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Chapter 7: Carbon Capture & Storage 

Introduction 

Another possible approach for reducing CO2 emissions from existing fossil fuel-fired 

EGUs is through the application of carbon capture and storage technology (CCS; sometimes also 

referred to as carbon capture and sequestration). In the recently proposed standards of 

performance for new fossil fuel-fired EGUs (79 FR 1430), the EPA proposed to find that the best 

system of emission reduction for new fossil fuel-fired boilers and IGCC units is partial 

application of CCS. In that proposal, the EPA found that, for new units, partial CCS has been 

adequately demonstrated; it is technically feasible; it can be implemented at reasonable costs; it 

provides meaningful emission reductions; and its implementation will serve to promote further 

development and deployment of the technology. This chapter examines the potential for 

implementation of CCS technology at existing fossil fuel-fired utility boilers and IGCC units. 

Carbon Capture Options for Existing Fossil Fuel-fired EGUs 

In general, CO2 capture technologies applicable to existing fossil fuel-fired power 

generation can be categorized into three approaches – (1) post-combustion capture; (2) precombustion capture; and (3) oxy-combustion. Each of these is described and discussed in more 

detail below. 

Post-combustion Capture 

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

to discharging to the atmosphere. Separating CO2 from such a gas stream can be challenging for 

a number of reasons. Because CO2 is a dilute fraction of the combustion flue gas – typically 13-

15 % in coal-fired systems and 3-4 % in natural gas-fired systems – a large volume of flue gas 

must be treated. The flue gas from typical combustion systems is usually at near atmospheric 

pressure. Therefore, most of the available capture systems rely on chemical absorption 

(chemisorption) options (e.g., amines) that require added energy to release the captured CO2 and 

regenerate the solvent. Many of the chemical solvents require a flue gas stream that is free of or 

has very low quantities of components – such as SO2, NOX, and HCl – that can degrade the 

solvent. The captured CO2 must then be compressed from near atmospheric pressure to much 

higher pipeline pressures (about 2,000 psia). 

 
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Pre-combustion Capture 

Pre-combustion capture systems are applicable to fossil fuel gasification power plants 

(i.e., IGCC units) where coal or other solid fossil fuel (e.g., pet coke) is converted into a 

synthesis gas (or “syngas”) by applying heat under pressure in the presence of steam and limited 

O2. The product syngas contains primarily H2 and CO – and, depending on the fuel and 

gasification system – some lesser amount of CO2. The amount of CO2 in the resulting syngas 

stream 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. The resulting CO2 contained in the syngas is then captured before combustion of 

the H2-enriched syngas for power generation in a combined cycle system. Contrary to the postcombustion capture flue gas, the IGCC syngas can contain a high volume of CO2 and is 

pressurized. This allows the use of physical absorbents (e.g., SelexolTM, Rectisol®) that require 

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

pipeline standards. 

Oxy-combustion 

Oxy-combustion systems for CO2 capture rely on combusting coal or other fuels with 

relatively pure O2 diluted with recycled CO2 or CO2/steam mixtures. Under these conditions, the 

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

water. Challenges associated with oxy-combustion include the capital cost and energy 

consumption for a cryogenic air separation unit (ASU) to produce oxygen, introduction of N2 via 

boiler air infiltration, and excess O2 in the CO2 product stream. 

CO2 Transportation and Storage 

CO2 Pipeline Infrastructure 

Carbon dioxide has been transported via pipelines in the U.S. for nearly 40 years. 

Approximately 50 million metric tons of CO2 are transported each year through 3,600 miles of 

pipelines. Moreover, a review of the 500 largest CO2 point sources in the U.S. shows that 95 

percent are within 50 miles of a possible geologic sequestration site, which would lower 

transportation costs. There are multiple factors that contribute to the cost of CO2 transportation 

via pipelines including but not limited to: availability and acquisition of rights-of-way for new 

pipelines, capital costs, operating costs, length and diameter of pipeline, terrain, flow rate of 

CO2, and the number of sources utilizing the pipeline. 

 
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Geologic Storage 

 Existing project and regulatory experience, research, and analogs (e.g. naturally existing 

CO2 sinks, natural gas storage, and acid gas injection), indicate that geologic sequestration is a 

viable long term CO2 storage option. The viability of geologic sequestration of CO2 is based on a 

demonstrated understanding of the fate of CO2 in the subsurface. Geologic storage potential for 

CO2 is widespread and available throughout the U.S. and Canada. Nearly every state in the U.S. 

has or is in close proximity to formations with carbon storage potential including vast areas 

offshore. Estimates based on DOE studies indicate that areas of the U.S. with appropriate 

geology have a storage potential of 2,300 billion to more than 20,000 billion metric tons of CO2

in deep saline formations, oil and gas reservoirs and un-mineable coal seams.1 Other types of 

geologic formations such as organic rich shale and basalt may also have the ability to store CO2; 

and the DOE is currently evaluating their potential storage capacity. 

 Further evidence of the widespread availability of CO2 storage reserves in the U.S. 

comes from the Department of Interior’s U.S. Geological Survey (USGS) which has recently 

completed a comprehensive evaluation of the technically accessible storage resource for carbon 

storage for 36 sedimentary basins in the onshore areas and State waters of the United 

States.2 The USGS assessment estimates a mean of 3,000 billion metric tons of subsurface CO2

storage potential across the United States. For comparison, this amount is 500 times the 2011 

annual U.S. energy-related CO2 emissions of 5.5 Gigatons (Gt).3

Enhanced Oil Recovery (EOR) 

Geologic storage options also include use of CO2 in EOR, which is the injection of fluids 

into a reservoir to increase oil production efficiency. EOR is typically conducted at a reservoir 

after production yields have decreased from primary production. 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 and make it available for recovery. The crude oil and CO2 mixture is 

produced, and sent to a separator where the crude oil is separated from the gaseous hydrocarbons 

                                                            

1

 The United States 2012 Carbon Utilization and Storage Atlas, Fourth Edition, U.S Department of Energy, Office of 

Fossil Energy, National Energy Technology Laboratory (NETL). 2

 U.S. Geological Survey Geologic Carbon Dioxide Storage Resources Assessment Team, 2013, National 

assessment of geologic carbon dioxide storage resources – Results: U.S. Geological Survey Circular 1386, 41 p., 

http://pubs.usgs.gov/fs/2013/1386/. 3

 U.S. Geological Survey Geologic Carbon Dioxide Storage Resources Assessment Team, 2013, National 

assessment of geologic carbon dioxide storage resources – Summary: U.S. Geological Survey Factsheet 2013-3020, 

6p.http://pubs.usgs.gov/fs/2013/3020/.
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and CO2. The gaseous CO2-rich stream then is typically dehydrated, purified to remove 

hydrocarbons, recompressed, and re-injected into the oil or natural gas reservoir to further 

enhance recovery. 

CO2-EOR has been successfully used at many production fields throughout the U.S. to 

increase oil recovery. The oil and natural gas industry in the United States has over 40 years of 

experience of injection and monitoring of CO2 in the deep subsurface for the purposes of 

enhancing oil and natural gas production. This experience provides a strong foundation for the 

injection and monitoring technologies that will be needed for successful deployment of CCS.

Evaluation of Retrofit CCS as BSER for Existing Fossil Fuel-fired EGUs 

Technical Feasibility 

In evaluating partial CCS as the BSER for new fossil fuel-fired boilers and IGCC units, 

the EPA determined that the technology is feasible and adequately demonstrated for new units 

because the major components of CCS – the capture, the transportation, and the storage – are all 

proven technologies that have been demonstrated at large scale. While the EPA found that partial 

CCS is technically feasible for new fossil fuel-fired boilers and IGCC units, it is much more 

difficult to make that determination for the entire fleet of existing fossil fuel-fired EGUs. 

Developers of new generating facilities can select a physical location that is more amenable to 

CCS – such as a site that is near an existing CO2 pipeline or an existing oil field. Existing sources 

do not have the advantage of pre-selecting an appropriate location. Some existing facilities are 

located in areas where CO2 storage is not geologically favorable and are not near an existing CO2

pipeline. Developers of new facilities also have the advantage of integrating the partial CCS 

system into the original design of the new facility. Integrating a retrofit CCS system into an 

existing facility is much more challenging. Some existing sources have a limited footprint and 

may not have the land available to add partial CCS system. Integration of the existing steam 

system with a retrofit CCS system can be particularly challenging. 

Partial CCS has been demonstrated at existing EGUs. It has been demonstrated at a pilotscale at Southern Company’s Plant Barry; it is being installed for large-scale demonstration at 

NRG’s WA Parish facility; and it will very soon be applied at commercial-scale as a retrofit at 

SaskPower’s Boundary Dam coal-fired EGU in Canada. However, all of these facilities are 

located in areas that are either near an existing oil field or in an area that is geologically 

favorable for CO2 storage. Thus, at some existing facilities, the implementation of partial CCS 

may be a viable GHG mitigation option and some utilities may choose to pursue that option. 
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However, the EPA does not believe that it can serve as the best system of emission reduction for 

a broadly applicable GHG mitigation program. Therefore, the EPA does not propose to find that 

CCS is a component of the best system of emission reduction for CO2 emissions from existing 

fossil fuel-fired EGUs.

Reasonableness of Cost 

In the proposed standard of performance for new fossil fuel-fired EGUs (79 FR 1430), 

the EPA found that the costs to implement partial CCS (to a level to meet the proposed emission 

standard of 1,100 lb/MWh-gross) were consistent with costs for other non-natural gas-fired 

generating technologies – such as nuclear, biomass and geothermal – that utilities are considering 

for new intermediate and base load generating capacity. 

The EPA also noted in the proposal, that most of the relatively few new projects that are 

in the development phase are already planning to implement CCS; and, as a result, the standard 

would not have a significant impact on nationwide energy prices. In contrast, the EPA noted that 

identifying CCS as BSER for new natural gas-fired stationary combustion turbines, would likely 

result in higher nationwide electricity prices and could adversely affect the supply of electricity 

since the majority of new fossil-fuel fired power generation is projected to be natural gas 

combined cycle (NGCC). An emission standard for existing units based on CCS (or even partial 

CCS) would most certainly have an even more significant effect on nationwide electricity prices 

and could affect the reliability of the supply of electricity. Therefore, we do not find that the cost 

to implement existing source emission standards to be reasonable, which further supports the 

determination that CCS is not an appropriate component of the best system of emission reduction 

for CO2 emissions from existing fossil fuel-fired EGUs.

Emission Reductions and Promotion of Advanced Technology 

An emission standard for existing units based on CCS (or even partial CCS) would 

clearly result in significant emission reductions and would certainly serve to promote further 

deployment, development and improvement in the most advanced technology. However, the 

EPA has determined that such an emission standard is not technically feasible in all cases and 

cannot be done at a reasonable cost at this time.