DOE/NETL’s Carbon Capture R&D 

Program for Existing Coal-Fired 

Power Plants 

DOE/NETL- 2009/1356 

February 2009 
Disclaimer

This report was prepared as an account of work sponsored by an agency of the 

United States Government. Neither the United States Government nor any agency 

thereof, nor any of their employees, makes any warranty, express or implied, or 

assumes any legal liability or responsibility for the accuracy, completeness, or 

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any agency thereof. The views and opinions of authors expressed therein do not 

necessarily state or reflect those of the United States Government or any agency 

thereof. 
DOE/NETL’s Carbon Capture R&D Program for 

Existing Coal-Fired Power Plants 

DOE/NETL-2009/1356 

February 2009 

NETL Contact: 

Jared Ciferno 

Technology Manager 

Existing Plants—Emissions & Capture 

NETL Strategic Center for Coal 

National Energy Technology Laboratory 

www.netl.doe.gov 
Prepared by: 

Timothy Fout 

Project Manager, Existing Plants—Emissions & Capture 

NETL Strategic Center for Coal 

James T. Murphy 

Andrew P. Jones 

Research and Development Solutions LLC 

Science Applications International Corp. 

Contract Information: 

DE-AC26-04NT 41817.311.01.03 

2 
Abstract 

Coal-fired power plants have continued to make significant progress in reducing emissions of 

sulfur and nitrogen oxides (SOx and NOx), particulate matter, and mercury since passage of the 

1970 Clean Air Act. However, there is a possibility that carbon dioxide (CO2) emissions could 

also be regulated in the near future to address climate change. Recognizing that current CO2

capture technology is not cost-effective and has not been demonstrated at scale, the U.S 

Department of Energy’s National Energy Technology Laboratory (DOE/NETL) has initiated a 

research and development (R&D) program directed specifically at post- and oxy-combustion 

CO2 capture technologies that can be retrofit to existing coal-fired power plants, as well designed 

into new plants. The goal of the DOE/NETL effort, which is being carried out as part of the 

Existing Plants, Emissions and Capture (EPEC) Program, is to develop advanced CO2 capture 

and compression technologies for both existing and new coal-fired power plants that when 

combined can achieve 90 percent CO2 capture at less than a 35 percent increase in cost of 

electricity (COE). An aggressive R&D plan has been established in order to develop multiple 

CO2 capture technology options, capable of meeting the cost and performance target, at a 

commercial scale by 2020. 

Introduction 

Coal-fired power plants generate more than 50 percent of the electricity in the United States. 

DOE’s Energy Information Administration projects that the more than 300 gigawatts (GW) of 

coal-fired electricity generating capacity currently in operation will increase to over 400 GW by 

2030 (1).1 However, electricity production from fossil fuel-based power plants will be 

challenged by growing concerns that anthropogenic emission of greenhouse gases (GHG), such 

as CO2, are contributing to global climate change. The existing fleet of coal-fired power plants 

emits about two billion tons of CO2 annually, accounting for roughly two-thirds of the total CO2

emissions in the U.S. power sector. Moreover, as shown in Figure 1, more than 90 percent of the 

coal-fired CO2 emissions projected to be released from 2007 through 2030 will originate from 

today’s existing coal-fired power plants as less than 4 GW of capacity is projected to retire 

during that period (1). 

3 
Existing units:

• 91.9% of 

cumulative 

coal-fired CO2 

2007 − 2030

• 79.4% of 2030 

coal-fired CO2

402 GW

0

500

1,000

1,500

2,000

2,500

3,000

CO2 Emissions (Million Metric Tons)

0

1995 2000 2005 2010 2015 2020 2025 2030

IGCC

Unscrubbed Steam

Scrubbed Steam

New Steam New Steam 307 GW

Year

Existing units:

• 91.9% of 

cumulative 

coal-fired CO2 

2007 − 2030

• 79.4% of 2030 

coal-fired CO2

402 GW

0

500

1,000

1,500

2,000

2,500

3,000

CO2 Emissions (Million Metric Tons)

0

1995 2000 2005 2010 2015 2020 2025 2030

IGCC

Unscrubbed Steam

Scrubbed Steam

New Steam New Steam 307 GW

Year

Figure 1: U.S. Coal-Fired Electric Power Generation Carbon Dioxide Emission Projections 

While a technological portfolio will be necessary to stabilize global GHG emissions (2),2 carbon 

capture and storage (CCS) represents a promising option for directly reducing CO2 emissions 

from coal-fired power plants. Under an integrated CCS concept, CO2 would be captured, 

compressed, transported via pipeline, and permanently stored and monitored in geologic 

formations, such as depleted oil and gas fields, saline formations, and unmineable coal seams 

(3).3

 DOE/NETL has been dedicated to advancing all aspects of CCS systems for over a decade 

(4),4 but this paper will focus primarily on the CO2 capture R&D tailored for the existing fleet. 

The two general approaches for capture at existing plants are post- and oxy-combustion. 

Background 

Post-combustion CO2 capture, or separation of CO2 produced by conventional coal combustion 

in air, presents technical challenges since the flue gas is at atmospheric pressure and the CO2

concentration is 10 to 15 volume percent, resulting in a low CO2 partial pressure and a large 

volume of gas to be treated. In spite of this difficulty, post-combustion CO2 capture offers the 

greatest near-term potential for reducing GHG emissions because it can be retrofitted to existing 

units and can also be tuned for various levels of CO2 capture, which may accelerate market 

acceptance. 

The limited chemical potential for separating CO2 from existing power plant flue gas streams 

supports the use of chemical processes, such as amine-based scrubbing with an aqueous 

monoethanolamine (MEA) solution (Figure 2), which are capable of achieving high levels of 

CO2 capture (90% or more) from flue gas due to fast kinetics and strong chemical reactions. 

However, off-the-shelf amine solvents are corrosive, susceptible to degradation by trace flue gas 

constituents (particularly SOx), and necessitate significant amounts of energy, in the form of 

low-pressure steam, for sensible heating, heat of reaction, and stripping for CO2 regeneration. In 

fact, DOE/NETL has estimated that MEA-based CCS will increase the COE for a new 

4 
pulverized coal (PC) plant by about 80 to 85 percent, and even more for retrofits, while reducing 

the power plant net efficiency by about 30 percent (5,6).5,6

 Further, although MEA-based 

scrubbing has been utilized for over 60 years for natural gas purification and food-grade CO2

production, it has not been demonstrated at the larger-scale necessary for 90 percent CO2 capture 

at a 500-MW coal-fired power plant where 10,000 to 15,000 tons of CO2 would be removed per 

day. 

Figure 2: Schematic Diagram of an Amine CO2 Capture Process 

With the potential of large-scale power plant CO2 mitigation on the horizon, technology 

developers, such as Fluor Corporation (Econamine FG PlusSM) and Mitsubishi Heavy Industries 

(KM-CDR Process), have begun to optimize chemical scrubbing technology (7,8).7,8 The 

modifications are focused primarily on extensive thermal integration of the CO2 capture system 

with the power plant and the development of improved solvent formulations with lower stripping 

steam requirements and lower solvent circulation rates than MEA (9).9

 These process 

improvements have potential to decrease the cost and energy-intensity of post-combustion CO2

capture, which is estimated to account for about three-fourths of the total cost of an integrated 

CCS system. 

PC oxy-combustion power plants are designed to utilize high-purity oxygen (O2) mixed with 

recycled flue gas (primarily CO2) to combust coal and produce a highly concentrated CO2 stream 

(greater than 60 percent by volume). The CO2 is further purified by condensing the water (H2O) 

vapor through the use of cooling, desiccant systems, and compression to a dew point of -40oF. 

Depending on the end-use and pipeline specification, additional treatment may be necessary to 

reduce other gas constituents (O2, SOx and NOx). Although PC oxy-combustion is a relatively 

new concept and experience with integrated systems is limited, most key process components, 

including the cryogenic air separation unit (ASU) for O2 production are proven and 

commercially-available. PC oxy-combustion is currently being evaluated at the 30 megawatt 

thermal (MWth) scale by Babcock & Wilcox Company (B&W) and Vattenfall (10,11).10,11 

5 
However, the appeal of oxy-combustion is tempered by a few key challenges, namely the capital 

cost and energy consumption for cryogenic ASU operation, boiler air infiltration that dilutes the 

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

recycle (approximately 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 (12).12 Consequently, the economic 

benefit of oxy-combustion compared to amine-based scrubbing systems is limited. In 

comparison to a supercritical PC plant without CCS, DOE/NETL estimates that a new oxy-fired 

supercritical PC plant would incur a COE increase of about 60 percent (6). 

Given the significant economic penalties associated with current CO2 capture technologies, stepchange improvements in both cost and energy efficiency will be required to ensure that CCS for 

existing plants can be done at costs and impacts that are economically-acceptable. 

DOE/NETL’s Carbon Capture for Existing Plants R&D Program 

The EPEC Program is conducting R&D on advanced post- and oxy-combustion CO2 capture 

technologies, and novel CO2 compression techniques for existing coal-fired power plants. In 

addition to funding external R&D projects, DOE/NETL also conducts in-house research through 

the Office of Research and Development (ORD) to develop new breakthrough concepts for CO2

capture that could lead to dramatic improvements in cost and performance relative to today’s 

technologies. The EPEC CO2 emissions control R&D activity also sponsors systems analysis 

studies of the cost and performance of CO2 capture technologies (5,6).5,6

 The EPEC Program 

goal is to develop post- and oxy-combustion capture technologies for new and existing coal-fired 

power plants that achieve 90 percent CO2 capture at less than a 35 percent increase in COE and 

are available for commercial deployment by 2020. 

In support of this goal, DOE/NETL on July 31, 2008 announced that it will provide $36 million 

for 15 new laboratory- through pilot-scale post- and oxy-combustion CO2 capture R&D projects. 

These projects (denoted by an asterisk in Table 1) will build upon the current portfolio of CO2

capture research that was initiated in 2006 under DOE/NETL’s Carbon Sequestration Program 

and focus on five technology pathways: solvents, sorbents, and membranes for post-combustion 

CO2 capture, oxy-combustion (flue gas purification and boiler development), and chemical 

looping combustion (CLC). DOE/NETL is developing a broad portfolio of CO2 capture 

technologies for the existing fleet to accommodate differences in plant age, size, configuration, 

and other site-specific factors like available space and ductwork design. 

6 
Table 1: DOE/NETL Current CO2 Capture Technology R&D Projects

Project Focus Participant Project Focus Participant 

High-Capacity Oligomers* GE Global Research PC Oxy-Combustion Pilot Testing Babcock & Wilcox 

Integrated Vacuum 

Carbonate Absorption 

Process* 

Illinois State 

Geological Survey 

Oxy-Combustion Impacts in Existing 

Coal-Fired Boilers* 

Reaction 

Engineering 

International 

Phase Transitional 

Absorption Hampton University Oxy-Combustion Boiler 

Development for Tangential Firing* Alstom Power 

Ionic Liquids University of Notre 

Dame 

Oxy-Combustion Boiler Material 

Development* 

Foster Wheeler NA, 

Corp. 

Post-Combustion Solvents 

Reversible Ionic Liquids* Georgia Tech 

Research Corp. 

Oxy-Combustion CO2 Recycle 

Retrofit 

Southern Research 

Institute 

Amine-Grafted Zeolites University of Akron Pilot-Scale Oxy-Fuel Research CANMET

Dry Carbonate Process Research Triangle 

Institute (RTI) 

PC Oxy-Combustion with Integrated 

Pollutant Removal 

Jupiter Oxygen 

Corporation 

Low-Cost CO2 Sorbent* TDA Research Evaluation of CO2

Capture/Utilization/Disposal Options 

Argonne National 

Laboratory 

Metal Organic Frameworks UOP LLC Flue Gas Purification using SOx/NOx 

Reactions during CO2 Compression* 

Air Products and 

Chemicals, Inc. 

Carbon Sorbents* SRI International Near-Zero Emissions OxyCombustion Flue Gas Purification* Praxair, Inc. 

Solid Sorbents* ADA-ES, Inc. Oxy-Combustion with CO2 Capture DOE/NETL’s ORD 

Reactor Design Studies DOE/NETL’s ORD Oxy-Fired Combustion Simulation DOE/NETL’s ORD 

Carbon-Supported Amine 

Sorbents DOE/NETL’s ORD Materials Performance in OxyCombustion Environments DOE/NETL’s ORD 

Supported Amine Sorbent 

Modeling DOE/NETL’s ORD Oxy-Fuel Flame Property 

Measurement DOE/NETL’s ORD 

CO2 Capture Sorbent-Based 

Device Simulation DOE/NETL’s ORD Wireless Sensing in Oxy-Fuel 

Environments DOE/NETL’s ORD 

Oxy-Combustion 

Surface Immobilization 

Nanotechnology for 

Sorbents 

DOE/NETL’s ORD Oxygen Transport Membrane-Based 

Oxy-Combustion Praxair, Inc. 

O2 Supply 

Post-Combustion Sorbents 

CO2 Sorbent Development DOE/NETL’s ORD CLC Prototype* Alstom Power, Inc. 

Biomimetic Membrane Carbozyme, Inc. Coal Direct Chemical Looping* Ohio State 

University 

CO2 Membrane Process* RTI CLC Oxygen Carrier Studies DOE/NETL’s ORD 

Membrane Process for CO2 

Capture* 

Membrane 

Technology & 

Research (MTR) 

CLC Model Development DOE/NETL’s ORD 

Novel Dual-Functional 

Membrane 

University of New 

Mexico Laboratory-Scale CLC Combustor DOE/NETL’s ORD 

Novel Polymer Membranes MTR Design and Control of CLC Systems DOE/NETL’s ORD 

Chemical Looping Combustion 

Post-Combustion Membranes 

Electrochemical Membranes DOE/NETL’s ORD Novel Concepts for CO2

Compression 

Southwest Research 

Institute 

All 

Power Systems 

Development Facility – 

Carbon Research Center 

Southern Company Supersonic Shock Wave Compression 

Technology 

Ramgen Power 

Systems 

Compression 

7 
Solvents 

Solvent-based CO2 capture involves chemical or physical sorption of CO2 from flue gas into a 

liquid carrier. As discussed previously, solvent-based systems are in commercial use today 

scrubbing CO2 from industrial flue gases and process gases; however, they have not been applied 

to removing large volumes of CO2, as would be encountered in the flue gas from existing coalfired power plants. Research projects in this pathway address technical challenges to solventbased CO2 capture, such as large flue gas volume, relatively low CO2 concentration, flue gas 

contaminants, and high parasitic power demand for solvent recovery. 

Chemical Solvents 

Chemical absorption involves one or more reversible chemical reactions between CO2 and an 

aqueous solution of an absorbent, such as an alkanolamine (e.g., MEA), hindered amine, aqueous 

ammonia, or a carbonate, to form water-soluble compounds. Chemical solvents are able to 

capture high levels of CO2 from flue gas streams with a low CO2 partial pressure due to chemical 

reactivity, but capacity is equilibrium-limited. Thus, chemical solvent-based systems incur a 

significant cost and efficiency penalty during the regeneration step, which involves a temperature 

swing to break the absorbent-CO2 chemical bond. DOE/NETL is investigating advanced 

solvents that have lower regeneration heat duties than MEA, and that are also resistant to flue gas 

impurities. Previous research focused on potassium carbonate promoted with piperazine (13),13

while future work will evaluate an integrated vacuum carbonate absorption process (14)

14 and 

novel oligomeric solvents. 

Taking the Next Step 

DOE/NETL ORD researchers developed and patented a novel ammonia solvent-based CO2

capture technology that relies upon a temperature swing to cycle between ammonium carbonate 

and ammonium bicarbonate. This reaction has a significantly lower heat of reaction than aminebased systems, resulting in energy savings, provided the absorption/desorption cycle can be 

limited to this mechanism. Ammonia-based absorption has a number of other advantages over 

amine-based systems, such as the potential for high CO2 capacity, lack of degradation during 

absorption/regeneration, tolerance to O2 in the flue gas, low cost, and potential for regeneration 

at high pressure. 

Powerspan Corporation subsequently licensed the aqueous ammonia process in 2007 and rebranded it ECO2

®. Through integration with the ECO® multi-pollutant control system, 

Powerspan is currently conducting a 1-MW pilot test at FirstEnergy’s R.E. Burger Power Station 

in Ohio. Powerspan has also announced plans to conduct full-scale demonstrations (120-MW) of 

the ECO2

TM process at NRG Energy’s W.A. Parish Power Plant in Texas and Basin Electric’s 

Antelope Valley Station in North Dakota beginning in 2012 (15).15 

Physical Solvents

Another CO2 capture process currently being used in smaller-scale industrial applications, 

physical absorption, is a bulk phenomenon where inorganic or organic liquids preferentially 

absorb a gaseous species from the gas mixture. Although physical solvent regeneration is less 

energy-intensive than chemical systems, this technology is considered more practical for 

8 
processing the high-pressure fuel gas generated at coal gasification plants since CO2 solubility in 

physical solvents increases with partial pressure (16).16 

The University of Notre Dame and Georgia Tech, however, are investigating a new class of 

physical solvents that are designed to capture CO2 from low-pressure flue gas streams. Ionic 

liquids (ILs) include a broad category of salts, typically containing an organic cation and either 

an inorganic or organic anion. ILs have essentially no vapor pressure and are thermally stable at 

temperatures up to several hundred degrees Centigrade, which minimizes solvent loss during 

CO2 separation. Task-specific ILs containing amine functionality have been developed with CO2

solubility 40 times greater than exhibited prior to the start of the DOE/NETL-funded R&D 

project. One possible drawback is that the high viscosity of many ILs could adversely affect the 

ability to pump ILs in a power plant application (17).17

Sorbents 

Solid sorbents, including sodium and potassium oxides, zeolites, carbonates, amine-enriched 

sorbents, and metal organic frameworks (MOFs), are also being explored for CO2 capture at 

existing plants. A temperature swing facilitates sorbent regeneration following chemical and/or 

physical adsorption, but a key attribute of CO2 sorbents is that less H2O is present, compared to 

solvent-based systems, thereby reducing the sensible heating and stripping energy requirements. 

Possible configurations for contacting the flue gas with the sorbents include fixed, moving, and 

fluidized beds. Research projects in this pathway address key technical challenges to sorbentbased systems, such as solids circulation, sorbent attrition, low chemical potential, heat transfer, 

reactive flue gas contaminants, and the parasitic power and potential sweep gas demand for 

sorbent regeneration. 

 

DOE/NETL ORD scientists have developed amine-enriched sorbents that are prepared by 

treating high surface area substrates with various amine compounds. The implanting of the 

amine on a solid substrate increases the surface contact area of the amine for CO2 capture, thus 

requiring less sorbent/amine. This advantage, combined with the elimination of a H2O carrier, 

has the potential to improve the energy efficiency of the process compared to MEA scrubbing. 

Concurrently, DOE/NETL’s ORD is evaluating novel reactor designs for large-scale, sorbentbased CO2 capture systems applicable to new and existing PC power plants (18).18 

Research Triangle Institute (RTI) International is investigating the use of supported-sodium 

carbonate (Na2CO3 or soda ash) as an inexpensive and efficient CO2 sorbent. The Na2CO3 reacts 

with CO2 and H2O to form sodium bicarbonate via a reversible reaction that requires a 

temperature swing from about 60°C to 120°C for sorbent regeneration. RTI’s Dry Carbonate 

Process was successfully integrated into the U.S. Environmental Protection Agency’s MultiPollutant Control Research Facility – a 4 MMBTU/hr bench-scale furnace. During a total of 105 

hours of testing with coal-derived flue gas, the Dry Carbonate Process achieved 90 percent CO2

capture. In comparison to MEA scrubbing, the Dry Carbonate Process offers four distinct 

economic advantages: (1) reduced capital costs; (2) lower auxiliary power load; (3) reduced 

steam turbine power de-rating; and (4) and lower reactive material costs (19).19

9 
UOP LLC is leading the DOE/NETL effort to develop MOFs - a class of materials that are 

thermally-stable, have adjustable chemical functionality that can be tailored for high CO2

adsorption capacity, and possess very high porosity. UOP has developed a Virtual High 

Throughput Screening model to reduce the number of MOF synthesis experiments to only those 

that have the highest probability of success. A wide variety of MOFs have been successfully 

synthesized (Figure 3) and preliminary results indicate that MOFs are hydrothermally-stable and 

capable of separating CO2 from simulated flue gas streams (20).20 

Figure 3: Illustration of MOFs Developed by the University of Notre Dame 

Membranes 

Membrane-based CO2 capture uses permeable or semi-permeable materials that allow for the 

selective transport and separation of CO2 from flue gas. Gas separation is accomplished by some 

physical or chemical interaction between the membrane and the gas being separated, causing one 

component in the gas to permeate through the membrane faster than another. In general, 

membrane processes offer the following advantages: (1) passive operation with no moving parts; 

(2) tolerant of chemical contaminants (SOx, NOx); (3) energy-efficient with low operating costs; 

and (4) small, modular footprint. 

While membranes are more advantageous for separating CO2 in high-pressure applications, such 

as coal gasification, the EPEC Program is focused on developing highly-selective and permeable 

membrane systems designed specifically for CO2 separation from low partial pressure flue gas 

streams. For instance, gas absorption membranes, where separation is promoted by a hybrid 

membrane/absorption liquid (e.g., amine solvent or enzymes) combination that selectively 

removes CO2 from the flue gas stream (Figure 4), are a promising retrofit technology. 

 

10 
Figure 4: Schematic of a Gas Absorption Membrane 

Flue Gas containing CO2

Exhaust Gas to Stack Regenerated Solvent

CO2-rich Solvent 

to Regeneration

Gas Phase Liquid Phase

CO2

CO2

CO2

CO

C

2

O2

CO2

CO2

CO2

CO

C

2

O2

CO2

CO2

CO2

CO

C

2

O2

CO2

CO2

CO2

CO

C

2

O2

Membrane

Flue Gas containing CO2

Exhaust Gas to Stack Regenerated Solvent

CO2-rich Solvent 

to Regeneration

Gas Phase Liquid Phase

CO2

CO2

CO2

CO

C

2

O2

CO2

CO2

CO2

CO

C

2

O2

CO2

CO2

CO2

CO

C

2

O2

CO2

CO2

CO2

CO

C

2

O2

CO2

CO2

CO2

CO

C

2

O2

CO2

CO2

CO2

CO

C

2

O2

CO2

CO2

CO2

CO

C

2

O2

CO2

CO2

CO2

CO

C

2

O2

Membrane

Membrane Technology and Research (MTR) for example, is investigating novel thin-film, 

composite polymer membranes and associated process configurations to increase the flux of CO2

across the membrane, thereby reducing membrane area. A novel countercurrent design that 

utilizes a portion of the incoming combustion air as a sweep gas is being pursued to maximize 

the driving force for membrane permeation. Preliminary results indicate that 90 percent CO2

capture at a 600-MW coal-fired power plant will require about 700,000 cubic meters of 

membrane, or 135 of MTR’s nested module skids with a total footprint of about 0.5 acres (21).21

Another membrane process, under development by Carbozyme, leverages the carbonic 

anhydrase (CA) enzyme to catalyze the conversion of CO2 to bicarbonate at the flue gas interface 

and reverses the process via a pressure swing at the CO2 product interface. The Carbozyme 

permeator consists of two hollow-fiber, microporous membranes separated by a thin liquid 

membrane. CA is attached to the hollow-fiber wall to ensure that the incoming CO2 contacts the 

CA at the gas-liquid interface to maximize conversion efficiency. While the CA process has 

been shown to have a low heat of absorption that reduces the energy penalty typically associated 

with absorption processes, potential technical limitations include membrane boundary layers, 

pore wetting, surface fouling, loss of enzyme activity, long-term operation, and scale-up, which 

are currently being addressed. The Carbozyme permeator system was validated recently during 

laboratory-scale testing on a 0.5 cubic meter permeator, in which, 85 percent removal of CO2

from a 15.4 percent CO2 feed stream was achieved. Upon fabrication, the next-scale permeator 

will be shipped to the Energy and Environmental Research Center for testing on coal combustion 

flue gas (22).22

Oxy-combustion 

PC oxy-combustion involves the use of relatively pure O2 mixed with recycled flue gas 

(primarily CO2) for coal combustion to produce a concentrated CO2 stream. Experience with 

coal oxy-combustion is limited and therefore, continued R&D on oxy-combustion flame 

characteristics, burner and coal-feed design, and analyses of the interaction of oxy-combustion 

11 
products with boiler materials are necessary to ensure the development of low-cost and efficient 

oxy-combustion power plant systems. As a result, DOE/NETL is conducting laboratory- through 

pilot-scale R&D of the following oxy-combustion supporting processes: 

• Advanced oxy-combustion boilers designed with new materials of construction to handle 

higher combustion flame temperatures and potentially higher sulfur concentrations for 

co-sequestration applications; 

• Advanced oxy-burner designs to maintain a stable combustion flame; 

• Novel O2 separation/boiler integrated designs to reduce the cost of O2 production; and 

• Advanced flue gas purification and compression technologies. 

B&W completed successful oxy-combustion testing at the 1.5-MWth scale and is currently 

operating a 30-MWth oxy-combustion pilot unit at B&W’s Clean Environment Development 

Facility in Alliance, OH. Preliminary results indicate that flue gas volume is reduced by about 

80 percent with CO2 concentrations greater than 80 percent achieved. Pilot-scale testing has also 

demonstrated a smooth transition between air- and oxy-firing modes, and led to the development 

of two near full-scale oxy-burners - B&W DRB-XCL® for eastern bituminous coal, and DRBPAXTM for low-rank coals (10).

In 2004, Alstom Power conducted pilot-scale (3-MWth) testing of an oxygen-fired circulating 

fluidized bed (CFB) combustor with both bituminous coal and petroleum coke in O2/CO2

mixtures containing up to 50 percent O2 by volume. The testing successfully addressed several 

technical issues, such as furnace operability, temperature control, heat transfer, recarbonation, 

criteria and trace gaseous emissions, and unburned carbon. The pilot-scale tests confirmed the 

operability and technical feasibility of an oxygen-fired CFB system. Alstom completed a 

conceptual design and economic analysis for the conversion of an existing 90-MW CFB unit to 

oxy-firing that indicated a cost of $37 per ton of CO2 avoided (23).23

Oxygen Supply 

For oxy-combustion to be a cost-effective power generation option, a low-cost supply of pure O2

is required. Although a cryogenic ASU can be used to supply high-purity O2 to the boiler, this 

commercially-available technology is both capital- and energy-intensive (6). Novel O2

production technologies currently under development, such as ion transport membranes, have the 

potential to reduce the cost of O2 production. 

Praxair, Inc. is investigating the design and operation of oxygen transport membranes (OTMs), 

which utilize chemical potential for the O2 separation driving force instead of pressure. The 

OTMs are designed to integrate directly with the boiler such that the combustion reaction occurs 

on the fuel side of the membrane thus creating a low O2 partial pressure driving force. This 

chemical potential gradient drives O2 through the membrane without the need for additional air 

compression. In preparation for pilot-scale testing, a ceramic membrane and seal assembly has 

been developed for thermal integration between the high-temperature membrane and the 

combustion process. Prototype single- and multi-tube reactors have been built to demonstrate 

membrane performance and durability. Praxair estimates that OTMs can deliver O2 for oxycombustion using only 20 to 30 percent of the energy required for a cryogenic ASU (24).24

12 
Chemical Looping Combustion

Another advanced coal oxy-combustion technology, known as chemical looping combustion 

(CLC), involves the use of a metal oxide or other compound as an O2 carrier to transfer O2 from 

the combustion air to the fuel. Since direct contact between fuel and combustion air is avoided 

(Figure 5), the products from combustion (CO2 and H2O) will be kept separate from the rest of 

the flue gases (primarily N2). CLC splits combustion into separate oxidation and reduction 

reactions. The metal oxide (e.g., iron, nickel, copper, or manganese) releases the O2 in a 

reducing atmosphere and the O2 reacts with the fuel. The metal is then recycled back to the 

oxidation chamber where the metal oxide is regenerated by contact with air. The primary 

advantage of the CLC process is that no separate ASU is required and CO2 separation takes place 

during combustion. Supporting R&D projects will advance the development of CLC systems by 

addressing key issues, such as solids handling and O2 carrier capacity, reactivity, and attrition 

(25,26).25,26

Air

Air 

Reactor 

MyOx

N2, O2

MyOx-1

Fuel 

CO2, H2O 

Fuel 

Reactor

Figure 5: CLC Process Schematic

Under DOE/NETL support, Alstom Power is planning on installing and operating a 3-MWth

CLC prototype at their existing Power Plant Laboratory in Windsor, CT. The prototype will 

utilize limestone as the O2 carrier and include process loops to transfer solids and O2 between the 

reducing and oxidation reactors. Information obtained from operation will be used to develop a 

technical plan and cost estimate for a subsequent commercial demonstration project at a fullscale power plant (27).27

CO2 Compression 

In preparation for pipeline transport and permanent storage (enhanced oil recovery, deep 

geologic formations), the concentrated CO2 stream must be further dehydrated and compressed 

to a supercritical liquid (1,070 psi, 74 bar). DOE/NETL estimates that for a new 667-MW 

13 
supercritical PC power plant, multi-stage, centrifugal CO2 compression from the stripper 

regeneration column (20 to 25 psi) to 2,200 psi (pipeline pressure set by the NETL Systems 

Analysis Guidelines) would consume nearly 50 MW of auxiliary power, or about 0.1 MW per 

ton of CO2 (6). 

Liquefaction of CO2 to supercritical conditions can take place via two thermodynamic routes - 

multi-stage compression with interstage cooling, or a combination of compression, cooling, and 

pumping to supercritical pressures. In pursuit of the latter approach, Southwest Research 

Institute is investigating the use of refrigeration to liquefy the CO2 so that its pressure can be 

increased using a pump, rather than a compressor. The primary power requirements for the 

hybrid refrigeration approach are the initial compression to boost the CO2 to approximately 250 

psi and further refrigeration required to liquefy the gaseous CO2. Once the CO2 is liquefied, the 

pumping power to boost the pressure to pipeline supply pressure is minimal. 

Ramgen Power Systems is developing a supersonic shock wave compression technology that 

features a rotating disk operating at high peripheral speeds to generate shock waves that 

compress the CO2. There are several proposed advantages of the Rampressor compared to the 

conventional multi-stage or hybrid refrigeration approaches. First, shock compression employs 

only 2 stages of compression (versus 6 to 10 stages with a multi-stage approach) and therefore, 

offers potential capital cost savings up to 50 percent. In addition, the compressed CO2 is 

recovered at higher temperatures (400o

F to 600oF, depending on the efficiency) due to fewer 

stages (higher compression ratio), providing an opportunity for heat recovery through integration 

into either the power plant steam cycle or CO2 capture process. Recent prototype testing has 

achieved a 7.8:1 compression ratio (28).28

Summary 

DOE/NETL’s EPEC Program is carrying out a comprehensive R&D effort directed at advancing 

the technical performance and cost-effectiveness of CO2 capture technologies for new and 

existing coal-fired power plants. The program is focused on advanced post- and oxy-combustion 

capture technologies that can achieve 90 percent CO2 capture at less than a 35 percent increase in 

COE. It is anticipated that through well managed Federal research, development, and 

demonstration programs, a broad suite of cost-effective capture technologies will be available for 

commercial deployment by 2020 to respond to any future climate change regulations imposed 

upon the Nation’s power generation sector. 

Additional information related to DOE/NETL’s EPEC Program is available at the following 

website: http://www.netl.doe.gov/technologies/coalpower/ewr/co2/index.html. 

Acknowledgement 

This report would not have been possible without the efforts of DOE/NETL project managers 

and researchers who provided valuable technical input. The authors would like to acknowledge 

the contributions of Henry Pennline, Charles Alsup, Heino Beckert, Jose Figueroa, David Lang, 

Bruce Lani, William Aljoe, Charles Miller, Morgan Mosser, Robert Patton, and Andrew 

O’Palko. 

14 
Disclaimer 

Neither the United States Government nor any agency thereof, nor any of their employees, 

makes any warranty, express or implied, or assumes any legal liability or responsibility for the 

accuracy, completeness, or usefulness of any information, apparatus, product, or process 

disclosed, or represents that its use would not infringe privately owned rights. Reference therein 

to any specific commercial product, process, or service by trade name, trademark, manufacturer, 

or otherwise does not necessarily constitute or imply its endorsement, recommendation, or 

favoring by the United States Government or any agency thereof. The views and opinions of 

authors expressed herein do not necessarily state or reflect those of the United States 

Government or any agency thereof. 

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