1 

Strategic Assessment of Bioenergy 

Development in the West 

Bioenergy Conversion Technology 

Characteristics 

FINAL REPORT

Antares Group Inc.  

September 1, 2008 
i 

Strategic Assessment of Bioenergy Development in the West 

In February 2008, the Western Governors’ Association adopted a policy reaffirming the 

governors’ strong commitment to enhance and diversify the region's transportation fuels 

portfolio. The Strategic Assessment of Bioenergy Development in the West represents a 

major step in fulfilling that commitment and expands upon earlier work through WGA's 

Clean and Diversified Energy Initiative and the Transportation Fuels Initiative. The 

Bioenergy Assessment Team was formed to examine the potential for future development 

and to create a comprehensive framework to assess environmental, technical and 

socioeconomic impacts associated with national, state and regional bioenergy and biomass 

management policies. This assessment will assist the governors individually and collectively 

as they develop bioenergy policies. The extensive evaluations conducted by the Assessment 

Team are contained in the following areas: 

• Biomass Resources in the Western States 

• Biofuel Conversion Technologies 

• Spatial Analysis and Supply Curve Development 

• Analyses of Deployment Scenarios and Policy Interactions 

While the assessment represents the consensus view of its authors, it is not adopted policy 

and does not represent the views of WGA or any individual Western Governor. Support for 

this work was provided by the U.S. Department of Agriculture. 

Members of the Western Bioenergy Assessment Team 

Western Governors’ Association: Gayle Gordon 

University of California, Davis: Nathan Parker, Peter Tittmann, Quinn Hart, Mui Lay, 

Joshua Cunningham and Bryan Jenkins 

Kansas State University: Richard Nelson 

U.S. Forest Service: Ken Skog, Marcia Patton Mallory, Robert Rummer and R. James 

Barbour 

U.S. Department of the Interior: John Stewart 

Antares Group, Inc.: Edward Gray, Anneliese Schmidt and Chris Lindsey 

Future Resources Association: Gregg Morris 

National Renewable Energy Laboratory: Anelia Milbrandt 

 

Consultants: Jim Kerstetter and Ralph Overend 
ii 

TABLE OF CONTENTS 

1 INTRODUCTION ................................................................................................................................................. 1

2 CURRENT TECHNOLOGIES ........................................................................................................................... 4

2.1 GRAIN TO ETHANOL CONVERSION ................................................................................................................ 4

2.1.1 Technology Description ...................................................................................................................... 4

2.1.2 Performance and cost analysis ......................................................................................................... 6

2.2 FATTY ACID TO METHYL ESTERS: TRANSESTERIFICATION (BIODIESEL) ................................................... 10

2.2.1 Technology Description .................................................................................................................... 10

2.2.2 Performance and cost analysis ....................................................................................................... 12

2.3 SUGAR TO ETHANOL FERMENTATION ......................................................................................................... 14

3 TECHNOLOGIES READY FOR COMMERCIALIZATION IN THE MIDTERM (2010 – 2025) ............. 16

3.1 LIGNOCELLULOSICS TO ETHANOL: HYDROLYSIS AND FERMENTATION ...................................................... 16

3.1.1 Technology Description .................................................................................................................... 17

3.1.2 Performance and cost analysis ....................................................................................................... 20

3.2 LIGNOCELLULOSICS TO ETHANOL: THERMOCHEMICAL CONVERSION AND FERMENTATION ...................... 27

3.2.1 Technology Description .................................................................................................................... 28

3.3 LIGNOCELLULOSICS TO MIDDLE DISTILLATES: FISCHER TROPSCH ........................................................... 30

3.3.1 Technology Description .................................................................................................................... 30

3.3.2 Performance and cost analysis ....................................................................................................... 32

3.4 LIGNOCELLULOSICS TO MIXED ALCOHOLS: THERMOCHEMICAL CONVERSION .......................................... 36

3.4.1 Technology Description .................................................................................................................... 36

3.4.2 Performance and cost analysis ....................................................................................................... 38

3.5 LIGNOCELLULOSICS TO GASOLINE: UPGRADING PYROLYSIS OIL .............................................................. 40

3.5.1 Technology Description .................................................................................................................... 40

3.5.2 Performance and cost analysis ....................................................................................................... 44

3.6 FATTY ACIDS TO HYDROCARBON (RENEWABLE DIESEL): HYDROTREATMENT ......................................... 47

3.6.1 Technology Description .................................................................................................................... 48

3.6.2 Performance and cost analysis ....................................................................................................... 50

4 EMISSIONS DATA FOR BIOFUEL CONVERSION TECHNOLOGIES .................................................. 53

4.1 YIELDS AND WATER USE ............................................................................................................................. 53

4.2 GREENHOUSE GAS AND CRITERIA POLLUTANT EMISSIONS ....................................................................... 54

REFERENCES .......................................................................................................................................................... 58

APPENDIX A CONVERSION TECHNOLOGY STATUS MATRIX .................................................................. 62

APPENDIX B CONVERSION TECHNOLOGY PRETREATMENT MATRIX .................................................. 64

APPENDIX C ECONOMIC ANALYSIS FACTORS ............................................................................................ 65

APPENDIX D ADDITIONAL INFORMATION - GRAIN TO ETHANOL PROCESSES ................................. 67

APPENDIX E OILSEED CROP FEEDSTOCK CONVERSION TO OIL .......................................................... 70

APPENDIX F BIOMASS RECOVERED FROM MSW ........................................................................................ 72

APPENDIX G CONVERSION TECHNOLOGY MODEL CALCULATORS ..................................................... 73
iii 

List of Figures 

FIGURE 1 – SCHEMATIC DIAGRAM OF DRY MILLING ETHANOL PRODUCTION PROCESS ............................................ 4

FIGURE 2 – SCHEMATIC DIAGRAM OF WET-MILLING PROCESS FOR CONVERSION OF GRAIN TO STARCH ............... 6

FIGURE 3 – PROJECTED CORN PRICES ...................................................................................................................... 10

FIGURE 4 – SCHEMATIC DIAGRAM OF TRANSESTERIFICATION PROCESS ................................................................. 11

FIGURE 5 – SCHEMATIC DIAGRAM OF LCE FERMENTATION/HYDROLYSIS PROCESS ................................................ 18

FIGURE 6 – ETHANOL PRODUCTION EFFICIENCY AND YIELD FROM PUBLISHED DATA FOR VARIOUS TIME PERIODS . 21

FIGURE 7 – ETHANOL PRODUCTION CAPACITY AND TOTAL CAPITAL INVESTMENT FOR VARIOUS TIME PERIODS ...... 22

FIGURE 8 – SCHEMATIC DIAGRAM SHOWING LCE FERMENTATION/TC PROCESS .................................................... 29

FIGURE 9 – SCHEMATIC DIAGRAM SHOWING GENERAL PROCESS STEPS FOR FTS .................................................. 31

FIGURE 10 – BASIS FOR MID-TERM LCMD - FT TECHNOLOGY CHARACTERIZATION .............................................. 34

FIGURE 11 - SCHEMATIC DIAGRAM OF THERMOCHEMICAL ETHANOL PRODUCTION PROCESS .................................. 37

FIGURE 12 – SCHEMATIC DIAGRAM OF THE LCG UPGRADING/PYROLYSIS PROCESS ............................................. 43

FIGURE 13 – CAPITAL COST AND PLANT SIZE RELATION FOR FAST PYROLYSIS ......................................................... 46

FIGURE 14 – LABOR COST SCALING BY FACILITY SIZE FOR PYROLYSIS OIL PRODUCTION ......................................... 47

FIGURE 15 – SCHEMATIC DIAGRAM OF RENEWABLE DIESEL PRODUCTION IN PETROLEUM REFINERY ...................... 49

FIGURE 16 – PROJECTED SOYBEAN OIL PRICE ......................................................................................................... 71

FIGURE 17 – PROJECTED CANOLA OIL PRICE ........................................................................................................... 71

List of Tables 

TABLE 1 – CURRENT AND ADVANCED BIOFUEL CONVERSION TECHNOLOGIES .......................................................... 2

TABLE 2 - EXAMPLE COST AND PERFORMANCE OUTPUTS FOR DRY MILL FACILITY .................................................. 9

TABLE 3 - EXAMPLE COST AND PERFORMANCE OUTPUTS FOR WET MILL FACILITY .................................................. 9

TABLE 4 – BIODIESEL YIELDS FOR VARIOUS FEEDSTOCKS ......................................................................................... 13

TABLE 5 - EXAMPLE COST AND PERFORMANCE FOR BASE CATALYZED TRANSESTERIFICATION FACILITY ............. 14

TABLE 6 - EXAMPLE COST AND PERFORMANCE FOR ACID CATALYZED TRANSESTERIFICATION FACILITY .............. 14

TABLE 7 - TYPICAL BIOCHEMICAL COMPOSITIONS OF VARIOUS FEEDSTOCKS ........................................................... 17

TABLE 8 - CAPITAL COST BREAK-OUT FOR LCE FERMENTATION/HYDROLYSIS WITH DILUTE ACID PRETREATMENT 23

TABLE 9 - CONVERSION RATES FOR LCE FERMENTATION/HYDROLYSIS .................................................................. 24

TABLE 10 - FEEDSTOCK COMPOSITION AND YIELD DATA .......................................................................................... 26

TABLE 11 - EXAMPLE COST AND PERFORMANCE - MID TERM DILUTE ACID LCE FERMENTATION/HYDROLYSIS .... 27

TABLE 12 - EXAMPLE COST AND PERFORMANCE - MID TERM STEAM EXPLOSION LCE

FERMENTATION/HYDROLYSIS ............................................................................................................................. 27

TABLE 13 - EXAMPLE COST AND PERFORMANCE FOR FISCHER TROPSCH FACILITY ............................................... 36

TABLE 14 - EXAMPLE COST AND PERFORMANCE FOR ETHANOL FROM LCMA SYNTHESIS/TC ............................... 40

TABLE 15 - EXAMPLE COST AND PERFORMANCE FOR LCG UPGRADING/PYROLYSIS .............................................. 47

TABLE 16 - EXAMPLE COST AND PERFORMANCE FOR FAHC - HYDROTREATMENT STAND ALONE PROCESS ....... 52

TABLE 17 - EXAMPLE COST AND PERFORMANCE FOR FAHC - HYDROTREATMENT CO-PROCESSING .................... 52

TABLE 18 – WATER USE AND YIELD FOR VARIOUS CONVERSION TECHNOLOGIES .................................................. 53

TABLE 19 - SUMMARY OF CONVERSION TECHNOLOGY EMISSIONS FROM PUBLISHED LIFE CYCLE ANALYSES ....... 54

TABLE 20 – CO2 EMISSIONS (G/GALLON) FROM BIOFUEL CONVERSION BASED ON TECHNOLOGY MODEL DATA ...... 56

TABLE 21 – OIL CONTENT OF VARIOUS OILSEED FEEDSTOCKS .................................................................................. 70

TABLE 22 COMPOSITION OF MSW STREAM COMPONENTS ..................................................................................... 72
iv 

Contributors 

Antares Group, Inc. 

Ed Gray, President 

Christopher Lindsey, Associate Principal 

Anneliese Schmidt, Renewable Research Scientist 

Acknowledgements 

The authors would like to acknowledge the efforts of the following people for their technical 

review of this report: Jim Kerstetter; Nick Nagel, National Renewable Energy Laboratory; 

Graham Parker, Pacific Northwest National Laboratory; John Scahill, U.S. Department of 

Energy Golden Field Office; Richard Hamilton, Ceres, Inc.; Ken Vogel, University of 

Nebraska; Joe Bouton, The Noble Foundation; Thomas Robb, Abengoa Bioenergy; David 

Hallberg, PRIME BioSolutions; Bill Carlson, Carlson Small Power Associates. 
1 

1 Introduction 

This analysis investigates the biofuel conversion technologies that are currently available, as 

well as technologies currently under development that are far enough along the 

development path to potentially be available on a commercial basis in the time frame for 

the strategic assessment (circa 2015). Due to the complexity of the biofuel conversion 

technologies, there is no simple equation to describe production costs and process yields. 

As such, spreadsheet models were developed to calculate the costs and yields for selected 

technologies based on key variables: feedstock type, conversion option and facility size.1

 

The technologies were chosen to be representative of the types of biofuel production 

processes that the assessment team believes can be commercial in the mid term. They are 

not endorsements of any specific technology and the assessment team believes that the 

actual plant configurations built will likely incorporate features that could not be foreseen in 

this study. The technology choices for detailed analysis were based on the relative benefits 

and challenges for each conversion process, status of the technology, and availability of 

published data. It is assumed that to have a significant presence in future markets, 

competing technologies will need to have similar or better yields and similar or lower 

production costs than the modeled technologies. 

Ten biofuel conversion technologies were considered in the assessment. Brief explanations 

and process descriptions for each of these conversion technologies are given in Table 1. 

Reference name abbreviations are also included in this table. An overview of the benefits, 

challenges and status of each technology is provided in Appendix A. Detailed technical 

descriptions of the current conversion processes are given in Section 2, and descriptions of 

the advanced technologies are provided in Section 3. A summary of pretreatment 

requirements for the technologies is given in Appendix B. 

From the detailed characterization, the following conversion technologies were selected to 

include in the supply curve assessment: grain to ethanol production via dry and wet milling, 

FAME transesterification to produce biodiesel, lignocellulosic ethanol production via 

enzymatic hydrolysis and fermentation, Fischer Tropsch synthesis, pyrolysis oil production 

and upgrading, and renewable diesel2

 production via hydrotreatment of fatty acids. The 

subsection treating each technology includes a description of the methodology and 

assumptions used to generate the performance and cost model and an overview of the 

results. 

This report focuses on technologies that convert solid biomass into liquid fuels, as these 

form the basis for current research and are most likely to be available in the 2015 time 

period. Never-the-less, it is worthwhile to mention that other conversion technologies and 

fuels could potentially be incorporated in the transportation market in the future. For 

example, there is a potential for the use of compressed biogas as an alternative to natural 

gas for buses or specialized fleets. Biogas can be generated from manure and wastes via 

anaerobic digestion, and is also a by-product from landfills that can be harnessed for 

energy. However, such alternatives are not included in this analysis as they are not 

expected to make up a significant portion of the fuels market in the considered time frame. 

 

1

 Some of the technologies have different process options that can affect the yield and performance of the 

conversion. For example, renewable diesel can be generated via stand-alone or co-processing conditions, and 

lignocellulosic ethanol production has several pretreatment process options. 

2

 Renewable Diesel is a hydrocarbon fuel which is generated via hydrotreatment of plant oils and animal fats. 
2 

Table 1 – Current and Advanced Biofuel Conversion Technologies 

Reference Name Feedstock

Conversion 

Technology Fuel Type

Size Range* 

(MGY) Description

Current Representative Technologies

Grain to Ethanol - Dry Mill Grains / 

Starches

Enzymatic 

Fermentation Ethanol 5 to 100

Dry milling process - grains are ground into 

a flour, and the starch is converted into 

sugar with enzymes and fermented to 

produce ethanol. 

Grain to Ethanol - Wet Mill Grains / 

Starches

Separation and 

Fermentation Ethanol 50 to 300

Wet milling process - grain separated into 

components and starch is yeast fermented 

and distilled.

Fatty Acid to Methyl Ester (FAME)

Seed Oil / 

Waste Oils / 

Animal Fats

Esterfication Methyl Esters 1 to 80

Vegetable oils and fats are filtered and 

converted via base catalyzed 

transesterfication, producing biodiesel and 

glycerin which must be separated.

Sugar to Ethanol Fermentation Sugars Fermentation Ethanol 5 to 100 Sugar crops (like sugar cane) are milled 

and fermented to produce ethanol.

Additional Technologies Projected to be in Use by 2015 to 2025

LignoCellulosics to Ethanol - 

Fermentation/Hydrolysis 

(LCE Fermentation/Hydrolysis)

Lignocellulosic 

Biomass

Hydrolysis and 

Fermentation Ethanol 20 to 100+

Cellulose and hemicellulose converted to 

sugars via hydrolysis. Various options for 

hemicellulose conversion (pretreatment). 

Conversion of sugars to alcohol via 

fermentation.

LignoCellulosics to Ethanol - 

Fermentation/ThermoChemical 

(LCE Fermentation/TC)

Lignocellulosic 

Biomass

Gasification and 

Fermentation Ethanol 50 to 100+

Gasification to produce syngas, which is 

then conditioned and compressed. The 

compressed gas is fermented to ethanol.

LignoCellulosics to Middle Distillates - 

Fischer Tropsch (LCMD - FT)

Lignocellulosic 

Biomass

Gasification and 

Fischer Tropsh 

Synthesis

Middle 

Distillates, 

Gasoline

5 to 100+

Gasification to produce syngas, which is 

then cleaned and purified. The clean syngas 

then undergoes catalytic synthesis (reactor 

with Co catalyst to maximize diesel 

fraction). The product is separated and 

upgraded.

LignoCellulosic to Mixed Alcohol - 

ThermoChemical (LCMA - TC)

Lignocellulosic 

Biomass

Gasification and 

Thermochemical 

Conversion

Mixed 

Alcohols 15 to 100+

Syngas production via biomass 

gasification, followed by catalytic 

conversion to mixed alcohols.

LignoCellulosics to Gasoline - 

Upgrading/Pyrolysis 

(LCG - Upgrading/Pyrolysis)

Lignocellulosic 

Biomass

Pyrolysis Oil 

Production and 

Upgrading via 

hydrotreatment / 

hydrocracking

Bio-oil, Diesel, 

Gasoline 5 to 100+

Biomass conversion to bio-oil via fast 

pyrolysis, co-processing with fossil fuels in 

petroleum refinery.

Fatty Acids to HydroCarbon - 

Hydrotreatment 

(FAHC - Hydrotreatment)

Seed Oil / 

Waste Oils / 

Animal Fats

Upgrading via 

hydrotreatment

Renewable 

Diesel 5 to 200

Biomass oils conversion to diesel and other 

hydrocarbons via hydrotreating methods as 

in petroleum refinery

* Size Range gives potential facility sizes expected in the 2015 time frame. 

Conversion Technology Model Overview

Conversion technology models were developed to provide an estimate of the cost and 

performance of the selected technologies in terms of feedstock type and facility size for the 

GIS based supply analysis for the Western states. These models are based on data 

available from published studies. An overview of the major assumptions and methodology 

that apply to the models is given here for reference. Some of the limitations of the models 

are also discussed. 

In general, the key input variables for each model are the feedstock input type and 

quantity. Key outputs are biofuel yield, capital and O&M costs, and by-product quantity and 

value. Levelized non-feedstock production costs are also calculated from the key outputs 
3 

and economic factors described below. Further analysis will be done by the UC Davis team 

to generate the biofuel supply curves for the Western Region. 

Some of the overall standards for reporting are as follows: 

o All reported cost values are given in U.S. 2006$ unless otherwise noted. Price 

conversions from other years were performed using the Chemical Engineering Plant 

Cost Index (CEPCI) and standard relations. 

o Models for current commercial grain ethanol and FAME biodiesel production 

technologies are based on current cost and performance data. As these technologies 

are already well developed, no projections of future improvements are included. 

o Advanced technologies models are based on cost and performance projections 

available in the literature. The projected costs are typically estimates for the nth 

plant, with accuracy in the range of +/- 25% to 30%. 

o All cost and performance models for the advanced technologies include projections 

for the 2015 (“mid-term”) time period. Models of other time periods were also 

included for technologies that had additional projections available.3

 

o Economic factors for calculation of levelized non-feedstock production costs are 

based on the values used in the CDEAC study, as recommended by the Quantitative 

Work Group. The production cost uses a Fixed Charge Rate (FCR) of 12.3%, 

calculated based on an economic lifetime is 25 years and a weighted cost of capital 

of 9.7%. Additional details on these factors are provided in Appendix C. 

Although efforts were made to perform a comparable analysis of each technology it was not 

always possible to make the same assumptions for each model, since these models are 

based on data from published studies with varying levels of detail. This can be particularly 

significant for items which have highly fluctuating market values. For example, electricity 

costs and fuel prices have increased sharply over the past few years. Where possible, these 

increased costs have been accounted for by directly substituting current values into 

calculation of these operational costs. However, in some studies there is not sufficient 

detail to make this substitution. In these cases the utility costs may be underestimated. In 

order to make the assumptions for each analysis as transparent as possible, as much detail 

as practical is included in the report regarding the estimations and calculations for each 

model. 

 

3

 For example, lignocellulosic ethanol production is modeled for 3 time periods – near term (2010), mid term 

(2015), and long term (2025+). 
4 

2 Current Technologies 

Ethanol and FAME biodiesel are currently produced in significant quantities using commercial 

conversion technologies. These technologies include enzymatic fermentation of sugars and 

starch (grains) to produce ethanol, and transesterification of oils and greases to generate 

biodiesel. 

2.1 Grain to Ethanol Conversion 

Ethanol (ethyl alcohol) production is primarily a fermentation process that converts glucose 

into alcohol.4

 The main difference between the conversion technologies currently 

commercially available is the preliminary treatment of the feedstock before fermentation. 

As of February 2007, there were 120 grain ethanol plants in operation in the U.S. with a 

total production capacity of 5,120 MGY (Industrial Information Resources 2007). More than 

98% of the current U.S. ethanol production capacity comes from corn. Of the corn ethanol 

plants in operation approximately two-thirds are dry-mills. These facilities have high overall 

ethanol conversion rates and can be built at a scale that is affordable for large agricultural 

cooperatives and companies focused on ethanol production. About 80% of the U.S. ethanol 

production comes from dry-mill facilities (Solomon, Barnes and Halvorsen 2007). 

2.1.1 Technology Description 

Dry Mill Ethanol Facilities

Figure 1 illustrates the basic steps of the dry-milling or enzymatic fermentation process.5

 In 

this process, the corn or grain feedstock is initially ground into a flour or fine meal to 

release the starch. This material is then mixed with water to produce a mash, which is 

processed in a high temperature cooker with enzymes to convert the starch to sugar and 

reduce bacterial contamination before fermentation. Ethanol is produced during 

fermentation, which usually takes 40 to 50 hours (RFA 2005). The ethanol is purified and 

separated from the stillage during distillation. Further distillation and dehydration (as with 

molecular sieves) must be done to purify the ethanol for use as a fuel and alter the alcohol 

concentration. 

Figure 1 – Schematic Diagram of Dry Milling Ethanol Production Process 

Corn or 

Grain Grinder

Arrows show process links Stillage

Cooker

Water + 

enzymes

Fermenter

40 – 50 hrs

Distillation Ethanol

Corn or 

Grain Grinder

Arrows show process links Stillage

Cooker

Water + 

enzymes

Fermenter

40 – 50 hrs

Distillation Ethanol

 

4

 “Fermentation typically refers to the conversion of sugar to alcohol using yeast under anaerobic conditions. A 

more general definition of fermentation is the chemical conversion of carbohydrates into alcohols or acids.” 

(Source: Wikipedia) 

5

 A more detailed schematic diagram is given in Appendix D. 
5 

The whole stillage (WS) by-product of the dry-milling process, also known as distillers’ 

grain, includes the fiber, oil and protein components of the grain, as well as the nonfermented starch. It is currently sold as an animal feed in a variety of forms. As a result of 

its high moisture content, stillage is readily perishable and only has a shelf life of 6 to 10 

days. To increase durability of the product, thin stillage can be separated and dried to a 

thick, viscous syrup which is mixed back with the solids to create a feed product known as 

wet distillers’ grains with solubles (WDGS). WDGS, containing 65% moisture, can be used 

directly as an animal feed product. However, the shelf life of WDGS is only slightly longer 

than WS (one to two weeks), so end-uses such as feedlots must be nearby (typically within 

about 50-100 miles of the mill) to avoid spoiling. To increase shelf life and lower 

transportation costs, WDGS is usually dried to 10-12% moisture to produce a product 

known as dried distillers’ grain with solubles (DDGS). However, the drying process is 

extremely energy-intensive, and can consume about one-third of the energy requirements 

of the entire dry mill facility. 

DDGS competes with corn, soybean meal, and dicalcium phosphate in animal feed markets 

as a source of protein and phosphorus. DDGS has a very long shelf life, and is easily 

transported across the U.S. and all over the world. The U.S. domestic markets account for 

about 75% of production, while the remaining 25% is produced to satisfy the demand of 

international markets (Antares Group Inc. 2005a). 

As more dry-mill ethanol facilities come on line, the market may become saturated with 

these types of animal feed products and alternate end-uses or disposal options will need to 

be explored in order to keep a high value for this by-product. In general, the overall animal 

feed market is far larger than existing DDGS production capacities, thus theoretically there 

is room for growth in that area. However, DDGS producers will need to consider expanding 

into non-traditional feed markets, beyond feed for ruminating animals like dairy beef and 

cattle. An additional option is increasing exports to other countries, but these can be stifled 

by high freight costs. 

Wet Mill Ethanol Facilities 

In the wet milling process, the grain is separated into components (germ, gluten, fiber, and 

starch) before fermentation, yielding a number of valuable by-products. Figure 2 shows the 

basic steps of the separation process that is used to produce a fermentable starch.6

 The 

grain is first steeped in a mixture of water and dilute sulfurous acid for 24 to 48 hours to 

facilitate the separation into components (RFA 2005). The germ slurry is then separated, 

and goes through a process of grinding and screening to separate the fibrous material from 

the germ. The germ can be sold to crushers, or further processed on-site into an oil 

product. The gluten is separated from the starch, producing a gluten meal by-product that 

can be used for animal feed. The separated starch can then be hydrolyzed, fermented and 

distilled to produce ethanol, using the same steps as those described above for dry milling. 

The gluten meal produced from the wet-milling process has high moisture content and is 

readily perishable. Thus the same problems occur as with the whole stillage by-products of 

dry milling – the gluten meal must either be used quickly or dried. 

 

6

 Appendix D has a more detailed schematic diagram of this process. 
6 

Figure 2 – Schematic Diagram of Wet-Milling Process for Conversion of Grain to Starch 

Grain Steeping

Arrows show process links

Dashed lines for secondary processes

Starch-Gluten 

Separation

Water + Dilute 

Sulfurous Acid

Slurry

Grinding and 

Screening

Germ

Oil

Fiber Gluten Meal

Starch

Grain Steeping

Arrows show process links

Dashed lines for secondary processes

Starch-Gluten 

Separation

Water + Dilute 

Sulfurous Acid

Slurry

Grinding and 

Screening

Germ

Oil

Fiber Gluten Meal

Starch

2.1.2 Performance and cost analysis 

Dry Mill Ethanol Facilities 

Ethanol yield is directly related to amount of fermentable starch in corn kernels, plant 

efficiency, plant age, types of equipment, and plant management. Shapouri, Gallagher and 

Graboski (2002) reported that the average ethanol yield was 2.68 gal/bu for small facilities 

(<40MGY), and 2.65 gal/bu for large plants. For newer facilities, ethanol yield has increased 

to 2.8 gallons per bushel. 

There have been several technology improvements since the 1970’s that have reduced the 

cost of ethanol production, including a 20% increase in yield of ethanol production from 

corn from improved biochemistry, higher starch quantities in the kernels, and a 35% 

reduction in heat energy required for conversion by re-use of process heat (Gallagher, 

Brubaker and Shapouri 2005). New dry-mill plants use 30,000 Btu of thermal energy and 

less than 1kWh of electricity to produce 1 gallon of ethanol and by-products (Shapouri and 

Gallagher 2002). Furthermore, new ethanol plants have minimal discharge of wastewater, 

and typically do not require wastewater treatment facilities (Shapouri and Gallagher 2002). 

There is a clear relationship between capital cost and plant capacity for dry mill facilities, as 

investigated in Gallagher, Brubaker and Shapouri (2005). This study analyzed several dry 

mill facilities of varying sizes constructed over a 25 year period, and found that capital costs 

decrease on a $/gallon basis with increasing size up to an optimum capacity of about 55-74 

MGY, beyond which costs increase with size. The minimum capital cost is $1.14 per gallon 

ethanol production capacity (Gallagher et al. 2005). 

In 2004, there were about 40 large dry-mill ethanol plants (40-100 MGY) in operation or 

under construction (Shapouri and Gallagher 2005). The capital costs for new plants at this 

time ranged from $1.05 to $3.00 per gallon of capacity. As expected, the cost for expansion 
7 

of existing plants was much lower, from $0.20 to $1.00 per gallon capacity (with an average 

of $0.50/gal). 

According to Shapouri, Gallagher and Graboski (2002) DDGS made up 70% of all distiller’s 

grain products from dry mill facilities, while WDGS and MDGS (modified distillers grains) 

accounted for 21% and 9%, respectively (all on a dry basis). Furthermore, 17 of 21 ethanol 

facilities surveyed indicated that they sold wet and modified distiller grains. 

Wet Mill Ethanol Facilities 

Since wet mills are more complex than dry mills, they have a different plant-size to capital 

cost relationship (Gallagher, Brubaker and Shapouri 2005). Wet mills also have higher 

capital and O&M costs. However, energy expenses tend to be lower in wet mills than dry 

mills as they typically include cogeneration of steam and electricity (Shapouri, Gallagher 

and Graboski 2002). 

Wet mills have a number of valuable by-products, including corn gluten feed, corn gluten 

meal, and corn oil. The separated starch component can either be fermented to produce 

ethanol, or it can be further processed into corn syrup and sugar. In this analysis we 

assume that all of the starch is fermented in an ethanol producing wet mill facility. 

However, it is important to note that the flexibility of product distribution from wet mills can 

insulate these facilities from large price fluctuations for one of more of the potential 

products. For a value of $2/gallon or higher, ethanol production from a wet mill is 

competitive with corn syrup production. 

Outline for model analyses 

The key values and assumptions used to calculate the current technology analysis and 

economic performance model for wet and dry mills are described below. An example of the 

detailed analysis is shown in Appendix G. 

• Feedstock input quantity is a variable, and should be given on an as-received basis 

(typically about 15% moisture). Dry mills can use corn or sorghum, while wet mills use 

only corn. 

• Applicable facility size ranges are 5 MGY to 100 MGY for dry mills, and 50 MGY to 300 

MGY for wet mills, based on data from Gallagher et al. 2005. 

• Ethanol yield is calculated based on the average of values reported in the literature. 

New dry mills typically produce 2.8 gallons per bushel of corn (100 gal/ton), and wet 

mills produce about 2.5 gal/bu (89.3 gal/ton) (Shapouri and Gallagher 2005; McAloon et 

al. 2000, Butzen and Hobbs 2002). 

• The conversion efficiency of corn to fuel is estimated to be 64% (on an energy basis) for 

a dry mill and 57% for a wet mill. This is calculated using a typical HHV for ethanol of 

84,000 Btu/gal, and a HHV for corn of 6,600 Btu/lb (at 15% moisture content). 

• It is assumed that all distiller's grains from dry mill facilities are converted to DDGS. It is 

estimated that dry mill facilities produce 6.7 lb DDG per gallon of ethanol produced 

(McAloon et al. 2000). 

• The wet mills by-products include corn gluten feed, corn gluten meal, and corn oil, of 

which 11.4 lb, 3 lb, and 1.6 lb are produced from 1 bushel of corn, respectively (Butzen 

and Hobbs 2002).7

• The amount of CO2 production from fermentation for a dry mill facility is estimated to be 

17.5 lb per bushel of corn (Antares Group Inc. 2005a; McAloon et al. 2000). The CO2

production for wet mills is based on the same value, but is scaled by the ethanol 

conversion rate. 

 

7

 1 bushel of corn is equivalent to 56 lbs. 
8 

• The average water requirement for a dry mill facility is 4.7 gallons of water per gallon of 

ethanol produced (Shapouri & Gallagher 2005). Based on data from Shapouri, Gallagher 

and Graboski (2002), wet mills use 5.2 times as much water as dry mills. 

• Capital cost data for dry mill facilities is based on the relationship derived from Shapouri 

and Gallagher (2005). The minimum capital cost on a $/gal basis occurs at 65 MGY. For 

larger facilities the cost increases with capacity. 

• Wet mill capital costs are based on data from Whims 2002, using a scaling factor of 0.6.8

The capital for a wet mill facility is higher than for a dry mill facility due to additional 

process equipment requirements. 

• Average wholesale values of the co-products are based on current data from United 

States Department of Agriculture (USDA 2007). The value of DDGS is $90 - $115 per 

ton (similar to data from McAloon et al. 2000 and Shapouri and Gallagher 2005). Corn 

gluten feed is $40-60/ton, corn gluten meal is $335-350/ton, and corn oil is $0.31-

0.32/lb. These current wet mill co-product values from USDA are comparable to those 

reported for 2003 in Shapouri and Gallagher (2005). 

• Consumables for both processes include enzymes, yeast, chemicals, and denaturant. 

The consumables cost for small dry mills (< 40 MGY) is $0.13/gal, while for large dry 

mills (40 to 100 MGY) the cost is $0.12/gal (Shapouri and Gallagher 2005). The cost of 

consumables for wet mils is $0.19/gal (Shapouri, Gallagher and Graboski 2002). 

• Utilities include electricity, fuels, water and waste management. The cost for small dry 

mills is $0.27/gal and for large dry mills the cost is $0.19/gal (Shapouri and Gallagher 

2005). Average electricity use is 1.19 kWh/gallon of ethanol produced, and the average 

heat use is 34,800 Btu per gallon of ethanol. The cost of electricity for the dry mill 

facilities has been updated to 2005 average wholesale value for the industrial sector of 

5.7¢/kWh. New dry mill facilities have minimal wastewater discharge. Wet mill utility 

costs are $0.19/gal (Shapouri et al. 2002).9

 Wet mill energy usage is lower than dry 

mills as they typically employ cogeneration of steam and electricity. 

• Annual labor costs for small dry mill facilities are $0.077/gal, and $0.060/gal for large 

facilities (Shapouri and Gallagher 2005). Labor costs for wet mills are $0.096/gal, based 

on data from Shapouri, Gallagher and Graboski 2002. No scaling included for the wet 

mill costs as the data represents various size facilities. 

• Other fixed O&M costs include maintenance, administrative costs, and other costs. For 

dry mills, other fixed costs are equivalent to $0.090/gal for small facilities and 

$0.106/gal for large facilities (Shapouri and Gallagher 2005). For wet mills other fixed 

costs is $0.108/gal (Shapouri, Gallagher and Graboski 2002). 

• The levelized non-feedstock production cost of ethanol is calculated based on the annual 

operating expenses and capital cost payment, co-product credit, and quantity of fuel 

produced. 

Model Results

Some of the key cost and performance results for current ethanol production processes are 

shown in Table 2 and Table 3. These tables show results for the range of applicable facility 

sizes based on selected input quantities, and illustrate the high and low end costs. In 

general, the analysis shows that ethanol production from wet mill facilities has lower costs 

than the dry mills as a result of the co-product value. However, it is important to note that 

the value for these co-products will fluctuate as the market changes. For similar sized 

facilities the wet mills have higher capital and O&M costs than dry mills, as the process is 

 

8

 This scaling factor was derived from the Whims (2002) data. 

9

 Electricity prices have not been updated to reflect current market value as there was not sufficient detail in the 

Shapouri et al. (2002) to perform the calculations. 
9 

more complex. It should also be noted that both tables show results only for the nonfeedstock portion of the production costs. 

Table 2 - Example Cost and Performance Outputs for Dry Mill Facility 

Sample Model Results - Grain Ethanol (Dry Mill)

Feedstock Input (as rec'd ton/yr) 50,000 1,000,000

Ethanol Yield (MGY) 5 100

DDG Yield (ton/yr) 16,750 335,000

CO2 Stream (ton/yr) 15,625 312,500

Water Consumption (1000 gal/yr) 23,500 470,000

Capital Cost (Million $) $12.6 $167.2

Annual O&M Costs (Million $/yr) $2.9 $49.9

By-Product Credit (Million $/yr) $1.7 $34.3

Non-feedstock Production Cost ($/gal) $0.55 $0.36

Table 3 - Example Cost and Performance Outputs for Wet Mill Facility 

Sample Model Results - Grain Ethanol (Wet Mill)

Feedstock Input (as rec'd ton/yr) 560,000 3,360,000

Ethanol Yield (MGY) 50 300

Corn Gluten Feed Yield (ton/yr) 114,000 684,000

Corn Gluten Meal Yield (ton/yr) 30,000 180,000

Corn Oil Yield (ton/yr) 16,000 96,000

CO2 Stream (ton/yr) 156,250 937,500

Water Consumption (1000 gal/yr) 1,222,000 7,332,000

Capital Cost (Million $) $139.1 $407.7

Annual O&M Costs (Million $/yr) $29.5 $176.9

By-Product Credit (Million $/yr) $26.1 $156.3

Non-feedstock Production Cost ($/gal) $0.41 $0.24

According to USDA AMD 2007, the average price for corn in late 2007 was around $135/ton 

(including an estimated delivery cost of $10/ton).10 This implies a feedstock cost for 

ethanol production of $1.35/gallon for dry mills and $1.51/gallon for wet mills, based on the 

conversion yields used in the model. The resulting ethanol production costs are about 

$1.71 to $1.92 per gallon. For comparison, current FOB ethanol prices are around $1.75-

$2.15/gal (USDA AMS 2007). This is very similar to the results of the ethanol production 

models reported here. 

Projected prices for corn at the farm gate from FAPRI’s 2007 and 2008 U.S. and World 

Agricultural Outlook are shown in Figure 3. Since the 2008 data was not available at the 

time of analysis, the 2007 data is used in the report. Note that although the more recent 

data shows higher corn price projections, both data sets have relatively flat price escalation 

curves.11 The higher corn prices from the 2008 data likely reflect increasing costs of 

energy. As such, using the 2007 corn price data for analysis is consistent with the energy 

price projections employed in this analysis. 

According to the 2007 data, corn is project to cost about $119/ton in 2015 including the 

same $10/ton transportation cost as above. This leads to ethanol production costs of $1.55 

to $1.74 per gallon for dry mills and $1.57 to $1.74 per gallon for wet mills. 

 

10 Corn price based on data from USDA AMS 2007. Estimated delivery cost based on Antares experience, using a 

typical cost of $0.20/ton-mile for truck transportation and a distance of 50 miles. 

11 The projected corn price escalation from 2008 to 2015 is -5.6% with the 2007 FAPRI data, and -1.3% with the 

2008 FAPRI data. 
10 

Figure 3 – Projected Corn Prices 

100

110

120

130

140

150

2006 2008 2010 2012 2014 2016 2018 2020

Farm Price - Corn ($/ton)

FAPRI 2007

FAPRI 2008

Data from FAPRI 2007 and FAPRI 2008 

2.2 Fatty Acid to Methyl Esters: Transesterification (Biodiesel) 

There are three basic conversion routes for fatty acid methyl ester (FAME) production: base 

catalyzed transesterification of oil with alcohol; direct acid catalyzed transesterification of oil 

with methanol; or conversion of oil to fatty acids, followed by acid catalyzation to alkyl 

esters (EUBIA 2006; NBB n.d.). The first option tends to be the most economic for virgin 

feedstocks and as such is most commonly used to produce esters on a commercial scale.12 

There are several reasons that favorably affect the process economics, including low 

temperature and pressure processing requirement, high conversion rates (around 98%), 

lower reaction times, and direct conversion to methyl esters without producing any 

intermediate compounds (EUBIA 2006). 

Acid catalyzed transesterification is expected to be the preferred method for conversion of 

waste oils, since it is less sensitive to free fatty acids in the feedstock. This conversion 

method seems to be more economical than base catalyzed transesterification of waste oils, 

which requires an extra pretreatment step to remove impurities (Zhang et al. 2003b). 

Although acid catalyzed transesterification has not yet been optimized for commercial scale 

production, it is expected that this reaction method could be available by 2015. 

2.2.1 Technology Description 

Figure 4 illustrates the main process steps for transesterification of vegetable oil. Before 

transesterification, the vegetable oils and fats are filtered to remove water and 

contaminants. The oil is then mixed with an alcohol (often methanol, because of its low 

cost) and a catalyst (usually sodium hydroxide or potassium hydroxide for base catalyzed 

reaction, and sulfuric acid for the acid catalyzed process) in a simple closed reactor system 

at low temperature and pressure. For base catalyzed process the molar ratio of methanol to 

oil is about 6:1, while for an acid catalyzed process the ratio is about 50:1 (Zhang et al. 

 

12 Virgin feedstocks include vegetable (seed) oils and animal fats. 
11 

2003a). The mixture is left to settle in the reaction vessel for 1 to 8 hours, after which the 

glycerin and crude biodiesel (methyl esters) are separated. The majority of the alcohol is 

recovered from the glycerin by-product and recycled back into the system. The biodiesel is 

purified by a washing process to remove residual catalyst and soaps. 

Figure 4 – Schematic Diagram of Transesterification Process 

Methanol + 

Catalyst

Vegetable Oil

Methanol 

Recovery

Crude 

Biodiesel Transesterfication

Crude Glycerin

Glycerin 

Refining

Arrows show process links

Dashed lines for secondary-processes Glycerin

Refining

Biodiesel

Methanol + 

Catalyst

Vegetable Oil

Methanol 

Recovery

Crude 

Biodiesel Transesterfication

Crude Glycerin

Glycerin 

Refining

Arrows show process links

Dashed lines for secondary-processes Glycerin

Refining

Biodiesel

The purity and yield of the methyl esters are affected by the molar ratio of glycerides to 

alcohol, type of catalyst, reaction time, reaction temperature, and the free fatty acids and 

water present (Vicente, Martinez and Aracil 2007; Ma and Hanna 1999).13 The presence of 

water causes soap formation during the reaction, and free fatty acids significantly reduce 

ester yields (particularly for base catalyzed reaction). The formation of soap is an 

undesirable by-product as it reduces the biodiesel yield and makes glycerol separation more 

difficult (Vicente, Martinez and Aracil 2007). 

Experiments involving the transesterification of sunflower oil feedstock showed that the 

initial catalyst concentration was the most important factor for biodiesel purity and yield. 

The catalyst concentration was found to positively affect the biodiesel purity, and negatively 

affect the yield (Vicente, Martinez and Aracil 2007). In other words, a higher initial catalyst 

concentration produced more pure biodiesel in smaller quantities than a lower catalyst 

concentration. Vicente, Martinez and Aracil (2007) also found that higher temperatures 

negatively affected biodiesel yield and positively affected the purity. 

Although under similar conditions the acid catalyzed transesterification process has a slower 

reaction rate than the base catalyzed process, this can be overcome by a number of 

methods including longer reaction times, using a larger quantity or increased concentration 

of acid catalyst, or a higher reaction temperature (Zhang et al. 2003a). However, the acid 

catalyzed process has not yet been done on a commercial scale. 

 

13 Fatty acids can be bonded to another molecule (such as glycerol in triglicerides). Free fatty acids are not 

attached to another molecule, and are a type of impurity in oils used for biodiesel production. Ma and Hanna 

(1999) note that if oils are not dry and free fatty acids (<0.5%), ester yields may be significantly reduced. 
12 

2.2.2 Performance and cost analysis 

A study by Haas et al. (2006) investigated the economics of a 10 MGY acid catalyzed FAME 

facility using virgin oil feedstock. They found that the largest portion of the capital cost was 

storage tanks to hold a 25 day supply of oil feedstock, which made up about 1/3 of 

equipment costs. An analysis by Zhang et al. (2003b) showed that the transesterification 

reactor vessels and distillation columns were the largest portions of the equipment costs, 

particularly for the acid catalyzed process (which has a much larger methanol requirement 

and requires 2 reactors and stainless steel vessels). However, their analysis did not include 

the cost of feedstock storage vessels. 

For a transesterification processes using virgin oil, the feedstock is the bulk of the 

production costs. For example, in the analysis by Haas et al. (2006), soybean oil made up 

88% of the calculated production costs. Furthermore, production cost was found to vary 

linearly with feedstock costs, and inversely with market value of glycerol. In their analysis, 

Zhang et al. (2003a) showed that the base catalyzed process with virgin oil was the most 

simple and had the least process equipment, but also had very high feedstock costs. Zhang 

et al. (2003b) showed that the economics of acid catalyzed process using waste oil 

feedstocks can be competitive with base catalyzed process using virgin feedstocks. 

Although the acid catalyzed process has higher capital and O&M costs, the feedstock is 

much less expensive. In their analysis, Zhang et al. (2003b) showed that plant capacity 

and feedstock oil price had the largest effect on production costs of biodiesel for both types 

of processes. 

Outline for model analysis

The key values and assumptions used to calculate the current technology analysis and 

economic performance model for transesterification are described below. An example of the 

detailed analysis is shown in Appendix G. 

• Feedstock type and input quantity are variables. The feedstock options are virgin oil, 

animal fats, and yellow grease, and the applicable size range is 1 to 80 MGY. 

• Biodiesel yield is calculated based on the average of values reported in the literature for 

each feedstock type (summarized in Table 4). In general, the virgin feedstocks have 

higher yields than yellow grease. Reported yields from virgin oil are from 246.2 to 270 

gal/ton (90% - 99% conversion on a mass basis), and for yellow grease the yields are 

234.9 to 263.2 gal/ton (86% - 97% conversion).14 

• The conversion efficiency of oil/fat to fuel on an energy basis is estimated to be 88-94%, 

depending on the feedstock. This is calculated using an average HHV of oil feedstocks of 

16,500 Btu/lb, and a typical biodiesel heating value of 117,000 Btu/gal. 

• Glycerin is the only significant by-product of transesterification. The average production 

rate is 0.8 lb glycerin per gallon of biodiesel produced from virgin feedstocks (Bender 

1999, Haas et al. 2006). These studies refer to the production of a partly purified 

glycerol product, which contains about 80% glycerol by mass. Although waste oils may 

have slightly higher glycerin yields, this has not been included in the analysis. The value 

of the glycerol is estimated to be $0.05/lb, based on current market price data from 

Nilles (Sept. 2006) and personal communication with Leland Tong (National Biodiesel 

Board contributor). Note that this is a particularly variable market and it is difficult to 

predict what the product value will be in the future. 

• Annual water consumption is estimated to be 0.25 lb per gallon biodiesel produced, 

based on data from Haas et al 2006. 

• Capital cost for base catalyzed transesterification is based on data for a 10 MGY facility 

from Haas et al. 2006. The acid catalyzed facility cost is based on equipment cost from 

Zhang et al. 2003b for a 2.4 MGY facility, with added cost for storage facilities from Haas 

 

14 Sources: Haas et al. 2006, Sheehan et al. 1998, Zhang et al. 2003a, Canakci and van Gerpen 2001. 
13 

et al. 2006. Additionally, the multiplier from Haas et al. (2006) was used to calculate 

the total capital investment for this facility. Capital cost is scaled using a scaling factor of 

0.6, based on data from Bender (1999). 

• In general, the capital costs of acid catalyzed transesterification are estimated to be 

higher than base catalyzed transesterification because the process uses a greater 

quantity of methanol, which requires more and larger transesterification reactors and a 

larger distillation column (Zhang et al. 2003b). Additionally, the acid catalyzed process 

is much more corrosive and requires expensive stainless steel process equipment. The 

increased methanol requirement and feedstock pretreatment also leads to increased 

O&M costs for the acid catalyzed process. 

• Labor costs are calculated based on data for a virgin oil facility from Haas et al. 2006, 

but the operator salary was increased to $20/hr from $12.5/hr based on Antares 

experience. Values in Zhang et al. (2003b) suggest that acid catalyzed facilities have 

higher labor requirements, so Antares estimated there would be one additional operator 

per shift for a 10 MGY facility.15 The total labor cost is scaled by facility size, based on 

scaling data available from pyrolysis oil production facilities. 

• Annual non-labor fixed O&M costs are calculated as a percentage (2.1%) of the capital 

cost, following Haas et al. (2006). 

• Annual Variable O&M costs include consumables (methanol, sodium methoxide, 

hydrochloric acid, sodium hydroxide, and water) and utilities (natural gas, WWT, waste 

disposal, and electricity). The annual cost for utilities are calculated on a $/gallon basis 

of biodiesel produced, based on data from Haas et al. 2006 for the base catalyzed 

process and Zhang et al. 2003b for the acid catalyzed process.16 The annual cost of 

consumables for both processes is based on data from Haas et al. (2006). However, the 

quantity and price of the methanol and sulfuric acid for the acid catalyzed process are 

substituted using data from Zhang et al. (2003b). 

• The levelized non-feedstock production costs for biodiesel are calculated based on the 

annual operating expenses and capital cost payment, co-product credit, and quantity of 

fuel produced. 

Table 4 – Biodiesel yields for various feedstocks 

Feedstock (1)

Yield range 

(gal/ton)

Average Yield 

(gal/ton) Sources

Virgin Oil (2) 246.4-270.0 258.2 Haas et. al 2006, Sheehan et al. 1998, Zhang 

et al. 2003a, Canakci and van Gerpen 2001

Animal Fats 266.3 266.3 Bender 1999

Yellow Grease (3) 234.9 - 263.2 249.1 Zhang et al. 2003a, Canakci and van 

Gerpen 2001

1) All data based on feedstocks with negligible water content.

3) Conversion yield for waste greases based on acid catalyzed reaction. For comparison, the transesterification reaction for virgin 

feedstocks use base catalysts.

2) Based on data for degummed soybean oil. High end of the yield range from Haas et al 2006, which assumes a negligible free fatty 

acid content in the feedstock.

Model Results:

Some of the key cost and performance results for current FAME production processes are 

shown in Table 5 and Table 6. These tables show results for the range of applicable facility 

sizes based on selected input quantities, and illustrate the high and low end costs. In 

 

15 For comparison the base catalyzed facility had 2 operators per shift. 16 Electricity prices have not been updated to reflect current market value as there was not sufficient detail in the 

published studies to perform the calculations. 
14 

general, the analysis shows that the levelized non-feedstock production cost of biodiesel for 

the base catalyzed transesterification process is significantly lower than the acid catalyzed 

process, as expected. However, the feedstock cost will be much more expensive for the 

virgin oil transesterification facility (typically waste grease is about half as expensive as 

virgin oil). 

Table 5 - Example Cost and Performance for Base Catalyzed Transesterification Facility 

Sample Model Results - FAME Biodiesel w/ Virgin Oil

Feedstock Input (ton/yr) 5,000 310,000

Biodiesel Yield (MGY) 1.3 80.0

Crude Glycerin Yield (ton/yr) 516 32,020

Water Consumption (1000 gal/yr) 39 2,400

Capital Cost (Million $) $3.3 $39.5

Annual O&M Costs (Million $/yr) $0.5 $20.1

By-Product Credit (Million $/yr) $0.05 $3.2

Non-feedstock Production Cost ($/gal) $0.67 $0.27

Table 6 - Example Cost and Performance for Acid Catalyzed Transesterification Facility 

Sample Model Results - FAME Biodiesel w/ Waste Grease

Feedstock Input (ton/yr) 5,000 310,000

Biodiesel Yield (MGY) 1.2 77

Crude Glycerin Yield (ton/yr) 498 30,880

Water Consumption (1000 gal/yr) 37 2,310

Capital Cost (Million $) $5.2 $61.5

Annual O&M Costs (Million $/yr) $1.0 $45.8

By-Product Credit (Million $/yr) $0.05 $3.1

Non-feedstock Production Cost ($/gal) $1.26 $0.65

According to USDA AMS (2007), the current cost for crude soybean oil is about 32.5 cents 

per pound ($2.5/gallon), and the cost for biodiesel is around $3.10/gallon. This implies a 

non-feedstock production cost of $0.60, similar to the projections from the model for small 

base catalyzed transesterification facilities. Haas et al. (2006) estimate a biodiesel 

production cost of $2.00/gallon for a 10 MGY facility using crude soybean oil at $1.81 per 

gallon (23.5¢/lb). For a similar size facility using the same feedstock price, the FAME 

biodiesel model gives a production cost of $2.20/gal. 

The Food and Agricultural Policy Research Institute (FAPRI) 2007 U.S. and World 

Agricultural Outlook, projects 2015 soybean oil prices will be about $681.40/ton (34.1¢/lb). 

Including $10/ton for delivery, this gives production costs of $2.98 - $3.36 per gallon for 

biodiesel.17 Note that this does not include the cost of distribution, which would be included 

in the retail fuel price. Refer to Appendix E for details on the conversion of oilseed crops to 

oil. 

2.3 Sugar to Ethanol Fermentation 

The conversion of sugars (like sugarcane) to ethanol is simpler than the conversion of 

starches as it requires fewer process steps. This process is very similar to the dry milling 

process described above except that no cooking is required. The feedstock is milled and 

 

17 Delivery cost estimated for truck transportation, using $0.20/ton-mile and a 50 mile delivery radius. Including 

delivery, the soybean oil price is $2.66/gallon. 
15 

pressed, and then fermented to generate ethanol. The resulting product is purified during 

distillation, and can be dehydrated to change the alcohol concentration. 

Ethanol production directly from sugars is generally only performed in locations where there 

is a large quantity of available feedstocks, such as sugarcane crop in Brazil and sugar beets 

in parts of Europe. According to the USDA National Agriculture Statistics Service (NASS), 

the entire U.S. produced about 34 million tons of sugar beets and 30 million tons of 

sugarcane in 2006 (USDA NASS 2007).18 For comparison, the U.S. soybean crop from 2006 

was nearly 90 million tons and the corn crop was 300 million tons (USDA NASS 2007). As a 

result of limited feedstock availability, sugar crops are not a significant source of ethanol 

production in the U.S. 

 

18 The top states with sugarcane crops are Florida, Louisiana, Hawaii and Texas, while the top sugar beet growing 

states are Minnesota, North Dakota, Idaho, Michigan and California (USDA NASS 2007). 
16 

3 Technologies Ready for Commercialization in the 

Midterm (2010 – 2025) 

There are a number of advanced biofuel technologies being developed that may be available 

in the 2010 to 2025 time frame. One of the key differences between these and the current 

commercial biofuel technologies is the types of biomass feedstocks used for production. 

While the current technologies typically use grain and oil seed crops (which are expensive 

and compete with food usage), many of the advanced technologies use lignocellulosic 

biomass such as wood, switchgrass and agricultural residues. Although these biomass 

feedstocks are generally more difficult to convert to biofuels, they are not a human food 

source and can be much less expensive than grain and seed crops. 

Cost and performance models for several of the advanced technologies have been 

developed. Since the advanced technologies do not currently have commercial plants in 

operation, these models are based on cost and performance projections available in the 

literature. The projected costs are typically estimates for the nth plant, with accuracy in the 

range of +/- 25% to 30%. All cost and performance models for the advanced technologies 

include projections for the 2015 (“mid-term”) time period. Models of other time periods 

were also included for technologies that had additional projections available in published 

studies. 

3.1 Lignocellulosics to Ethanol: Hydrolysis and Fermentation 

Lignocellulosic biomass consists mainly of cellulose, hemicellulose and lignin. This includes 

woody biomass, grasses, and agricultural residues. Lignocellulosic biomass typically contains 

40-60 wt% cellulose (dry weight) and 20-40 wt% hemicellulose, both which can be 

hydrolyzed to sugars and fermented to produce ethanol. Most of the remaining fraction 

(10-25 wt%) is lignin, a complex polymer which is resistant to biological degradation and 

cannot be fermented, but can be thermochemically treated or used directly to produce heat 

and/or power.19 There are also small amounts of proteins, lipids, and ash. 

The chemical composition of the biomass (i.e. the lignin/hemicellulose/cellulose ratio) is a 

major factor in the ethanol yield. Materials with high sugar content (cellulose and 

hemicellulose) have the potential to produce the greatest amount of ethanol. Table 7 shows 

typical biochemical compositions for various biomass feedstocks. Most woody biomass has 

about 27% lignin, while grasses such as switchgrass have about 18% (Hamelinck, van 

Hooijdonk and Faaij 2005). Switchgrass has a large fraction of ash and other materials 

which can not be converted to ethanol or used for heat and power production. 

 

19 The higher heating value (HHV) of lignin is 10,495 +/- 515 Btu/lb (dry), whereas the (hemi)cellulose and other 

components have a much lower HHV around 7,310 Btu/lb (dry) (Hamelinck, van Hooijdonk and Faaij 2005). 
17 

Table 7 - Typical biochemical compositions of various feedstocks20

Feedstock Composition (wt%)

Feedstock Hemicellulose Cellulose Lignin Other

Agricultural Resources 23-26% 33-40% 17-24% 10-27%

Switchgrass 25% 32% 18% 25%

Hardwoods (i.e. Poplar) 13-19% 42-50% 26-28% 3-19%

Pine (Softwood) 22% 45% 28% 6%

Sources: U.S. DOE EERE Biomass Program Jan 25, 2006; Hamelinck, van Hooijdonk and Faaij 2005 

3.1.1 Technology Description 

Production of ethanol from lignocellulosic materials is similar to production from grains, 

except that it is more difficult to break down the feedstock into fermentable sugars. In 

other words, hydrolysis of lignocellulose is more difficult than hydrolysis of starch.21 The 

hydrolysis or saccharification of cellulose produces glucose (a sugar containing 6 carbon 

atoms), and hydrolysis of hemicellulose produces various 5 carbon and 6 carbon sugars. 

Figure 5 shows the basic process steps for the conversion of LignoCellulosics to Ethanol via 

Hydrolysis and Fermentation (LCE Fermentation/Hydrolysis). The biomass is first pretreated 

to clean and size the materials and alter the cell structure so that it is more accessible to 

conversion. Hemicellulose hydrolysis is part of the pretreatment, and can be performed by a 

variety of methods (see below). After pretreatment, the solids (cellulose and lignin) are 

filtered and pressed and undergo cellulose hydrolysis, while the sugar-containing liquids are 

diverted to fermentation. Cellulose hydrolysis is the main hydrolysis step, in which the 

cellulose is converted to sugars. The primary methods for this reaction are described below. 

After hydrolysis, the sugars are converted to ethanol via fermentation, and the ethanol is 

recovered in a distillation column and concentrated. The lignin and other solid residuals can 

be thermochemically treated (gasified) or used directly to produce heat/power via 

combustion. Unfermented sugars in liquid effluent can also be dried and fired in a boiler. An 

alternate use of the lignin is to produce high-value co-products such as high-octane 

hydrocarbon fuel additives, but these conversions are complex and expensive. Note that 

although each step is shown below as a separate process, integration of two or more 

process steps is a potential ways to reduce costs and increase overall efficiencies. In the 

descriptions below each major process step is discussed separately in order to clarify the 

difference aspects of the process. 

It is important to mention another potential method of ethanol production from 

lignocellulosic materials; hemicellulose conversion of biomass in a forest product biorefinery. 

In this process sugars are extracted from the hemicellulose component of the biomass and 

fermented to ethanol. The rest of the biomass is then used to produce high value pulp and 

paper products. Production of lignocellulosic ethanol as a by-product of the forest products 

industry is very appealing, as the required biomass infrastructure is already well developed. 

Although there is significant interest in this type of biorefinery, there was not sufficient data 

publicly available for a detailed characterization of this process for this analysis. However, 

the inclusion of this process will be re-evaluated for future work, as additional technical 

information is published. 

 

20 “Other” includes ash, acids, and extractives (low molecular weight organic materials like aromatics and alcohols). 21 Hydrolysis is the breakdown of organic materials through the use of water. 
18 

Figure 5 – Schematic diagram of LCE Fermentation/Hydrolysis process 

Cellulosic 

Biomass

Pre-treatment

Mechanical

Hemicellulose Hydrolysis

Waste 

water

Steam

Fermentation Purification

Ethanol

Cellulose Hydrolysis

Heat / Power 

Generation

Solid 

Residuals

Electricity

Liquids (sugars)

Solids

Based on Figure in Hamelinck, van Hooijdonk and Faaij 2005

Cellulosic 

Biomass

Pre-treatment

Mechanical

Hemicellulose Hydrolysis

Waste 

water

Steam

Fermentation Purification

Ethanol

Cellulose Hydrolysis

Heat / Power 

Generation

Solid 

Residuals

Electricity

Liquids (sugars)

Solids

Cellulosic 

Biomass

Pre-treatment

Mechanical

Hemicellulose Hydrolysis

Waste 

water

Steam

Fermentation Purification

Ethanol

Cellulose Hydrolysis

Heat / Power 

Generation

Solid 

Residuals

Electricity

Liquids (sugars)

Solids

Based on Figure in Hamelinck, van Hooijdonk and Faaij 2005

Pretreatment and Conditioning

Pretreatment is an important part of the conversion process because it has a very significant 

impact on the ethanol yield. It is also a very energy intensive step – sizing the biomass can 

take up to one third of the total energy requirement for the process. The hemicellulose 

saccharification is also included in pretreatment step, as it helps to make the cellulose 

easier to convert to sugars. In fact, cellulose hydrolysis without the hemicellulose hydrolysis 

pretreatment step typically has yields below 20%, while after this pretreatment step the 

cellulose hydrolysis can have yields greater than 90%. Some of the primary hemicellulose 

hydrolysis methods are described below. 

• Chemical pretreatment processes such as dilute acid: The acid catalyzed 

hydrolysis process uses dilute sulfuric, hydrochloric, or nitric acid.22 This method is 

currently available and gives reasonably high sugar yields (75-90%). However, the acid 

needs to be removed and neutralized before fermentation which creates a lot of gypsum 

for disposal. This method also requires very small biomass particle sizes, typically about 

1 to 3mm, as smaller particles have larger percentages of surface area available 

(Hamelinck, van Hooijdonk and Faaij 2005). 

Acids need to be removed before enzymatic hydrolysis and fermentation. This is done by 

separating remaining solids from the liquid, followed by washing and pressing. Acids are 

then removed or recovered from the liquid fraction via membrane separation (about 

80% effective recovery) or by continuous ion exchange (97% recovery with 2% of 

sugars lost). Low acid concentrations can be neutralized by adding lime, causing a 

conversion to gypsum which can then be filtered out for disposal.23 Conditioning is also 

used to remove inhibitors produced during pretreatment, as they reduce ethanol yields. 

• Physical pretreatment processes such as steam explosion and liquid hot water 

(LHW): In steam explosion biomass is heated using high pressure steam for several 

minutes, and the reaction is stopped by sudden decompression to atmospheric pressure. 

This process results in sugar yields around 45-65% (Hamelinck, van Hooijdonk and Faaij 

 

22 Note that there is also a concentrated acid hydrolysis process, but it is currently very expensive and will not be 

discussed in detail here. 

23 There is typically 0.02 kg gypsum produced per kg feedstock after recovery. With acid catalyzed hydrolysis with 

no acid recovery this can be as high as 0.6 - 0.9 kg of gypsum per kg of feedstock. 
19 

2005). LHW uses compressed hot liquid water to hydrolyze the hemicellulose, resulting 

in high yields of 88-98%. These high yields and the fact that no acid or chemical 

catalyst required make the process extremely attractive. However, LHW is currently in 

the demonstration stage of development, and is not expected to be available for large 

scale commercial projects for another 5 years. Biomass feedstock size required for 

these processes are around 19mm, much larger than the dilute acid hydrolysis step 

(Hamelinck, van Hooijdonk and Faaij 2005). This significantly lessens the pretreatment 

energy requirement. 

• Biological pretreatments (Fungi): The process is characterized by low energy use 

and mild environmental conditions. However, it also has low conversion yields and long 

reaction times. This method tends to be more effective in combination with chemical 

treatments (Hamelinck, van Hooijdonk and Faaij 2005). 

Cellulose Hydrolysis

Cellulose hydrolysis is typically performed via enzymatic hydrolysis. In this process, 

cellulase enzymes convert the cellulose to sugars under mild process conditions.24 This 

method results in relatively high yields (75-85%) and has lower maintenance costs than 

acid hydrolysis (described below). Cellulase is currently a very expensive part of ethanol 

production, although there are research activities that focus on lower costs and increasing 

yields.25 Yields are expected to increase to 85-95% by 2020. Recovery and reuse of the 

enzymes also helps to minimize costs, although they do degrade over time. 

Acid hydrolysis is the only current cellulose hydrolysis process that does not use enzymes. 

Acid hydrolysis can only be used in conjunction with an acid hydrolysis pretreatment (2-

stage acid process). Dilute acid hydrolysis, the oldest cellulosic conversion to ethanol 

process (the first commercial plant was operating in 1898), is not currently competitive with 

the enzymatic hydrolysis process. However, concentrated acid hydrolysis has significantly 

higher conversion rates than dilute acid hydrolysis, with sugar yields around 90%. Since 

acid hydrolysis has high operating costs, minimal acid use and maximal recovery are 

needed. 

 

Fermentation:

In the fermentation process, microorganisms (bacteria, yeast, or fungi) convert 

carbohydrates to ethanol in an anaerobic environment. The chemical reactions for 

conversion of 5-carbon and 6-carbon sugars to ethanol are shown below. 

3C5H10O5 → 5C2H5OH + 5CO2 (1) 

C6H12O6 → 2C2H5OH + 2CO2 (2) 

Genetic engineering has been used to generate bacteria and yeast that can ferment both 

types of sugars (Hamelinck, van Hooijdonk and Faaij 2005). Continued research to provide 

microorganisms with higher conversion efficiency and resistance would further improve 

process economics. According to McAloon et al. (2000), the hydrolysis and fermentation 

steps to produce ethanol from lignocellulosic biomass take about 7 days.26 For comparison, 

 

24 Cellulase enzymes are actually a complex mixture of enzymes, produced by organisms that live on cellulosic 

material (Hamelinck, van Hooijdonk and Faaij 2005). 

25 Key enzyme producers including Genencor International and Novozymes Biotech have both been successful in 

these developments in recent DOE-supported research. 26 Although long-term projections include reduced time for fermentation. For example, Wooley et al. (1999) 

estimate a decreasing residence time requirement as technology and microorganisms are further developed, such 

that fermentation only requires 2 days in the long-term scenario. 
20 

the existing mill technology for converting starch to ethanol (not including pretreatment) 

only takes 2 days. 

McAloon et al. (2000) estimate that 39 lb lignocellulosic residue per gallon of fuel ethanol is 

produced using a dilute acid pretreatment process with corn stover feedstock. The residue 

typically has a moisture content around 60%. Potential co-products from ethanol 

production include cell matter, furfural, and acetic acid.27 

3.1.2 Performance and cost analysis 

Projected cost and performance for ethanol production from the LCE Fermentation/ 

Hydrolysis process has been developed by looking at different pretreatment options for 

three distinct time periods. The time periods in this analysis include near term (2010), mid 

term (2015-2020), and long term (2025+). The near term model only includes dilute acid 

pretreatment and relatively small sizes (25 to 60 MGY). The mid term model uses dilute 

acid pretreatment for medium size facilities (60 to 100 MGY) and steam explosion for large 

facilities (>100 MGY). The long term model uses dilute acid pretreatment for medium size 

facilities (60 to 100 MGY) and liquid hot water (LHW) for large facilities (>100 MGY). The 

pretreatment technology and size ranges for each time period were selected based on the 

projections from NREL, Utrecht University, and other institutions (details given below). 

This LCE Fermentation/Hydrolysis production model has been derived based on available 

data from published studies.28 All of the studies used to develop the analysis use enzymatic 

hydrolysis for cellulose conversion, and a variety of pretreatments for hemicellulose 

hydrolysis (dilute acid, steam explosion, and LHW). The references use of either poplar or 

corn stover feedstocks, and all except one use a boiler for power and steam production 

(there is one that uses biomass integrated gasification combined cycle - BIGCC). 

Most of the papers used in the analysis presented a time frame for development of a 

commercial ready process. The data were grouped by the number of years projected for 

each technology (i.e. a “2005” technology described by Wooley et al. (1999) was projected 

to be developed in 6 years). Technologies in the near term include those developed within 

5 years, mid term technologies are those developed within 6 to 15 years, and long term 

technologies are those that are expected to be available after more than 15 years. 

Figure 6 shows the values reported in various studies for ethanol conversion efficiency 

(bars) and yield (points) for various time periods.29 The conversion efficiency and yield are 

directly related. The conversion efficiency is calculated as the ratio between the heating 

value (HHV) of the ethanol produced and the HHV of the feedstock input. The reported 

values include a variety of pretreatment technologies over a range of projected time 

periods. There is a clear correlation between ethanol conversion efficiency (or yield) and 

time period, as the long term processes are projected to approach theoretical conversion 

efficiencies. This development of production performance will be an important factor in the 

economic favorability of these technologies. 

 

27 However, as detailed studies have not been made on the development of these co-products they will not be 

included in this analysis. Electricity is the only by-product from the process evaluated here. 28 Sources: Hamelinck, van Hooijdonk and Faaij 2005; Wooley et al. 1999; Lynd et al. 2005; Aden et al. 2002; and 

McAloon et al. 2000. 

29 Ibid 
21 

Figure 6 – Ethanol production efficiency and yield from published data for various time periods 

0%

10%

20%

30%

40%

50%

60%

Short Term

Mid Term

Long Term

Ethanol Conversion Efficiency (HHV basis)

0

20

40

60

80

100

120

Ethanol Yield (gal/dry ton)

32% to 36%

38% to 49%

48% to 52%

Colors represent different feedstocks: poplar is blue, yellow is corn stover.

Bars show ethanol conversion efficiency, Points show ethanol yield.

Note: Arrows are used on the figure to reference which axis pertains to each series. The bars represent ethanol 

conversion efficiency (left axis), while the points show ethanol yield (right axis). 

A near term conversion process based on dilute acid hydrolysis with a 35% conversion to 

ethanol has an overall process efficiency of about 60% including electricity production from 

lignin and other residuals in a boiler (Hamelinck, van Hooijdonk and Faaij 2005). 

Improvements in the pretreatment methods and other processes could lead to a 48% 

ethanol conversion efficiency (or greater), and overall process efficiencies of 68% 

(Hamelinck, van Hooijdonk and Faaij 2005). 

Figure 7 shows the total capital investment in relation to the ethanol production capacity 

and time period.30 As with the ethanol production performance data discussed above, these 

values are from a number of studies and include several pretreatment technologies. As 

there are no commercial lignocellulosic ethanol production facilities in operation, these 

values have been derived using factored estimation analysis or detailed process design.31 

The Total Capital Investment (TCI) is generally +/- 30% (or better), and includes the 

equipment costs, installation, contingency and other indirect costs.32 

 

30 Ibid (except Lynd et al. 2005). 31 Iogen currently has an operational demonstration facility in Canada. A number of companies have 

demonstration and commercial facilities planned for start-up in the near-term (Solomon, Barnes and Halvorsen 

2007). 

32 All costs are reported in 2006 US$, converted using the Chemical Engineering Plant Cost Index (CEPCI) where 

necessary. 
22 

Figure 7 – Ethanol production capacity and total capital investment for various time periods 

$3.61

$2.80

$6.15

$3.46

$4.61

$2.35

$6.97

$8.06

$5.76

$3.51

$4.50

0

50

100

150

200

250

300

350

Short Term

Mid Term

Long Term

Ethanol Production Capacity (MGY)

$0

$2

$4

$6

$8

$10

Total Capital Investment ($/gal)

Green bars represent technologies based on:

- dilute acid hydrolysis of hemicellulose (pretreatement)

- enzymatic hydrolysis of cellulose

- boiler power production

- poplar or corn stover feedstocks

Purple bars represent technologies with steam explosion 

pretreatement,with boiler and BIGCC

Orange bar represents technology with LHW pretreatement

best of 

industry

BIGCC

As expected there is a clear trend towards increased plant sizes with time. The average 

short term plant size is 45 MGY, while the long term facilities are projected to be about 100 

to 300 MGY. Furthermore, the capital cost decreases with time, which corresponds with the 

economies of scale as plant sizes increase, as well as the availability of lower cost 

equipment. 

In the short term, the only clear outlier with respect to capital cost is the “best of industry” 

(labeled in graph), which has a TCI of $4.50/gallon. The outlier for the mid term is the 

facility which includes gasification for power production instead of a boiler (labeled “BIGCC). 

The TCI for this facility is $6.15/gal, significantly higher than the equivalent facility which 

uses a boiler ($4.61/gal). As both of these examples have significantly different 

technologies from the other modeled facilities, their cost information is not included in the 

average used for the ethanol production cost model. 

The relative costs of the major equipment areas from several studies for near term LCE 

Fermentation/Hydrolysis facilities using dilute acid pretreatment technology are shown in 

Table 8. Note that the first two facilities include cellulase production, while the 69 MGY 

plant does not.33 Note that at least for the near term, it is more likely that enzymes would 

be purchased rather than produced. 

 

33 While some of the LCE Fermentation/Hydrolysis facilities from the published studies used in the analysis include 

on-site production of cellulase for enzymatic hydrolysis, others assume the cellulase is purchased for use, 

depending on which option was more economically favorable. The cost of purchased cellulase is included in the 

consumables portion of the Variable O&M costs. 
23 

The power and steam production area is the most expensive, followed by pretreatment. 

This suggests that lowering the costs of these process steps could be most beneficial in 

reducing overall capital costs. 

Table 8 - Capital cost break-out for LCE Fermentation/Hydrolysis with dilute acid pretreatment 

Plant Size (MGY) 25 52.5 69

Major Equipment Area % of total cost

Feedstock Handling 4.0% 3.6% 6.6%

Pretreatment 21.9% 19.5% 23.6%

Saccharification / Fermentation 10.6% 9.9% 8.3%

Cellulase Production 13.3% 11.5% 0.0%

Distillation / Separation 10.5% 9.6% 19.2%

Power / Steam Production 27.6% 33.0% 33.7%

Other* 12.2% 12.9% 8.8%

Total 100.0% 100.0% 100.0%

Source McAloon et 

al. 2000

Wooley et 

al. 1999

Aden et al. 

2002

* Other includes wastewater treatment, storage, and utilities

Outline for model analysis

Due to the complexity of the LCE Fermentation/Hydrolysis process, it was necessary to use 

a number of assumptions to generate a simple and useable model. The cost and 

performance model was developed as follows: 

• Hemicellulose hydrolysis (pretreatment) varies based on facility size and time period 

o The only available technology for short term (2010) is dilute acid pretreatment, in 

the size range from 25 to 60 MGY. 

o Mid term (2015-2020) pretreatment technologies are dilute acid for medium size 

facilities (60 to 100 MGY), and steam explosion for large facilities (> 100 MGY). 

o Long term (2025+) pretreatment technologies include dilute acid for medium size 

facilities, and Liquid Hot Water (LHW) for large facilities. 

o It is assumed that small facilities (< 60 MGY) are not constructed after the short 

term time period. 

• Cellulose hydrolysis step is performed using enzymatic hydrolysis (with cellulase) for all 

modeled processes. 

• Cellulase is produced on-site for most scenarios used in this analysis, although in some 

cases it is purchased. The selection for on-site production versus purchase of cellulase 

follows the choices reported in the literature for each technology option. On-site 

cellulase production will affect O&M costs, capital costs, and overall ethanol yields, as a 

fraction of the sugar stream is diverted to feed the microorganisms. Purchased cellulase 

only affects O&M costs, and is generally more expensive overall. 

• Electricity and steam are produced with a boiler and turbogenerator from residual solids 

(lignin, unconverted holocellulose, cell mass), and unconverted sugars which are 

partially dried to a syrup. 

• Electricity is the only co-product produced from the process, and is valued at 5.7¢/kWh 

based on the average industrial electricity cost from Energy Information Administration 

(EIA 2006). Note that EIA’s projections for industrial electricity for the 2010 to 2030 

time period is 5.8¢/kWh, only slightly higher than current value (EIA AEO 2007). 

Selection of feedstock type is a critical component of the model, as the composition of the 

biomass affects the ethanol production. In particular, the hemicellulose, cellulose, and 

lignin content of the feedstock affect yield (gallons of ethanol produced per dry ton of 

feedstock). The pretreatment technology also has a significant effect on the ethanol yield, 
24 

as each technology has a different conversion factor. The feedstock composition and yield 

in turn affect the material available for power production – a portion of the unfermented 

sugars are dried and the resulting syrup is fired in the boiler along with the lignin and cell 

mass. In addition, different feedstocks will have different costs and availability. 

The conversion rates of hemicellulose and cellulose into sugars and the fermentation of 

sugars into ethanol are technology dependent. These conversions also increase with time, 

such that for each pretreatment process the conversion rates in the long term are 

significantly higher than in the short term rates. Conversion rates for saccharification of 

cellulose and hemicellulose and fermentation of the glucose and other sugars are expressed 

as a percent of theoretical conversion for each technology available in each time period, as 

shown in Table 9. 

Table 9 - Conversion rates for LCE Fermentation/Hydrolysis 

Conversion (% of theoretical) (1)

Short Term Mid Term Long Term

Pretreatment Technology Dilute Acid Dilute Acid Steam 

Explosion Dilute Acid LHW

Saacharification

 Hemicellulose 83% 85% 55% 85% 93%

 Cellulose 75% 85% 93% 90% 98%

Fermentation

 Xylose & other sugars (2) 86% 90% 85% 95% 94%

 Glucose (2) 93% 94% 93% 95% 94%

Source

Hamelinck et al. 

2005, Wooley et al. 

1999

Wooley et al. 

1999

Hamelinck et al. 

2005

Wooley et al. 

1999

Hamelinck et al. 

2005

2) Cellulose is converted to glucose during saacharification, while hemicellulose is converted to xylose and other sugars

1) Average conversion estimates based on poplar feedstock and the reported pretreament technologies. The advanced technologies for mid 

and long term pretreatments may not be suitable for all feedstocks.

The theoretical ethanol yield from biomass feedstocks is derived based on the dry weight of 

fraction of C-5 and C-6 sugars. Theoretical yield is equal to the total weight percent of C6 

sugars times 172.82, plus the total weight percent of C5 sugars times 176.87 (U.S. DOE 

EERE Biomass Program 2006).34 The calculation for actual ethanol yield is very similar, 

except that the percent of theoretical conversion for each step is taken into account. 

The electricity production depends on the amount of material available for boiler fuel and 

the steam use, which are related to the facility type. The dilute acid distillation process and 

LHW pretreatment have high steam requirements which implies lower electricity production. 

Facilities with higher conversion rates will have fewer unconverted sugars to use a boiler 

fuel. 

Operations and Maintenance (O&M) costs are separated into fixed and variable components. 

The fixed O&M includes annual costs which are a function of the plant’s capacity not its 

annual ethanol production. These costs include labor, maintenance, taxes and insurance. 

Variable O&M costs include raw materials (such as sulfuric acid and lime for dilute acid 

pretreatment, ammonia and corn steep liquor for cellulase production, or purchased 

 

34 These factors are derived from the following conversions: 1.11 pounds of C6 sugar per pound of C6 polymeric 

sugar, 1.36 pounds of C5 sugar per pound of C5 polymeric sugar, each pound of sugars can produce a maximum of 

0.51 pounds of ethanol, and there are 6.55 pounds of ethanol per gallon. 
25 

cellulase if it is not made in the process) and solids disposal (i.e. ash and gypsum). The 

O&M values used in the model are derived from published studies for each technology type. 

The key values and assumptions used to calculate the mid-term (2015) technology analysis 

and economic performance model for LCE Fermentation/Hydrolysis are described below. An 

example of the detailed analysis for all periods is shown in Appendix G. 

• Feedstock type and input quantity are variables. Applicable feedstocks include corn 

stover, wheat straw, switchgrass, poplar (hardwood) and pine (softwood), and portions 

of the MSW stream (see Appendix f for details on biomass from MSW). These 

feedstocks were selected based on available composition data, and can be used to 

represent a range of wood and agricultural residues. 

• The applicable size range for facilities in this time period is 60 to 150 MGY, based on 

facility sizes from sources (Hamelinck, van Hooijdonk and Faaij 2005; Wooley et al. 

1999; Aden et al. 2002). Facilities with capacities from 60 to 100 MGY are modeled to 

use dilute acid pretreatment, while larger facilities (> 100 MGY) use steam explosion 

pretreatment. 

• Ethanol yield is based on the feedstock composition and pretreatment technology. 

Biochemical compositions (hemicellulose, cellulose, and lignin percentages) for the 

feedstocks are based on data from U.S. DOE EERE Biomass Program (2006) and 

Hamelinck, van Hooijdonk and Faaij (2005), as shown in Table 7 above. The actual 

yields are calculated based on projected conversion of hemicellulose and cellulose to 

sugars during saccharification, and the fermentation of these sugars to ethanol. The 

projected conversion rates for each technology are given in Table 9 above. Yield data 

for various feedstocks are shown in Table 10. 

• The total conversion efficiency (HHV) is 38-41% for dilute acid and 36-40% for steam 

explosion, depending on the feedstock type. Corn stover and pine have the highest 

conversion rates of the selected feedstocks. 

• Capital cost data is based on average of results from (Hamelinck, van Hooijdonk and 

Faaij 2005; Wooley et al. 1999; Aden et al. 2002; and McAloon et al. 2000).35 Each 

pretreatment technology has a different base capital cost, which is scaled by facility size 

using a typical scaling factor for biofuels of 0.8. The base cost for a mid term dilute acid 

facility is $3.31/gal for a 68 MGY facility, and the cost for a 130 MGY steam explosion 

facility is $4.61/gal. 

• Net electricity production is based on heat and power production with partially dried 

solid residuals (lignin, cell mass) and unfermented sugars (dried to a syrup), fired in a 

boiler. The amount of electricity generated is dependent on the pretreatment 

technology. For the mid-term period, electricity production for the dilute acid process is 

about 2 kWh per gallon of ethanol produced, following Wooley et al. 1999, while steam 

explosion pretreatment gives about 6.3 kWh/gal based on data from Hamelinck, van 

Hooijdonk and Faaij (2005). Note that the net electricity production for the steam 

explosion pretreatment is much higher than other technologies as this method has lower 

steam requirements. Furthermore, cellulase is not made on site in the steam explosion 

case, which means a larger quantity of non-fermented sugars and residuals are available 

for power generation. 

• Annual water consumption is calculated based on the annual feedstock input, using data 

from Wooley et al. (1999) for near-term dilute acid process. Potential changes in water 

consumption for different time periods or for different pretreatment processes are not 

included in this analysis. 

 

35 Note that the BIGCC case and best of industry are excluded from capital cost estimates, as they are not 

representative of an average facility. 
26 

• The CO2 production stream is estimated by assuming that the amount of CO2 produced 

is approximately 96% of the weight of ethanol produced, since the theoretical max yield 

is 51% ethanol and 49% CO2 (by weight) from sugars. 

• Annual Fixed and Variable O&M costs are calculated based on data in published studies. 

Mid-term dilute acid O&M costs are based on Wooley et al. (2005), and steam explosion 

data is from Hamelinck, van Hooijdonk and Faaij (2005). Variable O&M includes raw 

materials (sulfuric acid & lime for dilute acid, ammonia & CSL for cellulase production, 

other chemicals) and solids disposal (i.e. ash and gypsum). Fixed O&M includes labor, 

maintenance supplies, insurance and property taxes. 

• The co-product credit for electricity is based on the net electricity available for export 

and a current electricity value of $0.057/kWh, based on the 2005 average wholesale 

price of electricity for industrial sector from EIA (2006). 

• The levelized non-feedstock production cost for ethanol is calculated based on the 

annual operating expenses and capital cost payment, co-product credit, and quantity of 

fuel produced. 

Table 10 - Feedstock Composition and Yield Data 

Yield Actual Yield (gal/ton) (2)

Feedstock

Theoretical 

Max Yield (1) 

(gal/dry ton)

Short Term 

(Dilute Acid)

Mid Term 

(Dilute Acid)

Mid Term 

(Steam 

Explosion)

Long Term 

(Dilute Acid)

Long Term 

(LHW)

Agricultural Resources

Corn Stover 107.6 72.6 80.6 77.3 86.0 82.0

Wheat Straw 98.8 69.3 76.8 73.6 82.0 77.9

Grass Resources

Switchgrass 99.7 70.0 77.4 74.4 82.6 78.7

Woody Resources

Hybrid Poplar 109.9 76.9 85.9 81.2 91.9 98.6

Pine 115.1 80.9 90.2 83.7 96.4 103.5

Other Resources

Yard Trimmings / 

Green Waste 108.0 63.9 70.0 68.6 74.4 73.4

Mixed Paper 116.2 76.8 86.0 83.5 92.1 98.8

1) Maximum yield values based on sugar content, calculated from EERE's Theoretical Ethanol Yield Calculator 

(http://www1.eere.energy.gov/biomass/ethanol_yield_calculator.html)

2) Actual yields calculated based on average conversion values for all feedstocks in short term, and wood for all terms. Agricultural and 

grass feedstock yields for advanced mid and long term pretreatment technologies based on average increase of wood feedstock yields 

from short to mid term (4.4% of theoretical), as the conversion technology information does not apply to these materials, but other 

comparable advanced technologies may apply.

Model Results:

Some of the key cost and performance results for projected mid-term LCE Fermentation/ 

Hydrolysis processes are shown in Table 11 and Table 12. These tables show results for the 

range of applicable facility sizes based on selected input quantities, illustrating the high and 

low end costs for each pretreatment technology. The analysis shows that in general the 

non-feedstock production cost of ethanol for dilute acid is lower than the steam explosion. 

Although the steam explosion process generates significantly more electricity, it also has 

much higher capital and O&M costs than dilute acid. However, steam explosion has 

environmental and other benefits that are not accounted for in this simple economic 

analysis that may encourage development of these facilities. 
27 

Table 11 - Example Cost and Performance - Mid Term Dilute Acid LCE Fermentation/Hydrolysis 

Sample Model Results - LCE Fermentation/Hydrolysis w/ Poplar (dilute acid)

Feedstock Input (dry ton/yr) 700,000 1,160,000

Ethanol Yield (MGY) 60 100

Electricity Production (MWh/yr) 120,800 200,200

CO2 Stream (ton/yr) 190,400 315,500

Water Consumption (1000 gal/yr) 373,900 619,600

Capital Cost (Million $) $203.4 $304.7

Annual O&M Costs (Million $/yr) $17.7 $29.3

By-Product Credit (Million $/yr) $6.9 $11.4

Non-feedstock Production Cost ($/gal) $0.60 $0.56

Table 12 - Example Cost and Performance - Mid Term Steam Explosion LCE Fermentation/Hydrolysis 

Sample Model Results - LCE Fermentation/Hydrolysis w/ Poplar (steam explosion)

Feedstock Input (dry ton/yr) 1,250,000 1,850,000

Ethanol Yield (MGY) 101 150

Electricity Production (MWh/yr) 642,160 950,390

CO2 Stream (ton/yr) 321,500 475,800

Water Consumption (1000 gal/yr) 667,700 988,200

Capital Cost (Million $) $491.2 $672.1

Annual O&M Costs (Million $/yr) $39.6 $58.6

By-Product Credit (Million $/yr) $36.6 $54.2

Non-feedstock Production Cost ($/gal) $0.62 $0.58

Hamelinck, van Hooijdonk and Faaij (2005) estimate the mid term ethanol production cost 

from poplar using steam explosion pretreatment is about $1.42 per gallon for a facility with 

600,000 dry ton per year input. Using similar feedstock cost ($57 per dry ton) and facility 

size gives a comparable ethanol production cost from the model, about $1.27/gal. For 

further comparison, Aden et al. (2002) estimate an ethanol production cost of $1.35/gal for 

a 69 MGY dilute acid facility using corn stover feedstock.36 The feedstock cost from the 

study is about $38/dry ton. This gives an ethanol production cost from the LCE model of 

$1.04/gal for this configuration, slightly lower than the projection from Aden et al. Different 

economic analysis methods may contribute to this variation. 

3.2 Lignocellulosics to ethanol: Thermochemical Conversion and 

Fermentation 

In the Lignocellulosics to Ethanol via ThermoChemical conversion and Fermentation (LCE 

Fermentation/TC) process, gasification is used to convert biomass feedstocks into a syngas 

rich in CO and H2 which is then fermented to produce ethanol. As this technology is based 

on gasification, it has a wide range of feedstock flexibility. Furthermore, unlike the LCE 

Fermentation/Hydrolysis process, the lignin part of the biomass directly contributes to 

syngas production. Gasification requires dried and sized material, so biomass feedstocks 

must be pretreated before use. 

 

36 Costs have been converted to 2006$ using CEPCI. 
28 

3.2.1 Technology Description 

Gasification Overview

Gasification is the process of converting a solid fuel into a gaseous fuel. Gasification is 

appealing for biomass because a wide variety of materials can be gasified, some of which 

could be difficult or undesirable to combust directly (such as sludges and hazardous 

wastes). There is also a lot of flexibility in the end use of the gas. Provided it is cleaned of 

contaminants, a gaseous fuel can be used to make biobased liquids for liquid fuels and 

chemicals, or it can be used in high-efficiency power generation systems such as a gas 

turbine-combined cycle and fuel cells. 

The two main reactions occurring during gasification are as follows: 

 The Boudouard Reaction: C + CO2 ⇔ 2 CO (3) 

 The Water-Gas Reaction: C + H2O ⇔ CO + H2 (4) 

These reactions require heat input. In simple gasifiers the heat is drawn from the 

combustion of the pyrolysis gases formed during gasification, while in more complex 

gasifiers it is provided externally. These reactions produce more syngas from the biomass 

and typically leave little unreacted carbon in the ash. 

In general, the carbon conversion in a fluidized bed gasifier increases as the temperature 

increases. Furthermore, a recent study has shown that the feedstock is an important factor 

in the conversion behavior (Moilanen 2006). For example, pine wood has high carbon 

conversion at relatively low temperatures, whereas pine bark has relatively low conversion 

efficiency even at higher temperatures. Additionally, straw has high conversion efficiencies 

above 850oC, but ash sintering causes operational problems.37 This study also 

demonstrated that the reactivity of the biomass (gasification rate) is dependent on the 

biomass fuel properties, the gasifying agent, and the temperature and pressure conditions 

during reaction (Moilanen 2006). Some of these effects seem to be related to the behavior 

of the ash-forming substances during gasification, which are difficult to characterize. 

The main challenges facing biomass gasification are as follows: 

• The high moisture content of un-dried woody biomass; 

• Commercial availability of gas clean-up technologies that are sufficiently robust and 

effective to allow the product gas to be used in a turbine or engine; and 

• The relatively high cost of gasification equipment, which is currently built on a 

custom basis. 

Furthermore, gasification for power generation is currently a challenge as there is limited 

industry experience in using biomass gasifiers in advanced power generation cycles. 

There are currently two principal types of gasifiers: fixed bed and fluidized bed. The former 

is typically simpler, less expensive and produces a low BTU syngas. The latter is more 

complicated, more expensive and produces a syngas with a higher heating value. 

In fluidized bed systems, steam and/or air are passed through a particle bed and cause the 

bed to levitate (i.e., become “fluidized”). Fuel is added to the bed which is often composed 

of inert heat transfer media such as sand or dolomite. Other materials such as alumina may 

be used to further enhance the heat transfer. Fluidized bed devices are noted for their high 

energy output (per area of bed) and fuel flexibility. 

 

37 Note that these experimental results can be used to describe the characteristics of the fuel, but conversion in a 

gasifier will be affected by many additional factors, such as the partial pressure of the gasification agent and the 

size distribution of feedstock particles. 
29 

At present, there are numerous small, fixed-bed gasifiers in use around the world. These 

units typically convert wood and agricultural residues into a low-BTU gas for use in process 

heating or district heating. These applications have developed as alternatives to traditional 

boilers. There has been a significant effort to develop large-scale (>10 MWe) gasifiers for 

use in a biomass integrated gasification combined cycle (BIGCC). These efforts have not 

yet resulted in a sustainable commercial operation. 

Syngas Fermentation to Ethanol

Figure 8 shows the general arrangement for the LCE Fermentation/TC process. After 

gasification, the syngas is conditioned and compressed for fermentation. In the fermentor, 

anaerobic micro-organisms ferment the syngas to produce ethanol. Although these 

organisms prefer CO to H2, the syngas can contain any mixture of these gases for 

conversion. The chemical reactions for ethanol production for this process are as follows:38 

6CO + 3H2O Æ CH3CH2OH + 4CO2 (5) 

2CO2 + 6H2 Æ CH3CH2OH + 3H2O (6) 

Typical CO conversions reported in literature for laboratory scale fermentation are ~90%, 

while conversions for H2 only about 70% (Spath and Dayton 2003). 

Figure 8 – Schematic diagram showing LCE Fermentation/TC process 

Biomass

Pre-treatment

Sizing

Dryer

Arrows show process links

Steam

Fermentation Purification

Ethanol

Gas Clean-up

and

Compression

Steam / Power 

Production

Ash

Electricity

Gasifier Syngas

Tail gas

Cell mass

Steam

Biomass

Pre-treatment

Sizing

Dryer

Arrows show process links

Steam

Fermentation Purification

Ethanol

Gas Clean-up

and

Compression

Steam / Power 

Production

Ash

Electricity

Gasifier Syngas

Tail gas

Cell mass

Steam

Source: Diagram based on figure in (Spath and Dayton 2003) 

Unlike the by-products of corn ethanol production, the cell mass produced during 

fermentation of syngas is not currently approved for animal feed (Spath and Dayton 2003). 

An alternate use for the material is to recycle it to gasifier for re-processing. The exhaust 

gas produced from fermentation can be used to produce steam and power. The steam can 

be used to dry the biomass feedstock during pretreatment. 

Theoretically, all the chemical energy in biomass can be converted to syngas. However, not 

all of the syngas will be converted to ethanol. Estimates of the ethanol yield produced from 

biomass with this process can be estimated using the following equation, assuming all of the 

syngas produced by the gasifier (after conditioning) goes to fermentation:39

5 1.5 10

( / ) ( / ) ( )

×

× × × = Feed ton day HHV Btu lb C

Ethanol MGY in η gasification ; (7) 

 

38 Source: (Spath and Dayton 2003) 39 Source: (Spath and Dayton 2003) 
30 

Where Feedin is the rate of feed input to the gasifier in dry tons per day; 

 HHV is the higher heating value of the feedstock; 

ηgasification is the cold gas efficiency of the gasifier and gas conditioning; and 

 C is the conversion rate of CO and H2 to ethanol, as a fraction of theoretical 

Projected yields for LCE Fermentation/TC process are 70-105 gallons of ethanol per dry ton 

of feedstock (Spath and Dayton 2003). This is lower than the yields from current grain 

ethanol production technologies, which are around 100 gal/ton. Spath and Dayton (2003) 

note that this is a result of losses from gasification, gas conditioning, and fermentation 

steps which counteract the benefits of direct utilization of the lignin component of the 

biomass. 

University of Arkansas and Bioengineering Resources Inc (BRI) have been working on this 

technology since the 1980’s. BRI has a patented fermentation bacteria for the process 

(Bioengineering Resources 2007), and is part of a team that was recently selected to build a 

demonstration facility with funding from DOE (U.S. DOE Feb. 2007). Several other 

universities have also been involved in research efforts. However, as yet this technology 

does not seem to be near commercialization, and there is not sufficient information about 

the cost and performance for a detailed model. As such, the syngas fermentation process 

for ethanol production will not be further characterized here. 

3.3 Lignocellulosics to Middle Distillates: Fischer Tropsch 

Fischer Tropsch (FT) synthesis is a method of generating hydrocarbons from gaseous 

mixtures of CO and H2 using a metal catalyst. This process has been known since the early 

1900’s, and the first commercial plant was built by Sasol in South Africa in 1955 (using coal 

syngas). FT synthesis produces a range of hydrocarbon products, and a large amount of 

heat from the highly exothermic reaction. The distribution of products generated from FT 

synthesis is affected by reaction temperature and pressure, input syngas composition, and 

catalyst type and composition. Among many other products, FT can be used to generate 

diesel and gasoline fuels. Although the FT process is relatively well characterized, there has 

not been a lot of analysis or testing with biomass feedstocks. 

3.3.1 Technology Description 

The general steps for the LignoCellulosics to Middle Distillates – Fischer Tropsch (LCMD – 

FT) process are shown in Figure 9. As typical for gasification processes, the biomass must 

first be sized and dried for use (see detailed gasification description in Section 3.2.1 above). 

After gasification, impurities such as particulates, sulfur, and tar must be removed from the 

raw syngas. The amount of gas clean-up required will depend on the type of process and 

economics. However, this is a very important step in the LCMD - FT process, as the FT 

catalysts (Iron (Fe) or Cobalt (Co)) are extremely sensitive to chemical poisoning by sulfur, 

as well as by halides and nitrogen. 

After clean-up, the syngas is then sent to either a Low Temperature (200-240oC) or a High 

Temperature (300-350oC) FT reactor (Spath and Dayton 2003). Reactor pressures are 

generally 145-580 psi (Spath and Dayton 2003). Low temperature synthesis typically uses 

Co catalysts, and is used to maximize the diesel fraction of the product, while high 

temperature synthesis uses Fe catalysts and maximizes gasoline production. 
31 

There are four types of reactors that have been used commercially, including: 

• Multi-tubular fixed bed, also known as the ARGE reactor. Has conversion efficiencies 

around 70%, and the products are about 50% wax) 

• Circulating fluidized bed, such as the original Synthol reactors which produce high 

fractions of gasoline and light olefins. These reactors are complex, and the circulating 

bed material causes considerable erosion which leads to high O&M costs. They have 

reached design limit for capacity at 7,500 bpd. 

• Fixed fluidized bed, or Sasol Advanced Synthol reactor, which has replaced the older 

Synthol reactor. It is half the size and cost for same capacity as the Synthol reactors, 

and has lower operating costs. Size limit is 20,000 bpd. 

• Fixed slurry bed reactors, which are low temperature reactors optimized for wax 

production. They cost less than tubular reactors, but have only recently been used for 

commercial FTS. Separating the wax from the catalyst can be a challenge. 

Temperature control is critical in the reactor, as it affects the product distribution and can 

harm the catalyst. In addition to the chemical poisoning mentioned above, catalysts loose 

activity due to sintering, carbon deposition, and oxidation. Furthermore, reactor 

temperatures above 400oC encourage methane formation, an unwanted gaseous product 

(Spath and Dayton 2003). 

The off-gas produced from the FT reactor can be diverted and recycled back through the 

reactor to generate additional hydrocarbon products, or it can be used to generate 

power/steam (not shown in the figure). Product liquids generated from FT synthesis are 

upgraded using a combination of hydrotreating, hydrocracking, hydroisomerization, and 

separated. 

Figure 9 – Schematic diagram showing general process steps for FTS 

Biomass

Pre-treatment

Sizing

Dryer

Arrows show process links

Low Temp 

FTS

Gas Clean-up

Particulate Removal

Wet Scrubbing

Tar & Sulfur Removal

WGS, etc

Ash

Gasifier

Clean 

Syngas

High Temp 

FTS

Upgrading

Diesel

Waxes (>C20)

Upgrading

Gasoline

Olefins 

(C3 – C11)

Biomass

Pre-treatment

Sizing

Dryer

Arrows show process links

Low Temp 

FTS

Gas Clean-up

Particulate Removal

Wet Scrubbing

Tar & Sulfur Removal

WGS, etc

Ash

Gasifier

Clean 

Syngas

High Temp 

FTS

Upgrading

Diesel

Waxes (>C20)

Diesel

Waxes (>C20)

Upgrading

Gasoline

Olefins 

(C3 – C11)

Upgrading

Gasoline

Olefins 

(C3 – C11)

Based on figure in (Spath and Dayton 2003) 

Fischer Tropsch synthesis is characterized as a polymerization reaction with stepwise chain 

growth. The primary reaction that occurs during synthesis is given below. 

FT Synthesis Reaction: CO + 2H2 Æ --CH2-- + H2O (8) 

The -–CH2-- is a building block for hydrocarbon chains. A secondary reaction occurs when 

Fe catalysts are used, Water-Gas Shift (WGS). 

WGS Reaction: CO + H2O Æ H2 + CO2 (9) 
32 

The combination of these reactions gives the net overall reaction for Fe catalyzed FT 

synthesis: 

2CO + H2 Æ --CH2-- + CO2 (10) 

The syngas entering the reactor needs to have a H2/CO ratio of 2.15 for a cobalt catalyst, 

and 1.7 for an iron catalyst (lower because of the WGS reaction). The composition of the 

syngas can be altered by changing the gasification conditions, or by processing the syngas 

after clean-up via WGS, CO2 removal, or methane reforming (which converts methane with 

steam into CO and H2). 

It is clear that FT catalysts are a very important part of the synthesis. Co catalysts tend to 

last longer than Fe, and they have better carbon conversion to products, since there is no 

major impact from the secondary WGS reaction. Additionally, Co doesn’t require as high of 

pressures as Fe, which equates to lower operating costs. However, Fe is attractive because 

it is much less expensive than Co (approximately 200 times cheaper). 

The product selectivity from FT synthesis is based on the catalyst’s ability to encourage 

chain growth versus chain termination. Regardless of operating conditions, the Fischer 

Tropsch reaction always produces a range of olefins, paraffins, and oxygenated compounds 

like alcohols, aldehydes, acids, and ketones. Only methane and paraffin wax can be 

produced with very high selectivity (Spath and Dayton 2003). The maximum gasoline 

product fraction selectivity is 48%, while for diesel the maximum is about 40% (Spath and 

Dayton 2003). 

Technology Status

There has been a lot of research and development of FT synthesis technologies. Sasol has 

several commercial FT plants in South Africa that use coal and crude oil feedstock. Sasol’s 

first FT plant was built in 1955 and because of its success two more were built in 1980’s. 

These facilities are currently using Sasol Advanced Synthol reactors, which have much lower 

O&M costs than the original Synthol reactors. 

Two other plants became operational in the 1990’s, both of which use natural gas feedstock. 

The Mossgas plant is a Fischer Tropsch facility in South Africa that produces 1.1 million 

tons/yr of FT products (Spath and Dayton 2003). Shell commissioned a plant in Malaysia in 

1993 which produces 0.6 million tons per year of FT products. 

3.3.2 Performance and cost analysis 

The LCMD - FT performance and cost model has been developed primarily based on recent 

work Antares performed for US DOE and NREL (Antares 2003a, Antares 2003b, and Antares 

2003c). In this analysis, Antares developed process models, capital costs, and O&M costs 

for several FT systems with varied size and technology types. One of the commercial scale 

systems modeled previously was selected for use as the basis for mid-term (2015) LCMD - 

FT technology in this analysis. 

The defining characteristics of the configuration are the gasifier, FT reactor and steam 

reforming system. The selected configuration uses an air-blown, indirect, atmospheric 

gasifier, which is represented by the BCL/FERCO gasifier (abbreviated as BCL). After 

cleaning and conditioning, the compressed syngas is processed in a steam methane 
33 

reformer (SMR) to convert much of the hydrocarbons to carbon monoxide and hydrogen.40 

The syngas then undergoes a shift reaction to produce an H2 to CO ratio of about 2:1. This 

configuration uses two (low temperature) fixed bed FT reactors with Co catalysts. Each 

reactor has a CO conversion of about 42%, so that the overall conversion is 66%. Two 

reactors are used in this process to increase the yield of FT-liquids, as recycling is not an 

effective option for air-blown gasifiers. The unconverted syngas is used for electricity and 

heat production in a combined cycle power plant. The FT-liquids produced in the reactor are 

hydrocracked and undergo primary distillation before they are sent to an off-site refinery. 

The final products are distillate and naptha. A diagram showing the major components and 

process flows for this system is shown in Figure 10. 

In general, the total capital investment for cases involving SMR is greater than that for the 

cases involving ATR. However, it is important to realize that the reformer choice affects 

O&M costs. Relative to ATR, the use of SMR increases FT liquids production and boosts 

exportable power revenues, thus resulting in lower total O&M costs on a $/bbl basis. 

The overall process efficiency of this system including electricity and steam production is 

58% on LHV basis (Antares 2003a). For this configuration of the LCMD - FT process, about 

73% of the energy produced is embodied in the FT liquids (C5+), and the remainder is 

exportable power.41

 

40 Note that although SMR has higher capital costs then autothermal reforming (ATR), it is also more efficient. ATR 

is currently the only practical reformer to use for biomass-derived syngas, but it is expected that STR reforming 

could be available for use by the mid-term period. An optimistic view of SMR is used in the model. 41 BIG-FT stands for Biomass Integrated Gasification – Fischer Tropsch. 
34 

Figure 10 – Basis for Mid-Term LCMD - FT Technology Characterization 
35 

Outline for model analysis

The key values and assumptions used to calculate the advanced technology analysis and 

economic performance model for Fischer Tropsch synthesis are described below. An 

example of the detailed analysis is shown in Appendix G. 

• Feedstock type and input quantity are variables. Applicable feedstocks include woody 

and agricultural residues. 

• This model is applicable for facility sizes with greater than 185,000 dry ton biomass 

input per year, based on Tijmensen, Faaij and van Hardeveld (2002). 

• Yield of FT liquids are calculated based on the LHV conversion efficiency. As different 

feedstocks have distinct heating values, the feedstock choice affects the amount of FT 

liquids produced. The conversion efficiency for distillates and naptha have been 

calculated in Antares 2003a. For the selected system, LHV efficiencies for the products 

are 30.4% for distillates and 12% for naptha.42 This leads to a total energy conversion 

efficiency of 42% for the process. 

• The FT liquids produced from this configuration have estimated heating values (LHV) of 

125,684 Btu/gal for the distillates and 115,263 Btu/gal for the naptha. 

• The amount of electricity generated is calculated to be about 560 kWh per barrel of FT 

liquids produced, following Antares 2003a. 

• Annual water consumption is equivalent to about 33,500 thousand gallons for a facility 

with a feedstock input of 700,000 dry ton per year, based on data from Antares 2003a. 

• Capital cost data is based on values for a commercial facility with a biomass input of 80 

dry ton per hour (about 700,000 ton/yr) from Antares 2003c. The scaling factors are 

0.74 for a biomass input from 185,000 – 750,000 dry ton/yr, and 0.91 for a biomass 

input greater than 750,000 dry ton/yr, following (Tijmensen, Faaij and van Hardeveld 

2002).43

• Annual non-labor fixed O&M costs are calculated as a percentage (2.3%) of the capital 

cost, following Antares 2003a. Maintenance and repair accounts for 2% of the cost 

based on capital investment, and the operating supplies are estimated to be 15% of the 

total maintenance cost. 

• Labor costs are calculated based on the number of people required to operate the 

facility, with an assumed current labor rate of $82,000 per year per employee (including 

fringe and benefits). The base labor requirement for a facility with 700,000 ton/yr 

biomass input is $5,660,000/yr. This cost is scaled by facility size using a scaling factor 

of 0.25, as in (Tijmensen, Faaij and van Hardeveld 2002). 

• Annual Variable O&M costs include steam, water, wastewater treatment, ash and 

catalyst disposal, consumables, and FT catalysts. These are calculated on a $/gallon 

basis of the FT liquid products, following Antares 2003a. 

• The co-product credit for electricity is based on the net electricity available for export 

and a current electricity value of $0.057/kWh (based on the 2005 average wholesale 

price of electricity for industrial sector from EIA 2006). The co-product credit for naptha 

is estimated to be $63/bbl, based on average market data over the past year from 

Plastemarte (2007).44 

• The levelized non-feedstock production cost for the FT distillates are calculated based on 

the annual operating expenses and capital cost payment, co-product credit, and quantity 

of fuel produced. 

 

 

42 These yields were calculated using the Anderson-Schulz-Flory (ASF) theory to model the FT product distribution 

(Antares 2003a). For the cobalt catalyst the chain growth probability is assumed to be 0.93, which corresponds to 

a C5+ selectivity of 94.9%. 

43 "When scale is between 100 and 400 MWth the overall scaling factor for the entire plant (with respect to overall 

total investment costs) is approximately 0.74. When capacities go beyond 400 MWth, the average scaling factor 

increases to 0.91" (Tijmensen, Faaij and van Hardeveld 2002, p. 143) 

44 The market value of naptha ranged from $580 to $755 per ton over the past year (Plastemarte 2007). 
36 

Model Results

Some of the key cost and performance results projected for LCMD - FT are shown in Table 

13. This table shows results for the range of applicable facility sizes based on selected input 

quantities, and illustrates the high and low end costs. The low end feedstock input shows 

the minimum applicable facility size, and the high end was selected to show a reasonable 

range of sizes and costs. In general, the analysis shows that the non-feedstock production 

cost of distillates from FT synthesis is fairly expensive. However, the by-product credit is a 

critical factor and can have a significant effect on the production costs. 

Table 13 - Example Cost and Performance for Fischer Tropsch Facility 

Sample Model Results - Fischer Tropsch Synthesis w/ Poplar

Feedstock Input (dry ton/yr) 185,000 1,500,000

FT Distillate Yield (MGY) 7.5 61

Naptha Yield (MGY) 3.2 26

Electricity Production (MWh/yr) 142,940 1,158,980

Water Consumption (1000 gal/yr) 8,860 71,800

Capital Cost (Million $) $250.2 $1,354

Annual O&M Costs (Million $/yr) $9.9 $57.7

By-Product Credit (Million $/yr) $13.0 $105.4

Non-feedstock Production Cost ($/gal) $3.66 $1.94

Tijmensen, Faaij and van Hardeveld (2002) project the cost of FT-liquids is about $2.70/gal 

for an 80 tph facility (about 700,000 dry ton per year).45 The production of FT-distillates 

from the model for a similar sized facility using a feedstock cost of $37.90/dry ton for poplar 

is $3.10/gal. Although this result is slightly higher than the cost suggested by Tijmensen et 

al. (2002), these results cannot be directly compared as the FT-liquids from the model are 

separated into components. In the conversion technology model, the naptha is sold as a 

lower value by-product, at a value of about $1.50/gallon. 

3.4 Lignocellulosics to Mixed Alcohols: Thermochemical 

Conversion 

3.4.1 Technology Description 

The conversion of LignoCellulosics to Mixed Alcohols via ThermoChemical Synthesis (LCMA 

Synthesis/TC) is very similar to the process described above for syngas conversion to 

ethanol (LCE Fermentation/TC), except the fermentation step is replaced by a catalyst 

conversion.46 It is also similar to the LCMD – FT process, although the end products are 

alcohols not distillates. Figure 11 shows a block diagram for a typical LCMA Synthesis/TC 

process. Higher Alcohol Synthesis (HAS) is done in reactors similar to those used for FT and 

methanol synthesis. The most effective types of catalysts include modified methanol 

synthesis catalysts, modified FT catalysts, and alkali-doped molybdenum catalysts (Nexant 

Inc. 2006). The modified methanol synthesis and Mo catalysts show higher alcohol yields 

than modified FT catalysts. The Mo catalysts also have the best selectivity for higher 

alcohols, and a high tolerance for CO2 and sulfur in the syngas (Nexant Inc. 2006). 

However, although this higher sulfur tolerance requires less clean-up of the syngas before 

conversion, it may require sulfur removal downstream in the mixed alcohol fuel. 

 

45 Production cost converted to 2006$ using CEPCI. 46 See section 3.2.1 for further details. 
37 

Figure 11 - Schematic diagram of thermochemical ethanol production process 

Biomass

Pre-treatment

Sizing

Dryer

Conversion / 

Alcohol Synthesis

Alcohol 

Separation

Ethanol

Gas Clean-up

&

Conditioning

Heat / Power 

Production

Ash

Gasifier Syngas

Other 

Alcohols

Biomass

Pre-treatment

Sizing

Dryer

Conversion / 

Alcohol Synthesis

Alcohol 

Separation

Ethanol

Gas Clean-up

&

Conditioning

Heat / Power 

Production

Ash

Gasifier Syngas

Other 

Alcohols

Diagram based on Figure in Phillips et al. (2007) 

LCMA Synthesis/TC involves complex set of reactions that produce a variety of products, 

depending on catalyst used and process conditions. The major reactions include methanol 

synthesis, FT reactions, higher alcohol synthesis, and water-gas shift. The process is 

optimized at syngas compositions with ratios of H2/CO ~ 1 (Spath and Dayton 2003). 

Regardless of the type of catalyst used, typically 40 to 90% of product stream needs to be 

recycled to maximize mixed alcohol production (Nexant Inc. 2006). The main by-products of 

the process are CO2 and water, and large quantities of methane are also often produced. 

Technology Status

Although the process to generate higher alcohols from syngas has been known since the 

early 1900’s, the technology has not yet reached commercialization (Spath and Dayton 

2003). As of April 2005, there were no commercial plants that solely produce mixed 

alcohols in the C2 to C6 range (Nexant Inc. 2006). However, Range Fuels, Inc. is planning a 

demonstration facility to generate ethanol and other alcohols via thermochemical conversion 

(see details below). The main technical hurdles for higher alcohol synthesis include poor 

selectivity to higher alcohols and low yields. Typical conversion rate for single pass 

processes is about 10% production of alcohols, which is mostly methanol (Spath and Dayton 

2003). The methanol can be recycled back through process to generate higher alcohols. 

Research and development efforts for HAS have been performed by several companies since 

the early 1980’s. Some of the most advanced processes were developed by DOW, IFP and 

Snamprogetti (Spath and Dayton 2003). However, none of these companies are currently 

active in this area of research (Nexant Inc. 2006). Recent efforts for commercialization of 

the process have been spurred by new catalyst developments, new project developers, and 

the interest in alternative fuels (Nexant Inc. 2006). Some of the current commercialization 

efforts are described below based on information from Nexant Inc. (2006): 

• Pearson Technologies has a 30 ton/day biomass gasification with syngas conversion to 

alcohols in Aberdeen, Mississippi. Pearson is also trying to develop a demonstration plant 

in Hawaii. 

• As mentioned above, Range Fuels Inc. is developing a 1,200 ton/day (wood chip input) 

demonstration facility to generate ethanol and methanol. This project is supported by 

DOE and is scheduled for completion in 2011 (see U.S. DOE 2007). 

• Power Energy Fuels is continuing to work on their proprietary EcaleneTM process. 

Although this process is currently only developed at the bench-scale, there are 2 or 3 

pilot plants under consideration which would produce mixed alcohols from biomass 

sources (wood chips, RDF, and tires). One of these pilot facilities is a 2,000 gallon per 

day plant that would be located at Wabash River Coal Gasification facility (with 

ConocoPhillips). 
38 

• Standard Alcohol Company of America is continuing to work on their EnviroleneTM

process. This is only a bench scale process currently, but the company is interested in 

developing a pilot. 

Despite this recent surge of development, there are still a number of technical and economic 

hurdles that must be overcome for the commercialization of the LCMA Synthesis/TC 

process. According to Nexant Inc. (2006, p. 3-2), the primary technical barriers include: 

“the overall process feasibility to produce the desired product slate, the ability to scale-up 

the process to a commercial level, the appropriate process conditions both in the reactor 

and upstream units, performance of various catalysts at commercial conditions, catalyst 

sensitivities, and appropriate syngas compositions.” Additionally, large-scale mixed alcohol 

synthesis will require detailed consideration of the market interest and production costs 

relative to other fuels. 

3.4.2 Performance and cost analysis 

The performance and cost model for thermochemical ethanol production via mixed alcohol 

synthesis has been developed primarily based on recent work by NREL (Phillips et al. 2007). 

In this report, NREL developed a detail process model and economic analysis for a projected 

thermochemical ethanol facility. The analysis is based on the DOE targets for synthesis 

yields and selectivity for a 2,205 dry ton/day facility (equivalent to 772,000 ton/yr for a 

plant with 96% availability). 

The NREL model configuration uses an indirect steam gasifier and a conventional steam 

power cycle. The syngas clean-up and conditioning step includes tar reforming, water 

scrubbing (for cooling and quench), and acid gas removal. Clean syngas is converted to 

alcohols in a fixed bed reactor, using a MoS2 catalyst with a very high ethanol selectivity. 47 

The alcohol separation section includes dehydration and separation of alcohols. Methanol is 

recovered and recycled through the alcohol synthesis section to increase yield of ethanol 

and higher alcohols.

A portion of the unconditioned syngas is diverted to generate electricity and heat. Although 

this model produces exactly the amount of energy required to sustain the process 

(consuming 28% of the syngas), an actual plant could vary the energy production 

depending on favorable market conditions to buy or sell electricity from the grid. 

If all the syngas was converted to alcohols, the ethanol yield would be 110.9 gallons per dry 

ton of biomass, and the total alcohol production would be 130.0 gal/ton (Phillips et al. 

2007). With 28% of the syngas used for energy production, the ethanol yield is 80.1 

gal/ton. 

Outline for model analysis

The key values and assumptions used to calculate the advanced technology analysis and 

economic performance model for thermochemical ethanol production via higher alcohol 

synthesis are described below. An example of the detailed analysis is shown in Appendix G. 

All aspects of the model analysis are based on data from Phillips et al. 2007, unless 

otherwise noted. 

 

47 This is a modified Fischer Tropsch catalyst based on the former Dow/UCC catalyst, with conversion performance 

modeled based on target results. In addition to higher total CO conversion and higher alcohol selectivity, the 

projected distribution of ethanol and methanol used in the NREL model differ from current results. The Phillips et 

al. (2007) model assumes that 71% of the alcohol production is ethanol, and 5% is methanol. In contrast, the 

Dow distribution was 30-70% methanol and 34.5% ethanol. 
39 

• Feedstock type and input quantity are variables. Applicable feedstocks include woody 

and agricultural residues. The moisture content of these feedstocks must be less than 

50% for optimal operation. 

• This model is applicable for facility sizes with greater than 185,000 dry ton biomass 

input per year, following the size range for Fischer Tropsch synthesis which has similar 

technology characteristics. 

• As different feedstocks have distinct heating values, the feedstock choice affects the 

syngas produced in the gasifier and thus the alcohol conversion. Yield of ethanol and 

other alcohols are calculated based on the HHV conversion efficiency. Ethanol 

conversion is equivalent to 38.9% of the input energy from biomass, converted to 

gallons using a typical ethanol HHV of 84,000 Btu/gal. The yield of other alcohols is 

based on an HHV efficiency of 7.6%. Nearly all of this stream consists of propanol, which 

has an HHV of about 97,300 Btu/gal. 

• Annual water consumption is estimated to be 1.94 gallons per gallon of ethanol 

produced. This water use includes cooling tower make-up, process water, and other 

system losses. 

• Capital cost data is based on values from Phillips et al. 2007 for a 2,205 dry ton/day 

plant and a scaling factor of 0.8 which is typical for biofuel conversion facilities. 

• Annual Fixed O&M costs include a labor costs and other fixed O&M. Labor costs are 

calculated following Phillips et al. 2007, with a base cost of $4,720,000/yr for a 772,000 

ton/yr facility. The labor costs are scaled by facility size using a scaling factor of 0.25, 

following the Fischer Tropsch analysis (see above for details). The other fixed O&M 

costs (maintenance, insurance, and taxes) are calculated as a percentage (4%) of the 

total capital investment. 

• Annual Variable O&M costs include consumables (such as catalysts, gasifier bed 

material, and other raw materials) and waste disposal. These are calculated on a 

feedstock input basis. No electricity purchase is required, as a portion of the syngas is 

diverted for heat and power production. 

• The co-product credit for mixed alcohols is calculated following the methodology of 

Phillips et al. 2007. The value of the alcohols is estimated to be $1.4/gal, based on the 

current wholesale gasoline prices from EIA of $1.95/gal (average from January 2006 

through April 2007), a 78% discount for lower energy density, and a 10 ¢/gal reduction 

for potential additional processing requirements before use.48

• The levelized non-feedstock production cost for the ethanol is calculated based on the 

annual operating expenses and capital cost payment, co-product credit, and quantity of 

fuel produced. 

Model Results

Some of the key cost and performance results projected for LCMA Synthesis/TC are shown 

in Table 14. This table shows results for the range of applicable facility sizes based on 

selected input quantities, illustrating the high and low end costs. The low end feedstock 

input shows the minimum applicable facility size, and the high end was selected to show a 

reasonable range of sizes and costs. In general, the analysis shows that the non-feedstock 

production cost of ethanol from thermochemical conversion of biomass to mixed alcohols is 

relatively low, although it is slightly higher than the non-feedstock production cost of 

ethanol from the LCE Fermentation/Hydrolysis process. 

 

48 The 10 ¢/gal discount is applied to account for the fact that no special effort is made to ready the mixed alcohols 

for blending or sale. 
40 

Table 14 - Example Cost and Performance for Ethanol from LCMA Synthesis/TC 

Sample Model Results - LCE Fermentation/TC w/ Poplar

Feedstock Input (dry ton/yr) 185,000 1,500,000

Ethanol Yield (MGY) 15.4 125

Other Alcohols Yield (MGY) 2.6 21

Water Consumption (1000 gal/yr) 29,920 242,570

Capital Cost (Million $) $64.9 $346

Annual O&M Costs (Million $/yr) $9.7 $20.3

By-Product Credit (Million $/yr) $3.6 $29.5

Non-feedstock Production Cost ($/gal) $1.38 $0.74

Phillips et al. (2007) estimate the minimum selling price of thermochemical ethanol is 

$1.08/gal for a 772,000 dry ton per year facility.49 The ethanol production cost from the 

model for a similar sized facility using a delivered feedstock cost of $35/dry ton for poplar is 

$1.260/gal. As the Phillips et al. (2007) study is the basis of this analysis, it is likely that 

different economic factors and analysis methods contribute to this variation. 

The LCMA Synthesis/TC process is very similar to LCMD – FT, such that one would expect 

similar capital cost projections and biofuel yields for both processes. However, a 

comparison of the example results from the technology characterization models (Table 13 

and Table 14) portrays LCMA Synthesis/TC as having much lower capital costs and higher 

yields than the FT process. It is possible that this is due to more optimistic technology 

development projections for LCMA Synthesis/TC. There do not seem to be any published 

studies showing experimental support for the targets given in Phillips et al. 2007. As such, 

the LCMA Synthesis/TC technology will not be included in the Western supply curve model. 

However, it is important to point out that this technology uses similar feedstocks and has a 

similar production cost as LCE Fermentation/Hydrolysis, so this should not have a large 

effect on the overall supply curve. 

3.5 Lignocellulosics to Gasoline: Upgrading Pyrolysis Oil 

LignoCellulosics to Gasoline via Pyrolysis and Upgrading (LCG Upgrading/Pyrolysis) is the 

conversion of biomass to bio-oil via fast pyrolysis, and then upgrading via hydrotreatment 

followed by hydrocracking at a petroleum refinery to produce a hydrocarbon fuel. In this 

process the bio-oil is mixed with petroleum products during some stage in the refining 

process, which enables usage of advanced refinery technologies and economies of scale. In 

the following discussion the general method of biomass pyrolysis will first be reviewed, 

followed by an analysis of the development of bio-oil co-processing in refineries. 

3.5.1 Technology Description 

Biomass Pyrolysis

Pyrolysis of biomass is a rapid thermal process conducted in an environment without oxygen 

to prevent combustion. By controlling temperatures and reaction times, pyrolysis can be 

used to convert solid biomass materials into a liquid oil comprised of low molecular weight 

fragments of the lignin, cellulose and hemicellulose. This “bio-oil” can be used directly as a 

substitute for petroleum fuel oil in boilers and gas turbines. Alternately, bio-oil can be 

further treated to produce refined fuels or natural chemicals such as adhesives, resins, 

 

49 Production cost converted from 2005$ to 2006$ using CEPCI. 
41 

polymers and flavorings. A variety of biomass feedstocks have been used for pyrolysis, 

including wood, bark, paper, bagasse, corn fibers and other agricultural residues. The bio-oil 

yield primarily depends on the processing conditions with the rate of heat transfer and 

product vapor residence time being the key parameters. Feedstock composition, principally 

the ash component, can also be a factor but plays a lesser role. Under optimum process 

conditions liquid yields of 60-80% by weight can be realized (Ensyn Group Inc. 2001). 

To prepare the biomass for fast pyrolysis, the feedstock is dried to less than 10% moisture 

content and sized to small relatively homogeneous particles. This is important to ensure a 

rapid heat transfer. In commercial pyrolysis processes, the reaction occurs in a fluidized 

bed reactor using an inert material such as sand to transfer heat to the incoming biomass 

particles. This process occurs so fast that the biomass is flash vaporized, becoming a 

mixture of gas, vapor, aerosols and solid char. Fast pyrolysis produces higher yields of the 

liquid fraction in bio-oil than conventional pyrolysis, with a typical composition of 75% 

liquid, 12% char, and 13% gas (Ringer, Putsche and Scahill 2006).50 

The pyrolysis step typically occurs at temperatures around 450-500oC, at atmospheric 

pressure, with a reaction time from less than one second to several seconds. After the char 

is separated out (using a cyclone), the vapor product is rapidly cooled and condenses into 

liquid bio-oil. The remaining non-condensable gas is recycled within the process and used 

as a fluidizing gas for pyrolysis and as a fuel combined with the solid char to provide 

process heat. 

The bio-oil product is an oxygenated fuel that consists primarily of carbon, hydrogen and 

oxygen and small amount of nitrogen and sulfur. The exact composition of the product 

depends on the feedstock composition and the reaction conditions. 

Status of commercialization 

There are currently two main companies that have developed commercial pyrolysis oil 

technologies - Ensyn Corporation and DynaMotive Energy Systems Corporation. Each 

company has a patented pyrolysis technique and a wide range of experience producing biooil from different feedstocks. Their products have been tested and used in various 

applications. By 2005 Ensyn had 7 commercial RTPTM biomass plants, and the largest plant 

can process 160 green tons of wood per day (Ensyn Corporation n.d.). DynaMotive Energy 

Systems Corporation reached commercialization in 2004 with a 110 ton/day biomass 

pyrolysis BioThermTM plant in Ontario. DynaMotive also completed their first modular 220 

ton/day biomass pyrolysis plant in December 2006 (Dynamotive Energy Systems 

Corporation 2006). 

Ringer, Putsche and Scahill (2006) note that although pyrolysis oil production is technically 

commercialized, most of these commercial facilities are fairly small and the larger ones 

primarily produce products such as flavoring compounds which have limited markets. Only 

a small amount of bio-oil is currently produced for fuel. 

Co-processing bio-oil in petroleum refineries

Crude pyrolysis oil can be used directly to produce heat and power. However, upgrading 

bio-oil to a hydrocarbon fuel via hydrotreatment and hydrocracking can significantly 

increase the value of the product by producing fungible gasoline and diesel fuels. 

Hydrotreating and hydrocracking are well-developed processes currently used for rejecting 

 

50 Conventional pyrolysis involves lower reaction temperatures and long residence times, and typically results in 

nearly equal fractions of liquid, gas, and char produced (Bridgwater 2007). 
42 

nitrogen, oxygen and other heteroatoms51 from crude petroleum oils. This potential 

upgrading approach is the focus of efforts to co-refine pyrolysis oils with petroleum. 

One of the main issues with crude bio-oil is the lack of stability over time. According to 

Ringer, Putsche and Scahill (2006), bio-oil viscosity increases with time at much faster rate 

than petroleum products. Such highly viscous oil cannot be used as motor fuel. 

Furthermore, the phase change which accompanies the increase in viscosity is also a 

problem for usage. Char fines in the bio-oil seem to be a critical factor causing this lack of 

stability. Advanced technologies that can successfully remove fine particles can significantly 

increase the shelf life of the product and are currently under development.52

Other potential issues with bio-oil include re-vaporization from liquid state and potential 

environmental and health effects. Bio-oil has a very complex chemical composition, and 

more than 300 specific compounds have identified so far (Ringer, Putsche and Scahill 2006). 

Some of the compounds present are known carcinogens, and experimental tests have 

shown mixed results with respect to health risks. Further, although bio-oil biodegrades in 

soil more easily than petroleum-based hydrocarbon fuels, its acidity can be harmful to water 

environments in the event of large spills (Ringer, Putsche and Scahill 2006). 

Additionally, incorporation of new fuels into a mature and accepted framework can be 

difficult. Using bio-oil directly as a transportation fuel would likely require engine 

modifications and new infrastructure. However, “if bio-oils could be upgraded chemically to 

produce a product that looked more like petroleum hydrocarbons then the end use device 

would require little to no modification. This would be the fastest way to gain acceptance of 

biomass-based fuels into the existing infrastructure.” (Ringer, Putsche and Scahill 2006, p. 

27) 

The bio-oil upgrading process primarily involves oxygen removal by hydrotreatment 

followed by hydrocracking. Catalytic hydrotreating and cracking deoxygenate the bio-oil 

and reform the remaining carbon and hydrogen into hydrocarbon compounds in the gasoline 

and diesel boiling point range. Since the carbon oxides and water are removed, these 

processes reduce the yield of the liquid product of bio-oil (by weight), although 

hydrotreating gives higher yields than catalytic cracking (Ringer, Putsche and Scahill 2006). 

The hydrocarbon product from catalytic cracking processes is also dominated by aromatic 

compounds which limits the amount that can be blended into motor fuels (Ringer, Putsche 

and Scahill 2006). 

Pyrolysis oil contains a mixture of products including water-soluble oxygenated compounds 

(derived from the hemicellulose), and insoluble pyrolytic lignin (UOP 2005). The pyrolytic 

lignin is a lower molecular weight version of lignin, which results from the thermal 

conversion of biomass feedstocks. This component of the pyrolysis oil is lower in oxygen 

and has a higher energy content than the water soluble portion. It can be separated out via 

gravity separation or by adding water to the pyrolysis oil to precipitate out the insoluble 

pyrolytic lignin portion. Hydrotreatment of the pyrolytic lignin requires less hydrogen than 

the pyrolysis oil because of the lower oxygen content, and can also be done at mild reaction 

conditions. 

 

51 A heteroatom is an organic chemistry term to describe any atom that is not carbon or hydrogen (Source: 

Wikipedia). 

52 A 6-month shelf (equivalent to that of petroleum products) life can be achieved with the addition of alcohol or 

other solvents and removing the char fines. The fine particle removal is difficult and somewhat analogous to gasclean up from gasification. Additional research is needed in order to find an easy, effective, low-cost solution. 
43 

High oxygen and acid content is a challenge for processing bio-oils and other biomass 

products. Typical refinery feedstocks like crude oil have little or no oxygen, but pyrolysis 

oils have oxygen contents on the order of 35-45% (UOP 2005). The pyrolytic lignin has less 

oxygen than the water-soluble carbohydrate portion of the bio-oil, and therefore requires 

less hydrogen consumption during the upgrading process. However, the carbohydrate 

portion of bio-oil has been shown to be a promising feedstock for reforming to hydrogen 

which could provide a synergy with co-processing of both components of the bio-oil. The 

water soluble portion can also be used as a fuel to generate heat and power for the 

upgrading process. 

Pyrolysis oils are much more acidic than other refined fuels. The acidity of refinery 

processed feedstocks is measured by total acid neutralization (TAN) number.53 The TAN for 

crude is <1, while a typical pyrolysis oil has TAN of 78 (UOP 2005). This level of acidity 

requires processing in stainless steel vessels, which are expensive and not standard in 

refineries. Pretreatment of the pyrolysis oils can be done in stainless steel vessels to reduce 

the acidity, making co-processing in the downstream vessels possible. 

Figure 12 shows a potential arrangement for producing pyrolysis oil and co-processing in a 

petroleum refinery. The biomass feedstock is first sized and dried for pyrolysis. After the 

reaction, the pyrolysis oil is separated into components - the oil fraction and pyrolytic lignin 

are co-processed to produce conventional fuels while the water-soluble components are 

converted into oxygenated products. Process residues are used for energy generation. 

Figure 12 – Schematic Diagram of the LCG Upgrading/Pyrolysis Process 

Biomass

Pre-treatment

Sizing

Drying

Arrows show process links

Lignin-rich 

bio-liquid

Co-processing 

in conventional 

refinery De-oxygenation

Process 

Residues

Conventional 

Fuels & 

Pyrolysis Chemicals

Reactor

Energy 

Production

Hydrocarbon-rich bio-liquid

Conversion

Water-soluble oxygenated components

Oxygenated 

Products

Biomass

Pre-treatment

Sizing

Drying

Arrows show process links

Lignin-rich 

bio-liquid

Co-processing 

in conventional 

refinery De-oxygenation

Process 

Residues

Conventional 

Fuels & 

Pyrolysis Chemicals

Reactor

Energy 

Production

Hydrocarbon-rich bio-liquid

Conversion

Water-soluble oxygenated components

Oxygenated 

Products

Based on figure in (Solantausta 2006)

One of the key barriers for development of the co-processing technology is that refineries 

are unwilling to experiment with processing for small quantities of pyrolysis oil that may 

detrimentally affect their catalysts or end product (UOP 2005). A typical U.S. petroleum 

refinery generates 150,000 barrels per day (bpd), while the total production of pyrolysis oil 

is only a small fraction of that amount (UOP 2005). 

BIOCOUP is a consortium of research partners that have formed to evaluate the 

development of co-processing bio-liquids in refineries. According to a presentation given at 

the 2006 European Conference on Biorefinery Research (Solantausta 2006), the 

consortium’s objectives for pyrolysis oil co-processing include: reducing bio-oil production 

 

53 Total acid neutralization number is defined as the number of milligrams of potassium hydroxide to neutralize on 

gram of feedstock (UOP 2005). 
44 

costs, develop and scale de-oxygenation technology for upgrading bio-oil, assess the 

viability of co-processing upgraded bio-liquids, optimize recovery and fractionation 

strategies for conversion to chemicals, and to develop life cycle analysis and scenario 

analysis. 

3.5.2 Performance and cost analysis 

Bio-oil yield is affected by a number of factors, including feedstock composition, reaction 

temperature and heat transfer rate, and amount of inert gas in the reaction environment. 

Furthermore, the mineral matter in biomass acts as a catalyst for cracking and 

polymerization during pyrolysis, which affects the composition of the bio-oil product (Ringer, 

Putsche and Scahill 2006). However, despite the importance of many factors in bio-oil 

production, the heating value of the product is relatively constant (on a dry basis) at about 

7,500-8,000 Btu/lb (Ringer, Putsche and Scahill 2006). This is only a slight reduction from 

the heating values of the biomass feedstocks used for pyrolysis, which are generally around 

8,500 Btu/lb. 

The water content in the biomass feedstock is also an important factor in bio-oil production. 

In fact, even pyrolysis of bone-dry biomass produces bio-oil with 12-15 wt% water (Ringer, 

Putsche and Scahill 2006). Any moisture in the input biomass will contribute to this 

percentage. As water is an unfavorable component on bio-oil, which also acts as a heat 

sink, it is advantageous to remove as much water as possible from the incoming biomass 

before pyrolysis. 

Upgrading bio-oil is important for a number of reasons. Hydrotreating and hydrocracking 

pyrolysis oil converts it to a hydrocarbon fuel that can be blended and transported with 

petroleum fuels. This provides access to a wide infrastructure already in place. Upgrading 

can also significantly increase the value of the bio-oil. 

The ratio of pyrolytic lignin and water soluble pyrolysis oils is such that in the near term, a 

substantial electricity/steam plant should accompany development of any fuel project based 

on this technology to ensure maximum use of the incoming resource. As complete and 

efficient use of incoming feedstock is critical to any project, the energy/liquid fuel product 

ratio will be an important consideration in siting. A potential alternative for the long-term is 

to reform the water-soluble portion of the bio-oil to generate hydrogen for use in the 

upgrading process. Although the reforming technology is currently too expensive to support 

a stand-alone pyrolysis oil upgrading facility, is it a possible future development. 

The evolution of pyrolysis oil production and upgrading is assumed to be as follows: 

• Short term: no pyrolysis oil upgrading technologies available (still in research phase) 

• Mid term: hydrotreating / hydrocracking of pyrolytic lignin and oil fraction in separate 

(skid-mounted) process co-located at a refinery; resulting products blended with 

petroleum products for storage and distribution. 

• Long term: no analysis of the technology for this period. However, hydrotreating / 

hydrocracking the pyrolytic lignin and oil fraction via co-processing in a stand-alone 

refinery, and reforming the water-soluble portion of bio-oil for hydrogen production is a 

potential long-term scenario. 

Outline for model analysis

The key values and assumptions used to calculate the mid-term technology analysis and 

economic performance model for LCG Upgrading/Pyrolysis are described below. An example 

of the detailed analysis is shown in Appendix G. 
45 

• Feedstock type and quantity are variables for input. Types of materials that can be used 

for pyrolysis include woody and agricultural feedstocks. The applicable size range for 

the model is biomass input of 30,000 - 800,000 dry tons per year, based on reported 

facility sizes in UOP 2005; Ringer, Putsche and Scahill 2006; and Polagye, Hodgson and 

Malte 2007. 

• The facility is assumed to be operational at full load 330 days per year, which is 

equivalent to a capacity factor of 90%. 

• Pyrolysis yield depends on feedstock type, and the values used are based on published 

data from Ensyn and Dynamotive (Ensyn Group Inc. 2001; Dynamotive Energy Systems 

Corporation 2000). 

• The conversion efficiency of biomass to pyrolysis oil is estimated to be 66-83% (on an 

energy basis) depending on the feedstock, with bark giving the lowest yield and bagasse 

and mixed paper giving the highest. This is calculated using the HHV of the feedstocks 

and typical pyrolysis oil properties. 

• Pyrolytic lignin (including the oil fraction) is the only portion of the bio-oil that undergoes 

hydrotreatment / hydrocracking for upgrading to hydrocarbon fuels, and the 

hydrotreatment and hydrocracking units are sized based on this feed stream. 

• The pyrolytic lignin content (weight percentage) for all herbaceous feedstocks based on 

values for bagasse, and percentage for woody feedstocks is based on data for softwood 

(from Dynamotive Energy Systems Corporation 2000). 

• The only significant by-products of pyrolysis oil production are solid char and noncondensable gases. It is assumed both of these products are recycled into the process 

to use as a heat source and fluidizing gas for the reaction. There are several products 

from upgrading, including gasoline and diesel, light hydrocarbons and the un-treated 

water-soluble bio oil. Gasoline is the primary product, accounting for 30% of the 

converted pyrolytic lignin (by weight). 

• The diesel and light hydrocarbon by-products are valued at $1.76/gal and $0.93/gal 

respectively, based on the average 2005 wholesale values from EIA AER 2005.54 

• The water-soluble bio-oil can be cofired with natural gas (or refinery off-gas) to provide 

heat and/or electricity. This material needs to be co-fired because of it’s relatively high 

water content (20-30%) and low heating value (5,000 Btu/lb on a moisture-free basis). 

If the water-soluble bio-oil was not combusted it would become a disposal liability. To 

simplify the model, it is assumed that the value of the heat/electricity produced from cofiring the water-soluble bio-oil offsets the cost of natural gas consumed for combustion. 

As such, there is no net value or cost associated with the water-soluble component of 

the bio-oil. 

• The yield of the concentrated CO2 generated from hydrotreatment is derived from UOP 

2005. No value is assigned to this stream in the analysis. 

• Water consumption is estimated based on data from Ringer et al. 2006. According to 

Ringer et al. (2006), a 200,750 dry ton per year facility uses about 160 thousand gal/hr 

water, mostly for cooling. It is assumed that only 2% of this water is lost in blowdown, 

so that the annual consumption is about 28,000 thousand gallons per year. This value is 

scaled based on feedstock input. No additional water consumption is added for 

hydrotreatment. 

• Capital costs for the pyrolysis process and hydrotreatment are calculated separately, as 

they have different size and economies of scale. 

• Total capital investment values for pyrolysis oil production for a range of sizes were 

available from various sources.55 These values were used to determine a relationship 

 

54 For comparison, the projected values of diesel and Liquefied Petroleum Gas in 2015 are $2.04/gal and $1.34/gal 

($633/ton), respectively (EIA AEO 2007). 

55 Sources: Ringer, Putsche and Scahill 2006; Polague et al. 2007; UOP 2005; and Cole Hill Associates 2004. 
46 

between facility size and capital cost, shown in Figure 13. A scaling factor of 0.8 is used 

for capital cost calculations. 

• The capital cost for hydrotreatment is based on a value of $30 million for a unit that 

processes 2,250 barrels per day, and a standard scaling factor of 0.6 (UOP 2005). 

• Variable O&M costs for the process include electricity and other utilities, hydrogen gas 

for hydrotreatment, and waste disposal. These annual costs are estimated individually 

based on plant size. Electricity cost for pyrolysis oil production has been updated to 5.7 

cents/kWh based on the 2005 average cost for electricity in the industrial sector from 

EIA (2006). The electricity cost for hydrotreatment has not been updated as there was 

not sufficient detail in the published studies, but the difference is expected be minimal 

and would not have significant effect on the production cost. 

• Annual fixed O&M costs include labor, maintenance, insurance, overhead, and other 

costs. Except for the labor component, these costs are estimated as a percentage of 

total capital cost. The labor portion only applies to the pyrolysis oil production process, 

and is scaled based on project size using a relation derived from the available data from 

Polagye et al. (2007) and Ringer, Putsche and Scahill (2006). This relationship is shown 

in Figure 14. 

• The levelized non-feedstock production costs for gasoline are calculated based on the 

annual operating expenses and capital cost payment, co-product credit, and quantity of 

fuel produced. 

Figure 13 – Capital cost and plant size relation for fast pyrolysis 

y = 0.2023x0.7715

R2 = 0.933

$-

$10

$20

$30

$40

$50

$60

$70

$80

$90

0 200 400 600 800 1,000 1,200 1,400 1,600 1,800 2,000

Plant Size (dry ton/day)

TCI (Million $)

Based on data from Cole Hill Associates 2004, Ringer et al. 2006, Polagye et al. 2007, UOP 2005. 
47 

Figure 14 – Labor cost scaling by facility size for pyrolysis oil production 

y = 58.335x-0.3144

R2 = 0.7853

0.0

2.0

4.0

6.0

8.0

10.0

12.0

14.0

16.0

0 500 1000 1500 2000

Plant size (dry tpd)

Labor cost ($/dry ton/yr)

Based on data from Polagye et al. 2007; and Ringer, Putsche and Scahill 2006. 

Model Results

Some of the key cost and performance results projected for LCG Upgrading/Pyrolysis are 

shown in Table 15. This table shows results for the range of applicable facility sizes based 

on selected input quantities, illustrating the high and low end costs. In general, the analysis 

shows that the non-feedstock production cost of gasoline with this method is quite 

expensive. This suggests that further development is needed to make pyrolysis oil with 

upgrading competitive with other biofuel technologies. For example, co-processing in a 

refinery could have significant impact on the production cost if the processing challenges 

can be overcome. 

Table 15 - Example Cost and Performance for LCG Upgrading/Pyrolysis 

Sample Model Results - LCG Upgrading/Pyrolysis w/ Wood

Feedstock Input (dry ton/yr) 30,000 800,000

Crude Pyrolysis Oil Yield (MGY) 4.6 122

Gasoline Yield (MGY) 0.5 13.5

Diesel Yield (MGY) 0.1 3.3

Light Hydrocarbon Yield (ton/yr) 839 22,380

CO2 Stream (ton/yr) 7,600 202,620

Water Consumption (1000 gal/yr) 4,180 111,420

Capital Cost - pyrolysis (Million $) $6.6 $82.6

Capital Cost - hydrotreatment (Million $) $4.1 $29.4

Annual O&M Costs (Million $/yr) $2.0 $35.1

By-Product Credit (Million $/yr) $0.6 $15.7

Non-feedstock Production Cost ($/gal) $5.32 $2.45

3.6 Fatty Acids to Hydrocarbon (Renewable Diesel): 

Hydrotreatment 

Green diesel and renewable diesel are some of the terms used to describe a hydrocarbon 

fuel produced from biomass oil feedstocks to differentiate them from biodiesel generated via 
48 

transesterification. Although renewable diesel is produced from vegetable oils and waste 

greases, unlike fatty acid methyl ester (FAME) biodiesel this product does not have oxygen 

in its molecular structure. It can also utilize oil feedstocks with higher amounts of free fatty 

acids than the FAME transesterification process. Furthermore, renewable diesel has superior 

properties to petroleum-based diesel and can be blended readily as it is a hydrocarbon fuel 

(UOP 2005). For example green diesel typically has less than 10 ppm Sulfur, has cetane 

numbers as high as 100, and cloud point temperatures as low as -30° C (which minimizes 

cold weather gel issues). And unlike with FAME production, there is no glycerin co-product 

produced, which could become a waste disposal issue for that industry. Fatty Acids to 

HydroCarbon (FAHC) renewable diesel also has a superior emission profile when compared 

to either conventional petroleum based diesel or FAME biodiesel. Particulates, NOx, HC, and 

CO are all reduced whereas biodiesel has sometimes shown higher levels of NOx (Climate 

Change 2006). Renewable diesel can be produced in petroleum refineries to take 

advantage of economies of scale and similar process requirements, which helps minimize 

the cost of production. 

3.6.1 Technology Description 

The Fatty Acids to HydroCarbon – Hydrotreatment (FAHC – Hydrotreatment) production 

process for renewable diesel in petroleum refineries is very similar to the process for 

upgrading pyrolysis oils described above, except that it does not typically involve 

hydrocracking. However, the Super Cetane Technology developed by the CANMET Energy 

Technology Center (CETC) at Natural Resources Canada does involve a hydrocracking step 

to tailor the molecular weight of some of the hydrocarbon compounds. They have reported 

cetane numbers exceeding 100 with their technology (Natural Resources Canada n.d.). As 

with the hydrotreatment / hydrocracking of pyrolysis oil, upgrading biomass oil feedstocks 

can be done in a stand alone skid-mounted unit or pretreated and co-processed with 

petroleum feedstocks. Schematic diagrams of these configurations are shown in Figure 15. 

In the FAHC - Hydrotreatment process, vegetable oil or animal fat is upgraded using 

hydrogen gas, producing diesel and propane or other light hydrocarbons. Some water and 

CO2 are also released in the process. A heterogeneous catalyst is used for hydrotreatment, 

which tend to be less expensive than homogeneous catalyst required for FAME biodiesel 

(UOP 2005). The product distribution is typically 83-86% diesel and 2-5% light 

hydrocarbons by weight (in terms of incoming biomass) (UOP 2005). By comparison, the 

FAME process results in approximately 96% diesel production. This higher biodiesel yield 

from FAME is due to the retention of oxygen in the product. In hydrotreatment the oxygen 

is rejected in the form of CO2 or H2O. 
49 

Figure 15 – Schematic diagram of renewable diesel production in petroleum refinery 

Feedstock

Vegetable oil

Animal fats

Pre-treatment

Impurity Removal

Renewable 

Diesel for 

Blending & Sale

Hydrotreater Hydrogen

CO2

Water

Stand-Alone Process

Light HC

Biomass Feedstock

Vegetable oil

Animal fats

Pre-treatment

Impurity Removal

Mixture of Traditional & 

Renewable Diesel for 

Transport & Sale

H Hydrotreater 2

CO2

Water

Co-Processing in Refinery

Crude

Crude 

Distillation

Light HC & other 

by-products

Feedstock

Vegetable oil

Animal fats

Pre-treatment

Impurity Removal

Renewable 

Diesel for 

Blending & Sale

Hydrotreater Hydrogen

CO2

Water

Stand-Alone Process

Light HC

Feedstock

Vegetable oil

Animal fats

Pre-treatment

Impurity Removal

Renewable 

Diesel for 

Blending & Sale

Hydrotreater Hydrogen

CO2

Water

Stand-Alone Process

Light HC

Biomass Feedstock

Vegetable oil

Animal fats

Pre-treatment

Impurity Removal

Mixture of Traditional & 

Renewable Diesel for 

Transport & Sale

H Hydrotreater 2

CO2

Water

Co-Processing in Refinery

Crude

Crude 

Distillation

Light HC & other 

by-products

Biomass Feedstock

Vegetable oil

Animal fats

Pre-treatment

Impurity Removal

Mixture of Traditional & 

Renewable Diesel for 

Transport & Sale

H Hydrotreater 2

CO2

Water

Co-Processing in Refinery

Crude

Crude 

Distillation

Light HC & other 

by-products

Oils and greases typically have an oxygen content of 11-12%, which is much lower than 

pyrolysis oils but still significantly higher than petroleum (UOP 2005). As with pyrolysis oil 

hydrotreatment / hydrocracking, the acidity of the oils generally means that they must be 

processed in stainless steel vessels. This is particularly true for waste greases which tend to 

have higher acidity than virgin feedstocks (UOP 2005). 

UOP analyzed co-processing in a distillate hydrotreater for ultra-low sulfur diesel, and found 

that for brown grease feedstocks “standard refinery distillate hydrotreating units do not 

appear to be suitable for green diesel production in a co-processing scheme.” (UOP 2005, p. 

18). In addition to the potential affect on metallurgy requirement, co-processing can 

detrimentally affect catalyst lifetime. This is partly due to the fact that hydroprocessing 

conditions for standard hydrotreating for ultra-low sulfur diesel in refinery favors 

hydrodeoxygenation (HDO), which produces water from biomass feedstocks and can have a 

negative affect on catalyst activity. UOP (2005) further noted that although co-processing 

with brown grease had a positive effect on catalyst in terms of sulfur, higher heat release 

causes increased deactivation rate which lowered the catalyst lifetime. 

Stand alone, skid-mounted processing of biomass oil and grease feedstocks seems to be an 

effective alternative, as it avoids some of the issues caused by co-processing but still has 

some benefits from refinery integration. In this configuration, biomass feedstocks are first 

pre-processed to remove contaminants, typically using some combination of the following: 

hydroclones, dewatering, acid washing, ion exchange, desalting, fixed guard bed catalyst. 

The feedstocks can then be hydrotreated with a skid mounted system. A benefit of skidmounted system is the ability to optimize the reaction for biomass feedstocks, so that the 

hydrotreatment conditions favor decarboxylation (DeCO2) instead of HDO. The DeCO2 

process removes oxygen from the feedstock as CO2 instead of water, which can be captured 

relatively easy. DeCO2 also reduces hydrogen consumption, as it only requires 0.8 wt% H2

whereas HDO requires 3%. 

Both skid-mounting and co-processing are potential treatment options in refineries. Despite 

the current processing issues, it is likely that with further technology developments and 
50 

pretreatment methods, co-processing of waste greases could be an economically favorable 

process in the long-term. Furthermore, several of the companies developing renewable 

diesel refining use co-processing techniques with vegetable oils and animal fats, which 

suggests this process is already favorable for virgin feedstocks. 

Status of Commercialization 

ConocoPhillips has completed a commercial demonstration of FAHC renewable diesel 

production at Whitegate refinery in Cork, Ireland, which co-processes vegetable oil with 

crude oil. The facility was able to produce 42,000 gallons per day of renewable diesel 

product (Green Car Congress 2006). ConocoPhillips has also partnered with Tyson to 

develop a facility to process animal fats in the US. This facility is planned for start up in late 

2007, and will be able to produce up to 500,000 gallons per day of renewable diesel 

(ConcoPhillips 2007). 

Neste also has developed a process to generate renewable diesel, using stand-alone 

hydrotreatment of vegetable oils and animal fats. Their NExBTL (NExt Biomass To Liquid) 

process will be demonstrated at the Porvoo oil refinery in Finland, with a 60 MGY renewable 

diesel facility (Neste Oil n.d.). In late 2006 Neste Oil announced plans to build a second 60 

MGY plant adjacent to the first plant to meet growing domestic demand. In addition Neste 

Oil has another FAHC renewable diesel production facility under development with OMV in 

Austria. Although the NExBTL process is stand-alone, it will take advantage of existing 

refinery infrastructure for energy, blending, logistics, and laboratories (Koskinen, Nurminen 

and Sourander 2005). For example, a refinery-based NExBTL plant has readily available 

access to hydrogen and utilities. Additionally, the renewable diesel can be blended, stored, 

and transported with petroleum based diesel which improves process economics and 

logistics.56 

The Petrobras H-BIO process uses co-processing of vegetable oils to generate FAHC 

renewable diesel. Petrobras has tested a range of oils and process conditions, and the 

process has a conversion rate of 95% by volume or higher (Petrobras n.d.). Petrobras is 

planning to have H-BIO process operations in at least 3 refineries by the end of 2007, with a 

total capacity to process more than 250,000 tons of vegetable oil annually. Further 

implementation in 2 more refineries is planned for 2008 (Petrobras n.d.). 

Others companies that are currently involved in FAHC renewable diesel production include 

Nippon Oil in Japan which expects to have a commercial process within 3 years, and BP 

which has a 80,000 gallon per day demonstration facility planned for start-up in Australia 

this year (ConocoPhillips 2007). 

3.6.2 Performance and cost analysis 

Outline for model analysis

The key values and assumptions used to calculate the technology analysis and economic 

performance model for stand-alone and co-processing FAHC - Hydrotreatment processes are 

described below. An example of the detailed analysis is shown in Appendix G. 

• Feedstock input quantity is a variable. 

• Applicable feedstocks are virgin oil, animal fats, and yellow grease. However, feedstock 

choice does not affect the product yield in this model. The typical heating values of the 

 

56 NExBTL diesel is compatible with existing fuel logistics and vehicles, and meets diesel fuel standards in all 

properties except density, which is about 780 kg/m3

 (Neste Oil n.d). As such, the density value is the only blending 

constraint and limits blends of NExBTL product to 65% by volume (Koskinen, Nurminen and Sourander 2005). 
51 

feedstocks are very similar, generally about 16,500 to 17,000 Btu/lb HHV (US EPA 

2001). Although processing of yellow grease feedstocks may lead to higher capital costs 

as a result of additional pre-processing (such as desalting) and different metallurgy 

requirements due to higher acidity, the potential added cost has not been included as it 

is expected to be minimal (on the order of a few percent according to discussions with 

industry contacts). 

• The applicable size range for the model is 15 to 200 MGY of renewable diesel, based on 

current and planned facility sizes for ConocoPhillips, Neste, and Petrobras. The smallest 

facility reported by these companies can produce around 1,000 barrels per day of 

renewable diesel, and the largest (planned) facility will be able to generate about 12,000 

barrels per day. 

• Stand-alone FAHC renewable diesel yield is 86 wt% based on data from UOP (2005). Coprocessing yield is 81 wt% based on data for Petrobras H-BIO system (Petrobras n.d.). 

The renewable diesel yields are converted to volumetric quantities using a typical 

density of 6.5 lb/gal. 

• The conversion efficiency of oil/fat to fuel (on an energy basis) is estimated to be 98% 

for skid-mounted and 96% for co-processing. This is calculated using an average LHV of 

oil feedstocks of 16,000 Btu/lb, and a typical renewable diesel (lower) heating value of 

123,200 Btu/gal. 

• Hydrogen consumption is calculated as a percentage of the feedstock input (by weight). 

The stand-alone system favors DeCO2, which requires less hydrogen than the HDO 

reaction favored in co-processing. According to UOP (2005), typical hydrogen 

consumption ranges from 1.5 - 3.8 wt% of feedstock input. The low end value is used 

for the stand-alone hydrotreatment in the model, while the high end value is used for 

co-processing. 

• Light hydrocarbon production is estimated to be 3.5 wt% for stand alone process and 

4.4 wt% for co-processing, based on input feedstock (UOP 2005, Petrobras n.d.) 

• Water and CO2 are also generated during hydrotreatment. The processing conditions for 

the stand alone process favor CO2 production, while conditions for co-processing 

typically produce water. The total amount of CO2 and water produced is calculated as 

the difference between the inputs and other outputs, which give results similar to UOP 

(2005).57 

• Water consumption data is not included for hydrotreatment processes, as it is assumed 

to be minimal. 

• Near term capital costs are based on reported costs of facilities under development from 

Neste (stand alone) and Petrobras (co-processing), and a scaling factor of 0.6.58

• Mid term capital costs are decreased based on next generation facility development and 

a learning rate of 20% (McDonald and Schrattenholzer 2002). This rate is similar to that 

found for ethanol production facilities and retail petrol processing. 

• Variable O&M costs include utilities and hydrogen. The utility cost is based on data for 

pyrolysis oil hydrotreatment from UOP (2005). Annual hydrogen cost is based on 

hydrogen consumption and cost data from UOP 2005. 

• Fixed O&M costs include maintenance, insurance, and overhead. These costs are 

estimated to be 5.5% of near term capital cost, based on pyrolysis oil hydrotreatment 

O&M. No labor cost is added, as renewable diesel production is part of larger refinery 

operation and will not require additional operators. 

• The propane/light hydrocarbon co-product value is calculated using the average 2005 

wholesale price of $0.93/gal (EIA AER 2005).59 The estimated added cost for 

compressing propane is negligible and has not been included.60

 

57 UOP (2005) estimates that the total water and CO2 output is equivalent to 12-16 wt% of feedstock input. 58 This scaling factor is equivalent to the value used for pyrolysis hydrotreatment, following UOP (2005). 59 For comparison, the projected value of Liquefied Petroleum Gas is projected to be $1.34/gal ($633/ton) in 2015 

(EIA AEO 2007). 
52 

• The levelized non-feedstock production costs for FAHC - Hydrotreatment are calculated 

based on the annual operating expenses and capital cost payment, co-product credit, 

and quantity of fuel produced. 

Model Results

Some of the key cost and performance results projected for the FAHC - Hydrotreatment 

processes are shown in Table 16 and Table 17. These tables show results for the range of 

applicable facility sizes based on selected input quantities, illustrating the high and low end 

costs. In general, the analysis shows that the non-feedstock production cost of FAHC 

renewable diesel via co-processing in a refinery is cheaper than a stand-alone process, as 

expected. However, it seems that either method could be used to produce biofuel 

economically. The projected non-feedstock costs on a $/gallon basis are more than 

competitive with FAME biodiesel, and the resulting fuel is higher quality and can be readily 

integrated into existing infrastructure. 

Table 16 - Example Cost and Performance for FAHC - Hydrotreatment Stand Alone Process 

Sample Model Results - FAHC Hydrotreatment (skid-mounted) - mid term

Feedstock Input (ton/yr) 20,000 785,000

Renewable Diesel Yield (MGY) 5.1 200

Light Hydrocarbon Yield (ton/yr) 700 27,475

Capital Cost (Million $) $25.8 $233.3

Annual O&M Costs (Million $/yr) $2.2 $31.1

By-Product Credit (Million $/yr) $0.3 $12.1

Non-feedstock Production Cost ($/gal) $0.98 $0.24

Table 17 - Example Cost and Performance for FAHC - Hydrotreatment Co-Processing 

Sample Model Results - FAHC Hydrotreatment (co-processing) - mid term

Feedstock Input (ton/yr) 20,000 800,000

Renewable Diesel Yield (MGY) 5.0 200

Light Hydrocarbon Yield (ton/yr) 880 35,200

Capital Cost (Million $) $4.1 $37.3

Annual O&M Costs (Million $/yr) $1.3 $41.5

By-Product Credit (Million $/yr) $0.4 $15.5

Non-feedstock Production Cost ($/gal) $0.27 $0.15

For perspective, the projected 2015 price for crude soybean oil is about $681.40/ton (FAPRI 

2007). Including an estimated delivery cost of $10/ton,61 the feedstock cost for renewable 

diesel production is $2.71/gal for a skid-mounted process and $2.77/gal for co-processing. 

This gives a total production cost of $2.95 to $3.69 per gallon for stand-alone and $2.92 to 

$3.04 per gallon for co-processing.62 These costs are very similar to the projected 

production costs for FAME biodiesel from virgin oil in 2015, which range from $2.98 to $3.36 

per gallon for facilities from 1 to 80 MGY (see Section 2.2.2 for details). For comparison, 

the national average wholesale price for diesel over the past year is $2.03 per gallon (EIA 

July 2007). Also note that the current retail biodiesel price is about $3.20/gal (USDA AMS 

2007). 

 60 Antares estimates that compressing 17,000 tons per year of propane would cost estimate about $100K/yr, using 

an electricity price of 9¢/kWh. 61 Based on a truck transportation cost of $0.20/ton-mile and a 50 mile delivery radius. 62 The production cost does not include distribution costs or profit, which are both factored into retail fuel prices. 
53 

4 Emissions Data for Biofuel Conversion Technologies 

Water use, greenhouse gas and criteria pollutant emissions data were estimated for each 

modeled conversion technology, in order to be used as inputs for the environmental benefits 

analysis in Task 5. These data were calculated based on the conversion technology models 

or available data in the literature. Additional information about data sources and 

calculations are included below. 

4.1 Yields and Water Use 

Table 18 summarizes the water use and fuel yields for various conversion technologies. The 

biomass conversion technology data are based on the technology models developed for this 

effort. The crude oil refining data is included for comparison, based on results from 

Sheehan et al. 1998. 

Table 18 – Water Use and Yield for Various Conversion Technologies 

Technology Feedstock Yield (gal/ton)* Water Use 

(gal / gal product) 

Biomass Conversion Technologies 

Grain to Ethanol (Dry Mill) Grains 100.0 4.7 

Grain to Ethanol (Wet Mill) Grains 89.3 24.4 

FAME Biodiesel 

Virgin Oil 258.2 0.03 

Waste Oil 249.1 0.03 

Animal Fat 266.3 0.03 

LCE Fermentation / Enzymatic 

Hydrolysis (dilute acid pretreatment) 

Wood Chips (hardwood) 85.9 6.2 

Wood Chips (softwood) 90.2 5.9 

Corn Stover / Ag Residues 80.6 6.6 

Wheat Straw / Ag Residues 76.8 7.0 

Switchgrass / HEC 77.4 6.9 

LCMD - Fischer Tropsch 

Wood Chips (hardwood) 40.6 1.2 

Wood Chips (softwood) 42.0 1.1 

Corn Stover / Ag Residues 36.8 1.3 

Wheat Straw / Ag Residues 38.7 1.2 

Switchgrass / HEC 37.7 1.3 

LCG - Upgrading/Pyrolysis 

Clean Wood Chips 16.9 8.2 

Softwood 15.7 8.9 

Bark 14.2 9.8 

FAHC - Hydrotreatment (stand-alone) Vegetable Oil or Animal Fat 255.4 0.0 

 (co-processing) Vegetable Oil or Animal Fat 250.5 0.0 

Crude Oil Refining 

Gasoline Refining* Petroleum -- 0.003 

Diesel Refining* Petroleum -- 0.001 

* Yield reported in gallons per dry ton except for Grains (in Grain to Ethanol), which are in as rec’d tons (15% MC) 

** Data from Sheehan et al. 1998 
54 

4.2 Greenhouse Gas and Criteria Pollutant Emissions 

Table 19 shows the reported emissions resulting from biofuel conversion, based on data 

from various published Life Cycle Analysis (LCA) studies. These studies use detailed 

analyses of all the significant energy use and emissions impacts from the entire biofuel 

production process, including emissions released in the conversion process, emissions 

associated with energy use (electricity and steam), and emissions allocated to the 

production of consumables used in the process. Publicly available LCA data for biofuel 

conversion processes is limited – the only processes with published results are the current 

conversion technologies (grain to ethanol and FAME biodiesel from virgin oil), and LCE via 

fermentation and enzymatic hydrolysis for some feedstocks. Although there are some LCA 

studies available for other advanced biofuel conversion processes, they typically only report 

the overall results of a well-to-wheels analysis. These are insufficient for our analysis, since 

several aspects of the analysis are location-dependant, including feedstock production. As 

such, an analysis of the CO2 emissions has been developed based on the conversion 

technology models and data from other various sources. This will be discussed below in 

detail. 

Table 19 - Summary of Conversion Technology Emissions from Published Life Cycle Analyses 

Technology Feedstock Total GHG 

(g CO2-eq/gal)* 

GHG Emissions (g/gal) Criteria Pollutants (g/gal) Allocation 

basis Source 

CO2 CH4 N2O CO PM SO2 NOx

Biomass Conversion Technologies 

Grain to Ethanol 

(Dry Mill) Grains 2,032.1 n/a n/a n/a n/a n/a n/a n/a mass Kim and 

Dale 2005 

Grain to Ethanol 

(Wet Mill) Grains 2,376.3 n/a n/a n/a n/a n/a n/a n/a mass Kim and 

Dale 2005 

FAME Biodiesel Soybean Oil 606.0 566.5 1.67 0.00 0.21 0.60 8.17 1.36 mass Sheehan et 

al. 1998 

LCE Fermentation / 

Enzymatic hydrolysis 

(dilute acid 

pretreatment) 

Wood (50%), 

Grass (50%) n/a n/a 0.21 n/a 5.67 2.35 0.87 3.52 

credit for 

displaced 

electricity 

Delucchi 

2003 

Corn Stover 8,921.5 9,051.1 n/a n/a n/a n/a n/a n/a 

credit for 

displaced 

electricity 

Sheehan et 

al. 2004 

Crude Oil Refining 

Gasoline Refining Petroleum 1,671.2 1,530.6 5.65 0.04 1.55 0.44 1.56 3.11 n/a Delucchi 

2003 

Diesel Refining Petroleum 909.1 837.5 2.21 0.07 1.30 0.31 1.83 1.56 n/a Delucchi 

2003 

* For cases in which the Total GHG Emissions was not provided, this value was calculated using 100-year Global Warming Potentials 

from IPCC 2001 to convert the GHG emissions into CO2-eq factors (CO2 (1); CH4 (23); N20 (296)).

Note that the data shown in Table 19 only correspond to the portion of the emissions 

attributed to the conversion of the feedstock to fuel; it does not include feedstock 

production, end use of the fuel, or any other component of the life cycle analysis. 

Several conversion technologies produce byproducts in addition to biofuels (such as glycerin 

in the FAME Biodiesel process), so the environmental impacts must be distributed among 

the products. An allocation method is used to determine the portion of the emissions that 

are attributable to biofuels for each process. There are several methods for allocation, 
55 

including by product weight, energy content, value, or replacement products.63 Each 

method will give different results for the environmental impacts of biofuels. Although some 

authors argue that the replacement method is the most robust (Kim and Dale 2005), the 

mass and energy allocation methods are frequently used due to simplicity and ease of 

application. All of the LCA studies reported here use the mass based allocation method. 

Table 20 shows the calculated CO2 emissions from biofuel conversion technologies based on 

estimations from the characterization models and other sources. Definitions, data sources 

and assumptions are given below. Note that these emissions do not include those related to 

the production and use of chemical consumables in the processes. The LCA study from 

Sheehan et al. 1998 showed that the effect of the consumables can make up a large portion 

of the overall GHG emissions. For example, the GHG emissions associated with production 

of chemicals used in the FAME biodiesel process makes up more than 40% of the total CO2

emissions. As such, the total CO2 emissions for FAME Biodiesel with virgin oil shown in 

Table 20 are much smaller than those in Table 19. However, the energy usage portion of 

the emissions from Sheehan et al. 1998 (364 g CO2-eq/gal) are very similar to the emissions 

estimated from this analysis (344 g CO2/gal). 

Definitions:

• The total Gross CO2 values includes emissions related to grid electricity use, 

steam/thermal energy use, conversion process, on-site hydrogen production, and stack 

and other CO2 emissions for the entire conversion process. 

• The biofuel Gross CO2 is the biomass portion of the total gross CO2, using the mass 

basis allocation shown in the table. 

• The avoided CO2 from net electricity production is the emissions that are avoided by 

displacement of grid electricity in processes that produce power as a byproduct. 

• The Biofuel Net CO2 is the resulting emissions attributed to biomass, less the avoided 

CO2 from electricity production. 

• The Total CO2 from Biomass is reported to differentiate from the fossil fuel CO2. The 

biomass portion of the CO2 emissions may be excluded from the total, as biomass can 

be considered net neutral for carbon due to its uptake in growth cycles. The biomass 

CO2 includes any emissions from the conversion process itself, and CO2 emitted from 

the stack during biomass fueled cogeneration. 

 

63 For the replacement products method, emissions associated with materials that would be used to replace the 

product are tallied and subtracted from the gross process emissions. For example, for distiller’s dried grains, the 

emissions due to production of an alternate animal feed such as soybean meal would be used. 
56 

Table 20 – CO2 emissions (g/gallon) from biofuel conversion based on technology model data 

Technology Feedstock Allocation (mass basis) Gross CO2 (total) Gross CO2 (biofuel) Avoided CO2 (electricity) Net CO2 (biofuel) Total C

from Biomas

Relationships Equations A B C = A x B D E = C – D F Grain to Ethanol (Dry Mill) Grains 50% 6,096 3,024 0 3,024 2,835 Grain to Ethanol (Wet Mill) Grains 51% 8,426 4,281 0 4,281 2,835 FAME Biodiesel 

Soybean Oil 81% 425 344 0 344 0 

Waste Oil 81% 1,214 984 0 984 0 

Animal Fat 81% 425 344 0 344 0 

LCE Fermentation / Enzymatic Hydrolysis (dilute acid pretreatment) 

Wood Chips (hardwood) 100% 11,217 11,217 1,228 9,989 11,217 

Wood Chips (softwood) 100% 11,199 11,199 1,228 9,971 11,199 

Corn Stover / Ag 

Residues 100% 9,663 9,663 1,228 8,434 9,663 

Wheat Straw / Ag 

Residues 100% 9,578 9,578 1,228 8,349 9,578 

Switchgrass / HEC 100% 9,756 9,756 1,228 8,527 9,756 

LCMD - Fischer Tropsch 

Wood Chips (hardwood) 75% 25,728 19,399 11,612 7,787 25,728 

Wood Chips (softwood) 75% 27,761 20,932 11,612 9,320 27,761 

Corn Stover / Ag 

Residues 75% 25,559 19,272 11,612 7,660 25,559 

Wheat Straw / Ag 

Residues 75% 23,198 17,491 11,612 5,879 23,198 

Switchgrass / HEC 75% 28,201 21,264 11,612 9,652 28,201 

LCG - Upgrading/Pyrolysis (1) 

Clean Wood Chips 55% 91,941 50,291 0 50,291 79,584 

Softwood 55% 108,762 59,493 0 59,493 95,874 

Bark 55% 128,890 70,503 0 70,503 115,25

FAHC – Hydrotreatment (2)  (stand alone) Soybean Oil 96% 2,756 2,646 0 2,646 531  (co-processing) Soybean Oil 95% 3,684 3,496 0 3,496 653 

1). No thermal energy credits or consumption are included here as sufficient details on the process are not available. Although some 

used for energy production (such as char from pyrolysis, and water-soluble bio-oil for upgrading), fossil fuels may be needed to help cmaterials (such as the water-soluble bio-oil which has a 30% MC). 2). One of the output streams from this process is a mixture of water and CO2. Although the ratios of each component depend on the 

we assume equal amounts of each. 

Note that emissions for LCG – Upgrading/Pyrolysis are much higher than any other conversion technology, 

low yields from the upgrading process.
57 

Data Sources and Assumptions: 

• Grid electricity use was determined using conversion technology models where possible. 

Emissions associated with grid electricity use based on the Western Region average 

from EIA 2002. 

• Electricity production from LCE Fermentation / Enzymatic Hydrolysis and LCMD – 

Fischer Tropsch based on conversion technology characterization models. Avoided 

emissions from net electricity exported to grid are based on the Western Region 

average from EIA 2002. Total process energy for LCE Fermentation / Enzymatic 

Hydrolysis based on data from Hamelinck et al. 2005. 

• Emissions associated with fossil fuel derived thermal energy are based on emissions 

factors from Sheehan et al. 1998 for steam production in an industrial boiler using coal 

and natural gas. 

• Data for energy use for dry mill Grain to Ethanol process from Shapouri and Gallagher 

2005; data for wet mill process from Shapouri et al. July 2002. Kim and Dale 2005 

suggest the thermal energy for wet milling is about 20% natural gas and 80% coal. It 

is assumed that all of the thermal energy production from dry milling comes from 

natural gas. 

• Energy requirements for FAME Biodiesel for base catalyzed process (virgin oil and 

animal fats) are based on data from Sheehan et al. 1998 and Haas et al. 2006. 

According to Zhang et al. 2003, the energy requirements for the acid catalyzed process 

(waste grease) are 3 times higher and the electricity requirements are twice as high as 

base catalyzed process. For both FAME Biodiesel processes it is estimated that all 

thermal energy is produced from natural gas. 

• Thermal energy use for FAHC – Hydrotreatment based on data for diesel 

hydrotreatment in a refinery from Wang et al. 2004. 

• Hydrogen use for LCG – Upgrading/Pyrolysis and FAHC – Hydrotreatment are from 

technology characterization models. Emissions from on-site hydrogen production based 

on natural gas refining from Contadini et al. 2000. 

• Stack and other CO2 emissions were determined by via difference in carbon between 

the biomass input and product outputs. 

• Conversion process CO2 emissions are from the conversion technology models. 
58 

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61 

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62 

Appendix A 

Conversion Technology Status Matrix 
63 

Reference Name Feedstock

Conversion 

Technology Fuel Type Benefits Issues/Challenges 

Current Representative Technologies

Grain Ethanol - Dry Mill Grains / Starches Enzymatic Fermentation Ethanol Commercial technology - many facilities already operational and in construction. 

Grain Ethanol - Wet Mill Grains / Starches Separation and Fermentation Ethanol Commercial technology - many facilities already operational and in construction. Fatty Acid Methyl Ester (FAME)

Seed Oil / Waste Oils / Animal Fats

Esterfication Methyl Esters

Ease of conversion, biodiesel can be used in diesel engines without adjustments. Significant heating oil market.

Relatively small scale. Limited opportunity for process improvements. Cold weather technical issues.

Sugar to Ethanol Fermentation Sugars Fermentation Ethanol Commercial technology. More efficient than conversion of starches. Limited feedstock availability in North America Additional Technologies Projected to be in Use by 2015 to 2025

Enzymatic Hydrolysis and Fermentation Ethanol Relatively low maintenance costs. Potentially very high glucose yield. Cellulase costs must be reduced. Enzymes are sensitive to poisoning. 

Acid Hydrolysis and Fermentation Ethanol

Technically mature - dilute acid process is oldest cellulosic ethanol technology.

Expensive vessels and high maintenance costs (corrosion). Large amount of gypsum for disposRequires improved acid recovery (especially strong acid process).

LignoCellulosics to Ethanol - Fermentation/ThermoChemical (LCE Fermentation/TC)

Lignocellulosic Biomass

Gasification and Fermentation Ethanol

Higher yield of ethanol per ton of feedstock than direct fermentation of biomass. See Note #2.

See Note #3. 

LignoCellulosics to Middle Distillates -Fischer Tropsch (LCMD - FT)

Lignocellulosic Biomass

Gasification and Fischer Tropsh Synthesis

Middle 

Distillates, 

Gasoline

FT diesel can be substituted directly for conventional diesel with lower emissions. See Note #2.

See Note #3. Catalysts sensitive to poisoning ansintering. Requires improved yields.

LignoCellulosic to Mixed Alcohol - ThermoChemical (LCMA - TC)

Lignocellulosic Biomass

Gasification and Thermochemical Conversion

Mixed Alcohols Mixed alcohols are easily blended with gasoline. See Note #2.

See Note #3. Catalysts sensitive to deactivation from sintering. Process requires improved yieldsPotential groundwater contamination from mixealcohols usage.

LignoCellulosics to Gasoline - Upgrading/Pyrolysis (LCG - Upgrading/Pyrolysis)

Lignocellulosic Biomass

Pyrolysis Oil Production and Upgrading via hydrotreatment / hydrocracking

Bio-oil, Diesel, 

Gasoline

Using refinery technologies already in place, ease of adoption into current infrastructure

In early development stages. Refinery integratioissues.

Fatty Acids to HydroCarbon - Hydrotreatment (FAHC - Hydrotreatment)

Seed Oil / Waste Oils / Animal Fats

Upgrading via hydrotreatment Renewable Diesel

Using refinery technologies already in place, ease of adoption into current infrastructure

In early development stages. Refinery integratioissues.

1) Examples of some of the key players for each technology type. Universities and National Laboratories are shown in parenthesis.2) High range of feedstock flexibility. Intermediate product from gasification can be used for broad slate of end-products (i.e. fuels, power, heat, etc.)

3) Gasification requires dried biomass. High level of syngas clean-up required.

Feedstock availability and production is limited, and there is competition with food products. Net energy balance lower than projections for cellulosic ethanol. Limited opportunity for improvement.

Lignocellulosic Biomass

LignoCellulosics to Ethanol - Fermentation/Hydrolysis (LCE Fermentation/Hydrolysis)
64 

Appendix B 

Conversion Technology Pretreatment Matrix 

Pretreatment requirements for selected biofuel conversion technologies 

Conversion Technology Pretreatment Description

Required 

Moisture 

Content

Size Source

Grain to Ethanol - Dry Mill Milling to a fine flour -- fine RFA 2005

Grain to Ethanol - Wet Mill Steeping -- -- RFA 2005

Fatty Acid to Methyl Ester (FAME) Filtering, dewatering ~ 0% -- Zhang et al. 2003a

Cleaning (2), Sizing & Milling, 

Dilute Acid Hydrolysis -- 1-3 mm Hamelinck et al. 2005

Cleaning (2), Sizing, Steam 

Explosion -- 19 mm Hamelinck et al. 2005

Cleaning (2), Sizing, Liquid Hot 

Water -- 19 mm Hamelinck et al. 2005

Lignocellulosics to Middle 

Distillates - Fischer Tropsch (3) Sizing, Drying 10-15 wt% 6-13 mm Tijmensen et al. 2002

Lignocellulosics to Gasoline - 

Upgrading/Pyrolysis Sizing, Drying 5-10 wt% 2 mm Ringer, Putsche and Scahill 

2006

Fatty Acids to Hydrocarbon - 

Hydrotreatment

Combination of filtering, 

dewatering, acid washing, ionexchange, desalting~ 0% -- UOP 2005

3) The required material size for gasification depends on the gasifier type and the feedstock. Woody biomass is typically sized to 1/4" minus, while 

agricultural residues are generally 1/2" minus, based on Antares experience.

Lignocellulosics to Ethanol - 

Fermentation/Hydrolysis (1)

1) This process has a drier to remove moisture from solid residuals before used for heat - usually available at MC of 60%, dried to 15%. 

2) Cleaning is not required for all feedstocks. For example, de-barked forest residues do not generally need to be cleaned, while agricultural residues 

such as corn stover needs to be washed.
65 

Appendix C 

Economic Analysis Factors 

 

CDEAC Quantitative Work Group Economic Analysis Guidance

Factors for Levelized Production Cost Calculations

Equity Share 45% Yellow cells mark inputs recommended by Quantitative Work Group

Debt Share 55%

Nominal Return on Equity 16.7%

Nominal Return on Debt 6.5%

Federal Corporate Tax Rate 35%

State Corporate Tax Rate 5%

Effective Corporate Tax Rate 38.2%

Economic Book Life (years) 25

Weighted Cost of Capital 9.7%

Present Value Depreciation Fraction 0.778 MACRS DB Depreciation

Capital Recovery Factor 10.8%

Fixed Charge Rate (FCR) 12.26% does not include production incentives, or additional property tax or insurance

Nominal Non-Feedstock Levelized 

Production Cost ($/gal) = (FCR * Total Capital Investment($) + Annual Operating Cost ($/yr)) / Biofuel Yield (gal/yr)

Year

MACRS - 5 Yr 

Depreciation Fract State

Avg. State 

Corporate Tax

1 0.2000 0.182 AK 5.2

2 0.3200 0.266 AZ 6.968

3 0.1920 0.145 CA 8.84

4 0.1152 0.079 CO 4.63

5 0.1152 0.072 HI 5.5

6 0.0576 0.033 ID 7.6

KS 4

MT 6.75

NE 6.695

NM 6.2

ND 4.8

OR 6.6

NV 0

WA 0

WY 0

AVERAGE 4.92
66 

Comparison of Annual Change for CEPCI and CPI 

0%

2%

4%

6%

8%

10%

12%

1999 2000 2001 2002 2003 2004 2005 2006

% Change from Previous Year

CEPCI

CPI

The graph above compares the annual change (from the previous year) for the Chemical 

Engineering Plant Cost Index (CEPCI) and the Consumer Price Index (CPI). In general, 

there is not a clear relationship between the CEPCI and the CPI. Furthermore, the CEPCI 

has seen large increases in recent years, particularly from 2003 to 2004. As a result of 

these increases, there is some concern within the biofuels industry about capital cost 

projections which will not adequately account for cost increases of materials used for 

chemical facilities (like steel). While this may indeed add significant costs to the capital, the 

same cost increases will apply to all fuel production industries. As such, the relative capital 

costs between the biofuel industries and oil refineries will remain the same.
67 

Appendix D 

Additional Information - Grain to Ethanol Processes 

Source: Antares 2005a 
68 

Source: Antares 2005a 
69 

DDGS 10-Year Historical Wholesale Price History64

0

20

40

60

80

100

120

140

160

180

200

Jan-95

Jul-95

Jan-96

Jul-96

Jan-97

Jul-97

Jan-98

Jul-98

Jan-99

Jul-99

Jan-00

Jul-00

Jan-01

Jul-01

Jan-02

Jul-02

Jan-03

Jul-03

Jan-04

Jul-04

Jan-05

Jul-05

Jan-06

Jul-06

Jan-07

Jul-07

Timeline

Price ($/ton)

Central Illinois California Pts.

Chicago Law renceburg, In

Minnesota-Duluth Wisconsin-Eastern MN

St. Louis Portland

Source: Antares 2005b and USDA AMS 2007 

As shown in the graph above, DDGS prices have fluctuated significantly over the past 

decade, ranging from $60/ton to more than $170/ton. Current DDGS prices are around $90 

to $115 per ton, not including delivery costs. 

 

64 Note that the California and Portland prices are consistently higher than the other DDGS prices, as these 

numbers include the cost of rail delivery. 
70 

Appendix E 

Oilseed Crop Feedstock Conversion to Oil 

A typical method for conversion of oilseed feedstocks to oils is the n-hexane extraction 

process (Sheehan et al. 1998). Although alternate processes such as mechanical extraction 

are also available, hexane extraction has been selected for modeling in this analysis due to 

high oil yield and data availability. 

CONVERSION 

Table 21 shows the percentage oil in selected feedstocks. In general, the oil content is 20-

40% of the total feedstock. The rest of the oilseed consists of hulls, moisture, meal, and 

other solids. For example, a typical break-down of soybeans includes about 20% oil, 7% 

hulls, 14-18% moisture, and 57% meal (approximate weight percentages from Sheehan et 

al. 1998). A large percentage of this non-oil product, including meal and hulls, is sold as 

animal feed. This is critical by-product and revenue source for the crushing/extraction 

process. 

Table 21 – Oil content of various oilseed feedstocks 

Feedstock Oil Content 

(Wt%) 

Soybean 19% 

Canola 40% 

Sunflower 40% 

Rapeseed 40% 

Safflower 25% 

Based on data from Tyson et al. 2004 

Sheehan et al. (1998) estimate that oil extraction can recover 98.5% of the oil in 

soybeans, including losses. The end product is pure degummed soybean oil ready for 

transesterification. For comparison, Tyson et al. (2004) suggest that the hexane extraction 

method can extract 99.5% of the oil from soybeans. However, this is the maximum 

extraction potential and does not fully adjust for losses. 

ENERGY REQUIREMENTS 

The energy requirements for the extraction process includes: 63.19 kWh/ton of electricity; 

958.8 MMBtu/ton of natural gas; and 792.2 MMBtu/ton of steam (Sheehan et al. 1998).65 

Furthermore, extraction requires 4.04 lb hexane and 0.77 gallons of water per ton of 

feedstock processed (Sheehan et al. 1998). 

PROJECTED PRICES 

According to the Food and Agricultural Policy Research Institute (FAPRI) 2007 U.S. and 

World Agricultural Outlook, soybean oil is expected to be the largest source of feedstock for 

biodiesel in the mid-term. For the 2015 time period, FAPRI estimates that 75% of biodiesel 

will be produced from soy oil, 16% from canola oil, and the remainder produced from other 

fats and oils. The FAPRI 2007 price projections for virgin soybean oil and canola oil in the 

US are shown in Figure 16 and Figure 17, respectively. The projected soybean oil price is 

$681.40/ton in 2015. The projected price for canola oil in 2015 is $753.40/ton. 

 

65 All quantities given per ton of soybeans as received (i.e. with about 15% moisture). The natural gas is used for 

drying in the bean preparation step. 
71 

Figure 16 – Projected Soybean Oil Price 

0

200

400

600

800

1000

2006 2008 2010 2012 2014 2016 2018

Virgin Soybean Oil Price ($/ton)

Projected Price for 2015: $681.40/ton

Data from FAPRI 2007 

Figure 17 – Projected Canola Oil Price 

0

200

400

600

800

1000

2006 2008 2010 2012 2014 2016 2018

Virgin Canola Oil Price ($/ton)

Projected Price for 2015: $753.40/ton

Data from FAPRI 2007 
72 

Appendix F 

Biomass Recovered from MSW 

Biomass materials in the MSW stream include paper and cardboard, green waste, food 

waste, construction wood waste. Engineers at Taylor Recycling estimate that today's 

systems for culling biomass from the mixed stream will add about $25 to $30 per ton to the 

cost of biomass recovered from a mixed waste stream.66 This cost covers the labor for hand 

picking clean materials or alternatively for rejecting visibly tainted materials, as well as O&M 

and capital recovery. Equipment for biomass recovery can include trommel screens, 

vibratory screens, air clarifiers, finger screen separators and shredders. 

While much of the recovered biomass material can potentially be used for gasification-based 

processes like Fischer Tropsch (LCMD – FT), the same is not true for biochemical processes 

such as LCE Fermentation/ Hydrolysis. The LCE Fermentation/Hydrolysis process is 

particularly sensitive to feedstock composition quality and consistency as well as poisoning 

from contaminants, which limits the type of recovered materials that could be used. Based 

on discussions with industry experts, it has been determined that at least a portion of the 

recovered paper products and yard trimmings could potentially be used for the LCE 

Fermentation/Hydrolysis process, in addition to clean wood waste residues. 

The compositions of the MSW materials applicable for the LCE Fermentation/Hydrolysis 

process are shown in Table 22. The paper composition is an average for newsprint and 

other paper. The yard waste is assumed to be a mix of leaves (20% by weight), grass 

(20%) and woody residues (60%), based on data from McKeever and Skog (2003). The 

yard waste composition is calculated as a weighted average of these materials. 

Table 22 Composition of MSW Stream Components 

Hemicellulose Cellulose Lignin

Paper, Average 15.2% 48.1% 22.6%

 Paper 13% 45% 17%

 Newsprint paper 16% 43% 27%

 Newsprint paper (preconsumer waste) 16% 43% 26%

 Newsprint 16% 61% 21%

Yard Waste 31.8% 20.0% 20.6%

Leaves, Average 20% 24% 17%

 Fallen leaves, oak 26% 30% 24%

 Mixed fresh leaves, wood 14% 19% 10%

Grass - mowing waste 5% 15% 5%

Wood, mixed 45% 20% 27%

 Poplar - hardwood 45% 19% 26%

 Pine - softwood 45% 22% 28%

Data from (Energy Research Centre of the Netherlands, n.d.) 

 

66 Teleconference with Mark Paisley, Director of R&D for Taylor Recycling, on December 10, 2007 
73 

Appendix G 

Conversion Technology Model Calculators