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Gasoline from Coal and/or Biomass with CO2 Capture and Storage, Part A: Process Designs and Performance Analysis Guangjian LIU, Eric D. Larson, Robert H. Williams, and Xiangbo Guo Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/ef502667d • Publication Date (Web): 28 Jan 2015 Downloaded from http://pubs.acs.org on February 3, 2015

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Gasoline from Coal and/or Biomass with CO2 Capture and Storage, Part A: Process Designs and Performance Analysis Guangjian Liu,a,* Eric D. Larson,b Robert H. Williams,b Xiangbo Guod a

School of Energy and Power Engineering, North China Electric Power University, Beijing, China

b

Princeton Environmental Institute, Princeton University, Guyot Hall, Princeton, NJ, USA

c

Research Institute of Petroleum Processing, SINOPEC, Beijing, China

* Corresponding author: [email protected]

Abstract Fifteen alternative process designs for the production of synthetic gasoline from coal, biomass, or coal+biomass via gasification, methanol synthesis, and methanol-to-gasoline synthesis are analyzed, including some that produce a substantial electricity co-product and some that employ CO2 capture, with CO2 stored in deep saline formations or via injection for enhanced oil recovery. This paper reports process mass/energy balance simulation results and fuel-cycle greenhouse gas (GHG) emissions comparisons. A companion paper addresses economic and strategic issues. Key findings of the performance analysis include: i) for two plants designed with the same liquid fuel output, but with one co-producing electricity, the additional feedstock needed for coproduction is converted to electricity more efficiently than if that feedstock were used in a stand-alone power plant; ii) plants using only coal as feedstock have fuel-cycle GHG emissions greater than the conventional fossil fuels their products would displace, except for a coproduction system with CO2 capture and storage (CCS) which has about 40% less emissions; iii) plants that co-process 35% to 47% sustainably-provided biomass with coal achieve net zero fuel-cycle GHG emissions; iv) the logistics of biomass supply constrain these latter plants to modest scales (< 10,000 barrels per day gasoline); and v) a biomass-only plant with CCS has highly negative net GHG emissions and a more severe scale constraint (~ 4,000 bpd).

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Keywords: coal, biomass, gasification, methanol-to-gasoline; GHG emissions; coproduction; CCS

Nomenclature AGR ASU ATR BF bbl BTG CBTG CCS

Acid gas removal Air separation unit Auto-thermal reformer Biomass fraction of total feedstock energy input (HHV basis) barrel Biomass-to-gasoline Coal+biomass-to-gasoline CO2 capture and storage

CO2 EOR CO2e CTG DSF EF GHG FT FTL GHGI IGCC (L) LCOE LCOG MDC MEGE MTG NETL NGCC

CO2 Enhanced oil recovery CO2 equivalent Coal-to-gasoline Deep saline formation Electricity fraction of energy in products (energy in liquid fuels expressed as LHV) Greenhouse gas Fischer Tropsch Fischer Tropsch Liquids Greenhouse gas emissions index Coal integrated gasification combined cycle power plant Large Levelized cost of electricity Levelized cost of gasoline Minimum dispatch cost for electricity generation Marginal electric generating efficiency Methanol-to-gasoline National Energy Technology Laboratory Natural gas combine cycle power plant

PB RC (S) Sup PC V WGS

Partial bypass of methanol synthesis Recycle methanol synthesis Small Supercritical pulverized coal power plant Vent CO2 Water gas shift

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1. Introduction Two commercially demonstrated routes for converting solid feedstocks like coal or biomass to transportation fuels through gasification are the well-established Fischer-Tropsch (FT) route and the less widely-implemented methanol-to-gasoline (MTG) process (Figure 1) The FT process produces a broad spectrum of straight chain paraffins and olefins that require upgrading to produce finished gasoline, diesel, jet fuel, and lubricants. The MTG process produces primarily a finished-grade gasoline, with most of the remainder being propane and butane (LPG) (see Table 1). If made from coal, such liquid fuels can provide an important domestic transportation energy option for the United States and other coal-rich countries.

Figure 1. Two routes for producing liquid fuels from coal and/or biomass.

Table 1. Product slates (% by mass) of FT and MTG processes.

Methane Ethylene Ethane Propylene Propane Butylenes Butane C5-160 oC Distillate Heavy Oil/Wax Water soluble oxygenates Total

Fischer-Tropscha Iron Catalyst1 Cobalt Catalyst1 (220 oC) (340 oC) 5 8 0.05 4 1 3 2 11 1 2 2 9 1 1 19 36 22 16 46 5 1 5 100 100

Methanol-to-Gasoline ExxonMobil Haldor-Topsoe Process27,2 TIGAS3 0.7 1.9 4.28 0.4 0.2 4.3 6.73 1.1 10.9 12.11 82.3 74.98 0.1 100 100

(a) FT yields are prior to refining for gasoline octane and diesel pour point improvement.

In the case of coal-derived FT fuels, however, the fuel-cycle greenhouse gas (GHG) emissions associated with their production and use would be nearly double those of the 3


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equivalent fuels derived from crude oil.4 This arises because the liquid fuels have a molar H/C ratio of about 2, compared to a ratio much less than 1 for the input coal, so converting the coal to liquids necessitates rejecting some carbon (or adding some hydrogen from an external source, an option not considered in this paper). If CO2 capture and storage (CCS) is integrated into the process, then fuel-cycle greenhouse gas (GHG) emissions for the FT fuels are roughly the same as for the petroleum fuels displaced.4 By co-processing some sustainably grown biomass5 with coal to make FT fuels and using CCS, fuel-cycle GHG emissions of the resulting fuels can be low, zero, or negative,4,6,7,8,9,10 thereby providing both energy security and carbon mitigation benefits. Similar conclusions are likely to hold for MTG systems, but no analyses of biomass co-processing with coal for MTG production, or MTG production with CCS have been reported in the literature. An early conceptual design study for coal to gasoline using the MTG process11 included a pressurized Lurgi dry-ash moving-bed coal gasifier to generate syngas and the Lurgi methanol synthesis process to make methanol. Other process feasibility studies for coal to gasoline via MTG followed.12,13,14 Zhao, et al.15 provide a more recent update of developments of the MTG process from coal including improved MTG catalysts, heat integration, and process optimization. Biomass as a feedstock has also been considered in two recent MTG system studies, both of which focus on a system with a design feed rate of 2000 metric ton/day biomass (dry basis). A PNNL study16 focuses on what is considered to be currently achievable technology performance, including one case using an indirectly-heated gasifier and the other using an oxygen-blown fluidized-bed gasifier. An NREL study17 focuses on advanced technologies whose performance has yet to be demonstrated to be achievable, including high-performance tar reforming technology and a fluidized-bed MTG reactor system. This paper and its companion18 present a detailed comparative technical and economic assessment of the production of MTG fuels from coal and/or lignocellulosic 4


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biomass, without and with capture and storage of byproduct CO2, and with substantial electricity coproduction in some cases. In all cases that involve biomass as a feedstock it is assumed that the biomass is provided in a sustainable manner so that low or negative GHG emissions are feasible when biomass accounts for a sufficient fraction of the total feedstock. The analysis uses the process evaluation philosophy and analytical framework developed in Liu et al. (2011),4 where 16 different process designs were developed for the production of FT fuels from coal and/or biomass, with and without CCS and with and without substantial electricity coproduction. The work presented here developed 15 MTG system designs. Mass and energy balance simulation results are reported in this paper, along with estimates of full fuel-cycle GHG emissions. The simulations provide a basis for estimating plant capital and operating costs, as discussed in the companion paper,18 which analyzes financial performance and discusses strategic issues relating to technology commercialization.

2. Background on MTG Processes Several companies are active in methanol-to-gasoline technology. Exxon-Mobil and Haldor-Topsoe offer commercial technologies today. Primus Green Energy, is seeking to commercialize an advanced methanol-to-gasoline process.19 The Haldor-Topsoe process, called TIGAS, utilizes an initial single-step conversion of syngas into a mixture of dimethyl ether (DME) and methanol, followed by conversion of this mixture into gasoline in a separate reactor.20,21 The TIGAS process was first demonstrated at a pilot plant in the mid-1980s operating on synthesis gas made from natural gas.22 No commercial-scale operation has occurred yet, but ground was broken in August 2014 for a commercial plant in Turkmenistan with a capacity to produce 15,500 bbl/day of synthetic gasoline.23 The Exxon-Mobil process involves a first step of conventional methanol production from syngas, followed by partial conversion of methanol to DME in a separate reactor, 5


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followed by conversion of the DME/methanol mixture into gasoline in a third, fixed-bed reactor.24 The Exxon Mobil process was first operated commercially starting in 1985 in New Zealand on an industrial scale (15,000 barrels per day production) with methanol from natural gas.25 After ten years of operation, poor economics caused by a large fall in oil prices caused the plant to be shut down. With a return of higher oil prices in the past decade, there has been renewed interest in going forward with MTG based on the Exxon-Mobil technology. In China, a pilot-scale coal-to-MTG plant in Jincheng, Shanxi Province started up in 2009, with a capacity of about 270 bbl/day of gasoline,26 and several commercial projects are being planned. Commercial development of a full-scale (15,000 barrels per day gasoline) MTGfrom-coal plant was initiated for Medicine Bow, Wyoming,27 though that project appears to be stalled as of this writing. Synthesis Energy Systems, Inc. was granted licensing rights for up to 15 MTG units planned for use with coal gasification projects in West Virginia and elsewhere.28 G2X Energy is developing a natural gas-to-MTG facility in Southwestern Louisiana.29 Because the Exxon-Mobil MTG process has commercial operating experience and because sufficient technical details needed to simulate the process are found in the literature, this technology has been selected for the process configurations designed and simulated in the present analysis.

3. Process Designs Steady-state mass and energy balances are simulated for 15 plant designs. Table 2 gives key distinguishing features and acronyms of each design.

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Table 2. Cases investigated in this study. Acronym Key process features CTG-RC-V(L) Coal feed, recycle unconverted syngas for maximum liquids, vent CO2, 50000 bbl/day gasoline output CTG-RC-CCS(L) Coal feed, recycle unconverted syngas for maximum liquids, capture/store CO2, 50000 bbl/day gasoline output CTG-PB-V(L) Coal feed, syngas partial bypass to coproduce electricity, vent CO2, coal input same as CTG-RC-V CTG-PB-CCS(L) Coal feed, syngas partial bypass to coproduce electricity, capture/store CO2, coal input same as CTG-RC-CCS BTG-RC-V Biomass feed, recycle unconverted syngas for max liquids, vent CO2, 106 t/yr biomass input (dry) BTG-RC-CCS Biomass feed, recycle unconverted syngas for max liquids, capture/store CO2, 106 t/yr biomass in (dry) CBTG-RC-CCS Coal+biomass feed, recycle unconverted syngas for max liquids, capture/store CO2, 106 t/yr biomass, GHGI= 0a CBTG-PB-CCS Coal+biomass feed, syngas partial bypass to coproduce electricity, capture/store CO2, 106 t/yr biomass, GHGI = 0a CTG-RC-CCS(S) CTG-RC-CCS(L) design, but scaled down to gasoline output capacity of CBTG-RC-CCS CTG-PB-CCS(S) CTG-PB-CCS(L) design, but scaled down to gasoline output capacity of CBTG-PB-CCS CBTG-CCS (39% B, 1% E) CBTG-RC-CCS design, 106 t/yr biomass input, BF set so GHGI = 0.17a CBTG-CCS (5% B, 73%E) CBTG-PB-CCS, partial bypass for 73% electricity fraction, BF set so GHGI = 0.17,a total capital cappedb CBTG-CCS (15% B, 47% E) CBTG-PB-CCS partial bypass for 47% electricity fraction, BF set so GHGI = 0.17,a total capital cappedb CBTG-CCS (25% B, 26% E) CBTG-PB-CCS, partial bypass for 26% electricity fraction, 106 t/yr biomass, BF set so GHGI = 0.17a CTG-PB-CCS(S*) CTG-PB-CCS(L) design, but scaled down to gasoline output capacity of CBTG-CCS (25% B, 26% E). (a) GHGI is the greenhouse gas emissions index defined in Box A. (b) Scale for this plant set by capping total capital investment at same level as CBTG-CCS (25% B, 26% E). See companion paper.18

3.1 Coal-to-Gasoline with Venting of CO2 Figure 2 is a schematic layout of the recycle coal to gasoline (CTG-RC-V) and partial-bypass coal to gasoline (CTG-PB-V) designs that vent CO2. These designs are identical, except that CTG-PB-V includes a partial bypass of syngas around the fuel production area and a gas turbine/steam turbine combined cycle in the power island; CTGRC-V includes no syngas bypass, and the power island is based on a steam Rankine cycle. The key distinction between the two layouts is that the main export with the CTG-RC-V design is synthetic gasoline, with LPG and electricity as minor by-products. Electricity is a major co-product in the CTG-PB-V design.

Figure 2. Process layout for coal conversion to gasoline, LPG, and electricity without CO2 capture. The process layouts for the CTG-RC-V and CTG-PB-V designs are identical except for the indicated syngas partial bypass used in the CTG-PB-V design. See Table 2 for explanation of the acronyms used to identify different process configurations. 7


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The CTG-PB-V (and other partial bypass, “PB”) designs in this paper are motivated by our prior work that found that plants co-producing FT fuels and electricity from coal and biomass are in some situations more profitable than plants maximizing liquid fuels output,4,6,30,31 and in a wide range of circumstances plants with CCS are much more profitable than plants with CCS that provide only electricity.32 In the prior work, electricity coproduction was a natural feature of our FT plant designs, which utilized slurry-phase, ironcatalyzed FT synthesis without recycle of unconverted synthesis gas. Such reactors have relatively high single-pass syngas conversion rates but the unconverted stream is still substantial; using syngas unconverted in a single pass (“once through” system configuration) for power generation in a combined cycle power plant avoids the complications of recycle and was found to have better economic performance than recycle systems in many situations. In contrast, the present analysis involves fixed-bed synthesis of both methanol and gasoline, each of which requires recycle of unconverted feed gas for temperature control and other process reasons. This results in ultra-high syngas conversion to gasoline so that coproducing a substantial amount of electricity requires bypassing some syngas to the power island.33 In the process depicted in Figure 2, bituminous coal (Table 3) is milled, slurried with water, and pumped into an entrained flow oxygen-blown gasifier (simulated as a GE Energy quench gasifier) operating at 75 bar pressure and reaching 1371ºC operating temperature. Oxygen (99.5% purity) is supplied from a dedicated air separation unit (ASU). In the lower section of the gasifier, the raw synthesis gas passes through a quench, followed by an external scrubber that removes remaining particulate matter. The gas leaves the scrubber at close to 250ºC and with an H2/CO molar ratio of 0.67.The syngas then undergoes partial water gas (ு ି஼ை )

మ మ shift (WGS) resulting in a stoichiometric number (஼ைା஼ை of 2.05 as it reaches the methanol ) మ

synthesis reactor. (The corresponding molar H2/CO ratio is 2.2.) All of the H2S and most of the CO2 in the syngas are removed by Rectisol® absorption following the WGS. The concentrated stream of CO2 is vented to the atmosphere and the H2S is converted to elemental 8


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sulfur for disposal or sale. In the CTG-RC-V design all of the CO2-depleted syngas leaving the Rectisol unit is delivered to the methanol synthesis reactor. In the CTG-PB-V design 35% of the syngas is bypassed to the power island.34 This bypass fraction gives a liquids-toelectricity output energy ratio for the plant of approximately 2:1, a ratio that in our prior FT work4 provided more favorable economics than did designs that maximized liquid fuels production under many circumstances, as noted above.

Table 3. Feedstock characteristics. Coala Proximate Analysis (wt%, as-received) Fixed carbon 44.19 Volatile matter 34.99 Ash 9.7 Moisture 11.12 LHV (MJ/kg) 25.861 HHV (MJ/kg) 27.114 Ultimate Analysis (wt%, dry basis) Carbon 71.72 Hydrogen 5.06 Oxygen 7.75 Nitrogen 1.41 Chlorine 0.33 Sulfur 2.82 Ash 10.91 HHV (MJ/kg) 30.506

Biomassb 18.1 61.6 5.26 15 14.509 15.935 46.96 5.72 40.18 0.86 0 0.09 6.19 18.748

a. Illinois No. 6 (high-volatile bituminous). b. Switchgrass, as reported in Appendix C of Tarka, et al.7

The fuels synthesis area is fed the CO2-depleted syngas from the Rectisol unit. Gasphase methanol synthesis is modeled based on technology commercially offered by Lurgi.35,36 The synthesis product is cooled to separate crude methanol from unconverted syngas, and the methanol is sent for conversion to gasoline. Purge gases from the methanol synthesis and MTG recycle loops provide fuel for the power island in the CTG-RC-V case, in which the power island consists of a boiler/steamturbine, with less than 40% of the energy input coming from the purge gases. Over 60% of energy input to the power island is lower-grade heat recovered from upstream process areas. In contrast, in the CTG-PB-V case, about 70% of the energy input to the power island is fuel gas, including the bypass syngas, and the rest is recovered process heat. A gas 9


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turbine/steam turbine combined cycle is used to generate electricity. The hot gas turbine exhaust and the waste heat recovered from upstream processes are used to raise steam for the bottoming steam cycle. The high ratio of fuel gas to process heat going to the power island in the CTG-PB-V case is well matched thermodynamically to the combined cycle because the hot gas turbine exhaust provides a sufficient amount of high-grade heat to superheat the steam raised using lower-grade recovered process heat, thereby providing an attractive efficiency for the combined cycle as a whole. In the CTG-RC-V design, however, more saturated steam can be raised by heat recovery from synthesis and other process exotherms than could be superheated with the exhaust from a gas turbine fired only with purge gases. As a result, the power island efficiency of a combined cycle used in the CTG-RC-V case would not be substantially higher than with a boiler/Rankine cycle, while the required capital investment would be higher. For these reasons, all of the RC designs in this work use a steam Rankine cycle power island. All of the PB designs use a combined cycle. In all of the plant designs, the power island generates at least as much electricity as needed to supply the parasitic power demand of the plant. Far more electricity than this is generated in the PB designs.

3.2 Coal-to-Gasoline with CCS Both coal-to-gasoline processes shown in Figure 2 vent a stream of pure CO2 from the Rectisol acid gas removal (AGR) unit and a dilute stream from the power island. For coalfed process designs involving CO2 capture and storage (CTG-RC-CCS and CTG-PB-CCS), the pure CO2 stream upstream of synthesis is compressed to 150 bar for delivery to a pipeline for transport to an underground DSF storage repository or for a CO2 EOR field operation. Also, because the syngas that bypasses the fuels synthesis area is rich in CO in the partial bypass design (CTG-PB-CCS), a two-stage water gas shift (WGS) and a Rectisol CO2 absorption column (sharing a solvent regeneration column with the upstream Rectisol unit) 10


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are inserted immediately upstream of the power island to capture some CO2 that would otherwise be vented at the power island (Figure 3). Additional CO2 could be captured if the higher hydrocarbons in the fuel gas sent to the power island were reformed prior to the WGS, but the added CO2 captured would be modest because few hydrocarbons are present (as suggested by the product slate for the ExxonMobil MTG technology shown in Table 1) and additional capital investment would be required. Likewise, the relatively modest, unconcentrated CO2 in the power island flue gas is not captured in either CTG-RC-CCS or CTG-PB-CCS because so doing would require a chemical absorption unit that would severely penalize overall plant efficiency and increase capital cost. To help understand the impact of plant scale on economics, both large (L) and small (S) CTG-RC-CCS and CTG-PB-CCS plants were simulated (see Table 2). As discussed in detail later, the small versions were designed with one-quarter to one-fifth the coal input, and the simplifying assumption was made that mass and energy balances per unit of feedstock input are the same for large and small versions of each design, but capital costs are scaled appropriately.

Figure 3. CTG-RC-CCS and CTG-PB-CCS process configurations. The process layouts for the two plant designs are identical except for the indicated syngas partial bypass path and the indicated WGS & Rectisol units just ahead of the power island.

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3.3 Biomass-to-Gasoline without and with CCS Our two process designs that use only biomass as feed, one without CCS and one with, each utilize the RC design for the synthesis island. The biomass feedstock is switchgrass (Table 3), which arrives with 15% moisture content and so needs no drying prior to gasification. The equipment components in the BTG-RC-V and BTG-RC-CCS designs (Figure 4) differ from those in the corresponding CTG-RC-V and CTG-RC-CCS cases in the following ways: 1) the gasifier is a pressurized fluidized-bed gasifier (based on the Gas Technology Institute’s design) with dry ash removal, which facilitates the possibility of returning inorganic minerals concentrated in the ash to the soil for their nutrient value; the asreceived switchgrass is chopped and fed to the gasifier via lock-hoppers using CO2 from the Rectisol area for pressurization; 2) a catalytic tar cracking step is required after gasification to convert into light gases the heavy hydrocarbons that form at typical biomass gasification temperatures, thereby avoiding problems that might arise from downstream tar condensation; the cracker converts all heavy hydrocarbons and also 90% of the methane produced in the gasifier; 3) an autothermal reformer is included after tar cracking to reform the remaining methane into additional CO and H2 and thereby increase the liquid fuel yield; 4) high quality steam is recovered by syngas cooling following the ATR, and 5) a compressor is included to boost the biomass-derived syngas to the pressure required for methanol synthesis. As in all cases using the RC design, the power island prime mover is a steam turbine in the BTG-RC cases.

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Figure 4. BTG-RC-V and BTG-RC-CCS process configurations. The process layouts for the two plant designs are identical except for the disposition of the concentrated CO2 streams.

3.4 Coal + Biomass-to-Gasoline with CCS CBTG-RC-CCS and CBTG-PB-CCS coprocess coal and biomass. It is feasible to do this in a single gasifier,37 but here we consider separate coal and biomass gasification trains as was considered for FT in Liu, et al. (2011).4 Figure 5 shows the process layout for CBTG cases. Syngas produced in the coal gasification train is combined with syngas from the biomass gasification train prior to CO2 removal and further downstream processing. The coal gasification train is identical to that in Figure 3, and the biomass gasification train is as shown in Figure 4 except that no autothermal reformer (ATR) is included in the PB design (CBTGPB-CCS). If an ATR were included, the small amount of methane remaining in the syngas at that point would be reformed, which would enable slightly increased liquids production and slightly greater CO2 capture at the AGR unit. However, since adding the ATR would entail additional capital costs and the marginal benefits would be small, the decision was made to design CBTG-PB-CCS without the ATR. The recycle case (CBTG-RC-CCS) captures CO2 only at the upstream Rectisol unit. Because a substantially larger amount of carbon flows to the power island in the partial bypass case, CBTG-PB-CCS (like CTG-PB-CCS) includes a WGS and Rectisol CO2 absorption column to capture additional CO2 immediately upstream of the power island.38 Finally, the power island in the CBTG-RC-CCS design utilizes a steam turbine, while in the

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CBTG-PB-CCS case a gas turbine/steam turbine combined cycle is utilized (as in the corresponding CTG cases).

Figure 5. CBTG-RC-CCS and CBTG-PB-CCS process configurations. The process layouts for the two plant designs are identical except for the indicated syngas partial bypass path and the indicated WGS & Rectisol units just ahead of the power island.

One variant of the CBTG-RC-CCS design and three variants of the CBTG-PB-CCS design were also developed. Each of these variants is distinguished by a unique pairing of biomass fraction (BF, the fraction of total HHV feedstock energy input that is biomass) and electricity fraction (EF, the fraction of energy outputs of the plant that is electricity, with fuel energy expressed as LHV). The BF and EF pairs were selected so that each plant would be characterized by the same greenhouse gas emissions index (GHGI), an indicator of a plant’s carbon footprint described in Box A.

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Box A: The Greenhouse Gas Emissions Index (GHGI) The GHGI, first introduced by Liu et al. (2011),4 is defined as the system-wide fuelcycle GHG emissions for a particular process configuration (including from combustion of the fuel products) divided by the fuel-cycle emissions for the fossil fuels that would be displaced by the products of that plant. The GHGI is used here in preference to other metrics of carbon footprint such as kgCO2e/GJproduct, because it is especially informative when comparing plant designs with widely varying co-product outputs: it does not require an allocation of emissions among co-products but at the same time gives a clear quantification of potential emissions reductions relative to a well-defined reference system. For the fossil fuels displaced, we assume equivalent liquid fuels derived from crude oil and electricity generated by a supercritical pulverized coal plant that vents CO2 (Sup PC-V). Table 7, notes (c), (d), and (e) give details of assumed emissions for the fossil fuels displaced.

4. Process Simulation Methodology Aspen Plus® process simulations were developed to generate mass and energy balances for all plant designs. For coal processing, the simulation of upstream steps through acid gas removal were done as described by Liu,et al. (2011),4 as were biomass gasification and tar cracking;4 the reader is referred to that paper for details. The ATR included in some cases in the biomass syngas production train was also simulated following Liu, et al. (2011),4 as were process heat recovery systems and the power islands; the reader is referred to that paper for discussion of these as well. The fuels synthesis simulation is described in detail here. The operation of the gas-phase methanol synthesis reactor is simulated at 50 bar and about 250oC, a temperature maintained by recycling syngas and controlling the evaporation pressure of cooling water. An Aspen Plus® “RPlug” block is used for the simulation with kinetic rate expressions developed by Zhang39 (see Part A in the online supporting material). The hot reactor product vapor is cooled to 32oC and flashed to separate crude methanol from non-condensable gases. Approximately 95% percent of the vapor phase is then compressed and recycled to the methanol reactor. The crude methanol is further reduced in pressure to 15


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produce raw methanol at about 96 wt% purity (with most of the remainder being water), which is sufficient for sending to gasoline synthesis. The MTG area is modeled on the Exxon-Mobil process that converts a mixture of dimethyl ether (DME) and methanol into primarily gasoline range molecules (C5 C10).24,40,41,42 Practically no hydrocarbons larger than C10 form because of the shape-selective nature of the ZSM-5 catalyst. Two variants of the Exxon Mobil process have been proposed: fixed-bed and fluid-bed.11 Only the fixed-bed process has been commercially deployed, and this is the focus for the simulations here. A block flow diagram of the simulated MTG process is shown in Figure 6. The crude methanol is pumped to 22.7 bar and then vaporized and superheated (to 297oC) by heat exchange with reactor effluent before entering a fixed-bed dehydration (DME) reactor. An Aspen Plus® “REquil” block is used to simulate the DME reactor, assuming that the methanol dehydration reaction is at chemical equilibrium – a good approximation.11,14,24 The small amounts of CH4 and C2H6 dissolved in the feed methanol are assumed to be inert in the DME reactor (and also in the subsequent MTG reactor).24 The DME reactor is modeled as adiabatic, and the equilibrium mixture of DME, methanol, and water leaves at 409oC.

Figure 6. Schematic of the simulated methanol-to-gasoline synthesis and refining process.24

Few technical details of the gasoline synthesis reactor have been published since the recent resurgence of commercial interest in the MTG process. We have consequently relied for our simulation on older publications. We use an Aspen “RYield” block to simulate the 16


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MTG reaction. We developed a detailed product yield structure by scrutinizing Barker, et al.(1983)14 and Schreiner (1978)11and adopting a structure for our simulations based on these (Table 4). Our simulation produces an aggregated yield structure that is compared with other published values in Table 5.

Table 4. Comparison of fixed-bed MTG yield structures (per kg of pure methanol input to DME reactor) published by Barker14 Jones16 and Schreiner.11 The last column is the yield structure assumed for the simulation work reported in this paper. Barker14 Schreiner11 Jones16(a) This work Component mol. wt. kg Kg kg kg Hydrogen 2.02 0.0000250 0.0000252 0.0000228 0.0000252 Water 18.02 0.5656386 0.5594173 0.5570008 0.5590208 Carbon monoxide 28.01 0.0001501 0.0001486 0.0000000 0.0001486 Carbon dioxide 44.01 0.0007346 0.0007298 0.0082849 0.0007280 Methane 16.04 0.0037719 0.0037417 0.0044198 0.0037352 Ethene 28.05 0.0001590 0.0001579 0.0002228 0.0001576 Ethane 30.07 0.0018291 0.0018144 0.0005574 0.0018113 Propene 42.08 0.0008487 0.0008423 0.0002211 0.0008405 Propane 44.1 0.0125621 0.0203181 0.0210006 0.0202860 1-Butene 56.11 0.0009999 0.0047361 0.0082600 0.0047280 n-Butane 58.12 0.0074167 0.0120836 0.0132194 0.0120633 i-Butane 58.12 0.0248072 0.0391568 0.0385787 0.0390925 Cyclopentane 70.13 0.0010290 0.0000000 0.0022012 0.0010288 1-Pentene 70.13 0.0009996 0.0095379 0.0380469 0.0095222 N-pentane 72.15 0.0060935 0.0060456 0.0121068 0.0060349 I-pentane 72.15 0.0606043 0.0530755 0.0440310 0.0529853 Gasolineb 104.4 0.3123309 0.2834821 0.2470224 0.2643679 Durene 134.22 0.0048034 0.0182642 Acetone 58.08 0.0023418 0.0023384 Acetic acid 46.03 0.0023452 0.0023415 (a) Results from Jones are included here, but in determining what reactor yield structure to use in our simulation we have discounted Jones’ estimates because their published gasoline yield is far lower than other published estimates (Table 5). (b) Barker represented gasoline as n-heptane, which has a molar mass of 100.2 kg/kmol. Schreiner indicates gasoline is a mix of C6 to C10 hydrocarbons for which the average molar mass is 104.4 kg/kmol.

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Table 5. Comparison of aggregated yield structure for fixed-bed MTG reactor obtained in this work with published literature. Wise43 Yield, wt% of Methanol Charged Methanol + DME 0 Hydrocarbons 43.66 Water 56.15 CO, CO2 0.04 Coke, oxygenates 0.15 Total 100 Hydrocarbon Product, wt% light gas 1.4 propane 5.5 propylene 0.2 isobutane 8.6 n-butane 3.3 butylenes 1.1 C5+ gasoline 79.9 Total 100 Fuel products, wt% Gasoline 85 LPG 13.6 Fuel gas 1.4

Schreiner11

Tabak, Yurchak44

Tabak, et al.27 Zhao, et al.15(a)

Jones16 (b)

This work

0 43.45 56.45 0.09 0.05 100.0

0 43.66 56.15 0.04 0.15 100

NA NA NA NA NA NA

0 43.58 55.57 0.83 0.02 100

0 43.96 55.9 0.09 0.05 100

1.42 4.67 0.19 9.01 2.78 1.09 80.84 100.0

1.3 4.6 0.2 8.8 2.7 1.1 81.3 100

1.1 4.3 0.2 10.9 1.1 82.3 99.9

1.2 4.8 0.05 8.87 3.04 1.9 80.1 100.0

1.21 4.55 0.19 8.84 2.73 1.07 81.42 100.0

86.13 11.65 2.22

86 12.7 1.3

88.8 10.0 1.1

71.83 17.59 10.58

86.6 11.4 2.03

(a) Hydrocarbon product distribution based on [15]. Fuel products distribution as given in [27]. (b) See Table 4, note (a).

The raw MTG product is cooled and then the light gases, water, and hydrocarbon liquids are separated by flashing. A large recycle of light gases to the adiabatic MTG reactor is used to limit outlet temperature to 400oC. (A molar ratio of recycle gas to fresh feed of 7.5 is used. This was the design value for the New Zealand commercial unit.24,45) The liquid hydrocarbon product is sent for finishing, where one undesirable component of the raw MTG gasoline, durene (1,2,4,5-tetramethyl benzene), is treated. Durene can cause carburetor "icing" because of its high melting point. The raw MTG gasoline contains 3-6 wt% durene. In the finishing process, some durene undergoes isomerisation, disproportionation and demethylation in the presence of hydrogen to convert it to isodurene, which eliminates potential carburetor icing issues. The hydrogen requirements are estimated assuming that the durene is reduced to 2 wt% in the final gasoline product, an acceptable level for engine use.46 The hydrogen is supplied by feeding a portion of the purge gas from the methanol synthesis recycle loop to a pressure swing adsorption (PSA) unit, the tail gas from which is recompressed to rejoin the purge gases. The products leaving the fuels

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synthesis area are a high-octane gasoline, LPG, and light gases. The light gases fuel the power island. The LPG is sold as a co-product. With the above-described approach, the simulated energy and carbon balance around the MTG area is as shown in Table 6. (See Part B in the online supporting material for additional details.) To complete the basic mass/energy balance for the MTG area, we assume parasitic electricity consumption in the MTG area (including for gasoline synthesis and finishing) of 2.2 kW per barrel per day (bbls/d) gasoline.24 Details of the raw gasoline upgrading process, including parasitic steam demands (met via waste heat recovery steam generation), are given in Part C of the online supporting material.

Table 6. Energy and carbon balance for MTG area. Methanol in Makeup H2 for durene treatment Outputs Fuel gas LPG Gasoline Water, coke

MW, HHV 1681 4.3

MW, LHV 1478 3.6

kgC/sec 27.85 0.0

71.8 164.6 1287.9 1.2

66.9 152 1203.7 1.2

1.46 2.71 23.65 0.04

5. Plant Performance Results Steady-state process simulation results are described after first discussing how plant scales were selected.

5.1 Rationale for Selecting Plant Scales Scale determinations are summarized in Table 2 and described in detail here. Both large-scale (L) and small-scale (S) units are considered for systems that use only coal to make gasoline (CTG systems). For L systems with syngas recycle [CTG-RC-V(L) and CTG-RC-CCS(L)], the coal-input rate is fixed at 22,663 tonnes per day (as-received), resulting in a design synthetic gasoline output of 50,000 bbls/d (petroleum-gasoline equivalent energy), a typical scale aspired to by coal synthetic fuel project developers. The same coal input rate is assumed for the CTG designs with partial syngas bypass 19


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[CTG-PB-V(L) and CTG-PB-CCS(L)].47 The resulting liquids production capacity for these PB plants is about ⅔ of that for the recycle plants. Historically, plants as large as these designs were considered necessary to achieve scale economies to enable competitive liquid fuel production. But considering that crude oil prices are now relatively high and the difficulty of financing multi-billion dollar facilities, smaller-scale (S) plants are also analyzed for the -CCS variants. The CTG-RCCCS(S) and CTG-PB-CCS(S) plant scales were set such that their gasoline output capacities match those of the much smaller coal/biomass coprocessing plants, CBTG-RCCCS and CBTG-PB-CCS, respectively, described below. These two (S) cases thereby help illuminate the impact of scale economies via comparisons to their (L) counterparts, and they also help understand the impact of biomass coprocessing, independent of scale, via comparison to their CBTG counterparts. These economic and strategic issues are discussed in the companion paper.18 For BTG-RC-V, BTG-RC-CCS, CBTG-RC-CCS, and CBTG-PB-CCS, the biomass input rate was fixed at 3,581 metric tonnes (dry basis) per day. This results in an annual biomass input of approximately 1 million dry tonnes per year (assuming 90% capacity factor), which is considered a logistical maximum for truck-delivery of bales of herbaceous biomass in the U.S.31 For the two CBTG-CCS designs, the biomass fraction of input was selected to realize a zero greenhouse gas emissions index (GHGI), the carbon footprint metric discussed in Box A. As a result, BF = 0.47 for CBTG-RC-CCS and 0.35 for CBTG-PB-CCS. When BF is increased to 1.0 (BTG cases), GHGI = + 0.07 for BTG-RC-V and GHGI = – 1.1 for BTG-RC-CCS. Four additional variants of CBTG designs involve alternative combinations of BF and EF that each result in GHGI = 0.17. The case with the highest BF utilizes a RC configuration. The other three cases use a PB configuration and bypass different fractions of syngas around the synthesis area to vary the EF. For the two cases with the highest BF values [CBTG-CCS 20


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(39% B, 1% E) and CBTG-CCS (25% B, 26% E)], the biomass input was fixed at 1 million dry tonnes per year. For the remaining two variants [CBTG-CCS (5% B, 73% E) and CBTGCCS (15% B, 47% E)], a 1 million t/yr biomass input scale would lead to impractically large plant sizes and prohibitively-large capital requirements. Instead, these plants were sized for a total estimated capital investment18 matched to that for CBTG-CCS (25% B, 26% E), the more costly of the other two variants. A CTG-PB-CCS(S*) option that has the same process configuration as CTG-PB-CCS(L), but with gasoline output capacity the same as CBTG-CCS (25% B, 26% E), is also considered later. The strategic importance of biomass for the realization of low GHGI values (via either BTG or CBTG system configurations) and the constraint of limiting biomass supplies to no more than 1 million dry tonnes per year together imply that the production of synfuels characterized by low carbon footprints must be carried out at relatively modest scales (~ 4,000 bbls/day for BTG plants but up to ~ 13,000 bbls/day for CBTG plants), as will be seen in performance results discussed below.

5.2 Mass and Energy Balance Simulation Results Table 7 and Table 8 summarize performance simulation results for 10 of the 15 process designs. Table 9 gives results for the remaining five systems. CTG-RC-V(L) converts 49% of the coal input energy (HHV) into liquid fuels (89% gasoline and 11% LPG). Gross electricity production is over 594 MWe, but more than 80% of this is used to meet onsite needs (Table 8), resulting in net export electricity of 110 MWe (EF = 0.03), equivalent to 1.5% of the input coal rate (HHV basis). About 58% of carbon input as coal is vented to the atmosphere at the plant, and an additional 38% reaches the atmosphere when fuel products are eventually combusted. The carbon conversion results are consistent with other studies11,12,13,14,48 that have estimated 30% to 44% carbon conversion from coal to final liquids.49 The GHGI of 1.9 for CTG-RC-V(L) 21


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indicates that its carbon footprint is nearly double that of a system that would produce the same amounts of liquid fuel and electricity from crude oil and coal, respectively.

Table 7. Process simulation results. Feedstock>>> Technology>>>

Coal Recycle Partial bypass CTG-RC-V CTG-RC-CCS CTG-PB-V CTG-PB-CCS ) (L) (L) (L) (S) (L) (S)

Biomass Recycle BTGBTGRC-V RC-CCS

Coal + Biomass Recycle PB CBTGCBTGRC-CCS PB-CCS

Coal input As-received, metric t/day 22,663 22,663 4,474 22,663 22,663 6,098 0 0 2,415 3,963 Coal, MW HHV 7,112 7,112 1,404 7,112 7,112 1,914 0 0 758 1,244 Biomass input 0 0 0 0 0 0 3,581 3,581 3,581 3,581 As-received metric t/day Biomass, MW HHV 0 0 0 0 0 0 661 661 661 661 0 0 0 0 0 0 1.0 1.0 0.466 0.347 Biomass fraction of inputs, HHV basis (BF) Liquids output LPG, MW LHV 359 359 71 248 248 67 31 31 71 65 Gasoline, MW LHV 2,913 2,913 575 1,977 1,977 532 256 256 575 532 bbl/day crude oil products displaced (excl. LPG) 50,000 50,000 9,871 33,924 33,924 9,128 4,390 4,390 9,871 9,128 Electricity metrics Gross production, MW 594 594 117 1,523 1,486 400 76 76 135 431 On-site consumption, MW 484 582 115 563 696 187 46 58 132 195 Net export to grid, MW 110 12 2.4 959 790 213 30 19 3.5 236 Electricity fraction of products (EF), LHV basis 0.033 0.0038 0.301 0.262 0.095 0.061 0.0054 0.283 Energy ratios (HHV basis) Liquid fuels out /Energy in 0.494 0.494 0.336 0.336 0.467 0.467 0.489 0.337 Net electricity/Energy in 0.015 0.002 0.135 0.111 0.046 0.028 0.0025 0.124 Total Energy out/Energy in 0.509 0.496 0.471 0.447 0.512 0.495 0.492 0.461 0.389 0.343 0.391b Marginal Electricity Generation Efficiencya (MEGE) Carbon accounting C input as feedstock, kgC/sec 167.2 167.2 33.0 167.2 167.2 45.0 16.5 16.5 34.4 45.8 % stored as CO2 0.0% 48.7% 0.0% 63.7% 0.0% 59.6% 53.8% 65.4% % in char (land-filled, sequestered from atmosphere) 4.0% 4.0% 4.0% 4.0% 3.0% 3.0% 3.5% 3.6% % vented to atmosphere 57.6% 8.9% 69.9% 6.1% 62.9% 3.3% 5.7% 5.4% % in liquid fuels 38.4% 38.4% 26.1% 26.1% 34.1% 34.1% 36.9% 25.6% CO2stored, 106 tCO2/yr (90% capacity factor) 8.47 1.67 11.09 2.98 1.03 1.93 3.11 Greenhouse Gas Emissions Index (GHGI)c,d,e 1.9 1.1 1.5 0.59 0.07 -1.1 0.00 0.00 (a) The marginal electricity generating efficiency (MEGE) is defined as the ratio of A to B, where A is the difference in net electricity output between a “PB” plant design (e.g., CTG-PB-CCS) and the corresponding “RC” design (e.g., CTG-RC-CCS) when both plants are scaled to the same liquid fuels output, and B is the difference in feedstock energy input between the two scaled designs. (b) For CBTG-PB-CCS, MEGE is calculated relative to a CBTG-RC-CCS option (not listed) that has the same biomass input fraction (0.347) as CBTG-PB-CCS; that CBTG-RCCCS option was created (for purposes of this calculation) as a linear combination of the listed CBTG-RC-CCS and CTG-RC-CCS options, each having the same gasoline output capacity as CBTG-PB-CCS. (c) The Greenhouse Gas Emissions Index is defined (see Box A) as the lifecycle GHG emissions associated with a particular plant divided by the lifecycle GHG emissions associated with the fossil fuel-derived products displaced by the fuels and electricity produced by the process. Assumed emissions for the fossil-fuel products displaced are 90.6 kgCO2e/GJLHV for petroleum-derived gasoline50and our estimate of 86.1 kgCO2e/GJLHV for the lifecycle emissions for petroleum-derived LPG. Additionally, for electricity we assume 827 kgCO2e/MWh, the estimated lifecycle emissions for a supercritical pulverized coal power plant (789 kgCO2/MWh at the plant53 plus 38 kgCO2e/MWh from coal mining/transport.50) (d) For the systems considered here, GHG emissions include positive emissions to the atmosphere that occur (i) during production and delivery of feedstocks (1.785 kgCe/GJLHV for biomass and 1.024 kgCe/GJLHV for coal), (ii) at the plant during feedstock conversion (as noted in this table), (iii) during delivery of liquids to the point of use (0.1551 kgCe/GJLHV for gasoline and 0.183 kgCe/GJLHV for LPG), and (iv) during fuel combustion (assuming complete combustion). Carbon removed from the atmosphere and stored in the input biomass feedstock is counted as negative emissions. (e) Here the simplifying assumption is made that GHGI is the same whether CO2is stored via CO2 EOR or in deep saline formations (DSFs)—i.e., emissions arising from the eventual combustion of the liquid fuels derived from the extra crude oil produced via CO2 EOR are neglected. It is implicitly assumed that in the current oil market the amount of oil produced is set by the level of oil demand, so that crude oil-derived emissions globally would be the same regardless of whether incremental oil is produced via EOR or not. Also possible differences in emissions from crude oil produced via CO2 EOR and other means are neglected.

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Table 8. Parasitic power demands. Gross Output (MWe) Gas turbine Steam turbine Expander Onsite Consumption (MWe) Feedstock grinding and feeding Air separation unit Acid gas removal (Rectisol) Recycle compressor Methanol synthesis area MTG synthesis and finishing CO2 compression N2 compression Balance of plant

CTG-RCV(L) 594 0 586 8 484 20 270 33 8 24 112 0 0 17

CTG-RCCCS(L) 594 0 586 8 582 20 270 33 8 24 112 98 0 17

CTG-PBV(L) 1523 748 767 8 563 20 270 33 7 20 76 0 83 54

CTG-PBCCS(L) 1,486 717 750 19 696 20 270 43 7 20 76 128 77 55

BTGRC-V 76 0 74 2 46 1 26 4 1 2 10 1 0 2

BTGRC-CCS 76 0 74 2 58 1 26 4 1 2 10 12 0 2

CBTGRC-CCS 135 0 134 1 132 3 52 10 3 5 22 23 0 13

CBTGPB-CCS 431 205 220 6 195 4 65 15 2 6 21 37 22 23

Table 9. Process simulation results for four CBTG configurations with GHGI = 0.17 and a CTGPB-CCS(S*) reference design for which GHGI = 0.59.

Biomass Fraction Electricity Fraction

PB designs CBTG-CCS CBTG-CCS (15% B, 47% E) (25% B, 26% E) 0.150 0.250 0.467 0.264

CBTG-CCS (5% B, 73% E) 0.050 0.73

CTG-PBCCS(S*) 0 0.262

RC design CBTG-CCS (39% B, 1% E) 0.391 0.011

Coal input 8,091 7,310 6,315 8,652 3,273 As-received, metric t/day 2,539 2,294 1,982 2,715 1,027 Coal, MW HHV Biomass input As-received metric t/day 725 2,195 3,581 0 3,581 134 405 661 0 661 Biomass, MW HHV Liquids output 26.8 61.6 93.0 94.8 85.0 LPG, MW LHV Gasoline, MW LHV 214 497 755 755 689 3,678 8,531 12,951 12,951 11,820 bbl/day crude oil products displaced (excl. LPG) Electricity metrics 956.8 779.0 570.3 567.2 156.3 Gross production, MW 304.3 289.0 265.7 265.6 147.9 On-site consumption, MW 652.5 490.0 304.6 301.6 8.4 Net export to grid, MW Electricity fraction of outputs EF), LHV basis 0.73 0.467 0.264 0.262 0.011 Energy ratios (HHV basis) 0.097 0.222 0.344 0.336 0.492 Liquid fuels out /Energy in 0.244 0.182 0.115 0.111 0.005 Net electricity/Energy in 0.341 0.404 0.460 0.447 0.497 Total Energy out/Energy in Marginal Electricity Generation Efficiencya (MEGE) 0.303 0.327 0.372 0.343 Carbon accounting 63.0 64.1 63.1 63.8 40.7 C input as feedstock, kgC/sec 82.4 73.2 64.3 63.7 53.0 % stored as CO2 3.9 3.8 3.7 4.0 3.6 % in char (sequestered via land-fill) 6.1 5.9 5.6 6.1 6.1 % vented to atmosphere 7.5 17.1 26.4 26.1 37.3 % in liquid fuels CO2stored, million tCO2/yr (90% capacity factor) 5.40 4.88 4.22 4.23 2.24 0.17 0.17 0.17 0.59 0.17 Greenhouse Gas Emissions Index (GHGI) (a) The MEGE for each PB design is calculated relative to an RC design (not listed) that has the same biomass input fraction as the corresponding PB design; these RC designs were created as linear combinations of the listed CBTG-CCS (39% B, 1% E) and the CTG-RC-CCS in Table 7. The linear combination plants were scaled to the same gasoline output capacity as the corresponding PB design for the purpose of calculating MEGE.

CTG-RC-CCS(L), like CTG-RC-V(L), converts 49% of input coal energy into liquid fuels, but exports hardly any electricity (12 MWe, EF = 0.004) due primarily to the higher onsite power requirements for compressing captured CO2 (Table 8). Nearly half of 23


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coal carbon input is captured as CO2 and compressed for storage. This implies a much lower GHGI (1.1) than for CTG-RC-V(L), but a carbon footprint still somewhat larger than for the fossil fuels that would be displaced by the products. CTG-RC-CCS(S), for reasons discussed in Section 5.1, has an input coal rate that is 19.7% of that for the CTG-RC-CCS(L) plant. All plant outputs are similarly 19.7% of those for the larger plant. CTG-PB-V(L) exports an order of magnitude more electricity (959 MWe, EF = 0.30) than CTG-RC-V(L) but its first law system efficiency is lower (47.1% vs 50.9%) as a result of the intrinsically lower efficiency of converting syngas into electricity compared to liquid fuels. GHGI (1.5) is lower than for CTG-RC-V(L) but higher than for CTG-RC-CCS(L). CTG-PB-CCS(L), in which CO2 is captured both upstream of fuels synthesis and from the fuel gas feeding the power island (Figure 3), has GHGI = 0.59 (Table 7).This is almost as low as the GHGI for a new natural gas combined cycle plant that vents CO2 (GHGI = 0.57 for NGCC-V—see Table 10). Net electricity exports (790 MWe, EF = 0.26) are 18% less than for CTG-PB-V(L) due to the large onsite CO2 compressor power demand, and the overall efficiency is reduced by 2.4 percentage points. The efficiency penalty due to addition of CO2 capture is larger for this PB case than it is for the analogous RC case because of higher parasitic energy needs with capture of a larger fraction of the input feedstock carbon in the PB case (64% vs. 49%, Table 7). The electricity “penalty” for adding CCS in the RC case is 91 kWh per tonne of CO2 captured,51 which is the amount of power needed to compress the captured CO2 to 150 bar. In the PB case, the penalty is 120 kWh/tCO2 captured, which includes not only the penalty for CO2 compression upstream of synthesis but also for the added parasitic demand of downstream CO2 capture.

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Table 10. Stand-alone electricity generating plant characteristics.a NGCC-V NGCC-CCS Sup PC-Vb Sup PC-CCSb IGCC-Vc IGCC-CCSc

Net Generating Capacity (MWe) 555.1 473.6 550.0 550.0 622.1 543.3

GHGI 0.57 0.20 1.00 0.20 0.99 0.17

Efficiency (% HHV) 50.2 42.4 39.3 28.5 39.0 32.7

CO2 capture rate (t/MWhe)e 0.381 0.979 0.890

a) Based mainly on NETL.52 b) Supercritical pulverized coal plant. c) IGCC using General Electric Energy gasifier. d) GHG emission rates for coal and natural gas upstream of the power plants are included based on the 2011 version of the GREET model.

Comparing results for the PB and RC designs (Table 7) highlights the trade-off involved between a design that maximizes liquid fuels production and one that coproduces a significant amount of electricity. A useful comparative metric in this regard is the marginal electricity generation efficiency (MEGE),4 defined as ࡭ൗ࡮ , where A is the additional net power generated by the PB design relative to the net power of the corresponding RC design when both plants are sized for the same liquid fuels output, and B is the difference in the rate of feedstock energy input between the two scaled designs. The MEGE for the CTG-PB design is 38.9% with CO2 vented and 34.3% when CO2 is captured and stored (Table 7). These efficiencies can be compared with efficiencies for new stand-alone coal power plants that vent CO2 [(39.3% for Sup PC-V and 39.0% for a coal integrated gasification combined cycle (CIGCC-V)] and for coal power plants that capture and store CO2 (28.5% for Sup PC-CCS and 32.7% for CIGCC-CCS).53 The attractive marginal efficiencies for CTG-PB arise primarily because of the effective recovery and use of process heat to boost electricity output. In PB designs, the electricity fraction (EF) of the energy products is an important parameter affecting overall plant (first-law) energy efficiency and MEGE. The first law efficiency increases with decreasing EF because syngas can be converted to liquids more efficiently than to electricity. The MEGE also increases with decreasing EF. This can be explained in part by considering the ratio of power generated by the steam turbine bottoming cycle (Pst) to the total generated by the gas turbine plus steam turbine (Pgt+Pst) 25


Energy & Fuels

on the power island. See Figure 7 for CTG-PB-V. For a design with EF = 1.0 (i.e., an IGCC, which produces only electricity), this ratio is about 0.39.54 With increasing liquids co-production (decreasing EF), Pst/(Pgt+Pst) increases due to integrated heat recovery leading to additional steam generation and steam turbine output.

60%

60% Pst/(Pgt+Pst)

CTG-PB-V 55%

50%

50% EEF

45%

45% MEGE

40%

40%

35%

Pst/(Pgt+Pst)

55%

Efficiency (%)

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

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35% Efficiency of IGCC-V

30% 0%

20%

40%

60%

80%

30% 100%

Electricity fraction of products (%, LHV basis)

Figure 7. Variations in system first law efficiency (EEF, HHV basis), Marginal Electricity Generation Efficiency (MEGE, HHV basis), and the ratio of steam turbine to steam turbine plus gas turbine power output in CTG-PB-V designs with different electricity fractions (EF, LHV basis). The dotted line shows the HHV efficiency when only power is generated via an IGCC with CO2 vented. Details for each of the points plotted are available in Table D1 of the online supplemental material.

CTG-PB-CCS(S) has the same process configuration as CTG-PB-CCS(L), but for reasons discussed in Section 5.1 has an input coal rate that is 26.9% of that for CTG-PBCCS(L). All outputs are similarly 26.9% of those for the large plant. CTG-PB-CCS(S*) also has the same process configuration as CTG-PB-CCS(L), but for reasons discussed in Section 5.1 has a gasoline output capacity matched to that for the CBTG-CCS (25% B, 26% E) design discussed later in this section. This constraint gives CTG-PB-CCS(S*) an input coal rate that is 38.2% of that for CTG-PB-CCS(L). All outputs are similarly 38.2% of those for CTG-PB-CCS(L). BTG-RC designs yield slightly higher total plant efficiency than the corresponding 26


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Energy & Fuels

CTG-RC design without CCS and about the same efficiency as the CTG-RC design with CCS (Table 7). The cold-gas efficiency for the biomass gasifier island (including the tar cracker and ATR) is 68%, compared with 75% for the coal gasifier island. This results in a lower liquids yield in the BTG case. At the same time, the syngas cooler present in the biomass gasifier island (but not in the coal gasifier island) enables greater heat recovery for steam generation, resulting in a higher electricity yield for the BTG case. The lower liquids yield and higher electricity yield essentially offset each other to keep overall plant efficiency of BTG and CTG close to each other. The fraction of the input biomass carbon converted to liquids is 34%, which is somewhat higher than values in other studies (28%33%).16,17,55 The higher value here is due primarily to the lower moisture content of the as-received biomass in our analysis, which avoids the need to use any of the feedstock energy content for drying prior to gasification. The GHGI is close to zero (0.07) for BTG-RC-V and highly negative for BTG-RC-CCS (-1.1) because the carbon input as feedstock is of photosynthetic origin: the sum of carbon in the CO2 emitted to the atmosphere at the conversion facility + that contained in the synthetic fuels produced + that stored underground as CO2 + that stored as char in the gasifier ash is assumed to be equal to the carbon in CO2 removed from the atmosphere via photosynthesis in the growing of replacement biomass. CBTG-RC-CCS and CBTG-PB-CCS, as noted earlier, were designed with biomass input fractions set to achieve GHGI = 0 (i.e., net fuel-cycle GHG emissions are zero for the fuels and net electricity provided). Figure 8 quantifies how CBTG-PB-CCS achieves this: the large carbon flow from the atmosphere via photosynthesis is exactly offset by the sum of several return flows to the atmosphere. Also, more carbon is stored underground (as CO2 and gasifier char) than is extracted as coal, which balances emissions to the atmosphere in excess of the amount of CO2 extracted by photosynthesis.

27


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1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

To Atmosphere

Coal mining and transportation

105 tC/d

Biomass cultivation and transportation

Photosynthesis

93 tC/d

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-1430 tC/d

Combustion of liquid fuels

Transport of liquid fuels

Vent

214 tC/d

1013 tC/d

8 tC/d

Liquid fuels

Biomass

1013 tC/d 1430 tC/d CBTG-PB-CCS

2526 tC/d

144 tC/d

Char in gasifier ash (land-filled)

Coal mine

2585 tC/d

Captured CO2 underground storage

Figure 8. Equivalent-carbon flows (tCeq/day) for the CBTG-PB-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. The liquid fuels include 89.3% gasoline and 10.7% LPG (energy, LHV basis).

First law efficiency for the CBTG-RC-CCS case is similar to those for CTG-RCCCS and BTG-RC-CCS,56 but the MEGE of 39.1% for CBTG-PB-CCS is markedly higher than for CTG-PB-CCS (Table 7) and equal to the efficiency of electricity generation of a supercritical pulverized coal plant venting CO2 (Sup PC-V). The high MEGE arises because: i) CBTG-RC-CCS includes an energy-intensive ATR in the biomass gasifier island that is not present in CBTG-PB-CCS nor in CTG-RC-CCS and CTG-PB-CCS, ii) high pressure steam is generated by cooling of biomass syngas, but not coal syngas, and this steam is used more effectively for power generation in the PB configuration than in the RC configuration; and iii) the higher average cold-gas efficiency of syngas production and tar cracking for CBTG-PB-CCS (76.5%) compared with CTGPB-CCS (75.0%) leads to a larger rate of energy delivery (as unconverted fuel gases and 28


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Energy & Fuels

recovered synthesis heat) to the power island per incremental unit of feedstock energy input for the PB system relative to its RC counterpart. Because gasoline is produced in CBTG plants by co-processing coal with biomass, only 1.16 to 1.25 MW LHV of dry biomass input are required per MWLHV of gasoline produced, compared with 2.41 MWLHV of dry biomass per MWLHV in the BTG-RC-V (“pure” biomass) case. The latter number is representative of the prospective biomass requirements for many pure biofuels, including cellulosic ethanol.57 The much lower biomass requirement for producing low-carbon liquid fuels via CBTG versus a pure biofuel is an important feature of CBTG-CCS designs, which can thus produce much more low carbon fuels from scarce biomass supplies than is feasible with pure biofuels. By designing a CBTG-PB-CCS plant with a different biomass fraction (BF) and/or electricity fraction (EF), different GHGI levels can be achieved. Figure 9 shows approximate values of BF and EF for different target GHGI. To achieve a specified GHGI using a lower BF

requires a design with higher EF and vice versa. The higher EF enables a larger fraction of the carbon input to the plant to be captured as CO2 for storage, thereby reducing the numerator of the GHGI, and it also contributes to a larger value for the denominator of the GHGI due to greater displacement of coal electricity, which is more carbon-intensive than the crude oil products displaced by the synthetic liquid fuels. Notably, a given fractional increase in BF reduces GHGI about three times as much as the same fractional increase in EF (see Figure 9). Detailed simulations were developed for four CBTG cases with different BF, EF pairings that each give GHGI = 0.17 for the system (Table 9). The motivation for this particular GHGI target is described in the companion paper.18

29


Energy & Fuels

1.0

GHGI

0.9

-1.0 0.8

Electricity Fraction (EF)

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

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-0.75 0.7

-0.50 0.6

-0.25 0.5

0.0 0.4

0.25 0.3

0.50 0.2 0.1 0.0 0

0.2

0.4

0.6

0.8

1

Biomass Fraction (BF)

Figure 9. Lines of constant GHGI for different Electricity Fraction and Biomass Fraction for the CBTG-PB-CCS design. A linear regression correlation was derived from a subset of results and was used to generate this plot. The regression (r2 = 0.96) is ‫ = ܫܩܪܩ‬0.746 − (1.66 ∙ ‫ )ܨܤ‬− (0.544 ∙ ‫)ܨܧ‬. See Table D2 in the online supporting material.

6. Conclusions The detailed design and process simulations described in this paper provide important insights concerning the relative attractiveness of different plant configurations for making gasoline and/or electricity from coal, biomass, or coal-plus-biomass. Comparing two plants using the same feedstock and having the same liquid fuel output – one producing only liquids and one coproducing electricity – the additional feedstock needed for coproduction is converted to electricity more efficiently than if that amount of feedstock were used in a stand-alone electric generating plant. This marginal electricity generating efficiency is especially high for CBTG plant designs and has important cost implications, as discussed in the companion paper. Plants using only coal as feedstock have fuel-cycle GHG emissions greater than the conventional fossil fuels their products would displace, except if the plant design includes coproduction of electricity and CO2 capture and storage (CCS). Emissions are about 60% of those for the fossil fuel products displaced in that case. 30


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Energy & Fuels

CBTG plants that co-process 35% to 47% sustainably-provided biomass with coal achieve net zero fuel-cycle GHG emissions. The logistics of biomass supply constrain such plants to modest scale (< 10,000 bbl/d gasoline output capacity). A biomass-only plant with CCS has highly negative net GHG emissions and a more severe scale constraint (~ 4,000 bbl/d). The results in this paper provide the basis for estimating capital and operating costs needed to understand prospective financial performance, as discussed in detail in the companion paper.18

Acknowledgments We thank our colleague and good friend, James Katzer, for important contributions to the research described here. Sadly, Jim passed away before our work was completed. We thank Tom Kreutz for helpful discussions in the course of the research. For funding in support of this work, Liu acknowledges China’s National Natural Science Foundation (project no. 51106047); Larson and Williams thank the Edgerton Foundation and Princeton University’s Carbon Mitigation Initiative.

Supporting Information Available Supporting information mentioned in this paper is available free of charge online at http://pubs.acs.org/.

References and Notes

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Steynberg, A.P.; Dry, M.E. Fischer-Tropsch Technology, Elsevier, 2004.

2

Katzer, J. Coal (and Biomass) to Liquid Fuels, Environmental and Energy Study Institute Energy Briefing, 1310 Longworth House Office Building, 18 March 2009.

3

Shu, G. Coal Liquefaction Technology. China Coal Industry Publishing House, Beijing,

China, 2003; pp 252-259. 31


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Liu, G.; Larson, E.D.; Williams, R.H.; Kreutz, T.G. Energy and Fuels, 2011, 25, 415-437.

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Biomass is sustainably grown if one new tonne of biomass is grown for each tonne of biomass consumed, and biomass is provided in ways that avoid adverse direct and indirect land-use impacts (e.g., assuming no good cropland is used for growing dedicated energy crops). 6

Williams, R.H.; Liu, G.; Kreutz, T.G.; Larson, E.D. Ann. Rev. Chem. Biomol. Eng., 2011, 2, 529-553.

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Tarka, T.J. Affordable, Low-Carbon Diesel Fuel from Domestic Coal and Biomass, National Energy Technology Laboratory, 2009. 8

Reed, M.E. Increasing Security and Reducing Carbon Emissions of the U.S. Transportation Sector: A Transformational Role for Coal with Biomass, National Energy Technology Laboratory, 2007. 9

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El-Malki, E.; Hindman, M. Methanol to Gasoline (MTG) Technology, presented at GTL North America, Houston, Texas, March 2014. 29

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A slurry-phase methanol synthesis reactor design may require less or no recycle of unconverted syngas. In that case, the use of a partial-bypass design to provide fuel for power generation may not be needed. Instead, syngas unconverted after methanol synthesis might be usable for this purpose. 34

In the CTG-PB-V case, WGS conditioning would not be required for the syngas that bypasses the fuels area to the power island, but desulphurization is needed to meet emission standards, so the syngas bypass split is placed after the Rectisol unit, rather than before the WGS. The CO2 recovered from the Rectisol could be recompressed and added to the bypass syngas, which would increase mass flow to the power island. It is uncertain if the capital and operating costs of the added CO2 compressor in this case would be offset by the added power island output that results. This possibility was not investigated in the present work. 35

Supp, E. How to Produce Methanol from Coal, Springer-Verlag, Berlin, 1990.

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Larson, E.D.; Williams, R.H.; Kreutz, T.G.; Liu, G.; Hannula, I.; Lanzini, A. Energy, Environmental, and Economic Analyses of Design Concepts for the Co-Production of Fuels and Chemicals with Electricity via Co-Gasification of Coal and Biomass, contract DEFE0005373, final report to National Energy Technology Lab., 2012. 38

One of the FT plant designs (called CBTL-OTA-CCS) in Liu, et al. (2011)4 included an

ATR just ahead of the downstream WGS and Rectisol units. This enabled substantially increased CO2 capture compared with not including the ATR because of the significant C1 to C4 hydrocarbons produced by iron-catalyzed FT synthesis (Table 1). The MTG systems analyzed here produce less light hydrocarbons (Table 1), and the C3 and C4 components are recovered as a saleable byproduct rather than being used as fuel gas, so including an ATR would provide little in the way of added CO2 capture. 39

Zhang, J.; Song, W.; Wang, H.; Fang, D. “Reaction kinetics of methanol synthesis in the presence of C301 Cu-based catalyst (II): Model of global kinetics,” Journal of Chemical Industry and Engineering (Chinese), 1988, 4, 409-415. 40

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45

The ten years of commercial operating experience in New Zealand and additional research and development efforts since then have probably led to improvements in catalyst performance and in reactor operation that would enable the recycle ratio to be reduced, leading to a lower recycle compressor load among other benefits. As a side calculation, we estimated that overall plant efficiency (product energy output divided by feedstock energy input) for the CTG-RC-V case would increase by less than half of one percent were the recycle ratio to be decreased from 7.5 to 5.5. Capital cost impacts might be more substantial, but we did not investigate this. 46

de Klerk, A.; Prasad, V. “Methane for Transportation Fuel and Chemical Production,” in Materials for a Sustainable Future, Letcher and Scott (eds), RSC, Cambridge, UK, 2012, pp 327-384. 47

The gas turbines in the power island of all plants using a PB design are simulated as having F-Class firing temperature and performance, but as “rubber” turbines that can be sized to the available turbine fuel input rate. Actual turbines are available only in discrete sizes. This simplification does not qualitatively change the comparative results presented in this paper. 48

Hemming, D.F.; Holmes, J.M.; Teper, M. The cost of liquid fuels from coal. Part III: Methanol and methanol-derived gasoline, IEA EAS E3/81/3, International Energy Agency, Paris, 1983. 49

The wide range of carbon conversion estimates in the literature reflects the fact that the

achievable conversion varies with coal type and process topology. 50

Argonne National Laboratory, Greenhouse Gases, Regulated Emissions, and Energy Use in Transportation (GREET) Model, release 1.8b, September 2008. 51

The electricity penalty is calculated as the difference in net electricity generation between a “V” and corresponding “CCS” design, divided by the rate of CO2 capture in the “CCS” design.

35


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52

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Energy Plants: Volume 1: Bituminous Coal and Natural Gas to Electricity, Revision 2a, DOE/NETL-2010/1397, Pittsburgh, 2013. 53

National Energy Technology Laboratory, Cost and Performance Baseline for Fossil Energy Plants: Volume 1: Bituminous Coal and Natural Gas to Electricity, DOE/NETL2007/1281(Rev. 1), Pittsburgh, 2007. 54

This is our simulated result for an IGCC system using performance assumptions consistent

with those used for the CTG-PB-V results in Error! Reference source not found.. 55

Gonzalez, M.I.; Kraushaar-Czarnetzki, B.; Schaub, G. Biomass Conv. Bioref., 2011, 1, 229-243. 56

One would expect efficiency for the CBTG-RC system to be intermediate between the efficiencies for the CTG-RC and BTG-RC systems. This is not the case here because of an artifact of the Aspen modeling, which requires error bounds to be set on iteration loops. Because of the complexity of the systems modeled, setting convergence error bounds too tightly makes convergence for the overall flowsheet difficult to achieve. 57

In comparing alternative systems for providing low-carbon fuels, a fairer comparison would be of alternative systems having the same carbon footprints. Liu, et al. (2011)4 estimate that future cellulosic EtOH derived from switchgrass in a system with GHGI = 0.17 would require 2.49 MWLHV of dry biomass per MWLHV of gasoline equivalent. For comparison, the CBTG-RC-CCS option with 39% biomass and the CBTG-PB-CCS option with 25% biomass (discussed in detail later) have GHGI = 0.17. The required biomass inputs for those two cases are, respectively, 0.90 and 0.82 MWLHV of dry switchgrass per MWLHV of gasoline.

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or Biomass with CO2 ... - ACS Publications

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