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NREL Final Report and Deliverable 

Mixed Alcohols from Woody Biomass – 2010, 2015, 2022 

Andy Aden 

Updated Dec. 3, 2009 – include material flows in overall energy balance table 

September 23, 2009 

Under Interagency Agreement, NREL is supporting the EPA by conducting detailed technoeconomic 

analysis of several biomass conversion routes to renewable fuels. This supports EPA’s life cycle 

modeling efforts for the rulemaking activities associated with EISA legislation and the RFS II. Several key 

deliverables have been identified for 2010, 2015 and 2022 timeframes. These include: 

- Biochemical conversion of corn stover to ethanol 

- Thermochemical conversion of wood to mixed alcohols (high ethanol concentrations) 

- Thermochemical conversion of wood to Fischer-Tropsch diesel (2022 only) 

- Generation of oil from microalgae (2022 only) 

- Co-location of corn ethanol with cellulosic ethanol technology 

- Understanding the yield and process impacts that different biomass feedstocks can have on 

biochemical and thermochemical process technologies. 

Of particular interest from these modeling activities are: 

- Fuel yields (gallons per ton biomass) 

- Annual production (MM gal/yr) 

- Delivered feedstock cost assumptions 

- Capital costs 

- Overall Minimum Fuel Selling Prices (MFSP) to meet 10% Internal Rate of Return (IRR) 

- Emissions flowrates and component fractions 

- Overall Process Energy Balance 

The biochemical models were completed early in FY09 and were largely summarized in a report by Tao 

and Aden in November 2008. Subsequent results not included in that report include overall energy 

balances, which have been provided to EPA separately. This report is the next deliverable in the series, 

summarizing the mixed alcohol results for 2010, 2015, and 2022. Aspen Plus simulation software was 

used to simulate the process and the detailed economics were calculated using Excel spreadsheets. 

The general process diagram is depicted in the following figure. The models developed for the mixed 

alcohols scenarios are largely based on variations of the design report models described by Phillips, et.al. 

in 2007. (http://www.nrel.gov/docs/fy07osti/41168.pdf) This process, as designed, first gasifies woody 

biomass in a low-pressure indirectly-heated circulating fluidized bed steam gasification system. The 
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“dirty” syngas then undergoes cleanup and conditioning. This constitutes a tar reforming step that 

reforms organic “tars” into syngas using a nickel-based attrition-resistant reforming catalyst. Cleanup of 

the tars is required to avoid buildup and contamination in downstream equipment such as compressors. 

Acid gas scrubbing is also required to adjust the sulfur and carbon dioxide levels in the syngas to proper 

specifications for the mixed alcohols catalyst. The mixed alcohols catalyst is a Co-Mo-S2 catalyst in a 

fixed-bed reactor system, although future reactor designs are targeting slurry-phase systems for better 

heat mitigation and conversion. These reactions are largely exothermic. The liquid alcohols are 

condensed and distilled to separate the C1- and C2 alcohols from the C3 and higher alcohols. The C3+ 

alcohols are sold over refinery gates for a co-product credit. The alcohol is refined to fuel-grade, and the 

methanol is recycled back to the synthesis reactor to enhance the conversions to higher alcohols. Any 

unconverted syngas in this system is recycled back to the tar reformer. 

Two key design criteria were energy self-sufficiency and water minimization. To avoid purchasing fossilbased fuels (natural gas or coal), char was combusted to provide the heat for the endothermic 

gasification reactions. A slipstream of unrefined syngas was also combusted to provide all necessary 

energy for the process. An integrated steam system with turbines was also included in this design. 

Water minimization successfully lowered process water usage to less than 2 gallons per gallon ethanol. 
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Discounted cash flow economics were developed using the material and energy balance data from these 

models. Economics are in consistent year-$2007. Standard economic assumptions in these models 

include: 

- 10% IRR 

- 100% equity financing 

- 20-year plant life 

- 96% online time 

- IRS MACRS depreciation accounting system (not straight-line) 

- 39% Income Tax Rate 

- Nth plant assumptions that eliminate cost spikes from pioneer (first-of-a-kind) biorefineries 

NREL routinely uses these models to guide the thermochemical R&D activities at NREL. State of 

technology assessments are completed annually where data from actual bench and pilot-scale 

experiments are input into the models. In this fashion, researchers can quantify how technical progress 

can lead to overall cost reductions in the process, and measure progress towards technical and 

economic targets for the process. As such, NREL has leveraged these state of technology models and 

target models for this particular EPA project. A 3-year period is assumed for construction and start-up 

of these biorefineries. With this 3-year differential, NREL’s 2007 state of technology model was used for 

the 2010 scenario. Likewise, NREL’s 2012 target models were used for the EPA 2015 scenario. These 

models required very little additional modeling by NREL. However, NREL does not maintain outyear 

models beyond 2012. As such an ouryear model was created by NREL for the 2022 EPA scenario. 

Major process assumptions and model inputs are shown in the following table. A series of process 

improvements are being targeted that will reduce the overall process costs from the 2007 SOT levels to 

those shown in 2012. Additional research is envisioned that can then lead to further cost reductions 

towards the 2022 timeframe. These process improvements are targeted in several areas, including 

increased tar and methane conversion yields during tar reforming, and increased conversions and yields 

during mixed alcohol synthesis. Reductions in Feedstock cost come from targeted research at Idaho 

National Laboratory on feedstock handling, storage, and logistics. The feedstock costs for 2012 were 

held steady for 2019/2022 due to envisioned market dynamics. 
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Targeted Research for Mixed Alcohols Synthesis from Biomass 

The results of this economic modeling are shown in the following tables. Significant cost reduction 

occurs between 2010 and 2015, while additional but less significant cost reduction occurs between 2015 

and 2022. The ethanol yields range from 63 gal/ton in 2010 to 80 gal/ton in 2022. Capital costs for the 

upfront sections (feed handling, drying, gasification) do not change, but reductions between 2010 and 

2015 are seen in cleanup & conditioning (tar reforming, acid gas scrubbing) and fuel synthesis 

(compression, etc). Very little change is seen with the cooling water and other utilities. The alcohol 

separation costs actually increase because of the increased levels of alcohol. 

Feedstock 2007 SOT 2008 SOT 2009 Target 2010 Target 2011 Target 2012 Target

 Feedstock Cost ($/dry ton) $60. $60. $46.10 

Clean-up & Conditioning 

 Tar Reforming % methane 

conversion 20% 50% 50% 80% 80% 80% 

 tar Reforming % tar 

conversion 97% 97% 97% 99% 99% 99% 

Catalytic Fuel Synthesis 

 Pressure (Psia) 2000 2000 1500 1500 1500 1500 

 Overall CO conversion 40% 40% 40% 40% 50% 50% 

 CO selectivity to alcohols 

(CO2-free basis) 80% 80% 80 80 80 80 

 Catalyst Productivity(g/kg/hr) 300 300 300 450 450 600 

Model 

AD0810-

SOT2008-

FY07-

MatchOld 

AD0810-

SOT2008-

FY12 
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 2010 2015 2022 

Minimum Ethanol Selling Price (MESP) ($/gallon) $2.15 $1.33 $1.21 

Annual Ethanol Production (MM gal/yr) 48.8 56.7 61.9 

Annual total Alcohols Production (MM gal/yr) 57.5 66.6 72.7 

Ethanol yield 

(gal/dry 

ton) 63.2 73.4 80.1 

Total Alcohols Yield 

(gal/dry 

ton) 74.5 86.2 94.1 

 

Capital Costs ($MM) ($MM) ($MM) ($MM) 

 Feed Handling & Drying $25.2 $25.2 $25.2 

 Gasification $14.0 $14.0 $14.0 

 Tar Reforming & Quench $53.4 $38.6 $41.6 

 Acid Gas and Sulfur Removal $20.4 $14.6 $15.8 

 Alcohol Synthesis Compression $35.4 $18.5 $17.3 

 Other Synthesis Costs $6.1 $4.7 $5.1 

 Alcohol Separation and Purification $6.8 $7.5 $7.8 

 Steam System and Power Generation $19.2 $19.7 $18.2 

 Cooling Water and Other Utilities $4.2 $4.3 $3.9 

Total Installed Equipment Cost $184.7 $147.1 $148.9 

 Added Cost Factors $72.1 $57.5 $58.1 

total Project Investment $256.8 $204.6 $207.0 

Model 

AD0810-

SOT2008-

FY07-

MatchOld 

AD0810-

SOT2008-

FY12 

FY12-Design 

Report 

AD200812 

Mixed Alcohols Economic Results and Capital Costs 

Some reduction in feedstock cost occurs between 2010 and 2015. However, significant catalyst cost 

reductions are targeted in this timeframe. Olivine costs remain constant. “Other raw materials” 

includes makeup amine, boiler chemicals, makeup water, etc. and these remain relatively constant along 

with waste disposal costs. In 2015 and 2022, the power is balanced across the plant. However, in 2010, 

balancing the power demands of the plant to zero was not possible which results in a slight co-product 

credit for electricity. The co-product credit for the higher alcohols remains constant at $0.21/gallon 

ethanol. As many of these costs are lowered, the feedstock costs ($/gal) become a larger fraction of the 

overall cost of ethanol. 
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 2010 2015 2022 

Operating Costs ($MM/yr) ($/gal etoh) ($MM/yr) ($/gal etoh) ($MM/yr) ($/gal etoh)

 Feedstock $46.4 $0.95 $35.4 $0.63 $35.6 $0.58 

 Catalysts $7.6 $0.16 $0.2 $0.003 $0.2 $0.003 

 Olivine $0.5 $0.01 $0.5 $0.01 $0.5 $0.01 

 Other Raw Materials $0.4 $0.02 $0.4 $0.02 $0.3 $0.02 

 Waste Disposal $0.3 $0.01 $0.3 $0.01 $0.3 $0.01 

 Electricity -$1.8 -$0.04 $0.0 $0.00 $0.0 $0.00 

 Fixed Costs $14.8 $0.30 $12.7 $0.23 $12.8 $0.21 

 Co-product Credits -$10.4 -$0.21 -$11.8 -$0.21 -$12.9 -$0.21 

 Capital Depreciation $12.8 $0.26 $10.2 $0.18 $10.3 $0.17 

 Average Income Tax $9.6 $0.20 $7.9 $0.14 $7.9 $0.13 

 Average Return on 

Investment $23.9 $0.49 $19.0 $0.34 $19.3 $0.31 

Total $104.1 $2.15 $74.8 $1.33 $74.3 $1.21 

Model 

AD0810-SOT2008-FY07-

MatchOld AD0810-SOT2008-FY12 

FY12-Design Report 

AD200812 

Operating Costs 

There are several plant output (emissions) streams calculated by the Aspen Plus models. Solid emissions 

include sand and ash from the dry ash gasification and combustion systems, and sulfur from the LO-CAT 

unit, which recovers sulfur similar to a refinery Klaus unit. Liquid effluents include a fraction of the 

quench water that is sent to wastewater treatment. Vapor emissions include the flue gas from both 

char and syngas combustion, and CO2 emitted from the acid gas scrubbing section. Aspen Plus 

calculates the material flowrate for each of these streams to complete the overall balance, however, 

NREL feels that they serve more properly as emissions estimates and guidelines rather than rigorous 

emissions calculations for permitting or policy purposes. There are many emissions measurements of 

interest that the models currently don’t calculate, such as COD/BOD of wastewater, PM for vapor 

emissions, etc. Only when actual materials are produced and used in vendor testing applications can 

there be an expectation of better emissions data. 

The solid emissions (sand, ash, sulfur) remain relatively unchanged between all 3 models. The process 

improvements made between models do not seem to impact these solids emissions in any significant 

way. The amount of wastewater in 2015 and 2022 is greatly reduced from the 2010 values. The amount 

of CO2 vent from the acid-gas scrubber does not fluctuate drastically either. However, as the yields 

increase from 2010 to 2015 and 2022, the flue gas total flowrates decrease. 
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2010 2015 2022 

Sand/Ash Sulfur Wastewater vent Flue Gas Sand/As

CO2 

h Sulfur Wastewater vent Flue Gas Sand/As

CO2 

h Sulfur Wastewater vent Flue Gas 

CO2 

(lb/hr) Mass flow Aspen Stream # 219 324 305 357 112 219 324 305 357 112 219 324 305 357 112 

Nitrogen (N2) -- -- -- -- 631904.0 -- -- -- -- 569085 -- -- -- -- 531064 

(H2)  Hydrogen  Oxygen (O2) -- -- -- -- 30004.0 -- -- -- -- 25559 -- -- -- -- 24203 

-- -- -- -- -- -- -- -- -- -- -- -- -- -- -- 

 Argon (AR) -- -- -- -- 10774.0 -- -- -- -- 9703.0 -- -- -- -- 9054.0  Water 242.8 -- 1775.5 -- 265618.0 242.8 -- 1093.0 -- -- 242.8 -- 1163.3 -- 255110.0  CO -- -- -- -- -- -- -- -- -- 265917.0 -- -- -- -- --  CO2 -- -- 0.3 50851.0 203326.0 -- -- 0.2 49548.0 190983.0 -- -- 0.2 52642.0 178475.0  H2S -- -- 0.01 0.4 -- -- -- 0.01 0.4 -- -- -- 0.01 0.4 --  SO2 -- -- -- -- 91.7 -- -- -- -- 130.7 -- -- -- -- 113.5  NH3 -- -- 5.3 -- -- -- -- 1.2 -- -- -- -- 1.3 -- --  NO2 -- -- -- -- 203.3 -- -- -- -- 323.2 -- -- -- -- 268.2  CH4 -- -- -- -- -- -- -- -- -- -- -- -- -- -- --  Methanol -- -- -- -- -- -- -- -- -- -- -- -- -- -- --  Ethanol -- -- -- -- -- -- -- -- -- -- -- -- -- -- --  C3+ Alcohols -- -- -- -- -- -- -- -- -- -- -- -- -- -- --  Ash 1690.0 -- -- -- -- 1690.0 -- -- -- -- 1690.0 -- -- -- --  Sulfur (solid) -- 119.0 -- -- -- -- 99.6 -- -- -- -- 108.2 -- -- --  Olivine 495.2 -- -- -- -- 495.2 -- -- -- -- 495.2 -- -- -- -- Total 2,428 119 1,781 50,851 1,141,921 2,428 100 1,094 49,548 1,061,701 2,428 108 1,165 52,642 998,288 

Estimated Emissions (lb/hr) 
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Detailed energy balances were developed for each of the 3 models as well. These are shown in the 

following table. Much of the process is modeled using physical property packages within Aspen Plus 

that are more appropriate for gas-phase systems of this type. However, the liquid section is modeled 

using NRTL, a more appropriate system for liquid-phase processes such as the alcohol condensation and 

recovery sections. This change in physical property systems within the same model leads to slight 

variations in the overall energy calculations. However, as the summary balance information shows, the 

balance is accurate within 3%. 

Energy Flow (LHV 

Basis) Material Flowrate 

Energy Flow (LHV 

Basis)

Material 

Flowrate 

Energy Flow (LHV 

Basis) Material Flowrate 

(MMBTU/hr) (lb/hr) (MMBTU/hr) (lb/hr) (MMBTU/hr) (lb/hr)

Energy Inlets

 Wood Chip Feedstock 

(wet) 1270 367,437 1270 367,437 1270 367,437

 Air 3 853,331 2 768,488 2 717,140

 Olivine 0 538 0 538 0 538

 MgO 0 7 07 0 7

 Water -174 154,282 -190 168,687 -133 118,585

 Tar Reforming Catalyst 0 147 01 0 1

 Other 0 4 04 0 3

Total 1098 1,375,746 1082 1,305,162 1139 1,203,711

Energy Outlets

 Ethanol 489 38,479 568 44,670 620 48,760

 Higher Alcohol Co-product 99 7,114 112 8,047 122 8,796

 Byproduct Electricity 12 -- 0 -- 0 --

 Cooling Tower Evaporation 25 96,716 25 100,167 17 66,545

 Flue Gas 51 1,141,931 49 1,061,719 46 998,303

 Sulfur 1 119 0 100 0 108

 Compressor Heat 267 -- 174 -- 178 --

 Heat from Air-cooled 

Exchangers 211 -- 212 -- 199 --

 Vents to Atmosphere 1 51,153 1 49,797 1 52,912

 Sand and Ash 16 2,428 16 2,428 16 2,428

 Wastewater -2 1,781 -1 1,094 -1 1,165

 Other -40 36,024 -41 37,138 -27 24,693

Total 1129.9 1,375,745 1115 1,305,160 1171 1,203,710

2010 2015 2022

Overall Energy Balances 

Very few energy inputs exist beyond the feedstock itself because of the key design criterion of energy 

self-sufficiency and integration. Because the balance was done on a lower heating value (LHV) basis, 

and because of the temperature of the input water relative to the reference temperature, the energy 

flow is negative for fresh water input to the system. In 2010, less than 50% of the energy is captured in 

the 3 products: ethanol, higher alcohols, and electricity. The rest of the energy leaves the system in the 

form of heat losses from compression and from air-cooled exchangers. Some losses also occur from 

cooling water evaporation and windage. The energy efficiencies in 2015 and 2022 are higher than 2010, 

with over 50% of the feedstock energy captured in the products. Less heat is lost from the system under 

these scenarios. Between all 3 models, energy losses in the flue gas are relatively constant.