1555 Wilson Boulevard Corporate Headquarters:

Suite 300 57 Water Street

Arlington, VA 22209 Watertown, MA 02472

Tel: 703.247.6000 An Employee-Owned Company Tel: 617.673.7000

Fax: 703.247.6001 www.cadmusgroup.com Fax: 617.673.7001

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.
Draft

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. 1A 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. 

Figure 1. A typical CCS chain (Aspelund and Jordal, 2007).

 

1 Report of the Interagency Task Force on Carbon Capture and Storage, 2010. Accessed at 

http://www.fe.doe.gov/programs/sequestration/ccstf/CCSTaskForceReport2010.pdf. 

Gas 

Conditioning Compression

Pipeline 

Transport

Injection/Final 

Storage

Capture
Draft

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).
Draft

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/m3under 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).
Draft

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 noncondensable gases)As proposed in ENCAP project* Costs

O2 N/A Inconsistent literature Challenges in the reservoir

Ar <4 vol.% (all noncondensable gases)As proposed in ENCAP project* Costs

H2 <4 vol.% (all noncondensable 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/). 
Draft

Table 2. Recommended CO2 stream composition limits for three design cases (DOE, 2012). 

C

o

mponent

Unit (Max 

unless 

Otherwise 

noted)

Carbon Steel

Pipeline

Enhanced Oil

Recovery

Saline Reservoir

Sequestration

Saline

Reservoir

CO2 & H2S Cosequestration

Venting

Concerns

C

onceptual

Design

Range in 

Literature

C

onceptual

Design

Range in 

Literature

C

onceptual

Design

Range in 

Literature

C

onceptual

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/m3(organo)

Glycol ppmv 46 0-174 46 0-174 46 0-174 46 0-174
Draft

C

o

mponent

Unit (Max 

unless 

Otherwise 

noted)

Carbon Steel

Pipeline

Enhanced Oil

Recovery

Saline Reservoir

Sequestration

Saline

Reservoir

CO2 & H2S Cosequestration

Venting

Concerns

C

onceptual

Design

Range in 

Literature

C

onceptual

Design

Range in 

Literature

C

onceptual

Design

Range in 

Literature

C

onceptual

Design

Range in 

Literature

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). 
Draft

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-
Draft

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 highpressure 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).
Draft

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 precombustion 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 precombustion 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 precombustion)
Draft

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 
Draft

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, oxygenbearing 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. 
Draft

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 DC101TM 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, ambientintermediate pressures Dow Chemical, USA

Amine Guard 

(MEA)

5 n monoethanolamine and 

chemical inhibitors

~40°C, ambientintermediate pressures Union Carbide, USA
Draft

Absorption process Solvent Process Conditions Developer/licensor

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, KS2, 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). 
Draft

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 
Draft

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 PostCombustion

New Mexico Institute 

of Mining and 

Technology

Under 

Development

Polaris Membrane PostCombustion

Membrane Technology 

and Research

Commercially 

Available

Pebax thin-film 

membranes

PostCombustionMembrane 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. 
Draft

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). 
Draft

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. 
Draft

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.
Draft

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 
Draft

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 energyeffective 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 
Draft

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.
Draft

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 cryopump from 250 to 2,215 psia 

16,198 BHP (12.08 MW) (Includes 7,814 BHP 

for refrigeration)

centrifugal compression to 250 psia with semiisothermal 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
Draft

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 acidgas-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 diisoproponal (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 ). 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). 
Draft

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 ).

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 ). 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 
Draft

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. 
Draft

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 

1010 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 Postcombustion

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 fossilfuel 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 7 below 

summarizes the plant configurations used in the report and the costs estimated for each configuration.

NETL (2010) study (Table 7) 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 7 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. 
Draft

Table 71. Case descriptions and costs estimated in the NETL (2010) report for baseline estimates.

Unit 

Cycle

CO2

Capture

Gasifier/

Boiler

Oxida

nt

H2S 

separation/re

moval

Sulfur 

removal/Re

covery

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 EGas

95 

mol% 

O2

Refrigerated 

MDEA Claus Plant

Cyclone, 

barrier filter 

and scrubber

N2 dilution -

1,913 1,469,577 93.8

IGCC 90% CoP Egas

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% Subcritic

al PC Air -

Wet 

FGD/Gypsu

m

Baghouse LNB w/OFA 

and SCR -

1,622 1,098,124 75.3

PC 90% Subcritic

al PC Air -

Wet 

FGD/Gypsu Baghouse LNB w/OFA and SCR Amine absorber 2,942 1,985,432 139
Draft

Unit 

Cycle

CO2

Capture

Gasifier/

Boiler

Oxida

nt

H2S 

separation/re

moval

Sulfur 

removal/Re

covery

PM control NOx control CO2 Separation

TOTAL COST

Plant cost 

(2007 $/kW)

Overnight cost 

(2007x1,1000)

LCOE 

(mills/kWh, 

2007$)

m

PC 0% Supercrit

ical PC Air -

Wet 

FGD/Gypsu

m

Baghouse LNB w/OFA 

and SCR -

1,647 1,113,445 74.7

PC 90% Supercrit

ical PC Air -

Wet 

FGD/Gypsu

m

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
Draft

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 82). 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 82. 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 93). 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 93). Further details on the 

carbon capture technologies employed for each project are provided in Table A-1 in the Appendix. 

Table 93. 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
Draft

Carbon Capture 

Type/Technology # of Projects

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

Aspelund A, MlnvikM J and De Koeijer G (2006) Ship transport of C0 2 – technical solutions and analysis 

of costs, energy utilization, energy efficiency and C02 emissions, Chem Eng Res Des, 84-A9, 847-855.

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
Draft

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

Centers for Disease Control and Prevention (CDC), National Institute for Occupational Safety and Health. 

2012. Chemical Listings and Documentation. H2S.-http://www.cdc.gov/niosh/idlh/7783064.html. 

Department of Energy (DOE). 2012. Quality guidelines for energy system studies: CO2 impurity design 

parameters. DOE, NETL. DOE/NETL-341/011212. http://www.netl.doe.gov/energyanalyses/pubs/QGESSSec3.pdf. 

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-Update2011_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.” 1st

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/herzogmeldon-hatton.pdf
Draft

Kohl, A., and R. Nielsen. 1997. Gas Purification, Fifth Edition. Gulf Publishing Company, Houston, TX. 

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/energyanalyses/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.

Wilcox, J. Carbon Capture, 2012. Springer Science + Business Media. 

Wu, Y., J. Carroll, and Z. Du. 2011. Carbon Dioxide Sequestration and Related Technologies. Scrivener 

Publishing LLC, Salem, Massachusetts. 
Draft

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/So

urce

Project 

Type State Operating Status

Operating 

Status Detail

Unit 

Base 

Powe

r

Unit 

Base 

Name

Project 

Start 

Date

Cost (US 

$) 

(x1000)

Capture 

Type

Capture 

Technolog

y

Capture 

Technology 

Detail

% 

Capt

ure

Captur

e Rate

Captur

e Unit 

of 

Measu

re

# of 

Cap

ture 

Unit

s

CO2 

Fate

Processing Location/ 

Technology

AES Shady 

Point

Shady 

Point 

Power 

Plant

Capture OK Active Plant in 

Operation 320 Megawatt 1/1/1991 --

PostCombustion Amine Ethanol-amino 

solvent -- 73,000 Tons/yr 4

Food/

Bever

age

--

AES Warrior 

Run

Warrior 

Run 

Power 

Plant

Capture MD Active Plant in 

Operation 180 Megawatt 2/1/2000 --

PostCombustion Amine Ethanol-amino 

solvent --

120,00

0

Tons/yr 3

Food/

Bever

age

--

Bellingham 

Cogeneration 

Facility

Bellingha

m 

Cogenera

tion 

Facility

Capture MA Active Plant in 

Operation 320 Megawatt 9/1/1991 --

PostCombustion Amine Fluor Econamine 

FG scrubber

85-

95%

110,00

0

Tonnes

/yr 2

Food/

Bever

age

--

DKRW 

Energy LLC

Medicine 

Bow CTL Capture WY Active PermittingPlanning

2000

0

Barrels 

per 

Day

1/1/2014 $2,000,00

0 

PreCombustion Gasification

GE Coal 

gasification 

technology to 

produce 

synthetic gas

-- -- -- -- EOR

Offsite- CO2 will be removed, 

dried, channeled and 

pressurized. 
Draft

Project 

Name

Plant/So

urce

Project 

Type State Operating Status

Operating 

Status Detail

Unit 

Base 

Powe

r

Unit 

Base 

Name

Project 

Start 

Date

Cost (US 

$) 

(x1000)

Capture 

Type

Capture 

Technolog

y

Capture 

Technology 

Detail

% 

Capt

ure

Captur

e Rate

Captur

e Unit 

of 

Measu

re

# of 

Cap

ture 

Unit

s

CO2 

Fate

Processing Location/ 

Technology

Evaluation of 

Solid 

Sorbents as a 

Retrofit 

Technology 

for CO2 

Capture

Alabama 

Power 

Co. Plant 

Miller

Capture AL Active Engineering 

design 1

Megaw

att

10/1/201

0

$18,750 PostCombustion Adsorption Solid sorbent 0.9 2,100 lbs/hr 1 -- --

Excelsior 

Energy

Mesaba 

Coal 

IGCC

Capture MN Active Plant Design 602 Megaw

att- Net 1/1/2012 $2,000,00

0

PreCombustion Gasification

ConocoPhillips 

E-Gas 

Gasification

30-

90% -- --

1 to 

6

EOR 

or 

Salin

e 

Onsite- CO2 will be 

compressed and dried.

Great River 

Energy

Coal 

Creek 

Station

Capture ND Active Planning 1100 Megaw

att 1/1/2009 --

PostCombustion Amine Amines -- -- -- 2 -- --

Intermountain 

Power Project

Holly 

Avenue 

Electrical 

Power 

Generatin

g Station

Capture UT Active - 950 Megaw

att 1/1/2009 --

PostCombustion Amine Amines -- -- -- 2 -- --

Oxycombustion 

Technology 

Development 

for Industrial 

Scale Boiler 

Applications

Alstom's 

15 MWth 

Boiler 

Simulatio

n Facility

Capture CT Active Plant in 

Operation 15 Megawatt

10/1/200

8

$18,012 Oxycombusti

on

Oxyfuel

Oxyfuel 

CombustionAlstom 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 PostCombustion Amine

POSTCAP 

technologyAqueous amino 

acid salt-based 

solvent

0.9 -- -- 4 EOR --
Draft

Project 

Name

Plant/So

urce

Project 

Type State Operating Status

Operating 

Status Detail

Unit 

Base 

Powe

r

Unit 

Base 

Name

Project 

Start 

Date

Cost (US 

$) 

(x1000)

Capture 

Type

Capture 

Technolog

y

Capture 

Technology 

Detail

% 

Capt

ure

Captur

e Rate

Captur

e Unit 

of 

Measu

re

# of 

Cap

ture 

Unit

s

CO2 

Fate

Processing Location/ 

Technology

Slipstream 

Testing of a 

Membrane 

CO2 Capture 

Process for 

Existing CoalFired Power 

Plants

APS 

Cholla -

National 

Carbon 

Capture 

Center

Capture AR Active -- 995 Megaw

att

10/1/201

0

$18,750 PostCombustion Membrane MTR Membrane 

System 0.9 1

Tons/d

ay

3 -- --

Touchstone 

Algae 

Production

Cedar 

Lane 

Farms

Capture OH Active -- 2.8 Megaw

att 1/1/2010 $1 8,446 -- Biological Algae assimilation 0.6 -- -- --

Algae 

produ

ction

--

Sweeny 

Polygeneratio

n with CO2 

Capture

Commerc

ial 

Source

Capture TX Cancelled Cancelled 683 Megaw

att 1/1/2015 --

PreCombustion -- -- -- -- -- --GS/E

OR --

We Energies 

Pleasant 

Prairie Field 

Pilot

Pleasant 

Prairie Capture WI Completed

Capture 

Complete 1.7 Megawatt

10/1/200

9

--

PostCombustion Ammonia

Alstom Chilled 

Ammonia 

Process

0.9 15,000 Tonnes

/yr 2

Vente

d to 

the 

atmos

phere

--

American 

Electric 

Power - Great 

Bend IGCC

Great 

Bend 

IGCC

Capture OH Hold Plant Design 629 Megaw

att -- $1,100,00

0

PreCombustion -- -- -- -- -- -- -- --

Taylorville 

Energy 

Center

Taylorvill

e Energy 

Center 

IGCC

Capture IL Hold Permitting 716

Megaw

attGross1/1/2014 $3,500,00

0 

PreCombustion -- -- -- -- -- -- -- --

CCS Project -

Coffeyville

Coffeyvill

e 

Resource

s 

Fertilizers 

Plant

Capture

and 

Injection

KS Potential Planning -- NA 6/1/2013 --

PreCombustion Ammonia -- -- -- -- -- EOR --

Edison 

Mission 

Group

Powerton 

Station Capture IL Potential -- 1538 Megawatt 1/1/2009 --

PostCombustion Amine Amines -- -- -- 2 -- --
Draft

Project 

Name

Plant/So

urce

Project 

Type State Operating Status

Operating 

Status Detail

Unit 

Base 

Powe

r

Unit 

Base 

Name

Project 

Start 

Date

Cost (US 

$) 

(x1000)

Capture 

Type

Capture 

Technolog

y

Capture 

Technology 

Detail

% 

Capt

ure

Captur

e Rate

Captur

e Unit 

of 

Measu

re

# of 

Cap

ture 

Unit

s

CO2 

Fate

Processing Location/ 

Technology

American 

Electric 

Power - Red 

Rock Facility

Red Rock 

Generatin

g Facility

Capture OK Terminate

d

Permitting 

Planning 950 Megawatt 1/1/2011 $1,800,00

0

PostCombustion -- -- -- -- -- -- -- --

NRG Energy 

Inc. 

(Somerset 

Plant)

Somerset 

Plant Capture MA Terminated

Retrofit Plans 380 Megaw

att -- $200,000 PreCombustion -- -- -- -- -- -- -- --

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 1,000,0

00 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 PostCombustion --

CO2 captured 

from industrial 

flue gas streams 

with in-duct 

scrubbers, and 

converted 

directly to 

carbonates and 

bicarbonates.

-- -- -- -- GS --

Duke Energy 

- Edwardsport 

Plant

Edwards

port 

IGCC

Capture 

and 

Injection

IN Active Engineering 

design 618 Megawatt

10/1/201

2

$2,300,00

0 

PreCombustion -- -- -- -- -- -- -- --

FutureGen 

2.0 -

Meredosia

Ameren's 

200 MW 

Unit 4

Capture 

and 

Injection

IL Active Plant Design 200 Megaw

att 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

Precombustion Gasification Lurgi gasifiers --2,000,0

00 Tons/yr -- EOR --

Hydrogen 

Energy 

California 

Project

HECA 

IGCC 

Plant

Capture 

and 

Injection

CA Active Permitting 

Planning 390

Megaw

attGross

12/1/201

9

$2,800,00

0

PreCombustionPhysical 

Absorption

Acid gas 

recoveryRectisol

technology in a 

solid-feed IGCC

0.9 -- -- -- EOR --
Draft

Project 

Name

Plant/So

urce

Project 

Type State Operating Status

Operating 

Status Detail

Unit 

Base 

Powe

r

Unit 

Base 

Name

Project 

Start 

Date

Cost (US 

$) 

(x1000)

Capture 

Type

Capture 

Technolog

y

Capture 

Technology 

Detail

% 

Capt

ure

Captur

e Rate

Captur

e Unit 

of 

Measu

re

# of 

Cap

ture 

Unit

s

CO2 

Fate

Processing Location/ 

Technology

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 $2,400,00

0

PreCombustion 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 

CoGeneratio

n Plant

Capture 

and 

Injection

LA Active Plant in 

Operation -- NA 1/1/2010 $540 PreCombustion 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 LargeVolume 

Sequestration 

Test: Ethanol 

Plant Source

ADM 

Ethanol 

FacilityDecatur 

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.
Draft

Project 

Name

Plant/So

urce

Project 

Type State Operating Status

Operating 

Status Detail

Unit 

Base 

Powe

r

Unit 

Base 

Name

Project 

Start 

Date

Cost (US 

$) 

(x1000)

Capture 

Type

Capture 

Technolog

y

Capture 

Technology 

Detail

% 

Capt

ure

Captur

e Rate

Captur

e Unit 

of 

Measu

re

# of 

Cap

ture 

Unit

s

CO2 

Fate

Processing Location/ 

Technology

MRCSP 

Michigan 

Basin 

Geologic Test 

and LargeVolume 

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 --

200,00

0

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 PostCombustion Amine Fluor Econamine 0.9 500,000

Tonnes

/yr 4 EOR

Onsite- Testing absorber 

intercooling and lean solution 

vapor compression.

PCOR Bell 

Creek 

Demonstratio

n Project

ConocoP

hillips 

Lost 

Cabin/Ma

dden Gas 

Plant

Capture 

and 

Injection

MT Active Developing 

Infrastructure

5000

0000

Cubic 

feet per 

day

1/1/2012 $94,000 PostCombustion -- -- --

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 

Processin

g Plant

Capture 

and 

Injection

NM Active Plant in 

Operation -- NA 10/8/2010

$1,200,00

0

Separation -- -- --

5,000,0

00

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 --

PostCombustion Amine

AminesaMDEA, 

activated amine

0.9 300,00

0

Tons/yr -- GS Onsite- Compression and 

drying. 

Purdy, ShoVel-Tum EOR 

Project

Koch 

Nitrogen 

Company

's Enid 

Fertilizer 

Plant

Capture 

and 

Injection

OK Active Injection 

Ongoing -- NA 1/1/1998 --

PreCombustion Membrane

Amino Acidbased solvents 

& Membranes

--

680,00

0

Tonnes

/yr --

EOR/

GS --

Searles 

Valley 

Minerals

Power 

Plant 

Capture

Capture 

and 

Injection

CA Active Plant in 

Operation 108 Megawatt 1/1/1978 --

PostCombustion Membrane

MEA solvent 

recovery 

process

--

300,00

0

Tons/yr 2

Soda 

Ash 

Produ

ction

--
Draft

Project 

Name

Plant/So

urce

Project 

Type State Operating Status

Operating 

Status Detail

Unit 

Base 

Powe

r

Unit 

Base 

Name

Project 

Start 

Date

Cost (US 

$) 

(x1000)

Capture 

Type

Capture 

Technolog

y

Capture 

Technology 

Detail

% 

Capt

ure

Captur

e Rate

Captur

e Unit 

of 

Measu

re

# of 

Cap

ture 

Unit

s

CO2 

Fate

Processing Location/ 

Technology

SECARB 

Anthropogeni

c Test and 

Stage 1

Plant 

James M. 

Barry

Capture 

and 

Injection

AL Active -- 25 Megaw

att 6/1/2011 --

PostCombustion Amine Amines --

100,00

0-

150,00

0

Tonnes

/yr -- EOR

Onsite- Facility site map 

shows a condenser, CO2 

compressor, compressor 

suction scrubber and intercooler (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 

Processin

g 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 6,000,0

00

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 DresserRand. 

Summit 

Energy -

Texas Clean 

Energy 

Project 

(TCEP)

Penwell 

IGCC 

Plant

Capture 

and 

Injection

TX Active Plant Design 400

Megaw

attGross1/1/2010 $ 

2,400,000

PreCombustionPhysical 

Absorption

Siemens IGCC 

technology and 

Linde Rectisol 

acid-gas capture 

technology

0.9 3,000,0

00 Tons/yr --

EOR 

(~79

%) 

and 

urea 

fertiliz

er 

(~21

%)

Onsite- Selas Fluid 

Processing will be handling 

the synthesis gas produced 

by the Siemens gasifiers, 

including Shift and Gas 

Cooling, and Rectisol® 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 

Generatio

n

Capture 

and 

Injection

KY Active Permitting 

Planning 565 Megawatt 1/1/2015 $ 1,500,000 

PreCombustion -- -- --2,000,0

00

Tonnes

/yr -- EOR --
Draft

Project 

Name

Plant/So

urce

Project 

Type State Operating Status

Operating 

Status Detail

Unit 

Base 

Powe

r

Unit 

Base 

Name

Project 

Start 

Date

Cost (US 

$) 

(x1000)

Capture 

Type

Capture 

Technolog

y

Capture 

Technology 

Detail

% 

Capt

ure

Captur

e Rate

Captur

e Unit 

of 

Measu

re

# of 

Cap

ture 

Unit

s

CO2 

Fate

Processing Location/ 

Technology

Trailblazer 

Energy 

Center

Tenaska 

Trailblaze

r Energy 

Center

Capture 

and 

Injection

TX Active Permitting 

Planning 765

Megaw

attGross1/1/2015 $ 

3,000,000

PostCombustion 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 -- -- --

1,400,0

00 Tons/yr -- EOR --

Antelope 

Valley Carbon 

Dioxide 

Capture and 

Storage 

Project

Antelope 

Valley 

Station

Capture 

and 

Injection

ND Cancelled -- 120 Megaw

att 1/1/2012 --

PostCombustion Ammonia -- -- -- -- -- EOR --

American 

Electric 

Power -

Mountaineer

Mountain

eer 

Capture 

and 

Injection

WV Complete

d

Injection 

Complete 30 Megawatt

10/1/200

9

$ 

76,800

PostCombustion Ammonia

Ammoniabased- Alstom 

Chilled Ammonia 

Process0.9 -- -- 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 

Generatin

g Station

Capture 

and 

Injection

TX Complete

d

Injection 

Complete 50 Megawatt 1/1/1982 --

PostCombustion Amine Gas/Spec FT-1; 

solvents -- 1,100 Tons/day

-- EOR --
Draft

Project 

Name

Plant/So

urce

Project 

Type State Operating Status

Operating 

Status Detail

Unit 

Base 

Powe

r

Unit 

Base 

Name

Project 

Start 

Date

Cost (US 

$) 

(x1000)

Capture 

Type

Capture 

Technolog

y

Capture 

Technology 

Detail

% 

Capt

ure

Captur

e Rate

Captur

e Unit 

of 

Measu

re

# of 

Cap

ture 

Unit

s

CO2 

Fate

Processing Location/ 

Technology

ECO2 Burger

R.E. 

Burger 

Power 

Plant

Capture 

and 

Injection

OH Complete

d

Injection 

Complete 1

Megaw

att 1/1/2008 --

PostCombustion Ammonia

Powerspan's 

ECO2 carbon 

dioxide capture 

process

0.9 20 Tons/d

ay

--

Vente

d to 

the 

atmos

phere

--

Mitchell 

Energy 

Bridgeport 

Plant

Bridgepor

t

Capture 

and 

Injection

TX Complete

d

Injection 

Complete -- NA 1/1/1991 --

PostCombustion Amine Aminesinhibited MEA -- 500 Tons/d

ay

-- EOR --

American 

Electric 

Power -

Northeastern 

Station

Northeast

ern 

Station

Capture 

and 

Injection

OK Hold

Site 

Characterizati

on

450 Megaw

att 1/1/2011 --

PostCombustion Ammonia

Ammoniabased- Alstom 

Chilled Ammonia 

Process

0.9 1,500,0

00 Tons/yr -- EOR --

Wallula 

Energy 

Resource 

Center 

(WERC)

Wallula 

IGCC 

Plant

Capture 

and 

Injection

WA Hold Permitting 

Planning 914 Megawatt 5/1/2014 $3,200,00

0

PreCombustion Gasification Gasification 0.65 -- -- -- -- --

WESTCARB 

Kimberlina 

Test Facility

Kimberlin

a Test 

FacilityClean 

Energy 

System's 

Oxy-Field 

Combusti

on 

(ZEPP-1) 

Power 

Plant)

Capture 

and 

Injection

CA Hold -- 50 Megaw

att

10/1/201

1

$90,719 Oxycombusti

on

Oxyfuel Oxyfuel 

combustion -- -- -- -- -- Onsite

Coal Plant 

Outside NY 

City

Coal-fired 

power 

plant

Capture 

and 

Injection

NJ Potential -- 500 Megaw

att 1/1/2014 $5,000,00

0

-- -- -- -- -- -- -- GS --

Great Lakes 

Energy 

Research 

Park

Alma 

IGCC 

plant

Capture 

and 

Injection

MI Potential -- 250 Megaw

att -- $2,000,00

0

PreCombustion Gasification

ConocoPhillips 

E-Gas 

Gasification

-- -- -- -- EOR --

Kentucky 

NewGas

Kentucky 

NewGas

Capture 

and 

Injection

KY Active Site Selection -- NA 1/1/2017 $3,000,00

0

PreCombustion Gasification

ConocoPhillips 

E-Gas 

Gasification

--

5,000,0

00

Tonnes

/yr -- GS --
Draft

Project 

Name

Plant/So

urce

Project 

Type State Operating Status

Operating 

Status Detail

Unit 

Base 

Powe

r

Unit 

Base 

Name

Project 

Start 

Date

Cost (US 

$) 

(x1000)

Capture 

Type

Capture 

Technolog

y

Capture 

Technology 

Detail

% 

Capt

ure

Captur

e Rate

Captur

e Unit 

of 

Measu

re

# of 

Cap

ture 

Unit

s

CO2 

Fate

Processing Location/ 

Technology

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 --

PreCombustion -- -- -- -- -- -- -- --

Project Viking

Project 

Viking 

Zero 

Emission 

Power 

Plant

Capture 

and 

Injection

NM Potential Plant Design 150 Megaw

att 4/1/2013 $ 120,000

PostCombustion --

Converts 

refinery pitch to 

electricity, 

steam, and 

pipeline quality 

compressed 

CO2.

--

1,200,0

00

Tonnes

/yr -- EOR --

Waste 

Management 

& Processors 

PTY., LLC

Gilberton 

Early 

Entry CoProductio

n (EECP) 

Plant

Capture 

and 

Injection

PA Potential Developing 

Infrastructure 5000

Barrels 

per 

Day

1/1/2008 $ 

612,500

PreCombustion -- -- -- -- -- -- -- --
Draft

Project 

Name

Plant/So

urce

Project 

Type State Operating Status

Operating 

Status Detail

Unit 

Base 

Powe

r

Unit 

Base 

Name

Project 

Start 

Date

Cost (US 

$) 

(x1000)

Capture 

Type

Capture 

Technolog

y

Capture 

Technology 

Detail

% 

Capt

ure

Captur

e Rate

Captur

e Unit 

of 

Measu

re

# of 

Cap

ture 

Unit

s

CO2 

Fate

Processing Location/ 

Technology

ZENG 

WorshamSteed

ZENG 

Worsham

-Steed

Capture 

and 

Injection

TX Potential Plant Design 70 Megaw

att -- --

Oxycombusti

on

Oxyfuel

Combustion of 

gaseous 

hydrocarbon 

fuels with 

oxygen,

resulting in 

production of a 

high temperature

and highpressure

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/d

ay

-- EOR --

C6 Resources 

CCS Project TBD

Capture 

and 

Injection

CA Terminate

d

Site Selection -- -- 1/1/2010 $ 

3,000 Industrial -- -- -- -- -- -- -- --

CEMEX Inc. 

Cement CO2 

Capture 

Project

TBD

Capture 

and 

Injection

TX Terminate

d

Site Selection -- -- 1/1/2010 $ 

1,137 Industrial Dry Sorbent -- -- -- -- -- -- --

FutureGen -

Jewett

FutureGe

n - Jewett

Capture 

and 

Injection

TX

Terminate

d

Site 

Characterizati

on

275 Megaw

att 1/1/2015 $ 1,000,000

PreCombustion -- -- -- -- -- -- -- --

FutureGen -

Mattoon

FutureGe

n -

Mattoon

Capture 

and 

Injection

IlL

Terminate

d

Site 

Characterizati

on

275 Megaw

att 1/1/2015 $1,400,00

0 

PreCombustion -- -- -- -- -- -- -- --

FutureGen -

Odessa

FutureGe

n -

Odessa

Capture 

and 

Injection

TX Terminate

d

Site 

Characterizati

on

275 Megaw

att 1/1/2015 $1,000,00

0 

PreCombustion -- -- -- -- -- -- -- --
Draft

Project 

Name

Plant/So

urce

Project 

Type State Operating Status

Operating 

Status Detail

Unit 

Base 

Powe

r

Unit 

Base 

Name

Project 

Start 

Date

Cost (US 

$) 

(x1000)

Capture 

Type

Capture 

Technolog

y

Capture 

Technology 

Detail

% 

Capt

ure

Captur

e Rate

Captur

e Unit 

of 

Measu

re

# of 

Cap

ture 

Unit

s

CO2 

Fate

Processing Location/ 

Technology

FutureGen -

Tuscola

FutureGe

n -

Tuscola

Capture 

and 

Injection

IL Terminate

d

Site 

Characterizati

on

275 Megaw

att 1/1/2015 $1,000,00

0 

PreCombustion -- -- -- -- -- -- -- --

Jamestown 

BPU

Samuel 

J. 

Carlson 

Generatin

g Station

Capture 

and 

Injection

NY Terminate

d

Permitting 

Planning 40 Megawatt 1/1/2013 $145,000 PreCombustion -- -- -- -- -- -- -- --

Leucadia 

Energy 

Capture 

Project -

Mississippi

Moss 

Point 

SNG 

Plant

Capture 

and 

Injection

MS Terminate

d

Permitting 

Planning -- -- 1/1/2010 $1,689,00

0

PreCombustion -- -- -- -- -- --GS/E

OR --

LeucadiaMississippi 

Gasification

NA

Capture 

and 

Injection

MS Terminate

d

-- -- NA -- -- -- -- -- -- -- -- -- EOR --

Lockwood 

Gasification 

Plant

Lockwoo

d 

gasificati

on plant

Capture 

and 

Injection TX

Terminate

d

-- -- -- 1/1/2015 $2,400,00

0 

PreCombustion -- -- -- -- -- --GS/E

OR --

NRG Energy 

Inc - Huntley 

IGCC Project

Huntley 

IGCC

Capture 

and 

Injection

NY Terminate

d

Permitting 

Planning 680 Megawatt 1/1/2013 $1,500,00

0 

PreCombustion Amine

Mitsubishi HI 

Gasification (KS1)-- -- -- -- -- --

Praxair Inc. 

CO2 Capture 

and 

Sequestration 

Project

BP 

Refinery 

and 

Hydrogen 

Productio

n Facility

Capture 

and 

Injection

MS Terminate

d

Plant in 

Operation -- -- 1/1/2010 $1,719 Industrial -- -- -- -- -- -- -- --

Wolverine 

Power Supply 

Cooperative 

Inc. -

Industrial 

Capture 

Project

Wolverin

e Power 

Plant

Capture 

and 

Injection

MI Terminate

d

Plant Design 600 Megaw

att 1/1/2010 $2,723 PostCombustion Amines -- -- -- -- -- -- --

Xcel Energy 

Inc.

Xcel 

Energy 

IGCC 

plant

Capture 

and 

Injection

CO Terminate

d

-- 600 Megaw

att 1/1/2016 $2,000,00

0 

PreCombustion -- -- -- -- -- -- -- --
Draft

Table A-2. Carbon capture and processing project sources. 

Project Name Project Link Capture References Processing References

AES Shady Point http://www.co2captureandstorage.info/pro

ject_specific.php?project_id=22

http://www.netl.doe.gov/technologies/carbon_seq/FA

Qs/carboncapture2.html --

AES Warrior Run

http://www.mgs.md.gov/geo/pub/co2seqp

aper.pdf

http://www.netl.doe.gov/technologies/carbon_seq/FA

Qs/carboncapture2.html

http://216.109.210.162/userdata/Phase%20I%20Repor

t/MRCSP_Phase_I_Final.pdf

--

Bellingham 

Cogeneration 

Facility

http://www.zeroemissionsplatform.eu/proj

ects/globalprojects/details/29.html?mn=154

http://www.tractebelpowerinc.com/utilities

/documents/Bellingham.pdf

http://www.cnie.org/NLE/CRSreports/10Aug/R41325.p

df

http://www.zeroemissionsplatform.eu/projects/globalprojects/details/29.html?mn=154

--

DKRW Energy 

LLC

http://www.dkrwadvancedfuels.com/fw/m

ain/Medicine-Bow-111.html

http://www.dkrwadvancedfuels.com/fw/main/Medicin

e-Bow-111.html

http://www.dkrwadvancedfuels.com/fw

/main/Medicine_Bow_CTL_Process160.html

Evaluation of 

Solid Sorbents as 

a Retrofit 

Technology for 

CO2 Capture

http://www.netl.doe.gov/publications/proc

eedings/11/co2capture/presentations/1-

Monday/22Aug11-Starns-ADAESSolid%20Sorbents%20Retrofit.pdf

http://www.netl.doe.gov/technologies/coal

power/ewr/co2/post-combustion/evalsolid-sorbent.html

http://www.netl.doe.gov/publications/proceedings/11/

co2capture/presentations/1-Monday/22Aug11-StarnsADAES-Solid%20Sorbents%20Retrofit.pdf--

Excelsior Energy http://www.excelsiorenergy.com/mesaba/i

ndex.html

http://www.netl.doe.gov/technologies/coalpower/cctc

/EIS/mesaba_pdf/Mesaba_DEIS_Appx_A.pdf

http://www.netl.doe.gov/technologies/c

oalpower/cctc/EIS/mesaba_pdf/Mesaba

_DEIS_Appx_A.pdf

Great River 

Energy

http://www.greatriverenergy.com/makingel

ectricity/coal/coalcreekstation.html

http://www.greatriverenergy.com/aboutus/pressroom/

archives/doc086606.pdf

http://www.businesswire.com/news/home/200901270

--
Draft

Project Name Project Link Capture References Processing References

http://www.netl.doe.gov/technologies/coal

power/cctc/topicalreports/pdfs/topical25.p

df

06492/en/EPRI-Study-Adding-Carbon-Capture-ExistingCoal

Intermountain 

Power Agency

http://www.ipautah.com/

http://www.ipautah.com/data/upfiles/news

letters/PowerLines%20Dec_10_forWeb.pdf

http://www.businesswire.com/news/home/200901270

06492/en/EPRI-Study-Adding-Carbon-Capture-ExistingCoal--

Oxy-combustion 

Technology 

Development for 

Industrial Scale 

Boiler 

Applications

http://www.netl.doe.gov/technologies/coal

power/ewr/co2/oxycombustion/tangential.html

http://www.netl.doe.gov/publications/facts

heets/project/NT0005290.pdf

http://www.netl.doe.gov/publications/proc

eedings/11/co2capture/presentations/3-

Wednesday/24Aug11-Levassuer-AlstomOxyComb%20IndustScaleBoiler.pdf

http://www.netl.doe.gov/publications/factsheets/proje

ct/NT0005290.pdf --

Slipstream 

Development 

and Testing of 

Siemens 

POSTCAP 

Capture and 

Separation 

Technology

http://www.netl.doe.gov/technologies/coal

power/ewr/co2/post-combustion/siemenspostcap.html

http://www.netl.doe.gov/publications/proceedings/11/

co2capture/presentations/2-Tuesday/23Aug11-

Winkler-SiemensTechnology%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 Coalhttp://www.netl.doe.gov/publications/proc

eedings/11/co2capture/presentations/1-

Monday/22Aug11-Merkel-MTREfficient%20Membrane%20Pilot%20Test.pd

f

http://www.netl.doe.gov/publications/proceedings/11/

co2capture/presentations/1-Monday/22Aug11-MerkelMTR-Efficient%20Membrane%20Pilot%20Test.pdf--
Draft

Project Name Project Link Capture References Processing References

Fired Power 

Plants

Touchstone 

Algae Production

http://www.netl.doe.gov/publications/facts

heets/project/FE0002546.pdf

http://fossil.energy.gov/programs/sequestration/indust

rial/industrial_ccs.html --

Sweeny 

Polygeneration 

with CO2 

Capture

http://coalgasificationnews.com/tag/conoc

ophillips/ -- --

We Energies 

Pleasant Prairie 

Field Pilot

http://www.power.alstom.com/home/abou

t_us/strategy/clean_power_today/carbon_c

apture_storage_ccs/pilots_and_demonstrat

ions/50484.EN.php

http://sequestration.mit.edu/tools/projects/pleasant_p

rairie.html --

American Electric 

Power - Great 

Bend IGCC

http://www.sourcewatch.org/index.php?titl

e=Great_Bend_IGCC

http://www.mydailysentinel.com/pages/full

_story?page_label=home_top_stories_news

&article-AEP-Clean-coal-plant-onhold%20=&id=1913848-AEP-Clean-coalplant-onhold&widget=push&instance=secondary_ne

ws_left_column&open=&

-- --

Taylorville 

Energy Center

http://www.cleancoalillinois.com/tec.html -- --

CCS Project -

Coffeyville

http://www.cvrenergy.com/NitrogenFertiliz

erOperations/index.html http://www.globalccsinstitute.com/projects/12441 --

Edison Mission 

Group

http://www.edison.com/ourcompany/emg.

asp?id=1608

http://www.edison.com/ourcompany/emg.asp?id=160

8

--

American Electric 

Power - Red 

Rock Facility

http://www.aep.com/newsroom/newsrelea

ses/?id=1396 -- --
Draft

Project Name Project Link Capture References Processing References

NRG Energy Inc. 

(Somerset Plant)

http://www.clf.org/newsroom/somersetstation-coal-plant-shuts-down-permanentlyending-pollution-legacy-in-somerset/

-- --

Air Products and 

Chemicals Inc. 

CCS Project

http://www.fossil.energy.gov/recovery/proj

ects/industrial_ccs.html

http://www.netl.doe.gov/publications/factsheets/proje

ct/FE0002381.pdf

http://www.fe.doe.gov/news/techlines/2010/10017-

DOE_Selects_Industrial_CCS_Project.html

http://www.netl.doe.gov/publications/fa

ctsheets/project/FE0002381.pdf

Alcoa Inc. --

http://www.netl.doe.gov/publications/factsheets/proje

ct/FE0002415.pdf --

Duke Energy -

Edwardsport 

Plant

http://www.duke-energy.com/aboutus/edwardsport-overview.asp

http://en3pro.com/wpcontent/uploads/2011/04/CCS-factsheet.pdf

-- --

FutureGen 2.0 -

Meredosia

http://www.futuregenalliance.org/pdf/Futu

reGenFacts.pdf

http://www.futuregenalliance.org/futuregen-2-0-

project/

http://sequestration.mit.edu/tools/projects/futuregen.

html

--

Great Plains 

Synfuels Plant

http://www.zeroco2.no/projects/the-greatplains-synfuels-planthttp://www.netl.doe.gov/technologies/carbon_seq/FA

Qs/carboncapture2.html --

Hydrogen Energy 

California Project

http://sequestration.mit.edu/tools/projects

/heca.html

http://www.netl.doe.gov/publications/facts

heets/project/FE0000663.pdf

http://sequestration.mit.edu/tools/projects/heca.html

http://sequestration.mit.edu/tools/projects/DOE%20pr

ojects/CCPI%20projects/HECA-Tech-Update-2011.pdf

http://sequestration.mit.edu/tools/proje

cts/DOE%20projects/CCPI%20projects/H

ECA-Tech-Update-2011.pdf

Kemper County 

Project

http://www.mississippipower.com/kemper/

home.asp

http://www.secarbon.org/wpcontent/uploads/2012/09_Esposito.pdf

http://sequestration.mit.edu/tools/projects/kemper.ht

ml --
Draft

Project Name Project Link Capture References Processing References

La Veta NG 

Processing

http://www.ghgworks.com/3-what.html

http://www.netl.doe.gov/publications/proceedings/07/

rcsp/factsheets/2-

SWP_Deep%20Saline%20Deployment%20Project.pdf

--

Leucadia Energy 

Capture Project -

Louisiana

http://www.fossil.energy.gov/recovery/proj

ects/industrial_ccs.html

http://www.netl.doe.gov/publications/proceedings/10/

co2capture/presentations/thursday/Doug%20Cathro%2

0-%20FE0002314.pdf

http://www.netl.doe.gov/publications/p

roceedings/10/co2capture/presentation

s/thursday/Doug%20Cathro%20-

%20FE0002314.pdf

MGSC LargeVolume 

Sequestration 

Test: Ethanol 

Plant Source

http://www.netl.doe.gov/publications/facts

heets/project/NT42588.pdf

http://sequestration.org/mgscprojects/dee

psalinestorage.html

http://sequestration.mit.edu/tools/projects

/decatur.html

http://www.netl.doe.gov/publications/facts

heets/project/Project678_4P.pdf

http://www.netl.doe.gov/publications/proc

eedings/07/rcsp/factsheets/4-MGSC_LargeVolume%20Sequestration%20Test%20with

%20Ethanol%20Plant%20So.pdf

http://globalenergyobservatory.org/geoid/40262 http://www.netl.doe.gov/publications/fa

ctsheets/project/NT42588.pdf

MRCSP Michigan 

Basin Geologic 

Test and LargeVolume 

Injection: 

Otsego County, 

MI

http://216.109.210.162/MichiganBasin_vali

dation.aspx

http://www.netl.doe.gov/publications/facts

heets/project/Project686_8P.pdf

http://www.netl.doe.gov/technologies/carbon_seq/FA

Qs/carboncapture2.html

http://www.netl.doe.gov/publications/factsheets/proje

ct/Project686_8P.pdf

http://216.109.210.162/userdata/Fact%

20Sheets/Michigan.pdf

NRG Energy Inc. 

(W.A. Parish 

Plant)

http://www.netl.doe.gov/publications/facts

heets/project/FE0003311.pdf

http://sequestration.mit.edu/tools/projects/wa_parish.

html

http://sequestration.mit.edu/tools/proje

cts/DOE%20projects/CCPI%20projects/

WA-PArish-Tech-Update-2011pdf.pdf
Draft

Project Name Project Link Capture References Processing References

PCOR Bell Creek 

Demonstration 

Project

http://www.netl.doe.gov/publications/facts

heets/project/Project679_4P.pdf

http://www.netl.doe.gov/publications/factsheets/proje

ct/Project679_4P.pdf

http://www.netl.doe.gov/publications/fa

ctsheets/project/Project679_4P.pdf

Pecos County, 

Texas - Gas 

Processing

http://www.sandridgeenergy.com/AboutSa

ndRidge/CenturyPlant/tabid/125/Default.as

px

-- --

Polk Station 

Carbon Dioxide 

Capture and 

Storage Project

http://www.tampaelectric.com/news/articl

e/index.cfm?article=541

http://www.netl.doe.gov/publications/proc

eedings/02/Hybrid/Hybrid2Hornick.PDF

http://www.netl.doe.gov/technologies/coalpower/gasif

ication/projects/gas-clean/00489/19HORNICK.pdf

http://sequestration.mit.edu/tools/projects/polk.html

http://www.netl.doe.gov/technologies/c

oalpower/gasification/projects/gasclean/00489/19HORNICK.pdf

Purdy, Sho-VelTum EOR Project

http://globalenergyobservatory.org/geoid/4

0281

http://www.netl.doe.gov/KMD/cds/disk22/

FARI%20Basin%20Oriented%20Strategies%2

0for%20CO2/oklahoma_report.pdf

http://www.globalccsinstitute.com/projects/12561

http://www.zeroco2.no/projects/enid-fertiliser-plant

http://www.sourcewatch.org/index.php?title=Enid_Fer

tilizer

--

Searles Valley 

Minerals

http://mydocs.epri.com/docs/public/00000

0000001014698.pdf

http://www.netl.doe.gov/technologies/carbon_seq/FA

Qs/carboncapture2.html

http://my.epri.com/portal/server.pt?space=Community

Page&cached=true&parentname=ObjMgr&parentid=2

&control=SetCommunity&CommunityID=405

--

SECARB 

Anthropogenic 

Test and Stage 1

http://www.netl.doe.gov/publications/facts

heets/project/NT42590.pdf

http://www.alabamapower.com/about/pla

nts.asp

http://www.netl.doe.gov/publications/facts

heets/project/Project680_4P.pdf

http://www.netl.doe.gov/publications/factsheets/proje

ct/NT42590.pdf

http://www.secarbon.org/files/anthropogenic-test.pdf

http://sequestration.mit.edu/tools/projects/plant_barr

y.html

http://www.netl.doe.gov/publications/fa

ctsheets/project/NT42590.pdf

http://www.southerncompany.com/plan

etpower/demonstration_carboncapture.

aspx

http://www.netl.doe.gov/publications/p

roceedings/11/carbon_storage/tuesday/
Draft

Project Name Project Link Capture References Processing References

SECARB_Hill_RCSPInfrastructureMtg_PIT%20%287%29%20

11-15-11.pdf

Shell Chemical 

CCS Project

-- -- --

Shute Creek 

Plant

http://www.wyomingcarbonstorage.com/cc

srm/eor-projects-wyoming/shutecreek

http://www.netl.doe.gov/technologies/carbon_seq/FA

Qs/carboncapture2.html

http://www.nist.gov/pml/high_megawatt/upload/2_3-

Kubek-Approved.pdf

http://www.seminole-electric.com/about_us.php

http://www.ogj.com/articles/2010/12/exxonmobilfinishes.html

http://www.exxonmobil.com/Corporate/Files/news_pu

b_Carbon_Capture_Storage_brochure.pdf

http://www.nist.gov/pml/high_megawat

t/upload/2_3-Kubek-Approved.pdf

Summit Energy -

Texas Clean 

Energy Project 

(TCEP)

http://www.netl.doe.gov/publications/facts

heets/project/FE0002650.pdf

http://sequestration.mit.edu/tools/projects/DOE%20pr

ojects/CCPI%20projects/TCEP-Tech-Update-2011.pdf

http://www.netl.doe.gov/publications/factsheets/proje

ct/FE0002650.pdf

http://www.netl.doe.gov/publications/fa

ctsheets/project/FE0002650.pdf

http://www.texascleanenergyproject.co

m/project/

The Erora Group 

- Cash Creek 

IGCC

http://www.erora.com/

http://www.globalccsinstitute.com/projects

/12626

http://www.sourcewatch.org/index.php?titl

e=Cash_Creek_Generation

http://www.globalccsinstitute.com/projects/12626 --

Trailblazer 

Energy Center

http://www.tenaskatrailblazer.com/

http://cdn.globalccsinstitute.com/sites/default/files/pu

blications/32321/traiblazer-front-end-engineering-anddesign-study-report-final.pdf

http://cdn.globalccsinstitute.com/sites/d

efault/files/publications/32321/traiblaze

r-front-end-engineering-and-design-
Draft

Project Name Project Link Capture References Processing References

study-report-final.pdf

Val Verde NG 

Plants

http://www.thefreelibrary.com/Val+Verde+

CO2+Pipeline+Completes+Construction+and

+Begins+Operations-a053019153

http://www.ghgworks.com/4cvalverde.html

http://www.netl.doe.gov/technologies/carbon_seq/FA

Qs/carboncapture2.html --

Antelope Valley 

Carbon Dioxide 

Capture and 

Storage Project

http://sequestration.mit.edu/tools/projects

/antelope_valley.html -- --

American Electric 

Power -

Mountaineer

http://www.aep.com/environmental/climat

echange/carboncapture/

http://sequestration.mit.edu/tools/projects/aep_alsto

m_mountaineer.html

http://www.aep.com/environmental/cli

matechange/carboncapture/

Carbon Dioxide 

Technology Corp 

- Lubboch Plant

--

http://services.bepress.com/cgi/viewcontent.cgi?article

=1006&context=eci/separations_technology_vi --

ECO2 Burger

http://216.109.210.162/AppalachianBasin.a

spx

http://www.carboncapturejournal.com/disp

laynews.php?NewsID=735

http://sequestration.mit.edu/tools/projects/berger.ht

ml

http://powerspan.com/technology/eco2-co2-capture/

http://powerspan.com/wpcontent/themes/simplo/siteimages/Powerspan_Integrated_ECO-SO2-

ECO2_Process_Flow.pdf

--

Mitchell Energy 

Bridgeport Plant

http://www.worleyparsons.com/CSG/Hydro

carbons/SpecialtyCapabilities/Documents/C

arbon%20Capture%20Overview.pdf

http://sequestration.mit.edu/pdf/introduction_to_capt

ure.pdf

http://www.worleyparsons.com/CSG/Hydrocarbons/Sp

ecialtyCapabilities/Documents/Carbon%20Capture%20

Overview%20%283%29.pdf

--
Draft

Project Name Project Link Capture References Processing References

American Electric 

Power -

Northeastern 

Station

http://www.prnewswire.com/newsreleases/aep-to-install-carbon-capture-ontwo-existing-power-plants-company-will-befirst-to-move-technology-to-commercialscale-52165432.html

http://www.carboncapturejournal.com/displaynews.ph

p?NewsID=91

http://www.zeroco2.no/projects/aep-northeastern

--

Wallula Energy 

Resource Center 

(WERC)

http://www.wallulaenergy.com/index.tpl?d

sp=what -- --

WESTCARB 

Kimberlina Test 

Facility

http://www.netl.doe.gov/publications/proc

eedings/08/rcsp/factsheets/22-

WESTCARB_Large%20Volume%20Sequestra

tion%20Test_PhIII.pdf

--

http://www.netl.doe.gov/publications/p

roceedings/08/rcsp/factsheets/22-

WESTCARB_Large%20Volume%20Seques

tration%20Test_PhIII.pdf

Coal Plant 

Outside NY City

http://www.nytimes.com/2009/04/18/busi

ness/energyenvironment/18clean.html?_r=2-- --

Great Lakes 

Energy Research 

Park

http://www.mandmenergy.com/index2.html

http://www.mandmenergy.com/documents

/morningsun_energypark_122007.pdf

http://www.mandmenergy.com/documents/GVSU_GLE

RP_final_042408.pdf --

Kentucky 

NewGas

-- http://www.globalccsinstitute.com/projects/22957 --

Leucadia -

Indiana

http://www.cbsnews.com/8301-

505244_162-57430964/idem-filesproposed-permit-for-gasification-plant/

http://www.energy.utah.gov/media/energysummit/doc

s/2012/Mar/Ben.pdf --

Lima Polygen -- -- --

Project Viking

http://www.co2.no/default.asp?uid=157&CI

D=157

http://www.sourcewatch.org/index.php?titl

e=Project_Viking

http://www.co2.no/default.asp?uid=157&CID=157 --
Draft

Project Name Project Link Capture References Processing References

Waste 

Management & 

Processors PTY., 

LLC

http://www.hydrocarbonstechnology.com/projects/co_production/

http://www.netl.doe.gov/technologies/coal

power/turbines/refshelf/reports/41776%20

GE%20SemiAnnual_Fuel%20Flexible%20Combustion.PD

F

-- --

ZENG WorshamSteed

http://www.cleanenergysystems.com/

http://www.co2.no/download.asp?DAFID=3

4&DAAID=3

http://sequestration.mit.edu/tools/projects

/worsham_steed.html

http://sequestration.mit.edu/tools/projects/worsham_

steed.html

http://www.co2.no/download.asp?DAFID=34&DAAID=3

--

C6 Resources 

CCS Project

http://www.fossil.energy.gov/recovery/proj

ects/industrial_ccs.html -- --

CEMEX Inc. 

Cement CO2 

Capture Project

http://www.fossil.energy.gov/recovery/proj

ects/industrial_ccs.html -- --

FutureGen -

Jewett

http://www.futuregenalliance.org/ -- --

FutureGen -

Mattoon

http://www.futuregenalliance.org/ -- --

FutureGen -

Odessa http://www.futuregenalliance.org/ -- --

FutureGen -

Tuscola http://www.futuregenalliance.org/ -- --

Jamestown BPU

http://www.sourcewatch.org/index.php?titl

e=Clean_Coal_Plant_Project_(Jamestown%2

C_New_York)

-- --

Leucadia Energy 

Capture Project -

Mississippi

http://www.fossil.energy.gov/recovery/proj

ects/industrial_ccs.html -- --
Draft

Project Name Project Link Capture References Processing References

LeucadiaMississippi 

Gasification

--

http://blog.al.com/live/2009/11/public_meeting_set_o

n_proposed.html

http://www.energy.utah.gov/media/energysummit/doc

s/2012/Mar/Ben.pdf

http://blog.gulflive.com/mississippi-pressnews/2011/11/gasification_project_leaders_r.html

--

Lockwood 

Gasification 

Plant

-- -- --

NRG Energy Inc -

Huntley IGCC 

Project

http://www.snl.com/irweblinkx/file.aspx?II

D=4057436&FID=3211361

-- --

Praxair Inc. CO2 

Capture and 

Sequestration 

Project

http://www.fossil.energy.gov/recovery/proj

ects/industrial_ccs.html -- --

Wolverine Power 

Supply 

Cooperative Inc. 

- Industrial 

Capture Project

http://www.fossil.energy.gov/recovery/proj

ects/industrial_ccs.html -- --

Xcel Energy Inc.

http://www.redorbit.com/news/business/1

128394/xcel_cancels_bent_county_power_

plant/

http://www.sourcewatch.org/index.php?titl

e=Unnamed_Xcel_Energy_Plant

-- --