National Energy Technology Laboratory

Increasing Security and Reducing Carbon 

Emissions of the U.S. Transportation Sector: A 

Transformational Role for Coal with Biomass 

This work was performed for the Department of Energy, 

National Energy Technology Laboratory and the 

Department of Defense, Air Force 

August 24, 2007 

DOE/NETL-2007/1298 
Increasing Security and Reducing Carbon 

Emissions of the U.S. Transportation Sector: 

A Transformational Role for Coal with Biomass 

DOE/NETL–2007/1298 

August 24, 2007 

NETL Contact: 

Michael E. Reed 

Senior Systems Analyst 

Office of Systems, Analyses, and Planning 

Prepared by: 

David Gray, Charles White, Glen Tomlinson (consultant) 

Noblis 

Mark Ackiewicz 

 TMS 

Ed Schmetz, John Winslow 

 LTI 

National Energy Technology Laboratory 

www.netl.doe.gov 
i 

Disclaimer 

This report was prepared as an account of work sponsored by an agency of the United States 

(U.S.) government. Neither the U.S., nor any agency thereof, nor any of their employees, nor 

any of their contractors, subcontractors, or their employees makes any warranty, expressed or 

implied, or assumes any legal liability or responsibility for the accuracy, completeness, or 

usefulness of any information, apparatus, product, or process disclosed, or represents that its use 

would not infringe privately owned rights. Reference herein to any specific commercial product, 

process, or service by trade name, trademark, manufacturer, or otherwise does not necessarily 

constitute or imply its endorsement, recommendation, or favoring by the U.S. government or any 

agency thereof. The views and opinions of authors expressed herein do not necessarily state or 

reflect those of the U.S. government or any agency thereof. 
ii 

Acknowledgements 

This study was performed for DoD/AF and DOE under the technical direction of the National 

Energy Technology Laboratory under contract NBCH-D-02-0039/0051. The authors are 

especially grateful for the support and guidance provided by Greg Kawalkin, Michael Reed, 

Julianne Klara, John Wimer, and Maria Vargas of the National Energy Technology Laboratory 

as well as William Harrison of the Air Force. 
iii 

Table of Contents 

1 Introduction........................................................................................................1

1.1 Background ...................................................................................................................... 1 

1.2 Objectives and Scope ....................................................................................................... 2 

2 Methodology.......................................................................................................3

2.1 Carbon Balances and Atmospheric CO2 Emissions......................................................... 3 

2.2 Estimates for CO2 Emissions for FT Diesel..................................................................... 4 

2.3 Naphtha Disposition......................................................................................................... 5 

2.4 CO2 Apportionment from Refinery and CBTL Processing ............................................. 6 

2.5 Baseline Emissions from Petroleum Refinery ................................................................. 6 

2.6 Coal and Biomass to Liquids Process – Design Basis ..................................................... 7 

2.7 Estimation of CO2 Emissions for FT Diesel from CBTL Process ................................... 9 

3 CBTL Feedstock Assessment..........................................................................10

3.1 Illinois – Assessment of Regional Biomass Demand and Availability.......................... 10 

3.2 Feedstock Production CO2 Emissions Results............................................................... 14 

3.3 Land Availability and CBTL Capacity .......................................................................... 15 

3.4 Biomass Economics ....................................................................................................... 17 

3.4.1 Biomass Feedstock Costs........................................................................................ 17 

3.5 Feedstock Analyses........................................................................................................ 19 

4 Conceptual CBTL Plant Evaluation..............................................................21

4.1 CBTL Process Units....................................................................................................... 22 

4.1.1 Feedstock Processing and Drying........................................................................... 22 

4.1.2 The Air Separation Unit.......................................................................................... 24 

4.1.3 Gasification............................................................................................................. 24 

4.1.4 Gas Cooling, Raw Water Gas Shift, Carbonyl Sulfide Hydrolysis, and Mercury 

Removal.................................................................................................................. 24 

4.1.5 Acid Gas Removal .................................................................................................. 24 

4.1.6 Hydrogen Recovery ................................................................................................ 25 

4.1.7 Sulfur Polishing ...................................................................................................... 25 

4.1.8 Fischer-Tropsch Synthesis...................................................................................... 25 

4.1.9 FT Product Upgrading ............................................................................................ 26 

4.1.10 Carbon Dioxide Removal in Recycle Loop............................................................ 26 

4.1.11 Power Generation Block......................................................................................... 26 

4.1.12 Balance of Plant (BOP) Units................................................................................. 26 

4.2 General Technical Plant Description of the Cases Analyzed......................................... 26 

4.3 Case Details of Woody Biomass CBTL Plant Meeting 20 Percent Lower Carbon 

Footprint Criteria than Petroleum Refining ................................................................... 28 

4.4 Comparison with a Reference Petroleum Refinery........................................................ 34 

4.5 Comparison of Petroleum Naphtha and FT Naphtha..................................................... 41 

4.6 Sensitivity to FT Product Specifications (Diesel versus Jet Fuel) ................................. 41 
Table of Contents (Concluded) 

Section Page 

iv

4.7 Economic Analysis for Woody Biomass Cases ............................................................. 42 

4.8 Case Details of Switchgrass and Corn Stover Biomass CBTL Plants Meeting 20 Percent 

Lower Carbon Footprint Criteria than Petroleum Refining........................................... 46 

4.9 Economic Analysis for Switchgrass and Corn Stover Cases ......................................... 52 

5 Roadmap for 100,000 BPD Industry .............................................................55

5.1 National Scope Resource Assessment............................................................................ 55 

5.2 Analysis of Plant Capacity Feasibility ........................................................................... 55 

5.3 Hypothetical Timelines for Target FT Diesel Production Level.................................... 57 

6 Conclusions and Recommendations ..............................................................61

Acronyms and Abbreviations ...............................................................................64

Appendix A: GREET 1.7 Assumptions and Fuel Specifications.......................66

7 References.........................................................................................................68
v 

List of Tables 

Table Page 

Table 1. CO2 Emissions Sources for Petroleum-Derived and Fischer-Tropsch Diesel ......... 3 

Table 2. CO2 Emissions from Production, Transportation, and Refining Crude Oil Into 

Low-Sulfur Diesel Fuel and Naphtha and Transporting and Distributing the Fuel 

to the Station, from GREET 1.7 ............................................................................... 6 

Table 3. Illinois Land Surface, Cropland, and Potential Energy Crop Area........................ 11 

Table 4. Potential Acreage of Land Available in Illinois for Energy Crop Production Based 

on Feedstock Farmgate (Production) Price ($2006)............................................... 11 

Table 5. Estimated Collection Areas and Delivery Distances for Various Plant Sizes for 

Switchgrass, Poplar Trees, and Corn Stover .......................................................... 13 

Table 6. Feedstock Production and Transport CO2 Emissions Estimates for Switchgrass, 

Poplar Trees, Corn Stover, and Coal...................................................................... 16 

Table 7. Range of Feedstock Production Costs from Various Studies ($2006)................... 17 

Table 8. Illinois #6 Bituminous Coal Analysis .................................................................... 20 

Table 9. Biomass Analysis, Dry Basis ................................................................................. 20 

Table 10. Cases Analyzed in the Study.................................................................................. 21 

Table 11. CBTL Plant Carbon Balance for 10 wt% Biomass ................................................ 31 

Table 12. Input/Output Summary for CBTL Plant with Woody Biomass/Coal Feed (10 wt% 

Biomass)................................................................................................................. 32 

Table 13. Overall Carbon Credits and Debits Woody Biomass 10 wt% Case....................... 32 

Table 14. Summary of CTL Only Plant ................................................................................. 37 

Table 15. Input/Output Summary for CBTL Plant With Woody Biomass/Coal Feed (15 wt% 

Biomass)................................................................................................................. 38 

Table 16. Overall Carbon Credits and Debits 15 wt% (10 energy %) Woody Biomass Case.. 

 ................................................................................................................................ 40 

Table 17. Plant Equipment Costs for 15 wt% and 10 wt% Woody Biomass Cases ............. 42 

Table 18. Additional Capital Costs for 15 wt% and 10 wt% Woody Biomass Cases (Millions 

Dec 2005 $) ............................................................................................................ 43 

Table 19. Annual Operating Costs for 15% and 10% Woody Biomass Cases (Millions Dec 

2005 $).................................................................................................................... 44 

Table 20. Economic Summary for 15 wt% and 10 wt% Woody Biomass Cases .................. 45 

Table 21. Economic Assumptions for DCF Analyses............................................................ 46 
List of Tables (Concluded) 

Table Page 

vi

Table 22. Overall Carbon Credits and Debits 12 wt% Switchgrass Case............................. 49 

Table 23. Overall Carbon Credits and Debits for 12 wt% Corn Stover Case ....................... 51 

Table 24. Plant Equipment Costs for 12% Switchgrass and 12% Corn Stover Cases .......... 52 

Table 25. Additional Capital Costs for Switchgrass and Corn Stover Cases (MM Dec 2005 $) 

 ................................................................................................................................ 53 

Table 26. Annual Operating Costs for Switchgrass and Corn Stover Cases.......................... 54 

Table 27. Economic Summary for 12% Switchgrass and 12% Corn Stover Cases............... 54 

Table 28. Hypothetical Timelines for Ramp-Up for CBTL Industry..................................... 58 
vii 

List of Figures 

Figure Page 

Figure 1. Transportation Cost for Corn Stover...................................................................... 18 

Figure 2. Delivered Cost of Biomass as a Function of CBTL Plant Biomass Demand ........ 19 

Figure 3. Generic Block Flow Schematic of a CBTL Facility .............................................. 23 

Figure 4. Block Flow Schematic of the 10 wt % (7 energy %) Woody Biomass Case......... 30 

Figure 5. Block Flow Schematic of the Coal Only CTL Plant.............................................. 36 

Figure 6. Block Flow Schematic of the 15 wt % (10 energy %) Woody Biomass Case....... 39 

Figure 7. Schematic of Switchgrass and Corn Stover Prep System ...................................... 47 

Figure 8. Block Flow Schematic of the 12 wt % (7 energy %) Switchgrass Case................ 48 

Figure 9. Block Flow Schematic of the 12 wt % (7 energy %) Corn Stover Case................ 50 

Figure 10. Distribution of Cellulosic Feedstock from Crop Residues and Dedicated Energy 

Crops ...................................................................................................................... 56 

Figure 11. Cumulative Diesel Production For Hypothetical CBTL Ramp-up Timelines ....... 59 
viii

Executive Summary 

The Air Force has set a goal to supply fifty percent of its CONUS (lower 48 United States) fuel 

requirements from domestic synthetic sources by 2016. One option for doing this is the 

production of liquid fuels from coal via gasification and Fischer-Tropsch (FT) synthesis, a 

process known as coal-to-liquids (CTL). In addition, the Department of Defense (DoD) will 

require that providers of synthetic fuel practice carbon dioxide (CO2) emissions capture, 

sequestration or reuse/reform. Although CTL, when coupled with carbon capture and 

sequestration during fuel production, can limit CO2 emissions to a level approximately 

equivalent (+4% to -5%) to that of the existing petroleum-based fuel supply chain, the DoD 

wishes to explore options that will further improve its environmental performance by reducing 

the carbon footprint of the plant to be below that of a conventional petroleum refinery. The coconversion of coal and biomass to liquid fuels (CBTL) has been recently proposed as a possible 

option to accomplish this. The option to use various process (including algae) for reuse/reform 

of CO2 emissions with CTL/CBTL process has been proposed, but is not in the scope of this 

report. This option will be considered in future research. 

CTL can produce high quality, zero sulfur, and paraffinic fuels from coal by gasifying the coal 

and then passing the clean coal-derived gas, essentially carbon monoxide and hydrogen, over 

Fischer-Tropsch catalysts. However, because of the energy used in the conversion process and 

the high carbon content of the coal feedstock, the carbon dioxide emissions, on a well-to-wheels 

basis, are 1.8 times more than petroleum. In order to obtain carbon dioxide emissions less than 

petroleum from a CTL process biomass can be co-processed with the coal. In this way carbon 

emissions can be significantly less than petroleum. The carbon contained in the biomass is not 

counted as a carbon input penalty because the biomass has recently removed this carbon from the 

atmosphere by photosynthesis. A portion of this biomass carbon is then subsequently captured 

and sequestered within the CBTL facility during the conversion process. In this way a double 

benefit accrues to the biomass carbon. 

This study had two primary objectives. The first was to develop a coal-biomass-to-liquids 

(CBTL) plant design that is potentially capable of co-gasifying mixtures of coal and biomass to 

produce a clean synthesis gas that can then be sent to Fischer-Tropsch units for synthesis of clean 

diesel, jet and naphtha liquid fuels. The goal of this CBTL plant was to determine the 

appropriate mixture of coal and biomass that would produce these fuels with a net carbon 

footprint twenty percent lower than would occur from the production of low sulfur diesel from 

an existing conventional petroleum refinery. The second objective of this study was to develop a 

CBTL pathway for diesel fuel production that has the potential for meeting the DoD goal of 

providing 100,000 BPD of synthetic fuel with the requirement that carbon dioxide emissions 

should be less than those from conventional petroleum. Three biomass types were selected for 

study: woody biomass, switchgrass, and corn stover. These biomass types are relatively 

abundant and their use will not directly affect food supplies. 
ix

The comparison of CO2 emissions between petroleum-derived diesel and FT diesel was based on 

a limited well-to-wheel life cycle analysis. The analysis for each fuel included the major CO2

sources from the production and transportation of the feedstocks to the refinery/plant, the CO2

emitted during production, and the CO2 emissions resulting from transportation of the diesel 

product to the end user and the combustion of the product. Most of these CO2 emissions, apart 

from the combustion of the fuel itself, result from the energy used in each processing step. The 

major limit imposed on the life cycle analysis was that the CO2 emissions resulting from the 

construction of the CTL facility were not considered. To be conservative, no credit was taken 

for soil carbon storage by the biomass. Complete greenhouse gas (GHG) emissions were not 

considered. The study considered only emissions of carbon dioxide. 

Three types of biomass were examined in this study: switchgrass, poplar trees, and corn stover. 

In all cases, Illinois #6 bituminous coal was used. A conceptual process design was prepared for 

a CBTL facility capable of co-feeding coal and biomass into a gasifier to produce a syngas 

suitable for FT synthesis. The conceptual design estimated the performance, size, and cost of the 

major pieces of equipment and provided the basis for estimating the CO2 emissions associated 

with the synthesis of FT diesel. 

Most of the estimates for CO2 emissions associated with the production, transportation, and 

processing of feedstocks and end products were obtained from the Argonne National Laboratory 

(ANL) Greenhouse Gases, Regulated Emissions, and Energy Use in Transportation (GREET) 

Model version 1.7. GREET is a publicly available model that was sponsored by the DOE Office 

of Energy Efficiency and Renewable Energy and has been used to evaluate various fuel and 

vehicle systems for government and industry. It is a widely accepted model for estimating 

greenhouse gas emissions from fuels on a well-to-wheels basis. This study is a well-to-wheels 

carbon analysis and includes the carbon dioxide emitted in production of the feeds to the CBTL 

plant, the carbon dioxide emitted during conversion of the input coal and biomass to FT fuels, 

and the transportation and combustion of these fuels. 

Estimates for the CO2 emissions from a conventional refinery were obtained from multiple 

sources including GREET. A broad range of estimates were reported, depending on the assumed 

operating efficiency of the refinery. 

Conceptual CBTL designs were examined for all three types of biomass. In these conceptual 

designs coal and biomass are gasified in entrained flow gasifiers and the raw synthesis gas is 

cleaned of impurities. The clean synthesis gas is then sent to slurry phase FT reactors where the 

hydrocarbon fuels are produced. Slurry phase reactor technology is under development by 

several companies and Sasol is utilizing these reactors at their Oryx Gas-to-Liquids (GTL) plant 

in Qatar. Slurry reactors have excellent heat transfer characteristics and allow high conversions 

of synthesis gas per pass. However, there has not been much commercial experience with these 

reactors and there are issues relating to hydrodynamics and separation of the wax produced in the 

FT process from the fine catalyst. Wax is produced to maximize the distillate yield. The wax is 

hydrocracked to produce additional distillate product. 
x

For each conceptual plant, estimates were made for the amount of biomass that would have to be 

co-fed with coal to attain the target 20% reduction in CO2 emissions. In these plant 

configurations about 88% of the carbon dioxide emissions resulting from the conversion of the 

coal to FT fuels are captured and compressed to 2,200 psi. After compression it is assumed that 

the carbon dioxide is piped from the CBTL plant boundary. In this analysis, except for one 

sensitivity case, no additional cost for sequestering or storing the carbon dioxide is included in 

the economics. In the sensitivity case a cost of $4.60 per metric tonne was added for carbon 

dioxide transportation, sequestering, and monitoring (TS&M). This increased the required 

selling price of the FT fuels by about 1.8 percent compared to cases with no costs for TS&M. 

However, if the carbon dioxide could be sold for enhanced oil recovery (EOR) operations or 

other reuse it would have a net positive value and be a credit in the economic analysis. 

The results of the study indicated that FT diesel can be produced at the target CO2 reduction 

level by co-gasifying coal with a relatively modest amount of biomass. For woody biomass, the 

CO2 reduction target could be attained using 10-15% woody biomass by weight (7-10% by 

energy) on an as-received basis. For switchgrass, the CO2 reduction target could be attained 

using 12-18% biomass by weight (7-10% by energy) and for corn stover the needed amount is 

12-18% biomass by weight (7-11% by energy). 

As part of this study, a scoping level economic analysis was performed for the coal-only plant 

and the CBTL plants. Based on the economic parameters used in this study, the required selling 

price (RSP) of the diesel product was estimated to be about $71/barrel for a coal-only (CTL) 

plant. On a crude oil equivalent basis this would be about $55/bbl. For the woody biomass 

CBTL plants the RSP of the fuel is estimated to be about $76/barrel. On a crude oil equivalent 

basis, this is equivalent to $58-59/bbl or about seven percent higher than the coal-only case. For 

the corn stover and switchgrass plants the RSP of the fuel was estimated to be about $75/bbl. On 

a crude oil equivalent basis this is about $58/bbl. 

Some sources, including GREET, indicate that dedicated energy crops including short rotation 

woody biomass and switchgrass could further reduce the CO2 footprint of a CBTL plant. If the 

full soil carbon credit can be realized, it would be possible to meet the CO2 reduction goal with 

as little as 5-10% by weight woody biomass. However, whether or not soil carbon sequestration 

should be included and the amount of this credit is a controversial issue at present. To be 

conservative it was decided not to include this credit in this analysis. 

Because the percentage of biomass required is relatively low and within the range of the limited 

demonstration test data available for coal:biomass co-feeding to pressurized gasifiers, it is 

concluded that the proposed CBTL process is potentially feasible. 

A limited resource assessment was performed to determine if sufficient biomass can be harvested 

and transported to a CBTL facility of sufficient size to be economically practical. It was 

determined that the biomass availability would not be a major limiting factor for CBTL plants in 

the 7,500 BPD diesel capacity range. This size CBTL facility would require a sustainable annual 

supply of biomass of about 1,000 TPD. For switchgrass and poplar with dry yields per acre of 
xi

about 5-6 tons, the total land area required would be about 1,440 square miles (a radius of about 

22 miles). This assumes that only 8 percent of the land is available for production of the energy 

crops. For corn stover with a lower crop yield of about two dry tons per acre (half of the crop is 

left on the land for soil conditioning), the area required for sustained operations to produce 1000 

TPD would be about 920 square miles (radius of about 17 miles) because the land available for 

production is assumed to be as high as 31 percent. 

While this study concludes that it is practical to attain the desired CO2 emissions reduction target 

it must be cautioned that, because the amount of actual field data available on gasification of 

biomass in pressurized entrained flow gasifiers is so limited, considerable RD&D will be needed 

to determine the pretreatment necessary and the optimum type of feed system needed to enable 

reliable feeding of these biomass types to these high pressure gasification systems. Biomass 

gasification using high temperature and pressure entrained flow gasifiers would be preferable to 

eliminate tar and methane formation from the biomass. Also the CBTL plants would be simpler 

and less costly if the same gasifier could be used to process both the coal and the biomass. 

Separate feed systems for coal and biomass may also be preferable so that, if there are problems 

with the biomass feed system, the gasifier can be kept in operation using coal. Another potential 

option is separate gasification of biomass. This option is out of the scope of this report but will 

be considered in future work. 

All three biomass types examined in this study showed nearly equivalent performance in the 

CBTL process. Regional land availability will be the most important determinant of which 

biomass type to use for a specific site. 

The reference plant studied was a 7,500 BPD diesel plant located in southern Illinois. This plant 

size was chosen based on a preliminary and highly approximate estimate for the amount of 

biomass that may be required. The report does not suggest that 7,500 BPD is either the 

maximum or optimum size for a CBTL plant. It was shown that larger plants of at least 30,000 

BPD are feasible based on biomass resource availability. It is left as a recommendation for 

further work to perform a more detailed biomass resource and infrastructure assessment which 

would be needed to determine the maximum CBTL plant size that is technically feasible and to 

determine the optimum plant size for which economies of larger scale balance the increased cost 

of collecting larger quantities of biomass. 

Multiple scenarios were presented with timelines for the build up of a CBTL industry. In the 

most conservative scenario, the production goal of 100,000 BPD is not attained until 2026. 

Incentives could stimulate the development of the industry. An aggressive hypothetical 

production ramp-up was prepared for the construction of seven CBTL facilities that would meet 

the DoD goal of obtaining 100,000 BPD of synthetic fuel by 2016. The ramp-up assumes that 

the first two plants will be small 7,500 BPD facilities of the same design as the reference plant. 

These first plants will use corn stover since this type of biomass is currently available. It is 

assumed that over time, more plants will be constructed simultaneously; future plants will be 

larger in capacity (up to 22,500 BPD) and shake down periods for start-up will grow shorter. 

These later plants would use mixtures of switchgrass, corn stover, and woody biomass. 
xii

Although specific plant locations were not proposed, a national biomass resource assessment has 

forecast that there will be abundant quantities of suitable biomass available in multiple 

geographic regions in the U.S. by 2016 and that the hypothetical ramp-up is feasible with respect 

to resource availability. 

Because biomass availability is often seasonal for some crops it is recommended that any CBTL 

plant have processing equipment on site that is suitable for several biomass types. Although this 

will increase capital cost, in that way when corn stover is available, after the corn harvest, the 

CBTL facility can utilize this crop predominately. When the switchgrass is available after 

harvesting, the facility could use this feed. The woody biomass should be available most of the 

time depending on the cutting cycle. The coal would act as the flywheel to keep the plant 

operating at a fairly constant output. 

The concept of using both coal and biomass together to produce high quality FT fuels via 

gasification should be advantageous to both coal and biomass to energy technologies. Coprocessing biomass with coal can significantly reduce the carbon footprint of a CTL facility and 

the gasification route allows non-food product biomass-like cellulose and lignin to be used for 

energy production. 
1 

1 Introduction 

1.1 Background 

The Air Force is the largest energy consumer in the federal government and presently uses about 

200,000 bbl/day of fuel1

 with the majority of this used by tactical aircraft. Most of this fuel is 

derived from petroleum sources and, as with other segments of the US, the majority of this 

petroleum is imported. In recognition of the vulnerabilities associated with reliance on imported 

petroleum, the Office of the Secretary of Defense set forth the Assured Fuels Initiative to 

catalyze industry to produce fuels for the military from domestic energy sources without placing 

an undue burden on domestic oil supplies. The Air Force has also established goals for reducing 

the environmental impact of its energy use. Specifically, the Air Force has set a goal to use 

synthetic fuels that generate significantly lower levels of CO2 than diesel derived from 

petroleum. As recently expressed by the AF Secretary, the Air Force has set a goal to supply fifty 

percent of its CONUS fuel requirements from domestic synthetic sources by 20162

. Many 

alternative fuel options are being pursued including biodiesel (B20), E85, and synthetic FischerTropsch (FT) diesel derived from natural gas, coal, or biomass. FT diesel production from 

synthesis gas (mixture of carbon monoxide and hydrogen) is a mature technology that has been 

used at commercial scale for over sixty years. An advantage of FT diesel synthesis is that the 

synthesis gas feedstock can be obtained from many different sources that are domestically 

abundant, including coal and biomass. 

Coal has advantages of great abundance, relatively low cost and high energy density. 

Furthermore, the production of synthesis gas from coal is a proven technology at commercial 

scale. Unfortunately, coal has a low hydrogen to carbon ratio and the production of FT diesel 

from coal produces approximately twice as much CO2 as does the refining of petroleum into 

diesel. This disadvantage can be managed by the capture and sequestration or reuse of the CO2

produced with FT diesel. When this is done, the CO2 produced with FT diesel is approximately 

the same as that from petroleum-refined diesel. If biomass is used as the source of the synthesis 

gas, the resulting FT diesel will have essentially no net impact on atmospheric CO2 levels 

because the carbon in the biomass that goes into the synthesis gas is generated from atmospheric 

CO2 by photosynthesis. Unfortunately, biomass has numerous disadvantages as a feedstock to 

produce synthesis gas including a low energy density and high moisture content leading to high 

production and processing costs. It is also difficult to reliably feed into a pressurized gasification 

reactor and there have been very few demonstrations of this technology at commercial scale. 

An approach that may succeed in meeting all of the Air Fore goals is to use FT diesel derived 

from a combination of coal and biomass. The biomass component would act to reduce the net 

CO2 emissions associated with the production of FT diesel and if small enough amounts of 

biomass were required, it may work reliably with existing coal gasification equipment. 

Because of the potential of this approach the Air Force (AF) and the National Energy 

Technology Laboratory (NETL) commissioned Noblis to undertake this analysis. 
2 

1.2 Objectives and Scope 

The first objective of this study is to develop a coal-biomass-to-liquids (CBTL) plant design that 

is potentially capable of co-gasifying mixtures of coal and biomass to produce a clean synthesis 

gas that can then be sent to Fischer-Tropsch units for synthesis of clean diesel, jet and naphtha 

liquid fuels. The goal of this CBTL plant is to produce these fuels with a net carbon footprint 20 

percent lower than would occur from the production of low sulfur diesel from an existing 

conventional petroleum refinery. This goal will be achieved by varying the quantity of biomass 

and coal feed to the CBTL plant so that the resultant mix will attain this 20 percent goal. The 

study examines three types of biomass: woody biomass, switchgrass, and corn stover. These 

biomass types were selected because of their relative abundance and because their use will not 

directly affect food supplies. 

The second objective of this study is to develop a CBTL pathway for diesel fuel production that 

appears to have the potential for meeting the DoD goal of providing approximately 100,000 BPD 

of synthetic CBTL fuel by 2016 with the required carbon dioxide emissions reductions. The 

third objective is to formulate conclusions, identify assumptions and recommend steps forward. 

This analysis is considered to be a first order scoping study and the level of detail given is 

considered appropriate for such a study. 
3 

2 Methodology 

2.1 Carbon Balances and Atmospheric CO2 Emissions 

The comparison of CO2 emissions between petroleum-derived diesel and Fischer-Tropsch (FT) 

diesel was based on a limited life cycle analysis. The analysis for each fuel included the major 

CO2 sources from the production and transportation of the feedstocks to the refinery/plant, the 

CO2 emitted during production, and the CO2 emissions resulting from transportation of the diesel 

product to the end user and the combustion of the fuels. This is, then, a limited well-to-wheels 

life cycle analysis (LCA) for carbon. Most of these CO2 emissions result from the energy used 

in each processing step. The major limit imposed on the life cycle analysis was that the CO2

emissions resulting from the construction of the CTL facility were not considered. 

Table 1 following summarizes the major CO2 sources for the refinery-derived and FT synthesis 

routes for the production of diesel. 

Table 1. CO2 Emissions Sources for Petroleum-Derived and Fischer-Tropsch Diesel 

CO2 Generation Path Petroleum-derived low 

sulfur diesel 

FT diesel 

Crude oil: exploration, 

drilling, pumping, 

transportation to refinery 

Coal: mining, collection, 

transportation to plant 

Well-to-plant 

 Biomass: cultivation, 

growth, harvesting, initial 

preprocessing, 

transportation to plant 

Plant operations Distillation, reforming, 

cracking, coking, hydrogen 

production 

Final feedstock 

preprocessing, gasification, 

clean-up, FT synthesis, 

upgrading, CO2

compression and delivery 

Plant-to-pump Transportation and piping 

to Air Force refueling 

facility 

Transportation and piping 

to Air Force refueling 

facility 

For the refinery-derived diesel, the CO2 emissions were assumed to be the emissions associated 

with the exploration, drilling, pumping, and delivery of crude oil to the refinery, plus the 

emissions associated with refinery operations required for the production of low-sulfur diesel, 

plus the emissions arising from the piping and transportation of the diesel product to an Air 

Force refueling depot and the combustion of the fuel. 
4 

For the FT diesel, the CO2 emissions were assumed to be those resulting from the mining and 

delivery of the coal, the cultivation, growth, harvesting, and delivery of the biomass to the plant, 

the emissions associated with the production of diesel from the CBTL facility including 

preprocessing of the biomass feedstock, plus the emissions arising from the piping and 

transportation of the diesel product to an Air Force refueling depot and the combustion of the 

fuel. 

The reference point for the CO2 balance was the CO2 level in the atmosphere. Any processing 

step that increases atmospheric CO2 levels has a positive emissions value and any step that 

decreases atmospheric CO2 levels has a negative emissions value. 

The CO2 emissions associated with the actual growth of the biomass are negative. It is assumed 

that all of the carbon in the gasified biomass is obtained via photosynthesis from atmospheric 

CO2. The CO2 uptake by the biomass is substantially larger than that contained in the harvested 

and gasified portion. Under certain circumstances, much of this additional carbon can lead to 

long term carbon storage in the soil. However, based on the assumptions given in the report on 

“Soil Carbon Changes for Bioenergy Crops”3

 we have taken their conservative approach to this 

issue. Because of uncertainties and the lack of data, no net carbon sequestration benefit was 

assumed for land use changes resulting from soil carbon by cultivation of bioenergy crops. This 

approach was taken because it is unclear if there would be any net change in soil carbon storage 

compared to the existing land use soil carbon storage over the lifetime of the plant. 

The comparison between the two diesel products was done on an equivalent energy replacement 

basis, rather than on a direct barrel per barrel basis. Because FT diesel has a lower density than 

petroleum-derived diesel, a greater amount of FT diesel is needed to replace a barrel of 

petroleum-derived diesel and this difference was accounted for in the analysis. 

The CBTL plants considered in this study capture CO2 and are sequestration or reuse/reform 

ready. The plant designs, mass balances, and capital and operating costs all reflect a process that 

captures approximately 88% of the carbon in the feed and compresses it to 2,200 psia, a pressure 

suitable for sequestration in saline aquifers or for use in enhanced oil recovery. Because of the 

uncertainty of the value of the carbon dioxide, no costs associated with its disposal are included 

in this analysis. CTL processes are well-suited for carbon capture and storage because the 

removal of CO2 from the feed to the FT reactor is required for optimal operation of the FT 

reactors. The only additional processing requirements associated with sequestration are the costs 

and energy required to compress the CO2 and transport it to a sequestration site. In this study, 

the CO2 was compressed but not sequestered. However, the additional CO2 emissions associated 

with sequestration after the CO2 has been compressed are small. The petroleum refinery was 

assumed to operate without CO2 capture and storage. 

2.2 Estimates for CO2 Emissions for FT Diesel 

Most of the well-to-plant CO2 emissions estimates for the CBTL feedstocks were obtained using 

the Argonne National Laboratory (ANL) Greenhouse Gases, Regulated Emissions, and Energy 

Use in Transportation (GREET) Model version 1.7. GREET is a publicly available model that 

was sponsored by the DOE Office of Energy Efficiency and Renewable Energy and has been 
5 

used to evaluate various fuel and vehicle systems for government and industry, including 

General Motors. It includes over 100 fuel production pathways and over seventy vehicle/fuel 

systems, allowing users to evaluate various system pathways on a “well-to-wheels” basis. 

GREET calculates the consumption of total energy, fossil energy, and petroleum, coal, and 

natural gas; emissions of carbon dioxide and other greenhouse gases; and emissions of criteria 

pollutants. It calculates these by using an iterative process that calculates the energy and 

emissions to produce the energy (and so forth for 100 steps) used to recover the feedstock, 

transport it, convert it into product, and finally consume the product in a vehicle. 

GREET 1.7 does not contain a CBTL pathway for FT diesel and hence, estimates for the CO2

emissions from the CBTL plant operations were obtained by developing a conceptual level 

design of the CBTL facility and performing steady-state mass and energy balances around each 

of the processing units. The conceptual level process design does not attempt to perform a 

system optimization nor is there a rigorous heat exchanger design for the system heat integration. 

Hence there is some uncertainty in the estimates for process efficiency and CO2 emissions. With 

a more in depth study or more engineering data, this uncertainty could be reduced. However, the 

level of accuracy of the process model is well within the accuracy of the other life cycle CO2

emissions and is considered adequate for the objectives of this feasibility study. 

Estimates for the plant-to-pump CO2 emissions were based on assumed distances for pipeline 

and tanker truck transport of the product diesel to an Air Force refueling station. These distances 

were estimated after a site was selected for the initial CBTL facility. 

2.3 Naphtha Disposition 

Since the purpose of the study was to examine the feasibility of reducing CO2 emissions using 

FT diesel derived from a mixture of coal and biomass, two simplifications were introduced 

regarding the byproduct naphtha. First, the naphtha product from the CBTL plants is assumed to 

be used as a feedstock for ethylene production in a petroleum refinery and is assumed to have no 

significant impact on net refinery CO2 emissions compared to using petroleum-derived naphtha 

for the same application. Secondly, it is assumed that the secondary impacts of fuel substitution 

on the petroleum refinery industry product yields are negligible. 

Both of these assumptions are reasonable and valid for a feasibility study for a CBTL production 

capacity at the level considered in this study. Compared to the total amount of naphtha 

processed at petroleum refineries nation-wide, the amount generated by the CBTL plant is small 

and would not be expected to have significant impacts on either the overall refinery operations or 

CO2 emissions. U.S. refineries typically do not produce naphtha but convert it to gasoline. 

Some naphtha is fed to crackers to produce ethylene but the major feedstock is ethane or natural 

gas liquids (NGL). The U.S. produced about 29 million tons of ethylene in 2006. To 

manufacture a part of this ethylene the U.S. used about 500,000 BPD of naphtha of which about 

55% was imported as feed to ethylene crackers. One 10,000 BPD CBTL plant produces about 

3,500 BPD of naphtha therefore 10 of these plants would produce only 30,000 BPD of naphtha. 

This is only 6 % of the naphtha used for ethylene and would reduce imported naphtha. 
6 

2.4 CO2 Apportionment from Refinery and CBTL Processing 

In this study, the comparison of CO2 between CBTL and refinery derived diesel focused on the 

diesel product and the portion of CO2 attributable to that product. In the case of the refinery, 

GREET estimates the energy required for the refinery processing steps leading to diesel 

production and assigns the diesel portion based on the weight fraction of diesel in the final 

product mix. In the case of CBTL, the CO2 emissions from the entire plant processes were 

estimated and those emissions were distributed between the diesel and naphtha products on a 

weight basis. 

2.5 Baseline Emissions from Petroleum Refinery 

The baseline from which the FT diesel was compared was the life cycle CO2 emissions resulting 

from the production of an equivalent amount of low sulfur diesel from a conventional petroleum 

refinery. Table 2 following gives the well-to-pump CO2 emissions estimates from a typical 

petroleum refinery for the production of low sulfur diesel. This data was obtained from 

GREET 1.7. The model assumptions used to generate this data are listed in Appendix A. 

Table 2. CO2 Emissions from Production, Transportation, and Refining Crude Oil 

Into Low-Sulfur Diesel Fuel and Naphtha and Transporting and Distributing 

the Fuel to the Station, from GREET 1.7 

Crude Oil 

Production/ 

Transportation* Refining 

Refining – NonCombustion 

Emissions 

Transportation 

and 

Distribution Total 

CO2 Emissions 

(lbs CO2/barrel 

diesel) 

44.5 131.8 13.9 1.54 191.7 

CO2 Emissions 

(lbs CO2/barrel 

naphtha) 

49.0 78.8 8.7 1.54 138.0 

*

Includes multiple delivery methods and distances, such as ocean tankers, pipelines, and barges. 

This data assumes that the refinery efficiency is approximately 85%. Since operations data from 

refineries is considered proprietary, this is an assumed value. Other sources have suggested that 

the operations efficiency for a typical refinery is higher, perhaps as high as 90%4. Because of 

the large range of estimates in the literature and the lack of definitive data from the refinery 

industry, a range was used for the estimate of CO2 emissions in this study. A recent publication 

from EPA (2007)5 reports that greenhouse gas emissions from a CTL process with sequestration 

are approximately 3% higher than from a conventional refinery. Using that as a reference point, 

a more optimistic estimate for total CO2 emissions from a petroleum refinery would be about 176 

lbs of CO2/bbl low sulfur diesel. It should be noted that there is disagreement in the literature 
7 

concerning the exact amount of CO2 emissions that are attributed to diesel fuel production using 

existing commercial processes. The nature of background data, calculation methods, and 

allocation assumptions all contribute to different, but credible, outcomes. An independent NETL 

study places the CTL with sequestration process at -5% relative to conventional petroleum. 

However, the EPA ratio was used to keep the CBTL conceptual design on a conservative basis.

2.6 Coal and Biomass to Liquids Process – Design Basis 

This section presents the basis for the conceptual design of the CBTL processes. The technical 

details and parameters for specific plant configurations are presented in Section 4 following. 

While many studies have been performed to evaluate the techno-economic performance of CTL 

processes, there are few published studies on the performance of such processes with cogasification of coal and biomass. The major design issues for the CBTL process were sizing and 

site selection for the plants, selection of gasifier technology, design of feed systems, design of 

biomass preprocessing systems, choice between biomass preprocessing at the plant or at the 

harvest site and selection of FT reactor. Many of these design issues depend on the amount of 

biomass required which was an unknown that the study was to determine. Hence, a prescreening level analysis was preformed to roughly estimate the amount of biomass required to 

meet the CO2 emissions target. Design basis decisions based on the estimated amount of 

biomass required were checked when the final value for the amount of biomass required was 

determined. 

Since the carbon in the biomass does not contribute to atmospheric CO2 emissions and since 

almost 90% of the CO2 is captured in the standard CTL process configuration, it was estimated 

that roughly 10-18% biomass by weight would be required to meet the CO2 reduction target, 

given the range of CO2 emissions from a petroleum refinery. 

Based on this preliminary estimate, it appeared likely that the amount of biomass needed would 

be relatively small compared to the coal required and that the gasification system design would 

be based primarily on the coal properties. Nevertheless, a literature review was performed on 

biomass gasifiers to identify design issues specific to biomass that may need to be addressed. 

Although considerable research has been performed on biomass gasification, there has yet to be a 

large, commercial scale biomass gasification plant built. Most biomass gasification systems 

described in the literature are small scale, air-blown, low temperature, atmospheric pressure 

systems. Such gasifiers were deemed inappropriate for the application under study. For 

economic considerations, the gasification system must operate at elevated pressure. 

Unfortunately, there is very little data in the literature for high pressure biomass gasifiers. 

Because of the fibrous nature of most biomass sources, the material is very difficult to feed into a 

high pressure gasifier. Typical problems include clumping and bridging. However, there have 

been reports of successful pressurized biomass:coal co-feeding operations for mixtures 

containing up to 30% biomass by weight. 

At the NUON plant in the Netherlands they successfully fed a mixture of 30 percent by weight of 

demolition wood and 70 percent coal to the Shell high pressure, entrained gasifier. Even though 

we are not sure of the size that was used, possibly it was sawdust, based on this experience we 
8 

have assumed that it is possible to feed small wood particles of 1 mm size to a pressurized 

entrained gasifier. This assumption is supported by ECN in their report on entrained flow 

gasification of biomass6

. 

Since the order of magnitude estimate for the amount of biomass required for a 20% reduction in 

CO2 emissions was within the range of demonstrated coal:biomass feed systems for pressurized 

gasifiers, it was assumed that existing technology was adequate for the proposed process. It was 

assumed that biomass dried to 10% moisture and reduced in size to approximately 1 mm 

diameter, can be reliably fed to pressurized gasifiers either co-mixed with the crushed coal or fed 

through a dedicated feed system. For the purposes of the plant cost estimate, a separate feed 

system was assumed. However, given the well documented challenges of feeding biomass to 

high pressure systems, further R&D will be necessary to be certain that this can be successfully 

achieved. 

Because of the high methane content in syngas produced from low temperature gasifiers, it was 

decided to base the process design on a high-temperature dry feed, entrained flow, oxygen-blown 

gasifier. This system will also eliminate the tars associated with the low temperature gasification 

of biomass. A quench design was selected for the gasifier to help reduce capital costs. For the 

FT reactor, a low temperature slurry phase FT reactor with iron catalyst was selected. Low 

temperature FT slurry phase reactors were used in the study to produce a high net product of 

distillate rather than naphtha. Also slurry reactors give a higher conversion per pass because of 

the superior heat transfer characteristics. Iron is used as catalyst because it is cheaper than cobalt 

and readily obtained in the U.S. 

Sizing and plant site selection were based on the order of magnitude estimate for biomass 

requirements, yield data for the three types of biomass, and a preliminary resource assessment 

for the biomass sources. Because of its lower density, biomass transportation costs were 

expected to be greater than those for coal and hence it was assumed that the optimal plant site 

would be in close proximity to the biomass source. There are considerations for the location of 

the facility including the expected volume of coal needed for large scale facilities. This topic 

will be the subject of future research. For this study, the site was assumed to be rural and based 

on the order of magnitude biomass feed requirement, it was decided to use a nominal capacity of 

7,500 bpd diesel for the index CBTL plant. Because of its abundant coal resources, large 

agricultural industry, and proximity to potential CO2 sinks, the index plant was sited in southern 

Illinois also close to operating coal mines. 

The choice of 7,500 bpd diesel as the reference plant size is not intended to imply that this is 

either the maximum or optimum size for a CBTL plant. It is likely that the maximum size for a 

CBTL plant will be limited by the maximum amount of biomass that can be economically 

collected and determining this will require an extensive and detailed biomass resource 

assessment which was beyond the scope of the present study. It is left as a recommendation for 

further work to determine the maximum CBTL plant size that is technically feasible and to 

determine the optimum plant size for which economies of larger scale balance the increased cost 

of collecting larger quantities of biomass. 
9 

2.7 Estimation of CO2 Emissions for FT Diesel from CBTL Process 

The life cycle CO2 emissions for FT diesel were estimated as the sum of the CO2 emissions from 

the CBTL process, the life cycle CO2 emissions from the CBTL feedstocks, the total CO2

emissions attributed to the transportation and delivery of the FT diesel product, and the 

combustion of the fuel. The life cycle CO2 emissions from the CBTL feedstocks depend on the 

amounts required, the amount and type of preparation required, and the transportation distance to 

the plant. This data in turn depends on the nature of the biomass, its yields, and the frequency 

with which it can be harvested. 

Section 3 following describes a resource assessment for the biomass (switch grass, corn stover, 

and short rotation woody biomass) feedstocks under consideration as well as coal. The 

assessment addresses resource requirements and availability, production cost, and life cycle CO2

emissions associated with production and delivery to the plant gate. This data was also used to 

determine the optimum biomass preprocessing steps. 

The CO2 emissions associated with the mining, cleaning, and transport of the coal was estimated 

from GREET. For the most part, the default assumptions in GREET were used. The site 

specific assumptions used for the proposed CBTL plant are listed in Appendix A. The coal is 

assumed to be obtained from an underground mine located within 65 miles of the CBTL plant. 

To estimate the CO2 emissions from the CBTL process, a conceptual level CBTL process design 

was developed using the design basis described in the previous section. Mass and energy 

balances were closed around each major process section using spreadsheet models validated 

against developer data. A detailed description of the CBTL process is provided in section 4. 

The total CO2 emissions from the transportation and delivery of the FT diesel product were 

estimated from GREET using a scenario in which the product is assumed to be piped 300 miles 

and delivered by tanker truck for another 60 miles. This resulted in CO2 emissions for 

transportation/delivery of 1.54 lbs CO2/bbl FT diesel. 
10 

3 CBTL Feedstock Assessment 

Substituting biomass for coal in a co-gasification, FT diesel production facility has both positive 

and negative impacts on the net CO2 emissions. As noted above, the CO2 from the gasification 

or combustion of carbon in the biomass does not introduce new CO2 into the atmosphere. 

However, biomass is a much poorer quality feedstock for FT diesel synthesis. Compared to coal, 

it has a lower heating value, a lower carbon content, and a higher moisture content. Furthermore, 

biomass has a much lower bulk density at the point of harvest. All of these factors act to 

decrease system performance and/or increase parasitic energy requirements. This leads to 

increased CO2 emissions and reduced process efficiency. At sufficiently high biomass moisture 

contents, sufficiently low net crop yields, and sufficiently large plant sizes, the net impact of 

using biomass could have a deleterious impact on overall atmospheric CO2 levels. 

The key issues to be addressed in the biomass resource assessment are the availability of suitable 

lands for biomass cultivation, the net crop yields, and the energy costs and CO2 emissions 

associated with the cultivation, harvesting, transportation, and preprocessing of the biomass. 

3.1 Illinois – Assessment of Regional Biomass Demand and Availability 

Another concern regarding biomass resource availability is the regional impact on plant size. 

Due to varying climatic conditions throughout the United States, some areas of the United States 

will likely produce higher yields or have a greater percentage of land available for production of 

biomass feedstock than others which could influence both the size and number of CBTL plants. 

This section details the steps required to calculate the biomass feedstock land requirements and 

delivery distances for the feedstock to understand the impact on CBTL plant size. The delivery 

distance will subsequently be used to calculate the energy and CO2 emissions associated with 

production and delivery of the biomass resources. 

Table 3 shows the total land surface area in Illinois, the amount of cropland area, and the 

cropland area that is potentially suitable for poplar or switchgrass growth. Illinois has over 36 

million acres of land surface area, about two-thirds of which (24 million acres) is used in crop 

production. Of the 24 million acres of cropland, 11.2 million acres are used for corn production, 

10.1 million acres for soybean production, and 2.7 million acres for other crop production. Of 

these 24 million acres, almost 97 percent of it is potentially suitable for growing either poplar or 

switchgrass7

. 

The amount of crop residues or dedicated energy crops produced will ultimately depend on 

feedstock price. Typically, the higher the price, the more feedstock is potentially available. 

Table 4 shows the potential incremental amount of land that may be available in Illinois to 

produce poplars or switchgrass at various feedstock production levels based on ORNL8

 analyses. 

It should be noted that the ORNL assessment estimates that the majority of energy crop 

production in Illinois will be from switchgrass because, in the near term, it has higher yields and 

lower production costs. However, this does not preclude woody biomass crops such as poplars 

from being grown on these areas, and therefore poplars should still be considered as a potential 
11 

resource in this analysis. Other factors regarding the feedstock such as plant operating 

conditions and additional equipment requirements may dictate feedstock selection beyond the 

actual feedstock price. 

At a sufficiently high price for the energy crops, land use changes would occur that would 

potentially remove land from some food crop production. Therefore, the impact on other crop 

prices and food/commodity supplies would also need to be determined but that is beyond the 

scope of this analysis. 

Table 3. Illinois Land Surface, Cropland, and Potential Energy Crop Area 

Total Land Surface Area (million acres) 36.1 

Current Cropland Area (million acres) 24.0 

Corn 11.2 

Soybeans 10.1 

Other 2.7 

Other land use (pasture, forest, urban areas, etc.) 12.1 

Potential acreage of cropland in Illinois that could be 

suitable for poplar and/or switchgrass growth 23.2 

Source: USDA Natural Resources Conservation Service (NRCS), Illinois NRCS 

News Release, NRI Data Shows Progress in Illinois Soil Conservation 

Efforts, January 30, 2007. 

Table 4. Potential Acreage of Land Available in Illinois for Energy Crop Production 

Based on Feedstock Farmgate (Production) Price ($2006) 

Yield 

(ton/acre

/ year) 

Acreage of 

Land with 

Farmgate 

Price 

<$44/dry 

ton 

Incremental 

Acreage of 

Land Added 

with Farmgate 

Price $44-

$51/dry ton 

Incremental 

Acreage of 

Land Added 

with Farmgate 

Price $51-

$59/dry ton 

Incremental 

Acreage of 

Land Added 

with Farmgate 

Price $59-

$66/dry ton 

Poplars 5 0 0 0 0 

Switchgrass 5.96 0 13,000 2,800,000 4,870,000 

Source: ORNL, A National Assessment of Promising Areas for Switchgrass, Hybrid Poplar, or Willow 

Energy Crop Production, February 1999. 
12 

Corn stover acreage will depend on the amount of corn acreage available. For Illinois, the 

amount of corn acreage was previously shown in Table 2 (11.2 million acres) and thus is the 

amount of corn stover acreage available. To minimize soil degradation some of the corn stover 

must be left in the field. Typically only half the corn stover should be removed. 

Table 5 shows the estimated land requirements and delivery distances for switchgrass, poplar 

trees, and corn stover at various CBTL plant biomass demand levels. As plant size increases, the 

collection area required for sustained operations and subsequently the delivery distance of the 

feedstock to the plant, also increase. 

The total biomass collection area and the delivery distance to the plant are a function of the 

following key variables: the total annual amount of biomass required for the plant, the yield of 

the biomass per acre per year, percent of land available for feedstock production, and the harvest 

cycle. The total annual amount of biomass is the amount required to sustain plant operations, 

factoring in the plant capacity factor and any feedstock losses. Table 5 shows five CBTL plant 

biomass demand levels: 500, 1,000, 1,500, 2,000, and 2,500 tons per day. The plant capacity 

factor is assumed to be 90 percent and the biomass feedstock loss factor is 10 percent. 

The resulting annual biomass demand (in tons) is then divided by the biomass yield (dry 

tons/acre/year) to arrive at the total annual area required to grow that particular amount of 

biomass feedstock. The yields used for switchgrass and poplars are based on ORNL assessments 

and are assumed to be six and five dry tons/acre/year, respectively, for Illinois. Most studies 

show that nationwide switchgrass yields can range from three to seven dry tons/acre/year and are 

also dependent upon location and other factors9,10,11. The situation for poplars is similar to that 

of switchgrass with the potential for some locations to reach levels of 8 to 10 dry tons/acre/year. 

The yield for corn stover is assumed to be 1.98 dry tons/acre/year and is the value calculated and 

used in GREET. Corn stover yield depends on corn yield and the corn stover collection rate 

which GREET assumes are 166 bushels/acre and fifty percent, respectively. 

However, not all of the land is available around the plant to grow the feedstock because there 

will be other uses of land in the area such as other crop production, pasture, forest, and urban 

areas. Therefore, the percent of land available for feedstock production must also be considered 

when calculating the collection area. In Illinois, the percent of land available for switchgrass and 

poplar growth was assumed to be eight percent for this analysis. This was calculated by taking 

the amount of land available for switchgrass growth at a delivered cost of $51-59/dry ton from 

Table 3 and dividing by the total land surface area of Illinois. For corn stover, the percent of 

land available is 31 percent and is derived from the current amount of land in Illinois that is used 

to produce corn divided by the total land surface area of Illinois. 
Table 5. Estimated Collection Areas and Delivery Distances for Various Plant Sizes fo

Switchgrass, Poplar Trees, and Corn Stover 

Feedstock 

Biomass 

required 

(tons/day) 

Biomass 

required 

(tons/year) 

Conversion 

plant 

capacity 

factor 

Biomass 

Storage 

and 

handling 

losses 

Annual 

biomass 

demand 

(tons) 

Yield 

(dry tons/ 

acre) 

Total 

annual 

area 

required 

(acres) 

Total 

annual 

area 

required 

(sq miles) 

Percent 

land avail 

for 

production 

Adjusted 

total area 

required 

(sq miles) 

Harvest 

cycle 

(years) 

Total area 

required 

for 

sustained 

operations

(sq miles) 

500 182,500 90% 10% 180,675 6 30,113 47 8% 588 1.25 735 

1,000 365,000 90% 10% 361,350 6 60,225 94 8% 1,176 1.25 1,470 1,500 547,500 90% 10% 542,025 6 90,338 141 8% 1,764 1.25 2,206 2,000 730,000 90% 10% 722,700 6 120,450 188 8% 2,353 1.25 2,941 

Switchgrass 2,500 912,500 90% 10% 903,375 6 150,563 235 8% 2,941 1.25 3,676 

500 182,500 90% 10% 180,675 5 36,135 56 8% 706 1 706 

1,000 365,000 90% 10% 361,350 5 72,270 113 8% 1,412 1 1,412 1,500 547,500 90% 10% 542,025 5 108,405 169 8% 2,117 1 2,117 2,000 730,000 90% 10% 722,700 5 144,540 226 8% 2,823 1 2,823 

Poplar trees 2,500 912,500 90% 10% 903,375 5 180,675 282 8% 3,529 1 3,529 

500 182,500 90% 10% 180,675 1.98 91,250 143 31% 460 1 460 

1,000 365,000 90% 10% 361,350 1.98 182,500 285 31% 920 1 920 1,500 547,500 90% 10% 542,025 1.98 273,750 428 31% 1,380 1 1,380 2,000 730,000 90% 10% 722,700 1.98 365,000 570 31% 1,840 1 1,840 

Corn 

Stover 2,500 912,500 90% 10% 903,375 1.98 456,250 713 31% 2,300 1 2,300 
14 

Another factor to consider is the harvest cycle. While the total land area does not depend 

directly on the harvest cycle, there is an indirect impact and the harvest cycle directly impacts the 

processing and transportation costs, storage requirements, and biomass losses. Corn stover can 

be harvested annually, so it has a harvest cycle of one year. A poplar stand can be harvested 

essentially continuously with any individual tree harvested on a seven year cycle. 

Switchgrass is a perennial crop and can be harvested annually like corn, but analyses suggest that 

it will most likely be placed on ten-year crop rotations to allow introduction of newer, higher 

yielding varieties. Additionally, switchgrass typically requires a two-year establishment period 

prior to harvest to reach full potential. Based on this data, 25 percent additional capacity is 

required to continually sustain plant operations. 

Once the total area required for sustained plant operations is determined, one can assume a 

circular area around the plant and calculate the radius of the collection area. This radius will be 

the straight-line distance to the plant. Roads to the plant will not follow a straight line, so to 

calculate the actual distance to the plant, a winding factor of 1.3 is assumed12,13. Multiplying the 

radius by the winding factor provides the actual delivery distance. It should be noted that this is 

a maximum delivery distance for the collection area and not an average delivery distance and 

thus is a conservative estimate. Table 5 estimates the collection areas and actual delivery 

distances for different plant sizes for each type of biomass reviewed in this analysis. 

The data from Table 5 can be used to make assessments regarding potential constraints on plant 

size or number of plants due to feedstock availability at various CBTL plant demand levels. The 

delivery distance from Table 5 can also be used to calculate the CO2 emissions for biomass 

feedstock production and transport to the CBTL plant when inputted into GREET. 

3.2 Feedstock Production CO2 Emissions Results 

From the delivery distances associated with the plant demand levels shown in Table 5, the CO2

emissions for the coal, petroleum, switchgrass, poplar trees, and corn stover feedstocks can be 

calculated using GREET. Table 6 shows the CO2 emissions results for the feedstock production 

stage using GREET and shown on a pounds (lbs) of CO2/ton of feedstock basis (petroleum is 

shown on a lbs of CO2/barrel basis). The key assumptions inputted into GREET, including the 

fuel specifications used in this analysis, are shown in Appendix A. It should be noted that the 

data for corn stover does not include any apportionment of the CO2 emissions associated with 

corn production. 

Overall, feedstock production CO2 emissions account for a minor amount of the fuel-vehicle 

pathway total CO2 emissions. The biomass feedstock options have CO2 emissions separated into 

the categories where energy is used for farming, fertilizer production and use, herbicide and 

insecticides use, and feedstock transportation to the CBTL plant. The coal case includes coal 

mining and transport to the CBTL plant or refinery. 

Table 6 shows a large CO2 emissions credit for land use change/soil carbon sequestration. 

However, as noted previously, it is unclear if the soil carbon would remain sequestered over the 
15 

lifetime of the CBTL plant and hence to be conservative, this credit was not included in the total 

CO2 emissions from feedstock production. 

3.3 Land Availability and CBTL Capacity 

The analysis of switchgrass and poplar trees in Table 5 is based on 8 percent of the land in 

Illinois being available for switchgrass or poplar growth. This is 2,813,000 acres or 

approximately 4,400 square miles. Under this assumption, the range of biomass demand levels 

analyzed in Table 5 shows that demand levels greater than 1,500 dry tons/day would mean that 

only one plant could be supplied with enough biomass to sustain operations. The Southern 

States Energy Board Report The American Energy Security Study included analysis of two cases 

which co-fed coal and woody biomass (poplar trees), one with ten percent biomass by weight 

and the other with twenty percent. These plants had capacity for 10,000 barrels per day and 

required 560 and almost 1,200 tons of biomass per day respectively. At these biomass demand 

levels, approximately five and three 10,000 barrel per day plants respectively could be built that 

would have sufficient biomass supply under the assumptions used for the estimates in Table 5. 

However, if higher yields or more land was available for biomass production, these could 

significantly impact both the number and size of the plants. With all other factors held constant, 

higher yields will result in more biomass available per acre and will shorten delivery distances or 

allow larger scale plants. For example, the recent report by the University of Tennessee used 

projected switchgrass yields of 7.8 dry tons/acre in 10 years and 9.6 dry tons/acre in 20 years in 

its analysis for the “Corn Belt” region (i.e., states of Ohio, Indiana, Illinois, Iowa, and 

Missouri)14. If these switchgrass yields were achieved, biomass availability could be increased 

to 2,750 dry tons/day and 3,250 dry tons/day respectively while maintaining the delivery 

distance required for the 2,000 dry tons/day plant under current yields. Alternatively, lower 

yields than those used in this analysis will result in larger collection areas, longer delivery 

distances, and negatively impact the scale and number of plants. 

A second important factor is the percent of land available around the plant for switchgrass and 

poplar trees production. If the land available in Illinois for dedicated energy crop production was 

doubled from the current estimate of eight percent to sixteen percent, this would result in a 

doubling of the potential CBTL plant capacity that could be supported at current yields and 

delivery distances, significantly impacting the size and number of plants. 

For corn stover, there are not expected to be dramatic deviations in the short or mid-term from 

the yield assumed in this analysis. However, the percentage of land available is a critical factor. 

Currently in Illinois, 31 percent of the land (11.2 million acres or about 17,500 square miles) is 

available for corn stover collection based on current levels of corn production as a percent of 

total Illinois land surface area (see Table 3). At this land availability percentage and the assumed 

yield of 1.98 dry tons/acre, corn stover has the potential to provide larger quantities of biomass 

and support larger plant sizes. For example, corn stover supply for a 2,500 dry ton/day plant 

requires about the same collection area needed to supply only 1,500 dry tons/day of biomass for 

the switchgrass and poplar tree cases. 
Table 6. Feedstock Production and Transport CO2 Emissions Estimates for 

Switchgrass, Poplar Trees, Corn Stover, and Coal 

Fossil Fuel 

Production or 

Biomass Farming 

(lbs/ton) Biomass Farming Fertilizer Use (lbs/ton) Biomass Farming Pesticide Use (lbs/ton) 

CO

2 credit from land 

use change/soil 

carbon (lbs/ton) 

Fossil Fuel or 

Biomass 

Ti

Feedstock 

Biomass 

required 

(tons/day) 

Delivery 

distance 

(miles) Nitrogen P2O5 K2O Herbicide Insecticide 

500 20 45.4 51.4 0.3 0.3 1.2 0.0 -106.8 10.

1,000 28 45.4 51.4 0.3 0.3 1.2 0.0 -106.8 14.1,500 34 45.4 51.4 0.3 0.3 1.2 0.0 -106.8 17.2,000 40 45.4 51.4 0.3 0.3 1.2 0.0 -106.8 20.

Switchgrass 2,500 44 45.4 51.4 0.3 0.3 1.2 0.0 -106.8 22.

500 19 48.1 3.4 0.4 0.5 1.0 0.1 -247.8 15.

1,000 28 48.1 3.4 0.4 0.5 1.0 0.1 -247.8 22.1,500 34 48.1 3.4 0.4 0.5 1.0 0.1 -247.8 27.2,000 39 48.1 3.4 0.4 0.5 1.0 0.1 -247.8 31.

Poplar trees 2,500 44 48.1 3.4 0.4 0.5 1.0 0.1 -247.8 36.

500 16 46.3 15.4 3.3 11.5 0.0 0.0 0.0 8.2 

1,000 22 46.3 15.4 3.3 11.5 0.0 0.0 0.0 11.1,500 27 46.3 15.4 3.3 11.5 0.0 0.0 0.0 13.2,000 31 46.3 15.4 3.3 11.5 0.0 0.0 0.0 15.

Corn stover 2,500 35 46.3 15.4 3.3 11.5 0.0 0.0 0.0 17.Coal* N/A 65 47.7 N/A N/A N/A N/A N/A N/A 3.9 

*Coal delivery assumes fifty percent transport by railcar and fifty percent transport by conveyor over a 65 mile distance. 
17 

3.4 Biomass Economics 

Biomass is similar to hydrocarbon resources in that higher price and improved technologies 

could make more resources economic. Currently, it is considered that dedicated biomass energy 

feedstocks such as switchgrass and poplars, and agricultural residues such as corn stover are 

technically “recoverable” but uneconomic at delivered prices less than $30/dry ton. However, as 

the price rises or technological advancements are made, resources may become available and 

economically attractive. 

3.4.1 Biomass Feedstock Costs 

There are two components to calculating the delivered biomass feedstock cost – the production 

cost and the transportation cost. Table 7 shows the range of feedstock production costs for 

switchgrass, poplars, and corn stover from various studies reviewed15,16,17. As shown in Table 7, 

the production cost for dedicated energy crops such as switchgrass and poplars cover a broad 

range. This is primarily due to lack of sufficient data since there are a limited number of field 

trials. Additionally, most of the studies are based on current agricultural technologies and 

practices and do not account for improved harvesting, collection, storage, pre-processing, or 

transportation methods. 

Table 7. Range of Feedstock Production Costs from Various Studies ($2006) 

Type of Biomass 

Production Cost 

Range 

($/dry ton) 

Production Cost 

Range 

($/MMBtu) (HHV)* 

Switchgrass 20-70 1.28-4.49 

Poplars 25-95 1.41-5.37 

Corn Stover 20-40 1.34-2.67 

*

GREET Model 1.7 default fuel specifications use the following higher heating 

values: poplars – 17,703,170 Btu/ton, switchgrass – 15,582,870 Btu/ton, and corn 

stover – 14,974,460 Btu/ton. These values were used to convert $/dry ton to 

$/MMBtu. 

Many factors influence the feedstock production cost, namely location and associated land costs, 

yields, labor, equipment and machinery, variable inputs such as fertilizers, seeds, and fuel, and 

other costs. A conservative estimate for switchgrass and poplar feedstock production costs 

would be in the $30/dry ton to $50/dry ton range. Recent data from two field tests of 

switchgrass – one by the University of Nebraska and the USDA Agricultural Research Service, 

and the other by Iowa State University – had production costs of $27/ton and $40/ton, 

respectively18. 
18 

For the present study, switchgrass is assumed to have a feedstock production cost of $40/dry ton 

($2.57/MMBtu (HHV)). Poplars are assumed to have a higher feedstock cost on a dry ton basis 

compared to switchgrass due to lower yields and higher farming costs. Therefore, they are 

assumed to have a feedstock production cost of $45/dry ton ($2.54/MMBtu (HHV)). The 

assumed feedstock production cost for corn stover is $30/dry ton ($2.00/MMBtu (HHV)). 

The second component of the delivered biomass feedstock cost is the transportation cost. 

Feedstock transportation costs typically account for $5-15/dry ton depending upon the hauling 

distance to the plant. Figure 1 shows the cost of corn stover delivery to the process facility and is 

based on data plotted from an ORNL study19. For this analysis, we assume that the equation in 

Figure 1 for corn stover is also applicable to assess the transportation costs for switchgrass and 

poplar. 

Figure 1. Transportation Cost for Corn Stover 

0.00

2.00

4.00

6.00

8.00

10.00

12.00

14.00

0 10 20 30 40 50 60 70 80

Hauling Distance (Miles)

Transport Cost ($/dry ton)

Transport Cost = 6.21 + 0.12 * Hauling Distance

Source: Perlack, Robert D., Turhollow, Anthony F., Oak Ridge National Laboratory (ORNL), 

Assessment of Options for the Collection, Handling, and Transport of Corn Stover, 

September 2002. Assumed this study was in $2001 and estimated on $2006 basis. 

Currently, DOE’s Biomass Program assesses the total delivered cost (production and transport) 

of biomass feedstock as $53/dry ton based on the 2004 state of technology. The program’s goal 

is to reduce the total delivered feedstock cost to $45/dry ton by 2010, $35/dry ton by 2015 and to 

less than $35/dry ton by 202020. For illustrative purposes, the total delivered cost assumed for 

each type of biomass versus the plant demand for biomass is shown in Figure 2. The delivered 

feedstock cost is calculated by adding the assumed production cost for each biomass type and 

then calculating the transportation cost based on the formula from Figure 1 for the hauling 

distances associated with the amount of biomass required to meet the CBTL facility demand. 
19 

The actual hauling distances for the biomass demand amounts in Figure 2 are calculated later in 

this section. 

Figure 2. Delivered Cost of Biomass as a Function of CBTL Plant Biomass Demand 

2.00

2.20

2.40

2.60

2.80

3.00

3.20

3.40

0 500 1,000 1,500 2,000 2,500 3,000

CBTL Plant Biomass Demand (dry ton/day)

Biomass Delivered Cost ($/MMBtu, HHV)

Switchgrass

Poplar Trees

Corn Stover 

Notes: 

Delivered Cost = Production Cost plus Transport Cost 

Assumptions: Switchgrass Production Cost = $40/dry ton; Poplar Trees Production Cost = $45/dry ton; Corn 

Stover Production Cost = $30/dry ton 

3.5 Feedstock Analyses 

The analysis of the coal and biomass assumed in the study are given in Tables 8 and 9, 

respectively. 
20 

Table 8. Illinois #6 Bituminous Coal Analysis 

Dry As Received 

C 71.72 63.75 

H 5.06 4.49 

O 7.75 6.89 

N 1.41 1.25 

S 2.82 2.51 

Cl 0.33 0.29 

Total 89.09 79.18 

Ash 10.91 9.70 

Moisture 12.5 11.11 

Total 112.5 100 

HHV (Btu/lb) 13,126 11,667 

Table 9. Biomass Analysis, Dry Basis 

Corn Stover Poplar Switchgrass 

C 44.50 51.7 42.6 

H 5.56 5.8 6.55 

O 43.31 41.75 41.98 

N 0.61 0 1.31 

S 0.01 0 0.01 

Cl 0.00 0.1 0.1 

Total 93.99 99.35 92.55 

Ash 6.01 0.65 7.45 

Moisture 0.0 0.0 0.0 

Total 100.00 100.00 100.00 

HHV (MMBtu/ton) 15.06 17.70 15.58 

HHV (Btu/lb) 7,528 8,855 7,787 
21 

4 Conceptual CBTL Plant Evaluation 

This section presents the technical details and performance results for a CBTL plant designed to 

produce ultra clean transportation fuels from syngas produced by the gasification of mixtures of 

coal and biomass. The CBTL plant is designed to capture approximately 88 percent of the total 

carbon input to the plant which is not contained in the finished fuel. The carbon dioxide is 

captured and compressed to 2,200 psi for subsequent sequestration. The advantage of this 

approach is that the carbon in the biomass can essentially be captured twice. Once from the 

growing process where carbon is taken from the biosphere into the plant material by 

photosynthesis and this carbon is captured and sequestered or reused/reformed so that it is not 

released back into the biosphere. No value was attached to the captured carbon in this study. 

The carbon dioxide could have a positive value is used for enhanced oil recovery (EOR) or a 

negative value if it had to be pumped into a saline aquifer or disposed of in other ways. 

In all, a total of five cases were analyzed in some detail in this study. The description of these 

cases is given in Table 10. This report considered three biomass types, hybrid poplar obtained 

from short rotation woody cropping (SRWC) plantations, switch grass and corn stover. A typical 

Illinois #6 bituminous coal was assumed in all cases. 

Table 10. Cases Analyzed in the Study 

1. A CBTL plant configuration feeding 10 wt. % (7 energy %) woody 

biomass (poplar) and 90% Illinois #6 coal 

2. A CBTL plant configuration feeding 15 wt. % (10 energy %) woody 

biomass and 85% Illinois #6 coal 

3. A CBTL plant configuration feeding 12 wt. % (7 energy %) switchgrass 

and 88% Illinois #6 coal 

4. A CBTL plant configuration feeding 12 wt. % (7 energy %) corn stover 

and 88% Illinois #6 coal 

5. A CTL coal only plant feeding 100% Illinois #6 coal 

All plants are sized to produce about 7500 barrels per day of finished product in the diesel/jet 

fuel boiling range. In addition to this distillate product, about 3500 Bbl/day of paraffinic naphtha 

(about 30 percent of the total liquid product) boiling below 300 F is produced. All hydrocarbons 

C4 or lighter are consumed in the process mostly for on-site electric power generation or for 

fired heaters for drying the feed materials and for the FT product upgrading section of the plant. 

Because all of the CBTL plants produce the same quantities of liquid products their land area 

requirements are about the same in all cases. Typically for this size CTL plant a land area of 
22 

approximately 150 acres is required. This includes key process units such as the gasification 

island, gas treatment, FT synthesis, and the power block as well as coal storage, transfer, and 

grinding. All offsites and utilities, exclusive of coal conveying to the plant, roads and water wells 

and piping are also accounted for. 

The total land area requirement of the facility including coal conveying, rail spur for product 

shipment, roads, water wells, and pipelines to the plant is expected to be about 200 acres. This 

assumes that large quantities of biomass will not be stored at the plant site. 

For a CTL plant the staffing is estimated to total about 190, we assume a similar number for a 

CBTL plant. This includes about 25 professionals and 115 operators, with the remainder being 

administrative, security, and maintenance labor. These CBTL plants will require varying 

quantities of coal depending on the ratio of coal to biomass used. The Illinois #6 coal input 

ranges from about 4,500 to 5,000 tons per day (TPD) for the plants analyzed. Because of the 

seasonal nature of biomass availability it would also be beneficial for a CBTL plant to have 

feedstock preparation facilities for a variety of different biomass feeds. 

4.1 CBTL Process Units 

Regardless of size, overall configuration, and feedstock, the CBTL conceptual plants analyzed in 

this study all have essentially the same process units in common. This is shown in the block 

flow diagram in Figure 3. The following describes the overall function of these individual 

process operations. 

4.1.1 Feedstock Processing and Drying 

The coal feedstock to the plant the coal must be reclaimed from the coal storage area, crushed 

and ground to a pulverized size distribution and dried to be suitable for feeding to the dry feed 

gasifier. 

In this study it is assumed that the biomass is delivered to the plant gate in a state that is almost 

ready for gasification. For the woody poplar it is assumed that the delivered chipped wood is 

further dried and reduced in size to about 1 mm to minimize feeding problems to the high 

pressure gasifier. The caveat here is that there has been very little experience in feeding wood to 

high pressure gasification systems. 

For the switch grass and corn stover it is assumed that these feedstocks are cut, field dried, and 

baled and then transported to the CBTL plant in rectangular bales in the size of approximately 

three feet by four feet by eight feet and weighing about 1,000 pounds. At the CBTL plant the 

biomass is sent to a de-baler where the bales are broken up into loose grass or loose cut stover. 

The grass is then reduced in size by grinding in a collision mill. To control dust a negative 

pressure is maintained on the mill and the ground grasses are collected in baghouse filters. It is 

assumed that the finely ground grass is conveyed by augers to a lock hopper system and then 

pneumatically conveyed into the gasifier.
Figure 3. Generic Block Flow Schematic of a CBTL Facility 

COS 

Hyd Selexol

H2 Recovery 

HgRemoval

AGT

SHIFT

CO2

Removal To CO2 Compression 

H2

BFW

ST Boiler

CW 

System Make-up Water

Stack Gas

Coal

Oxygen

Air ASU

To CO2 Compression

Gasification 

Quench

Feedstock 

Processing 

and Drying

Biomass

Biomass

Net Power Plant Power

~

Coal

Air

Slag

CO2 Injection Gas
24 

4.1.2 The Air Separation Unit 

The oxygen for coal gasification is provided by an air separation unit (ASU). This design uses a 

conventional cryogenic ASU for production of 95 percent purity oxygen for coal gasification and 

for nitrogen for inert gas uses. 

4.1.3 Gasification 

In all cases, a single stage, dry feed gasifier with quench was used. This would be similar in 

concept to a Shell or a Siemens gasifier. It is an oxygen-blown entrained gasifier where a 

membrane wall with pressurized water or steam is used to cool the gasifier inside surface so that 

a constantly forming liquid slag layer from melting of the coal mineral matter forms the 

refractory lining. This is different from the other gasifier systems like GE/Texaco and E-Gas 

where a brick refractory lining is used. It is assumed that the coal and the biomass are fed 

through separate systems so that if there is plugging problems in the biomass feed system the 

gasifier can still be operated on coal. Entrained flow gasifiers have advantages in that they 

produce no tars and the solid waste is an inert slag. Also the synthesis gas is almost entirely 

carbon monoxide and hydrogen with little methane. Therefore the syngas is an excellent feed for 

the Fischer-Tropsch process. Gasification takes place at slagging temperatures, typically about 

2,600 oF and 450 psia. The carbon conversion in this gasifier is typically about 98 to 99 percent. 

The reactants which are fed to the gasifier are converted in the flame section. The oxygen to 

coal ratio is adjusted to keep the gasification temperature high enough to melt the mineral matter 

that then flows vertically downward in parallel with the synthesis gas and leaves the gasifier 

through the bottom discharge section. Depending on the intended use of the synthesis gas, a 

direct contact water quench spray system or an indirect cooling heat recovery steam generator 

system can be installed at the gasifier exit. In this study, it is assumed that the direct water 

quench system is used. The quench removes hydrogen chloride, cyanide, ammonia, and 

particulate matter before further processing of the syngas. 

4.1.4 Gas Cooling, Raw Water Gas Shift, Carbonyl Sulfide Hydrolysis, and Mercury Removal 

The treatment scheme for the syngas produced in all cases is the same. The synthesis gas stream 

leaving the gasifier quench section is split, and a portion of the stream is sent to a raw water gas 

shift reactor to adjust the hydrogen to carbon monoxide molar ratio to that required for the FT 

reactors. The other portion of the synthesis gas is sent to a carbonyl sulfide hydrolysis unit 

where the COS is hydrolyzed to hydrogen sulfide. The two streams, having a molar hydrogen to 

carbon monoxide ratio of about 1.0, are then combined and both streams are then cooled in gas 

coolers before being sent to activated carbon filtration for removal of mercury. This cooled gas 

is then sent to a two-stage Acid Gas Removal (AGR) unit for removal of hydrogen sulfide and 

carbon dioxide. 

4.1.5 Acid Gas Removal 

The raw synthesis gas at about 400 psi from mercury removal is sent to an AGR unit. The AGR 

unit selected is used for the selective removal of hydrogen sulfide and for bulk removal of carbon 
25 

dioxide. The acid gas produced by this selective absorption is suitable for feeding to a Claustype unit for acid gas treatment (AGT) and recovery of elemental sulfur. 

4.1.6 Hydrogen Recovery 

A portion of the clean synthesis gas leaving the AGR unit is sent to the hydrogen recovery unit 

where sufficient hydrogen is separated and purified for use in the FT upgrading section of the 

plant. This hydrogen is required for hydrotreating and hydrocracking. The hydrogen separation 

system chosen for this study is a combination of membranes and Pressure Swing Adsorption 

(PSA). The membrane system is used to avoid a pressure drop in the main synthesis gas stream. 

The final purification of the hydrogen is achieved by sending the permeate stream from the 

membrane unit to a PSA unit. Here the hydrogen is produced at 99.99 percent purity. The 

hydrogen leaves the PSA at essentially feed pressure while the PSA purge gases leave at 

essentially atmospheric pressure. 

4.1.7 Sulfur Polishing 

Depending on operating conditions, the synthesis gas exiting the AGR unit still contains about 

1-2 ppmv H2S. This quantity of H2S is still too great to feed to the sulfur sensitive iron-based 

catalysts in the Fischer-Tropsch synthesis process. To remove this residual H2S, zinc oxide 

polishing reactors are used. The zinc oxide reacts with the hydrogen sulfide to form solid zinc 

sulfide. The product gas leaving the polishing reactor contains less than 0.03 ppmv H2S. 

4.1.8 Fischer-Tropsch Synthesis 

The clean synthesis gas containing less than 0.03 ppmv H2S from the sulfur polishing reactor is 

sent to the FT section of the plant. At the required product production rates used in this study, 

multiple trains of slurry phase reactors are needed to process the clean synthesis gas. Low 

temperature slurry phase FT reactors are used to maximize distillate production via wax 

cracking. Iron catalysts are used because they are cheaper than cobalt catalysts and have water 

gas shift capability. The synthesis gas is heated to about 450 oF and about 30 bar pressure and 

fed to the bottom of the FT reactors. The gas bubbles up through the reactors that are filled with 

liquid hydrocarbons in which are suspended fine iron-based catalyst particles. Reaction heat is 

removed via heat exchangers suspended in the reactors. The liquid medium enables rapid heat 

transfer to the heat exchangers which allows high synthesis gas conversions in a single pass 

through the reactor. Synthesis gas conversions of about 75 percent per pass can be obtained. 

Volatile overhead product swept from the reactors is separated in hot and cold separators to 

recover liquid hydrocarbons. Complete conversion of the synthesis gas to hydrocarbons does not 

occur in one pass through the FT reactors. In the simple recycle configuration used in all cases 

in this study, the effluent from the FT reactors is cooled to recover the portion constituting liquid 

fuels and the unconverted synthesis gas is recycled back to the FT reactors to increase the 

conversion to fuels. The carbon dioxide produced during the synthesis process is removed in the 

recycle loop. Heavy product that is non-volatile under reaction conditions is removed from the 

reactor and separated from the catalyst. Slurry phase reactor technology is under development 

by several companies and Sasol is utilizing these reactors at their Oryx Gas-to-Liquids (GTL) 

plant in Qatar. Slurry reactors have excellent heat transfer characteristics and allow high 
26 

conversions of synthesis gas per pass. However, there has not been much commercial 

experience with these reactors and there are issues relating to hydrodynamics and separation of 

the wax produced in the FT process from the fine catalyst. 

The raw FT products consisting of crude naphtha, crude middle distillate, and crude wax are sent 

directly to product upgrading. Fresh FT catalyst is activated in a separate catalyst activation 

reactor and then added on-line to the FT reactors to replace spent catalyst and to maintain overall 

activity. The catalyst replacement rate assumed in this study is 0.5 pounds per barrel of FT 

product. 

4.1.9 FT Product Upgrading 

The raw FT products need to be upgraded to produce naphtha and high quality diesel or jet fuel. 

The raw naphtha and middle distillate is sent to a hydrotreating unit to saturate the olefins that 

are produced in the FT process. The wax material is sent to a hydrocracker where the wax is 

converted into hydrocarbon gases, naphtha and diesel or jet fuel. 

4.1.10 Carbon Dioxide Removal in Recycle Loop 

The FT tail gas containing light hydrocarbon gases, unconverted hydrogen and carbon monoxide, 

some nitrogen, and carbon dioxide is split into two streams. One stream is recycled back to the 

FT unit to increase liquids yield and the other stream is sent to the power generation block. The 

recycled tail gas is processed in an amine unit to remove the carbon dioxide that is inert and 

takes up space in the slurry FT reactors. This is a standard MDEA unit with a single carbon 

dioxide absorber and solvent regenerator. An amine unit is used in this case because Selexol 

solvent would remove the light hydrocarbons from the FT tail gas. 

4.1.11 Power Generation Block 

The FT tail gas that is not recycled back to the FT reactors is sent to a boiler where high pressure 

steam is produced. This steam is used to drive a three stage steam turbine to generate the electric 

power for the plant. The steam turbine consists of a high pressure section (~1,800 psig, 

1,050 oF), an intermediate pressure section (~ 400 psig, 1,050 oF), and a low pressure section. All 

three sections are connected mechanically to an electric power generator by a common shaft. 

4.1.12 Balance of Plant (BOP) Units 

The conceptual design included materials and equipment for product storage (storage tanks are 

on site for storing naphtha and diesel fuels), water systems (systems are provided for cooling 

towers, to prepare boiler feed water (BFW), waste water treating, storm water handling, and fire 

water systems), electrical transformers and plant power distribution facilities and unit operations 

instrumentation and control systems. 

4.2 General Technical Plant Description of the Cases Analyzed 

Figure 3 shows a generic block flow diagram for the cases analyzed in this study. The CBTL 

plant produces about 10,000 barrels per day on an equivalent diesel basis of naphtha and diesel 
27 

and jet fuel. It uses Illinois #6 coal and various quantities of biomass as feed material. These are 

fed to two trains of single stage, entrained flow, dry feed gasifiers. The Fischer-Tropsch (FT) 

configuration used is a simple recycle system where the unconverted synthesis gas and light 

hydrocarbon gases are recycled back to the FT reactor after removal of the carbon dioxide 

produced during the synthesis. The clean syngas is sent to four FT synthesis reactor trains. Each 

FT reactor produces about 2,500 BPD of product. These smaller FT units are used because of 

transportation issues involved with larger units. In rural areas the feasibility of transporting large 

pieces of equipment may well be a limiting factor on size. If the plants are located on water 

ways like the Mississippi or Ohio rivers then it would be possible to bring in larger reactors. 

After feed preparation, the coal and biomass are fed to the two entrained gasifiers through 

separate feed systems where they are gasified with oxygen. The coal is assumed to be fed 

through a system of pressurized lock hoppers as is the usual practice with a Shell type gasifier. 

According to ECN6

 they believe that due to the high reactivity of the biomass particles, the wood 

could be fed as large a 1 mm particles. The advantages of this are that torrefaction of the wood 

is not necessary and this direct size reduction only consumes about 0.01-0.02 kWe/kWth wood 

of energy. ECN also assumes that screw feeders would be preferred over lock hoppers for the 

biomass. ECN does not believe that pneumatic feeding will be successful for this type of 

biomass feed. It is assumed in this study that the gasifier design has to be modified to include 

the two separate feed systems and dedicated biomass burners. However, the Stamet∗

 posimetric 

pump could well be an alternative possibility for co-feeding the woody biomass and the coal in a 

single feed system. Stamet received samples from NUON in the Netherlands that contained 

thirty percent wood sawdust and seventy percent by weight coal. This was the same feed 

material that was successfully gasified in the Shell gasifier at the NUON plant. According to 

Stamet21 they were able to successfully feed this mixed material up to pressures just under 500 

psi. In fact the material was easier to feed than an all coal feed. However, one advantage of 

having separate feed systems would be that, if the biomass system becomes inoperable for a time 

because of plugging, the gasifier can still continue to operate on coal only. For the switchgrass 

and corn stover the ground biomass is assumed to be pneumatically transported into the high 

pressure gasifier through a series of lock hoppers. If this proves not to be successful then a 

similar feeding system to the woody biomass (screw feeders) may be necessary. 

Carbon dioxide is used as the transport gas to move the pulverized coal into the lock hoppers and 

into the coal gasifier burners. Carbon dioxide is used because it can be recovered downstream in 

the AGR units. If nitrogen were used this would build up and dilute the stream making it 

difficult to achieve maximum carbon capture. Because the ash from biomass is rich in calcium 

oxide it is difficult to melt even at typical operating temperatures of entrained flow gasifiers. 

This fact may require the addition of fluxing agents to obtain acceptable slag properties. 

Addition of silica or clay could be used for this. 

Simulation runs using various mixtures of biomass and coal were used to identify the ratio of 

coal to biomass that will achieve the twenty percent carbon footprint reduction compared to 

petroleum. The raw synthesis gas is water quenched and then split so that some of the gas is sent 

 

∗

 GE Energy recently announced in a June 15, 2007 news release that it has acquired high-pressure feeder pump 

technology from Stamet Inc. 
28 

to a water gas shift reactor for adjustment of the carbon monoxide to hydrogen ratio needed for 

the FT process. The other stream is sent to carbonyl sulfide hydrolysis to convert the COS and 

HCN to hydrogen sulfide and ammonia. After further cooling and scrubbing the syngas is sent 

to an activated carbon reactor to remove mercury. The cooled gas is then sent to a two stage acid 

gas removal (AGR) system where hydrogen sulfide is removed in one stage and bulk carbon 

dioxide removal occurs in the second stage. 

A portion of the clean syngas stream is sent to hydrogen recovery for recovery of enough 

hydrogen for the hydrotreaters and hydrocracker in the raw product upgrading section. The 

syngas is then sent through a zinc oxide polishing reactor where the final sulfur level is reduced 

to around 0.03 ppmv to protect the sulfur sensitive FT catalyst. 

The clean syngas is then sent through four slurry phase FT reactors for the synthesis of the 

hydrocarbon liquids. The effluent from the FT reactors is cooled and the condensable 

hydrocarbons separated from the gases. The wax is withdrawn from the reactors and sent to the 

wax hydrocracker where cracking and isomerization occurs to produce diesel and jet fuels. The 

raw FT distillate products are hydrotreated to remove olefins and the liquid product is distilled 

into naphtha and distillate fractions. 

The unconverted synthesis gas together with the light hydrocarbon gases are recycled through an 

amine system to remove the carbon dioxide produced during the synthesis and sent back to the 

FT reactors to obtain greater conversion to liquid products. 

A portion of the FT tail gas containing the light hydrocarbon gases and unconverted hydrogen 

and carbon monoxide is sent to boiler where high pressure steam is generated to provide the 

power needed for the plant. Any excess power can be sold. 

Because these plants are configured to maximize capture of carbon dioxide, the carbon dioxide 

from both the AGR and the FT recycle are dehydrated and compressed to 2,200 psi for 

subsequent sequestration. The only carbon dioxide emitted to the atmosphere is from the 

boiler/superheater stack and the fired heaters in the upgrading section. Overall about 88 percent 

of the non fuel based carbon entering the plant can be captured. The other carbon is still 

contained in the FT hydrocarbon products that are shipped from the plant to the end user. 

4.3 Case Details of Woody Biomass CBTL Plant Meeting 20 Percent Lower 

Carbon Footprint Criteria than Petroleum Refining 

The Noblis in-house spreadsheet CTL computer simulation models were used to determine the 

ratio of woody biomass to coal needed to reduce the carbon footprint of the CBTL plant by 

twenty percent on a carbon basis compared to a petroleum refinery. Several cases were analyzed 

with varying quantities of poplar woody biomass added to the coal to determine the overall plant 

carbon balance. These overall plant carbon balances were then used to quantify the carbon 

associated with the production of FT diesel fuel. This was then compared to the carbon 

associated with the production of diesel fuel from a generic petroleum refinery. 
29 

Figure 4 shows a block flow diagram of a CBTL plant configuration that has the potential to 

reduce the carbon footprint to twenty percent below a petroleum refinery. In this plant Illinois 

#6 coal and chipped woody biomass are delivered to the plant gate. This plant consumes ninety 

weight percent coal on an as received basis and ten weight percent (seven energy percent) woody 

biomass poplar on an as-received basis. It is assumed that the coal has been delivered from a 

nearby mine and the woody biomass has been harvested from a short rotation woody cropping 

plantation where the poplar is grown, cut and chipped for transport to the plant. Although not 

specifically located, it can be assumed that the CBTL plant is in a rural agricultural area of 

Southern Illinois close to the coal. 

In the feedstock processing and drying section of the plant both the as received woody biomass 

and coal are dried to ten percent moisture. It is assumed that the delivered chipped woody 

biomass can be reduced further in size to an average particle size of about 1 mm as suggested by 

ECN for feeding to the pressurized entrained gasifier. 

Referring to Figure 4, 4,589 tons per day (TPD) of Illinois #6 coal and 510 TPD of woody 

biomass are delivered as received to the plant. The carbon contained in the coal is equivalent to 

2,926 TPD and the carbon in the woody biomass is equivalent to 224 TPD. Total carbon input to 

the plant is therefore 3,150 TPD. Assuming a plant capacity factor of 90 percent (328.5 days per 

year) and a carbon loss of 1 percent during feed stock processing, the total carbon input to the 

plant is 1,024,381 tons per year (TPY). 

The coal and biomass are co-gasified in dry feed, pressurized, entrained flow gasifiers with 95 

percent purity oxygen from the cryogenic air separation unit (ASU). Carbon dioxide injection 

gas is used to entrain the pulverized coal into the gasifier burners. As mentioned above, it is 

assumed that a separate feed system is used to deliver the woody biomass to the gasifier; a screw 

feeder is assumed to be suitable for this. The gasifier would be modified to have separate 

burners for the coal and the biomass and some fluxing material (silica or clay) is added to reduce 

the biomass ash melting temperature. 

A portion of the raw synthesis gas is shifted in the water gas shift reactors and the unshifted gas 

is sent to carbonyl sulfide hydrolysis. After cooling the combined gas stream is sent to activated 

carbon beds for mercury removal. The synthesis gas is then sent to the Selexol acid gas removal 

section of the plant where hydrogen sulfide and carbon dioxide are removed. The Selexol unit is 

assumed to remove about 95 percent of the carbon dioxide or 1,038 TPD of carbon. Some of this 

carbon dioxide is recycled to the gasifier for entrainment of the coal for feeding. The hydrogen 

sulfide stream is sent to the Acid Gas Treating (AGT) Claus plant where it is converted into 

elemental sulfur. Some of the cleaned synthesis gas is sent to the hydrogen recovery section 

where hydrogen is recovered from the gas for hydrotreating and hydrocracking the raw FT 

product. Let down from the hydrogen recovery unit produced fuel gas for various plant uses. 

The synthesis gas is then sent to a final zinc oxide polishing reactor where the total sulfur content 

of the gas is reduced to below 0.03 ppmv to protect the FT catalyst from sulfur poisoning. 

The clean synthesis gas is then fed to the FT reactors where the synthesis of the hydrocarbons 

takes place. Because of the rural location of the CBTL plant it was decided to use smaller 

reactors of about fifteen feet in diameter so that these could be more readily transported to the 
Figure 4. Block Flow Schematic of the 10 wt % (7 energy %) Woody Biomass Case 

COS 

Hyd Selexol

H2 Recovery 

HgRemoval

AGT

SHIFT

CO2

Removal To CO2 Compression (849 TPD Carbon) 

H2

BFW

Boiler ST 148.6 MW

CW 

System Make-up Water

Stack Gas

(222 TPD Carbon)

Coal

4,589 TPD AR

(2,926 Carbon)

Oxygen

Air ASU

(1,206 TPD Ca

To CO2 Compression

(829 TPD Carbon)

Gasification 

Quench

(2 Gasifier Trains)

Poplar510 TPD AR(224 Carbon)

Slag (31 TPD

Carbon)

10.1 MW Net Power 138.5 MW Plant Power

~

CO2 Injection Gas (209 TPD Carbon)

Biomass

Coal

Feedstock 

Processing 

and Drying

Air
31 

proposed plant site. This size of slurry iron catalyzed FT reactor can produce about 2,500 barrels 

per day (BPD) of liquid fuels. The FT effluent is cooled and the liquid hydrocarbon products are 

recovered. The wax product is withdrawn from the reactors and sent to the wax hydrocracker to 

maximize the production of diesel and jet fuels. The naphtha product constituting about thirty 

percent of the total liquids is hydrotreated. It is assumed that this naphtha can be transported 

from the CBTL plant and sold either as a zero sulfur gasoline blending stock to a local refinery 

or used as a petrochemical feed for ethylene production. 

A portion of the unconverted synthesis gas and the light hydrocarbon gases are recycled back to 

the FT reactors after passing through an amine unit for removal of the carbon dioxide formed 

during the synthesis process. In this case 849 TPD of carbon are removed in the carbon dioxide 

removal system. The FT tail gas not recycled is sent to a boiler for production of high pressure 

steam. This steam is used in a steam turbine to generate power for the CBTL plant. The carbon 

dioxide exiting the boiler and the upgrading section of the plant from use of fuel gas is 

equivalent to 235 TPD of carbon. This carbon is vented to the atmosphere. The diesel and 

naphtha liquid product contains 1,206 TPD of carbon in their hydrocarbon fuels. This carbon 

will remain until the fuels are combusted in end use applications after they are shipped from the 

CBTL plant. 

Table 11 shows the overall carbon balance around this CBTL plant in TPD on a carbon basis. 

The carbon captured in the plant is 88 percent of the non-fuel carbon. 

Table 11. CBTL Plant Carbon Balance for 10 wt% Biomass 

Input Carbon (TPD) (TPD) 

Coal 2926 

Woody Biomass 224 

Total 3150 

 

Output Carbon (TPD) (TPD) 

Selexol Carbon 829 

Amine Carbon 849 

Fuel Carbon 1206 

Stack Gas & Fuel Gas 235 

Slag Carbon 31 

Total 3150 
32 

114,767

58,557

Table 12 summarizes the inputs and outputs for the CBTL plant. From these the overall plant 

efficiency is estimated to be 51 percent. 

Table 12. Input/Output Summary for CBTL Plant with 

Woody Biomass/Coal Feed (10 wt% Biomass) 

 TPD MMBtu/day

Inputs AR Illinois Coal (11667 Btu/#) 4589 107,094 

 AR Woody Biomass (7524 Btu/#) 510 7,673 

 Totals 114,767 

 BPD MMBtu/day

Outputs Naphtha (5.023 MMBtu/bbl) 3,509 17,626 

 Diesel (5.345 MMBtu/bbl) 7,500 40,088 

 Power (10 MW) 843 

 Total Fuels 11,009 58,557 

 Overall Thermal Efficiency = = 51% (HHV) 

Table 13 summarizes the overall carbon debits and credits for the production and transportation 

of the biomass to the plant, the production and transport of the coal to the plant, and for the 

carbon conversions that occur within the plant. Referring to Table 13 the total carbon input to 

the plant is made up of the woody biomass and the coal and is 1,024,383 TPY of carbon. The 

carbon contained in the biomass is 72,871 TPY. Because this biomass has removed carbon from 

the biosphere during growth, this carbon can be credited to the system so that the effective input 

carbon is now 951,512 TPY. 

Table 13. Overall Carbon Credits and Debits 

Woody Biomass 10 wt% Case 

# Description Carbon (TPY)

1 Total Carbon In 1,024,383 

2 Biomass Carbon 72,871 

3 Biomass Production 1,222 

4 Biomass Transport 370 
33 

5 Coal Prod & Transportation 10,588 

6 Diesel Transportation 517 

7 Power Credit 7,965 

8 Sequestered 551,302 

9 Total Effective Carbon 404,942 

10 Diesel Effective Carbon 281,434 

However the production of the biomass requires several operations. These are: planting the 

poplars, harvesting, fertilizing, irrigating, pesticide treatment, and biomass transportation from 

the energy crop farm to the CBTL plant. Each of these operations requires the use of fossil fuels 

and hence there is a carbon penalty associated with each. This was discussed in an earlier 

section of the report and tabulated in Table 6. The production of the woody biomass from the 

GREET analysis shows a penalty of 53.5 pounds of carbon dioxide per ton of woody biomass. 

This does not include the carbon penalty associated with the transportation of the biomass to the 

plant and does not include any credit for land use change and/or carbon sequestered in the soil. 

For the 510 tons per day of woody biomass needed in the CBTL plant the carbon penalty for 

production is estimated to be 1,222 TPY. To transport this quantity of biomass from the field to 

the plant the average transportation distance is estimated to be about 22 miles. This is equivalent 

to 370 TPY of carbon as the transportation penalty. 

GREET estimates that the carbon penalty for mining and transporting one ton of coal would be 

51.5 pounds of carbon dioxide per ton. This is equivalent to 10,588 TPY for the CBTL coal feed 

rate of 4,589 TPD. 

The estimate for the carbon penalty of transporting the diesel product from the refinery to the 

point of delivery is estimated to be 517 TPY. 

The CBTL plant generates about 10 MW of electric power for sales. If this power were to be 

generated by using a natural gas combined cycle (NGCC) plant the carbon credit for that amount 

of power would be 7,965 TPY. Using NGCC as the reference to estimate a power credit is a very 

conservative approach. If the carbon emissions representing the average power generation mix 

were to be used, the carbon dioxide credit would be about 70 percent higher. However, this plant 

(like the others in this study) was designed to minimize export power and this carbon credit is 

very small compared to other credits and debits. Hence for this study, the reference used for 

carbon credit does not have a significantly impact the overall results and does not affect the 

conclusions of the study. 

Referring to Figure 4, the carbon captured comes from the Selexol unit and the amine unit in the 

FT recycle loop. The sum of these carbon values are 1,887 TPD. The recycled carbon dioxide 

from the Selexol unit used to feed the coal into the gasifier is about 209 TPD. Therefore the total 

captured carbon per year is 551,302 tons (see Table 13). 
34 

The overall total effective carbon generated in producing the FT liquid fuels (diesel and naphtha) 

is then given by adding items 1, 3, 4, 5, and 6 in Table 13. These represent the carbon penalties 

in the input feed, the production and transporting of the biomass to the plant, the production and 

transport of the coal to the CBTL plant, and the transport of the liquid products from the plant. 

The carbon credits are then subtracted from this total. These are the carbon contained in the 

biomass (2), the carbon captured during the conversion at the plant that is assumed to be 

sequestered (8), and the electric power credit for the power sales. This gives the total effective 

carbon for fuels production and utilization from this plant as 404,942 TPY. The portion of this 

carbon associated with the diesel portion of the FT product is assumed to be equal to the ratio of 

the weights of the naphtha and diesel product. This is about 0.695. The total effective carbon 

generated as a result of producing and using the diesel fuel is then 281,434 TPY. 

4.4 Comparison with a Reference Petroleum Refinery 

Determining the actual carbon emissions from a petroleum refinery is a complex issue. This is 

because of the large variations in crude quality feedstock to a refinery and because of the 

different refinery operations in different refineries that produce different final product slates. In 

this study we did not attempt to independently determine what these carbon emissions would be, 

instead we relied on emissions results obtained from the current GREET model for diesel fuel 

produced in a typical refinery. 

According to the estimate in the GREET model, the carbon dioxide associated with the 

production, refining and transportation of crude petroleum to low sulfur diesel is 191.7 pounds of 

carbon dioxide per barrel. Because of the difference in density, 7,500 BPD FT diesel is 

equivalent to about 6,896 BPD of petroleum diesel. Therefore the carbon associated with 

production, refining, and transporting this quantity of crude to diesel will be 59,285 TPY of 

carbon. The fuel carbon for this quantity of petroleum diesel is approximately equal to 292,540 

TPY of carbon. The total diesel effective carbon for the well-to-wheels petroleum crude to 

diesel use will then be the sum of these, or 351,828 TPY. 

Comparing this diesel effective carbon from petroleum with the diesel effective carbon 

calculated from the CBTL case described above where ten weight percent (seven energy percent) 

woody biomass is used, the ratio is 281,435/351,828 or eighty percent. Therefore co-processing 

ten weight percent of woody biomass with the coal at his generic CBTL plant would result in a 

reduction of twenty percent carbon dioxide compared to a petroleum refinery. 

However, because of the uncertainties surrounding the actual carbon emissions from a petroleum 

refinery and the difficulties in ascribing those emissions relating to the diesel portion of the 

output we also used a more conservative approach. A recent EPA Emissions Fact Sheet 3

attempted to quantify the greenhouse impacts of renewable and alternative fuels on a standard 

petroleum refinery. According to the EPA, the analysis presented in chart form in this fact sheet 

represents the best available information on the impact of these fuels on lifecycle greenhouse 

emissions. From this analysis it is estimated that a coal-to-liquids plant with carbon capture and 

storage would have just over three percent more greenhouse gas emissions than the petroleum 

based fuel that is displaced. 
35 

In order to use this assumption it was first necessary to simulate a coal-to-liquids plant and 

estimate the effective diesel carbon associated with the production of the diesel fuel from this 

plant. This simulated CTL plant was sized to produce the same quantity of diesel fuel as the ten 

weight percent biomass CBTL plant described above. The CTL plant also had the same overall 

configuration as the CBTL plant. A summary of the characteristics of this CTL plant is shown in 

Table 14 and a block flow diagram of the CTL plant is shown in Figure 5. It was estimated that 

the diesel effective carbon produced from the CTL plant would be 331,778 TPY. Using the EPA 

assumption that a carbon captured CTL plant emits just over three percent more carbon dioxide 

than a petroleum refinery; this would make the diesel effective carbon for the petroleum refinery 

321,800 TPY. 
Figure 5. Block Flow Schematic of the Coal Only CTL Plant 

COS 

Hyd Selexol

H2 Recovery 

HgRemoval

AGT

F

SHIFT

CO2

Removal To CO2 Compression (851 TPD Carbon) 

H2

BFW

Boiler ST 145.1 MW

CW 

System Make-up Water

Stack Gas

(224 TPD Carbon)

Coal

4,891 TPD 

(3,118 TPD 

Carbon) Oxygen

Air ASU

(1,206 TPD Carb

To CO2 Compression

(795 TPD Carbon)

Gasification 

Quench

(2 Gasifier Trains)

Slag (31 TPD 

Carbon)

9.7 MW Net Power 135.4 MW Plant Power

~

CO2 Injection Gas (200 TPD Carbon)

Air
37 

≡

≡

≡

≡

Table 14. Summary of CTL Only Plant 

Coal Input 4,891 TPD (AR) 114,132 MMBtu/day 

Outputs 

Naphtha 3,509 BPD 17,626 MMBtu/day 

Diesel 7,500 BPD 40,088 MMBtu/day 

Electric Power 9.7 MW 794 MMBtu/day 

 58,507 MMBtu/day 

 

Overall Thermal Efficiency = = 51.26% (HHV) 

Carbon Balance TPY 

Carbon In 1,014,022 

Coal Prod/Transport 11,283 

Product Transport 517 

Carbon Captured 540,761 

Power Credit 7,680 

Total Effective Carbon 477,380 

Diesel Effective Carbon 331,778 

Economic Summary for CTL Plant

Bare Erected Cost $694 MM 

Total Capital Cost $1,013 MM 

Capital Cost Per Daily Barrel $92,025 / DB 

RSP of Diesel $71.23 / bbl 

Crude Oil Equivalent Cost $54.80 / bbl 

The GREET refinery model estimates that the diesel effective carbon refinery emissions 

associated with the production of petroleum diesel would be as high as 351,828 TPY. The 

conceptual carbon captured CTL plant in this analysis actually produces about five percent less 

carbon dioxide than this unsequestered GREET refinery. The reason for this may be because the 

CTL plant analyzed in this study uses a high efficiency configuration that includes a dry feed 

entrained flow gasification system with a cold gas efficiency of about eighty percent and 

advanced slurry phase FT reactors. The basis of the GREET CTL data is unknown. 

Additional CBTL cases were then analyzed to determine the percent biomass needed to obtain 

the twenty percent carbon dioxide reduction goal if the diesel effective carbon for a refinery were 

to be 321,800 TPY instead of 351,828 TPY as was assumed in the ten weight percent woody 

114,132

58,507
38 

115,110

58,557

biomass case described above. For this assumption it was found that a woody biomass input of 

fifteen percent by weight (ten percent by energy) and 85 percent by weight of coal would give 

the desired goal of a twenty percent reduction in carbon dioxide compared to a petroleum 

refinery. 

Figure 6 shows a block flow schematic of the fifteen weight percent (ten energy percent) woody 

biomass case. Referring to Figure 6, 4,429 tons per day (TPD) of Illinois #6 coal and 782 TPD 

of woody biomass are delivered as received to the plant. The carbon contained in the coal is 

equivalent to 2,823 TPD and the carbon in the woody biomass is equivalent to 343 TPD. Total 

carbon input to the plant is therefore 3,166 TPD. Assuming a plant capacity factor of ninety 

percent (328.5 days per year) and a carbon loss of one percent during feed stock processing, the 

total carbon input to the plant is 1,029,935 tons per year (TPY). 

Table 15 is the input/output summary for this fifteen weight percent woody biomass case and 

Table 16 summarizes the overall carbon debits and credits for the production and transportation 

of the biomass to the plant, the production and transport of the coal to the plant, and for the 

carbon conversions that occur within the plant. The same methodology was used as for the 

previous ten weight percent (seven energy percent) woody biomass case. 

Table 15. Input/Output Summary for CBTL Plant With Woody 

Biomass/Coal Feed (15 wt% Biomass) 

TPD MMBtu/day 

Inputs AR Illinois Coal (11,667 Btu/lb) 4429 103,349 

 AR Woody Biomass (7,524 Btu/lb) 781.6 11,762 

 Totals 115,111 

 

BPD MMBtu/day 

Outputs Naphtha (5.023 MMBtu/bbl) 3,509 17,626 

 Diesel (5.345 MMBtu/bbl) 7,500 40,088 

 Power (10 MW) 843 

 Total Fuels 11,009 58,557 

 Overall Thermal Efficiency = = 50.87% (HHV) 
Figure 6. Block Flow Schematic of the 15 wt % (10 energy %) Woody Biomass Case 

COS 

Hyd Selexol

H2 Recovery 

HgRemoval

AGT

FT 

R

R

U

SHIFT

Amine 

CO2

Removal

To CO2 Compression

(848 TPD Carbon)

H2

BFW

Boiler ST 150 MW

CW 

System Make-up Water

Stack Gas

(220 TPD Carbon)

Coal

4,429 TPD AR 

(2,823 Carbon)

Oxygen

Air ASU

(1,206 TPD Carbo

To CO2 Compression

(848 TPD Carbon)

Gasification 

Quench

(2 Gasifier Trains)

Poplar

782 TPD AR 

(343 Carbon)

Slag (31 TPD

Carbon)

10 MW Net Power 140 MW Plant Power

~

Biomass

Coal

Feedstock 

Processing 

and Drying

CO2 Injection Gas (213 TPD Carbon)

Air
40 

Referring to Table 16 the total carbon input to the plant is made up of the woody biomass and the 

coal and is 1,029,936 TPY of carbon. The carbon contained in the biomass is 111,700 TPY. 

Because this biomass has removed carbon from the biosphere in growing this carbon can be 

credited to the system so that the effective input carbon is now 918,236 TPY. 

For the 782 tons per day of woody biomass needed in the CBTL plant the carbon penalty for 

production is estimated to be 1,873 TPY. To transport this quantity of biomass from the field to 

the plant the average transportation distance is estimated to be about 22 miles. This is equivalent 

to 703 TPY of carbon as the transportation penalty. 

GREET estimates that the carbon penalty for mining and transporting one ton of coal would be 

51.5 pounds of carbon dioxide per ton. This is equivalent to 10,217 TPY for the CBTL coal feed 

rate of 4,429 TPD. The estimate for the carbon penalty of transporting the diesel product from 

the refinery to the point of delivery is estimated to be 517 TPY. The power credit is 8,125 TPY. 

The total captured carbon per year is 556,932 tons (see Table 16). 

The overall total effective carbon generated in producing and using the FT liquid fuels (diesel 

and naphtha) is then given by adding items 1, 3, 4, 5, and 6 and subtracting 2, 7, and 8 in Table 

16. This gives the total effective carbon for fuels production from this plant as 366,489 TPY. 

Table 16. Overall Carbon Credits and Debits 15 wt% 

(10 energy %) Woody Biomass Case 

# Description Carbon (TPY) 

1 Total Carbon In 1,029,936 

2 Biomass Carbon 111,700 

3 Biomass Production 1,873 

4 Biomass Transport 703 

5 Coal Prod & Transportation 10,217 

6 Diesel Transportation 517 

7 Power Credit 8,125 

8 Sequestered 556,932 

9 Total Effective Carbon 366,489 

10 Diesel Effective Carbon 254,709 
41 

The portion of this carbon associated with the diesel portion of the FT product is assumed to be 

equal to the ratio of the weights of the naphtha and diesel product. This is about 0.695. The total 

effective carbon generated as a result of producing the diesel fuel is then 254,709 TPY. 

Comparing this diesel effective carbon from the CBTL plant to the petroleum refinery, that is 

254,709/321,800, the reduction is 79.15 percent. This plant configuration with fifteen weight 

percent (ten energy percent) woody biomass would therefore meet the requirement for a twenty 

percent smaller well-to-wheels carbon footprint than a petroleum refinery under the assumption 

that the CTL coal only plant emits just over three percent more carbon dioxide than a 

conventional petroleum refinery. 

4.5 Comparison of Petroleum Naphtha and FT Naphtha 

From the carbon balance data in Figure 4 and Table 13, and assuming that the CO2 LCA 

emissions are apportioned between diesel and naphtha in proportion to product mass fraction, 

then the CO2 emissions associated with FT naphtha are approximately 788 lbs CO2/bbl. This 

assumes that the carbon in the FT naphtha is eventually released to the atmosphere. Using the 

LCA data for petroleum naphtha in Table 2 and correcting for the density difference between FT 

naphtha and petroleum naphtha, the estimated CO2 emissions associated with petroleum-derived 

naphtha are estimated as 881 lbs CO2/bbl equivalent FT naphtha. The CO2 footprint of FT 

naphtha is thus approximately 90% of that for petroleum derived naphtha. This means that the 

estimate for the required biomass to attain a twenty percent reduction in CO2 emissions is 

somewhat conservative because the overall reduction in CO2 emissions for all CBTL products is 

slightly lower than the target goal. 

4.6 Sensitivity to FT Product Specifications (Diesel versus Jet Fuel) 

The FT reactor model used in this study is based on the Anderson-Schulz-Flory yield model for 

FT chemistry and tuned using data provided by developers of this technology for reactors 

designed to produce primarily diesel and naphtha. With additional hydrocracking and greater 

recycle, the principle products could be jet fuel (e.g., JP-8) and naphtha. However, there are no 

published reports that show the net yields for these products. It is estimated, based on the 

differences in boiling fractions and chemical composition between diesel and JP-8 that the yields 

would be about 60% JP-8 and 40% naphtha. There would be slight increases in the amount of 

hydrogen required and the amount of auxiliary power for the plant but it would not substantially 

increase the CO2 emissions from the CTL/CBTL plant. However, there would be a moderate 

decrease in the CO2 emissions associated with producing JP-8 from a conventional petroleum 

refinery since there is less energy used in producing this product compared to diesel. However, 

GREET does not currently estimate GHG emissions for petroleum-derived jet fuel (or kerosene) 

nor does it have a coal to jet fuel pathway. 

An approximate sensitivity analysis on the product specification was performed for the 15 wt% 

woody biomass case. The CO2 emissions associated with the production of JP-8 were estimated 

as 84% of the CO2 emissions for the production of diesel. This was based on the relative energy 

requirements for processing kerosene and diesel as reported by Wang22. With the JP-8 yield 
42 

adjusted to sixty percent, the estimated amount of biomass needed to produce synthetic JP-8 with 

a 20% less CO2 footprint than petroleum-derived JP-8 was 13.3 wt%. This is a decrease of 

approximately eleven relative percent over the estimate for diesel fuel. Because of the 

uncertainties in the estimated properties of synthetic JP-8, the actual amount of biomass needed 

may be closer to 15%. To be conservative, it is assumed in this study that the amount of biomass 

needed to produce jet fuel with a 20% reduction in CO2 emissions would be the same as that 

required for diesel. 

4.7 Economic Analysis for Woody Biomass Cases 

Table 17 summarizes the capital equipment costs for both the ten and fifteen weight percent 

woody biomass cases analyzed in this study. For convenience the capital costs are disaggregated 

into major plant sections. Costs for most of the process units in this CBTL plant were derived 

from a recent study commissioned by the Southern States Energy Board23. 

Table 17. Plant Equipment Costs for 15 wt% and 10 wt% 

Woody Biomass Cases 

15 wt% Woody 

Biomass 

10 wt% Woody 

Biomass 

Coal/Biomass Handling 21 21 

Coal & Biomass Prep and Feed 36 35 

Plant Water Systems 45 45 

Gasification 176 176 

Air Separation 74 74 

Syngas Cleaning & Shift 104 104 

CO2 Removal & Compression 28 28 

Ft Synthesis 106 106 

Boiler 38 38 

Steam Turbine 22 21 

Ash/Spent Sorbent Handling 27 27 

Accessory Electrical Plant 10 10 

Instrumentation & Control 12 12 

Site Improvements 12 12 

Buildings & Structures 12 12 

Bare Erected Cost (MM Dec 2005 $) 723 720 
43 

Coal and biomass handling and feeding refers to all equipment associated with the storage, 

reclaiming, conveying, crushing, preparation, drying, and sampling of coal and biomass feeds. 

The gasification section includes: the coal and biomass feed systems, the gasifiers, quench 

system, and slag removal. The air separation unit (ASU) is a standard cryogenic system for 

separation of oxygen and nitrogen. The syngas cleanup system contains several components that 

remove hydrogen sulfide, carbonyl sulfide, cyanide, ammonia, particulates, mercury, and carbon 

dioxide. It also includes acid gas treatment to remove hydrogen sulfide and bulk removal of 

carbon dioxide, sulfur recovery, hydrogen recovery and water gas shift. The carbon dioxide 

removal and compression includes the amine system for removal of the carbon dioxide in the FT 

recycle loop, dehydration, and compression of the carbon dioxide to 2,200 psi. 

The FT synthesis section includes the FT slurry phase synthesis reactors, catalyst activation, FT 

product upgrading that includes wax hydrocracking, hydrotreating and product distillation, and 

hydrocarbon recovery. The power block includes a boiler for production of high pressure steam 

and a steam turbine. The plant water systems include cooling water systems, boiler feedwater 

systems, waste water treatment and other plant water treatment systems. The balance of plant 

includes product tankage, the plant electrical and distribution system, instrumentation and 

controls, site improvements, and buildings and structures. 

Referring to Table 17 the bare erected cost of the ten weight percent (seven energy percent) 

woody biomass CBTL plant is estimated to be $720 million (MM) and for the fifteen weight 

percent (ten energy percent) woody biomass case $723 MM. 

Table 18 summarizes the additional capital requirements for the plants. 

Table 18. Additional Capital Costs for 15 wt% and 

10 wt% Woody Biomass Cases (Millions Dec 2005 $) 

15% Woody 

Biomass 

10% Woody 

Biomass 

Home Office 61 61 

Process Contingency 72 72 

Project Contingency 108 108 

License Fees 25 25 

Financing/Legal 25 25 

Non-Depreciable Capital 41 40 

Bare Erected Cost 723 720 

Total Capital Requirement 1,055 1,051 
44 

This includes home office costs (mostly front end engineering and design, i.e.: FEED, and 

detailed engineering design), process contingency and an overall project contingency of fifteen 

percent of the bare erected cost, license, financing and legal fees, and non-depreciable capital. A 

large process contingency was applied to the gasification plant (33 percent) because of the 

modifications considered to be necessary for co-feeding the biomass. An overall project 

contingency of fifteen percent has been applied to the bare erected cost to reflect the level of 

project definition for this non-site specific feasibility analysis. With the addition of these costs, 

the total capital requirement for the ten weight percent (seven energy percent) woody biomass 

CBTL plant is estimated to be $1,051 MM and $1,055 MM for the fifteen weight percent (ten 

energy percent) woody biomass case. 

Table 19 summarizes the annual operating costs for these CBTL cases. Fixed operating costs 

include royalties, labor and overhead, administrative labor, local taxes and insurance, and 

maintenance materials. Variable operating costs include coal and biomass feedstock costs 

considered to be $35/ton for the as-received Illinois and $70 per dry ton for the woody biomass, 

catalyst, water and chemicals, and other which is primarily solids disposal costs. The coal cost 

of $35 per ton is used because of the relative proximity of the CBTL plant to the coal mine and 

because it is a high sulfur coal. The by product credit refers to sales of recovered sulfur. Net 

annual operating costs are estimated to be $125 MM annually for the ten weight percent woody 

biomass case and $129 MM for the fifteen weight percent woody biomass case. There are no 

purchases of electricity because all power required is generated on site. The small quantities of 

natural gas required for start up are not included. 

Table 19. Annual Operating Costs for 15% and 

10% Woody Biomass Cases (Millions Dec 2005 $) 

Plant Configuration 

15 wt% Woody 

Biomass 

10 wt% Woody 

Biomass 

Royalties 4 4 

Coal 51 53 

Catalyst/Chemicals 8 8 

Labor/Overhead 20 20 

Administrative 3 3 

Local Tax & Insurance 20 20 

Maintenance & Materials 8 8 

Biomass 15 10 

Other 3 2 

Gross Annual Operating Cost 132 128 

By Product Credits 3 3 

Net Annual Operating Cost 129 125 
45 

Table 20 summarizes the economics for these cases. The capital cost of the ten weight percent 

woody biomass CBTL plant in terms of capital dollars per daily barrel (DB) of fuels produced is 

estimated to be about $95,486/DB and for the fifteen weight percent woody biomass case is 

$95,822/DB. The annual revenue required is the sum of the capital cost component, the 

operating and maintenance cost, and the feedstock costs. This amounts to $252 million for the 

ten weight percent biomass case and $257 million for the fifteen weight percent case. It is 

assumed that the value of the electric power is $35.6/MWH and that the naphtha is sold at 77% 

of the diesel price on a per barrel basis. The required selling price (RSP) of the FT diesel fuel is 

estimated to be about $75.19/bbl for the ten weight percent case and $76.58/bbl for the fifteen 

weight percent case. On a crude oil equivalent basis the cost is reduced to $57.84/bbl for the ten 

weight percent case and $58.91/bbl for the fifteen weight percent case. A factor of 1.3 is used to 

convert to crude oil equivalent based on an average price ratio of low sulfur CARB diesel to 

West Texas Intermediate crude oil. The RSPs were calculated using a discounted cash flow 

analysis with the economic assumptions shown in Table 21. For the ten weight percent woody 

biomass case a sensitivity case was analyzed to determine the impact on the cost of fuels of 

adding a cost of $4.60 per metric tonne for the transportation, sequestering, and monitoring of 

the captured carbon dioxide. The cost of $4.60 was estimated by NETL. When this cost is 

added the RSP on a COE basis increases from $57.84/barrel to $58.90/barrel; an increase of 1.8 

percent. It is reasonable to believe that the costs of all the other cases will increase by a similar 

amount when accounting for this additional cost. 

Table 20. Economic Summary for 15 wt% and 10 wt% Woody Biomass Cases 

15 wt% 10 wt% 

 Capital $/DB $ 95,822 $ 95,486 

 $/bbl Basis $/bbl Basis

 Capital ($MM/yr) 130.39 38.92 129.93 38.78 

 O&M ($MM/yr) 63.00 18.80 62.00 18.51 

 Biomass 15.00 4.48 9.80 2.93 

 Coal ($MM/yr) 51.00 15.22 53.00 15.82 

 Total ($MM/yr) 259.39 77.42 254.73 76.03 

 Power Credit ($MM/yr) 2.81 0.84 2.81 0.84 

 256.58 76.58 251.92 75.19 

 Annual Revenue Required 

($MM/yr) 

256.58 251.92 

 RSP Diesel ($/bbl) 76.58 75.19 

 EQ Diesel (bbl/yr) 3,350,372 3,350,372 

 RSP COE ($/bbl) 58.91 57.84 
46 

Table 21. Economic Assumptions for DCF Analyses 

Return on Equity (ROE) 15% 

Plant Life 25 years 

Depreciation (DDB) 16 years 

Debt 66% 

Debt Interest 8% 

Term 20 years 

General Inflation 3% 

Tax Rate 36% 

4.8 Case Details of Switchgrass and Corn Stover Biomass CBTL Plants 

Meeting 20 Percent Lower Carbon Footprint Criteria than Petroleum 

Refining 

The overall CBTL configuration for both the switchgrass and corn stover biomass cases are 

almost identical to the woody biomass configurations described in detail above. The only 

difference is in the front end processing of the biomass feeds. There is little if any actual 

experience in feeding these types of biomass feeds to high pressure entrained gasifiers. 

Therefore it is assumed in this study that successful feeding can be accomplished although it is 

expected that more R&D into this area will be needed. 

A schematic of the proposed switchgrass and corn stover processing system is shown in Figure 7. 

This system was used at the Alliant Energy project for direct injection of switchgrass at the 

Ottumwa Generating station in Iowa. It is assumed that the switchgrass and corn stover are 

delivered to the plant in three foot by four foot by eight foot bales weighing about 1,000 pounds. 

These are stored in a covered building at the plant site to keep the feed dry. For gasifying, the 

bales are taken from storage and conveyed to a de-baler where the bales are broken up into loose 

grass and biomass stover. The grinding of the biomass is assumed to be accomplished in a 

commercially available collision mill called the eliminator. In the eliminator the biomass is 

reduced in size to less than 1 inch minus by colliding the biomass particles together in the mill. 

As the rate of biomass feed is increased to the mill the average size of the particles is reduced. A 

negative pressure is maintained on the mill to minimize release of dust. The ground biomass is 

collected in baghouses. An enclosed tube conveyer transports the processed biomass to a surge 

bin where screw feeders or augers move the biomass into a pneumatic transport system and then 

into the gasifier feed system. Carbon dioxide can be used as the transport gas. 
47 

Figure 7. Schematic of Switchgrass and Corn Stover Prep System 

Simulations using the spreadsheet computer model identified a case where co-gasifying a mix of 

twelve weight percent (seven energy percent) switchgrass and 88 percent coal on an as-received 

basis would achieve the twenty percent carbon dioxide goal. That is, the carbon emissions are 

twenty percent lower than the GREET case petroleum refinery. Figure 8 shows a block flow 

schematic of this case. Apart from the front end biomass processing the CBTL plant 

configuration is identical to the previously described woody biomass cases. 

The analysis methodology is identical to the woody biomass cases and will not be described 

again only the results will be given. Table 22 shows the overall carbon credits and debits for this 

case. The overall efficiency for this case is calculated to be 50.8 percent on an HHV basis. 

Referring to Table 22 the total carbon input to the plant is made up of the switchgrass biomass 

and the coal and is 1,024,023 TPY of carbon. The carbon contained in the biomass is 73,610 

TPY. For the 625 tons per day of switchgrass needed in the CBTL plant the carbon penalty for 

production is estimated to be 2,761 TPY. To transport this quantity of biomass from the field to 

the plant the average transportation distance is estimated to be about 22 miles. This is equivalent 

to 503 TPY of carbon as the transportation penalty. The carbon penalty for mining and 

transporting the coal is 10,575 TPY for the CBTL coal feed rate of 4,584 TPD. 

The estimate for the carbon penalty of transporting the diesel product from the refinery to the 

point of delivery is estimated to be 517 TPY. The power credit is 8,298 TPY. The total captured 

carbon per year is 551,299 tons. 

The overall total effective carbon generated in producing and using the FT liquid fuels (diesel 

and naphtha) is then given by adding items 1, 3, 4, 5, and 6 and subtracting 2, 7, and 8 in Table 

22. This gives the total effective carbon for fuels production from this plant as 405,172 TPY. 

And the total effective carbon generated as a result of producing and using the diesel fuel is 

281,590 TPY. Comparing this diesel effective carbon from the CBTL plant to the petroleum 

refinery, that is 281,590/351,840, the reduction is eighty percent. This plant configuration with 

the twelve weight percent (seven energy percent) switchgrass would therefore meet the 

requirement for a twenty percent smaller carbon footprint than the GREET baseline petroleum 

refinery. 

Bales

De-Baler Eliminator

Transport Gas

Baghouse

Filter

Blower

Surge Bin

to Gasifier Feed

Bales

De-Baler Eliminator

Transport Gas

Baghouse

Filter

Blower

Surge Bin

to Gasifier Feed
Figure 8. Block Flow Schematic of the 12 wt % (7 energy %) Switchgrass Case 

COS 

Hyd Selexol

H2 Recovery 

HgRemoval

AGT

SHIFT

CO2

Removal To CO2 Compression (839 TPD Carbon) 

H2

BFW

Boiler ST 150.4 MW

CW 

System Make-up Water

Stack Gas

(219 TPD Carbon)

Coal

4,584 TPD AR 

(2,922 Carbon)

Oxygen

Air ASU

(1,206 TPD Car

To CO2 Compression

(840 TPD Carbon)

Gasification 

Quench

(2 Gasifier Trains)

Switchgrass

625 TPD AR

(226 Carbon)

Slag

(31 TPD 

Carbon)

10.5 MW Net Power 140 MW Plant Power

~

Biomass

Coal Feedstock 

Processing

CO2 Injection Gas (213 TPD Carbon)

Air
49 

Table 22. Overall Carbon Credits and Debits 

12 wt% Switchgrass Case 

# Description Carbon (TPY) 

1 Total Carbon In 1,024,023 

2 Biomass Carbon 73,610 

3 Biomass Production 2,671 

4 Biomass Transport 503 

5 Coal Prod & Transportation 10,575 

6 Diesel Transportation 517 

7 Power Credit 8,298 

8 Sequestered 551,299 

9 Total Effective Carbon 405,172 

10 Diesel Effective Carbon 281,594 

11 Overall Efficiency 50.8% (HHV) 

The case for corn stover is very similar to the switchgrass case. Figure 9 shows the block flow 

schematic for the twelve weight percent (seven energy percent) corn stover and 88 weight 

percent coal case on an as-received basis. Again it was determined from the computer 

simulation that this mix of corn stover biomass and coal would achieve the required twenty 

percent carbon footprint reduction compared to the GREET petroleum refinery case. 

Again the analysis methodology is identical to that of the switchgrass and woody biomass cases 

and will not be described again. Only the results will be given. Table 23 shows the overall 

carbon credits and debits for this case. The overall efficiency for this case is calculated to be 

50.9 percent on an HHV basis. 

Referring to Table 23 the total carbon input to the plant is made up of the corn stover and the 

coal and is 1,029,499 TPY of carbon. The carbon contained in the biomass is 77,060 TPY. For 

the 626 tons per day of corn stover needed in the CBTL plant the carbon penalty for production 

is estimated to be 2,063 TPY. To transport this quantity of biomass from the field to the plant 

the average transportation distance is estimated to be about 22 miles. This is equivalent to 

250 TPY of carbon as the transportation penalty. The carbon penalty for mining and transporting 

the coal is 10,598 TPY for the CBTL coal feed rate of 4,594 TPD.
Figure 9. Block Flow Schematic of the 12 wt % (7 energy %) Corn Stover Case 

COS 

Hyd Selexol

H2 Recovery 

HgRemoval

AGT

F

SHIFT

CO2

Removal

To CO2 Compression

(850 TPD Carbon)

H2

BFW

Boiler ST 151.3 MW

CW 

System Make-up Water

Stack Gas

(215 TPD Carbon)

Coal

4,594 TPD AR 

(2,923 Caron)

Oxygen

Air ASU

(1,206 TPD Carb

To CO2 Compression

(844 TPD Carbon)

Gasification 

Quench

(2 Gasifier Trains)

Corn Stover

626 TPD AR 

(237 Carbon)

Slag

(32 TPD 

Carbon)

140.2 MW Plant Power

~

11.1 MW Net Power

Coal Feedstock Processing

Biomass

Air

CO2 Injection Gas (214 TPD Carbon)
51

The estimate for the carbon penalty of transporting the diesel product from the refinery to 

the point of delivery is estimated to be 517 TPY. The power credit is 8,829 TPY. The 

total captured carbon per year in the CBTL plant is 556,403 tons. 

Table 23. Overall Carbon Credits and Debits for 

12 wt% Corn Stover Case 

# Description Carbon (TPY) 

1 Total Carbon In 1,029,499 

2 Biomass Carbon 77,060 

3 Biomass Production 2,063 

4 Biomass Transport 250 

5 Coal Prod & Transportation 10,598 

6 Diesel Transportation 517 

7 Power Credit 8,829 

8 Sequestered 556,403 

9 Total Effective Carbon 400,635 

10 Diesel Effective Carbon 278,441 

11 Overall Efficiency 50.9% (HHV) 

The overall total effective carbon generated in producing and using and using the FT 

liquid fuels (diesel and naphtha) is then given by adding items 1, 3, 4, 5, and 6 and 

subtracting 2, 7, and 8 in Table 23. This gives the total effective carbon for fuels 

production from this plant as 400,635 TPY. And the total effective carbon generated as a 

result of producing and using the diesel fuel is 278,440 TPY. 

Comparing this diesel effective carbon from the CBTL plant to the petroleum refinery, 

that is 278,440/351,840, the reduction is 79 percent. This plant configuration with the 

twelve weight percent (seven energy percent) corn stover would therefore meet the 

requirement for a twenty percent smaller carbon footprint than the GREET baseline 

petroleum refinery. 

The cases described above for the switchgrass and corn stover were compared to the 

GREET analysis petroleum refinery emissions of carbon dioxide. If they are compared to 

the more conservative refinery case where we assumed that the CTL coal only plant 

emitted just over three percent higher carbon dioxide than a petroleum refinery then the 

percentages of switchgrass required to achieve the twenty percent reduction goal would 
52

be increased from twelve weight percent (seven energy percent) to seventeen weight 

percent (ten energy percent) of the feed. Similarly for the corn stover case the percentage 

would be increased from twelve weight percent (seven energy percent) to eighteen weight 

percent (eleven energy percent) to attain the reduction goal. 

4.9 Economic Analysis for Switchgrass and Corn Stover Cases 

Table 24 summarizes the capital equipment costs for both the twelve weight percent 

switchgrass and twelve weight percent corn stover cases. As before, for convenience the 

capital costs are disaggregated into major plant sections. 

Referring to Table 24 the bare erected cost of the twelve weight percent switchgrass 

CBTL plant is estimated to be $725 million (MM) and for the twelve weight percent corn 

stover plant the estimate is also $725 MM. 

Table 24. Plant Equipment Costs for 12% Switchgrass 

and 12% Corn Stover Cases 

12 wt% 

Switchgrass 

12 wt% Corn 

Stover 

Coal/Biomass Handling 21 21 

Coal & Biomass Prep and Feed 36 36 

Plant Water Systems 45 45 

Gasification 176 176 

Air Separation 74 74 

Syngas Cleaning & Shift 104 104 

CO2 Removal & Compression 28 28 

Ft Synthesis 106 106 

Boiler 38 38 

Steam Turbine 22 22 

Ash/Spent Sorbent Handling 29 29 

Accessory Electrical Plant 10 10 

Instrumentation & Control 12 12 

Site Improvements 12 12 

Buildings & Structures 12 12 

Bare Erected Cost (MM Dec 2005 $) 725 725 
53

Table 25 summarizes the additional capital requirements for the plants. With the addition 

of these costs, the total capital requirement for both the twelve weight percent 

switchgrass CBTL plant and the twelve weight percent corn stover plant is $1,057 MM. 

Table 25. Additional Capital Costs for Switchgrass 

and Corn Stover Cases (MM Dec 2005 $) 

12% 

Switchgrass 

12% Corn 

Stover 

Home Office 61 61 

Process Contingency 73 73 

Project Contingency 108 108 

License Fees 25 25 

Financing/Legal 25 25 

Non-Depreciable Capital 40 40 

Bare Erected Cost 725 725 

Total Capital Requirement 1,057 1,057 

Table 26 summarizes the annual operating costs for these CBTL cases. Fixed operating 

costs include royalties, labor and overhead, administrative labor, local taxes and 

insurance, and maintenance materials. Variable operating costs include coal and biomass 

feedstock costs considered to be $35/ton for the Illinois #6 coal as received and $55 per 

dry ton for the switchgrass and $40 per ton dry for the corn stover, catalyst, water and 

chemicals, and other which is primarily solids disposal costs. The by product credit 

refers to sales of recovered sulfur. Net annual operating costs are estimated to be 

$124 MM annually for the twelve weight percent switchgrass case and $123 MM for the 

twelve weight percent corn stover case. Again there are no purchases of electricity 

because all power required is generated on site. The small quantities of natural gas 

required for start up are not included. 

Table 27 summarizes the economics for these cases. The capital cost of the twelve 

weight percent switchgrass CBTL plant in terms of capital dollars per daily barrel (DB) 

of fuels produced is estimated to be about $96,080/DB and for the twelve weight percent 

corn stover case is $95,990/DB. The required selling price (RSP) of the FT diesel fuel is 

estimated to be $75.31/bbl for the twelve weight percent switchgrass case and $74.78/bbl 

for the twelve weight percent corn stover case. On a crude oil equivalent basis the cost is 

reduced to $57.93/bbl for the twelve weight percent switchgrass case and $57.52/bbl for 

the twelve weight percent corn stover case. 
54

Table 26. Annual Operating Costs for Switchgrass and Corn Stover Cases 

Plant Configuration 12% Switchgrass 12% Corn Stover 

Royalties 4 4 

Coal 53 53 

Catalyst/Chemicals 8 8 

Labor/Overhead 20 20 

Administrative 3 3 

Local Tax & Insurance 19 20 

Maintenance & Materials 8 8 

Biomass 9 7 

Other 3 3 

Gross Annual Operating Cost 127 126 

By Product Credits 3 3 

Net Annual Operating Cost 124 123 

Table 27. Economic Summary for 12% Switchgrass and 12% Corn Stover Cases 

12% Switchgrass 12% Corn Stover 

Capital $/DB $ 96,080 $ 95,990 

 $/bbl Basis $/bbl Basis $/bbl Basis 

Capital ($MM/yr) 130.74 39.02 130.61 38.99 

O&M ($MM/yr) 62.00 18.51 63.00 18.80 

Biomass 9.40 2.81 7.00 2.09 

Coal ($MM/yr) 53.00 15.82 53.00 15.82 

Total ($MM/yr) 255.14 76.15 253.61 75.70 

Power Credit ($MM/yr) 2.81 0.84 3.09 0.92 

 252.33 75.31 250.53 74.78 

Annual Revenue Required 

($MM/yr) 252.33 250.53 

RSP Diesel ($/bbl) 75.31 74.78 

EQ Diesel (bbl/yr) 3,350,372 3,350,372 

RSP COE ($/bbl) 57.93 57.52 
55

5 Roadmap for 100,000 BPD Industry 

5.1 National Scope Resource Assessment 

On a national level, various assessments have been made regarding the amount of 

biomass that could be available for energy production. A joint study by DOE and the 

U.S. Department of Agriculture (USDA) in 200524 suggests that an annual biomass 

supply (including forestry and forest product residues, agriculture residues, urban wastes, 

and dedicated energy crops) of 1.3 billion dry tons is technically feasible. Approximately 

256 million dry tons of which is corn stover and 377 million dry tons is energy crops 

such as switchgrass and poplars. Additionally, a 1999 study by ORNL25 suggests that 

over 500 million dry tons of biomass could potentially be available in the United States at 

delivered prices between $55 and $65/dry ton ($2006), over 330 million of which is 

agricultural residues or energy crops (i.e., switchgrass, poplars, or other). 

More recently, the previously cited study by the University of Tennessee analyzed two 

scenarios where biomass plays a more significant role in the nation’s total energy future 

and results in 1-1.3 billion dry tons of biomass being available nationwide by 2025. 

Figure 10 shows one scenario of the quantity and location of crop residues (such as corn 

stover) and dedicated energy crops (such as switchgrass and poplar trees) that may be 

available throughout the nation between 2010 and 2025. 

In the near-term (~2015), the greatest concentration of crop residues and dedicated 

energy crops are located in Illinois, Iowa, and other Midwestern states. For near-term 

applications, it is more likely that the central United States would be the site of first 

adoption for CBTL plants because of greater availability of biomass and close proximity 

to Illinois coal basins. Longer term (~2025), crop residues and dedicated energy crops 

are widely available throughout the United States with the highest concentrations located 

in the central, eastern, and southeastern sections of the country. 

From these studies, one can conclude that a significant amount of biomass feedstock may 

exist and that, on a national level, the ability to produce 100,000 barrels/day of fuel 

should not be constrained by the availability of the biomass resource. 

5.2 Analysis of Plant Capacity Feasibility 

It is assumed that corn stover can be harvested wherever corn is grown and that there are 

no technical barriers to its collection. It is likely that if corn stover becomes a widely 

used energy feedstock, it will stimulate the development of harvesting machinery that 

will collect and bale the stover at the same time that the corn crop is harvested. Current 

practice requires a second collection pass over the corn fields. It is assumed that the limit 

for the amount of stover that can be economically collected is limited by the 

transportation costs. As the collection radius increases, the transportation cost increases 

but the plant size also increases (by the square of the collection radius) and there is a cost 

savings resulting from economies of scale. An economic limit for the collection radius 

would be the point at which the incremental transportation cost just equaled the cost 

savings from economies of scale. 
56

Figure 10.Distribution of Cellulosic Feedstock from Crop Residues 

and Dedicated Energy Crops 

Source: English, Burton C., et al., University of Tennessee Agricultural Economics, 25% 

Renewable Energy for the United States by 2025: Agricultural and Economic Impacts, 

November 2006. The figures shown are from the “All Energy” Scenario. 
57

An approximation for the economies of scale can be obtained from the data in the SSEB 

report23 which gives the estimated required selling price for diesel at three plant 

capacities. Using the data in Table 5, the transportation cost function in Figure 1, the 

conservative estimate of the amount of corn stover needed to meet the CO2 emissions 

target (18 wt % or 11 energy % corn stover), and the economies of scale function derived 

from the SSEB data, the economic optimum transportation distance was calculated as 106 

miles. The corresponding collection area could supply enough corn stover for a plant 

more than ten times larger than the reference plant. If a conservative transportation 

distance of 50 miles is used, based on the data in Table 5, this corresponds to a plant size 

of approximately 40,000 bpd diesel requiring approximately 5,000 tons/day of biomass 

and a collection area of 4,600 square miles for sustained operations. Up to three plants of 

this size could be built in Illinois. 

A similar analysis gives the economic optimum transportation distance as 109 miles and 

108 miles for woody biomass and switchgrass, respectively. Again using the 

conservative limit of 50 miles for the transportation distance provides enough woody 

biomass or switchgrass for a 30,000 bpd diesel plant. One plant of that capacity could be 

built in Illinois. 

5.3 Hypothetical Timelines for Target FT Diesel Production Level 

Table 28 presents a set of four hypothetical timelines for the build-up of a CBTL industry 

capable of supplying 100,000 BPD of FT diesel. Each timeline shows an initial period 

dedicated to permitting and the design of the facility followed by a construction period 

and then plant operation. During plant operation, a ramp-up scenario is applied to the 

first 1-2 years of operation allowing for shakedown. The cumulative diesel production 

rate for each timeline is plotted on Figure 11. 

The choice of biomass types is somewhat arbitrary but in each scenario the first plants are 

assumed to use corn stover as it is already available. The entry of CBTL plants that use 

switchgrass or woody biomass occurs in 2015 or later allowing sufficient time for 

cultivation and maturity of these crops. 

The first hypothetical timeline is conservative and assumes that one developer will enter 

the market and begin the permitting and design process in 2008. Two years are allotted 

for this phase followed by a four year construction period. The plant begins producing 

product in 2014 with a first year capacity factor of 50% of maximum and a second year 

capacity factor of 90% of maximum followed by sustained operations at the rated plant 

capacity. As with all of the timelines, corn stover was selected as the biomass for the 

first of a kind plant. 

After a full year of operation, work begins on the second generation plant of double the 

original capacity. The second generation plant is expected to require only one year for 

design and permitting and only three years for construction. It is assumed that a second 

developer will enter the market at the time that the first developer starts the second 

generation plant. This developer focuses on the two other biomass types. 
58

Ramp-up to 100,000 BPD - Conservative RD&D Path

Feed Developer BPD 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026

CS 1 7,500 3,750 6,750 7,500 7,500 7,500 7,500 7,500 7,500 7,500 7,500 7,500 7,500 7,500

CS 1 15,000 13,500 15,000 15,000 15,000 15,000 15,000 15,000 15,000

SG 2 15,000 7,500 13,500 15,000 15,000 15,000 15,000

SRWC 2 10,000 5,000 9,000 10,000 10,000 10,000 10,000

CS 1 25,000 22,500

SG 2 15,000 13,500

SRWC 2 20,000 18,000

3,750 6,750 7,500 7,500 7,500 21,000 22,500 35,000 45,000 47,500 47,500 47,500 101,500

Ramp-up to 100,000 BPD - Accelerated Scale-up

Feed Developer BPD 2008 2009 2010 2011 2012 2013 2,014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026

CS 1 7,500 3,750 6,750 7,500 7,500 7,500 7,500 7,500 7,500 7,500 7,500 7,500 7,500 7,500 7,500

CS 2 15,000 7,500 13,500 15,000 15,000 15,000 15,000 15,000 15,000 15,000 15,000 15,000 15,000 15,000 15,000

CS 3 15,000 7,500 13,500 15,000 15,000 15,000 15,000 15,000 15,000 15,000 15,000 15,000 15,000 15,000 15,000

SG 1 15,000 7,500 13,500 15,000 15,000 15,000 15,000 15,000 15,000 15,000 15,000

SRWC 2 30,000 15,000 27,000 30,000 30,000 30,000 30,000 30,000 30,000

CS 3 50,000 25,000 45,000 50,000 50,000 50,000 50,000 50,000

33,750 37,500 37,500 45,000 51,000 67,500 104,500 127,500 132,500 132,500 132,500 132,500 132,500

Ramp-up to 100,000 BPD - Accelerated Deployment

Feed Developer BPD 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026

CS 1 7,500 3,750 6,750 7,500 7,500 7,500 7,500 7,500 7,500 7,500 7,500 7,500 7,500 7,500

CS 2 7,500 3,750 6,750 7,500 7,500 7,500 7,500 7,500 7,500 7,500 7,500 7,500 7,500 7,500

CS 3 7,500 3,750 6,750 7,500 7,500 7,500 7,500 7,500 7,500 7,500 7,500 7,500 7,500 7,500

CS 1 15,000 7,500 13,500 15,000 15,000 15,000 15,000 15,000 15,000 15,000

CS 2 15,000 7,500 13,500 15,000 15,000 15,000 15,000 15,000 15,000 15,000

CS 3 22,500 11,250 20,250 22,500 22,500 22,500 22,500 22,500 22,500 22,500

SG 1 7,500 3,750 6,750 7,500 7,500 7,500 7,500 7,500 7,500 7,500

SG 2 7,500 3,750 6,750 7,500 7,500 7,500 7,500 7,500 7,500 7,500

SRWC 1 10,000 5,000 9,000 10,000 10,000 10,000 10,000 10,000 10,000 10,000

SRWC 2 10,000 5,000 9,000 10,000 10,000 10,000 10,000 10,000 10,000 10,000

11,250 20,250 22,500 22,500 66,250 101,250 110,000 110,000 110,000 110,000 110,000 110,000 110,000

Ramp-up to 100,000 BPD - Compressed Schedule

Feed Developer BPD 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026

CS 1 7,500 3,750 6,750 7,500 7,500 7,500 7,500 7,500 7,500 7,500 7,500 7,500 7,500 7,500 7,500 7,500

CS 1 7,500 3,750 6,750 7,500 7,500 7,500 7,500 7,500 7,500 7,500 7,500 7,500 7,500 7,500 7,500 7,500

CS 2 15,000 13,500 15,000 15,000 15,000 15,000 15,000 15,000 15,000 15,000 15,000 15,000 15,000

SG 2 15,000 13,500 15,000 15,000 15,000 15,000 15,000 15,000 15,000 15,000 15,000 15,000 15,000

SG 1 15,000 15,000 15,000 15,000 15,000 15,000 15,000 15,000 15,000 15,000 15,000 15,000

CS 2 22,500 20,250 22,500 22,500 22,500 22,500 22,500 22,500 22,500 22,500 22,500 22,500

SRWC 2 22,500 20,250 22,500 22,500 22,500 22,500 22,500 22,500 22,500 22,500 22,500 22,500

7,500 13,500 15,000 42,000 100,500 105,000 105,000 105,000 105,000 105,000 105,000 105,000 105,000 105,000 105,000

CS = Corn Stover

SG = Switchgrass

SRWC = Short Rotation Woody Crops

operation

Total

Total

Total

Total

design and permitting

construction

Table 28. Hypothetical Timelines for Ramp-Up for CBTL Industry 
59

Figure 11.Cumulative Diesel Production For Hypothetical CBTL Ramp-up Timelines 

0

20,000

40,000

60,000

80,000

100,000

120,000

140,000

2008 2010 2012 2014 2016 2018 2020 2022 2024 2026

Cumulative Diesel Production (BPD)

Conservative Path

Rapid Scale-up

Rapid Deployment

Rapid Development

Target

After these new plants have been in operation for a year, work begins on a set of third 

generation plants beginning in 2022 which come on-line in 2026. This scenario 

represents a conservative view to the build-up of the CBTL industry but it is a reasonable 

one barring a steep escalation in the crude oil price or the implementation of any 

incentive programs by the government. Under this scenario, the Air Force target goal of 

100,000 BPD of domestic synthetic fuels will not be met using CBTL technology until 

2026. 

In order to meet the target production rate of 100,000 BPD diesel, the ramp-up will have 

to be substantially accelerated and this will likely require one or more incentive programs 

from the government. The second and third timelines in Table 28 and Figure 11 

represent accelerated scenarios that come much closer to meeting the target production 

goal by 2016. In scenario 2, the movement to large scale plants occurs rapidly. Large 

capacity plants have significant economies of scale, at least up to the size of 80,000 BPD 

total product but still require extremely large capital investments. The likelihood of this 

scenario could be increased through loan guarantee incentives. In scenario 3, the 

deployment of the technology occurs rapidly. This can occur by having more developers 

enter the market or by having developers build a greater number of plants. The 

likelihood of this scenario could be increased through incentives that guarantee a floor 

price and/or market for the product diesel. Scenario 2 attains only 23% of the target 

production by 2016 but meets the target level a year earlier than scenario 3, in 2019. 
60

Scenario 3 attains 38% of the target production by 2016 and meets the target level by 

2020. 

In order to meet the target production level of 100,000 BPD diesel by 2016, an even more 

aggressive development timeline will be needed. This could be accomplished by either a 

combination of the accelerated deployment and accelerated scale-up scenarios or by 

compressing the design and construction timelines and elimination of the learning period 

between the completion of one plant and the beginning of construction of the next plant. 

Such a hypothetical scenario is shown as the fourth timeline in Table 28 and Figure 11. 

The likelihood of this scenario could be increased through time-limited diesel floor price 

guarantees. 
61

6 Conclusions and Recommendations 

The primary conclusion of this report is it is feasible to use the CBTL process to produce 

diesel fuel and meet the Air Force goal of production with 20% less CO2 emissions than 

equivalent fuel derived from a conventional petroleum refinery. Specifically, it was 

found that the CO2 emissions goal could be attained using a mixture containing 10-15 

wt% (7-10 energy %) woody biomass, or 12-18 wt% (7-10 energy %) switchgrass or 12-

18 wt% (7-11 energy %) corn stover. These three biomass types are advantageous in that 

their use does not directly affect the food supply. 

As part of this study, a scoping level economic analysis was performed for the coal-only 

plant and the CBTL plants. Based on the economic parameters used in this study, the 

required selling price (RSP) of the diesel product was estimated to be about $71/barrel for 

the coal-only plant. On a crude oil equivalent basis this would be about $55/bbl. For the 

woody biomass CBTL plants the RSP, on a crude oil equivalent basis was estimated to be 

$58-59/bbl or about seven percent higher than the coal-only case. For the corn stover and 

switchgrass plants the RSP on a crude oil equivalent basis was estimated to be about 

$58/bbl. 

Some sources, including GREET, indicate that dedicated energy crops including short 

rotation woody biomass and switchgrass could further reduce the CO2 footprint of a 

CBTL plant. If the full soil carbon credit can be realized, it would be possible to meet the 

CO2 reduction goal with as little as 5-10% by weight woody biomass. 

All three biomass types examined in this study showed nearly equivalent performance in 

the CBTL process. Regional land availability will be the most important determinant of 

which biomass type to use for a specific site. 

The reference plant studied was a 7,500 BPD diesel plant located in southern Illinois. 

This plant size was chosen somewhat arbitrarily based on a preliminary and highly 

approximate estimate for the amount of biomass that may be required. The report does 

not suggest that 7,500 BPD is either the maximum or optimum size for a CBTL plant. It 

was shown that larger plants of at least 30,000 BPD are feasible based on biomass 

resource availability. It is left as a recommendation for further work to perform a more 

detailed biomass resource and infrastructure assessment which would be needed to 

determine the maximum CBTL plant size that is technically feasible and to determine the 

optimum plant size for which economies of larger scale balance the increased cost of 

collecting larger quantities of biomass. 

Multiple scenarios were presented with timelines for the build up of a CBTL industry. In 

the most conservative scenario, the production goal of 100,000 BPD is not attained until 

2026. Incentives could stimulate the development of the industry. An aggressive 

hypothetical production ramp-up was prepared for the construction of seven CBTL 

facilities that would meet the DoD goal of obtaining 100,000 BPD of synthetic fuel by 

2016. The ramp-up assumes that the first two plants will be small 7,500 BPD facilities of 

the same design as the reference plant. These first plants will use corn stover since this 
62

type of biomass is currently available. It is assumed that over time, more plants will be 

constructed simultaneously; future plants will be larger in capacity (up to 22,500 BPD) 

and shake down periods for start-up will grow shorter. These later plants would use 

mixtures of switchgrass, corn stover, and woody biomass. Although specific plant 

locations were not proposed, a national biomass resource assessment has forecast that 

there will be abundant quantities of suitable biomass available in multiple geographic 

regions in the U.S. by 2016 and that the hypothetical ramp-up is feasible with respect to 

resource availability. 

The concept of using both coal and biomass together to produce high quality FT fuels via 

gasification should be advantageous to both coal and biomass to energy technologies. 

Co-processing biomass with coal can significantly reduce the carbon footprint of a CTL 

facility and the gasification route allows non-food product biomass like cellulose and 

lignin to be used for energy production. The use of coal with biomass significantly 

improves the economies of scale compared to a BTL facility and also dampens the impact 

of biomass supply fluctuations. 

However, it must be cautioned that there is very little actual field data available on 

pressurized gasification of biomass in entrained systems. Because of this, considerable 

RD&D will be needed to determine the pretreatment and optimum type of feed system 

needed to enable reliable feeding of these biomass types to high pressure gasification 

systems. Biomass gasification using high temperature and pressure entrained flow 

gasifiers would be preferable to lower temperature gasification systems to eliminate tar 

and methane formation from the biomass. Also the CBTL plants would be simpler and 

less costly if the same gasifier could be used to process both the coal and the biomass. 

Separate feed systems for coal and biomass may also be preferable so that, if there are 

problems with the biomass feed system, the gasifier can be kept operating using coal. 

Clearly RD&D should be undertaken to prove the viability of the concept of coal/biomass 

co-gasification in pressurized entrained flow of transport type gasifiers. Issues that 

should be investigated include the necessary preparation of the biomass, the optimum 

feeding techniques for biomass and coal to pressurized gasifiers, and the impact of the 

biomass on the gasification process. 

To demonstrate commercial feasibility of the CBTL concept it is recommended that 

commercial scale prototype plants be constructed. These should be of sufficient size to 

prove the commercial scale operation of the gasifiers and to produce sufficient fuels for 

testing. The plants should be used to investigate the performance on different coals and 

different biomass types. 

Because biomass availability is often seasonal for some crops it is recommended that any 

CBTL plant have processing equipment on site that is suitable for several biomass types. 

In that way when corn stover is available, after the corn harvest, the CBTL facility can 

utilize this crop predominately. When the switchgrass is available after harvesting the 

facility could use this feed. The woody biomass should be available most of the time 

depending on the cutting cycle. The coal would act as the flywheel to keep the plant 

operating at a fairly constant output. 
63

This study examined the feasibility of producing FT diesel with a CO2 footprint 20% less 

than low sulfur diesel from a conventional petroleum refinery and found that a small 

amount of biomass was sufficient. The reference refinery used in this study did not 

capture or sequester CO2. However, some of the non-combustion CO2 emissions arising 

from a petroleum refinery are due to processes that produce CO2 streams that could be 

captured and sequestered relatively easily. An example would be hydrogen production 

by the steam reforming of methane. It would be of interest to determine the CO2

footprint reduction attained by the cases presented in this study when compared to a 

partially sequestering petroleum refinery that captures and sequesters those CO2

emissions that are amenable to conventional CO2 capture technologies. It would be of 

further interest to determine the amount of biomass needed to produce FT diesel having a 

CO2 footprint 20% less than such a partially sequestering refinery. 

This study examined a limited range of CBTL processes all using less than twenty weight 

percent biomass. It would be worthwhile to conduct a more comprehensive study to 

quantify the CO2 emissions benefits of CBTL plants that use larger proportions of 

biomass, including the limiting case of using 100% biomass. 

It is also recommended that a more rigorous and systematic analysis be undertaken to 

determine the availability of biomass energy crops in other regions of the country and to 

determine the impact of CBTL plant size and biomass transportation distance on overall 

economics. 
64

Acronyms and Abbreviations 

ANL Argonne National Laboratory 

AF As Fed 

AGR Acid Gas Removal 

AGT Acid Gas Treatment 

AR As Received 

ASU Air Separation Unit 

bbl Barrel 

CW Cooling Water 

DB Daily Barrel 

BFW Boiler Feed Water 

BPD Barrels per Day 

BTL Biomass to Liquids 

CBTL Coal and Biomass to Liquids 

CTL Coal to Liquids 

DDB Double-Declining Balance 

DoD Department of Defense 

DOE Department of Energy 

ECN Energy research Centre of the Netherlands 

EOR Enhanced Oil Recovery 

EPA Environmental Protection Agency 

FEED Front End Engineering and Design 

FT Fischer-Tropsch 

GHG Greenhouse Gas 

GREET Greenhouse Gases, Regulated Emissions, and Energy Use in Transportation 

GTL Gas to Liquids 

HHV Higher Heating Value 

kWe kilowatt electric 

kWth kilowatt thermal 

lbs pounds 

LCA Life Cycle Analysis 

MDEA Methyl Diethanolamine 

MM Million 

MMBtu Million Btus 

MW Megawatt 

MWH Megawatt Hour 

NETL National Energy Technology Laboratory 

NGCC Natural Gas Combined Cycle 

NGL Natural Gas Liquids 

NRCS Natural Resources Conservation Service

ORNL Oak Ridge National Laboratory 

ppmv parts per million, volume basis 

PSA Pressure Swing Adsorption 
65

psi pounds per square inch 

psia pounds per square inch absolute 

R&D Research & Development 

RD&D Research, Development & Demonstration 

ROE Return on Equity 

RSP Required Selling Price 

SRWC Short Rotation Woody Crop 

SSEB Southern States Energy Board 

ST Steam Turbine 

TPD Ton per Day 

TPY Ton per Year 

TS&M Transportation, Sequestering, and Monitoring 

USDA United States Department of Agriculture 

wt % weight percent 
66 

Appendix A: GREET 1.7 Assumptions and Fuel 

Specifications 

These are the key assumptions that have been inputted, or used to calculate key 

assumptions that were inputted, into GREET Model 1.7. 

Assumptions for Coal Mining and Transportation to the Plant 

• 100 percent underground mining 

• fifty percent of coal transported by conveyor and fifty percent by rail 

• Coal transported a distance of 65 miles 

Assumptions for Petroleum Extraction and Transportation to Refinery

• Assumes conventional crude oil only. Oil sands-derived crude oil is not included. 

• Crude oil transportation is greater than 100 percent because multiple methods are 

sometimes used to deliver the crude oil to the refinery. For example, ocean tankers 

carrying crude oil reach the port, unload, and ship the crude oil through a pipeline to 

the refinery. 

• 57 percent transport by ocean tanker at a one-way distance of 5,080 miles 

• one percent barge transport at a one-way distance of 500 miles 

• 100 percent pipeline transport at a one-way distance of 750 miles 

Assumptions for Conventional Oil Refining to Diesel Fuel and Transport and 

Distribution of the Fuel to the Station

• Assumes 87 percent refining efficiency. 

• Diesel transportation (greater than 100 percent because multiple methods are 

sometimes used to transport low-sulfur diesel product) 

- 16 percent ocean tanker at a one-way distance of 1,450 miles 

- six percent barge at a one-way distance of 520 miles 

- 75 percent pipeline at a one-way distance of 400 miles 

- seven percent rail at a one-way distance of 800 miles 

• Diesel distribution 

- 100 percent truck delivery at a one-way distance of 30 miles 

Assumptions for Biomass Feedstock Production and Transport to the Plant 

• Moisture content of delivered biomass 

- Switchgrass = 15 percent 

- Poplar trees = 25 percent 

- Corn stover = 15 percent 
67 

• Biomass yields 

- Switchgrass = 6 dry tons/acre/year 

- Poplar trees = 5 dry tons/acre/year 

- Corn stover = 1.98 dry tons/acre/year 

• Corn stover collection rate = fifty percent 

• Corn yield = 166 bushels/acre 

• Delivery Truck Payloads/Capacity 

- Corn stover and switchgrass – 24 tons 

- Poplar trees – 17 tons 

Table A-1 provides the feedstock fuel specifications that were used in this analysis. 

Table A-1: Fuel Specifications 

Feedstock Heat content 

(HHV) 

density 

(lbs/gallon) 

% weight 

carbon 

Liquid Fuels Btu/gallon 

Crude oil 138,350 7.06 85.3 

Low-sulfur diesel fuel 138,490 7.06 87.1 

F-T diesel 127,347 6.21 ~85 

Solid fuels MMBtu/ton 

Illinois #6 bituminous coal 23.45 N/A 75.5 

Poplar trees 17.70 N/A 51.7 

Switchgrass 15.58 N/A 42.6 

Corn stover 14.97 N/A 44.5 
68 

7 References

 

1

 Remarks to the Air Force Energy Forum, Arlington, Virginia, March 8, 2007 by Secretary of the Air 

Force Michael Wynne. 

2

 Defense Energy Support Center (DESC) Fact Book for 2006. 

3

 David Andress & Associates, Inc. Soil Carbon Changes for Bioenergy Crops, September 18, 2002. 

4

 John Marano and Jared Ciferno, Life-Cycle Greenhouse Gas Emissions Inventory for Fischer-Tropsch 

Fuels, June 2001. 

5

 EPA Fact Sheet, EPA 420-F-07-035, Greenhouse Gas Impacts of Expanded Renewable and Alternative 

Fuel Use, April 2007. 

6

 A. van der Drift, H. Boerrigter, B. Coda, M.K. Cieplik, and K.Hemmes, ECN, Entrained Flow 

Gasification of Biomass, ECN-C-04-039, April 2004. 

7

 USDA Natural Resources Conservation Service (NRCS), Illinois NRCS News Release, NRI Data Shows 

Progress in Illinois Soil Conservation Efforts, January 30, 2007. 

8

 ORNL, A National Assessment of Promising Areas for Switchgrass, Hybrid Poplar, or Willow Energy 

Crop Production, February 1999. 

9

 USDA, Economic Impacts of Bioenergy Crop Production on U.S. Agriculture, February 2003. 

10 Kszos, Lynn and Walsh, Marie, ORNL; McLaughlin, Samuel B., University of Tennessee, Bioenergy 

from Switchgrass: Reducing Production Costs by Improving Yield and Optimizing Crop Management. 

11 Haq, Zia, Energy Information Administration, Biomass for Electricity Generation, 2002. 

12 ORNL, Assessment of Options for the Collection, Handling, and Transportation of Corn Stover, 

September 2002. 

13 National Renewable Energy Laboratory (NREL), Lifecycle Assessment of a Biomass Gasification 

Combined Cycle System, December 1997. 

14 ORNL, Assessment of Options for the Collection, Handling, and Transportation of Corn Stover, 

September 2002. 

15 English, Burton C., et al., University of Tennessee Agricultural Economics, 25% Renewable Energy for 

the United States by 2025: Agricultural and Economic Impacts, November 2006. 

16 Kszos, ORNL, Tools for Evaluating Economic Impacts of Yield and Management – BIOCOST and 

POLYSYS. 

17 Walsh, Marie, ORNL, Production Costs and Supply of Biomass by U.S. Region, October 1994. 

18 Collins, Keith, USDA, The New World of Biofuels: Implications for Agriculture and Energy, EIA 

Annual Energy Outlook Conference 2007, March 28, 2007. 

19 Perlack, Robert D., Turhollow, Anthony F., Oak Ridge National Laboratory (ORNL), Assessment of 

Options for the Collection, Handling, and Transport of Corn Stover, September 2002. 
69 

 20 DOE Office of the Biomass Program, Multi-Year Program Plan 2007-2012, August 2005. 

21 Tim Saunders, Stamet, Personnel Communication May 2007. 

22 Wang, M., Lee, H., and J. Molburg, Allocation of Energy Use in Petroleum Refineries to Petroleum 

Products, Int J LCA, vol 9, p34, 2004. 

23 SSEB, American Energy Security, Building a Bridge to Energy Independence and to a Sustainable 

Energy Future, Report July 2006. 

24 U.S. Department of Energy (DOE) and U.S. Department of Agriculture (USDA), Biomass as Feedstock 

for a Bioenergy and Bioproducts Industry: The Technical Feasibility of a Billion-Ton Annual Supply, 

April 2005. 

25 Oak Ridge National Laboratory (ORNL), University of Tennessee, Science Applications International 

Corporation (SAIC), Biomass Feedstock Availability in the United States: 1999 State Level Analysis, 

January 2000. 
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