A Review of CO2 Capture and Processing

                             Contract EP-W-10-055
                              Work Assignment 27
                        Technical Directive 3, Part 3

                                    6/25/12
                                  Revised(2)

                     Submitted by The Cadmus Group, Inc.
Under Subcontract to Eastern Research Group, Inc.
                    A Review of CO2 Capture and Processing
Abstract
A cursory review of capture and processing technologies for CO2 is conducted to identify those techniques and designs that are currently being used and activities take place between capture and transport of CO2, referred to as "processing" in this paper. This review includes general description of each technology and activity identified, provides manufacturers' information where available for the equipment and/or materials used, and summarizes costs associated with these technologies as estimated and reported in the literature.
Introduction
Carbon capture and storage (CCS) is a step-wise process including the capture of carbon dioxide (CO2) from industrial and power generating sources; transport of the captured CO2 to injection facilities; and injection of the captured CO2 into suitable geologic reservoirs for long-term storage.   A typical CCS chain includes four steps: (1) Power plant with CO2 capture; (2) Processing of CO2, including conditioning and compression; (3) Transport (pipeline or ship); and (4) Recompression (if necessary) and Final Storage. An overview of a CCS chain is provided in Figure 1 below.
System requirements (e.g., temperature, pressure, CO2 quality) for a CCS chain depend upon the chosen transport mechanism (e.g., pipeline, ship) and also the terminal point of the transport and storage requirements (Aspelund and Jordal, 2007). Therefore, capture and processing specifications for CO2 are not only determined by the available technologies, but also by the requirements for transport (pipeline) and final injection (Figure 1).  The composition of the CO2 stream is not expected to change during transport unless there is significant leakage, which necessitates that the CO2 quality specifications for injection and transport be met by the CO2 capture and conditioning process and be determined by the safety and operation requirements in the pipeline, reservoir requirements, technical and economical evaluation, and regulatory framework.
Gas
Conditioning
Compression
Pipeline
Transport
Injection/Final Storage
Capture
Figure 1. A typical CCS chain (Aspelund and Jordal, 2007).
This paper provides an overview of CO2 capture and processing prior to pipeline transport, including descriptions of associated technologies and methodologies for capturing, conditioning, and compressing CO2, which are shown as red boxes in Figure 1. Some background information is given in the following section on the physical and chemical CO2 transport and storage specifications that control the selection of capture and processing technologies. This review also includes a summary inventory of the current capture and processing facilities in the United States (US) presented in Appendix A.
Background Information
CO2Transport and Storage Requirements
The discussion of physical and chemical specifications for transport and storage of CO2 is presented in this section as background to supplement the review information provided later in the document as these requirements or specifications have direct effect on the design and/or selection of specific technologies for capturing and processing.
Furthermore, there are multiple options for transporting compressed CO2 from the source to the geologic sequestration site, including motor carrier, rail, and pipeline. Although the selection of a transport option depends upon multiple factors (e.g., location of capture and storage), the quantity to be transported is the dominant factor. On average, a single 500-MW coal-fired power plant would need to transport 2-3 million metric tonnes (Mt) of compressed CO2 in a year (Wilcox, 2012). Therefore, the pipeline transport may be considered as the only viable option for overland transport and is the transport option considered in the discussion below. However, some specifications for ship transport in terms of pressure and temperature values can also be found in Figure 2.
Physical Requirements
Regardless of whether CO2 is destined for geologic sequestration or used as a feedstock in chemical processing, aggregate formation, or enhanced oil recovery (EOR), it must be compressed for transport following capture and separation (Wilcox, 2012).
In order to efficiently transport large amounts, CO2 must be transformed into a high density form, such as liquid, solid, or in supercritical phase. For pipeline transport, CO2 must be compressed and cooled to the liquid and/or supercritical state (Wilcox, 2012). By operating the pipelines at the supercritical pressure of CO2 (above 7.38 MPa), the formation of CO2 gas with subsequent complexities of multiphase flow, and frictional and static pressure drops are avoided. NETL (2011) notes that the captured CO2 is needed to be compressed to typical pipeline levels of 1,500-2,200 psia (approximately 10 MPa  -  15MPa). As shown in Figure 2, typical pipeline transport conditions for CO2 are also defined approximately as 8-15 MPa (about 80-150 bar) by Wilcox (2012).

Figure 2. Phase diagram of CO2 indicating pressure and temperature ranges for pipeline transport (Wilcox, 2012).
Figure 3 presents the CO2 density as a function of pressure. The CO2 density ranges between 800 and 1000 kg/m[3] under typical pipeline transport pressures. The operating temperatures are assumed to be equivalent to the surrounding soil temperatures, which can vary seasonally from several degrees below zero to 6-8 °C; in some tropical regions this may be as high as 20 °C (Wilcox, 2012).

Figure 3. CO2 density as a function of pressure (Aspelund et al., 2006).
Chemical Requirements
Processing specifications for CO2 depend upon a variety of factors including the gas stream temperature, pressure, and composition following capture, and also requirements for the pipeline transport (Figure 1). The gas quality from the power plant or an industrial source will vary depending on both the capture process and the original feedstock (e.g., coal, natural gas, and biomass). For instance, on a dry basis, the gas quality ranges from almost pure (amine absorption) to less than 95% for some oxyfuel processes for natural gas. Coal or biomass power plants will generally have a higher concentration of impurities (e.g., H2S) and volatiles (e.g., N2) (Maroto-Valer, 2010). More information on the gas quality and capture processes is provided in the following section.
Table 1 and Table 2 below present some recommended quality parameters for CO2 pipeline transport and several different injection cases.
Table 1. Quality recommendations for CO2 transported by pipeline (Maroto-Valer, 2010).
                                   Component
                                 Concentration
                                  Limitation
                                    Reason
                                      H2O
500 ppm
Design and operational
Corrosion, hydrate formation
                                      H2S
200 ppm
Health and safety considerations
Short-term exposure limits
                                      CO
2000ppm
Health and safety considerations
Short-term exposure limits
                                      CH4
Aquifer <4 vol.%, EOR <2 vol.%
As proposed in ENCAP project*
Costs/Energy
                                      N2
<4 vol.% (all non-condensable gases)
As proposed in ENCAP project*
Costs
                                      O2
N/A
Inconsistent literature
Challenges in the reservoir
                                      Ar
<4 vol.% (all non-condensable gases)
As proposed in ENCAP project*
Costs
                                      H2
<4 vol.% (all non-condensable gases)
Reduction is recommended due to its energy content
Costs/Energy
                                      CO2
>95.5%
Balanced with other compounds
Economy
* European Enhanced Capture of CO2 Project (ENCAP) (http://www.encapco2.org/).

Table 2. Recommended CO2 stream composition limits for three design cases (DOE, 2012).
                                   Component
                       Unit (Max unless Otherwise noted)
                                 Carbon Steel
                                   Pipeline
                                 Enhanced Oil
                                   Recovery
                               Saline Reservoir
                                 Sequestration
                                    Saline
                                   Reservoir
                        CO2 & H2S Co-sequestration
                                    Venting
                                   Concerns

                                   Conceptual
                                     Design
                              Range in Literature
                                   Conceptual
                                     Design
                              Range in Literature
                                   Conceptual
                                     Design
                              Range in Literature
                                   Conceptual
                                     Design
                              Range in Literature

                                      CO2
                                  vol% (Min)
                                      95
                                    90-99.8
                                      95
                                    90-99.8
                                      95
                                    90-99.8
                                      95
                                  20  -  99.8
                             Yes-IDLH 40,000 ppmv
                                      H2O
                                     ppmwt
                                      300
                                   20 - 650
                                      300
                                   20 - 650
                                      300
                                   20 - 650
                                      300
                                   20 - 650

                                      N2
                                     vol%
                                       4
                                   0.01 - 7
                                       1
                                   0.01 - 2
                                       4
                                   0.01 - 7
                                       4
                                  0.01  -  7

                                      O2
                                     vol%
                                       4
                                  0.01  -  4
                                     0.01
                                 0.001  -  1.3
                                       4
                                  0.01  -  4
                                       4
                                  0.01  -  4

                                      Ar
                                     vol%
                                       4
                                  0.01  -  4
                                       1
                                  0.01  -  1
                                       4
                                  0.01  -  4
                                       4
                                  0.01  -  4

                                      CH4
                                     vol%
                                       4
                                  0.01  -  4
                                       1
                                  0.01  -  2
                                       4
                                  0.01  -  4
                                       4
                                  0.01  -  4
                           Yes-Asphyxiate, Explosive
                                      H2
                                     vol%
                                       4
                                   0.01 - 4
                                       1
                                  0.01  -  1
                                       4
                                  0.01  -  4
                                       4
                                  0.02  -  4
                           Yes-Asphyxiate, Explosive
                                      CO
                                     ppmv
                                      35
                                   10 - 5000
                                      35
                                   10 - 5000
                                      35
                                   10 - 5000
                                      35
                                   10 -5000
                              Yes-IDLH 1,200 ppmv
                                      H2S
                                     vol%
                                     0.01
                                 0.002  -  1.3
                                     0.01
                                 0.002  -  1.3
                                     0.01
                                 0.002  -  1.3
                                      75
                                    10 - 77
                               Yes-IDLH 100 ppmv
                                      SO2
                                     ppmv
                                      100
                                   10 -50000
                                      100
                                  10 - 50000
                                      100
                                  10 - 50000
                                      100
                                   10 -50000
                               Yes-IDLH 100 ppmv
                                      NOX
                                     ppmv
                                      100
                                   20 - 2500
                                      100
                                   20 - 2500
                                      100
                                   20 - 2500
                                      100
                                    20-2500
                                   Yes-IDLH
                          NO-100 ppmv, NO2 -200 ppmv
                                      NH3
                                     ppmv
                                      50
                                     0-50
                                      50
                                     0-50
                                      50
                                     0-50
                                      50
                                     0-50
                                   Yes-IDHL
                                   300 ppmv
                                      COS
                                     ppmv
                                     trace
                                     trace
                                       5
                                      0-5
                                     trace
                                     trace
                                     trace
                                     trace
                 Lethal @ High Concentrations (>1,000 ppmv)
                                     C2H6
                                     vol%
                                       1
                                     0 - 1
                                       1
                                     0 - 1
                                       1
                                     0 - 1
                                       1
                                     0 - 1
                           Yes-Asphyxiate, Explosive
                                     C3[+]
                                     vol%
                                     <1
                                     0 - 1
                                     <1
                                     0 - 1
                                     <1
                                     0 - 1
                                     <1
                                     0 - 1

                                     Part.
                                     ppmv
                                       1
                                     0 - 1
                                       1
                                     0 - 1
                                       1
                                     0 - 1
                                       1
                                     0 - 1

                                      HCl
                                     ppmv
                                      N/A
                                      N/A
                                      N/A
                                      N/A
                                      N/A
                                      N/A
                                      N/A
                                      N/A
                               Yes-IDLH 50 ppmv
                                      HF
                                     ppmv
                                      N/A
                                      N/A
                                      N/A
                                      N/A
                                      N/A
                                      N/A
                                      N/A
                                      N/A
                               Yes-IDLH 30 ppmv
                                      HCN
                                     ppmv
                                     trace
                                     trace
                                     trace
                                     trace
                                     trace
                                     trace
                                     trace
                                     trace
                               Yes-IDLH 50 ppmv
                                      Hg
                                     ppmv
                                      N/A
                                      N/A
                                      N/A
                                      N/A
                                      N/A
                                      N/A
                                      N/A
                                      N/A
                          Yes-IDLH 2 mg/m[3] (organo)
                                    Glycol
                                     ppmv
                                      46
                                     0-174
                                      46
                                     0-174
                                      46
                                     0-174
                                      46
                                     0-174

                                      MEA
                                     ppmv
                                      N/A
                                      N/A
                                      N/A
                                      N/A
                                      N/A
                                      N/A
                                      N/A
                                      N/A
                       MSDS Exp. Limits 3 ppmv, 6 mg/m3
                                    Selexol
                                     ppmv
                                      N/A
                                      N/A
                                      N/A
                                      N/A
                                      N/A
                                      N/A
                                      N/A
                                      N/A

For pipeline transport, the main considerations are corrosion and hydrate formation. Free water present in the CO2 will cause operational challenges. Furthermore, transporting other gases will result in additional costs due to an increase in compressor power and higher investment costs for the pipeline. Health and safety considerations also affect the desired design factors. For example, recommended limits (Table 1 and Table 2) for H2S are based on the toxicity of the components (DOE, 2012). Specifically, the 0.01 (vol%) limit was determined based on the total weighted average value from National Institute for Occupational Safety and Health (NIOSH) (10 ppm) and Dynamis' (2007) 200 ppm recommendation, which would be cost prohibitive to implement (DOE, 2012). The 200 ppm recommendation was established by applying a safety factor of five on the known maximum exposure limit of 1000 ppm (Dynamis, 2000; DOE, 2012). The Immediately Dangerous to Life and Health (IDLH) concentration, or the maximum level to which an individual may be exposed for 30 minutes without suffering irreversible health effects, has been set by NIOSH for H2S at 300 ppm (CDC, 2012).
The type of reservoir (e.g., EOR or geologic sequestration) may also affect the gas quality specifications. For EOR operations, immiscible components may increase the miscible pressure in the reservoir and decrease the efficiency of the CO2. Similarly, oxygen in the CO2 stream may cause precipitation reactions and thereby reduce the permeability of the reservoir. Additionally, oxygen may cause overheating at the injection point by reacting with oil. However, oxygen removal to the desired levels may not be achieved during conventional separation without significantly increasing the reboiler and condenser duty, which in turn would increase the complexity and costs for conditioning of all oxyfuel concepts.
Methodology & Data
Researching the processes and technologies used for CO2 capture and processing involved collecting and analyzing information from a variety of sources.  Sources include studies, fact sheets, and reports from federal government agencies (primarily DOE/NETL), universities, CO2 capture and processing technology manufacturers, and NETL grantees receiving funding for research and development in this area. The majority of sources cited in this report were previously subjected to peer review (e.g. peer reviewed journal articles, NETL reports).
The NETL's Carbon Capture and Storage Database (Version 3), which was last updated in April, 2011, served as the base of information for developing the inventory of capture and processing facilities in the US (Table A-1 in the Appendix). Additional projects were included in the inventory from EPA's OAR table of projects, as well as from the following sources: Massachusetts Institute of Technology's Carbon Capture and Sequestration Technologies website, the Global CCS Institute, the Zero Emissions Resource Organization, and the European Technology Platform for Zero Emission Fossil Fuel Power Plants. Each project was individually researched to understand the status of the operation (i.e., active, potential, terminated, etc.), and the types of technologies used for carbon capture and processing. Table A-1 in the Appendix contains the following information (where data is available): the name of the project; the CO2 plant/source; the type of project (i.e., capture only, or capture and injection); the state; operating status (i.e., active, potential, on hold, cancelled, or terminated); unit base power; the project start date; cost; capture type and technology; % CO2 capture; capture rate; the number of capture units; the fate of the CO2; and processing technologies used. Note that complete information is not available for all projects, particularly for processing technologies. Table A-2 in the Appendix contains a complete listing of sources used for each project, which included the above mentions sources, in addition to project and facility websites.
The inventory of CO2 capture and processing facilities in the Appendix differs slightly from the information provided in the table in the Assessments of Carbon Dioxide Sequestration Demonstration Projects (Assessment report). The key difference is that the table in this report contains only projects where CO2 capture is part of the process, whereas the Assessment report focuses on projects involving CO2 injection. Thus, while there is some overlap between the tables (e.g., projects that involve both capture and injection), injection-only projects are not included in this report.
Similarly, inventory provided in this table differs from the document "ASSESSMENT OF THE POTENTIAL COSTS, BENEFITS, AND OTHER IMPACTS OF THE CONDITIONAL EXCLUSION FROM THE RCRA DEFINITION OF HAZARDOUS WASTE FOR CO2 STREAMS MANAGED IN UIC CLASS VI WELLS FOR THE PURPOSES OF GEOLOGIC SEQUESTRATION, AS PROPOSED" even though some of the same databases are used for the current search. The access date to these databases in the Economic Analysis document above is not given. However, it is anticipated that the updated database information is the reason for the differences.
Results & Findings
Capture and processing technologies are discussed in the following two sections. Additionally, a discussion of costs associated with capture and processing technologies is also included in a separate subsection here.
Capture
CO2 capture processes have been used for decades for natural gas purification and chemical processing, with chemical and physical solvents as the best established methods; emerging capture technologies are also under development. The potential suitability of the various established and emerging methods for a particular facility depends, among other factors, on the power plant technology and the characteristics of the flue gas stream. CO2 capture may take place in the following power plant scenarios: post-combustion capture, capture from an oxy-combustion system, or pre-combustion capture (see Figure 4 and Table 3). Prior to a discussion below of specific capture technologies, the three types of capture scenarios are described as follows:
1. In post-combustion capture, CO2 is removed from the gas stream prior to discharge to the atmosphere.  For a conventional coal- or gas-fired power plant, the CO2 capture process would be located downstream of pollutant controls such as flue gas desulfurization and particulate removal (DOE/NETL, 2011).  The CO2 concentration in the flue gas from a coal-fired power plant is low (approximately 13-15% volume), and the flue gas is at ambient pressure.  The available technologies to be considered for post-combustion CO2 stripping involve chemical absorption with solvents and possibly capture by membranes (Gupta et al., 2003).  Research and development are underway for emerging technologies such as the use of cryogenics and improved membrane technology (DOE/NETL, 2011).
2. Pre-combustion capture would take place in an integrated gasification combined cycle (IGCC) or natural gas combined cycle (NGCC) facility, where gasification of the fuel stock produces syngas consisting of H2 and CO. A water-gas shift reaction converts the CO to CO2, and the resulting high-pressure stream is rich in CO2 and H2 (Gupta et al., 2003).  Because the volume percentage of CO2 in the stream is high, (25-40%), it is easier to capture the CO2. Physical solvents such as Selexol and Rectisol are the most readily available options for CO2 capture, although other options are being researched.
3. Oxy-combustion involves removal of nitrogen from the air before combustion via a cryogenic air separation unit. The resulting flue gas contains CO2 and water, which can be removed by condensation. This produces a clean CO2 stream, some of which is recycled (Figueroa et al. 2008). Research is ongoing in adaptation and scaling of this technology for use in power plants (e.g., Ciferno, 2008).

Figure 4. Block diagrams illustrating post-combustion, pre-combustion, and oxy-combustion systems (Figueroa et al., 2008).
Table 3. Advantages and Disadvantages of Types of CO2 Capture (Figueroa et al. 2008).
                                Capture Process
                                  Advantages
                          Barriers to implementation
Post-combustion
 Applicable to the majority of existing coal-fired power plants
   * Retrofit technology option
Flue gas is ...
    Dilute in CO2
    At ambient pressure
... resulting in ...
    Low CO2 partial pressure
    Significantly higher performance or circulation volume required for high capture levels
    CO2 produced at low pressure compared to sequestration requirements
Pre-combustion
Synthesis gas is ...
    Concentrated in CO2
    High pressure
... resulting in ...
    High CO2 partial pressure
    Increased driving force for separation
    More technologies available for separation
    Potential for reduction in compression costs/loads
     Applicable mainly to new plants, as few gasification plants are currently in operation
     Barriers to commercial application of gasification are common to pre-combustion capture
         o         Availability
         o         Cost of equipment
         o         Extensive supporting systems requirements

Oxy-combustion
   Very high CO2 concentration in flue gas
   Retrofit and repowering technology option
    Large cryogenic O2 production requirement may be cost prohibitive
    Cooled CO2 recycle required to maintain temperatures within limits of combustor materials
         o         Decreased process efficiency
         o         Added auxiliary load
The CO2 capture technologies available and under research can be grouped into four categories (e.g., Gupta et al., 2003):
   * Absorption with physical and chemical solvents (suitable for post-combustion and pre-combustion capture)
   * Adsorption (potential application to post-combustion and pre-combustion)
   * Membranes (potential application to pre-combustion and post-combustion)
   * Cryogenics (applicable for air separation in oxycombustion, possible applicability to pre-combustion)
The subsections below cover some of the established CO2 capture technologies and also provide brief descriptions of some of the technologies under development. Innovative research is underway for a number of capture technologies, and the reader is referred to DOE/NETL (2011) for a more comprehensive list and coverage of emerging technologies that are sponsored by DOE.
Absorption
CO2 capture by absorption is based on mass transfer between the gas and a liquid solvent.  The process may be based on chemical reactions between the CO2 and the solvent or physical dissolution alone.  During absorption, the CO2 diffuses through the gas phase and dissolves into the liquid phase as determined by Henry's Law.  If the process relies on chemical absorption, the CO2 then binds to the active ingredient in the solvent solution.  Desorption reverses the process and releases the CO2 back into the gas phase for capture (Wilcox, 2012).
Chemical Absorption
Amines are the most common class of chemical solvents for CO2 capture.  They have been used for at least 60 years to scrub CO2 from natural gas and hydrogen (Rochelle, 2009). The technology is widely used and well understood.
Primary, secondary, and tertiary amines react with CO2 to form water soluble compounds. Amines can capture CO2 from streams with low partial pressure of CO2. The CO2 is absorbed near ambient temperature into an aqueous solution. Solvent loading for amines is higher at low partial pressures of CO2 and levels off and is less effective at higher partial pressures (see Figure 5). Therefore, chemical absorption with amines is suitable for post-combustion capture from conventional coal-fired power plants, where the flue gas has a low partial pressure of CO2.
A CO2 capture unit using a solvent has coupled columns for absorption and desorption; an example layout is provided in Figure 5. The absorption and desorption columns contain packed material through which the gas and liquid move in opposite directions (i.e., liquid moving down, and gas moving up). The goal is to maximize contact between the gas and liquid. The amine is then thermally regenerated in the desorption column by stripping with water vapor at a temperature of 100 to 20 °C.  The water is removed by condensation, resulting in a CO2 gas stream (Rochelle, 2009) in which 75-90% of the CO2 has been captured (Rubin and Rao, 2002).
The rate of mass transfer depends upon a number of gas and solvent properties as well as physical design considerations. Design should take into account the solubility of CO2 in the solvent and the chemical reactivity between CO2 and the solvent.  Some of the physical parameters to consider include liquid and vapor flow rates, absorber height and diameter, and the number of stages. Theses design considerations have a direct effect on the capital cost of the system (Wilcox, 2012).
One of the disadvantages of an amine-based chemical solvent system is the large amount of heat needed to thermally strip the CO2 from the solvent and regenerate it. The heat can be taken from the steam cycle of the power plant, but this reduces the efficiency of the plant (energy penalty) and adds to overall cost (Rubin and Rao, 2002).  Furthermore, the CO2 exits at low pressure and requires compression for transport (discussed more in the later sections of this document).  Some ongoing work on amine-based systems involves improving integration of the CO2 capture unit into the overall plant system, including the steam cycle (Eswaran et al., 2010).

Figure 5. Schematic for an absorption based CO2 capture system (Wilcox, 2012).
Monoethanolamine (MEA)
The most commonly used amine solvent is monoethanolamine (MEA) (C2H7NO); it has been adapted to capture CO2 from flue gas streams (more detailed information on technologies currently used can be found in Appendix, Table A-1). One disadvantage of MEA is that impurities such as SO2 and NOx react with the MEA to form heat stable salts.  These reduce the capacity of the solvent (Rubin and Rao, 2002) and increase the need for new solvent. Therefore, it is important to have effective contaminant removal systems upstream of the capture unit. MEA is also corrosive to equipment, requiring the addition of corrosion inhibitors (Herzog et al., 2009).  Because of the problems with degradation and corrosion, the concentration of MEA in the solvent solution is generally only 20-30%, necessitating the use of large equipment (Herzog et al., 2009).
The two main vendors of MEA systems are 1) ABB/Lummus, who holds the license for a 20% MEA solution developed by Kerr-McGee that is used with coal-fired boilers and 2) Fluor, which licenses Econamine FG, originally developed by DOW (30% MEA, has been used for natural gas plants) (Herzog et al. 2009).
According to Reddy et al. (2008), Econamine FG is designed to capture CO2 from low-pressure, oxygen-bearing flue gases and is being adapted for coal-fired power plants. Part of Fluor's process involves upstream removal of impurities (NOx, SO2, particulates, Hg).  The solvent is formulated with 30% MEA and is designed to have increased reaction rates and higher solvent capacity. Their process also claims a new process for lower temperature regeneration (ion exchange), which would reduce energy needs in the stripping stage.
Other Commercial Amine Processes
Sterically hindered amines used for CO2 capture include 2-amino 2-methyl 1-propanol (AMP), 1,8-pmethanediamine (MDA), and 2piperidine ethanol (PE) (these were originally developed by Exxon). Several amine-based technologies and systems are produced by commercial vendors. Mitsubishi Heavy Industries (MHI) has developed a process (KM-CDR) based on a proprietary solvent named KS-1 (Endo et al., 2010), which may be a sterically hindered amine (Herzog et al., 2009).  KS-1 has a lower heat of reaction with CO2 and regenerates at a lower temperature (Endo et al., 2010; Gupta et al., 2003).  As of 2009, four units for gas-fired plants had been built with using KM-CDR, and tests had been conducted on coal-fired flue gas.
Cansolv's CO2 capture process uses a proprietary solvent named Absorbent DC101[TM] that uses tertiary amines. It has oxidation inhibitors and is claimed to be able to remove SOx, NOx, and particulate matter.  It has been used in demonstration plants, but not yet in commercial plants (Herzog et al., 2009) Table 4 below provides a summary of some chemical and physical solvent products.
Aqueous Ammonia
Use of aqueous ammonia is similar to the use of amine solvents.  Ammonia reacts with CO2 to form ammonium bicarbonate.  It can achieve 99% CO2 removal (as compared to about 94% for MEA), with a CO2 loading capacity of 1.2 kg CO2/kg NH3 (compared to 0.4 kg CO2/kg MEA) (Gupta et al., 2003). It is not degraded by impurities and is inexpensive. It also offers the potential for regeneration of the CO2 at high pressure. However, ammonia is more volatile than MEA, necessitating cooling of the flue gas to minimize ammonia loss (Figueroa et al., 2008), and ammonia may be lost due to higher temperature during regeneration. A system by Alstom that uses chilled ammonia at near-freezing temperature has been employed in a pilot test at the AEP Mountaineer Plant (Kozak et al., 2011).
Table 4. Developers of absorption-based CO2 capture processes (modified from Gupta et al., 2003).
                              Absorption process
                                    Solvent
                              Process Conditions
                              Developer/licensor
Physical Solvent
Rectisol
Methanol
-10/-70°C, >2 MPa
Lurgi and Linde, Germany;
Selexol
dimethylethers of polyethylene glycol (DMPEG)
-40°C, 2-3 MPa
Union Carbide, USA
Fluor Solvent
Propylene carbonate
Below ambient temperatures, 3.1-6.9 MPa
Fluor Corporation, USA
Chemical Solvent
Organic (Amine Based)
MEA
2.5 n monoethanolamine and chemical inhibitors
~40°C, ambient-intermediate pressures
Dow Chemical, USA
Amine Guard (MEA)
5 n monoethanolamine and chemical inhibitors
~40°C, ambient-intermediate pressures
Union Carbide, USA
Econamine  FG Plus (DGA)
6 n diglycolamine
80-120°C, 6.3 MPa
Fluor Corporation, USA
ADIP (DIPA &MDEA)
2-4 n diisopropanolamine; 2n methyldiethanolamine
35-40°C, >0.1 MPa
Shell, Netherlands
MDEA
2 n methyldiethanolamine

Flexsorb/KS-1, KS-2, KS-3
Hindered amine

Exxon, USA; M.H.I.
Inorganic
Benfield and versions
Hot potassium carbonate & catalysts, Lurgi and Catarcab with arsenic trioxide
70-120°C, 2.2-7 MPa
Lurgi, Germany; Eickmeyer and Associates, USA; Catacarb, USA; Giammarco Vetrocoke, Italy
Physical/Chemical Solvents
Sulfinol-D and Sulfinol-M
Mixture of DIPA or MDEA, water and tetrahydrothiopene (DIPAM) or diethylamine
>0.5 MPa
Shell, Netherlands
Amisol
Mixture of methanol and EMA, DEA, diisopropylamine (DIPAM) or diethylamine
5/40°C, >1 MPa
Lurgi, Germany

Amino Acid Salts
TNO Energy and Environment has developed the DECAB process using an amino acid salt solution. When CO2 dissolves in an amino acid salt solution, carbonate compounds precipitate (Feron, undated).  Because of the formation of the precipitate, the partial pressure of CO2 over the solution remains lower than it would if no precipitate formed; which results in high CO2 loading capacity. As with other chemical solvents, heat is required for regeneration.  This process requires less energy for regeneration than an MEA-based process. Feron (undated) estimates that the cost of CO2 avoided might be approximately half the cost of an MEA process.
Carbonate Slurry
Soluble carbonate forms a bicarbonate when it reacts with CO2; heating reverses the reaction and releases CO2.  The energy requirements for regeneration of carbonate are lower than for amines (Figueroa et al., 2008).  Research in this area has been conducted at the University of Texas at Austin.  Also, Carbon Capture Scientific, LLC is developing a hot carbonate slurry process using aqueous K2CO3 or Na2CO3 (or a mixture) as the solvent.  Other manufacturers/developers are listed in Table 4. As with chilled ammonia, the reaction of CO2 with the solvent produces a precipitate and forms a slurry. It offers the promise of a high CO2 absorption capacity (2-3 times that of MEA). The regeneration/stripping can take place at a higher temperature and higher pressure, reducing the energy required for compression.  The solvent does not degrade, and reaction kinetics are rapid (Carbon Capture Scientific, LLC, 2010).
Physical Absorption
CO2 dissolves into a physical solvent but does not chemically bind with the active ingredient.  Figure 6 illustrates the difference between physical and chemical absorbents.  Because the absorption capacity of a physical solvent increases linearly with the partial pressure of CO2 (Figure 6), this type of technology is suitable for pre-combustion capture, where the syngas is at high pressure and also has high partial pressure of CO2.  The solvent is regenerated and the CO2 released by pressure swing (reduced pressure).  A disadvantage is that the syngas needs to be cooled to at least ambient temperature for absorption. Developments needed include the ability to recover CO2 at higher pressure, improved selectivity, solvents with high CO2 loading at higher temperature (DOE/NETL, 2011) and low energy requirements for regeneration (Gupta et al., 2003).
Physical solvents have been used in industrial applications such as ammonia production plants. The commercially available acid gas removal systems suitable for pre-combustion capture (from an IGCC plant) include Selexol and Rectisol.  Selexol, which is manufactured by DOW, is a mixture of the dimethyl ethers of polyethylene glycol. Rectisol (licensed by Linde AG and Lurgi AG) uses cold methanol.  Other related products include the Fluor process, which uses propylene carbonate, and the Amisol process (a hybrid physical/chemical solvent that uses methanol and secondary amines). A comparison of these solvents is provided by Burr and Lyddon (undated). These authors found that the available physical solvents were all suitable for CO2 scrubbing and that the appropriate choice should be made based on feed gas composition, minor constituents in the gas, and the limitations of the various solvents.

Figure 6. Comparison between chemical and physical solvents (DOE/NETL 2011).
Membranes
Membranes may be organic (e.g., polymers) or inorganic (e.g., metallic, ceramic, zeolites). In particular, polymeric membranes have been used in a number of industrial gas separation processes, including air separation, recovery of H2 from ammonia, and separation of CO2 from natural gas (Table 5). Constituents in a gas are separated based on their rates of diffusion through the membrane (DOE/NETL, 2011), and membranes are more effective at high pressure.  For a pre-combustion scenario, there are CO2-selective membranes that can provide a high recovery and a high-purity CO2 stream. According to DOE/NETL (2011), however, membranes have not yet been employed commercially for CO2 capture from an IGCC system.  Challenges to upscaling include expense, and the need to minimize fouling and maximize surface area, as well as the need for improved selectivity. For post-combustion applications, membranes with a large surface area are needed to accommodate the large volumes of flue gas. Membrane types may include hollow-fiber and spiral-wound membranes.
Figueroa et al. (2008) described a potential hybrid system in which flue gas passes through a bundle of membrane tubes while an amine solution flows through the other side.  The CO2 that passes through the membrane is absorbed in the amine solution, and impurities that degrade the amine solution are blocked.  Researchers at the University of New Mexico have been researching a microporous silica membrane with amine functional groups to separate CO2 from flue gas. Other avenues of research include zeolite membranes (New Mexico Institute of Mining and Technology), and an organization named Membrane Technology and Research (MTR) that is researching the use of thin-film composite polymer membranes (Figueroa et al., 2008).
Table 5. Examples of Membrane Technologies Available or in Development
Technology Type
                                 Capture Type
                                   Developer
                                 Availability
Zeolite Membrane
                                Post-Combustion
                 New Mexico Institute of Mining and Technology
                               Under Development
Polaris Membrane
                                Post-Combustion
                       Membrane Technology and Research
                            Commercially Available
Pebax thin-film membranes
                                Post-Combustion
                       Membrane Technology and Research
                                 Pilot Testing
Polybenzimidazole (PBI) membrane
                                Pre-Combustion
                  DOE's Los Alamos National Laboratory (LANL)
                               Under Development

Adsorbents
Sorbents are solids that react with CO2 to form compounds and are then regenerated to release the CO2.  Sorbents present a possible option to reduce the energy penalty associated with CO2 capture (DOE, 2010). The effectiveness of an adsorbent system will depend upon the affinity of the solid material for CO2 and the heat required for regeneration. Adsorption for CO2 capture has not yet been commercialized, but research efforts are underway.  Examples of research include work sponsored by NETL in treating high surface area substrates with amine compounds, which may be a more efficient process than traditional amine scrubbing (Figueroa et al., 2008).  Work at RTI has focused on dry, regenerable Na2CO3, which is used with temperature swing (increased temperature) to regenerate the sorbent.  DOE/NETL (2011) provides a complete list of DOE-sponsored research on adsorbent-based CO2 capture methods.
Figure 7 presents a schematic of a reactor based on zeolites with amines grafted onto them (part of DOE/NETL research). Note that the design bears some similarity to absorption units in providing for sorption and subsequent stripping.

Figure 7. CO2 capture unit with metal  monolithic amine-grafted zeolites. Available on the Internet at: http://www.netl.doe.gov/technologies/coalpower/ewr/co2/post-combustion/zeolite.html
Cryogenics
Cryogenic processes allow separation of gasses because the various flue gas constituents have different freezing temperatures.  For post-combustion capture, this requires a large amount of energy.  According to DOE/NETL (2011), at the partial pressure of CO2 in a typical flue gas, the temperature would need to be lowered to -120 °C to achieve a 90% capture rate. Work is being done at Brigham Young University on a post-combustion cryogenic carbon capture process, and another process has been proposed by the Center for Energy and Processes at Ecole des Mines de Paris in collaboration with ALSTOM.
In an oxycombustion system (which could be retrofitted to a conventional power plant), a cryogenic unit would be used to separate the CO2 from a gas stream for the high-oxygen combustion stage (Figure 8).  The combustion products are CO2 and H2O, and the H2O can be separated from the CO2 by condensation (DOE/NETL, 2011).

Figure 8. Diagram of an oxy-combustion system, including a cryogenic unit (DOE/NETL, 2011).

Processing
The discussion pertaining to all activities between capture and transport of CO2, referred to as "processing" in this paper, including the conversion to supercritical state, is included in this section. It is important to note that, however, some of these processing activities might be considered as part of the capture design in the literature, such as removal of impurities prior to CO2 separation.
While the literature on carbon capture and sequestration has been continuously growing, general literature of CO2 gas conditioning and compression has been slower in its development. The awareness, however, that the removal of liquids other than water and volatile gases must be considered in the CCS chain, is increasing. As stated in the Background Information section, the requirements related to system parameters (e.g., temperature, pressure, quality) depend upon the chosen transport mechanism (e.g., pipeline, ship) and also the terminal point of the transport and storage requirements (Aspelund and Jordal, 2007). Typical conditioning and compression steps within a CCS chain are given in Figure 9 and Figure 10.

Figure 9. A typical CCS chain (Maroto-Valer, 2010).
The CO2 from the power plant or industrial source is normally saturated with water and will contain some nitrogen. Therefore, cooling the CO2 to ambient conditions and removing water in gravity-based separators would be the first step of processing (Figure 9). The CO2 is then compressed to 20-30 bar (about 2-3 MPa) in two stages with intermediate cooling. It is important to remove the remaining water at this point by using regenerative adsorption columns.
For pipeline transport, the CO2 can be compressed directly to the transport pressure. However, this would result in volatiles such as nitrogen and oxygen to not be removed from the stream. Therefore, where the removal of volatiles is important, the CO2 is initially compressed to 60-65 bar (about 6-6.5 MPa) and condensed by seawater or by a refrigeration unit (Figure 9). The volatiles can then be removed in a distillation column or a flash tank (when the amounts of volatiles are very small). The liquid, purified CO2 is then pumped to injection pressure and sent to the pipeline. For cases where the pipelines are long or the injection reservoir is highly pressurized, recompression might be necessary prior to injection (Maroto-Valer, 2010).
Typically, processing of CO2 from the end of the capture process until the point of pipeline transport include the following steps (Maroto-Valer, 2010):
   * Removal of water and other liquids in vapor-liquid separation drums;
   * Compression and cooling;
   * Removal of water by adsorption;
   * Removal of unwanted components by chemical or physical treatment or advanced separation processes;
   * Removal of volatile gases and condensation; and
   * Pumping to pipeline transport pressure.

Figure 10. Schematic presentation of typical processing of CO2 prior to pipeline transport (Maroto-Valer, 2010).
Dehydration and removal of other liquids
Separation of liquids is needed to ensure removal of bulk liquid content prior to the first stage of compression and cooling. The dehydrators are usually designed for a specification of 30 lb H2O/MMscfd of gas. The dehydrator system itself is not a primary cost element, but optimization of its location is a critical factor that affects the operating and capital costs of the entire compression system (Bechtel, 2011). Dehydration at higher pressure requires a smaller and less expensive system, since upstream compression and intercooling remove some of the water from the CO2 stream. However, some smaller systems may require greater material thickness, therefore, may increase the cost. If the dehydration is performed at higher pressure, many of the inter-stage compressors may require a significantly higher aftercooler outlet temperature to avoid hydrate formation which in turn may reduce compression system efficiency.
The construction of the dehydration system at the upstream portion of the compression system would require the use of expensive duplex stainless steel because a wet CO2 stream causes carbonic acid corrosion in less-expensive carbon steel. Downstream of dehydration, carbon steel can be used to construct the system (Bechtel, 2011).
Separation by gravity (e.g., using liquid-vapor separator drums) is a simple and cost- and energy-effective method for the removal of bulk components of liquids with higher densities. While separating liquids, impurities dissolved in water will also be removed. As shown in Figure 10, multiple stages of liquid removal and compression/cooling might be necessary. As the gas is compressed and cooled, most of the remaining water condenses. The last free water should be removed at a pressure between 20-40 bar. With proper design, the vapor-liquid separator drums can remove water down to approximately 400-500 ppm (Maroto-Valer, 2010).
During the removal of liquids, some CO2 that is dissolved in water will also be removed. For power cycles that contain large amounts of water in contact with the CO2, this loss might be at a significant level (Aspelund and Jordal, 2007).
If needed, following the compression and cooling stages further removal of remaining liquids can be achieved by using regenerative adsorption columns (molecular sieves or silica). Impurities such as H2S can also be removed from the CO2 stream at this point, as discussed later in this section.
Molecular sieves can be used for dehydration and the selective adsorption of other compounds. Whether the process involves the removal of water vapor or some other gas-phase impurity, the basic concept involves that the gas passes through a bed of the adsorbent material at a velocity consistent with pressure drop and other requirements of material transfer. The bed would eventually become loaded with the impurity and must then either be discarded, removed for reclaiming, or regenerated in place (Kohl and Nielsen, 1997).
Compression and Cooling
Compression is an integral part of any CO2 capture system since separation typically occurs at low pressure and the volume reduction by compression is needed for transport (NETL, 2011).  For compressing large amounts of CO2, centrifugal compressors are generally used, particularly when CO2 is produced near atmospheric pressure. Some of the unique characteristics of CO2 that need to be considered for this process are: real gas effects, high volume reduction, low speed of sound, and avoiding liquid formation. Its high molecular weight allows CO2 to be liquefied at relatively high temperatures allowing hybrid compression and pumping options (NETL, 2011). Figure 11 below shows two types of compressor that are typically used for CO2 compression.

                                      (a)
                                      (b)
Figure 11. Typical compressors used for CO2 compression: (a) A stage integrally geared compressor (MAN Turbo); and (b) Multi-stage back-to-back centrifugal compressor (Dresser-Rand) (NETL, 2011).
Integrally geared compressors are usually driven by electric motors that drive a large bull-gear that control multiple centrifugal compressors on each end. This design has a separate inlet and exit flange for each stage, therefore, permitting intercooling between each stage that can approach isothermal compression and minimize the power requirement. However, the large size and potential reliability issues with the many bearings, seals, and unshrouded impellers may be considered as the drawback for this type of design (NETL, 2011).
Multi-stage, beam style compressors (as shown in Figure 11(b)) are commonly used in the petrochemical and natural gas industry. These compressors can be configured in a straight-through or back-to-back design, which allows intercooling between the multiple sections and compressor bodies. These compressors contain only to bearing and seals, and have demonstrated reliable service in many applications (e.g., liquefied natural gas applications) and high pressures (e.g., up to 15,000 psi). Although some intercooling is possible, this type of designs will typically consume more power compared to integrated geared compressors.
Some design options for CO2 compression have been studied by the Southwest Research Institute and summarized in the NETL (2011) report. Compression options analyzed were: conventional multistage centrifugal compression; isothermal and semi-isothermal inter-stage cooling; two-stage, high pressure ratio compression; and liquefaction and pumping. A summary of the power requirements of these different compression designs are given in Table 6.

Table 6. Summary of power requirements for different compression technology options (NETL, 2011).
Compression Technology
                              Power Requirements
conventional Dresser-rand centrifugal 16-stage compressor (2 bodies)
                             23,251 BHP (17.35 MW)
conventional Dresser-rand centrifugal 16-stage compressor (2 bodies) and with additional cooling
                             21,522 BHP (16.06 MW)
isothermal compression at 70 °f and 80% efficiency
                             14,840 BHP (11.07 MW)
Semi-isothermal compression at 70 °f and 1.55 pressure ratio
                             17,025 BHP (12.70 MW)
Semi-isothermal compression at 100 °f and 1.55 pressure ratio
                             17,979 BHP (13.41 MW)
high pressure ratio compression at 90% efficiency and no inter-stage cooling
                             34,192 BHP (25.51 MW)
high pressure ratio compression at 90% efficiency with 1st and 2nd stage cooling
                             24,730 BHP (18.45 MW)
centrifugal compression to 250 psia and liquid cryo-pump from 250 to 2,215 psia
         16,198 BHP (12.08 MW) (Includes 7,814 BHP for refrigeration)
centrifugal compression to 250 psia with semi-isothermal cooling at 100 °f and liquid cryo-pump from 250 to 2,215 psia
         15,145 BHP (11.30 MW) (Includes 7,814 BHP for refrigeration)

It is important to note that these compressors are designed to withstand the expected corrosion. For example, compressor valve failure due to fracture and corrosion has been reported in CanmetENERGY's CO2 capture and compression unit, which is coupled to its 0.3 MW oxy-fuel pilot plant (Emadi et al., 2011).
Membrane or centrifugal pumps are typically used for energy-efficiency to achieve transport pressure. Pumping of CO2 from 65 bar to 150 bar is about 10-15% more energy-efficient than compression depending on the cooling temperatures.  For example, Weyburn-Midale pilot program at commercial scale uses a 64-stage horizontal centrifugal pump that pressurizes the dense phase to the pipeline condition of 160 bar (Wu et al., 2011).
Removal of Impurities
To achieve the desired quality of the CO2 stream for pipeline transport or final injection into a certain reservoir (see Table 1 and Table 2), some components remaining in the stream from the liquid separation phases might need to be removed. Such components are usually the components with boiling points and densities similar to CO2 and can be removed by chemical or physical treatment or advanced separation processes such as absorption or adsorption towers; rigorous distillation or membranes; or burnt in catalytic processes. Some components that cannot be easily separated from CO2 by flashing or simple distillation are propane, ethane, H2S, and SO2 (Aspelund and Jordal, 2007). Small quantities of propane and ethane are not expected to cause any operational problems. However, H2S levels, expected to be in an IGCC setting, might be a safety hazard and removal of H2S generally consists of absorption by a regenerable solvent (NETL, 2010). The most commonly used technique is based on countercurrent contact with the solvent. Acid-gas-rich solution from the absorber is stripped of its acid gas in a regenerator, usually by application of heat. The regenerated lean solution is then cooled and recirculated to the top of the absorber. Figure 12 below presents a flow diagram for a conventional acid-gas-removal (AGR) unit that might be used for H2S removal.

Figure 12. Flow diagram for a conventional AGR unit (NETL, 2010).
Some of the AGR processes used for H2S removal are: Rectisol, Sulfinol, MDEA, Selexol, aqueous di-isoproponal (ADIP) amine, and FLEXSORB (NETL, 2010). It might be more cost-efficient to remove H2S in the capture process (Maroto-Valer, 2010). Therefore, sulfur removal is usually discussed in the context of capture technologies. Further information about the use of some these processes for CO2 separation is given in Capture section of this review paper.
The AGR processes can be categorized as: chemical solvents; physical solvents; and hybrid solvents. Chemical solvents are usually more suitable than physical or hybrid solvents for applications at lower operating pressures. Chemical reagents are used to remove the acid gases by a reversible chemical reaction of the acid gases with an aqueous solution of various alkonolamines or alkaline salts in water (Table 7). MDEA, a tertiary amine, has been used widely in the gas-treating market for its superior capabilities for selectively removing H2S in the presence of CO2, resistance to degradation by organic sulfur compounds, tendency for corrosion, and its low circulation rate and efficiency (NETL, 2010).

Table 7. Common chemical reagents used in AGR processes (NETL, 2010).
Chemical reagent
                                    Acronym
                      Process Licensors Using the Reagent
Monoethanolamine
                                      MEA
                       Dow, Exxon, Lurgi, Union Carbide
Diethanolamine
                                      DEA
                                  Elf, Lurgi
Diglycolamine
                                      DGA
                                 Texaco, Fluor
Triethanolamine
                                      TEA
                                     AMOCO
Diisopropanolamine
                                     DIPA
                                     Shell
Methyldiethanolamine
                                     MDEA
     BASF, Dow, Elf, Snamprogetti, Shell, Union Carbide, Coastal Chemical
Hindered amine

                                     Exxon
Potassium carbonate
                                 "hot pot"
                    Eickmeyer, Exxon, Lurgi, Union Carbide
Physical solvents include absorption of acid gases into certain organic solvents that have a high solubility for acid gases. Physical solvent absorbers are usually operated at lower temperatures than is the case for chemical solvents. Most physical solvents are capable of removing organic sulfur compounds and they can be designed for selective H2S or total AGR (for capture, the CO2 is flashed off at various pressures)(NETL, 2010). Several physical solvents that use anhydrous organic solvents have been commercialized (Table 8).
Table 8. Common physical solvents used in AGR processes (NETL, 2010).
Solvent
                          Solvent/Process Trade Name
                               Process Licensors
Dimethyl ether of poly-ethylene glycol
                                    Selexol
                                      UOP
Methanol
                                   Rectisol
                              Linde AG and Lurgi
Methanol and toluene
                                  Rectisol II
                                   Linde AG
N -- methyl pyrrolidone
                                    Purisol
                                     Lurgi
Polyethylene glycol and dialkyl ethers
                                 Sepasolv MPE
                                     BASF
Propylene carbonate
                                 Fluor Solvent
                                     Fluor
Tetrahydrothiophenedioxide
                                   Sulfolane
                                     Shell
Tributyl phosphate
                                  Estasolvan
                                 Uhde and IFP
Hybrid solvents combine the high treated-gas purity offered by chemical solvents with flash regeneration and lower energy requirements of physical solvents (Table 9). The mixed solvent allows the solution to absorb an appreciable amount of gas while the amine portion is effective as a reagent to remove the acid to low levels when high purity is desired.
Table 9. Common hybrid  solvents used in AGR processes (NETL, 2010).
Solvent/Chemical Reagent
Solvent/Process Trade Name
Process Licensors
Methanol/MDEA or diethylamine
Amisol
Lurgi
Sulfolane/MDEA or DIPA
Sulfinol
Shell
Methanol and toluene
Selefining
Snamprogetti
(Unspecified) /MDEA
FLEXSORB PS
Exxon
Removal of Volatile Gases and Condensation
As shown in Table 1, removal of volatile gases, such as N2 or Ar, might be desirable due to cost issues. Technical and economic evaluations will be needed to determine the level of purity in pipeline transport. These evaluations may include the comparison of the cost associated with the additional capacity needed to transport and inject these gases versus the cost of removal (Maroto-Valer, 2010). Furthermore, if the CO2 is used for EOR, the specifications might be more stringent to prevent any increase in the miscible pressure in the reservoir which in turn can decrease the efficiency of CO2. Additionally, CO2 may also cause precipitation reactions and reduce the permeability of the reservoir. However, oxygen removal may require increasing the re-boiler and condenser duty significantly (Aspelund and Jordal, 2007). Removal of volatiles can be achieved by using a distillation column or a flash tank (when the amounts of volatiles are very small).
Condensation of CO2 is required following removal of volatiles. For condensation, seawater or an external refrigeration unit (e.g., with ammonia as the working fluid) can be used. For pipeline transport, the CO2 should be condensed at 50-65 bar (Maroto-Valer, 2010).
Cost of Capture & Processing
IEA (2011) conducted an analysis of techno-economic data available from feasibility studies and pilot projects (i.e., about 50 studies of CO2 capture installations at power plants) for CO2 capture from power generation and CO2 conditioning and compression combined, but not transport and storage, to support energy scenario modeling and policy making. The studies included in this analysis were conducted by the following organizations:
   * Carnegie Mellon University  -  CMU
   * China-UK Near Zero Emissions Coal Initiative  -  NZEC
   * CO2 Capture Project  -  CCP
   * Electric Power Research Institute  -  EPRI
   * Global CCS Institute  -  GCCSI
   * Greenhouse-Gas Implementing Agreement  -  GHG IA
   * National Energy Technology Laboratory  -  NETL
   * Massachusetts Institute of Technology  -  MIT
The results are presented in capital cost and levelised cost of electricity (LCOE). Their results indicated that no single CO2 capture & processing technology outperforms available alternatives for coal-fired power generation. Overnight costs of power plants with CO2 capture in regions of the Organization for Economic Co-operation and Development (OECD) were about $3,800 per kW across different capture options, which was found to be 74% higher than the reference costs without capture & processing.
For natural gas-fired power generation, their results showed that post-combustion CO2 capture is the most analyzed and attractive near-term option. Overnight costs for this option found to be $1,700 per kW including capture & processing, or 82% higher than the costs without capture.
Average cost figures from IEA (2011) analysis for different capture applications are presented in Table 10 below. The data used for generating these average figures included the information for capture, conditioning, and compression, but not transport and storage.
Table 10. Average cost data by CO2 capture option, including processing (IEA, 2011).
                                   Fuel Type
                                     Coal
                                  Natural Gas
                                Capture Process
                                Post-combustion
                                Pre-combustion
                                Oxy-combustion
                                Post-combustion
Reference plant w/o capture
                                      PC
                                   IGCC (PC)
                                      PC
                                     NGCC
Overnight cost w/ capture ($/kW)
                                     3,808
                                     3,714
                                     3,959
                                     1,715
Overnight cost increase ($/kW)
                                     1,647
                                     1,128
                                     1,696
                                      754
LCOE w/ capture ($/MWh)
                                      107
                                      104
                                      102
                                      102
LCOE increase
                                      41
                                      29
                                      40
                                      25

NETL (2010) reported some estimated baseline values for the cost and performance of the various fossil-fuel energy power systems, specifically IGCC, PC, and NGCC plants. They analyzed twelve different power plant designs with various CO2 capture and processing technologies. The Table 11 below summarizes the plant configurations used in the report and the costs estimated for each configuration.
NETL (2010) study (Table 9) estimates performance and cost for IGCC, PC (pulverized coal), and NGCC (natural gas combined cycle) power plants, both with and without CO2 capture. The various cases include descriptions of certain process parameters, boiler technologies, contaminant removal technologies, and CO2 separation technologies. Table 9 shows that the COE is expected to increase by approximately 80 - 84% with the incorporation of CO2 capture by amine absorption into a pulverized coal power plant.  Use of CO2 capture by physical absorption in an IGCC or NGCC plant would result in a 38-49% increase in COE.

Table 11. Case descriptions and costs estimated in the NETL (2010) report for baseline estimates.
                                  Unit Cycle
                                  CO2 Capture
                                Gasifier/Boiler
                                    Oxidant
                            H2S separation/removal
                            Sulfur removal/Recovery
                                  PM control
                                  NOx control
                                CO2 Separation
                                  TOTAL COST

                            Plant cost (2007 $/kW)
                         Overnight cost (2007x1,1000)
                            LCOE (mills/kWh, 2007$)
                                     IGCC
                                      0%
                               GEE Radiant Only
                                  95 mol% O2
                             Single-Stage Selexol
                                  Claus Plant
                      Quench, scrrubber and AGR adsorber
                                  N2 dilution
                                       -
                                     1,987
                                   1,521,880
                                     96.7
                                     IGCC
                                      90%
                               GEE Radiant Only
                                  95 mol% O2
                               Two-Stage Selexol
                                  Claus Plant
                      Quench, scrrubber and AGR adsorber
                                  N2 dilution
                                Selexol 2-stage
                                     2,711
                                   1,811,411
                                     133.9
                                     IGCC
                                      0%
                                   CoP E-Gas
                                  95 mol% O2
                               Refrigerated MDEA
                                  Claus Plant
                     Cyclone, barrier filter and scrubber
                                  N2 dilution
                                       -
                                     1,913
                                   1,469,577
                                     93.8
                                     IGCC
                                      90%
                                   CoP E-gas
                                  95 mol% O2
                                    Selexol
                                  Claus Plant
                     Cyclone, barrier filter and scrubber
                                  N2 dilution
                                Selexol 2-stage
                                     2,817
                                   1,780,290
                                     139.9
                                     IGCC
                                      0%
                                     Shell
                                  95 mol% O2
                                  Sulfinol-M
                                  Claus Plant
                     Cyclone, barrier filter and scrubber
                                  N2 dilution
                                       -
                                     2,217
                                   1,708,524
                                     103.1
                                     IGCC
                                      90%
                                     Shell
                                  95 mol% O2
                                    Selexol
                                  Claus Plant
                     Cyclone, barrier filter and scrubber
                                  N2 dilution
                                Selexol 2-stage
                                     3,181
                                   1,939,878
                                     151.4
                                      PC
                                      0%
                                Subcritical PC
                                      Air
                                       -
                                Wet FGD/Gypsum
                                   Baghouse
                               LNB w/OFA and SCR
                                       -
                                     1,622
                                   1,098,124
                                     75.3
                                      PC
                                      90%
                                Subcritical PC
                                      Air
                                       -
                                Wet FGD/Gypsum
                                   Baghouse
                               LNB w/OFA and SCR
                                Amine absorber
                                     2,942
                                   1,985,432
                                      139
                                      PC
                                      0%
                               Supercritical PC
                                      Air
                                       -
                                Wet FGD/Gypsum
                                   Baghouse
                               LNB w/OFA and SCR
                                       -
                                     1,647
                                   1,113,445
                                     74.7
                                      PC
                                      90%
                               Supercritical PC
                                      Air
                                       -
                                Wet FGD/Gypsum
                                   Baghouse
                               LNB w/OFA and SCR
                                Amine absorber
                                     2,913
                                   1,963,644
                                     135.2
                                     NGCC
                                      0%
                                     HRSG
                                      Air
                                       -
                                       -
                                       -
                                  LNB and SCR
                                       -
                                      584
                                    398,290
                                     74.7
                                     NGCC
                                      90%
                                     HRSG
                                      Air
                                       -
                                       -
                                       -
                                  LNB and SCR
                                Amine absorber
                                     1,226
                                    709,039
                                     108.9

Inventory
This section provides an overview of the number and types of carbon capture and processing projects in the US. More detailed information on each project is provided in the Appendix tables; Table A-1 contains an inventory of projects and Table A-2 identifies the sources consulted for each project. As of May, 2012, there are an estimated 72 "carbon capture" and "capture and injection" projects in 33 states (Table 12). Of the 72 projects, 48% are active and 14% are potential projects. The remaining 38% have been completed, are on hold, or have been cancelled or terminated. Projects which were cancelled or terminated were not further investigated and therefore, limited information is provided for those projects in the inventory in the Appendix.
Table 12. Carbon capture projects in the US by operating status as of May, 2012.
                       Project Type and Operating Status
                                 # of Projects
Capture
                                      19
Active
                                      12
Potential
                                       1
Hold
                                       2
Completed
                                       1
Cancelled
                                       1
Terminated
                                       2
Capture and Injection
                                      53
Active
                                      23
Potential
                                       8
Hold
                                       3
Completed
                                       4
Cancelled
                                       1
Terminated
                                      13
Total
                                      72

Post-combustion and pre-combustion are the most commonly used carbon capture processes in the US, with 70% of projects using these methods (Table 13). Understanding the most common types of carbon capture technologies used (e.g., amines, membranes, etc.) is challenging given that this information is not available for a significant portion (38%) of the projects. However, for the projects where capture technology is available, amines are a commonly used technology (Table 13). Further details on the carbon capture technologies employed for each project are provided in Table A-1 in the Appendix.
Table 13. Carbon capture processes and technologies used for each project. (--) signifies that the information is not available.
                        Carbon Capture Type/Technology
                                 # of Projects
Post-Combustion
                                      26
--
                                       3
Adsorption
                                       1
Amine
                                      14
Biological
                                       1
Ammonia
                                       5
Membrane
                                       2
Pre-Combustion
                                      29
--
                                      16
Amine
                                       1
Ammonia
                                       1
Gasification
                                       8
Membrane
                                       1
Physical Absorption
                                       2
Oxycombustion
                                       4
Oxyfuel
                                       4
Separation
                                       2
--
                                       1
Membrane
                                       1
Industrial
                                       7
--
                                       4
Adsorption
                                       1
Amine
                                       1
Dry Sorbent
                                       1
Unknown
                                       4
--
                                       3
Cryogenics
                                       1
Total
                                      72

For the majority of carbon capture projects in the US, the technologies used to compress and processes CO2 prior to injection, are not reported or discussed on project websites, fact sheets, or other related documents. Therefore, descriptive statistics on the technologies used for processing are not described here. However, for the few projects where processing information is available, specific details are provided in Table A-1 in the Appendix.
References
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Aspelund, A. and K. Jordal. 2007. Gas Conditioning  -  The interface between CO2 capture and transport. International Journal of Greenhouse Gas Control. 1(3): 343-354.
Bechtel. 2011. CO2 Compression and Dehydration for Carbon Capture and Sequestration. Available on the Internet at: http://www.bechtel.com/assets/files/TechJournal/2011/OG&C%2004%20CO2%20Compression%20Final.pdf
Burr, B., and Lyddon, L., undated.  A Comparison of Physical Solvents for Acid Gas Removal.  Available on the Internet at: http://www.bre.com/portals/0/technicalarticles/a%20comparison%20of%20physical%20solvents%20for%20acid%20gas%20removal%20revised.pdf
Carbon Capture Scientific, LLC.  2010.  http://carboncapturescientific.com/technology.html#top
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DOE/NETL, 2011.  Advanced Carbon Dioxide Capture R&D Program: Technology Update, May 2011.  Available on the Internet at:  http://www.netl.doe.gov/technologies/coalpower/ewr/pubs/CO2Handbook/CO2-Capture-Tech-Update-2011_Front-End%20Report.pdf
Dynamis. Dynamis CO2 quality recommendations. European Commission, 2007. Project no: 019672.
Emadi, D., K. Zanganeh, C. Salvador, S. Papavinasam, J. Li, A, Doiron, and A. Pratt. 2011. Material Challenges in CO2 Compression and Transport Systems. http://www.ieaghg.org/docs/General_Docs/PCCC1/Abstracts_Final/pccc1Abstract00037.pdf.
Endo, T., Kajiya, Y., Nagayasu, H., Iijima, M., Ohishi, T., Tanaka, H., and Mitchell, R., 2010.  Current status of MH1 CO2 capture plant technology, large scale demonstration project and road map to commercialization for coal-fired flue gas application.  Energy Procedia.
Feron, P., undated.  New solvents based on amino-acid salts for CO2 capture from flue gases.  Available on the Internet at:  http://uregina.ca/ghgt7/PDF/papers/nonpeer/243.pdf.
Figueroa, J.D., Fout, T., Plasynski, S., McIlvried, H., and Srivastava, R.D., 2008. Advances in CO2 capture technology  -  The U.S. Department of Energy's Carbon Sequestration Program.  International Journal of Greenhouse Gas Control, 2, 9-20.
Finkenrath, M., 2011.  Cost and Performance of Carbon Dioxide Capture from Power Generation. International Energy Agency.  Working Paper.  Available on the Internet at: http://www.iea.org/papers/2011/costperf_ccs_powergen.pdf
Gupta, M., Coyle, I., and Thambimuthu, K., undated.  CO2 Capture Technologies and Opportunities in Canada.  "Strawman Document for CO2 Capture and Storage (CC&S) Technology Roadmap."  1[st] Canadian CC&S Technology Roadmap Workshop, 18-19 September 2003, Calgary, Alberta, Canada.
Herzog, H., Meldon, J., and Hatton, A., 2009.  Advanced Post-Combustion CO2 Capture.  Prepared for the Clean Air Task Force.  Available on the Internet at:  http://web.mit.edu/mitei/docs/reports/herzog-meldon-hatton.pdf
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Kozak, F., Telikapalli, V., Hiwale, R., Bollinger, R., 2011. CCS Project: Chilled Ammonia Process at the AEP Mountaineer. Available on the Internet at:
Maroto-Valer, M. 2010. Developments and Innovation in Carbon Dioxide (CO2) Capture and Storage Technology. Volume 1: Carbon Dioxide (CO2) Capture, Transport, and Industrial Applications. Woodhead Publishing Limited and CRC Press LLC.
NETL. 2010. Cost and Performance Baseline for Fossil Energy Plants Volume 1: Bituminous Coal and Natural Gas to Electricity. Available on the Internet at:  http://www.netl.doe.gov/energy-analyses/pubs/BitBase_FinRep_Rev2.pdf
Occupational Safety and Health Administration. 2010. Hydrogen sulfide in workplace atmospheres. http://www.osha.gov/dts/sltc/methods/inorganic/id141/id141.html.
Reddy, S., Johnson, D., and Gilmartin, J., 2008.  Fluor's Econamine FG Plussm  Technology for CO2 Capture at Coal-Fired Power Plants.  Presented at: Power Plant Air Pollutant Control "Mega" Symposium, August 25-28, 2008, Baltimore, MD.
Rochelle, G.T., 2009.  Amine scrubbing for CO2 capture.  Science, 325, 1652-1654.
Rubin, e.S., and Rao, A.B., 2002.  A Technical, Economic and Environmental Assessment of Amine-based CO2 Capture Technology for Power Plant Greenhouse Gas Control.  Annual Technical Progress Report.  DOE/DE-FC26-00NT40935.
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                                   Appendix
                   Capture and Processing Facility Inventory
The following tables provide more detailed information on each of the carbon capture and processing facilities/projects in the US. A more detailed description of how the information in these tables was obtained is provided in the Methodology & Data section of this report.
Note: Facility information presented in this table is used for general analytical estimates only and should not be considered the Agency's final determination as to facility status or plans.
Abbreviations used in the tables include: -- or NA= information not available/applicable; tonnes = metric tons; tons = US short ton; EOR= enhanced oil recovery; GS= geological sequestration; ECBM= enhanced coalbed methane recovery.
Table A-1. Inventory of US carbon capture and processing projects as of May, 2012.
                                 Project Name
                                 Plant/Source
                                 Project Type
                                     State
                               Operating Status
                            Operating Status Detail
                                Unit Base Power
                                Unit Base Name
                              Project Start Date
                                  Cost (US $)
                                    (x1000)
                                 Capture Type
                              Capture Technology
                           Capture Technology Detail
                                   % Capture
                                 Capture Rate
                            Capture Unit of Measure
                              # of Capture Units
                                   CO2 Fate
                        Processing Location/ Technology
AES Shady Point
Shady Point Power Plant
Capture
OK
Active
Plant in Operation
                                      320
Megawatt
                                                                       1/1/1991
 --
Post-Combustion
Amine
Ethanol-amino solvent
                                      --
                                    73,000
Tons/yr
                                       4
Food/Beverage
--
AES Warrior Run
Warrior Run Power Plant
Capture
MD
Active
Plant in Operation
                                      180
Megawatt
                                                                       2/1/2000
 --
Post-Combustion
Amine
Ethanol-amino solvent
                                      --
                                    120,000
Tons/yr
                                       3
Food/Beverage
--
Bellingham Cogeneration Facility
Bellingham Cogeneration Facility
Capture
MA
Active
Plant in Operation
                                      320
Megawatt
                                                                       9/1/1991
 --
Post-Combustion
Amine
Fluor Econamine FG scrubber
                                    85-95%
                                    110,000
Tonnes/yr
                                       2
Food/Beverage
--
DKRW Energy LLC
Medicine Bow CTL
Capture
WY
Active
Permitting Planning
                                     20000
Barrels per Day
                                                                       1/1/2014
 $2,000,000
Pre-Combustion
Gasification
GE Coal gasification technology to produce synthetic gas
                                      --
                                      --
--
                                      --
EOR
Offsite- CO2 will be removed, dried, channeled and pressurized.
Evaluation of Solid Sorbents as a Retrofit Technology for CO2 Capture
Alabama Power Co. Plant Miller
Capture
AL
Active
Engineering design
                                       1
Megawatt
                                                                      10/1/2010
 $18,750
Post-Combustion
Adsorption
Solid sorbent
                                      0.9
                                     2,100
lbs/hr
                                       1
--
--
Excelsior Energy
Mesaba Coal IGCC
Capture
MN
Active
Plant Design
                                      602
Megawatt- Net
                                                                       1/1/2012
 $2,000,000
Pre-Combustion
Gasification
ConocoPhillips E-Gas Gasification
                                    30-90%
                                      --
--
                                    1 to 6
EOR or Saline
Onsite- CO2 will be compressed and dried.
Great River Energy
Coal Creek Station
Capture
ND
Active
Planning
                                     1100
Megawatt
                                                                       1/1/2009
 --
Post-Combustion
Amine
Amines
                                      --
                                      --
--
                                       2
--
--
Intermountain Power Project
Holly Avenue Electrical Power Generating Station
Capture
UT
Active
-
                                      950
Megawatt
                                                                       1/1/2009
 --
Post-Combustion
Amine
Amines
                                      --
                                      --
--
                                       2
--
--
Oxy-combustion Technology Development for Industrial Scale Boiler Applications
Alstom's 15 MWth Boiler Simulation Facility
Capture
CT
Active
Plant in Operation
                                      15
Megawatt
                                                                      10/1/2008
 $18,012
Oxycombustion
Oxyfuel
Oxyfuel Combustion- Alstom will perform a focused R&D program
                                      0.9
                                      --
--
                                      --
--
--
Slipstream Development and Testing of Siemens POSTCAP Capture and Separation Technology
Big Bend Station
Capture
FL
Active
Engineering design
                                      2.5
Megawatt
                                                                       1/1/2013
 $18,750
Post-Combustion
Amine
POSTCAP technology- Aqueous amino acid salt-based solvent
                                      0.9
                                      --
--
                                       4
EOR
--
Slipstream Testing of a Membrane CO2 Capture Process for Existing Coal-Fired Power Plants
APS Cholla - National Carbon Capture Center
Capture
AR
Active
--
                                      995
Megawatt
                                                                      10/1/2010
 $18,750
Post-Combustion
Membrane
MTR Membrane System
                                      0.9
                                       1
Tons/day
                                       3
--
--
Touchstone Algae Production
Cedar Lane Farms
Capture
OH
Active
--
                                      2.8
Megawatt
                                                                       1/1/2010
 $1 8,446
--
Biological
Algae assimilation
                                      0.6
                                      --
--
                                      --
Algae production
--
Sweeny Polygeneration with CO2 Capture
Commercial Source
Capture
TX
Cancelled
Cancelled
                                      683
Megawatt
                                                                       1/1/2015
 --
Pre-Combustion
--
--
                                      --
                                      --
--
                                      --
GS/EOR
--
We Energies Pleasant Prairie Field Pilot
Pleasant Prairie
Capture
WI
Completed
Capture Complete
                                      1.7
Megawatt
                                                                      10/1/2009
 --
Post-Combustion
Ammonia
Alstom Chilled Ammonia Process
                                      0.9
                                    15,000
Tonnes/yr
                                       2
Vented to the atmosphere
--
American Electric Power - Great Bend IGCC
Great Bend IGCC
Capture
OH
Hold
Plant Design
                                      629
Megawatt
--
 $1,100,000
Pre-Combustion
--
--
                                      --
                                      --
--
                                      --
--
--
Taylorville Energy Center
Taylorville Energy Center IGCC
Capture
IL
Hold
Permitting
                                      716
Megawatt- Gross
                                                                       1/1/2014
 $3,500,000
Pre-Combustion
--
--
                                      --
                                      --
--
                                      --
--
--
CCS Project - Coffeyville
Coffeyville Resources Fertilizers Plant
Capture and Injection
KS
Potential
Planning
                                      --
NA
                                                                       6/1/2013
 --
Pre-Combustion
Ammonia
--
                                      --
                                      --
--
                                      --
EOR
--
Edison Mission Group
Powerton Station
Capture
IL
Potential
--
                                     1538
Megawatt
                                                                       1/1/2009
 --
Post-Combustion
Amine
Amines
                                      --
                                      --
--
                                       2
--
--
American Electric Power - Red Rock Facility
Red Rock Generating Facility
Capture
OK
Terminated
Permitting Planning
                                      950
Megawatt
                                                                       1/1/2011
 $1,800,000
Post-Combustion
--
--
                                      --
                                      --
--
                                      --
--
--
NRG Energy Inc. (Somerset Plant)
Somerset Plant
Capture
MA
Terminated
Retrofit Plans
                                      380
Megawatt
--
 $200,000
Pre-Combustion
--
--
                                      --
                                      --
--
                                      --
--
--
Air Products and Chemicals Inc. CCS Project
Methane Steam Reformer Waste Streams
Capture and Injection
TX
Active
Developing Infrastructure
                                      --
NA
                                                                      11/1/2012
$961
Industrial
Adsorption
Air Products will concentrate CO2 from two steam methane reformer (SMR) hydrogen production plants; vacuum swing adsorption
                                      0.9
                                   1,000,000
Tons/yr
                                       2
EOR
Onsite- CO2 will be purified, compressed and dried.
Alcoa Inc.
Alcoa Technical Center
Capture and Injection
PA
Active
--
                                      --
NA
--
$16,872
Post-Combustion
--
CO2 captured from industrial flue gas streams with in-duct scrubbers, and converted directly to carbonates and bicarbonates.
                                      --
                                      --
--
                                      --
GS
--
Duke Energy - Edwardsport Plant
Edwardsport IGCC
Capture and Injection
IN
Active
Engineering design
                                      618
Megawatt
                                                                      10/1/2012
 $2,300,000
Pre-Combustion
--
--
                                      --
                                      --
--
                                      --
--
--
FutureGen 2.0 - Meredosia
Ameren's 200 MW Unit 4
Capture and Injection
IL
Active
Plant Design
                                      200
Megawatt
                                                                       1/1/2012
 $552,535
Oxycombustion
Oxyfuel
Oxyfuel Combustion
                                      0.9
                                   1,300,000
Tonnes/yr
                                       1
GS
--
Great Plains Synfuels Plant
Great Plains Synfuels Plant
Capture and Injection
ND
Active
Injection Ongoing
                                      900
Megawatt
                                                                       9/1/2000
$2,100,000
Pre-combustion
Gasification
Lurgi gasifiers
                                      --
                                   2,000,000
Tons/yr
                                      --
EOR
--
Hydrogen Energy California Project
HECA IGCC Plant
Capture and Injection
CA
Active
Permitting Planning
                                      390
Megawatt- Gross
                                                                      12/1/2019
 $2,800,000
Pre-Combustion
Physical Absorption
Acid gas recovery- Rectisol technology in a solid-feed IGCC
                                      0.9
                                      --
--
                                      --
EOR
--
Kemper County Project
Kemper County IGCC Plant (a.k.a. Ratcliffe IGCC plant)
Capture and Injection
MI
Active
Developing Infrastructure
                                      582
Megawatt
                                                                       1/1/2014
 $2,400,000
Pre-Combustion
Gasification
TRIG Technology
                                     0.65
                                      --
--
                                      --
EOR
--
La Veta NG Processing
La Veta NG Plant
Capture and Injection
CO
Active
Injection Ongoing
                                      --
NA
                                                                       1/1/2007
 $33,000
Separation
Membrane
Non-amine membrane process for separating CO2
                                      --
                                      --
--
                                      --
--
--
Leucadia Energy Capture Project - Louisiana
Lake Charles Co-Generation Plant
Capture and Injection
LA
Active
Plant in Operation
                                      --
NA
                                                                       1/1/2010
 $540
Pre-Combustion
Gasification
GE Quench gasification
                                     0.85
                                   4,500,000
Tons/yr
                                      --
EOR
Onsite- Compression involves the use of integrally geared multistage centrifugal compressors with 8 stages of compression and 6 stages of intercooling, configured as 2x50% serving two rectisol units.
MGSC Large-Volume Sequestration Test:  Ethanol Plant Source
ADM Ethanol Facility- Decatur Complex
Capture and Injection
IL
Active
Injection Ongoing
                                      --
NA
                                                                       1/1/2010
 $           96,214
Industrial
Amine
Amines
                                      --
                                     1,000
Tonnes/day
                                      --
GS
Onsite- CO2 is
compressed to a supercritical fluid (~1,400 psig) by two 4-stage reciprocating
compressors running in parallel and powered by 632 kW motors. Glycol
dehydration occurs between the 3rd and 4th stages of compression. At the injection site, an additional pump is integrated into the system just
downstream of the compressors to boost pressure above 1,400 psi if additional
pressure is needed to maintain an injection rate 1,000 tonnes per day.
MRCSP Michigan Basin Geologic Test and Large-Volume Injection:  Otsego County, MI
DTE Turtle Creek Natural Gas Plant
Capture and Injection
MI
Active
Injection Complete
                                      --
NA
                                                                       1/1/2010
 $           23,000
Separation
Amine
Amines- Gas Separation
                                      --
                                    200,000
Tons/yr
                                      --
EOR/GS
Nearby- Compression facility near DTE Energy's Turtle Lake NG processing plant. CO2 compressed to supercritical pressure, physical moisture removed, and cooled.
NRG Energy Inc. (W.A. Parish Plant)
W.A. Parish Plant
Capture and Injection
TX
Active
Developing Infrastructure
                                      60
Megawatt
                                                                       1/1/2010
 $333,608
Post-Combustion
Amine
Fluor Econamine
                                      0.9
                                    500,000
Tonnes/yr
                                       4
EOR
Onsite- Testing absorber intercooling and lean solution vapor compression.
PCOR Bell Creek Demonstration Project
ConocoPhillips Lost Cabin/Madden Gas Plant
Capture and Injection
MT
Active
Developing Infrastructure
                                   50000000
Cubic feet per day
                                                                       1/1/2012
 $94,000
Post-Combustion
--
--
                                      --
                                  50,000,000
cubic feet per day
                                      --
EOR
Nearby- Plan to build compression facilities adjacent to the Lost Cabin Gas Plant. Compression will involve taking the CO2 from 50 to 2,200 psi allowing for delivery to the project site at injection-ready pressure.
Pecos County, Texas - Gas Processing
Century Gas Processing Plant
Capture and Injection
NM
Active
Plant in Operation
                                      --
NA
                                                                      10/8/2010
 $1,200,000
Separation
--
--
                                      --
                                   5,000,000
Tonnes/yr
                                      --
EOR
--
Polk Station Carbon Dioxide Capture and Storage Project
Polk Power Station IGCC Plant
Capture and Injection
FL
Active
Engineering design
                                      250
Megawatt
                                                                       1/1/2013
 --
Post-Combustion
Amine
Amines- aMDEA, activated amine
                                      0.9
                                    300,000
Tons/yr
                                      --
GS
Onsite- Compression and drying.
Purdy, Sho-Vel-Tum EOR Project
Koch Nitrogen Company's Enid Fertilizer Plant
Capture and Injection
OK
Active
Injection Ongoing
                                      --
NA
                                                                       1/1/1998
 --
Pre-Combustion
Membrane
Amino Acid-based solvents & Membranes
                                      --
                                    680,000
Tonnes/yr
                                      --
EOR/GS
--
Searles Valley Minerals
Power Plant Capture
Capture and Injection
CA
Active
Plant in Operation
                                      108
Megawatt
                                                                       1/1/1978
 --
Post-Combustion
Membrane
MEA solvent recovery process
                                      --
                                    300,000
Tons/yr
                                       2
Soda Ash Production
--
SECARB Anthropogenic Test and Stage 1
Plant James M. Barry
Capture and Injection
AL
Active
--
                                      25
Megawatt
                                                                       6/1/2011
 --
Post-Combustion
Amine
Amines
                                      --
                                100,000-150,000
Tonnes/yr
                                      --
EOR
Onsite- Facility site map  shows a condenser, CO2 compressor, compressor suction scrubber and inter-cooler (HP), dehydration unit, and a compressor suction scrubber and inter-cooler (LP).The CO2, will be dehydrated and compressed
to approximately 2,000 psig.
Shell Chemical CCS Project
Multiple
Capture and Injection
LA
Active
Site Selection
                                      --
NA
                                                                       1/1/2010
 $             3,000
Industrial
--
--
                                      --
                                      --
--
                                      --
--
--
Shute Creek Plant
Shute Creek Natural Gas Processing Plant
Capture and Injection
WY
Active
Injection Ongoing
                                      --
NA
                                                                       1/1/2010
 $           86,000
--
Cryogenics
Controlled Freeze ZoneTM technology, which freezes the CO2 out of the gas emission stream
                                      0.5
                                   6,000,000
Tonnes/yr
                                       2
EOR
Onsite- CO2 compressed to 1750 psig prior to transport. Single 20,000-HP MP/HP compressor and a 3,000-HP LP compressor by Dresser-Rand.
Summit Energy - Texas Clean Energy Project (TCEP)
Penwell IGCC Plant
Capture and Injection
TX
Active
Plant Design
                                      400
Megawatt- Gross
                                                                       1/1/2010
 $      2,400,000
Pre-Combustion
Physical Absorption
Siemens IGCC technology and Linde Rectisol acid-gas capture technology
                                      0.9
                                   3,000,000
Tons/yr
                                      --
EOR (~79%) and urea fertilizer (~21%)
Onsite- Selas Fluid Processing will be handling the synthesis gas produced by the Siemens gasifiers, including Shift and Gas Cooling, and Rectisol(R) Wash Unit; CO2 compression, mercury removal, sulfuric acid production, and urea production. 21% of CO2 will be used in producing approximately 2,156 tons/day of urea fertilizer. The balance  of the CO2 will be compressed for transport by existing pipelines.
The Erora Group - Cash Creek IGCC
Cash Creek Generation
Capture and Injection
KY
Active
Permitting Planning
                                      565
Megawatt
                                                                       1/1/2015
 $      1,500,000
Pre-Combustion
--
--
                                      --
                                   2,000,000
Tonnes/yr
                                      --
EOR
--
Trailblazer Energy Center
Tenaska Trailblazer Energy Center
Capture and Injection
TX
Active
Permitting Planning
                                      765
Megawatt- Gross
                                                                       1/1/2015
 $      3,000,000
Post-Combustion
Amine
Fluor Econamine FG plus technology
                                    85-90%
                                    16,420
Tonnes/day
                                      --
EOR/GS
Onsite- CO2 compression equipment- large compressor machines, inter and after coolers, driers, and catalytic oxidation equipment.
Val Verde NG Plants
Val Verde Natural Gas plants (Terrell, Gray Ranch, Mitchell, Puckett)
Capture and Injection
TX
Active
--
                                      --
NA
--
 --
Industrial
--
--
                                      --
                                   1,400,000
Tons/yr
                                      --
EOR
--
Antelope Valley Carbon Dioxide Capture and Storage Project
Antelope Valley Station
Capture and Injection
ND
Cancelled
--
                                      120
Megawatt
                                                                       1/1/2012
 --
Post-Combustion
Ammonia
--
                                      --
                                      --
--
                                      --
EOR
--
American Electric Power - Mountaineer
Mountaineer
Capture and Injection
WV
Completed
Injection Complete
                                      30
Megawatt
                                                                      10/1/2009
 $           76,800
Post-Combustion
Ammonia
Ammonia-based- Alstom Chilled Ammonia Process-
                                      0.9
                                      --
--
                                       1
GS
Unknown location. Once captured, the CO2 is compressed into a liquid-like state.
Carbon Dioxide Technology Corp - Lubboch Plant
Holly Avenue Electrical Power Generating Station
Capture and Injection
TX
Completed
Injection Complete
                                      50
Megawatt
                                                                       1/1/1982
 --
Post-Combustion
Amine
Gas/Spec FT-1; solvents
                                      --
                                     1,100
Tons/day
                                      --
EOR
--
ECO2 Burger
R.E. Burger Power Plant
Capture and Injection
OH
Completed
Injection Complete
                                       1
Megawatt
                                                                       1/1/2008
 --
Post-Combustion
Ammonia
Powerspan's ECO2 carbon dioxide capture process
                                      0.9
                                      20
Tons/day
                                      --
Vented to the atmosphere
--
Mitchell Energy Bridgeport Plant
Bridgeport
Capture and Injection
TX
Completed
Injection Complete
                                      --
NA
                                                                       1/1/1991
 --
Post-Combustion
Amine
Amines- inhibited MEA
                                      --
                                      500
Tons/day
                                      --
EOR
--
American Electric Power - Northeastern Station
Northeastern Station
Capture and Injection
OK
Hold
Site Characterization
                                      450
Megawatt
                                                                       1/1/2011
 --
Post-Combustion
Ammonia
Ammonia-based- Alstom Chilled Ammonia Process
                                      0.9
                                   1,500,000
Tons/yr
                                      --
EOR
--
Wallula Energy Resource Center (WERC)
Wallula IGCC Plant
Capture and Injection
WA
Hold
Permitting Planning
                                      914
Megawatt
                                                                       5/1/2014
 $3,200,000
Pre-Combustion
Gasification
Gasification
                                     0.65
                                      --
--
                                      --
--
--
WESTCARB Kimberlina Test Facility
Kimberlina Test Facility- Clean Energy System's Oxy-Field Combustion (ZEPP-1) Power Plant)
Capture and Injection
CA
Hold
--
                                      50
Megawatt
                                                                      10/1/2011
 $90,719
Oxycombustion
Oxyfuel
Oxyfuel combustion
                                      --
                                      --
--
                                      --
--
Onsite
Coal Plant Outside NY City
Coal-fired power plant
Capture and Injection
NJ
Potential
--
                                      500
Megawatt
                                                                       1/1/2014
 $5,000,000
--
--
--
                                      --
                                      --
--
                                      --
GS
--
Great Lakes Energy Research Park
Alma IGCC plant
Capture and Injection
MI
Potential
--
                                      250
Megawatt
--
 $2,000,000
Pre-Combustion
Gasification
ConocoPhillips E-Gas Gasification
                                      --
                                      --
--
                                      --
EOR
--
Kentucky NewGas
Kentucky NewGas
Capture and Injection
KY
Active
Site Selection
                                      --
NA
                                                                       1/1/2017
 $3,000,000
Pre-Combustion
Gasification
ConocoPhillips E-Gas Gasification
                                      --
                                   5,000,000
Tonnes/yr
                                      --
GS
--
Leucadia - Indiana
NA
Capture and Injection
IIN
Potential
Permitting Planning
                                      --
NA
--
 --
--
--
--
                                      --
                                      --
--
                                      --
EOR
--
Lima Polygen
Lima IGCC
Capture and Injection
OH
Potential
Permitting Planning
                                      540
Megawatt
                                                                       1/1/2013
 --
Pre-Combustion
--
--
                                      --
                                      --
--
                                      --
--
--
Project Viking
Project Viking Zero Emission Power Plant
Capture and Injection
NM
Potential
Plant Design
                                      150
Megawatt
                                                                       4/1/2013
 $         120,000
Post-Combustion
--
Converts refinery pitch to electricity, steam, and pipeline quality compressed CO2.
                                      --
                                   1,200,000
Tonnes/yr
                                      --
EOR
--
Waste Management & Processors PTY., LLC
Gilberton Early Entry Co-Production (EECP) Plant
Capture and Injection
PA
Potential
Developing Infrastructure
                                     5000
Barrels per Day
                                                                       1/1/2008
 $         612,500
Pre-Combustion
--
--
                                      --
                                      --
--
                                      --
--
--
ZENG Worsham-Steed
ZENG Worsham-Steed
Capture and Injection
TX
Potential
Plant Design
                                      70
Megawatt
--
 --
Oxycombustion
Oxyfuel
Combustion of gaseous hydrocarbon fuels with oxygen,
resulting in production of a high temperature
and high-pressure
steam (with ~10% CO2) gas
mixture. The steam (and CO2) is
expanded in a reconfigured steam
turbine, following which the CO2 is
separated in the steam condensation
process.
                                      --
                                      870
Tons/day
                                      --
EOR
--
C6 Resources CCS Project
TBD
Capture and Injection
CA
Terminated
Site Selection
                                      --
--
                                                                       1/1/2010
 $             3,000
Industrial
--
--
                                      --
                                      --
--
                                      --
--
--
CEMEX Inc. Cement CO2 Capture Project
TBD
Capture and Injection
TX
Terminated
Site Selection
                                      --
--
                                                                       1/1/2010
 $             1,137
Industrial
Dry Sorbent
--
                                      --
                                      --
--
                                      --
--
--
FutureGen - Jewett
FutureGen - Jewett
Capture and Injection
TX
Terminated
Site Characterization
                                      275
Megawatt
                                                                       1/1/2015
 $      1,000,000
Pre-Combustion
--
--
                                      --
                                      --
--
                                      --
--
--
FutureGen - Mattoon
FutureGen - Mattoon
Capture and Injection
IlL
Terminated
Site Characterization
                                      275
Megawatt
                                                                       1/1/2015
 $1,400,000
Pre-Combustion
--
--
                                      --
                                      --
--
                                      --
--
--
FutureGen - Odessa
FutureGen - Odessa
Capture and Injection
TX
Terminated
Site Characterization
                                      275
Megawatt
                                                                       1/1/2015
 $1,000,000
Pre-Combustion
--
--
                                      --
                                      --
--
                                      --
--
--
FutureGen - Tuscola
FutureGen - Tuscola
Capture and Injection
IL
Terminated
Site Characterization
                                      275
Megawatt
                                                                       1/1/2015
 $1,000,000
Pre-Combustion
--
--
                                      --
                                      --
--
                                      --
--
--
Jamestown BPU
Samuel J. Carlson Generating Station
Capture and Injection
NY
Terminated
Permitting Planning
                                      40
Megawatt
                                                                       1/1/2013
 $145,000
Pre-Combustion
--
--
                                      --
                                      --
--
                                      --
--
--
Leucadia Energy Capture Project - Mississippi
Moss Point SNG Plant
Capture and Injection
MS
Terminated
Permitting Planning
                                      --
--
                                                                       1/1/2010
 $1,689,000
Pre-Combustion
--
--
                                      --
                                      --
--
                                      --
GS/EOR
--
Leucadia- Mississippi Gasification
NA
Capture and Injection
MS
Terminated
--
                                      --
NA
--
 --
--
--
--
                                      --
                                      --
--
                                      --
EOR
--
Lockwood Gasification Plant
Lockwood gasification plant
Capture and Injection

TX
Terminated
--
                                      --
--
                                                                       1/1/2015
 $2,400,000
Pre-Combustion
--
--
                                      --
                                      --
--
                                      --
GS/EOR
--
NRG Energy Inc - Huntley IGCC Project
Huntley IGCC
Capture and Injection
NY
Terminated
Permitting Planning
                                      680
Megawatt
                                                                       1/1/2013
 $1,500,000
Pre-Combustion
Amine
Mitsubishi HI Gasification (KS-1)
                                      --
                                      --
--
                                      --
--
--
Praxair Inc. CO2 Capture and Sequestration Project
BP Refinery and Hydrogen Production Facility
Capture and Injection
MS
Terminated
Plant in Operation
                                      --
--
                                                                       1/1/2010
 $1,719
Industrial
--
--
                                      --
                                      --
--
                                      --
--
--
Wolverine Power Supply Cooperative Inc. - Industrial Capture Project
Wolverine Power Plant
Capture and Injection
MI
Terminated
Plant Design
                                      600
Megawatt
                                                                       1/1/2010
 $2,723
Post-Combustion
Amines
--
                                      --
                                      --
--
                                      --
--
--
Xcel Energy Inc.
Xcel Energy IGCC plant
Capture and Injection
CO
Terminated
--
                                      600
Megawatt
                                                                       1/1/2016
 $2,000,000
Pre-Combustion
--
--
                                      --
                                      --
--
                                      --
--
--

Table A-2. Carbon capture and processing project sources.
                                 Project Name
                                 Project Link
                              Capture References
                             Processing References
AES Shady Point
http://www.co2captureandstorage.info/project_specific.php?project_id=22
http://www.netl.doe.gov/technologies/carbon_seq/FAQs/carboncapture2.html
--
AES Warrior Run
http://www.mgs.md.gov/geo/pub/co2seqpaper.pdf
http://www.netl.doe.gov/technologies/carbon_seq/FAQs/carboncapture2.html

http://<IP_ADDRESS>/userdata/Phase%20I%20Report/MRCSP_Phase_I_Final.pdf
--
Bellingham Cogeneration Facility
http://www.zeroemissionsplatform.eu/projects/global-projects/details/29.html?mn=154

http://www.tractebelpowerinc.com/utilities/documents/Bellingham.pdf
http://www.cnie.org/NLE/CRSreports/10Aug/R41325.pdf

http://www.zeroemissionsplatform.eu/projects/global-projects/details/29.html?mn=154
--
DKRW Energy LLC
http://www.dkrwadvancedfuels.com/fw/main/Medicine-Bow-111.html
http://www.dkrwadvancedfuels.com/fw/main/Medicine-Bow-111.html
http://www.dkrwadvancedfuels.com/fw/main/Medicine_Bow_CTL_Process-160.html
Evaluation of Solid Sorbents as a Retrofit Technology for CO2 Capture
http://www.netl.doe.gov/publications/proceedings/11/co2capture/presentations/1-Monday/22Aug11-Starns-ADAES-Solid%20Sorbents%20Retrofit.pdf

http://www.netl.doe.gov/technologies/coalpower/ewr/co2/post-combustion/eval-solid-sorbent.html
http://www.netl.doe.gov/publications/proceedings/11/co2capture/presentations/1-Monday/22Aug11-Starns-ADAES-Solid%20Sorbents%20Retrofit.pdf
--
Excelsior Energy
http://www.excelsiorenergy.com/mesaba/index.html
http://www.netl.doe.gov/technologies/coalpower/cctc/EIS/mesaba_pdf/Mesaba_DEIS_Appx_A.pdf
http://www.netl.doe.gov/technologies/coalpower/cctc/EIS/mesaba_pdf/Mesaba_DEIS_Appx_A.pdf
Great River Energy
http://www.greatriverenergy.com/makingelectricity/coal/coalcreekstation.html

http://www.netl.doe.gov/technologies/coalpower/cctc/topicalreports/pdfs/topical25.pdf
http://www.greatriverenergy.com/aboutus/pressroom/archives/doc086606.pdf

http://www.businesswire.com/news/home/20090127006492/en/EPRI-Study-Adding-Carbon-Capture-Existing-Coal
--
Intermountain Power Agency
http://www.ipautah.com/

http://www.ipautah.com/data/upfiles/newsletters/PowerLines%20Dec_10_forWeb.pdf
http://www.businesswire.com/news/home/20090127006492/en/EPRI-Study-Adding-Carbon-Capture-Existing-Coal
--
Oxy-combustion Technology Development for Industrial Scale Boiler Applications
http://www.netl.doe.gov/technologies/coalpower/ewr/co2/oxy-combustion/tangential.html

http://www.netl.doe.gov/publications/factsheets/project/NT0005290.pdf

http://www.netl.doe.gov/publications/proceedings/11/co2capture/presentations/3-Wednesday/24Aug11-Levassuer-Alstom-OxyComb%20IndustScaleBoiler.pdf
http://www.netl.doe.gov/publications/factsheets/project/NT0005290.pdf
--
Slipstream Development and Testing of Siemens POSTCAP Capture and Separation Technology
http://www.netl.doe.gov/technologies/coalpower/ewr/co2/post-combustion/siemens-postcap.html
http://www.netl.doe.gov/publications/proceedings/11/co2capture/presentations/2-Tuesday/23Aug11-Winkler-Siemens-Technology%20Slipstream%20Testing.pdf

http://www.powermag.com/POWERnews/2909.html

http://www.tampaelectric.com/news/article/index.cfm?article=541
--
Slipstream Testing of a Membrane CO2 Capture Process for Existing Coal-Fired Power Plants
http://www.netl.doe.gov/publications/proceedings/11/co2capture/presentations/1-Monday/22Aug11-Merkel-MTR-Efficient%20Membrane%20Pilot%20Test.pdf
http://www.netl.doe.gov/publications/proceedings/11/co2capture/presentations/1-Monday/22Aug11-Merkel-MTR-Efficient%20Membrane%20Pilot%20Test.pdf
--
Touchstone Algae Production
http://www.netl.doe.gov/publications/factsheets/project/FE0002546.pdf
http://fossil.energy.gov/programs/sequestration/industrial/industrial_ccs.html
--
Sweeny Polygeneration with CO2 Capture