1

Agreement #: FY10 Level: WBS #: Completion Date: Scheduled Completion: Platform Area: Analysis Title: Catalytic Fast Pyrolysis with Upgrading to Gasoline and Diesel Blendstocks Authors: Christopher Kinchin Participating R esearchers: Project Name: Project Leader: Strategic Analysis Andy Aden Key Words: Catalytic Fast Pyrolysis, GHG Emissions Reviewed By: Andy Aden 

## 1. Abstract An AspenPlus model was used to simulate catalytic fast pyrolysis of wood to bio - oil , and subsequent upgrading and separation to gasoline and diesel blendstocks . The results of the simulation show that catalytic fast pyrolysis yields about 50% less bio - oil than conventional fast pyrolysis, but more product gases, char, and water. The bio -oil from catalytic fast pyrolysis contains less oxygen than bio - oil from conventional fast pyrolysis, resulting in less chemical hydrogen consumption in the upgrading steps. The separation steps a re modeled as commercially available fl ash drums and distillation columns. Hydrogen production is modeled as a conventional steam methane reforming hydrogen plant. More gasoline is produced than diesel, which is in contrast to conventional fast pyrolysis. The major energy consumers are feedstock size reduction, the air blower for the char combustor, and hydrogen compression steps in the hydrotreating area . E xcess electricity is produced that can be sold to the electric grid. More research into catalytic fast pyrolysis, particularly upgradin g bio - oil derived from catalytic fast pyrolysis, is necessary for future analyses. An economic analysis was not performed. The purpose of this analysis is to support lifecycle modeling efforts by the Environmental Protection Agency (EPA). 

## 2. I ntroduction Biomass can be converted to infrastructure - compatible transportation fuels by several different thermochemical processes, such as gasification, pyrolysis, and liquefaction. Fast pyrolysis is a very promising thermal conversion technology because operating conditions are less severe (lower temperatures and pressures) than gasification and liquefaction. In fast pyrolysis, biomass is rapidl y heated, usually in less than one second, to about 500 °C at or slightly above atmospheric pressure . The2

rapid heating thermally decomposes biomass, converting it to pyrolysis vapor, which is later condensed to a liquid bio - oil. Fast pyrolysis is an economically promising technology for converting biomass t o liquid transportation fuels . However, commercial viability is c urrently limited due to undesirable characteristics of the bio - oil, such as high oxygen content and instability under storage and heating conditions (Lappas et. al. 2002) . Pyrolysis oil can be upgraded using hydroprocessing technology to improve these characteristics, however this increases the cost of the final product, and commercial hydroprocessing operations are usually geared towards removing sulfur rather than oxygen . Also, hydroproce ssing equipment is more commonly available at capacities on the scale of petroleum refineries rather than biorefineries. Catalytic fast pyrolysis has the potential to reduce expensive downstream hydroprocessing steps. An AspenPlus model has been developed to simulate a catalytic fast pyrolysis process and estimate the material and energy flows . This report describes the model and presents results. The results reported are limited to the conversion step of the supply chain (biomass to gasoline a nd diesel blend stocks ) and do not include energy inputs incurred in preceding or subsequent stages of the supply chain (feedstock production and logistics, product distribution , end use, etc . ) . The purpose of this analysis is to support lifecycle modeli ng efforts by the Environmental Protection Agency (EPA). T he Renewable Fuel Standard (RFS2) program under the Energy Independence and Security Act (EISA) of 2007 expands the required use of renewable fuels while requiring lifecycle greenhouse gas (GHG) pe rformance threshold standards to ensure that each category of renewable fuel emits fewer GHGs than the petroleum it replaces. T he EPA is performing a lifecycle assessment that includes the entire supply chain for pathways utilizing catalytic pyrolysis : fe edstock production and logistics, conversion, distribution, and end use. The results of the catalytic pyrolysis model reported here will provide the input and output data for the conversion (biomass to liquid fuel) step of the full lifecycle a ssessment. 

## 3. Methods and Results 3.1 Overview of Aspen Plus Catalytic Fast Pyrolysis Model To model a catalytic fast pyrolysis process, two previous modeling efforts a re modified and combined, one from the National Renewable Energy Laboratory ( NREL ) and one from Pacific Northwest National Laboratory ( PNNL ) . The NREL model, “Large - Scale Pyrolysis Oil Production: A Technological and Economic Assessment” (Ringer et. al. 2006), converts wood chips to bio - oil via conventional (non catalytic) fast pyrolysis. This mode l is modified such that the pyrolysis reactor, a circulating fluidized bed, circulates a zeolite catalyst in addition to olivine. Also, t he original NREL Fast Pyrolysis M odel produces bio - oil, but does not include additional downstream hydroprocessing and separation steps necessary to convert the bio -oil to finished transportation fuel. These additional downstream steps are added to the modified (catalytic) NREL Fast Pyrolysis Model. The additional downstream steps are based on a ChemCAD model developed by Sue3

Jones at PNNL, “Production of Gasoline and Diesel from Biomass via Fast Pyrolysis, Hydrotreating and Hydrocracking: A Design Case” (Jones et. al. 2009) . The combined AspenPlus model is divided into several areas, each of which is described in the following sections of this report. A simplified block flow diagram of the process is presented in Figure 1. Utilities such as electricity, steam pro duction, and cooling water are not included in Figure 1 but are included in the AspenPlus model.

Figure 1. Block flow diagram of the process. 

### 3. 2 Drying and Size Reduction Wood is received as chips at 50 wt% moisture. The wood chips are dried to 7 wt% moisture in a wood dryer using hot flue gas from downstream c ombustion processes (char combustor and natural gas furnaces in the h ydroprocessing section ) . The chips are then ground to a maximum diameter of 3 mm. The grinding process is not modeled in AspenPlus, although the power requirement is estimated at 50 kWh /ton (Ringer et. al. 2006). Small particle size is important in fast pyrolysis operations to ensure the entire wood particle is heated rapidly . S mall particle size reduces mass transfer effects, such as pyrolysis vapors in the particle interior encounter ing a char layer on the particle surface (Zhang et. al. 2009). The ground, dried wood is then sent to the pyrolysis reactor. Biomass Drying and Size

Reduction Dry

Biomass Catalytic Fast

Pyrolysis Bio - Oil Hydroprocessing Upgraded Bio - Oil Separation Gasoline Diesel

Water Hydrogen Recovery Unit Hydrogen Production Natural Gas H 2

H 2 PSA Tail Gas

Flue Gas

Combustion Exhaust Combustion Exhaust

Flue Gas H 2- Rich Fuel Gas4



### 3.3 Catalytic Fast Pyrolysis The catalytic step can take place in - situ (in the pyrolysis reactor) or in a separate vessel following the pyrolysis reactor. The in - situ design is used in this model , and is illustrated in Figure 2 . The pyrolysis reactor is a circulating fluidized bed reactor operat ing at 500 °C and 20 psia. B iomass is fed to the pyrolysis reactor, where it mi xe s with olivine and catalyst. Commercial operation may require olivine mixed with catalyst, or catalyst alone. The solids in the reactor are fluidized using recycled product gas. In the reactor the wood is converted to pyrolysis vapors, water vapor, no n - condensable product gases ( H 2, CO, CO 2, CH 4, etc.), char, coke, and ash. The solid pyrolysis products (char, coke, and ash) along with the olivine and catalyst are separated from the pyrolysis vapors, wat er vapor, and product gases in cyclone s . The so lid products are sent to a char combustor where the h eat for pyrolysis is generated by combusting char and coke in the char combustor, and recycling the hot olivine and catalyst back to the pyrolysis reactor. The pyrolysis vapors and water are cooled and q uenched in a multi - step process. The vapors and gases are first cooled and quenched using recycled , condensed bio -oil . Secondary recovery of uncondensed pyrolysis vapors occurs in a wet ESP (electrostatic precipitator).

Figure 2 . Circulating fluidized bed reactor system (Ringer et. al. 2006) The product yield of the catalytic pyrolysis reactor is the most significant modification to the NREL F ast P yrolysis M odel . Catalytic pyrolysis of biomass generally leads to the production of more water, char5

and product gases compared to conventional (non - catalytic) fast pyrolysis. However, the liquid product quality and composition is improved ( Lappas et . al . 2002 ). There are very few published results on catalytic pyrolysis of biomass, and there is c onsiderable variation among the published results . Therefore, t he overall product yield from the pyrolysis reactor is calculated by averaging the results of three literature sources that most closely resemble the process modeled in this report (Aho et. al. 2008, Lappas et. al. 2002, and Zhang et. al. 2009). The overall pyrolysis yields are presented in Table 1 , along with conventional fast pyrolysis yields reported in the PNNL Fast Pyrolysis design report (Jones et. al. 2009) . Table 1. Pyrolysis o il composition. Product Catalytic Fast Pyrolysis Yield (wt% of dry biomass) Conventional Fast Pyrolysis Yield * (wt% of dry biomass) Oil 32.7 65 Water 27.9 10 Gas 16.2 12 Char/Coke 20.5/2.7 13 *Jones et. al. 2009. Ash contents a re not reported in the literature sources use d to calculate the catalytic pyrolysis yields in Table 1, therefore the yields are on a non - ash basis . In the AspenPlus model the ash in the wood is assumed to be inert and passes through the pyrolysis reactor unchanged . Also, c har and coke are both combusted in the char combustor, therefore in t he AspenPlus model the coke yield is added to the char yield and both are treated as char. As can be seen in Table 1, c atalytic pyrolysis produces less bio -oil, but more water, product gas, and char/coke. The composition of the bio -oil changes as well. Catalytic fast pyrolysis produces bio -oil with less oxygen, and generally smaller hydrocarbon molecules. As a result, catalytic fast pyrolysis oil requires less downstream hydroprocessi ng than conventional fast pyrolysis oil. Also, the increased char yield improves the overall heat balance of the process because the heating value of the char and coke are recovered in the char combustor. 

### 3.3.1 Composition of the oil fraction All t hree literature sources report the composition of the oil fraction in terms of functional groups (aldehydes, acids, alcohols, ketones, phenols, polyaromatic hydrocarbons, etc.) but only one source, Aho et. al. 2008, lists the chemical compounds determined by ga s chromatography- mass spectroscopy (GCMS ). Therefore, the composition of the oil fraction in the AspenPlus model is based on results from Aho et. al. 2008. Unfortunately, BTX (benzene, toluene, xylene ) comp o unds are not included in the list of6

chemical compounds, therefore BTX compounds a re added to the list based on results from French and Czernik 2010. The composition of the oil fraction and yields of each compound used in the AspenPlus model are presented in Table 2.

Table 2 . Yield and c omposition of oil fraction in pyrolysis oil . Product Yield (wt% of dry biomass) Oil Composition (wt% of oil fraction ) Acids 1.37 4 . 18 Acetic Acid, Ethanoic Acid 1.37 4 . 18 2 - Butenoic Acid, Crotonic Acid 0 0 4 - Hydroxy- 3 - methoxy- benzeneacetic acid, Vanilacetic Acid 0 0 Alcohols 1.38 4 . 21 Ethylene Glycol, Ethylene Alcohol, 1,2 - Ethanediol 1.11 3 . 40 Glycerin, Glycerol, 1,2,3 - Propanetriol 0.17 0 . 51 Glycidol, 2,3 - Epoxy- 1 - Propanol 0 0 1,2 Benzenediol 0 0 1,4 - Benzenediol, Hydroquinone 0.10 0.29 Phenols 5.78 17. 66 Phenol, Carbolic Acid 0.20 0.61 2 - Methyl - phenol, O - Cresol 0.14 0.44 3 - Methyl - phenol, M - Cresol 0.11 0.34 4 - Methyl - phenol, P - Cresol 0.07 0.20 2 - Methoxy- phenol, Guaiacol 0.83 2.52 2,4 - Dimethyl - phenol, 2,4 -Xylenol 0.07 0.20 2 - Methoxy-4 - methyl - phenol 2.64 8.07 2 - methoxy-4 - propyl - phenol, 4 - Propylguaiacol 0.33 1.01 2 - methoxy-4 - (1 - propenyl) - phenol, Isoeugenol 1.40 4.27 Aldehydes 4.00 12 . 24 Glycol - aldehyde, hydroxyacetaldehyde 1.7 2 5 . 26 Pentanal, Valeraldehyde 0. 23 0 . 71 Furfural, 2 - Furancarboxaldehyde 0. 58 1 . 79 5 - methyl - 2 -furancarboxaldehyde, 5 - methylfurfural 0. 76 2 . 347

Product Yield (wt% of dry biomass) Oil Composition (wt% of oil fraction ) Isophthalaldehyde 0 0 4 - hydroxy- 3 - methoxy- benzaldehyde, Vanillin 0. 70 2 . 14 Ketones 9.44 28. 85 Acetol, 1 - Hydroxy- 2 - propanone 5.88 17 . 96 2 - Butanone, 1 - Hydroxy- 2 - butanone 0 0 2 - Cyclopenten - 1 -one, Cyclopentenone 0.71 2 . 16 2 - Methyl - 2 - cyclopenten - 1 -one 0.84 2 . 58 2 - Hydroxy- 3 - methyl - 2 - cyclopenten - 1 - one, Corylon 0 0 1 - (4 - Hydroxy- 3 - methoxyphenyl) - ethanone, Acetophenone, Acetovanillone 2.01 6 . 15 PAH's 3 .30 10. 08 Naphthalene 0.88 2.68 1 - Methylnaphthalene 1.53 4.69 Phenanthrene 0 0 Anthracene 0.14 0.44 2,7 - Dimethyl - naphthalene 0.52 1.60 1,7 - Dimethyl - naphthalene 0.09 0.27 1,4 - Dimethyl - naphthalene 0.08 0.24 1,4.5 -Trimethyl - naphthalene 0 0 1,4.6 -Trimethyl - naphthalene 0 0 1,6.7 -Trimethyl - naphthalene 0.06 0.17 BTX 6.62 20.23 Benzene 0.7 5 2.28 Toluene 3.7 3 11.42 Xylene 2.14 6.53 Other 0. 83 2.55 Levoglucosan, 1'6 -Anhydro - beta - D -glucopyranose 0.8 3 2.55 Total 32.7 2 100.008

Most of the chemical compounds reported in Aho et. al. 2008 are standard components in Aspen Plus. Compounds not available in AspenPlus are represented by a similar compound in the same functional group. 

### 3.3.2 Composition of product gas fraction The re is significant variation among literature sources regarding the total yield of the product gas fractio n ( non - condensable gases), but there i s general ly stro ng agreement regarding the composition of the product gas : it i s almost entirely CO and CO 2 . Lappas et. al. 2002 and Zhang et. al. 2009 provide the most detailed analysis of gas composition , therefore the composition of the gas product used in the Aspen m odel is calculated by averaging these two literature sources. The yield of each product gas component is calculated by multiplying its composition by the total gas product yield as reported in Table 1 of this report. Table 3 provides the composition and yields of the product gas.

Table 3 . Yield and composition of gas product fraction in pyrolysis product. Product Gas Yield

(wt% of dry biomass) Gas Composition (wt% of product gas ) CO 5.93 36.54 CO 2 7.86 48.40 CH 4 0. 40 2.49 H 2 0.0 3 0.18 C 2 H 4 0. 49 3.01 C 2 H 6 0. 15 0.92 C 3 H 6 0. 33 2.05 C 3 H 8 0. 15 0.95 NC4, n - Butane 0.00 0.00 C 5 's, n - Pentane 0.53 3.28 NC 6 's, n - Pentane 0. 35 2.18 Sum/Total 16 . 2 2 100.009



### 3.3.3 Catalyst All literature sources used to calculate the pyrolysis product composition use zeolite catalyst ZSM - 5 (Lappas and Aho) or HZSM - 5 (Zhang). The purpose of the catalyst is to remove oxygen from the pyrolysis vapors after they have formed, but before the y con dense, potentially eliminating or reducing downstream hydroprocessing requirements. The zeolite catalysts remove oxygen from the pyrolysis vapor mostly as water, but also as CO and CO 2 . The reaction route for the catalytic conversion of pyrolysis vapors is presented in Zhang et. al. 2009, and is reproduced in Figure 3 . Primary (conventional) fast pyrolysis occurs just as in a non - catalytic environment. The pyrolysis vapors are then catalytically cracked and partially deoxygenated before leaving the pyro lysis reactor.

Figure 3 . Catalytic conversion of pyrolysis vapors (Zhang et. al. 2009) 

### 3. 4 Hydrotreating Petroleum refineries generally use two stages of hydrotreating, as did the PNNL design report, therefore two stages a re used in the catalytic pyrolysis model . H owever, the product oil from catalytic pyrolysis may be sufficiently de oxygenated to require only one hydrotreating step. More research in to upgrading10

product oil from catalytic pyrolysis is necessary to confidently eliminate either hyd rotreating step from the model. The bio - oil is first pumped to 2500 psi a , mixed with hydrogen, and heated to 2 40 °C (465 °F) before entering the first hydrotreater. The product from the first hydrotreater is then heated to 371 °C (700 °F) in a furnace before entering the second hydrotreater, which operates at 2015 psi a . The furnace before the second hydrotreaters is fueled by natural gas and PSA tail gas from the hydrogen recovery section. The hydrotreated oil contains less than 2% oxygen. A block flow diagram of the h ydrotreating area is presented in Figure 4.

Figure 4 . Block flow diagram of the h ydrotreating area . The main objective of hydrotreating is to remove oxygen, sulfur, nitrogen, olefins and metals (Parkash 2003). In a petroleum refinery, hydrogen consumption is d ominated by sulfur removal. Pyrolysis oil, on the other han d, has much less sulfur but more oxygen . T herefore, in this model the hydrogen consumption is d ictated by oxygen removal. The chemical hydrogen consumption in the hydrotreating section in the PNNL Fast Pyrolysis design report is 5 . 0 lb/100 lb of dry oil. In the catalytic pyrolysis model the hydrogen consumption is reduced to 3.5 lb/lb of dry oil based on the reduced oxygen content in the oil. I t should be noted that the chemical hydrogen consumption includes only the hydrogen consumed in the hydrotreaters, but does not include hydrogen losses such as imperfect separation in the hydrogen recovery area. The amount of hydrogen fed to the hydrotrea ters is controlled to maintain a desired hydrogen partial pressure of 1200 psia (Parkash 2003) at the outlet of the second hydrotreater, which results in a large amount of unreacted hydrogen exiting the hydrotreaters. Hydrogen production and recovery is e xplained in more detail in the hydrogen production section of this report. A summary of the h ydrotreating conditions is presented in Table 4.

Pum p Bio - Oil

1 st Hyd rotreater 2 nd Hyd rotreater Furnace Natural Gas

Air Exhaust to Wood Dryer

Heat Exchanger H2

Upgraded Bio - Oil 122 F 30 psia 175 F 2500 psia 465 F 2500 psia 483 F 2500 psia 700 F 2500 psia 700 F 2015 psia

426 F 2015 psia11 Table 4. Hydrotreating Conditions Design Parameter 1 st Stage Hydrotreater 2 nd Stage

Hydrotreater Temperature, °C (°F ) 240 (465) 371 (700) Pressure, psi a 2500 2015 Total c hemical h ydrogen c onsumption, lb/100 lb dry bio -oil 3.54 Currently no literature sources report the product composition of hydrotreated bio - oil derived from catalytic pyrolysis, therefore an estimation was made based on the composition reported in the PNNL Fast Pyrolysis design report, although molecules greater than C 14 were excluded. For example, in the PNNL fast pyrolysis design report, very large molecules such as diamantane (C 1 8 H 24 ) are produced in the hydrotreating process. In the catalytic pyrolysis AspenPlus model, the largest molecules entering the hydrotreating process are anthracene and phenanthrene (both C 14 H 10 ), making large hydrotreating products such as diamantane unrealistic. Therefore, the composition of the hydrotreating product in the AspenPlus model matches the composition of the hydrotreating product in the PNNL model, excluding products greater than C 14 . The composition of the hydrotreating produ ct in the PNNL Fast Pyrolysis design report is based on data from Elliot 2007 and Beckman et. al. 1990. The hydrotreating product stream is then scaled to maintain overall mass balance, and the composition of the gas products (CO and CO 2 ) are adjusted sli ghtly to maintain overall element balances. Admittedly this is not an ideal strategy for predicting the composition of the hydrotreating product, but until published results are available it provides a reasonable first estimate. 

### 3. 5 Separation The upgraded bio -oil from the hydrotreating area is separated into off-gas, wastewater, and stabilized oil streams in a series of flash d rums. The off-gas is sent to the hydrogen recovery unit (HRU) where hydrogen is recovered and recycled to the hydrotreaters. Anaerobic digestion can be used to treat the less than 2% organics in the wastewater (Jones et. al. 2009) although the anaerobic digestion is not modeled for this report. If the anaerobic digestion is on - site, enough biogas can be produce d to replace all the natural gas used as fuel (combusted), and about half the natural gas fed to the steam methane reformer (SMR) in the hydrogen production area. Feeding biogas to a steam methane reformer is currently not practiced commercially, therefore it is not modeled for thi s report but is an attractive source of renewable methane and may be included in future design cases.12

The upgraded bio -oil is further separated into light hydrocarbon (C 4 and smaller) , gasoline, and diesel streams in a series o f distillation columns. The first distillation column operates similar to a debutanizer in a petroleum refinery. It removes all C4 and smaller components, which are used as fuel gas in the facility. Most petroleum refineries separate C4 molecules from C 3 and smaller molecules, then send the C4 stream to an alkylation unit to make iso -octane. These additional separation and alkylation steps are economically justified only if the C 4 components in the debutanizer distillate stream are produced in very large volumes. For this model, the distillate stream from the debutanizer is small enough that further separation and alkylation is probably not economically justified, therefore it is simply used as fuel gas elsewhere in the conversion facility. T his assum ption has not been tested, but may be the subject of a sensitivity study in further work. The l iquid product from the debutanizer is sent to a second distillation column, the nap h tha splitter, where gasoline range components are separated from heavier d iesel range components. Both gasoline and diesel are sent to product storage. In the non - catalytic PNNL Fast Pyrolysis design, components heavier than diesel require hydrocracking and an additional separation column. This highlights one of the advantages of catalytic pyrolysis: the heavy (greater than diesel range) components are eliminated or reduced to very small amou nts, eliminating the need for hydro cracking, although i t should again be noted t here is very little published research dedicated to upgrading bio - oil from catalytic pyrolysis . E liminating the hydrocracking step in this model is a design assumption based o n the composition of pyrolysis oil entering the hydrotreating section . Another consequence of the lack of published data is confidence in the composition and yield of the final products in the AspenPlus model. The yields of the catalytic pyrolysis step are based on literature values, therefore the re is more confidence in the overall volumetric yields of gasoline and diesel than in the composition of the gasoline and diesel products. T he final product s are gasoline and diesel blendstock, which will need to be blended with blendstocks from other refineries to achieve desired gasoline and diesel characteristics. 

### 3. 6 Hydrogen Production and Recovery As explained in the separations section, the upgraded bio - oil leaving the hydrotreating area is separated into off-gas, wastewater, and stabilized oil streams in a series of flash drums. The off-gas is sent to the hydrogen recovery unit (HRU) where excess hydrogen is recovered and recycled to the hydrotreaters. Makeup hydrogen is produced via steam methane reforming and pressure swing adsorption (PSA) separation . The hydrogen recovery and hydrogen production areas are not modeled in detail, but rather are modeled based on design rules taken from literature ( Parkesh 2003 for hydrogen recovery; Spath and Mann 2001 for hydrogen production ). For the hydrogen recovery area, u tilities such as natural gas consumed as fuel and feed, and electricity and steam demand are scaled based on the amount of hydrogen entering the hydrogen recovery area. For hydrogen product ion, the utilities are based on the amount of makeup hydrogen produced . Figure 5 (reproduction of Figure 1) illustrates the integration of13

the hydrogen recovery and hydrogen production areas into the rest of the model. Figure 6 is a block flow diagram of the hydrogen production area (Spath and Mann 2001). Tables 5 and 6 provide utility demands and operating parameters for the hydrogen recovery area and hydrogen production area, respectively.

Figure 5. Block flow diagram of the process. Biomass Drying and Size

Reduction Dry

Biomass Catalytic Fast

Pyrolysis Bio - Oil Hydroprocessing Upgraded Bio - Oil Separation Gasoline Diesel

Water Hydrogen Recovery Unit Hydrogen Production Natural Gas H 2

H 2 PSA Tail Gas

Flue Gas

Combustion Exhaust Combustion Exhaust

Flue Gas H 2- Rich Fuel Gas14

Table 5. Hydrogen recovery area utility demands and performance data (Parkesh 2003). Design Parameter Data Electricity demand, kWhr per ton of feed 1 . 08 Steam demand, mmBtu per ton of feed 2.25 Cooling water, gallons per ton of feed 13,240 Hydrogen recovery, percent of H2 in feed 83% Product hydrogen purity > 99 %

Figure 6 . Block flow diagram of the hydrogen production area (Spath and Mann, 2001) . Steam - Methane Reformer (SMR) Natural Gas Feedstock Hydrogenation

PSA Offgas ZnO Bed

High Temperature Shift (HTS) Steam Water

Pressure Swing Adsorption (PSA) H 2

H 2 Low Temperature Shift (LTS)

Steam Flue G as

Natural Gas Fuel15 Table 6 . Hydrogen Production Plant Data (Spath and Mann , 2001). Design Parameter Data Electricity demand, kWhr/lb H2 0.14 Steam demand, lb/lb H2, @380 psi 9.6 Steam demand p roduction, lb/lb H2, @700 psi 13.8 Natural gas consumed as fuel, lb/lb H2 0.32 Natural gas consumed as feed, lb/lb H2 2.91 Product hydrogen purity > 99 % 

### 3. 7 Utilities: Steam and Power Production , Cooling Water Char and product gas from the pyrolysis step are combusted to generate steam in a waste hea t boiler . Excess steam is also generated in the hydrogen production area. The steam is then used to generate electricity i n a steam turbine, with exc ess electricity that can be sold to the grid. The major consumers of electricity are wood grinding in the feed handling area , the air blower for the char combustor, and hydrogen compression steps in the hydrotreating area. Other consumers of electricity are the electrostatic precipitator and pumps for boiler water, cooling water, bio - oil and fuel product. An estimate of 700 kW for miscellaneous power usage, such as lighting and administrative areas, i s added (Phillips et. al. 2007). Cooling water is used to condense boiler water and cool raw pyrolysis o il. Cooling water is supplied to the process at 90°F, and returns to the cooling tower at 110°F. The cooling tower is not modeled in detail, although the power requirements for pumps and fans are esti mated using design equations. Natural gas is consumed as feed and fuel in the hydrogen production area, and also as furnace fuel in the hydrotreating area. Table 7 provides utility performance and operating data for electricity, water, and natural gas.16 Table 7. Utility performance and operating data . Design Parameter Data Excess e lectricity produced , kWhr/gal fuel product 0. 48 Boiler water makeup rate, gal/gal fuel product 0.1 Cooling water makeup rate, gal /gal fuel product 6 . 1 Total water makeup rate, gal/gal fuel product 6.2 Natural gas consumed as fuel for H2 production , scf /gal fuel product 4.7 Natural gas consumed as feed for H2 production, scf/gal fuel product 42.4 Natural gas consumed as fuel for hydrotreater furnace, scf/gal fuel product 4.8 Total natural gas consumed, scf/gal fuel product 51. 9 As can be seen in Table 7, excess electricity is produced although the total water makeup rate is high. In future revisions of the model, water cooling can be substituted with air cooling (powered by electric fans) , which will result in less excess electricity but reduced water demand. 

## 4. Conclusions and Recommendat ions AspenPlus i s used to model catalytic fast pyrolysis for gasoline and diesel production. Product yields and utility demands a re estimated, although no economic analysis i s performed. A summary of the process yields and efficiencies is presented in Table 8. Key findings of the analysis include:

 Catalytic fast pyrolysis produces less bio - oil but more water, gas, and char than conven tional, non - catalytic fast pyrolysis .  Catalytically pro duced pyrolysis oil is partially deoxygenated, which resu lts in less hydrogen required for upgrading. The chemical hydrogen consumption required to upgrade bio -oil derived from catalytic fast pyrolysis is 3.5 lb/lb of dry bio - oil, compared to 5.0 lb/lb of dry bio - oil for non - catalytic fast pyrolysis oil.  Non - catalytic fast pyrolysis produces bio - oil conducive to manufacturing mostly diesel and jet fuel range transportation fuels, with some gasoline - range product . Conversely, catalytic fast pyrolysis produ ces bio - oil with a composition slightly more favorable to manufacturing gasol ine . In the AspenPlus model, 54% of the final product is gasoline.17

 Due to very limited amount of published data on catalytic fast pyrolysis, particularly upgrading bio - oil prod uced from catalytic fast pyrolysis, t here is a great deal of uncertainty regarding the composition of the final products.  The composition of the bio - oil suggests hydrocracking is not necessary. According to literature sources, bio - oil produced from catalytic fast pyrolysis is comprised of molecules in the diesel range and smaller.  The major electricity consumers are wood grinding in the feed handling area, the combustion air blower for the char combustor, and hydrogen compression steps in the hydrotreating area, although excess electricity is produced and can be sold to the electric grid.  Because hydrogen is required for upgrading, natural gas is purchased for use as fuel and feed for hydrogen production and recovery, therefore the facility is not free of fossil fuel consumption, as is the case in biomass gasification followed by mixed alcohol synthesis (Phillips et. al. 2007) .

Table 8 . Overall plant performance and operating data. Design Parameter Data Gasoline b lendstock yield , gallons/ton of biomass 34.8 Diesel blendstock yield , gallons/ton of biomass 29.7 Total fuel product yield , gallons/ton of biomass 64.5 Gasoline blendstock yield , mmBtu/ton of biomass 4.2 Diesel blendstock yield , mmBtu/ton of biomass 4.1 Total fuel product yield , mmBtu/ton of biomass 8.3 Gasoline blendstock heating value , mmBtu/gal 0.12 Diesel blendstock heating value , mmBtu/gal 0.14 Total fuel product (weighted average), mmBtu/gal 0.13 Electricity produced, kWhr/gal fuel product 0. 48 Total water makeup rate, gal/gal fuel product 6.2 Natural gas combusted, scf/gal fuel product 9.5 Total natural gas consumed, scf/gal fuel product 51. 9 Overall plant efficiency, LHV% 46.5 Overall plant efficiency (w/out excess electricity), LHV% 45.918

To achieve higher confidence in the results, more research into catalytic fast pyrolysis and upgrading bio - oil derived from catalytic fast pyrolysis is needed . Additional data from laboratory experiments will help, although data from continuous bench or pilot scale operations would be ideal. S ensitivity analysis on several process variables can be explored:

 Size reduction of the incoming biomass consumes a very large amount of electricity, therefore understanding the power curves and the maximum particle size required is cr ucial to correctly estimating and minimizing the power required.  Hydrogen is separated from other components (CO, CO 2, etc.) in the hydrogen recovery area, although the pressure is reduced and later must be re - pressurized. If the hydrogen remains at hydrotreating pressures and is simply recycled, with a purge stream to prevent buildup of C O and CO 2, the energy- intensive compression step can be eliminated, but at the expense of less pure hydrogen. Refineries often operate in this configuration. Also, a n economic analysis of the process will provide a first estimate of minimum selling price, as well as identify opportunities and areas of focus for cost reduction. 

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