# Carbon Capture: A Technology Assessment > Briefs, arguments, decisions, and more. URL: https://www.frixlaw.com/law-library/documents/crs%3AR41325 ## Record - **Collection:** Congressional research report - **Document type:** CRS Report - **Published:** November 5, 2013 - **Citation:** R41325 ## Text 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. Congressional Research Service 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 Congressional Research Service Carbon Capture: A Technology Assessment 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 Congressional Research Service Carbon Capture: A Technology Assessment 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 Congressional Research Service Carbon Capture: A Technology Assessment 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 Congressional Research Service Carbon Capture: A Technology Assessment 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 Congressional Research Service Carbon Capture: A Technology Assessment 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 Congressional Research Service 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. Congressional Research Service 1 Carbon Capture: A Technology Assessment Acknowledgment This report was funded, in part, by a grant from the Joyce Foundation. Congressional Research Service 2 Carbon Capture: A Technology Assessment 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. Congressional Research Service 3 Carbon Capture: A Technology Assessment 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 Congressional Research Service 4 Carbon Capture: A Technology Assessment 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 Congressional Research Service 5 Carbon Capture: A Technology Assessment 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. Congressional Research Service 6 Carbon Capture: A Technology Assessment Chapter 2: Background and Scope of Report Introduction Global climate change is an issue of major international concern and the focus of proposed mitigation policy measures in the United States and elsewhere. In this context, the technology of carbon capture and storage (CCS) has received increasing attention over the past decade as a potential method of limiting atmospheric emissions of carbon dioxide (CO2)—the principal “greenhouse gas” linked to climate change. Worldwide interest in CCS stems principally from three factors. First is a growing consensus that large reductions in global CO2 emissions are needed to avoid serious climate change impacts.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. Congressional Research Service 7 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, Congressional Research Service 8 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. Congressional Research Service 9 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. Congressional Research Service 10 Carbon Capture: A Technology Assessment 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. Congressional Research Service 11 Carbon Capture: A Technology Assessment With current technology, the most effective method of CO2 capture from the flue gas of a PC plant is by chemical reaction with an organic solvent such as monoethanolamine (MEA), one of a family of amine compounds. In a vessel called an absorber, the flue gas is “scrubbed” with an amine solution, typically capturing 85% to 90% of the CO2. The CO2-laden solvent is then pumped to a second vessel, called a regenerator, where heat is applied (in the form of steam) to release the CO2. The resulting stream of concentrated CO2 is then compressed and piped to a storage site, while the depleted solvent is recycled back to the absorber. Figure 4 shows details of a post-combustion capture system design. Figure 4. Details of Flue Gas and Sorbent Flows for an Amine-Based Post-Combustion CO2 Capture System (absorber is shown on the left, and regenerator on the right) Source: Metz, Special Report. The same post-combustion capture technology that would be used at a PC plant also would be used for post-combustion CO2 capture at a natural gas-fired boiler or combined cycle (NGCC) power plant (see Figure 5). Although the flue gas CO2 concentration is more dilute than in coal plants, high removal efficiencies can still be achieved with amine-based capture systems. The absence of impurities in natural gas also results in a clean flue gas stream, so that no additional cleanup is needed for effective CO2 capture. Further details on the design, performance, and operation of amine-based capture technologies can be found in the technical literature.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. Congressional Research Service 12 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.” Congressional Research Service 13 Carbon Capture: A Technology Assessment Although the fuel conversion steps of an IGCC plant are more elaborate and costly than traditional coal combustion plants, CO2 separation is much easier and cheaper because of the high operating pressure and high CO2 concentration of this design. Thus, rather than requiring a chemical reaction to capture CO2 (as with amine systems in post-combustion capture), the mechanism employed in pre-combustion capture involves physical adsorption onto the surface of a solvent, followed by release of the CO2 when the sorbent pressure is dropped, typically in several stages, as depicted in Figure 7. Figure 7. Details of the Fuel Gas and Sorbent Flows for Pre-Combustion CO2 Capture 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. Congressional Research Service 14 Carbon Capture: A Technology Assessment Oxy-Combustion Systems Oxy-combustion (or oxyfuel) systems are being developed as an alternative to post-combustion CO2 capture for conventional coal-fired power plants. Here, pure oxygen rather than air is used for combustion. This eliminates the large amount of nitrogen in the flue-gas stream. After the particulate matter (fly ash) is removed, the flue gas consists only of water vapor and CO2, plus smaller amounts of pollutants such as sulfur dioxide (SO2) and nitrogen oxides (NOx). The water vapor is easily removed by cooling and compressing the flue gas. Additional removal of air pollutants leaves a nearly pure CO2 stream that can be sent directly to storage, as depicted in Figure 8. Figure 8. Schematic of a Coal-Fired Power Plant Using Oxy-Combustion 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 Congressional Research Service 15 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. Congressional Research Service 16 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). Congressional Research Service 17 Carbon Capture: A Technology Assessment 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. Congressional Research Service 18 Carbon Capture: A Technology Assessment 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. Congressional Research Service 19 Carbon Capture: A Technology Assessment 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.” Congressional Research Service 20 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). Congressional Research Service 21 Carbon Capture: A Technology Assessment 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. Congressional Research Service 22 Carbon Capture: A Technology Assessment 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. Congressional Research Service 23 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 Congressional Research Service 24 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. Congressional Research Service 25 Carbon Capture: A Technology Assessment 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. Congressional Research Service 26 Carbon Capture: A Technology Assessment The hundreds of commercial aqueous amine systems currently in operation typically vent the captured CO2 to the atmosphere. Of the projects listed in Table 5, three are at natural gas treatment plants (two in Norway, one in Algeria) in which the captured CO2 is sequestered in deep geological formations to prevent its release to the atmosphere. One of these projects, the Statoil natural gas production facility at Sleipner in the North Sea, has been operating since 1996. This is the longest-running commercial CCS project. Figure 13 shows a photograph of the amine-based CO2 capture unit installed more recently at a natural gas treatment plant in Algeria. That unit is part of an integrated CCS system that includes CO2 capture, pipeline transport, and sequestration in a nearby geological formation. Table 5. Commercial Post-Combustion Capture Processes at Power Plants and Selected Industrial Facilities 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.” Congressional Research Service 27 Carbon Capture: A Technology Assessment Figure 13. An Amine-Based CO2 Capture System Used to Purify Natural Gas at BP’s In Salah Plant in Algeria Source: Photo courtesy of IEA Greenhouse Gas Programme. As shown in Table 5, CO2 is also captured at several coal-fired and gas-fired power plants where a portion of the flue gas stream is fitted with a CO2 capture system. Figure 14 shows the amine systems installed at two U.S. power plants, one burning coal, the other natural gas. The CO2 captured at these plants is sold to nearby food processing facilities, which use it to make dry ice or carbonated beverages. The oldest and largest commercial CO2 capture system operating on flue gases is the IMC Global soda ash plant in California. Here, the mineral trona is mined locally and combined with CO2 to produce sodium carbonate (soda ash), a widely used industrial chemical.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 Congressional Research Service 28 Carbon Capture: A Technology Assessment Figure 14. Amine-Based Post-Combustion CO2 Capture Systems Treating a Portion of the Flue Gas from a Coal-Fired Power Plant in Oklahoma, USA (left), and a Natural Gas Combined Cycle (NGCC) Plant in Massachusetts, USA (right) Source: Photos courtesy of ABB Lummus, Fluor Daniels, and Chevron. Full-Scale Demonstration Plants Although several CO2 capture systems have operated commercially for nearly two decades on a portion of power plant flue gases, no capture units have yet been applied to the full flue gas stream of a modern coal-fired or gas-fired power plant. Thus, one or more demonstrations of post-combustion CO2 capture at full scale are widely regarded as crucial for gaining the acceptance of this technology by electric utility companies, as well as by the institutions that finance and regulate power plant construction and operation. Several years ago, for example, the European Union called for 12 such demonstrations in Europe, while in the United States there have been calls for at least 6 to 10 full-scale projects.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. Congressional Research Service 29 Carbon Capture: A Technology Assessment Nevertheless, it appears reasonable to assume that at least some of the large-scale projects currently planned for post-combustion CO2 capture in the United States and other countries will materialize over the next several years, with costs shared between the public and private sectors. Table 6 lists the features and locations of major announced demonstration projects at power plants in the United States and other countries. Most of these CO2 capture systems would be installed at existing coal-fired plants, with the captured CO2 transported via pipeline to a geological storage site (often in conjunction with enhanced oil recovery to reduce project costs). Table 6. Planned Demonstration Projects at Power Plants with Full-Scale Post-Combustion Capture 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. Congressional Research Service 30 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 Congressional Research Service 31 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). Congressional Research Service 32 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. Congressional Research Service 33 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.” Congressional Research Service 34 Carbon Capture: A Technology Assessment Laboratory- or Bench-Scale Processes A large number o [Text truncated at 120,000 characters. The full text is on the page linked above.] --- Source: Frix Law Library, https://www.frixlaw.com/law-library/documents/crs%3AR41325. Public record. Not legal advice.