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# A Review of CO **2** 

# 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 S ubcontract to Eastern Research Group, Inc**  **. Draft**  

## A Review of CO **2** 

## Capture and Processing

**Abstract** A cursory review of capture and processing technologies for CO 2 

### is conducted to identify those techniques and designs that are currently being used and activities take place between capture and transport of CO 2

### , referred to as “processing” in this paper. Th is 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 reporte d in the literature. 

## Introduction Carbon capture and storage (CCS) is a step -wise process including the capture of carbon dioxide (CO 2 

### ) from industrial and power generating sources; transport of the captured CO 2 

### to injection facilities; and injection of the captured CO 2 

### into suitable geologic reservoirs for long-term storage. 1 

### A typical CCS chain includes four steps: (1) Power plant with CO 2 

### capture; (2) Processing of CO 2

### , 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, pres sure, CO 2 

### 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 CO 2 

### 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 CO 2 

### stream is not expected to change during transport unless there is significant leakage, which necessitates that the CO 2 

### quality specifications for injection and t ransport be met by the CO 2 

### 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 Compre ssion

Pipeline Transport Injection/Final Storage Capture**Draft**



### This paper provide s an overview of CO 2 

### capture and processing prior to pipeline transport, including descriptions of associated technologies and methodologies for capturing, conditioning, and compressing CO 2

### , which are shown as red boxes in Figure 1. Some background information is given in the following section on the physical and chemical CO 2 

### transport and storage specifications that control the selection of capture and processing technologies. This review also include s a summary inventory of the current capture and processing facilities in th e United States (US) presented in Appendix A. 

## Background **Information CO** **2** 

## Transpor**t and**  **Storage Requirements**  The discussion of physical and chemical specifications for transport and storage of CO 2 

### 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 com pressed CO 2 

### 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 domi nant factor. On average, a single 500 - MW coal -fired power plant would need to transport 2 - 3 million metric tonnes ( Mt ) of compressed CO 2 

### in a year (Wilcox, 2012) . Therefore, the pipeline transport may be considered as the only viable option for overland tr ansport 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 CO 2 

### 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 follo wing capture and separation (Wilcox, 2012). In order to efficiently transport large amounts, CO 2 

### must be transformed into a high density form, such as liquid, solid, or in supercritical phase. For pipeline transport, CO 2 

### must be compressed and cooled to t he liquid and/or supercritical state (Wilcox, 2012). By operating the pipelines at the supercritical pressure of CO 2 

### (above 7.38 MPa), the formation of CO 2 

### gas with subsequent complexities of multiphase flow, and frictional and static pressure drops are av oided. NETL (2011) notes that the captured CO 2 

### 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 CO 2 

### are also defined approximately as 8 - 15 MPa (about 80 - 150 bar) by Wilcox (2012).**Draft**

**Figure 2**  **. Phase diagram of CO 2**  **indic ating pressure and temperature ranges for pipeline transport (Wilcox, 2012).**  

### Figure 3 presents the CO 2 

### density as a function of pressure. The CO 2 

### densi ty ranges between 800 and 1000 kg/m 3 

### under typical pipeline transport pressures. The operating temperatures are assumed to be equivalent to the surrounding soil temperatures, which can vary seasonally from several degrees below zero to 6 - 8 °C; in some tropical regions this may be as high as 20 °C (Wilcox, 2012).

**Figure 3**  **. CO 2**  **density as a function of pressure (Aspelund et al., 2006). Draft** 



### Chemical Requirements Processing specifications for CO 2 

### 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., H 2

### S) and volatiles (e.g., N 2 

### ) (Maroto -Valer, 2010). More informati on 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 CO 2 

### pipeline transport and several different injection cases. **Table 1**  **. Quality recommendations for CO 2**  **transported by pipeline (Maroto -** **Valer, 2010). Component**  **Concentration Limitation**  **Reason** H 2 O 500 ppm Design and operational Corrosion, hydrate formation H 2 S 200 ppm Health and safety considerations Short -term exposure limits CO 2000ppm Health and safety considerations Short -term exposure limits CH 4 Aquifer <4 vol.%, EOR <2

vol.% As proposed in ENCAP project* Costs/Energy
N 2 <4 vol.% (all non condensable gases) As proposed in ENCAP project* Costs
O 2 N/A Inconsistent literature Challenges in the reservoir Ar <4 vol.% (all non condensable gases) As proposed in ENCAP project* Costs
H 2 <4 vol.% (all non condensable gases) Reduction is recommended due to its energy content Costs/Energy
CO 2 >95.5% Balanced with other compounds Economy 

### * European Enhanced Capture of CO 2 

### Project (ENCAP) ( http://www.encapco2.org/ ).**Draft**

**Table 2**  **. Recommended CO 2**  **stream composition limits for three design cases (DOE, 2012). C** **o m** **p o** **n e** **n t**  **Unit (Max unless**  **Otherwise noted)**  **Carbon Steel**

**Pipeline Enhanced Oil** 

**Recovery Saline Reservoir** 

**Sequestration Saline** 

**Reservoir CO2 & H2S Co**  **** **sequestration Venting** 

**Concerns C** **o n** **c e** **p t** **u a** **l D** **e s** **i g** **n Range in**  **Literature C** **o n** **c e** **p t** **u a** **l D** **e s** **i g** **n Range in** 

**Literature C** **o n** **c e** **p t** **u a** **l D** **e s** **i g** **n Range**  **in**

**Literature C** **o n** **c e** **p t** **u a** **l D** **e s** **i g** **n Range in** 

**Literature** CO 2 vol% (Min) 95 90 - 99.8 95 90 - 99.8 95 90 - 99.8 95 20 – 99.8 Yes - IDLH 40,000 ppmv H 2 O ppmwt 300 20 - 650 300 20 - 650 300 20 - 650 300 20 - 650 N 2 vol% 4 0.01 - 7 1 0.01 - 2 4 0.01 - 7 4 0.01 – 7 O 2 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 CH 4 vol% 4 0.01 – 4 1 0.01 – 2 4 0.01 – 4 4 0.01 – 4 Yes -Asphyxiate, Explosive H 2 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 H 2 S 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 SO 2 ppmv 100 10 - 50000 100 10 - 50000 100 10 - 50000 100 10 - 50000 Yes - IDLH 100 ppmv NO X ppmv 100 20 - 2500 100 20 - 2500 100 20 - 2500 100 20 - 2500 Yes - IDLH NO - 100 ppmv, NO2 - 200 ppmv NH 3 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)
C 2 H 6 vol% 1 0 - 1 1 0 - 1 1 0 - 1 1 0 - 1 Yes -Asphyxiate, Explosive C 3 + vol% <1 0 - 1 <1 0 - 1 <1 0 - 1 <1 0 - 1 Part. ppmv 1 0 - 1 1 0 - 1 1 0 - 1 1 0 - 1 HCl ppmv N/A N/A N/A N/A N/A N/A N/A N/A Yes - IDLH 50 ppmv HF ppmv N/A N/A N/A N/A N/A N/A N/A N/A Yes - IDLH 30 ppmv HCN ppmv trace trace trace trace trace trace trace trace Yes - IDLH 50 ppmv Hg ppmv N/A N/A N/A N/A N/A N/A N/A N/A Yes - IDLH 2 mg/m 3 (organo) Glycol ppmv 46 0 - 174 46 0 - 174 46 0 - 174 46 0 - 174**Draft C** **o m** **p o** **n e** **n t**  **Unit (Max unless**  **Otherwise noted)**  **Carbon Steel**

**Pipeline Enhanced Oil** 

**Recovery Saline Reservoir** 

**Sequestration Saline** 

**Reservoir CO2 & H2S Co**  **** **sequestration Venting** 

**Concerns C** **o n** **c e** **p t** **u a** **l D** **e s** **i g** **n Range in**  **Literature C** **o n** **c e** **p t** **u a** **l D** **e s** **i g** **n Range in** 

**Literature C** **o n** **c e** **p t** **u a** **l D** **e s** **i g** **n Range**  **in**

**Literature C** **o n** **c e** **p t** **u a** **l D** **e s** **i g** **n 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 CO 2 

### 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 H 2

### S 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 H 2

### S 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 CO 2 

### . Similarly, oxygen in the CO 2 

### 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 a chieved 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 techn ologies used for CO 2 

### 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, CO 2 

### capture and pro cessing 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 web site, the Global CCS Institute , the Zero Emissions Resource Orga nization, and the European Technology Platform for Zero Emission Fossil Fuel Power Plant s . Each project was individually researched to understand the status of the operation (i.e., active, potential, terminated, etc.), and the types of technologies used fo r carbon capture and processing. Table A- 1 in the Appendix contains the following information (where data is available): the name of the project; the CO 2 

### 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; % CO 2 

### c apture; capture rate; the number of capture units; the fate of the CO 2

### ; and processing technologies use d. 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 CO 2 

### 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 CO 2 

### capture is part of the process, whereas the Assessment report focuses on projects involving CO 2 

### injection. Thus, while there is some overlap between the tables (e.g., p rojects 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 CO 2 

### 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 & **F indings**  Capture and processing technologies are discussed in the following two sections. Additionally, a discussion of cost s associated with capture and processing technologies is also included in a separate subsection here. 

## Capture CO 2 

### 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. CO 2 

### capture may take place in the following power plant scenarios : post -**Draft**



### combu stion 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, CO 2 

### is removed from the gas stream prior to discharge to the atmosphere. For a conventional coal - or gas -fired power plant, the CO 2 

### capture process would be located downstream of pollutant controls such as flue gas desulfurization and particulate removal (DO E/NETL, 2011). The CO 2 

### 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 CO 2 

### stripping involve chemic al 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 w ould 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 H 2 

### and CO. A water-gas shift reaction converts the CO to CO 2

### , and the resu lting high pressure stream is rich in CO 2 

### and H 2 

### (Gupta et al., 2003). Because the volume percentage of CO 2 

### in the stream is high, (25 -40%), it is easier to capture the CO 2 

### . Physical solvents such as Selexol and Rectisol are the most readily available opt ions for CO 2 

### 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 CO 2 

### and water, which can be removed by conde nsation. This produces a clean CO 2 

### 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 CO**  **2 Capture (Figueroa et al. 2008).**  **Capture Process Advantages**  **Barriers to implementation** 

**Post -** **combustion** • Applicable to the majority of existing coal -fired power plants  Retrofit technology option Flue gas is ...
• Dilute in CO2 • At ambient pressure ... resulting in ...
• Low CO2 partial pressure • Significantly higher performance or circulation volume required for high capture levels • CO2 produced at low pressure compared to sequestration requirements

**Pre -** **combustion** Synthesis gas is ...
• Concentrated in CO2 • High pressure ... resulting in ...
• High CO2 partial pressure • Increased driving force for separation • More technologies available for separation • Potential for reduction in compression costs/loads • Applicable mainly to new plants, as few gasification plants are currently in operation • Barriers to commercial application of gasification are common to pre combustion capture o Availability o Cost of equipment o Extensive supporting systems requirements

**Oxy -** **combustion** • Very high CO2 concentration in flue gas • Retrofit and repowering technology option • Large cryogenic O2 production requirement may be cost prohibitive • Cooled CO2 recycle required to maintain temperatures within limits of combustor materials o Decreased process efficiency o Added auxiliary load 

### The CO 2 

### capture technologies available and under research can be grouped into four categories (e.g., Gupta et al ., 2003):

 Absorption with physical and chemical solvents (suitable for post -combustion and pre combustion capture)  Adsorption ( potential application to post -combustion and pre - combustion)  Membranes (potential application to pre - combustion and post - combustion)  Cryogenics ( applicable for air separation in oxycombustion, possible applicability to pre combustion )**Draft**



### The subsection s below cover some of the established CO 2 

### 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 c overage of emerging technologies that are sponsored by DOE. 

### Absorption CO 2 

### 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 CO 2 

### and the solvent or physical dissolution alone. During absorption, the CO 2 

### 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 CO 2 

### then binds to the active ingredient in the solvent soluti on. Desorption reverses the process and releases the CO 2 

### back into the gas phase for capture (Wilcox, 2012). 

### Chemical	Absorption Amines are the most common class of chemical solvents for CO 2 

### capture. They have been used for at least 60 years to scrub C O 2 

### from natural gas and hydrogen (Rochelle, 2009). The technology is widely used and well understood. Primary, secondary, and tertiary amines react with CO 2 

### to form water soluble compounds. Amines can capture CO 2 

### from streams with low partial pressure of CO 2 

### . The CO 2 

### is absorbed near ambient temperature into an aqueous solution. Solvent loading for amines is higher at low partial pressures of CO 2 

### 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 CO 2 

### . A CO 2 

### 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 t he desorption column by stripping with water vapor at a temperature of 100 to 20 °C. The water is removed by condensation, resulting in a CO 2 

### gas stream (Rochelle, 2009) in which 75 -90% of the CO 2 

### has been captured (Rubin and Rao, 2002). The rate of mas s transfer depends upon a number of gas and solvent properties as well as physical design considerations. Design should take into account the solubility of CO 2 

### in the solvent and the chemical reactivity between CO 2 

### and the solvent. Some of the physical pa rameters 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 - base d chemical solvent system is the large amount of heat needed to thermally strip the CO 2 

### 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 add s to overall cost (Rubin and Rao, 2002). Furthermore, the CO 2 

### 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 CO 2 

### capture unit into the overall plant system, including the steam cycle (Eswaran et al., 2010).

**Figure 5**  **. Schematic for an absorption based CO 2**  **capture system (Wilcox, 2012).** 

### Monoethanolamine	(MEA) The most commonly used amine solvent is monoethanolamine (MEA) (C2H7NO); it has been adapted to capture CO 2 

### 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 S O 2 

### and NO x 

### 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%, necessitati ng 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 CO 2 

### from low - pressure, oxygen bearing flue gases and is being adapted for coal -fired power plants. Part of Fluor’s process involves upstream removal of impurities (NO x

### , SO 2

### , 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 ne w 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 CO 2 

### capture include 2 - amino 2 - methyl 1 - propanol (AMP), 1,8 - pmethaned iamine (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 CO 2 

### and regenerates at a lower temperature (Endo et al., 2010; Gupta et al., 2003). As of 2009, four units fo r gas -fired plants had been built with using KM - CDR, and tests had been conducted on coal -fired flue gas. Cansolv’s CO 2 

### capture process uses a proprietary solvent named Absorbent DC101 TM 

### that uses tertiary amines. It has oxidation inhibitors and is claim ed to be able to remove SO x

### , NO x

### , 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 CO 2 

### to form amm onium bicarbonate. It can achieve 99% CO 2 

### removal (as compared to about 94% for MEA), with a CO 2 

### loading capacity of 1.2 kg CO 2

### /kg NH 3 

### (compared to 0.4 kg CO 2

### /kg MEA) (Gupta et al., 2003). It is not degraded by impurities and is inexpensive. It also offers the potential for regeneration of the CO 2 

### 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 te mperature during regen eration. 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 -**  **base d**  **CO 2**  **capture processes (**  **modified from Gupta et al., 2003).**  **Absorption process Solvent**  **Process Conditions Developer/licensor**  **Physical Solvent** Rectisol Methanol - 10/
- 70°C, >2 MPa Lurgi and Linde, Germany; Selexol dimethylethers of

polyethylene glycol (DMPEG) -40°C, 2 - 3 MPa Union Carbide, USA Fluor Solvent Propylene carbonate Below ambient temperatures, 3.1 - 6.9 MPa Fluor Corporation , USA **Chemical Solvent Organic (Amine Based)**  MEA 2.5 n monoethanolamine and

chemical inhibitors ~40°C, ambient intermediate pressures Dow Chemical, USA Amine Guard (MEA) 5 n monoethanolamine and

chemical inhibitors ~40°C, ambient intermediate pressures Union Carbide, USA**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, KS 2, KS - 3 Hindered amine Exxon, USA; M.H.I. **Inorganic** Benfield and versions Hot p otassium 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 CO 2 

### dissolves in an amino acid salt solution, carbonate compounds precipitate (Feron, undated). Because of the formation of the precipitate, the partial pressure of CO 2 

### over the solution remains lower than i t would if no precipitate formed; which results in high CO 2 

### loading capacity. As with other chemical solvents, heat is required for regeneration. This process requires less energy for regenerat ion than an MEA- based process. Feron (undated) estimates that the cost of CO 2 

### avoided might be approximately half the cost of an MEA process. Carbonate	Slurry Soluble carbonate forms a bicarbonate when it reacts with CO 2

### ; heating reverses the reaction and releases CO 2 

### . 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 K 2 

### CO 3 

### or Na 2 

### CO 3 

### (o r a mixture) as the solvent. Other manufacturers/developers are listed in Table 4. As with chilled ammonia, the reaction of CO 2 

### with the solvent produces a precipitate and forms a slurry. It offers the promise of a high CO 2 

### 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**



### Physi**cal	Absorption** CO 2 

### 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 CO 2 

### ( 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 CO 2 

### . The solvent is regenerated and the CO 2 

### 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 CO 2 

### at higher pressure, improved selectivity, solvents with high CO 2 

### loading at higher temperature (DOE/NETL, 2011) and l ow 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 CO 2 

### 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, incl uding air separation, recovery of H 2 

### from ammonia, and separation of CO 2 

### from natural gas ( Table 5 ) . Constituents in a gas are separated based on their rates of diffu sion through the membrane (DOE/NETL, 2011), and membranes are more effective at high pressure. For a pre -combustion scenario, there are CO 2

### - selective membranes that can provide a high recovery and a high - purity CO 2 

### stream. According to**Draft**



### DOE/NETL (2011), however, membranes have not yet been employed commercially for CO 2 

### 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- combu stion 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 g as passes through a bundle of membrane tubes while an amine solution flows through the other side. The CO 2 

### 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 CO 2 

### from flue gas. Other avenues of research include zeolite membranes (New Mexico Institute of Mining and Technology), and an organizatio n 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 Developm** **ent**



### Technology Type **Capture Type Developer**  **Availability** Zeolite Membrane Post Combustion New Mexico Institute

of Mining and Technology Under

Development Polaris Membrane Post Combustion Membrane Technology

and Research Commercially

Available Pebax thin -film membranes Post Combustion Membrane Technology

and Research Pilot Testing Polybenzimidazole (PBI) membrane Pre - Combustion DOE's Los Alamos National Laboratory (LANL) Under

Development


### Adsorbents Sorbents are solids that react with CO 2 

### to form compounds and are then regenerated to release the CO 2 

### . Sorbents present a possible option to reduce the energy penalty associated with CO 2 

### capture (DOE, 2010). The effectiveness of an adsorbent system will depend upon the affinity of the solid ma terial for CO 2 

### and the heat required for regeneration. Adsorption for CO 2 

### 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 c ompounds, which may be a more efficient process than traditional amine scrubbing (Figueroa et al., 2008). Work at RTI has focused on dry, regenerable Na 2 

### CO 3

### , 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 CO 2 

### capture methods.**Draft**



### Figure 7 presents a schematic of a reactor based o n 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**  **. CO**  **2 capture unit with metal**  **monolithic amine -** **grafted zeolites. Available on the Internet at:**  **http://www.netl.doe.gov/technologies/coalpower/ewr/co2/post -**  **com bustion/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 CO 2 

### 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 propo sed 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 C O 2 

### from a gas stream for the high - oxygen combustion stage ( Figure 8 ). The combustion products are CO 2 

### and H 2 

### O, and the H 2 

### O can be separated from the CO 2 

### 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 a ll activities between capture and transport of CO 2

### , referred to as “processi ng” in this paper, including the conversion to supercritical stat e, is included in this section . I t 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 CO 2 

### s eparation . While the literature on carbon capture and sequestration has been continuously growing, general literature of CO 2 

### 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 th e 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 CO 2 

### from the power plant or industrial source is normally saturated with water and will contain some nitrogen. Therefore, cooling the CO 2 

### to ambient conditions and removing water in gravity- based separators would be the first step of processing ( Figure 9 ). The CO 2 

### 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 CO 2 

### 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 CO 2 

### 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 CO 2 

### is then pumped to injection pressure and sent to the pi peline. 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 CO 2 

### from the end of the capture process until the point of p ipeline 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 treatm ent 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 CO 2**  **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 H 2 

### O/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 pressu re requires a smaller and less expensive system, since upstream compression and intercooling remove some of the water from the CO 2 

### 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 dehydra tion system at the upstream portion of the compression system would require the use of expensive duplex stainless steel because a wet CO 2 

### stream causes carbonic acid corrosion in less - expensive carbon steel. Downstream of dehydration, carbon steel can be u sed 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 (Ma roto -Valer, 2010). During the removal of liquids, some CO 2 

### that is dissolved in water will also be removed. For power cycles that contain large amounts of water in contact with the CO 2

### , 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 H 2

### S can also be removed from the CO 2 

### 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 invol ves 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 CO 2 

### 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 CO 2

### , centrifugal compressors are generally used, particularly when CO 2 

### is produced near atmospheric pressure. Some of the unique characteristics of CO 2 

### 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 CO 2 

### to be liquefied at relatively high**Draft**



### temperatures allowing hybrid compressio n and pumping options (NETL, 2011). Figure 11 below shows two types of compressor that are typically used for CO 2 

### compression.

**(a) (b)**  **Figure 11**  **. Typical compressors used for CO**  **2 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 isot hermal 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, be am 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 -thro ugh 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 applica tions) 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 CO 2 

### 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 l iquefaction 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 com** **pression technology options (NETL, 2011). Compression Technology**  **Power Requirements** conventional Dresser- rand centrifugal 16 - stage compressor (2 bodies) 

### 23,251 BHP (17.35 MW) conventional Dresser- rand centrifugal 16 - stage compressor (2 bodies) and with additional cooling 

### 21,522 BHP (16.06 MW) isothermal compression at 70 °f and 80% efficiency 

### 14,840 BHP (11.07 MW) Semi - isothermal compression at 70 °f and 1.55 pressure ratio 

### 17,025 BHP (12.70 MW) Semi - isothermal compression at 100 °f and 1.55 pressure ratio 

### 17,979 BHP (13.41 MW) high pressure ratio compression at 90% efficiency and no inter- stage cooling 

### 34,192 BHP (25.51 MW) high pressure ratio compression at 90% efficiency with 1st and 2nd stage cooling 

### 24,730 BHP (18.45 MW) centrifugal compression to 250 psia and liquid cryo pump from 250 to 2,215 psia 

### 16,198 BHP (12.08 MW) (Includes 7,814 BHP for refrigeration) centrifugal compression to 250 psia with semi isothermal cooling at 100 °f and liquid cryo - pump from 250 to 2,215 psia 

### 15,145 BHP (11.30 MW) (Includes 7,814 BH P 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 CO 2 

### 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 CO 2 

### 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 pip eline condition of 160 bar (Wu et al., 2011). 

### Removal of Impurities To achieve the desired quality of the CO 2 

### 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 CO 2 

### 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 CO 2**Draft**



### by flashing or simple distillation are propane, ethane, H 2

### S, and SO 2 

### (Aspelund and Jordal, 2007). Small quantities of propane and ethane are not expected t o cause any operational problems. However, H 2

### S levels, expected to be in an IGCC setting, might be a safety hazard and removal of H 2

### S generally consists of absorption by a regenerable solvent (NETL, 2010). The most commonly used technique is based on count ercurrent contact with the solvent. Acid -gas - rich solution from the absorber is stripped of its acid gas in a regenerator, usually by application of heat. The regenerated lean solution is then cooled and recirculated to the top of the absorber. Figure 12 below presents a flow diagram for a conventional acid gas - removal (AGR) unit that might be used for H 2

### S removal.

**Figure 12**  **. Flow diagram**  **for a conventional AGR unit (NETL, 2010) .**  

### Some of the AGR processes used for H 2

### S removal are: Rectisol, Sulfinol, MDEA, Selexol, aqueous di isoproponal (ADIP) amine, and FLEXSORB (NETL, 2010). It might be more cost - efficient to remove H 2

### S in the capture p rocess (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 CO 2 

### separation is given in Capture section of this review paper. **The AGR pro cesses can be categorized as: chem** **ical solvents; physical solvents; and hybrid solvents. Chemical solvents are usually m** **ore suitable than physical or hybrid solvents for applications at lower operating pressures. Chemical reagents are used to rem** **ove the ac id gases by a reversible chemical reaction of**  **the acid gases with an aqueous solution of various alkonolam ines 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 H 2

### S in the presence of CO 2

### , resistance to degradation by organic sulfur compounds, tendency for corrosion, and its low circulation rate and effici ency (NETL, 2010) .**Draft**

**Table 7**  **. Comm on 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 H 2

### S or total AGR (for capture, the CO 2 

### is fla shed off at various pressures) (NETL, 2010). Several physical solvents that use anhydrous o rganic solvents have been commercialized ( Table ). **Table 8**  **. Comm on physical solvents used in AGR processes (NETL, 2010).** 

**Solvent Solvent/Process**  **Trade Name Process L** **icensors** 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 re agent to remove the acid to low levels when high purity is desired. **Table 9**  **. Comm on 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 N 2 

### 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 CO 2 

### is used for EOR, the specifications might b e more stringent to prevent any increase in the miscible pressure in the reservoir which in turn can decrease the efficiency of CO 2 

### . Additionally, C O 2 

### 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 CO 2 

### i s 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 CO 2 

### should be condensed at 50 - 65 bar (Maroto -Valer, 2010). 

## Cost of C **apture & Processing** IEA (2011) conducted an analysis of techno - economic data available from feasibility studies and pilot projects (i.e., about 50 studies of CO 2 

### capture installations at power plants) for CO 2 

### capture from power generation and CO 2 

### condition ing 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 Em issions Coal Initiative – NZEC  CO 2 

### 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 CO 2 

### capture & processing technology outperforms available alternatives for coal -fired power generation. Overnight costs of pow er plants with CO 2 

### 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**



### F or natural gas -fired power generation, their results showed that post -combustion CO 2 

### capture is the most analyzed and attractive near-term option. Overnight costs for this option found to be $1,700 per kW including capture & processing, or 82% higher than the costs without capture. Average cost figures from IEA (2011) analysis for different capture applications are presented in Table 10 10 below. The data used for genera ting these average figures included the information for capture, conditioning, and compression, but not transport and storage. **Table 10**  **. Average cost data by CO 2**  **capture option, including processing (IEA, 2011).**

**Fuel Type Coal**  **Natural Gas Capture Process**  **Post -** **combustion Pre**  **- combustion**  **Oxy -** **combustion Post** **** **combustion** Reference plant w/o capture PC IGCC (PC) PC NGCC Overnight cost w/ capture ($/kW) 3,808 3,714 3,959 1,715 Overnight cost increase ($/kW) 1,647 1,128 1,696 754 LCOE w/ capture ($/MWh) 107 104 102 102 LCOE increase 41 29 40 25 

### NETL (2010) reported some estimated baseline values for the cost and performance of the various fossil fuel energy power systems, specifically IGCC, PC, and NGCC plants. They analyzed twelve different power plant designs with various CO 2 

### capture and processing technologies. The Table 7 below summarizes the plant configurations used in the report and the costs estimated for ea ch 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 CO 2 

### capture. The various cases include descriptions of certain process parameters, boiler technologies, contaminant removal technologies, and CO 2 

### separation technologies. Table 7 shows that the COE is expected to increase by approximately 80 - 84% with the incorporation of CO 2 

### capture by amine absorption into a pulverized coal power plant. Use of CO 2 

### capture by physi cal absorption in an IGCC or NGCC plant would result in a 38 -49% increase in COE.**Draft**

**Table 7**  **1 . Case descriptions**  **and costs estimated in the NETL (2010) report for baseline**  **estimates .** 
**Unit Cycle**  **CO 2**  **Capture Gasifier/** 

**Boiler Oxida** 

**nt H**  **2 S**  **separation/re moval**  **Sulfur**

**removal/Re covery**  **PM control NO**  **x control**  **CO 2**  **Separation TOTAL COST**  **Plant cost (2007 $/kW)**  **Overnight cost**

**(2007x1,1000) LCOE** 

**(mills/kWh, 2007$)**  IGCC 0% GEE

Radiant Only 95 mol% O 2 Single -Stage Selexol Claus Plant Quench, scrrubber and AGR adsorber N 2 dilution - 1,987 1,521,880 96.7

IGCC 90% GEE

Radiant Only 95 mol% O 2 Two -Stage Selexol Claus Plant Quench, scrrubber and AGR adsorber N 2 dilution Selexol 2 - stage 2,711 1,811,411 133.9

IGCC 0% CoP E Gas 95 mol% O 2 Refrigerated MDEA Claus Plant Cyclone, barrier filter and scrubber N 2 dilution - 1,913 1,469,577 93.8

IGCC 90% CoP E gas 95 mol% O 2 Selexol Claus Plant Cyclone, barrier filter and scrubber N 2 dilution Selexol 2 - stage 2,817 1,780,290 139.9

IGCC 0% Shell 95 mol% O 2 Sulfinol - M Claus Plant Cyclone, barrier filter and scrubber N 2 dilution - 2,217 1,708,524 103.1

IGCC 90% Shell 95 mol% O 2 Selexol Claus Plant Cyclone, barrier filter and scrubber N 2 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**  **CO 2**  **Capture Gasifier/** 

**Boiler Oxida** 

**nt H**  **2 S**  **separation/re moval**  **Sulfur**

**removal/Re covery**  **PM control NO**  **x control**  **CO 2**  **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 8 2 ). Of the 7 2 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 o r terminated were not further investigated and therefore, limited information is provided for those projects in the inventory in the Appendix. **Table 8** **2 . 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 method s ( Table 9 3 ). 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 te chnology is available, amines are a commonly used technology (Table 9 3 ). Further details on the carbon capture technologies employed for each project a re provided in Table A- 1 in the Appendix. **Table 9** **3 . Carbon capture processes and technologies used for each project. (** **-- ) signifies that the inform** **ation is not available.**  **Carbon Capture Type/Technology**  **# of Projects Post** **- Combustion**  **26**

-- 3 Adsorption 1 Amine 1 4**Draft Carbon Capture**  **Type/Technology # of Projects**  Biological 1 Ammonia 5 Membrane 2 **Pre -** **Combustion 29** 

-- 1 6 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 CO 2 

### 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 processin g information is available, s pecific details are provided in Table A- 1 in the Appendix. 

## References Aspelund A, M lnvikM 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 CO 2 

### capture and transport. International Journal of Greenhouse Gas Control. 1(3): 343 - 354. Bechtel. 2011. CO 2 

### Compression and Dehyd ration for Carbon Capture and Sequestration. Available on the Internet at: http://www.bechtel.com/assets/files/TechJournal/2011/OG&C%2004%20CO2%2 0Compression%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/energy
analyses/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 - Update 2011_Front - End%20Report.pdf Dynamis . Dynamis CO2 quality recommendations. European Commission, 2007. Project no: 019672. Emadi, D., K. Zanganeh, C. Salvador, S. Papavinasam, J. Li, A, Doiron, and A. Pratt. 2011. Material Challenges in CO 2 

### 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. N ew 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 Generatio n. 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., unda ted. CO2 Capture Technologies and Opportunities in Canada. “Strawman Document for CO2 Capture and Storage (CC&S) Technology Roadmap.” 1 st 

### Canadian CC&S Technology Roadmap Workshop, 18 - 19 September 2003, Calgary, Alberta, Canada. Herzog, H., Meldon, J., and Hatton, A., 2009. Advanced Post - Combustion CO2 Capture. Prepared for the Clean Air Task Force. Available on the Internet at: http://web.mit.edu/mitei/docs/reports/herzo gmeldon - 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 (CO 2 

### ) Capture and Storage Technology. Volume 1: Carbon Dioxide (CO 2 

### ) Capture, Transport, and Industrial Applications. Woodhead Publishing Limited and CRC Press LLC. N ETL. 2010. Cost and Performance Baseline for Fossil Energy Plants Volume 1: Bituminous Coal and Natural Gas to Electricity . Available on the Internet at: http://www.netl. doe.gov/energy
analyses/pubs/BitBase_FinRep_Rev2.pdf Occupational Safety and Health Administration. 2010. Hydrogen sulfide in workplace atmospheres. http://www.osha.gov/dts/sl tc/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 + Busines s 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 a s 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 Megaw

att 1/1/1991 -- PostCombustion Amine Ethanol -amino solvent -- 7 3,000 Tons/yr 4 Food/ Bever age -- AES Warrior Run Warrior

Run Power Plant Capture MD Active Plant in Operation 180 Megaw

att 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 Megaw

att 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 Permitting Planning 2000

0 Barrels per Day 1/1/2014 $2,000,00

0 Pre Combustion 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 Pre Combustion 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 N D Active Planning 1100 Megaw att 1/1/2009 -- PostCombustion Amine Amines -- -- -- 2 -- --
Intermountain Power Project Holly

Avenue Electrical Power Generatin g Station Capture U T 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 Megaw

att 10/1/200

8 $18,012 Oxycombusti

on Oxyfuel Oxyfuel Combustion Alstom will perform a focused R&D program 0.9 -- -- -- -- -- Slipstream Development and Testing of Siemens POSTCAP Capture and Separation Technology Big Bend

Station Capture FL Active Engineering design 2.5 Megaw

att 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 Coal Fired 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 -- Pre Combustion -- -- -- -- -- -- GS/E OR -- We Energies Pleasant Prairie Field Pilot Pleasant

Prairie Capture WI Complete d Capture

Complete 1.7 Megaw

att 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 Pre Combustion -- -- -- -- -- -- -- -- Taylorville Energy Center Taylorvill

e Energy Center IGCC Capture IL Hold Permitting 716 Megaw attGross 1/1/2014 $3,500,00

0 Pre Combustion -- -- -- -- -- -- -- -- CCS Project - Coffeyville Coffeyvill

e Resource s Fertilizers Plant Capture

and Injection KS Potential Planning -- NA 6/1/2013 -- Pre Combustion Ammonia -- -- -- -- -- EOR -- Edison Mission Group Powerton

Station Capture IL Potential -- 1538 Megaw att 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 Megaw

att 1/1/2011 $1,800,00

0 PostCombustion -- -- -- -- -- -- -- -- NRG Energy Inc. (Somerset Plant) Somerset

Plant Capture MA Terminate d Retrofit Plans 380 Megaw att -- $ 200,000 Pre Combustion -- -- -- -- -- -- -- --

Air Products and Chemicals Inc. CCS Project Methane

Steam Reformer Waste Streams Capture

and Injection TX Active Developing Infrastructure -- NA 11/1/201 2 $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 bica rbonates. -- -- -- -- GS --
Duke Energy

- Edwardsport Plant Edwards

port IGCC Capture

and Injection IN Active Engineering design 618 Megaw

att 10/1/201

2 $2,300,00 0 Pre Combustion -- -- -- -- -- -- -- -- 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 Oxycombusti on Oxyfuel Oxyfuel Combustion 0.9 1,300,0 00 Tonnes /yr 1 GS -- Great Plains Synfuels Plant Great

Plains Synfuels Plant Capture

and Injection ND Active Injection Ongoing 900 Megaw

att 9/1/2000 $2,100,00

0 Pre combustion 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 Pre Combustion Physical

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 Megaw

att 1/1/2014 $2,400,00

0 Pre Combustion Gasification TRIG Technology 0.65 -- -- -- EOR --

La Veta NG Processing La Veta

NG Plant Capture

and Injection CO Active Injection Ongoing -- NA 1/1/2007 $33,000 Separation Membrane Non -amine membrane process for separating CO2 -- -- -- -- -- --
Leucadia Energy Capture Project - Louisiana Lake

Charles CoGeneratio n Plant Capture

and Injection LA Active Plant in Operation -- NA 1/1/2010 $540 Pre Combustion Gasification GE Quench gasification 0.85 4,500,0 00 Tons/yr -- EOR Onsite - Compression involves the use of integrally geared multistage centrifugal compressors with 8 stages of compression and 6 stages of intercooling, configured as 2x50% serving two rectisol units.

MGSC Large Volume Sequestration Test: Ethanol Plant Source ADM

Ethanol 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 Large Volume Injection: Otsego County, MI DTE

Turtle Creek Natural Gas Plant Capture

and Injection MI Active Injection Complete -- NA 1/1/2010 $ 23,000 Separation Amine Amines- Gas Separation -- 200,00 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 Megaw

att 1/1/2010 $333,608 PostCombustion Amine Fluor Econamine 0.9 500,00 0 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 10/8/201 0 $ 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 Megaw

att 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 -- Pre Combustion Membrane Amino Acid based solvents & Membranes -- 680,00 0 Tonnes /yr -- EOR/

GS --
Searles Valley Minerals Power

Plant Capture Capture

and Injection CA Active Plant in Operation 108 Megaw

att 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 attGross 1/1/2010 $

2,400,000 Pre Combustion Physical

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 trans port by existing pipelines. The Erora Group - Cash Creek IGCC Cash

Creek Generatio n Capture

and Injection KY Active Permitting Planning 565 Megaw

att 1/1/2015 $

1,500,000 Pre Combustion -- -- -- 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

attGross 1/1/2015 $

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

Natu ral 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 Megaw

att 10/1/200

9 $ 76,800 PostCombustion Ammonia Ammonia based - 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 Megaw

att 1/1/1982 -- PostCombustion Amine Gas/Spec FT- 1; solvents -- 1,100 Tons/d ay -- 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 Ammonia based - 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 Megaw

att 5/1/2014 $ 3,200,00

0 Pre Combustion 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 N J Potential -- 500 Megaw att 1/1/2014 $ 5,000,00

0 -- -- -- -- -- -- -- GS -- Great Lakes Energy Research Park Alma

IGCC plant Capture

and Injection M I Potential -- 250 Megaw att -- $ 2,000,00

0 Pre Combustion Gasification ConocoPhillips E - Gas Gasification -- -- -- -- EOR -- Kentucky NewGas Kentucky

NewGas Capture

and Injection KY Active Site Selection -- NA 1/1/2017 $ 3,000,00 0 Pre Combustion 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 I IN Potential Permitting Planning -- NA -- -- -- -- -- -- -- -- -- EOR -- Lima Polygen Lima

IGCC Capture

and Injection OH Potential Permitting Planning 540 Megaw

att 1/1/2013 -- Pre Combustion -- -- -- -- -- -- -- --
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 pipel ine 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 Pre Combustion -- -- -- -- -- -- -- --**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 Worsham Steed 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 producti on of a high temperature and high pressure steam (with ~10% CO2) gas mixture. The steam (and CO2) is expanded in a reconfigured steam turbine, following which the CO2 is separated in the steam condensation process. -- 870 Tons/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 Pre Combustion -- -- -- -- -- -- -- -- FutureGen - Mattoon FutureGe

n - Mattoon Capture

and Injection Il L Terminate

d Site

Characterizati on 275 Megaw

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

0 Pre Combustion -- -- -- -- -- -- -- -- FutureGen - Odessa FutureGe

n - Odessa Capture

and Injection TX Terminate

d Site

Characterizati on 275 Megaw

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

0 Pre Combustion -- -- -- -- -- -- -- --**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 Pre Combustion -- -- -- -- -- -- -- -- Jamestown BPU Samuel

J. Carlson Generatin g Station Capture

and Injection NY Terminate

d Permitting

Planning 40 Megaw

att 1/1/2013 $145,000 Pre Combustion -- -- -- -- -- -- -- -- Leucadia Energy Capture Project - Mississippi Moss

Point SNG Plant Capture

and Injection MS Terminate

d Permitting

Planning -- -- 1/1/2010 $ 1,689,00 0 Pre Combustion -- -- -- -- -- -- GS/E OR -- Leucadia Mississippi 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 Pre Combustion -- -- -- -- -- -- GS/E OR -- NRG Energy Inc - Huntley IGCC Project Huntley

IGCC Capture

and Injection NY Terminate

d Permitting

Planning 680 Megaw

att 1/1/2013 $1,500,00

0 Pre Combustion Amine Mitsubishi HI Gasification (KS 1) -- -- -- -- -- -- 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 Pre Combustion -- -- -- -- -- -- -- --**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_s eq/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/global
projects/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/global
projects/details/29.html?mn=154 --
DKRW Energy LLC http://www.dkrwadvancedfuels.co m/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_Process
160.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 -ADAES Solid%20Sorbents%20Retrofit.pdf http://www.netl.doe.gov/technologies/coal power/ewr/co2/post
- combustion/eval
solid - sorbent.html http://www.netl.doe.g ov/publications/proceedings/11/ co2capture/presentations/1
- Monday/22Aug11
- Starns ADAES - 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.busine sswire.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/oxy
combustion/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-Alstom OxyComb%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/siemens
postcap.html http://www.netl.doe.gov/publications/proceedings/11/ co2capture/presentations/2
-Tuesday/23Aug11
- Winkler-Siemens Technology%20Slipstream%20Testing.pdf http://www.pow ermag.com/POWERnews/2909.html http://www.tampaelectric.com/news/article/index.cfm ?article=541 --

Slipstream Testing of a Membrane CO2 Capture Process for Existing Coal http://www.netl.doe.gov/publications/proc

eedings/11/co2capture/pres entations/1
- Monday/22Aug11
- Merkel - MTR Efficient%20Membrane%20Pilot%20Test.pd f http://www.netl.doe.gov/publications/proceedings/11/ co2capture/presentations/1
- Monday/22Aug11
- Merkel MTR - 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 - on hold%20=&id=1913848 -AEP - Clean - coal plant - on hold&w idget=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/somerset
station - 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/publi cations/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/about
us/edwardsport
- overview.asp http://en3pro.com/wp
content/uploads/2011/04/CCS
-fact sheet.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
-great plains - synfuels - plant http://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 oject s/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/wp
content/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/pu blications/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 Large Volume 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 heet s/project/Project678_4P.pdf http://www.netl.doe.gov/publications/proc eedings/07/rcsp/factsheets/4
- MGSC_Large Volume%20Sequestration%20Test%20with %20Ethanol%20Plant%20So.pdf http://globalenergyobservatory.org/geoid/40262 http://www.netl.doe.gov/publication s/fa ctsheets/project/NT42588.pdf

MRCSP Michigan Basin Geologic Test and Large Volume 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 o alpower/gasification/projects/gas
clean/00489/19HORNICK.pdf

Purdy, Sho -Vel Tum EOR Project http://globalenergyobservatory.org/geoid/4

0281 http://www.netl.doe.gov/KMD/cds/disk22/ F ARI%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_RCSP InfrastructureMtg_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/exxonmobil
finishes.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/FE0002 650.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/trai blazer-front - end - engineering - and design - 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/4c
valverde.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=ec i/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/wp
content/themes/simplo/site
images/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/news
releases/aep
-to - install - carbon - capture - on two - existing - power- plants - company-will - be first -to - move -technology-to - commercial scale - 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.p df Coal Plant Outside NY City http://www.nytimes.com/2009/04/18/busi

ness/energy
environment/18clean.html?_r=2 -- -- Great Lakes Energy Research Park http://www.mandmenergy.com/index
2.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
-files proposed - 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.hydrocarbons
technology.com/projects/co_production/ http://www.netl.doe.gov/technologies/coal power/turbines/refshelf/reports/41776%20 GE%20Semi Annual_Fuel%20Flexible%20Combustion.PD F -- --

ZENG Worsham Steed 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**  Leucadia Mississippi 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
- press news/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 -- --