion SO2 and NOx capture systems
declined by 50% or more after about two decades of deployment at coal-fired power plants. This
trend is consistent with the “learning curve” behavior seen for many other classes of technology.
It thus appears reasonable to expect a similar trend for future CO2 capture costs once these
technologies become widely deployed.. This report also notes that the cost of CO2 capture also
depends strongly on other aspects of power plant design, financing, and operation—not solely on
the cost of the CO2 capture unit. Future improvements in net power plant efficiency, for example,
will tend to lower the unit cost of CO2 capture.
Some estimates of future electricity generation costs for advanced power plant designs with CO2
capture and storage offer even more optimistic forecasts of potential cost reductions from
advanced technologies. In general, however, the further away a technology is from commercial
reality, the lower its estimated cost. Thus, there is considerably uncertainty in the projected cost
of technologies that are not yet commercial, especially those that exist only as conceptual designs.
More reliable estimates of future technology costs typically are linked to projections of their
expected level of commercial deployment in a given time frame (i.e., a measure of their market
size). For power plant technologies like CO2 capture systems, this is commonly expressed as total
installed capacity. However, as with other technologies whose sole purpose is to control
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environmental emissions, there is no significant market for power plant CO2 capture systems
absent government actions or policies that effectively create such markets—either through
regulations that limit CO2 emissions or through voluntary incentives for its use. The historical
evidence and technical literature examined in this report strongly link future cost reductions to the
level of commercial deployment of a technology. In empirical “experience curve” models, the
latter measure serves as a surrogate for the many factors that influence future costs, including
expenditures for R&D and the knowledge gained through learning-by-doing (related to
manufacturing) and learning-by-using (related to technology use).
Based on such models, published estimates project the future cost of electricity from power plants
with CO2 capture to fall by up to 30% below current values after roughly 100,000 MW of capture
plant capacity has been installed and operated worldwide. That would represent a significant
decrease from current costs—one that would bring the cost and efficiency of future power plants
with CO2 capture close to that of current plants without capture. For reference, it took
approximately 20 years following passage of the 1970 Clean Air Act Amendments to achieve a
comparable level of technology deployment for SO2 capture systems at coal-fired power plants.
Uncertainty estimates for these projections, however, indicate that future cost reductions for CO2
capture also could be much smaller than indicated above. Thus, whether future cost reductions
will meet, exceed, or fall short of current estimates will only be known with hindsight.
In the context of this report, the key insight governing prospects for improved carbon capture
technology is that achieving significant cost reductions will require not only a vigorous and
sustained level of R&D, but also a substantial level of commercial deployment. That will require
a significant market for CO2 capture technologies, which can only be established by government
actions. At present such a market does not yet exist. While various types of incentive programs
can accelerate the development and deployment of CO2 capture technology, actions that
significantly limit emissions of CO2 to the atmosphere ultimately are needed to realize substantial
and sustained reductions in the future cost of CO2 capture.
Author Contact Information
Peter Folger
Specialist in Energy and Natural Resources Policy
pfolger@crs.loc.gov, 7-1517
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