# DOE/NETL’s Carbon Capture R&D Program for Existing Coal-Fired
Power Plants

DOE/NETL- 2009/1356 

## February 2009

## Disclaimer

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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 Develo pment Solutions LLC

Science Applications International Corp.

Contract Information:
DE-AC26-04NT 41817.311.01.03

2Abstract

Coal-fired power plants have continued to ma ke significant progress in reducing emissions of sulfur and nitrogen oxides (SOx and NOx), partic ulate matter, and mercur y since passage of the 1970 Clean Air Act. However, there is a possibility that carbon dioxide (CO 2 ) emissions could also be regulated in the near future to addr ess climate change. R ecognizing that current CO 2 capture technology is not cost-effective and has not been demonstrated at scale, the U.S Department of Energy’s National Energy Tech nology Laboratory (DOE/N ETL) has initiated a research and development (R&D) program dir ected specifically at post- and oxy-combustion
CO 2 capture technologies that can be retrofit to existing coal-fired power plants, as well designed into new plants. The goal of the DOE/NETL effo rt, which is being carried out as part of the Existing Plants, Emissions and Capture (EPE C) Program, is to develop advanced CO 2 capture and compression technologies for both existing and new coal-fired power plants that when combined can achieve 90 percent CO 2 capture at less than a 35 pe rcent increase in cost of electricity (COE). An aggressi ve R&D plan has been established in order to develop multiple
CO 2 capture technology options, capable of mee ting 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 current ly 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 anthropoge nic emission of greenhouse gases (GHG), such
as CO 2 , are contributing to global climate change. Th e existing fleet of coal-fired power plants
emits about two billion tons of CO 2 annually, accounting for roughly two-thirds of the total CO 2 emissions in the U.S. power sector. Moreover, as shown in Figure 1, more than 90 percent of the
coal-fired CO 2 emissions projected to be released from 2007 through 2030 will originate from today’s existing coal-fired power pl ants as less than 4 GW of capacity is projected to retire during that period ( 1 ).

3Existing units:

• 91.9% of

cumulative coal-fired CO 2 2007

− 2030

• 79.4% of 2030

coal-fired CO 2 402 GW

0 500 1,000 1,500 2,000 2,500 3,000CO2Emissions (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 CO 2 2007

− 2030

• 79.4% of 2030

coal-fired CO 2 402 GW

0 500 1,000 1,500 2,000 2,500 3,000CO2Emissions (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 Gen eration Carbon Dioxide Emission Projections

While a technological portfolio will be necessary to st abilize global GHG emissions ( 2 ), 2 carbon capture and storage (CCS) represents a promising option for directly reducing CO 2 emissions from coal-fired power plants. U nder an integrated CCS concept, CO 2 would be captured, compressed, transported via pipeline, and perm anently stored and m onitored in geologic formations, such as depleted oi l and gas fields, saline formati ons, and unmineable coal seams ( 3 ). 3 DOE/NETL has been dedicated to advancing a ll aspects of CCS systems for over a decade ( 4 ), 4 but this paper will focus primarily on the CO 2 capture R&D tailored for the existing fleet. The two general approaches for capture at ex isting plants are post- and oxy-combustion.

Background

Post-combustion CO 2 capture, or separation of CO 2 produced by conventional coal combustion in air, presents technical challenges since the flue gas is at atmospheric pressure and the CO 2 concentration is 10 to 15 volum e percent, resulting in a low CO 2 partial pressure and a large volume of gas to be treated. In spite of this difficulty, post-combustion CO 2 capture offers the greatest near-term potential for reducing GHG emi ssions because it can be retrofitted to existing
units and can also be tuned for various levels of CO 2 capture, which may accelerate market acceptance.

The limited chemical potential for separating CO 2 from existing power plant flue gas streams supports the use of chemical processes, such as amine-ba sed scrubbing with an aqueous monoethanolamine (MEA) solution (Figure 2), wh ich are capable of achieving high levels of
CO 2 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 (particularl y SOx), and necessitate significant amounts of energy, in the form of low-pressure steam, for sensible heati ng, heat of reaction, and stripping for CO 2 regeneration. In fact, DOE/NETL has estimated that MEA-ba sed CCS will increase the COE for a new

4pulverized coal (PC) plant by about 80 to 85 percent, and even more for retr ofits, 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 CO 2 production, it has not been demonstrated at th e larger-scale necessa ry for 90 percent CO 2 capture at a 500-MW coal-fired power plan t where 10,000 to 15,000 tons of CO 2 would be removed per day.

Figure 2: Schematic Di agram of an Amine CO 2 Capture Process

With the potential of large-scale power plant CO 2 mitigation on the horizon, technology developers, such as Fluor Co rporation (Econamine FG Plus SM ) and Mitsubishi Heavy Industries (KM-CDR Process), have begun to op timize chemical scrubbing technology ( 7,8 ). 7

, 8 The modifications are focused primarily on extensive thermal integration of the CO 2 capture system with the power plant and the deve lopment 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 co st and energy-intensity of post-combustion CO 2 capture, which is estimated to account for about thr ee-fourths of the total cost of an integrated CCS system.

PC oxy-combustion power plants are de signed to utilize high-purity oxygen (O 2 ) mixed with recycled flue gas (primarily CO 2 ) to combust coal and produc e a highly concentrated CO 2 stream (greater than 60 percent by volume). The CO 2 is further purified by condensing the water (H 2 O) vapor through the use of cooling, desiccant sy stems, and compression to a dew point of -40 o F. Depending on the end-use and pipeline specificati on, additional treatment may be necessary to reduce other gas constituents (O 2 , SOx and NOx). Although PC oxy-combustion is a relatively new concept and experience with integrated syst ems is limited, most key process components, including the cryogenic air separation unit (ASU) for O 2 production are proven and commercially-available. PC oxy-combustion is cu rrently being evaluated at the 30 megawatt thermal (MW th ) scale by Babcock & Wilcox Company (B&W) and Vattenfall ( 10,11 ). 10

, 11

5However, the appeal of oxy-combustion is temper ed by a few key challenges, namely the capital cost and energy consumption for cryogenic ASU ope ration, boiler air infiltration that dilutes the flue gas with nitrogen (N 2 ), and excess O 2 contained in the concentrated CO 2 stream. Flue gas recycle (approximately 70 to 80 percent) is also necessary to approximate the combustion characteristics of air since currently-availab le boiler materials cannot withstand the high temperatures resulting from coal combustion in pure O 2 ( 12 ). 12 Consequently, the economic benefit of oxy-combustion compared to amine-based scrubbing systems is limited. In comparison to a supercritical PC plant withou t 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 CO 2 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

T he EPEC Program is conducting R&D on advanced post- a nd oxy-combustion CO 2 capture technologies, and novel CO 2 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 CO 2 capture that could lead to dramatic improvement s in cost and performance relative to today’s technologies. The EPEC CO 2 emissions control R&D activity also sponsors systems analysis
studies of the cost and performance of CO 2 capture technologies ( 5,6 ). 5

, 6 The EPEC Program goal is to develop post- and oxy- combustion capture tec hnologies for new and existing coal-fired power plants that achieve 90 percent CO 2 capture at less than a 35 percent increase in COE and
are available for commerci al 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 pilo t-scale post- and oxy-combustion CO 2 capture R&D projects. These projects (denoted by an asterisk in Tabl e 1) will build upon the current portfolio of CO 2 capture research that was initiated in 2006 under DOE/NETL’s Carbon Sequestration Program and focus on five technology pathways: solven ts, sorbents, and membranes for post-combustion
CO 2 capture, oxy-combustion (flue gas purificati on and boiler development), and chemical looping combustion (CLC). DOE/NETL is developing a broad portfolio of CO 2 capture technologies for the existing fleet to accommodate di fferences in plant age, size, configuration, and other site-specific factors like av ailable space and ductwork design.

6Table 1: DOE/NETL Current CO 2 Capture Technology R&D Projects

Project Focus Participant Project Focus Participant
High-Capacity Oligomers* GE Gl obal 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 CO 2 Recycle
Retrofit Southern Research
Institute

Amine-Grafted Zeolites Universit y of Akron Pilot-Scale Ox y -Fuel Research CANMET

Dry Carbonate Process Research Triangle Institute (RTI) PC Oxy-Combustion with Integrated
Pollutant Removal Jupiter Oxygen Corporation

Low-Cost CO 2 Sorbent* TDA Research Evaluation of CO 2 Capture/Utilization/ Disposal Options Argonne National Laboratory

Metal Organic Frameworks UOP LLC Flue Gas Purification using SOx/NOx Reactions during CO 2 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 CO 2 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

CO 2 Capture Sorbent-Based
Device Simulation DOE/NETL’s ORD Wireless Sensing in Oxy-Fuel
Environments DOE/NETL’s ORDOxy-Combustion

Surface Immobilization Nanotechnology for
Sorbents DOE/NETL’s ORD Oxygen Transport Membrane-Based Oxy-Combustion Praxair, Inc.O2SupplyPost-Combustion Sorbents

CO 2 Sorbent Development DOE/NETL’s ORD CLC Prototype* Alstom Power, Inc.

Biomimetic Membrane Ca rbozyme, Inc. Coal Di rect Chemical Looping* Ohio State University

CO 2 Membrane Process* RTI CLC Oxygen Carrier Studies DOE/NETL’s ORD

Membrane Process for CO 2 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 ORDChemical Looping CombustionPost-Combustion Membranes

Electrochemical Membranes DOE/NETL’s ORD Novel Concepts for CO 2 Compression Southwest Research
InstituteAll Power Systems Development Facility –
Carbon Research Center Southern Company Supersonic Shock Wave Compression Technology Ramgen Power SystemsCompression

7Solvents

Solvent-based CO 2 capture involves chemical or physical sorption of CO 2 from flue gas into a liquid carrier. As discussed pr eviously, solvent-based system s are in commercial use today scrubbing CO 2 from industrial flue gases and process ga ses; however, they have not been applied to removing large volumes of CO 2 , as would be encountered in the flue gas from existing coalfired power plants. Research projects in this pathway address technical challenges to solventbased CO 2 capture, such as large flue gas volume, relatively low CO 2 concentration, flue gas contaminants, and high parasitic pow er demand for solvent recovery.

Chemical Solvents Chemical absorption involves one or more reversible chemical reactions between CO 2 and an aqueous solution of an absorben t, 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 CO 2 from flue gas streams with a low CO 2 partial pressure due to chemical reactivity, but capacity is equilibrium-limited. Thus, chemical solvent-based systems incur a significant cost and efficiency pe nalty during the regeneration st ep, which involve s a temperature swing to break the absorbent-CO 2 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 pota ssium carbonate promoted with piperazine ( 13 ), 13

while future work will eval uate 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 CO 2 capture technology that relies upon a temperatur e 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 CO 2 capacity, lack of degradation during absorption/regenerati on, tolerance to O 2 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 ECO 2 ® . 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 demons trations (120-MW) of
the ECO 2 TM process at NRG Energy’s W.A. Parish Po wer Plant in Texas and Basin Electric’s Antelope Valley Station in No rth Dakota beginning in 2012 ( 15 ). 15

Physical Solvents
Another CO 2 capture process currently being used in smaller-scale industrial applications, physical absorption, is a bulk phenomenon where inorga nic or organic liquids preferentially absorb a gaseous species from the gas mixture. Although physical solv ent regeneration is less energy-intensive than chemical systems, this technology is considered more practical for

8processing the high-pressure fuel gas genera ted at coal gasification plants since CO 2 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 ar e designed to capture CO 2 from low-pressure flue gas streams. Ionic liquids (ILs) include a broad category of salts, ty pically containing an organic cation and either an inorganic or organic anion. IL s have essentially no va por pressure and are thermally stable at temperatures up to several hundr ed degrees Centigrade, which minimizes solvent loss during
CO 2 separation. Task-specific ILs containing amine functionality have been developed with CO 2 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 coul d adversely affect the ability to pump ILs in a power plant application ( 17 ). 17

Sorbents

Solid sorbents, including sodium and potassium oxides, zeolite s, carbonates, amine-enriched sorbents, and metal organic frameworks (MOFs), are also being explored for CO 2 capture at existing plants. A temperature swing facilitates sorbent regeneration following chemical and/or physical adsorption, but a key attribute of CO 2 sorbents is that less H 2 O is present, compared to solvent-based systems, thereby reducing the sensib le heating and strippi ng energy requirements. Possible configurations for contacting the flue gas with the sorbents include fixed, moving, and fluidized beds. Research projects in this pa thway address key technical challenges to sorbentbased systems, such as solids circulation, sorbent attrition, low chemical pot ential, heat transfer, reactive flue gas contaminants, and the parasi tic 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 va rious amine compounds. The implanting of the
amine on a solid substrate increases the surface contact area of the amine for CO 2 capture, thus requiring less sorbent/amine. This advantage, combined with the elimination of a H 2 O carrier, has the potential to improve the energy efficiency of the process compared to MEA scrubbing. Concurrently, DOE/NETL’s ORD is evaluating nove l reactor designs for large-scale, sorbentbased CO 2 capture systems applicable to new and existing PC power plants ( 18 ). 18

Research Triangle Institute (RTI ) International is investigati ng the use of supported-sodium carbonate (Na 2 CO 3 or soda ash) as an inexpensive and efficient CO 2 sorbent. The Na 2 CO 3 reacts with CO 2 and H 2 O 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 CarbonateProcess was successfully integrated into the U.S. Environmental Protection Agency’s MultiPollutant Control Research Facility – a 4 MMBTU/h r bench-scale furnace. During a total of 105 hours of testing with coal-derived flue gas, the Dry Carbonate Process achieved 90 percent CO 2 capture. In comparison to MEA scrubbing, the Dr y 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

9UOP LLC is leading the DOE/NETL effort to de velop MOFs - a class of materials that are thermally-stable, have adjustable chemical functionality that can be tailored for high CO 2 adsorption capacity, and possess very high poro sity. 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 prelim inary results indicate that MOFs are hydrothermally-stable and capable of separating CO 2 from simulated flue gas streams ( 20 ). 20

Figure 3: Illustration of MOFs Deve loped by the University of Notre Dame

Membranes

Membrane-based CO 2 capture uses permeable or semi-permeable materials that allow for the selective transport and separation of CO 2 from flue gas. Gas separation is accomplished by some physical or chemical interaction between the me mbrane and the gas bein g separated, causing one component in the gas to permeate through the memb rane faster than another. In general, membrane processes offer the following advantag es: (1) passive operation with no moving parts; (2) tolerant of chemical contam inants (SOx, NOx); (3) energy-efficient with low operating costs; and (4) small, modular footprint.

While membranes are more advantageous for separating CO 2 in high-pressure applications, such as coal gasification, the EPEC Program is focu sed on developing highly-selective and permeable membrane systems designed specifically for CO 2 separation from low partial pressure flue gas streams. For instance, gas absorption membra nes, where separation is promoted by a hybrid membrane/absorption liquid (e.g., amine solvent or enzymes) combination that selectively
removes CO 2 from the flue gas stream (Figure 4) , are a promising retrofit technology.

10Figure 4: Schematic of a Gas Absorption Membrane Flue Gas containing CO 2 Exhaust Gas to Stack Regenerated Solvent

CO 2 -rich Solvent to Regeneration Liquid Phase Gas Phase C O 2 C O

2 CO 2 C O 2 C O

2

C O 2 C O

2 CO 2 C O 2 C O

2

C O 2 C O

2 CO 2 C O 2 C O

2

C O 2 C O

2 CO 2 C O 2 C O

2 Membrane

Flue Gas containing CO 2 Exhaust Gas to Stack Regenerated Solvent

CO 2 -rich Solvent to Regeneration Liquid Phase Gas Phase C O 2 C O

2 CO 2 C O 2 C O

2 C O 2 C O

2 CO 2 C O 2 C O

2

C O 2 C O

2 CO 2 C O 2 C O

2 C O 2 C O

2 CO 2 C O 2 C O

2

C O 2 C O

2 CO 2 C O 2 C O

2 C O 2 C O

2 CO 2 C O 2 C O

2

C O 2 C O

2 CO 2 C O 2 C O

2 C O 2 C O

2 CO 2 C O 2 C O

2 Membrane

Membrane Technology and Research (MTR) for example, is investig ating novel thin-film, composite polymer membranes and associated pro cess configurations to increase the flux of CO 2 across the membrane, thereby reducing membrane area. A novel countercurrent design that utilizes a portion of the incomi ng combustion air as a sweep gas is being pursued to maximize the driving force for membrane permeation. Pr eliminary results indica te that 90 percent CO 2 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 footprin t of about 0.5 acres ( 21 ). 21

Another membrane process, under developmen t by Carbozyme, leverages the carbonic anhydrase (CA) enzyme to ca talyze the conversion of CO 2 to bicarbonate at th e flue gas interface and reverses the process via a pressure swing at the CO 2 product interface. The Carbozyme permeator consists of two hollow-fiber, mi croporous membranes separated by a thin liquid
membrane. CA is attached to the hollow-fi ber wall to ensure that the incoming CO 2 contacts the CA at the gas-liquid interface to maximize conver sion 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, pot ential technical limitations in clude membrane boundary layers, pore wetting, surface fouling, loss of enzyme activity, long-term operation, and scale-up, which are currently being addressed. The Carbozyme pe rmeator system was validated recently during laboratory-scale testing on a 0.5 cubic meter permeator, in which, 85 percent removal of CO 2 from a 15.4 percent CO 2 feed stream was achieved. Upon fabr ication, the next-scale permeator will be shipped to the Energy and Environmental Re search Center for testing on coal combustion flue gas ( 22 ). 22

Oxy-combustion

PC oxy-combustion involves the use of relatively pure O 2 mixed with recycled flue gas (primarily CO 2 ) for coal combustion to produce a concentrated CO 2 stream. Experience with coal oxy-combustion is limite d and therefore, continued R&D on oxy-combustion flame characteristics, burner and coal-feed design, and analyses of the interaction of oxy-combustion

11products with boiler materials are necessary to en sure the development of low-cost and efficient oxy-combustion power plant systems. As a re sult, 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 poten tially higher sulfur concentrations for co-sequestration applications;

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

• Novel O 2 separation/boiler in tegrated designs to reduce the cost of O 2 production; and

• Advanced flue gas purification and compression technologies.

B&W completed successful oxy-co mbustion testing at the 1.5-MW th scale and is currently operating a 30-MW th oxy-combustion pilot unit at B&W’ s Clean Environment Development Facility in Alliance, OH. Pre liminary results indicate that flue gas volume is reduced by about 80 percent with CO 2 concentrations greater than 80 percent achieved. Pilot-scale testing has also
demonstrated a smooth transition between air- an d oxy-firing modes, and led to the development
of two near full-scale ox y-burners - B&W DRB-XCL ® for eastern bituminous coal, and DRBPAXTM for low-rank coals ( 10 ).

In 2004, Alstom Power conducted pilot-scale (3-MW th ) testing of an oxygen-fired circulating fluidized bed (CFB) combustor with both bi tuminous coal and petroleum coke in O 2 /CO 2 mixtures containing up to 50 percent O 2 by volume. The testing successfully addressed several technical issues, such as furnace operability, te mperature control, heat transfer, recarbonation, criteria and trace gaseous emi ssions, and unburned carbon. The p ilot-scale tests confirmed the operability and technical feasibility of an oxygen-fired CFB system. Alstom completed a conceptual design and economic analysis for th e conversion of an existing 90-MW CFB unit to oxy-firing that indicated a cost of $37 per ton of CO 2 avoided ( 23 ). 23

Oxygen Supply

For oxy-combustion to be a cost-e ffective power generation option, a low-cost supply of pure O 2 is required. Although a cryogenic ASU can be used to supply high-purity O 2 to the boiler, this commercially-available technology is bot h capital- and energy-intensive ( 6 ). Novel O 2 production technologies currently un der development, such as ion transport membranes, have the potential to reduce the cost of O 2 production.

Praxair, Inc. is investigati ng the design and operation of oxygen transport membranes (OTMs), which utilize chemical potential for the O 2 separation driving force instead of pressure. The OTMs are designed to integrate directly with the boiler such that the co mbustion reaction occurs
on the fuel side of the memb rane thus creating a low O 2 partial pressure driving force. This chemical potential gradient drives O 2 through the membrane without the need for additional air compression. In preparation for pilot-scale test ing, a ceramic membrane and seal assembly has been developed for thermal integration betw een the high-temperature membrane and the combustion process. Prototype single- and multi- tube reactors have been built to demonstrate membrane performance and durability. Pr axair estimates that OTMs can deliver O 2 for oxycombustion using only 20 to 30 percent of the energy required for a cryogenic ASU ( 24 ). 24

12Chemical Looping Combustion

Another advanced coal oxy-combustion technology, known as chemical looping combustion (CLC), involves the us e of a metal oxide or other compound as an O 2 carrier to transfer O 2 from
the combustion air to the fuel. Since direct c ontact between fuel and combustion air is avoided (Figure 5), the products from combustion (CO 2 and H 2 O) will be kept separate from the rest of the flue gases (primarily N 2 ). CLC splits combustion into separate oxidation and reduction reactions. The metal oxide (e .g., iron, nickel, copper, or manganese) releases the O 2 in a reducing atmosphere and the O 2 reacts with the fuel. The metal is then recycled back to the
oxidation chamber where the meta l oxide is regenerated by cont act with air. The primary advantage of the CLC process is that no separate ASU is required and CO 2 separation takes place during combustion. Supporting R&D projects will a dvance the development of CLC systems by addressing key issues, such as solids handling and O 2 carrier capacity, reac tivity, and attrition ( 25,26 ). 25

, 26



### Air Air
Reactor M y 

### O x 

### N 2 

### , O 2



### M y 

### O x-1



### Fuel CO 2 

### , H 2 

### O

Fuel
Reactor

Figure 5: CLC Process Schematic

Under DOE/NETL support, Alstom Power is planning on installing and operating a 3-MW th CLC prototype at their existing Power Plant La boratory in Windsor, CT. The prototype will
utilize limestone as the O 2 carrier and include process l oops to transfer solids and O 2 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

CO 2 Compression

In preparation for pipeline transport and perm anent storage (enhanced oil recovery, deep geologic formations), the concentrated CO 2 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

13supercritical PC power plant, multi-stage, centrifugal CO 2 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 CO 2 ( 6 ).

Liquefaction of CO 2 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 pressu res. In pursuit of the latter approach, Southwest Research Institute is investigating the use of refrigeration to liquefy the CO 2 so that its pressure can be increased using a pump, rather than a compre ssor. The primary power requirements for the hybrid refrigeration approach are th e initial compression to boost the CO 2 to approximately 250 psi and further refrigeration requi red to liquefy the gaseous CO 2 . Once the CO 2 is liquefied, the pumping power to boost the pressure to pi peline supply pressure is minimal.

Ramgen Power Systems is developing a supers onic shock wave compression technology that features a rotating disk operating at high periphe ral speeds to generate shock waves that compress the CO 2 . 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 stag es with a multi-stage approach) and therefore, offers potential capital cost savings up to 50 percent. In addition, the compressed CO 2 is recovered at higher temperatures (400 o F to 600 o F, 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 CO 2 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 comp rehensive R&D effort directed at advancing the technical performance a nd cost-effectiveness of CO 2 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 CO 2 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-eff ective capture technologies will be available for commercial deployment by 2020 to respond to any fu ture climate change regulations imposed upon the Nation’s power generation sector.

Additional information related to DOE/NETL’s EP EC Program is available at the following
website: http://www.netl.doe.gov/technologies /coalpower/ewr/co2/index.html

.

Acknowledgement

This report would not have b een possible without the efforts of DOE/NETL project managers and researchers who provided valuable technica l input. The authors would like to acknowledge the contributions of Henry Pennline, Charles Al sup, Heino Beckert, Jose Figueroa, David Lang, Bruce Lani, William Aljoe, Charles Miller, Morgan Mosser, Robert Patton, and Andrew
O’Palko.

14Disclaimer

Neither the United States Government nor any agency thereof, nor any of their employees, makes any warranty, express or im plied, or assumes any legal liabi lity or responsibility for the accuracy, completeness, or usefulness of any information, apparatus, product, or process disclosed, or represents that its use would not in fringe privately owned rights. Reference therein to any specific commercial product, process, or service by trade name, trademark, manufacturer,
or otherwise does not necessari ly 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 st ate or reflect those of the United States Government or any agency thereof.

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