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 Researchers:

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 are modeled as commercially available flash 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. Excess electricity is produced that can be sold to the electric grid. More 

research into catalytic fast pyrolysis, particularly upgrading 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. Introduction

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 rapidly 

heated, usually in less than one second, to about 500 °C at or slightly above atmospheric pressure. The 
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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 to liquid transportation 

fuels. However, commercial viability is currently 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, hydroprocessing 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 and 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 modeling efforts by the Environmental Protection 

Agency (EPA). The 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) performance threshold standards to ensure that each category of renewable fuel 

emits fewer GHGs than the petroleum it replaces. The EPA is performing a lifecycle assessment that 

includes the entire supply chain for pathways utilizing catalytic pyrolysis: feedstock 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 assessment.

3. Methods and Results

3.1 Overview of AspenPlus Catalytic Fast Pyrolysis Model

To model a catalytic fast pyrolysis process, two previous modeling efforts are 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 (noncatalytic) fast pyrolysis. This model is modified such that the pyrolysis reactor, a circulating fluidized 

bed, circulates a zeolite catalyst in addition to olivine. 

Also, the original NREL Fast Pyrolysis Model 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 Sue 
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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 production, 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 combustion processes (char combustor and natural gas 

furnaces in the hydroprocessing 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. Small particle size reduces mass transfer effects, such as pyrolysis 

vapors in the particle interior encountering 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

H2

H2

PSA Tail Gas

Flue Gas

Combustion Exhaust

Combustion Exhaust

Flue Gas

H2-Rich Fuel Gas
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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 operating at 500 °C and 20 psia. Biomass is fed to the 

pyrolysis reactor, where it mixes 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, non-condensable product gases 

(H2, CO, CO2, CH4, 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, water vapor, and product gases in cyclones. The solid products are sent to a char 

combustor where the heat 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 quenched 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 Fast 

Pyrolysis Model. Catalytic pyrolysis of biomass generally leads to the production of more water, char
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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 considerable variation among the published results. 

Therefore, the 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 oil 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 are not reported in the literature sources used 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, char and coke are both 

combusted in the char combustor, therefore in the AspenPlus model the coke yield is added to the char 

yield and both are treated as char. 

As can be seen in Table 1, catalytic 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 hydroprocessing 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 three 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 gas 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) compounds are not included in the list of 
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chemical compounds, therefore BTX compounds are 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 composition 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 1.72 5.26

Pentanal, Valeraldehyde 0.23 0.71

Furfural, 2-Furancarboxaldehyde 0.58 1.79

5-methyl-2-furancarboxaldehyde, 5-methylfurfural 0.76 2.34
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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 0.75 2.28

Toluene 3.73 11.42

Xylene 2.14 6.53

 Other 0.83 2.55

Levoglucosan, 1'6-Anhydro-beta-D-glucopyranose 0.83 2.55

Total 32.72 100.00
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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

There is significant variation among literature sources regarding the total yield of the product gas

fraction (non-condensable gases), but there is generally strong agreement regarding the composition of 

the product gas: it is almost entirely CO and CO2. 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 model 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

CO2 7.86 48.40

CH4 0.40 2.49

H2 0.03 0.18

C2H4 0.49 3.01

C2H6 0.15 0.92

C3H6 0.33 2.05

C3H8 0.15 0.95

NC4, n-Butane 0.00 0.00

C5's, n-Pentane 0.53 3.28

NC6's, n-Pentane 0.35 2.18

Sum/Total 16.22 100.00
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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 they condense, potentially eliminating or reducing 

downstream hydroprocessing requirements. The zeolite catalysts remove oxygen from the pyrolysis 

vapor mostly as water, but also as CO and CO2. 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 pyrolysis 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 are used in the catalytic pyrolysis model. However, the product oil from catalytic pyrolysis 

may be sufficiently deoxygenated to require only one hydrotreating step. More research into upgrading 
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product oil from catalytic pyrolysis is necessary to confidently eliminate either hydrotreating step from 

the model.

The bio-oil is first pumped to 2500 psia, mixed with hydrogen, and heated to 240 °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 psia. 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 hydrotreating area is 

presented in Figure 4.

Figure 4. Block flow diagram of the hydrotreating area.

The main objective of hydrotreating is to remove oxygen, sulfur, nitrogen, olefins and metals (Parkash 

2003). In a petroleum refinery, hydrogen consumption is dominated by sulfur removal. Pyrolysis oil, on 

the other hand, has much less sulfur but more oxygen. Therefore, in this model the hydrogen 

consumption is dictated 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. It 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 hydrotreaters 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 explained in more detail in the hydrogen production section of this 

report. A summary of the hydrotreating conditions is presented in Table 4. 

Pump

Bio-Oil

1

st Hydrotreater 2nd Furnace Hydrotreater

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 psia
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Table 4. Hydrotreating Conditions

Design Parameter 1

st Stage 

Hydrotreater

2

nd Stage 

Hydrotreater

Temperature, °C (°F ) 240 (465) 371 (700)

Pressure, psia 2500 2015

Total chemical hydrogen consumption, 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 C14 were excluded. For example, in the 

PNNL fast pyrolysis design report, very large molecules such as diamantane (C18H24) are produced in the 

hydrotreating process. In the catalytic pyrolysis AspenPlus model, the largest molecules entering the 

hydrotreating process are anthracene and phenanthrene (both C14H10), 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 C14. The composition of the hydrotreating product 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 CO2) are adjusted slightly 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 drums. 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 produced 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 this report but is an attractive 

source of renewable methane and may be included in future design cases. 
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The upgraded bio-oil is further separated into light hydrocarbon (C4 and smaller), gasoline, and diesel 

streams in a series of 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 C3 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 C4 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. This assumption has not been tested, but may be the 

subject of a sensitivity study in further work. 

The liquid product from the debutanizer is sent to a second distillation column, the naphtha splitter, 

where gasoline range components are separated from heavier diesel 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 amounts, 

eliminating the need for hydrocracking, although it should again be noted there is very little published 

research dedicated to upgrading bio-oil from catalytic pyrolysis. Eliminating the hydrocracking step in 

this model is a design assumption based on 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 there is more confidence in the overall volumetric yields of gasoline and diesel than in 

the composition of the gasoline and diesel products. The final products 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, utilities 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 production, the utilities are based on the 

amount of makeup hydrogen produced. Figure 5 (reproduction of Figure 1) illustrates the integration of 
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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

H2

H2

PSA Tail Gas

Flue Gas

Combustion Exhaust

Combustion Exhaust

Flue Gas

H2-Rich Fuel Gas
14

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)

H2

H2

Low 

Temperature 

Shift (LTS)

Steam Flue Gas

Natural 

Gas Fuel
15

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 production, 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 heat boiler. 

Excess steam is also generated in the hydrogen production area. The steam is then used to generate 

electricity in a steam turbine, with excess 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, is added 

(Phillips et. al. 2007). 

Cooling water is used to condense boiler water and cool raw pyrolysis oil. 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 estimated 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.

 
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Table 7. Utility performance and operating data.

Design Parameter Data

Excess electricity 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 Recommendations

AspenPlus is used to model catalytic fast pyrolysis for gasoline and diesel production. Product yields and 

utility demands are estimated, although no economic analysis is 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 conventional, 

non-catalytic fast pyrolysis.

 Catalytically produced pyrolysis oil is partially deoxygenated, which results 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 produces bio-oil with a composition slightly more favorable to manufacturing gasoline. 

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 produced from catalytic fast pyrolysis, there 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 blendstock 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% 45.9
18

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. 

Sensitivity 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 crucial to correctly 

estimating and minimizing the power required.

 Hydrogen is separated from other components (CO, CO2, 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 CO 

and CO2, the energy-intensive compression step can be eliminated, but at the expense of less 

pure hydrogen. Refineries often operate in this configuration.

Also, an 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.

5. References

Aho et. al. 2008. “Catalytic pyrolysis of woody biomass in a fluidized bed reactor: Influence of zeolite 

structure”. Aho, A.; N. Kumar; K. Eranen; T. Salmi; M. Hupa; D. Yu. Murzin. Fuel 87 (2008) 2493-2501.

Beckman et. al. 1990. “Techno-economic Assessment of Selected Biomass Liquefaction Processes”. 

Beckman, D; D.C. Elliot; B. Gevert; C. Hornel; B. Kjellstrom; A. Ostman; Y. Solantausta; V. Tulnheimo. 

Research Report 697, VTT Technical Research Centre of Finland.

Elliot 2007. “Historical Developments in Hydrotreating Bio-Oils”. Elliot, D.C. Energy and Fuels 2007, 21, 

1792-1815. 

French and Czernik 2008. “Catalytic pyrolysis of biomass for fuels production”. French, Rick; Stefan 

Czernik. Fuel Processing Technology 91 (2010) 25-32.

Lappas et. al. 2002. “Biomass pyrolysis in a circulating fluid bed reactor for the production of fuels and 

chemicals”. Lappas, A.A.; M.C. Samolada; D.K. Iatridis; S.S. Voutetakis; I.A. Vasalos. Fuel 81 (2002) 2087-

2095.

Parkash 2003. “Refining Process Handbook”. Pakash, Surinder. Gulf Professional Publishing/Elsevier, 

Burlington, MA. 2003.

Phillips et. al. 2007. “Thermochemical Ethanol via Indirect Gasification and Mixed Alcohol Synthesis of 

Lignocellulosic Biomass”, Phillips, S.; A. Aden; J. Jechura; D. Dayton; T. Eggeman. April 2007. NREL 

Technical Report NREL/TP-510-41168. 
19

Jones et. al. 2009. “Production of Gasoline and Diesel from Biomass via Fast Pyrolysis; Hydrotreating 

and Hydrocracking: A Design Case”. Jones, SB; C. Valkenburg; C. Walton; D.C. Elliot; J.E. Holladay; D.J. 

Stevens; C. Kinchin; and S. Czernik. Pacific Northwest National Laboratory Report PNNL-18284 Rev. 1. 

February 2009. http://www.pnl.gov/main/publications/external/technical_reports/PNNL-18284.pdf

Ringer et. al. 2006. “Large-Scale Pyrolysis Oil Production: A Technology Assessment and Economic 

Analysis”. Ringer, M.; V. Putsche; J. Scahill. NREL Technical Report NREL/TP-510-37779. November 

2006. http://www.nrel.gov/docs/fy07osti/37779.pdf

Spath and Mann 2001. “Life Cycle Analysis of Hydrogen Production via Natural Gas Steam Reforming”. 

Spath, P. L.; M. K. Mann. National Renewable Energy Laboratory Technical Report NREL/TP-570-27637. 

February 2001. http://www.nrel.gov/docs/fy01osti/27637.pdf

Zhang et. al. 2009. “Comparison of non-catalytic and catalytic fast pyrolysis of corncob in a fluidized bed 

reactor”. Zhang, Huiyan; Rui Xiao; He Huang; and Gang Xiao; Bioresource Technology 100 (2009) 1428-

1434.