Carbon Capture: A Technology Assessment
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Carbon Capture: A Technology Assessment
(name redacted), Coordinator
Specialist in Energy and Natural Resources Policy
November 5, 2013
Congressional Research Service
7-....
www.crs.gov
R41325
CRS Report for Congress
Prepared for Members and Committees of Congress
Carbon Capture: A Technology Assessment
Summary
Carbon capture and sequestration (or carbon capture and storage, 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 would likely depend, in part, on the cost
of the technology deployed to capture CO2. This report assesses prospects for improved, lowercost 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 CO2 capture efficiencies (typically about 90%), the
major drawbacks of current processes are their high cost and the large energy requirements for
operation. Another drawback in terms of their availability for greenhouse gas mitigation is that at
present, there are still no full-scale applications of CO2 capture on a coal-fired or gas-fired power
plant (i.e., a scale of several hundred megawatts of plant capacity). 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. 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 postcombustion 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.
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).
Key questions regarding the outcomes from these R&D efforts are when advanced CO2 capture
systems would be available for commercial rollout, and how much cheaper they would 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 would be commercial in the 2020 time frame.
Such projections acknowledge, however, that this would require aggressive and sustained efforts
to advance promising concepts to commercial reality.
Achieving significant cost reductions would 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 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 would be needed to
realize substantial and sustained reductions in the future cost of CO2 capture.
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Carbon Capture: A Technology Assessment
Contents
Introduction...................................................................................................................................... 1
Authorship and Structure of the Report ........................................................................................... 1
Acknowledgment ....................................................................................................................... 2
Chapter 1: Executive Summary ....................................................................................................... 3
Background................................................................................................................................ 3
Current Research and Development (R&D) Activities ............................................................. 3
Future Outlook........................................................................................................................... 4
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
Liquid Solvent-Based Approaches .................................................................................... 35
Solid Sorbent-Based Approaches ...................................................................................... 37
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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
The Duct Sorbent Injection Process .................................................................................. 81
Implications for Advanced Carbon Capture Systems........................................................ 82
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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 PostCombustion 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 PostCombustion 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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Carbon Capture: A Technology Assessment
Introduction
Congressional interest has grown in carbon capture and sequestration (or carbon capture and
storage, CCS) as part of legislative strategies to mitigate global climate change. 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 would likely depend on whether
and how CCS is deployed if legislative or regulatory actions curtail future CO2 emissions.
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 would
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.
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. 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.
Authorship and Structure of the Report
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
aspects of U.S. energy policy. (name redacted), CRS Specialist in Energy and Natural Resources
Policy, served as the CRS project coordinator.
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.
The material in this report is current as of July 19, 2010. The report will not be updated.
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Acknowledgment
This report was funded, in part, by a grant from the Joyce Foundation.
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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; precombustion 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 postcombustion 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 gasificationbased 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.
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.
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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 oxycombustion 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 Mellon
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 oxycombustion 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).
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
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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
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
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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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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.1
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.2
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.
1
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.
2
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
Fossil Fuels;
Biomass
Air or
Oxygen
Power Plant
or Industrial
Process
CO2
USEFUL
PRODUCTS
(e.g., electricity, fuels,
chemicals, hydrogen)
CO2
Capture &
Compress
CO2
Transport
CO2 Storage
(Sequestration)
- Post-combustion
- Pre-combustion
- Oxyfuel combustion
- Pipeline
- Tanker
- Depleted oil/gas fields
- Deep saline formations
- Unmineable coal seams
- Deep Ocean
- Mineralization
- Reuse
Source: E. S. Rubin, “Will Carbon Capture and Storage be Available in Time?,” American Association 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, lowercost 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 PreCombustion 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.3
Figure 2.Technical Options for CO2 Capture
CO2 Separation and Capture
Absorption
Adsorption
Cryogenics
Membranes
Microbial/Algal
Systems
Chemical
Adsorber
Beds
Gas
Separation
MEA
Caustic
Other
Alumina
Zeolite
Activated C
Polyphenyleneoxide
Polydimethylsiloxane
Physical
Regeneration
Method
Gas
Absorption
Polypropelene
Selexol
Rectisol
Other
Pressure Swing
Temperature Swing
Washing
Ceramic Based
Systems
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).
3
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 precombustion 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
Steam
Turbine
Generator
Flue gas
to atmosphere
Electricity
Coal
Air
PC Boiler
Air Pollution
Control Systems
(NOx, PM, SO2)
CO2 Capture Mostly
N2
Amine
Stack
Steam
Amine/CO2
Amine/CO2
Separation
CO2
CO2
Compression
CO2 to
storage
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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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.4
4 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
Electricity
Steam
TurbineGenerator
Flue gas
to atmosphere
Natural
Gas
Combustor
Heat
Recovery
Steam Gen
Gas
Turbine
CO2 Capture
System
Amine
Air
Compressor
Air
Mostly
N2
Stack
Steam
Amine/CO2
Amine/CO2
Separation
CO2
CO2
Compression
CO2 to
storage
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
Electricity
Coal
H2O
Gasifier
Air
H2O
O2
Quench
System
Shift
Reactor
H2
H2 Gas Turbine
Sulfur
CO2 Capture
Combined
Removal CO2
Cycle Plant
Selexol
Sulfur
Recovery
Selexol/CO2
Selexol/CO2
Separation
CO2
CO2
Compression
Stack
Air
Separation
Unit
Air
Flue gas
to atmosphere
CO2 to
storage
Source: Rubin, “CO2 Capture.”
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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
H2 Fuel Gas
CO2 to Storage
(to Power Block)
Absorber
COMP3
Shifted
Syngas
COMP2
COMP1
Rich
Solvent
Lean
Solvent
CO2
Recycle
Gas
TURB1
Cooler
SUMP
FLASH1
CO2
FLASH2
CO2
FLASH3
TURB2
Pump
Source: Adapted from C. Chen, “A Technical and Economic Assessment of CO2 Capture Technology for IGCC
Power Plants”(Ph.D. thesis, Carnegie Mellon 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.5 Further details regarding the design, performance, and operation of pre-combustion
capture systems can be found in the literature.6
5
Scottish and Southern Energy, “SSE, BP and Partners Plan Clean Energy Plant in Scotland,” at http://www.scottishsouthern.co.uk/SSEInternet/index.aspx?id=894&TierSlicer1_TSMenuTargetID=444&
TierSlicer1_TSMenuTargetType=1&TierSlicer1_TSMenuID=6.
6
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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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
Steam
Turbine
Generator
Electricity
Stack
Flue gas
to atmosphere
Steam
Coal
Air Pollution
CO2
Control Systems
H2O
( PM, SO2)
PC Boiler
O2
Distillation
System
CO2
Compression
CO2 to
storage
Flue gas recycle
Air
Separation
Unit
H2O
Air
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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Carbon Capture: A Technology Assessment
have been proposed for commercial systems.7 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, postcombustion 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
Power plant type, and
capture system type
Net plant efficiency
(%) without CCS
Existing subcritical PC, postcombustion capture
Net plant efficiency
(%) with CCS
Energy penalty: Added
fuel input (%) per net
kWh output
33
23
40%
New supercritical PC, postcombustion capture
40
31
30%
New supercritical PC, oxycombustion capture
40
32
25%
New IGCC (bituminous coal),
pre-combustion capture
40
34
19%
New natural gas combined
cycle, post-combustion
capture
50
43
16%
Sources: Metz, Special Report; Massachusetts Institute of Technology (MIT), The Future of Coal (Cambridge, MA:
MIT, 2007); Carnegie Mellon 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
7
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
Energy Type and Function
Approximate % of Total
Energy Penalty
Thermal energy for amine solvent regeneration (post-combustion) or loss in watergas shift reaction (pre-combustion); or, electricity for oxygen production (oxycombustion)
~60%
Electricity for CO2 compression
~30%
Electricity for pumps, fans, etc.
~10%
Sources: MIT, “Future of Coal”; Carnegie Mellon, “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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SCPC
120
100
80
New
Natural
Gas-Fired
Plant
New
Plants
with
CCS
NGCC
Cost of Electricity (2007$ / MWh)
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
New
Subcritical
Coal Plant
IGCC
NGCC
IGCC
60
New
Advanced
Coal Plant
SCPC
PC
40
20
0
0
0.1
0.2
0.3
0.4
0.5
0.6
0.7
0.8
0.9
1.0
CO2 Emission Rate (tonnes / MWh)
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.8
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.9 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.10 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.11 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,
8
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.
9
Rao and Rubin, “Technical, Economic.”
10
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.
11
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
All 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.12 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.
12
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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Figure 10. Stages of Technological Change and Their Interactions
Invention
R&D
Innovation
(new or better
product)
Adoption
Diffusion
(early use)
(improved
technology)
Learning
By Doing
Learning
By Using
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 postcombustion carbon capture technologies,13 discussed later in “Chapter 5: Status of PostCombustion Capture.”
13
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.14
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.15 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.
14
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).
15
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, precombustion, 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).16 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 postcombustion 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.17 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.18
16
U.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.
17
G. Rochelle, “Amine Scrubbing for CO2 Capture,” Science, vol. 325 (2009), pp. 1652-1654.
18
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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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
Project Name and Location
Plant and
Fuel Type
Year of
Startup
Approx.
Capture Plant
Capacity
Capture
System Type
(Vendor)
CO2 Captured
(106
tonnes/yr)
United States
IMC Global Inc. Soda Ash Plant
(Trona, CA)
Coal and
petroleum cokefired boilers
1978
43 MW
Amine
(Lummus)
0.29
AES Shady Point Power Plant
(Panama City, OK)
Coal-fired power
plant
1991
9 MW
Amine
(Lummus)
0.06
Bellingham Cogeneration Facility
(Bellingham, MA)
Natural gas-fired
power plant
1991
17 MW
Amine (Fluor)
0.11
Warrior Run Power
Plant (Cumberland, MD)
Coal-fired
power plant
2000
8 MW
Amine
(Lummus)
0.05
Soda Ash Botswana Sua Pan
Plant (Botswana)
Coal-fired
power plant
1991
17 MW
Amine
(Lummus)
0.11
Sumitomo Chemicals
Plant (Japan)
Gas & coal boilers
1994
8 MW
Amine (Fluor)
0.05
Statoil Sleipner West Gas Field
(North Sea, Norway)
Natural gas
separation
1996
N/A
Amine (Aker)
1.0
Petronas Gas Processing Plant
(Kuala Lumpur, Malaysia)
Natural gas-fired
power plant
1999
10 MW
Amine (MHI)
0.07
BP Gas Processing Plant
(In Salah, Algeria)
Natural gas
separation
2004
N/A
Amine
(Multiple)
1.0
Mitsubishi Chemical Kurosaki
Plant (Kurosaki, Japan)
Natural gas-fired
power plant
2005
18 MW
Amine (MHI)
0.12
Snøhvit Field LNG and CO2
Storage Project
(North Sea, Norway)
Natural gas
separation
2008
N/A
Amine (Aker)
0.7
Huaneng Co-Generation Power
Plant (Beijing, China)
Coal-fired
power plant
2008
0.5 MW
Amine
(Huaneng)
0.003
Outside the United States
Sources: DOE, “NETL Carbon”; IEAGHG, “CO2 Capture”; MIT, “Carbon Capture”; GCCSI, “Strategic
Analysis.”
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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.19
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.20 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.
19
IEAGHG, “CO2 Capture.”
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.
20
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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.21
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.22 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.23
21
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.
22
Kuuskraa, “Accelerate Deployment.”
23
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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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
Project Name
and Location
Plant
and Fuel
Type
Year of
Startup
Approx.
Capture
Plant
Capacity
Capture
System
Type
(Vendor)
Annual CO2
Captured
(106 tonnes)
Current
Status
(March
2010)
United States
Basin Electric Antelope
Valley Station (Beulah,
ND)
Coal-fired
power
plant
2012
120 MW
Amine
(HTC)
1.0
Site
Selection
Tenaska Trailblazer
Energy Center
(Sweetwater, TX)
Coal-fired
power
plant
2014
600 MW
Amine
(Fluor)
4.3
Permitting
American Electric
Power Mountaineer
Plant (New Haven,
WV)
Coal-fired
power
plant
2015
235 MW
Chilled
Ammonia
(Alstom)
1.5
Scoping
Coal-fired
power
plant
2014
115 MW
Amine
(Cansolv)
1.0
Plant Design
E.ON Kingsnorth
Ruhrgas UK PostCombustion Project
(Kent, United Kingdom)
Coal-fired
power
plant
2014
300 MWa
Amine (Fluor
& MHI)
1.9
Plant Design
TransAlta Project
Pioneer Keephills 3
Power Plant
(Wabamun, Canada)
Coal-fired
power
plant
2015
200 MW
Chilled
Ammonia
(Alstom)
1.0
Plant Design
Vattenfall Janschwalde
(Janschwalde, Germany)
Coal-fired
power
plant
2015
125 MW
Amine (TBD)
—
Permitting
Porto Tolle (Rovigo,
Italy)
Coal-fired
power
plant
2015
200 MWa
Amine (TBD)
1.0
Scoping
Outside the United States
SaskPower
Boundary Dam Polygon
(Estevan, Canada)
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 scaleup 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
Plant
Capacity
Capture
System Type
(Vendor)
Annual CO2
Captured (106
tonnes)
1 MW
Ammonia
(Powerspan)
0.007
2009
20 MW
Chilled
Ammonia
(Alstom)
0.1
Coal-fired
power
plant
2009
0.5 MWa
Amines (Dow/
Alstom)
0.002
Coal-fired
power
plant
2012
60 MW
Amine (Fluor)
0.5
Nanko Natural Gas Pilot
Plant (Osaka, Japan)
Gas-fired
power
plant
1991
0.1 MW
Amine (MHI)
0.001
Matsushima Coal Plant
(Nagasaki, Japan)
Coal-fired
power
plant
2006
0.8 MWa
Amine (MHI)
0.004
Project Name
and Location
Plant and
Fuel Type
Year of
Startup
First Energy R.E. Burger Plant
(Shadyside, OH)
Coal-fired
power
plant
2008
American Electric Power
Mountaineer Plant
(New Haven, WV)
Coal-fired
power
plant
Dow Chemicals South
Charleston Plant
(Charleston, WV)
NRG Energy WA Parish Plant
(Houston, TX)
United States
Outside the United States
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Carbon Capture: A Technology Assessment
Project Name
and Location
Plant and
Fuel Type
Year of
Startup
Approx.
Capture
Plant
Capacity
Munmorah Pilot Plant
(Lake Munmorah, Australia)
Coal-fired
power
plant
2008
Tarong Power Station
(Nanango, Australia)
Coal-fired
power
plant
Hazelwood Carbon Capture
(Morewell, Australia)
Capture
System Type
(Vendor)
Annual CO2
Captured (106
tonnes)
1 MWa
Ammonia (Delta
& CSIRO)
0.005
2008
0.5 MWa
Amine (Tarong
& CSIRO)
0.0015
Coal-fired
power
plant
2008
2 MW
Amine (Process
Group)
0.01
CASTOR CO2 from Capture
to Storage (Esbjerg,
Denmark)
Coal-fired
power
plant
2008
3 MW
Amine (Multiple)
0.008
Eni and Enel Federico II
Brindisi Power Plant
(Brindisi, Italy)
Coal-fired
power
plant
2009
1.5 MW
Amine (Enel)
0.008
CATO-2 CO2 Catcher
(Rotterdam, Netherlands)
Coal-fired
power
plant
2008
0.4 MW
Amine (Multiple)
0.002
Statoil Mongstad
Cogeneration Pilot
(Mongstad, Norway)
Natural
gas-fired
power
plant
2010
15 MWa
Chilled NH3
(Alstom)
0.08
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.24
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
24
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.25
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.26
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.
25
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.
26
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.27 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.
27
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.28 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 Mellon
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.29 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
28
U.S. Department of Energy, Proceedings of 1st Existing Plant Program Annual Meeting, National Energy
Technology Laboratory, Pittsburgh, PA, March 2008.
29
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,
often forming a salt. The solvent is
regenerated by heating
(temperature swing), which
reverses the absorption reaction
(normally exothermic). Solvent is
often alkaline.
Chemical solvents provide fast
kinetics to allow capture from
streams with low CO2 partial
pressure.
The large amount of steam required
for solvent regeneration de-rates the
power plant significantly.
Wet scrubbing allows good heat
integration and ease of heat
management (useful for exothermic
absorption reactions).
Energy required to heat, cool, and
pump non-reactive carrier liquid
(usually water) is often significant.
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.30 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.31 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.32 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.33
30
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.
31
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.
32
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.
33
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.34
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.35
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 CO2.36 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.37
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.38 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.39 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.40 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.
34
GCCSI, “Strategic Analysis.” DOE, “Carbon Dioxide Capture.”
35
Figueroa et al., “Advances CO2 Capture.”
36
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.
37
Clean Air Task Force, “Coal without Carbon.”
38
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.
39
DOE, “Carbon Dioxide Capture.”
40
GCCSI, “Strategic Analysis.”
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Carbon Capture: A Technology Assessment
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 Mellon
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.41 The amine sorbent can be physically supported by a number
of different materials, including relatively inexpensive activated carbon.42 Such sorbents have
been shown to have high CO2 carrying capacities compared to other solid sorbents.43 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 SO2.44
Sodium carbonate-based sorbents also have been recognized for their CO2 capture potential,45
although their performance is degraded by contaminants in flue gas.46 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.47
41
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.
42
M. G. Plaza et al., “CO2 Capture by Adsorption with Nitrogen Enriched Carbons,” Fuel, vol. 86 (2007), pp.
2204-2212.
43
S. Sjostrom and H. Krutka, “Evaluation of Solid Sorbents as a Retrofit Technology for CO2 Capture,” Fuel, vol. 89
(2010), pp. 1298-1306.
44
DOE, “Technology Sheets.”
45
Y. Liang et al., “Carbon Dioxide Capture Using Dry Sodium-Based Sorbent,” Energy & Fuels, vol. 18 (2004), pp.
569-575.
46
GCCSI, “Strategic Analysis.”
47
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.48 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.49 Researchers at the University of Akron are
investigating an approach combining zeolites with amines to improve overall performance.50
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.51 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 pellets are contacted
with flue gas, CO2 is absorbed onto
chemically reactive sites on the pellet.
Pellets are then regenerated by a
temperature swing, which reverses
the absorption reaction.
Chemical sites provide large
capacities and fast kinetics, enabling
capture from streams with low CO2
partial pressure.
Heat required to reverse chemical
reaction (although generally less than
for wet-scrubbing).
Higher capacities on a per mass or
volume basis than similar wetscrubbing chemicals.
Lower heating requirements than
wet-scrubbing in many cases (CO2
and heat capacity dependent).
Heat management in solid systems is
difficult. This can limit capacity and/or
create operational issues for
exothermic absorption reactions.
Pressure drop can be large in flue gas
applications.
Sorbent attrition may be high.
Source: DOE, “Carbon Dioxide Capture.”
48
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.’
49
Clean Air Task Force, “Coal without Carbon.”
50
Figueroa et al., “Advances CO2 Capture.”
51
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.52 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.53 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 CO2.54 Another active research
area is gas absorption membranes.55 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.56 This
approach holds potential for better performance than conventional absorber and stripper
configurations.57
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.58 One effort to exploit this
process is a liquid membrane system catalyzed by carbonic anhydrase being developed by
Carbozyme Inc.59 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
52
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.
53
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.
54
Figueroa et al., “Advances CO2 Capture”; Clean Air Task Force, “Coal without Carbon.”
55
EPRI, “Post-Combustion.”
56
GCCSI, “Strategic Analysis.”
57
Clean Air Task Force, “Coal without Carbon.”
58
E. Hand, “The Power Player,” Nature, vol. 462 (2009), pp. 978-983.
59
Figueroa et al., “Advances CO2 Capture.”
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capture.60 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.61
Table 11. Technical Advantages and Challenges for Membrane-Based Approaches
to Post-Combustion CO2 Capture
Description
Advantages
Challenges
Uses permeable or semi-permeable
materials that allow for the
selective transport and separation
of CO2 from flue gas.
No steam load.
Membranes tend to be more suitable for
high-pressure processes such as IGCC.
No chemicals needed.
Tradeoff between recovery rate and product
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.62
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
60
Clean Air Task Force, “Coal without Carbon.”
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.
62
Favre, “Biogas, Membranes.”
61
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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.63 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.
63
M. D. Eisaman, “CO2 concentration using bipolar membrane electrodialysis,” Proc. Gordon Research Conference on
Electrochemistry, 2010.
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Figure 17. Schematic of a Process Concept Using Electrodialysis to Capture
and Regenerate CO2, While Generating Hydrogen and Oxygen as By-Products
Clean
Flue Gas
Recovered (lean) solvent
(mainly N2)
CO2
O2
H2
(to storage)
(byproduct)
(byproduct)
K+
K+
+
CO2
scrubber
OHH+
CO2-rich solvent
H+
-
HCO3OH-
Electrodialysis
Solvent Recovery
CO2- laden
Flue Gas
Source: Edward S. Rubin, Aaron Marks, Hari Mantripragada, Peter Versteeg, and John Kitchin, Carnegie Mellon
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.64
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.65 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.66 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.
64
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.
65
H. W. Pennline et al., “Separation of CO2 from flue gas using electrochemical cells,” Fuel, vol. 89 (2010), pp. 13071314.
66
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.67 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.”68 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 PostCombustion 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 typically requires a stream of concentrated CO2
that has already been captured.
67
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.’
68
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 precombustion 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.69 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 precombustion 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
69
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.70 Nevertheless, it appears reasonable that at least some of the largescale 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
Project Name and Location
Plant and
Fuel Type
Expected
Year of
Startup
Plant Size or
Capacity
CO2
Capture
System
Annual CO2
Captured
(106 tonnes)
United States
Baard Energy Clean Fuels
(Wellsville, Ohio)
Coal+biomass
to liquids
2013
53,000
barrels/day
Rectisol
N/A
DKRW Energy (Medicine Bow,
Wyoming)
Coal to liquids
2014
20,000
barrels/day
Selexol
N/A
Summit Power (Penwell, Texas)
Coal IGCC
2014
400 MWg
Selexol
3.0
Taylorville Energy Center
(Taylorville, Illinois)
Coal IGCC
2014
602 MW
N/A
N/A
Mississippi Power, Kemper
County IGCC (Mississippi)
Lignite IGCC
2014
584 MW
N/A
N/A
Wallula IGCC (Walla Walla
County, Washington)
Coal IGCC
2014
600-700 MW
N/A
N/A
Hydrogen Energy
(Kern County, California)
Petcoke IGCC
2015
250 MW
N/A
N/A
Southern California Edison
IGCC (Utah)
Coal IGCC
2017
500 MW
Selexol
3.5
FutureGen Alliance
(Mattoon, Illinois)a
Coal IGCC
>2012a
275 MW
N/A
N/A
Coal IGCC and
poly-generation
2011
(stage I)
250 MW
N/A
N/A
Eston Grange IGCC
(Teesside, UK)
Coal IGCC
2012
800 MW
N/A
5
Hartfield IGCC (Hartfield, UK)
Coal IGCC
2014
900 MW
Selexol
4.5
Genesee IGCC
(Edmonton, Canada)
Coal IGCC
2015
270 MW
N/A
1.2
RWE Goldenbergwerk
(Hurth, Germany)
Lignite IGCC
2015b
360 MW
N/A
2.3
Outside the United States
GreenGen (Tianji Binhai, China)
70
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
Year of
Startup
Plant Size or
Capacity
CO2
Capture
System
Annual CO2
Captured
(106 tonnes)
Project Name and Location
Plant and
Fuel Type
Kedzierzyn Zero Emission
Power and Chemicals (Opole,
Poland)
Coal-biomass
IGCC and
polygen
2015
309 MW
N/A
2.4
Nuon Magnumc
(Eeemshaven, Nether
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