NREL is a national laboratory of the U.S. Department of Energy, Office of Energy 

Efficiency & Renewable Energy, operated by the Alliance for Sustainable Energy, LLC.

Contract No. DE-AC36-08GO28308

Techno-Economic Analysis of 

Biomass Fast Pyrolysis to 

Transportation Fuels

Mark M. Wright, Justinus A. Satrio, and 

Robert C. Brown

Iowa State University

Daren E. Daugaard

ConocoPhillips Company

David D. Hsu

National Renewable Energy Laboratory

Technical Report

NREL/TP-6A20-46586

November 2010
NREL is a national laboratory of the U.S. Department of Energy, Office of Energy 

Efficiency & Renewable Energy, operated by the Alliance for Sustainable Energy, LLC.

National Renewable Energy Laboratory

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Golden, Colorado 80401

303-275-3000 • www.nrel.gov

Contract No. DE-AC36-08GO28308

Techno-Economic Analysis of 

Biomass Fast Pyrolysis to 

Transportation Fuels

Mark M. Wright, Justinus A. Satrio, and 

Robert C. Brown

Iowa State University

Daren E. Daugaard

ConocoPhillips Company

David D. Hsu

National Renewable Energy Laboratory

Prepared under Task No. BB07.7510

Technical Report

NREL/TP-6A20-46586

November 2010
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iii

Foreword

The purpose of this techno-economic analysis is to determine the economics of converting 

biomass to transportation fuel components via fast pyrolysis. Every effort has been made to place

this analysis on an equivalent basis with other biomass conversion technologies analyzed in 

separate reports by using common assumptions. The process design and parameter value choices 

underlying this analysis are exclusively based on public domain literature. Accordingly, the

results should not be interpreted as optimal performance of mature technology, but as the most 

likely performance given the current state of public knowledge.
iv

Acknowledgments

This study was made possible by support from ConocoPhillips Company under project number 

2007-P-01 and from the National Renewable Energy Laboratory. We would like to acknowledge 

the U.S. Department of Energy Office of Energy Efficiency and Renewable Energy’s Biomass 

Program. We appreciate the helpful comments of Andy Aden, Christopher Kinchin, and Mary 

Biddy from NREL, and Richard Jefferys and Lou Burke from ConocoPhillips Company.
v

List of Acronyms

ASPEN Advanced Simulator for Process Engineering (software)

bbl barrel

BTU British thermal unit

DB declining balance

DOE U.S. Department of Energy

ESP electrostatic precipitator

GGE gallons of gasoline equivalent

IC indirect costs

IRR internal rate of return

IRS Internal Revenue Service

MACRS (IRS) Modified Accelerated Cost Recovery System

MM million

MT metric ton

NCG non-condensable gas

NREL National Renewable Energy Laboratory

PV product value

TEIC total equipment installed cost

TPI total project investment

USDA U.S. Department of Agriculture

VOCs volatile organic compounds
vi

Executive Summary

The purpose of this study is to develop techno-economic models for assessment of the 

conversion of biomass to valuable fuel products via fast pyrolysis and bio-oil upgrading. 

Liquefaction of biomass by fast pyrolysis and subsequent upgrading of the resulting pyrolysis oil 

(bio-oil) by hydrotreating and hydrocracking—refinery processes that use hydrogen to remove 

impurities and break large molecules down to smaller ones—is a promising means for producing 

renewable transportation fuel. The upgrading process assessed in this study produces a mixture 

of naphtha-range (gasoline blend stock) and diesel-range (diesel blend stock) products. This 

study develops techno-economic models and uses them to analyze the economics of two 

scenarios. In one, hydrogen needed for the upgrade process is produced onsite by reforming biooil. In the other, the hydrogen is purchased from an outside source. 

Both scenarios are based on a fast pyrolysis plant with bio-oil upgrading using 2,000 metric tons 

per day (MT/day) of corn stover feedstock. Major assumptions made for this analysis match 

those of companion analyses for producing transportation fuel from biomass via biochemical and 

gasification technologies. Product value—defined as the value of the product needed for a net 

present value of zero with a 10% internal rate of return—is first calculated for a mature industry 

or nth plant and then adjusted for a pioneer plant or one of the first of its kind. 

The study results indicate that petroleum fractions in the naphtha distillation range and in the 

diesel distillation range are produced from corn stover at a product value of $3.09/gal 

($0.82/liter) with onsite hydrogen production or $2.11/gal ($0.56/liter) with hydrogen purchase. 

These values correspond to a $0.83/gal ($0.21/liter) cost to produce the bio-oil. Based on these 

nth plant numbers, product value for a pioneer hydrogen-producing plant is about $6.55/gal

($1.73/liter) and for a pioneer hydrogen-purchasing plant is about $3.41/ gal ($0.92/liter). 

Although these results suggest that pyrolysis-derived biofuels are competitive with other 

alternative fuels, the technology is relatively immature, resulting in a high level of uncertainty in 

these estimates.

Capital costs for integrated hydrogen production are estimated at $287 million with a fuel yield

of 35 million gallons (134 million liters) of naphtha-range and diesel-range products per year. 

Capital costs with purchased hydrogen are estimated at $200 million with a fuel yield of 58 

million gallons (220 million liters) of naphtha-range and diesel-range products per year.

Sensitivity analysis identifies fuel yield as a key variable for the hydrogen-production scenario. 

A 5% decrease in the bio-oil to naphtha and diesel fuel yields increases fuel costs by $0.80/gal ( 

$0.21/liter) for the hydrogen production scenario and $0.27/gal ($0.07/liter) for the hydrogen

purchase scenarios. Biomass cost is important for both scenarios. Changing feedstock cost from

$50–$100 per short ton changes the price of fuel in the hydrogen production scenario from 

$2.57–$3.62/gal ($0.68–$0.96/liter).
vii

Table of Contents

Background ................................................................................................................................................. 1

Model and Process Description ................................................................................................................ 2

Design Basis................................................................................................................................................ 4

Chopping/Grinding ....................................................................................................................6

Drying ........................................................................................................................................7

Pyrolysis.....................................................................................................................................7

Cleanup ......................................................................................................................................9

Oil Collection.............................................................................................................................9

Storage .....................................................................................................................................10

Combustion..............................................................................................................................10

Hydroprocessing ......................................................................................................................10

Economics................................................................................................................................12

Sensitivity Analysis .................................................................................................................14

Pioneer Plant Analysis.............................................................................................................14

Results ....................................................................................................................................................... 16

Hydrogen-Production Scenario................................................................................................17

Hydrogen-Purchase Scenario...................................................................................................21

Conclusions............................................................................................................................................... 24

References................................................................................................................................................. 25

Appendix A. Equipment Cost and Description ...................................................................................... 28

Appendix B. Aspen Plus Software Mass Flow and Balance Results and Process Flow Diagrams . 33

Appendix C. Selection Process of Pyrolysis Reactor Technologies for Further Analysis under Iowa 

State University/ConocoPhillips Company/National Renewable Energy Laboratory 

Collaborative Study............................................................................................................................ 48

Appendix D. Assumptions for Pyrolysis Technologies Techno-Economic Studies.......................... 51
viii

List of Figures

Figure 1. Fast pyrolysis oil costs from previous biomass fast pyrolysis studies [1-7] adapted for 

inflation from Ringer et al. [8]........................................................................................................ 1

Figure 2. Combined biomass fast pyrolysis and hydrogen production/purchase upgrading process 

diagram ........................................................................................................................................... 3

Figure 3. Upgrading of pyrolysis oil to naphtha-range and diesel-range products....................... 11

Figure 4. Comparison of process energy flows for 2,000 MT/day biomass fast pyrolysis and 

upgrading [33, 34]......................................................................................................................... 17

Figure 5. Sensitivity analysis for 2,000 MT/day hydrogen-production fast pyrolysis and 

upgrading scenario........................................................................................................................ 20

Figure 6. Sensitivity analysis for 2,000 MT/day hydrogen-purchase fast pyrolysis and upgrading 

scenario ......................................................................................................................................... 23

Figure B-1. Biomass chopping process flow diagram (PFD)....................................................... 34

Figure B-2. Biomass drying PFD.................................................................................................. 34

Figure B-3. Biomass pyrolysis PFD ............................................................................................. 36

Figure B-4. Pyrolysis gas cleaning PFD....................................................................................... 38

Figure B-5. Bio-oil recovery PFD ................................................................................................ 40

Figure B-6. Bio-oil reforming and hydroprocessing PFD ............................................................ 42
ix

List of Tables

Table 1. Process Model Sections, Descriptions, and Key Assumptions......................................... 4

Table 2. Corn Stover Ultimate and Proximate Analysis [14]......................................................... 5

Table 3. Char Ultimate and Proximate Analysis [15]..................................................................... 5

Table 4. Corn Stover (2,000 MT/day) Fast Pyrolysis Scenarios .................................................... 6

Table 5. Corn Stover Fast Pyrolysis Yields.................................................................................... 8

Table 6. Pyrolysis Product Composition ........................................................................................ 8

Table 7. Pyrolysis Lignin Hydrotreating/Hydrocracking Yield [9].............................................. 11

Table 8. Pyrolysis Oil Hydrotreating/Hydrocracking Yields [10]................................................ 12

Table 9. Sensitivity Analysis Parameters for Fast Pyrolysis and Upgrading ............................... 14

Table 10. Description of Pioneer Plant Analysis Parameters....................................................... 15

Table 11. Selected Pioneer Plant Analysis Parameters for Biomass Fast Pyrolysis and Upgrading

....................................................................................................................................................... 16

Table 12. Summary of nth Plant Cost Results............................................................................... 16

Table 13. Capital Costs for 2,000 MT/day Hydrogen-Production Fast Pyrolysis and Upgrading 

Scenario......................................................................................................................................... 18

Table 14. Operating Costs for 2,000 MT/day Hydrogen-Production Fast Pyrolysis and Upgrading 

Scenario......................................................................................................................................... 19

Table 15. Pioneer Analysis for 2,000 MT/day Hydrogen-Production Fast Pyrolysis and 

Upgrading Scenario ...................................................................................................................... 21

Table 16. Capital Costs for 2,000 MT/day Hydrogen-Purchase Fast Pyrolysis and Upgrading 

Scenario......................................................................................................................................... 21

Table 17. Operating Costs for 2,000 MT/day Hydrogen-Purchase Fast Pyrolysis and Upgrading 

Scenario......................................................................................................................................... 22

Table 18. Pioneer Analysis for 2,000 MT/day Hydrogen-Purchase Fast Pyrolysis and Upgrading 

Scenario......................................................................................................................................... 24

Table A-1. Equipment Costs for Fast Pyrolysis and Bio-Oil Upgrading with Hydrogen 

Production..................................................................................................................................... 28

Table A-2. Equipment Costs for Fast Pyrolysis and Bio-Oil Upgrading with Hydrogen Purchase

....................................................................................................................................................... 31

Table B-1. Aspen Plus Software Section Mass and Mole Balances............................................. 33

Table B-2. Stream Table for Biomass Drying .............................................................................. 35

Table B-3. Stream Table for Biomass Pyrolysis........................................................................... 37

Table B-4. Stream Table for Pyrolysis Gas Cleaning................................................................... 39

Table B-5. Stream Table for Bio-Oil Recovery............................................................................ 41

Table B-6. Stream Table for Bio-Oil Reforming and Hydroprocessing....................................... 43

Table D-1. Biomass Pyrolysis/Torrefaction Design Matrix ......................................................... 55

Table D-2. Hydrogen-Production Scenario Discounted Cash Flow Rate of Return Worksheet.. 56

Table D-3. Hydrogen-Purchase Scenario Discounted Cash Flow Rate of Return Worksheet ..... 58

Table D-4. Hydrogen-Production Scenario Detailed Operating Cost Analysis ........................... 60

Table D-5. Hydrogen-Purchase Scenario Detailed Operating Cost Analysis............................... 61

Table D-6. Hydrogen-Production Scenario Detailed Capital Investment Analysis ..................... 62

Table D-7. Hydrogen-Purchase Scenario Detailed Capital Investment Analysis......................... 62
1

Background

A number of studies analyze the techno-economics of biomass fast pyrolysis to produce 

bio-oil, but very few explore upgrading of bio-oil to transportation fuel. Also, key 

assumptions found in the literature for biomass cost, plant capacity, reactor technology, 

and other variables vary widely among different studies. It is therefore difficult to 

compare costs from various previous studies without taking into account differences in 

process assumptions.

Figure 1. Fast pyrolysis oil costs from previous biomass fast pyrolysis studies [1-7]

adapted for inflation from Ringer et al. [8]

Figure 1 shows bio-oil costs for previous biomass fast pyrolysis techno-economic studies. 

Bio-oil cost estimated in this study is also included [$0.83/gal for 2,000 metric ton per 

day (MT/day) capacity] in Figure 1. Capital cost estimates for these studies range from 

$143 million [6] to $37 million [7] for 1,000 MT/day capacities. A recent study by the 

National Renewable Energy Laboratory (NREL) for a 550 dry MT/day wood fast 

pyrolysis plant producing 28 million gallons (106 million liters) of bio-oil per year finds

the capital cost to be $48.2 million and the operating cost to be $9.6 million/year (based 

on $0.62/gal product value). 

Few studies explore the upgrading of bio-oil to naphtha-range and diesel-range products. 

Although the technology for bio-oil hydroprocessing is based on commercially available 

equipment, actual implementations are in development. UOP LLC is one of the main 

$26 [1]

$26 [1]

$41 [2]

$41 [2]

$41 [2]

$65 [3]

$62 [4]

$65 [5]

$65 [6]

$17 [7] $67 [7]

$83 (this study)

$-

$0.50 

$1.00 

$1.50 

$2.00 

$2.50 

0 500 1000 1500 2000 2500

Bio-oil Cost ($/gal)

Plant Capacity (MT/day)

Labels Indicate Feedstock Cost ($/dry MT)
2

developers of this technology, and they have published various studies on bio-oil 

upgrading. A 2005 study finds that gasoline from bio-oil is economically attractive if biooil is available at $18/bbl ($0.43/gal) and crude oil sells for $50/bbl [9]. A recent article 

estimates the cost of naphtha-range and diesel-range fuel from corn stover to be $1.80/gal

[10].

Model and Process Description

Biomass fast pyrolysis is a thermochemical process that converts feedstock into gaseous, 

solid, and liquid products through the heating of biomass in the absence of oxygen. A

computational model is developed in this study to simulate this process in order to 

conduct a techno-economic study of transportation biofuels via fast pyrolysis and bio-oil 

upgrading. To accomplish this goal, Aspen software is employed to calculate mass and 

energy balances and economic costs related to the process. 

This model is based on the conversion of corn stover to naphtha-range and diesel-range 

distillation fractions (gasoline blend stock and diesel blend stock, respectively, 

hereinafter referred to as naphtha and diesel). For modeling, the upgraded pyrolysis oil 

products are modeled as C8 and C10 hydrocarbons. The biomass plant assumed here 

processes 2,000 dry MT/day of corn stover using common equipment found in 

thermochemical conversion facilities. Modifications to existing equipment will be 

necessary to develop this process; major changes are discussed in this report. The impacts 

of process uncertainties are considered in the sensitivity and pioneer plant analyses.

General processing steps include biomass pretreatment, fast pyrolysis, solids removal, 

bio-oil collection, char combustion, and bio-oil upgrading. 

An overall description of the biomass fast pyrolysis process to produce naphtha and 

diesel is shown in Figure 2. The hydrogen production scenario employs optional 

equipment to generate requisite hydrogen. Biomass with 25% moisture content is dried to 

7% moisture and ground to 3-mm-diameter size prior to being fed into a fluid bed 

pyrolyzer operating at 480°C and atmospheric pressure. Standard cyclones remove solids 

consisting mostly of char particles entrained in the vapors exiting the pyrolyzer. Vapors 

are condensed in indirect contact heat exchangers, yielding liquid bio-oil that can be 

safely stored at ambient conditions prior to upgrading to transportation fuels. Noncondensable gases are recycled to the pyrolysis reactor after being combusted to provide 

process heat. This analysis assumes that pyrolysis solid products are sent to a combustor 

to provide heat for the drying and pyrolysis process. Excess solids consisting of char are 

sold as a low-heating-value coal substitute. Bio-oil upgrading, which is discussed in the 

hydroprocessing section, generates fuel compatible with existing infrastructure.
3

Figure 2. Combined biomass fast pyrolysis and hydrogen production/purchase upgrading 

process diagram

Biomass condition, as typically delivered, is an important factor not studied in detail in 

this analysis. Typical feedstock collection methods remove significant soil matter with 

the biomass from the ground. Soil matter reduces the thermal value of biomass and poses 

maintenance difficulties for combustion equipment. Ash content can cause fouling and 

plugging of high-temperature equipment. Minerals catalyze thermal decomposition 

reactions that are detrimental to the production of quality pyrolysis oil. Biomass washing 

using water or acid-removal techniques can reduce alkali content in biomass [11]. 

Mineral effects are not considered in this study because of the limited knowledge of the 

mechanisms by which alkali content affects pyrolysis yields.

The upgrading process considered in this study is bio-oil hydrotreating and 

hydrocracking. Hydrotreating and hydrocracking (hydroprocessing) are commonly 

employed in the petroleum industry to remove undesired compounds such as sulfur from 

crude oil and to break large hydrocarbon molecules to produce clean naphtha and diesel. 

Bio-oil typically contains significant quantities of oxygenated compounds that are 

undesirable for combustion in vehicle engines. Hydrotreating can convert oxygen found 

in bio-oil to water and carbon dioxide molecules, leaving hydrocarbons that are suitable 

for internal combustion engines. Complex hydrocarbon compounds are found in bio-oil,

and hydrocracking is a potential method to decompose these heavy compounds into 

naphtha and diesel. 

Process modeling is accomplished by employing Aspen Plus software to develop mass 

and energy calculations. Assumptions and operating conditions are taken from the 

literature and experimental data when available. Economic analysis uses a combination of 

Aspen Icarus software equipment cost and sizing and spreadsheet investment analysis 

calculations. Major assumptions made for this analysis match those of companion 

analyses for producing transportation fuel from biomass via biochemical and gasification 

technologies [12, 13]. See Appendix D for more details.
4

Design Basis

The purpose of the assessed process is to convert biomass into liquid fuels suitable for 

transportation applications. This is achieved by converting biomass into bio-oil, which is 

subsequently upgraded to transportation fuels. The design-basis model employs nine 

distinct sections as described in Table 1. 

Table 1. Process Model Sections, Descriptions, and Key Assumptions

Section Name Section Description Key Assumptions

Chopping Particle size reduction to 10 mm Incoming biomass average size of 

10 to 25 mm

Drying Biomass drying to 7% moisture Steam drying at 200°C

Grinding Particle size reduction to 3 mm Incoming biomass maximum size 

of <10 mm

Pyrolysis Biomass conversion to pyrolysis 

products

480°C and 1 atm

2.75 kg of fluidizing gas per kg of 

biomass

Heat provided by char combustion

Solids Removal Removal of entrained solid particles 

from vapor stream

~90% particle removal

Bio-Oil Recovery Collection of condensing vapors Rapid condensation to about 50°C

95% collection of aerosols

Storage Storage of bio-oil and char 4 weeks storage capacity

Combustion Provides process heat and steam 

generation

120% excess air combustion

1,100°C gas temperature

200°C steam generation

Hydroprocessing Upgrading of bio-oil to naphtharange and diesel-range product 

fractions

Hydrogen production from oil by 

aqueous phase reforming

P >1,000 psia and T >300°C 

Biomass is modeled on a proximate and ultimate analysis basis. There is scarce 

information in the literature that is specific to corn stover pyrolysis. Nonetheless, this 

process feedstock is modeled using information from Table 2. This corn stover analysis is 

adapted from U.S. Department of Agriculture (USDA) experimental data [14]. The ash 

content value is specified as 6% to meet the requirements of this study, and other values 

are adjusted accordingly. Char analysis is based on laboratory results [15], shown in 

Table 3, and these values are not modified in the model.
5

Table 2. Corn Stover Ultimate and Proximate Analysis [14]

Ultimate Analysis

(dry basis) 

Element Value (wt %)

Ash 6

Carbon 47.28

Hydrogen 5.06

Nitrogen 0.8

Chlorine 0

Sulfur 0.22

Oxygen 40.63

Proximate Analysis

(wet basis)

Element Value (wt %)

Moisture 25.0

Fixed Content 17.7

Volatile Matter 52.8

Ash 4.5

Table 3. Char Ultimate and Proximate Analysis [15]

Ultimate Analysis

(dry basis)

Element Value (wt %)

Ash 33.3

Carbon 51.2

Hydrogen 2.12

Nitrogen 0.45

Chlorine 0.471

Sulfur 0.935

Oxygen 11.5

Proximate Analysis

(dry, ash-free)

Element Value (wt %)

Moisture 0

Fixed Content 51.21

Volatile Matter 49.79

Ash 0

Biomass pyrolysis generates a large variety of organic and inorganic compounds that 

make modeling efforts difficult. Hundreds of compounds have been identified in biooil— the primary fast pyrolysis product [16]. A common approach is to employ model 

compounds to represent chemical groups based on their significance and quantity. This 

model adapts pyrolysis oil and gas composition from research by NREL as described in 

the “Pyrolysis” section of this report [8]. 

Two models are developed to study the performance of biomass pyrolysis for different 

scenarios: a hydrogen production scenario employing bio-oil reforming to generate 

requisite hydrogen for bio-oil upgrading, and a hydrogen purchase scenario using 

merchant hydrogen for bio-oil upgrading. Pyrolysis is a flexible process that can be 

designed with numerous configurations and scaled to various capacities. Small-scale 
6

pyrolysis is suitable for distributed processing scenarios that could lower costs associated 

with biomass transportation. Table 4 shows a description of the scenarios explored in this 

study.

The source of hydrogen for the hydrogen purchase scenario is not specified, although 

non-fossil energy sources are preferred to achieve the highest reductions in greenhouse 

gas emissions associated with hydrogen production. The advantage of this approach is 

that it maximizes the conversion of carbon in biomass to biofuels [17].

These scenarios employ many of the same process sections described in Table 1 and 

share most of the general assumptions. Assumptions for biomass fast pyrolysis to 

generate bio-oil are identical for both scenarios; the scenarios only differ by the bio-oil 

upgrading technology. Hydrogen production fast pyrolysis and oil upgrading employs a 

portion of the bio-oil produced to generate the required hydrogen for oil hydroprocessing. 

Additional equipment, including a reformer and gas compressor, are required by the 

hydrogen production system. The second scenario forgoes the additional investment by 

purchasing hydrogen from a remote source. Scenarios are based on 2,000 MT/day corn 

stover input.

Table 4. Corn Stover (2,000 MT/day) Fast Pyrolysis Scenarios

Scenario Description

Hydrogen Production Fast 

Pyrolysis with Bio-Oil Upgrading

Large-scale pyrolysis with oil hydroprocessing employing 

hydrogen derived from bio-oil reforming

Hydrogen Purchase Fast 

Pyrolysis with Bio-Oil Upgrading

Large-scale pyrolysis with oil hydroprocessing employing offsite generation of hydrogen

Chopping/Grinding

Delivered feedstock typically requires processing prior to being fed into a pyrolysis 

reactor to avoid penalties that reduce yields and increase heat requirements. Mechanical 

particle-size reduction and drying are commonly used in thermochemical processes. 

Grinding biomass is an expensive and energy-intensive process. Grinding costs can add 

up to $11/MT of biomass [18]. Specific energy requirements can vary based on 

equipment and feedstock conditions. A common assumption is that 50 kWh of energy is 

required per ton of ground biomass [19]. This model employs research by Mani et al. [20]

that correlates the grinder screen size to the energy requirement for a hammer mill based 

on various types of biomass, including corn stover. According to their model, the energy 

consumption for grinding biomass from a mean chop size of 7.15 mm to between 3.5 and 

0.5 mm is approximated by the following equation:

Energy [kWh * ton-1

] = 5.31 * size2 – 30.86 * size + 55.45 

There are various advantages and disadvantages to using hammer mills for biomass 

grinding. Hammer mills can employ various screen sizes and work with friable material 

such as fiber. They incur low capital costs and require minimal maintenance. On the other 

hand, disadvantages of hammer mills are that they create excess noise and pollution; they 
7

are less efficient than other types of grinders; and they produce a less uniform particle 

size output than roller mills do [21].

Drying 

Feedstock drying is very important for thermochemical processes. Moisture embedded in 

the feed consumes process heat and contributes to lower process yields. For reasonable 

pyrolysis performance, moisture content of less than 7% is recommended [22]. Biomass 

drying typically requires about 50% more energy than the theoretical minimum of 2,442 

kJ per kg of moisture evaporated [23].

Dryers can be generally classified as direct or indirect dryers based on how heat is 

provided. Direct drying involves contact between the heating medium and the feed. 

Direct dryers can further be classified as either air or superheated-steam dryers. Most 

commercial dryers employ heated air or process gas to dry the feed. An example of an air 

dryer is the rotary dryer, which has the advantage of being less sensitive to particle size 

and can accept hot flue gases. An important disadvantage of air dryers is the potential fire 

hazard due to the nature of their operation. On the other hand, steam dryers pose less of a 

fire hazard and emit no air emissions. The disadvantages of steam dryers are higher 

capital costs and small particle size requirement [24]. This study assumes that biomass is

steam dried to 7% moisture.

Steam dryers can employ excess steam generated by a process plant. Thermochemical 

plants typically require steam as a means to provide, or remove, heat from different 

equipment. Harmful volatile organic compounds (VOCs) can, however, become 

entrained in the evaporating moisture. The implication is that dryer steam will require 

water treatment to reduce the accumulation of large quantities of unwanted chemicals and 

to prevent the release of these compounds once the steam is discarded. Unfortunately, 

there is not enough information to properly model the release of VOCs from biomass 

drying at this time. 

Pyrolysis

Fast pyrolysis of biomass is a thermal process that requires temperatures near 500°C, 

rapid heat transfer, and low residence times. Various reactor designs have been proposed 

for this process [25]. Because of concerns over the scalability of existing reactor designs, 

this study assumes that multiple 500 MT/day reactors are employed in parallel. This size 

is selected based on assumptions from a report by NREL [8]. Commercial units as large 

as 200 MT/day are currently in operation. Pyrolysis product distribution is adapted from

USDA data [14] using the bio-oil and non-condensable gas (NCG) composition shown in 

Table 6. Bio-oil and NCG composition is modified from a previous NREL analysis [8]. 

Bio-oil compounds are selected based on available Aspen Plus software compounds and 

may not share the same properties as compounds selected by NREL. Table 5 shows 

various pyrolysis yields for corn stover [14, 26]. Table 6 includes the initial pyrolysis 

product yields employed in this study. The final yield is adjusted to ensure mole and mass 

balance.
8

Table 5. Corn Stover Fast Pyrolysis Yields

Material Yields (wt % dry basis) NREL [26] NREL [26] USDA [14]a

Non-Condensable Gas 14.3 11.7 21.9

Oil 57.6 55.0 61.6b

Water 4.9 7.9 -

Char/Ash 19.4 19.5 17

Total 96.2 94.1 100 a Current results adjusted from these yield values. b Includes water content.

The USDA corn stover fast pyrolysis yield data are listed in Table 5. This study employs 

a more detailed pyrolysis product composition, shown in Table 6, as a starting point for 

pyrolysis yield calculations. The pyrolysis product composition reported in this study 

varies from the original references to achieve a mole balance. For example, the USDA oil 

yield is listed as 61.6 wt %, but calculations estimate oil yields of 63 wt % (dry basis). 

The USDA corn stover had a moisture content of 2.5% at the pyrolysis reactor, while our 

analysis assumes 7% moisture content, which increases the combined water and oil yield 

to 72 wt % (about 4% of reaction water is generated during the pyrolysis process). 

Table 6. Pyrolysis Product Composition

Gas Compounds

Composition

(kg/100 kg of dry biomass)

Carbon Dioxide 5.42

Carbon Monoxide 6.56

Methane 0.035

Ethane 0.142

Hydrogen 0.588a

Propane 0.152

Ammonia 0.0121

Bio-Oil Compounds

Acetic Acid 5.93

Propionic Acid 7.31

Methoxyphenol 0.61

Ethylphenol 3.80

Formic Acid 3.41

Propyl-Benzoate 16.36

Phenol 0.46

Toluene 2.27

Furfural 18.98

Benzene 0.77

Other Compounds

Water 10.80

Char/Ash 16.39 a Corrected to 0.02 kg/kg of biomass based on engineering judgment.

Yield adjustments from the original analysis are accomplished by using yield factors. 

Different factors are applied to the yield of individual compounds until a 100% mole 
9

balance within 1% is achieved. This effort is made to maintain carbon, hydrogen, oxygen, 

and nitrogen mole balance plus ash mass balance throughout the model. Closer attention 

is given to carbon, hydrogen, and oxygen because these are the most relevant elements in 

both the feedstock and final products. 

Cleanup

Gases exiting from the pyrolysis reactor contain entrained particles of various sizes. 

Compared to particles generated from gasification, pyrolysis particles can be much 

smaller, with sizes less than 25 microns. The particle size is important because it affects 

the design and performance of cleaning equipment such as cyclones and filters. This 

model assumes that a set of parallel cyclones is employed to remove 90% of entrained 

char particles. Baghouse filters can be considered as a secondary collection unit, but 

conventional baghouse filters require modifications to be employed in pyrolysis 

applications. Even then, they may still cause yield reductions and require costly 

maintenance due to coking and vapor condensation on the filter surface.

Char collected from the cleanup section is sent to the combustion section, where it is 

employed to provide process heat. A portion of the char is burned, while the rest is 

collected and sold as a by-product. 

Oil Collection

There are various possible approaches to the collection of pyrolysis oil. To collect highquality oil and maintain high yields, vapors should be condensed within fractions of a 

second after exiting the pyrolysis reactor. Longer residence time allows secondary 

reactions to take place in the gas phase and reduces the quantity of oil collected. 

To accomplish rapid condensation of pyrolysis vapors, this model employs an indirect 

heat exchanger to transfer heat from the vapors to a water stream. This design allows for 

the generation of excess steam. Although not considered in this report due to lack of 

reliable data, staged condensation of bio-oil allows for the collection of oil fractions with 

attractive properties. A simple example is to condense a majority of water in a specific 

condenser and a higher concentration of oil in a different condenser. This takes advantage 

of the fact that different compounds will condense at different temperatures in similar 

fashion to the crude distillation process. After most of the oil is condensed, an 

electrostatic precipitator (ESP) unit collects remaining droplets known as aerosols by 

using high voltage charges. The formation of aerosols is a complex process, with scarce 

information available on the mechanism involved. This model simply assumes that any 

remaining char entrained in the vapors is collected in the ESP unit.

NCGs include significant amounts of methane and other combustible gases. NCGs are 

sent to the combustor to provide heat for biomass drying and the pyrolysis reaction. 

Combustion gases are then recycled to the reactor on a 1.6 kg gas/kg dry biomass ratio to 

provide process heat and aid in fluidizing the reactor. 
10

Storage

Bio-oil and char are collected in the storage section, which can store up to 4 weeks of 

product. Bio-oil storage equipment must be made of stainless steel material to prevent 

corrosion from bio-oil acids. Char contains volatile material and when handled 

improperly can pose a fire hazard. Furthermore, the small size of char particles poses an 

inhalation hazard for people handling the material. Storage for the naphtha and diesel

products is similarly sized for 4 weeks of capacity.

Combustion

Process heat is required to operate the pyrolysis reactor. Heat can be provided to smallscale reactors by employing guard heaters with insulation to prevent heat loss. Largescale reactors require a direct form of heating, which could consist of using hot gases as 

the fluidizing agent. A possible scheme is to combust pyrolysis gases in the combustion 

section prior to recycling back to the pyrolysis reactor.

The current model assumes that recycled NCGs and a fraction of pyrolysis char (27.5 

MJ/kg [15]) are combusted to provide the necessary process heat for the pyrolysis 

process and steam generation. Combustion air, at 90% of the stoichiometric requirement, 

is sent to the combustion reactor. Combustion gases are cooled to provide additional heat 

to generate steam. Finally, cyclones collect ash from the combustion gases at a solids 

disposal cost of $18/short ton [27]. 

Hydroprocessing

Hydrotreating is an exothermic process commonly used in the oil industry to selectively 

remove impurities that could affect downstream equipment. Hydrotreating takes place in 

a hydrogen-rich environment (about 95 mol % or 5% by weight). Typical process 

conditions for hydrotreating are 7–10 MPa (1,000–1,500 psi) pressure and 300°–400°C

using a cobalt-molybdenum catalyst. 

Hydrocracking breaks down heavy molecules into shorter chains. For example, heavy 

hydrocarbons with 30 or more carbon atoms can be split into chains within the diesel 

(C12) or gasoline (C8) range. Process conditions are a bit more severe than for 

hydrotreating, with pressures of 10–14 MPa (1,500–2,000 psi) and temperatures of 400°–

450°C using a nickel-molybdenum catalyst.

Bio-oil contains a large variety of heavy and light compounds. Bio-oil includes a watersoluble aqueous phase that can be reformed to produce the required hydrogen and 

contains heavy molecules that can be hydrocracked to lighter molecules. Bio-oil may be 

suitable for both hydrotreating at an oil refinery where hydrogen can be provided 

separately and hydrogen production processing that employs the oil aqueous phase to 

generate hydrogen. In 2005, UOP LLC published one of the few publically available 

reports on bio-oil hydrotreating [9]. Their initial report employed bio-oil’s aqueous phase 

to generate hydrogen to process the pyrolysis lignin (heavy) phase. Table 7 shows yields 

from UOP’s 2005 report.
11

Table 7. Pyrolysis Lignin Hydrotreating/Hydrocracking Yield [9]

Feed Wt %

Pyrolytic Lignin 100

Hydrogen 4–5

Product

Light Ends 15

Gasoline 30

Diesel 8

Water, Carbon Dioxide 51–52

A schematic of the process proposed by UOP is shown in Figure 3. This process employs 

gravity separation to separate pyrolysis lignin from the water-soluble bio-oil compounds 

(aqueous phase oil). Aqueous phase oil is mixed with steam and sent to a hightemperature pre-reformer and converted into syngas. This syngas is then fed into a 

reformer with methane to produce hydrogen. Various reactions including water-gas-shift 

take place in the reformer to produce hydrogen. Analysis from Marquevich et al. [28] is

employed in this analysis to model the reforming process. The general chemical formula 

for reactions taking place in the reformer is:

CnHmOk + (2n - k) * H2O→nCO2 + (2n + m/2 – k) * H2

Figure 3. Upgrading of pyrolysis oil to naphtha-range and diesel-range products

This study modifies the original UOP analysis by assuming that a smaller fraction of oil 

is separated for reforming purposes. Bio-oil’s aqueous phase can account for up to 70% 

of the bio-oil weight, which leaves only 30% for upgrading. This study assumes that the

process can be optimized to only separate as much bio-oil as required to produce the 

needed hydrogen. Estimates show that 38% of the bio-oil needs to be reformed into 

hydrogen to upgrade the remaining bio-oil. 

UOP updated their bio-oil hydrotreating analysis in 2008 [10]. This more recent study 

explores converting all bio-oil components to transportation fuels, therefore maximizing 

yields from pyrolysis oils. This approach requires a remote source of hydrogen such as an 

oil refinery. Yields for this scenario are shown in Table 8. 
12

Table 8. Pyrolysis Oil Hydrotreating/Hydrocracking Yields [10]

Feed Wt %

Pyrolysis Oil 100

Hydrogen 3–4.5

Products

Naphtha Range 21

Diesel Range 21

Water, Carbon Dioxide, Lights 60

Hydrocracking typically processes hydrocarbons of long (greater than 30) carbon chain 

lengths. The longest carbon chain for a compound used in this model has 10 carbon 

atoms, and therefore hydrocracking is not properly modeled. Nevertheless, a 

hydrocracking unit is included because this is an important component in the conversion 

of bio-oil to transportation fuels. Unit size and cost are based on the mass and energy 

requirements calculated by Aspen Plus software. It is known that metals (P, K, Na, Ca,

and other) originating from corn stover will be contained in bio-oil. Traditionally, the 

concentration of metals is lowered to 10 ppm or less by utilizing a guard bed with 

sacrificial catalyst to prevent significant poisoning of the hydrotreating catalyst. Typical 

levels of total metal content in bio-oil can be as high as 500 ppm. It is recognized that 

technology to remove metals specifically found in bio-oil is not well understood and is 

under current development. Therefore, in this model a placeholder component for the 

guard bed is included. Capital costs for the guard bed are estimated as 15% of the 

hydroprocessing capital expenditure.

Bio-oil hydroprocessing generates significant amounts of fuel gas consisting mostly of 

methane and lesser amounts of carbon monoxide. A product value of $5 per million Btu 

is employed in this study, which is comparable to the price of low-cost industrial natural 

gas [29]. 

Economics

This study employs Aspen Icarus software to estimate equipment costs and a method 

from Peters and Timmerhaus to calculate project investment expenditures [30]. Estimates 

based on this methodology are typically accurate within 30%. The profitability of a given 

process can be determined from the operating costs and profitability analysis. NREL 

developed a discounted cash flow rate of return analysis spreadsheet to calculate the 

product value (PV), which is used in this study.

The plant is designed based on the current state of technology and is assumed to be the nth

plant of its kind. Economic analysis for a pioneer plant is developed using risk analysis 

formulas that take into account the maturity of the knowledge and accuracy of the 

simulation. The online time is 328 days per year (equivalent capacity factor of 90%). 

Construction time of less than 24 months is considered. The startup period is 25% of the 

construction time (6 months). During this period, an average of 50% production is 

achieved with expenditures of about 75% of variable expenses and 100% of fixed 

expenses. Contingency is calculated as a 20% factor of total installed equipment cost and 

indirect costs. A pioneer contingency factor of 30% is employed. Equipment costing data 
13

and installation factors are collected from direct quotation, published data, and Aspen 

Icarus software evaluation with preference given in the order shown here.

Feedstock cost is assumed to be $75/dry short ton ($83/dry metric ton) and includes

delivery cost. Electricity cost is assumed to be $0.054/kWh. Catalyst replacement costs 

are estimated at $1.77 million/year based on costs for crude oil processing [31].

Working capital is assumed to be 15% of the total capital investment. It is assumed that 

the product, transportation fuel, will be made and shipped and payment received in 30 

days. Annual maintenance materials are 2% of the total installed equipment cost. 

General overhead is a factor of 60% applied to the total salaries and covers items such as 

safety, general engineering, general plant maintenance, payroll overhead (including 

benefits), plant security, janitorial and similar services, phone, light, heat, and plant 

communications.

The total plant investment cost is determined by applying overhead and contingency 

factors to installed equipment costs. Insurance and taxes are considered as 1.5% of the 

total installed equipment cost.

To determine the product value per gallon of naphtha and diesel, a discounted cash flow 

analysis is used after determining the major three costs areas: (i) total project investment, 

(ii) variable operating costs, and (iii) fixed operating cost. A 10% discounted cash flow 

rate of return is used over a 20-year plant life. The plant is considered 100% equity 

financed. The IRS modified accelerated cost recovery system is employed to calculate the 

federal tax return, with depreciation based on a declining balance (DB) method. This 

allows for the shortest recovery period and largest deductions. The general plant 

depreciation period is assumed to be 7 years. Property listed with a recovery period of 

less than 10 years uses a 200% DB depreciation method. A 20-year-recovery-period 

property uses 150% DB depreciation. State tax is not considered for these calculations 

because the location of the plant is not specified. Return on investment is calculated on a 

per-gallon basis and income tax is averaged over the plant life.

In the hydrogen purchase scenario explored for this study, bio-oil is upgraded employing 

hydrogen from an external source. The purchase price of hydrogen considered here is

$1.50/gallon of gasoline equivalent (GGE) or nearly $1.50/kg. 
14

Sensitivity Analysis

Table 9 shows the sensitivity analysis parameters selected for this study. These 

parameters can have a strong impact on the performance and economics of the process. 

Capital cost is selected as a sensitivity variable because of the uncertainty associated with 

the estimate in this study. Upgrading of bio-oil to naphtha and diesel is a developing 

technology with little public information about the system performance. Upgrading yields 

can be strongly affected by bio-oil quality and catalyst performance and require further 

research.

Table 9. Sensitivity Analysis Parameters for Fast Pyrolysis and Upgrading

Sensitivity Analysis Favorable Base Case Unfavorable

Biomass Cost ($/ton) $50 $75 $100

Bio-Oil Yield (wt/wt feed) 0.7 0.63 0.55

Fuel Gas Credit Value ($/MMBTU) $10 $5 $2.5

Char Value ($/ton) $30 $20 $10

Capital Cost (millions $) $173 $247 $321

Catalyst Cost (millions $) $0.88 $1.77 $3.53

Fuel Yield (wt/wt feed) 0.3 0.25 0.2

Hydrogen Purchase Scenario

Capital Cost (millions $) $120 $172 $223

Fuel Yield (wt/wt feed) 0.47 0.42 0.37

Hydrogen Price ($/GGE) $1 $1.5 $2

Pioneer Plant Analysis

RAND Corporation analysis was employed to estimate the costs associated with 

construction and operation of a pioneer plant [32]. This analysis appropriately takes into 

account the risk associated with building a first-of-a-kind plant or processing unit. The 

methodology used is based on statistical regressions for plant performance and cost 

growth. Plant performance is based on the assumption that a pioneer plant can require a 

few years to operate at peak capacity, and therefore a revenue penalty is assigned due to 

reduced output. Cost growth estimates the total project investment cost of a pioneer plant, 

which is typically higher than an equivalent nth plant. Plant performance and cost growth 

are estimated using the equations shown below and the parameters from Table 10.

Plant Performance = 85.77 – 9.69*NEWSTEPS + 0.33*BALEQS –

4.12*WASTE – 17.91*SOLIDS

Cost Growth = 1.1219 – 0.00297*PCTNEW – 0.02125*IMPURITIES –

0.01137*COMPLEXITY + 0.00111*INCLUSIVENESS –

C1*PROJECT DEFINITION
15

Table 10. Description of Pioneer Plant Analysis Parameters

Parameters Range Definition

NEWSTEPS ≥ 0 Number of new process areas

BALEQS 0–100

Percentage of mass and energy balance equations 

based on commercial plant data

SOLIDS 0 or 1 A factor based on the presence of solids

WASTE 0–5 A factor of waste disposal 

Plant Performance 0–86

PCTNEW 0–100

Percentage of equipment cost for new (under-developed) 

equipment

IMPURITIES 0–5 A factor of impurities present in the process

COMPLEXITY 0–5 Number of consecutively linked plant areas

INCLUSIVENESS 0–100

Percentage of land purchase/lease, initial plant 

inventory/parts/catalysts, and pre-operating personnel 

costs included in the analysis

PROJECT DEFINITION 2–8 A factor of level of detail in the analysis

Cost Growth

Once the risk analysis parameters are selected and plant performance and cost growth are 

calculated, the total project investment (TPI) and first year operating costs are calculated 

as follows:

TPI (Pioneer Plant) = TPI (nth)/Cost Growth

Operating Cost (1st year) = Operating Cost*Plant Performance

The plant performance factor increases by 20% every year until it reaches 100%, at 

which point the plant is operating at full capacity. It is important to note that if a plant 

fails to reach a 40% plant performance factor within the first year of operation, the plant 

is unlikely to achieve full nameplate capacity without significant capital investment. 

Subsequent plants will likely achieve improved performance. Table 11 includes the 

selected parameter values and pioneer plant analysis results. The plant performance 

results suggest that a biomass fast pyrolysis plant based on our assumptions will fail to 

achieve full nameplate capacity. 
16

Table 11. Selected Pioneer Plant Analysis Parameters for Biomass Fast Pyrolysis and 

Upgrading

RAND Analysis Optimistic Base Case Pessimistic Range

NEWSTEPS 2 3 4 -

BALEQS 0% 0% 0% 0–100%

SOLIDS 1 1 1 0,1

WASTE 3 4 5 0–5

Plant Performance 36.12 22.31 8.50 0–100

PCTNEW 25.00% 60.00% 75.00% 0%–100%

IMPURITIES 3 4 5 0–5

COMPLEXITY 4 5 6 2–7

INCLUSIVENESS 66% 0% 0% 0%–100%

PROJECT DEFINITION 6 8 8 2–8

Cost Growth 0.56 0.29 0.22 0-1

Results

Table 12 includes a comparison of key results from this study. The hydrogen production

scenario has higher capital costs than the hydrogen purchase scenario due to additional 

equipment required for bio-oil upgrading. Annual operating costs are higher for the 

hydrogen purchase scenario at a hydrogen price of $1.50/GGE (nearly $1.50/kg). Higher 

fuel yields from upgrading all available bio-oil offset the increase in costs, resulting in a 

lower product value for the hydrogen purchase scenario. Detailed analyses of these 

results are provided in the following sections.

Table 12. Summary of nth Plant Cost Results

Hydrogen

Production

Hydrogen 

Purchase

Capital Cost (millions $) $287 $200

Annual Operating Cost (millions $) $109 $123

Fuel Yield (million gallons/year) 35.4 58.2

PV ($/gal gasoline equivalent) $3.09 $2.11 

Pioneer Plant Capital Cost (million $) $911 $585

Pioneer PV ($/GGE) $6.55 $3.41

An interesting comparison for these scenarios involves detailing the primary energy 

flows, which are shown in Figure 4 [30, 31]. The hydrogen production scenario has a 

biomass-to-fuel efficiency of almost 40% and an overall efficiency of 77% when energy 

in the excess char and fuel gas are considered. The hydrogen purchase scenario achieves 

a biomass-to-fuel efficiency of 70%, primarily due to bypassing a bio-oil reforming step. 

Purchase of external hydrogen is shown here as a negative energy input, which brings the 

overall efficiency to the same as the hydrogen production scenario (77%).

Efforts are taken to ensure that these scenarios avoid consumption of fossil fuel 

resources. Purchased electricity can come from nuclear, hydroelectric, or wind power, 
17

which are all prevalent in the Corn Belt. Most available hydrogen is derived from fossil 

fuel processing, although it is conceivable that hydrogen could be produced by hydrolysis 

of water with electricity from non-fossil sources. The hydrogen-production scenario 

produces more fuel gas due to the bio-oil reforming process, which causes a decrease in 

liquid fuel yield.

Figure 4. Comparison of process energy flows for 2,000 MT/day biomass fast pyrolysis 

and upgrading [33, 34]

Hydrogen-Production Scenario

The product value for a 2,000 MT/day corn stover hydrogen-production fast pyrolysis 

and upgrading plant is $3.09/gal ($0.82/liter) of fuel. This corresponds to a bio-oil 

production cost of $0.83/gal ($0.22/liter). Capital expenditures for this plant are estimated 

at $287 million. 

Estimated bio-oil yield for a 2,000 MT/day corn stover pyrolysis plant is 104 million 

gallons (394 million liters) per year, representing 72% yield by weight of the dry biomass 

input with 15% water content. For the hydrogen-production scenario, 38% of the bio-oil 

is reformed to produce 1,500 kg/hour of hydrogen. Biomass-to-liquid-fuel efficiency for 

the hydrogen-production scenario is estimated at 36%. Fuel yield for the hydrogenproduction scenario is 35.4 million gallons (134 million liters) of fuel per year.

Capital costs are shown in Table 13. Hydroprocessing incurs the largest expenditure. 

Large-scale hydroprocessing is typically employed in industry to take advantage of 

economies of scale. At the plant capacity assumed in this study (2,000 MT/day), 

hydroprocessing costs are relatively expensive on a per-gallon-of-output basis. Storage 

-40%

-20%

0%

20%

40%

60%

80%

100%

120%

Hydrogen Production Hydrogen Purchase

Energy Flow per Biomass Energy Input (%)

Key Process Energy Flows

Net Fuel Gas (30.5 GJ/tonne)

Net Char (24.0 GJ/tonne)

Net Liquid Fuel (45.3 GJ/tonne)

Net Electricity

Net Hydrogen (141.9 GJ/tonne)
18

costs include 1 month of fuel storage. The project contingency for both scenarios is

assumed as 20% of total direct and indirect costs.

Table 13. Capital Costs for 2,000 MT/day Hydrogen-Production Fast Pyrolysis and 

Upgrading Scenario

Capital Costs (millions $)

Hydroprocessing $48.7

Combustion $47.3

Pyrolysis and Oil Recovery $28.0

Pretreatment $20.2

Utilities $9.1

Storage $5.8

Total Equipment Installed Cost $159.1

Indirect Costs $46.9

 (% of TEIC + IC) 20%

 Project Contingency $41.2

Total Project Investment (TPI) $287.4

Installed Cost per Annual Gallon $4.50

Total Project Investment per Annual Gallon $8.12

Lang Factor 5.46

Operating costs for the hydrogen-production scenario are shown in Table 14. Feedstock 

costs contribute half the cost of producing fuel from biomass in this scenario. Co-product 

credits, primarily from the sale of fuel gas, generate significant income.

Electricity costs are estimated to contribute $0.164/gal to the cost of fuel. Investment in 

power generation could yield additional income from the sale of excess electricity, but 

this scenario is not explored in this study.
19

Table 14. Operating Costs for 2,000 MT/day Hydrogen-Production Fast Pyrolysis and 

Upgrading Scenario

Operating Costs (cents/gal product)

Feedstock 153.8

Electricity 16.4

Solids Disposal 5.1

Catalyst 5.1

Fixed Costs 32.5

Co-Product Credits -31.9

Capital Depreciation 33.6

Average Income Tax 26.4 

Average Return on Investment (10% IRR) 63.5

Total 309.4 

Operating Costs (millions $/yr)

Feedstock $54.4

Electricity $5.8

Solids Disposal $1.8

Catalyst $1.8

Fixed Costs $11.5

Co-Product Credits -$11.3

Capital Depreciation $11.9

Average Income Tax $9.3

Average Return on Investment $22.5

Total $109.5

Sensitivity analysis results shown in Figure 5 indicate a strong impact from fuel yield. 

This implies that slight improvements in the bio-oil upgrading process could reduce the 

cost of fuel significantly, whereas lower yields could cause a rapid increase in fuel cost. 

Biomass cost sensitivity is also important, not only because of its impact, but also 

because the cost to acquire feedstock can vary widely between locations and throughout 

the year. Overall, sensitivity results suggest a greater negative sensitivity.
20

Figure 5. Sensitivity analysis for 2,000 MT/day hydrogen-production fast pyrolysis and upgrading scenario

Char Credit Value ($30; $20; $10/short ton)

Catalyst Cost ($0.88; $1.77; $3.53 MM/yr)

Gas Credit Value ($10; $5; $2.5/MMBTU)

Fixed Capital Cost ($173; $247; $321 MM)

Bio-oil Yield (70; 63; 55 wt% feed)

Biomass Cost ($50; $75; $100/ton) 

Fuel Yield (30; 25; 20 wt% bio-oil)

Product Value ($/gal)

2,000 MT/day Fast Pyrolysis and Upgrading with Hydrogen 

Production

(Favorable; Base Case; Unfavorable)
21

Table 15 shows the risk analysis results for the hydrogen-production scenario. These are 

the estimated costs for a pioneer plant based on the current process analysis. Absent of 

learning effects from available commercial implementations, building a first-of-a-kind 

biomass fast pyrolysis and upgrading plant is expected to cost about $864 million. Fuel 

costs from this plant are $6.55/gal.

Table 15. Pioneer Analysis for 2,000 MT/day Hydrogen-Production Fast Pyrolysis and 

Upgrading Scenario

nth Plant Optimistic Base Case Pessimistic

Capital Cost (millions $) $287 $479.8 $911.6 $1,236.3

Product Value ($/GGE) $3.09 $4.32 $6.55 $8.23 

Hydrogen-Purchase Scenario

The product value for a 2,000 MT/day fast pyrolysis and upgrading plant with external 

hydrogen production is $2.11/gal of fuel. Capital expenditures for this plant are estimated 

at $200 million. 

The hydrogen-purchase scenario employs 2,040 kg/h of hydrogen to upgrade 60,000 kg/h 

of bio-oil. Feedstock-to-liquid-fuel efficiency for the hydrogen-purchase scenario is 

estimated at 50% and includes the hydrogen energy input (120 MJ/kg or 0.98 GGE/kg of 

hydrogen). Fuel production for the hydrogen-purchase scenario is 58.2 million gallons

per year.

Table 16 includes capital costs for the hydrogen-purchase scenario. Compared to the 

hydrogen-production scenario, the hydroprocessing section has a much lower cost 

because it does not include equipment to reform and compress hydrogen. 

Table 16. Capital Costs for 2,000 MT/day Hydrogen-Purchase Fast Pyrolysis and 

Upgrading Scenario

Capital Costs (millions $)

Combustion $45.9

Pyrolysis and Oil Recovery $28.0

Pretreatment $20.2

Hydroprocessing $14.8

Storage $1.7

Total Equipment Installed Cost $110.6

Indirect Costs $70.9

 (% of TEIC + IC) 20%

 Project Contingency $32.6

Total Project Investment (TPI) $200

Installed Equipment Cost per Annual Gallon $1.90

Total Project Investment per Annual Gallon $3.43

Lang Factor 5.46
22

Table 17 shows the operating costs for the hydrogen-purchase scenario. Feedstock costs 

contribute almost half the cost of fuel. Although most operating expenditures are 

comparable to the hydrogen-production scenario, the increase in fuel yield reduces the 

per-gallon cost of fuel.

Table 17. Operating Costs for 2,000 MT/day Hydrogen-Purchase Fast Pyrolysis and 

Upgrading Scenario

Operating Costs (cents/gal product)

Feedstock 93.5

Hydrogen 40.7

Electricity 8.4

Solids Disposal 3.1

Catalyst 3.1

Fixed Costs 15.5

Co-Product Credits -10.1

Capital Depreciation 14.8

Average Income Tax 11.7

Average Return on Investment (10% IRR) 31.1

Total 211.4

Operating Costs (millions $/yr)

Feedstock $54.4

Hydrogen $23.7

Electricity $4.9

Solids Disposal $1.8

Catalyst $1.8

Fixed Costs $8.8

Co-Product Credits -$5.9

Capital Depreciation $8.6

Average Income Tax $6.8

Average Return on Investment $18.1

Total $123.0

Sensitivity analysis results for the hydrogen-purchase scenario are shown in Figure 6. 

Biomass cost has a significant impact on the cost of fuel, and at $100/ton, the product 

value estimate is $2.43/gal.

Risk analysis for this scenario shows a similar trend to the hydrogen-production pioneer 

plant. As shown in Table 18, capital cost estimates for base case assumptions are $585

million with pioneer plant fuel costs of $3.41/gal. 
23

Figure 6. Sensitivity analysis for 2,000 MT/day hydrogen-purchase fast pyrolysis and upgrading scenario

Char Value ($30; $20; $10/short ton)

Catalyst Cost ($0.88; $1.77; $3.53 MM/yr)

Gas Credit Value ($10; $5; $2.5/MMBTU)

Hydrogen Price ($1; $1.5; $2.00/GGE)

Fixed Capital Cost ($123; $176; $228 MM)

Fuel Yield (47; 42; 37 wt% bio-oil)

Bio-oil Yield (70; 63; 55 wt% feed)

Biomass Cost ($50; $75; $100/short ton)

Product Value ($/gal)

2,000 MT/day Fast Pyrolysis and Upgrading with Hydrogen Purchase

(Favorable; Base Case; Unfavorable)
24

Table 18. Pioneer Analysis for 2,000 MT/day Hydrogen-Purchase Fast Pyrolysis and 

Upgrading Scenario

nth Plant Optimistic Base Case Pessimistic

Capital Cost (millions $) $200 $307.9 $584.9 $793.2

Product Value ($/GGE) $2.11 $2.54 $3.41 $4.07

Conclusions

This techno-economic study explores the cost of converting corn stover into naphtharange and diesel-range stock fuel via fast pyrolysis and bio-oil upgrading. Based on the 

current analysis, naphtha and diesel can potentially be produced from biomass by an nth

plant at a competitive product value (PV) of $3.09/gal or $2.11/gal when hydrogen is 

procured from a remote source. For a pioneer plant, projected fuel PV increases to 

$6.55/gal for hydrogen-production technology and $3.41/gal for hydrogen-purchase 

technology. 

Two scenarios are modeled in this study. One is a hydrogen-production scenario 

employing bio-oil reforming to generate requisite hydrogen. The other is a hydrogenpurchase scenario that relies on merchant hydrogen. Both scenarios process 2,000 metric 

tons per day of corn stover to generate 35 million and 58 million gallons of naphtharange and diesel-range stock fuel, respectively. The hydrogen-production scenario 

sacrifices a portion of bio-oil to produce hydrogen, which results in lower yields 

compared to the purchase scenario. nth plant capital costs are estimated at $287 million 

for the hydrogen-production scenario and $200 million for the hydrogen-purchase 

scenario. The difference is primarily due to the high cost of reforming equipment. 

The source of hydrogen for the hydrogen-purchase scenario is not specified in this report. 

Non-fossil energy sources are preferable to achieve the highest reductions in greenhouse 

gas emissions associated with transportation fuel production. The advantage of this 

approach is that it maximizes the conversion of carbon in biomass to biofuels.

Sensitivity analysis of key process variables finds fuel conversion yields to have the most 

impact on the final cost of transportation fuel. Variations of 5% in the bio-oil upgrading 

yield result in product values of $2.60–$3.89/gal for the hydrogen-production scenario. 

Biomass cost and bio-oil yield are found to have significant impact on the cost of fuel for 

both scenarios. The capital cost sensitivity range is ±30% and has a relatively small 

impact, with product values ranging between $2.71 and $3.48. 

Pioneer plant analysis is employed in this study to estimate the capital and operating costs 

of a first-of-a-kind biomass fast pyrolysis and upgrading plant. Results indicate that a 

pioneer hydrogen-production fast pyrolysis and upgrading plant could require an 

investment of $912 million and have a product value of $6.55. These high costs indicate 

that some aspects of this technology, notably the bio-oil upgrading process, require 

further development to reduce uncertainties in costs.
25 

References

1. Islam, M.; Ani, F. “Techno-Economics of Rice Husk Pyrolysis, Conversion with 

Catalytic Treatment to Produce Liquid Fuel.” Bioresource Technology; Vol. 

73(1), 2000; pp. 67-75. 

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11. Davidsson, K. O.; Korsgren, J. G.; Pettersson, J. B. C.; Jäglid, U. “The Effects of 

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tor?canprint=false. Accessed July 2009.
28

Appendix A. Equipment Cost and Description

Table A-1. Equipment Costs for Fast Pyrolysis and Bio-Oil Upgrading with Hydrogen Production

Number 

Required

Number 

Spares

No. 

Req. 

Variable

Area Equipment Name Equipment Type Equipment 

Cost

Total Equipment 

Cost (with spares)

Installed Cost

1 0 1 Upgrading Liquid/Gas Fuel Separator DVT CYLINDER $283,200 $283,200 $855,264

1 0 1 Upgrading Bio-oil Separation Vessel DVT CYLINDER $145,100 $145,100 $438,202

1 1 2 Upgrading Reforming Bio-oil Pump DCP CENTRIF $47,600 $95,200 $287,504

1 1 2 Upgrading Hydroprocessing Pump DCP CENTRIF $114,200 $228,400 $689,768

1 1 2 Upgrading Reforming Water Pump DCP CENTRIF $48,700 $97,400 $294,148

1 0 1 Upgrading Hydrotreater/hydrocracker DAT REACTOR $329,700 $329,700 $995,694

1 1 2 Upgrading Reforming Water Heater DHE FLOAT HEAD $737,700 $1,475,400 $4,455,708

1 1 2 Upgrading Reforming Preheater DHE FLOAT HEAD $241,100 $482,200 $1,456,244

1 1 2 Upgrading hydrogen Cooler DHE FLOAT HEAD $599,300 $1,198,600 $3,619,772

1 1 2 Upgrading Reformer Recycle Heater DHE FLOAT HEAD $739,500 $1,479,000 $4,466,580

1 0 1 Upgrading Catalyst Guard Bed C $827,815 $827,815 $2,500,000

1 0 1 Upgrading Reforming Steam/Water Sep DVT CYLINDER $180,700 $180,700 $545,714

1 0 1 Upgrading Flue Gas Water Condenser DVT CYLINDER $137,700 $137,700 $415,854

1 0 1 Upgrading hydrogen Compressor DGC CENTRIF $2,015,500 $2,015,500 $6,086,810

1 0 1 Upgrading hydrogen Compressor 2 DGC CENTRIF $3,655,600 $3,655,600 $11,039,912

1 0 1 Upgrading Pressure Swing Adsorption DVT CYLINDER $76,300 $76,300 $230,426

1 0 1 Upgrading Bio-oil Reformer DVT JACKETED $184,800 $184,800 $558,096

1 0 1 Upgrading Bio-oil Prereformer DVT JACKETED $209,300 $209,300 $632,086

1 0 1 Upgrading Flue Gas Blower EFN CENTRIF $214,700 $214,700 $648,394

1 0 1 Upgrading Flue Gas Combustor EFU VERTICAL $2,800,100 $2,800,100 $8,456,302
29

4 0 4 Pyrolysis Screw Feeder ECO SCREW $162,500 $650,000 $1,963,000

1 1 2 Pyrolysis Condenser Water Pump DCP CENTRIF $669,700 $1,339,400 $4,044,988

1 1 2 Pyrolysis Bio-oil Condenser DHE FLOAT HEAD $998,700 $1,997,400 $6,032,148

4 0 4 Pyrolysis Biomass Feeding Bin DVT CONE BTM $41,400 $165,600 $500,112

1 0 1 Pyrolysis Electro-Static Precipitator EDC ELC L VOLT $292,400 $292,400 $883,048

1 0 1 Pyrolysis NCG/Oil Separation DVT CYLINDER $215,400 $215,400 $650,508

1 0 1 Pyrolysis Pyrolysis Vapor Cyclones EDC CYCLONE $1,262,000 $1,262,000 $3,811,240

4 0 4 Pyrolysis Pyrolysis Fluid Bed DVT JACKETED $836,000 $3,344,000 $10,098,880

1 0 1 Combustion Char/Ash Feeding Bin DVT CONE BTM $165,700 $165,700 $500,414

1 0 1 Combustion Screw Feeder ECO SCREW $379,600 $379,600 $1,146,392

1 0 1 Combustion Water Softener System C $1,858,000 $1,858,000 $5,611,160

1 0 1 Combustion Deaerator C $223,000 $223,000 $673,460

1 0 1 Combustion Solids Combustor DVT JACKETED $244,300 $244,300 $737,786

1 1 2 Combustion BFW Pump DCP CENTRIF $129,700 $259,400 $783,388

1 1 2 Combustion BFW Heater DHE FLOAT HEAD $2,543,600 $5,087,200 $15,363,344

1 1 2 Combustion BFW Preheater DHE FLOAT HEAD $3,141,200 $6,282,400 $18,972,848

1 0 1 Combustion Combustor Cyclones EDC CYCLONE $1,104,700 $1,104,700 $3,336,194

1 0 1 Combustion Combustion Gas Blower EFN CENTRIF $62,200 $62,200 $187,844

2 0 2 Pretreatment Bale Transport Conveyor C $533,000 $1,066,000 $3,219,320

2 0 2 Pretreatment Bale Unwrapping Conveyor C $200,000 $400,000 $1,208,000

1 0 1 Pretreatment Discharge Conveyor C $67,000 $67,000 $202,340

1 0 1 Pretreatment Truck Scales C $45,000 $45,000 $135,900

4 0 4 Pretreatment Truck Unloading Forklift C $24,000 $96,000 $289,920

4 0 4 Pretreatment Bale Moving Forklift C $24,000 $96,000 $289,920
30

1 0 1 Pretreatment Concrete Storage Slab C $600,000 $600,000 $1,812,000

1 0 1 Pretreatment Belt Press C $133,000 $133,000 $401,660

1 0 1 Pretreatment Magnetic Separator C $19,000 $19,000 $57,380

1 0 1 Pretreatment Biomass Chopping Screen EVS ONE DECK $22,500 $22,500 $67,950

4 0 4 Pretreatment Rotary Dryer ERD DIRECT $681,400 $2,725,600 $8,231,312

1 0 1 Pretreatment Biomass Grinding Screen EVS ONE DECK $23,000 $23,000 $69,460

1 0 1 Pretreatment Steam Blower EFN CENTRIF $803,300 $803,300 $2,425,966

1 0 1 Pretreatment Grinding Hammer Mill ECR HAMMER MED $302,200 $302,200 $912,644

1 0 1 Pretreatment Chopper ECR HAMMER MED $302,200 $302,200 $912,644

$0 $0

4 0 4 Storage Fuel Storage DVT STORAGE $469,800 $1,879,200 $5,675,184

1 1 2 Storage Liquid Fuel Pump DCP CENTRIF $24,300 $48,600 $146,772

1 0 1 Utilities Cooling Tower ECTWCOOLING WP $3,005,100 $3,005,100 $9,075,402

Totals $35,197,515 $52,683,115 $159,103,006
31

Table A-2. Equipment Costs for Fast Pyrolysis and Bio-Oil Upgrading with Hydrogen Purchase

Number 

Required

Number 

Spares

No. Req. 

Variable

Area Equipment Name Equipment Type Equipment 

Cost

Total Equipment 

Cost (with spares)

Installed Cost

1 1 2 Upgrading Hydroprocessing Pump DCP CENTRIF $114,200 $228,400 $689,768

1 0 1 Upgrading Hydrotreater/hydrocracker DAT REACTOR $329,700 $329,700 $995,694

1 0 1 Upgrading Catalyst Guard Bed C $827,815 $827,815 $2,500,000

1 1 2 Upgrading Flue Gas Water Condenser DVT CYLINDER $137,700 $275,400 $831,708

1 1 2 Upgrading Flue Gas Blower EFN CENTRIF $214,700 $429,400 $1,296,788

1 0 1 Upgrading Flue Gas Combustor EFU VERTICAL $2,800,100 $2,800,100 $8,456,302

4 0 4 Pyrolysis Screw Feeder ECO SCREW $162,500 $650,000 $1,963,000

1 1 2 Pyrolysis Condenser Water Pump DCP CENTRIF $669,700 $1,339,400 $4,044,988

1 1 2 Pyrolysis Bio-oil Condenser DHE FLOAT HEAD $998,700 $1,997,400 $6,032,148

4 0 4 Pyrolysis Biomass Feeding Bin DVT CONE BTM $41,400 $165,600 $500,112

1 0 1 Pyrolysis Electro-Static Precipitator EDC ELC L VOLT $292,400 $292,400 $883,048

1 0 1 Pyrolysis NCG/Oil Separation DVT CYLINDER $215,400 $215,400 $650,508

1 0 1 Pyrolysis Pyrolysis Vapor Cyclones EDC CYCLONE $1,262,000 $1,262,000 $3,811,240

4 0 4 Pyrolysis Pyrolysis Fluid Bed DVT JACKETED $836,000 $3,344,000 $10,098,880

1 0 1 Combustion Char/Ash Feeding Bin DVT CONE BTM $165,700 $165,700 $500,414

1 0 1 Combustion Screw Feeder ECO SCREW $379,600 $379,600 $1,146,392

1 0 1 Combustion Water Softener System C $1,858,000 $1,858,000 $5,611,160

1 0 1 Combustion Deaerator C $223,000 $223,000 $673,460

1 0 1 Combustion Solids Combustor DVT JACKETED $244,300 $244,300 $737,786

1 1 2 Combustion BFW Pump DCP CENTRIF $129,700 $259,400 $783,388
32

1 1 2 Combustion BFW Heater DHE FLOAT HEAD $2,543,600 $5,087,200 $15,363,344

1 1 2 Combustion BFW Preheater DHE FLOAT HEAD $3,141,200 $6,282,400 $18,972,848

1 0 1 Combustion Combustor Cyclones EDC CYCLONE $653,300 $653,300 $1,972,966

1 0 1 Combustion Combustion Gas Blower EFN CENTRIF $62,200 $62,200 $187,844

2 0 2 Pretreatment Bale Transport Conveyor C $533,000 $1,066,000 $3,219,320

2 0 2 Pretreatment Bale Unwrapping Conveyor C $200,000 $400,000 $1,208,000

1 0 1 Pretreatment Discharge Conveyor C $67,000 $67,000 $202,340

1 0 1 Pretreatment Truck Scales C $45,000 $45,000 $135,900

4 0 4 Pretreatment Truck Unloading Forklift C $24,000 $96,000 $289,920

4 0 4 Pretreatment Bale Moving Forklift C $24,000 $96,000 $289,920

1 0 1 Pretreatment Concrete Storage Slab C $600,000 $600,000 $1,812,000

1 0 1 Pretreatment Belt Press C $133,000 $133,000 $401,660

1 0 1 Pretreatment Magnetic Separator C $19,000 $19,000 $57,380

1 0 1 Pretreatment Biomass Chopping Screen EVS ONE DECK $22,500 $22,500 $67,950

4 0 4 Pretreatment Rotary Dryer ERD DIRECT $681,400 $2,725,600 $8,231,312

1 0 1 Pretreatment Biomass Grinding Screen EVS ONE DECK $23,000 $23,000 $69,460

1 0 1 Pretreatment Steam Blower EFN CENTRIF $803,300 $803,300 $2,425,966

1 0 1 Pretreatment Grinding Hammer Mill ECR HAMMER MED $302,200 $302,200 $912,644

1 0 1 Pretreatment Chopper ECR HAMMER MED $302,200 $302,200 $912,644

1 0 1 Storage Fuel Storage DVT STORAGE $497,800 $497,800 $1,503,356

1 1 2 Storage Liquid Fuel Pump DCP CENTRIF $24,300 $48,600 $146,772

Totals $25,609,715 $39,624,415 $119,665,732
33

Appendix B. Aspen Plus Software Mass Flow and Balance 

Results and Process Flow Diagrams

Table B-1. Aspen Plus Software Section Mass and Mole Balances

In Out

% 

Change In Out % Change

Plant Recovery

Carbon 0.91 0.91 100.03% Carbon 1.12 1.12 100.00%

Hydrogen 2.54 2.54 100.05% Hydrogen 1.51 1.51 100.00%

Oxygen 1.92 1.92 100.24% Oxygen 1.52 1.52 100.00%

Nitrogen 2.44 2.44 99.92% Nitrogen 1.50 1.50 100.00%

Ash 1.39 1.37 98.33% Ash 0.21 0.21 100.00%

Mass 287,148 287,252 100.04% Mass 218,126 218,126 100.00%

Drying Storage

Carbon 0.91 0.91 100.00% Carbon 0.67 0.67 100.00%

Hydrogen 2.03 2.03 100.00% Hydrogen 1.20 1.20 100.00%

Oxygen 1.02 1.02 100.00% Oxygen 0.45 0.45 100.00%

Nitrogen 0.01 0.01 100.00% Nitrogen 0.00 0.00 100.00%

Ash 1.39 1.39 100.00% Ash 1.00 1.00 100.00%

Mass 110,905 110,905 100.00% Mass 62,957 62,957 100.00%

Pyrolysis Combustion

Carbon 1.29 1.29 100.38% Carbon 0.73 0.73 100.00%

Hydrogen 1.61 1.61 100.05% Hydrogen 0.47 0.47 100.00%

Oxygen 1.53 1.53 100.07% Oxygen 1.30 1.30 100.00%

Nitrogen 1.51 1.51 99.88% Nitrogen 2.26 2.26 100.00%

Ash 1.42 1.39 98.36% Ash 1.19 1.19 100.00%

Mass 230,902 231,006 100.04% Mass 226,395 226,395 100.00%

Cleanup Hydrotreating

Carbon 1.29 1.29 100.00% Carbon 0.56 0.56 99.18%

Hydrogen 1.61 1.61 100.00% Hydrogen 1.65 1.65 100.03%

Oxygen 1.53 1.53 100.00% Oxygen 1.14 1.14 100.30%

Nitrogen 1.51 1.51 100.00% Nitrogen 1.67 1.67 100.00%

Ash 1.39 1.39 100.00% Ash 0.20 0.20 100.00%

Mass 231,005 231,005 100.00% Mass 180,854 180,854 100.00%
34

Figure B-1. Biomass chopping process flow diagram (PFD)

Figure B-2. Biomass drying PFD
35

Table B-2. Stream Table for Biomass Drying

DR01 DR03 DR04 DRST1 DRST2 DRST3

Temperature °C 25 100 100 196.7 120 132.8

Pressure bar 1.013 1.013 1.013 14.479 1.983 2.181

Mass Flow kg/hr 

 N2 0 0 0 0 0 0

 O2 0 0 0 0 0 0

 H2 0 0 0 0 0 0

 CO 0 0 0 0 0 0

 CO2 0 0 0 0 0 0

 WATER 27778 21633 6145 0 0 0

 NH3 0 0 0 0 0 0

 CH4 0 0 0 0 0 0

 C2H4 0 0 0 0 0 0

 C3H6 0 0 0 0 0 0

 AR 0 0 0 0 0 0

 C2H4O2 0 0 0 0 0 0

 C3H6O2 0 0 0 0 0 0

 C7H8O2 0 0 0 0 0 0

 C8H10O 0 0 0 0 0 0

 CH2O2 0 0 0 0 0 0

 C10H12O2 0 0 0 0 0 0

 C6H6O 0 0 0 0 0 0

 C7H8 0 0 0 0 0 0

 C5H4O2 0 0 0 0 0 0

 C6H6 0 0 0 0 0 0

 NO 0 0 0 0 0 0

 NO2 0 0 0 0 0 0

 SULF 0 0 0 0 0 0

 METHANOL 0 0 0 0 0 0

 C8H18 0 0 0 0 0 0

 C10H22 0 0 0 0 0 0

 CL2 0 0 0 0 0 0

 STEAM 0 0 0 767236 767236 767236

 SO2 0 0 0 0 0 0

 CHAR 0 0 0 0 0 0

 STOVER 83334 0 83334 0 0 0

 ASH 0 0 0 0 0 0
36

Figure B-3. Biomass pyrolysis PFD
37

Table B-3. Stream Table for Biomass Pyrolysis

PY01 PY02 PY03 PY04

Temperature °C 100 56.7 250 480

Pressure bar 1.013 1.098 1.013 1.013

Mass Flow kg/hr 

 N2 0 75485 75485 75840

 O2 0 0 0 0

 H2 0 0 0 3

 CO 0 328 328 4953

 CO2 0 57392 57392 67651

 WATER 6145 7564 13709 16849

 NH3 0 0 0 0

 CH4 0 53 53 806

 C2H4 0 1 1 19

 C3H6 0 1 1 22

 AR 0 0 0 0

 C2H4O2 0 46 46 2818

 C3H6O2 0 79 79 13723

 C7H8O2 0 0 0 433

 C8H10O 0 1 1 2836

 CH2O2 0 362 362 12882

 C10H12O2 0 3 3 13698

 C6H6O 0 0 0 36

 C7H8 0 22 22 363

 C5H4O2 0 41 41 3032

 C6H6 0 0 0 6

 NO 0 0 0 0

 NO2 0 0 0 0

 SULF 0 0 0 0

 METHANOL 0 0 0 0

 C8H18 0 0 0 0

 C10H22 0 0 0 0

 CL2 0 0 0 0

 STEAM 0 0 0 0

 SO2 0 0 0 0

 CHAR 0 288 288 15121

 STOVER 83334 0 83334 0

 ASH 0 0 0 55
38

Figure B-4. Pyrolysis gas cleaning PFD
39

Table B-4. Stream Table for Pyrolysis Gas Cleaning

CL01 CL08 CL10

Temperature °C 480 480 480

Pressure bar 1.013 0.997 0.997

Mass Flow kg/hr 

 N2 75840 0 75840

 O2 0 0 0

 H2 3 0 3

 CO 4953 0 4953

 CO2 67651 0 67651

 WATER 16849 0 16849

 NH3 0 0 0

 CH4 806 0 806

 C2H4 19 0 19

 C3H6 22 0 22

 AR 0 0 0

 C2H4O2 2818 0 2818

 C3H6O2 13723 0 13723

 C7H8O2 433 0 433

 C8H10O 2836 0 2836

 CH2O2 12882 0 12882

 C10H12O2 13698 0 13698

 C6H6O 36 0 36

 C7H8 363 0 363

 C5H4O2 3032 0 3032

 C6H6 6 0 6

 NO 0 0 0

 NO2 0 0 0

 SULF 0 0 0

 METHANOL 0 0 0

 C8H18 0 0 0

 C10H22 0 0 0

 CL2 0 0 0

 STEAM 0 0 0

 SO2 0 0 0

 CHAR 15121 12853 2268

 STOVER 0 0 0

 ASH 55 47 8
40

Figure B-5. Bio-oil recovery PFD
41

Table B-5. Stream Table for Bio-Oil Recovery

RE01 RE02 RE03 RE04 RE05 RE06 RE07

Temperature °C 480 150 50 50 50 50 50

Pressure bar 0.997 0.997 1.014 1.014 1.013 1.013 1.013

Mass Flow kg/hr 

 N2 75840 75840 75840 0 0 0 75840

 O2 0 0 0 0 0 0 0

 H2 3 3 3 0 0 0 3

 CO 4953 4953 4953 0 0 0 4953

 CO2 67651 67651 67606 46 46 0 67606

 WATER 16849 16849 6159 10690 10690 0 6159

 NH3 0 0 0 0 0 0 0

 CH4 806 806 806 0 0 0 806

 C2H4 19 19 19 0 0 0 19

 C3H6 22 22 21 0 0 0 21

 AR 0 0 0 0 0 0 0

 C2H4O2 2818 2818 689 2129 2129 0 689

 C3H6O2 13723 13723 1197 12526 12526 0 1197

 C7H8O2 433 433 0 432 432 0 0

 C8H10O 2836 2836 8 2828 2828 0 8

 CH2O2 12882 12882 5472 7410 7410 0 5472

 C10H12O2 13698 13698 44 13653 13653 0 44

 C6H6O 36 36 1 35 35 0 1

 C7H8 363 363 338 25 25 0 338

 C5H4O2 3032 3032 615 2417 2417 0 615

 C6H6 6 6 6 0 0 0 6

 NO 0 0 0 0 0 0 0

 NO2 0 0 0 0 0 0 0

 SULF 0 0 0 0 0 0 0

 METHANOL 0 0 0 0 0 0 0

 C8H18 0 0 0 0 0 0 0

 C10H22 0 0 0 0 0 0 0

 CL2 0 0 0 0 0 0 0

 STEAM 0 0 0 0 0 0 0

 SO2 0 0 0 0 0 0 0

 CHAR 2268 2268 454 1815 2210 396 58

 STOVER 0 0 0 0 0 0 0

 ASH 8 8 2 7 8 1 0
42

Figure B-6. Bio-oil reforming and hydroprocessing PFD
43

Table B-6. Stream Table for Bio-Oil Reforming and Hydroprocessing

HY01 HY02 HY03 HY05 HY06 HY07 HY08

Temperature °C 50 50 56.2 450 140.7 50 260

Pressure bar 1.014 1.014 68.948 68.948 1.014 1.014 13.79

Mass Flow kg/hr 

 N2 0 0 0 0 0 0 0

 O2 0 0 0 0 0 0 0

 H2 0 0 0 1 0 0 0

 CO 0 0 0 0 0 0 0

 CO2 46 28 28 8500 0 18 18

 WATER 10690 6576 6576 10501 0 4115 24204

 NH3 0 0 0 0 0 0 0

 CH4 0 0 0 1070 0 0 0

 C2H4 0 0 0 0 0 0 0

 C3H6 0 0 0 0 0 0 0

 AR 0 0 0 0 0 0 0

 C2H4O2 2129 1310 1310 0 0 820 820

 C3H6O2 12526 7705 7705 0 0 4821 4821

 C7H8O2 432 266 266 0 0 166 166

 C8H10O 2828 1739 1739 0 0 1088 1088

 CH2O2 7410 4558 4558 0 0 2852 2852

 C10H12O2 13653 8398 8398 0 0 5255 5255

 C6H6O 35 22 22 0 0 14 14

 C7H8 25 15 15 0 0 10 10

 C5H4O2 2417 1487 1487 0 0 930 930

 C6H6 0 0 0 0 0 0 0

 METHANOL 0 0 0 0 0 0 0

 C8H18 0 0 0 6691 6691 0 0

 C10H22 0 0 0 6691 6691 0 0

 CL2 0 0 0 0 0 0 0

 STEAM 0 0 0 0 0 0 0

 SO2 0 0 0 0 0 0 0

 CHAR 2210 1360 1360 1360 0 851 851

 STOVER 0 0 0 0 0 0 0

 ASH 8 5 5 5 0 3 3
44

(continued) HY09 HY10 HY11 HY012 HY12 HY13 HY14

Temperature °C 400 696.1 700 50 410 40 38.8

Pressure bar 13.79 13.79 13.79 1.014 13.79 13.79 9.632

Mass Flow kg/hr 

 N2 0 0 0 0 0 0 0

 O2 0 0 0 0 0 0 0

 H2 0 0 1350 0 1350 1350 1350

 CO 0 0 5029 0 5029 5029 0

 CO2 18 18 15763 46 15763 15763 0

 WATER 24204 24204 14862 10690 14862 14862 0

 NH3 0 0 0 0 0 0 0

 CH4 0 0 3175 0 3175 3175 0

 C2H4 0 0 0 0 0 0 0

 C3H6 0 0 0 0 0 0 0

 AR 0 0 0 0 0 0 0

 C2H4O2 820 820 0 2129 0 0 0

 C3H6O2 4821 4821 0 12526 0 0 0

 C7H8O2 166 166 0 432 0 0 0

 C8H10O 1088 1088 0 2828 0 0 0

 CH2O2 2852 2852 0 7410 0 0 0

 C10H12O2 5255 5255 0 13653 0 0 0

 C6H6O 14 14 0 35 0 0 0

 C7H8 10 10 0 25 0 0 0

 C5H4O2 930 930 0 2417 0 0 0

 C6H6 0 0 0 0 0 0 0

 METHANOL 0 0 0 0 0 0 0

 C8H18 0 0 0 0 0 0 0

 C10H22 0 0 0 0 0 0 0

 CL2 0 0 0 0 0 0 0

 STEAM 0 0 0 0 0 0 0

 SO2 0 0 0 0 0 0 0

 CHAR 0 0 0 2210 0 0 0

 STOVER 0 0 0 0 0 0 0

 ASH 0 0 0 8 0 0 0
45

(continued) HY15 HY16 HY17 HY21 HY22 HY24 HY25

Temperature °C 174.5 38.8 26.4 25 50.7 25 25.6

Pressure bar 25 9.632 1.013 1.014 1.014 1.014 13.79

Mass Flow kg/hr 

 N2 0 0 0 78064 78065 0 0

 O2 0 0 0 23703 3951 0 0

 H2 1350 0 1 0 0 1 0

 CO 0 5029 5029 0 0 0 0

 CO2 0 15763 24244 0 43750 8500 0

 WATER 0 14862 631 0 10137 10501 20089

 NH3 0 0 0 0 0 0 0

 CH4 0 3175 4230 0 0 1070 0

 C2H4 0 0 0 0 0 0 0

 C3H6 0 0 0 0 0 0 0

 AR 0 0 0 0 0 0 0

 C2H4O2 0 0 0 0 0 0 0

 C3H6O2 0 0 0 0 0 0 0

 C7H8O2 0 0 0 0 0 0 0

 C8H10O 0 0 0 0 0 0 0

 CH2O2 0 0 0 0 0 0 0

 C10H12O2 0 0 0 0 0 0 0

 C6H6O 0 0 0 0 0 0 0

 C7H8 0 0 0 0 0 0 0

 C5H4O2 0 0 0 0 0 0 0

 C6H6 0 0 0 0 0 0 0

 METHANOL 0 0 0 0 0 0 0

 C8H18 0 0 0 0 0 0 0

 C10H22 0 0 0 0 0 0 0

 CL2 0 0 0 0 0 0 0

 STEAM 0 0 0 0 0 0 0

 SO2 0 0 0 0 0 0 0

 CHAR 0 0 0 0 851 1360 0

 STOVER 0 0 0 0 0 0 0

 ASH 0 0 0 0 3 5 0
46

(continued) HY26 HY27 HY28 HY30 HY31 HY071 HY152

Temperature °C 371.1 370 400 51.3 382

Pressure bar 13.79 13.79 13.79 13.79 69

Mass Flow kg/hr 

 N2 0 0 0 0 0

 O2 0 0 0 0 0

 H2 0 0 0 0 1350

 CO 0 0 0 0 0

 CO2 0 0 0 18 0

 WATER 20089 20089 0 4115 0

 NH3 0 0 0 0 0

 CH4 0 0 0 0 0

 C2H4 0 0 0 0 0

 C3H6 0 0 0 0 0

 AR 0 0 0 0 0

 C2H4O2 0 0 0 820 0

 C3H6O2 0 0 0 4821 0

 C7H8O2 0 0 0 166 0

 C8H10O 0 0 0 1088 0

 CH2O2 0 0 0 2852 0

 C10H12O2 0 0 0 5255 0

 C6H6O 0 0 0 14 0

 C7H8 0 0 0 10 0

 C5H4O2 0 0 0 930 0

 C6H6 0 0 0 0 0

 METHANOL 0 0 0 0 0

 C8H18 0 0 0 0 0

 C10H22 0 0 0 0 0

 CL2 0 0 0 0 0

 STEAM 0 0 0 0 0

 SO2 0 0 0 0 0

 CHAR 0 0 851 851 0

 STOVER 0 0 0 0 0

 ASH 0 0 3 3 0
47

(continued) HYEFFGAS HYEFFLIQ HYWATER

Temperature °C 62 26.4 25

Pressure bar 1.115 1.013 1.013

Mass Flow kg/hr 

 N2 78065 0 0

 O2 3951 0 0

 H2 0 0 0

 CO 0 0 0

 CO2 43750 19 0

 WATER 10137 24732 20089

 NH3 0 0 0

 CH4 0 15 0

 C2H4 0 0 0

 C3H6 0 0 0

 AR 0 0 0

 C2H4O2 0 0 0

 C3H6O2 0 0 0

 C7H8O2 0 0 0

 C8H10O 0 0 0

 CH2O2 0 0 0

 C10H12O2 0 0 0

 C6H6O 0 0 0

 C7H8 0 0 0

 C5H4O2 0 0 0

 C6H6 0 0 0

 METHANOL 0 0 0

 C8H18 0 0 0

 C10H22 0 0 0

 CL2 0 0 0

 STEAM 0 0 0

 SO2 0 0 0

 CHAR 851 1360 0

 STOVER 0 0 0

 ASH 3 5 0
48

Appendix C. Selection Process of Pyrolysis Reactor 

Technologies for Further Analysis under Iowa State 

University/ConocoPhillips Company/National Renewable 

Energy Laboratory Collaborative Study

Purpose

The purpose of this section is to describe the selection process employed to down select 

pyrolysis technologies and bio-oil upgrading to transportation fuels for further research 

and development.

Summary 

Six different pyrolysis technologies were initially chosen to compare based on selected 

criteria. These technologies, based on the reactor design, were bubbling bed, circulating 

(transported) bed, auger, free fall (entrained flow), ablative, and catalytic pyrolysis (fluid 

bed). Hydrothermal processing was added during the down-selection process based on its 

similar primary liquid product. Two bio-oil upgrading technologies were considered: 

hydrogenation (hydrocracking) and gasification via the Fischer-Tropsch process.

Bubbling-bed pyrolysis was chosen as the base case because of the availability of reliable 

and established data. Positive and negative ratings were given to other technologies based 

on how they compared to the base case on various criteria. These ratings allowed for the 

selection of technologies for focus in the current study. Bubbling-bed, auger, and freefall pyrolysis reactors were chosen for further research. Further inquiries into 

hydrothermal processing and hydrogenation will be done as well.

Background

A process design matrix was developed to aid in the collection of data for various 

technologies. These technologies were grouped into biochemical, gasification, pyrolysis, 

upgrading, and supporting technologies. The selected criteria included capital 

expenditure, operating costs, plant efficiency, carbon efficiency, capacity factor, plant 

size (typical), complexity of process, level of technology development, and energy 

content, among others. Based on these criteria, circulating (transported) bed, auger, free 

fall (entrained flow), ablative, and catalytic pyrolysis (fluid bed) were rated and 

compared to bubbling bed pyrolysis.

This down selection process was an informal process, based on the knowledge and 

experience of the team. No specific references were consulted in this process.

Selection Process

Bubbling-bed pyrolysis was chosen as the base-case pyrolysis technology because of the 

availability of reliable and established information. Following is a short description of 

how each of the considered alternative technologies compares to the base case in terms of 

the process design criteria.
49

Circulating (Transported) Bed

This technology requires a higher capital cost due to the need for additional reactor 

vessels and related equipment. Operating costs are also expected to be higher because of 

increased fluidizing gas requirements and the recirculation of inert bed material. Based 

on available knowledge, circulating bed has a lower plant and carbon efficiency. The 

capacity factor rating, defined as the availability of the system, is lower than the base 

case due to additional maintenance requirements associated with the use of additional 

equipment. Circulating-bed reactors, similar to bubbling-bed reactors, are better suited 

for larger sizes and are therefore not attractive economically for a distributed processing 

scenario. The complexity of this process is higher than for the base case. In terms of level 

of technology development, this configuration had an identical rating to the bubbling-bed 

technology.

Auger

The auger reactor was given an identical capital expenditure rating to the base case based 

on the assumption that increases in capital requirements for the reactor could be offset by 

savings in auxiliary equipment. Augers are expected to reduce operating costs. Plant 

efficiency was given an identical rating, while the carbon efficiency is expected to suffer 

under this configuration due to lower yields. The use of mechanical moving parts reduced 

the capacity factor rating. An auger reactor’s typical size is well suited for a distributed 

processing scenario where smaller is better. Process steps might be eliminated, reducing 

the complexity of the process. The level of technology development is considered low for 

this technology.

Free Fall (Entrained Flow)

A free-fall reactor is the only option with a lower capital expense requirement. This 

reactor is also expected to have lower operating costs. Its plant efficiency is lower than 

the bubbling bed’s efficiency, and the same applies to the carbon efficiency due to lower 

yields. This is the only option with a better capacity factor than the base case. The typical 

plant size is comparable to the bubbling bed. The complexity is expected to be lower, 

although the level of development is low.

Ablative

Capital expenditure for ablative reactors is expected to be comparable to the bubblingbed technology. Operating costs are rated lower than the base case. Plant efficiency is 

similar to the bubbling bed. The carbon efficiency is lower for this technology, as is the 

capacity factor due to the mechanical requirements. Ablative reactors are better suited to 

small-scale operations. The complexity and level of technology development both 

received a negative rating.

Catalytic Pyrolysis

The catalytic pyrolysis analysis was based on the assumption that it employed a fluid-bed 

reactor design. There has not been much research done in this area, but like catalytic 

gasification, catalytic pyrolysis suffers from sulfur and chlorine poisoning of the 

catalysts. This option received negative ratings for all criteria with the exception of plant 

size, for which it is expected to have the same typical size as the base case.
50

Other Technologies

Hydrothermal processing is a different process than pyrolysis. This process involves 

pressurizing biomass in an aqueous solution using a batch process that requires heat and 

significant amounts of water. The hydrocarbon portion of the product contains less 

oxygen than typical bio-oil and is closer in composition to fossil-based oil. Because it is 

currently at a very early development stage, not enough techno-economic information is 

available, although up-to-date commercialization efforts have not been promising. This 

process yields a superior product, in terms of energy content, compared to pyrolysis, and 

this is the main reason for its inclusion in this study. 

Hydrogenation/hydrocracking was selected for further study as well. This upgrading 

technology would be used at a large-scale facility. The level of technology development 

for this process is considered to be low at this time.

Action

The next step in this collaboration is to prepare Aspen software models for the selected 

technologies: bubbling-bed, auger, and free-fall pyrolysis. Hydrogenation/hydrocracking 

will also be evaluated. For this purpose, a work plan is being developed. In January of 

2008, the plan will be presented regarding the Aspen software models’ level of detail and 

assumptions.
51

Appendix D. Assumptions for Pyrolysis Technologies 

Techno-Economic Studies

Plant Size, Location, and Construction

• Various plant sizes will be regarded as economically feasible plant size, 

specifically plant capacities of 5, 50, and 550 tons/day (dry feedstock)

• Scenarios will aggregate plants to a total capacity of 2,000 tons/day

• Biomass collection area for 2,000 tons/day has a 50 mile radius, and 

transportation costs are 23% of feedstock costs with linear scaling for smallersized areas

• The plant produces pyrolysis gas, bio-oil, and charcoal

• The plant is considered to be located in the middle of corn farmland

o 25% of the land will be tied up in infrastructure (roads and buildings), and 

o 75% of the farm land plants corn 

• The plant will be designed based on the state of the technology and would be the 

nth plant of its kind 

• The online time would be 350 days/year (equivalent capacity factor of 96%) 

• Construction time of less than 24 months is considered based on judgment

o Startup period would be 25% of the construction time (6 months)

o During this period, an average of 50% production will be 

achieved with expenditure of about 75% of variable expenses 

and 100% of fixed expenses

Feedstock

• Corn stover (comprised of stalks, leaves, cobs and husks) is considered as 

feedstock

o The feedstock will be delivered to the feed handling area of the plant 

o Moisture content in the feedstock is 15% (wet basis)

o Variation of feed compositions will be incorporated in the model

o The feedstock transportation and management protocol are not considered

o Feed cost is assumed to be $50/dry MT with credit for reduced 

transportation cost

Material and Energy Balance

Material Balance 

• Biomass will be modeled using ultimate and proximate analyses data and the 

Aspen software coal model

• Biomass handling will be specified to less than 5-mm grinding size and 7% 

moisture content, also depending on specific process requirements
52 

• No biomass material is lost during washing 

• Various bio-oil compositions will be considered; bio-oil components of interest 

are formic acid, hydroxyacetaldehyde, acetic acid, diacetyl, glyoxal, acetol, 

levoglucosan, cellobiosan, water, and pyrolytic lignin 

• Where necessary, nitrogen will be employed as a fluidizing agent and pyrolysis 

gas recirculation will also be considered 

• Carbon efficiency can be calculated based on carbohydrate carbon content, as 

follows: 

ൌ ሻ%ሺ ݕ݂݂݁݅ܿ݅݁݊ܿ ݊݋ܾݎܽܥ

݈݅݋ െ ݋݅ܤ ݅݊ ݊݋ܾݎܽܥ

100 ൈ ݁ݐܽݎ݀ݕ݄݋ܾݎܽܥ ݏݏ݉ܽ݋݅ܤ ݅݊ ݊݋ܾݎܽܥ

Energy Balance 

• An Aspen software yield reactor model will be employed to calculate reaction 

energy balance 

• Combustor energy losses will be factored into the model 

• The energy value of the products will be reported to measure an overall energy 

balance.

Equipment Design, Material of Construction and Costing 

Equipment Design 

• The reactors will be modeled using experimentally determined conversions of 

specific reactions (kinetic expressions will be not used because of the level of 

their development) 

• If the size of any equipment is known to change linearly with the inlet flow, that 

information can be used for equipment scaling (a characteristic of the size might 

be the heat duty for a heat exchanger if the log-mean temperature difference is 

known not to change) 

• For some equipment, nothing can be easily related to the size, in which case the 

unit will be resized with each process change (for example, heat exchangers with 

varying temperature profiles; in this case, the heat exchanger area will be 

calculated each time the model will be run and the cost will be scaled using the 

ratio of the new and original areas) 

Material of Construction 

• Most construction material will consist of stainless steel 

Costing 

• Equipment costing data and installation factors will be collected from direct 

quotations, published data, and Aspen Icarus software evaluation, with preference 

given in the order shown here 

• If process changes are made and the equipment size changes, the equipment will 

be re-costed following the exponential scaling expression: 
53 

ܰ݁ݓ ݐݏ݋ܥ ൌ ܱݎ݈݅݃݅݊ܽ Cost ൬ New size כ

Original size כ൰

ୣ୶୮

 *or characteristic linearly related to the size 

• The purchased equipment cost obtained in a particular year will be indexed to the 

year of interest (2012) using the Chemical Engineering Index 

o The existing value of the index will be regressed to extrapolate to the 

future year (2012)

Chemical Costing 

• Costs for acids and other chemicals, if considered, will be obtained from 

quotation 

o The cost of the chemicals will also be indexed following the Industrial 

Inorganic Chemical Index (from SRI) to estimate the cost of the chemicals 

in the future year of interest (2012) 

Operating Cost 

• Working capital is assumed to be 5% of the total capital investment 

o It is assumed that the product will be made and shipped and that payment 

will be received in 30 days 

• Annual maintenance materials cost will be 2% of the total installed equipment 

cost 

• Employee salaries will be indexed to the future year of interest (2012) following 

the data of the Bureau of Labor Statistics 

• Salaries of the yard employees will not include benefits and will be covered in the 

general overhead category 

o General overhead will be a factor of 60% applied to the total salaries and 

covers items such as safety, general engineering, general plant 

maintenance, payroll overhead (including benefits), plant security, 

janitorial and similar services, phone, light, heat, and plant 

communications 

Wastewater Treatment Plant 

• The process will be designed for zero discharge to a municipal treatment plant in 

a steady state mode 

• Any process upset (sudden increase of solids in the wastewater) will not 

considered in the model 

• Rain and snow run-off, equipment washing, and other non-process waters are 

assumed to flow to the municipal wastewater treatment system; other intermittent 

loads (process spills) will not be considered in the design 
54

Greenhouse Emissions and Control 

• All of the sulfur going into the combustor is converted to SO2

Cost Analysis

• The total plant investment cost will be determined by applying overhead and 

contingency factors (NREL experience and literature) to installed equipment 

costs

• Insurance and taxes will be considered as 1.5% of the total installed equipment 

cost (Delta-T/NREL/published data)

o The estimates are location-sensitive 

• To determine the product value per gallon of liquid fuel, a discounted cash flow 

analysis will be used after knowing the major three costs areas: (i) total project 

investment, (ii) variable operating costs, and (iii) fixed operating cost 

o A 10% discounted cash flow rate of return will be used over a 20-year 

plant life

o The plant is considered 100% equity financed

• For federal tax returns, depreciation will be determined as follows:

o The IRS modified accelerated cost recovery system, including the general 

depreciation system will be followed; this allows both the 200% and 150% 

declining balance (DB) methods of depreciation

o This allows the shortest recovery period and the largest 

deductions

o Other property not specifically described in the publication should be 

depreciated using a 7-year recovery period 

o Property listed with a recovery period less than 10 years will 

use the 200% DB depreciation method and 20-year-recoveryperiod property will use the 150% DB depreciation

o State tax will not be considered for the calculation (because the location of 

the plant is not specified) 

• Return on investment will be calculated on a per gallon basis; income tax will be 

averaged over the plant life and that average will be calculated on a per gallon 

basis 
55

Table D-1. Biomass Pyrolysis/Torrefaction Design Matrix

2 matrices - stover and softwood Capital Expenditure (Total Project Investment)

Operating Costs ($ per year)Fuel Cost ($/gal)IRREconomic Rsk/Uncertainty (L, M, H)Plant Efficiency(Energy in product/(Energy in + Energy bioCarbon Efficiency (C in Productsl/C in FeedstocProcess Fuel Yield (liters/tonne)Capacity Factor/On-stream TimePlant Size (tons feed or gallons fuel) *Complexity of Process (No. of steps)Level of Technology Development (L, M, H)Water Use/Discharge (gal water/gal fuel)Greenhouse Gas Emissions (Nox, Sox, CO, CO2)Particulates/Solid Wastes (tons/year)

Air Emissions (tons/year)

Types of Waste Treatment RequiredToxic Materials Generated or Used?Energy Content (LHV, Btu/gal)Engine CompatibilityUse Emissions

Infrastructure C

Fuel Toxi

Ab 

Pyrolysis Technologies (Bio-oil product) (ISU lead)

Bubbling Bed 0 0 0 0 0 0 0 0 0

Circulating / Transport Bed - - - - - - - 0 0

Auger 0 + 0 - - + + - 0

Free Fall (Entrained Flow) + + - - + 0 + - 0

Ablative 0 + 0 - - + - - 0

Catalytic Pyrolysis (Fluid Bed) - - - - - 0 - - 0

Hydrothermal Processing (HTP) - - 0 - - 0 - 0 +

Bio-oil Upgrade to Transportation Fuels

Hydrogenation/Hydrocracking + + + + + 0 + -

Gasification (FT process)

Supporting Technologies

Lignin depolymerization/catalysis

Lignin pyrolysis/hydrogenation

Lignin gasification

Torrefaction

Economics Process Environmental Fuel Properties
56

Table D-2. Hydrogen-Production Scenario Discounted Cash Flow Rate of Return Worksheet
57
58

Table D-3. Hydrogen-Purchase Scenario Discounted Cash Flow Rate of Return Worksheet
59
60

Table D-4. Hydrogen-Production Scenario Detailed Operating Cost Analysis
61

Table D-5. Hydrogen-Purchase Scenario Detailed Operating Cost Analysis
62

Table D-6. Hydrogen-Production Scenario Detailed Capital Investment Analysis

Table D-7. Hydrogen-Purchase Scenario Detailed Capital Investment Analysis
F1147-E(10/2008)

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Techno-Economic Analysis of Biomass Fast Pyrolysis to 

Transportation Fuels 

5a. CONTRACT NUMBER

DE-AC36-08-GO28308

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6. AUTHOR(S)

M.M. Wright, J.A. Satrio, R.C. Brown, D.E. Daugaard, and D.D. Hsu

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NREL/TP-6A20-46586

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BB07.7510

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14. ABSTRACT (Maximum 200 Words)

This study develops techno-economic models for assessment of the conversion of biomass to valuable fuel products 

via fast pyrolysis and bio-oil upgrading. The upgrading process produces a mixture of naphtha-range (gasoline blend 

stock) and diesel-range (diesel blend stock) products. This study analyzes the economics of two scenarios: onsite 

hydrogen production by reforming bio-oil, and hydrogen purchase from an outside source. The study results for an 

nth plant indicate that petroleum fractions in the naphtha distillation range and in the diesel distillation range are 

produced from corn stover at a product value of $3.09/gal ($0.82/liter) with onsite hydrogen production or $2.11/gal 

($0.56/liter) with hydrogen purchase. These values correspond to a $0.83/gal ($0.21/liter) cost to produce the bio-oil. 

Based on these nth plant numbers, product value for a pioneer hydrogen-producing plant is about $6.55/gal 

($1.73/liter) and for a pioneer hydrogen-purchasing plant is about $3.41/ gal ($0.92/liter). Sensitivity analysis 

identifies fuel yield as a key variable for the hydrogen-production scenario. Biomass cost is important for both 

scenarios. Changing feedstock cost from $50–$100 per short ton changes the price of fuel in the hydrogen 

production scenario from $2.57–$3.62/gal ($0.68–$0.96/liter).

15. SUBJECT TERMS

biomass; biofuels; techno-economic analysis; pyrolysis; bio-oil; thermochemical; hydroprocessing

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