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CARBON SEPARATION AND CAPTURE

Melanie D. Jensen, Energy & Environmental Research Center

Mark A. Musich, Energy & Environmental Research CenterJohn D. Ruby, Nexant, Inc.

Edward N. Steadman, Energy & Environmental Research CenterJohn A. Harju, Energy & Environmental Research Center

June 2005

EXECUTIVE SUMMARY

This report provides a qualitative summaryof a large number of existing and emergingprocesses that could be used to separate

CO2 from combustion gases for thepurpose of controlling carbon emissions.

The largest sources of concern are fossil-fuel-fired electric generating plants. Citedstudies comparing the application ofcommercial gas separation processes tothese plants indicate very high cost andperformance penalties for existingpulverized-coal (pc)-fired plants. Naturalgas-fired combined-cycle plants are alsoseverely impacted because of thesensitivity to reduced efficiency associatedwith high fuel cost. Much lower cost andperformance penalties are indicated forcoal-fired integrated gasification combined-cycle (IGCC) plants, where CO2 capture canbe integrated into the design. The time linefor adoption of CO2 capture dependscritically on policy incentives to addressthe economic and technical risks. Coal-fired IGCC plants with provision forsequestration-ready CO2 separation are onthe near horizon to supply the growing CO2demand for enhanced oil recovery (EOR).Applications for new or existing pc-firedplants will require substantialimprovements in technologies underdevelopment or very large policy incentives.

The assessment presented in this reportprovides a snapshot of the rapidly

changing developments that are inprogress.

The separation of CO2 from other speciesin mixed-gas streams has been practiced

on the commercial scale for over 50 years.Most of these applications have been fornatural gas sweetening operations,purification of reformer synthesis gas(syngas) to produce H2 in refineryoperations, and for ammonia production.High-purity sources of CO2 are used in thefood industry and as a consumablerefrigerant. The largest use of CO2 is forEOR. The growing interest in reducing CO2emissions, the emerging carbon tradingmarkets, and the increasing demand forCO2 for EOR all underscore the need forimproved CO2 capture technologies.

Commercial and still-developing conceptsfor CO2 capture and separation can begrouped into five categories: absorption,cryogenic cooling, gas separationmembranes, gas absorption membranes,and adsorption. These technologies can beapplied to three broad categories of fuel-to-heat/power processes, includingpostcombustion (stack gas cleaning),precombustion (e.g., gasification orreforming), and oxygen combustion (insome CO2 sequestration literature, thisprocess is called oxyfuel combustion).Using oxygen rather than air forcombustion eliminates the large quantityof N2 diluent. Although most of the

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development efforts in CO2 capture havefocused on power production, capture andseparation processes would be applicableto industrial boilers and turbines, processheaters, kilns, cupolas, and other sources.

The leading importance of power

generation is clearly indicated by thedistribution of sources shown in

Tables ES-1 and ES-2.

The near-term options for separating CO2use either amine scrubbing solutions forpostcombustion flue gas capture orphysical solvents such as Selexol forprecombustion IGCC systems. Oxygencombustion is under development at thepilot scale. All current commercialapproaches to CO2 capture result in

significant energy and cost penalties. Theenergy penalty for a pc-fired power plantcan approach 30% because of the largeparasitic steam loads.

Gasification combined-cycle systems

provide inherent efficiency and costadvantages to CO2 capture through higheroperating pressure and CO2concentrations. Some studies indicate thatoxygen combustion may also be cost-effective. Performance and cost of CO2capture from lignite-fired power plants,cement production, and petroleum refiningwere estimated using the PCORPartnerships spreadsheet estimation tool.

The costs ranged from $22/ton CO2 for acoal-fired power plant retrofitted with an

Table ES-1. Top Six CO2 Emission Sources*

Fossil Fuel Combustion 6185.1

Iron and Steel Production 60.0

Cement Manufacturing 47.3

Waste Combustion 20.7

Ammonia/Urea Production 19.5

Lime Manufacturing 13.6

Total CO2 6374.0

* U.S. 2002 CO2 emissions, million tons of CO2 equivalent (from EPA data [2004]).

Table ES-2. Subsets of Fossil Fuel Combustion*

Electricity Generation 2469.3

Transportation

Industrial 1053.6Residential 411.3

Commercial 254.9

U.S. Territories 51.3

* U.S. 2002 CO2 emissions, million tons of CO2 equivalent (from EPA data [2004]).


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amine scrubber to $51/ton for a petroleumrefinery. While these estimates aresubstantially higher than the U.S.Department of Energy (DOE) goal of$10/ton, costs will drop as technologiesimprove and industry recognizes the

potential for profit from the use of CO2 inenhanced resource recovery operations.

ACKNOWLEDGMENTS

The PCOR Partnership is a collaborativeeffort of public and private sectorstakeholders working toward a betterunderstanding of the technical andeconomic feasibility of capturing andstoring (sequestering) anthropogeniccarbon dioxide (CO2) emissions fromstationary sources in the central interior ofNorth America. It is one of seven regionalpartnerships funded by the U.S.Department of Energys (DOEs) NationalEnergy Technology Laboratory (NETL)Regional Carbon Sequestration Partnership(RCSP) Program. The Energy &Environmental Research Center (EERC)would like to thank the following partnerswho provided funding, data, guidance,and/or experience to support the PCOR

Partnership:

Alberta Department of Environment Alberta Energy and Utilities Board Alberta Energy Research Institute Amerada Hess Corporation Basin Electric Power Cooperative Bechtel Corporation Center for Energy and Economic

Development (CEED) Chicago Climate Exchange Dakota Gasification Company

Ducks Unlimited Canada Eagle Operating, Inc. Encore Acquisition Company Environment Canada Excelsior Energy Inc. Fischer Oil and Gas, Inc. Great Northern Power Development,

LP Great River Energy

Interstate Oil and Gas CompactCommission

Kiewit Mining Group Inc. Lignite Energy Council Manitoba Hydro Minnesota Pollution Control Agency

Minnesota Power Minnkota Power Cooperative, Inc. MontanaDakota Utilities Co. Montana Department of

Environmental Quality Montana Public Service Commission Murex Petroleum Corporation Nexant, Inc. North Dakota Department of Health North Dakota Geological Survey North Dakota Industrial Commission

Lignite Research, Development andMarketing Program

North Dakota Industrial CommissionOil and Gas Division

North Dakota Natural ResourcesTrust

North Dakota Petroleum Council North Dakota State University Otter Tail Power Company Petroleum Technology Research

Centre Petroleum Technology Transfer

Council Prairie Public Television Saskatchewan Industry and

Resources SaskPower Tesoro Refinery (Mandan) University of Regina U.S. Department of Energy U.S. Geological Survey Northern

Prairie Wildlife Research Center Western Governors Association Xcel Energy

The EERC also acknowledges the followingpeople who assisted in the review of thisdocument:

Erin M. OLeary, EERCKim M. Dickman, EERCStephanie L. Wolfe, EERC

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INTRODUCTION

As one of seven Regional CarbonSequestration Partnerships (RCSPs), thePlains CO2 Reduction (PCOR) Partnershipis working to identify cost-effective CO2

sequestration systems for the PCORPartnership region and, in future efforts, tofacilitate and manage the demonstrationand deployment of these technologies. InPhase I of the project, the PCORPartnership is characterizing the technicalissues, enhancing the publicsunderstanding of CO2 sequestration,identifying the most promisingopportunities for sequestration in theregion, and developing an action plan forthe demonstration of regional CO2sequestration opportunities.

This report describes technologies used tocapture CO2 from flue gas and process gasstreams produced during the course of fuelcombustion. Although typically pursued inthe context of utility power generation,these technologies would also apply toindustrial and municipal heat/power,process heaters, kilns, cupolas, and othersources. Information is also presented on

new combustion processes and powercycles that facilitate more effective CO2capture. Limited public data are presentedon the cost and performance ofcommercially offered power generationsystems incorporating CO2 separation andcapture.

While each existing or future CO2 source inthe PCOR Partnership region will havemany site- and process-specificperformance criteria and cost issues, the

objective of this report is to provide generalinformation that can be used for earlyscreening and decision making or modelingto examine what if issues. Site- andtechnology-specific decisions will requireadditional evaluation in later phases of thework.

CO2 SEPARATION AND REMOVALPROCESSES

Gas AbsorptionGas absorption processes are commonlyused in commercial plants to remove CO2

from mixed-gas streams over a wide rangeof pressures and CO2 concentrations. Twotypes of solvents are typically used for CO2removal: physical solvents and chemicallyreactive solvents. Physical solvents dissolveCO2, following Henrys law, but do notreact with it. Chemically reactive solventsfirst dissolve CO2 and then react with it.Physical solvents are more suitable formixed-gas streams that are under highpressure. The elevated pressure increasesCO2 solubility, which, in turn, reduces thesolvent circulation rate. Pressure does notaffect the performance of chemicallyreactive solvents.

If the mixed-gas stream containing CO2 isat elevated pressure, the physical solventcan be recovered by flashing off CO2 at alower pressure. Chemically reactivesolvents require heat to separate thedissolved gas. Commercial experience hasshown that the physical solvent process ismore economical if the CO2 partialpressure is above 200 psia. At low inletCO2 partial pressure, and where a very lowoutlet CO2 concentration is required,chemically reactive solvent processes aremore effective.

Hybrid solvents combine the bestcharacteristics of both chemical andphysical solvents and are usuallycomposed of a number of complementarysolvents. Developments are under way to

develop tailor-made complementarysolvents where the proportions are variedto suit the application.

Some of the more commonly usedcommercial gas absorption processes arelisted in Table 1. The first four processesuse solvents that physically absorb theCO2 and are applied to mixed-gas streams

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under high pressure that contain a highconcentration of CO2. The solventcirculation rates for these processes aregenerally high. The three other processesuse chemically reactive solvents. All of thechemical absorption processes can be used

at atmospheric pressure, but in practicethey are used for treating mixed-gasstreams under substantial pressure suchas for the removal of CO2 from natural gasand synthesis gas.

Alkanolamines are a group of amines thatare commonly used for acid gas removal(including CO2). They includemonoethanolamine (MEA), diethanolamine(DEA), diglycolamine (DGA),diisopropanolamine (DIPA), andtriethanolamine (TEA). Of these, MEA isthe most alkaline; it has the highestdissociation constant and the highest pHin water solution. The others areprogressively less alkaline in the orderlisted. Other properties that bear on theuse of these amines follow in the sameorder as their alkalinities. The chemicalreaction with CO2 is fastest with MEA anddecreases with the others. For thesereasons, MEA-based processes are the

most popular and are considered the bestavailable control technology (BACT) for theremoval of CO2 from flue gas with lowconcentration and low partial pressure ofCO2.

Cryogenic CoolingCO2 can be separated from a mixed-gasstream by liquefaction when the CO2concentration is sufficient. CO2 can beliquefied at any temperature between itstriple point (!70F) and its critical point

(88F) by compressing it to thecorresponding liquefaction pressure andremoving the heat of compression andcondensation. There are two commoncommercial liquefaction processes. In thefirst process, the CO2 is liquefied near thecritical temperature, and water is used forcooling. This process requires compressionof the CO2 gas to about 1100 psia. A

second liquefaction process operates attemperatures from 10 to 70F and with aliquefaction pressure of about 250 to350 psia. This process requiresdehydration of the feed stream with anactivated alumina or silica gel dryer and

distillation of the condensate in a strippingcolumn. The third cryogenic process coolsthe mixed-gas stream to a temperaturesufficiently low to condense CO2 out of thegas phase. This method is also used toremove vapors of organic compounds fromvent gases and for other operations.

Gas Separation MembranesGas separation membranes use partialpressure as the driving force for separationand, consequently, will be most effective at

high CO2 concentrations and pressure.Differences in physical or chemicalinteraction between the componentspresent in a gas mixture with themembrane material cause one componentto permeate through the membrane fasterthan the other component. The gascomponent dissolves into the membranematerial and diffuses through it to theother side. The membrane divides the feedgas stream into the permeate stream andthe retentate stream. Ideally, the permeate

stream would require little recompressionfor utilization.

The quality of the separation is determinedby membrane selectivity and by twoprocess parameters: 1) the ratio of thepermeate flow to the feed flow and 2) theratio of permeate pressure to the feedpressure. Depending upon the selectivity ofthe membrane, a high-purity CO2 productmay require a large number of stages,leading to increased recompression andcapital costs. Membrane separation oftencompetes with cryogenic separation andpressure swing adsorption when mediumquantities of low-purity product gas arerequired. Membrane separation technologyis currently better suited to treatment ofmixed-gas streams fed from a high-pressure source, such as natural gasprocessing.

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Table 1. Gas Absorption Processes Used for CO2 Removal

No.Process

(and solvent) Owner Use1 Sulfinol

(MDEA and accelerator)Shell Oil Company Natural gas, refinery gases

and synthesis gases2 Selexol

(a dimethyl ether ofpolyethylene glycol)

UOP Natural gas, refinerygases, and synthesis gases

3 Rectisol(cold methanol)

Lurgi GmbH andLinde AG

Heavy oil partial oxidationprocess of Shell andTexaco; also Lurgi

gasification4 Purisol

(N-methyl-2-pyrrolidone)Lurgi GmbH Natural gas, hydrogen,

and synthesis gases5 Catacarb

(hot potassium carbonateand borate activator)

Eickmeyer &Associates, Kansas

Any mixed-gas stream

6 Benfield(hot potassium carbonate

and ACT-1 corrosioninhibitor)

UOP Synthesis gas, hydrogen,natural gas, town gas, and

others

7 Amines(alkanolamines andhindered amines)

Both generic solventsand proprietary

formulations withadditives

Any mixed-gas stream

Gas Absorption MembranesGas absorption membranes are used ascontacting devices between a gas flow and

a liquid flow. The presence of anabsorption liquid on one side of themembrane selectively removes certaincomponents from a gas stream on theother side of the membrane. In effect, theabsorption liquid increases the drivingforce across the membrane because thepartial pressure of the absorbed gas on theliquid side is essentially zero. In contrastwith gas separation membranes, it is notessential that the absorption membrane beselective as its purpose is solely to providea contacting area without mixing gas andabsorption liquid flow. The selectivity of theprocess is derived from the absorbingliquid.

Removal of flue gas components such asSO2 or CO2 is achieved through the use ofporous hydrophobic membranes in

combination with suitable absorptionliquids, such as sulfite, carbonate, oramine solutions. For example, CO2 isremoved from flue gas with the aid of gasabsorption membranes used incombination with MEA.

Gas AdsorptionGassolid adsorption systems that may beapplicable to removal of CO2 from mixed-gas streams employ adsorbent beds ofalumina, zeolite, or activated carbon. Othersolid materials used commercially in gasseparation processes are alumina gel andsilica gel, although processes using thesegels are a hybrid of adsorption andabsorption.

Four methods are used commercially forregeneration. Pressure-swing adsorptionand regeneration (PSA) involves raising andlowering the pressure in the bed topreferentially capture and release the

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gases to be separated. Technologiesrequiring a vacuum for regeneration arecalled vacuum pressure-swing adsorption(VPSA) units. PSA and VPSA regenerationcycles are relatively short and are typicallymeasured in seconds. Thermal- (or

temperature-) swing adsorption (TSA)employs high-temperature regenerationgas to drive off trapped gases. TSAregeneration cycles are quite long(measured in hours) and require largerquantities of adsorbent than PSA systems.

The third regeneration method employs astream of fluid that does not contain any ofthe trapped gas to wash the bed. Thefourth method uses a gas stream thatcontains a material that can displace thetrapped gas from the bed and is essentiallya chromatographic procedure.

Most commercial units use either PSA-typeregeneration or a combined thermalswing/wash method that regenerates atreduced pressure, known as thermalswing. PSA technology is used for dryingair, hydrogen purification in refineries, n-paraffin removal, and small- to medium-scale air fractionation. Depending on thefeed gas and the species to be adsorbed,

two vessels are filled with an adsorbentsuch as silica gel, molecular sieves, ormolecular sieve carbon. One vessel servesas an adsorbing bed, with the feed enteringat elevated pressure. When the bed issaturated, the feed is switched to thesecond vessel. Pressure in the first (spent)vessel is lowered to release the adsorbedspecies. The adsorbent in the vessel isregenerated, and the vessel is pressurizedto make it ready for another cycle. Theprocess is repeated in the second vessel.

Similar to the absorption process, theadsorption can be primarily chemical orphysical with physical adsorption being theless energy-intensive to reverse. Theseprocesses compete with cryogenic airseparation units in applications requiringhigh-purity products, where the number ofstages and the recycle flow rates increase

to such an extent that the adsorptionprocesses cannot successfully compete.

Combustion Modification TechnologiesSubstitution of oxygen for all or part of thecombustion air has been proposed to

produce a CO2-rich flue gas requiringminimum separation for use orsequestration. Conventional aircombustion processes in boilers or gasturbines produce flue gas that containspredominantly nitrogen (>80 vol %) andexcess oxygen in addition to CO2 andwater. Separation technologies mustseparate CO2 from these othercomponents. If the air is replaced byoxygen, the nitrogen content of the flue gasapproaches zero (assuming minimal airleakage into the system), and the flue gascontains predominantly CO2 along with asmall amount of excess oxygen andcombustion water. The CO2 can berecovered by compressing and cooling,followed by dehydration. The adiabaticflame temperature can be moderated byrecirculating a part of the recovered CO2.

While oxygen combustion with the recycleof flue gas has been studied conceptually,

there are no field units. Commercial plantfeasibility may be difficult to justifybecause of the auxiliary powerconsumption of the air separation unitneeded to produce the oxygen.

APPLICATION OF CO2 CAPTURETECHNOLOGIES TO FUEL COMBUSTION

Postcombustion RemovalFor removal of CO2 from low-pressure(


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the range of 100 to 1100 tons/day, whichis significantly less than the5500 tons/day for a 500-MW coal-firedplant. Commercial providers of MEAtechnology include Fluor Daniel and ABBLummus Global. A diagram of a system

employing an MEA process for CO2 captureis presented in Figure 1.

In gas turbine combined-cycle systems,flue gas from the heat recovery steamgenerator (HRSG) is cooled to about 110Fwith circulating cooling water. Additionalcooling is not required in systemsemploying flue gas desulfurization (FGD).

The flue gas is partially compressed to17.5 psia by a centrifugal blower toovercome the gas-path pressure drop. The

flue gas enters the absorber base and flowsupward countercurrent to the lean MEAsolution. CO2 is removed from the flue gasin the packed-bed absorber columnthrough direct contact with MEA. The CO2-depleted flue gas is exhausted to the

atmosphere. The CO2-rich solution isheated in a heat exchanger and sent to thestripper unit where low-pressure steamfrom the steam turbine crossover providesthe thermal energy to liberate the CO2. TheCO2 vapor is condensed, cooled, and sentto a multistaged compressor where the CO2is compressed to a pressure of over1200 psia. The CO2-laden stream isdehydrated using glycol or molecular sieveprocesses. After drying, the CO2 is readyfor transport and sequestration.

Figure 1. Process flow diagram of CO2 removal by MEA absorber/stripper.

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The MEA process can achieve recoveries of85% to 95%, with CO2 purities over99 vol%. However, the MEA process alsorequires a significant amount of power tooperate pumps and blowers for gas andsolvent circulation. The largest parasitic

load to the power cycle is associated withthe steam used for solvent regeneration.Energy consumption as steam can be ashigh as 3.6 to 4.5 106/ton CO2 recovered.Additional issues with the process areequipment corrosion; solvent degradationcaused by the presence of dissolved O2 andother impurities; or reaction with SO2, SO3,and NOx to produce nonregenerable, heat-stable salts. This requires SO2 levels below10 ppm, NO2 levels below 20 ppm, and NOxbelow 400 ppm. Solvent degradation andloss also occur during regeneration.

Recent advances in chemical solvents haveincluded the commercial introduction ofthe KS-family of hindered amines byMitsubishi Heavy Industries (MHI). Theirmolecular structure is tailored to enhancereactivity toward a specific gas component,in this instance CO2. Benefits relative toMEA include higher absorption capacity(only 1 mol of hindered amine is required

to react with 1 mol CO2 compared with2 mol MEA), 90% less solvent degradation,20% lower regeneration energy, 15% lesspower, 40% lower solvent recirculationrates due to higher net absorptioncapacity, lower regeneration temperature,less corrosion in the presence of dissolvedoxygen, and lower chemical additive cost.

Other advanced liquid sorbent systemsbeing developed include:

Potassium carbonate/piperazinecomplex (University of Texas atAustin, which may permit the use ofwaste heat because the regenerationtemperature is lower (131 vs.248F).

Aqua (Aqueous) Ammonia Process(Powerspan, National Energy

Technology Laboratory [NETL]),which has the ability to also captureSO2, NOx, HCl, and HF and toproduce potentially marketable by-products.

PSR solvents (University of Regina,Saskatchewan), which areproprietary designer solventsformulated for optimized separationof CO2 from any gas stream.

These chemical solvent systems are beingdeveloped to improve the cost-effectivenessof CO2 capture through higher CO2absorption capacity, faster CO2 absorptionrates (to achieve lower solvent circulationrates and smaller equipment), reducedsolvent degradation, less corrosiveness,and lower regeneration energyrequirements. Development efforts forthese technologies range from bench topilot scale.

Dry, regenerable, solid sorbents are alsobeing developed for postcombustion CO2capture in both low- and elevated-temperature flue gas. With these sorbents,essentially pure CO2 (>99%) is recovered

owing to selective absorption of CO2. Dryregenerable solid sorbent systems underdevelopment include:

Alkali carbonate system (ResearchTriangle Institute [RTI]).

Amine-enriched sorbents (NETL).

The first process requires a multiplereactor system, with absorption occurringin one reactor and transfer of the loaded

sorbent to a second reactor forregeneration and release of CO2. Thesecond process involves cyclic use ofmultiple beds, similar to PSA/TSA.Because these are dry systems, there is noneed to heat and cool large amounts ofwater, as required in an MEA system,which leads to lower regeneration energyrequirements. Another advantage is the

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higher contact area for CO2 absorption.Development efforts for these technologiesare currently at the bench scale.

Membrane systems being developed for theseparation of CO2 from flue gas include:

Molecular gate membrane (ResearchInstitute of Innovative Technologyfor the Earth [RITE]), a cardo-polyimide membrane that isselective to CO2 permeation.

Kvaerner hybrid membraneabsorption system (KvaernerProcess Systems), a gasliquidmembrane contactor that replaces atraditional absorber. CO2 diffusesthrough a microporous,hydrophobic solid membrane intoliquid flow. The solvent, rather thanthe membrane, provides theselectivity. Compared to aconventional absorber, it weighs70% less and has a 65% smallerfootprint.

Precombustion RemovalPrecombustion removal principally refers

to near-complete capture of CO2 before fuelcombustion and would be implemented inconjunction with gasification (of coal, coke,waste, residual oil) or steam/partialoxidation reforming (of natural gas) toproduce syngas containing CO and H2.Subsequent shift conversion produces CO2from CO to allow maximum recovery ofcarbon (as CO2) while producing H2-richsyngas. The H2-containing syngas (with N2added for temperature control) can becombusted in gas turbines, boilers, or

furnaces.

Typical CO2 concentrations before captureare 25 to 40 vol% at pressures of 363 to725 psia. The high partial pressure of CO2,relative to that in flue gas, enables easierseparation through solvent scrubbing. Inrefineries and ammonia-productionfacilities, where H2-rich syngas is produced

by gas reforming, H2 recovery (by acid gasremoval) is performed using chemicalsolvents (e.g., Benfield or MDEA[methyldiethanolamine]). PSA is also used,but the CO2-rich stream may havesignificant residual fuel value, making it an

attractive stream for in-plant use.

The MDEA and Rectisol processes continueto be used for deep sulfur removal in IGCCapplications; bulk CO2 removal is alsoachieved. The Rectisol process removesCO2 and H2S in methanol at -94EF, whichrequires large amounts of gas cooling andreheating. With respect to potential futurerequirements for high (>90%) CO2 recoveryduring gasification, the double-stageSelexol process combining desulfurizationand CO2 separation is favored. The double-stage or double-absorber Selexol unitpreferentially removes H2S in one productstream and then removes CO2 as a secondproduct stream. The synthesis gas entersthe first absorber unit at approximately686 psia and 105F. In this absorber, H2Sis removed from the fuel gas stream byloading the lean Selexol solvent with CO2.

The CO2 -saturated solvent preferentiallyremoves H2S. The rich solution is

regenerated in a stripper by heating. Thestripper acid gas stream, consisting of33% H2S, 59% CO2, and water, is then sentto a Claus sulfur removal unit (U.SDepartment of Energy, 2002).

Following processing in the Claus unit,cleaned fuel gas from the first absorber iscooled and routed to the second absorberunit. In this absorber, the fuel gas iscontacted with lean solvent. The solventremoves approximately 97% of the CO2

from the fuel gas stream. The fuel gas fromthis second absorber is warmed andhumidified in the fuel gas saturator,reheated and expanded, and then sent tothe burner of the combustion turbine. CO2is flashed from the rich solution and isthen ready for compression anddehydration to pipeline-ready conditions.

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Although very effective for CO2 removal,current solvent absorption methodsproduce system efficiency lossesprincipally because of the need to cool theraw gas to near or below ambienttemperature. To improve overall power

generation efficiency, new CO2 separationapproaches are being developed for bothgasification and reforming applications.Most of these technologies are based onselective membrane systems.

New systems under development include:

Sorption-enhanced watergas shiftprocess (Air Products), in which awatergas shift catalyst is combinedwith CO2-selective hydrotalciteadsorbent. Multiple adiabatic fixedbeds are used for cyclicreaction/adsorption andregeneration.

CO2 selective membrane (Media andProcess Technology, University ofSouthern California), a membranereactor that combines watergasshift with CO2 removal. It employs atubular ceramic membrane,

permeable only to CO2, inside awatergas shift reactor.

Membrane watergas shift reactor(Eltron Research/SOFCo/Chevron

Texaco) is a catalytic membranereactor (CMR) that utilizes oxygentransport membrane technology tofacilitate in situ partial oxidationreforming. Syngas passes to a densemetal alloy membrane reactor tofacilitate selective permeation of H2

and enhanced shift. H2permeabilities are one order ofmagnitude higher than palladiumand two orders of magnitude lessexpensive. Sweet syngas is required,however.

Hydrogen membrane reformer(Norsk Hydro, SINTEF, and UiO) is a

two-reactor process that combinesreforming, watergas shift reaction,and H2 separation. It utilizes adense, mixed conducting membrane(MCM). Since the transport processis based on ion diffusion, the

selectivity of the membrane isinfinite as long as the membrane isgas impervious (barring any defects).

Palladium membrane reactor(NETL). This reactor systemcombines a palladium-basedmembrane with the watergas shiftreaction. The high temperature(1652EF) and pressure of operationand the catalytic effect of themembrane eliminate the need for aseparate watergas shift catalyst. Asulfur-tolerant membrane ispossible.

Hybrid alumina/organosilanemembrane (NETL). In this system,organic molecules are grafted onto asubstrate surface to attain higherselectivity toward CO2 permeation.

Electrical swing adsorption (Oak

Ridge National Laboratory) usescarbon-bonded activated carbonfiber as adsorption material.Adsorbed gas is removed by a low-energy electric current.

Thermally optimized polymermembrane (Los Alamos NationalLaboratory, Idaho NationalEngineering & EnvironmentalLaboratory, Pall Corporation,University of Colorado, Shell Oil

Company), in which polymer-basedmembranes exhibit high selectivitybecause of size-based exclusion andsolubility variances of moleculeswithin the polymer matrix. Polymermembranes have been commerciallysuccessful for a number ofindustrial applications. The intent of

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additional research is to increasethe temperature of application.

Inorganic nanoporous membrane(ORNL) with pore sizes of less than1 nm. Composite membranes made

of a ~2-m membrane (e.g.,alumina) layer on a ~450-m poroussupport structure can allowoperation at temperatures up to1852F.

Warm gas sodium-based solidsorbents (NETL) have beendeveloped for PSA/TSA applicationfor removal of IGCC syngas streams.

They rely on chemical reaction forCO2 capture. Regenerationtemperatures are currently too highat 1292F.

Other advanced processes and/orunconventional systems are beingdeveloped with the intent of improvingefficiencies and lowering the cost tocapture and purify CO2. These include:

Regenerative carbonate process(Alstom Power), which utilizes a

recirculating stream of lime (CaO) tocapture CO2 during combustion.Calcium carbonate is regenerated ina calciner to liberate pure CO2. Inthis process, there is nothermodynamic efficiency loss forCO2 capture.

Chemical looping gasification(Alstom Power). The intent of thisprocess is to produce a nearly pureCO2 stream and a medium-Btu gas

(>90% H2) after CO2 separation. Thehigh energy and cost penaltyassociated with O2 separation isavoided (it is similar in concept tochemical-looping combustion). Ituses two separate chemical loops,one for oxygen transfer and one forCO2 capture.

ZEC technology (ZECA Corporation),hydrogasification of carbon-basedfuel to H2 with CO2 capture in acarbonate cycle. It would achievepermanent sequestration of CO2through mineral carbonization. The

ultimate embodiment of the processis the high-efficiency (70% to 75%)conversion of H2 fuel gas toelectricity through application of acoal-compatible fuel cell (CCFC).

Unmixed fuel processor (UFP) (GEGlobal Research [GEGR]) is agasification process developed toconvert coal, steam, and air intohydrogen; sequestration-ready CO2;and a low-quality, high-temperatureair stream used for powerproduction in a gas turbine.Regenerable oxygen transfermaterial is used to provide oxygenfor the process; no external airseparation unit (ASU) is required.

CO2 hydrate (SIMTECHE, Nexant,Los Alamos National Laboratory) is abelow-ambient-temperature, high-pressure, aqueous-based process

that captures CO2 from syngasthrough the formation of CO2hydrates. H2 acts as an inert and isnot retained in the hydrate crystal.

The CO2 is recovered from thehydrate slurry by heating andreducing pressure.

Oxygen CombustionOxygen combustion is used in industry forthe treatment of nonferrous scrap andcould be applicable to process heaters,

large industrial and utility boilers, and gasturbines. Air is replaced with an enrichedor nearly pure oxygen stream producedfrom an ASU. A tempering medium such asrecycled flue gas or water is added tocontrol system temperatures and heatrelease/transfer. A CO2-rich stream isproduced, with the intended sequestrationapplication dictating the level of upgrading.

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For enhanced coalbed methane recovery(ECBM) or saline aquifer sequestration,only condensation of moisture may berequired as some constituents (e.g., N2) canbe present, and a supercritical, dense-phase fluid is not required. Under this

scenario, zero emissions would be possible.Where supercritical fluid is required, non-condensable contaminants such as N2,NOx, O2, and Ar can be removed byflashing in a gasliquid separator. Thelevels of noncondensable impurities andthermodynamics limit recovery of CO2 andaffect the purity of the sequestrationstream.

Oxygen combustion has severaladvantages. The volume of flue gasreaching downstream systems is one-thirdto one-fifth that of conventional coalboilers. Recycle of flue gas is limited to50% in current gas turbines, so flue gasvolumes to the HRSG would be reduced byhalf. The process produces a flue gasstream containing more than 80 vol% CO2,depending upon the fuel composition,purity of oxygen from air separation, andair leakage into the boiler.

Impurities such as SO2, NOx, particulate,and Hg become concentrated in the fluegas, thus reducing capital and operatingcosts for contaminant removal. NOx may below enough to eliminate further control,and capital and operating cost savings (forcontrol systems) may offset air separationcapital and operating costs.

Retrofit applications would be designed tomaintain the same steam outletconditions. The higher heat capacity of the

gas should potentially facilitate greaterheat absorption. Higher heat absorptionwould result in higher boiler efficiency, butthis would be offset by higher auxiliarypower load for fan power to the recycle gasfor temperature control.

Issues with oxygen combustion centerprincipally around the high cost for air

separation, which is currently attainable atvery large scale only by cryogenicdistillation. Relative to coal gasification,combustion requires up to three times theamount of oxygen because all of the carbonis converted to CO2. The air separation

unit capacity (and parasitic power load)likewise will be commensurately larger.Other issues include expected lower fluegas exit temperature (that may increasethe risk of low-temperature corrosion fromcondensation of sulfuric acid), burneroperation, flame stability, levels ofunburned carbon, flame luminosity andlength, and changes in slagging/foulingcharacteristics under the differentatmosphere.

Development efforts involving conventionalpulverized coal testing with oxygencombustion are at the scale of severalhundred kW and less. Developers andtesting organizations include CANMET,Mitsui Babcock, American Air Liquide,Babcock & Wilcox, Foster Wheeler NorthAmerica, and the Energy & EnvironmentalResearch Center.

Oxygen firing in circulating fluid-bed

boilers may have an advantage over pcfiring in that a significant degree oftemperature control can be achieved byrecirculating solids. Lower flue gas recyclewould reduce parasitic power load for fans.In addition, higher O2 concentrations maybe possible, resulting in a smaller boilerisland size and reduced capital cost.Development issues center aroundcontinuous solids recirculation. Currently,testing is at the large pilot scale withdevelopment efforts being conducted by

Alstom Power, ABB Lummus Global,Praxair, and Parsons Energy.

As previously mentioned, the high cost ofoxygen separation is a major issue withoxygen combustion. State-of-the-artcryogenic distillation air separation haslittle room for improvement or costreduction. Current development activities

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are centered on ion transport membranes.These are complex crystalline structureswith oxygen ion vacancies onto whichoxygen adsorbs and decomposes into ions.

The ions are transported through themembrane by sequential occupation of

oxygen ion vacancies with the iontransport balanced by the counterflow ofelectrons. Oxygen partial pressure providesthe driving force, which requires high-pressure air at temperatures above1292F. Barring the presence of defects,the membrane is selective to oxygentransport only.

The ion transport membranes cantheoretically integrate high-temperatureoxygen separation from air with the

combustion process, leading to asignificant reduction in parasitic power aswell as lower cost for O2 production.Development issues include materials ofconstruction, integration with or into theboiler, control of wall temperature (as aconsequence of combustion reaction), andcarbon formation. Developers and systemsinclude Praxair and Alstom Power (oxygentransport membrane [OTM]), and airproducts (ion transport membrane [ITM]).

Concepts being developed that utilize iontransport membranes for oxygenseparation include:

Advanced zero emission power(AZEP) process (Alstom Power,Norsk Hydro), which is utilized withconventional gas turbines. Air fromthe compressor is supplied to a newMCM reactor. The reactor combinesO2 separation, combustion, andheat transfer. Preliminaryevaluations show a 2% loss in plantefficiency for separation vs. a 10%loss with flue gas CO2 separation.

Integration into a fired boiler(Praxair) in which an OTM isincorporated directly into the boiler.It can be utilized with gaseous orliquid fuel.

Utilization with circulating fluidized-bed (CFB) or circulating moving-bed(CMB) boiler (Alstom Power). In thiscase, the OTM stands alone but isthermally integrated with the boiler.It requires a high-temperature air

source and is heated by in-bed heatexchange of CFB or CMB.

Other advanced processes and/orunconventional cycles are being developedwith the intent of improving efficienciesand lowering the cost to capture and purifyCO2. These include:

CO2 hybrid process (Foster WheelerNorth America). This processcombines oxygen-blown partialgasification with oxygen combustionof syngas in a gas turbine. The gasturbine exhaust provides sensibleheat and oxygen for charcombustion to produce steam forpartial gasification. Flue gas fromthe char combustion contains all ofthe CO2 from the process; recoveryis accomplished by compression andflash of noncondensables.

Chemical looping combustion orsorbent energy transfer system (TDAResearch, Alstom Power, ChalmersUniversity). In this technology,separation of CO2 occurs duringcombustion, and no energy isexpended for CO2 separation. Thereis no direct contact of fuel with air,and no air separation unit isrequired. An oxygen carriertransfers oxygen from thecombustion air to the fuel. The net

chemical reaction and heat releaseis equivalent to that of conventionalcombustion. The process iscurrently applicable only to gaseousor liquid fuels unless the solid fuelis first gasified in O2.

Water cycle (Clean Energy Systems)is based on a high-

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temperature/pressure aerospace-derived gas generator operating at1500 psi and 3000F. The fuel isfired stoichiometrically with oxygen,and water is injected to controltemperature and protect gas

generator components. The workingmedium is a high-pressure, high-temperature steamCO2 mixturecomprising 90% steam and 10%CO2.

Graz cycle (Institute for ThermalTurbomachinery and MachineDynamics). As with the water cycle,it uses a 25:75 steamCO2 mixtureas the working fluid. It combines thegas turbine cycle with the steamcycle to improve efficiency. Gaseousfuel is reacted with stoichiometricoxygen in the combustor at 580 psi,with steam (as opposed to water)injected for temperature control.

MATIANT cycle (Institute ofMechanical Engineering, Universityof Liege [Belgium]) combines aBrayton-like cycle (in which CO2serves as the principal working

fluid) with a steam cycle.

IMPACT OF CO2 CAPTURE ON SYSTEMEFFICIENCY

Gttlicher (2004) has summarized CO2removal systems for fossil fuel-fired powerplants and divided them into the followingfive groups:

Process Group I comprisesprocesses with CO shift or steam

reforming prior to CO2 removal. Theresulting hydrogen-rich fuel gas canthen be combusted with air afterH2/CO2 separation.

Process Group II covers processeswhere fuel is combusted in anatmosphere of oxygen mixed withrecycled CO2 or steam.

Process Group III includes all kindsof fossil fuel-fired power generationsystems in which CO2 is removedfrom the flue gas after combustionat the exhaust end of the plant.

Process Group IV includes theHydrocarb processes wherebycarbon is separated from the fuelprior to combustion.

Process Group V deals with CO2separation in fuel cells suitable forthe use of fossil fuel-derived gases.

Gttlicher (2004) states that CO2separation processes applied to a fossilfuel-fired power plant result in additionalparasitic energy consumption andreduction of power output. Assuming apipeline pressure of 1595 psia, the energyrequirement for liquefaction by intercooled5-stage compression starting from14.5 psia amounts to about 0.06 kWh/lbCO2. For 90% CO2 removal, the CO2liquefaction reduces the efficiency of aPittsburgh No. 8 coal-fired power plant by3.1 percentage points, while the efficiencyof natural gas-fired power plants is

reduced by 2.0 percentage points. Thesereductions in efficiency depend on thecarbon content and heating value of thefuel and the extent of CO2 removal. Thefollowing figures on efficiency reduction arebased on the assumption that the CO2removed is at 14.5 psia.

Process Group IIn Process Group I, the efficiency reductiondue to CO2 removal is predominantlycaused by:

Energy destruction because ofsteam reforming or gasification andCO shift results in an overallefficiency reduction of 2.5 to5 percentage points.

Energy demand of the gasseparation process (i.e.,

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regeneration, compression) reducesefficiency by about 1 percentagepoint.

Volume displacement of theseparated carbon dioxide produces

an efficiency reduction of about1 percentage point.

The efficiency reductions for ProcessGroup I range from 4 to 7.4 percentagepoints for an IGCC with CO shift (in which80% to 90% of the CO2 is removed) andaround 14.5 percentage points for anatural gas-fired combined cycle withsteam reforming, CO shift, and absorptionby MDEA (resulting in CO2 removal below60%).

Process Group IIEfficiency reductions because of O2/CO2firing (as cited in the literature and ascalculated by the authors) range from 4.8to 8.5 percentage points for IGCC powerplants and about 6 percentage points fornatural gas-fired plants.

Process Group IIIIn this process scheme, most of the

concepts apply flue gas scrubbing withamine-based chemical sorbent. Suchremoval processes consume up to two-thirds of the steam during solventregeneration. Efficiency figures cited in theliterature are in the range of 8 to11 percentage points when 80% to 90% ofthe CO2 is removed from coal-poweredplants or 5.5 to 11 percentage points whenremoved from gas turbine combined-cycle(GTCC) plants.

Process Group IVThese processes separate carbon from thefuel prior to combustion. This option is areasonable approach only for fuelscontaining a high proportion of hydrogen.For example, in the Hydrocarb process, afuel mixture consisting of biomass andnatural gas or oil undergoes hydropyrolysisto form a methane-rich fuel gas, which

then goes to a methane cleavage reactorwhere H2 and carbon are produced. Thecarbon is separated from the H2 stream.

The specific CO2 emissions of the fuel thatis produced by this process group arelower than the CO2 emissions from the

feedstocks. Conversion efficiencies (on anHHV basis) for various mixtures of biomassand coal, oil, or natural gas range from3.5% (for hydrogen production frombiomass only) to 71.6% (for synthesis gasproduction from biomass and methane).Comparison of this process with other CO2removal options discussed earlier requiresmultiplication of the conversion efficiencyby a cycle or plant efficiency (i.e., forreciprocating engines, steam and gasturbine cycles, etc.).

Process Group VPhosphoric acid fuel cells (PAFC), moltencarbonate fuel cells (MCFC), and solidoxide fuel cells (SOFC) can be operatedwith fossil fuel-derived gases. Theefficiency of power plants with PAFC isbelow the efficiencies of other combinedcycles. MCFC or SOFC combined cycles areexpected to achieve higher efficiencies. Inall three cases, extra energy demand in the

range of 0.02 to 0.05 kWh/lb CO2 isrequired for the necessary separation ofresidual fuel, and the CO2 removal rate isprobably limited to around 80% withspecific CO2 emissions of 0.33 to 0.37 lb ofCO2 per kWh.

COST OF CO2 CAPTURE INREPRESENTATIVE COMMERCIAL POWERGENERATION SYSTEMS

Capital and operating cost data for CO2

capture were calculated for threecommercial power generation technologies(U.S. Department of Energy [DOE], 2002,2004). The case numbers have been takenfrom studies performed by DOE, EPRI, andParsons. The three systems include:

Case 1B natural gas turbinecombined cycle (GTCC).

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Case 3E coal gasificationcombined cycle (IGCC).

Case 7A supercritical steampulverized coal-fired (SCPC).

Table 2 presents the major performancemetrics for the three cases with CO2removal. For comparison, the net plantefficiencies for 1B, 3E, and 7A without CO2removal are 53.6%, 43.1%, and 40.5%,respectively.

Gas Turbine Combined CycleCase 1B is a GTCC plant using a single-train General Electric H-class gas turbinewith CO2 removal using an amine process.Net generation is 311 MWe at a higherheating value (HHV) efficiency of 43.3%.

The power plant design includes removal of90% of the CO2 from the HRSG flue gas.An aqueous solution of inhibited (oxygen-tolerant) MEA is used to remove the CO2,which is then concentrated, dried, andcompressed to a supercritical conditionsuited for pipeline transport.

Table 3 presents the costs estimated forthe GTCC power plant with and without

CO2 removal. The table shows that the cost

of CO2 removal and compression is roughly$85 million. The cost of CO2 removal andcompression can be estimated as thedifference between the plant with removal(Case 1B) and the plant without (Case 1D),or $447/kW. This exercise shows that CO2

removal makes up about 35% of the totalplant cost.

Integrated Gasification Combined CycleThe IGCC example in the DOE report usesadvanced technology for both the gasifier(high-pressure E-Gas technology) andgas turbine (General Electric H-classadvanced turbine system [ATS] machine)featuring the gas turbine and steamturbine on a single shaft and generator.

The gasification case with CO2 removal isdesignated 3E in the report and in Table 4.

Estimation of the cost for CO2 removal issomewhat more complex for thegasification plant because some of the gascleaning would be needed whether or notCO2 is a required product. Additionally,equipment costs other than those requiredfor watergas shift equipment may benecessary.

Table 2. Summary of Power System Performance with CO2 Removal

DOE/EPRI/Parsons Cases

Major Performance Metrics1B,

GTCC3E,

IGCC7A,

SCPC

Gross Plant Power, kWe 343,107 474,275 402,254

Auxiliary Power Load, kWe 32,290 87,490 72,730

Net Plant Power, kWe 310,817 386,785 329,294Net Plant HHV Efficiency, % 43.3 35.4 28.9

Net Heat Rate, Btu/kWh HHV 7879 9638 11,816

CO2 Removed, ton/day 3105 8158 8525

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Table 3. GTCC Plant with and Without CO2 Removal

Bare Erected CostCase 1B (with

removal) Cost, $KCase 1D (withoutremoval) Cost, $K

Difference 1B !1D, $K

CO2 Removal andCompression

85,024 0 85,024

Combustion Turbineand Accessories

52,608 52,608 0

HRSG, Ducting andStack

20,737 20,844 !107

Steam T-G Plant,including coolingwater system

16,936 36,342 !19,406

Accessory ElectricPlant

19,948 13,551 6397

Balance of Plant 35,076 28,954 6122

Subtotal 230,329 152,299 78,030

Engineering Servicesand Fee

13,820 9138 4682

Process Contingency 11,262 5172 6090

Project Contingency 37,555 24,141 13,414

Total Plant Cost (TPC) 292,965 190,749 102,216

TPC, $/kW 943 496 447

The DOE report also describes an IGCCsystem, Case 3B, in which CO2 is notrecovered. For Case 3B, the plant uses aproprietary amine solvent in a traditionalabsorber/stripper arrangement to removeH2S from the fuel gas stream, after whichelemental sulfur is recovered in a Clausplant.

Costs reported for the CO2 removal(Case 3E) gasification plant are presentedin Table 4. The costs associated with CO2removal, capture, and compression hasbeen estimated by determining the

difference between the cases with andwithout CO2 removal. The estimated unitcost of $399/kW is less than the $447/kWthat was estimated for the natural gascombined-cycle case, indicating that thegasification process may be more amenableto the chemical steps needed to modify thepower generation design for CO2 recoveryand sequestration. Owing to reduced fuel

cost, the gasification process may also beless expensive to operate with CO2 capture.

This is shown in Table 5, which presentsthe estimated first-year operating costs forthe natural gas combined-cycle and IGCCplants.

Supercritical PCThe DOE Case 7A is a coal-fired,supercritical steam plant with CO2 removaland recovery. The coal-fired boiler is stagedfor low NOx formation and is also equippedwith a selective catalytic reformer and awet limestone forced-oxidation FGD to

limit SO2 emissions. A once-through steamgenerator powers a double-reheatsupercritical steam turbine with a poweroutput of 402 MWe. The steam turbineconditions are 3500 psig/1050F throttlewith 1050F at both reheats. Net plantpower, after consideration of the auxiliarypower load, is 329 MWe. The plantoperates with an estimated HHV efficiency

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Table 4. IGCC Plant with and Without CO2 Removal

Bare Erected CostCase 3E (with

removal) Cost, $KCase 3B (withoutremoval) Cost, $K

Difference 3E !3B, $K

Gasifier, ASU, andAccessories

128,621 130,308 !1687

Gas Cleanup and Piping 73,607 26,496 47,111CO2 Compression 42,662 0 42,662Combustion Turbine and

Accessories62,161 61,863 298

HRSG, Ducting, andStack

20,429 20,684 !255

Steam T-G Plant,including cooling watersystem

33,436 36,618 !3182

Accessory Electric Plant 27,855 23,066 4789Balance of Plant 80,209 77,260 2949Subtotal 468,980 376,295 92,685Engineering Services and

Fee28,139 22,578 5561

Process Contingency 17,647 16,267 1380Project Contingency 69,347 56,340 13,007

TPC 584,112 471,480 112,6 TPC, $/kW 1510 1111 399

of 28.9% at a corresponding heat rate of11,816 Btu/kWh. Flue gas from the FGDsystem goes to an inhibited MEA absorber

stripper system where 90% of the CO2 isremoved.

The costs reported for the supercritical PCcases with and without CO2 removal (i.e.,7A and 7C, respectively) are presented in

Table 6. Large increases in both total plantcosts and unit cost per kW are indicated.

Comparison of GTCC, IGCC, and SCPCA summary of plant efficiency, poweroutput, plant cost, and cost of electricity is

presented in Table 7 for the three powersystems with CO2 capture. Results are alsopresented for the baseline plants forcomparison. Costs are based on a 90% CO2capture level, coal costs of $1.24/millionBtu natural gas costs of $2.70/million Btu,and a capacity factor of 80%. The resultspresented in Table 7 show that each powergeneration system is impacted by the

addition of CO2 capture technologies. Plantpower output reductions vary fromapproximately 9% for IGCC to as high as

almost 30% for supercritical PC. Theimpact on IGCC is the least because thehigh pressure of operation and highrelative CO2 concentration allows CO2 to becaptured using the more efficient physicalsolvent.

A more recent study by the CO2 CaptureProject (CCP) shows a trend towardreduced costs and improved performance.In a paper presented at the 2004 CarbonSequestration Conference (U.S.

Department of Energy, 2004), results werereported for conceptual design workperformed to reduce the performance andcost penalties imposed by CO2 capture onGTCC power generation. The workevaluated a base case using technologyand designs associated with todays use ofamine capture systems, largely in thecontext of petroleum refineries. The study

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Table 5. Operating Costs of GTCC and IGCC with CO2 Removal

First-Year Cost Case 1B, GTCC, $K Case 3E, IGCC, $K

Operating Labor 2064 5503

Maintenance 5846 11,828

Administrative and Support Labor 1100 2559

Consumables 5014 1927

By-Product Credits NA* !972

Fuel 37,649 26,321

TPC 51,673 * Not applicable

Table 6. Supercritical Steam Plant Cost Data with and Without CO2 Removal

Bare Erected Cost

Case 7A (withremoval) Cost,

$KCase 7C (withoutremoval) Cost, $K

Difference7A ! 7C, $K

PC Boiler and Accessories 108,950 109,560 !610

Flue Gas Cleanup 59,410 61,490 !2080

CO2 Removal andCompression 111,770 NA 111,770

Ducting and Stack 18,010 20,540 !2530

Steam T-G Plant, includingcooling-water system 79,380 92,470 !13,090

Accessory Electric Plant 31,340 24,150 7190

Balance of Plant 121,570 125,840 !4270

Subtotal 530,430 434,050 96,380

Engineering Services and Fee 31,830 26,040 5790

Process Contingency 6020 NA 6020

Project Contingency 84,140 67,990 16,150

TPC 652,420 528,080 124,34

TPC, $/kW 1981 1143 838

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Table 7. Plant Impact and Avoided CO2 Costs

Natural GasCombined Cycle

GasificationCombined Cycle Supercritical PC

1DWithout

Capture

1Bwith

Capture

3BWithout

Capture

3Ewith

Capture

7CWithout

Capture

7Awith

CaptureNet Plant Output, MW 384 311 425 387 462 329

Energy Penalty, % 19.0 8.9 28.8

Net Plant Efficiency, % 53.6 43.3 43.1 35.4 40.5 28.9

Plant Cost, $/kW $496 $943 $1111 $1510 $1143 $1980

Cost of Electricity(COE), /kWh

3.07 4.88 4.10 5.36 4.48 7.39

Incremental COE,/kWh

1.81 1.26 2.91

Avoided CO2 Cost,$/ton

$54.79 $17.69 $39.55

then evaluated degrees of designintegration and simplification (the low-cost and low-cost integrated cases). Theresults are given in Table 8. The bestintegrated technology design assumesimprovements in amine performance inaddition to the equipment and design costreductions included in the low-cost andlow-cost integrated cases. The reduction of

avoided cost from about $54 to $26/ton issignificant and, while still higher thanDOEs goal of $10/ton, indicates a positivetrend.

CASE STUDY OF THE ENGINEERINGFEASIBILITY AND ECONOMICS OF CO2CAPTURE ON AN EXISTING COAL-FIREDPOWER PLANT

Alstom Power Inc., ABB Lummus GlobalInc., and American Electric Power assessed

the retrofit of CO2 capture technologies forUnit No. 5 of the AEP Conesville PowerPlant (Alstom Power, 2001). Alstom Powerexamined three retrofit concepts termed A,B, and C and defined as follows:

A. Conventional coal combustion inair, followed by CO2 separation with

a commercial MEA-based absorptionand stripping process.

B. Coal combustion in oxygen with fluegas recycle for temperature control(oxycombustion).

C. Coal combustion in air with oxygenremoval and CO2 separation using a

mixture of MEA and MDEA.

Each concept was compared to the basecase, i.e., the existing plant operatingwithout CO2 capture. The study concludedthat:

There are no major technicalbarriers to prevent application of theconcepts.

Gas cleaning and compression are

relatively simple.

Energy penalties for capture andcompression are high for all of theconcepts. Net plant output isreduced from the base case by 59%(for Concept C) to 77% (forConcept A).

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Specific costs are high, ranging from$800 to $1800/kW withreplacement power included andfrom $1000 to $2200/kW whenreplacement power is not included.

The incremental cost of electricityranges from 3.4 to 8.4 cents/kWhand the avoided CO2 cost rangesfrom $42 to $98/ton of CO2.

The CO2 capture ranged from 91%

to 96% of the amount generated.

The oxycombustion concept is thebest alternative of the three basedon incremental cost of electricityand mitigation cost evaluationcriteria.

The processes used in the three conceptsare basically the same as described earlierfor oxycombustion and amine capturetechnologies. Important aspects specific tothe three concepts that were studiedinclude:

For Concept A, solvent regenerationrequires approximately 4.7 million

Btu/ton CO2. In the Alstom study,steam from the intermediatepressure turbine served as thesource of the thermal energy.

A conventional cryogenic ASUprovides the oxygen for combustionin Concept B.

In Concept C, the oxygen in the fluegas would poison the sorbents,requiring conversion to CO2 by

burning natural gas in a De-Oxycatalyst process. The CO2 couldthen be removed with the mixture ofMEA and MDEA. Solventregeneration requires about3.4 million Btu/ton CO2 or 72% ofthat required in Concept A.

Table 9 presents major plant performanceestimates for the three concepts. Net plantoutput was significantly reduced as aresult of the CO2 capture systems, whichcan be easily seen in the table. Therefore,each concept was also analyzed with

replacement power making up thedifference. It was assumed thatreplacement power would be supplied by anatural gas-fired turbine combined-cycle(GTCC) operation with an efficiency of57.1% on a lower heating value (LHV)basis. CO2 would not be captured duringthe production of replacement power.

Net plant efficiencies are reduced from35% (HHV basis) for the base case to20.5% for Concept A, 22.5% for Concept B,and 22.4% for Concept C (all calculatedwithout replacement power). The efficiencyof the oxycombustion concept is similar tothe other concepts despite its much largerauxiliary power requirement because theother concepts consume large amounts ofsteam, thus penalizing their efficiencies.

The reported costs for the three conceptsare shown in Table 10. The specific costs($/kW) are based on the lower net output

in cases without replacement power. Thereplacement power is assumed to be GTCCwithout CO2 capture capabilities (asdescribed in the previous paragraph),which is priced at $450 per kW installed.

Annual operating and maintenance (O&M)costs for the base case are about $16/kWof fixed O&M and about $0.0045/kWh forvariable O&M. The variable costs are solelyfor FGD lime and for ash and sludgedisposal. Incremental costs for Concepts A,

B, and C were calculated to range fromabout 0.4 to 0.6 cents/kWh for fixed costsand about 0.9 to 2.3 cents/kWh forvariable O&M.

The report also performed a sensitivityanalysis in which 66 CO2 capture caseswere compared. All of the cases indicatedthat the cost of electricity would

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Table 9. Conesville Station Performance Data (without replacement powerunless otherwise noted)

Performance ItemBase CaseNo Capture

Concept AMEA

Concept BOxycombustion

Concept CMEA and

MDEA

Coal Energy Input,millionBtu/h

4229 4229 4140 4229

Natural Gas EnergyInput, million Btu/h

0 18 11 886

Total Energy Input,million Btu/h

4229 4247 4151 5114

Total T-G Output,kW

463,478 331,422 463,056 431,290

Total Auxiliary

Power, kW 29,700 76,007 189,709 95,317

Net Plant Output,kW

433,778 255,414 273,347 335,973

Net PlantEfficiency,%, HHV

35.0 20.5 22.5 22.4

Net Plant Efficiencywith ReplacementPower, % HHV

NA 27.3 28.4 25.7

Net Plant Heat Rate,Btu/kWh, HHV 9749 16,626 15,188 15,223

Table 10. Concept Costs for the Conesville Station CO2 Capture Retrofit

Concept Units

WithoutReplacement

PowerWith Replacement

Power

$ millions 409 489A. MEA Scrubbing

$ per kW 1602 1128

$ millions 285 357B. Oxygen Combustion

$ per kW 1042 823

$ millions 738 782C. MEA MDEAScrubbing $ per kW 2197 1803

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significantly increase as a result of CO2capture but that the oxygen combustiontechnology, Concept B, would result in thelowest incremental cost of electricity(12%to 19% lower than Concept A and47% to 51% lower than Concept C) of the

concepts studied for CO2 capture over90%. Similar results were obtained whenmitigation costs were compared. If less CO2could be captured, Concept A wouldprobably be the best alternative.

ESTIMATION OF CAPTURE COSTS FORIMPORTANT CO2 SOURCES IN THE PCORPARTNERSHIP REGION

A spreadsheet tool was prepared tosupport the PCOR Partnerships evaluation

of options for CO2 sequestration. Theobjective of the spreadsheet is to calculateperformance and cost estimates for variousCO2 separation and capture scenarios forthree important CO2 sources in the PCORPartnership region: power generation,petroleum refining, and cementproduction. An effort was made to provideconsistent estimates across all of theoptions; therefore, the results are bestused for screening and comparison.Because performance and cost for many

components within the systems arevariable, plant-, site-, or technology-specific evaluations would requireadditional process design and engineeringfor each specific case. Costs and otherimpacts of replacement power are notcurrently considered in the spreadsheettool. All of the spreadsheets calculate costsfor the production of the CO2 stream at theappropriate pressure for pipeline transportand sequestration. The spreadsheet wasdeveloped using the guidelines prescribed

in the Carbon Capture and SequestrationSystems Analysis Guidelines prepared byNETL and dated April 2005.

Power GenerationCoal-fired power generation is the largeststationary source of CO2 in the PCORPartnership region. The spreadsheet tool

can be used to calculate the CO2 capturecost for six different subcritical pc unitsfiring either lignite, bituminous orsubbituminous coal:

Plants without CO2 removal withSO2 and NOx control.

Plants without CO2 removal or SO2or NOx control.

Retrofit plants with amine systemCO2 removal.

New plants with amine system CO2removal.

Retrofit plants with oxygencombustion systems.

New plants with oxygen combustionsystems.

The spreadsheet can also be used tocalculate the cost of CO2 removal in IGCCand GTCC plants.

Several subcritical pulverized lignite-firedunits are located in west-central North

Dakota, so plant performance and CO2capture costs were estimated for retrofitplants with 1) an amine system and 2) anoxygen combustion system. The results,presented in Table 11, indicate that bothcapture methods are similar in net thermalefficiency. The cost to produce electricityfor the oxygen combustion system isroughly 30% higher than the amine plant.

The table presents both capture andavoided cost for power plants. The capturecost is the actual cost of removing the CO2

from the flue gas and is calculated bysubtracting the cost of electricity of thereference case without CO2 removal fromthe cost of electricity for the case with CO2removal and converting this differentialcost of electricity to an annual cost andthen dividing by the tons of CO2 removedper year. In the case of power plants, inwhich some of the power produced is used

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Table 11. Estimates for CO2 Capture in Typical PCOR Partnership Lignite-FiredPower Plants

Subcritical PC PlantWithout CO2 Removal

RetrofitPlant, amine

process

Retrofit Plant,oxygen

combustion

Net Thermal Efficiency, % 33.0 23.5 21.2Cost of Electricity, /kWh 2.0 2.5 3.3

CO2 Capture Cost, $/ton CO2 NA 23.2 31.6

Avoided Cost, $/ton CO2 NA 35.0 54.7

to capture the CO2, it is usually consideredmore appropriate to express the costs ofCO2 avoided, sometimes referred to as themitigation cost. This is calculated bycomparing a plant with removal to a

reference plant without removal by dividingthe differential cost of electricity by thedifference between the quantity of CO2emitted by the plant without removal andthe quantity of the CO2 emitted by theplant with CO2 removal (Haines et al.,2004).

The costs of producing electricity are in therange of those calculated for the ConesvilleStation retrofit case study. Avoided CO2costs calculated by the spreadsheet are

slightly lower than the range calculated forthe case study.

Other IndustriesSpreadsheets were also developed for twoof the PCOR Partnership regions largeststationary CO2 sources: petroleum refiningand cement production. To construct thespreadsheets, data from power generationstudies were combined with data from theindustry and CO2 production and capturevia amine systems. These performance andcost estimates are considered to be order-of-magnitude approximations.

The spreadsheets were used to estimateCO2 removal costs of $50.77/ton and$45.54/ton for typical PCOR Partnershippetroleum refining and cement productionoperations, respectively.

CONCLUSIONS

Several conclusions can be drawn aboutthe cost and effectiveness of technologiesthat can be used to capture CO2 from large

industrial sources:

A wide range of CO2 separation andremoval processes are eitheravailable or under development.

The concentrations of SO2, SO3, andNOx in flue gas limit the techniquesthat can be applied to the capture ofCO2 from fossil fuel-fired powerplants, the largest source of CO2emissions in the United States.

When applied to fossil fuel-firedpower plants, CO2 separationprocesses reduce power outputthrough an increase in energyconsumption. Efficiency reductionscan range from 2% to roughly 11%,depending upon the fuel, the plantconfiguration, and the type ofcapture system.

Calculated avoided CO2 costscurrently range from roughly $18 to$55/ton. Improvements in bothdesign integration/simplificationand sorbents are reducing thesecosts.

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Oxygen combustion technology wasfound to be the best alternative forCO2 capture for a bituminous coal-fired power plant. The PCORPartnership cost and efficiencyestimations for lignite-fired power

plants reached similar conclusions.

The spreadsheet tool developed foruse by the PCOR Partnership toscreen scenarios and estimate costand performance of source/capturetechnology pairs appears to produceresults that agree reasonably wellwith other studies and models.

REFERENCES

Alstrom Power, 2001, Engineeringfeasibility and economics of CO2capture on an existing coal-fired powerplant: Final Report by Alstom PowerInc., ABB Lummus Global Inc.,American Electric Power for the OhioCoal Development Office and the U.S.Department of Energy, National Energy

Technology Laboratory ContractDE-FC-26-99FT40576 June 2001,www.netl.doe.gov/coal/Carbon%20

Sequestration/pubs/analysis/AlstomReport.pdf(accessed June 2005).

CO2 Capture Project. www.co2capture project.org/index.htm (accessed

June 2005).

DOE NETL. www.netl.doe.gov/coal/(underCarbon Sequestration) (accessedMay 2005).

EPRI and U.S. Department of Energy,2000, Evaluation of innovative fossilfuel power plants with CO2 removal:EPRI, Palo Alto, California, U.S.Department of Energy Office of FossilEnergy, Germantown, Maryland and

U.S. Department of Energy/NationalEnergy Technology Laboratory,Pittsburgh, Pennsylvania, 1000316www.netl.doe.gov/coal/gasification/pubs/pdf/EpriReport.PDF (accessedMay 2005).

Gttlicher, G., 2004, The energetics ofcarbon dioxide capture in power plants:U.S. Department of Energy Office ofFossil Energy National Energy

Technology Laboratory, February 2004.

Haines, M., Leslie, J., and Macdonald, D.,2004, Co-capture and storage of CO2with other impurities from coal andheavy fuel-fired power plant flue gases:Presented at the 7th InternationalConference on Greenhouse Gas Control

Technologies, Vancouver, BritishColumbia, September 2004, Paper 498.

IEA Greenhouse Gas R&D Programme

www.co2sequestration.info (accessedJune 2005).

NETL, 2005, Carbon capture andsequestration systems analysisguidelines: www.netl.doe.gov/coal/

carbon%20Sequestration/pubs/CO2CaptureGuidelines.pdf(accessed

June 2005).

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http://www.netl.doe.gov/coal/Carbon%20Sequestration/pubs/analysis/AlstomReport.pdfhttp://www.netl.doe.gov/coal/Carbon%20Sequestration/pubs/analysis/AlstomReport.pdfhttp://www.netl.doe.gov/coal/Carbon%20Sequestration/pubs/analysis/AlstomReport.pdfhttp://www.co2captureproject.org/index.htmhttp://www.co2captureproject.org/index.htmhttp://www.co2captureproject.org/index.htmhttp://www.co2captureproject.org/index.htmhttp://www.co2captureproject.org/index.htmhttp://www.netl.doe.gov/coal/http://www.netl.doe.gov/coal/http://www.netl.doe.gov/coal/gasification/pubs/pdf/EpriReport.PDFhttp://www.netl.doe.gov/coal/gasification/pubs/pdf/EpriReport.PDFhttp://www.co2sequestration.info/http://www.co2sequestration.info/http://www.netl.doe.gov/coal/carbon%20Sequestration/pubs/CO2CaptureGuidelines.pdfhttp://www.netl.doe.gov/coal/carbon%20Sequestration/pubs/CO2CaptureGuidelines.pdfhttp://www.netl.doe.gov/coal/carbon%20Sequestration/pubs/CO2CaptureGuidelines.pdfhttp://www.netl.doe.gov/coal/carbon%20Sequestration/pubs/CO2CaptureGuidelines.pdfhttp://www.netl.doe.gov/coal/carbon%20Sequestration/pubs/CO2CaptureGuidelines.pdfhttp://www.co2sequestration.info/http://www.netl.doe.gov/coal/http://www.netl.doe.gov/coal/carbon%20Sequestration/pubs/CO2CaptureGuidelines.pdfhttp://www.netl.doe.gov/coal/gasification/pubs/pdf/EpriReport.PDFhttp://www.netl.doe.gov/coal/gasification/pubs/pdf/EpriReport.PDFhttp://www.co2captureproject.org/index.htmhttp://www.netl.doe.gov/coal/Carbon%20Sequestration/pubs/analysis/AlstomReport.pdfhttp://www.netl.doe.gov/coal/Carbon%20Sequestration/pubs/analysis/AlstomReport.pdfhttp://www.netl.doe.gov/coal/Carbon%20Sequestration/pubs/analysis/AlstomReport.pdf


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U.S. Department of Energy, 2002, Updatedcost and performance estimates forfossil fuel power plants with CO2removal: Interim Report 1004483,Cosponsors U.S. Department of EnergyOffice of Fossil Energy, National Energy

Technology Laboratory, and EPRI.Prepared by Parsons Infrastructure and

Technology Group, December 2002,www.netl.doe.gov/coal/Carbon%20Sequestration/pubs/analysis/Updated%20Costs.pdf(accessed May 2005).

U.S. Department of Energy, 2004, Costefficient amine plant design for postcombustion CO2 capture from powerplant flue gas: U.S. Department ofEnergy, National Energy TechnologyLaboratory 3rd Annual Conference onCarbon Capture and Sequestration,Alexandria, Virginia, May 36, 2004,www.uregina.ca.ghgt7/PDF/papers/nonpeer/379.pdf(accessed June 2005).

U.S. Environmental Protection Agency,2004, Inventory of U.S. greenhouse hasemissions and sinks: 19902002, U.S.Environmental Protection Agency,Washington, DC, 2004.

For more information on this topic, contact:

Melanie D. Jensen, EERC Research Engineer(701) 777-5115; [email protected]

Edward N. Steadman, EERC Senior Research Advisor(701) 777-5279; [email protected]

John A. Harju, EERC Associate Director for Research(701) 777-5157; [email protected]

Visit the PCOR Partnership Web site atwww.undeerc.org/PCOR.
http://www.netl.doe.gov/coal/Carbon%20Sequestration/pubs/analysis/Updated%20Costs.pdfhttp://www.netl.doe.gov/coal/Carbon%20Sequestration/pubs/analysis/Updated%20Costs.pdfhttp://www.netl.doe.gov/coal/Carbon%20Sequestration/pubs/analysis/Updated%20Costs.pdfhttp://www.uregina.ca.ghgt7/PDF/papers/nonpeer/379.pdfhttp://www.uregina.ca.ghgt7/PDF/papers/nonpeer/379.pdfhttp://www.undeerc.org/PCORhttp://www.undeerc.org/PCORhttp://www.undeerc.org/PCORhttp://www.undeerc.org/PCORhttp://www.undeerc.org/PCORhttp://www.uregina.ca.ghgt7/PDF/papers/nonpeer/379.pdfhttp://www.uregina.ca.ghgt7/PDF/papers/nonpeer/379.pdfhttp://www.netl.doe.gov/coal/Carbon%20Sequestration/pubs/analysis/Updated%20Costs.pdfhttp://www.netl.doe.gov/coal/Carbon%20Sequestration/pubs/analysis/Updated%20Costs.pdfhttp://www.netl.doe.gov/coal/Carbon%20Sequestration/pubs/analysis/Updated%20Costs.pdf

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