Making Fischer-Tropsch Fuels and Electricity From Coal and Biomass

415r 2010 American Chemical Society pubs.acs.org/EF

Energy Fuels 2011, 25, 415–437 : DOI:10.1021/ef101184ePublished on Web 12/06/2010

Making Fischer-Tropsch Fuels and Electricity from Coal and Biomass:

Performance and Cost Analysis

Guangjian Liu,*,†,‡ Eric D. Larson,†,§ Robert H. Williams,† Thomas G. Kreutz,† and Xiangbo Guo†,^

†Princeton Environmental Institute, Princeton University, Guyot Hall, Washington Road, Princeton, New Jersey 08544,United States , ‡School of Energy, Power and Mechanical Engineering, North China Electric Power University,

Beijing 102206, China, §Climate Central, 1 Palmer Square, Princeton, New Jersey 08542, United States, and ^Research Institute ofPetroleum Processing, SINOPEC, Beijing, China

Received September 2, 2010. Revised Manuscript Received October 28, 2010

Major challenges posed by crude-oil-derived transportation fuels are high current and prospective oilprices, insecurity of liquid fuel supplies, and climate change risks from the accumulation of fossil fuel CO2

and other greenhouse gases in the atmosphere. One option for addressing these challenges simultaneouslyinvolves producing ultraclean synthetic fuels from coal and lignocellulosic biomass with CO2 capture andstorage. Detailed process simulations, lifecycle greenhouse gas emissions analyses, and cost analysescarried out in a comprehensive analytical framework are presented for 16 alternative system configurationsthat involve gasification-based coproduction of Fischer-Tropsch liquid (FTL) fuels and electricity fromcoal and/or biomass, with andwithout capture and storage of byproduct CO2. Systematic comparisons aremade to cellulosic ethanol as an alternative low GHG-emitting liquid fuel and to alternative options fordecarbonizing stand-alone fossil-fuel power plants. The analysis indicates that FTL fuels are typically lesscostly to produce when electricity is generated as a major coproduct than when producing mainly liquidfuel. Coproduction systems that utilize a cofeed of biomass and coal and incorporate CO2 capture andstorage in the design offer attractive opportunities for decarbonizing liquid fuels and power generationsimultaneously. Such coproduction systems considered as power generators can provide decarbonizedelectricity at lower costs than is feasible with stand-alone fossil-fuel power plant options under awide rangeof conditions. At a plausible GHG emissions price under a future U.S. carbon mitigation policy ($50/tCO2eq), such a coproduction system built at a scale suitable for competing as a power generator would beable to provide low-GHG-emitting synthetic fuels at the same estimated unit cost as for coal synfuelscharacterized by ten times the GHG gas emission rate that are produced in a plant with CO2 capture andstorage that does not provide electricity as a major coproduct having three times the synfuel outputcapacity and requiring twice the total capital investment. Moreover, the low GHG-emitting synfuelsproduced by such systems would be less costly to produce than cellulosic ethanol and require only half asmuch lignocellulosic biomass.

1. Introduction

Concerns about current and prospective high oil prices andabout oil supply insecurity are catalyzing wide interest inmaking synthetic fuels from coal;so-called coal-to-liquid(CTL) fuels;in light of coal’s relatively low prices and theabundance of coal both in the U.S. and in other world regionsthat are not politically volatile. Much of this attention hasbeen focused onFischer-Tropsch liquid (FTL) fuels.1-4 Coal

can do much to improve energy security if it is used to makeFTL fuels. Moreover, the synfuels provided are likely to becleaner than the crude oil products they displace, havingessentially zero sulfur and other contaminants and low aro-matic content. Also, for FTL fuels produced from synthesisgas generated inmodern entrained flow gasifiers, air pollutantemissions from the plant are extremely low.But synthetic fuelsmade from coal without capture and storage of byproductCO2 result in net GHG emissions about double those frompetroleum fuels.5 And even with CO2 capture and storage(CCS), the net GHG emissions are reduced only to levelscomparable to those from petroleum fuels.

One approach to reducingGHGemissions belowpetroleum-fuel levels is to make FTL fuels from sustainably producedbiomass;termed biomass-to-liquid (BTL) fuels whose netclimate impact (i.e. after transportation, distribution, andcombustion) is roughly carbon neutral. Adding CCS toBTL fuel systems reduces GHG emissions even further; anintrinsic feature of converting biomass (or coal) to FTL fuels

*To whom correspondence should be addressed. E-mail: [email protected].(1) Van Bibber, L.; Shuster, E.; Haslbeck, J.; Rutkowski, M.; Olsen,

S.; Kramer, S. Baseline Technical and Economic Assessment of a Com-mercial Scale Fischer-Tropsch Liquids Facility; DOE/NETL-2007/1260;National Energy Technology Laboratory: Pittsburgh, April 2007.(2) Van Bibber, L.; Shuster, E.; Haslbeck, J.; Rutkowski, M.; Olsen,

S.; Kramer, S. Technical and Economic Assessment of Small-ScaleFischer-Tropsch Liquids Facilties; DOE/NETL-2007/1253; National En-ergy Technology Laboratory: Pittsburgh, February 2007.(3) VanBibber, L.; Thomas,C.; Chaney,R.AlaskanCoalGasification

Feasibility Studies - Healy Coal-to-Liquids Plant; DOE/NETL-2007/1251; National Energy Technology Laboratory: Pittsburgh, July 2007.(4) Bechtel Corp., Global Energy Inc., and Nexant Inc. Gasification

Plant Cost and Performance Optimization, Task 2 Topical Report: Coke/Coal Gasification with Liquids Coproduction; USDOE contract DE-AC26-99FT40342, September 2003.

(5) Kreutz, T.G.; Larson, E.D.; Williams, R.H.; , Liu, G. Fischer-Tropsch Fuels from Coal and Biomass. In Proceedings of the 25thAnnual International Pittsburgh Coal Conference, Pittsburgh, PA, 2008.

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Energy Fuels 2011, 25, 415–437 : DOI:10.1021/ef101184e Liu et al.

is the production of a stream of pure by-product CO2 thatcontains more than half of the carbon in the feedstock. If thisCO2 is captured and securely stored in geological media, FTLfuelsmade entirely from sustainably produced biomasswouldbe characterized by strong negative net GHG emissionsbecause of the storage of photosynthetic CO2. Unfortunately,sustainably-produced biomass is expensive, and the size ofBTL facilities is limited by the quantities of biomass that canbe gathered in a single location;implying relatively high unitcosts. Furthermore, sustainably-produced biomass is a scarceresource, and BTL plants are able to convert only a third ofthe biomass carbon into FTL fuels.

These challenges for BTL technology could be mitigated toa significant degree by coprocessing biomass with coal in thesame facility, and employing CCS. The economies of scaleinherent in coal conversion could thereby be exploited,the average feedstock cost would be lower than that for apure BTL plant, and CO2 emissions can be reduced by CCS,leading to FTL fuels with low, zero, or even negative netemissions depending on the coal/biomass ratio.5-9 Further-more, adding coal and CCS to BTL dramatically boosts thebiomass utilization effectiveness, more than doubling theamount of low-C transportation fuel energy that can beproduced from a unit of biomass energy. In recent years,government and industry in the United States have begun toshow great interest in the coal/biomass-to-liquids with CCS(CBTL-CCS) concept,10-13 but a systematic assessment of thefield is clearly needed.

This paper presents a comprehensive assessment of thecoproduction of FTL fuels and electricity from coal and/orlignocellulosic biomass, without andwith capture and storageof byproduct CO2. We investigate (1) BTL vs CBTL vs CTLoptions (generically referred to as “XTL” plants), (2) theamount of biomass that might be accommodated in CBTLsystems, (3) the appropriate scales for XTL plants, (4) theextent to which CCS might plausibly be pursued for XTLsystems, (5) how plants that seek to maximize liquid fueloutput compare to those that produce electricity as a majorcoproduct, and (6) comparative prospective economics of

alternative XTL designs. We employ a unified analyticalframework to systematically analyze 16 separate process de-signs, simulating for each detailedmass/energy balances usingAspen Plus software, and calculating their full lifecycle green-house gas (GHG) emissions.A self-consistent set of component-level capital cost estimates is developed, and overall economicsare evaluated under alternative oil price and GHG emissionsprice assumptions from the perspective of both a liquidfuel producer and an electricity generator. Table 1 providesnomenclature used to refer to each process design, along withsome key acronyms.

2. Process Designs

The equipment for gasification-based production of liquidfuels from coal and biomass are commercial or nearly com-mercial in all cases. Industrial-scale coal gasifiers are commer-cially available today, with more than 420 gasifiers already incommercial use in some 140 facilities worldwide.8 The tech-nology for cogasifyingbiomass and coal is close tobeing readyfor commercial deployment; the commercial Buggenumintegrated-gasification combined cycle (IGCC) facility in TheNetherlands has been cogasifying coal together with modestquantities of biomass in a coal gasifier since 2006.14 Stand-alone biomass gasification technologies, while not yet de-ployed at large commercial scale, have been the subject ofextensive research, development, anddemonstration,15 aswellas commercial design studies16 that provide the data neededfor scale-up to commercial size. Technologies for convertingsyngas into FTL fuels have been successfully employed atindustrial scale formany decades by Sasol in SouthAfrica.AllCO2 capture technologies described here are commerciallyestablished, and underground storage of CO2 is under activedevelopment worldwide.17

2.1. Plant Designs with CO2 Vented to the Atmosphere.All16 of the process designs considered here share some similarfeatures (for details see Appendix A of the SupportingInformation). We begin with a description of two basiccoal-to-liquid designs, termed “recycle” (RC) and “once-through” (OT) configurations (Figure 1). A key differencebetween the two is in the amount of coproduct electricityavailable for export after on-site parasitic power needs aremet. In both designs, Illinois No. 6 bituminous coal (Table 2)is mixed with water to form a slurry that is pumped into apressurized entrained flow gasifier (with characteristics ofGE Energy’s total water quench gasifier design) operating at72 bar and 1371 �C. Oxygen is supplied to the gasifier from adedicated cryogenic air separation unit (ASU). In the lowersection of the gasifier, the raw synthesis gas passes through awater quench and then through an external gas scrubber;both remove water-soluble contaminants and particu-late matter. The syngas exits the scrubber at 251 �C with a

(6) Larson, E. D.; Williams, R. H.; Jin, H. Fuels and electricity frombiomass with CO2 capture and storage. In Proceedings of the 8thInternational Conference on Greenhouse Gas Control Technologies,Trondheim, Norway, June 2006.(7) Williams, R. H.; Larson, E. D.; Jin, H., Synthetic fuels in a world with

high oil and carbon prices.Proceedings of the 8th International Conference onGreenhouse Gas Control Technologies, Trondheim, Norway, June 2006.(8) NationalResearchCouncil’s Panel onAlternative Transportation

Fuels for America’s Energy Future study. Liquid Transportation Fuelsfrom Coal and Biomass Technological Status, Costs, and EnvironmentalImpacts; U.S. National Academy of Sciences: Washington, DC, 2009.(9) Larson, E.D.; Fiorese,G.; Liu,G.;Williams,R.H.;Kreutz, T.G.;

Consonni, S. Co-production of decarbonized synfuels and electricityfrom coal þ biomass with CO2 capture and storage: An Illinois casestudy. Energy Environ. Sci. 2010, 3 (1), 28–42.(10) Western Governors’ Association. Transportation Fuels for the

Future: A Roadmap for the West, Denver, 2008.(11) Baardson, J.; Dopuch, S.; Wood, R.; Gribik, A.; Boardman, R.

Coal-to-Fuel Plant Simulation Studies for Optimal Performance andCarbonManagement. InProceedings of the 24th Annual Pittsburgh CoalConference, Johannesburg, 2007.(12) Tarka, T. J.; Wimer, J. G.; Balash, P. C.; Skone, T. J.; Kern,

K. C.; Vargas, M. C.; Morreale, B. D.; White, C. W.; Gray., D.Affordable, Low-Carbon Diesel Fuel from Domestic Coal and Biomass;DOE/NETL-2009/1349; National Energy Technology Laboratory: Pittsburgh,January 2009.(13) Bartis, J.; Camm, F.; Ortiz, D. S. Producing Liquid Fuels from

Coal: Prospects and Policy Issues, Project Air Force and Infrastructure,Safety, and Environment; United States Air Force and the National EnergyTechnology Laboratory of the United States Department of Energy: Pittsburgh,2009.

(14) Van Haperin, R.; de Kler, R., Nuon Magnum. Presented atGasification Technologies Conference, San Francisco, CA, 2007.

(15) Ciferno, J. P.; Marano, J. J. Benchmarking Biomass GasificationTechnologies for Fuels, Chemicals and Hydrogen Production;NationalEnergy Technology Laboratory, U.S. Department of Energy: Pittsburgh,June 2002.

(16) DeLong,M.M.EconomicDevelopment Through Biomass SystemIntegration: Summary Report; NREL/TP-430-20517; National RenewableEnergy Laboratory: Golden, CO, December 1995; 63 pp.

(17) Three commercial-scale demonstration projects are each an-nually injecting one million tonnes or more of CO2 underground. Thelongest running of these been injecting CO2 under the bed of the NorthSea since 1996. A large number of smaller tests are also ongoing.See http://sequestration.mit.edu/ for an up-to-date database of CCSactivities.

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H2/CO ratio of 0.67. After scrubbing, some of the syngasenters a single-stage (adiabatic) sour water gas shift (WGS)reactor and some bypasses the WGS. The syngas bypass isadjusted to ensure that a molar H2/CO ratio of 1 is realizedfor the fresh syngas entering the FT synthesis island. The twostreams of syngas are combined and cooled following theWGS and then expanded to a pressure suitable for down-stream FT synthesis. The syngas is cooled to 40 �C, and CO2

and H2S are then removed in a methanol-based acid gasremoval (AGR) system (with characteristics of the commer-cial Rectisol process).H2S is removed to protect downstreamcatalysts and is converted to elemental sulfur in Claus/SCOTprocesses. The CO2 is removed to improve FTL yield andeconomics and is vented to the atmosphere. For the designsin Figure 1, this recovered CO2 is essentially pure, so that it isa relatively simple matter to compress it for undergroundstorage, as discussed in Section 2.2. Following the AGR, thesyngas is heated and delivered to the FT synthesis island at 24bar and 245 �C.

The FT island is designed around a synthesis unit using aniron catalyst. Iron-based catalysts are well suited for syngasfrom coal and/or biomass feedstocks, because these feed-stocks produce syngas with H2/CO ratio below the stoichio-metric optimum of 2 for FT synthesis. The water-gas-shiftactivity inherent in iron catalysts is able to compensate forthis suboptimal syngas composition. The main commercialalternatives to iron-based catalysts are cobalt-based cata-lysts, which have nowater-gas-shift activity. Cobalt catalystsare commercially deployed today with syngas produced bythe reforming of natural gas, which can achieve the optimumH2/CO ratio for FT synthesis without the need for water gasshift.

On the FT synthesis island, the syngas is fed to the bottomof a slurry-phase FT reactor. The syngas bubbles up throughan inert heavy hydrocarbon liquid medium in which aresuspended fine catalyst particles. Reaction heat is removedvia heat exchangers suspended in the reactors. The liquidmedium, together with boiling heat transfer inside the tubes,

Table 1. Nomenclature and Acronyms

Acronyms

CTL- coal to FTL fuels (diesel/jet, gasoline) þ electricityBTL- biomass to FTL fuels (diesel/jet, gasoline) þ electricityCBTL- coal þ biomass to FTL fuels (diesel/jet, gasoline) þ electricity (∼40% of input feedstock is biomass - HHV basis)CBTL1- coal þ biomass to FTL fuels (diesel/jet, gasoline) þ electricity (∼12% of input feedstock is biomass - HHV basis)-V coproduct CO2 is vented to the atmosphere.-CCS coproduct CO2 captured, compressed, and piped to underground storage site (deep saline formation)-RC- FTL synthesis with recycle (RC) of unconverted syngas to maximize FTL output-OT- FTL synthesis with once-through (OT) synthesis; after single pass through synthesis reactor

unconverted syngas burned to make electricity as major coproduct in combined cycle power plant-OTA- OT plant design to which an autothermal reformer and extra CO2 capture equipment are added downstream

of synthesis to increase the fraction of feedstock C not in FTL products that is captured/stored as CO2

-OTS- OT plant design that uses biomass grown on carbon-depleted soils, leading to substantial buildup/storage of carbon insoil and roots, complementing underground storage of CO2 captured at the conversion facility

-OTAS- OTA plant design that uses biomass grown on carbon-depleted soils, leading to substantial buildup/storage ofcarbon in soil and roots, complementing underground storage of CO2 captured at the conversion facility

sup PC- supercritical pulverized coal power plantCIGCC- coal integrated gasification combined cycle power plantNGCC- natural gas combine cycle power plant

System acronyms and plant sizing parameters for XTL plants evaluated as synfuel providers

CTL-RC-V 50,000 barrels/day of finished FTL fuels (diesel/jet and gasoline)CTL-RC-CCS same coal input as CTL-RC-VCTL-OT-V same coal input as CTL-RC-VCTL-OT-CCS same coal input as CTL-RC-VCTL-OTA-CCS same coal input as CTL-RC-VBTL-RC-V CBIR (common biomass input rate =1 million metric ton(dry)/year)BTL-RC-CCS CBIRCBTL-RC-V CBIR, same coal input as CBTL-RC-CCSCBTL-RC-CCS CBIR, C/B ratio for near-zero lifecycle GHG emissionsCBTL-OT-V CBIR, same coal input as CBTL-OT-CCSCBTL-OT-CCS CBIR, C/B ratio for near-zero lifecycle GHG emissionsCBTL1-OT-CCS same FTL fuels output capacity as for CBTL-OT options, C/B ratio approximately 5x CBTL-OT-CCS valueCBTL-OTS-CCS CBIR, C/B ratio for near-zero lifecycle GHG emissions, soil/root C storageCBTL-OTA-V CBIR, same coal input as CBTL-OTA-CCSCBTL-OTA-CCS CBIR, C/B ratio for near-zero GHG emission, aggressive CCSCBTL-OTAS-CCS CBIR, C/B for near-zero GHG emissions, soil/root C storage, aggressive CCS

Acronyms used in text

GHGI greenhouse gas emissions index: lifecycle GHG emissions associated with the facility divided by lifecycleemissions for production and use of an LHV-equivalent amount of fossil fuel-derived products displaced

GHGA greenhouse gas emissions avoided: GHGA= (1 - GHGI)*(lifecycle GHG emissions for the displaced fossil fuels)MEGE marginal electric generation efficiency (defined in the main text)XTL X refers to coal, biomass, or coalþbiomass; TL refers to FTL fuels (diesel/jet, gasoline) þ electricityLCOE levelized cost of electricity: calculated for the assumptions in Table 8MDC minimum dispatch cost for electricity generation: feedstock þ operating costs - liquid fuel revenuesa

SRMC short run marginal cost for electricity generationASU air separation unitAGR acid gas removal (for CO2 and H2S)

aFor power generating plants, separate estimates of fixed and variable operating costs were available,36 and in these cases the MDC is the sum offeedstockand variable operating costs. For theCBTL systems,we haveonly estimated total operating costs (without separating fixed fromvariable). Forthese systems the MDC is the sum of feedstock and total operating costs, less liquid fuel revenues.

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enables the rapid heat removal needed to maintain theisothermal conditions that promote high synthesis gas con-versions. In our modeling 51% of the C in CO in incomingsyngas is converted into raw FTL products in a single pass,

which is consistent with modeling carried out in the 1990s bythe Bechtel Group for the U.S. Department of Energy for aslurry-phase FT synthesis reactor.18 The raw product fromthe FT reactor is separated by distillation in the hydrocarbonrecovery area into naptha, middle distillate, and heavy waxstreams, along with a gas stream containing unreacted H2

and CO, and CO2 and light hydrocarbons (C1 to C4) formedduring synthesis.

The liquid fractions in our designs are upgraded to dieseland gasoline blendstocks.19 The FTL upgrading area uses arelatively conventional refining design that is a modificationof a Bechtel design developed in the mid-1990s.20,21 Crude-oil-derived gasoline specifications have evolved since theBechtel design was published, so we have made modifica-tions to ensure that the gasoline blendstock produced in theupgrading area will meet existing U.S. standards for gaso-line, specifically California reformulated gasoline standards.Figure 2 shows schematically our upgrading design, detailsof which are provided in the Supporting Information. The

Figure 1.Twobasic process configurations forCTL systems producingFTL fuels from coal while venting all CO2: (a) ‘‘recycle’’ (RC) synthesis,with only modest net exportable electricity; (b) ‘‘once-through’’ (OT) synthesis, with significant exportable electricity coproduct.

Table 2. Feedstocks

coala biomassb

proximate analysis (wt%, as-received)fixed carbon 44.19 18.1volatile matter 34.99 61.6ash 9.7 5.26moisture 11.12 15.0LHV (MJ/kg) 25.86 14.51HHV (MJ/kg) 27.11 15.94

ultimate analysis (wt%, dry basis)carbon 71.72 46.96hydrogen 5.06 5.72oxygen 7.75 40.18nitrogen 1.41 0.86chlorine 0.33 0.00sulfur 2.82 0.09ash 10.91 6.19LHV (MJ/kg) 29.40 17.50HHV (MJ/kg) 30.51 18.75

aProperties of coal can be quite variable. Here the design coal isIllinois No. 6 (high-volatile bituminous), with properties taken fromNETL.36 bBiomass properties are for switchgrass, as reported in Ap-pendix C of Tarka, et al.12

(18) Bechtel Group, Inc. Slurry Reactor Design Studies: Slurry vs.Fixed-BedReactors for Fischer-Tropsch andMethanol; Final Report undercontract DE-AC22-89PC89867 to U.S. Department of Energy, PittsburghEnergy Technology Center, 1990.

(19) The naphtha could be sold directly as a chemical feedstock ratherthan being upgraded to gasoline, but chemical markets for naphtha arerelatively small relative to fuels markets, so this would be a limitedoption if FTL fuels production were to become widespread. Here weassume that the naphtha is upgraded to a gasoline blendstockbecauseweare interested in understanding the economics under a scenario in whichFTL technology is extensively deployed.

(20) Bechtel. Baseline Design/Economics for Advanced Fischer-TropschTechnology; Report under contract DE-AC22-91PC90027 to U.S. Departmentof Energy, Federal Energy Technology Center: Pittsburgh, April 1998.

(21) Bechtel. Aspen Process Flowsheet Simulation Model of a BattelleBiomass-Based Gasification, Fischer-Tropsch Liquefaction and Combined-Cycle Power Plant; Report under contract DE-AC22-93PC91029-16 to U.S.Department of Energy, Pittsburgh, PA, May 1998.

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naphtha and distillate streams are first hydrotreated, whilethe heavy waxes are hydrocracked into distillate-range andnaphtha-range compounds. No further processing of thedistillate streams is required. The C5 and C6 components inthe naphtha streams are isomerized (from normal paraffinsto isoparaffins) to boost their octane levels. The remainingcomponents of the straight-run naphtha (from the hydro-treater) and the naphtha from the hydrocracker are pro-cessed in either a Pt/L-zeolite reformer or a non-hydrogenupgrading unit.

Pt/L-zeolite reforming (in contrast to the Pt/Al2O3 re-forming assumed in the earlier-cited Bechtel studies from the1990s) provides a superior conversion of n-paraffins toaromatics and hydrogen.22 The n-paraffin content instraight-run naphtha will be above 90% after hydrotreating,so Pt/L-zeolite reforming will produce a high-octane gaso-line blending component. About half of the C7þ naphthacomponents from the hydrotreater are sent to this reformerto generate the aromatics content in the final gasoline blend-stock. The remainder, together with naphtha emerging fromthe wax hydrocracker, is upgraded to boost octane withoutadding aromaticity. Typically, octane number can be in-creased by 20-30 units via isomerization.23,24 The finishedliquid products consist of about 63% diesel and 37% gaso-line (lower heating value basis). Each step in the refining areagenerates some light gases (C1 to C4) that are collected andmixed with the unconverted syngas from the hydrocarbonrecovery step for use as fuel on the power island.

Thedistinctionbetween the twoprocess designs inFigure 1is primarily in the FT synthesis and power island designs.The “recycle” (RC) case (Figure 1a) is designed to maximizeliquid fuel production. Most of the syngas unconverted in asingle pass through the synthesis reactor is compressed,combined with steam and oxygen, and passed through anautothermal reformer (ATR) from which emerges a gaseousmixture primarily made up of CO, H2, and CO2 at 1000 �C.The ATR output is combined with fresh syngas upstream ofthe AGR unit and then recycled back through the synthesisreactor. A purge stream from the recycle loop prevents

excessive buildup of inert gases25 and, together with the lightgases collected from the refining area, constitutes the fuel forthe power island. This gas mixture fuels a steam Rankinecycle that generates all the electricity needed to run the entirefacility plus a small amount of export electricity (∼ 11% ofthe total plant output of fuel (LHV) and power;see Table 3).

In the plant designs with electricity as a major coproduct,designated as “once-through” (OT) configurations (Figure 1b),the syngas passes only once through the synthesis reactor,and all of the unconverted syngas plus light gases from FTLrefining are compressed and supplied to the power islandwhere a gas turbine/steam turbine combined cycle (GTCC)provides the power needed to operate the plant, as well as asubstantial amount of export power (up to 37% of the totalplant output of fuel (LHV) and power;see Table 3).

2.2. Plant Designs with CO2 Capture and Storage (CCS).Ten of the FTL systems employ CCS (Table 3), where it isassumed that the CO2 is separated, dehydrated, and com-pressed to 150 bar for subsequent pipeline transport to asuitable geological storage site.

In the CTL configurations in Figure 1, CO2 is vented fromboth the AGR unit and the power island. Greenhouse gasemissions can be reduced if one or both of these CO2 streamsis or are captured and stored underground.

In the traditional CTL-RC-V design (Figure 1a), most(83%) of the plant’s CO2 emissions come from the concen-trated CO2 stream exiting the AGR unit. Capturing thisstream for geologic storage eliminates most of the plant’sGHG emissions and involves only compressing the CO2 forpipeline transport. This is the strategy adopted for the CTL-RC-CCS design.

In the CTL-OT-V plant (Figure 1b), the amount of CO2

vented from the power island is more substantial than in theRC case (equivalent to 47%vs 10%ofC in coal).We developtwo alternative designs for capturing this CO2 in addition tothat more readily captured from the AGR unit upstream ofFT synthesis.

In the firstCCSdesign, designatedCTL-OT-CCS (Figure3a),CO2 is captured not only upstream of the FT reactor in theAGR unit, but also downstream from the power island fuelgas. In the latter step, CO2 generated in the FT synthesisreactor is removed from the exiting syngas by passing it

Figure 2. Design of hydrocarbon recovery and upgrading downstream of FT synthesis.

(22) Tamm, P. W.; Mohr, D. H.; Wilson, C. R. Octane enhancementby selective reforming of light paraffins. Stud. Surf. Sci. Catal. 1988, 38,335.(23) Liu, H. Isomerization Technique Enhancing Octane Number of

Straight-run Gasoline. Pet. Refin. Eng. 2001, 31 (2), 23–25 (in Chinese,with English abstract).(24) Lei, J. Industrial application of non-hydrogen quality-changing

technology for straight-run gasoline.Nat. Gas Oil 2007, 25 (1), 35–38 (inChinese, with English abstract).

(25) In all of the RC designs in this work, the ASU is designed toproduce extra-high purity oxygen (99.5% molar) to minimize inert gasbuildup. This compares with 94.3%molar purity for designs that do notutilize recycle.

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through a chilled methanol-solvent absorption column;pure CO2 is recovered during solvent regeneration. (Cost

savings are achieved by having a single regeneration unitserve the two absorption columns.) Removing CO2 from the

Figure 3. Two OT process configurations for coproduction of FTL fuels and electricity from coal with capture and storage of CO2: (a) CTL-OT-CCS (simple CCS); (b) CTL-OTA-CCS (aggressive CCS).

Table 3. Summary of Process Simulation Mass and Energy Balances for Alternative FTL System Configurations

plant name

inputs

bio %b

production capacityc output/inputd

coal biomass FTL

MWe FTL electrict/da MWHHV t/da MWHHV bbl/d MWLHV

CTL-RC-V 24,087 7559 - - - 50,000 3,159 404 0.45 0.05CTL-RC-CCS 24,087 7559 - - - 50,000 3,159 295 0.45 0.04CTL-OT-V 24,087 7559 - - - 35,706 2,256 1,260 0.32 0.17CTL-OT-CCS 24,087 7559 - - - 35,705 2,256 1,058 0.32 0.14CTL-OTA-CCS 24,087 7559 - - - 35,705 2,256 843 0.32 0.11BTL-RC-V - - 3,581 661 100 4,521 286 42 0.47 0.06BTL-RC-CCS - - 3,581 661 100 4,521 286 31 0.47 0.05CBTL-RC-V 2,562 804 3,581 661 45 9,845 622 76 0.46 0.05CBTL-RC-CCS 2,562 804 3,581 661 45 9,845 622 53 0.46 0.04CBTL-OT-V 3,220 1,011 3,581 661 40 8,036 508 301 0.33 0.18CBTL-OT-CCS 3,220 1,011 3,581 661 40 8,036 508 257 0.33 0.15CBTL1-OT-CCS 4,725 1,483 1,129 208 12 8,036 508 224 0.32 0.14CBTL-OTS-CCS 6,726 2,111 3,581 661 24 13,213 835 410 0.32 0.15CBTL-OTA-V 5,150 1,616 3,581 661 29 10,881 687 408 0.32 0.18CBTL-OTA-CCS 5,150 1,616 3,581 661 29 10,882 687 287 0.32 0.13CBTL-OTAS-CCS 9,760 3,063 3,581 661 18 17,669 1,116 464 0.32 0.12

aAs-received metric tonnes/day input when plant is operating at 100% capacity. bPercent of total higher heating value of input feedstocks that isbiomass. cExports of finished liquid fuels (63% diesel and 37% gasoline, LHV basis) and electricity. dHigher heating value of indicated output dividedby higher heating value of input feedstock(s). HHV/LHV = 1.076 for FTL products.

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fuel gas increases its heating value, necessitating measures (notneeded in CTL-OT-V) to ensure that thermal NOx emissionsfrom combustion in the power island remain below regulatedlimits.26 NOx emissions control is achieved by first passing thegas turbine fuel gas through a water saturator and then addingnitrogen for further dilution. Nitrogen for this purpose istaken from the ASU and compressed from 1.45 to 28 bar.

In the CTL-OT-CCS design, some carbon in the fuel gas(C1 to C4 hydrocarbons) will still reach the atmosphere asCO2 after combustion in the power island, yielding an overallCO2 capture rate for nonfuel carbon of ∼73%, ∼1/2 up-stream and ∼1/2 downstream of synthesis.

Our second CCS design reduces emissions further by firstreforming the power island fuel gas with steam and O2 in anATR so as to convert most of the C1 to C4 hydrocarbons toCO andH2. The reformed syngas passes through a two-stageWGSunit inwhichCOand steam react to producemostlyH2

and CO2. The CO2 is then removed in the absorption column.We adopt this approach for our CTL-OTA-CCS design(Figure 3b), in which 89% of nonfuel carbon is capturedas CO2.

2.3. Designs with Biomass. The various CTL-CCS designsdescribed in the previous section have lower GHG emissionsthan CTL-V designs, but nevertheless still have substantialfuel-cycle-wide GHG emissions due to the CO2 releasedduring combustion of the liquid fuels. One approach forfurther reducing GHG emissions involves introducing bio-mass as a feedstock. Neglecting for the moment fuel-cycle-wide GHG emissions arising from energy and chemicalinputs to the growing and transporting of biomass and fromtransporting biofuels to refueling stations (emissions that areincluded in the analysis in Section 3), release to the atmo-sphere of CO2 originating in biomass results in no netaccumulation of CO2 in the atmosphere when an equivalentamount of CO2 is absorbed by new biomass growth. Thus anFTL plant operating on biomass only, termed BTL, yieldsfuels whose net CO2 emissions (including conversion at theplant and subsequent combustion in vehicles) are zero. ForBTL plants that also incorporate CCS, the net lifecycle CO2

emissions are strongly negative becausemore than half of thebiomass carbon is captured and stored underground.

Our analysis includes two RC plant designs that utilizeonly biomass in the form of chopped switchgrass (Table 2)as the feedstock. In one design, byproduct CO2 is vented

(BTL-RC-V); in the other, CO2 is captured and stored (BTL-RC-CCS). The downstream portions of these plants, startingwith the acid gas removal area, are essentially identical tothose for the corresponding CTL-RC designs in Figure 1.The upstream portions of the BTL designs include a biomasshandling system feeding a pressurized (30 bar) fluidized-bedgasifier operating at temperatures low enough that ash isremoved as a dry material, 816 �C.27 The gasifier is followedby a tar cracking unit, modeled as an ATRwith a syngas exittemperature of 882 �C that converts into syngas the heavyhydrocarbons that form at typical biomass gasificationtemperatures and that would otherwise condense and causeoperating difficulties downstream. TheATR also converts intosyngas 90% of the methane, which is much more abundant insyngas produced in relatively low-temperature biomass gasi-fiers than in syngas from higher-temperature coal gasifiers.

Biomass can also be used as a cofeed with coal at the samefacility. The lifecycle GHG emissions for such facilities willvary with the coal-to-biomass ratio, as well as with otherdesign details (especially CO2 capture). We have designedseveral coal/biomass-to-liquids (CBTL) plants, all of whichuse separate coal and biomass gasification trains identicalto those described earlier. The separate syngas streams arecombined for subsequent downstream processing. TheCBTL plants include RC and OT configurations; Figure 4shows CBTL-RC-CCS. The CBTL-OT designs include (1)two plants with different coal-to-biomass ratios (CBTL-OT-CCS and CBTL1-OT-CCS) in which the downstream CO2

capture is the same as in CTL-OT-CCS (Figure 3a), and (2)another plant (CBTL-OTA-CCS) that employs the moreaggressive CO2 capture strategy used by CTL-OTA-CCS(Figure 3b).

Finally, under certain biomass growing conditions (e.g.,the sustained growing ofmixed prairie grasses on abandonedcropland28), some photosynthetically absorbed carbon willbe stored permanently in the soil/root system, adding a nega-tive emissions credit to the biomass conversion facility. Ourplant designs that utilize biomass grown with soil/rootcarbon accumulation are designated CBTL-OTS-CCS andCBTL-OTAS-CCS. Aside from the distinction in the sourceof the biomass feedstock and relative biomass/coal input

Figure 4.CBTL-RC-CCS process configuration for maximumFTL fuels production from coal plus biomass with capture and storage of CO2.

(26) For simulation purposes, we assume that the adiabatic flametemperature in the gas turbine combustormust not exceed 2300K ifNOx

emissions are to remain below 25 ppmv.

(27) Dry ash from a biomass gasifier might be returned to the soil forits inorganic nutrient value.

(28) Tilman, D.; Hill, J.; Lehman, C. Carbon-Negative Biofuels fromLow-Input High-Diversity Grassland Biomass. Science 2006, 315 (Dec. 8),1598–1600.

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rates (as discussed below), these designs are identical toCBTL-OT-CCS and CBTL-OTA-CCS, respectively.

3. Process Simulation Methodology and Results

For eachof the 16plant designs,wehave developed detailedmass, energy, and carbon balance simulations using AspenPlus software.29All designs are for a bituminous IllinoisNo. 6coal and switchgrass as the biomass feedstock (Table 2). Thelatter arrives at the plant gate with 15% moisture content,which is low enough that further drying of the feedstock priorto gasification is not needed. We assume that plants proces-sing biomass will utilize no more than one million dry tonnesper year, which appears to be a plausible maximum deliveryrate in the Midwestern United States.9 The amount of coalprocessed at each facility is set according to a different set ofcriteria. For example, our CTL-RC-V system is designed withcoal input that results in 50,000 barrels per day of FTLproduction.Table 1 summarizes the scale-determiningparam-eters for each of the 16 designs. For any given plant design, wemake the simplifying assumption that unit energy perfor-mance of equipment does not vary with plant scale, and onthis basis we have also included some subsequent analysis forplants with sizes other than those indicated in Table 1.

We have estimated for each plant design lifecycle GHG(LGHGemissions) that include all emissions other than thoseinvolved in manufacturing and constructing the plant equip-ment. Emissions at the facility are based on our simulationresults. To these emissionsweadded emissions associatedwithfeedstock production and delivery operations upstream of theplant and with fuel delivery and combustion downstream ofthe plant. Combustion emissions are based on the carboncontent of the fuel, and emissions fromotherprocesses outsideof the plant gate are based on the GREET model.30 For

biomass the CO2 absorbed during photosynthesis (equal tothe carbon in the biomass) is counted as a negative emission.For biomass feedstocks, we assume the GREET results forherbaceous biomass. The GREET model takes into accountchanges in GHG emissions associated with direct land-usechange impacts of biomass production but does not includeindirect land-use change impacts.31 The latter is zero if thebiomass is not grown as a dedicated energy crop on goodcropland requiring putting new land into cropland elsewherein the world;which we assume to be the case here.

For biomass grown with attendant soil/root carbon sto-rage, we assume 0.3 tonnes of carbon are stored in the soil/roots per dry tonne of harvested biomass as an average over a30-year period28 and substitute this land use impact for theland use impact estimated for herbaceous biomass in theGREET model. We further assume 7% of the harvestedbiomass is lost during delivery to the conversion facility,9 sothat this carbon storage rate is 0.323 t carbonper t dry biomassdelivered to the conversion facility.

To facilitate comparisons of greenhouse gas emissionsmitigation among systems that produce different energyproducts we introduce two metrics for measuring LGHGemissions mitigation: a greenhouse gas emissions index(GHGI) and the greenhouse gas emissions avoided (GHGA).

We define GHGI to be the LGHG emissions associatedwith the facility divided by the LGHG emissions associatedwith the fossil energy displaced by the products of the facility.We assume the latter are petroleum-derived diesel and gaso-line and electricity generated by a new supercritical pulverizedcoal plant that vents CO2 (Sup PC-V). (See Table 4, footnoteb, for details.) The GHGI metric is useful in that it does notrequire any allocation of emissions to different products whilegiving a clear quantification of potential emissions reductionsrelative to state-of-the-art fossil-fuel systems.GHGI is a helpful

Table 4. Carbon Balance Simulation Results and Alternative Metrics for GHG Emissions for Alternative FTL System Configurations

plant name input to plant (kgC/s)

% of input C that ends up

CCS ratea (tCO2/d) GHGIb

GHGA (kg CO2eq/GJ FTL)c

in char vented in FTL stored as CO2 FTL electricity total

CTL-RC-V 178 4.0 61.9 34.1 0.0 0 1.71 -64.9 -20.9 -85.8CTL-RC-CCS 178 4.0 10.3 34.1 51.6 29,039 0.89 10.2 2.4 12.6CTL-OT-V 178 4.0 71.6 24.4 0.0 0 1.31 -28.7 -40.4 -69.1CTL-OT-CCS 178 4.0 19.5 24.4 52.2 29,343 0.70 27.9 32.9 60.8CTL-OTA-CCS 178 4.0 7.9 24.4 63.7 35,864 0.59 37.2 35.0 72.2BTL-RC-V 17 3.0 63.9 33.1 0.0 0 0.06 85.9 31.9 117.8BTL-RC-CCS 17 3.0 8.2 33.1 55.7 2919 -0.95 178.2 48.9 227.1CBTL-RC-V 35 3.5 62.8 33.7 0.0 0 0.96 3.4 1.0 4.4CBTL-RC-CCS 35 3.5 9.0 33.7 53.7 6,032 0.03 89.0 19.1 108.1CBTL-OT-V 40 3.6 72.2 24.2 0.0 0 0.77 20.9 31.1 52.0CBTL-OT-CCS 40 3.6 18.2 24.2 54.0 6,889 0.09 83.1 105.9 189.1CBTL1-OT-CCS 40 3.9 19.0 24.3 52.9 6,708 0.50 46.0 55.8 101.8CBTL-OTS-CCS 66 3.7 18.7 24.2 53.3 11,169 0.09 83.2 103.0 186.3CBTL-OTA-V 55 3.7 72.1 24.2 0.0 0 0.90 8.8 13.2 22.1CBTL-OTA-CCS 55 3.7 6.6 24.2 65.5 11,306 0.09 83.8 88.2 172.0CBTL-OTAS-CCS 89 3.8 7.1 24.2 64.9 18,188 0.08 84.3 88.1 172.4

aDaily rate at which CO2 is captured and stored underground when the plant is operating at 100% capacity. In addition to the amount shown here, asmall amount of carbon leaves the gasifier with the ash and is assumed to be sequestered from the atmosphere when landfilled. (See Column 3 formagnitude of this carbon stream.) bTheGreenhouseGas Emissions Index is defined as the lifecycle GHGemissions associated with the energy productsdivided by the lifecycleGHGemissions associatedwith the fossil-fuel-derived products displaced.We assume the latter are petroleum-derived fuels (withemissions of 91.6 kgCO2eq/GJLHV for a 63/37 diesel/gasoline mix, based on the ArgonneNational Labmethodology,30 which allocates a fraction of thetotal emissions of a refinery to gasoline and to diesel and some emissions also to other refinery products, such as bunker oil) and electricity generated by asupercrital pulverized coal plant (830.5 kg CO2eq/MWh).41 cTheGreenhouse Gas Emissions Avoided, as discussed in the text, is (1-GHGI)*(lifecycleGHG emissions of the fossil fuels displaced). GHGA is here expressed per GJLHV of liquid fuels produced.

(29) The Supporting Information provides detailed component-by-component input assumptions for the Aspen Plus simulations.(30) Argonne National Laboratory. The Greenhouse Gases, Regu-

lated Emissions, and Energy Use in Transportation (GREET) Model,release 1.8b, September 2008.

(31) Searchinger, T.; Heimlich, R.; Houghton, R. A.; Dong, F.;Elobeid, A.; Fabiosa, J.; Tokgoz, S.; Hayes, D.; Yu, T.-H. Use of U.S.croplands for biofuels increases greenhouse gases through emissionsfrom land-use change. Science 2008, 319 (5867), 1238–1240.

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metric in measuring GHG emissions mitigation in relation tooverall societal goals for emissions reduction. For example, ifa nation’s goal is an 80% reduction in total emissions over acertain time period, it would aim to promote technologies forwhich GHGI e 0.2.

GHGA is LGHG emissions for the displaced fossil fuelsminus LGHGemissions for the energy products, orGHGA=(1-GHGI)*(LGHG emissions for the displaced fossil fuels).GHGA can be helpful in better understanding, for a givenemissions reduction goal (i.e., a given GHGI level), howalternative technologies compare with regard to overall car-bon mitigation.

The GHGI and GHGA metrics can be characterized asmeasuring, respectively, the depth and breadth of mitigation.

In this paper GHGA is expressed in kg CO2eq per GJ ofliquid fuel produced for systems evaluated from a liquid fuelproduction perspective and in kg CO2eq per MWh of electric-ity generated for systems evaluated from an electric powergeneration perspective.

It should be noted that the economics of producing fuelsand electricity (discussed below) are not a function of themetrics selected for LGHG emissions.

Table 3 summarizes results from the mass/energy balancesimulations for all 16 designs. All the options using biomassexcept CBTL1-OT-CCS use biomass at a rate of 1 million drytonnes per year (dt/y). TheCBTL1-OT-CCSoption (consuming12%biomass onan energybasis) is intended tobe representativeof a plant that could be built in the relatively near termconsuming instead 0.315 million dt/y.

Table 4 provides carbon balances and the two metrics forLGHG emissions mitigation.

Illustrating our process simulation results, Figure 5 showsdetailed stream flows for the CBTL-OT-CCSdesign, in whichone million dt/y of biomass accounts for 40% of the inputfeedstock energy (HHV basis). This plant’s output capacitiesfor finished FTL fuels and net electricity exports are 8036

barrels per day and 257 MWe, respectively. The liquidsrepresent slightlymore than two-thirds of the total plant energyoutputs (electricity plus liquid fuels), a valuewhich is similar forall OT plants. Figure 6 shows carbon flows for this system,including carbon-equivalent GHG emission flows associatedwith activities upstream and downstream of the conversionfacility. For this system the gross flow rate of equivalent carbonto the atmosphere is 1661 tonnes per day,which is offset by 1430tonnes per day of carbon extracted from the atmosphere forbiomass grown on a sustainable basis, yielding a net equivalentcarbon flow to the atmosphere of 231 tonnesper day, equivalentto 11% of the carbon in the coal used by the system.

4. Discussion

The 16 detailed process simulations provide a rich set ofquantitative results for understanding performance implica-tions of different design choices.

4.1. Recycle vs Once-Through Synthesis. Comparing pro-cess designs for RC and OT synthesis configurations high-lights trade-offs between liquid fuels and electricity outputsfor these systems. For example, liquid fuel output falls nearly30% while electricity exports more than quadruple in shift-ing from CTL-RC-V to CTL-OT-V, assuming the same coalinput rate for both. Similar changes are evident in comparingthe output ratios in Table 3 for other analogous pairs ofconfigurations, e.g., CBTL-OT-CCS vs CBTL-RC-CCS.

An important observation is that, in each of these paireddesigns, the additional electricity in the OT case is producedwith a very high marginal electric generation efficiency(MEGE). The MEGE, the definition of which we haveadapted from the work of Cicconardi, et al.,32 is the ratioof the additional electric power generated in the OT design

Figure 5. Process simulation results for CBTL-OT-CCS design.

(32) Cicconardi, S. P.; Perna, A.; Spazzafumo, G. Combined powerand hydrogen production from coal. Part B. Comparison between theIGHP and CPH systems. Int. J. Hydrogen Energy 2008, 33, 4397–4404.

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relative to the RC design, when both plants are sized toproduce the same amount of FTL, to the additional coalconsumed. Table 5 shows that the MEGEs for the CTL-OTand CBTL-OT designs are well in excess of the efficienciesthat can be achieved with new stand-alone coal-fired powerplants. For example, comparing plant designs that incorpo-rate CCS, the coproduction designs have marginal efficien-cies that are a remarkable 6-18 percentage points higherthan efficiencies for stand-alone power plants. These highMEGEs have important implications for both the GHGemissions mitigation potential and the economics of copro-duction systems, as discussed later.

The highMEGEs are a natural consequence of two systemcharacteristics: (1) the intense exothermicity of FT synthesis,and (2) the much higher ratio of the FT synthesis exothermenergy to power island fuel energy in the RC case than in the

OT case. Heat generated by the FT synthesis reactions mustbe removed to maximize conversion in the reactor. Heatremoval is accomplished by evaporatingwater in boiler tubesimmersed in the FT slurry bed. Saturated steam at 33 bar and240 �C is produced as a result. If subsequently superheated,the steam can be expanded through a turbine to generatepower. In the OT designs there is more than enough high-temperature heat available in the gas turbine exhaust gas tosuperheat all of this saturated steam. The RC options aredesigned to recycle 97% of the unconverted syngas exiting thesynthesis reactor (so as to maximize liquid fuel production),and the remaining 3% purge gas is burned to superheatsaturated steam produced by the synthesis reactor and otherexotherms. However, the purge gas is adequate to superheatonly about 60% of this saturated steam, resulting in lesselectricity production from expansion of the steam than if allof it were superheated. This difference between the RC andOT systems can be seen by comparing the energy balancearound the steam turbine cycle shown in Figure 7 for theCTL-OT-CCS and CTL-RC-CCS designs.

Fundamentally, the FT exotherm is better utilized forpower generation with the OT designs than with the RCdesigns.33 An important indicator of the better utilization ofthe FT exotherm is the ratio of energy generated as steamturbine electricity to energy in FTL fuels. In the CTL-OT-CCS system, this ratio is 1.7 times the value for theRCdesign(Figure 7).

A strikingdifferencebetweenOTandRCdesigns is themuchhigher rate of greenhouse gas emissions avoided perGJ of FTLfuels produced (GHGA) for a carbon-mitigating OT optionthan for the corresponding RC option when both have com-parable GHGI values. For example, the GHGA for CBTL-OT-CCS is 1.7� as large forCBTL-RC-CCS even thoughbothprovide liquid fuels and electricitywithGHGI<0.1. Themain

Figure 6. Equivalent-carbon flows (tC/day) for the CBTL-OT-CCS design, including upstream and downstream processes. Flows of methaneand N2O (associated with coal mining and biomass production, respectively) have been converted to flows of carbon that provide the sameglobal warming potential as CO2.

Table 5. Comparison of Electricity Generating Efficiencies

efficiency (% HHV)a

coproduction power plantsCTL-OT-V 44.9CBTL-OT-V 50.2CTL-OT-CCS 39.2CBTL-OT-CCS 44.9

stand-alone coal power plantssup PC-Vb 39.2CIGCC-Vc 37.5NGCC-Vb 50.8sup PC-CCSb 27.2CIGCC-CCSc 31.0NGCC-CCSb 43.7

aFor the coproduction plants, these are marginal electricity generat-ing efficiencies (MEGE), as defined in the main text. b Source: NETL.36cCalculated by authors using framework consistent with XTL calculations.

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reason for the wide range in GHGA values is that displacing1 MW of sup PC-V electricity reduces 2.5 times moreGHG emissions than displacing 1 MW of petroleum fuels.

4.2. CO2 Capture and Storage. All 10 of the CCS systemsmodeled are characterized by GHGI < 1.0; in cases wherebiomass is a cofeed, GHGI , 1.0 (Table 4).

CO2 captured upstream of synthesis accounts for all CO2

captured in RC cases, and the percentages of feedstockC captured as CO2 are comparable in all cases. In CTL-RC-CCS, the capture rate is equivalent to 52% of the carbon in

the coal feedstock, and 78% of the “available” input carbon,i.e., that not contained in the FTL fuels.

In CTL-OT-CCS, CO2 capture in just the upstream sec-tion is equivalent to 27% of the feedstock carbon, and 36%of non-FTL carbon. Additionally capturing CO2 from syn-gas downstream of FT synthesis brings the total carboncapture rate to 52%, and 69% of non-FTL carbon. Eventhough the capture rate of non-FTL carbon is less for CTL-OT-CCS than for CTL-RC-CCS, its climate benefit is high-er; the GHGI for CTL-OT-CCS (0.70) is lower than that ofCTL-RC-CCS (0.89). This is a consequence of both the highMEGE (39.3%) for the CTL-OT-CCS system (Table 5) andthe higher electricity/fuels ratio, which implies more GHGemissions displaced perMWof total output (see Section 4.1).

As discussed in Section 2.2, OTA cases are once-throughsystems with “aggressive” CO2 capture and substantially in-creased capture rates. For example, CTL-OTA-CCS captures64%of the feedstock carbon, and 84%of non-FTL carbon. ItsGHGI is 0.59, the lowest of all coal-only plants.

InCCSplants, the energy penalty for capturingCO2 varieswith the extent of capture. For example, in CTL-RC-CCS,where all CO2 capture occurs upstream of synthesis, thepenalty (relative to CTL-RC-V) is 91 kWh per tCO2 cap-tured, the energy required to compress the CO2 to 150 barfor pipeline transport (Table 6). For CTL-OT-CCS and

Figure 7. Energy flows (HHV basis) for (a) CTL-OT-CCS, upper, and (b) CTL-RC-CCS, lower. The scale of each system has been normalizedto 1000 MW of FTL fuels production.

(33) The technologyutilized on the power islandwill also influence theMEGE. For example, based on simulations we have carried out (butwhich are not reported in this paper), if a CTL-RC-CCS plant weredesigned with a gas turbine combined cycle (GTCC) on the power islandinstead of a steam rankine cycle, the marginal efficiency of powergeneration arising from a comparison of OT vs RC plant configurationswould be even higher than what we report for the plant configurationsanalyzed in this paper. This counter-intuitive outcome is because whenan external source of saturated steam is available to the power island (inthis case generated from the FT synthesis exotherm), there is muchmoreheat available for superheating that steam in the steam turbine case(when all of the heat arising from combustion of the fuel gas sent to thepower island is available for superheating) than in the GTCC case (inwhich case only the exhaust heat from the gas turbine is available forsuperheating). Thus the opportunity to utilize more of the externallyprovided saturated steam for making electricity outweighs the intrinsi-cally higher efficiency of a stand-alone GTCC relative to a stand-alonesteam rankine cycle.

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CTL-OTA-CCS, which involve additional CO2 capturedownstream of synthesis, several factors contribute to theenergy penalty (see Table 6): (1) CO2 compression, (2)nitrogen compression to supply N2 to the gas turbine forNOx control, (3) methanol circulation in the downstreamAGR unit, (4) reduced gross power output, and for CTL-OTA-CCSonly, (5) additionalASUpower to produceO2 forthe ATR. The total penalty for CO2 capture in CTL-OT-CCS is 165 kWh/tCO2 captured, but in CTL-OTA-CCS, it isalmost twice as large, 279 kWh/t CO2 captured (Figure 8).Aggressive CO2 capture engenders a dramatic loss (-165MWe) in gross power output, caused by the loss of fuel gasmass flow to the gas turbine due to fuel gas decarbonization.

4.3. Biomass. When biomass is introduced as a feedstock,GHG emissions can be dramatically reduced relative to coalonly systems;especially when biomass is deployed in sys-tems with CCS. For biomass-only designs, the GHGI isalmost zero when CO2 is vented and strongly negative whenCO2 is captured and stored.

Consider CBTL-OT systems for which biomass accountsfor 40% of input energy (HHV basis) (Table 3). Notably,GHGI drops from 0.77 to 0.093 when CCS is added to theCBTL-OT-V option. Figure 9a and b illustrate how such adramatic 88% reduction in GHGI is realized by simplyadding CCS that involves capturing only 71% of the non-FTL carbon. The main reason is that, although the GHGemissions reduction credit for extracting carbon from theatmosphere is the same (33 kg C per GJ of FTL) for theseoptions, this credit is relative to a much higher base for thesystem’s positive emissions components in the CBTL-OT-Vcase (81 kg C per GJ of FTL) compared to the CBTL-OT-CCS case (38 kg C per GJ of FTL). In short, CCS providesabout half of the climate benefit in CBTL-OT-CCS, and thebiomass provides the other half.

Figure 9c shows how it is feasible to realize aGHGI as lowas 0.5 by adding only 12%biomass to the system. In this casethe baseline positive GHG emission components for thesystem sum to 38 kg C per GJ of FTL (the same as for theCBTL-OT-CCS case). Although the GHG emissions reduc-tion credit for extracting carbon from the atmosphere is

much less in this case (10 kg C perGJ of FTL compared to 33kg C per GJ for CBTL-OT-CCS), there is a larger credit forthe electricity coproduct (15 kg C per GJ of FTL comparedto 3 kg C per GJ in the CBTL-OT-CCS case).34

It is of interest to understand the relative merits of variouscombinations of CCS and biomass use in reducing GHGemissions for FTL fuels production relative to ethanol (EtOH)made from the same lignocellulosic biomass feedstock(switchgrass) via enzymatic hydrolysis. Cellulosic ethanol isthe main focus of biofuels development efforts in the UnitedStates.

We have not carried out detailed independent Aspen Plusand cost modeling of cellulosic ethanol technologies, butrather we have taken findings from the America’s EnergyFuture study of the National Research Council8 and havepresented these findings here in the analytical framework wehave developed for assessing alternative FTL technologies.This NRC study considered only cellulosic ethanol systemsthat vent CO2 (EtOH-V). In light of our findings relating tothe importance of coupling biomass and CCS to enhancecarbon mitigation for FTL systems, we have included in ourcomparative analysis a CCS option for cellulosic ethanol(EtOH-CCS), the analysis of which is straightforward be-cause a stream of pure CO2 is naturally generated in theethanol fermenter (1 molecule of CO2 for each molecule ofethanol (C2H5OH) produced) that is easily captured forgeological storage. Details of our analysis of cellulosic

Table 6. Electricity Balances for Alternative FTL System Configurations

plant name

gross output (MWe) onsite consumption (MWe)

GT ST exp SUM grind, feed ASU AGR RC comp FT synth FT refine CO2 comp N2 comp BOP SUM

CTL-RC-V 0 783 66 849 21 324 40 16 22 11 0 0 11 445

CTL-RC-CCS 0 783 66 849 21 324 40 16 22 11 109 0 11 555

CTL-OT-V 701 900 61 1,661 21 304 24 0 15 8 0 0 28 401

CTL-OT-CCS 732 860 61 1,653 21 304 39 0 15 8 111 69 28 595

CTL-OTA-CCS 562 866 61 1,489 21 342 44 0 15 8 135 50 30 646

BTL-RC-V 0 77 0 77 0 24 4 1 2 1 1 0 2 35

BTL-RC-CCS 0 77 0 77 0 24 4 1 2 1 12 0 2 46

CBTL-RC-V 0 151 7 157 2 57 8 3 4 2 1 0 3 81

CBTL-RC-CCS 0 151 7 157 2 57 8 3 4 2 24 0 3 104

CBTL-OT-V 163 211 8 382 3 60 6 0 3 2 1 0 7 81

CBTL-OT-CCS 171 205 8 384 3 60 9 0 3 2 27 17 7 127

CBTL1-OT-CCS 167 197 12 376 4 66 9 0 3 2 26 16 6 132

CBTL-OTS-CCS 279 329 17 624 6 104 15 0 6 3 43 27 11 214

CBTL-OTA-V 219 289 13 521 4 84 8 0 5 2 1 0 9 113

CBTL-OTA-CCS 177 276 13 466 4 84 14 0 5 2 44 17 9 179

CBTL-OTAS-CCS 286 448 25 759 8 142 22 0 8 4 69 27 14 295

Figure 8. Electricity penalty for three CCS configurations.

(34) The GHG emissions allocated to the electricity coproduct (inkgCeq per GJ of FTL) = (GHGI)*(E/F)*ERSupPC-V, where E/F is theratio of electricity/FTL output (in MWhe/GJ) and ERSupPC-V is theemission rate for a new supercritical coal plant (226.7 kgCeq/MWh).

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ethanol technologies are presented in the Supporting Infor-mation.

Figure 10 presents GHGI and GHGA values for all 16FTL systems analyzed along with those for EtOH-V andEtOH-CCS. The following observations can be made aboutthe GHGI values: (1) Nine of the systems have GHGI <0.20, and these are truly low-C transportation fuel options.(2) Both BTL-RC-CCS and EtOH-CCS have negativeGHGI emission values that can be exploited to offsetGHG emissions from difficult to decarbonize energy sourcessuch as transportation fuels derived from crude oil. (3) The

GHGA for BTL-RC-CCS is 56% higher than that of EtOH-CCS;largely because 56% of the biomass carbon is storedunderground for BTL-RC-CCS compared to only 15% forEtOH-CCS.

Offsetting GHG emissions from crude-oil-derived prod-ucts with negative emissions is an important carbon mitiga-tion benefit offered by the BTL-RC-CCS and EtOH-CCSoptions. But this benefit should be considered in the contextof the complementary public policy goal of enhancing energysecurity by reducing dependence on oil imports. Becausesustainably produced biomass is a relatively scarce resource,

Figure 9. Carbon balances and GHG emission flows for (a, upper) CBTL-OT-V (GHGI = 0.772), (b, center) CBTL-OT-CCS (GHGI =0.093), and (c, lower) CBTL1-OT-CCS (GHGI = 0.498). Shown for comparison are GHG emissions for crude oil products displaced. Herechar refers to carbon in the ash residue from coal and biomass gasification.

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the effectiveness of its use in providing liquid fuel alternativesto imported oil is an important consideration. Figure 11shows one measure of biomass effectiveness in providingliquid fuels with low GHGI values: the GJ of biomassfeedstock required per GJ of transportation fuel produced.Shown for comparison are estimates for cellulosic ethanolmade from the same biomass via enzymatic processing. Theethanol and BTL systems have comparable biomass require-ments per unit of low-C fuel provided.35 For the CBTLdesigns the required amount of biomass is half or less sothat these options can offer more secure supplies of low-carbon alternatives to crude-oil-derived products than canthe pure biofuel options.

Because carbon mitigation and energy security enhance-ment goals will be pursued simultaneously in public policy,both of these strategies for using biomass are likely to be

pursued. The technology mix that emerges is likely to bedetermined to a large extent by relative economics.

5. Cost Analysis

5.1. Capital Cost Estimates.Our process simulation resultsare used as inputs to a self-consistent set of capital costestimates for all 16 plant designs that provides the basis formeaningful comparisons of their overall economics.

We have not attempted to be “up-to-date” in our estimatesof capital costs, which change rapidly (especially during theperiod 2003-2008). High-quality estimates of absolute costsare valuable, highly prized intellectual property, changerapidly, and are not readily found in the open literature.Instead our aim is put forth a methodology that makes itfeasible to estimate with a reasonably high degree of con-fidence how relative costs will compare among the alterna-tive systems analyzed.

To estimate total plant costs, we developed a reference setof capital costs for system components within each majorcategory of plant operations. We drew on literature sources,extensive discussions with industry experts, and our ownprior work in developing a capital cost database. We madeadjustments to ensure that assumptions regarding installa-tion factors, balance of plant, indirect costs, and maximum

Figure 10. (a) GHGI and (b) GHGA values for alternative liquid fuel production systems. The basis for the two ethanol systems is presented inthe Supporting Information.

(35) But note that the biofuel production with CCS designs would becharacterized by negativeGHGemissions, so that there would be “roomin the atmosphere” for using some conventional petroleum fuels whilemaintaining overall zero net GHG emissions from the liquid fuels.(36) National Energy Technology Laboratory.Cost and Performance

Baseline for Fossil Energy Plants: Volume 1: Bituminous Coal andNatural Gas to Electricity; DOE/NETL-2007/1281 (Rev. 1), Pittsburgh,August 2007.

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unit-capacity limits were applied consistently and realisti-cally across all plant designs. We relied heavily, but notexclusively, on a major NETL study36 for reference compo-nent costs. We used appropriate factors to scale costs fromthe reference unit capacities to the unit capacities determinedfrom our process simulations.

Our economic analyses assume “Nth plant” technology, i.e.,that added risks/costs that typically accompany technologiesnot yet established in the market are not taken into account.We make this assumption for two reasons. First, we areinterested in understanding the long-term commercial viabil-ity of the different systems analyzed based on currenttechnologies. Second, nearly all of the component technol-ogies included in our plant designs are already commerciallyestablished (see Section 2), so it is plausible that these systemscould reach commercial maturity within the next decade or so.

The Chemical Engineering Plant Cost Index37 was used toescalate all construction cost estimates to 2007 (therebytaking into account cost escalations in materials, equipment,engineering, and construction up to that point in time); allcosts are expressed in constant 2007 U.S. dollars. Theestimated uncertainty in our total plant capital cost estimatesin this framework is (30%, based on the level of detail(factored estimates for major plant areas) and the nature ofliterature and industry sources used. The Supporting Infor-mation provides detailed documentation on all of our re-ference costs and scaling factors. Table 7 shows our capitalcost estimates. Total capital costs range from around $0.7billion for the relatively small BTL designs to nearly $5billion for the largest coal-only facilities. Comparing specificplant costs ($/kWHHV input, last column in Table 7) revealsthe strong scale economies achieved with the largest (coal-only) facilities relative to the smallest (biomass-only) facil-ities. Specific costs for the CBTL facilities fall in the mid-range, as might be expected.

5.2. Production Cost Estimates. The capital cost estimatesdiscussed above provide the basis for estimating the totalenergy production costs at each facility.

In the case of plants with CCS, the capital costs presentedin Table 7 include capital costs for compression of capturedCO2 to 150 bar but exclude costs for CO2 pipeline and

injection facilities; these are instead included as operatingcost items in the estimates of production costs. We assumethat the CO2 is transported 100 km from the conversionfacility and stored 2 km underground in deep saline forma-tions viawells forwhich the assumedmaximum injection rateperwell is 2500 tonnes per day.Costs per tonne ofCO2 storedwere estimated using a model for CO2 transmission andstorage developed by Ogden38,39 that takes into accountvarious nonlinear variations in costs with scale (tonnes peryear) and distance.

Because XTL facilities coproduce both electricity andliquid fuels, we examine production economics from theperspectivesofbotha fuelsproducerandanelectricitygenerator.

5.2.1. Liquid Fuel Producer’s Perspective. For the fuelproducer perspective, we assume revenue from the sale ofelectricity is a credit against the production cost of the liquidfuels. The value of coproduct electricity is calculated using asimple model that attempts to project how the cost of CO2

emissions might be reflected in the average U.S. grid price ofelectricity. The value of coproduct electricity,V(T) ($/MWh)is given by:

V ðTÞ ¼ BþXT

where B is 60 $/MWh, the average price paid to U.S. powergenerators in 2007, X is 0.636 tonne CO2eq/MWh, the grid-average GHG emissions intensity of U.S. power generationin 2007 andT is theGHG emissions price ($/tonne CO2eq). Itshould be noted that GHG emissions intensity of the grid,assumed here to be constant, will decrease with increasingGHG emissions price. While uncertainty in the true value ofcoproduct electricity is not likely to significantly affect theoverall economics of XTL-RC systems which produce only amodest amount of power (∼ 10% of the total plant output),it can potentially be quite significant for XTL-OT systems.For that reason, we draw attention to our simple modelhere;which underlies all XTL plant economics assessedfrom the perspective of a fuel producer;and urge the

Figure 11. Primary energy consumed per unit of liquid fuel produced.

(37) Chemical Engineering Magazine, monthly. See http://www.che.com/pci/.

(38) Ogden, J. Modeling infrastructure for a fossil hydrogen energysystem with CO2 sequestration. In Gale, J., Kaya, Y, Eds.; Proceedingsof the 6th International Conference on Greenhouse Gas Control Technol-ogies; Elsevier Science: Oxford, 2003; pp 1069-1074.

(39) Ogden, J. M. Conceptual Design of Optimized Fossil EnergySystems with Capture and Sequestration of Carbon Dioxide; ResearchReport UCD-ITS-RR-04-34, Institute of Transportation Studies, Universityof California Davis, 2004.

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knowledgeable reader to substitute her own model for ourswhen appropriate. For all of our cost calculations,we adopt thebaseline set of assumptions in Table 8 and also examine costsas a function of a greenhouse gas (GHG) emissions price.

Table 9 shows levelized liquid fuel production costs whenno GHG emissions price is considered. For the coal-onlyplants, the relatively low cost of coal (compared to biomass)makes capital charges the most significant production costcomponent despite the scale-economy benefits of their largesize relative to other plant designs. For biomass-only facilities,costs for capital and feedstock are of comparable importance.

In the absence of a GHG emissions price, all CTL plantshave total FTL production costs below $2 per gallon ($0.53per liter) of gasoline equivalent (gge) on a LHV energy basis,while fuel costs for the BTL plants exceed $3 per gge ($0.79per liter). All CBTL plants produce FTL for 2-2.7 $/gge($0.53-$0.71 per liter)

The ranking of production costs among the systemsdepends critically on the GHG emission price (Figure 12a).40

However, using our model of the value of coproduct elec-tricity, no RC plant is the least-cost fuel producer at anyemission price. CTL-OT-V provides the lowest FTL fuel costat emission prices less than $21/tCO2eq because of the lowcost of coal and the powerful thermodynamic advantage ofthe OT design compared to the RC option. But CTL-OT-V,for which GHGI is 1.3, is not a GHG emissions reductionoption. From $21/t to $73/tCO2eq, CTL-OT-CCS providesthe least costly fuel and offers modest emission reductions(GHGI = 0.7). CBTL-OT-CCS (GHGI = 0.093) providesthe lowest cost fuel when the emission price is between $73/tand $110/t. Finally, BTL-RC-CCS, with its negative GHGemissions, is the provider of the least costly fuel when theGHG emissions price exceeds $110/t (off graph).

Table 9 also reports for zero GHG emissions price thebreakeven oil price (BEOP), the price of crude oil at whichthe FTL production cost (on a $/GJLHV basis) equals thewholesale (refinery-gate) price of the equivalent crude-oil-derived products. In the absence of a GHG emissionsprice, the CTL-CCS systems have BEOPs in the range $59-$65 per barrel, compared to $145 per barrel for a BTL-RC-CCS plant. All CBTL-CCS designs for which GHGI is lessthan 0.1 have BEOPs between $84 and $110 per barrel. Forperspective, the world oil price at the time of writing this paperwas $75 a barrel, and the levelized crude oil price over the period2016-2035 is projected to be $100 a barrel (Table 8).

Breakeven oil price estimates as a function of GHGemissions price (Figure 12b) provide an important insightregarding risk-mitigation that coproduction might provideto investors in such systems in the future. If a strong enoughcarbon mitigation policy is in place, the economics ofcoproduction would remain favorable even if the world oilprice were to collapse. For example, in the presence of the$73/t CO2eq GHG emissions price needed to make CBTL-OT-CCS the least costly option, this system would becompetitive at crude oil prices down to $45 a barrel. Incontrast, the CBTL-RC-CCS, which makes only a minor

Table 7. Estimated Total Plant Capital Costs (TPC or “Overnight” Costs) for Alternative FTL System Configurations

plant name

million 2007 $ $/kWHHV

ASUislanda

biomassislandb

coalislandc

gascond.d

CO2

comp.FT

islandenaphthaupgradef

toppingpower g

heat recov þ steamcycleh

total

costi

specific

costj

CTL-RC-V 808 0 1,468 849 0 882 86 35 723 4,852 642

CTL-RC-CCS 808 0 1,468 849 67 882 86 35 723 4,919 651

CTL-OT-V 711 0 1,468 636 0 519 70 272 713 4,390 581

CTL-OT-CCS 742 0 1,468 727 60 519 70 280 708 4,574 605

CTL-OTA-CCS 783 0 1,468 762 73 676 70 238 757 4,826 638

BTL-RC-V 100 336 0 59 2 137 21 0 69 724 1,097

BTL-RC-CCS 100 336 0 59 14 137 21 0 69 737 1,115

CBTL-RC-V 208 335 226 158 2 244 33 7 136 1,349 921

CBTL-RC-CCS 208 335 226 158 22 244 33 7 136 1,369 935

CBTL-OT-V 206 335 263 133 2 171 29 77 156 1,372 821

CBTL-OT-CCS 217 335 263 151 24 171 29 80 155 1,427 854

CBTL1-OT-CCS 225 138 340 187 23 170 29 81 175 1,369 810

CBTL-OTS-CCS 286 335 473 235 33 246 39 127 180 1,955 706

CBTL-OTA-V 243 335 396 180 2 208 35 98 224 1,720 755

CBTL-OTA-CCS 255 335 396 215 33 263 35 86 168 1,786 784

CBTL-OTAS-CCS 387 334 649 372 46 385 47 135 257 2,611 701

aAir separation unit and O2 and N2 compressors. b Includes biomass preparation, feeding, gasification, and gas cleanup. c Includes coal preparation,feeding, gasification, and quench cleanup. dGas conditioning includes all water gas shift, acid gas removal, and Claus/SCOT H2S conversion toelemental sulfur. e IncludesFT synthesis, recycle compressor,ATR(s), andFT refining, except for naphthaupgrading. fManyproposedFTplant designspropose to sell naphtha as a chemical feedstock.We have separated out the costs of naphtha upgrading (isomerization and catalytic reforming units;seeFigure 2) to facilitate readers making their own evaluation of this option. gThis is the topping cycle in the power island. For all designs except BTLsystems, this includes a syngas expander used to generate power (e.g., see Figure 5). Additionally, for all -OT designs, this includes a gas turbine andrelated auxiliaries. hThis includes the cost of all heat recovery at the plant, plus the cost of steam turbine and related auxiliaries in the power island. iThisis total plant cost (TPC), or “overnight capital cost” (which excludes interest during construction). jThis is the cost perMWHHV of total feedstock input.

(40) For simplicity we have excluded fromFigure 12 results for plantsthat incorporate autothermal reforming to increase the amount of CO2

captured (CTL-OTA-CCS, CBTL-OTA-CCS, and CBTLOTAS-CCS).Although the cost per extra tonne of CO2 captured is relatively high forthese systems (see right-most column in Table 9), they are nonethelesssometimes economically superior to the analogous OT plants (withoutATR). For example, at zero GHG emissions price, the CBTL-OTA-CCS option offers less costly FTL fuel than the corresponding CBTL-OToption (see Table 9). In addition, becauseOTAdesigns vent less CO2

than their OT analogs, they utilize biomass more efficiently—e.g., thecarbon in FTL fuels is equivalent to 80% of the carbon in the biomassfeed for CBTL-OTA-CCS but only 59% for CBTL-OT-CCS. We havealso excluded fromFigure 12 results for plants using biomass grownwithsoil/root C storage (CBTL-OTS-CCS, CBTL-OTAS-CCS), becausesuch biomass supplies are likely to be limited compared with otherbiomass supplies.(41) Our estimate of the lifecycle GHG emissions for a supercritical

PC coal power plant is based on the power plant emissions (NETL36)plus upstream emissions for coal mining and delivery based on theGREET model.30

(42) Based on the GREET model,30 the estimated lifecycle emissionrate for a 63/37 mix (LHV basis) of petroleum-derived diesel/gasoline is91.6 kgCO2eq/GJLHV.

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electricity coproduct, would not be able to compete if crudeoil prices fell below $69 per barrel.

Finally, in light of the carbonmitigation and biomass utiliza-tion benefits offered by some XTL-CCS options relative tocellulosic ethanol (EtOH-V and EtOH-CCS options;see Figure 10a and b and Figure 11), it is important tounderstandalso the relative economicmeritsof thesealternative

thermochemical and biochemical energy conversion options.Figure 13 shows how levelized costs of production comparefor EtOH-V, EtOH-CCS,CBTL-RC-CCS, CBTL-OT-CCS,and both BTL-RC options;each of which has been sized toconsume the same amount of biomass (0.46 million tonnes peryear). (Details relating to the cost calculations for cellulosicethanol are presented in the Supporting Information.)

Table 8. Feedstock Prices and Financial Assumptions

Levelized coal price to U.S. average coal power generator, 2016-2035 ($/GJHHV)a 1.86

Levelized natural gas price to U.S. average natural gas power generator, 2016-2035 ($/GJHHV)a 6.35

Biomass price delivered to conversion plants ($/GJHHV)b 5.0

Annual average capacity factor for XTL plants (%) 90Annual average capacity factor for power-only plants (%) 85Assumed economic life of energy conversion plants (years) 20IDC [interest during construction = fraction of total plant cost (TPC or overnight plant capital)]c 0.0716Annual capital charge rate (ACCR) applied to [ TPC*(1 þ IDC)], fractiond 0.1422Annual O&M costs at the conversion facility (% of TPC or overnight plant capital) 4CO2 transport and injection/storage costs, $ per tonne of CO2 varies with scalee

20-yr levelized electricity sale price with zero GHG emission price ($ per MWh)f 60Assumed GHG emission rate for electric grid into which electricity is sold (kg CO2eq per MWh)f 636Crude oil price at time of writing this paper ($ per bbl) 75Levelized crude oil price ($ per bbl) with zero GHG emissions price, 2016-2035 ($/barrel)g 100Assumed refinery markups for diesel/gasoline displaced by FTL (¢/liter)h 7.90/8.51

aThese are fossil fuel prices to average power generators in theU.S. in 2007 dollars levelized over the period 2016-2035 (assuming a 7%discount rate),based on the Reference Scenario projection by the Energy Information Administration.45 bFor comparison, a detailed biomass logistics analysis forseventeen states in the central U.S. estimated the costs for annually delivering one million tonnes (dry basis) of biomass to a central conversion facilityrange from $3.8 to $6.2 per GJHHV (for corn stover biomass) and from $5 to $8.6 per GJHHV (for low-yield, low-planting densitymixed prairie grasses).9c Interest during construction (IDC) is based on a 3-year construction schedule with equal annual payments and a real discount rate of 7%/year. dTheannual capital charge rate (ACCR) (used in the EPRI TAG methodology to calculate the annual capital charge = [ACCR*(1 þ IDC)*TPC (in $ peryear)], assuming a 7% real discount rate, a 55/45 debt/equity ratio, a 39% corporate income tax rate, a 2% property tax/insurance rate, and a 20-yeareconomic life for plants).46 eFor designs incorporatingCCS,CO2 is available at 150 bar at the plant gate.We assume theCO2 is transported 100 km fromthe conversion facility and stored 2 km underground in deep saline formations. Costs per tonne of CO2 stored are estimated using a model for CO2

transmission and storage developed byOgden38,39 that takes into account various nonlinear variations in costs with scale (tonnes per year) and distance.fFor comparison, the average price at which power generators in the U.S. sold their electricity into the grid in 2007 was $60 per MWh.47 For nonzeroGHG emission prices, we assume that the sale price increases by an amount equal to the GHG emission price times the grid-average GHG emissions intheU.S. in 2007 (636 kgCO2eq/MWh).30 gThis is the crude oil price at a zeroGHGemissions price in $2007/bbl levelized over the period 2016-2035 (7%discount rate), based on the Reference Scenario of the Energy Information Administration.45 hFor U.S. refineries, margins (in 2007$) averaged during1990-2003 32.2¢ a gallon for gasoline and 24.9¢ a gallon for diesel.48 For the future, it is assumed that the gasoline margin is the same but that the dieselmargin is increased by 5.0¢ a gallon in order to comply with the sulfur standards that that took effect in 2007.49 Thus the assumedmargins in the absenceof price on GHG emissions are 32.2¢ a gallon (8.51¢ a liter) and 29.9¢ a gallon (7.90¢e a liter), respectively.

Table 9. Estimated Liquid Fuel Production Costs at Zero GHG Emissions Price

levelized liquid fuel production costs $/GJLHV

cost of CCS ($/tCO2)dplant name capital O&M coal biomass CO2 disposal

b electricity revenue

total total

BEOPc ($/bbl)$/GJLHV $/gge

a

CTL-RC-V 8.3 2.2 4.5 0.0 0.0 -2.1 12.8 1.5 58 -

CTL-RC-CCS 8.5 2.2 4.5 0.0 0.5 -1.6 14.1 1.7 65 12.4

CTL-OT-V 10.6 2.7 6.2 0.0 0.0 -9.3 10.2 1.2 44 -

CTL-OT-CCS 11.0 2.9 6.2 0.0 0.7 -7.8 13.0 1.6 59 20.6

CTL-OTA-CCS 11.6 3.0 6.2 0.0 0.9 -6.2 15.5 1.9 73 34.7

BTL-RC-V 13.8 3.6 0.0 11.6 0.0 -2.5 26.4 3.2 133 -

BTL-RC-CCS 14.0 3.6 0.0 11.6 1.4 -1.8 28.8 3.4 145 20.9

CBTL-RC-V 11.8 3.1 2.4 5.3 0.0 -2.0 20.5 2.5 100 -

CBTL-RC-CCS 12.0 3.1 2.4 5.3 0.9 -1.4 22.3 2.7 110 16.9

CBTL-OT-V 14.7 3.8 3.7 6.5 0.0 -9.9 18.8 2.3 91 -

CBTL-OT-CCS 15.3 4.0 3.7 6.5 1.2 -8.4 22.2 2.7 110 24.0

CBTL1-OT-CCS 14.6 3.8 5.4 2.1 1.2 -8.0 19.1 2.3 93 -

CBTL-OTS-CCS 12.7 3.3 4.7 4.0 1.0 -8.2 17.5 2.1 84 -

CBTL-OTA-V 13.6 3.5 4.4 4.8 0.0 -9.9 16.4 2.0 78 -

CBTL-OTA-CCS 14.1 3.7 4.4 4.8 1.3 -7.0 21.2 2.5 104 30.3

CBTL-OTAS-CCS 12.7 3.3 5.1 3.0 1.1 -6.9 18.2 2.2 88 -

aThis is $ per gallon of gasoline equivalent, obtained bymultiplying total production cost ($/GJLHV) by the energy content of gasoline (0.12GJLHV/gallon).bThis is the cost for 100 km of CO2 transport by pipeline from the conversion facility and injection 2 km underground into a deep saline formation. SeeTable 8 for source of cost estimate. cThis is the breakeven oil price, which we define to be the price of crude oil in $ per barrel at which wholesale pricespaid to refiners for petroleum-derived productswould equal (on a $ perGJLHV basis) our calculated costs for producingFTL fuels. As described in detailby Kreutz et al.,5 our BEOP is calculated from the FTL fuels production cost by subtracting the refiner’s margin. (The refiner’s margin is the differencebetween the price of crude oil paid by a refiner and the wholesale price at which the refiner sells finished petroleum products;see Table 8.) When theGHG emissions price is nonzero, GHG emission charges for petroleum-derived products (see Table 4, footnote b) are factored into the BEOPcalculation. dThis is calculated as the difference in levelized production cost ($/GJ) for a plantwithCCSversus a plant of the samebasic design (and sameratio of coal-to-biomass inputs) but without CCS, divided by the amount of CO2 captured with CCS. We do not calculate the cost of CO2 capture forplants with CCS for which we have not developed an equivalent -V plant design.

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This internally self-consistent analysis shows the least costlyoption is CBTL-RC-CCS up to a GHG emissions price of$13/t CO2eq, above which CBTL-OT-CCS is the least costlyoption (at this scale of biomass input) up to a GHG emis-sions price of $123/t (not shown), at which price BTL-RC-CCS becomes the least costly option. Cellulosic ethanol isnever one of the least costly options.

A striking feature of this analysis is that while a shift froma -V to a -CCS system configuration dramatically reduces thelevelized production cost with rising GHG emissions pricefor both the BTL-RC and CBTL-OT options (Figure 12a),the economic benefit of shifting from -V to -CCS is modest inthe cellulosic ethanol case (Figure 13). The reason is that theCO2 capture rate, expressed as a fraction of the carbon in thebiomass feedstock, is much smaller in the EtOH-CCS case(16%), compared to 54% and 56% in CBTL-OT-CCS andBTL-RC-CCS, respectively.

5.2.2. Electricity Generator’s Perspective. Electricity ac-counts for roughly one-third of the energy output fromplants with OT designs, making it relevant to consider theseplants as electricity generators and analyze their economicsin comparison with stand-alone electricity generation tech-nologies.

Economic comparisons are made among the 5 OT optionsand the 6 stand-alone power options listed in Table 10.

The XTL-OT systems considered here are designed tohave capacities smaller than in Table 3, which were the basisfor the previous analysis from a liquid fuel producer’sperspective, because they would be distributed widely nearelectricity demand centers (like conventional power plants)rather than built as huge plants sited at remote locations. Toillustrate the economic implications of this strategic perspec-tive, the levelized costs of electricity (LCOE) is estimated forsystem capacities determined according to the followingalgorithms: (1) gasification-based energy systems using onlycoal were assigned the same coal input rate as a new super-critical coal plant that vents CO2 (sup PC-V;considered thereference coal power system); and (2) all XTL-OT systemswere assigned the same FTL fuels production capacity as theCTL-OT options (6637 barrels per day).

Coal integrated gasifier combined cycle (CIGCC) systemswere modeled using the same techniques and analyticalframework as for FTL systems described above. Systemcharacteristics for sup PC and NGCC in Table 10 were not

modeled but are taken from NETL,36 and LCOEs wereestimated using the same financial, fuel price, and otherassumptions as used for XTL systems (Table 8). GHGIand GHGA values for the NETL-based stand-alone poweroptions were calculated using the same methodology asfor the fully modeled systems.41 Cost comparisonsamong the NETL-based stand-alone options and the fullymodeled systems are likely to be meaningful because theanalytical framework for cost estimation used in the presentstudy is based largely on that used byNETL,36 as mentionedearlier.

When evaluating coproduction systems as power genera-tors, a credit is received for the sale of the FTL fuelcoproduct. It is assumed that (1) FTL products are sold atthe wholesale (refinery gate) prices of crude oil products theycould displace (Table 8), and (2) when a GHG emissionsprice is considered, the selling prices are assumed to increase

Figure 12. (a, left) Levelized FTL fuel production cost estimates and (b, right) corresponding breakeven oil prices as functions of GHGemissions price for selected plant designs.

Figure 13. Levelized production costs for alternative low-carbonfuels derived from switchgrass. Cost estimates for EtOH-V arebased on the analysis inNRC,8 except that that analysis is presentedin the same analytical framework as for the FTL fuel options (seeSupporting Information for details). The authors developed the costestimates for EtOH-CCS, starting with the NRC results for EtOH-V (see Supporting Information for details). In all cases, the assumedannual biomass input rate is 0.46 million dry tonnes per year;therate assumed for EtOH-V in NRC.8

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by an amount equal to the fuel-cycle-wide GHG emissionrates for the crude oil products times the GHG emissionsprice.42

LCOEs are compared as a function of GHG emissionsprice in Figure 14 for the 11 power options listed in Table 10when the crude oil price is at its current (2010) level, $75 abarrel. Particular attention is given to the 9 options shown inTable 10 that might be considered as lower GHG-emittingalternatives to a new sup PC-V plant (for which GHGI =1.0);the least costly new coal power option at a zero GHGemissions price.

Adiscussionofkey systemattributesof the stand-alonepowersystem and their LCOEs as a function of GHG emissions pricecan be found in the Supporting Information. Here it suffices tosay that (i) CIGCC-CCS is the least-costly coal stand-alonepoweroptionwithCCS, and (ii) consideredaspowergenerators,coproduction systems outperform stand-alone power systemsunder a wide range of conditions.

A striking feature of the LCOE vs GHG emission pricecurves (Figure 14) is the wide range of slopes among the fiveXTL-OT systems;a phenomenon that arises because GHGemissions enter the LCOE calculation in two ways: (a) chargesfor the gross fuel-cycle-wide GHG emissions for productionand consumption of the system products (which vary by afactor of 13), and (b) credits for GHG emissions of the crudeoil products displaced (which vary by a factor of 1.3). The netemissions charged to the produced electricity is (c) [= (a)- (b)](whichmight be called the “effectiveGHGemission rate” forLCOE evaluation purposes), and the corresponding slopesof the LCOE vs. GHG emissions price curves thus rangefrom strongly positive to strongly negative (Table 11).

One important finding for XTL-OT options is the muchlowerGHGemissions price required for breakeven between -Vand -CCS options than for any of the stand-alone poweroptions ($27/t for CTL-OT and $28/t for CBTL-OT vs $54/tto $88/t for the three stand-alone power options);reflectingmainly the fact that CO2 has to be removed upstream of

Table 10. Alternative Electric Generation Technologies

technologyfuel input,

MWt (HHV)biomass input,

dry t/daynet electric,

MWe

FT,bbls/d GHGI

GHGA, kg CO2eq/MWh

CO2 stored, 106 t/yr TPC, $109El FTL total

sup PC-Va 1,405 0 550 0 1.0 0 0 0 0 0.89sup PC-CCSa 2,004 0 546 0 0.21 660 0 660 4.2 1.62CIGCC-V 1,405 0 528 0 1.0 -2.6 0 -2.6 0.0 1.00CIGCC-CCS 1,405 0 435 0 0.15 705 0 705 2.9 1.17NGCC-Va 1,102 0 560 0 0.51 410 0 410 0.0 0.32NGCC-CCSa 1,102 0 482 0 0.13 721 0 721 1.4 0.58CTL-OT-V 1,405 0 234 6,637 1.31 -260 -185 -446 0.0 1.05CTL-OT-CCS 1,405 0 197 6,637 0.70 253 214 467 1.8 1.09CBTL1-OT-CCS 1,397 793 202 6,637 0.50 417 344 761 1.8 1.16CBTL-OT-V 1,380 2,514 249 6,637 0.77 189 127 316 0.0 1.17CBTL-OT-CCS 1,380 2,514 212 6,637 0.09 753 591 1,344 1.9 1.22

a Source: NETL.36

Figure 14.Levelized electricity generating costs as a function ofGHGemissions price. The revenue for FTL products is assumed to be the sameas the cost (including cost of carbon emissions) for making an equivalent amount (LHV basis) of diesel and gasoline from crude oil purchasedfor $75/bbl.

(43) EPA (Environmental Protection Agency) 2010: EPA Analysis ofthe American Power Act in the 111th Congress, 14 June.(44) MIT. The Future of Natural Gas, an Interim Report; The MIT

Energy Initiative, 2010.(45) Energy Information Administration. Annual Energy Outlook

2010. www.eia.doe.gov.(46) Electric Power Research Institute. Technical Assessment Guide

(TAG) Electricity Supply;1993; TR-102276-V1R7; EPRI: Palo Alto, CA,1993.(47) Energy Information Administration. Annual Energy Outlook

2008. www.eia.doe.gov.(48) Energy Information Administration. Annual Energy Review

2007; DOE/EIA-0384(2007); June 2008.(49) U.S. Environmental Protection Agency. Control of air pollution

from new motor vehicles: heavy-duty engine and vehicle standards andhighway diesel fuel sulfur standards and highway diesel sulfur controlrequirements; final rule; 40 CFR (Code of Federal Regulations) Parts69, 80, and 86. Federal Register, 18 January, 2001, Vol. 66 (12).

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synthesis even in the absence of a carbon policy, so thatenergy penalties are low (less than 10%, Figure 15), as arecapture costs (Figure 16).

Another important result is that, in the absence of theNGCC-V option, XTL-OT plants provide the least costlypower over the entire range of GHG emission prices con-sidered: CTL-OT-V (GHGI=1.31) has the lowest LCOEup to $27/t CO2eq, followed by CTL-OT-CCS (GHGI= 0.70)for GHG emission prices between $27 and $44/t CO2eq,above which CBTL-OT-CCS (GHGI = 0.093) yields theleast costly LCOE.

With NGCC-V (GHGI = 0.51) also competing;assum-ing an 85% design capacity factor and a natural gas price of$6.35/GJ (see Table 8);the only change is that NGCC-Vyields the least costly LCOE over the range 12-54 $/tonneCO2eq, abovewhichCBTL-OT-CCSbecomes the least costlypower system.

It is desirable to understand the relative economics of the11 competing technologies in the framework of possiblefuture GHG emissions prices under a comprehensive carbonmitigation policy. The U.S. Environmental ProtectionAgency43 has carried out a detailed analysis of the implica-tions for the U.S. of enacting the American Power Act(Kerry-Lieberman bill proposed in the U.S. Senate in early2010) along with a parallel analysis of the American CleanEnergy and Security Act (ACESA) of 2009 (Waxman-Markey bill passed in the U.S. House of Representatives in2009). The EPA estimates that, if the APA were to beenacted, the market clearing price for the sale of emissionallowances (in effect, the market price of GHG emissions)would rise at a rate of 5%per year from$17/t in 2013 to $102/tin 2050 (in $2005);with a very similar GHG emissionsprice trajectory if the ACESA were enacted instead. Forthis GHG emissions price trajectory the 20-year levelizedGHG price for power plants coming on line in 2026(assuming a 7% discount rate) would be $50/t CO2eq

(in $2007). At this price, a CBTL-OT-CCS plant would bethe least costly coal-using option in terms of the LCOE overthe 20-year economic life of power plants coming on linein that year if the levelized crude oil price over that period is$75 a barrel.

Power plant investors will want to have a good sense ofwhat the downside risks and upside rewards might be forinvestments in coproduction technologies. We provide aperspective on this issue in the context of a $50/t CO2eq

GHG emissions price.On the downside, an important consideration is the risk of

a collapse in the oil price. It is of interest to know the oil priceat which the LCOEs for XTL-OT options would be the sameas for an CIGCC-CCS system;the least costly coal optionfor providing decarbonized electricity in a new power plant(Figure 14). The oil price influences the LCOE for XTL-OTpower systems as the 20-year levelized oil price over theeconomic life of the plant. These breakeven oil prices are $82,

$65, $67, and $60 a barrel for CTL-OT-V, CTL-OT-CCS,CBTL1-OT-CCS, and CBTL-OT-CCS systems, respec-tively, for a $50/t CO2eq levelized GHG emissions price.Thus, an investment in a coproduction plant with CCShaving a high fraction of biomass input would have a higherdegree of protection against the risk of oil price collapseunder a serious carbon policy compared to the protectionoffered (or not) by alternative investment opportunities forcoproducing synfuels.

Persistence of the current crude oil price might be viewedas an overly pessimistic outlook from the perspective of

Table 11. Effective Net GHG Emissions for Coproduction Systems (kg CO2eq per MWh)

(a) GHG emissions for system(b) GHG emissions credit for crude

oil products displacedaeffective net emissions for evaluating LCOE:

(c) = (a) - (b)

CTL-OT-V 1,867 591 1,276CTL-OT-CCS 1,067 703 364CBTL1-OT-CCS 754 685 69CBTL-OT-V 1,071 556 515CBTL-OT-CCS 138 652 -514

a See Table 4 footnote (b) for emissions charged to petroleum-derived diesel and gasoline.

Figure 15. Energy penalty for CCS. For power-only systems, theenergy penalty is 100(ηv/ ηc - 1) where ηv and ηc are HHV plantefficiencies for -V and -CCS options, respectively. For XTL-OT-CCS options, energy penalty = 100(extra coal energy required tomake up for lost power in shifting from -Vf -CCS;assumed to bevia CIGCC-CCS)/(coal energy use by XTL-OT-V).

Figure 16. CO2 capture costs for alternative power systems withCCS.

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potential coproduction facility investors. The U.S. EnergyInformation Administration projected in its 2010 ReferenceScenario that the world crude oil price will rise to $90/barrelby 2016 and then to $121/barrel by 2035. For this projection,the corresponding levelized crude oil price, 2016-2035, is$100/barrel ($2007);see Table 8. At that crude oil price and aGHGemissions price of $50/t, theLCOE for aCBTL-OT-CCSsystem for whichGHGI= 0.093 would be 14% less than fora sup PC-V plant at a zero GHG emissions price (Figure 17),compared to 43% more when the crude oil price is $75 abarrel. Moreover, per MWh of electricity generated, theCBTL-OT-CCS option offers a GHGA rate (Table 10) thatis 1.9� that for a CIGCC-CCS plant and, at a $100/barrelcrude oil price, a much lower LCOE at all GHG emissionsprices (Figure 17).

Those seeking to establish coal-derived synthetic fuels inthe market have focused on large plants such as the CTL-RC-V (GHGI = 1.71) and CTL-RC-CCS (GHGI = 0.89)plants for which levelized FTL fuels production costs arepresented in Figure 12. That analysis showed that under amodest carbon mitigation policy (GHG emissions pricegreater than ∼$10/t CO2eq), the CCS option would bepreferred. Under a more stringent carbon mitigation policy(GHG emissions price greater than ∼$50/t CO2eq) emphasiswould be on coprocesssing biomass as a substantial fractionof the feedstock as well as on CCS. Constraints on theamount of biomass that can be delivered to the conversionplant imply that these plants would have relatively low FTLoutput capacities. It is of interest to understand the interplaybetween the scale economy effect and the carbon mitigationpolicy effect in shaping investment decisions. Table 12 showsthat at the plausible future GHG emissions price of $50/tCO2eq, the CBTL-OT-CCS coproduction systems modeledhere would be able to provide low GHG emitting synthetic

fuels at the same unit cost as for coal synfuels (via CTL-RC-CCS) characterized by ten times the GHG gas emission ratethat are produced in plants having three times the synfueloutput capacity and requiring twice the capital investment,while providing electricity at lower generation cost thanfor alternative new stand-alone fossil fuel power plants(Figure 14 and Figure 17).

Being able to provide low-carbon synfuels in small plantsthat can compete at a wide range of crude oil prices ought tomake synfuel project financing easier for CBTL-OT-CCSsystems than for the large plants based on coal only that areenvisioned for a future synfuels industry by most potentialsynfuel investors.

However, prospective synfuel investors might be hesitantto get involved in coproducing electricity, the sale of which isdetermined on a moment-by-moment basis via economicdispatch competition. Prospective synfuel investors willwant their plants to operate at∼90%capacity;the assumedcapacity factor for XTL-OT plants (Table 8) designed asmust-run baseload plants. But these investors might notethat the average capacity factor for coal power plants in theU.S. electric power sector, determined to a large extent byeconomic dispatch competition, was only 74% in 2008.

So it is important to assess how coproduction plantswouldoperate in economic dispatch competition, which, to a largeextent determines a power plant’s capacity factor. Theelectric grid system operator determines the merit order fordispatching plants selling electricity into the grid, typicallyon an hour-by-hour basis, based on bid prices to sell from thevarious power generating units connected to the grid. Theminimum price that a power plant operator will be willingto bid is its minimum dispatch cost (MDC) determined byequating revenues for the bidding period with the system’sshort run marginal cost (SRMC, i.e., operating cost, excluding

Figure 17.LCOEs for alternative power systems for crude oil prices of $75 and $100 a barrel and for two alternative capacity factors for power-only systems.

Table 12. System Attributes at Breakeven FTL Production Cost for CTL-RC-CCS and CBTL-OT-CCS at $50/t CO2eq

CTL-RC-CCS CBTL-OT-CCS

Breakeven FTLfuels cost, $/GJ

Corresponding crudeoil price, $/barrel

LCOE (CBTL-OT-CCS),$/MWhGHGI

FTL output,B/D TPC, $106 GHGI

FTL output,B/D TPC, $106

0.89 22,936 2,485 0.093 6,637 1,218 19.5 75 85.0100 52.4

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capital amortization and fixed operation and maintenancecosts). Because coproduction systems provide two revenuestreams, the minimum dispatch cost is given by MDC ($ perMWh)= SRMC ($ perMWh)- (FTL revenues perMWh),which implies very low MDC values at sufficiently high oiland GHG emission prices.

Figure 18 presents MDCs for CBTL-OT-CCS systems atthree alternative crude oil prices, for five of the stand-alonepower systems listed in Table 10, and for a nuclear plant. TheMDC at zero GHG emission price for a CBTL-OT-CCSplant is the same as for a nuclear plant and for a sup PC-Vplant (the closest competitors) for crude oil prices of $67 and$57 a barrel, respectively. Moreover, the MDC for CBTL-OT-CCS reaches $0/MWh (with zero GHG emission price)when the crude oil price is $74 a barrel. Thus coproduc-tion systems will be able to defend high capacity factorsin economic dispatch competition and would be able todrive down the capacity factors of competing systems asdeployment of coproduction technologies on electric gridsincreases.

Notably, the actual average capacity factor for the 190GWe of NGCC capacity in the U.S. been only 41%.44 Thislow capacity factor reflects, to a large extent, slow electricitydemand growth in the U.S. and the fact that when both coaland NGCC plants have been competing to provide the samepower demand, the coal plants have tended to win theeconomic dispatch competition, giving them much highercapacity factors. It is not unreasonable to expect that, with alarge amount of CBTL-OT-CCS capacity on the grid, eco-nomic dispatch competition might constrain the capacityfactor for stand-alone power plants to 50%;in which caseCBTL-OT-CCS would offer a lower LCOE at $50/t CO2eq

than all stand-alone fossil fuel power plants, includingNGCC-V, at oil prices of both $75 and $100 a barrel(Figure 17).

The economic performances of coproduction systemsunder a carbon mitigation policy look especially attractivewhen they are evaluated as electricity generators largelybecause (1) the CO2 capture costs are much less than thosefor stand-alone power plants (Figure 16), (2) theMEGEs aremuch higher than the efficiencies of stand-alone power plantalternatives (Table 5), (3) the credit for the FTL coproductrises rapidly with crude oil price, (4) the “effective GHG

emissions rate” for LCOE evaluation purposes is stronglynegative at high biomass input rates (Table 11), and (5) theirlow MDCs enable them to defend high design capacityfactors and force down capacity factors of competingstand-alone power plants.

6. Summary and Conclusions

Detailed process simulations, lifecycle greenhouse gas emis-sions analyses, and cost analyses have been carried out in acomprehensive analytical framework for 16alternative systemconfigurations that involve gasification-based production ofFischer-Tropsch liquid fuels from coal and/or biomass, withandwithout capture and storage of byproduct CO2, includingvia systems that generate electricity as a major coproduct.These analyses provided the basis for adiscussionof themeritsof alternative system designs for addressing simultaneouslykey challenges posed by petroleum-based transportation fuelsand coal and natural gas power generation: high current andprospective oil prices, insecurity of liquid fuel supplies, andclimate change risks.Also, systematic comparisonsweremadeto alternative options (cellulosic ethanol for making lowcarbon fuels and alternative new fossil-fuel based powerplants) for addressing these challenges.

Amajor finding is that, using our simple model of the valueof coproduct electricity as a function of GHG emission price,synthetic liquid fuels are typically less costly to produce whenelectricity is generated as a major coproduct than when theplants are designed to producemainly liquid fuels. Coproduc-tion systems that utilize a cofeed of biomass and coal andincorporate CO2 capture and storage in the design offerattractive opportunities for decarbonizing both liquid fuelsand power generation simultaneously. Such coproductionsystems, when considered as power generators, can providedecarbonized electricity at lower costs than is feasible withnew stand-alone fossil fuel power plants under awide range ofconditions.

At a plausible GHG emissions price of $50/t CO2eq under afuture U.S. carbon mitigation policy, such coproductionsystems competing as power suppliers would be able toprovide low-GHG-emitting synthetic fuels at the same unitcost as for coal synfuels characterized by ten times the GHGemission rate that are produced in plants having three timesthe synfuel output capacity and requiring twice the totalcapital investment. Moreover, the low-GHG-emitting syn-fuels produced by such systems would be less costly andrequire only half as much lignocellulosic biomass (or less) toproduce as would cellulosic ethanol.

This strategy depends on the viability of CCS as a majorcarbon mitigation option, but all system components for thefirst generation of the required conversion technologies(including carbon capture components) areproven technolog-ically, so that commercial-scale projects for coproductionplants with CCS that have modest biomass input rates(∼ 10%) could be demonstrated during this decade.

Acknowledgment. We received helpful commentary and dis-cussion from many individuals during the research for andwriting of this paper. We would like to especially thank DavidGray, Chuck White, and Glen Tomlinson (Noblis), Tom Tarka,John Wimer, Ken Kern, and Michael Reed (NETL), RobertSocolow (Princeton), Francis Lau (SES Energy), Rick Knight(Gas Technology Institute), and JimKatzer and SheldonKramer(independent). For financial support, we are grateful toPrincetonUniversity’s Carbon Mitigation Initiative and its sponsors (BP

Figure 18.MDCs for alternative power systems at alternative crudeoil prices. Parameters used to estimate stand-alone fossil fuel powerplant and nuclear electricity costs are discussed in the SupportingInformation.

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and the Ford Motor Company), NetJets Inc., and The Williamand Flora Hewlett Foundation. Also, this paper was derived inpart from work funded by the National Academy of Sciences,with support from the National Academy of Engineering, Na-tional Research Council, the U.S. Department of Energy, Gen-eralMotors, Intel Corporation, Kavli Foundation, and the KeckFoundation. The findings and conclusions herein are solely thoseof the authors and are not necessarily accepted or adopted by anyof the foregoing entities. Any errors of omission or commissionare entirely ours.

Supporting Information Available: (A) Process design param-eter assumptions for Aspen Plus simulations, (B) Method andparameters used for estimating overnight capital costs(including installation, BOP, general facilities, engineering,overhead and contingencies) in year 2007 US dollars,(C) Simulation of FTL upgrading process, (D) Performancesand LCOEs for stand-alone power systems, (D) Cellulosicethanol parameters, and (F) Estimate of short-run marginalcost of nuclear electricity. This material is available free ofcharge via the Internet at http://pubs.acs.org.

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Making Fischer-Tropsch Fuels and Electricity From Coal and Biomass