### 1 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 h ave 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 simu late 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 rep ort 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 circulatin g 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 -S 2 

### 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 synthe sis 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 fossil based 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 al so 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 exp eriments 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 levera ged 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.

### 4 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 2 015 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 increas ed levels of alcohol. Feedstock 2007 SOT 2008 SOT 2009 Target 2010 Target 2011 Target 2012 Target 2019/2022 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 FY12

Report AD200812

### 5 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, balancin g 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 $0.21/gallon ethanol. As many of these costs are lowered, the feedsto ck costs ($/gal) become a larger fraction of the overall cost of ethanol.

### 6 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 CO 2 

### 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 rigoro us 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 thes e 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 2 010 to 2015 and 2022, the flue gas total flowrates decrease.

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### 8 2010 2015 2022 Sand/Ash Sulfur Wastewater CO2 vent Flue Gas Sand/Ash Sulfur Wastewater CO2 vent Flue Gas Sand/Ash Sulfur Wastewater CO2 vent Flue Gas Aspen Stream # 219 324 305 357 112 219 324 305 357 112 219 324 305 357 112 Mass flow (lb/hr) Nitrogen (N2) -- -- -- -- 631904.0 -- -- -- -- 569085 -- -- -- -- 531064 Oxygen (O2) -- -- -- -- 30004.0 -- -- -- -- 25559 -- -- -- -- 24203 Hydrogen (H2) -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- 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%.

Ene rgy Fl ow

(LHV Ba sis) Ma ter ial Fl owrate En er gy Fl ow (LHV Ba sis) Ma ter ial

Fl owr ate En er gy Fl ow (LHV

Ba sis) Ma ter ial Fl owra te (MMBTU/h r) (l b/hr) (MMBTU/hr ) (l b/hr) (MMBTU/hr ) (l b/hr) Ene rgy In le ts Wood Chip Feedstoc

k (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 Mg O 0 7 0 7 0 7 Wat er -174 154, 282 -1 90 168, 687 -1 33 118, 585 T ar Reformin g Catalyst 0 147 0 1 0 1 Other 0 4 0 4 0 3 Tot al 1098 1, 375, 746 1082 1, 305, 162 1139 1, 203,711 Ene rgy Outl ets Eth anol 489 38, 479 568 44, 670 620 48, 760 Hig her A lcohol Co-pr

oduct 99 7, 114 112 8, 047 122 8, 796 Bypr oduct Electricity 12 -- 0 -- 0 -- Cooling Tower

Evapor at ion 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 Compr essor Heat 267 -- 174 -- 178 -- Heat fr omA ir -cooled Exch angers 211 -- 212 -- 199 -- V ent s t o At mospher e 1 51, 153 1 49, 797 1 52, 912 Sand and Ash 16 2, 428 16 2,428 16 2,428 Wast ewa ter -2 1, 781 -1 1, 094 -1 1, 165 Other -40 36, 024 -4 1 37, 138 -27 24, 693 Tot al 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 referenc e 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 l osses 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.