Making FischerâTropsch Fuels and Electricity from Coal and

Energy Fuels 2011, 25, 415–437 Published on Web 12/06/2010

: DOI:10.1021/ef101184e

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 of Petroleum 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 oil prices, 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 simultaneously involves producing ultraclean synthetic fuels from coal and lignocellulosic biomass with CO2 capture and storage. Detailed process simulations, lifecycle greenhouse gas emissions analyses, and cost analyses carried out in a comprehensive analytical framework are presented for 16 alternative system configurations that involve gasification-based coproduction of Fischer-Tropsch liquid (FTL) fuels and electricity from coal and/or biomass, with and without capture and storage of byproduct CO2. Systematic comparisons are made to cellulosic ethanol as an alternative low GHG-emitting liquid fuel and to alternative options for decarbonizing stand-alone fossil-fuel power plants. The analysis indicates that FTL fuels are typically less costly to produce when electricity is generated as a major coproduct than when producing mainly liquid fuel. Coproduction systems that utilize a cofeed of biomass and coal and incorporate CO2 capture and storage in the design offer attractive opportunities for decarbonizing liquid fuels and power generation simultaneously. Such coproduction systems considered as power generators can provide decarbonized electricity at lower costs than is feasible with stand-alone fossil-fuel power plant options under a wide range of conditions. At a plausible GHG emissions price under a future U.S. carbon mitigation policy ($50/t CO2eq), such a coproduction system built at a scale suitable for competing as a power generator would be able to provide low-GHG-emitting synthetic fuels at the same estimated unit cost as for coal synfuels characterized by ten times the GHG gas emission rate that are produced in a plant with CO2 capture and storage that does not provide electricity as a major coproduct having three times the synfuel output capacity and requiring twice the total capital investment. Moreover, the low GHG-emitting synfuels produced by such systems would be less costly to produce than cellulosic ethanol and require only half as much lignocellulosic biomass.

can do much to improve energy security if it is used to make FTL fuels. Moreover, the synfuels provided are likely to be cleaner than the crude oil products they displace, having essentially zero sulfur and other contaminants and low aromatic content. Also, for FTL fuels produced from synthesis gas generated in modern entrained flow gasifiers, air pollutant emissions from the plant are extremely low. But synthetic fuels made from coal without capture and storage of byproduct CO2 result in net GHG emissions about double those from petroleum fuels.5 And even with CO2 capture and storage (CCS), the net GHG emissions are reduced only to levels comparable to those from petroleum fuels. One approach to reducing GHG emissions below petroleumfuel levels is to make FTL fuels from sustainably produced biomass;termed biomass-to-liquid (BTL) fuels whose net climate impact (i.e. after transportation, distribution, and combustion) is roughly carbon neutral. Adding CCS to BTL fuel systems reduces GHG emissions even further; an intrinsic feature of converting biomass (or coal) to FTL fuels

1. Introduction Concerns about current and prospective high oil prices and about oil supply insecurity are catalyzing wide interest in making synthetic fuels from coal;so-called coal-to-liquid (CTL) fuels;in light of coal’s relatively low prices and the abundance of coal both in the U.S. and in other world regions that are not politically volatile. Much of this attention has been focused on Fischer-Tropsch liquid (FTL) fuels.1-4 Coal *To whom correspondence should be addressed. E-mail: liugj@ ncepu.edu.cn. (1) Van Bibber, L.; Shuster, E.; Haslbeck, J.; Rutkowski, M.; Olsen, S.; Kramer, S. Baseline Technical and Economic Assessment of a Commercial 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-Scale Fischer-Tropsch Liquids Facilties; DOE/NETL-2007/1253; National Energy Technology Laboratory: Pittsburgh, February 2007. (3) Van Bibber, L.; Thomas, C.; Chaney, R. Alaskan Coal Gasification 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-AC2699FT40342, September 2003. r 2010 American Chemical Society

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

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is the production of a stream of pure by-product CO2 that contains more than half of the carbon in the feedstock. If this CO2 is captured and securely stored in geological media, FTL fuels made entirely from sustainably produced biomass would be characterized by strong negative net GHG emissions because of the storage of photosynthetic CO2. Unfortunately, sustainably-produced biomass is expensive, and the size of BTL facilities is limited by the quantities of biomass that can be gathered in a single location;implying relatively high unit costs. Furthermore, sustainably-produced biomass is a scarce resource, and BTL plants are able to convert only a third of the biomass carbon into FTL fuels. These challenges for BTL technology could be mitigated to a significant degree by coprocessing biomass with coal in the same facility, and employing CCS. The economies of scale inherent in coal conversion could thereby be exploited, the average feedstock cost would be lower than that for a pure BTL plant, and CO2 emissions can be reduced by CCS, leading to FTL fuels with low, zero, or even negative net emissions depending on the coal/biomass ratio.5-9 Furthermore, adding coal and CCS to BTL dramatically boosts the biomass utilization effectiveness, more than doubling the amount of low-C transportation fuel energy that can be produced from a unit of biomass energy. In recent years, government and industry in the United States have begun to show great interest in the coal/biomass-to-liquids with CCS (CBTL-CCS) concept,10-13 but a systematic assessment of the field is clearly needed. This paper presents a comprehensive assessment of the coproduction of FTL fuels and electricity from coal and/or lignocellulosic biomass, without and with capture and storage of byproduct CO2. We investigate (1) BTL vs CBTL vs CTL options (generically referred to as “XTL” plants), (2) the amount of biomass that might be accommodated in CBTL systems, (3) the appropriate scales for XTL plants, (4) the extent to which CCS might plausibly be pursued for XTL systems, (5) how plants that seek to maximize liquid fuel output compare to those that produce electricity as a major coproduct, and (6) comparative prospective economics of

alternative XTL designs. We employ a unified analytical framework to systematically analyze 16 separate process designs, simulating for each detailed mass/energy balances using Aspen Plus software, and calculating their full lifecycle greenhouse gas (GHG) emissions. A self-consistent set of componentlevel capital cost estimates is developed, and overall economics are evaluated under alternative oil price and GHG emissions price assumptions from the perspective of both a liquid fuel producer and an electricity generator. Table 1 provides nomenclature used to refer to each process design, along with some key acronyms. 2. Process Designs The equipment for gasification-based production of liquid fuels from coal and biomass are commercial or nearly commercial in all cases. Industrial-scale coal gasifiers are commercially available today, with more than 420 gasifiers already in commercial use in some 140 facilities worldwide.8 The technology for cogasifying biomass and coal is close to being ready for commercial deployment; the commercial Buggenum integrated-gasification combined cycle (IGCC) facility in The Netherlands has been cogasifying coal together with modest quantities of biomass in a coal gasifier since 2006.14 Standalone biomass gasification technologies, while not yet deployed at large commercial scale, have been the subject of extensive research, development, and demonstration,15 as well as commercial design studies16 that provide the data needed for scale-up to commercial size. Technologies for converting syngas into FTL fuels have been successfully employed at industrial scale for many decades by Sasol in South Africa. All CO2 capture technologies described here are commercially established, and underground storage of CO2 is under active development worldwide.17 2.1. Plant Designs with CO2 Vented to the Atmosphere. All 16 of the process designs considered here share some similar features (for details see Appendix A of the Supporting Information). We begin with a description of two basic coal-to-liquid designs, termed “recycle” (RC) and “oncethrough” (OT) configurations (Figure 1). A key difference between the two is in the amount of coproduct electricity available for export after on-site parasitic power needs are met. In both designs, Illinois No. 6 bituminous coal (Table 2) is mixed with water to form a slurry that is pumped into a pressurized entrained flow gasifier (with characteristics of GE Energy’s total water quench gasifier design) operating at 72 bar and 1371 C. Oxygen is supplied to the gasifier from a dedicated cryogenic air separation unit (ASU). In the lower section of the gasifier, the raw synthesis gas passes through a water quench and then through an external gas scrubber; both remove water-soluble contaminants and particulate matter. The syngas exits the scrubber at 251 C with a

(6) Larson, E. D.; Williams, R. H.; Jin, H. Fuels and electricity from biomass with CO2 capture and storage. In Proceedings of the 8th International 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 on Greenhouse Gas Control Technologies, Trondheim, Norway, June 2006. (8) National Research Council’s Panel on Alternative Transportation Fuels for America’s Energy Future study. Liquid Transportation Fuels from Coal and Biomass Technological Status, Costs, and Environmental Impacts; 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 electricity from coal þ biomass with CO2 capture and storage: An Illinois case study. 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 and Carbon Management. In Proceedings of the 24th Annual Pittsburgh Coal Conference, 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 Energy Technology Laboratory of the United States Department of Energy: Pittsburgh, 2009.

(14) Van Haperin, R.; de Kler, R., Nuon Magnum. Presented at Gasification Technologies Conference, San Francisco, CA, 2007. (15) Ciferno, J. P.; Marano, J. J. Benchmarking Biomass Gasification Technologies for Fuels, Chemicals and Hydrogen Production;National Energy Technology Laboratory, U.S. Department of Energy: Pittsburgh, June 2002. (16) DeLong, M. M. Economic Development Through Biomass System Integration: Summary Report; NREL/TP-430-20517; National Renewable Energy Laboratory: Golden, CO, December 1995; 63 pp. (17) Three commercial-scale demonstration projects are each annually injecting one million tonnes or more of CO2 underground. The longest running of these been injecting CO2 under the bed of the North Sea since 1996. A large number of smaller tests are also ongoing. See http://sequestration.mit.edu/ for an up-to-date database of CCS activities.

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sup PCCIGCCNGCC-

Acronyms coal to FTL fuels (diesel/jet, gasoline) þ electricity biomass to FTL fuels (diesel/jet, gasoline) þ electricity coal þ biomass to FTL fuels (diesel/jet, gasoline) þ electricity (∼40% of input feedstock is biomass - HHV basis) coal þ biomass to FTL fuels (diesel/jet, gasoline) þ electricity (∼12% of input feedstock is biomass - HHV basis) coproduct CO2 is vented to the atmosphere. coproduct CO2 captured, compressed, and piped to underground storage site (deep saline formation) FTL synthesis with recycle (RC) of unconverted syngas to maximize FTL output 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 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 OT plant design that uses biomass grown on carbon-depleted soils, leading to substantial buildup/storage of carbon in soil and roots, complementing underground storage of CO2 captured at the conversion facility OTA plant design that uses biomass grown on carbon-depleted soils, leading to substantial buildup/storage of carbon in soil and roots, complementing underground storage of CO2 captured at the conversion facility supercritical pulverized coal power plant coal integrated gasification combined cycle power plant natural gas combine cycle power plant

CTL-RC-V CTL-RC-CCS CTL-OT-V CTL-OT-CCS CTL-OTA-CCS BTL-RC-V BTL-RC-CCS CBTL-RC-V CBTL-RC-CCS CBTL-OT-V CBTL-OT-CCS CBTL1-OT-CCS CBTL-OTS-CCS CBTL-OTA-V CBTL-OTA-CCS CBTL-OTAS-CCS

System acronyms and plant sizing parameters for XTL plants evaluated as synfuel providers 50,000 barrels/day of finished FTL fuels (diesel/jet and gasoline) same coal input as CTL-RC-V same coal input as CTL-RC-V same coal input as CTL-RC-V same coal input as CTL-RC-V CBIR (common biomass input rate =1 million metric ton(dry)/year) CBIR CBIR, same coal input as CBTL-RC-CCS CBIR, C/B ratio for near-zero lifecycle GHG emissions CBIR, same coal input as CBTL-OT-CCS CBIR, C/B ratio for near-zero lifecycle GHG emissions same FTL fuels output capacity as for CBTL-OT options, C/B ratio approximately 5x CBTL-OT-CCS value CBIR, C/B ratio for near-zero lifecycle GHG emissions, soil/root C storage CBIR, same coal input as CBTL-OTA-CCS CBIR, C/B ratio for near-zero GHG emission, aggressive CCS CBIR, C/B for near-zero GHG emissions, soil/root C storage, aggressive CCS

CTLBTLCBTLCBTL1-V -CCS -RC-OT-OTA-OTS-OTAS-

GHGI GHGA MEGE XTL LCOE MDC SRMC ASU AGR

Acronyms used in text greenhouse gas emissions index: lifecycle GHG emissions associated with the facility divided by lifecycle emissions for production and use of an LHV-equivalent amount of fossil fuel-derived products displaced greenhouse gas emissions avoided: GHGA = (1 - GHGI)*(lifecycle GHG emissions for the displaced fossil fuels) marginal electric generation efficiency (defined in the main text) X refers to coal, biomass, or coalþbiomass; TL refers to FTL fuels (diesel/jet, gasoline) þ electricity levelized cost of electricity: calculated for the assumptions in Table 8 minimum dispatch cost for electricity generation: feedstock þ operating costs - liquid fuel revenuesa short run marginal cost for electricity generation air separation unit acid gas removal (for CO2 and H2S)

a For power generating plants, separate estimates of fixed and variable operating costs were available,36 and in these cases the MDC is the sum of feedstock and variable operating costs. For the CBTL systems, we have only estimated total operating costs (without separating fixed from variable). For these systems the MDC is the sum of feedstock and total operating costs, less liquid fuel revenues.

H2/CO ratio of 0.67. After scrubbing, some of the syngas enters a single-stage (adiabatic) sour water gas shift (WGS) reactor and some bypasses the WGS. The syngas bypass is adjusted to ensure that a molar H2/CO ratio of 1 is realized for the fresh syngas entering the FT synthesis island. The two streams of syngas are combined and cooled following the WGS and then expanded to a pressure suitable for downstream FT synthesis. The syngas is cooled to 40 C, and CO2 and H2S are then removed in a methanol-based acid gas removal (AGR) system (with characteristics of the commercial Rectisol process). H2S is removed to protect downstream catalysts and is converted to elemental sulfur in Claus/SCOT processes. The CO2 is removed to improve FTL yield and economics and is vented to the atmosphere. For the designs in Figure 1, this recovered CO2 is essentially pure, so that it is a relatively simple matter to compress it for underground storage, as discussed in Section 2.2. Following the AGR, the syngas is heated and delivered to the FT synthesis island at 24 bar and 245 C.

The FT island is designed around a synthesis unit using an iron catalyst. Iron-based catalysts are well suited for syngas from coal and/or biomass feedstocks, because these feedstocks produce syngas with H2/CO ratio below the stoichiometric optimum of 2 for FT synthesis. The water-gas-shift activity inherent in iron catalysts is able to compensate for this suboptimal syngas composition. The main commercial alternatives to iron-based catalysts are cobalt-based catalysts, which have no water-gas-shift activity. Cobalt catalysts are commercially deployed today with syngas produced by the reforming of natural gas, which can achieve the optimum H2/CO ratio for FT synthesis without the need for water gas shift. On the FT synthesis island, the syngas is fed to the bottom of a slurry-phase FT reactor. The syngas bubbles up through an inert heavy hydrocarbon liquid medium in which are suspended fine catalyst particles. Reaction heat is removed via heat exchangers suspended in the reactors. The liquid medium, together with boiling heat transfer inside the tubes, 417

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Figure 1. Two basic process configurations for CTL systems producing FTL 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.

which is consistent with modeling carried out in the 1990s by the Bechtel Group for the U.S. Department of Energy for a slurry-phase FT synthesis reactor.18 The raw product from the FT reactor is separated by distillation in the hydrocarbon recovery area into naptha, middle distillate, and heavy wax streams, along with a gas stream containing unreacted H2 and CO, and CO2 and light hydrocarbons (C1 to C4) formed during synthesis. The liquid fractions in our designs are upgraded to diesel and gasoline blendstocks.19 The FTL upgrading area uses a relatively conventional refining design that is a modification of a Bechtel design developed in the mid-1990s.20,21 Crudeoil-derived gasoline specifications have evolved since the Bechtel design was published, so we have made modifications to ensure that the gasoline blendstock produced in the upgrading area will meet existing U.S. standards for gasoline, specifically California reformulated gasoline standards. Figure 2 shows schematically our upgrading design, details of which are provided in the Supporting Information. The

Table 2. Feedstocks a

coal

b

biomass

fixed carbon volatile matter ash moisture LHV (MJ/kg) HHV (MJ/kg)

proximate analysis (wt%, as-received) 44.19 34.99 9.7 11.12 25.86 27.11

18.1 61.6 5.26 15.0 14.51 15.94

carbon hydrogen oxygen nitrogen chlorine sulfur ash LHV (MJ/kg) HHV (MJ/kg)

ultimate analysis (wt%, dry basis) 71.72 5.06 7.75 1.41 0.33 2.82 10.91 29.40 30.51

46.96 5.72 40.18 0.86 0.00 0.09 6.19 17.50 18.75

a Properties of coal can be quite variable. Here the design coal is Illinois No. 6 (high-volatile bituminous), with properties taken from NETL.36 b Biomass properties are for switchgrass, as reported in Appendix C of Tarka, et al.12

(19) The naphtha could be sold directly as a chemical feedstock rather than being upgraded to gasoline, but chemical markets for naphtha are relatively small relative to fuels markets, so this would be a limited option if FTL fuels production were to become widespread. Here we assume that the naphtha is upgraded to a gasoline blendstock because we are interested in understanding the economics under a scenario in which FTL technology is extensively deployed. (20) Bechtel. Baseline Design/Economics for Advanced Fischer-Tropsch Technology; Report under contract DE-AC22-91PC90027 to U.S. Department of Energy, Federal Energy Technology Center: Pittsburgh, April 1998. (21) Bechtel. Aspen Process Flowsheet Simulation Model of a Battelle Biomass-Based Gasification, Fischer-Tropsch Liquefaction and CombinedCycle Power Plant; Report under contract DE-AC22-93PC91029-16 to U.S. Department of Energy, Pittsburgh, PA, May 1998.

enables the rapid heat removal needed to maintain the isothermal conditions that promote high synthesis gas conversions. In our modeling 51% of the C in CO in incoming syngas is converted into raw FTL products in a single pass, (18) Bechtel Group, Inc. Slurry Reactor Design Studies: Slurry vs. Fixed-Bed Reactors for Fischer-Tropsch and Methanol; Final Report under contract DE-AC22-89PC89867 to U.S. Department of Energy, Pittsburgh Energy Technology Center, 1990.

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

excessive buildup of inert gases25 and, together with the light gases collected from the refining area, constitutes the fuel for the power island. This gas mixture fuels a steam Rankine cycle that generates all the electricity needed to run the entire facility plus a small amount of export electricity (∼ 11% of the 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 FTL refining are compressed and supplied to the power island where a gas turbine/steam turbine combined cycle (GTCC) provides the power needed to operate the plant, as well as a substantial amount of export power (up to 37% of the total plant 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 is assumed that the CO2 is separated, dehydrated, and compressed to 150 bar for subsequent pipeline transport to a suitable geological storage site. In the CTL configurations in Figure 1, CO2 is vented from both the AGR unit and the power island. Greenhouse gas emissions can be reduced if one or both of these CO2 streams is 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 concentrated CO2 stream exiting the AGR unit. Capturing this stream for geologic storage eliminates most of the plant’s GHG emissions and involves only compressing the CO2 for pipeline transport. This is the strategy adopted for the CTLRC-CCS design. In the CTL-OT-V plant (Figure 1b), the amount of CO2 vented from the power island is more substantial than in the RC case (equivalent to 47% vs 10% of C in coal). We develop two alternative designs for capturing this CO2 in addition to that more readily captured from the AGR unit upstream of FT synthesis. In the first CCS design, designated CTL-OT-CCS (Figure 3a), CO2 is captured not only upstream of the FT reactor in the AGR unit, but also downstream from the power island fuel gas. In the latter step, CO2 generated in the FT synthesis reactor is removed from the exiting syngas by passing it

naphtha and distillate streams are first hydrotreated, while the heavy waxes are hydrocracked into distillate-range and naphtha-range compounds. No further processing of the distillate streams is required. The C5 and C6 components in the naphtha streams are isomerized (from normal paraffins to isoparaffins) to boost their octane levels. The remaining components of the straight-run naphtha (from the hydrotreater) and the naphtha from the hydrocracker are processed in either a Pt/L-zeolite reformer or a non-hydrogen upgrading unit. Pt/L-zeolite reforming (in contrast to the Pt/Al2O3 reforming assumed in the earlier-cited Bechtel studies from the 1990s) provides a superior conversion of n-paraffins to aromatics and hydrogen. 22 The n-paraffin content in straight-run naphtha will be above 90% after hydrotreating, so Pt/L-zeolite reforming will produce a high-octane gasoline blending component. About half of the C7þ naphtha components from the hydrotreater are sent to this reformer to generate the aromatics content in the final gasoline blendstock. The remainder, together with naphtha emerging from the wax hydrocracker, is upgraded to boost octane without adding aromaticity. Typically, octane number can be increased by 20-30 units via isomerization.23,24 The finished liquid products consist of about 63% diesel and 37% gasoline (lower heating value basis). Each step in the refining area generates some light gases (C1 to C4) that are collected and mixed with the unconverted syngas from the hydrocarbon recovery step for use as fuel on the power island. The distinction between the two process designs in Figure 1 is primarily in the FT synthesis and power island designs. The “recycle” (RC) case (Figure 1a) is designed to maximize liquid fuel production. Most of the syngas unconverted in a single pass through the synthesis reactor is compressed, combined with steam and oxygen, and passed through an autothermal reformer (ATR) from which emerges a gaseous mixture primarily made up of CO, H2, and CO2 at 1000 C. The ATR output is combined with fresh syngas upstream of the AGR unit and then recycled back through the synthesis reactor. A purge stream from the recycle loop prevents (22) Tamm, P. W.; Mohr, D. H.; Wilson, C. R. Octane enhancement by 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 (in Chinese, with English abstract).

(25) In all of the RC designs in this work, the ASU is designed to produce extra-high purity oxygen (99.5% molar) to minimize inert gas buildup. This compares with 94.3% molar purity for designs that do not utilize recycle.

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

inputs coal a

biomass a

output/inputd

FTL b

plant name

t/d

MWHHV

t/d

MWHHV

bio %

bbl/d

MWLHV

MWe

FTL

electric


24,087 24,087 24,087 24,087 24,087 2,562 2,562 3,220 3,220 4,725 6,726 5,150 5,150 9,760

7559 7559 7559 7559 7559 804 804 1,011 1,011 1,483 2,111 1,616 1,616 3,063

3,581 3,581 3,581 3,581 3,581 3,581 1,129 3,581 3,581 3,581 3,581

661 661 661 661 661 661 208 661 661 661 661

100 100 45 45 40 40 12 24 29 29 18

50,000 50,000 35,706 35,705 35,705 4,521 4,521 9,845 9,845 8,036 8,036 8,036 13,213 10,881 10,882 17,669

3,159 3,159 2,256 2,256 2,256 286 286 622 622 508 508 508 835 687 687 1,116

404 295 1,260 1,058 843 42 31 76 53 301 257 224 410 408 287 464

0.45 0.45 0.32 0.32 0.32 0.47 0.47 0.46 0.46 0.33 0.33 0.32 0.32 0.32 0.32 0.32

0.05 0.04 0.17 0.14 0.11 0.06 0.05 0.05 0.04 0.18 0.15 0.14 0.15 0.18 0.13 0.12

a As-received metric tonnes/day input when plant is operating at 100% capacity. b Percent of total higher heating value of input feedstocks that is biomass. c Exports of finished liquid fuels (63% diesel and 37% gasoline, LHV basis) and electricity. d Higher heating value of indicated output divided by higher heating value of input feedstock(s). HHV/LHV = 1.076 for FTL products.

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

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

savings are achieved by having a single regeneration unit serve the two absorption columns.) Removing CO2 from the 420

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

fuel gas increases its heating value, necessitating measures (not needed in CTL-OT-V) to ensure that thermal NOx emissions from combustion in the power island remain below regulated limits.26 NOx emissions control is achieved by first passing the gas turbine fuel gas through a water saturator and then adding nitrogen for further dilution. Nitrogen for this purpose is taken 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 as CO2 after combustion in the power island, yielding an overall CO2 capture rate for nonfuel carbon of ∼73%, ∼1/2 upstream and ∼1/2 downstream of synthesis. Our second CCS design reduces emissions further by first reforming the power island fuel gas with steam and O2 in an ATR so as to convert most of the C1 to C4 hydrocarbons to CO and H2. The reformed syngas passes through a two-stage WGS unit in which CO and steam react to produce mostly H2 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 captured as CO2. 2.3. Designs with Biomass. The various CTL-CCS designs described in the previous section have lower GHG emissions than CTL-V designs, but nevertheless still have substantial fuel-cycle-wide GHG emissions due to the CO2 released during combustion of the liquid fuels. One approach for further reducing GHG emissions involves introducing biomass as a feedstock. Neglecting for the moment fuel-cyclewide GHG emissions arising from energy and chemical inputs to the growing and transporting of biomass and from transporting biofuels to refueling stations (emissions that are included in the analysis in Section 3), release to the atmosphere of CO2 originating in biomass results in no net accumulation of CO2 in the atmosphere when an equivalent amount of CO2 is absorbed by new biomass growth. Thus an FTL plant operating on biomass only, termed BTL, yields fuels whose net CO2 emissions (including conversion at the plant and subsequent combustion in vehicles) are zero. For BTL plants that also incorporate CCS, the net lifecycle CO2 emissions are strongly negative because more than half of the biomass carbon is captured and stored underground. Our analysis includes two RC plant designs that utilize only 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 (BTLRC-CCS). The downstream portions of these plants, starting with the acid gas removal area, are essentially identical to those for the corresponding CTL-RC designs in Figure 1. The upstream portions of the BTL designs include a biomass handling system feeding a pressurized (30 bar) fluidized-bed gasifier operating at temperatures low enough that ash is removed as a dry material, 816 C.27 The gasifier is followed by a tar cracking unit, modeled as an ATR with a syngas exit temperature of 882 C that converts into syngas the heavy hydrocarbons that form at typical biomass gasification temperatures and that would otherwise condense and cause operating difficulties downstream. The ATR also converts into syngas 90% of the methane, which is much more abundant in syngas produced in relatively low-temperature biomass gasifiers than in syngas from higher-temperature coal gasifiers. Biomass can also be used as a cofeed with coal at the same facility. The lifecycle GHG emissions for such facilities will vary with the coal-to-biomass ratio, as well as with other design details (especially CO2 capture). We have designed several coal/biomass-to-liquids (CBTL) plants, all of which use separate coal and biomass gasification trains identical to those described earlier. The separate syngas streams are combined for subsequent downstream processing. The CBTL plants include RC and OT configurations; Figure 4 shows CBTL-RC-CCS. The CBTL-OT designs include (1) two plants with different coal-to-biomass ratios (CBTL-OTCCS 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 more aggressive CO2 capture strategy used by CTL-OTA-CCS (Figure 3b). Finally, under certain biomass growing conditions (e.g., the sustained growing of mixed prairie grasses on abandoned cropland28), some photosynthetically absorbed carbon will be stored permanently in the soil/root system, adding a negative emissions credit to the biomass conversion facility. Our plant designs that utilize biomass grown with soil/root carbon accumulation are designated CBTL-OTS-CCS and CBTL-OTAS-CCS. Aside from the distinction in the source of the biomass feedstock and relative biomass/coal input (27) Dry ash from a biomass gasifier might be returned to the soil for its inorganic nutrient value. (28) Tilman, D.; Hill, J.; Lehman, C. Carbon-Negative Biofuels from Low-Input High-Diversity Grassland Biomass. Science 2006, 315 (Dec. 8), 1598–1600.

(26) For simulation purposes, we assume that the adiabatic flame temperature in the gas turbine combustor must not exceed 2300 K if NOx emissions are to remain below 25 ppmv.

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Table 4. Carbon Balance Simulation Results and Alternative Metrics for GHG Emissions for Alternative FTL System Configurations GHGA (kg CO2eq/GJ FTL)c

% of input C that ends up plant name CTL-RC-V CTL-RC-CCS CTL-OT-V CTL-OT-CCS CTL-OTA-CCS BTL-RC-V BTL-RC-CCS CBTL-RC-V CBTL-RC-CCS CBTL-OT-V CBTL-OT-CCS CBTL1-OT-CCS CBTL-OTS-CCS CBTL-OTA-V CBTL-OTA-CCS CBTL-OTAS-CCS

input to plant (kgC/s) in char vented in FTL stored as CO2 CCS ratea (tCO2/d) GHGIb 178 178 178 178 178 17 17 35 35 40 40 40 66 55 55 89

4.0 4.0 4.0 4.0 4.0 3.0 3.0 3.5 3.5 3.6 3.6 3.9 3.7 3.7 3.7 3.8

61.9 10.3 71.6 19.5 7.9 63.9 8.2 62.8 9.0 72.2 18.2 19.0 18.7 72.1 6.6 7.1

34.1 34.1 24.4 24.4 24.4 33.1 33.1 33.7 33.7 24.2 24.2 24.3 24.2 24.2 24.2 24.2

0.0 51.6 0.0 52.2 63.7 0.0 55.7 0.0 53.7 0.0 54.0 52.9 53.3 0.0 65.5 64.9

0 29,039 0 29,343 35,864 0 2919 0 6,032 0 6,889 6,708 11,169 0 11,306 18,188

1.71 0.89 1.31 0.70 0.59 0.06 -0.95 0.96 0.03 0.77 0.09 0.50 0.09 0.90 0.09 0.08

FTL

electricity

total

-64.9 10.2 -28.7 27.9 37.2 85.9 178.2 3.4 89.0 20.9 83.1 46.0 83.2 8.8 83.8 84.3

-20.9 2.4 -40.4 32.9 35.0 31.9 48.9 1.0 19.1 31.1 105.9 55.8 103.0 13.2 88.2 88.1

-85.8 12.6 -69.1 60.8 72.2 117.8 227.1 4.4 108.1 52.0 189.1 101.8 186.3 22.1 172.0 172.4

a Daily rate at which CO2 is captured and stored underground when the plant is operating at 100% capacity. In addition to the amount shown here, a small amount of carbon leaves the gasifier with the ash and is assumed to be sequestered from the atmosphere when landfilled. (See Column 3 for magnitude of this carbon stream.) b The Greenhouse Gas Emissions Index is defined as the lifecycle GHG emissions associated with the energy products divided by the lifecycle GHG emissions associated with the fossil-fuel-derived products displaced. We assume the latter are petroleum-derived fuels (with emissions of 91.6 kgCO2eq/GJLHV for a 63/37 diesel/gasoline mix, based on the Argonne National Lab methodology,30 which allocates a fraction of the total 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 a supercrital pulverized coal plant (830.5 kg CO2eq/MWh).41 c The Greenhouse Gas Emissions Avoided, as discussed in the text, is (1 - GHGI)*(lifecycle GHG emissions of the fossil fuels displaced). GHGA is here expressed per GJLHV of liquid fuels produced.

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

biomass the CO2 absorbed during photosynthesis (equal to the carbon in the biomass) is counted as a negative emission. For biomass feedstocks, we assume the GREET results for herbaceous biomass. The GREET model takes into account changes in GHG emissions associated with direct land-use change impacts of biomass production but does not include indirect land-use change impacts.31 The latter is zero if the biomass is not grown as a dedicated energy crop on good cropland requiring putting new land into cropland elsewhere in the world;which we assume to be the case here. For biomass grown with attendant soil/root carbon storage, we assume 0.3 tonnes of carbon are stored in the soil/ roots per dry tonne of harvested biomass as an average over a 30-year period28 and substitute this land use impact for the land use impact estimated for herbaceous biomass in the GREET model. We further assume 7% of the harvested biomass is lost during delivery to the conversion facility,9 so that this carbon storage rate is 0.323 t carbon per t dry biomass delivered to the conversion facility. To facilitate comparisons of greenhouse gas emissions mitigation among systems that produce different energy products we introduce two metrics for measuring LGHG emissions mitigation: a greenhouse gas emissions index (GHGI) and the greenhouse gas emissions avoided (GHGA). We define GHGI to be the LGHG emissions associated with the facility divided by the LGHG emissions associated with the fossil energy displaced by the products of the facility. We assume the latter are petroleum-derived diesel and gasoline and electricity generated by a new supercritical pulverized coal plant that vents CO2 (Sup PC-V). (See Table 4, footnote b, for details.) The GHGI metric is useful in that it does not require any allocation of emissions to different products while giving a clear quantification of potential emissions reductions relative to state-of-the-art fossil-fuel systems. GHGI is a helpful

3. Process Simulation Methodology and Results For each of the 16 plant designs, we have developed detailed mass, energy, and carbon balance simulations using Aspen Plus software.29 All designs are for a bituminous Illinois No. 6 coal and switchgrass as the biomass feedstock (Table 2). The latter arrives at the plant gate with 15% moisture content, which is low enough that further drying of the feedstock prior to gasification is not needed. We assume that plants processing biomass will utilize no more than one million dry tonnes per year, which appears to be a plausible maximum delivery rate in the Midwestern United States.9 The amount of coal processed at each facility is set according to a different set of criteria. For example, our CTL-RC-V system is designed with coal input that results in 50,000 barrels per day of FTL production. Table 1 summarizes the scale-determining parameters for each of the 16 designs. For any given plant design, we make the simplifying assumption that unit energy performance of equipment does not vary with plant scale, and on this basis we have also included some subsequent analysis for plants with sizes other than those indicated in Table 1. We have estimated for each plant design lifecycle GHG (LGHG emissions) that include all emissions other than those involved in manufacturing and constructing the plant equipment. Emissions at the facility are based on our simulation results. To these emissions we added emissions associated with feedstock production and delivery operations upstream of the plant and with fuel delivery and combustion downstream of the plant. Combustion emissions are based on the carbon content of the fuel, and emissions from other processes outside of the plant gate are based on the GREET model.30 For (29) The Supporting Information provides detailed component-bycomponent input assumptions for the Aspen Plus simulations. (30) Argonne National Laboratory. The Greenhouse Gases, Regulated 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 emissions from land-use change. Science 2008, 319 (5867), 1238–1240.

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

metric in measuring GHG emissions mitigation in relation to overall societal goals for emissions reduction. For example, if a nation’s goal is an 80% reduction in total emissions over a certain time period, it would aim to promote technologies for which GHGI e 0.2. GHGA is LGHG emissions for the displaced fossil fuels minus LGHG emissions for the energy products, or GHGA = (1 - GHGI)*(LGHG emissions for the displaced fossil fuels). GHGA can be helpful in better understanding, for a given emissions reduction goal (i.e., a given GHGI level), how alternative technologies compare with regard to overall carbon mitigation. The GHGI and GHGA metrics can be characterized as measuring, respectively, the depth and breadth of mitigation. In this paper GHGA is expressed in kg CO2eq per GJ of liquid fuel produced for systems evaluated from a liquid fuel production perspective and in kg CO2eq per MWh of electricity generated for systems evaluated from an electric power generation perspective. It should be noted that the economics of producing fuels and electricity (discussed below) are not a function of the metrics selected for LGHG emissions. Table 3 summarizes results from the mass/energy balance simulations for all 16 designs. All the options using biomass except CBTL1-OT-CCS use biomass at a rate of 1 million dry tonnes per year (dt/y). The CBTL1-OT-CCS option (consuming 12% biomass on an energy basis) is intended to be representative of a plant that could be built in the relatively near term consuming instead 0.315 million dt/y. Table 4 provides carbon balances and the two metrics for LGHG emissions mitigation. Illustrating our process simulation results, Figure 5 shows detailed stream flows for the CBTL-OT-CCS design, in which one million dt/y of biomass accounts for 40% of the input feedstock energy (HHV basis). This plant’s output capacities for finished FTL fuels and net electricity exports are 8036

barrels per day and 257 MWe, respectively. The liquids represent slightly more than two-thirds of the total plant energy outputs (electricity plus liquid fuels), a value which is similar for all OT plants. Figure 6 shows carbon flows for this system, including carbon-equivalent GHG emission flows associated with activities upstream and downstream of the conversion facility. For this system the gross flow rate of equivalent carbon to the atmosphere is 1661 tonnes per day, which is offset by 1430 tonnes per day of carbon extracted from the atmosphere for biomass grown on a sustainable basis, yielding a net equivalent carbon flow to the atmosphere of 231 tonnes per day, equivalent to 11% of the carbon in the coal used by the system. 4. Discussion The 16 detailed process simulations provide a rich set of quantitative results for understanding performance implications of different design choices. 4.1. Recycle vs Once-Through Synthesis. Comparing process designs for RC and OT synthesis configurations highlights trade-offs between liquid fuels and electricity outputs for these systems. For example, liquid fuel output falls nearly 30% while electricity exports more than quadruple in shifting from CTL-RC-V to CTL-OT-V, assuming the same coal input rate for both. Similar changes are evident in comparing the output ratios in Table 3 for other analogous pairs of configurations, e.g., CBTL-OT-CCS vs CBTL-RC-CCS. An important observation is that, in each of these paired designs, the additional electricity in the OT case is produced with a very high marginal electric generation efficiency (MEGE). The MEGE, the definition of which we have adapted from the work of Cicconardi, et al.,32 is the ratio of the additional electric power generated in the OT design (32) Cicconardi, S. P.; Perna, A.; Spazzafumo, G. Combined power and hydrogen production from coal. Part B. Comparison between the IGHP and CPH systems. Int. J. Hydrogen Energy 2008, 33, 4397–4404.

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

OT case. Heat generated by the FT synthesis reactions must be removed to maximize conversion in the reactor. Heat removal is accomplished by evaporating water in boiler tubes immersed in the FT slurry bed. Saturated steam at 33 bar and 240 C is produced as a result. If subsequently superheated, the steam can be expanded through a turbine to generate power. In the OT designs there is more than enough hightemperature heat available in the gas turbine exhaust gas to superheat all of this saturated steam. The RC options are designed to recycle 97% of the unconverted syngas exiting the synthesis reactor (so as to maximize liquid fuel production), and the remaining 3% purge gas is burned to superheat saturated steam produced by the synthesis reactor and other exotherms. However, the purge gas is adequate to superheat only about 60% of this saturated steam, resulting in less electricity production from expansion of the steam than if all of it were superheated. This difference between the RC and OT systems can be seen by comparing the energy balance around the steam turbine cycle shown in Figure 7 for the CTL-OT-CCS and CTL-RC-CCS designs. Fundamentally, the FT exotherm is better utilized for power generation with the OT designs than with the RC designs.33 An important indicator of the better utilization of the FT exotherm is the ratio of energy generated as steam turbine electricity to energy in FTL fuels. In the CTL-OTCCS system, this ratio is 1.7 times the value for the RC design (Figure 7). A striking difference between OT and RC designs is the much higher rate of greenhouse gas emissions avoided per GJ of FTL fuels produced (GHGA) for a carbon-mitigating OT option than for the corresponding RC option when both have comparable GHGI values. For example, the GHGA for CBTLOT-CCS is 1.7 as large for CBTL-RC-CCS even though both provide liquid fuels and electricity with GHGI < 0.1. The main

Table 5. Comparison of Electricity Generating Efficiencies efficiency (% HHV)a coproduction power plants CTL-OT-V CBTL-OT-V CTL-OT-CCS CBTL-OT-CCS

44.9 50.2 39.2 44.9 stand-alone coal power plants

sup PC-Vb CIGCC-Vc NGCC-Vb sup PC-CCSb CIGCC-CCSc NGCC-CCSb

39.2 37.5 50.8 27.2 31.0 43.7

a For the coproduction plants, these are marginal electricity generating efficiencies (MEGE), as defined in the main text. b Source: NETL.36 c Calculated by authors using framework consistent with XTL calculations.

relative to the RC design, when both plants are sized to produce the same amount of FTL, to the additional coal consumed. Table 5 shows that the MEGEs for the CTL-OT and CBTL-OT designs are well in excess of the efficiencies that can be achieved with new stand-alone coal-fired power plants. For example, comparing plant designs that incorporate CCS, the coproduction designs have marginal efficiencies that are a remarkable 6-18 percentage points higher than efficiencies for stand-alone power plants. These high MEGEs have important implications for both the GHG emissions mitigation potential and the economics of coproduction systems, as discussed later. The high MEGEs are a natural consequence of two system characteristics: (1) the intense exothermicity of FT synthesis, and (2) the much higher ratio of the FT synthesis exotherm energy to power island fuel energy in the RC case than in the 424

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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 normalized to 1000 MW of FTL fuels production.

reason for the wide range in GHGA values is that displacing 1 MW of sup PC-V electricity reduces 2.5 times more GHG emissions than displacing 1 MW of petroleum fuels. 4.2. CO2 Capture and Storage. All 10 of the CCS systems modeled are characterized by GHGI < 1.0; in cases where biomass 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 feedstock C captured as CO2 are comparable in all cases. In CTL-RCCCS, 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 section is equivalent to 27% of the feedstock carbon, and 36% of non-FTL carbon. Additionally capturing CO2 from syngas downstream of FT synthesis brings the total carbon capture rate to 52%, and 69% of non-FTL carbon. Even though the capture rate of non-FTL carbon is less for CTLOT-CCS than for CTL-RC-CCS, its climate benefit is higher; the GHGI for CTL-OT-CCS (0.70) is lower than that of CTL-RC-CCS (0.89). This is a consequence of both the high MEGE (39.3%) for the CTL-OT-CCS system (Table 5) and the higher electricity/fuels ratio, which implies more GHG emissions displaced per MW of total output (see Section 4.1). As discussed in Section 2.2, OTA cases are once-through systems with “aggressive” CO2 capture and substantially increased capture rates. For example, CTL-OTA-CCS captures 64% of the feedstock carbon, and 84% of non-FTL carbon. Its GHGI is 0.59, the lowest of all coal-only plants. In CCS plants, the energy penalty for capturing CO2 varies with the extent of capture. For example, in CTL-RC-CCS, where all CO2 capture occurs upstream of synthesis, the penalty (relative to CTL-RC-V) is 91 kWh per tCO2 captured, the energy required to compress the CO2 to 150 bar for pipeline transport (Table 6). For CTL-OT-CCS and

(33) The technology utilized on the power island will also influence the MEGE. For example, based on simulations we have carried out (but which are not reported in this paper), if a CTL-RC-CCS plant were designed with a gas turbine combined cycle (GTCC) on the power island instead of a steam rankine cycle, the marginal efficiency of power generation arising from a comparison of OT vs RC plant configurations would be even higher than what we report for the plant configurations analyzed in this paper. This counter-intuitive outcome is because when an external source of saturated steam is available to the power island (in this case generated from the FT synthesis exotherm), there is much more heat available for superheating that steam in the steam turbine case (when all of the heat arising from combustion of the fuel gas sent to the power island is available for superheating) than in the GTCC case (in which case only the exhaust heat from the gas turbine is available for superheating). Thus the opportunity to utilize more of the externally provided saturated steam for making electricity outweighs the intrinsically higher efficiency of a stand-alone GTCC relative to a stand-alone steam rankine cycle.

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Table 6. Electricity Balances for Alternative FTL System Configurations gross output (MWe) plant name

GT

ST

exp

SUM


0 0 701 732 562 0 0 0 0 163 171 167 279 219 177 286

783 783 900 860 866 77 77 151 151 211 205 197 329 289 276 448

66 66 61 61 61 0 0 7 7 8 8 12 17 13 13 25

849 849 1,661 1,653 1,489 77 77 157 157 382 384 376 624 521 466 759

onsite consumption (MWe) grind, feed ASU AGR RC comp FT synth FT refine CO2 comp N2 comp BOP SUM 21 21 21 21 21 0 0 2 2 3 3 4 6 4 4 8

324 324 304 304 342 24 24 57 57 60 60 66 104 84 84 142

40 40 24 39 44 4 4 8 8 6 9 9 15 8 14 22

CTL-OTA-CCS, which involve additional CO2 capture downstream of synthesis, several factors contribute to the energy penalty (see Table 6): (1) CO2 compression, (2) nitrogen compression to supply N2 to the gas turbine for NOx control, (3) methanol circulation in the downstream AGR unit, (4) reduced gross power output, and for CTLOTA-CCS only, (5) additional ASU power to produce O2 for the ATR. The total penalty for CO2 capture in CTL-OTCCS is 165 kWh/tCO2 captured, but in CTL-OTA-CCS, it is almost twice as large, 279 kWh/t CO2 captured (Figure 8). Aggressive CO2 capture engenders a dramatic loss (-165 MWe) in gross power output, caused by the loss of fuel gas mass 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 coal only systems;especially when biomass is deployed in systems with CCS. For biomass-only designs, the GHGI is almost zero when CO2 is vented and strongly negative when CO2 is captured and stored. Consider CBTL-OT systems for which biomass accounts for 40% of input energy (HHV basis) (Table 3). Notably, GHGI drops from 0.77 to 0.093 when CCS is added to the CBTL-OT-V option. Figure 9a and b illustrate how such a dramatic 88% reduction in GHGI is realized by simply adding CCS that involves capturing only 71% of the nonFTL carbon. The main reason is that, although the GHG emissions reduction credit for extracting carbon from the atmosphere is the same (33 kg C per GJ of FTL) for these options, this credit is relative to a much higher base for the system’s positive emissions components in the CBTL-OT-V case (81 kg C per GJ of FTL) compared to the CBTL-OTCCS case (38 kg C per GJ of FTL). In short, CCS provides about half of the climate benefit in CBTL-OT-CCS, and the biomass provides the other half. Figure 9c shows how it is feasible to realize a GHGI as low as 0.5 by adding only 12% biomass to the system. In this case the baseline positive GHG emission components for the system sum to 38 kg C per GJ of FTL (the same as for the CBTL-OT-CCS case). Although the GHG emissions reduction credit for extracting carbon from the atmosphere is

16 16 0 0 0 1 1 3 3 0 0 0 0 0 0 0

22 22 15 15 15 2 2 4 4 3 3 3 6 5 5 8

11 11 8 8 8 1 1 2 2 2 2 2 3 2 2 4

0 109 0 111 135 1 12 1 24 1 27 26 43 1 44 69

0 0 0 69 50 0 0 0 0 0 17 16 27 0 17 27

11 11 28 28 30 2 2 3 3 7 7 6 11 9 9 14

445 555 401 595 646 35 46 81 104 81 127 132 214 113 179 295

Figure 8. Electricity penalty for three CCS configurations.

much less in this case (10 kg C per GJ of FTL compared to 33 kg C per GJ for CBTL-OT-CCS), there is a larger credit for the electricity coproduct (15 kg C per GJ of FTL compared to 3 kg C per GJ in the CBTL-OT-CCS case).34 It is of interest to understand the relative merits of various combinations of CCS and biomass use in reducing GHG emissions for FTL fuels production relative to ethanol (EtOH) made from the same lignocellulosic biomass feedstock (switchgrass) via enzymatic hydrolysis. Cellulosic ethanol is the main focus of biofuels development efforts in the United States. We have not carried out detailed independent Aspen Plus and cost modeling of cellulosic ethanol technologies, but rather we have taken findings from the America’s Energy Future study of the National Research Council8 and have presented these findings here in the analytical framework we have developed for assessing alternative FTL technologies. This NRC study considered only cellulosic ethanol systems that vent CO2 (EtOH-V). In light of our findings relating to the importance of coupling biomass and CCS to enhance carbon mitigation for FTL systems, we have included in our comparative analysis a CCS option for cellulosic ethanol (EtOH-CCS), the analysis of which is straightforward because a stream of pure CO2 is naturally generated in the ethanol fermenter (1 molecule of CO2 for each molecule of ethanol (C2H5OH) produced) that is easily captured for geological storage. Details of our analysis of cellulosic

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

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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. Here char refers to carbon in the ash residue from coal and biomass gasification.

ethanol technologies are presented in the Supporting Information. Figure 10 presents GHGI and GHGA values for all 16 FTL systems analyzed along with those for EtOH-V and EtOH-CCS. The following observations can be made about the 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 negative GHGI emission values that can be exploited to offset GHG emissions from difficult to decarbonize energy sources such as transportation fuels derived from crude oil. (3) The

GHGA for BTL-RC-CCS is 56% higher than that of EtOHCCS;largely because 56% of the biomass carbon is stored underground for BTL-RC-CCS compared to only 15% for EtOH-CCS. Offsetting GHG emissions from crude-oil-derived products with negative emissions is an important carbon mitigation benefit offered by the BTL-RC-CCS and EtOH-CCS options. But this benefit should be considered in the context of the complementary public policy goal of enhancing energy security by reducing dependence on oil imports. Because sustainably produced biomass is a relatively scarce resource, 427

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

the effectiveness of its use in providing liquid fuel alternatives to imported oil is an important consideration. Figure 11 shows one measure of biomass effectiveness in providing liquid fuels with low GHGI values: the GJ of biomass feedstock required per GJ of transportation fuel produced. Shown for comparison are estimates for cellulosic ethanol made from the same biomass via enzymatic processing. The ethanol and BTL systems have comparable biomass requirements per unit of low-C fuel provided.35 For the CBTL designs the required amount of biomass is half or less so that these options can offer more secure supplies of lowcarbon alternatives to crude-oil-derived products than can the pure biofuel options. Because carbon mitigation and energy security enhancement 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 be determined to a large extent by relative economics. 5. Cost Analysis 5.1. Capital Cost Estimates. Our process simulation results are used as inputs to a self-consistent set of capital cost estimates for all 16 plant designs that provides the basis for meaningful comparisons of their overall economics. We have not attempted to be “up-to-date” in our estimates of capital costs, which change rapidly (especially during the period 2003-2008). High-quality estimates of absolute costs are valuable, highly prized intellectual property, change rapidly, and are not readily found in the open literature. Instead our aim is put forth a methodology that makes it feasible to estimate with a reasonably high degree of confidence how relative costs will compare among the alternative systems analyzed. To estimate total plant costs, we developed a reference set of capital costs for system components within each major category of plant operations. We drew on literature sources, extensive discussions with industry experts, and our own prior work in developing a capital cost database. We made adjustments to ensure that assumptions regarding installation factors, balance of plant, indirect costs, and maximum

(35) But note that the biofuel production with CCS designs would be characterized by negative GHG emissions, so that there would be “room in the atmosphere” for using some conventional petroleum fuels while maintaining 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 and Natural Gas to Electricity; DOE/NETL-2007/1281 (Rev. 1), Pittsburgh, August 2007.

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

injection facilities; these are instead included as operating cost items in the estimates of production costs. We assume that the CO2 is transported 100 km from the conversion facility and stored 2 km underground in deep saline formations via wells for which the assumed maximum injection rate per well is 2500 tonnes per day. Costs per tonne of CO2 stored were estimated using a model for CO2 transmission and storage developed by Ogden38,39 that takes into account various nonlinear variations in costs with scale (tonnes per year) and distance. Because XTL facilities coproduce both electricity and liquid fuels, we examine production economics from the perspectives of both a fuels producer and an electricity generator. 5.2.1. Liquid Fuel Producer’s Perspective. For the fuel producer perspective, we assume revenue from the sale of electricity is a credit against the production cost of the liquid fuels. The value of coproduct electricity is calculated using a simple model that attempts to project how the cost of CO2 emissions might be reflected in the average U.S. grid price of electricity. The value of coproduct electricity, V(T) ($/MWh) is given by: V ðT Þ ¼ B þ XT

unit-capacity limits were applied consistently and realistically across all plant designs. We relied heavily, but not exclusively, on a major NETL study36 for reference component costs. We used appropriate factors to scale costs from the reference unit capacities to the unit capacities determined from our process simulations. Our economic analyses assume “Nth plant” technology, i.e., that added risks/costs that typically accompany technologies not yet established in the market are not taken into account. We make this assumption for two reasons. First, we are interested in understanding the long-term commercial viability of the different systems analyzed based on current technologies. Second, nearly all of the component technologies included in our plant designs are already commercially established (see Section 2), so it is plausible that these systems could reach commercial maturity within the next decade or so. The Chemical Engineering Plant Cost Index37 was used to escalate all construction cost estimates to 2007 (thereby taking into account cost escalations in materials, equipment, engineering, and construction up to that point in time); all costs are expressed in constant 2007 U.S. dollars. The estimated uncertainty in our total plant capital cost estimates in this framework is (30%, based on the level of detail (factored estimates for major plant areas) and the nature of literature and industry sources used. The Supporting Information provides detailed documentation on all of our reference costs and scaling factors. Table 7 shows our capital cost estimates. Total capital costs range from around $0.7 billion for the relatively small BTL designs to nearly $5 billion for the largest coal-only facilities. Comparing specific plant costs ($/kWHHV input, last column in Table 7) reveals the strong scale economies achieved with the largest (coalonly) facilities relative to the smallest (biomass-only) facilities. Specific costs for the CBTL facilities fall in the midrange, as might be expected. 5.2. Production Cost Estimates. The capital cost estimates discussed above provide the basis for estimating the total energy production costs at each facility. In the case of plants with CCS, the capital costs presented in Table 7 include capital costs for compression of captured CO2 to 150 bar but exclude costs for CO2 pipeline and

where B is 60 $/MWh, the average price paid to U.S. power generators in 2007, X is 0.636 tonne CO2eq/MWh, the gridaverage GHG emissions intensity of U.S. power generation in 2007 and T is the GHG emissions price ($/tonne CO2eq). It should be noted that GHG emissions intensity of the grid, assumed here to be constant, will decrease with increasing GHG emissions price. While uncertainty in the true value of coproduct electricity is not likely to significantly affect the overall economics of XTL-RC systems which produce only a modest 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 model here;which underlies all XTL plant economics assessed from the perspective of a fuel producer;and urge the (38) Ogden, J. Modeling infrastructure for a fossil hydrogen energy system with CO2 sequestration. In Gale, J., Kaya, Y, Eds.; Proceedings of the 6th International Conference on Greenhouse Gas Control Technologies; Elsevier Science: Oxford, 2003; pp 1069-1074. (39) Ogden, J. M. Conceptual Design of Optimized Fossil Energy Systems with Capture and Sequestration of Carbon Dioxide; Research Report UCD-ITS-RR-04-34, Institute of Transportation Studies, University of California Davis, 2004.

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

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Table 7. Estimated Total Plant Capital Costs (TPC or “Overnight” Costs) for Alternative FTL System Configurations million 2007 $

$/kWHHV

plant name

ASU islanda

biomass islandb

coal islandc

gas cond.d

CO2 comp.

FT islande

naphtha upgradef

topping power g

heat recov þ steam cycleh

total costi

specific costj


808 808 711 742 783 100 100 208 208 206 217 225 286 243 255 387

0 0 0 0 0 336 336 335 335 335 335 138 335 335 335 334

1,468 1,468 1,468 1,468 1,468 0 0 226 226 263 263 340 473 396 396 649

849 849 636 727 762 59 59 158 158 133 151 187 235 180 215 372

0 67 0 60 73 2 14 2 22 2 24 23 33 2 33 46

882 882 519 519 676 137 137 244 244 171 171 170 246 208 263 385

86 86 70 70 70 21 21 33 33 29 29 29 39 35 35 47

35 35 272 280 238 0 0 7 7 77 80 81 127 98 86 135

723 723 713 708 757 69 69 136 136 156 155 175 180 224 168 257

4,852 4,919 4,390 4,574 4,826 724 737 1,349 1,369 1,372 1,427 1,369 1,955 1,720 1,786 2,611

642 651 581 605 638 1,097 1,115 921 935 821 854 810 706 755 784 701

a Air 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. d Gas conditioning includes all water gas shift, acid gas removal, and Claus/SCOT H2S conversion to elemental sulfur. e Includes FT synthesis, recycle compressor, ATR(s), and FT refining, except for naphtha upgrading. f Many proposed FT plant designs propose to sell naphtha as a chemical feedstock. We have separated out the costs of naphtha upgrading (isomerization and catalytic reforming units;see Figure 2) to facilitate readers making their own evaluation of this option. g This is the topping cycle in the power island. For all designs except BTL systems, this includes a syngas expander used to generate power (e.g., see Figure 5). Additionally, for all -OT designs, this includes a gas turbine and related auxiliaries. h This includes the cost of all heat recovery at the plant, plus the cost of steam turbine and related auxiliaries in the power island. i This is total plant cost (TPC), or “overnight capital cost” (which excludes interest during construction). j This is the cost per MWHHV of total feedstock input.

knowledgeable reader to substitute her own model for ours when appropriate. For all of our cost calculations, we adopt the baseline set of assumptions in Table 8 and also examine costs as a function of a greenhouse gas (GHG) emissions price. Table 9 shows levelized liquid fuel production costs when no GHG emissions price is considered. For the coal-only plants, the relatively low cost of coal (compared to biomass) makes capital charges the most significant production cost component despite the scale-economy benefits of their large size 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 plants have total FTL production costs below $2 per gallon ($0.53 per liter) of gasoline equivalent (gge) on a LHV energy basis, while fuel costs for the BTL plants exceed $3 per gge ($0.79 per liter). All CBTL plants produce FTL for 2-2.7 $/gge ($0.53-$0.71 per liter) The ranking of production costs among the systems depends critically on the GHG emission price (Figure 12a).40

However, using our model of the value of coproduct electricity, no RC plant is the least-cost fuel producer at any emission price. CTL-OT-V provides the lowest FTL fuel cost at emission prices less than $21/tCO2eq because of the low cost of coal and the powerful thermodynamic advantage of the OT design compared to the RC option. But CTL-OT-V, for which GHGI is 1.3, is not a GHG emissions reduction option. From $21/t to $73/tCO2eq, CTL-OT-CCS provides the least costly fuel and offers modest emission reductions (GHGI = 0.7). CBTL-OT-CCS (GHGI = 0.093) provides the lowest cost fuel when the emission price is between $73/t and $110/t. Finally, BTL-RC-CCS, with its negative GHG emissions, is the provider of the least costly fuel when the GHG emissions price exceeds $110/t (off graph). Table 9 also reports for zero GHG emissions price the breakeven oil price (BEOP), the price of crude oil at which the FTL production cost (on a $/GJLHV basis) equals the wholesale (refinery-gate) price of the equivalent crudeoil-derived products. In the absence of a GHG emissions price, the CTL-CCS systems have BEOPs in the range $59$65 per barrel, compared to $145 per barrel for a BTL-RCCCS plant. All CBTL-CCS designs for which GHGI is less than 0.1 have BEOPs between $84 and $110 per barrel. For perspective, the world oil price at the time of writing this paper was $75 a barrel, and the levelized crude oil price over the period 2016-2035 is projected to be $100 a barrel (Table 8). Breakeven oil price estimates as a function of GHG emissions price (Figure 12b) provide an important insight regarding risk-mitigation that coproduction might provide to investors in such systems in the future. If a strong enough carbon mitigation policy is in place, the economics of coproduction would remain favorable even if the world oil price were to collapse. For example, in the presence of the $73/t CO2eq GHG emissions price needed to make CBTLOT-CCS the least costly option, this system would be competitive at crude oil prices down to $45 a barrel. In contrast, the CBTL-RC-CCS, which makes only a minor

(40) For simplicity we have excluded from Figure 12 results for plants that 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 for these systems (see right-most column in Table 9), they are nonetheless sometimes economically superior to the analogous OT plants (without ATR). For example, at zero GHG emissions price, the CBTL-OTACCS option offers less costly FTL fuel than the corresponding CBTLOT option (see Table 9). In addition, because OTA designs vent less CO2 than their OT analogs, they utilize biomass more efficiently—e.g., the carbon in FTL fuels is equivalent to 80% of the carbon in the biomass feed for CBTL-OTA-CCS but only 59% for CBTL-OT-CCS. We have also excluded from Figure 12 results for plants using biomass grown with soil/root C storage (CBTL-OTS-CCS, CBTL-OTAS-CCS), because such biomass supplies are likely to be limited compared with other biomass 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 the GREET model.30 (42) Based on the GREET model,30 the estimated lifecycle emission rate for a 63/37 mix (LHV basis) of petroleum-derived diesel/gasoline is 91.6 kgCO2eq/GJLHV.

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Table 8. Feedstock Prices and Financial Assumptions Levelized coal price to U.S. average coal power generator, 2016-2035 ($/GJHHV)a Levelized natural gas price to U.S. average natural gas power generator, 2016-2035 ($/GJHHV)a Biomass price delivered to conversion plants ($/GJHHV)b Annual average capacity factor for XTL plants (%) Annual average capacity factor for power-only plants (%) Assumed economic life of energy conversion plants (years) IDC [interest during construction = fraction of total plant cost (TPC or overnight plant capital)]c Annual capital charge rate (ACCR) applied to [ TPC*(1 þ IDC)], fractiond Annual O&M costs at the conversion facility (% of TPC or overnight plant capital) CO2 transport and injection/storage costs, $ per tonne of CO2 20-yr levelized electricity sale price with zero GHG emission price ($ per MWh)f Assumed GHG emission rate for electric grid into which electricity is sold (kg CO2eq per MWh)f Crude oil price at time of writing this paper ($ per bbl) Levelized crude oil price ($ per bbl) with zero GHG emissions price, 2016-2035 ($/barrel)g Assumed refinery markups for diesel/gasoline displaced by FTL (¢/liter)h

1.86 6.35 5.0 90 85 20 0.0716 0.1422 4 varies with scalee 60 636 75 100 7.90/8.51

a These are fossil fuel prices to average power generators in the U.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 b For comparison, a detailed biomass logistics analysis for seventeen states in the central U.S. estimated the costs for annually delivering one million tonnes (dry basis) of biomass to a central conversion facility range 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 density mixed prairie grasses).9 c Interest during construction (IDC) is based on a 3-year construction schedule with equal annual payments and a real discount rate of 7%/year. d The annual capital charge rate (ACCR) (used in the EPRI TAG methodology to calculate the annual capital charge = [ACCR*(1 þ IDC)*TPC (in $ per year)], 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-year economic life for plants).46 e For designs incorporating CCS, CO2 is available at 150 bar at the plant gate. We assume the CO2 is transported 100 km from the 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 by Ogden38,39 that takes into account various nonlinear variations in costs with scale (tonnes per year) and distance. f For 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 nonzero GHG emission prices, we assume that the sale price increases by an amount equal to the GHG emission price times the grid-average GHG emissions in the U.S. in 2007 (636 kg CO2eq/MWh).30 g This is the crude oil price at a zero GHG emissions price in $2007/bbl levelized over the period 2016-2035 (7% discount rate), based on the Reference Scenario of the Energy Information Administration.45 h For U.S. refineries, margins (in 2007$) averaged during 1990-2003 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 diesel margin is increased by 5.0¢ a gallon in order to comply with the sulfur standards that that took effect in 2007.49 Thus the assumed margins in the absence of 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 total plant name CTL-RC-V CTL-RC-CCS CTL-OT-V CTL-OT-CCS CTL-OTA-CCS BTL-RC-V BTL-RC-CCS CBTL-RC-V CBTL-RC-CCS CBTL-OT-V CBTL-OT-CCS CBTL1-OT-CCS CBTL-OTS-CCS CBTL-OTA-V CBTL-OTA-CCS CBTL-OTAS-CCS

total

capital O&M coal biomass CO2 disposalb electricity revenue $/GJLHV $/ggea BEOPc ($/bbl) cost of CCS ($/tCO2)d 8.3 8.5 10.6 11.0 11.6 13.8 14.0 11.8 12.0 14.7 15.3 14.6 12.7 13.6 14.1 12.7

2.2 2.2 2.7 2.9 3.0 3.6 3.6 3.1 3.1 3.8 4.0 3.8 3.3 3.5 3.7 3.3

4.5 4.5 6.2 6.2 6.2 0.0 0.0 2.4 2.4 3.7 3.7 5.4 4.7 4.4 4.4 5.1

0.0 0.0 0.0 0.0 0.0 11.6 11.6 5.3 5.3 6.5 6.5 2.1 4.0 4.8 4.8 3.0

-2.1 -1.6 -9.3 -7.8 -6.2 -2.5 -1.8 -2.0 -1.4 -9.9 -8.4 -8.0 -8.2 -9.9 -7.0 -6.9

0.0 0.5 0.0 0.7 0.9 0.0 1.4 0.0 0.9 0.0 1.2 1.2 1.0 0.0 1.3 1.1

12.8 14.1 10.2 13.0 15.5 26.4 28.8 20.5 22.3 18.8 22.2 19.1 17.5 16.4 21.2 18.2

1.5 1.7 1.2 1.6 1.9 3.2 3.4 2.5 2.7 2.3 2.7 2.3 2.1 2.0 2.5 2.2

58 65 44 59 73 133 145 100 110 91 110 93 84 78 104 88

12.4 20.6 34.7 20.9 16.9 24.0 30.3 -

a This is $ per gallon of gasoline equivalent, obtained by multiplying total production cost ($/GJLHV) by the energy content of gasoline (0.12 GJLHV/gallon). This 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. See Table 8 for source of cost estimate. c This is the breakeven oil price, which we define to be the price of crude oil in $ per barrel at which wholesale prices paid to refiners for petroleum-derived products would equal (on a $ per GJLHV basis) our calculated costs for producing FTL fuels. As described in detail by 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 difference between 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 the GHG emissions price is nonzero, GHG emission charges for petroleum-derived products (see Table 4, footnote b) are factored into the BEOP calculation. d This is calculated as the difference in levelized production cost ($/GJ) for a plant with CCS versus a plant of the same basic design (and same ratio 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 for plants with CCS for which we have not developed an equivalent -V plant design. b

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

electricity coproduct, would not be able to compete if crude oil prices fell below $69 per barrel. Finally, in light of the carbon mitigation and biomass utilization benefits offered by some XTL-CCS options relative to cellulosic ethanol (EtOH-V and EtOH-CCS options; see Figure 10a and b and Figure 11), it is important to understand also the relative economic merits of these alternative 431

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

This internally self-consistent analysis shows the least costly option is CBTL-RC-CCS up to a GHG emissions price of $13/t CO2eq, above which CBTL-OT-CCS is the least costly option (at this scale of biomass input) up to a GHG emissions price of $123/t (not shown), at which price BTL-RCCCS becomes the least costly option. Cellulosic ethanol is never one of the least costly options. A striking feature of this analysis is that while a shift from a -V to a -CCS system configuration dramatically reduces the levelized production cost with rising GHG emissions price for both the BTL-RC and CBTL-OT options (Figure 12a), the economic benefit of shifting from -V to -CCS is modest in the cellulosic ethanol case (Figure 13). The reason is that the CO2 capture rate, expressed as a fraction of the carbon in the biomass feedstock, is much smaller in the EtOH-CCS case (16%), compared to 54% and 56% in CBTL-OT-CCS and BTL-RC-CCS, respectively. 5.2.2. Electricity Generator’s Perspective. Electricity accounts for roughly one-third of the energy output from plants with OT designs, making it relevant to consider these plants as electricity generators and analyze their economics in comparison with stand-alone electricity generation technologies. Economic comparisons are made among the 5 OT options and the 6 stand-alone power options listed in Table 10. The XTL-OT systems considered here are designed to have capacities smaller than in Table 3, which were the basis for the previous analysis from a liquid fuel producer’s perspective, because they would be distributed widely near electricity demand centers (like conventional power plants) rather than built as huge plants sited at remote locations. To illustrate the economic implications of this strategic perspective, the levelized costs of electricity (LCOE) is estimated for system capacities determined according to the following algorithms: (1) gasification-based energy systems using only coal were assigned the same coal input rate as a new supercritical coal plant that vents CO2 (sup PC-V;considered the reference coal power system); and (2) all XTL-OT systems were assigned the same FTL fuels production capacity as the CTL-OT options (6637 barrels per day). Coal integrated gasifier combined cycle (CIGCC) systems were modeled using the same techniques and analytical framework as for FTL systems described above. System characteristics for sup PC and NGCC in Table 10 were not

Figure 13. Levelized production costs for alternative low-carbon fuels derived from switchgrass. Cost estimates for EtOH-V are based on the analysis in NRC,8 except that that analysis is presented in the same analytical framework as for the FTL fuel options (see Supporting Information for details). The authors developed the cost estimates for EtOH-CCS, starting with the NRC results for EtOHV (see Supporting Information for details). In all cases, the assumed annual biomass input rate is 0.46 million dry tonnes per year;the rate assumed for EtOH-V in NRC.8

modeled but are taken from NETL,36 and LCOEs were estimated using the same financial, fuel price, and other assumptions as used for XTL systems (Table 8). GHGI and GHGA values for the NETL-based stand-alone power options were calculated using the same methodology as for the fully modeled systems. 41 Cost comparisons among the NETL-based stand-alone options and the fully modeled systems are likely to be meaningful because the analytical framework for cost estimation used in the present study is based largely on that used by NETL,36 as mentioned earlier. When evaluating coproduction systems as power generators, a credit is received for the sale of the FTL fuel coproduct. It is assumed that (1) FTL products are sold at the wholesale (refinery gate) prices of crude oil products they could displace (Table 8), and (2) when a GHG emissions price is considered, the selling prices are assumed to increase 432

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Table 10. Alternative Electric Generation Technologies GHGA, kg CO2eq/MWh

technology

fuel input, MWt (HHV)

biomass input, dry t/day

net electric, MWe

FT, bbls/d

GHGI

El

FTL

total

CO2 stored, 106 t/yr

TPC, $109

sup PC-Va sup PC-CCSa CIGCC-V CIGCC-CCS NGCC-Va NGCC-CCSa CTL-OT-V CTL-OT-CCS CBTL1-OT-CCS CBTL-OT-V CBTL-OT-CCS

1,405 2,004 1,405 1,405 1,102 1,102 1,405 1,405 1,397 1,380 1,380

0 0 0 0 0 0 0 0 793 2,514 2,514

550 546 528 435 560 482 234 197 202 249 212

0 0 0 0 0 0 6,637 6,637 6,637 6,637 6,637

1.0 0.21 1.0 0.15 0.51 0.13 1.31 0.70 0.50 0.77 0.09

0 660 -2.6 705 410 721 -260 253 417 189 753

0 0 0 0 0 0 -185 214 344 127 591

0 660 -2.6 705 410 721 -446 467 761 316 1,344

0 4.2 0.0 2.9 0.0 1.4 0.0 1.8 1.8 0.0 1.9

0.89 1.62 1.00 1.17 0.32 0.58 1.05 1.09 1.16 1.17 1.22

a

Source: NETL.36

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

by an amount equal to the fuel-cycle-wide GHG emission rates for the crude oil products times the GHG emissions price.42 LCOEs are compared as a function of GHG emissions price in Figure 14 for the 11 power options listed in Table 10 when the crude oil price is at its current (2010) level, $75 a barrel. Particular attention is given to the 9 options shown in Table 10 that might be considered as lower GHG-emitting alternatives to a new sup PC-V plant (for which GHGI = 1.0);the least costly new coal power option at a zero GHG emissions price.

A discussion of key system attributes of the stand-alone power system and their LCOEs as a function of GHG emissions price can be found in the Supporting Information. Here it suffices to say that (i) CIGCC-CCS is the least-costly coal stand-alone power option with CCS, and (ii) considered as power generators, coproduction systems outperform stand-alone power systems under a wide range of conditions. A striking feature of the LCOE vs GHG emission price curves (Figure 14) is the wide range of slopes among the five XTL-OT systems;a phenomenon that arises because GHG emissions enter the LCOE calculation in two ways: (a) charges for the gross fuel-cycle-wide GHG emissions for production and consumption of the system products (which vary by a factor of 13), and (b) credits for GHG emissions of the crude oil products displaced (which vary by a factor of 1.3). The net emissions charged to the produced electricity is (c) [= (a) - (b)] (which might be called the “effective GHG emission rate” for LCOE evaluation purposes), and the corresponding slopes of the LCOE vs. GHG emissions price curves thus range from strongly positive to strongly negative (Table 11). One important finding for XTL-OT options is the much lower GHG emissions price required for breakeven between -V and -CCS options than for any of the stand-alone power options ($27/t for CTL-OT and $28/t for CBTL-OT vs $54/t to $88/t for the three stand-alone power options);reflecting mainly the fact that CO2 has to be removed upstream of

(43) EPA (Environmental Protection Agency) 2010: EPA Analysis of the 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 and highway diesel fuel sulfur standards and highway diesel sulfur control requirements; final rule; 40 CFR (Code of Federal Regulations) Parts 69, 80, and 86. Federal Register, 18 January, 2001, Vol. 66 (12).

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

CTL-OT-V CTL-OT-CCS CBTL1-OT-CCS CBTL-OT-V CBTL-OT-CCS a

(a) GHG emissions for system

(b) GHG emissions credit for crude oil products displaceda

effective net emissions for evaluating LCOE: (c) = (a) - (b)

1,867 1,067 754 1,071 138

591 703 685 556 652

1,276 364 69 515 -514

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

synthesis even in the absence of a carbon policy, so that energy penalties are low (less than 10%, Figure 15), as are capture costs (Figure 16). Another important result is that, in the absence of the NGCC-V option, XTL-OT plants provide the least costly power over the entire range of GHG emission prices considered: CTL-OT-V (GHGI = 1.31) has the lowest LCOE up 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 the least costly LCOE. With NGCC-V (GHGI = 0.51) also competing;assuming an 85% design capacity factor and a natural gas price of $6.35/GJ (see Table 8);the only change is that NGCC-V yields the least costly LCOE over the range 12-54 $/tonne CO2eq, above which CBTL-OT-CCS becomes the least costly power system. It is desirable to understand the relative economics of the 11 competing technologies in the framework of possible future GHG emissions prices under a comprehensive carbon mitigation policy. The U.S. Environmental Protection Agency43 has carried out a detailed analysis of the implications for the U.S. of enacting the American Power Act (Kerry-Lieberman bill proposed in the U.S. Senate in early 2010) along with a parallel analysis of the American Clean Energy and Security Act (ACESA) of 2009 (WaxmanMarkey bill passed in the U.S. House of Representatives in 2009). The EPA estimates that, if the APA were to be enacted, the market clearing price for the sale of emission allowances (in effect, the market price of GHG emissions) would rise at a rate of 5% per year from $17/t in 2013 to $102/t in 2050 (in $2005);with a very similar GHG emissions price trajectory if the ACESA were enacted instead. For this GHG emissions price trajectory the 20-year levelized GHG 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 be the least costly coal-using option in terms of the LCOE over the 20-year economic life of power plants coming on line in 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 of what the downside risks and upside rewards might be for investments in coproduction technologies. We provide a perspective 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 price at which the LCOEs for XTL-OT options would be the same as for an CIGCC-CCS system;the least costly coal option for providing decarbonized electricity in a new power plant (Figure 14). The oil price influences the LCOE for XTL-OT power systems as the 20-year levelized oil price over the economic life of the plant. These breakeven oil prices are $82,

Figure 15. Energy penalty for CCS. For power-only systems, the energy penalty is 100(ηv/ ηc - 1) where ηv and ηc are HHV plant efficiencies for -V and -CCS options, respectively. For XTL-OTCCS options, energy penalty = 100(extra coal energy required to make up for lost power in shifting from -V f -CCS;assumed to be via CIGCC-CCS)/(coal energy use by XTL-OT-V).

Figure 16. CO2 capture costs for alternative power systems with CCS.

$65, $67, and $60 a barrel for CTL-OT-V, CTL-OT-CCS, CBTL1-OT-CCS, and CBTL-OT-CCS systems, respectively, for a $50/t CO2eq levelized GHG emissions price. Thus, an investment in a coproduction plant with CCS having a high fraction of biomass input would have a higher degree of protection against the risk of oil price collapse under a serious carbon policy compared to the protection offered (or not) by alternative investment opportunities for coproducing synfuels. Persistence of the current crude oil price might be viewed as an overly pessimistic outlook from the perspective of 434

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

GHGI

FTL output, B/D

TPC, $106

GHGI

FTL output, B/D

TPC, $106

Breakeven FTL fuels cost, $/GJ

Corresponding crude oil price, $/barrel

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

0.89

22,936

2,485

0.093

6,637

1,218

19.5

75 100

85.0 52.4

potential coproduction facility investors. The U.S. Energy Information Administration projected in its 2010 Reference Scenario that the world crude oil price will rise to $90/barrel by 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 a GHG emissions price of $50/t, the LCOE for a CBTL-OT-CCS system for which GHGI = 0.093 would be 14% less than for a sup PC-V plant at a zero GHG emissions price (Figure 17), compared to 43% more when the crude oil price is $75 a barrel. Moreover, per MWh of electricity generated, the CBTL-OT-CCS option offers a GHGA rate (Table 10) that is 1.9 that for a CIGCC-CCS plant and, at a $100/barrel crude oil price, a much lower LCOE at all GHG emissions prices (Figure 17). Those seeking to establish coal-derived synthetic fuels in the market have focused on large plants such as the CTLRC-V (GHGI = 1.71) and CTL-RC-CCS (GHGI = 0.89) plants for which levelized FTL fuels production costs are presented in Figure 12. That analysis showed that under a modest carbon mitigation policy (GHG emissions price greater than ∼$10/t CO2eq), the CCS option would be preferred. Under a more stringent carbon mitigation policy (GHG emissions price greater than ∼$50/t CO2eq) emphasis would be on coprocesssing biomass as a substantial fraction of the feedstock as well as on CCS. Constraints on the amount of biomass that can be delivered to the conversion plant imply that these plants would have relatively low FTL output capacities. It is of interest to understand the interplay between the scale economy effect and the carbon mitigation policy effect in shaping investment decisions. Table 12 shows that at the plausible future GHG emissions price of $50/t CO2eq, the CBTL-OT-CCS coproduction systems modeled here would be able to provide low GHG emitting synthetic

fuels at the same unit cost as for coal synfuels (via CTL-RCCCS) characterized by ten times the GHG gas emission rate that are produced in plants having three times the synfuel output capacity and requiring twice the capital investment, while providing electricity at lower generation cost than for alternative new stand-alone fossil fuel power plants (Figure 14 and Figure 17). Being able to provide low-carbon synfuels in small plants that can compete at a wide range of crude oil prices ought to make synfuel project financing easier for CBTL-OT-CCS systems than for the large plants based on coal only that are envisioned for a future synfuels industry by most potential synfuel investors. However, prospective synfuel investors might be hesitant to get involved in coproducing electricity, the sale of which is determined on a moment-by-moment basis via economic dispatch competition. Prospective synfuel investors will want their plants to operate at ∼90% capacity;the assumed capacity factor for XTL-OT plants (Table 8) designed as must-run baseload plants. But these investors might note that the average capacity factor for coal power plants in the U.S. electric power sector, determined to a large extent by economic dispatch competition, was only 74% in 2008. So it is important to assess how coproduction plants would operate in economic dispatch competition, which, to a large extent determines a power plant’s capacity factor. The electric grid system operator determines the merit order for dispatching plants selling electricity into the grid, typically on an hour-by-hour basis, based on bid prices to sell from the various power generating units connected to the grid. The minimum price that a power plant operator will be willing to bid is its minimum dispatch cost (MDC) determined by equating revenues for the bidding period with the system’s short run marginal cost (SRMC, i.e., operating cost, excluding 435

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emissions rate” for LCOE evaluation purposes is strongly negative at high biomass input rates (Table 11), and (5) their low MDCs enable them to defend high design capacity factors and force down capacity factors of competing stand-alone power plants. 6. Summary and Conclusions Detailed process simulations, lifecycle greenhouse gas emissions analyses, and cost analyses have been carried out in a comprehensive analytical framework for 16 alternative system configurations that involve gasification-based production of Fischer-Tropsch liquid fuels from coal and/or biomass, with and without capture and storage of byproduct CO2, including via systems that generate electricity as a major coproduct. These analyses provided the basis for a discussion of the merits of alternative system designs for addressing simultaneously key challenges posed by petroleum-based transportation fuels and coal and natural gas power generation: high current and prospective oil prices, insecurity of liquid fuel supplies, and climate change risks. Also, systematic comparisons were made to alternative options (cellulosic ethanol for making low carbon fuels and alternative new fossil-fuel based power plants) for addressing these challenges. A major finding is that, using our simple model of the value of coproduct electricity as a function of GHG emission price, synthetic liquid fuels are typically less costly to produce when electricity is generated as a major coproduct than when the plants are designed to produce mainly liquid fuels. Coproduction systems that utilize a cofeed of biomass and coal and incorporate CO2 capture and storage in the design offer attractive opportunities for decarbonizing both liquid fuels and power generation simultaneously. Such coproduction systems, when considered as power generators, can provide decarbonized electricity at lower costs than is feasible with new stand-alone fossil fuel power plants under a wide range of conditions. At a plausible GHG emissions price of $50/t CO2eq under a future U.S. carbon mitigation policy, such coproduction systems competing as power suppliers would be able to provide low-GHG-emitting synthetic fuels at the same unit cost as for coal synfuels characterized by ten times the GHG emission rate that are produced in plants having three times the synfuel output capacity and requiring twice the total capital investment. Moreover, the low-GHG-emitting synfuels produced by such systems would be less costly and require only half as much lignocellulosic biomass (or less) to produce as would cellulosic ethanol. This strategy depends on the viability of CCS as a major carbon mitigation option, but all system components for the first generation of the required conversion technologies (including carbon capture components) are proven technologically, so that commercial-scale projects for coproduction plants with CCS that have modest biomass input rates (∼ 10%) could be demonstrated during this decade.

Figure 18. MDCs for alternative power systems at alternative crude oil prices. Parameters used to estimate stand-alone fossil fuel power plant and nuclear electricity costs are discussed in the Supporting Information.

capital amortization and fixed operation and maintenance costs). Because coproduction systems provide two revenue streams, the minimum dispatch cost is given by MDC ($ per MWh) = SRMC ($ per MWh) - (FTL revenues per MWh), which implies very low MDC values at sufficiently high oil and GHG emission prices. Figure 18 presents MDCs for CBTL-OT-CCS systems at three alternative crude oil prices, for five of the stand-alone power systems listed in Table 10, and for a nuclear plant. The MDC at zero GHG emission price for a CBTL-OT-CCS plant is the same as for a nuclear plant and for a sup PC-V plant (the closest competitors) for crude oil prices of $67 and $57 a barrel, respectively. Moreover, the MDC for CBTLOT-CCS reaches $0/MWh (with zero GHG emission price) when the crude oil price is $74 a barrel. Thus coproduction systems will be able to defend high capacity factors in economic dispatch competition and would be able to drive down the capacity factors of competing systems as deployment of coproduction technologies on electric grids increases. Notably, the actual average capacity factor for the 190 GWe of NGCC capacity in the U.S. been only 41%.44 This low capacity factor reflects, to a large extent, slow electricity demand growth in the U.S. and the fact that when both coal and NGCC plants have been competing to provide the same power demand, the coal plants have tended to win the economic dispatch competition, giving them much higher capacity factors. It is not unreasonable to expect that, with a large amount of CBTL-OT-CCS capacity on the grid, economic dispatch competition might constrain the capacity factor for stand-alone power plants to 50%;in which case CBTL-OT-CCS would offer a lower LCOE at $50/t CO2eq than all stand-alone fossil fuel power plants, including NGCC-V, at oil prices of both $75 and $100 a barrel (Figure 17). The economic performances of coproduction systems under a carbon mitigation policy look especially attractive when they are evaluated as electricity generators largely because (1) the CO2 capture costs are much less than those for stand-alone power plants (Figure 16), (2) the MEGEs are much higher than the efficiencies of stand-alone power plant alternatives (Table 5), (3) the credit for the FTL coproduct rises rapidly with crude oil price, (4) the “effective GHG

Acknowledgment. We received helpful commentary and discussion from many individuals during the research for and writing of this paper. We would like to especially thank David Gray, Chuck White, and Glen Tomlinson (Noblis), Tom Tarka, John Wimer, Ken Kern, and Michael Reed (NETL), Robert Socolow (Princeton), Francis Lau (SES Energy), Rick Knight (Gas Technology Institute), and Jim Katzer and Sheldon Kramer (independent). For financial support, we are grateful to Princeton University’s Carbon Mitigation Initiative and its sponsors (BP 436

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Supporting Information Available: (A) Process design parameter assumptions for Aspen Plus simulations, (B) Method and parameters 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) Performances and LCOEs for stand-alone power systems, (D) Cellulosic ethanol parameters, and (F) Estimate of short-run marginal cost of nuclear electricity. This material is available free of charge via the Internet at http://pubs.acs.org.

and the Ford Motor Company), NetJets Inc., and The William and Flora Hewlett Foundation. Also, this paper was derived in part from work funded by the National Academy of Sciences, with support from the National Academy of Engineering, National Research Council, the U.S. Department of Energy, General Motors, Intel Corporation, Kavli Foundation, and the Keck Foundation. The findings and conclusions herein are solely those of the authors and are not necessarily accepted or adopted by any of the foregoing entities. Any errors of omission or commission are entirely ours.

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Making FischerâTropsch Fuels and Electricity from Coal and

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