1 

- TECHNICAL SUPPORT DOCUMENT – 

To: Docket EPA-HQ-OAR-2013-0495 

Date: July 10, 2015 

Subject: Literature Survey of Carbon Capture Technology

Introduction

On January 8, 2014, the Environmental Protection Agency (EPA) proposed New Source 

Performance Standards (NSPS) to limit carbon dioxide (CO2) emissions from new fossil fuelfired electricity generating units (EGUs) under Clean Air Act (CAA) §111(b).1

 Carbon capture 

and storage (CCS), also known as "carbon capture and sequestration," was evaluated as an option 

for new steam generating boilers and integrated gasification combined cycle (IGCC) units in 

developing the proposed and final NSPS. In determining the best system of emission reduction 

adequately demonstrated (BSER) to establish the standards, the EPA reviewed literature 

covering existing projects that implement CCS, existing projects that implement various 

components of CCS, planned CCS projects, and scientific and engineering studies of CCS. The 

final NSPS contains an emission limit of 1,400 pounds CO2 per megawatt hour on a gross basis 

(lb CO2/MWh-g) for new steam generating boilers and IGCC units based on partial CCS (i.e., 

CCS on a portion or "slip-stream" of the EGU exhaust). Among other compliance approaches,2

partial CCS was determined to be adequately demonstrated based on the fact that postcombustion CCS is demonstrated in full-scale operation within the electricity generating 

industry, and full-scale pre-combustion CCS has been demonstrated in several chemical industry 

plants with results that are reasonably transferable to the electricity generating sector. It is 

important to note that the NSPS does not require near-term widespread use of full CCS for all 

electric utilities, but rather is based on partial CCS for only the subset of new fossil-fuel fired 

electric utility boilers or IGCC units. 

The purpose of this technical support document (TSD) is to provide an overview of CCS 

technology and describes the status of sources implementing CCS projects to date. This TSD 

provides information on the technological feasibility of CCS (including partial CCS), but does 

not discuss costs. The EPA's conclusions regarding the costs and emission reductions associated 

with implementation of partial CCS are based on in-depth studies of costs by DOE/NETL reports 

and recent EIA AEO projections and are documented in a separate memorandum and the 

Regulatory Impact Analysis for the final NSPS. Similarly, a separate document discusses 

funding mechanisms associated with CCS projects. 

This document is organized as follows: 

 

1

 Standards of Performance for Greenhouse Gas Emissions From New Stationary Sources: Electric Utility 

Generating Units, 79 Fed. Reg. 1430. 

2

 It is noted that a new utility boiler or IGCC unit can meet the final standard of performance of 1,400 lb CO2/MWh 

by co-firing natural gas should project developers choose to delay implementation of partial CCS.
2 

I. Overview of CCS Technology for Fossil-fuel Fired EGUs 

A. CO2 Capture Technology 

1. Post-combustion CO2 capture 

2. Pre-combustion CO2 capture 

3. Oxy-combustion CO2 capture 

B. CO2 Compression 

C. CO2 Transportation Pipeline Infrastructure 

D. Geologic Sequestration 

E. Alternatives to Geologic Sequestration 

F. Continuing Research and Policy Development 

II. Sources Utilizing CCS 

A. Post-combustion 

B. Pre-combustion 

C. Oxy-combustion 

III. Bibliography 

I. Overview of CCS Technology for Fossil-fuel Fired EGUs

Use of fossil fuel to generate electricity commonly occurs in one of the following systems: 

• A steam generating unit (also referred to simply as a “boiler”) that feeds a steam 

turbine that spins an electric generator. 

• A combustion turbine (or reciprocating internal combustion engine) that directly 

drives the generator. Some modern power plants use a “combined cycle” electric 

power generation process, in which a gaseous or liquid fuel is burned in a combustion 

turbine that both drives electrical generators and provides heat to produce steam in a 

heat recovery steam generator (HRSG) that drives a second electric generator to 

increase the overall efficiency of the electric power generation process. 

• An integrated gasification combined cycle (IGCC) system that first gasifies solid fuel 

and burns the resulting syngas in a combined cycle stationary combustion turbine for 

electric generation. 

The majority of new fossil-fuel fired electric generating units are projected to use natural-gas 

combined cycle technology which results in lower CO2 emissions per MWh of electricity 

produced than steam generating units or IGCC systems burning solid fossil fuels such as coal. 

Use of CCS was analyzed as an option for reducing CO2 emissions from new steam generating 

units and new IGCC systems for purposes of the NSPS. 

Carbon capture and storage (CCS) involves the separation and capture of CO2 from flue gas, or 

syngas in the case of IGCC. CCS is a three-step process that includes: 

1. Capture of CO2 from electric generating units (or other industrial processes); 

2. Compression and transport of the captured CO2 (usually in pipelines); 

3. Underground injection and geologic sequestration (also referred to as storage) of the 

CO2 into deep underground rock formations. These formations are often a mile or 
3 

more beneath the surface and consist of porous rock that holds the CO2. Overlying 

these formations are impermeable, non-porous layers of rock that trap the CO2 and 

prevent it from migrating upward. 

Figure 1 illustrates the typical depth at which CO2 would be injected.

Figure 1. CCS Schematic 

(Subsurface depth to scale, 5,280 feet equals one mile) (EPA, 2013c)

Geologic sequestration is feasible in different types of geologic formations including deep saline 

formations (formations with high salinity formation fluids) or in oil and gas formations, such as 

where injected CO2 increases oil production efficiency through a process referred to as enhanced 

oil recovery (EOR). CO2 may also be used for other types of enhanced recovery, such as for 

natural gas production. Reservoirs such as unmineable coal seams also offer the potential for 

geologic storage.3 

 

3

 Other types of opportunities include organic shales and basalt.
4 

A study prepared for the U.S. DOE by the Pacific Northwest National Laboratory (Dooley, 

2009) evaluated the development status of various CCS technologies. The study addressed the 

availability of capture processes; transportation options (CO2 pipelines); injection technologies; 

and measurement, verification, and monitoring technologies. The study concluded that, in 

general, CCS was technically viable at the time of the report (2009) although full-scale CCS 

systems had not yet been installed and fully integrated at an EGU at that time. The study also did 

not address the cost or energy requirements of implementing CCS technology.4 

In 2010, an Interagency Task Force on Carbon Capture and Storage was established to develop a 

comprehensive and coordinated federal strategy to speed the commercial development and 

deployment of CCS technologies (Interagency Task Force, 2010). The Task Force was 

specifically charged with proposing a plan to overcome the barriers to the widespread, costeffective deployment of CCS within 10 years, with a goal of bringing commercial demonstration 

projects online by 2016. As part of its work, the Task Force prepared a report that summarizes 

the state of CCS and identified technical and non-technical barriers to implementation.5

Much research and development has occurred in the 5 years since these DOE and interagency 

reports were written in the 2009-2010 timeframe. As described in more detail in Section II of this 

report, full-scale EGU CCS demonstration projects are underway. Research to reduce the energy 

requirements of CCS technologies and improve its cost-effectiveness continues, as described in 

section I.F of this document. A more recent report from the DOE/NETL provides a technology 

update and summarizes research continuing research sponsored by the DOE (NETL, 2013). The 

EPA's updated cost analysis for CCS systems based on DOE/NETL analyses (from 2010-2015), 

EIA AEO projections (from 2014), and other recent information is presented in the RIA for the 

NSPS. 

The following subsections provide an overview of CO2 capture technology, CO2 compression, 

CO2 pipeline infrastructure for transportation, geologic sequestration, and alternatives to 

geologic sequestration. 

A. CO2 Capture Technology 

In general, CO2 capture technologies applicable to fossil-fuel fired power generation can be 

categorized into three approaches: 

• Post-combustion systems are designed to separate CO2 from the flue gas produced 

by fossil-fuel combustion in air. 

 

4

 For up-to-date information on Department of Energy’s National Energy Technology Laboratory’s 

(NETL) Carbon Sequestration Program go to the NETL web site (NETL, 2015b) at: 

http://www.netl.doe.gov/research/coal/carbon-storage/research-and-development. 

5

 For additional information on the Interagency Task Force and its findings on CCS, go to: 

http://www.epa.gov/climatechange/Downloads/ccs/CCS-Task-Force-Report-2010.pdf
5 

• Pre-combustion systems are designed to separate CO2 and H2 in the high-pressure 

syngas produced at IGCC power plants. 

• Oxy-combustion uses high-purity oxygen (O2), rather than air, to combust coal and 

therefore produces a highly concentrated CO2 stream. 

The post- and pre-combustion CO2-capture processes typically use solvents, solid sorbents, and 

membrane-based technologies for separating and capturing CO2. Solvents chemically absorb the 

CO2 which is separated from the solvent in a regeneration step. Solid sorbents capture CO2 

through chemical adsorption, physical adsorption, or a combination of the two effects. 

Membrane-based capture uses permeable or semi-permeable materials to produce a highly 

concentrated CO2 stream that does not require a separation/capture step. 

Each of the CO2-capture approaches results in increased capital and operating costs and 

decreased electricity output (or energy penalty6

), thereby increasing the cost of electricity.7 The 

energy penalty occurs because the CO2 capture process uses some of the energy produced from 

the plant (Interagency Task Force, 2010). Research is underway to reduce CO2 capture costs and 

to improve performance. The DOE/NETL sponsors an extensive research, development and 

demonstration program that is focused on developing advanced technology options that will 

dramatically lower the cost of capturing CO2 from fossil-fuel energy plants compared to 

currently available capture technologies. The large-scale CO2 capture demonstrations that are 

currently planned and in some cases underway, under DOE’s initiatives, as well as other 

domestic and international projects, will continue to generate operational knowledge and enable 

continued commercialization and deployment of these technologies. The EPA is currently 

finalizing an NSPS limit based on partial CCS (as opposed to CCS of the full exhaust stream) to 

help mitigate the energy penalty and costs of CCS as the technology continues to emerge and be 

refined through further research. 

Each of the CO2-capture systems are described and discussed in more detail in the subsections 

below. Facility-specific applications of CO2 capture systems are discussed in Section II. 

1. Post-combustion CO2 capture 

Post-combustion CO2 capture refers to removal of CO2 from combustion flue gas prior to 

discharge to the atmosphere. It is referred to as “post-combustion capture” because the CO2 is the 

 

6

 The energy penalty represents the percentage reduction in the power plant operating efficiency. For example, a 

reduction in efficiency from 30 percent to 20 percent represents a 10 percentage point drop in efficiency, which is 

equivalent to a 33 percent energy penalty. 

7

 There is on-going research sponsored by DOE/NETL and others to further reduce the energy requirements of the 

carbon capture systems. Progress is being made. For example, the heat duty (the energy required to regenerate the 

capture solvent) for the amine scrubbing process used at the Searles Valley facility in the mid-70’s was about 12 

MJ/mt CO2 removed as compared to a heat duty of about 2.5 MJ/mt CO2 removed for the amine processes used in 

2014 at Boundary Dam and for the amine system that will be used at the WA Parish facility. 
6 

product of the combustion of the primary fuel and the capture takes place after the combustion of 

that fuel. A simplified process schematic of post-combustion CO2 capture is shown in Figure 2 

(NETL, 2013). 

 
7 

Figure 2: Diagram Illustrating a Pulverized Coal Boiler with 

Post-Combustion CO2 Capture

As noted previously, in a typical fossil fuel-fired steam generating unit, fuel is burned with air in 

a boiler to produce steam that drives a turbine/generator to produce electricity. Flue gas from the 

boiler consists primarily of N2 and CO2 with other components in trace amounts (e.g., particulate 

matter (PM), sulfur oxides (SOx), nitrogen oxides (NOx), hydrochloric acid (HCl) etc.) The CO2

capture process is located downstream of the conventional pollutant controls for removal of PM 

and acid gases so these components will not interfere with CO2 removal. In addition to the need 

to remove pollutants upstream of the CO2 capture system, challenges to separating CO2 from 

steam generating unit combustion flue gas include: 

• the high volume of gas to be treated because the CO2 is dilute (13–15 volume percent 

in coal-fired systems); 

• the low pressure [15–25 pounds per square inch (psi)] of the flue gas; 

• and the large auxiliary power load to compress captured CO2 from near atmospheric 

pressure to pipeline pressure (about 2,200 psi). 

The volume of flue gas to be treated (and the associated energy penalty) is reduced in partial CO2

capture systems, where a slipstream of the flue gas is treated as opposed to the entire flue gas 

stream. 

The CO2 capture process involves use of a chemical solvent, solid sorbent, or membrane to 

separate CO2 from the flue gas. Amine-based solvent systems are most commonly used for postcombustion capture systems. When contacted with the combustion flue gas, then solvent 

participates in a chemical absorption (chemisorption) separation process in which the CO2 is 

absorbed by the liquid solvent. Solid sorbents can be used to capture CO2 from flue gas through 
8 

chemical adsorption, physical adsorption, or a combination of the two. Possible configurations 

for contacting the flue gas with solid sorbents include fixed, moving, and fluidized beds. 

Membrane-based capture uses permeable or semi-permeable materials that allow for the 

selective transport/separation of CO2 from flue gas (NETL, 2015c). 

Gas absorption processes using chemical solvents, such as amines, to separate CO2 from other 

gases have been in use since the 1930s in the natural gas industry to produce food and chemical 

grade CO2. Amine-based solvent systems are in commercial use for scrubbing CO2 from 

industrial flue gases and process gases, and are available for use in CCS systems at electric 

utilities. Following absorption into the amine-based solvent, a high purity CO2 stream is 

separated from the solvent in a steam stripping (solvent regeneration) process, where the solvent 

is heated with low pressure steam from the power plant’s steam cycle. Solvent regeneration is 

responsible for much of the “energy penalty” of the CO2 capture system because steam that 

could otherwise be used to generate electricity is instead used in the solvent regeneration 

process. Development of advanced solvents – those that are chemically stable, have high CO2

absorption capacities, and have low regeneration energy requirements – continues to be an active 

area of research. The DOE/NETL's post-combustion CO2 control technology R&D program 

includes projects directed at the use of solvents, solid sorbents, and membranes. 

Amines chemically react with CO2 via reversible reactions to form water-soluble compounds. 

Despite the low CO2 partial pressure in combustion flue gas, amines are capable of achieving 

high levels of CO2 capture due to fast kinetics and strong chemical reactions. However, the 

absorption capacity for commercially available amines is chemically limited, requiring two 

molecules of amine for each molecule of CO2. In addition, usable amine solution concentrations

are typically limited by viscosity and corrosion. Therefore, current amine systems are only 

between 20 and 30 percent amine with the remaining being water. Although the water present in 

the solution helps control the solvent temperature during absorption, which is an exothermic 

reaction, the water also requires significant amounts of sensible heating and stripping energy 

upon CO2 regeneration. Not every amine system is the same, and various vendors offer different 

designs. In general, depending on the amount of heat integration, anywhere from 1,550 to greater 

than 3,000 British thermal units (Btu) per pound of CO2 in the form of low pressure steam 

(approximately 45 psi) is required to regenerate the solvent to produce a concentrated CO2

stream at a pressure of approximately 25 psi (Interagency Task Force, 2010). 

An amine-based post-combustion capture process is depicted in Figure 3. 

 
9 

Figure 3. Schematic Diagram of Amine-based CO2 Capture Process 

After conventional air pollutant (SOx, NOx, PM) cleanup, the combustion flue gas enters an 

absorber reactor and flows counter-currently to a CO2-lean solvent where CO2 is absorbed into, 

and chemically reacts with the amine solution. The treated flue gas (mostly N2) is discharged to 

the atmosphere, and the CO2-rich amine solution is pumped to a solvent regeneration column 

where the CO2-rich solution is heated in order to reverse the chemical reactions between the CO2 

and amine solvent. Steam extracted from the turbine cycle provides the heat for regeneration of 

the amine solvent in the solvent regeneration column. Consequently, CO2 is released, producing 

a concentrated stream that exits the regeneration column and is then cooled and dehumidified in 

preparation for compression, transport, and storage. From the solvent regeneration column, the 

CO2-lean solution is cooled and returned to the absorber for reuse (Interagency Task Force, 

2010). 

Post-combustion CO2 capture offers the greatest near-term potential for reducing power sector 

CO2 emissions because it can be tuned for various levels of CO2 capture (e.g., in partial capture 

systems as indicated by the optional bypass in Figure 2). Post-combustion capture technologies 

are available for application to conventional coal-fired power plants and the combustion flue gas 

from IGCC power plants (Interagency Task Force, 2010; NETL, 2013). Many projects are in the 

planning stages for demonstration scale-up including the Alstom chilled ammonia process and 

several amine-based processes (e.g., Fluor [Econamine], ABB/Lummus, Mitsubishi Heavy 

Industries [MHI], HTC Purenergy, Aker Clean Carbon, Cansolv, et al.) (Interagency Task Force, 

2010). 

The advancement of amine-based solvents is an example of technology development that has 

improved the cost and performance of CO2 capture. Most single component amine systems are 
10 

not practical in a flue gas environment as the amine will rapidly degrade in the presence of 

oxygen and other contaminants. The Fluor Econamine FG process uses a monoethanolamine 

(MEA) formulation specially designed to recover CO2 and contains a corrosion inhibitor that 

allows the use of less expensive, conventional materials of construction. Other commercially 

available processes use sterically hindered amine formulations (for example, the Mitsubishi 

Heavy Industries KS–1 solvent) which are less susceptible to degradation and corrosion issues. 

Several companies offering post-combustion CO2 capture technologies have offered performance 

guarantees or made public statements regarding the technical feasibility of their systems for CO2

capture from fossil-fuel fired power plants. For example: 

• Linde and BASF offer performance guarantees for CCS technology. The two 

companies are jointly marketing new, advanced technology for capturing CO2 from 

low pressure gas streams in power or chemical plants. In product literature 

(BASF/Linde, undated) they note that Linde will provide a turn-key carbon capture 

plant using a scrubbing process and solvents developed by BASF, the world’s leading 

technical supplier for gas treatment. They further note that: 

o The captured carbon dioxide can be used commercially for example for EOR 

(enhanced oil recovery) or for the production of urea. Alternatively it can be 

stored underground as a carbon abatement measure. [...] The PCC (PostCombustion Capture) technology is now commercially available for lignite 

and hard coal fired power plant [...] applications. 

o The alliance between Linde, a world-leading gases and engineering company 

and BASF, the chemical company, offers great benefits [...] Complete capture 

plants including CO2 compression and drying ... Proven and tested processes 

including guarantee ... Synergies between process, engineering, construction 

and operation ... Optimized total and operational costs for the owner. 

• Fluor has developed patented CO2 recovery technologies to help its clients reduce 

GHG emissions. The Fluor product literature (Fluor, 2015) specifically points to 

Econamine FG PlusSM process which uses an amine solvent to capture and produce 

food grade CO2 from post-combustion sources. The literature further notes that 

Econamine FG PlusSM (EFG+) is also used for carbon capture and sequestration 

projects, that the proprietary technology provides a proven, cost-effective process for 

the removal of CO2 from power plant flue gas streams and that the process can be 

customized to meet a power plant's unique site requirements, flue gas conditions, and 

operating parameters. 

• Fluor has also published an article titled “Commercially Available CO2 Capture 

Technology” in which it describes the EFG+ technology (Johnson et. al, 2009). The 

article notes, “Technology for the removal of carbon dioxide (CO2) from flue gas 

streams has been around for quite some time. The technology was developed not to 

address the GHG effect but to provide an economic source of CO2 for use in 

enhanced oil recovery and industrial purposes, such as in the beverage industry.” 

• Mitshubishi Heavy Industries (MHI) offers a CO2 capture system that uses a 

proprietary energy-efficient CO2 absorbent called KS-1TM. Compared with the 
11 

conventional monoethanolamine (MEA)-based absorbent, KS-1TM solvent requires 

less solvent circulation to capture the CO2 and less energy to recover the captured 

CO2. 

• Shell has developed the CANSOLV CO2 Capture System, which Shell describes in its 

product literature as a world leading amine based CO2 capture technology that is ideal 

for use in fossil fuel-fired power plants where enormous amounts of CO2 are 

generated. The company also notes that the technology can help refiners, utilities and 

other industries lower their carbon intensity and meet stringent GHG abatement 

regulations by removing CO2 from their exhaust streams, with the added benefit of 

simultaneously lowering SO2 and NO2 emissions. 

The DOE/NETL and private industry are continuing to sponsor research on advanced solvents 

(including new classes of amines) to improve the CO2 capture performance and reduce costs. 

2. Pre-combustion CO2 capture 

Pre-combustion CO2 capture, as its name implies, takes place before the process gas is 

combusted to generate steam at a power plant. Pre-combustion capture is applicable mainly to 

IGCC processes where fuel is converted into gaseous components by applying heat under 

pressure in the presence of steam and limited O2, as shown in Figure 4. 

 
12 

Figure 4. Schematic of an integrated gasification combined cycle (IGCC) power plant. 

(EPA, 2010) 

In an IGCC system, the fuel (usually coal or petroleum coke at electric utilities) is heated with 

water and oxygen in an oxygen-lean environment. Unlike a boiler, a gasifier carefully 

controls the amount of air or oxygen available inside it so only a small portion of the fuel burns 

completely. This "partial oxidation" process provides heat to drive gasification reactions. Rather 

than burning, most of the fuel is chemically broken apart by the heat and pressure in the gasifier, 

setting into motion chemical reactions that produce syngas. The fuel (carbon), water and oxygen 

react to form primarily a mixture of hydrogen (H2) and carbon monoxide (CO) known as 

synthesis gas or "syngas" according to the following high temperature reaction: 

3C + H2O + O2  H2 + 3CO 

Although syngas is predominantly H2 and CO, it can include other gaseous constituents (e.g., 

hydrogen sulfide (H2S), carbonyl sulfide (COS), and CO2) in varying compositions depending on 
13 

fuel characteristics and the conditions in the gasifier. The amount of CO2 in syngas depends upon 

the specific gasifier technology used, the operating conditions, and the fuel used; but is typically 

less than 20 volume percent. The gasification process also produces inorganic materials 

originating from the coal (e.g., minerals, ash). After removal of the impurities, the syngas is 

combusted using a conventional combustion turbine in a combined cycle configuration (i.e., a 

combustion turbine combined with a heat recovery steam generator and steam turbine). 

Most syngas streams are at higher pressure and can contain higher concentrations of CO2 than 

conventional steam generating units (especially if the syngas is shifted to enrich the CO2

concentration as described below). As such, the pre-combustion CO2 capture systems can utilize 

physical absorption (physisorption) solvents rather than the chemical absorption solvents 

described earlier for post-combustion processes. Physical absorption has the benefit of relying on 

weak intermolecular interactions and, as a result, the absorbed CO2 can often be released 

(desorbed) by reducing the pressure rather than by adding heat. Pre-combustion capture systems 

have been used widely in industrial processes such as natural gas processing. 

Figure 5 is a simplified process schematic for pre-combustion CO2 capture. Components of the 

pre-combustion CO2 capture system include a water-gas shift (WGS) reactor, syngas cooler (to 

achieve optimum temperature for the CO2 separation step), CO2 separation system, and 

compressor needed to raise the captured CO2 to pipeline pressure. 

Figure 5. Pre-Combustion CO2 Capture for an IGCC Power Plant (NETL, 2015d) 

In preparation for pre-combustion CO2 capture, the amount of CO2 in the syngas can be 

increased by “shifting” the composition via the catalytic water-gas shift (WGS) reaction. This 

process involves the catalytic reaction of steam (“water”) with CO (“gas”) to form H2 and CO2

according to the following catalytic reaction: 

CO + H2O  CO2 + H2 
14 

A WGS reactor is typically a fixed-bed reactor containing shift catalysts to convert CO and water 

into additional H2 and CO2. The resulting CO2 contained in the syngas is then separated from the 

H2-enriched syngas which is used for combustion in a combined-cycle turbine system for 

electricity generation. The CO2 separation process uses a physical solvent, solid sorbent, or 

membrane to separate the CO2 from the syngas. Sulfur compounds and CO2 can be removed 

either simultaneously or selectively (in a subsequent sulfur recovery step), depending on the 

shifted syngas composition and conditions, as well as the end fuel gas specifications. Contrary to 

the post-combustion capture flue gas, the IGCC syngas can contain a high concentration of CO2

(at high partial pressure) and is pressurized. This allows the use of physical absorbents that 

require much less added energy to release the captured CO2 and require less compression to get 

to pipeline standards. The lower volume of syngas to be handled results in smaller equipment 

sizes and lower capital costs. (Interagency Task Force, 2010); NETL 2013) 

The current state-of-the-art pre-combustion CO2 capture technologies that could be applied to 

IGCC systems (the glycol-based SelexolTM process and the methanol-based Rectisol® 

process) employ physical solvents that preferentially absorb CO2 from the syngas mixture. Other 

CO2 separation processes that have yet to be built for full-scale IGCC power plants include the 

pyrolidone-based Purisol process and the polypropylene carbonate-based Fluor solvent 

(Interagency Task Force, 2010). Several Rectisol and Selexol systems are in use at commercial 

scale. For example, the Rectisol system is used for CO2 capture at the Dakota Gasification 

Company's substitute natural gas (SNG) plant in North Dakota, which is designed to remove 

approximately 1.5 million tons of CO2 per year from the syngas. The CO2 is purified, transported 

via pipeline and injected into the Weyburn oilfield in Saskatchewan, Canada (NETL, 2015d). 

A simplified flow scheme of the Rectisol® process provided by technology vendor Linde is 

displayed in Figure 6. This is a configuration intended for dual removal of sulfur gases and 

CO2 in separate fractions, resulting in a pure CO2 product and an H2S/COS enriched gas fraction 

(NETL, 2015h) 

 
15 

Figure 6: Rectisol Process Diagram (NETL, 2015h) 

Using the two-stage SelexolTM process as an example (Figure 7), in the first stage, untreated 

syngas enters the first of two absorbers where H2S is preferentially removed using CO2-rich 

solvent from the CO2 absorber. The gas exiting the H2S absorber passes through the second 

absorber, where CO2 is removed using both semi-lean and lean solvent streams. The treated 

syngas exits the absorber and is sent to the combustion turbine. The CO2-rich solvent exits the 

CO2 absorber, and a portion is sent to the H2S absorber, while the remainder is sent to a series of 

flash drums for regeneration. The CO2 product stream is obtained from the flash drums, and the 

semi-lean solvent is returned to the CO2 absorber. The H2S/CO2-rich solvent exiting the H2S 

absorber is sent to the acid gas stripper, where the absorbed gases are released using a steam 

heated reboiler. The acid gas from the stripper is sent to a Claus plant to produce elemental sulfur 

for commercial use, and the lean solvent exiting the stripper is returned to the CO2 absorber. 

(Interagency Task Force, 2010)

 
16 

Figure 7. Schematic Diagram of the Pre-Combustion Selexol

TM 

CO2 Capture Process 

The SelexolTM process is being used at Southern Company's Kemper, Mississippi IGCC facility., 

Southern Company’s Mississippi Power stated that, because the SelexolTM process has been used 

in industry for decades, the technical risk of its use at the Kemper IGCC facility are minimized. 

For example: 

The carbon capture process being utilized for the Kemper County IGCC is a 

commercial technology referred to as SelexolTM. The SelexolTM process is a 

commercial technology that uses proprietary solvents, but is based on a 

technology and principles that have been in commercial use in the chemical 

industry for over 40 years. Thus, the risk associated with the design and 

operation of the carbon capture equipment incorporated into the Plant’s design is 

manageable (Anderson, 2009). 

And ... 

“The carbon capture equipment and processes proposed in this project have been 

in commercial use in the chemical industry for decades and pose little technology 

risk.” (Mississippi Power Company, 2009). 

3. Oxy-combustion CO2 capture 
17 

Oxy-combustion (or oxy-fuel) refers to the replacement of air, either in the boiler or the gasifier, 

with pure oxygen (O2). Using purified O2 helps eliminate unwanted byproducts present in air, 

and also increases the CO2 purity of the resulting syngas or flue stream, making CCS more 

effective. 

Oxy-combustion systems for CO2 capture rely on combusting coal (or other fuel) with relatively 

pure O2 diluted with recycled CO2 or CO2/steam mixtures, as shown in Figure 8. The primary 

products of combustion are water and CO2, with the CO2 separated by condensing the water and 

removing any other gas constituents that infiltrated the combustion system (Interagency Task 

Force, 2010). 

Figure 8. Pulverized Coal Power Plant with Oxy-Combustion CO2 Capture 

(Interagency Task Force, 2010); NETL 2013) 

Oxy-combustion overcomes the technical challenge of low CO2 partial pressure normally 

encountered in conventional coal combustion flue gas by producing a highly concentrated CO2

stream (~60 percent), which is separated from water vapor by condensing the water through 

cooling and compression. An additional purification stage for the highly concentrated CO2 flue 

gas may be necessary to produce a CO2 stream that meets transportation and storage 

requirements. This purification step should have significantly less cost than a conventional postcombustion capture system, due to the high CO2 concentration and reduced flue gas volume 

(Interagency Task Force, 2010). 

The appeal of oxy-combustion is tempered by a few key challenges, including the capital cost 

and energy consumption for a cryogenic air separation unit (ASU), boiler air infiltration that 

dilutes the flue gas with N2, and excess O2 contained in the concentrated CO2 stream. Flue gas 

recycle (~70 to 80 percent) is also necessary to approximate the combustion characteristics of air, 

since currently available boiler materials cannot withstand the high temperatures resulting from 

coal combustion in pure O2. Consequently, the economic benefit of oxy-combustion compared to 

amine-based scrubbing systems is limited. (Interagency Task Force, 2010) 
18 

The conventional ASU is a cryogenic process that has a significant energy requirement. 

However, alternative oxygen separation methods are being researched for possible commercial 

scale development. These alternative methods include ion transport membranes (ITM), ceramic 

auto-thermal recovery, oxygen transport membranes, and chemical looping (EPA, 2010). 

Several research institutes have investigated laboratory- and pilot-scale testing of oxy-fuel 

combustion, including (EPA, 2010): 

• Pilot test programs for the European Enhanced Capture of CO2 (ENCAP) program 

and the Advanced Development of the Coal-Fired Oxy-fuel Process with CO2 

Separation (ADECOS) program). 

• A 30 MW oxy-firing pilot plant at the Schwarze Pumpe station in Spremberg, 

Germany. 

• A 32 MW oxy-firing demonstration project in France retrofitting an existing boiler to 

natural gas oxy-combustion. 

• A comprehensive test program using the 15 MW tangentially-fired Boiler Simulation 

Facility and 15 MW Industrial Scale Test Facility operated by Alstom Power, Inc., in 

Windsor, CT. 

Chemical looping is an advanced technology similar to oxy-combustion in that it relies on 

combustion or gasification of coal in a N2-free environment. However, rather than using an 

ASU, chemical looping involves the use of a metal oxide or other compound as an oxygen 

carrier to transfer O2 from air to the fuel. Figure 9 presents a simplified process schematic for 

chemical looping. Chemical looping splits combustion into separate oxidation and reduction 

reactions. In the fuel reactor, the oxygen carrier releases the O2 in a reducing atmosphere and the 

O2 reacts with the fuel. The carrier is then recycled back to the oxidation chamber, or air reactor, 

where it is regenerated by contact with air. Because air is not introduced into the fuel 

(combustion) reactor, the products of combustion are primarily CO2 and H2O. Chemical looping 

can be applied in either coal combustion or coal gasification processes. (NETL, 2013) 
19 

Figure 9: Chemical Looping Process (NETL, 2013) 

B. CO2 Compression 

Regardless of how CO2 is captured from a power plant, the CO2 must be compressed to a 

pressure between 1,500 and 2,200 psi to be transported via pipeline and then injected into an 

underground storage site. As discussed in Section I.C below, compressed CO2 is already being 

transported under these high pressures in a network of CO2 pipelines used for EOR. Although 

compression of CO2 to pipeline pressures is not new, research into more-advanced methods of 

CO2 compression is ongoing because the compression of CO2 requires mechanical energy and 

represents a potentially large auxiliary power load on the overall power plant system (NETL, 

2015e). 

Because CO2 separation typically occurs at low pressure, compression is required to reduce the 

volume flow making transport more practical. Carbon dioxide storage sites for geological 

sequestration require high pressure as well. Given the high volume flows, centrifugal 

compressors are typically employed, especially when the captured CO2 is produced near 

atmospheric pressure. The physics to compress CO2 in a centrifugal compressor is the same as 

any other gas. However, CO2 has unique characteristics compared to other gases that must be 

considered in the compressor design (e.g., the high volume reduction required, avoidance of 

water formation8). Its high molecular weight allows CO2 to be liquefied at relatively high 

temperatures permitting hybrid compression and pumping options (NETL, 2013). 

Compression of CO2 generally occurs in multiple stages before an optimal pressure is achieved 

for transport of the CO2. The gas temperature rises during each stage necessitating cooling 

 

8

 Since CO2 dissolves in water and forms carbonic acid, which is corrosive, strict control of the water content in the 

CO2 stream is essential for safe and efficient operation of the compressor
20 

between stages (Wong, 2006). A centrifugal compressor accommodates changes in volume flow 

several ways. First, the frame size of the compressor can be adjusted (smaller frame size for 

smaller volume flows and higher pressures) (NETL, 2013). For example, in an August 2007 

study conducted for NETL, CO2 compression was accomplished using a six-stage centrifugal 

compressor with inter-stage cooling that required an auxiliary load of approximately 7.5 percent 

of the gross power output of a subcritical pressure, coal-fired power plant (NETL, 2015e). 

Two types of centrifugal compressors typically are used for CO2 compression. The first is an 

integrally geared compressor. It is typically driven by an electric motor that drives a large bullgear which, in turn, drives multiple pinion gears that contain centrifugal compressors on each 

end. The low pressure stages run at lower speeds, and the speed increases for the higher pressure 

stages. The integrally geared design has a separate inlet and exit flange for each stage, permitting 

intercooling between each stage, which can approach isothermal compression and minimize the 

power requirement. The drawback of this design is the sheer size and potential reliability issues 

with the many bearings, seals, and unshrouded impellers. 

A second type of centrifugal compressor, a beam-style compressor, is commonly used in the 

petrochemical and natural gas industry. It can be configured in a straight-through or back-to-back 

configuration (as shown in Figure 10). The back-to-back design permits intercooling between 

the two sections and intercooling between multiple compressor bodies. The beam-style 

compressor contains only two bearings and seals and has demonstrated reliable service in many 

applications including large frame sizes in liquefied natural gas (LNG) applications (up to 78-

inch impellers) and high pressure (up to 15,000 psi). While some intercooling is possible, the 

beam-style design will typically consume more power for a given application. New DOE/NETLsponsored research in internally cooled diaphragms is working to close this gap. In the cooled 

diaphragm concept, the gas is continually cooled after each stage in the flow path through the 

compressor. A cooling jacket insert is used in the diaphragm of each stage to provide continuous 

cooling. Figure 1 shows a conceptual design for an internally cooled compressor. The flow of the 

CO2 is shown in red, while the cooling liquid is shown in blue. 
21 

Figure 10: Multi-Stage Back-to-Back Centrifugal Compressor (left) and Design for an 

Internally Cooled Compressor (right) (NETL, 2013) 

A technology evaluation for CO2 compression was provided in a report for the American Electric 

Power Mountaineer CCS Project (Usher, 2011). The report explained options evaluated for 

compressing the full CO2 product stream from the proposed nominal 235 MWe commercial scale 

application of Alstom’s chilled ammonia process (CAP) at American Electric Power’s 

Mountaineer generating station, in New Haven, West Virginia. The study focused on 

commercially available, integrally-geared, inter-cooled, gas compression systems. The scope of 

the study included all of the equipment required to compress and condition the captured CO2 for 

sequestration. In the end, two arrangements were considered technically and economically 

feasible for implementation on the commercial scale system. Both utilize compression of the 

CO2 to an intermediate condition, followed by variable-speed pumping to the final desired 

injection conditions. The compressor-pump arrangement allows for greater flexibility and higher 

operating efficiency throughout the life of the well, which is important based on the expected 

variability in injection pressure over the life of the injection wells. 

Additional information on compressors and summaries of multiple advanced compression 

research projects (pilot studies) to continue improving the efficiency of CO2 compression as part 

of CCS can be found in NETL 2013. Recent NETL-funded projects researching improvements to 

CO2 compression relevant for CCS include the following: 

• Southwest Research Institute is developing novel compression technology concepts to 

reduce CO2 compression power requirements by 10 percent compared to conventional 

compressor designs. The basic concept is a semi-isothermal compression process 

where the CO2 is continually cooled using an internal cooling jacket rather than using 
22 

conventional interstage cooling. The project has completed thermodynamic (Phase I) 

and prototype testing (Phase II). A full-scale demonstration of a multi-stage, 

internally cooled diaphragm pilot test program (Phase III) was completed in 2014. 

• Lehigh University set out to use systems analysis models to study the benefits of 

improved thermal integration for coal-fired power plants equipped with post- or oxycombustion CO2 capture systems. 

• Ramgen Power Systems is designing and developing a unique compressor technology 

based upon aerospace shock wave compression theory for use as a CO2 compressor. 

A shock wave-based gas turbine engine is also being developed. Ramgen’s 

compressor design features a rotating disk that operates at high peripheral speeds to 

generate shock waves that compress the CO2. Compared to conventional compressor 

technologies, shock compression offers several potential advantages: high 

compression efficiency; high single-stage compression ratios; opportunity for waste 

heat recovery; and low capital cost (NETL, 2015i). 

C. CO2 Transportation Pipeline Infrastructure 

Pipelines are the most economical and efficient method of transporting CO2 from commercial 

CCS facilities geologic storage sinks such as saline formations, coal seams, and oil and gas fields 

(Interagency Task Force, 2010). Technologies for the transport of CO2 through a regionally 

extensive network of CO2 pipelines are in use today. The Pipeline and Hazardous Materials 

Safety Administration (PHMSA) reported that in 2013 there were 5,195 miles of CO2 pipelines 

operating in the United States. (PHMSA, 2015) 

The design, construction, operation, and safety requirements for CO2 pipelines are proven. 

Design considerations for CO2 pipelines include pipeline material selection and fracture control; 

pipeline diameter and depth; valve, seal, elastomer, and pumping material selection; valve 

spacing; and quality considerations, such as composition of the stream. Construction 

requirements and standards are in place to protect pipelines from damage and to maximize the 

integrity of the system over its operating lifespan. See Interagency Task Force, 2010. 

Existing and new CO2 pipelines are comprehensively regulated by the Department of 

Transportation’s Pipeline Hazardous Material Safety Administration. The regulations govern 

pipeline design, construction, operation and maintenance, and emergency response planning. See 

generally 49 CFR 195.2. Additional regulations address pipeline integrity management by 

requiring heightened scrutiny to assure the quality of pipeline integrity in areas with a higher 

potential for adverse consequences. See 49 CFR 195.450 and 195.452. 

In addition to the PHMSA Hazardous Liquid Pipeline Safety Regulations (49 CFR Part 195) 

requirements, industry design standards from the American Society of Mechanical Engineers 

(ASME) and the American Petroleum Institute (API), which are incorporated into 49 CFR Part 

195 by reference, are in place to reduce pipeline risks from CO2 pipeline systems. (Interagency 

Task Force, 2010) 
23 

On-site pipelines are not subject to the Department of Transportation standards, but rather adhere 

to the Pressure Piping standards of the American Society of Mechanical Engineers (ASME B31), 

which the EPA has found would ensure that piping and associated equipment meet certain 

quality and safety criteria sufficient to prevent releases of CO2, such that certain additional 

requirements were not necessary (See 79 FR 358-59 (Jan. 3, 2014)). These existing controls 

over CO2 pipelines assure protective management, guard against releases, and assure that 

captured CO2 will be securely conveyed to a sequestration site. 

 

D. Geologic Sequestration 

Geologic sequestration (GS) – the long-term containment of a CO2 stream in subsurface geologic 

formations – is based on a demonstrated understanding of the processes that affect CO2 fate in 

the subsurface. Sequestration is already well proven. CO2 has been retained underground for 

eons in geologic (natural) repositories and the mechanisms by which CO2 is trapped underground 

are well understood. The physical and chemical trapping mechanisms, along with the regulatory 

requirements and safeguards of the Underground Injection Control (UIC) Program and 

complementary monitoring and reporting requirements of the Greenhouse Gas Reporting 

Program (GHGRP), together ensure that sequestered CO2 will remain secure and provide the 

monitoring to identify and address potential leakage using Safe Drinking Water Act (SDWA) 

and Clean Air Act (CAA) authorities. 

Subsurface formations suitable for GS of CO2 captured from affected EGUs are geographically 

widespread throughout most parts of the United States. GS is technically feasible based on a 

demonstrated understanding of the processes that affect CO2 fate in the subsurface; these 

processes can vary regionally as the subsurface geology changes. GS occurs through a 

combination of trapping mechanisms which are well understood and proven: 

1. Structural and stratigraphic trapping is a physical trapping mechanism that occurs 

when the CO2 reaches a stratigraphic zone with low permeability (i.e., geologic 

confining system) that prevents further upward migration. 

2. Residual trapping is a physical trapping mechanism that occurs as residual CO2 is 

immobilized in formation pore spaces as disconnected droplets or bubbles at the 

trailing edge of the plume due to capillary forces. 

3. Adsorption trapping is another physical trapping mechanism that occurs when CO2

molecules attach to the surfaces of coal and certain organic rich shales, displacing 

other molecules such as methane. 

4. Solubility trapping is a geochemical trapping mechanism where a portion of the CO2

from the pure fluid phase dissolves into native ground water and hydrocarbons. 

5. Mineral trapping is a geochemical trapping mechanism that occurs when chemical 

reactions between the dissolved CO2 and minerals in the formation lead to the 

precipitation of solid carbonate minerals. 

The effectiveness of long-term trapping of CO2 has been demonstrated by natural analogs in a 

range of geologic settings where CO2 has remained trapped for millions of years (Holloway et. 

al, 2007). For example, CO2 has been trapped for more than 65 million years in the Jackson 

Dome, located near Jackson, Mississippi (IPCC, 2005). Other examples of natural CO2 sources 

include Bravo Dome and McElmo Dome in Colorado and New Mexico, respectively. These 
24 

natural storage sites are themselves capable of holding volumes of CO2 that are larger than the 

volume of CO2 expected to be captured from a fossil fuel-fired EGU. In 2010, the DOE 

estimated current CO2 reserves of 594 million metric tons at Jackson Dome, 424 million metric 

tons at Bravo Dome, and 530 million metric tons at McElmo Dome (DiPietro, et. al, 2012). 

GS is feasible in different types of geologic formations including deep saline formations 

(formations with high salinity formation fluids) or in oil and gas formations, such as where 

injected CO2 increases oil production efficiency through a process referred to as enhanced oil 

recovery (EOR). Both deep saline and oil and gas formation types are widely available in the 

United States. Details on the geographic availability of geologic sequestration are provided in 

EPA, 2015. 

Deep saline formations offer the greatest potential storage resource and capacity. These 

formations are sedimentary rock layers that are generally more than 800 meters deep and are 

saturated with waters or brines that have a high total dissolved solids (TDS) content (i.e., over 

10,000 mg/L TDS) (Interagency Task Force, 2010). Deep saline formations are found throughout 

the United States, and many of these formations may be overlain by laterally extensive, 

impermeable formations that restrict upward movement of injected CO2. 

Eight Department of Energy Regional Carbon Sequestration Partnership (RCSP) “Development 

Phase” projects have been initiated and five of the eight projects are injecting or have completed 

CO2 injection into deep saline formations. Three of these projects have already injected more 

than one million metric tons each, and one, the Cranfield Site, injected over eight million metric 

tons of CO2 between 2009 and 2013 (NETL, 2013b). Various types of technologies for 

monitoring CO2 in the subsurface and air have been employed at these projects, such as seismic 

methods (crosswell seismic, 3-D and 4-D seismic, and vertical seismic profiling), atmospheric 

CO2 monitoring, soil gas sampling, well and formation pressure monitoring, and surface and 

ground water monitoring.9 No CO2 leakage has been reported from these sites, which further 

supports the availability of effective GS. 

Enhanced oil recovery (EOR) is a technique that is used to increase the production of oil. 

Approaches used for EOR include steam injection, injection of specific fluids such as surfactants 

and polymers, and gas injection including nitrogen and CO2. EOR using CO2, sometimes 

referred to as “CO2 flooding” or CO2-EOR, involves injecting CO2 into an oil reservoir to help 

mobilize the remaining oil to make it more amenable for recovery. The crude oil and CO2

mixture is then recovered and sent to a separator where the crude oil is separated from the 

gaseous hydrocarbons, native formation fluids, and CO2. The gaseous CO2-rich stream then is 

typically dehydrated, purified to remove hydrocarbons, re-compressed, and re-injected into the 

reservoir to further enhance oil recovery. Not all of the CO2 injected into the oil reservoir is 

recovered and re-injected. As the CO2 moves from the injection point to the production well, 

some of the CO2 becomes trapped in the small pores of the rock, or is dissolved in the oil and 

water that is not recovered. The CO2 that remains in the reservoir is not mobile and becomes 

sequestered. 

 

9

 A description of the types of monitoring technologies employed at RCSP projects can be found at DOE 2015a.
25 

The amount of CO2 used in an EOR project depends on the volume and injectivity of the 

reservoir that is being flooded and the length of time the EOR project has been in operation. 

Initially, all of the injected CO2 is newly received. As the project matures, some CO2 is 

recovered with the oil and the recovered CO2 is separated from the oil and recycled so that it can 

be re-injected into the reservoir in addition to new CO2 that is received. If an EOR operator will 

not require the full volume of CO2 available from an EGU, the EGU has other options such as 

sending the CO2 to other EOR operators, or sending it to deep saline formation GS facilities. 

CO2 used for EOR may come from anthropogenic or natural sources. The source of the CO2 does 

not impact the effectiveness of the EOR operation. CO2 capture, treatment and processing steps 

provide a concentrated stream of CO2 in order to meet the needs of the intended end use. CO2

pipeline specifications of the U.S. Department of Transportation Pipeline Hazardous Materials 

Safety Administration found at 49 CFR part 195 (Transportation of Hazardous Liquids by 

Pipeline) apply regardless of the source of the CO2 and take into account CO2 composition, 

impurities, and phase behavior. Additionally, EOR operators and transport companies have 

specifications related to the composition of the CO2 stream. The regulatory requirements and 

company specifications ensure EOR operators receive a known and consistent CO2 stream. 

EOR has been successfully used at numerous production fields throughout the United States to 

increase oil recovery. The oil industry in the United States has over 40 years of experience with 

EOR. An oil industry study in 2014 identified more than 125 EOR projects in 98 fields in the 

United States (Koottungal, 2014). More than half of the projects evaluated in the study have been 

in operation for more than 10 years, and many have been in operation for more than 30 years. 

This experience provides a strong foundation for demonstrating successful CO2 injection and 

monitoring technologies, which are needed for safe and secure GS that can be used for 

deployment of CCS across geographically diverse areas. 

 

A DOE-sponsored study has analyzed the geographic availability of applying EOR in 11 major 

oil producing regions of the United States and found that there is an opportunity to significantly 

increase the application of EOR to areas outside of current operations (Kuuskraa, 2011). DOEsponsored geologic and engineering analyses show that expanding EOR operations into areas 

additional to the capacity already identified and applying new methods and techniques over the 

next 20 years could utilize 18 billion metric tons of anthropogenic CO2 and increase total oil 

production by 67 billion barrels (Kuuskraa, 2011). The study found that one of the limitations to 

expanding CO2 use in EOR is the lack of availability of CO2 in areas where reservoirs are most 

amenable to CO2 flooding. DOE’s Carbon Utilization and Storage Atlas identifies 29 states with 

oil reservoirs amenable to EOR, 12 of which currently have active EOR operations (NACAP, 

2012). A comparison of the current states with EOR operations and the states with potential for 

EOR shows that an opportunity exists to expand the use of EOR to regions outside of current 

areas. The availability of anthropogenic CO2 in areas outside of current sources could drive new 

EOR projects by making more CO2 locally available. 
26 

Several EOR sites, which have been operated for years to decades, have been studied to evaluate 

the viability of safe and secure long-term sequestration of injected CO2. Examples are identified 

below. 

• CO2 has been injected in the SACROC Unit in the Permian basin since 1972 for EOR 

purposes. One study evaluated a portion of this project, and estimated that the 

injection operations resulted in final sequestration of about 55 million tons of CO2

(Han, 2010). This study used modeling and simulations, along with collection and 

analysis of seismic surveys, and well logging data, to evaluate the ongoing and 

potential CO2 trapping occurring through various mechanisms. The monitoring at this 

site demonstrated that CO2 can become trapped in geologic formations. In a separate 

study in the SACROC Unit, the Texas Bureau of Economic Geology conducted an 

extensive groundwater sampling program to look for evidence of CO2 leakage in the 

shallow freshwater aquifers (Romanak, 2010). No evidence of leakage was detected. 

• The International Energy Agency Greenhouse Gas Programme conducted an 

extensive monitoring program at the Weyburn oil field in Saskatchewan between 

2000 and 2010 (the site receiving CO2 captured by the Dakota Gasification synfuel 

plant discussed later in this document). During that time over 16 million metric tons 

of CO2 were safely sequestered as evidenced by soil gas surveys, shallow 

groundwater monitoring, seismic surveys and wellbore integrity testing. An extensive 

shallow groundwater monitoring program revealed no significant changes in water 

chemistry that could be attributed to CO2 storage operations (Roston, 2010). The 

International Energy Agency Greenhouse Gas Programme developed a best practices 

manual for CO2 monitoring at EOR sites based on the comprehensive analysis of 

surface and subsurface monitoring methods applied over the 10 years (Hitchon, 

2012). 

• The Texas Bureau of Economic Geology also has been testing a wide range of surface 

and subsurface monitoring tools and approaches to document sequestration efficiency 

and sequestration permanence at the Cranfield oilfield in Mississippi (Gulf Coast 

Carbon Center, 2015). As part of a DOE Southeast Regional Carbon Sequestration 

Partnership study, Denbury Resources injected CO2 into a depleted oil and gas 

reservoir at a rate greater than 1.2 million tons/year. Texas Bureau of Economic 

Geology is currently evaluating the results of several monitoring techniques 

employed at the Cranfield project and preliminary findings indicate no impact to 

groundwater (Gulf Coast Carbon Center, 2015). The project also demonstrates the 

availability and effectiveness of many different monitoring techniques for tracking 

CO2 underground and detecting CO2 leakage to ensure CO2 remains safely 

sequestered. 

CO2 may also be used for other types of enhanced recovery, such as for natural gas production. 

Reservoirs such as unmineable coal seams also offer the potential for geologic storage.10

Enhanced coalbed methane recovery is the process of injecting and storing CO2 in unmineable 

 

10 Other types of opportunities include organic shales and basalt.
27 

coal seams to enhance methane recovery. These operations take advantage of the preferential 

chemical affinity of coal for CO2 relative to the methane that is naturally found on the surfaces of 

coal. When CO2 is injected, it is adsorbed to the coal surface and releases methane that can then 

be captured and produced. This process effectively “locks” the CO2 to the coal, where it remains 

stored. 

In 2010, the EPA finalized an effective and coherent regulatory framework to ensure the longterm, secure and safe storage of large volumes of CO2. The EPA developed these Underground 

Injection Control (UIC) Class VI well regulations under authority of the Safe Drinking Water 

Act (SDWA) to facilitate injection of CO2 for GS, while protecting human health and the 

environment by ensuring the protection of underground sources of drinking water (USDWs). The 

Class VI regulations are built upon 35 years of federal experience regulating underground 

injection wells, and many additional years of state UIC program expertise. The EPA and states 

have decades of UIC experience with the Class II program, which provides a regulatory 

framework for the protection of USDWs for CO2 injected for purposes of EOR. 

In addition, to complement both the Class VI and Class II rules, the EPA used CAA authority to 

develop air-side monitoring and reporting requirements for CO2 capture, underground injection, 

and geologic sequestration through the GHGRP. Information collected under the GHGRP 

provides a transparent means for the EPA and the public to continue to evaluate the effectiveness 

of GS. 

Under SDWA, the EPA developed the UIC Program to regulate the underground injection of 

fluids in a manner that ensures protection of USDWs. UIC regulations establish six different well 

classes that manage a range of injectates (e.g., industrial and municipal wastes; fluids associated 

with oil and gas activities; solution mining fluids; and CO2 for geologic sequestration) and which 

accommodate varying geologic, hydrogeological, and other conditions. 

In 2010, the EPA established a new class of well, Class VI. Class VI wells are used to inject CO2

into the subsurface for the purpose of long-term sequestration. See 75 FR 77230 (Dec. 10, 2010). 

This rule accounts for the unique nature of CO2 injection for large-scale GS. Specifically, the 

EPA addressed the unique characteristics of CO2 injection for GS including the large CO2

injection volumes anticipated at GS projects, relative buoyancy of CO2, its mobility within 

subsurface geologic formations, and its corrosivity in the presence of water. The UIC Class VI 

rule was developed to facilitate GS and ensure protection of USDWs from the particular risks 

that may be posed by large scale CO2 injection for purposes of long-term GS. The Class VI rule 

establishes technical requirements for the permitting, geologic site characterization, area of 

review (i.e., the project area) and corrective action, well construction, operation, mechanical 

integrity testing, monitoring, well plugging, post-injection site care, site closure, and financial 

responsibility for the purpose of protecting USDWs.

The EPA has issued Class VI permits for six wells under two projects. 

• In September 2014, a UIC Class VI injection well permit (to construct) was issued by 

the EPA to Archer Daniels Midland for an ethanol facility in Decatur, Illinois. The 

goal of the project is to demonstrate the ability of the Mount Simon geologic 

formation, a deep saline formation, to accept and retain industrial scale volumes of 
28 

CO2 for permanent GS. The permitted well has a projected operational period of five 

years, during which time 5.5 million metric tons of CO2 will be injected into an area 

of review with a radius of approximately 2 miles.11 Following the operational period, 

Archer Daniels Midland plans a post-injection site care period of ten years.12 

• In September 2014, the EPA also issued four Class VI injection well permits (to 

construct) to the FutureGen Industrial Alliance project in Jacksonville, Illinois, which 

proposed to capture CO2 emissions from a coal-fired power plant in Meredosia, 

Illinois and transport the CO2 by pipeline approximately 30 miles to the deep saline 

GS site.13 The Alliance proposed to inject a total of 22 million metric tons of CO2 into 

an area of review with a radius of approximately 24 miles over the 20 year life of the 

project, with a post-injection site care period of fifty years.14 

The CO2 injection wells used for EOR are regulated through the UIC Class II program. 40 CFR 

§144.6(b). CO2 storage associated with Class II wells is a common occurrence and CO2 can be 

safely stored where injected through Class II-permitted wells for the purpose of enhanced oil or 

gas-related recovery. UIC Class II regulations issued under section 1421 of SDWA provide 

minimum federal requirements for site characterization, area of review, well construction (e.g., 

casing and cementing), well operation (e.g., injection pressure), injectate sampling, mechanical 

integrity testing, plugging and abandonment, financial responsibility, and reporting. Class II 

wells must undergo periodic mechanical integrity testing which will detect well construction and 

operational conditions that could lead to loss of injectate and migration into USDWs. 

In addition, to complement the Class II and VI rules, the EPA used CAA authority to develop 

air-side monitoring and reporting requirements for CO2 capture, underground injection, and 

geologic sequestration through the Greenhouse Gas Reporting Program (GHGRP) found in 40 

CFR Part 98. Information collected under the GHGRP provides a transparent means for the EPA 

and the public to continue to evaluate the effectiveness of GS. 

Subpart PP of the GHGRP (40 CFR 98.420 - 98.428) provides requirements to account for CO2

supplied to the economy. This subpart requires affected facilities with production process units 

that capture a CO2 stream for purposes of supplying CO2 for commercial applications or that 

capture and maintain custody of a CO2 stream in order to sequester or otherwise inject it 

underground to report the mass of CO2 captured and supplied to the economy. CO2 suppliers are 

required to report the annual quantity of CO2 transferred offsite and its end use, including GS. 

Reporting under subpart RR (40 CFR 98.440 - 98.449) is required for all facilities that have 

received a Class VI UIC permit for injection of CO2. Subpart RR requires facilities meeting the 

source category definition (40 CFR 98.440) for any well or group of wells to report basic 

 

11 http://www.epa.gov/region5/water/uic/adm/. In addition, Archer Daniels Midland received a UIC Class VI 

injection well permit for a second well in December 2014. Archer Daniels Midland had been injecting CO2 at this 

well since 2011 under a UIC Class I permit issued by the Illinois EPA. 

12 http://www.epa.gov/region5/water/uic/adm/.

13 After permit issuance, and for reasons unrelated to the permitting proceeding, DOE initiated a structured closeout 

of federal support for the FutureGen project in February 2015. However, these are still active Class VI permits. 

14 http://www.epa.gov/r5water/uic/futuregen/.
29 

information on the mass of CO2 received for injection; develop and implement an EPA-approved 

monitoring, reporting, and verification (MRV) plan; report the mass of CO2 sequestered using a 

mass balance approach; and report annual monitoring activities. The subpart RR MRV plan 

includes five major components: 

1. A delineation of monitoring areas based on the CO2 plume location. Monitoring may 

be phased in over time. 

2. An identification and evaluation of the potential surface leakage pathways and an 

assessment of the likelihood, magnitude, and timing, of surface leakage of CO2

through these pathways. The monitoring program will be designed to address the 

risks identified. 

3. A strategy for detecting and quantifying any surface leakage of CO2 in the event 

leakage occurs. Multiple monitoring methods and accounting techniques can be used 

to address changes in plume size and risks over time. 

4. An approach for establishing the expected baselines for monitoring CO2 surface 

leakage. Baseline data represent pre-injection site conditions and are used to identify 

potential anomalies in monitoring data. 

5. A summary of considerations made to calculate site-specific variables for the mass 

balance equation. Site-specific variables may include calculating CO2 emissions from 

equipment leaks and vented emissions of CO2 from surface equipment, and 

considerations for calculating CO2 from produced fluids. 

Monitoring programs conducted at international GS projects provide examples where large 

volumes of CO2 have been safely injected and securely sequestered for long periods of time at 

volumes and rates consistent with those expected from CCS at EGUs. This experience has also 

demonstrated the value and efficacy of monitoring programs to determine the location of CO2 in 

the subsurface and detect potential leakage through the presence of CO2 in the shallow 

subsurface, near surface and air. 

The Sleipner CO2 Storage Project is located at an offshore gas field in the North Sea where CO2

must be removed from the natural gas in order to meet customer requirements and reduce costs. 

The project began injecting CO2 into the deep subsurface in 1996. The single offshore injection 

well injects approximately 1 million metric tons per year into a thick, permeable sandstone above 

the gas producing zone. Approximately 15 million metric tons of CO2 have been injected since 

inception. Many U.S. and international organizations have conducted monitoring in conjunction 

with the Sleipner CO2 Storage Project. The location and dimensions of the CO2 plume have been 

measured numerous times using 3-dimensional seismic monitoring since the 1994 pre-injection 

survey. The monitoring data have demonstrated that although the plume is behaving differently 

than initially modeled due to thin layers of impermeable shale that were not initially identified in 

the reservoir model, the CO2 remains trapped in the injection zone. Numerous other techniques 

have been successfully used to monitor CO2 storage at Sleipner. The research and monitoring at 

Sleipner demonstrates the value of a comprehensive approach to site characterization, 

computational modeling and monitoring, as is required under UIC Class VI rules. The 

experience at Sleipner demonstrates that large volumes of CO2, of the same order of magnitude 

expected for an EGU, can be safely injected and stored in saline reservoirs over an extended 

period. 
30 

Snøhvit is another large offshore CO2 storage project, located at a gas field in the Barents Sea. 

Like Sleipner the natural gas must be treated to reduce high levels of CO2 to meet processing 

standards and reduce costs. Gas is transported via pipeline 95 miles to a gas processing and 

liquefied natural gas plant and the CO2 is piped back offshore for injection. Approximately 0.7 

million metric tons per year CO2 are injected into permeable sandstone below the gas reservoir. 

Between 2008 and 2011, the operator observed pressure increases in the injection formation 

(Tubaen Formation) greater than expected and conducted time lapse seismic surveys and studies 

of the injection zone and concluded that the pressure increase was mainly caused by a limited 

storage capacity in the formation (Grude et al., 2014). In 2011, the injection well was modified 

and injection was initiated in a second interval (Stø Formation) in the field to increase the storage 

capacity. 

CO2 from the Great Plains Synfuels plant in North Dakota has been injected into the Weyburn oil 

field in Saskatchewan Canada since 2000. The Great Plains Synfuels plant is discussed later in 

this document. It is anticipated that approximately 40 million metric tons of CO2 will be 

permanently sequestered over the lifespan of the project. Extensive monitoring by U.S. and 

international partners has demonstrated that no leakage has occurred. 

At the In Salah CO2 storage project in Algeria, CO2 is removed from natural gas produced at 

three nearby gas fields in order to meet export quality specification. The CO2 is transported by 

pipeline approximately 3 miles to the injection site. Three horizontal wells are used to inject the 

CO2 into the down-dip aquifer leg of the gas reservoir approximately 6,200 feet deep. Between 

2004 and 2011 over 3.8 million metric tons of CO2 were stored. Injection rates in 2010 and 2011 

were approximately 1 million metric tons per year. Storage integrity has been monitored by 

several US and international organizations and the monitoring program has employed a wide 

range of geophysical and geochemical methods, including time lapse seismic, microseismic, 

wellhead sampling, tracers, down-hole logging, core analysis, surface gas monitoring, 

groundwater aquifer monitoring and satellite data. The data have been used to support periodic 

risk assessments during the operational phase of the project. In 2010 new data from seismic, 

satellite and geomechanical models were used to inform the risk assessment and led to the 

decision to reduce CO2 injection pressures due to risk of vertical leakage into the lower caprock, 

and risk of loss of well integrity. The caprock at the site consisted of main caprock units, 

providing the primary seal, and lower caprock units, providing additional buffers. There was no 

leakage from the well or through the caprock, but the risk analysis identified an increased risk of 

leakage, therefore, the aforementioned precautions were taken. Additional analysis of the 

reservoir, seismic and geomechanical data led to the decision to suspend CO2 injection in June 

2011. No leakage has occurred and the injected CO2 remains safely stored in the subsurface. The 

decision to proceed with safe shutdown of injection resulted from the analysis of seismic and 

geomechanical data to identify and respond to storage site risk. The Salah project demonstrates 

the value of developing an integrated and comprehensive set of baseline site data prior to the 

start of injection, and the importance of regular review of monitoring data. 

Even though potentially adverse conditions were identified at some projects (In Salah and 

Snøhvit), there were no releases to air and the monitoring systems were effective in identifying 

the issues in a timely manner, and these issues were addressed effectively. In each case, the sitespecific characteristics were evaluated on a case-by-case basis to select a site where the geologic 
31 

conditions are suitable to ensure long-term, safe storage of CO2. Each project was designed to 

address the site-specific characteristics and operated to successfully inject CO2 for safe storage. 

In summary, the different regulatory components, already in place, assure the safety and 

effectiveness of GS. The effective regulatory structure complements the analysis of the technical 

feasibility of GS, which together affirm that the technical feasibility of GS is adequately 

demonstrated. 

E. Alternatives to Geologic Sequestration 

Potential alternatives to storing CO2 in geologic formations are emerging. Applications where 

captured anthropogenic CO2 is converted to a useable product may offer the opportunity to offset 

the cost of CO2 capture. Examples of CO2 utilization include: 

Carbonation/mineralization: Alkaline earth oxides react with CO2 to create insoluble carbonates. 

The carbonate materials produced can be tailored to optimize performance in specific industrial 

and commercial applications such as for use in construction or cement manufacture. For 

example: 

• Precipitated calcium carbonate (PCC) is produced through a chemical reaction 

process that uses calcium oxide (quicklime), water, and CO2. Some pulp and paper 

manufacturers supply anthropogenic CO2 from process exhausts to nearby PCC 

producers, which in turn supply PCC for use in paper manufacturing (40 CFR part 98, 

subpart PP). 

• The combination of magnesium oxide and CO2 results in a precipitation reaction 

where the CO2 becomes mineralized. 

• The Skyonics Skymine project, which opened its demonstration project in October 

2014, captures over 75,000 tons of CO2 annually from a San Antonio, Texas, cement 

plant and converts the CO2 into other products, including sodium carbonate, sodium 

bicarbonate, hydrochloric acid and bleach (Skymine, 2015). 

• Other companies – including Calera and New Sky – also offer commercially available 

technology for the beneficial use of captured CO2 (Calera, 2015; New Sky, 2015). 

Bio-fuel production using algae: Plants convert CO2 and water into starch using sunlight during 

the photosynthesis process. Although more advanced plants are not very effective in conversion 

of large quantities of CO2, micro-algae can use high concentrations of CO2 to create starch. The 

biomass product can be used to recycle CO2 into valuable industrial fuel such as methane, 

methanol, hydrogen and bio-diesel. 

Fuel production: Most carbon-based fuels are made up of carbon, hydrogen, and oxygen. CO2

can be hydrogenated in the presence of a catalyst to create low-carbon-chain fuel such as 

methanol. Procuring hydrogen requires energy for hydrolysis of water or partial oxidation of 

natural gas. 
32 

Chemical synthesis: Ceramics, fertilizers, rubber, and many other small-scale industries require 

CO2 at some stage of their manufacturing process. The largest use of CO2 in this area is in 

fertilizer plants, where CO2 is captured from the exhaust gases of NH3 reformer units and used to 

manufacture urea. 

CO2 utilization is a promising research area. There are currently no plenary systems of 

regulatory control and GHG reporting for these approaches, as there are for geologic 

sequestration. Nonetheless, CO2 utilization technologies not only show promise, but could 

potentially be demonstrated to show permanent storage of CO2. 

F. Continuing Research and Policy Development 

Climate science and climate change mitigation options – including CCS - are the subject of great 

academic interest and a large body of academic literature on the subjects exits. In addition, other 

research organizations (e.g., U.S. national laboratories and others) have also published studies on 

these subjects. 

The Thomson Reuters Web of Science database is a comprehensive source of academic 

publications from around the world. As a metric to gauge global interest and progress in CCS 

technologies, EPA conducted a search of the database using the keywords "carbon capture" and 

"carbon capture and sequestration" and searching by the title of the paper. After conducting the 

search, the data was sorted by year in order to create a timeline of CCS development. The results 

of this search are shown in Figure 11 below. The number of publications regarding CCS has 

grown dramatically in the past decade, from only 7 papers in 2004 to 147 publication in 2014, 

with a peak of 205 publications in 2013. 

In order to corroborate this trend, EPA also conducted a search using the U.S. patent database, 

using the keywords "Carbon Capture". The results of this search were segmented by year, and 

are shown in Figure 12 below. As with the publications, the number of patents issued regarding 

CCS technology has increased rapidly over the past decade, beginning in 2007. The number of 

patents issued peaked in 2014, with 160 patents issued. Both The U.S. patent office and 

Thomson Reuters confirm that industry and academia are both working towards technological 

advancements in all stages of CCS. 
33 

Figure 11. Number of Publications Regarding CCS per Year 

Figure 12. Number of Patents Regarding CCS per Year

Research is underway to reduce CO2 capture costs and to improve performance. The DOE/NETL 

sponsors an extensive research, development and demonstration program that is focused on 

developing advanced technology options that will dramatically lower the cost of capturing CO2

from fossil fuel energy plants compared to currently available capture technologies. The large0

50

100

150

200

250

2000 2002 2004 2006 2008 2010 2012 2014 2016

Number of Publications

Year

Number of Publications by year (2001-2014)

0

20

40

60

80

100

120

140

160

180

2002 2004 2006 2008 2010 2012 2014 2016

Number of Publications

Year

Number of Patents by year (2004-2014)
34 

scale CO2 capture demonstrations that are currently planned and in some cases underway, under 

DOE’s initiatives, as well as other domestic and international projects, will generate operational 

knowledge and enable continued commercialization and deployment of these technologies. The 

CCS Global Consortium and National Carbon Capture Center are examples of organizations 

dedicated to accelerating commercial CCS. 

SaskPower created the CCS Global Consortium (http://www.saskpowerccs.com/consortium/) to 

share the knowledge and experience from the Boundary Dam Unit #3 facility with global energy 

leaders, technology developers, and project developers. SaskPower, in partnership with 

Mitsubishi and Hitachi, is also helping to advance CCS knowledge and technology development 

through the creation of the Shand Carbon Capture Test Facility (CCTF) (SaskPower, 2015a). 

The test facility will provide technology developers with an opportunity to test new and 

emerging carbon capture systems for controlling carbon emissions from coal-fired power plants. 

The National Carbon Capture Center at the Power Systems Development Facility 

(PSDF) in Wilsonville, Alabama is a consortium between DOE/NETL and electric power 

producers offering a world-class test facility and a highly specialized staff to accelerate the 

commercialization of advanced technologies and enable fossil-fuel based power plants to achieve 

near-zero emissions. The NCCC was established in 2009 to build on the experience, expertise, 

and infrastructure in place at the PSDF, which has been in operation since 1996. In undertaking 

its mission, the NCCC is involved in a range of activities to develop the most promising 

technologies for future commercial deployment, thereby maximizing the impact of project funds. 

A large portion of NCCC research is focused on development of post-combustion CO2 capture 

for incorporation into pulverized coal power plants and pre-combustion CO2 capture for 

integration into the new generation of coal gasification power plants. Post-combustion and precombustion CO2 capture work has included multiple projects, such as testing of solvents, 

enzymes, gas separation membranes, sorbents, and catalysts, as well as other novel processes. 

The testing has supported technology developers from both industry and universities, and in 

many cases has yielded the bases for process improvements and scale-ups (Northington, et al., 

2012). 

In addition to research underway to accelerate commercial carbon capture, research is also 

underway to advance commercial use of geologic sequestration. The DOE has created a network 

of seven Regional Carbon Sequestration Partnerships (RCSPs) to deploy large-scale field 

projects in different geologic settings across the country to demonstrate that GS can be achieved 

safely, permanently, and economically at large scales. Collectively, the seven RCSPs represent 

regions encompassing 97 percent of coal-fired CO2 emissions, 97 percent of industrial CO2

emissions, 96 percent of the total land mass, and essentially all the geologic sequestration sites in 

the United States potentially available for GS (DOE, 2015a). The seven partnerships include 

more than 400 organizations spanning 43 states (and four Canadian provinces) (DOE, 

2015a). RCSP project objectives are to inject at least one million metric tons of CO2. In April 

2015, DOE announced that CCS projects supported by the department have safely and 

permanently stored 10 million metric tons of CO2 (DOE, 2015b). 
35 

In addition to Federal initiatives, multiple states have established emission performance 

standards or other measures to limit emissions of GHGs from new EGUs. The emission levels 

established by these standards would effectively require CCS. For example, 

• In September 2006, California Governor Schwarzenegger signed into law Senate Bill 

1368. The law limits long-term investments in base load generation by the state’s 

utilities to power plants that meet an emissions performance standard jointly 

established by the California Energy Commission and the California Public Utilities 

Commission. The Energy Commission has designed regulations that establish a 

standard for new and existing base load generation owned by, or under long-term 

contract to publicly owned utilities, of 1,100 lb CO2/MWh. 

• In May 2007, Washington Governor Gregoire signed Substitute Senate Bill 6001, 

which established statewide GHG emissions reduction goals, and imposed an 

emission standard that applies to any base load electric generation that commenced 

operation after June 1, 2008 and is located in Washington, whether or not that 

generation serves load located within the state. Base load generation facilities must 

initially comply with an emission limit of 1,100 lb CO2/MWh. 

• In July 2009, Oregon Governor Kulongoski signed Senate Bill 101, which mandated 

that facilities generating base load electricity, whether gas- or coal-fired, must have 

emissions equal to or less than 1,100 lb CO2/MWh, and prohibited utilities from 

entering into long-term purchase agreements for base load electricity with out-of-state 

facilities that do not meet that standard. 

• New York established emission standards of CO2 at 925 lb CO2/MWh for new and 

expanded base load fossil fuel-fired plants. 

• In May 2007, Montana Governor Schweitzer signed House Bill 25, adopting a CO2

emissions performance standard for EGUs in the state. House Bill 25 prohibits the 

state Public Utility Commission from approving new EGUs primarily fueled by coal 

unless a minimum of 50 percent of the CO2 produced by the facility is captured and 

sequestered. 

• On January 12, 2009, Illinois Governor Blagojevich signed Senate Bill 1987, the 

Clean Coal Portfolio Standard Law. The legislation establishes emission standards for 

new power plants that use coal as their primary feedstock. From 2009–2015, new 

coal-fueled power plants must capture and store 50 percent of the carbon emissions 

that the facility would otherwise emit; from 2016–2017, 70 percent must be captured 

and stored; and after 2017, 90 percent must be captured and stored. 

II. Facilities Utilizing CCS 

Many industries, including the power generation industry, are beginning to incorporate CCS into 

their plant designs. In the U.S. and abroad, multiple CCS projects are in various stages of 

development, from research and planning to currently operating pilot- and full-scale systems. 

Some of these projects are described in greater detail below. It should be noted that this section 

only highlights some of the major examples of CCS implementation, and should not be 

considered an exhaustive list of all CCS projects. 
36 

A. Post-combustion 

Table 2 lists seven facilities that have experience with post-combustion CO2 capture projects, 

including six EGUs and one soda ash production facility. Each project is briefly summarized in 

the following subsections. 

 
37 

Table 2. Summary of Post-combustion Carbon Capture and Storage Projects 

Project Name 

Domestic or International Location 

Facility type Unit type 

Capture details 

Date began operation (Date ended operation if ended) 

Amount of CO2 captured (metric tons/yr) 

Tranrt de

AEP/Alstom - Mountaineer Project Domestic 

New Haven, West Virginia EGU 

Coal-fired power plant (30 MW slipstream) 

Full (>90%) CCS 2009 100,000 Pipel

AES - Shady Point Domestic 

Panama, Oklahoma EGU 

Coal-fired power plant (320 MW) 

Partial (<10%) 1991 66,000 

Not transed 

AES - Warrior Run Domestic 

Cumberland, Maryland EGU 

Coal-fired power plant (180 MW) 

Partial (<10%) 2000 110,000 

Not transed 

Petra Nova - W.A. Parish Domestic 

Houston, Texas EGU 

Coal-fired power plant (240 MW slip steam) 

Full (>90%) CCS 

2017 (under construction) 

1,600,000 Pipel

SaskPower - Boundary Dam Unit #3 International 

Estevan, Saskatchewan, Canada EGU 

IGCC power plant (110 MW) 

Full (>90%) CCS 

October, 2014 

1,000,000 Pipel
38 

Searles Valley Minerals Domestic 

Trona, California 

Soda Ash 

Coal-fired power plant generating steam/power for onsite use 

Postcombustion amine scrubbing 1978 264,898 

NA: onsit

Fluor Corp. – Bellingham Domestic 

Bellingham, Massachusetts EGU 

Natural Gasfired power plant (40 MW slipstream of a 320 MW plant)

Full (>90%) CCS 

1991 (2005) 100,000 

Not transed 
39 

1. AEP/Alstom - Mountaineer Project 

AEP began a pilot CCS project at its Mountaineer Plant in New Haven, West Virginia in 

September, 2009. The project was a 20 MWe slipstream of the 1,300 MW plant, capturing 

100,000 metric tons CO2/year which was sequestered 1.5 miles underground in the neighboring 

Mount Simon Sandstone deposits. The project was initially planned to expand to 235 MW, with 

150,000 metric tons CO2/year, a 90% capture rate; however, uncertain federal climate regulation 

discouraged AEP from continuing the project (MIT, Mountaineer Fact Sheet, 2015). 

2. AES – Shady Point/Warrior Run 

The Shady Point (Panama, OK) and Warrior Run (Cumberland, MD) power plants use 

circulating fluidized bed reactors, and amine scrubbers developed by ABB/Lummus to capture 

CO2. Warrior Run began operations in 2000, and produces 180 MW of electricity along with 

steam for the CO2 production unit. The plant captures about 10% of its CO2 emissions, which are 

removed post-combustion via a slipstream (IEAGHG RD&D Database, 2013). Shady Point 

operates in a similar manner, except on a larger scale. The plant produces 320 MW, and has been 

operating since 1991. Shady Point extracts about 66,000 metric tons CO2/day from the flue gas, 

which is purified to food grade levels in the CO2 processing plant. The captured CO2 from the 

Shady Point and Warrior Run plants is purified and used in food-processing and other industrial 

applications like fire extinguishers (NETL, What Carbon Capture Technologies are in Use 

Today). 

3. Fluor Corp. – Bellingham 

 

 The Bellingham, Massachusetts CCS project, which incorporated the Fluor Ecomaine 

process described in section I, ran from 1991 to 2005 (Global CCS Institute, 2013). The project 

was a 40 MW slipstream of the 320 MW plant, capturing over 90% of CO2 emissions totaling 

100,000 metric tons of CO2/day. This plant is unique in that it was an NGCC incorporating CCS 

into its operations. The CO2 was sold for use in the beverage industry, as opposed to geologic 

sequestration (Bernton, 2014). 

4. Petra Nova – W. A. Parish 

The W.A. Parish CCS project near Houston, Texas will be the world's largest post-combustion 

CCS retrofit once it begins operation in 2017. The plant is a joint venture between NRG and JX 

Nippon Oil & Gas Exploration. Captured CO2 will be used for EOR in the Gulf Coast region. 

The unit will collect 90% of the emitted CO2 from a 240 MW slipstream of the 610 MW facility, 

for a total of 1.4 million metric tons CO2/year. The CO2 capture technology is provided by 

Kansai Mitsubishi, which has had CO2 capture technology in commercial use since 1999, and 

currently is operating at 11 facilities across the globe (NRG Energy Inc., 2015). The plant will 

utilize a high-performance solvent, which was tested at a pilot-scale project at the Alabama 
40 

Power Barry plant, which is described below. The project began as a 60 MW slipstream 

demonstration and received DOE Clean Coal Power Initiative funding on that basis, however, 

the project was later expanded to the 240 MW slipstream due to the need to capture larger 

volumes of CO2 for EOR operations. 

5. SaskPower – Boundary Dam Unit #3 

The Boundary Dam CCS project is the first commercial-scale post-combustion CCS plant in the 

world. Located in Saskatchewan, Canada, the Boundary Dam project incorporates EOR and 

Geological Sequestration into their operations, which began in October of 2014. Although 

initially only capturing 75% of CO2, currently the unit produces 110 MW net (139 MW gross) of 

electricity, with 90% CO2 capture totaling 1 million metric tons CO2/year at a purity of over 

99.999% (Monea, 2014). The plant uses a Shell Cansolv amine-based solvent to capture CO2, 

which comes from local Saskatchewan lignite coal. In order to mitigate the cost of the retrofit, 

SaskPower sells the CO2 to an oil drilling company for use in EOR and eventual sequestration, 

and to other industries for commercial use. The balance of unsaleable CO2 is sequestered. The 

plant also sells sulphuric acid and fly ash for added revenue (Hussain, 2014). CO2 that is not 

used in EOR is immediately stored in deep brine-filled sandstone formations Additionally, initial 

indications are that the generation side is producing more power than estimated and that the 

energy penalty (parasitic load) is much lower than expected (Monea, 2015). 

6. Searles Valley Minerals – Trona Soda Ash Plant 

The Searles Valley Minerals soda ash plant in Trona, Ca, is the longest running carbon capture 

project in the U.S. The plant has been capturing CO2 via post-combustion amine scrubbing since 

1978. This CO2 comes from the flue gas from a coal-fired power boiler generating steam and 

electricity for onsite use. The CO2 is used to for carbonation reactions to produce soda ash. Since 

its inception, the soda ash plant has collected roughly 270,000 metric tons of CO2 per year (EPA, 

2014). 

B. Pre-combustion 

Table 3 contains 11 facilities that are in various stages of pre-combustion CO2 capture projects, 

including nine EGUs, a fertilizer manufacturing plant, and a coal gasification facility. Each 

project is briefly summarized in the following subsections. 
41 

Table 3. Pre-combustion Carbon Capture and Storage Projects 

Project Name 

Domestic or International Location Facility type Unit type 

Capture details 

Date began operation (Date ended operation if ended) 

Amount of CO2 captured (metric tons/yr) 

Trandetail

2Co Energy - Don Valley Power Project International 

South Yorkshire, United Kingdom EGU 

920 MW (Gross), 650 MW (Net) 

Full (>90%) CCS 

2018/2019 (Planning Phase) 5,000,000 Pipeli

CVR Energy/Chaparral Energy - Coffeyville Fertilizer Plant Domestic 

Coffeyville, Kansas 

Fertilizer Plant Not EGU 2013 1,000,000 Pipeli

Dakota Gasification - Great Plains Synfuels Plant Domestic 

Beulah, North Dakota 

Coal Gasification Plant 

Coal Gasifier 

Partial (50%) 

1984 (began operation) 2000 (began CCS) 3,000,000 Pipeli

ELCOGAS, S.A. - Puertollano International 

Puertollano, Spain EGU 

IGCC (14 MW Slipstream) 

Full (>90%) CCS 2010 365,000 

Not transp

Emirates Steel Industries - Abu Dhabi International 

Abu Dhabi, United Arab Emirates EGU 

IGCC (~228 MW) 

Full (>90%) CCS 

2016 (under construction) 800,000 Pipeli

Huaneng - GreenGen IGCC Project International 

Tianjin City, Bohai Rim, China EGU 

IGCC (400 MW) 

Partial (>80%) 

2020 (currently testing pilot) 2,000,000 Pipeli

Southern Company - Kemper County Domestic 

De Kalb, Mississippi EGU 

IGCC power plant (582 MW) 

Partial (65%) 

2016 (construction completed, currently testing) 3,500,000 Pipeli

Southern Compnay - Barry Plant Domestic 

Mobile, Alabama EGU 

Coal-fired power plant (25 MW slipstream) 

June 2011 (capture) 2012 (storage) 150,000 Pipeli
42 

Project Name 

Domestic or International Location Facility type Unit type 

Capture details 

Date began operation (Date ended operation if ended) 

Amount of CO2 captured (metric tons/yr) 

Trandetail

Summit Power - Caledonia International 

Caledonia, Scotland, the United Kingdom EGU 

IGCC (570 MW) 

Full (>90%) CCS 

2022 (under construction) 3,800,000 Pipeli

Summit Power - Texas Clean Energy Project (TCEP) Domestic 

Odessa, Texas EGU 

IGCC (400 MW) 

Full (>90%) CCS 2019 3,000,000 Pipeli

Vattenfall/Nuon - Willem-Alexander Power Plant International 

Buggenum, the Netherlands EGU 

IGCC (20 MW Slipstrem) 

Full (>90%) CCS 2011 

Not provided 

Not transp
43 

1. CVR Energy/Chaparral Energy - Coffeyville Fertilizer Plant 

Chaparral Energy and Coffey Resources Nitrogen Fertilizers, a subsidiary of CVR Energy, have 

joined to capture and sequester roughly 1 million metric tons CO2/year using pre-combustion 

technology. Chaparral manages the compression, dehydration, and transportation facilities, while 

CVR owns the carbon and carbon capture sources. This retrofit, completed in 2013, allows the 

partnership to sell CO2 for use in EOR operations 112 km (70 miles) away (MIT, Coffeyville 

Fact Sheet, 2015). The plant utilizes absorption physical solvent-based process using Selexol for 

CO2 separation. Similar to an IGCC, the plant gasifies petroleum coke to create a hydrogen-rich 

syngas from which the CO2 is removed. The syngas is used to synthesize ammonia and urea 

ammonium nitrate fertilizers instead of being used for energy production (Chaparral Energy, 

2015). 

2. Dakota Gasification – Great Plains Synfuels Plant 

Located in Beulah, ND, the Great Plains Synfuels Plant began operations in 1984 and later added 

CCS operations in the year 2000. The plant consumes roughly 18,000 tons of North Dakota 

lignite coal each day and captures about 3 million metric tons of CO2 per year, which is the most 

CO2 captured from conversion at any facility of the world (Dakota Gasification Company, Great 

Plains Synfuels Plant, 2015). Although not an EGU, the processes at a coal gasification plant are 

very similar to those at an IGCC. Dakota Gasification uses a Rectisol® system to capture CO2

before the gasified coal is converted into synthetic natural gas (i.e., methane) via a methanation 

process (EPA, 2014). The CO2 captured at the plant is sold to drilling companies for EOR and 

permanent sequestration in Saskatchewan, Canada as part of the Weyburn CO2 Monitoring and 

Storage project, which is overseen by the International Energy Agency (IEA). The plant exports 

about 8,000 metric tons CO2/day, which is about 50% of the CO2 generated at the facility. As of 

December 31st, 2012, the facility had captured more than 24.5 million metric tons of CO2, 

demonstrating how CCS can be used long term to reduce emissions (EPA, 2014). 

3. ELCOGAS, S.A. – Puertollano 

Another pilot-scale project, located at the ELCOGAS Puertollano plant in Spain, was one of the 

first pre-combustion IGCC CCS pilot plants in the world when it began operations in 2008. The 

plant uses a slip stream to test a small scale (14 MW) IGCC unit. The plant captured its first 

metric ton of CO2 by 2010, and has since captured over 1,000 metric tons of CO2. The project 

has also produced over 6 metric tons of H2, as part of the project's stated goal to "obtain 

economic data enough to scale [the project] to the full Puertollano IGCC capacity in synthetic 

gas production." The Puertollano plant is part of a larger, Spanish national initiative to 

investigate advanced CCS technologies, including geological sequestration and oxy-fuel 

combustion (ELCOGAS, 2014). 

4. Emirates Steel Industries – Abu Dhabi 
44 

The United Arab Emirates' first CCS project is an ambitious 800,000 metric tons CO2/year 

facility operating adjacent to a steel mill in Abu Dhabi. Set to begin operations in 2016, this 

facility will process a 90% pure CO2 stream from the steel plant before piping it to an oil field 

for EOR 50 kilometers away (Masdar, 2015). The Abu Dhabi Future Energy Company and the 

Abu Dhabi National Oil Company decided to continue with the project after completing a 2 year 

pilot plant study which ended in 2011 (Evans, 2008). The plant is expected to produce around 

225 MW per year (Carvalho, 2011). 

5. Huaneng – GreenGen IGCC Project 

Scheduled to begin operations in 2020, Huaneng's GreenGen IGCC project is poised to be the 

largest EGU CCS project in Southeast Asia. The plant aims to capture 2 million metric tons 

CO2/year, which will come from sub-bituminous coal coming primarily from China. The plant 

will provide 400 MW of electricity at this new plant, the largest of its kind in China and one of 

the largest in the world. However, first it will operate as a 250 MW IGCC while CO2 capture 

technology is tested and developed. The facility will operate as a pre-combustion CCS plant, 

utilizing an amine chemical solvent-based process. (Global CCS Institute, 2011) 

6. Southern Company/Mississippi Power – Kemper County 

The Kemper County IGCC CCS project completed construction in late 2013 and is currently in 

the "startup and testing" phase, with plans to begin commercial operation in 2016. This facility, 

located in Kemper County, Mississippi, will provide 582 MW of lignite coal-based power while 

collecting 3.5 million metric tons CO2/year. Kemper County uses Pre-combustion IGCC 

technology, with unique CCS technology designed by KBR to provide 65% capture. 

Additionally, KRG designed (TRIGTM) gasification technology to more efficiently convert 

lignite coal into syngas for combustion. The TRIGTM is "an advanced pressurized circulating 

fluidized bed gasifier that operates at moderate temperatures (1,500-1950°F)" (Ariypadi, 2008). 

The TRIGTM can utilize both oxy-fuel and ambient air as combustion sources to mix with the 

lignite coal. The plant also utilizes SelexolTM, a solvent that has also been used extensively for 

acid gas removal, including CO2, for decades (Mississippi Power Company, 2009). 

7. Southern Company/Mitsubishi Heavy Industries (MHI) – Barry Plant 

The Southern Company partnered with MHI to create a pilot-scale CCS project at the Plant 

Barry Power station in Mobile, Alabama. The plant uses a 25 MW slip stream out of their 160 

MW plant to capture 150,000 metric tons of CO2/year. The plant uses an MHI amine based 

process called KM-CDR, and incorporates MHIA's KS-1 solvent. The plant has successfully 

captured CO2 since June 2011, and began sequestering it in an underground saline formation in 

August, 2012. The plant was initially selected to be scaled up to a much larger size (100,000 

metric tons of CO2 capture/year) however Southern Company decided to opt out of the program 

in 2010 (MIT, Plant Barry Fact Sheet, 2015). 

8. Summit Power – Caledonia 
45 

The Caledonia plant, in Scotland, the United Kingdom, is a large scale pre-combustion IGCC 

CSS project developed by Summit Power. The plant will produce 570 MW (net) from gasified 

bituminous coal, and will collect 3.8 million metric tons CO2/year, or 90% of the total CO2. This 

CO2 is sent via pipeline to a saline formation in the North Sea for geologic sequestration 

(Summit Carbon Capture, 2015). The plant is scheduled to open in 2022, however it was granted 

funding from the UK and Scottish governments in March, 2015 to help conduct an industrial 

research and feasibility study to design, site, finance, and build the Caledonia Plant. The results 

of this study will be "shared across industry and academia, increasing understanding of how to 

develop and deploy CCS at commercial scale." (UK Dept. of Energy and Climate Change, 2015) 

9. Summit Power - Texas Clean Energy Project (TCEP)

The TCEP will be a 400 MW IGCC facility located near Odessa, Texas. The plant will capture 

90% of its CO2, which will be around 3 million metric tons/year. The plant will sell the CO2 for 

use in EOR, and will also sell urea, sulfuric acid, argon, and inert slag for use in various 

chemical processes (Gureghian, 2010). The plant plans to begin construction in 2015, and will 

utilize the Linde Rectisol® gas cleanup process to capture CO2, the same process used at the 

Dakota Gasification plant. TCEP plans to begin construction in 2015 (Paul, 2015; MIT, TCEP 

Fact Sheet, 2015), and hopes to begin operations by 2019. Besides CO2 capture, the plant will 

capture 99% of Sulphur dioxide, 90% of Nitrogen Oxide, and 99% of mercury. 

10. Vattenfall/Nuon – Willem-Alexander Power Plant 

The William-Alexander Power Plant, located in Buggenum, the Netherlands, is a coal-andbiomass-fired EGU that provides 253 MW of electricity. In 2011, the plant opened a pilot-scale 

CCS project testing IGCC technology with 90% CO2 capture from pre-combustion technology. 

The plant used a slip stream of CO2 equivalent to the amount produced by 20 MW of power, and 

then captured, compressed, and returned the CO2 to the main stream instead of sequestering it. 

This process helped researchers determine feasibility and practicability of CCS for use in 

potential scale-ups to industrial size EGUs in the future. Due to the economic recession in the 

European Union, the project was discontinued in 2014, however valuable lessons were learned 

about CCS during the three years of operation (MIT, Buggenum Fact Sheet, 2015). 

11. 2Co Energy - Don Valley Power Project 

The Don Valley Power Project is the most ambitious pre-combustion CCS project to date. 2Co 

energy will produce 920 MW gross (650 MW net) of power in South Yorkshire, the United 

Kingdom. The plant will capture over 90% of emissions, totaling some 5 million metric tons of 

CO2/year, which will be sequestered in the North Sea (2Co Energy, Don Valley CCS Project). 

C. Oxy-combustion 
46 

Table 4 contains four EGU facilities that are implementing or planning oxy-fuel combustion 

CO2 capture projects. Each project is briefly summarized in the following subsections. 
47 

Table 4. Oxy-combustion Carbon Capture and Storage Projects 

Project Name 

Domestic or International Location 

Facility type Unit type 

Capture details 

Date began operation (Date ended operation if ended) 

Amount of CO2 captured (metric tons/yr) 

Tradeta

Capture Power Ltd. - White Rose International 

 North Yorkshire, United Kingdom EGU 

Coal-fired power plant (448 MW) 

Full (>90%) CCS 

planning/permitting phase 2,000,000 Pipe

CS Energy - Callide A Station International 

Biloela, Queensland, Australia EGU 

Coal-fired power plant (30 MW ) 

Full (>90%) CCS 2012 

220,000(does not continuously run, captures 75 mt/day when operating On R

FutureGen 2.0 Alliance Dommestic 

Meredosia, Illinois EGU 168 MW 

Full (>90%) CCS 

2017 (under construction) 1,100,000 Pipe

Total - Lacq International Lacq, France EGU 

Heavy oil-fired power plant (30 MW unit of larger facility) 

Full (>90%) CCS of the unit's emissions, 15% of the plant's emissions January, 2010 75,000 Pipe
48 

1. Capture Power Limited - White Rose CCS project 

Capture Power Limited, which is a consortium of Alstom, BOC, and Drax Power, is currently 

planning an industrial scale oxy-fuel CCS facility in North Yorkshire, the United Kingdom. The 

plant will produce 448 MW of electricity from coal, capturing over 90% of the emitted CO2, 

totaling 2 Million metric tons CO2/year. The CO2 will be piped to the North Sea, where it will be 

geologically sequestered (White Rose, 2015). 

2. CS Energy – Callide A Station 

Located in Queensland, Australia, the Callide A station is the first industrial-scale pilot plant in 

the country. The 30 MW coal-fired unit, part of the larger Callide plant, captures over 90% of its 

CO2 emissions when running the capture technology, which is not done continuously because it's 

a pilot plant. The plant captures roughly 220,000 metric tons of CO2/year. This CO2 is 

pressurized and sent via trucks to Victoria, Australia, where it is sequestered underground. This 

pilot plant began operations in 2012. This project shows how old units (Callide A first began 

operations in 1965) can be retrofitted with CCS technology to cost-effectively reduce emissions 

(Callide, 2015). 

3. FutureGen 2.0 Alliance 

The FutureGen 2.0 project is a combined effort from industry and government to produce a full 

scale oxy-fuel combustion CCS plant in the United States. Located in Meredosia, Illinois, the 

168 MW EGU will implement full CCS using purified oxygen as fuel, allowing the plant to 

capture over 1.1 Million metric tons of CO2/year (FutureGen 2.0, About FutureGen 2.0). CO2

captured from the plant will be sent via pipeline to various locations for use in EOR or simple 

geologic sequestration. Completion of the project is scheduled for 2017, making FutureGen the 

first full CCS plant using oxy-fuel combustion in the US (FutureGen 2.0, About FutureGen 2.0). 

The EPA has issued Class VI deepwell construction permits for the sequestration phase. 

4. Total – Lacq Plant 

Total, in combination with Air Liquide, the French Petroleum Institute, the French Bureau of 

Geological and Mining Reseach, and Alstom, worked to construct an oxy-fuel pilot plant at the 

Lacq facility in southern France. The 30 MW project runs on heavy oil, and captures over 90% 

of the unit's emissions, about 15% of the plant's total emissions. The Lacq oxfuel project began 

operations in January 2010, and has captured 75,000 metric tons of CO2/year each year since 

(Total, How CCS at the Lacq Pilot Works). This CO2 is transported via pipeline to Rousse, 

France, where it is used for natural gas recovery and geologic sequestration. 
49 

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