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

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

Process Design and Economics 

for the Conversion of 

Lignocellulosic Biomass to 

Hydrocarbon Fuels

Thermochemical Research Pathways 

with In Situ and Ex Situ Upgrading of 

Fast Pyrolysis Vapors

Abhijit Dutta, Asad Sahir, and Eric Tan

National Renewable Energy Laboratory

David Humbird

DWH Process Consulting

Lesley J. Snowden-Swan and Pimphan Meyer

Pacific Northwest National Laboratory

Jeff Ross, Danielle Sexton, Raymond Yap, 

and John Lukas 

Harris Group Inc.

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

Office of Energy Efficiency & Renewable Energy, operated by the Alliance 

for Sustainable Energy, LLC, under contract DE-AC36-08GO28308.

Pacific Northwest National Laboratory is operated by Battelle for the United 

States Department of Energy under contract DE-AC05-76RL01830.

Technical Report

NREL/TP-5100-62455

PNNL-23823

March 2015

Prepared for the U.S. Department of Energy Bioenergy Technologies Office
National Renewable Energy Laboratory

15013 Denver West Parkway

Golden, Colorado 80401

303-275-3000 • www.nrel.gov

Pacific Northwest National Laboratory

P.O. Box 999

Richland, WA 99352

1-888-375-7665 • www.pnl.gov

Process Design and Economics 

for the Conversion of 

Lignocellulosic Biomass to 

Hydrocarbon Fuels

Thermochemical Research Pathways 

with In Situ and Ex Situ Upgrading of 

Fast Pyrolysis Vapors

Abhijit Dutta, Asad Sahir, and Eric Tan

National Renewable Energy Laboratory

David Humbird

DWH Process Consulting

Lesley J. Snowden-Swan and Pimphan Meyer

Pacific Northwest National Laboratory

Jeff Ross, Danielle Sexton, Raymond Yap, 

and John Lukas 

Harris Group Inc.

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

Office of Energy Efficiency & Renewable Energy, operated by the Alliance 

for Sustainable Energy, LLC, under contract DE-AC36-08GO28308.

Pacific Northwest National Laboratory is operated by Battelle for the United 

States Department of Energy under contract DE-AC05-76RL01830.

Technical Report

NREL/TP-5100-62455

PNNL-23823

March 2015

Prepared for the U.S. Department of Energy Bioenergy Technologies Office
NOTICE

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

Neither the United States government nor any agency thereof, nor the Alliance for Sustainable Energy, LLC, nor 

Battelle Memorial Institute, nor any of their employees, makes any warranty, express or implied, or assumes any 

legal liability or responsibility for the accuracy, completeness, or usefulness of any information, apparatus, 

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herein to any specific commercial product, process, or service by trade name, trademark, manufacturer, or 

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iii

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Acknowledgements

We thank the reviewers of this report for their valuable comments. Reviewers are listed below by 

company/organization names. Note that review does not imply endorsement of the analysis 

presented, either by individuals or companies/organizations. Reviewer comments (unattributed) 

on the draft version of the report are presented in Appendix J along with authors’ responses.

National Renewable Energy Laboratory Bob Baldwin, Mary Biddy, Danny Carpenter, 

Mark Davis, Kristiina Iisa, Calvin Mukarakate, 

Joshua Schaidle, Stefan Czernik (retired)

Pacific Northwest National Laboratory Doug Elliott, Sue Jones, Mariefel Olarte, Alan 

Zacher

Idaho National Laboratory Jake Jacobson

Argonne National Laboratory Felix Adom, Jennifer Dunn

BP Peter Metelski

Colorado School of Mines Robert Braun

Cool Planet Energy Systems Daren Daugaard

Global Energy Management Institute

(University of Houston) and AOTA

Energy Consultants 

Steve Arbogast, Dave Paynter, Jim Wykowski

Iowa State University Mark Wright

Johnson Matthey Raymond Hadden, Andrew Heavers, Mike 

Watson

Pall Corporation Mark Hurwitz

RTI International David Dayton

University of Maine William DeSisto

VTT Technical Research Centre of Finland Yrjo Solantausta, Kristin Onarheim

We thank the U.S. Department of Energy’s Bioenergy Technologies Office for funding and 

supporting this work, and the Idaho National Laboratory for providing feedstock logistics 

information. Thanks to Anna Trendewicz (Colorado School of Mines) for fluidization 

calculations, to Ryan Davis for discussions about hydrotreating and Michael Talmadge for 

thermochemical analysis task management (both from the National Renewable Energy 

Laboratory), and Kathy Cisar for communications support.
iv

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Acronyms

ACCE Aspen Capital Cost Estimator

ANL Argonne National Laboratory

bbl barrel

BETO Bioenergy Technologies 

Office

BFW boiler feed water

CE Chemical Engineering

CFB circulating fluidized bed

CFP catalytic fast pyrolysis

CH4 methane

CO carbon monoxide

CO2 carbon dioxide

COD chemical oxygen demand

DCFROR discounted cash flow rate of 

return

DOE U.S. Department of Energy

EPA U.S. Environmental Protection 

Agency

EPC engineering, procurement, and 

construction

FCC fluid catalytic cracking

FCI fixed capital investment

FOB freight on board

FP fast pyrolysis

GGE gallon gasoline equivalent 

GHG greenhouse gas

GJ gigajoule

GREET Greenhouse Gases, Regulated 

Emissions, and Energy Use in 

Transportation Model

H2S hydrogen sulfide

HDS hydrodesulfurization

HGF hot gas filter

HHV higher heating value

HP high pressure

HT hydrotreating

INL Idaho National Laboratory

IRR internal rate of return

ISBL inside battery limits (of the 

plant)

kWh kilowatt hour

LCA life-cycle assessment

LCI U.S. Life Cycle Inventory

LHV lower heating value

LHSV liquid hourly space velocity

LP low pressure

MACRS IRS Modified Accelerated 

Cost Recovery System

MFSP minimum fuel selling price

MJ megajoule

MM million (e.g., MMBtu or 

$__MM)

MOC material of construction

NG natural gas

NO2 nitrogen dioxide

NREL National Renewable Energy 

Laboratory

OSBL outside battery limits (of the 

plant)

PFD process flow diagram

PNNL Pacific Northwest National 

Laboratory

PSA pressure swing adsorption

RO reverse osmosis

RTO regenerative thermal oxidizer

scf standard cubic feet

SMR steam methane reformer

SO2 sulfur dioxide

TCI total capital investment

TDC total direct cost

TIC total installed cost

TEA techno-economic analysis

TPEC total purchased equipment 

costs

VPU vapor-phase upgrading

WGS water gas shift

WHSV weight hourly space velocity

WW wastewater

WWT wastewater treatment

ZnO zinc oxide
v

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Executive Summary

This report was developed as part of the U.S. Department of Energy’s Bioenergy Technologies 

Office’s efforts to enable the development of technologies for the production of infrastructurecompatible, cost-competitive liquid hydrocarbon fuels from biomass. Specifically, this report 

details two conceptual designs based on projected product yields and quality improvements via

catalyst development and process integration. It is expected that these research improvements 

will be made within the 2022 timeframe. The two conversion pathways detailed are (1) in situ

and (2) ex situ upgrading of vapors produced from the fast pyrolysis of biomass. While the base 

case conceptual designs and underlying assumptions outline performance metrics for feasibility, 

it should be noted that these are only two of many other possibilities in this area of research. 

Other promising process design options emerging from the research will be considered for future 

techno-economic analysis.

Catalyst research and development, and the testing of catalysts in process-relevant equipment are 

the most important areas for the success of these two pathways. Some of the key objectives of 

catalyst development include the enabling of: (1) reduced coke and coke precursor formation, (2) 

reduced non-condensable species formation, (3) efficient hydrogen utilization, which ties into 

reduced aromatics in the product, reduced coke formation, and greater hydrodeoxygenation to 

allow higher carbon efficiency, (4) coupling (molecular combination) reactions to reduce the loss 

of smaller molecules to the gas phase and also enhance the formation of distillate range products, 

(5) attrition resistance of fluidizable catalysts, (6) catalyst maintenance and regeneration in

fluidized and fixed bed configurations, and (7) catalyst longevity. It is expected that these 

developments will result in significant vapor quality improvements with reduced reactivity; upon 

condensation, the recovered organic phase can be hydroprocessed to fuel blendstocks at 

relatively less severe conditions compared to raw bio-oil from non-catalytic fast pyrolysis.

The conceptual process models for the two processes were developed using Aspen Plus. Based 

on the process models, nth-plant process economics (in 2011 dollars) projecting minimum fuel 

selling prices (MFSP) were developed in Microsoft Excel using discounted cash flow rate of 

return analysis. Economic assumptions include a 30-year plant life, 40% equity financing with a 

10% internal rate of return, and the remaining 60% debt financed at 8% interest paid back over 

10 years. Impacts of deviations from these financial assumptions are captured through sensitivity 

studies. Capital cost estimates for some of the key equipment were provided by Harris Group 

through vendor quotes or previously developed mechanical design tools. The plant size was 

assumed to be 2,000 dry metric tonnes per day using woody biomass feedstock cost. The 

feedstock is delivered with 10 wt % moisture, low ash (<1%), and nominal size of 2 mm to the 

throat of the reactor for $80/dry short ton per recent Idaho National Laboratory feedstock 

logistics design projections.

It should be noted that the base case processes assume a pressure of 120 psia (~8 bar), with 

hydrogen-enrichment of the fluidizing gases during fast pyrolysis and vapor upgrading. While 

this is assumed in the base cases, the ultimate decision about the operating pressure and 

fluidizing gas composition will be made based on their impacts on the economics. These impacts

will be further quantified based on future experimental results. Table ES-1 shows key process 

conversion assumptions and metrics for both the in situ and ex situ upgrading cases, while the 
vi

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following Table ES-2 and Table ES-3 outline the economic summaries for the in situ and ex situ

cases, respectively.

Both the in situ and ex situ conceptual designs, using the underlying assumptions, project MFSPs 

of less than $3.5/gallon gasoline equivalent (GGE) in 2022. The performance assumptions for 

the ex situ process were more aggressive with higher distillate (diesel-range) products. This was 

based on an assumption that more favorable reaction chemistry (such as hydrogenation, 

hydrodeoxygenation and coupling) can be made possible in a separate reactor where, unlike in an 

in situ upgrading reactor, one does not have to deal with catalyst mixing with biomass, char, and 

mineral matter/ash, which pose challenges to catalyst performance and maintenance. Natural gas 

was used for hydrogen production in the process model, but only when off-gases from the 

process were not sufficient to meet the needs; natural gas consumption is insignificant in both the 

in situ and ex situ 2022 base cases. Heat produced from the burning of char, coke, and off-gases 

is converted to electricity, with surplus electricity sold to the grid allowing a small reduction of 

less than 5¢/GGE in the MFSP.

There remain significant uncertainties in some of the assumptions which will be resolved with 

research progress and availability of more experimental data. Sensitivity analysis shows the 

impacts of many of the uncertainties on the projected costs, and opportunities for further cost 

reduction.
vii

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Table ES-1. Key Process Metrics for the Proposed 2022 Target Cases

In Situ Ex Situ 

Fast Pyrolysis Intermediate

Gas Species – CO, CO2, C1-C4 (wt % of dry biomass) N/A* 13

Organics (wt % of dry biomass) N/A* 64

Water (wt % of dry biomass) N/A* 11

Char (wt % of dry biomass) N/A* 12

Vapor Upgrading Product

Gas (wt % of dry biomass) 23 23

Aqueous Phase (wt % of dry biomass) 29 30

Carbon Loss (% of C in biomass) 2.1 1.3

Organic Phase (wt % of dry biomass) 28 27

H/C Molar Ratio 1.5 1.6

Oxygen (wt % in organic phase) 10.5 6.4

Carbon Efficiency (%) 44 44

Solid Losses, Char + Coke (wt % of dry biomass) 12 + 8 12 + 8

Final Fuel Blendstock

Yield (%, w/w dry biomass) 24 25

Hydroprocessing Carbon Efficiency (%, not including light 

dissolved gases in feed and product; assumed efficiency scaling 

by O content in organic liquid feed—higher efficiency for lower 

O)

91 94

Overall Carbon Efficiency (% of C in biomass) 40.4 41.5

Overall Carbon Efficiency (% of C in biomass + NG) 40.4 41.5

Total Product (GGE/dry U.S. ton) 75 78

Gasoline-Range Product (gallons/dry U.S. ton) 56 36

Diesel-Range Product (gallons/dry U.S. ton) 18 39

Gasoline/Diesel-Range Product (% GGE basis) 73/27 45/55

Oxygen Content in Cumulative Product (wt %) 0.5 0.4

Minimum Fuel Selling Price ($/GGE) 3.46 3.31

Natural Gas† and Electricity

Natural Gas Energy Input (% of biomass, LHV basis) 0.1 0.2

Natural Gas Cost Contribution (¢/GGE) 0.1 0.2

Surplus Electricity Credit (¢/GGE) 4 3

Fuel Blendstock Production Efficiencies (various bases)

Biomass Feedstock (%, LHV basis) 54 57

Biomass + Natural Gas† (%, LHV basis) 54 57

Biomass + Natural Gas† + Electricity (%, LHV basis, all electrical 

energy converted to heat) 56 57

 *Not applicable for in situ case. †Negligible natural gas used in process designs.
viii

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Table ES-2. Economic Summary for In Situ Base Case (2022 Target)

Minimum Fuel Selling Price (MFSP) $3.37 /Gallon Gasoline Blendstock

$3.85 /Gallon Diesel Blendstock

$3.46 /Gallon Gasoline Equivalent (GGE)

Gasoline Blendstock Production 40.4 MM Gal per Year 55.8 Gal per Dry US Ton Feedstock

Diesel Blendstock Production 13.4 MM Gal per Year 18.5 Gal per Dry US Ton Feedstock

Total Gasoline Equivalent Production 54.2 MM GGE per Year 74.9 GGE per Dry US Ton Feedstock

Delivered Feedstock Cost $80.00 per Dry U.S. Ton (Includes Capital Up to Throat of Pyrolyzer)

Internal Rate of Return (After-Tax) 10.0%

Equity Percent of Total Investment 40.0%

On-Stream Factor 90.0%

Capital Costs Operating Costs (¢ / GGE Product)

100: Feedstock (Additional Dryer & Blower Only) $500,000 $504,616 Feedstock 106.9

200: Fast Pyrolysis & Vapor Upgrading $92,480,000 ####### Natural Gas 0.1

300: Pyrolysis Vapor Quench $22,390,000 ####### Catalysts 54.0

400: Hydroprocessing & Separation $32,540,000 ####### Sand -

500: Hydrogen Plant $70,640,000 ####### Other Raw Materials 1.1

600: Steam System & Power Generation $52,450,000 ####### Waste Disposal 1.8

700: Cooling Water & Other Utilities $9,450,000 ####### Purchased Electricity -

800: Water Management $17,160,000 ####### Fixed Costs 46.9

Total Installed Equipment Cost (TIC) $297,610,000 ####### Electricity Coproduct Credit (4.4)

Capital Depreciation 48.0

Land (115 Acres at $14000 per Acre) $1,600,000 Average Income Tax 19.3

Site Development $14,790,000 Average Return on Investment 72.5

(% of ISBL) 10.0%

Indirect Costs & Project Contingency $194,990,000 Operating Costs ($ / Year)

(% of TIC) 65.5% Feedstock $57,940,000

Natural Gas $100,000

Fixed Capital Investment (FCI) $519,960,000 Catalysts $29,290,000

Working Capital $26,000,000 Sand $0

Total Capital Investment (TCI) $545,960,000 Other Raw Materials $610,000

Waste Disposal $1,000,000

Loan Interest Rate 8.0% Purchased Electricity $0

Loan Term (Years) 10 Fixed Costs $25,410,000

Electricity Coproduct Credit -$2,360,000

Total Installed Equipment Cost per Annual GGE $5.49 Capital Depreciation $26,000,000

Fixed Capital Investment per Annual GGE $9.59 Average Income Tax $10,480,000

Average Return on Investment $39,300,000

Plant Operating Hours per Year 7884

On-Stream Percentage 90.0% Total Plant Electricity Usage (kW) 43,173

Electricity Produced on Site (kW) 48,291

Efficiencies Electricity Purchased from Grid (kW) 0

Carbon Eff. to Organic Liquid after In Situ Upgrade 44% Electricity Sold to Grid (kW) 5,117

Carbon Eff. for Hydroprocessing of Organic Liquid 91%

Carbon Eff. for Overall Process (Biomass to Fuel) 40.4% Plant Electricity Use (kWh /GGE) 6.28

Overall Plant Efficiency - HHV % 54.1% Specific Operating Conditions

Overall Plant Efficiency - LHV % 54.3% Feed Rate Dry Tonnes / Day 2,000

Dry Tons / Day 2,205

Feedstock Cost $/Dry Ton $80.00

Version: PyVPU-v218 IS - 2022 $/Moisture+Ash Free Ton $80.74

Process Engineering Analysis for Hydrocarbon Fuel Production

 via In Situ Upgrading of Fast Pyrolysis Vapors

2,000 Dry Metric Tonnes Biomass per Day

All Values in 2011$

Potential Research-Driven Pathway for Cost-Competitiveness by 2022
ix

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Table ES-3. Economic Summary for Ex Situ Base Case (2022 Target)

Minimum Fuel Selling Price (MFSP) $3.26 /Gallon Gasoline Blendstock

$3.68 /Gallon Diesel Blendstock

$3.31 /Gallon Gasoline Equivalent (GGE)

Gasoline Blendstock Production 25.9 MM Gal per Year 35.7 Gal per Dry US Ton Feedstock

Diesel Blendstock Production 27.9 MM Gal per Year 38.6 Gal per Dry US Ton Feedstock

Total Gasoline Equivalent Production 56.5 MM GGE per Year 78.0 GGE per Dry US Ton Feedstock

Delivered Feedstock Cost $80.00 per Dry U.S. Ton (Includes Capital Up to Throat of Pyrolyzer)

Internal Rate of Return (After-Tax) 10.0%

Equity Percent of Total Investment 40.0%

On-Stream Factor 90.0%

Capital Costs Operating Costs (¢ / GGE Product)

100: Feedstock (Additional Dryer & Blower Only) $430,000 $425,525 Feedstock 102.6

200: Fast Pyrolysis & Vapor Upgrading $126,940,000 ####### Natural Gas 0.2

300: Pyrolysis Vapor Quench $24,220,000 ####### Catalysts 36.2

400: Hydroprocessing & Separation $29,110,000 ####### Sand 0.5

500: Hydrogen Plant $66,760,000 ####### Other Raw Materials 1.1

600: Steam System & Power Generation $47,900,000 ####### Waste Disposal 1.7

700: Cooling Water & Other Utilities $9,280,000 ####### Purchased Electricity -

800: Water Management $12,910,000 ####### Fixed Costs 47.7

Total Installed Equipment Cost (TIC) $317,540,000 ####### Electricity Coproduct Credit (2.6)

Capital Depreciation 49.7

Land (115 Acres at $14000 per Acre) $1,600,000 Average Income Tax 19.8

Site Development $18,070,000 Average Return on Investment 74.6

(% of ISBL) 10.0%

Indirect Costs & Project Contingency $210,580,000 Operating Costs ($ / Year)

(% of TIC) 66.3% Feedstock $57,940,000

Natural Gas $100,000

Fixed Capital Investment (FCI) $561,550,000 Catalysts $20,430,000

Working Capital $28,080,000 Sand $300,000

Total Capital Investment (TCI) $589,630,000 Other Raw Materials $610,000

Waste Disposal $930,000

Loan Interest Rate 8.0% Purchased Electricity $0

Loan Term (Years) 10 Fixed Costs $26,950,000

Electricity Coproduct Credit -$1,480,000

Total Installed Equipment Cost per Annual GGE $5.62 Capital Depreciation $28,080,000

Fixed Capital Investment per Annual GGE $9.94 Average Income Tax $11,200,000

Average Return on Investment $42,150,000

Plant Operating Hours per Year 7884

On-Stream Percentage 90.0% Total Plant Electricity Usage (kW) 41,046

Electricity Produced on Site (kW) 44,247

Efficiencies Electricity Purchased from Grid (kW) 0

Carbon Eff. to Organic Liquid after Ex Situ Upgrade 44% Electricity Sold to Grid (kW) 3,201

Carbon Eff. for Hydroprocessing of Organic Liquid 94%

Carbon Eff. for Overall Process (Biomass to Fuel) 41.5% Plant Electricity Use (kWh /GGE) 5.73

Overall Plant Efficiency - HHV % 56.4% Specific Operating Conditions

Overall Plant Efficiency - LHV % 56.6% Feed Rate Dry Tonnes / Day 2,000

Dry Tons / Day 2,205

Feedstock Cost $/Dry Ton $80.00

Version: PyVPU-v218 ES - 2022 $/Moisture+Ash Free Ton $80.74

Process Engineering Analysis for Hydrocarbon Fuel Production

 via Ex Situ Upgrading of Fast Pyrolysis Vapors

2,000 Dry Metric Tonnes Biomass per Day

All Values in 2011$

Potential Research-Driven Pathway for Cost-Competitiveness by 2022
x

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Table of Contents

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

1.1 Motivation and Background.......................................................................................................... 1

1.2 Techno-Economic Analysis Approach.......................................................................................... 3

1.3 Definition of nth-Plant Economics................................................................................................. 4

1.4 Estimation of Capital Costs........................................................................................................... 5

2 Plant Design Basis ............................................................................................................................... 8

2.1 Feedstock and Plant Size............................................................................................................... 8

2.2 Process Overview.......................................................................................................................... 9

2.3 Aspen Plus Model ....................................................................................................................... 12

3 Process Design and Cost Estimation............................................................................................... 13

3.1 Area 100: Feed Handling and Drying ......................................................................................... 13

3.2 Area 200: Fast Pyrolysis and Vapor Upgrading.......................................................................... 14

3.2.1 Area 200 Overview ........................................................................................................ 14

3.2.2 Area 200 Design Basis................................................................................................... 18

3.2.3 Area 200 Equipment Cost Estimations .......................................................................... 19

3.3 Area 300: Pyrolysis Vapor Quench and Product Recovery ........................................................ 21

3.3.1 Area 300 Overview ........................................................................................................ 21

3.3.2 Area 300 Design Basis................................................................................................... 23

3.3.3 Area 300 Equipment Cost Estimations .......................................................................... 24

3.4 Area 400: Hydroprocessing and Product Separation................................................................... 25

3.4.1 Area 400 Overview ........................................................................................................ 25

3.4.2 Area 400 Design Basis................................................................................................... 29

3.4.3 Area 400 Equipment Cost Estimations .......................................................................... 32

3.5 Area 500: Hydrogen Plant........................................................................................................... 32

3.5.1 Area 500 Overview ........................................................................................................ 32

3.5.2 Area 500 Design Basis................................................................................................... 33

3.5.3 Area 500 Equipment Cost Estimations .......................................................................... 33

3.6 Area 600: Steam System and Power Generation......................................................................... 33

3.6.1 Area 600 Overview ........................................................................................................ 33

3.6.2 Area 600 Design Basis................................................................................................... 35

3.6.3 Area 600 Equipment Cost Estimations .......................................................................... 36

3.7 Area 700: Cooling Water and Other Utilities.............................................................................. 36

3.7.1 Area 700 Overview ........................................................................................................ 36

3.7.2 Area 700 Design Basis................................................................................................... 37

3.7.3 Area 700 Cost Estimation .............................................................................................. 37

3.8 Area 800: Wastewater Management and Recycle....................................................................... 38

3.8.1 Area 800 Cost Estimation .............................................................................................. 41

3.9 Additional Process Design Information ...................................................................................... 41

3.10 Pinch Analysis............................................................................................................................. 42

3.11 Energy Balance ........................................................................................................................... 44

3.12 Sustainability Metrics.................................................................................................................. 45

4 Process Economics ........................................................................................................................... 51

4.1 Total Capital Investment ............................................................................................................. 51

4.2 Variable Operating Costs............................................................................................................ 54

4.3 Fixed Operating Costs................................................................................................................. 55

4.4 Discounted Cash Flow Analysis and the Minimum Fuel Selling Price ...................................... 56

4.5 Value of Hydrocarbon Fuel Products From Biomass Pyrolysis.................................................. 57

5 Process Economics Summary and Sensitivity Analysis ............................................................... 58

5.1 Market, Financial, and Overall Assumptions.............................................................................. 60
xi

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5.2 Fast Pyrolysis and Catalytic Vapor Upgrading ........................................................................... 61

5.3 Hydroprocessing.......................................................................................................................... 62

5.4 Other Operations and Overall Plant ............................................................................................ 62

6 Conclusions ........................................................................................................................................ 63

7 Future TEA Work ................................................................................................................................ 64

8 References .......................................................................................................................................... 65

Appendix A. Equipment Description and Design Basis Summary...................................................... 71

Appendix B-1. Individual Equipment Cost Summary (In Situ Case).................................................... 76

Appendix B-2. Individual Equipment Cost Summary (Ex Situ Case) .................................................. 81

Appendix C-1. Discounted Cash Flow Rate of Return and Operating Cost Summary 

(In Situ Case)....................................................................................................................................... 86

Appendix C-2. Discounted Cash Flow Rate of Return and Operating Cost Summary 

(Ex Situ Case)...................................................................................................................................... 90

Appendix D-1. Process Parameter and Operating Summary (In Situ Case)....................................... 95

Appendix D-2. Process Parameter and Operating Summary (Ex Situ Case)...................................... 96

Appendix E. Assumptions and Analysis for Full Life-Cycle GHG Emissions .................................... 97

Feedstock Crop Establishment and Growing ....................................................................................... 97

Feedstock Harvesting, Preprocessing, and Transportation................................................................... 97

Conversion............................................................................................................................................ 98

Fuel Distribution and Consumption ..................................................................................................... 98

Life Cycle GHG Results....................................................................................................................... 98

Appendix E References........................................................................................................................ 99

Appendix F. Compounds in Aspen Plus Simulation ........................................................................... 100

Appendix G-1. Process Flow Diagrams and Stream Summary for the In Situ Case........................ 102

Appendix G-2. Process Flow Diagrams and Stream Summary for the Ex Situ Case, Including 

Detailed Heat Exchange Network.................................................................................................... 151

Appendix H. Heat Exchanger Costs for the Ex Situ Case................................................................... 218

Appendix I. Plant Footprint and Land Cost Calculation From Harris Group Inc.............................. 224

Appendix I References....................................................................................................................... 226

Appendix J. Reviewer Comments on Draft Design Report and Responses..................................... 227

Area A100: Feed Handling and Drying.............................................................................................. 227

Area A200: Fast Pyrolysis and Vapor Upgrading.............................................................................. 228

Area A300: Pyrolysis Vapor Quench and Product Recovery............................................................. 239

Area A400: Hydroprocessing and Product Separation....................................................................... 241

Area A500: Hydrogen Plant ............................................................................................................... 247

Area A600: Steam System and Power Generation............................................................................. 248

Area A700: Cooling Water and Other Utilities.................................................................................. 249

Area A800: Wastewater Management and Recycle ........................................................................... 249

Miscellaneous..................................................................................................................................... 250

Appendix J References....................................................................................................................... 261
xii

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List of Figures

Figure 1. Literature results for yields and oxygen content in bio-oil after catalytic upgrading of fast 

pyrolysis vapors using HZSM-5 as a function of biomass-to-catalyst ratio. (Reproduced with 

permission from Mukarakate et al. [4].)................................................................................... 2

Figure 2. Approach for in situ and ex situ fast pyrolysis vapor upgrading process design and analysis...... 4

Figure 3. Chemical Engineering’s Plant Cost Index data ............................................................................. 7

Figure 4. Simplified flow diagram for the conversion processes.................................................................. 9

Figure 5. Simplified process flow diagram for fast pyrolysis and catalytic vapor upgrading .................... 14

Figure 6. Simplified process flow diagram of pyrolysis vapor quench and product recovery.................... 21

Figure 7. Simplified process flow diagram of the hydroprocessing and product separation area .............. 25

Figure 8. Assumed hydroprocessing carbon efficiency vs. oxygen content in organic liquid feed............ 27

Figure 9. Pinch analysis composite curve for the in situ case..................................................................... 43

Figure 10. Pinch analysis composite curve for the ex situ case .................................................................. 43

Figure 11. Overall energy balance (basis: LHV of wood + natural gas). Values rounded to nearest tenth.44

Figure 12. Contributing processes to conversion GHGs for catalytic pyrolysis pathways......................... 49

Figure 13. Cost contribution details from each process area for the in situ 2022 target case ..................... 58

Figure 14. Cost contribution details from each process area for the ex situ 2022 target case..................... 59

Figure 15. Results of sensitivity analyses for the ex situ case .................................................................... 60

List of Tables

Table ES-1. Key Process Metrics for the Proposed 2022 Target Cases ..................................................... vii

Table ES-2. Economic Summary for In Situ Base Case (2022 Target).....................................................viii

Table ES-3. Economic Summary for Ex Situ Base Case (2022 Target)...................................................... ix

Table 1. Summary of nth-Plant Assumptions for Techno-Economic Analysis............................................. 5

Table 2. Ultimate Analysis of Woody Biomass Feedstock........................................................................... 8

Table 3. Comparison of In Situ and Ex Situ Upgrading.............................................................................. 17

Table 4. Design Basis for Fast Pyrolysis and Catalytic Vapor Upgrading ................................................. 19

Table 5. Capital Cost Estimates for the Fast Pyrolysis and Catalytic Vapor Upgrading Area ................... 20

Table 6. Design Basis for Pyrolysis Vapor Quench and Product Recovery ............................................... 23

Table 7. Cost Estimate for Pyrolysis Vapor Quench and Product Recovery.............................................. 24

Table 8. Process Model Flow Information for A400 .................................................................................. 28

Table 9. Design Basis Parameters for Hydrotreating Reactor .................................................................... 30

Table 10. Design Basis Parameters for Hydrocracking Reactor................................................................. 30

Table 11. Design Parameters for Hydrogen Compressors.......................................................................... 31

Table 12. Cost Estimate for the Hydroprocessing Area.............................................................................. 32

Table 13. Design Basis Parameters for Hydrogen Plant............................................................................. 33

Table 14. Cost Estimate for Hydrogen Production Area ............................................................................ 33

Table 15. Plant Power Requirements for In Situ Case ................................................................................ 35

Table 16. Plant Power Requirements for Ex Situ Case ............................................................................... 35

Table 17. Cost Estimate for Steam System and Power Generation Area ................................................... 36

Table 18. Design Basis for Cooling Water System..................................................................................... 37

Table 19. Cost Estimate for Cooling Water and Other Utilities Area......................................................... 37

Table 20. Pyrolysis Plant Water Balance.................................................................................................... 40

Table 21. Cost Estimate for Wastewater Management Area ...................................................................... 41

Table 22. Utility and Miscellaneous Design Information........................................................................... 41

Table 23. Material and Energy Flows for the In Situ Case ......................................................................... 46

Table 24. Material and Energy Flows for the Ex Situ Case ........................................................................ 47

Table 25. SimaPro Processes Used for Conversion Process Inputs............................................................ 48

Table 26. Summary of Sustainability Metrics for the In Situ and Ex Situ Cases........................................ 49
xiii

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Table 27. General Cost Factors in Determining Total Installed Equipment Costs..................................... 52

Table 28. Cost Factors for Indirect Costs ................................................................................................... 52

Table 29. Project Cost Worksheet............................................................................................................... 53

Table 30. Summary of Variable Operating Costs....................................................................................... 54

Table 31. Salary Costs for Plant Employees............................................................................................... 55

Table 32. Fixed Operating Costs ................................................................................................................ 55

Table 33. Projected Selling Prices of Hydrocarbon Fuels From Biomass Pyrolysis.................................. 57

Table E-1. Farming Energy Values from GREET and Modified for this Analysis.................................... 97

Table F-1. Compounds in Aspen Plus Simulation.................................................................................... 100

Table F-2. Structures of Compounds Identified by Formula .................................................................... 101

Table F-3. Ultimate Analysis of Non-Conventional Components............................................................ 101

Table I-1. Plant Footprint and Land Cost Calculation From Harris Group Inc. ....................................... 225
1

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1 Introduction

1.1 Motivation and Background

Fast pyrolysis-based biomass conversion processes have the potential to offer high efficiencies 

for the production of liquid transportation fuels such as gasoline and diesel blendstocks, or 

petroleum refinery compatible intermediates for conversion to liquid fuels. The process involves 

rapid heating of biomass particles in the absence of air at approximately 500°C with the 

production of permanent gases, vapors including water, and solids including mineral matter and 

char. The liquid product fraction collected after the condensation of the vapors is also known as 

bio-oil or pyrolysis oil [1]. The attractiveness of such conversion lies in the yield of a significant 

proportion of products directly in the liquid phase.

However, challenges lie in the modification of the quality of the liquid product to make it 

compatible with the current transportation fuels infrastructure and end use vehicles, which are 

predominantly operated with liquid hydrocarbon fuels. The source of this challenge is inherent to 

biomass feedstocks which usually contain substantial quantities of oxygen (~40 wt % in wood). 

Fast pyrolysis of such feedstocks yields oxygenated compounds that can react easily, posing a 

variety of processing challenges. Catalytically reducing the oxygen content, during or 

immediately after fast pyrolysis while the products are still in the vapor phase, can ease 

downstream processing challenges and provide many of the benefits outlined in this design 

report.

Included in this report are descriptions of process models and assumptions for two related 

conversion pathways: (1) in situ (also referred to elsewhere as catalytic fast pyrolysis), where 

catalytic vapor upgrading happens within the fast pyrolysis reactor, and (2) ex situ (also referred 

to elsewhere as vapor phase upgrading), where catalytic vapor upgrading happens in a separate 

reactor following the fast pyrolysis reactor. An in situ system includes catalytic upgrading within 

the circulating fluidized bed fast pyrolysis reactor system. This has the potential to reduce capital 

costs by precluding the use of additional vapor phase upgrading reactors and potentially a hot gas 

filter (HGF) in an ex situ configuration. However, the catalyst needs to survive in a considerably 

more challenging environment in an in situ reactor because of mixing with other solids including 

inhibitory mineral matter, char, and biomass. These other solids impose challenges for 

maintaining physical and chemical integrity required for a functional catalyst. In an ex situ

configuration the elimination of such detriments can allow more focus on the achievable 

chemistry rather than on the mitigation of impacts of other solids. It is to be noted that a hybrid 

of an in situ configuration using relatively inexpensive catalyst followed by ex situ upgrading 

reactors may also be economically justifiable.

The in situ and ex situ catalytic fast pyrolysis vapor upgrading processes were identified by the 

U.S. Department of Energy’s (DOE) Bioenergy Technologies Office (BETO) as research 

pathways for enabling the production of cost-competitive liquid transportation fuels from 

biomass [2, 3]. It should be noted that although circulating catalyst in fluidized beds were used 

as the basis for the conceptual designs, research and development will also consider other 

catalysts, including those with noble metals, suitable for use in ex situ fixed bed systems. Such 

design variations will be captured in future techno-economic analysis (TEA) and will leverage

experimental data as they become available. Overall, this report captures envisioned process 

performances to be achieved for cost-competiveness by 2022. Intermediate research targets 
2

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leading up to 2022 were developed subsequently for publication in BETO’s Multi-Year Program 

Plan, using key assumptions in this report as the foundation; those metrics will be updated 

annually with research realities, and necessary deviations from the current design basis.

Numerous experimental studies have been conducted in the area of fast pyrolysis vapor 

upgrading, particularly with zeolite catalysts, and most commonly with HZSM-5 [4, 5, 6, 7]. 

Figure 1 illustrates how better quality, reflected by lower oxygen content, follows an inverse 

trend with liquid product yield. Lower biomass to catalyst ratios, corresponding to higher 

catalyst activity, result in better product quality at the expense of yield; potential organic liquid 

yield is lost to gas phase products, water, and coke. Since both improved bio-oil quality and high 

yields are necessary for economic viability, significant catalyst improvements will be necessary 

to break out of the performance mold demonstrated by current catalysts. In this regard it should 

be noted that performance in continuous systems with regeneration may be significantly better 

than in batch systems [8]. Some discussion of catalysts and associated references are provided in 

Section 3.2.1.6.

Figure 1. Literature results for yields and oxygen content in bio-oil after catalytic upgrading of fast 

pyrolysis vapors using HZSM-5 as a function of biomass-to-catalyst ratio. (Reproduced with 

permission from Mukarakate et al. [4].)

In this respect, modified zeolites and other families of catalysts [9] will need to be developed.

Some of the key objectives of catalyst development include the enabling of: (1) reduced coke 

and coke precursor formation, (2) reduced non-condensable species formation, (3) efficient 

hydrogen utilization, which ties into reduced aromatics in the product, reduced coke formation,

and greater hydrodeoxygenation to allow higher carbon efficiency, (4) coupling (molecular 

combination) reactions to reduce the loss of smaller molecules to the gas phase and also enhance 

the formation of distillate range products, (5) attrition resistance of fluidizable catalysts, (6) 

catalyst maintenance and regeneration in fluidized and fixed bed configurations, and (7) catalyst 

longevity. It is expected that these developments will result in significant vapor quality 

improvements with reduced reactivity; upon condensation the recovered organic phase can be 
3

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hydroprocessed to fuel blendstocks at relatively less severe conditions compared to raw bio-oil 

from non-catalytic fast pyrolysis. Note that quality is a function of not only the oxygen content, 

but also the types of remaining oxygenated species and functional groups in the oil, e.g. acids are 

more detrimental than phenol.

Some hydrogen reactivity during vapor upgrading will be necessary for higher organic liquid 

yields; hydrogen reactivity will need to be facilitated by the inclusion of metals within catalyst 

formulations. In order to help hydrogen reactivity in the vapor phase, the proposed designs for 

both in situ and ex situ configurations operate at slightly elevated pressures and include hydrogen 

in the fluidizing gas, with the aim of maintaining a nominal hydrogen partial pressure of 72–95

psia (5–6.6 bar) at the various reactor inlets (fast pyrolysis, in situ catalytic fast pyrolysis, and ex 

situ vapor phase upgrading). This process design decision does not require significant 

modifications to the vessel thicknesses of refractory-lined fluidized reactors operated at near 

ambient pressures. This inference was based on a design-study by Worley and Yale [10] who 

concluded that the minimum vessel wall thicknesses necessary to maintain mechanical integrity 

during fabrication and handling would be consistent with wall thicknesses of vessels designed 

for 150 psia. That study is the basis for the cost of fluidized reactors in this report. It is important 

to distinguish this process from conventionally known biomass hydropyrolysis processes 

operated at significantly higher pressures of 300–525 psia (20–35 bar) and a temperature range 

of 350°C–480°C [11].

The conceptual designs in this report assume stand-alone plants for the production of gasolineand diesel-range blendstocks. It may be possible to produce sufficiently upgraded intermediates

acceptable to petroleum refiners for further processing immediately after pyrolysis vapor

upgrading. In such cases, it may be possible to further reduce or eliminate the on-site 

hydroprocessing facilities assumed in this report. However, such configurations will only be 

feasible after careful scrutiny of product quality and buy-in from refiners regarding compatibility 

with refinery unit operations [12].

1.2 Techno-Economic Analysis Approach

The general approach used in the process design, process model, and economic analysis is 

depicted in Figure 2. This design report includes information from previously published reports 

including those by the National Renewable Energy Laboratory (NREL) and Pacific Northwest 

National Laboratory (PNNL), reviews of commercially available technologies, process modeling 

using Aspen Plus software, equipment cost estimation through vendor quotes and Aspen Capital 

Cost Estimator (ACCE) software, and discounted cash flow analysis. The techno-economic 

analysis ultimately provides a minimum fuel selling price (MFSP) based on the financial 

assumptions in Table 1.
4

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Figure 2. Approach for in situ and ex situ fast pyrolysis vapor upgrading process design and 

analysis

Aspen Plus Version 7.2 was used to develop mass and energy balances for the process. The plant

operations are separated into eight major process areas:

• Area 100: Feed handling and drying

• Area 200: Fast pyrolysis and vapor upgrading

• Area 300: Pyrolysis vapor quench and product recovery

• Area 400: Hydroprocessing and product separation

• Area 500: Hydrogen plant

• Area 600: Steam system and power generation

• Area 700: Cooling water and other utilities

• Area 800: Wastewater management and recycle.

1.3 Definition of nth-Plant Economics

The techno-economic analysis reported here uses nth-plant economics. The key assumption 

associated with nth-plant economics is that several plants using the same technology have already 

been built and are operating. In other words, the assumption reflects a future in which a 

successful industry has been established with many operating plants. Because the technoeconomic model is a tool used primarily for (1) studying new process technologies or (2) 

comparing integrated processes in order to comment on their relative economic impact, it is 

prudent to ignore artificial inflation of project costs associated with risk financing, longer start-
5

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ups, equipment overdesign, and other costs associated with pioneer plants, as these overshadow 

the real economic impact of advances in conversion science or process engineering research. At 

the very least, nth-plant economics should help to provide justification and support for early 

technology adopters and pioneer plants about longer-term prospects.

Because equipment costs in this design report have been estimated explicitly, the nth-plant 

assumptions apply primarily to the factored cost model used to determine the total capital 

investment from the purchased equipment cost and to the assumptions applied for plant 

financing. The nth-plant assumption also applies to operating parameters, such as process uptime 

and start-up time. A summary of the nth-plant assumptions applied in this report are listed in

Table 1. These financial assumptions are consistent with assumptions used for other economic 

analyses done for DOE’s Bioenergy Technologies Office, with some deviations to reflect the 

uniqueness of the current processes.

Table 1. Summary of nth-Plant Assumptions for Techno-Economic Analysis

Description of Assumption Assumed Value

Internal rate of return (IRR) 10%

Plant financing by equity/debt 40%/60% of total capital investment

Plant life 30 years

Income tax rate 35%

Interest rate for debt financing 8.0% annually

Term for debt financing 10 years

Working capital cost 5.0% of fixed capital investment

(excluding land purchase cost)

Depreciation schedule 7-year MACRS schedule [13]

Steam plant depreciation 20-year MACRS schedule [13]

Construction period (spending schedule) 3 years (8% Y1, 60% Y2, 32% Y3)

Plant salvage value No value

Start-up time 6 months

Revenue and costs during startup Revenue = 50% of normal

Variable costs = 75% of normal

Fixed costs = 100% of normal

On-stream percentage after startup 90% (7,884 operating hours per year)

1.4 Estimation of Capital Costs

Capital costs were estimated using a variety of resources. For sub-processes that utilize welldeveloped technologies and can be purchased as modular packages (e.g., steam reforming unit

and refrigeration), an overall package cost was used instead of the sum of costs for individual 

pieces of equipment. Costs for common process equipment (e.g., tanks, drums, pumps, and

simple heat exchangers) were estimated using ACCE costing software. Fluidized bed equipment 

(e.g., fast pyrolysis and in situ and ex situ reactors) specific to this process was estimated by
6

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Harris Group using a mechanical design spreadsheet tool previously developed for gasifier costs 

[10]; design parameters were modified based on flow rates from the Aspen Plus process 

simulations and additional process inferences from mature fluid catalytic cracking (FCC) 

systems available in literature [14]. Hydroprocessing reactor costs were developed using ACCE, 

with some vendor quotes obtained by Harris Group used as supporting information. Some other 

major equipment costs, such as for the hydrogen compressors, were also obtained from vendors. 

Further details of equipment cost assumptions are provided under individual process areas in 

Section 3.

The original (base) purchased equipment costs reflect the base case for equipment size and cost 

year. Equipment sizes required for the process may vary from the original base case, requiring 

adjustment of the equipment costs. Instead of re-pricing equipment after minor changes in size, 

exponential scaling is applied to adjust the purchased equipment costs using Equation 1:

(Eq. 1)

The characteristic scaling exponent, n, is typically in the range of 0.6 to 0.7 for process 

equipment. The sizing parameters are based on a characteristic of the equipment related to 

production capacity, such as inlet flow for a process vessel or heat transfer duty for a heat 

exchanger. Equation 1 assumes that all other process parameters (pressure, temperature, etc.) 

remain constant relative to the base case. Scaling exponents were determined from the following 

sources:

• Vendors’ estimates of scaling exponent or inference from vendor quotes when multiple 

quotes were available for equipment of various processing capacities

• Development of correlations by multiple estimates from the ACCE software

• Standard reference from published sources such as Garrett [15], Peters, Timmerhaus, and 

West [16], and Perry et al. [17].

When cost data were not available in 2011 dollars, costs were adjusted with Chemical 

Engineering’s (CE) Plant Cost Index [18] using Equation 2:

(Eq. 2)

The CE indices used in this study are listed and plotted in Figure 3. The index data show a sharp 

increase after 2003 due to increases in global steel demand and a dip in 2009 due to the global 

recession. An intermediate 2014 index was used for 2014 corresponding to roughly the time 

when most of the recent cost quotes were obtained.

Scale-Up Equipment Cost = Base Equipment Cost 

Scale-Up Capacity

Base Capacity

n
7

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Figure 3. Chemical Engineering’s Plant Cost Index data

Once the total purchased equipment costs (TPEC) were determined, scaled, and time-corrected, 

an equipment installation factor was applied to estimate the total installed cost (TIC) for the 

equipment or process unit including associated piping, instrumentation and controls, electrical 

systems, buildings, yard improvements, and direct labor per Equation 3, where fInstallation is the 

installation factor:

(Eq. 3)

Where possible, specific installation factors from vendor quotes, ACCE, or published data [19]

were applied to equipment or process units to estimate the TIC. Details for TPEC, installation 

factors, and TIC values for each process area are presented in Section 3.

Once the scaled TICs were determined, overhead and contingency factors were applied to 

determine a total capital investment (TCI) cost. The TCI, along with plant operating expenses,

serves as the basis for the discounted cash flow analysis. The discounted cash flow analysis then 

yields the MFSP on a gallon gasoline equivalent (GGE) basis, a metric by which this conceptual 

process performance can be compared to alternate fuel production designs.

Total Installed Cost (TIC) = f Installation * Total Purchased Equipment Cost (TPEC)
8

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2 Plant Design Basis

2.1 Feedstock and Plant Size

The dry basis elemental composition of the feedstock, shown in Table 2, is identical to previous 

NREL and PNNL design reports [20, 21]. The composition was originally assumed to come 

from pulpwood. Recent feedstock logistics work at the Idaho National Laboratory (INL) 

suggests that the use of blended material may be required to meet a cost target of $80/dry U.S.

ton while still meeting these specifications [22]. For the purpose of this report, it is assumed that 

any blended material provided to meet this feedstock elemental composition will not adversely 

affect fast pyrolysis conversion efficiencies. Ongoing studies being conducted jointly by INL, 

NREL, and PNNL will provide experimental evidence of the impact of blended feedstocks on 

fast pyrolysis and gasification processes. Future TEA will be modified to reflect conversion 

impacts inferred from such studies.

Table 2. Ultimate Analysis of Woody Biomass Feedstock

Component Weight % (Dry Basis [20, 21])

Carbon 50.94

Hydrogen 6.04

Nitrogen 0.17

Sulfur 0.03

Oxygen 41.90

Ash 0.92

Heating valuea (Btu/lb) 8,601 HHV

7,996 LHV

a Calculated using the Aspen Plus Boie correlation.

The current feedstock moisture specification is 10 wt %, unlike the previous studies [20, 21]

where a moisture content of 30 wt % was assumed at the plant gate. The cost of the material 

provided to the fast pyrolysis reactor (for ex situ) or catalytic fast pyrolysis reactor (for in situ) is 

$80/dry U.S. ton [22]. This includes all feedstock logistics including the delivery of a nominal

particle size of 2 mm into the reactors.

The design capacity for this study is 2,000 dry metric tonnes per day (2,205 dry tons per day), 

which matches that of previous design reports. With an expected 7,884 operating hours per year 

(90% on-stream factor/availability), the annual feedstock requirement is approximately 657,000 

dry metric tonnes per year (724,000 dry tons per year). The assumed on-stream factor allows 

approximately 36 days of planned and unplanned downtime per year.

The delivered feedstock cost was estimated using INL’s model. This cost of $80 per dry ton 

includes all capital costs, operating costs, and dry matter losses associated with feed delivery, 

drying, and handling as determined by INL. The only additional equipment included with the 

plant costs is a cross-flow dryer, which was included for warming up the feedstock using flue gas 

and allowing for drying contingency during the wet weather.

It should be noted that the term mineral matter is used throughout the text to refer to the 

inorganic content in the feedstock, while the term ash is used to refer to the residual inorganic 

product after the combustion of biomass.
9

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2.2 Process Overview

A block flow diagram of the current design is shown in Figure 4. A high level description of the 

conversion steps and their main purposes are presented below, with further details in Section 3.

Figure 4. Simplified flow diagram for the conversion processes
10

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• Feed handling and preparation. The modeled biomass feedstock has an ultimate analysis 

shown in Table 2. The assumed moisture content is 10 wt %, with an ash content of <1% 

and nominally sized to 2 mm for the fast pyrolysis reactor. A cross-flow dryer is included 

in the system to allow warming up of the feed prior to feeding in to the reactor, using 

process waste heat. This also allows for contingencies during wet weather when 

additional feed drying may be necessary. The feedstock is delivered at $80/dry U.S. ton.

• Fast pyrolysis with in situ or ex situ vapor upgrading. The in situ configuration combines 

fast pyrolysis and catalytic vapor upgrading within the same reactor, while the ex situ

configuration has a front end non-catalytic fast pyrolysis reactor followed by a separate 

ex situ catalytic vapor upgrading reactor system. The ex situ reactor is not exposed to 

biomass associated solids (biomass, char, and mineral matter) beyond the unintended 

entrainment of fine material such as attrited solids and some mineral matter/ash, making 

it a more benign environment for catalyst performance and maintenance. It is also 

possible for the ex situ reactor to have a fixed bed configuration. In this report, all three 

reactors, (1) non-catalytic fast pyrolysis, (2) catalytic fast pyrolysis or in situ upgrading, 

and (3) separate vapor phase upgrading or ex situ reactors, are dual circulating fluidized 

bed (CFB) systems. Each has an entrained flow reactor and a second fluidized bed 

combustor for char/coke combustion, similar to FCC reactors. In the in situ and ex situ

catalytic systems the combustor also serves as a catalyst regenerator by burning off coke 

deposits. In the conceptual designs presented, all three reactors operate at 500°C (932°F)

reactor outlet temperatures, with short residence times (<2 s), under approximately 72–95

psia (5–6.6 bar) of hydrogen partial pressure, and 120 psia (~8 bar) total pressure. The 

catalytic vapor upgrading step is designed to help reduce oxygen content in the produced 

bio-oil organic liquid fraction, making it less reactive and amenable to hydroprocessing 

under less severe conditions into fuel blendstocks. It should be noted that the above 

parameters are for one possible design, which are used for our base cases. The fluidizing 

gas composition and pressure assumed for the base case may be altered as benefits are 

analyzed with further catalyst development and experiments. Other design variations may 

include hot gas filters, fixed bed vapor phase upgrading reactor systems, and catalysts 

other than zeolites. Such changes can alter process conditions, including operating 

temperatures and catalyst regeneration protocols.

• Pyrolysis vapor quench. Upgraded vapors from both in situ and ex situ systems are 

quenched to separate vapors from non-condensable gases. The base case assumes that 

there will remain concerns about fouling of indirect heat exchange equipment during the 

condensation of the heavy fraction of the organic vapors. A first absorber/condenser is 

thus used to recover the heavy organic fraction after vapors are cooled to the stream’s 

predicted dew point. The absorber/condenser is followed by indirect heat exchange to 

cool down the remaining vapor. This stream then enters a second absorber/condenser 

where a light organic phase and an aqueous phase are condensed from non-condensable 

gases. The organic fraction is sent for hydroprocessing, while the aqueous fraction is sent 

to wastewater treatment. The majority of the non-condensable gases are recycled to the 

fast pyrolysis reactor for fluidization. The remaining gas is used for hydrogen production 

via sour water gas shift and pressure swing adsorption (PSA). Economic impacts of the 

inability to use any indirect heat exchange for energy recovery from the hot upgraded 
11

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vapors are discussed later in Section 5 as part of sensitivity analysis; equipment 

configuration modifications for such scenarios were not modeled in this study.

• Hydroprocessing and product separation. The organic liquid fraction is sent to a 

hydrotreater for deoxygenation and saturation of a portion of the products to reduce

aromatic content. Note that the separation of the aqueous phase after the condensation of 

upgraded vapors reduces the liquid flow to the hydrotreater significantly. The 

hydrotreater is modeled with a specified inlet temperature of 375°C (707°F), and inlet 

pressures of 1,845 psia and 1,545 psia for the in situ and ex situ cases, respectively. The 

products are fractionated into gasoline and diesel boiling ranges. The heavier product is 

sent to a hydrocracking reactor with a specified inlet temperature of 392°C (738°F) and 

inlet pressure of 1,945 psia. Products from hydrocracking are also sent for fractionation 

to produce gasoline and diesel boiling range products.

• Hydrogen production. A fixed-bed steam methane reformer (SMR) package was used for 

hydrogen production. Natural gas was used only as a supplement for hydrogen 

production; in the base cases there is sufficient fuel gas available in the process to 

provide all the duty necessary to operate the reformer at high temperatures as well as 

produce required quantities of hydrogen. In the base cases negligible amounts of

supplemental natural gas was used for both the in situ and ex situ cases (as shown in

Table 13). The natural gas demand increases for sensitivity cases where higher liquid fuel 

product yields are assumed. The process design and costs [21] include sulfur removal 

from the fuel gases fed to the reformer, a water gas shift reactor for the enhancement of 

hydrogen production, and a subsequent PSA for hydrogen purification.

• Heat and power. A conventional steam cycle uses process heat to produce electricity.

There is a significant amount of heat available in the process that needs to be managed 

efficiently to positively impact the economics. The significant sources of heat are the char 

and coke combustors, hot upgraded pyrolysis vapors (including fluidization gases), steam 

reformer flue gas, and reformed gas quench. In both the in situ and ex situ designs, excess 

electricity is available after consumption in the plant. This electricity is sold to the grid,

and the credit reduces the MFSP.

• Cooling water. A cooling water system is included in the Aspen Plus model to determine 

the requirements of each cooling water heat exchanger within the biomass conversion 

process.

• Wastewater management. Wastewater from the vapor condensation section is sent to a 

reboiler system to generate steam for process use (sour water gas shift and steam 

reforming). However, to avoid fouling in the reboiler, not all the wastewater is 

evaporated. The carbon in the remaining wastewater after partial evaporation is 

approximately 25 wt %. This wastewater is sent to an aqueous regenerative thermal 

oxidizer (RTO) to eliminate the varied carbon species that may be present. The Aspen 

Plus process model predicts that the aqueous RTO is self-sustaining with some extra heat 

available from the combustion of the carbon remaining in the aqueous phase. The 

remaining wastewater is sent for conventional treatment. However, there remain 

significant opportunities to recover valuable products from the wastewater using 

processes such as aqueous phase reforming and biological upgrading; such processes are
12

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not considered in this design in order to focus on the core technology of in situ and ex situ

fast pyrolysis vapor upgrading.

2.3 Aspen Plus Model

An Aspen Plus Version 7.2 simulation was used as the basis for this report. Since the products in 

pyrolysis are numerous and varied, only selected model compounds were used to represent the 

product slate. Additional hydrocarbon species were added to represent hydroprocessing products. 

Many of the desired molecular species in the desired boiling ranges for light and heavy fractions 

did not exist in Aspen Plus databanks and physical property parameters needed to be estimated. 

The biomass feedstock, ash, char, and coke were modeled as non-conventional components.

Appendix F provides information about compounds selected to represent the process. The PengRobinson with Boston-Mathias modifications (PR-BM) equation of state was used throughout 

most of the process simulation. The ASME 1967 steam table correlations (STEAM-TA) were 

used for the steam cycle calculations.
13

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3 Process Design and Cost Estimation

The process design broadly consists of the following areas:

• Area 100: Feed handling and drying

• Area 200: Fast pyrolysis and vapor upgrading

• Area 300: Pyrolysis vapor quench and product recovery

• Area 400: Hydroprocessing and product separation

• Area 500: Hydrogen plant

• Area 600: Steam system and power generation

• Area 700: Cooling water and other utilities

• Area 800: Wastewater management and recycle.

The following sections present process overviews, design bases, and installed equipment cost 

estimations for each process area of the plant. Heat balance and pinch analysis are discussed 

separately in Section 3.10. Note that additional details of equipment costs and economics are 

provided in Appendices B and C. Detailed process flow diagrams and stream summaries are 

presented in Appendix G. Note that appendix name suffixes “-1” and “-2” are used when there 

are separate sets of information presented for the in situ and ex situ cases, respectively.

3.1 Area 100: Feed Handling and Drying

Feed handling and drying, as well as all other off-site logistics are described in detail in a recent 

INL report [22]. As mentioned in Section 2, INL’s cost model for the material uses blended 

material. The blend constituents include pulpwood (45%), woody residues (32%), switchgrass 

(3%), and construction and demolition waste (20%). Further details are provided in the INL 

report [22]. The dry basis ultimate analysis of this blended material is similar to pulpwood. It is 

assumed that the biomass feedstock modeled will be provided at $80/dry U.S. ton to the throat of 

the reactor and will have similar conversion performance to pulpwood for the processes under 

consideration in this report. It remains to be experimentally determined whether this assumption 

is correct; INL, NREL, and PNNL are jointly working on this aspect. Table 2 shows the 

feedstock ultimate analysis used in this design. This ultimate analysis is used in the simulation 

for atomic balance closure. The moisture content of the material is 10 wt %, with a nominal 

particle size of 2 mm. The conceptual plant is modeled to consume 2,000 dry metric tonnes of 

biomass feedstock per day. 

While all feedstock logistics including capital and energy requirements for drying and size 

reduction are included in the feedstock cost, an additional cross-flow dryer and a flue gas blower

was added to the plant equipment list (the small power consumption for feed handling and drying 

shown in Table 15 and Table 16 are from these additional operations). The capital costs and 

installation factors are shown in Appendix B. This dryer was added to help warm up the biomass 

feedstock prior to feeding into the reactor. It will also help to control feedstock moisture content 

during wet weather. In both the in situ and ex situ process models the feedstock is warmed in the 

cross-flow dryer from 15.6°C (60°F) to 103.3°C (218°F) using flue gases from the combustors in 

the process.
14

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3.2 Area 200: Fast Pyrolysis and Vapor Upgrading

The following section presents an overview, basis for design, and cost estimates for construction 

of the fast pyrolysis, in situ catalytic fast pyrolysis, and ex situ vapor upgrading facilities. 

3.2.1 Area 200 Overview

Figure 5 shows a simplified flow diagram for the fast pyrolysis and catalytic vapor upgrading 

equipment.

Figure 5. Simplified process flow diagram for fast pyrolysis and catalytic vapor upgrading

The in situ configuration combines fast pyrolysis and catalytic vapor upgrading within the same 

reactor, while the ex situ configuration has a front end non-catalytic fast pyrolysis reactor 

followed by a separate ex situ catalytic vapor phase upgrading reactor system. The ex situ reactor 

is not exposed to biomass associated solids (biomass, char, and mineral matter/ash) beyond 

unintended entrainment of fine material such as attrited solids and some mineral matter/ash

mixed with char. It should be noted that much of the mineral matter/ash is mixed with the char 

that is removed by the cyclones after the non-catalytic fast pyrolysis reactor. This makes the ex 

situ configuration a more benign environment for catalyst performance and maintenance; some

of the superior performance assumptions in this design for ex situ over in situ are based on this 

advantage. It is also possible for the ex situ reactor to have a fixed bed configuration, with a hot 

gas filter to remove fine solid material before the vapors from the fast pyrolysis reactor enter the 

ex situ upgrading reactor. In this report, all three reactors, (1) non-catalytic fast pyrolysis for the 

ex situ case, (2) catalytic fast pyrolysis or in situ, and (3) separate vapor phase upgrading or ex

situ reactors, are CFB systems. A hot gas filter may also be an option for ensuring that all

remaining entrained mineral matter/ash (even after two cyclones in the fast pyrolysis system) is

eliminated prior to the ex situ CFB reactor; this is not considered in the base case, and any future 

inclusion will be based on benefits to catalyst maintenance assessed from experimental results. 

Each of the CFB systems has an entrained flow reactor and a second fluidized bed combustor for 
15

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char/coke combustion, similar to FCC reactors. In the in situ and ex situ catalytic systems the 

combustor also serves as a catalyst regenerator by burning off coke deposits. The following 

paragraph focuses on the non-catalytic fast pyrolysis reactor and discusses some of the basis for 

the Aspen Plus model implementation, and equipment costs that needed to be taken into 

consideration [10]. Some of the key operating parameters and assumptions in our design are 

noted. Following this description of the non-catalytic system, variations introduced for the in situ

and ex situ upgrading reactors are pointed out.

3.2.1.1 Fast Pyrolysis System

The non-catalytic fast pyrolysis reactor outlet temperature is maintained at approximately 500°C. 

The reactor is operated at approximately 120 psia (~8 bar) with a hydrogen partial pressure of 

approximately 72–95 psia (5–6.6 bar) in the inlet fluidizing gas. The riser reactor is sized for a

residence time of less than 2 seconds, and velocity of 30 ft/s for design purposes. Hot sand 

returned from the combustor bed provides the heat necessary for the endothermic pyrolysis 

reactions. The reaction products include char and mineral matter in the solid phase along with 

vapors including water, as well as non-condensable light gases dominated by carbon monoxide 

(CO) and carbon dioxide (CO2). Upon exiting the riser reactor, the solids consisting of sand and 

mineral matter mixed with char are separated from the vapors in two cyclones in series. These 

solids are returned to the combustor. The vapor products are sent to an ex situ upgrading reactor. 

The combustor is operated at nearly the same pressure as the reactor; 20% excess air is supplied 

to burn the char. The combustor is sized assuming a superficial velocity of 2.5 ft/s and a 

transport disengagement height of 19 feet [23]. The reactor and combustor capital costs are

scaled based on actual gas volumetric flow rate; consequently there is a significant capital cost 

reduction predicted for higher operating pressures. The capital cost for the fast pyrolysis reactor 

and condensation train is comparable to the 2013 PNNL-led report [21] if the reactor and 

combustor are scaled using a higher volumetric flow rate at a lower pressure of 20 psia. Note that 

higher operating pressures assumed in this report also result in higher combustion-air 

compression costs, which is factored in the process model. The residual ash and finer particles 

are entrained in the flue gas and separated by two cyclones in series. The fines are sent for 

disposal and the flue gases go through a heat recovery train. Sand is heated during the 

combustion process. The hot sand is partially cooled in a solids-cooler to produce high pressure

steam; this allows the sand returning to the pyrolysis reactor to have the thermal capacity to 

maintain 500°C at the exit of the fast pyrolysis reactor because pyrolysis is an endothermic 

process. A 1% heat loss on a lower heating value (LHV) of biomass basis is assumed, each in the 

combustor and the pyrolysis reactor. The sand flow is calculated within the constraints of 

delivering the right amount of heat to the pyrolyzer, while at the same time maintaining the 

combustor at a specified temperature of 720°C (1,328°F). The solids cooler consists of a vessel 

containing a series of 2.5-inch diameter A335 P91 tubes, and is sized based on the required heat

duty and an assumed overall heat transfer coefficient of 31.7 Btu/hr-ft2

-°F [24]. The solids cooler 

price is scaled based on duty. All of the vessels and ducts are made of carbon steel with 

refractory lining, and were originally estimated based on a 150 psia design pressure [10]. Two 

parallel trains are proposed, each handling 1,000 dry metric tonnes per day of biomass, because 

of anticipated biomass feeding constraints into a single reactor.
16

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3.2.1.2 In Situ Upgrading System

The in situ catalytic fast pyrolysis reactor has a similar design as the system described above. In 

this case, the circulating solid is a catalyst instead of sand. A significant change occurs in the 

thermal balance and heat removal requirements due to the formation of coke that needs to be 

burned along with the char in the combustor bed. Hydrogen partial pressure in the fluidizing gas 

was chosen to be slightly higher (still within the 72–95 psia range), with the consideration that 

some additional pressure will be necessary for hydrogen reactivity in a more challenging in situ

catalytic environment (compared to the ex situ case). The assumption of partial pressure will be 

revised later (approximately within the 25 psia to 120 psia range) based on experimental results 

for both the in situ and ex situ systems. The in situ reactor design is otherwise similar to the noncatalytic system. Catalyst circulation is calculated within the thermal constraints described for 

the non-catalytic fast pyrolysis reactor. The combustor temperature was lower at 650°C

(1,202°F), based on constraints for HZSM-5 [25]. Two percent of the catalyst inventory is

replenished per day; typical FCC replenishment rates are between 1% and 3% per day [26]. An 

additional 1.6% of the inventory is assumed to be replaced to account for attrition. It is expected 

that an equilibrium catalyst (E-Cat) with activity commensurate to conversion requirements will 

be established as the system is operated. Catalyst costs and related assumptions are based on 

FCC catalysts, using the rare earth metals lanthanum and cerium for catalyst stability. The 

$19,500/ton catalyst cost was in anticipation of the use of rare earth metals [27] and nonprecious metals such as nickel for hydrogenation, in addition to a base catalyst cost [28]. As 

noted earlier, catalyst research will be key to the success of these conversion pathways, and these 

assumptions will be modified with advances in the research. Stripping steam is used in this 

reactor system and also in the ex situ upgrading reactor system to recover additional product 

from the catalyst surface. A design specification of 3 lbs of steam per 1,000 lbs of catalyst was 

used with a catalyst flux of 600 lb/min/ft2 [14]. Cost of an additional vessel with structured 

410SS packing internals was added for this purpose, and was sized assuming a height of 28 feet 

based on vendor estimates. The stripper is scaled based on catalyst flow rate, which is the 

primary variable affecting the vessel diameter.

3.2.1.3 Ex Situ Upgrading System

The ex situ system catalyst material assumptions are the same as for in situ systems. The catalyst 

replenishment rate was also assumed to be 2% of the inventory per day. In addition it is assumed 

that 1.6% of the inventory is added to the reactor system per day to account for attrition losses. 

The total replacement assumption of 3.6% of the inventory per day may be conservative; this 

leaves leeway for the future use of more expensive catalysts with lower replacement rates for the 

in situ and ex situ cases. The catalyst flow rate was fixed at 5 times the mass flow rate of dry 

biomass, which is lower than the corresponding value of 7.5 times for the in situ case, an 

assumption based on a more benign environment for in the ex situ reactor. This is a parameter 

that can be adjusted in the simulation based on specific catalyst activity and performance. The 

heat balance in the ex situ reactor is significantly different because this system is expected to be 

exothermic (as also predicted by the Aspen Plus model) and an additional catalyst cooling step to 

341°C (645°F) is necessary after the catalyst is regenerated at 650°C (1,202°F). While reactor 

design temperature in the base case is 500°C (932°F) at the outlet of the ex situ reactor, this 

temperature will likely be revised as experimental results become available. Also, there is no 

biomass feed into the ex situ vapor phase upgrading reactor because it follows a separate noncatalytic biomass fast pyrolysis reactor. Thus the ex situ reactor does not have the scale-up
17

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constraints associated with biomass feed; in this report we limited each CFB system with

biomass feed to 1,000 dry metric tonnes/day capacity based on publicly available industrial fast 

pyrolysis reactor sizing information. Therefore, a single large ex situ reactor can process the 

entire vapor stream from 2x1,000 dry metric tonnes/day fast pyrolysis reactors. Note that this

scale-up is the primary reason for the lower cost of the ex situ reactor compared to the other CFB 

reactor systems (with biomass feed) shown in Table 5. The total heat loss in the ex situ reactor 

was assumed to be 1% of the LHV of biomass (0.5% each in the reactor and catalyst 

regenerator). The use of a hot gas filter is not considered in the base case, although some 

discussion is provided with the sensitivity analysis presented in Section 5. The use of precious 

metals in catalysts, which may be feasible in fixed bed reactor systems, is also left for future 

consideration and analysis.

3.2.1.4 Comparison of In Situ and Ex Situ Upgrading

A summary of some of the key differences between the in situ and ex situ upgrading approaches 

are summarized in Table 3.

Table 3. Comparison of In Situ and Ex Situ Upgrading

In Situ Ex Situ

Fluidized bed systems only Fluidized or fixed bed; fixed bed systems 

can use precious metal catalysts. Coke 

formation needs to be minimized for the 

feasibility of fixed bed systems.

Lower capital because of single reactor Higher capital because of separate ex situ

upgrading reactor.

Hot gas filter (HGF) not required HGF necessary for fixed bed systems, and 

maybe desirable for fluidized systems; HGF 

can result in additional yield losses.

Catalyst mixes with biomass, char, mineral 

matter/ash

Biomass, char, mineral matter/ash reduced 

or removed upstream of reactor.

Higher catalyst replacement requirement 

because of higher irreversible catalyst 

deactivation from inorganic material (e.g.,

alkali)

Lower catalyst replacement requirement 

because of the removal of inorganic matter 

upstream of the reactor (using cyclones and 

optionally a hot gas filter).

Operating conditions closely tied to fast 

pyrolysis conditions

Flexibility to operate at different conditions 

(e.g., temperature, contact time) compared 

to upstream fast pyrolysis reactor; this will 

allow optimizations for higher carbon 

efficiency, product selectivity, deactivation 

rates, etc.

3.2.1.5 Pressure and Hydrogen Assumptions

The conceptual designs presented in this report assume higher than atmospheric pressures and 

hydrogen-enriched fluidizing gases as described above (Table 4). While the primary 

consideration for proposing an elevated pressure was the potential benefit to the chemistry 

including hydrodeoxygenation, hydrogenation, and yield improvements, there are also

advantages from a process economics standpoint based on the following:
18

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• Hydrogen partial pressure is below the embrittlement pressure for carbon steel as 

indicated by Nelson curves [29]. Based on this information it was not required to modify 

the proposed reactor materials of construction (refractory-lined carbon steel) for this 

conceptual process design.

• Capital costs are lower because of lower volumetric flow rates and smaller equipment.

• There is increased feasibility of using a hot gas filter in future variations of this design. 

Hot gas filter costs scale by the actual volumetric gas flow rate. The process can remain 

cost competitive even with the addition of a hot gas filter because of the lower volumetric 

flow rate at these slightly elevated pressures.

3.2.1.6 Catalysts

Catalyst research and development will be key for achieving the functionality and product yields 

targeted in this report for 2022. Zeolite-based catalysts have been used extensively for fast 

pyrolysis vapor upgrading [30, 31]. Experimental results using ZSM-5 and its variations are the 

most widely reported in the literature [8, 32, 33, 34, 35, 36, 37]. In this report we assumed the

use of similar catalysts, with metal additives for hydrogen activity, and rare earth metal additives 

for stability, deployed in a circulating fluidized bed system.

It is understood that performance outlined with respect to hydrodeoxygenation, hydrogenation, 

and molecular combination (coupling) will require significant advances in catalysts. In addition, 

with further maturity of the research and product characterization, ring-opening chemistry will 

likely become very desirable; the optimal location for utilizing such chemistry in the process 

configuration will need to be determined, with the downstream hydroprocessing step being an 

option to consider. The conceptual processes outlined in this report are expected to be modified 

(in the 2017 timeframe) based on experimental results for the catalysts being developed. The use

of noble metals in fixed bed reactors (preceded by a hot gas filter) during ex situ upgrading is 

another promising configuration. The use of bifunctional catalysts has been suggested for this 

vapor upgrading step [9]. Information about the chemistry and candidate catalysts for enhancing 

coupling reactions such as ketonization, aldol condensation, and hydroalkylation are also

available in literature [9, 38]. The biggest challenge for the ex situ pathway is to accomplish and 

optimize the chemistry to desired products within an economically feasible number of steps, 

while also minimizing yield losses in each step, including during any associated hot gas 

filtration.

It will be important to reduce rates of irreversible catalyst deactivation to improve longevity and 

reduce replacement rates. Critical catalyst deactivation mechanisms are poisoning by inorganic 

impurities, structural changes that result from elevated temperatures during regeneration, and the 

presence of water and acids leading to physical degradation. By analogy with FCC systems, all 

components of the catalyst (active site, matrix, binder) will need to exhibit stability under 

process conditions.

3.2.2 Area 200 Design Basis

The design basis for the fast pyrolysis and catalytic vapor upgrading area is presented in Table 4.

This basis reflects the overall plant capacity of 2,000 dry metric tonnes per day (2,205 dry tons 

per day). Product flow information is provided under Area 300. Detailed process flow diagrams 
19

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and stream summaries are presented in Appendix G (A-201 in Appendix G-1 for in situ, and A201 to A-203 in Appendix G-2 for ex situ).

Table 4. Design Basis for Fast Pyrolysis and Catalytic Vapor Upgrading

Configuration In Situ Ex Situ

Reactor for Fast 

Pyrolysis with In 

Situ Vapor 

Upgrading

Reactor for NonCatalytic Fast 

Pyrolysis

Reactor for Ex 

Situ Vapor 

Upgrading

Reactor

Parallel trains for reactor and 

combustor 2 2 1

Total biomass feed rate per 

train, dry metric tonnes/day 1,000 1,000 N/A

Biomass moisture (wt %) 10 10 N/A

Exit temperature, °C (°F) 500 (932) 500 (932) 500 (932)

Pressure, psia (bar) 121 (8.3) 121 (8.3) 117 (8.1)

Bed solids material Catalyst (ZSM-5) Sand Catalyst (ZSM-5)

Bed solids inventory (ton) 115 120 77

Catalyst replacement (% of 

reactor system inventory) 2 N/A 2

Additional catalyst attrition (% of 

reactor system inventory) 1.6 N/A 1.6

Ratio of bed solids to dry 

biomass (w/w) 7.5 7.8 5.0

Number of cyclones per reactor 2 2 2

Stripping steam (lb/1,000 lb 

catalyst) 3 - 3

Fluidizing gases to dry biomass 

(w/w) 0.86 0.76 -

H2 partial pressure in fluidizing 

gas, psia (bar) 86 (6) 93 (6.4) 72 (5.0)

Combustor/Regenerator

Temperature, °C (°F) 650 (1,202) 720 (1,328) 650 (1,202)

Pressure, psia (bar) 117 (8.1) 117 (8.1) 113 (7.8)

Excess air (%) 20 20 20

Solids temperature before 

transfer to reactor, °C (°F) 650 (1,202) 720 (1,328) 341 (645)

No. of cyclones per combustor 2 2 2

3.2.3 Area 200 Equipment Cost Estimations

Capital costs for the equipment in this area were estimated by Harris Group. A previously 

developed spreadsheet tool for gasifier costs was leveraged for this exercise. Cost estimates from 

this tool were compared with order of magnitude estimates from technology vendors and 

documented in Appendix I of Worley et al. [10]. Of particular interest for this report, because of 

significant parallels to the three reactors in our design (as discussed in Section 3.2.1), is the CFB 
20

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gasifier. The CFB gasifier estimation tool was used with the flow rates in the Aspen Plus model 

for developing cost estimates shown in Table 5. Another advantage of using the tool was its 

adaptability to add on estimates for additional vessels such as catalyst coolers and steam 

strippers, which were not originally built into the CFB gasifier configuration. The tool also 

provided estimates for the biomass feeder, which was not included into our economics because 

INL’s feedstock logistics already includes biomass feeding within the $80/dry U.S. ton feedstock 

cost. Operating cost assumptions are shown in Section 4 and impacts on the overall economics 

are summarized in Appendix C.

Table 5. Capital Cost Estimates for the Fast Pyrolysis and Catalytic Vapor Upgrading Area

TPEC

(2011$k)

TIC

(2011$k)

In Situ Configuration

Catalytic fast pyrolysis CFB reactor/regenerator $28,558 $85,829

Heat integration $2,524 $6,651

Area A200 subtotal $31,082 $92,480

Ex Situ Configuration

Fast pyrolysis CFB reactor/combustor $23,163 $71,847

Ex situ catalytic vapor upgrading

reactor/regenerator $14,835 $48,103

Heat integration $2,653 $6,991

Area A200 subtotal $40,651 $126,941
21

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3.3 Area 300: Pyrolysis Vapor Quench and Product Recovery

The following section presents an overview, basis for design, and cost estimates for upgraded 

pyrolysis vapor quench, product recovery and fluidizing gas recycle. 

3.3.1 Area 300 Overview

Figure 6 is a simplified flow diagram showing the major equipment in this section.

Figure 6. Simplified process flow diagram of pyrolysis vapor quench and product recovery

Upgraded vapors from both in situ and ex situ configurations are quenched to condense and 

separate vapors from non-condensable gases. Note that there is a significant proportion of noncondensable gases beyond those produced from the pyrolysis reactions. In particular, the gases 

are rich in hydrogen because of a deliberate attempt to create a hydrogen-rich atmosphere to

favorably impact the chemistry. In addition, water constitutes a large fraction of the condensable 

vapors. The base case assumes that there will remain concerns about fouling of indirect heat 

exchange equipment during the condensation of the heavy fraction of the organic vapors. Heat is 

recovered via indirect heat exchange up to the dew point of the vapors, predicted to be 241°C 

(466°F). A first absorber/condenser is then used to recover the heavy organic fraction using a 

quench stream of recycled liquid consisting of the light organic fraction. Nearly 40 wt % of the 

organic product is condensed out and recovered at the bottom of the absorber/condenser. The 
22

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overhead products exit at 176°C (348°F) and 181°C (358°F) for the in situ and ex situ cases,

respectively, and enter an indirect heat exchanger train to cool down the remaining vapors. 

Process heat recovery, air cooling to 60°C (140°F), water cooling to 43.3°C (110°F) and chilled 

water cooling to 15.6°C (60°F) are used in sequence. This stream then enters a second 

absorber/condenser where a light organic phase and an aqueous phase are recovered as the 

bottoms product and separated by decantation. The recycled light organic product is chilled to 

10°C (50°F) and used as the quench liquid. The light and heavy organic fractions are mixed and 

sent for hydroprocessing, while the aqueous fraction is sent to wastewater treatment. Filters are 

included for all three product streams (heavy organic, light organic, aqueous). Proper filtration to 

remove particulates from the organic phases is important for the maintenance of the downstream 

hydrotreating catalyst.

The non-condensable gases from the top of the absorber-condenser are split into (1) a purge 

stream (1%) to the reformer, (2) recycle to the fast pyrolysis reactor for fluidization (75% for in 

situ and 71% for ex situ), and (3) the balance sent to a sour water gas shift (WGS) reactor. The

inlet temperature of the WGS reactor is 240°C (464°F) [39]. Steam for the WGS reactor is 

generated from the collected waste aqueous streams using a reboiler (discussed later under 

A800). The product from the WGS reactor is cooled and condensed water is sent to the 

wastewater section. The gases are then compressed to approximately 220 psia and cooled to 

43.3°C (110°F) before being sent to a PSA unit with 84% hydrogen recovery at 99% purity. The 

PSA off-gases are sent to the reformer section for use either as fuel or reformer feed; this split is 

determined by the heat balance of the reformer system. The hydrogen is recycled back to the fast 

pyrolysis reactor (ex situ case) or the catalytic fast pyrolysis reactor (in situ case). In both the in 

situ and ex situ configurations, supplemental hydrogen is added to maintain the design H2 partial 

pressure of approximately 72–95 psia in the fluidizing gas.
23

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3.3.2 Area 300 Design Basis

Table 6 summarizes the design basis and other key information for this area. Detailed process 

flow diagrams and stream summaries are presented in Appendix G (A-301 to A-304 in Appendix 

G-1 for in situ, and A-301 to A-305 in Appendix G-2 for ex situ).

Table 6. Design Basis for Pyrolysis Vapor Quench and Product Recovery

Configuration In Situ Ex Situ

Heavy fraction condenser-absorber

Overhead temperature, °F 348 358

Pressure, psia 114 110

Feed rate, lb/h 329,131 310,342

Recycle liquid flow, lb/h 86,730 81,043

Vapor product, lb/h 396,315 371,714

Bottoms liquid product, lb/h 19,547 19,671

Light fraction condenser-absorber

Feed temperature, °F 60 60

Overhead pressure, psia 101 97

Recycle liquid flow, lb/h 964,869 901,600

Vapor product, lb/h 199,763 182,444

Bottoms liquid flow, lb/h 1,161,420 1,090,871

Mole % H2 overhead in gas 62% 68%

Aqueous phase

Flow rate, lb/h 77,273 77,811

Mass percent C 2.6% 1.6%

Total organic phase (heavy + light)

Flow rate, lb/h 52,053 50,051

Mass percent C, H, O 80%, 10%, 10% 83%, 11%, 6%

Water gas shift

Feed gas flow rate, lb/h 48,356 51,621

Inlet temperature, °F 464 464

Outlet temperature, °F 663 637

Pressure, psia 88 86

Steam flow rate, lb/h 29,556 30,755

Temperature approach to equilibrium, °F 35 35

Wastewater (condensate), lb/h 19,648 20,736

Pressure swing adsorption (PSA)

Inlet flow rate, lb/h 58,265 61,652

Inlet hydrogen mole % 67% 71%

Hydrogen recovery % 84% 84%

Hydrogen purity % 99% 99%

Hydrogen product stream, lb/h 5,462 7,032
24

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3.3.3 Area 300 Equipment Cost Estimations

Table 7 presents the capital cost summary for this area. Further capital cost details are available 

in Appendix B.

Table 7. Cost Estimate for Pyrolysis Vapor Quench and Product Recovery

TPEC

(2011$k)

TIC

(2011$k)

In Situ Configuration

Product condensation and separation $4,977 $8,542

Water gas shift and PSA $5,312 $8,890

Heat integration $1,881 $4,958

Area A300 subtotal $12,170 $22,390

Ex Situ Configuration

Product condensation and separation $5,071 $8,652

Water gas shift and PSA $6,146 $10,286

Heat integration $2,004 $5,282

Area A300 subtotal $13,221 $24,220
25

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3.4 Area 400: Hydroprocessing and Product Separation

The following section presents an overview, basis for design, and cost estimates for the 

hydrotreating, hydrocracking, and product fractionation operations.

3.4.1 Area 400 Overview

Figure 7 presents a simplified process flow diagram for this area. Some equipment, including 

many heat exchangers, is not shown for simplicity.

Figure 7. Simplified process flow diagram of the hydroprocessing and product separation area

The organic liquid fraction collected from the condensation of upgraded vapors in A300 is sent 

to a hydrotreater for further deoxygenation, as well as for saturating a portion of the products to 

reduce aromatic content. A sulfided CoMo catalyst is assumed for the hydrotreating reactor, 

although other catalysts may also be considered [40]. Note that the separation of the aqueous 

phase in A300 significantly reduces the liquid flow to the hydrotreater. The hydrotreater is 

modeled as a three-bed packed reactor with intermediate hydrogen quench to limit temperature 

rise in the reactor within 27.8°C (50°F). The organic liquid feed is mixed with 34% of the total 

hydrogen feed into the reactor. This feed is cross-exchanged with the hydrotreating reactor 

product for preheating the feed and cooling the reactor effluent. Following this a feed preheat 

furnace, designed for a 40°C (72°F) temperature rise, heats the feed to 375°C (707°F). The 
26

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remaining 66% of the hydrogen is introduced in equal amounts (33% each) between the reactor 

beds. The inlet temperature for these hydrogen streams is 43.3°C (110°F). The reactor outlet, 

after cross-exchange with the reactor feed, is further cooled via process, air, and water 

exchangers in series. The products are then sent to a flash drum where the gas (mostly hydrogen) 

and liquid streams are separated. The aqueous portion of the liquid stream is separated via 

decantation and sent to the wastewater handling section (A800). The organic portion is sent for 

fractionation (discussed below). The gases are then recycled to the hydrotreating reactor after 

recompression. A portion of the gases are purged (19% for the in situ case and 12% for the ex 

situ case) to maintain less than 10 mole % impurities in the feed hydrogen. Makeup hydrogen is 

added to account for purge losses and hydrogen consumption in the reactor. The purge stream is 

fed directly to the PSA in Area 500. The total hydrogen feed to the reactor based on these design 

assumptions was 14,174 scf/bbl (4,133 scf/bbl makeup) for the in situ case and 9,161 scf/bbl 

(2,306 scf/bbl makeup) for the ex situ case. While there is a significant amount of information in 

literature about petroleum refinery hydrotreating and rules of thumb for hydrogen use, there is 

very little information about hydrotreating highly oxygenated products at scale; hence, we 

decided to use the logical steps dictated by the process operations and temperature control 

considerations outlined above to determine hydrogen consumption and recycle. An acid gas 

removal system for controlling hydrogen sulfide (H2S) was not deemed necessary because of the 

low sulfur content in the biomass feedstock. PSA systems can be designed to handle low

quantities of H2S produced or sulfur introduced for maintenance of sulfided hydrotreating 

catalysts [41]. H2S concentrations at the hydrotreater inlet in the model were ~100 ppm (in situ

case) and ~170 ppm (ex situ case) on a mole basis, which should be capable of keeping the 

catalyst sulfided.

The hydrotreater inlet pressures for the in situ and ex situ cases were 1,845 psia and 1,545 psia,

respectively. This decision was based on the premise that less severe hydrotreating will be 

necessary for the lower oxygen content product from the ex situ upgrading case. This assumption 

will require future experimental validation. 

The product from the hydrotreater is sent for fractionation. The first column separates light gases 

and a gasoline boiling range fraction as its overhead product, with an off-gas stream purged and 

used as fuel. Note that products from hydrocracking are also fed to a lower section of this same 

column. The bottoms product from this column is sent to a second column where diesel boiling 

range product is recovered overhead. The heavier bottoms product is sent for hydrocracking; any

products heavier than the distillate/diesel-range are recycled to extinction via hydrocracking.

The design of the hydrocracker follows the same logic outlined under the discussion for the 

hydrotreater. Note that the oxygen content of the organic liquid feed to the hydrocracker is 

assumed to be reduced to ~1% as a result of the previous hydrotreating operation. The catalyst is 

assumed to be crystalline silica-alumina based with rare earth metals and metals added for 

hydrogenation activity [42]. The hydrocracking inlet pressure was 1,945 psia, with a reactor inlet 

temperature of 392°C (738°F). The same limitations of a 27.8°C (50°F) temperature rise within

the reactor and 10% impurity in the hydrogen feed were also assumed here. The hydrogen feed 

to the reactor was 16,347 scf/bbl (6,867 scf/bbl makeup) for the in situ case and 8,272 scf/bbl 

(3,091 scf/bbl makeup) for the ex situ case. Again, we relied on the simulated operational 

considerations mentioned above for a logical derivation of hydrogen consumption based on 

operational and temperature constraints.
27

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Process model flow information for the hydrotreater, hydrocracker, and fractionation columns is 

summarized in Table 8. Detailed process flow diagrams and stream summaries are presented in 

Appendix G (A-401 to A-403 in Appendix G-1 for in situ, and A-401 to A-404 in Appendix G-2 

for ex situ). Note that an additional design specification was added to scale the carbon efficiency 

based on oxygen content of the feed material entering the hydrotreater. A linear scale was 

assumed with 85% carbon efficiency for ~20% oxygen content [43] and 98.5% carbon efficiency 

for negligible oxygen content as is usually the case in petroleum refineries (based on 

approximations from case studies outlined by Gary and Handwerk for petroleum refineries [42]).

This is shown in Figure 8.

Figure 8. Assumed hydroprocessing carbon efficiency vs. oxygen content in organic liquid feed
28

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Table 8. Process Model Flow Information for A400

In Situ Ex Situ

Hydrotreater

Liquid feed, lb/h 52,053 50,051

Liquid feed wt % C, H, O 80%, 10%, 10% 83%, 11%, 6%

Total hydrogen feed (pure H2), lb/h 11,219 7,249

Hydrogen stream mole % purity 90% 90%

Makeup hydrogen (pure H2), lb/h 3,274 1,824

Product gas (HP flash), lb/h 28,548 17,435

Product gas (HP flash) mole % hydrogen 87% 87%

Purge gas (HP flash), lb/h 5,327 2,061

Purge gas (LP flash), lb/h 870 787

Aqueous phase product, lb/h 4,696 2,912

Organic phase product, lb/h 45,023 46,446

Organic phase product wt % C,H,O 87%, 12%, 1% 86%, 13%, 1%

Hydrocracker

Liquid feed, lb/h 8,833 16,654

Liquid feed wt % C, H, O 88%, 11%, 1% 88%, 11%, 1%

Total hydrogen feed (pure H2), lb/h 2,154 2,109

Hydrogen stream mole % purity 90% 90%

Makeup hydrogen (pure H2), lb/h 905 647

Product gas (HP flash), lb/h 5,487 4,353

Product gas (HP flash) mole % hydrogen 84% 87%

Purge gas (HP flash), lb/h 1,342 298

Purge gas (LP flash), lb/h 412 356

Aqueous phase product, lb/h 80 129

Organic phase product, lb/h 8,068 16,636

Organic phase product wt % C,H,O 85%, 15%, 0% 86%, 14%, 0%

Gasoline boiling range column

Feed from hydrotreater, lb/h 45,023 46,446

Feed from hydrocracker, lb/h 8,068 16,636

Gasoline range product, lb/h 31,866 20,408

Light gases, lb/h 547 1,281

Bottoms flow to diesel column, lb/h 20,678 41,393

Diesel boiling range column

Feed from gasoline-range column, lb/h 20,678 41,393

Diesel-range product, lb/h 11,845 24,739

Bottoms product to hydrocracker, lb/h 8,833 16,654

Overall efficiency

Carbon efficiency % 91% 94%

Yield lb product/lb feed 0.84 0.90

Oxygen content in feed/product (wt %) 10.5%/0.5% 6.4%/0.4%
29

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3.4.2 Area 400 Design Basis

For our equipment design, we assumed a relatively high severity would be required in 

hydrotreating. In addition to higher temperature and pressure, higher severity is characterized by 

lower weight hourly space velocity (WHSV):

WHSV=

mass flow of feed

mass of catalyst

We chose WHSV to avoid using liquid density predictions, which can sometimes be highly 

dependent on the model compounds and physical property methods chosen. We assumed 0.5 h-1

for hydrotreating and hydrocracking in our design, which is considered severe for most

petroleum refining hydroprocessing operations. A WHSV of 0.5 h-1 usually translates to a lower 

liquid hourly space velocity (LHSV) for most feedstock and catalyst combinations with an 

example of such conversion provided by Elliott et al. [44]. Hydrotreating of raw bio-oil without 

vapor phase deoxygenation is expected to be even more severe (lower space velocity) as 

indicated by LHSV values in literature [21, 40, 45]. For a given feed rate, the WHSV determines 

the total mass of catalyst required. Given a catalyst density, the total reactor volume is also 

determined by WHSV. However, because of the relatively high pressure requirements as noted 

above, these hydrotreating reactors have relatively thick walls of 2–4 inches and are thus quite 

heavy. When we estimated the price of the hydrotreating reactors, we therefore specified adders 

within the cost estimation software for field fabrication.

The design basis for the hydrotreating and hydrocracking reactor systems are presented in Table

9 and Table 10. Note that the vessel length of 48 feet is not entirely catalyst-full. Reactor 

internals were assumed to occupy 33% of the reactor volume, and additionally a 70% overdesign 

was applied to bed length to accommodate catalyst deactivation over time [46, 47]. Included

among the reactor internals are inlet distributors, catalyst supports, redistribution trays, quench 

distributors, and outlet collection. The design catalyst bed length was therefore 19 feet. 

The hydrotreating and hydrocracking reactor products are cooled and flashed at two different 

pressures to separate the hydrocarbons from reaction water and unreacted hydrogen. A recycle

compressor serves the higher-pressure flash (approximately 20 psi below reactor outlet) gas 

stream. Both the hydrotreating and hydrocracking reactors also have hydrogen makeup 

compressors to bring hydrogen from Area 500 up to reactor pressure. The specifications for the 

compressors are summarized in Table 11.
30

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Table 9. Design Basis Parameters for Hydrotreating Reactor

Process Parameters In Situ Ex Situ

Reactor inlet temperature, °C (°F) 375 (707) 375 (707)

Reactor outlet temperature, °C (°F) 403 (757) 403 (757)

Reactor pressure, psia 1,845 1,545

Reactor pressure drop, psi 30 30

Hydrogen inlet purity 90 mol% 90 mol%

Outlet hydrogen stream recycle/purge, % 81/19 88/12

Hydrogen feed (and makeup), scf/bbl HT feed 14,174 (4,133) 9,161 (2,306)

Chemical hydrogen consumption (lb/100 lb HT feed) 2.6 2.1

No. of internal beds per modeled reactor 3 3

Reactor Design Parameters

Reactor length, ft 48 48

Reactor diameter, ft 10 10

Weight hourly space velocity, hour-1 0.5 0.5

Catalyst density, lb/ft3 78 78

Catalyst bed length overdesign 70% 70%

Reactor internals volume 33% 33%

Mass of catalyst (design), lb 122,520 112,000

Mass of catalyst (actual), lb 208,290 190,430

Material of construction A204C with Inconel Cladding

Table 10. Design Basis Parameters for Hydrocracking Reactor

Process Parameters In Situ Ex Situ

Reactor inlet temperature, °C (°F) 392 (738) 392 (738)

Reactor outlet temperature, °C (°F) 420 (788) 420 (788)

Reactor pressure, psia 1,945 1,945

Reactor pressure drop, psi 30 30

Hydrogen inlet purity 90 mol% 90 mol%

Outlet hydrogen stream recycle/purge, % 76/24 93/7

Hydrogen feed (and makeup), scf/bbl HC feed 16,347 (6,867) 8,272 (3,091)

Chemical hydrogen consumption (lb/100 lb HC feed) 5.4 3.1

No. of internal beds per modeled reactor 3 3

Reactor Design Parameters

Reactor length, ft 48 48

Reactor diameter, ft 6.5 6.5

Weight hourly space velocity, hour-1 0.5 0.5

Catalyst density, lb/ft3 78 78

Catalyst bed length overdesign 70% 70%

Reactor internals volume 33% 33%

Mass of catalyst per reactor (design), lb 21,200 36,600

Mass of catalyst per reactor (actual), lb 36,060 62,200

Material of construction A204C with Inconel Cladding
31

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Table 11. Design Parameters for Hydrogen Compressors

Hydrotreating Recycle Compressor

Service Recycled unreacted hydrogen

Inlet pressure 1,793 psia (in situ)/1,493 psia (ex situ)

Outlet pressure 1,900 psia (in situ)/1,600 psia (ex situ)

Inlet mass flow 27,085 lb/h (in situ)/17,528 lb/h (ex situ)

Inlet molecular weight 2

Drive power source Electric motor

Inter-stage cooling Process, air, cooling water

Number of stages 1

Electrical consumption 176 kW (in situ)/134 kW (ex situ)

Hydrocracking Recycle Compressor

Service Recycled unreacted hydrogen

Inlet pressure 1,893 psia

Outlet pressure 2,000 psia

Inlet mass flow 5,214 lb/h (in situ)/4,819 lb/h (ex situ)

Inlet molecular weight 2

Drive power source Electric motor

Inter-stage cooling Process, air, cooling water

Number of stages 1

Electrical consumption 32 kW (in situ)/31 kW (ex situ)

Hydrotreating Makeup Compressor

Service Pipeline hydrogen

Inlet pressure 245 psia

Outlet pressure 1,795 psia (in situ)/1,495 psia (ex situ) 

Inlet mass flow 3,865 lb/h (in situ)/2,154 lb/h (ex situ)

Inlet molecular weight 2

Drive power source Electric motor

Inter-stage cooling Process, air, cooling water

Number of stages 4

Electrical consumption 1,765 kW (in situ)/888 kW (ex situ)

Hydrocracking Makeup Compressor

Service Pipeline hydrogen

Inlet pressure 245 psia

Outlet pressure 1,995 psia 

Inlet mass flow 1,068 lb/h (in situ)/764 lb/h (ex situ)

Inlet molecular weight 2

Drive power source Electric motor

Inter-stage cooling Process, air, cooling water

Number of stages 4

Electrical consumption 516 kW (in situ)/369 kW (ex situ)
32

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3.4.3 Area 400 Equipment Cost Estimations

The estimated purchased equipment costs and total installed costs for the hydroprocessing area 

were gathered from various sources, including technology licensors, industrial suppliers, 

published literature, and ACCE. The sources are listed in Appendix A.

Table 12 presents the equipment list and cost estimates for the hydroprocessing area of the plant.

Table 12. Cost Estimate for the Hydroprocessing Area

Equipment Description In Situ Ex Situ

TPEC TIC TPEC TIC

(2011$k) (2011$k) (2011$k) (2011$k)

Hydrotreating reactor $8,351 $13,257 $6,213 $10,514

Hydrocracking reactor $1,548 $3,274 $2,472 $5,116

Recycle and makeup compressors $7,013 $11,221 $5,159 $8,254

Product separation columns $1,105 $2,804 $1,287 $3,188

Heat integration $754 $1,988 $772 $2,033

Area A400 subtotal $18,771 $32,544 $15,902 $29,106

3.5 Area 500: Hydrogen Plant

The following section presents an overview, basis for design, and cost estimates for the steam 

reformer, water gas shift reactor, PSA, and associated equipment used for hydrogen production. 

3.5.1 Area 500 Overview

A fixed-bed steam methane reformer package was used for hydrogen production. The small 

amount of natural gas feed (shown in Table 13) was used entirely for hydrogen production and 

fed to the reformer because there is sufficient fuel gas available in the process to provide all the 

heat duty necessary to run the reformer. The reformer was modeled as a Gibbs equilibrium 

reactor operating at 115 psia and 880°C (1,616°F) with a 30°C (54°F) approach to equilibrium. 

Steam is provided from a wastewater recycle boiler in Area 800. The product gases are quenched 

and sent to high temperature and low temperature shift reactors in series with intermediate heat

exchange for temperature control. Following the reformer, the gases are cooled and condensate 

removed. The gases are then compressed to 278 psia for feeding to a PSA. The PSA design 

assumes 80% hydrogen recovery with 99% purity. Off-gases from the PSA are used as 

combustion fuel.
33

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3.5.2 Area 500 Design Basis

Table 13 summarizes the design basis for the equipment in the hydrogen plant, including the 

steam methane reformer, WGS reactor, and PSA unit. Detailed process flow diagrams and 

stream summaries are presented in Appendix G (A-501 to A-504 in Appendix G-1 for in situ, 

and A-501 to A-505 in Appendix G-2 for ex situ).

Table 13. Design Basis Parameters for Hydrogen Plant

Hydrogen Plant Design Parameters

Hydrogen production rate 30.0 MMscfd (in situ)/27.4 MMscfd (ex situ)

Supplemental natural gas* 54 lb/h (in situ)/125 lb/h (ex situ)

Hydrogen outlet purity 99 mol %

Hydrogen outlet pressure 266 psia

 *Negligible natural gas required because of the availability of fuel gas from the process.

3.5.3 Area 500 Equipment Cost Estimations

For consistency, the hydrogen plant cost was derived from the same sources and methodology 

cited in the 2013 design report led by PNNL [21]. The report documented equipment costs for a 

large hydrogen plant producing 44.5 million scf/day of hydrogen. The costs were reported as a 

package, including the sulfur guard bed, pre-reformer, SMR, WGS, PSA, compressors, and heat 

integration. The total cost was entered into our model and scaled to the required hydrogen 

production rates shown above using the same scaling law as in the 2013 report [21]. Table 14

shows the major costs in the hydrogen plant area.

Table 14. Cost Estimate for Hydrogen Production Area

Equipment Description In Situ Ex Situ

TPEC TIC TPEC TIC

(2011$k) (2011$k) (2011$k) (2011$k)

SMR, WGS, PSA package $28,968 $55,330 $27,368 $52,267

Pyrolysis off-gas compressor to SMR $4,447 $7,159 $4,219 $6,799

Additional heat integration $3,093 $8,152 $2,920 $7,696

Area A500 subtotal $36,508 $70,640 $34,507 $66,762

3.6 Area 600: Steam System and Power Generation

The following section presents an overview, basis for design, and cost estimates for construction 

of the steam system and power generation facilities. 

3.6.1 Area 600 Overview

A conventional steam cycle uses process heat to produce electricity. There is a significant 

amount of heat available in the process that needs to be managed efficiently to positively impact 

the economics. The big sources of heat are the char and coke combustors, upgraded pyrolysis 

vapors (including fluidization gases) cooling, steam reformer flue gas, and reformed gas quench. 

In both the in situ and ex situ designs there is excess electricity available after all consumption in 

the plant is met. This electricity is sold to the grid and reduces the MFSP by 4¢/GGE and 
34

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3¢/GGE for the in situ and ex situ cases, respectively. Excess heat available for power generation 

was determined by conducting an overall plant heat balance. The heat balance assumptions are 

checked for thermodynamic viability by drawing heating and cooling curves for pinch analysis 

and ensuring there is no crossover between the curves. Electricity is generated using two steam 

turbines, with intermediate reheat. Pre-heaters, steam generators, and super-heaters are integrated 

within the process design to generate the steam from boiler feed water (BFW). Process 

condensate is recycled to the steam cycle, de-gassed, treated, and combined with makeup water.

The steam turbine efficiencies are assumed to be 75% and the generator mechanical efficiencies 

are assumed to be 97%. The first stage turbine drops the steam pressure from 1,321 psia to 350 

psia. The second stage turbine drops the pressure from 345 psia to 3.5 psia. The steam inlets to 

both turbine stages are preheated to 1,000°F. 

Low pressure (3.5 psia) steam exhaust from the turbine is cooled by exchanging heat with other 

process streams and is condensed in an air-cooled condenser. While an air-cooled exchanger is 

considerably more expensive than a water cooler, it has the advantage of reducing water 

consumption through evaporation in the cooling towers and was preferred in this design for 

sustainability considerations. A condensate collection tank gathers the condensate returns from 

indirect heat exchange along with the steam turbine condensate. The condensate from the 

collection tank is treated in the hot condensate polishing unit, mixed with treated makeup water, 

and sent to the condensate surge tank. From the surge tank, the water is pumped, heated to the 

saturation temperature, and sent to the deaerator to remove any dissolved gases from the water. 

The water from the deaerator is pumped to a pressure of 1,351 psia and then pre-heated to its 

saturation (bubble point) temperature using a series of exchangers. Steam is generated by heat 

exchange with hot streams in the process. This saturated steam is collected in the steam drum. To 

prevent buildup of solids, water is periodically discharged from the steam drum (also known as 

blowdown). Saturated steam from the steam drum is superheated with another series of 

exchangers to 538°C (1,000°F) before it goes to the steam turbine. Detailed process flow 

diagrams and stream summaries are presented in Appendix G (A-601 to A-603 in Appendix G-1 

for in situ, and A-601 to A-605 in Appendix G-2 for ex situ).

The Aspen Plus model increases or decreases the boiler feed water flow rate through the steam 

cycle in order to close the heat balance. The control system in the plant will function in a similar 

fashion by controlling the flow rate of boiler feed water makeup to the steam system in order to 

maintain levels in the deaerator and steam drum.

All compressors, pumps, fans, etc., utilize electric motor drives and are modeled and quoted 

accordingly. An allowance of ~4 MW of excess power is specified to account for miscellaneous 

usage which may not be accounted for in the simulation and general electric needs (such as lights 

and computers).
35

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3.6.2 Area 600 Design Basis

Table 15 and Table 16 present summaries of the power requirements for each area for the in situ

and ex situ cases, respectively. Excess electricity is sold to the grid.

Table 15. Plant Power Requirements for In Situ Case

Plant Area Generated (kW) Consumed (kW)

Feed handling and dryinga 387

Pyrolysis 22,619

Condensation and product separation 3,500

Hydroprocessing 2,951

Hydrogen production and management 6,083

Steam system and power generation 48,291 1,588

Cooling water and other utilities 324

Wastewater management 1,798

Miscellaneous 3,925

Balance to grid 5,117

Plant totals 48,291 48,291

a Power costs for all feed handling, and for drying outside the plant, are included in the feedstock cost provided by 

INL. The small power consumption shown for this area reflects usage for a cross-flow dryer and flue gas blower.

Table 16. Plant Power Requirements for Ex Situ Case

Plant Area Generated (kW) Consumed (kW)

Feed handling and dryinga 298

Pyrolysis 22,783

Condensation and product separation 3,914

Hydroprocessing 1,811

Hydrogen production and management 5,875

Steam system and power generation 44,247 1,461

Cooling water and other utilities 327

Wastewater management 846

Miscellaneous 3,731

Balance to grid 3,201

Plant totals 44,247 44,247

a Power costs for all feed handling, and for drying outside the plant, are included in the feedstock cost provided by 

INL. The small power consumption shown for this area reflects usage for a cross-flow dryer and flue gas blower.
36

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3.6.3 Area 600 Equipment Cost Estimations

Table 17 presents the equipment list and cost estimates for the steam system and power

generation area of the plant.

Table 17. Cost Estimate for Steam System and Power Generation Area

Equipment Description In Situ Ex Situ

TPEC TIC TPEC TIC

(2011$k) (2011$k) (2011$k) (2011$k)

Power generation and associated 

equipment $26,183 $44,237 $23,875 $40,579

Heat integration $3,116 $8,212 $2,776 $7,316

Area A600 subtotal $29,300 $52,449 $26,651 $47,895

3.7 Area 700: Cooling Water and Other Utilities 

The following section presents an overview, basis for design, and cost estimates for construction 

of the cooling water facilities and other plant utility equipment. 

3.7.1 Area 700 Overview

Equipment list for this area is included in Appendix B. Detailed process flow diagrams and 

stream summaries are presented in Appendix G (A-701 to A-703 in Appendix G-1 for in situ, 

and A-701 to A-703 in Appendix G-2 for ex situ). A mechanical draft cooling tower (M-701) 

provides cooling water to several heat exchangers in the plant. The tower utilizes fans to force air 

through circulated water.

An instrument air system is included to provide compressed air for both service and instruments.

The system consists of an air compressor (K-701), dryer (S-701), and receiver (T-701). The 

instrument air is delivered at a pressure of 115 psia and a moisture dew point of -40°C (-40°F),

and it is oil free.

Other miscellaneous items that are taken into account in the design include the following:

• Firewater storage tank (T-702) and firewater pump (P-702) for fire emergencies

• Diesel tank (T-703) and diesel pump (P-703) to fuel the front loaders

• Ammonia storage tank (T-704), ammonia pump (P-704), BFW chemical storage tank (T708), and BFW chemical pump (P-707) for boiler feed water treatment

• Caustic (NaOH) storage tank (T-705) and pump (P-705)
37

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3.7.2 Area 700 Design Basis

Table 18 summarizes the design basis parameters for the plant’s cooling water system.

Table 18. Design Basis for Cooling Water System

Cooling Water System Design Parameters

Cooling water supply temperature (TS) 90°F

Cooling water return temperature (TR) 110°F

Losses from evaporation (FEVAP) 0.00085 * FS * (TR - TS)

Losses from drift 0.002 * FS

Cycles of concentration (C) 5

Required blowdown FEVAP/(C - 1)

Cooling water makeup pressure 14.7 psia

Cooling water makeup temperature 60°F

Note: Fs = Cooling water supply rate in gallons per minute.

Water losses from the cooling water system include evaporation, drift (water entrained in the 

cooling tower exhaust air), and tower basin blowdown. Drift losses were estimated to be 0.2% of 

the cooling water supply rate. Evaporation losses and blowdown were calculated based on 

information and equations in Perry et al. [17] (as shown in Table 18). 

3.7.3 Area 700 Cost Estimation

Table 19 presents the equipment list and cost estimates for the cooling water and other utilities 

area of the plant.

Table 19. Cost Estimate for Cooling Water and Other Utilities Area

Equipment Description In Situ Ex Situ

TPEC TIC TPEC TIC

(2011$k) (2011$k) (2011$k) (2011$k)

Cooling water and other utilities $4,712 $9,450 $4,633 $9,277

Area A700 subtotal $4,712 $9,450 $4,633 $9,277
38

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3.8 Area 800: Wastewater Management and Recycle

Area 800 has three process sub-areas for treating and recycling water discharges from the plant: 

a wastewater boiler, a regenerative thermal oxidizer, and a reverse osmosis unit for point 

treatment. The majority of the soluble carbon is found in the aqueous phase of the pyrolysis

quench loop in Area 300. This stream, with a significantly smaller makeup of clean recycled 

water is sent to a waste heat boiler system to first generate steam for process use in the sour

water gas shift reactor in Area 300. Any H2S present in the wastewater is expected to be stripped 

out of the water during this step. A following boiler generates steam for the reformer; small 

proportions of carbon species are also part of the steam and are expected to be utilized in the prereformer/reformer system for hydrogen production. Creating steam from the quench water serves 

to recycle some of the volatile carbon species back to the process, and also to concentrate the 

remaining soluble species like phenol. To avoid fouling in the boiler, not all the wastewater is 

evaporated.

The remaining wastewater, after the partial evaporation, has a chemical oxygen demand (COD)

of 68 wt % for the in situ case and 71 wt % for the ex situ case. Most of this COD is from varied 

oxygenated organic species and are modeled using surrogate compounds such as phenol and 

benzenediol. These compounds are toxic to typical microbial consortia used in wastewater 

treatment. Therefore the concentrated wastewater cannot be treated by digestion without 

significant re-dilution, so it is sent to an aqueous regenerative thermal oxidizer to eliminate the 

remaining carbon species that may be present. A high-level schematic of such a system is shown

on the website of Gulf Coast Environmental Systems [48]. The RTO essentially strips the 

wastewater into an excess of preheated air, and the resultant vapor is passed through hot ceramic 

blocks. The operation is cyclical with at least two sets of high heat capacity ceramic blocks. The 

ceramic blocks are heated by combustion products. Upon switching of the cycle these hot blocks 

preheat the inlet air, moisture, and carbonaceous matter; at this time the other set(s) of ceramic 

blocks are heated by combustion products. The preheated feed enters a combustion zone where 

supplemental fuel, such as natural gas, may be provided. Our Aspen Plus model of this subsystem predicts that the carbon content concentrated in the aqueous stream from the boiler has 

more than sufficient carbon and hydrogen to sustain the combustion and no supplemental fuel is 

necessary. The combustion zone is modeled as a reactor with complete oxidation of carbon (to 

CO2) and hydrogen at 820°C (1,508°F), in the presence of significant excess air (amount of air 

decided by the lower explosive limits of organic species). We acknowledge that an RTO has not 

specifically been applied for the type of process described here; however, we are aware that such 

equipment is currently in service at ethylene plants to treat cracking furnace quench water, a 

system with similarities to ours. Detailed process flow diagrams and stream summaries for our 

design are presented in Appendix G (A-801 to A-804 in Appendix G-1 for in situ, and A-801 to 

A-805 in Appendix G-2 for ex situ).

An on-site reverse osmosis (RO) unit is specified for point treatment and recycle of streams with 

low contamination. These include the cooling tower blowdown, water knockout from the PSA 

compressor in Area 300, and the flue gas scrubber effluent from Area 100. We assume that 75% 

of the water can be recovered and recycled to the flue gas scrubber, Area 600 boiler, and cooling 

tower to offset the total water demand for the process. The remaining 25% is collected for 

treatment, along with the hydroprocessing water knockout streams, which were considered 

unsuitable for the boiler and RTO due to nitrogen (ammonia) content. While we did not perform 
39

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a detailed design for an on-site wastewater treatment plant, it is expected that such treatment will 

entail demineralization of the RO retentate streams and probably activated sludge denitrification 

of the hydroprocessing water, followed by aerobic digestion and polishing. Anaerobic digestion 

is not likely to be economical due to the low remaining COD. We estimated an operating cost 

charge for wastewater using the aggregate CAPEX+OPEX cost contribution of the detailed 

wastewater facility designed for the 2011 biochemical ethanol design report [49]. At $0.022/gal 

wastewater, this conservatively estimated cost of treating the relatively less contaminated 

streams from the pyrolysis plant is a factor of 10 higher than the value cited in Peters and 

Timmerhaus [16] for treatment of boiler blowdown streams.

Table 20 summarizes the water balance for the plant. The consumptive water demand for the 

process is 0.76 gal/GGE for the in situ process and 0.70 gal/GGE for the ex situ process. Along 

with uncertainties surrounding the choice of equipment in Area 800, we note that there could

also be significant opportunities to recover valuable products from the wastewater using 

processes such as aqueous phase reforming or biological upgrading. These research areas are not 

considered in this design in order to focus on the core technology of in situ and ex situ vapor 

phase upgrading.
40

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Table 20. Pyrolysis Plant Water Balance

Area Stream Source/Destination In Situ Ex Situ

A100 Scrubber Water Input 30,000 30,000 lb/h

To Flue Gas Loss 7,640 6,571 lb/h

Scrubber Blowdown To Point Treatment 22,360 23,429 lb/h

COD 0 0 lb/h

A200 Catalyst Steam Stripper From Boiler A800 4,151 2,756 lb/h

A300 Aqueous Phase To Boiler A800 74,271 75,955 lb/h

COD 5,490 3,457 lb/h

WGS Steam Demand From Boiler A800 29,430 30,663 lb/h

PSA Water Knockout To Point Treatment 19,552 20,658 lb/h

COD 187 128 lb/h

A400 Hydrotreating HP Aq Phase To Full Treatment 4,660 2,877 lb/h

COD 1 0 lb/h

Hydrocracking Aq Phase To Full Treatment 80 129 lb/h

COD 0 0 lb/h

A500 Reformer Steam Demand From Boiler A800 40,842 45,491 lb/h

PSA Water Knockout To Boiler A800 13,979 15,786 lb/h

COD 0 0 lb/h

A600 Makeup Input 7,064 6,473 lb/h

Makeup Chemicals (In Model) Input 2 2 lb/h

Steam Drum Knockout To Cooling Tower Basin 7,067 6,475 lb/h

A700 Steam Drum Knockout From A600 7,067 6,475 lb/h

Makeup Input 52,033 53,446 lb/h

Blowdown To Point Treatment 10,788 10,937 lb/h

Drift Loss 5,162 5,237 lb/h

Evaporation Loss 43,150 43,747 lb/h

A800 Boiler

BFW Makeup 0 1,926 lb/h

Total Boiler Feed To Boiler A800 74,271 77,881 lb/h

COD 5,490 3,457 lb/h

Process Steam Generated To SMR+WGS 70,272 76,154 lb/h

Remaining to RTO Loss 3,999 1,727 lb/h

COD 0 0 lb/h

Point Treatment

Total Water for Treatment 75% Recovered 66,679 70,810 lb/h

Water Recycled Offsets Inputs 50,009 53,107 lb/h

Remainder To Full Treatment 16,670 17,702 lb/h

Full Treatment

Total Loss 21,410 20,708 lb/h

COD 1 0 lb/h

Total Water Makeup 93,251 94,603 lb/h

Net Water Makeup 43,242 41,495 lb/h

Net Water Makeup (Annual) 41.0 39.3 MMgal/y

Water Usage 0.76 0.70 gal/GGE

Liq Water Emission 21,410 20,708 lb/h

Liq Water Emission (Annual) 20.3 19.6 MMgal/y
41

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3.8.1 Area 800 Cost Estimation

Table 21 presents the equipment list and cost estimates for the wastewater treatment and recycle 

area. The RTO capital cost was based on estimates in a report from the U.S. Environmental 

Protection Agency (EPA) [50].

Table 21. Cost Estimate for Wastewater Management Area

Equipment Description In Situ Ex Situ

TPEC TIC TPEC TIC

(2011$k) (2011$k) (2011$k) (2011$k)

Wastewater boiler and ancillaries $139 $631 $162 $661

Regenerative thermal oxidizer and ancillaries $4,938 $11,295 $3,112 $7,118

Reverse osmosis and clarifier skid $1,022 $2,248 $1,032 $2,264

Heat integration $1,132 $2,982 $1,090 $2,871

Area A800 subtotal $7,230 $17,156 $5,395 $12.915

3.9 Additional Process Design Information

Table 22 contains additional information used in the Aspen Plus model and design basis. For 

those interested, any deviations in the pressure drop assumptions can be found in the stream 

tables (Appendix G).

Table 22. Utility and Miscellaneous Design Information

Item Design Information

Ambient air conditions a,b,c

Pressure: 14.7 psia

Tdry bulb: 90°F

Twet bulb: 80°F

Air composition (mol %):

N2: 75.7% O2: 20.3% Ar: 0.9% CO2: 0.03% H2O: 3.1%

Pressure drop allowance

Air pre-heat exchangers = 1 psi

Heat exchangers = 5 psi,

 2 psi in vapor condensation train

a In the GPSA Engineering Data Book [51], see Table 11.4 for typical design values for dry bulb and wet bulb 

temperature by geography. Selected values would cover summertime conditions for most lower 48 states.

b In Weast [52], see F-172 for composition of dry air. Nitrogen value is adjusted slightly to force mole fraction closure 

using only nitrogen gas (N2), oxygen (O2), argon (Ar), and carbon dioxide (CO2) as air components. c In Perry et al. [17], see psychrometric chart, Figure 12-2, for moisture content of air.
42

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3.10 Pinch Analysis

While an energy balance was performed within the Aspen Plus process simulation, it was also 

necessary to ensure that there was no temperature crossover when the assumption was made that 

the cold process streams can be heated using the available heat in hot process streams. A pinch 

analysis was performed to show the temperatures at which hot and cold duties are available. 

The concept of pinch technology offers a systematic approach for optimizing energy integration

in process design. Temperature and heat flow (Q) data were gathered for the hot process streams 

(streams cooled in the process), cold process streams (streams heated in the process), and utility 

streams like steam, flue gas, and cooling water. A composite curve, a graphical presentation of 

stream temperature and heat flow (Q) data, was constructed for the hot and cold process streams.

These two curves are shifted so that they touch at the pinch point. From this shifted graph, a 

grand composite curve is constructed that plots the difference in heat flow between the hot and 

cold composite curves as a function of temperature.

The total hot duty equals the total cold duty, as the Aspen Plus model is designed to adjust the 

water flow rate through the steam cycle until the heat balance in the system is closed. The 

minimum vertical distance between the curves is ΔTmin, which is theoretically the smallest 

approach temperature in the exchanger network. For the in situ case, the upper and lower pinch 

temperatures are 310.9°F and 288.3°F, respectively, resulting in ΔTmin of 22.6°F. For the ex situ

case, the upper and lower pinch temperatures are 309.9°F and 285.0°F, respectively, resulting in 

ΔTmin of 24.9°F. Figure 9 and Figure 10 show those curves for the in situ and ex situ cases. The 

figures demonstrate the feasibility of developing a network based on the current process models 

(since there is no crossover). A complete heat exchange network is provided for the ex situ case 

in Appendix H. The total heat exchanger network costs for the in situ and sensitivity cases

(Figure 15) were factored from the ex situ base case using total duties, and a scaling exponent of 

0.65. Since heat exchangers span the various process areas, heat exchanger network costs were 

distributed among the various areas based on duties from respective areas. The process flow 

diagrams in Appendix G-2 for the ex situ case include information from the heat exchanger 

network design shown in Appendix H.
43

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Figure 9. Pinch analysis composite curve for the in situ case

Figure 10. Pinch analysis composite curve for the ex situ case
44

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3.11 Energy Balance

Energy integration is important to the overall economics and efficiency of the process. Therefore 

a detailed understanding of how and where the energy is utilized and recovered is required. 

Detailed energy balances around the major process areas were derived using data from the Aspen 

Plus simulation. Comparing the process energy inputs and outputs allows the energy efficiency 

of the process to be quantified. Tracing energy transfer between process areas also makes it 

possible to identify potential improvements to the energy efficiency. 

This design for pyrolysis and upgrading of cellulosic biomass was constructed with the goal of 

utilization of heating values of solid (char and coke) and gaseous (off-gases) products within the 

process, with the export of excess electricity using any extra energy available. Relative to the 

energy in biomass, an insignificant amount of natural gas input is added to supplement process 

gases in the steam reformer for hydrogen production. The small amount of natural gas was 

introduced to maintain the process model in a state where natural gas could be introduced in the 

model to study sensitivity cases. Unreacted light-ends from pyrolysis are combusted to produce 

steam and electricity for the plant. On balance, the pyrolysis process requires no electricity from 

the grid and exports electricity instead.

The distribution of the total energy content in the feed is shown in Figure 11. The basis for these 

pie charts is the total energy in the dry portion of the feed (approximately 1,470 MMBtu/h) and 

the total energy in the small natural gas co-feed to the process (2 MMBtu/h for in situ, 3

MMBtu/h for ex situ). Figure 11 shows that >50% of the LHV is recovered as fuel-range 

hydrocarbon products in both cases. Another 1% is further exported as saleable surplus 

electricity. A significant amount (~35%) is lost through electricity-driven air-cooled exchangers, 

and the remainder of the energy is lost to the plant surroundings. Further optimization of the heat 

integration network can be evaluated if it is felt as necessary in the future.

Figure 11. Overall energy balance (basis: LHV of wood + natural gas). Values rounded to nearest 

tenth.
45

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3.12 Sustainability Metrics

An important aspect of evaluating biofuel processes is the quantification of life-cycle resource 

consumption and environmental emissions. Life-cycle assessment (LCA) provides a framework 

from which the environmental sustainability of a given process may be quantified and assessed.

This section presents the salient sustainability metrics of the current conceptual process at the 

conversion stage. Direct biorefinery emissions (i.e., CO2, NO2, and SO2), water consumption, 

and other process-related metrics were derived from the conversion process model described 

above.

SimaPro v. 8.02 software [53] was used to develop and link units quantifying life-cycle impacts. 

Greenhouse gas (GHG) basis values for natural gas (NG) and the U.S. average electricity mix 

from the grid were applied consistently with the basis from Argonne National Laboratory’s 

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

software; this includes GHG emission factors of 3.25 kg CO2e/kg NG (LHV) and 0.65 kg 

CO2e/kWh grid electricity [54]. Likewise, the basis from GREET was also applied for nonrenewable (fossil) energy consumption values of 52.1 MJ/kg (LHV) natural gas and 7.5 MJ/kWh 

grid electricity [54]. All other process input/output inventory estimates were derived from

Ecoinvent v.2.0 [55] and the U.S. Life Cycle Inventory (LCI) [56] processes to fill the data gaps. 

The Ecoinvent processes were modified to reflect U.S. conditions and the U.S. LCI processes 

were adapted to account for embodied emissions and fossil energy usage. The material and 

energy flows of the conversion step capture the impacts of input raw materials, and outputs, such 

as emissions, wastes, and coproducts as predicted by the process model, as shown in Table 23 for 

the in situ case and Table 24 for the ex situ case.
46

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Table 23. Material and Energy Flows for the In Situ Case

Production Rate

Products lb/hr gal/hr MMBtu/hr (LHV)

Gasoline fuel 31,866 4,978 579 

Diesel fuel 11,845 1,885 219 

Byproducts kW

Excess electricity 5,117

Resource Consumption

Flow 

Rate Per Gal Gasoline Per MMBtu

lb/hr lb/gal lb/MMBtu

Blended woody biomass (wet) 204,131 41.01 352.35

Blended woody biomass (dry) 183,718 36.91 317.12

Sand makeup 0 0.00 0.00

Natural gas 54 0.01 0.09

Zeolite catalyst 344 0.07 0.59

Hydrotreating catalyst 15 0.00 0.03

Hydrocracking catalyst 2 0.00 0.00

50 wt % caustic 291 0.06 0.50

Net water makeup 43,242 8.69 74.64

Boiler feed water chemicals 2 0.00 0.00

Cooling tower chemicals 1 2.01E-04 0.00

No. 2 diesel fuel 71 0.01 0.12

Waste Streams lb/hr lb/gal lb/MMBtu

Solids purge from fluidized bed reactors 2,555 0.51 4.41

Wastewater 21,410 4.30 36.96

Air Emissions lb/hr lb/gal lb/MMBtu

CO2 (Fossil) 147 0.03 0.25

CO2 (Biogenic) 204,428 41.07 352.86

CH4 0 0.00 0.00

CO 0 0.00 0.00

NO2 13 0.00 0.02

SO2 106 0.02 0.18

H2O 105,471 21.19 182.05

H2S 0 0.00 0.00

Note: Small quantities of ZnO and HDS catalyst not shown.
47

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Table 24. Material and Energy Flows for the Ex Situ Case

Production Rate

Products lb/hr gal/hr MMBtu/hr (LHV)

Gasoline fuel 20,408 3,236 375 

Diesel fuel 24,739 3,930 456 

Byproducts kW

Excess electricity 3,201

Resource Consumption

Flow 

Rate Per Gal Gasoline Per MMBtu

lb/hr lb/gal lb/MMBtu

Blended woody biomass (wet) 204,131 63.07 544.03

Blended woody biomass (dry) 183,718 56.77 489.63

Sand makeup 158 0.05 0.42

Natural gas 125 0.04 0.33

Zeolite catalyst 229 0.07 0.61

Hydrotreating catalyst 16 0.00 0.04

Hydrocracking catalyst 4 0.00 0.01

50 wt % caustic 294 0.09 0.78

Net water makeup 41,495 12.82 110.59

Boiler feed water chemicals 2 0.00 0.01

Cooling tower chemicals 1 3.09E-04 0.00

No. 2 diesel fuel 71 0.02 0.19

Waste Streams lb/hr lb/gal lb/MMBtu

Solids purge from fluidized bed reactors 2,335 0.72 6.22

Wastewater 20,708 6.40 55.19

Air Emissions lb/hr lb/gal lb/MMBtu

CO2 (Fossil) 342 0.11 0.91

CO2 (Biogenic) 200,605 61.98 534.64

CH4 0 0.00 0.00

CO 0 0.00 0.00

NO2 17 0.01 0.04

SO2 107 0.03 0.29

H2O 98,451 30.42 262.38

H2S 0 0.00 0.00

Note: Small quantities of ZnO and HDS catalyst not shown.

In addition to primary fuel production, the process also produces an excess amount of electricity 

as coproduct. It is assumed that the excess electricity would be sold to the grid translating to 

coproduct credits for avoided GHG emissions and fossil energy consumption. This exported 

electricity is treated as an avoided product using the product displacement method [57].

Coproduct displacement (also termed system boundary expansion) is based on the concept of 

displacing the existing product with the new product. The excess electricity coproduct displaces 

an equivalent amount of grid electricity, thus avoiding a significant amount of GHG emissions as 
48

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well as fossil energy consumption, assuming an average U.S. electricity grid mixture. The GHG 

and fossil energy consumption credits attributed to the displacement of an average U.S. 

electricity grid mixture is 0.65 kg CO2e/kWh and 7.5 MJ/kWh, respectively, as defined by 

GREET [54]. However, it is not clear whether power companies would be willing to buy the 

excess electricity generated from cellulosic biorefinery. Thus, a second scenario assumed that the 

excess electricity would not be sold to the grid and thus there were no coproduct credits for 

avoided GHG emissions and fossil energy consumption. Table 25 lists the SimaPro database 

processes used for the GHG calculations.

Table 25. SimaPro Processes Used for Conversion Process Inputs

Key Inputs SimaPro Processes

Electricity GREET

Natural gas GREET 

Sand makeup Silica sand, at plant/DE WITH US ELECTRICITY U

Zeolite catalyst Zeolite, powder, at plant/RER WITH US ELECTRICITY U

Hydrotreating catalyst Zeolite, powder, at plant/RER WITH US ELECTRICITY U

Hydrocracking catalyst Zeolite, powder, at plant/RER WITH US ELECTRICITY U

ZnO bed material Zeolite, powder, at plant/RER WITH US ELECTRICITY U

HDS catalyst before 

reformer Zeolite, powder, at plant/RER WITH US ELECTRICITY U

Steam reforming catalyst Zeolite, powder, at plant/RER WITH US ELECTRICITY U

Shift catalyst Zeolite, powder, at plant/RER WITH US ELECTRICITY U

PSA adsorbent Zeolite, powder, at plant/RER WITH US ELECTRICITY U

50 wt % caustic Sodium hydroxide, 50% in H2O, production mix, at plant/RER 

WITH US ELECTRICITY U

Net water makeup Water, process, unspecified natural origin/kg

Boiler feed water 

chemicals

Sodium hydroxide, 50% in H2O, production mix, at plant/RER 

WITH US ELECTRICITY U; Sulphite, at plant/RER WITH US 

ELECTRICITY U, Hydrochloric acid, 30% in H2O, at plant/RER 

WITH US ELECTRICITY U

Cooling tower chemicals Chemicals in organic, at plant/GLO WITH US ELECTRICITY U

On an energy basis and with electricity credits, the GHG emissions at the conversion stage for 

the in situ and ex situ cases are negative 2.6 g CO2e/MJ and negative 1.2 g CO2e/MJ, 

respectively. However, without electricity credits, the GHG emissions are higher, 1.3 and 1.2 g 

CO2e/MJ for the in situ and ex situ cases, respectively. Similarly, the fossil energy consumption 

for the case with electricity credits are negative 0.03 MJ/MJ and negative 0.01 MJ/MJ for the in 

situ and ex situ cases, respectively. Without electricity coproduct displacement credits, the fossil 

energy consumptions for both the in situ and ex situ cases are 0.02 MJ/MJ. The electricity 

coproduct displacement credits are only relevant to the GHG emissions and fossil energy

consumption assessment and not to other metrics in Table 26. The contributions of individual 

inputs to the total conversion stage GHG are shown in Figure 12.
49

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Figure 12. Contributing processes to conversion GHGs for catalytic pyrolysis pathways

In addition to GHG emissions and fossil energy consumption discussed above, water 

consumption (i.e., net water use during the biorefinery operation), total fuel efficiency (yield), 

and carbon-to-fuel efficiency are also reported in Table 26.

Biorefinery net water consumption includes, but is not limited to, water that is incorporated into 

the product and evaporation directly from process operations or indirectly from cooling and 

heating processes (e.g., cooling tower evaporative losses), but it does not include water that is 

directly returned to surface water or groundwater (such as blowdown). The net consumption for 

the in situ and ex situ cases are 468 and 449 m3/day, respectively. The total fuel yield is 74.9

GGE per dry ton for the in situ case and 78.0 GGE per dry ton for the ex situ case. The 

corresponding carbon-to-fuel efficiency for the in situ and ex situ cases are determined to be 

40.4% and 41.5%, respectively, calculated strictly as a ratio of carbon in the liquid fuel products 

relative to carbon in the biomass feedstock.

Table 26. Summary of Sustainability Metrics for the In Situ and Ex Situ Cases

Design Cases: In Situ Ex Situ

Electricity credit Yes No Yes No

GHG emissions (g CO2e/MJ) -2.6 1.3 -1.2 1.2

Net fossil energy consumption (MJ/MJ) -0.03 0.02 -0.01 0.02

Water consumption (m3/day) 470 450

Water consumption (gal/GGE fuel) 0.75 0.69

Total fuel yield (GGE/dry ton) 74.9 78.0

Carbon-to-fuel efficiency (C in fuel/C in biomass) 40.4% 41.5%

Wastewater generation (m3/day) 233 225

Wastewater generation (gal/GGE) 0.37 0.35

-2.6

-1.2

-5

-4

-3

-2

-1

0

1

2

InSitu ExSitu

g CO2e/MJ fuel produced

Waste Treatment/Disposal

Sand makeup

50 wt% Caustic

Biomass Loader (diesel)

Boiler, Cooling Chem

Catalyst, PSA adsorbent

Electricity Credit

Natural Gas

Total
50

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The analysis was expanded to estimate the full life-cycle GHG emissions for fuels produced 

from the projected 2017 model feedstock, a blend of pulpwood (45%), wood residues (32%), 

switchgrass (3%), and construction and demolition waste (20%) [22]. Full life-cycle GHGs for 

gasoline fuel from the 2017 model feedstock are estimated at 9.2 g CO2e/MJ and 10.2 g

CO2e/MJ for the in situ and ex situ cases, respectively. This corresponds to GHG reductions 

relative to the 2005 petroleum baseline GHGs (93.08 g CO2e/MJ) [58] of 90% and 89% for the 

in situ and ex situ cases, respectively. The underlying assumptions and detailed results for the 

full life-cycle GHG analysis are given in Appendix E. While this analysis provides a preliminary

estimate of GHG reduction associated with this biofuel, it is important to note that the EPA 

conducts its own LCA to make final determination of fuel qualification under the Renewable 

Fuel Standard 2. In addition, Argonne National Laboratory will provide more detailed LCA for 

these pathways in the future.
51

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4 Process Economics

The following section describes how the process model, detailed design, and cost estimation 

discussed so far is used to determine the economics of fuel production. The analysis is based 

entirely on estimated equipment costs and regular construction and project management costs 

associated with building a plant of this kind. The analysis does not take into account any policy 

factors such as carbon credits, subsidies, or mandates.

The TCI is first computed using a comprehensive list of mechanical equipment in the plant and 

its expected construction and project costs. Variable and fixed operating costs associated with 

plant operation and maintenance are determined next. With these estimated costs, a discounted 

cash flow analysis is used to determine an MFSP that resolves to a net present value of zero for 

the entire project at some assumed nonzero discount rate, also referred to in this report as the 

internal rate of return (IRR). In other words, given the production rates determined in the process 

model, fuel from the plant must be sold at its MFSP in order for the project to return the 

specified IRR and no more. This section describes the calculations and assumptions made in 

completing the discounted cash flow analysis.

4.1 Total Capital Investment

The following discussion summarizes the purchased and installed equipment costs presented in 

Section 3 and describes how the total installed costs for the plant serve as the basis for 

determining the total capital investment. As previously discussed, the equipment costs for each 

plant area were derived from various sources including equipment suppliers and licensors, cost 

estimates from Harris Group, published literature, and Aspen Capital Cost Estimator software. 

The sum of all items on a bare-equipment, freight on board (FOB) basis is the total purchased 

equipment cost. The installation cost for the bare equipment is estimated by applying installation 

factors to each piece of equipment. For those equipment costs estimated in ACCE, we used the 

installation factor implied by ACCE (total direct cost/equipment cost). For line items quoted as a 

package or drawn from other references (for example, the steam methane reformer), the 

installation factor implied in the source was used. Any remaining missing installation factors 

were determined as described in the 2011 NREL design report for biochemical ethanol [49], 

which used a table of installation factors by equipment type found in Walas [19], plus 0.3 to 

account for instrumentation, which NREL determined was deliberately excluded from these 

factors. See Appendix B for a complete listing of the equipment, along with its purchased and 

installed costs. Table 27 presents a summary of TPEC, aggregate installation factors (finstall), and 

TIC for each area of the plant.
52

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Table 27. General Cost Factors in Determining Total Installed Equipment Costs

In Situ Ex Situ

Area Process Description TPEC f install TIC TPEC f install TIC

(MM$) (MM$) (MM$) (MM$)

100 Feed handling and dryinga 0.3 1.96 0.5 0.2 1.97 0.4

200 Fast pyrolysis and vapor 

upgrading 31.1 2.98 92.5 40.7 3.12 126.9

300 Pyrolysis vapor quench and 

product recovery 12.2 1.84 22.4 13.2 1.83 24.2

400 Hydroprocessing and product

separation 18.8 1.73 32.5 15.9 1.83 29.1

500 Hydrogen plant 36.5 1.93 70.6 34.5 1.93 66.8

600 Steam system and power

generation 29.3 1.79 52.4 26.7 1.80 47.9

700 Cooling water and other utilities 4.7 2.01 9.4 4.6 2.00 9.3

800 Wastewater management and 

recycle 7.2 2.37 17.2 5.4 2.39 12.9

ISBL (Areas 100–400) 62.3 2.38 147.9 70.0 2.58 180.7

OSBL (Areas 500–800) 77.7 1.93 149.7 71.2 1.92 136.8

Total 140.0 2.13 297.6 141.2 2.25 317.5

a Most investment costs for feed handling and drying are included in the per-unit woody feedstock price. This cost is for a 

secondary biomass dryer that serves to recover heat.

The sum of equipment purchases and installation/construction costs is defined as the total direct 

cost (TDC). Indirect capital costs are non-construction costs typically associated with project 

management and engineering, procurement, and construction (EPC) services. Indirect costs are 

estimated with factors on the TDC as shown in Table 28. The sum of direct and indirect costs is 

defined as the fixed capital investment (FCI). Finally, working capital is determined to be 5% of 

the FCI. The sum of FCI and working capital is the TCI. Table 29 presents a summary of these 

capital quantities for the in situ and ex situ pyrolysis processes described in this report.

Table 28. Cost Factors for Indirect Costs

Indirect Costs % of TDC*

Prorated expenses 10.0

Home office and construction fees 20.0

Field expenses 10.0

Project contingency 10.0

Other costs (start-up and permits) 10.0

Total Indirect Costs 60.0

* Excluding land purchase cost.
53

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Table 29. Project Cost Worksheet

In Situ Ex Situ

Total purch. equipment cost (TPEC) $140,030,000 $141,180,000

 Installation factor 2.125 2.249

Total installed cost (TIC) $297,610,000 $317,540,000

Other direct costs

 Land (not depreciated) $1,610,000 $1,610,000

 Warehouse 4.0% of ISBL $5,920,000 $7,230,000

 Site development 10.0% of ISBL $14,790,000 $18,070,000

 Additional piping 4.5% of ISBL $6,660,000 $8,130,000

Total direct costs (TDC) $324,980,000 $350,970,000

Indirect costs % of TDC (ex land)

 Prorated expenses 10.0% $32,500,000 $35,100,000

 Home office and construction fees 20.0% $65,000,000 $70,190,000

 Field expenses 10.0% $32,500,000 $35,100,000

 Project contingency 10.0% $32,500,000 $35,100,000

 Other costs (start-up and permits) 10.0% $32,500,000 $35,100,000

Total indirect costs 60.0% $194,990,000 $210,580,000

Fixed capital investment (FCI) $519,960,000 $561,550,000

 Working capital 5.0% of FCI (ex land) $26,000,000 $28,080,000

Total capital investment (TCI) $545,960,000 $589,630,000

TCI/TPEC 3.899 4.177

FCI Lang Factor = FCI/ISBL TPEC 8.349 8.023

TCI Lang Factor = TCI/ISBL TPEC 8.766 8.424
54

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4.2 Variable Operating Costs

Variable operating costs, which include raw materials, waste handling charges, and by-product 

credits, are incurred only when the process is operating. Quantities of raw materials used and 

wastes produced were determined using the Aspen Plus material balance. Table 30 summarizes 

the basis for variable operating costs considered in this analysis. A detailed summary of variable 

plant operating costs is presented in Appendix C on a per-year and per-GGE basis.

Table 30. Summary of Variable Operating Costs

Variable Information and Operating Cost (cost year in parentheses)

Fluidized bed 

media

For fast pyrolysis, the bed medium is sand. In catalytic fast pyrolysis (in situ) and 

vapor-phase upgrading (ex situ), the medium is assumed to be a zeolite catalyst. 

Initial fill then a total replacement rate of 3.6 wt % of circulation per day for both the 

in situ and ex situ cases.

Sand price: $45.74/ton (2011) [59]; initial fill, then makeup for attrition.

Zeolite price: $19,500/ton (2011); estimated cost based on modifications, such as 

to include rare earth [27] and non-precious metals like nickel (Ni) up to 5 wt %.

Hydrotreating and 

hydrocracking 

catalysts

To determine the amount of catalyst inventory, the hydroprocessors were sized for 

a WHSV of 0.5/h based on the expected hydroprocessing severity. Initial fill is then 

replaced every 2 years.

Price: $20/lb (2011) based on NREL calculations using metals pricing and costs for 

manufacturing processes, and some buffer for modifications.

Steam methane 

reformer catalysts

Based on a literature value of price per unit hydrogen produced.

Price: $7.80/ton hydrogen (2011) [60].

Natural gas Purchased from pipeline for feed to steam methane reformer for hydrogen 

production. 

Price: $239/ton ($5/MMBtu) (2011).

Solids disposal Price: $33/tonne (1998) [16].

Diesel fuel Usage: 10 gal/h plant-wide use.

2012 price projection: $21.29/MMBtu (2009) [61] = $2.86/gal at 0.85 specific 

gravity.

Water makeup Price: $0.22/tonne (2001) [17] = $0.20/ton.

Chemicals Boiler feed water chemicals – Price: $75/MM lb blowdown (2014 vendor estimate).

Cooling tower chemicals – Price: $33.84/yr per ton of cooling capacity (2014

vendor estimate).

Caustic – Price: $150/dry ton (2010) [49].

Wastewater Most wastewater is cleaned using an RO system and recycled. Additional

treatment is assumed for the balance.

Price: $0.022/gallon (2011). Based on Humbird et al. [49].

Note: Costs shown were updated to 2011 dollars using an inorganic cost index [62]. 

Values used: 1998 = 148.7; 2001 = 158.4; 2010 = 233.9.; 2011 = 249.3, 2014 = 280.2 (extrapolated).
55

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4.3 Fixed Operating Costs

Fixed operating costs, which include employee salaries and benefits, overhead, plant 

maintenance costs, insurance, and taxes (other than income taxes), are generally incurred in full 

whether or not the plant is producing at full capacity. Table 31 lists the expected number of 

employees for the plant and their associated salaries. The salaries listed do not include benefits,

so a general overhead factor is applied, as shown in Table 32, along with fixed costs for 

insurance, taxes, and general plant maintenance, such as security, janitorial services, and

communications. A detailed summary of fixed plant operating costs is presented in Appendix C.

Table 31. Salary Costs for Plant Employees

Position Title Salary 

(2007)

Number of 

Positions

Total Cost*

(2011)

Plant manager $147,000 1 $161,362

Plant engineer $70,000 1 $76,389

Maintenance supervisor $57,000 1 $62,569

Laboratory manager $56,000 1 $61,471

Shift supervisor $48,000 5 $263,448

Lab technician $40,000 2 $87,816

Maintenance technician $40,000 16 $702,527

Shift operators $48,000 20 $1,053,790

Yard employees $28,000 12 $368,827

Clerks and secretaries $36,000 3 $118,551

Total salaries (2011$/yr) $2,960,000

* Additional 10% escalation to costs indicated in this column, as shown in Table 32,

Note: Labor costs are indexed, if necessary, to values from the U.S. Bureau of Labor Statistics 

(http://data.bls.gov/cgi-bin/srgate CEU3232500008).

Table 32. Fixed Operating Costs

Cost Item Factor In Situ Ex Situ

Salaries (plus 10% 

escalation) $3,250,000 $3,250,000

Benefits and overhead 90.0% of total salaries (after adding 10%) $2,922,000 $2,922,000

Maintenance 3.0% of fixed capital investment (FCI*) $15,599,000 $16,847,000

Insurance and taxes 0.7% of fixed capital investment (FCI*) $3,640,000 $3,931,000

Total fixed operating costs (2011$/yr) $25,410,000 $26,950,000

* Percentages of FCI exclude land purchase cost.
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4.4 Discounted Cash Flow Analysis and the Minimum Fuel Selling 

Price

Once the capital and operating costs are determined, an MFSP is determined using a discounted 

cash flow rate of return (DCFROR) analysis. The general methodology used is the same as that 

applied in previous NREL design reports [20, 49], with the small distinction that we normalize 

all fuel products from the plant (gasoline and diesel) by lower heating value to give a single 

gasoline-equivalent product. The discounted cash flow analysis determines the minimum selling 

price of a gallon of this gasoline-equivalent product, which yields a net present value of zero for 

the project. The financial parameters used to compute the net present value are as follows. 

Discount Rate/IRR

For this analysis, the cash flow discount rate was set to an internal rate of return of 10%. 

Equity Financing

For this analysis, it was assumed that the plant would be 40% equity financed. The terms of the 

loan on the remaining 60% debt were taken to be 8% interest for 10 years. The principal is taken 

out in stages over the 3-year construction period. Interest on the loan is paid during this period, 

but principal is not paid back. (This implies that cash flow comes from a parent company until 

the plant starts up.) 

Depreciation

Capital depreciation is computed according to the IRS Modified Accelerated Cost Recovery 

System (MACRS). The bulk of the plant capital is depreciated over a 7-year recovery period. 

Because the plant described here is a net exporter of electricity, the steam plant and power 

generation equipment is depreciated over a 20-year recovery period, according to the IRS.

Taxes

The federal corporate tax rate used in our analysis is 35%. Income tax is averaged over the plant 

life and that average is calculated on a per-GGE basis. The amount of income tax to be paid 

varies annually with changes in the volume of product produced and the allowable depreciation 

deduction. In fact, no income tax is paid in the first 8 years of operation because depreciation and 

loan interest deductions are greater than the net income. State taxes are not considered, primarily 

because the location of the plant has not been determined and tax rates vary from state to state 

(from 0% to 12%).

Construction Time

The construction time was taken to be 24 months. Twelve months are added before construction 

for planning and engineering.

Start-Up Time

Startup was taken to be 25% of the construction time, or 6 months in this case. It is assumed that 

the plant achieves 50% production during the start-up period while incurring 75% of variable 

expenses and 100% of fixed expenses.
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Lifetime

The plant and all equipment is assumed to have a 30-year life. No salvage value is assumed at 

the end of 30 years.

Working Capital

Working capital was taken to be 5% of the fixed capital investment.

4.5 Value of Hydrocarbon Fuel Products From Biomass Pyrolysis

The results of the cash flow analyses for the base in situ and ex situ cases are summarized in 

Table 33. As noted above, gasoline and diesel are normalized by lower heating value to represent 

a single gasoline-equivalent product and MFSP. To re-obtain individual selling prices for 

gasoline and diesel, the MFSP per GGE is ratioed back to these products by lower heating value.

The densities of the blendstocks were assumed to be those of U.S. conventional gasoline (2,819 

grams/gallon or 6.215 lb/gallon) and diesel fuels (3,167 grams/gallon or 6.982 lb/gallon) [63].

Table 33. Projected Selling Prices of Hydrocarbon Fuels From Biomass Pyrolysis

In Situ Ex Situ

Lower heating value for gasoline-range products 

from pyrolysis (simulation result) 112.988 Btu/gal 114,267 Btu/gal

Lower heating value for diesel-range products from 

pyrolysis (simulation result) 129,006 Btu/gal 128,779 Btu/gal

Calculated gasoline-equivalent MFSP $3.46/GGE $3.31/GGE

Calculated actual MFSP for gasoline-range products $3.37/gal $3.26/gal

Calculated actual MFSP for diesel-range products $3.85/gal $3.68/gal

Gasoline lower heating value for normalization 116,090 Btu/gal
58

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5 Process Economics Summary and Sensitivity 

Analysis

The contribution of individual areas toward the MFSP on a $/GGE basis are shown in Figure 13

for the in situ case and Figure 14 for the ex situ case. Additional summary tables with a detailed 

breakdown of costs are shown in the Executive Summary and not repeated here.

Figure 13. Cost contribution details from each process area for the in situ 2022 target case
59

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Figure 14. Cost contribution details from each process area for the ex situ 2022 target case

Since the design basis for the in situ and ex situ cases were similar, except for the fast pyrolysis 

and vapor upgrading reactors, it is not surprising that they show similar cost distribution trends. 

The key points to be noted are:

1. The higher capital cost due to separate fast pyrolysis and vapor upgrading reactors in the 

ex situ case (versus a single combined reactor in the in situ case) is offset by the lower 

catalyst replacement rate in the ex situ case. The assumed rate is 2% of the inventory per 

day for both the in situ and ex situ cases, with an additional 1.6% added to account for 

attrition. The catalyst to biomass ratio is 7.5 for the in situ case compared to 5 for the ex 

situ case, which results in a higher in situ catalyst inventory, hence higher losses.

2. The slightly higher hydroprocessing cost for the in situ case is primarily due to the higher 

oxygen content assumed in the organic liquid after vapor upgrading; hydrogen 

consumption and the hydrogen plant cost is also higher for the same reason.

3. Wastewater management costs are higher for the in situ case because of the assumption 

of higher carbon loss to the aqueous phase as a result of higher oxygen content in the 

organic liquid from in situ vapor upgrading.

While these are some of the key differences, there are other underlying differences within the 

process model and costs, as was noted in the tables comparing the two base cases throughout this 

report.
60

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As previously pointed out, the in situ and ex situ base cases are two of many possible scenarios 

for cost competiveness of these pathways through research focused primarily on catalyst 

development, and demonstration of credible process integration and scale-up. Significant 

uncertainties remain to be resolved through experimental corroboration. Thus, it is important to 

show the impacts of variations in some of the key underlying assumptions through sensitivity 

studies. Sensitivity scenarios for the ex situ case are summarized in Figure 15. Similar parameter 

variations for the in situ case are expected to follow the trends shown for the ex situ case.

Note that each sensitivity scenario in Figure 15 has an associated deviation value from the base 

case MFSP of $3.31/GGE. The sensitivity scenarios are discussed in the following sections. The 

case numbers in the text refer to the numbers shown in the labels of Figure 15. This being a 

tornado chart, the results are sorted by the magnitudes of impacts on the MFSP.

Figure 15. Results of sensitivity analyses for the ex situ case

5.1 Market, Financial, and Overall Assumptions

Variations in the TCI, shown in Case 1 of Figure 15, can have significant impacts on the MFSP. 

In this context it should be noted that some of the major equipment costs were derived from 

estimations based on similar equipment, or from costs derived from mechanical design tools. 

Variation in capital costs during an actual installation is potentially the biggest reason for 

changes in the TCI. A 30% increase in the TCI can increase the ex situ base case MFSP of 

$3.31/GGE by 16.1%.
61

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Case 3 shows that assuming a higher discount rate for DCFROR (also referred to here as the 

internal rate of return), of 15% instead of 10% can have a similar impact of 15.4% on the MFSP.

Similarly, Case 10 shows the impact of assuming a higher interest rate. 

Feedstock cost, which is shown as a significant contributor to the MFSP, can have a big impact 

as shown in Case 2. Increasing the feedstock cost from $80/dry U.S. ton to $120/dry U.S ton 

increased the MFSP by 15.7%. There is ongoing work at INL and other institutions toward 

enabling the provision of feedstock at $80/dry U.S. ton while meeting quality specifications. 

Some of their work is focused on improvements in feedstock logistics, and ways to soften market 

forces by expanding the feedstock pool to a wider range of blended material as mentioned 

earlier. The effects of blended material on product yields will be experimentally studied as part 

of ongoing research.

Case 6 shows the impact of a larger plant size, with feedstock available at the same price. This 

shows that the MFSP based on current assumptions can be significantly reduced to 

approximately $3/GGE by scaling up. The impact can be significantly larger if the assumed 

1,000 dry metric tonnes/day/reactor constraint imposed on the fast pyrolysis reactor is lifted and 

larger reactors can be designed. Additional references discuss economies of scale and refinery 

integration [64] and biorefinery sizing [65] as potential approaches toward cost reduction.

Assuming a plant life of 20 years instead of 30 years increases the MFSP by 4.1% as shown in 

Case 12. Case 16 shows that the assumption of 86% plant on-stream factor (versus 90% in the 

base case) results in an increase of 2.7% in the MFSP. 

5.2 Fast Pyrolysis and Catalytic Vapor Upgrading

The estimated impacts on the MFSP from the inclusion of a hot gas filter in the process are 

shown in Cases 4 and 14. A hot gas filter may be necessary even in the ex situ system if cyclones 

are inadequate for sufficiently removing mineral matter/ash from the vapor stream to prevent 

detrimental impacts on the catalyst. The capital cost of the HGF was scaled using the actual 

vapor flow rate in the process model, starting from original equipment cost estimates obtained 

for a near atmospheric system. The 120 psia system pressure (versus near atmospheric pressure) 

in the fast pyrolysis and vapor upgrading sections helped reduce gas volumes and reduce the 

capital impact of the HGF; the MFSP increased by 3.2%, as shown in Case 14. However, yield 

losses have not been quantified in a process configuration similar to that assumed in this process 

design. Assuming an organic liquid product yield loss of 10% due to cracking and coking leads 

to a higher (15.2%) impact on the MFSP as shown in Case 4.

A 40% increase in the reactor capital in the ex situ case leads to an increase of 9.2% to the MFSP 

(Case 8). Organic liquid yield after vapor upgrading is key to the process economics as indicated 

by an 11.6% increase in the MFSP from a 10% drop in yield (Case 5).

The impacts of higher catalyst replacements rates, higher catalyst to biomass ratios, and higher 

catalyst costs on the MFSP are captured in Cases 11, 13, and 7, respectively.

Heat recovery from upgraded vapors can have impacts on process efficiencies and design. The 

impact of lower efficiency (without accounting for the likely inclusion of new equipment in 

addition to those in the base case) is shown in Case 22. It reflects the scenario when no heat can 
62

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be recovered from the hot upgraded vapors between 931°F and 466°F. The beginning 

temperature for vapor condensation using the model compounds in the simulation is 466°F; it is 

assumed in the base case that indirect exchange can be used to recover heat from 931°F to 

466°F.

From an economic standpoint, Case 20 shows that losing carbon as gas is preferable over loss as 

coke. There are larger process operation and design implications of lower coke formation, 

especially if fixed bed vapor upgrading systems are used, and if regeneration protocols include 

reactor cycle times for offline regeneration.

Case 26 shows that there is a small impact of higher heat losses in the system. This is primarily 

due to a lower electricity credit. 

5.3 Hydroprocessing

The catalytic vapor upgrading reduces the dependency on downstream hydroprocessing of 

condensed organic liquid. As a result the impacts on variations in this section are relatively 

smaller than those in the fast pyrolysis and catalytic vapor upgrading sections. As mentioned 

earlier (Figure 8), carbon efficiency of organic liquid feed to fractionated liquid products was 

assumed to scale linearly based on the oxygen content, assuming 85% efficiency for 20% oxygen 

content feed and 98.5% efficiency for feed with negligible oxygen content. Assumption of 88% 

carbon efficiency, versus 94% carbon efficiency in the ex situ case, results in a 9% increase in

the MFSP, as shown in Case 9.

A 40% increase in hydroprocessing and separations area capital leads to a 2.1% increase in the 

MFSP (Case 19) using the underlying capital cost assumptions mentioned previously.

The impacts of hydrotreating and hydrocracking catalyst unit costs and hydrotreater operating

pressure are shown in Cases 18, 24, and 27, respectively. Case 25 shows that using three 

hydrotreating reactors with 50% capacity each, to enable more frequent catalyst maintenance

operations, adds 0.7% to the MFSP. 

5.4 Other Operations and Overall Plant

Case 23 shows the impact of the electricity credit of 2.6¢ in the base case on the MFSP. It is to 

be noted that unlike in a syngas conversion process, non-condensable carbonaceous products are 

not recoverable as liquid products in this process. Unless there are other local consumers of the 

excess heat available in the process (due to the formation of char, coke, and non-condensable 

fuel gases), electricity production is the logical way to capture this thermal energy.

The impacts of hydrogen plant, steam plant, and wastewater treatment capital costs on the MFSP 

are shown in Cases 15, 17, and 21, respectively. 
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6 Conclusions

This analysis lays out conceptual process designs for in situ and ex situ upgrading of fast 

pyrolysis vapors for the production of significantly deoxygenated bio-oil intermediate, with 

further hydroprocessing of the bio-oil to produce hydrocarbon fuel blendstocks that can be costcompetitive with petroleum-derived sources; this is contingent on the research helping achieve 

the performance goals (for 2022) outlined in this report. Advances in catalysts will be necessary 

to improve the quality and yields of the bio-oil intermediate for the success of this conversion 

pathway. Targeted catalyst development should enable bio-oil yield improvements by reducing 

losses to coke and non-condensable gases, quality improvements via hydrodeoxygenation and 

hydrogenation, and increased diesel-range products via molecular combination (coupling) in the 

vapor phase. Higher diesel-range products are targeted for the ex situ process because more 

favorable reaction chemistry (coupling reactions) is possible in a separate reactor where, unlike 

in an in situ upgrading reactor, one does not have to deal with catalyst detriments such as 

biomass, char, and mineral matter/ash. The catalysts developed for both the in situ and ex situ

cases need to be cost-justifiable with respect to maintenance, materials used, and reactor designs 

that are compatible with catalyst performance; the ex situ case can have added options such as 

the use of fixed bed reactors following a hot gas filter. 

The improvements outlined are targeted for the 2022 timeframe; new understanding and 

learnings from research will require adjustments to the conceptual design in the coming years.

While near-term developments (2017 timeframe) will likely enable yield improvements and 

deoxygenation, longer-term developments are expected to allow further hydrodeoxygenation and 

hydrogenation of the bio-oil intermediate, as well as coupling reactions for the production of a 

higher proportion of diesel-range molecules. In addition, further understanding of the bio-oil 

intermediate will lead to the optimization of downstream hydroprocessing. Valorization of 

carbon in the aqueous phase (separated from the bio-oil) can also be made feasible via research.

Techno-economic analysis in the near-term will identify and study process variations to 

encompass a wider range of research for these conversion pathways. Continued assessments of 

the state of technology based on research results, and re-evaluations of the feasibility of targets 

will be critical in the coming years. Characterization of products and intermediates and the 

understanding of their compatibility with the existing petroleum refining infrastructure will be

important for optimal integration and deployment of products. Characterization will become 

more feasible and meaningful after some progress in the research, and the availability of larger 

volumes of products from experimental reactors.

While the target cases with underlying assumptions project MFSPs below $3.5/GGE, further 

improvements and cost reductions to $3/GGE are possible, as shown in the sensitivity analysis. 

Significant impacts identified in the sensitivity cases include economies of larger scales, lower 

catalyst costs through catalyst longevity and lower unit costs, and higher product yields. 
64

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7 Future TEA Work

This design reflects metrics for one possible base case each for the in situ and ex situ fast 

pyrolysis vapor upgrading pathways. This work will evolve with more understanding and 

experimental knowledge during the course of the research. Areas for further studies, among 

others, include the following:

• Research of other process configurations, including the use of a hot gas filter, fixed bed 

vapor upgrading reactors, and different catalysts.

• Inclusion of further understanding of compounds and their physical properties, including 

further speciation and phase equilibrium. This will lead to more predictive process 

models.

• Experimental development of reaction kinetics information. This can facilitate 

development of reactor models (with scale-up prediction capabilities) for use in TEA 

work.

• Impact of feedstock variability on yields.

• Refinement of equipment cost estimates through further understanding of the specifics of 

feasible conversion processes.

• Providing updated state of technology information based on experimental data and 

reassessment of technical targets for cost-competitiveness.

• Refinery integration and details of inclusion of products into the current infrastructure 

based on experimental information.
65

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71

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Appendix A. Equipment Description and Design Basis

Summary

NREL’s Process Engineering Team has compiled information on the equipment in the 

benchmark model. The compilation contains information about the cost, reference year, scaling 

factor, scaling characteristic, design information, and back‐up cost referencing. The information 

is stored in the economic spreadsheet portion of the model.

The following table summarizes the important fields of information contained in the spreadsheet 

model. A partial listing of the information is attached for each piece of equipment. Additional 

information from the spreadsheet model is presented in Appendix B.

Equipment number:a,b Unique identifier, the first letter indicates the equipment type and the first number 

represents the process area, e.g., P-601 is a pump in Area 600

Equipment name:a,b Descriptive name of the piece of equipment

Equipment category:a Code indicating the general type of equipment, e.g., PUMP

Equipment type:a Code indicating the specific type of equipment, e.g., CENTRIFUGAL for a pump

Equipment description:a Short description of the size or characteristics of the piece of equipment, e.g., 20 

gpm, 82 ft head for a pump

Number required:b Number of duplicate pieces of equipment needed

Number spares:b Number of on-line spares

Original equip. cost:b Equipment cost

Source/reference:

a Source of the equipment cost, e.g., Aspen Capital Cost Estimator or vendor 

quotation 

Base year:b Year in which the cost estimate is based

Design flow:

b Value of the scaling stream or variable used to obtain the base cost of the 

equipment

Actual flow:

b Value of the actual stream from model used to derive size ratio relative to design 

flow

Size ratio:

b Actual flow/Design flow

Units:b Units of the scaling stream or variable, e.g., LB/HR, MMBtu/HR

Installation factor:b Value of the installation factor. Installed Cost = Base Cost x Installation Factor

Scaling exponent:b Value of the exponential scaling equation

MOC:

a Material of construction

Notes: Any other important information about the design or cost

a These fields are listed for all pieces of equipment in Appendix A. b These fields are part of the equipment cost listing in Appendix B.
72

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Equip ID Equipment Name Equipment 

Category Equipment Type

Design 

Pressure (psig)

Design Temp 

(F)

MOC Source/Reference

C-101 Hopper Feeder CONVEYOR VIBRATING-FEEDER CS Included in per unit cost of feedstock Idaho National Lab

C-102 Screener Feeder Conveyor CONVEYOR BELT CS Included in per unit cost of feedstock Idaho National Lab

C-103 Radial Stacker Conveyor CONVEYOR BELT CS Included in per unit cost of feedstock Idaho National Lab

C-104 Dryer Feed Screw Conveyor CONVEYOR SCREW CS Included in per unit cost of feedstock Idaho National Lab

C-105 Biomass Feed Screw Conveyor CONVEYOR SCREW CS Included in per unit cost of feedstock Idaho National Lab

K-101 Flue Gas Blower FAN CENTRIFUGAL CS 60,000 cfm 15" H2O 204 hp ACCE V8.4

M-101 Hydraulic Truck Dump with Scale SCALE TRUCK-SCALE CS Included in per unit cost of feedstock Idaho National Lab

M-102 Hammermill MISC SIZE REDUCER CS Included in per unit cost of feedstock Idaho National Lab

M-103 Front End Loaders VEHICLE LOADER CS Included in per unit cost of feedstock Idaho National Lab

M-104 Cross Flow Pellet Dryer MISC DRYER CS 50 ton/h 5% moisture reduction Idaho National Lab

S-101 Magnetic Head Pulley SEPARATOR MAGNET CS Included in per unit cost of feedstock Idaho National Lab

S-102 Vibratory Conveyor SEPARATOR SCREEN CS Included in per unit cost of feedstock Idaho National Lab

T-101 Dump Hopper TANK LIVE-BTM-BIN CS Included in per unit cost of feedstock Idaho National Lab

T-102 Hammermill surge bin TANK LIVE-BTM-BIN CS Included in per unit cost of feedstock Idaho National Lab

T-103 Dryer Feed Bin TANK LIVE-BTM-BIN CS Included in per unit cost of feedstock Idaho National Lab

T-104 Dried Biomass Hopper TANK VERTICAL-VESSEL CS Included in per unit cost of feedstock Idaho National Lab

T-105 Lock Hopper TANK VERTICAL-VESSEL CS Included in per unit cost of feedstock Idaho National Lab

T-106 Feed Hopper TANK VERTICAL-VESSEL CS Included in per unit cost of feedstock Idaho National Lab

A100 Pinch Exchanger CAPEX

Area A100: Feed Handling & Drying ↑

C-212 Fines purge cooler CONVEYOR SCREW CS HGI FCC Costing Sheet

K-211 Fluidizing gas recycle compressor COMPRESSOR RECIPROCATING SS 2-stage reciprocating 3648 hp Vendor quote via HGI

K-212 Combustor air compressor COMPRESSOR CENTRIFUGAL SS Multi-stage oil-free 10,000 hp Vendor quote via HGI

R-211 Fluidized Bed Reactor REACTOR FLUIDIZED BED 105 930 Refractory 1,000 tpd biomass 20,375 ACFM gas prod 7.8 lb media/lb HGI FCC Costing Sheet

R-212 Char Combustor REACTOR FLUIDIZED BED 105 1200 Refractory 718,690 lb/h solids 12,000 ACFM gas prod HGI FCC Costing Sheet

R-212C Sand Cooler HEAT EXCH SOLIDS COOLER 105 1200 Refractory 3.7 MMBtu/h HGI FCC Costing Sheet

S-211 Primary Cyclone SEPARATOR CYCLONE 105 930 CS 20,375 ACFM gas prod 718,690 lb/h solids 99.9% reject HGI FCC Costing Sheet

S-212 Secondary Cyclone SEPARATOR CYCLONE 105 930 CS 20,375 ACFM gas prod 720 lb/h solids 99.9% reject HGI FCC Costing Sheet

S-213 Char Combustor Primary Cyclone SEPARATOR CYCLONE 105 1200 CS 12,000 ACFM gas prod 718,690 lb/h solids 99.9% reject HGI FCC Costing Sheet

S-214 Char Combustor Secondary Cyclone SEPARATOR CYCLONE 105 1200 CS 12,000 ACFM gas prod 720 lb/h solids 99.9% reject HGI FCC Costing Sheet

T-211 Bed Media Bin VESSEL PRESSURE STORAGE 105 650 CS HGI FCC Costing Sheet

T-212 Depleted bed media and ash storage bin MISC ROLL-OFF DISPOSAL 0 300 CS HGI FCC Costing Sheet

T-217 Char combustor bed media feed bin VESSEL PRESSURE STORAGE 105 650 CS HGI FCC Costing Sheet

A211 Pinch Exchanger CAPEX ACCE V7.2

Area A211: Ex Situ Fast Pyrolysis ↑

C-202 Fines purge cooler CONVEYOR SCREW CS HGI FCC Costing Sheet

K-201 Fluidizing gas recycle compressor COMPRESSOR RECIPROCATING SS 2-stage reciprocating 3648 hp Vendor quote via HGI

K-202 Combustor air compressor COMPRESSOR CENTRIFUGAL SS Multi-stage oil-free 10,000 hp Vendor quote via HGI

R-201 Catalytic Fluidized Bed Reactor REACTOR FLUIDIZED BED 105 930 Refractory 1,000 tpd biomass 20,424 ACFM gas prod 7.8 lb media/lb HGI FCC Costing Sheet

R-202 Char Combustor REACTOR FLUIDIZED BED 105 1200 Refractory 727,725 lb/h solids 20,000 ACFM gas prod HGI FCC Costing Sheet

R-202C Catalyst Cooler HEAT EXCH SOLIDS COOLER 105 1200 Refractory 128 MMBtu/h HGI FCC Costing Sheet

S-201 Primary Cyclone SEPARATOR CYCLONE 105 930 CS 20,424 ACFM gas prod 712,880 lb/h solids 99.9% reject HGI FCC Costing Sheet

S-202 Secondary Cyclone SEPARATOR CYCLONE 105 930 CS 21,341 ACFM gas prod 720 lb/h solids 99.9% reject HGI FCC Costing Sheet

S-203 Char Combustor Primary Cyclone SEPARATOR CYCLONE 105 1200 CS 20,000 ACFM gas prod 713,000 lb/h solids 99.9% reject HGI FCC Costing Sheet

S-204 Char Combustor Secondary Cyclone SEPARATOR CYCLONE 105 1200 CS 20,000 ACFM gas prod 720 lb/h solids 99.9% reject HGI FCC Costing Sheet

T-201 Catalyst steam stripper VESSEL PRESSURE STORAGE 105 650 CS 1 min cat res. time 3 lb steam/1000 lb catalyst HGI FCC Costing Sheet

T-202 Depleted catalyst and ash storage bin MISC ROLL-OFF DISPOSAL 0 300 CS HGI FCC Costing Sheet

T-207 Catalyst feed bin VESSEL PRESSURE STORAGE 105 650 CS HGI FCC Costing Sheet

A201 Pinch Exchanger CAPEX ACCE V7.2

Area A201: In Situ Catalytic Fast Pyrolysis ↑

M-251 Hot Gas Filter package SEPARATOR FILTER 20 950 94500 ACFH 7400 lb/h solids Pall Corporation

Area A251: Hot Gas Filter ↑

C-262 Fines purge cooler CONVEYOR SCREW CS HGI FCC Costing Sheet

K-262 Regenerator air compressor COMPRESSOR CENTRIFUGAL SS Multi-stage oil-free 10,000 hp Vendor quote via HGI

R-261 Catalytic Fluidized Bed Reactor REACTOR FLUIDIZED BED 105 930 Refractory 2,000 tpd biomass equiv 42,200 ACFM gas prod 5.0 lb media/lb HGI FCC Costing Sheet

R-262 Catalyst Regenerator REACTOR FLUIDIZED BED 105 1200 Refractory 918,760 lb/h solids 10,200 ACFM gas prod HGI FCC Costing Sheet

R-262C Catalyst Cooler HEAT EXCH SOLIDS COOLER 105 1200 Refractory 272 MMBtu/h total for R-262C and R-262C-1 HGI FCC Costing Sheet

R-262C1 Catalyst cooler (secondary, included) HEAT EXCH SOLIDS COOLER 105 1200 Refractory Cost included with R-262C HGI FCC Costing Sheet

S-261 Primary Cyclone SEPARATOR CYCLONE 105 930 CS 42,200 ACFM gas prod 918,760 lb/h solids 99.9% reject HGI FCC Costing Sheet

S-262 Secondary Cyclone SEPARATOR CYCLONE 105 930 CS 42,200 ACFM gas prod 920 lb/h solids 99.9% reject HGI FCC Costing Sheet

S-263 Char Combustor Primary Cyclone SEPARATOR CYCLONE 105 1200 CS 18,000 ACFM gas prod 918,760 lb/h solids 99.9% reject HGI FCC Costing Sheet

S-264 Char Combustor Secondary Cyclone SEPARATOR CYCLONE 105 1200 CS 18,000 ACFM gas prod 920 lb/h solids 99.9% reject HGI FCC Costing Sheet

T-261 Catalyst steam stripper VESSEL PRESSURE STORAGE 105 650 CS 1 min cat res. time 3 lb steam/1000 lb catalyst HGI FCC Costing Sheet

T-262 Depleted catalyst and ash storage bin MISC ROLL-OFF DISPOSAL 0 300 CS HGI FCC Costing Sheet

T-267 Catalyst feed bin VESSEL PRESSURE STORAGE 105 650 CS HGI FCC Costing Sheet

A261 Pinch Exchanger CAPEX ACCE V7.2

R-261 VPU Fixed Bed Reactor VESSEL VERTICAL PRESSURE 130 1000 CS+Inconel 17' Ø 48' T-T +20% internals ACCE V8.4

A261 Pinch Exchanger CAPEX ACCE V7.2

Area A261: Ex Situ Vapor Phase Upgrading ↑

Sizing Information
73

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Equip 

ID Equipment Name Equipment Category Equipment Type

Design 

Pressure (psig)

Design Temp 

(F)

MOC Source/Reference

D-301 Heavy Fraction Condenser Absorber VESSEL TRAYED TOWER 120 500 316SS 12' Ø 70' T-T 14 trays sieve ACCE V8.4

D-302 Light Fraction Condenser Absorber VESSEL TRAYED TOWER 100 120 316SS 13' Ø 70' T-T 20 trays sieve ACCE V8.4

H-313 D-301 Vapor ACHE HEAT EXCH AIR COOLED 130 316SS 15,000 sq ft 45' tubes 3 bays x 15' 2 fan/bay ACCE V8.4

H-314 D-302 Feed Cooler HEAT EXCH SHELL & TUBE 150 190 316SS 5,000 sq ft Shell 43" Ø 20' L 955 X 1" tubes ACCE V8.4

H-315 D-302 Feed/overhead exchanger HEAT EXCH SHELL & TUBE 110 316SS 18,500 sq ft Shell 42" Ø 23' L 884 X 1" tubes 4 shells ACCE V8.4

H-316 D-302 Liquid feed chiller HEAT EXCH SHELL & TUBE 150 190 316SS 3,650 sq ft Shell 36" Ø 20' L 698 X 1" tubes ACCE V8.4

H-320 Heavy fraction ACHE HEAT EXCH AIR COOLED 130 316SS 70 sq ft 5' tubes 1 bays x 2' 2 fan/bay ACCE V8.4

H-320A Heavy fraction cooler HEAT EXCH SHELL & TUBE 2085 190 SS Clad CS 343 sq ft Shell 14''Ø 16' L 82 X 1" tubes H-463C

H-326 D-302 Quench circulation chiller HEAT EXCH PLATE & FRAME 200 200 316SS 7,500 sq ft 486 plates ACCE V8.4

P-318 D-301 Bottoms pump PUMP CENTRIFUGAL 125 250 316SS 56 gpm 75' head ACCE V8.4

P-323 Circulation filter charge pump PUMP CENTRIFUGAL 135 250 316SS 2655 gpm 69' head ACCE V8.4

P-329 Aqueous filter charge pump PUMP CENTRIFUGAL 125 250 316SS 182 gpm 30' head ACCE V8.4

P-331 Organic product pump PUMP CENTRIFUGAL 125 250 316SS 124 gpm 30' head ACCE V8.4

P-332 Quench recycle pump PUMP CENTRIFUGAL 125 250 316SS 215 gpm 9' head ACCE V8.4

S-319 D-301 Bottoms filter FILTER CARTRIDGE 316SS 52 gpm ACCE V8.4

S-322 D-302 Bottoms decanter VESSEL HORIZ LL SEP 110 150 316SS 11' Ø 35' T-T +20% internals ACCE V8.4

S-324 Quench circulation filter FILTER TUBULAR 316SS 2340 gpm 60 Mesh ACCE V8.4

S-329 Aqueous phase filter FILTER TUBULAR 316SS 182 gpm 400 Mesh ACCE V8.4

T-328 Organic product surge tank VESSEL VERTICAL PRESSURE 125 250 316SS 5' Ø 14' T-T ACCE V8.4

T-332 D-301 Circulation surge tank VESSEL VERTICAL PRESSURE 125 250 316SS 5' Ø 14' T-T T-328

A310 Pinch exchanger CAPEX ACCE V7.2

Area A310: Product Condensation and Separation ↑

H-373 Post-WGS ACHE HEAT EXCH AIR COOLED 150 316SS 1252 sq ft 24' tubes 1 bays x 8' 2 fan/bay ACCE V8.4

H-374 Post-WGS cooler HEAT EXCH SHELL & TUBE 150 140 316SS 1188 sq ft Shell 21''Ø 20' L 227 X 1" tubes ACCE V8.4

K-390 PSA compressor: multistage COMPRESSOR RECIPROCATING SS 2-stage reciprocating 3648 hp Vendor quote via HGI

M-385 PSA MISC MISC Vendor quote via HGI

P-377 Compressor condensate pump PUMP CENTRIFUGAL 125 250 316SS 56 gpm 30' head P-318

R-365 High-temperature WGS VESSEL VERTICAL PRESSURE 450 1000 316SS 12' Ø 24' T-T +20% internals ACCE V8.4

S-385 PSA Compressor suction KO VESSEL VERTICAL PRESSURE 135 150 316SS 5' Ø 7.5' T-T ACCE V8.4

S-386 PSA Compr disch KO VESSEL VERTICAL PRESSURE 280 160 316SS 4' Ø 7' T-T ACCE V8.4

T-377 Compressor condensate tank VESSEL VERTICAL PRESSURE 125 250 316SS 5' Ø 14' T-T T-328

A360 Pinch exchanger CAPEX ACCE V7.2

Area A360: Hydrogen Recycle and WGS ↑

H-410 Feed-effluent exchanger HEAT EXCH SHELL & TUBE 1910 650 316SS 2636 sq ft Shell 32''Ø 23' L 504 X 1" tubes ACCE V8.4

H-411 Feed furnace HEAT EXCH BOX FURNACE 1930 650 316SS 2.21 MMBtu/h 208 CFM gas ACCE V8.4

H-413A HT product ACHE HEAT EXCH AIR COOLED 150 316SS 432 sq ft 14' tubes 1 bays x 4' 2 fan/bay ACCE V8.4

H-413C HT product cooler HEAT EXCH SHELL & TUBE 2085 190 316SS 589 sq ft Shell 18''Ø 16' L 141 X 1" tubes ACCE V8.4

H-444 Quench hydrogen stage 2 cooler HEAT EXCH SHELL & TUBE 1650 650 316SS 57 sq ft Shell 8''Ø 8' L 29 X 1" tubes ACCE V8.4

H-445 Quench hydrogen stage 3 cooler HEAT EXCH SHELL & TUBE 1650 650 316SS 57 sq ft Shell 8''Ø 8' L 29 X 1" tubes H-444

K-412 Hydrogen makeup compressor COMPRESSOR RECIPROCATING 1,050 hp 4-stage recip Vendor quote via HGI

K-442 Hydrogen recycle compressor COMPRESSOR RECIPROCATING 146 hp single stage recip Vendor quote via HGI

P-410 HT feed pump PUMP DIAPHRAGM 90 316SS 135 gpm 5275' head ACCE V8.4

R-410 Hydrotreater, 1000 psi VESSEL VERTICAL PRESSURE 1130 850 CS+Inconel 10' Ø 48' T-T +60% internals ACCE V8.4

R-410 Hydrotreater, 1500 psi VESSEL VERTICAL PRESSURE 1640 850 CS+Inconel 10' Ø 48' T-T +60% internals ACCE V8.4

R-410 Hydrotreater, 2000 psi VESSEL VERTICAL PRESSURE 2070 850 CS+Inconel 10' Ø 48' T-T +60% internals ACCE V8.4

S-410 Vapor KO drum VESSEL VERTICAL PRESSURE 120 250 316SS 4.5' Ø 10' T-T ACCE V8.4

S-411 HP HT effluent flash: 3 phase VESSEL HORIZ LL SEP 2025 160 316SS 3' Ø 10' T-T +20% internals ACCE V8.4

S-412 LP HT effluent flash: 3 phase VESSEL HORIZ LL SEP 70 170 316SS 4' Ø 13' T-T +10% internals ACCE V8.4

A410 Pinch exchanger CAPEX ACCE V7.2

Area A410: Whole Oil Hydroprocessing ↑

D-450 Gasoline column VESSEL TRAYED TOWER 35 650 316SS 7.5' Ø 64' T-T 26 trays sieve ACCE V8.4

D-451 Diesel column VESSEL TRAYED TOWER 35 800 316SS 3.5' Ø 64' T-T 26 trays sieve ACCE V8.4

H-450C D-450 Condenser (startup) HEAT EXCH SHELL & TUBE 60 250 316SS 821 sq ft Shell 18''Ø 20' L 157 X 1" tubes ACCE V8.4

H-450R D-450 Reboiler (startup) HEAT EXCH SHELL & TUBE 60 250 316SS 980 sq ft Shell 30''Ø 25' L 94 X 1" tubes ACCE V8.4

H-451C D-451 Condenser (startup) HEAT EXCH SHELL & TUBE 150 190 316SS 72 sq ft Shell 18''Ø 20' L 28 X 1" tubes ACCE V8.4

H-451R D-451 Reboiler (startup) HEAT EXCH SHELL & TUBE 60 250 316SS 980 sq ft Shell 30''Ø 25' L 94 X 1" tubes H-450R

H-454 Gasoline product cooler HEAT EXCH SHELL & TUBE 150 250 CS 589 sq ft Shell 18''Ø 16' L 141 X 1" tubes ACCE V8.4

H-457A Diesel product ACHE HEAT EXCH AIR COOLED 150 CS 41 sq ft 10' tubes 1 bays x 1' 2 fan/bay ACCE V8.4

H-457C Diesel Product Cooler HEAT EXCH SHELL & TUBE 150 250 CS 58 sq ft Shell 8''Ø 8' L 28 X 1" tubes ACCE V8.4

H-459 D-450 Overhead vapor cooler HEAT EXCH SHELL & TUBE 150 250 CS 12 sq ft Shell 4''Ø 8' L 6 X 1" tubes ACCE V8.4

P-450 D-450 Reflux pump PUMP CENTRIFUGAL 35 250 316SS 253 gpm 225' head ACCE V8.4

P-451 D-451 Reflux pump PUMP CENTRIFUGAL 35 250 316SS 108 gpm 225' head ACCE V8.4

S-450 D-450 Overhead accumulator VESSEL HORIZ PRESSURE 35 250 316SS 4.5' Ø 13.5' T-T ACCE V8.4

S-451 D-451 Overhead accumulator VESSEL HORIZ PRESSURE 35 400 316SS 3.5' Ø 10.5' T-T ACCE V8.4

A450 Pinch exchanger CAPEX ACCE V7.2

Area A450: Oil Fractionation ↑

Sizing Information
74

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Equip 

ID Equipment Name Equipment Category Equipment Type

Design 

Pressure (psig)

Design Temp 

(F)

MOC Source/Reference

H-460 Feed-effluent exchanger HEAT EXCH SHELL & TUBE 2390 650 CS 276 sq ft Shell 14''Ø 18' L 66 X 1" tubes ACCE V8.4

H-461 Feed furnace HEAT EXCH BOX FURNACE 2100 750 316SS 0.68 MMBtu/h 48 CFM gas ACCE V8.4

H-463A HC product ACHE HEAT EXCH AIR COOLED 150 CS 243 sq ft 10' tubes 1 bays x 3' 2 fan/bay ACCE V8.4

H-463C HC product Cooler HEAT EXCH SHELL & TUBE 2085 190 SS Clad CS 343 sq ft Shell 14''Ø 16' L 82 X 1" tubes ACCE V8.4

H-494 Quench hydrogen stage 2 cooler HEAT EXCH SHELL & TUBE 1650 650 316SS 57 sq ft Shell 8''Ø 8' L 29 X 1" tubes H-444

H-495 Quench hydrogen stage 3 cooler HEAT EXCH SHELL & TUBE 1650 650 316SS 57 sq ft Shell 8''Ø 8' L 29 X 1" tubes H-444

K-462 Hydrogen makeup compressor COMPRESSOR RECIPROCATING 1,050 hp 4-stage recip Vendor quote via HGI

K-492 Hydrogen recycle compressor COMPRESSOR RECIPROCATING 146 hp single stage recip Vendor quote via HGI

P-460 HC feed pump PUMP DIAPHRAGM 90 316SS 135 gpm 5275' head P-410

R-460 Hydrocracker VESSEL VERTICAL PRESSURE 2070 850 CS+Inconel 6.5' Ø 48' T-T +60% internals ACCE V8.4

S-460 Vapor KO drum VESSEL VERTICAL PRESSURE 120 250 316SS 4.5' Ø 10' T-T S-410

S-461 HP effluent flash: 3 phase VESSEL HORIZ LL SEP 2025 160 316SS 3' Ø 10' T-T +20% internals ACCE V8.4

S-462 LP effluent flash VESSEL HORIZ LL SEP 70 170 316SS 1' Ø 7' T-T ACCE V8.4

A460 Pinch exchanger CAPEX ACCE V7.2

Area A460: Hydrocracking ↑

H-568A WGS Effluent ACHE HEAT EXCH AIR COOLED 150 CS 1392 sq ft 24' tubes 1 bays x 8' 2 fan/bay ACCE V8.4

H-568C WGS Effluent cooler HEAT EXCH SHELL & TUBE 60 250 CS 1281 sq ft Shell 22''Ø 20' L 245 X 1" tubes ACCE V8.4

K-511 Pyrolysis offgas compressor to reformer COMPRESSOR RECIPROCATING SS 2-stage reciprocating 3648 hp K-211

K-545 Reformer combustor air blower INCLUDED

K-580 PSA Compressor multistage INCLUDED

M-575 PSA INCLUDED

P-576 Compressor condensate pump PUMP CENTRIFUGAL 125 250 316SS 56 gpm 30' head P-318

R-530 Steam reformer package (PNNL) MISC PACKAGE UNIT 23053

R-565 WGS reactor INCLUDED

R-566 LTS reactor VESSEL VERTICAL PRESSURE 450 1000 316SS 12' Ø 24' T-T +20% internals R-365

S-575 Compressor suction KO drum INCLUDED

S-586 PSA Compressor discharge KO drum INCLUDED

T-576 Compressor condensate tank VESSEL VERTICAL PRESSURE 125 250 316SS 4.5' Ø 14' T-T T-328

A500 Pinch exchanger CAPEX ACCE V7.2

Area A500: Hydrogen Plant ↑

H-601 Steam turbine condenser HEAT EXCH AIR COOLED 58.25 MMBtu/h per module SPX Cooling

H-603 Blowdown cooler HEAT EXCH Shell and tube 50 CS 0.4 MMBtu/Hr; LMTD = 15 F; U = 100 Btu/hr-ft^2-F; Area = 265 Ft^2; U-Tube
 51400 Icarus 2006.5

M-601 BFW EDI+polishing MISC PACKAGE UNIT Quote from 51400 (RO+EDI+polish) with RO removed 51400 Siemens

M-602A Steam turbine generator Stage 1 GENERATOR STEAM-TURBINE CS Vendor quotation for 30.14 MW system. Excludes steam turbine condenser. Shin Nippon

M-602B Steam turbine generator Stage 2 GENERATOR STEAM-TURBINE CS Vendor quotation for 30.14 MW system. Excludes steam turbine condenser. Shin Nippon

M-603 Startup boiler MISC PACKAGE UNIT CS 40,000 lb/h (half of A800 steam at 2,000 TPD) ACCE V8.4

P-601 Makeup pump PUMP CENTRIFUGAL CS 160 gpm 35' head 51400 Icarus 2006.5

P-602 Condensate pump PUMP CENTRIFUGAL CS 500 gpm 60' head 51400 Icarus 2006.5

P-603 EDI pump PUMP CENTRIFUGAL CS 500 gpm 60' head 51400 Icarus 2006.5

P-604 Boiler feed water pump PUMP POS-DISPLACEMENT CS 1050 gpm 3340' head 51400 Icarus 2006.5

P-605 Condensate collection pump PUMP CENTRIFUGAL CS 500 gpm 60' head P-603

S-601 Blowdown flash drum VESSEL VERTICAL PRESSURE 1500 CS Liquid 30 gpm; 10 Minute Residence Time; Vessel Volume = 900 gal 51400 Icarus 2006.5

T-601 Condensate collection tank VESSEL VERTICAL PRESSURE CS Liquid 1,000 gpm; 5 minute Residence Time; Liquid Volume = 5,000 gal 51400 Icarus 2006.5

T-602 Condensate surge tank TANK HORIZONTAL-VESSEL CS Liquid 1,000 gpm; 5 minute Residence Time; Liquid Volume = 5,000 gal 51400 Icarus 2006.5

T-603 Deaerator TANK HORIZONTAL-VESSEL 50 CS Liquid 1,050 gpm; 10 Minute Residence Time; Vessel Volume = 21,000 gal 51400 Icarus 2006.5

T-603A Deaerator packed column COLUMN PACKED COLUMN CS Inside Diameter = 2 ft; Height = 10 ft; Packing Height = 8 ft 51400 Icarus 2006.5

T-605 Steam drum TANK HORIZONTAL-VESSEL CS Horizontal Drum; < 100% of Critical Velocity; Diameter = 5' T-T Length = 20' 51400 Icarus 2006.5

T-606 Steam turbine condensate tank VESSEL VERTICAL PRESSURE CS Liquid 1,000 gpm; 5 minute Residence Time; Liquid Volume = 5,000 gal T-601

A600 Pinch exchanger CAPEX ACCE V7.2

Area A600: Steam System & Power Generation ↑

Sizing Information
75

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Equip 

ID Equipment Name Equipment Category Equipment Type

Design 

Pressure (psig)

Design Temp 

(F)

MOC Source/Reference

K-701 Plant air compressor COMPRESSOR RECIPROCATING CS Flow Rate = 450 CFM; Outlet Pressure = 125 PSIG 51400 Icarus 2006.5

M-701 Cooling tower system COOLNG TWR INDUCED-DRAFT FIBERGLASS 15,000 gpm, 110 °F Cooling Tower Inlet Temperature Cooling Tower Depot

M-702 Hydraulic truck dump with scale SCALE TRUCK-SCALE CS Hydraulic Truck Dumper with Scale Vendor Quotation

M-703 Flue gas scrubber MISC VERTICAL-VESSEL SS304 Scrubber costs from TurboSonic. Quotation basis = $160,000/ACFM TurboSonic

M-704 Flue gas stack MISC MISC CS Base Diameter = 72 inches; Stack Height = 200 ft 51400 Icarus 2006.5

M-708 Chilled water system CHILLER CENTRIFUGAL CS 2,350 Ton Trane

M-710 Product loading rack MISC MISC Estimate

P-701 Cooling water pump PUMP CENTRIFUGAL CS 18620 gpm 185' head 51400 Icarus 2006.5

P-702 Firewater pump PUMP CENTRIFUGAL CS 2500 gpm 120' head 51400 Icarus 2006.5

P-703 Diesel pump PUMP CENTRIFUGAL CS 5 gpm 150' head 51400 Icarus 2006.5

P-704 Ammonia pump PUMP CENTRIFUGAL CS 1 gpm 150' head 51400 Icarus 2006.5

P-705 Caustic pump PUMP CENTRIFUGAL CS 0.5 gpm 10' head 51400 Icarus 2006.5

P-707 BFW chemical pump PUMP CENTRIFUGAL CS 1 gpm 150' head 51400 Icarus 2006.5

P-708 Flue gas scrubber circulation pump PUMP CENTRIFUGAL CS 1010 gpm 60' head 51400 Icarus 2006.5

P-790 Gasoline product pump PUMP CENTRIFUGAL 35 250 316SS 108 gpm 225' head P-450

P-792 Diesel product pump PUMP CENTRIFUGAL 35 250 316SS 108 gpm 225' head P-450

S-701 Instrument air dryer DRYER PACKAGE UNIT CS 400 SCFM Dewpt -40F Richardson (51400)

T-701 Plant air receiver TANK VERTICAL-VESSEL 200 CS 1000 gal 51400 Icarus 2006.5

T-702 Firewater storage tank TANK FLAT-BTM-STORAGE 0.5 CS 600,000 gal flat roof 51400 Icarus 2006.5

T-703 Purchased diesel storage tank TANK FLAT-BTM-STORAGE 0.5 CS 12,000 gal floating roof 51400 Icarus 2006.5

T-704 Ammonia storage tank TANK HORIZ-STORAGE 350 CS 560 gal 51400 Icarus 2006.5

T-705 Caustic storage tank TANK FLAT-BTM-STORAGE 0.5 CS 5,400 gal flat roof 51400 Icarus 2006.5

T-708 BFW chemical storage tank TANK HORIZ-STORAGE 10 SS316 400 gal 51400 Icarus 2006.5

T-790 Gasoline product storage tanks VESSEL STORAGE 15 250 CS 47' Ø 40' H 500,000 gal ACCE V8.4

T-792 Diesel product storage tank VESSEL STORAGE 15 250 CS 47' Ø 40' H 500,000 gal T-790

Area A700: Cooling Water & Other Utilities ↑

H-840 RTO Feed/Effluent exchanger MISC MISC Included with RTO

K-831 RTO blower FAN CENTRIFUGAL

M-805 Clarifier SEPARATOR CLARIFIER 1.4 Ft / Hr Rise Rate; 40' Diameter x 12' Height 51400 M-705

M-806 Belt press MISC MISC 51400 M-706

M-807 Sand filter MISC MISC 51400 M-707

M-833 Aqueous regenerative thermal oxidizer MISC MISC Refractory $100 /SCFM EPA Guideline

M-861 Reverse osmosis unit MISC MISC 15 gal/ft2/day HGI 9/21/14

P-801 Clarifier overflow pump PUMP CENTRIFUGAL 35 250 CS 50 gpm 40' head ACCE V8.4

P-809 Slurry pump PUMP CENTRIFUGAL 45 CS 2 gpm 10' head 51400 Icarus 2006.5

P-810 Boiler charge pump PUMP CENTRIFUGAL 170 250 CS 200 gpm 160' head ACCE V8.4

P-812 Condensate Pump PUMP CENTRIFUGAL 155 400 CS 140 gpm 20' head ACCE V8.4

P-814 Boiler charge pump PUMP CENTRIFUGAL 160 400 CS 145 gpm 5' head ACCE V8.4

P-815 Boiler makeup pump PUMP CENTRIFUGAL 170 70 CS 5 gpm 400' head ACCE V8.4

P-822 Concentrated waste water pump PUMP CENTRIFUGAL 150 400 304SS 7 gpm 20' head ACCE V8.4

P-860 RO Feed pump PUMP CENTRIFUGAL 85 250 CS 185 gpm 170' head ACCE V8.4

P-866 Clean water pump PUMP CENTRIFUGAL 40 250 CS 140 gpm 50' head ACCE V8.4

T-801 Clarifier overflow tank VESSEL STORAGE 15 250 CS 17' Ø 32' H 50,000 gal ACCE V8.4

T-809 Slurry tank VESSEL STORAGE 15 250 CS 17' Ø 32' H 50,000 gal T-801

T-810 Boiler Feed Tank VESSEL VERTICAL PRESSURE 110 250 CS 5' Ø 15' T-T ACCE V8.4

T-812 Steam drum VESSEL VERTICAL PRESSURE 160 410 CS 4.5' Ø 14' T-T ACCE V8.4

T-814 Boiler feed tank VESSEL VERTICAL PRESSURE 160 400 CS 4.5' Ø 14' T-T ACCE V8.4

T-822 Steam drum VESSEL VERTICAL PRESSURE 160 410 CS 4' Ø 12' T-T ACCE V8.4

T-860 RO Feed tank VESSEL STORAGE 15 250 CS 21.5' Ø 9.5' H ACCE V8.4

T-866 Clean water tank VESSEL STORAGE 15 250 CS 42' Ø 19' H ACCE V8.4

A800 Pinch exchanger CAPEX ACCE V7.2

Area A800: Water Management ↑

NOTES ACCE Aspen Capital Cost Estimator

HGI Harris Group

51400 2011 NREL mixed alcohols report

23053 2013 PNNL Pyrolysis report

Sizing Information
76

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Appendix B-1. Individual Equipment Cost Summary (In 

Situ Case)
77

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Equip 

ID

Required

Spares

Equipment Name

Design Flow 

(per unit)

Design Flow 

(total)

Actual Flow 

(total)

Units

Size Ratio

Original 

Equip Cost

(per unit)

Base Year

Total Orig 

Equip Cost 

(Req+Spare)

in Base YearScaling Exp.

Scaled Cost 

in Base Year

Install Factor

Installed 

Cost 

in Base Year

Installed 

Cost 

in 2011$

Scaled 

Uninstalled 

Cost in 2011$

C-101 Hopper Feeder INCLUDED

C-102 Screener Feeder Conveyor INCLUDED

C-103 Radial Stacker Conveyor INCLUDED

C-104 Dryer Feed Screw Conveyor INCLUDED

C-105 Biomass Feed Screw Conveyor INCLUDED

K-101 3 Flue Gas Blower 204 612 502 hp 0.82 $59,300 2013 $177,900 0.78 $152,406 1.94 $295,046 $304,616 $157,349 

M-101 Hydraulic Truck Dump with Scale INCLUDED

M-102 Hammermill INCLUDED

M-103 Front End Loaders INCLUDED

M-104 2 Cross Flow Pellet Dryer 102,066 204,131 204,131 lb/h 1.00 $50,000 2011 $100,000 0.80 $100,000 2.00 $200,000 $200,000 $100,000 

S-101 Magnetic Head Pulley INCLUDED

S-102 Vibratory Conveyor INCLUDED

T-101 Dump Hopper INCLUDED

T-102 Hammermill surge bin INCLUDED

T-103 Dryer Feed Bin INCLUDED

T-104 Dried Biomass Hopper INCLUDED

T-105 Lock Hopper INCLUDED

T-106 Feed Hopper INCLUDED

A100 1 Pinch Exchanger CAPEX 2008 $0 $0 2.64 $0 $0 $0 

Area A100: Feed Handling & Drying ↑ $277,900 $252,406 1.96 $495,047 $504,616 $257,350

C-202 2 Fines purge cooler

K-201 2 Fluidizing gas recycle compressor 3,648 7,296 2,259 hp 0.31 $4,700,000 2014 $9,400,000 0.90 $3,272,282 1.60 $5,235,650 $5,343,301 $3,339,563 

K-202 2 Combustor air compressor 10,000 20,000 25,042 hp 1.25 $2,600,000 2014 $5,200,000 0.78 $6,196,626 1.60 $9,914,602 $10,118,457 $6,324,036 

R-201 2 Catalytic Fluidized Bed Reactor 1,225,468 2,450,936 2,285,891 ACFH 0.93 $3,889,900 2011 $7,779,800 0.50 $7,513,290 4.01 $30,128,295 $30,128,295 $7,513,290 

R-202 2 Char Combustor 1,199,076 2,398,152 2,386,324 ACFH 1.00 $3,152,459 2011 $6,304,918 0.50 $6,289,351 3.97 $24,963,814 $24,963,814 $6,289,351 

R-202C 2 Catalyst Cooler 127,815,673 255,631,346 258,621,302 Btu/h 1.01 $1,793,235 2011 $3,586,470 0.80 $3,619,990 3.00 $10,859,970 $10,859,970 $3,619,990 

S-201 2 Primary Cyclone INCLUDED

S-202 2 Secondary Cyclone INCLUDED

S-203 0 Char Combustor Primary Cyclone INCLUDED

S-204 0 Char Combustor Secondary Cyclone INCLUDED

T-201 2 Catalyst steam stripper 2,139 4,278 4,151 lb/h 0.97 $742,538 2011 $1,485,076 0.30 $1,471,731 3.00 $4,415,194 $4,415,194 $1,471,731 

T-202 0 Depleted catalyst and ash storage bin INCLUDED

T-207 0 Catalyst feed bin INCLUDED

A201 1 Pinch Exchanger CAPEX 2008 $2,479,203 $2,479,203 2.64 $6,533,610 $6,650,565 $2,523,583 

Area A201: In Situ Catalytic Fast Pyrolysis ↑ $36,235,467 $30,842,473 2.98 $92,051,135 $92,479,596 $31,081,544

D-301 1 Heavy Fraction Condenser Absorber 12.0 11.5 ft 0.91 $1,085,800 2013 $1,085,800 0.60 $1,026,955 1.40 $1,436,489 $1,483,080 $1,060,264 

D-302 1 Light Fraction Condenser Absorber 13.0 12.8 ft 0.96 $1,085,300 2013 $1,085,300 0.60 $1,061,899 1.33 $1,407,875 $1,453,539 $1,096,341 

H-313 1 D-301 Vapor ACHE 61,000,000 73,704,854 Btu/h 1.21 $578,900 2013 $578,900 0.60 $648,490 1.32 $854,385 $882,096 $669,523 

H-314 1 D-302 Feed Cooler 12,067,840 11,873,657 Btu/h 0.98 $172,000 2013 $172,000 0.70 $170,058 2.03 $344,862 $356,047 $175,574 

H-315 1 D-302 Feed/overhead exchanger 4,850,345 4,515,958 Btu/h 0.93 $758,400 2013 $758,400 0.70 $721,410 1.52 $1,097,050 $1,132,632 $744,809 

H-316 1 D-302 Liquid feed chiller 10,138,754 10,271,256 Btu/h 1.01 $132,400 2013 $132,400 0.70 $133,609 2.33 $311,519 $321,622 $137,942 

H-320 1 Heavy fraction ACHE 280,000 278,343 Btu/h 0.99 $33,300 2013 $33,300 0.60 $33,182 2.42 $80,413 $83,021 $34,258 

H-326 1 1 D-302 Quench circulation chiller 13,087,000 13,478,244 Btu/h 1.03 $78,300 2013 $156,600 0.70 $159,863 4.63 $740,922 $764,953 $165,048 

P-318 1 1 D-301 Bottoms pump 56.0 51 gpm 0.92 $5,800 2013 $11,600 0.80 $10,822 4.38 $47,395 $48,932 $11,173 

P-323 1 1 Circulation filter charge pump 41 43 hp 1.05 $25,400 2013 $50,800 0.80 $52,656 4.61 $242,963 $250,843 $54,364 

P-329 1 1 Aqueous filter charge pump 182.0 179 gpm 0.99 $7,500 2013 $15,000 0.80 $14,822 4.20 $62,254 $64,273 $15,303 

P-331 1 1 Organic product pump 124.0 121 gpm 0.97 $6,500 2013 $13,000 0.80 $12,708 4.63 $58,846 $60,754 $13,120 

P-332 1 1 Quench recycle pump 0.53 0.55 hp 1.04 $7,800 2013 $15,600 0.80 $16,125 4.88 $78,766 $81,321 $16,648 

S-319 1 1 D-301 Bottoms filter 52 47 gpm 0.91 $14,600 2013 $29,200 0.80 $27,138 1.84 $50,000 $51,622 $28,018 

S-322 1 D-302 Bottoms decanter 1,013,050 1,084,143 lb/h 1.07 $294,700 2013 $294,700 0.70 $309,029 1.82 $562,900 $581,158 $319,052 

S-324 2 1 Quench circulation filter 2,340.0 2,432 gpm 1.04 $83,100 2013 $249,300 0.80 $257,122 1.71 $439,676 $453,937 $265,462 

S-329 1 1 Aqueous phase filter 182.0 179 gpm 0.99 $26,500 2013 $53,000 0.80 $52,372 1.77 $92,689 $95,695 $54,071 

T-328 1 Organic product surge tank 1,000 967 ACFH 0.97 $48,000 2013 $48,000 0.70 $46,878 3.24 $151,962 $156,890 $48,398 

T-332 1 D-301 Circulation surge tank 1,000 1,561 ACFH 1.56 $48,000 2013 $48,000 0.70 $65,554 3.24 $212,504 $219,397 $67,680 

A310 1 Pinch exchanger CAPEX 2008 $1,411,745 $1,411,745 2.64 $3,720,465 $3,787,064 $1,437,016 

Area A310: Product Condensation and Separation ↑ $6,242,645 $6,232,437 1.92 $11,993,934 $12,328,877 $6,414,064

H-373 1 Post-WGS ACHE 5,160,000 11,767,420 Btu/h 2.28 $88,300 2013 $88,300 0.60 $144,804 1.71 $248,282 $256,335 $149,500 

H-374 1 Post-WGS cooler 2,929,000 3,038,996 Btu/h 1.04 $45,600 2013 $45,600 0.70 $46,792 4.05 $189,426 $195,570 $48,310 

K-390 1 PSA compressor: multistage 3,648 2,506 hp 0.69 $4,700,000 2014 $4,700,000 0.90 $3,352,616 1.60 $5,364,186 $5,474,479 $3,421,550 

M-385 1 PSA 5,218 5,462 lb/h 1.05 $975,000 2013 $975,000 0.60 $1,002,124 1.80 $1,803,823 $1,862,329 $1,034,627 

P-377 1 1 Compressor condensate pump 56.0 47 gpm 0.83 $5,800 2013 $11,600 0.80 $10,035 4.38 $43,946 $45,372 $10,360 

R-365 1 High-temperature WGS 354,424 77,912 lb/h 0.22 $1,243,000 2013 $1,243,000 0.60 $500,865 1.42 $709,512 $732,525 $517,110 

S-385 1 PSA Compressor suction KO 288,000 308,258 ACFH 1.07 $44,900 2013 $44,900 0.70 $47,088 2.00 $94,176 $97,231 $48,615 

S-386 1 PSA Compr disch KO 103,650 110,914 ACFH 1.07 $52,500 2013 $52,500 0.70 $55,049 2.56 $141,031 $145,605 $56,835 

T-377 1 Compressor condensate tank 1,000 375 ACFH 0.37 $48,000 2013 $48,000 0.70 $24,148 3.24 $78,279 $80,818 $24,931 

A360 1 Pinch exchanger CAPEX 2008 $436,413 $436,413 2.64 $1,150,109 $1,170,696 $444,225 

Area A360: Hydrogen Recycle and WGS ↑ $7,645,313 $5,619,934 1.75 $9,822,769 $10,060,958 $5,756,064
78

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Equip 

ID

Required

Spares

Equipment Name

Design Flow 

(per unit)

Design Flow 

(total)

Actual Flow 

(total)

Units

Size Ratio

Original 

Equip Cost

(per unit)

Base Year

Total Orig 

Equip Cost 

(Req+Spare)

in Base Year

Scaling Exp.

Scaled Cost 

in Base Year

Install Factor

Installed 

Cost 

in Base Year

Installed 

Cost 

in 2011$

Scaled 

Uninstalled 

Cost in 2011$

H-410 1 Feed-effluent exchanger 22,846,147 27,103,960 Btu/h 1.19 $542,500 2013 $542,500 0.70 $611,440 2.23 $1,360,946 $1,405,088 $631,271 

H-411 1 Feed furnace 2,210,000 2,515,037 Btu/h 1.14 $263,800 2013 $263,800 0.60 $285,080 1.31 $373,802 $385,926 $294,326 

H-413A 1 HT product ACHE 1,780,000 2,877,173 Btu/h 1.62 $44,800 2013 $44,800 0.60 $59,759 1.93 $115,517 $119,264 $61,698 

H-413C 1 HT product cooler 1,452,000 2,344,968 Btu/h 1.61 $63,900 2013 $63,900 0.70 $89,376 3.20 $286,031 $295,308 $92,275 

H-444 1 Quench hydrogen stage 2 cooler 215,000 311,172 Btu/h 1.45 $21,500 2013 $21,500 0.70 $27,850 7.10 $197,803 $204,218 $28,754 

H-445 1 Quench hydrogen stage 3 cooler 215,000 311,172 Btu/h 1.45 $21,500 2013 $21,500 0.70 $27,850 7.10 $197,803 $204,218 $28,754 

K-412 1 Hydrogen makeup compressor 1,051 2,367 hp 2.25 $1,890,000 2014 $1,890,000 0.64 $3,178,074 1.60 $5,084,919 $5,189,470 $3,243,419 

K-442 1 Hydrogen recycle compressor 146 236 hp 1.62 $1,200,000 2014 $1,200,000 0.90 $1,848,080 1.60 $2,956,928 $3,017,726 $1,886,079 

P-410 1 1 HT feed pump 135.0 121 gpm 0.89 $43,200 2013 $86,400 0.80 $78,903 3.58 $282,189 $291,341 $81,462 

R-410 1 Hydrotreater, 2000 psi 55,000 55,000 61,262 lb/h 1.11 $6,045,800 2013 $6,045,800 1.00 $6,734,094 1.43 $9,603,362 $9,914,841 $6,952,509 

S-410 1 Vapor KO drum 56,193 52,053 lb/h 0.93 $48,500 2013 $48,500 0.70 $45,970 3.45 $158,573 $163,716 $47,461 

S-411 1 HP HT effluent flash: 3 phase 8,028 19,791 ACFH 2.47 $373,800 2013 $373,800 0.70 $702,970 2.05 $1,443,551 $1,490,372 $725,770 

S-412 1 LP HT effluent flash: 3 phase 9,494 6,961 ACFH 0.73 $45,200 2013 $45,200 0.70 $36,373 4.99 $181,462 $187,348 $37,553 

A410 1 Pinch exchanger CAPEX 2008 $212,784 $212,784 2.64 $560,763 $570,801 $216,593 

Area A410: Whole Oil Hydroprocessing ↑ $10,317,984 $13,327,163 1.61 $21,442,703 $22,034,550 $13,696,651

D-450 1 Gasoline column 52,557 45,023 lb/h 0.86 $491,900 2013 $491,900 0.70 $441,410 1.69 $745,704 $769,890 $455,727 

D-451 1 Diesel column 23,368 20,678 lb/h 0.88 $297,900 2013 $297,900 0.70 $273,459 1.91 $521,398 $538,309 $282,328 

H-450C 1 D-450 Condenser (startup) 16,444,000 13,989,118 Btu/h 0.85 $34,700 2013 $34,700 0.70 $30,987 4.58 $141,897 $146,499 $31,992 

H-450R 1 D-450 Reboiler (startup) 6,951,000 6,554,290 Btu/h 0.94 $50,500 2013 $50,500 0.70 $48,465 2.83 $137,045 $141,490 $50,037 

H-451C 1 D-451 Condenser (startup) 3,050,000 3,161,779 Btu/h 1.04 $13,200 2013 $13,200 0.70 $13,537 6.66 $90,143 $93,067 $13,976 

H-451R 1 D-451 Reboiler (startup) 6,951,000 2,871,306 Btu/h 0.41 $50,500 2013 $50,500 0.70 $27,197 2.83 $76,904 $79,399 $28,079 

H-454 1 Gasoline product cooler 1,731,000 1,346,878 Btu/h 0.78 $22,400 2013 $22,400 0.70 $18,792 4.04 $75,923 $78,385 $19,401 

H-457A 1 Diesel product ACHE 170,000 0 Btu/h 0.00 $29,700 2013 $29,700 0.60 $0 2.34 $0 $0 $0 

H-457C 1 Diesel Product Cooler 316,000 359,610 Btu/h 1.14 $10,300 2013 $10,300 0.70 $11,276 5.63 $63,493 $65,553 $11,641 

H-459 1 D-450 Overhead vapor cooler 54,900 72,347 Btu/h 1.32 $7,900 2013 $7,900 0.70 $9,583 6.30 $60,412 $62,371 $9,894 

P-450 1 1 D-450 Reflux pump 7,190,000 13,989,118 Btu/h 1.95 $9,400 2013 $18,800 0.80 $32,019 4.31 $137,954 $142,428 $33,057 

P-451 1 1 D-451 Reflux pump 7,436,000 3,161,779 Btu/h 0.43 $7,400 2013 $14,800 0.80 $7,467 3.96 $29,565 $30,523 $7,709 

S-450 1 1 D-450 Overhead accumulator 7,190,000 13,989,118 Btu/h 1.95 $39,100 2013 $78,200 0.70 $124,609 4.01 $499,392 $515,590 $128,651 

S-451 1 1 D-451 Overhead accumulator 7,436,000 3,161,779 Btu/h 0.43 $28,600 2013 $57,200 0.70 $31,435 4.34 $136,291 $140,711 $32,454 

A450 1 Pinch exchanger CAPEX 2008 $448,752 $448,752 2.64 $1,182,626 $1,203,796 $456,785 

Area A450: Oil Fractionation ↑ $1,626,752 $1,518,986 2.57 $3,898,746 $4,008,011 $1,561,731

H-460 1 Feed-effluent exchanger 1,395,356 1,489,635 Btu/h 1.07 $134,600 2013 $134,600 0.70 $140,903 3.37 $475,156 $490,568 $145,473 

H-461 1 Feed furnace 680,000 447,147 Btu/h 0.66 $142,800 2013 $142,800 0.60 $111,043 1.52 $168,898 $174,376 $114,645 

H-463A 1 HC product ACHE 1,000,000 471,298 Btu/h 0.47 $38,000 2013 $38,000 0.60 $24,197 2.05 $49,667 $51,278 $24,982 

H-463C 1 HC product Cooler 845,500 395,651 Btu/h 0.47 $45,300 2013 $45,300 0.70 $26,622 3.23 $85,918 $88,705 $27,485 

H-494 1 Quench hydrogen stage 2 cooler 215,000 66,371 Btu/h 0.31 $21,500 2013 $21,500 0.70 $9,443 7.10 $67,068 $69,243 $9,749 

H-495 1 Quench hydrogen stage 3 cooler 215,000 66,371 Btu/h 0.31 $21,500 2013 $21,500 0.70 $9,443 7.10 $67,068 $69,243 $9,749 

K-462 1 Hydrogen makeup compressor 1,051 692 hp 0.66 $1,890,000 2014 $1,890,000 0.64 $1,446,333 1.60 $2,314,132 $2,361,713 $1,476,071 

K-492 1 Hydrogen recycle compressor 146 43 hp 0.29 $1,200,000 2014 $1,200,000 0.90 $399,269 1.60 $638,830 $651,965 $407,478 

P-460 1 1 HC feed pump 135.0 29 gpm 0.22 $43,200 2013 $86,400 0.80 $25,568 3.58 $91,442 $94,408 $26,398 

R-460 1 Hydrocracker 24,000 24,000 10,606 lb/h 0.44 $2,615,800 2013 $2,615,800 1.00 $1,155,933 1.97 $2,273,288 $2,347,021 $1,193,425 

S-460 1 Vapor KO drum 56,193 8,833 lb/h 0.16 $48,500 2013 $48,500 0.70 $13,281 3.45 $45,813 $47,299 $13,712 

S-461 1 HP effluent flash: 3 phase 8,257 3,224 ACFH 0.39 $223,900 2013 $223,900 0.70 $115,927 2.15 $249,303 $257,389 $119,687 

S-462 1 LP effluent flash 2,520 2,529 ACFH 1.00 $8,100 2013 $8,100 0.70 $8,121 8.99 $72,990 $75,358 $8,385 

A460 1 Pinch exchanger CAPEX 2008 $79,483 $79,483 2.64 $209,466 $213,215 $80,905 

Area A460: Hydrocracking ↑ $6,421,283 $3,424,663 1.85 $6,333,885 $6,501,214 $3,512,672

H-568A 1 WGS Effluent ACHE 5,740,000 12,089,601 Btu/h 2.11 $76,300 2013 $76,300 0.60 $119,296 1.63 $194,031 $200,325 $123,165 

H-568C 1 WGS Effluent cooler 3,159,000 3,083,763 Btu/h 0.98 $32,600 2013 $32,600 0.70 $32,055 3.60 $115,239 $118,977 $33,094 

K-511 1 Pyrolysis offgas compressor to reformer 3,648 3,186 hp 0.87 $4,700,000 2014 $4,700,000 0.60 $4,333,528 1.60 $6,933,645 $7,076,208 $4,422,630 

K-545 1 Reformer combustor air blower INCLUDED

K-580 1 PSA Compressor multistage INCLUDED

M-575 1 PSA INCLUDED

P-576 1 Compressor condensate pump 50.0 33 gpm 0.67 $5,800 2013 $5,800 0.80 $4,191 4.38 $18,352 $18,948 $4,327 

R-530 1 Steam reformer package (PNNL) 49,000,000 29,956,484 SCFD 0.61 $66,875,000 2007 $34,830,729 0.65 $25,296,134 1.92 $48,568,578 $54,142,779 $28,199,364 

R-565 1 WGS reactor INCLUDED

R-566 1 LTS reactor 354,424 103,323 lb/h 0.29 $1,243,000 2013 $1,243,000 0.60 $593,302 1.42 $840,456 $867,715 $612,546 

S-575 1 Compressor suction KO drum INCLUDED

S-586 1 PSA Compressor discharge KO drum INCLUDED

T-576 1 Compressor condensate tank 1,000 267 ACFH 0.27 $48,000 2013 $48,000 0.70 $19,054 3.24 $61,768 $63,771 $19,672 

A500 Pinch exchanger CAPEX 2008 $3,038,752 $3,038,752 2.64 $8,008,226 $8,151,578 $3,093,148 

Area A500: Hydrogen Plant ↑ $43,975,181 $33,436,312 1.94 $64,740,295 $70,640,300 $36,507,945
79

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Equip 

ID

Required

Spares

Equipment Name

Design Flow 

(per unit)

Design Flow 

(total)

Actual Flow 

(total)

Units

Size Ratio

Original 

Equip Cost

(per unit)

Base Year

Total Orig 

Equip Cost 

(Req+Spare)

in Base Year

Scaling Exp.

Scaled Cost 

in Base Year

Install Factor

Installed 

Cost 

in Base Year

Installed 

Cost 

in 2011$

Scaled 

Uninstalled 

Cost in 2011$

H-601 1 Steam turbine condenser 1.00 7.00 Btu/h 7.00 $1,300,000 2010 $1,300,000 1.00 $9,100,000 1.40 $12,740,000 $13,547,237 $9,676,598 

H-603 1 Blowdown cooler 381,671 421,230 Btu/h 1.10 $16,780 2007 $16,780 0.65 $17,891 4.32 $77,300 $86,171 $19,944 

M-601 1 BFW EDI+polishing 300,000 353,336 Btu/h 1.18 $1,325,000 2010 $1,325,000 0.60 $1,461,692 2.00 $2,923,384 $3,108,616 $1,554,308 

M-602A 1 Steam turbine generator Stage 1 -40,418 -17,228 hp 0.43 $7,700,000 2010 $7,700,000 0.70 $4,238,925 1.80 $7,630,066 $8,113,525 $4,507,514 

M-602B 1 Steam turbine generator Stage 2 -40,418 -47,530 hp 1.18 $7,700,000 2010 $7,700,000 0.70 $8,625,126 1.80 $15,525,228 $16,508,943 $9,171,635 

M-603 1 Startup boiler 204,131 204,131 lb/h 1.00 $275,500 2013 $275,500 0.60 $275,500 1.69 $466,519 $481,650 $284,436 

P-601 1 1 Makeup pump 80,411 7,064 lb/h 0.09 $6,528 2007 $13,056 0.30 $6,294 4.72 $29,697 $33,105 $7,017 

P-602 1 1 Condensate pump 247,010 353,336 lb/h 1.43 $9,810 2007 $19,620 0.30 $21,844 4.61 $100,649 $112,201 $24,352 

P-603 1 1 EDI pump 247,010 353,336 lb/h 1.43 $9,810 2007 $19,620 0.30 $21,844 4.61 $100,649 $112,201 $24,352 

P-604 1 1 Boiler feed water pump 494,622 353,336 lb/h 0.71 $304,578 2007 $609,156 0.30 $550,684 1.35 $744,906 $830,399 $613,886 

P-605 1 1 Condensate collection pump 247,010 353,336 lb/h 1.43 $9,810 2007 $19,620 0.30 $21,844 4.61 $100,649 $112,201 $24,352 

S-601 1 Blowdown flash drum 9,892 7,067 lb/h 0.71 $47,205 2007 $47,205 0.65 $37,934 3.41 $129,542 $144,410 $42,288 

T-601 1 Condensate collection tank 500,400 353,336 lb/h 0.71 $28,505 2007 $28,505 0.65 $22,735 6.83 $155,286 $173,108 $25,344 

T-602 1 Condensate surge tank 500,400 353,336 lb/h 0.71 $27,704 2007 $27,704 0.65 $22,096 6.51 $143,881 $160,394 $24,632 

T-603 1 Deaerator 494,619 353,336 lb/h 0.71 $53,299 2007 $53,299 0.65 $42,832 5.07 $217,056 $241,967 $47,747 

T-603A 1 Deaerator packed column 494,619 353,336 lb/h 0.71 $18,405 2007 $18,405 0.65 $14,790 5.18 $76,584 $85,374 $16,488 

T-605 1 Steam drum 494,622 353,338 lb/h 0.71 $104,100 2007 $104,100 0.65 $83,656 2.28 $190,536 $212,404 $93,257 

T-606 1 Steam turbine condensate tank 500,400 353,336 lb/h 0.71 28,505 2007 $28,505 0.65 $22,735 6.83 $155,286 $173,108 $25,344 

A600 Pinch exchanger CAPEX 2008 $3,061,423 $3,061,423 2.64 $8,067,973 $8,212,394 $3,116,225 

Area A600: Steam System & Power Generation ↑ $22,367,498 $27,649,848 1.79 $49,575,189 $52,449,407 $29,299,717

K-701 2 1 Plant air compressor 262,454 204,131 lb/h 0.78 $87,922 2007 $263,766 0.30 $244,611 1.57 $383,656 $427,688 $272,685 

M-701 1 Cooling tower system 7,506,000 2,581,093 lb/h 0.34 $260,852 2010 $260,852 0.78 $113,444 2.47 $280,207 $297,962 $120,632 

M-702 1 Hydraulic truck dump with scale 367,437 204,131 lb/h 0.56 $80,000 1998 $80,000 0.60 $56,225 2.47 $138,875 $208,829 $84,546 

M-703 1 Flue gas scrubber 489,600 890,764 lb/h 1.82 $436,250 2010 $436,250 0.65 $643,701 2.47 $1,589,942 $1,690,684 $684,488 

M-704 1 Flue gas stack 939,119 890,764 lb/h 0.95 $169,187 2007 $169,187 0.65 $163,472 1.30 $212,376 $236,750 $182,234 

M-708 1 Chilled water system 28,200,000 23,749,500 Btu/h 0.84 $637,500 2011 $637,500 0.60 $575,074 1.80 $1,035,132 $1,035,132 $575,074 

M-710 1 Product loading rack 1 1 $25,000 2011 $25,000 1.00 $25,000 2.47 $61,750 $61,750 $25,000 

P-701 1 1 Cooling water pump 7,001,377 2,581,093 lb/h 0.37 $239,375 2007 $478,750 0.30 $354,891 2.14 $759,522 $846,692 $395,622 

P-702 1 1 Firewater pump 262,454 204,131 lb/h 0.78 $23,043 2007 $46,086 0.30 $42,739 3.70 $158,025 $176,162 $47,644 

P-703 1 1 Diesel pump 262,454 204,131 lb/h 0.78 $3,842 2007 $7,684 0.30 $7,126 5.39 $38,393 $42,800 $7,944 

P-704 1 1 Ammonia pump 262,454 204,131 lb/h 0.78 $3,842 2007 $7,684 0.30 $7,126 5.21 $37,095 $41,353 $7,944 

P-705 1 1 Caustic pump 1 1 $4,906 2007 $9,812 0.30 $9,812 4.30 $42,200 $47,043 $10,938 

P-707 1 1 BFW chemical pump 262,454 204,131 lb/h 0.78 $3,842 2007 $7,684 0.30 $7,126 5.21 $37,095 $41,353 $7,944 

P-708 1 1 Flue gas scrubber circulation pump 489,600 890,764 lb/h 1.82 $12,510 2007 $25,020 0.30 $29,941 4.12 $123,258 $137,404 $33,377 

P-790 1 1 Gasoline product pump 108.0 84 gpm 0.78 $7,400 2013 $14,800 0.80 $12,077 3.96 $47,817 $49,368 $12,468 

P-792 1 1 Diesel product pump 108.0 33 gpm 0.31 $7,400 2013 $14,800 0.80 $5,797 3.96 $22,954 $23,699 $5,985 

S-701 1 1 Instrument air dryer 262,454 204,131 lb/h 0.78 $8,349 2002 $16,698 0.60 $14,361 2.47 $35,471 $52,516 $21,262 

T-701 1 Plant air receiver 262,454 204,131 lb/h 0.78 $21,005 2007 $21,005 0.65 $17,839 5.44 $97,074 $108,215 $19,887 

T-702 1 Firewater storage tank 262,454 204,131 lb/h 0.78 $229,900 2007 $229,900 0.65 $195,252 1.46 $285,447 $318,207 $217,661 

T-703 1 Purchased diesel storage tank 262,454 204,131 lb/h 0.78 $104,674 2007 $104,674 0.65 $88,899 1.35 $119,665 $133,399 $99,102 

T-704 1 Ammonia storage tank 262,454 204,131 lb/h 0.78 $15,704 2007 $15,704 0.65 $13,337 5.39 $71,850 $80,096 $14,868 

T-705 1 Caustic storage tank 262,454 204,131 lb/h 0.78 $16,005 2007 $16,005 0.65 $13,593 3.01 $40,936 $45,634 $15,153 

T-708 1 BFW chemical storage tank 262,454 204,131 lb/h 0.78 $22,004 2007 $22,004 0.65 $18,688 6.70 $125,186 $139,553 $20,833 

T-790 1 1 Gasoline product storage tanks 50 84 gpm 1.68 $442,700 2013 $885,400 0.70 $885,400 1.75 $1,553,400 $1,603,784 $914,117 

T-792 1 1 Diesel product storage tank 50 33 gpm 0.67 $442,700 2013 $885,400 0.70 $885,400 1.75 $1,553,400 $1,603,784 $914,117 

Area A700: Cooling Water & Other Utilities ↑ $4,681,665 $4,430,930 2.00 $8,850,727 $9,449,857 $4,711,524
80

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Equip 

ID

Required

Spares

Equipment Name

Design Flow 

(per unit)

Design Flow 

(total)

Actual Flow 

(total)

Units

Size Ratio

Original 

Equip Cost

(per unit)

Base Year

Total Orig 

Equip Cost 

(Req+Spare)

in Base Year

Scaling Exp.

Scaled Cost 

in Base Year

Install Factor

Installed 

Cost 

in Base Year

Installed 

Cost 

in 2011$

Scaled 

Uninstalled 

Cost in 2011$

H-840 1 RTO Feed/Effluent exchanger INCLUDED

K-831 1 RTO blower 900 2,222 hp 2.47 $360,420 2009 $360,420 0.60 $619,845 1.60 $991,752 $1,112,989 $695,618 

M-805 1 Clarifier 220 220 $96,221 2007 $96,221 0.65 $96,221 2.41 $232,300 $258,961 $107,264 

M-806 1 Belt press 1 1 $135,000 2010 $135,000 0.65 $135,000 2.47 $333,450 $354,578 $143,554 

M-807 1 Sand filter 265 265 $120,400 2010 $120,400 0.65 $120,400 2.47 $297,388 $316,231 $128,029 

M-833 1 Aqueous regenerative thermal oxidizer 18,500 38,359 SCFM 2.07 $1,850,000 2002 $1,850,000 0.60 $2,865,414 2.40 $6,876,994 $10,181,637 $4,242,349 

M-861 1 Reverse osmosis unit 197,000 66,679 lb/h 0.34 $350,000 2012 $350,000 0.70 $163,958 1.15 $188,552 $188,907 $164,267 

P-801 1 1 Clarifier overflow pump 50 53 gpm 1.06 $4,500 2013 $9,000 0.80 $9,394 4.38 $41,126 $42,460 $9,699 

P-809 1 1 Slurry pump 1 1 $3,242 2007 $3,242 0.80 $3,242 3.10 $10,050 $11,204 $3,614 

P-810 1 1 Boiler charge pump 200 179 gpm 0.90 $6,500 2013 $13,000 0.80 $11,912 4.14 $49,298 $50,897 $12,298 

P-812 1 1 Condensate Pump 140 127 gpm 0.91 $5,100 2013 $10,200 0.80 $9,422 4.59 $43,229 $44,631 $9,727 

P-814 1 1 Boiler charge pump 145 128 gpm 0.88 $5,100 2013 $10,200 0.80 $9,204 4.59 $42,231 $43,600 $9,503 

P-815 1 1 Boiler makeup pump 5 0 gpm 0.00 $14,700 2013 $29,400 0.80 $0 1.84 $0 $0 $0 

P-822 1 1 Concentrated waste water pump 7 14 gpm 2.05 $4,900 2013 $9,800 0.80 $17,375 4.31 $74,821 $77,248 $17,939 

P-860 1 1 RO Feed pump 185 160 gpm 0.87 $6,400 2013 $12,800 0.80 $11,402 3.84 $43,828 $45,250 $11,772 

P-866 1 1 Clean water pump 140 120 gpm 0.86 $5,200 2013 $5,200 0.80 $4,596 4.35 $19,977 $20,624 $4,745 

T-801 1 Clarifier overflow tank 1 1 1.00 $85,800 2013 $85,800 0.65 $85,800 2.27 $195,000 $201,325 $88,583 

T-809 1 Slurry tank 1 1 1.00 $85,800 2013 $85,800 0.65 $85,800 2.27 $195,000 $201,325 $88,583 

T-810 1 Boiler Feed Tank 200 179 gpm 0.90 $24,600 2013 $24,600 0.70 $22,789 4.49 $102,365 $105,685 $23,528 

T-812 1 Steam drum 100,800 96,797 ACFH 0.96 $24,400 2013 $24,400 0.70 $23,718 4.46 $105,854 $109,288 $24,487 

T-814 1 Boiler feed tank 145 128 gpm 0.88 $24,400 2013 $24,400 0.70 $22,302 4.46 $99,538 $102,766 $23,026 

T-822 1 Steam drum 156,000 140,136 ACFH 0.90 $19,400 2013 $19,400 0.70 $17,997 5.23 $94,066 $97,117 $18,581 

T-860 1 RO Feed tank 185 160 gpm 0.87 $76,000 2013 $76,000 0.70 $68,687 2.24 $153,643 $158,626 $70,915 

T-866 1 Clean water tank 140 120 gpm 0.86 $194,200 2013 $194,200 0.70 $194,200 2.23 $434,000 $448,077 $200,499 

A800 1 Pinch exchanger CAPEX 2008 $1,111,734 $1,111,734 2.64 $2,929,827 $2,982,272 $1,131,635 

Area A800: Water Management ↑ $4,661,217 $5,710,414 2.37 $13,554,287 $17,155,696 $7,230,214

Plant Total $144,452,905 $132,445,567 2.13 $282,758,716 $297,613,083 $140,029,476
81

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Appendix B-2. Individual Equipment Cost Summary

(Ex Situ Case)
82

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Equip ID

Required

SparesSwitch

Equipment Name

Design Flow 

(per unit)

Design Flow 

(total)

Actual Flow 

(total)

Units

Size Ratio

Original 

Equip Cost

(per unit)

Base Year

Total Orig 

Equip Cost 

(Req+Spare)

in Base Year

Scaling Exp.

Scaled Cost 

in Base Year

Install Factor

Installed 

Cost 

in Base Year

Installed 

Cost 

in 2011$

Scaled 

Uninstalled 

Cost in 2011$

C-101 Hopper Feeder INCLUDED

C-102 Screener Feeder Conveyor INCLUDED

C-103 Radial Stacker Conveyor INCLUDED

C-104 Dryer Feed Screw Conveyor INCLUDED

C-105 Biomass Feed Screw Conveyor INCLUDED

K-101 2 on Flue Gas Blower 204 408 383 hp 0.94 $59,300 2013 $118,600 0.78 $112,835 1.94 $218,439 $225,524 $116,495 

M-101 Hydraulic Truck Dump with Scale INCLUDED

M-102 Hammermill INCLUDED

M-103 Front End Loaders INCLUDED

M-104 2 ON Cross Flow Pellet Dryer 102,066 204,131 204,131 lb/h 1.00 $50,000 2011 $100,000 0.80 $100,000 2.00 $200,000 $200,000 $100,000 

S-101 Magnetic Head Pulley INCLUDED

S-102 Vibratory Conveyor INCLUDED

T-101 Dump Hopper INCLUDED

T-102 Hammermill surge bin INCLUDED

T-103 Dryer Feed Bin INCLUDED

T-104 Dried Biomass Hopper INCLUDED

T-105 Lock Hopper INCLUDED

T-106 Feed Hopper INCLUDED

A100 1 on Pinch Exchanger CAPEX 2008 $0 $0 2.64 $0 $0 $0 

Area A100: Feed Handling & Drying ↑ $218,600 $212,835 1.97 $418,440 $425,525 $216,495

C-212 2 FP Fines purge cooler INCLUDED

K-211 2 FP Fluidizing gas recycle compressor 3,648 7,296 2,887 hp 0.40 $4,700,000 2014 $9,400,000 0.90 $4,081,188 1.60 $6,529,901 $6,664,163 $4,165,102 

K-212 2 FP Combustor air compressor 10,000 20,000 13,584 hp 0.68 $2,600,000 2014 $5,200,000 0.78 $3,845,515 1.60 $6,152,824 $6,279,333 $3,924,583 

R-211 2 FP Fluidized Bed Reactor 1,222,474 2,444,948 2,433,724 ACFH 1.00 $3,449,500 2011 $6,899,000 0.50 $6,883,146 4.01 $27,601,417 $27,601,417 $6,883,146 

R-212 2 FP Char Combustor 719,240 1,438,480 1,429,542 ACFH 0.99 $3,483,784 2011 $6,967,568 0.50 $6,945,888 3.97 $27,569,756 $27,569,756 $6,945,888 

R-212C 2 FP Sand Cooler 3,671,901 7,343,802 7,323,460 Btu/h 1.00 $623,441 2011 $1,246,882 0.80 $1,244,118 3.00 $3,732,355 $3,732,355 $1,244,118 

S-211 2 FP Primary Cyclone INCLUDED

S-212 2 FP Secondary Cyclone INCLUDED

S-213 2 FP Char Combustor Primary Cyclone INCLUDED

S-214 2 FP Char Combustor Secondary Cyclone INCLUDED

T-211 2 FP Bed Media Bin INCLUDED

T-212 2 FP Depleted bed media and ash storage bin INCLUDED

T-217 2 FP Char combustor bed media feed bin INCLUDED

A211 1 FP Pinch Exchanger CAPEX 2008 $1,841,846 $1,841,846 2.64 $4,853,940 $4,940,828 $1,874,816 

Area A211: Ex Situ Fast Pyrolysis ↑ $31,555,296 $24,841,702 3.08 $76,440,192 $76,787,851 $25,037,654

C-262 1 VPU Fines purge cooler INCLUDED

K-262 1 VPU Regenerator air compressor 10,000 10,000 11,036 hp 1.10 $2,600,000 2014 $2,600,000 0.78 $2,807,856 1.60 $4,492,569 $4,584,941 $2,865,588 

R-261 1 VPU Catalytic Fluidized Bed Reactor 2,534,057 2,534,057 2,526,198 lb/h 1.00 $3,818,400 2011 $3,818,400 0.50 $3,812,474 3.97 $15,132,548 $15,132,548 $3,812,474 

R-262 1 VPU Catalyst Regenerator 1,084,318 1,084,318 1,088,654 ACFH 1.00 $4,207,313 2011 $4,207,313 0.50 $4,215,716 3.93 $16,561,186 $16,561,186 $4,215,716 

R-262C 1 VPU Catalyst Cooler 272,000,000 272,000,000 240,298,657 Btu/h 0.88 $3,968,900 2011 $3,968,900 0.80 $3,594,315 3.00 $10,782,944 $10,782,944 $3,594,315 

R-262C1 1 VPU Catalyst cooler (secondary, included) 147,367,743 Btu/h

S-261 1 VPU Primary Cyclone INCLUDED

S-262 1 VPU Secondary Cyclone INCLUDED

S-263 1 VPU Char Combustor Primary Cyclone INCLUDED

S-264 1 VPU Char Combustor Secondary Cyclone INCLUDED

T-261 1 VPU Catalyst steam stripper 2,756 2,756 2,756 lb/h 1.00 $347,005 2011 $347,005 0.30 $346,999 3.00 $1,040,997 $1,040,997 $346,999 

T-262 1 VPU Depleted catalyst and ash storage bin INCLUDED

T-267 1 VPU Catalyst feed bin INCLUDED

A261 1 VPU Pinch Exchanger CAPEX 2008 $764,272 $764,272 2.64 $2,014,136 $2,050,190 $777,953 

R-261 2 1 FBVPU VPU Fixed Bed Reactor 161,200 322,400 0 lb/h 0.00 $3,841,800 2013 $0 0.70 $0 1.21 $0 $0 $0 

A261 1 FBVPU Pinch Exchanger CAPEX 2008 $0 $0 2.64 $0 $0 $0 

Area A261: Ex Situ Vapor Phase Upgrading ↑ $15,705,890 $15,541,632 3.22 $50,024,382 $50,152,808 $15,613,046
83

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Equip 

ID

Required

Spares

Equipment Name

Design Flow 

(per unit)

Design Flow 

(total)

Actual Flow 

(total)

Units

Size Ratio

Original 

Equip Cost

(per unit)

Base Year

Total Orig 

Equip Cost 

(Req+Spare)

in Base Year

Scaling Exp.

Scaled Cost 

in Base Year

Install Factor

Installed 

Cost 

in Base Year

Installed 

Cost 

in 2011$

Scaled 

Uninstalled 

Cost in 2011$

D-301 1 Heavy Fraction Condenser Absorber 12.0 12.1 ft 1.02 $1,085,800 2013 $1,085,800 0.60 $1,096,648 1.40 $1,533,974 $1,583,728 $1,132,217 

D-302 1 Light Fraction Condenser Absorber 13.0 12.7 ft 0.95 $1,085,300 2013 $1,085,300 0.60 $1,051,451 1.33 $1,394,022 $1,439,236 $1,085,554 

H-313 1 D-301 Vapor ACHE 61,000,000 77,484,946 Btu/h 1.27 $578,900 2013 $578,900 0.60 $668,246 1.32 $880,413 $908,968 $689,920 

H-314 1 D-302 Feed Cooler 12,067,840 11,973,851 Btu/h 0.99 $172,000 2013 $172,000 0.70 $171,061 2.03 $346,896 $358,148 $176,609 

H-315 1 D-302 Feed/overhead exchanger 4,850,345 4,850,345 Btu/h 1.00 $758,400 2013 $758,400 0.70 $758,400 1.52 $1,153,300 $1,190,707 $782,998 

H-316 1 D-302 Liquid feed chiller 10,138,754 10,138,689 Btu/h 1.00 $132,400 2013 $132,400 0.70 $132,399 2.33 $308,699 $318,711 $136,694 

H-320 1 Heavy fraction ACHE 280,000 284,155 Btu/h 1.01 $33,300 2013 $33,300 0.60 $33,596 2.42 $81,416 $84,057 $34,685 

H-326 1 1 D-302 Quench circulation chiller 13,087,000 13,088,111 Btu/h 1.00 $78,300 2013 $156,600 0.70 $156,609 4.63 $725,843 $749,385 $161,689 

P-318 1 1 D-301 Bottoms pump 56.0 56 gpm 1.00 $5,800 2013 $11,600 0.80 $11,588 4.38 $50,748 $52,394 $11,964 

P-323 1 1 Circulation filter charge pump 41 41 hp 1.01 $25,400 2013 $50,800 0.80 $51,124 4.61 $235,896 $243,548 $52,782 

P-329 1 1 Aqueous filter charge pump 182.0 182 gpm 1.00 $7,500 2013 $15,000 0.80 $14,990 4.20 $62,956 $64,998 $15,476 

P-331 1 1 Organic product pump 124.0 122 gpm 0.98 $6,500 2013 $13,000 0.80 $12,831 4.63 $59,416 $61,343 $13,247 

P-332 1 1 Quench recycle pump 0.53 0.53 hp 1.01 $7,800 2013 $15,600 0.80 $15,716 4.88 $76,768 $79,257 $16,226 

S-319 1 1 D-301 Bottoms filter 52 52 gpm 0.99 $14,600 2013 $29,200 0.80 $29,056 1.84 $53,535 $55,271 $29,998 

S-322 1 D-302 Bottoms decanter 1,013,050 1,013,055 lb/h 1.00 $294,700 2013 $294,700 0.70 $294,701 1.82 $536,802 $554,213 $304,259 

S-324 2 1 Quench circulation filter 2,340.0 2,338 gpm 1.00 $83,100 2013 $249,300 0.80 $249,131 1.71 $426,010 $439,828 $257,211 

S-329 1 1 Aqueous phase filter 182.0 182 gpm 1.00 $26,500 2013 $53,000 0.80 $52,963 1.77 $93,735 $96,775 $54,681 

T-328 1 Organic product surge tank 1,000 978 ACFH 0.98 $48,000 2013 $48,000 0.70 $47,274 3.24 $153,248 $158,219 $48,808 

T-332 1 D-301 Circulation surge tank 1,000 1,500 ACFH 1.50 $48,000 2013 $48,000 0.70 $63,768 3.24 $206,715 $213,419 $65,836 

A310 1 Pinch exchanger CAPEX 2008 $1,447,138 $1,447,138 2.64 $3,813,738 $3,882,006 $1,473,042 

Area A310: Product Condensation and Separation ↑ $6,278,038 $6,358,689 1.92 $12,194,129 $12,534,210 $6,543,897

H-373 1 Post-WGS ACHE 5,160,000 9,374,326 Btu/h 1.82 $88,300 2013 $88,300 0.60 $126,338 1.71 $216,621 $223,647 $130,436 

H-374 1 Post-WGS cooler 2,929,000 3,641,754 Btu/h 1.24 $45,600 2013 $45,600 0.70 $53,110 4.05 $215,003 $221,977 $54,833 

K-390 1 PSA compressor: multistage 3,648 3,031 hp 0.83 $4,700,000 2014 $4,700,000 0.90 $3,978,374 1.60 $6,365,399 $6,496,278 $4,060,174 

M-385 1 PSA 5,218 7,032 lb/h 1.35 $975,000 2013 $975,000 0.60 $1,166,164 1.80 $2,099,096 $2,167,179 $1,203,988 

P-377 1 1 Compressor condensate pump 56.0 49 gpm 0.88 $5,800 2013 $11,600 0.80 $10,478 4.38 $45,887 $47,375 $10,818 

R-365 1 High-temperature WGS 354,424 82,376 lb/h 0.23 $1,243,000 2013 $1,243,000 0.60 $517,890 1.42 $733,628 $757,423 $534,687 

S-385 1 PSA Compressor suction KO 288,000 391,976 ACFH 1.36 $44,900 2013 $44,900 0.70 $55,713 2.00 $111,425 $115,039 $57,520 

S-386 1 PSA Compr disch KO 103,650 141,872 ACFH 1.37 $52,500 2013 $52,500 0.70 $65,402 2.56 $167,553 $172,987 $67,523 

T-377 1 Compressor condensate tank 1,000 396 ACFH 0.40 $48,000 2013 $48,000 0.70 $25,078 3.24 $81,295 $83,931 $25,891 

A360 1 Pinch exchanger CAPEX 2008 $522,045 $522,045 2.64 $1,375,780 $1,400,408 $531,390 

Area A360: Hydrogen Recycle and WGS ↑ $7,730,945 $6,520,592 1.75 $11,411,687 $11,686,244 $6,677,260

H-410 1 Feed-effluent exchanger 22,846,147 22,846,148 Btu/h 1.00 $542,500 2013 $542,500 0.70 $542,500 2.23 $1,207,500 $1,246,665 $560,096 

H-411 1 Feed furnace 2,210,000 2,209,486 Btu/h 1.00 $263,800 2013 $263,800 0.60 $263,763 1.31 $345,852 $357,069 $272,318 

H-413A 1 HT product ACHE 1,780,000 2,075,079 Btu/h 1.17 $44,800 2013 $44,800 0.60 $49,119 1.93 $94,948 $98,028 $50,712 

H-413C 1 HT product cooler 1,452,000 1,707,068 Btu/h 1.18 $63,900 2013 $63,900 0.70 $71,565 3.20 $229,030 $236,458 $73,886 

H-444 1 Quench hydrogen stage 2 cooler 215,000 214,948 Btu/h 1.00 $21,500 2013 $21,500 0.70 $21,496 7.10 $152,674 $157,626 $22,194 

H-445 1 Quench hydrogen stage 3 cooler 215,000 214,948 Btu/h 1.00 $21,500 2013 $21,500 0.70 $21,496 7.10 $152,674 $157,626 $22,194 

K-412 1 Hydrogen makeup compressor 1,051 1,191 hp 1.13 $1,890,000 2014 $1,890,000 0.64 $2,047,681 1.60 $3,276,290 $3,343,654 $2,089,784 

K-442 1 Hydrogen recycle compressor 146 180 hp 1.23 $1,200,000 2014 $1,200,000 0.90 $1,449,203 1.60 $2,318,724 $2,366,400 $1,479,000 

P-410 1 1 HT feed pump 135.0 122 gpm 0.90 $43,200 2013 $86,400 0.80 $79,667 3.58 $284,920 $294,161 $82,251 

R-410 1 Hydrotreater, 1500 psi 55,000 55,000 56,010 lb/h 1.02 $4,775,000 2013 $4,775,000 1.00 $4,862,715 1.53 $7,438,070 $7,679,319 $5,020,434 

S-410 1 Vapor KO drum 56,193 50,051 lb/h 0.89 $48,500 2013 $48,500 0.70 $44,725 3.45 $154,279 $159,283 $46,176 

S-411 1 HP HT effluent flash: 3 phase 8,028 14,710 ACFH 1.83 $373,800 2013 $373,800 0.70 $571,135 2.05 $1,172,828 $1,210,868 $589,659 

S-412 1 LP HT effluent flash: 3 phase 9,494 5,752 ACFH 0.61 $45,200 2013 $45,200 0.70 $31,825 4.99 $158,774 $163,924 $32,857 

A410 1 Pinch exchanger CAPEX 2008 $159,918 $159,918 2.64 $421,442 $428,987 $162,781 

Area A410: Whole Oil Hydroprocessing ↑ $8,994,318 $9,674,309 1.67 $16,200,506 $16,653,402 $9,944,245

D-450 1 Gasoline column 52,557 46,446 lb/h 0.88 $491,900 2013 $491,900 0.70 $451,124 1.69 $762,115 $786,833 $465,756 

D-451 1 Diesel column 23,368 41,393 lb/h 1.77 $297,900 2013 $297,900 0.70 $444,514 1.91 $847,545 $875,035 $458,931 

H-450C 1 D-450 Condenser (startup) 16,444,000 7,190,523 Btu/h 0.44 $34,700 2013 $34,700 0.70 $19,447 4.58 $89,054 $91,942 $20,078 

H-450R 1 D-450 Reboiler (startup) 6,951,000 5,072,974 Btu/h 0.73 $50,500 2013 $50,500 0.70 $40,508 2.83 $114,546 $118,261 $41,822 

H-451C 1 D-451 Condenser (startup) 3,050,000 7,436,530 Btu/h 2.44 $13,200 2013 $13,200 0.70 $24,633 6.66 $164,036 $169,356 $25,432 

H-451R 1 D-451 Reboiler (startup) 6,951,000 6,062,749 Btu/h 0.87 $50,500 2013 $50,500 0.70 $45,891 2.83 $129,767 $133,976 $47,379 

H-454 1 Gasoline product cooler 1,731,000 897,375 Btu/h 0.52 $22,400 2013 $22,400 0.70 $14,142 4.04 $57,138 $58,991 $14,601 

H-457A 1 Diesel product ACHE 170,000 0 Btu/h 0.00 $29,700 2013 $29,700 0.60 $0 2.34 $0 $0 $0 

H-457C 1 Diesel Product Cooler 316,000 738,813 Btu/h 2.34 $10,300 2013 $10,300 0.70 $18,665 5.63 $105,104 $108,513 $19,270 

H-459 1 D-450 Overhead vapor cooler 54,900 188,200 Btu/h 3.43 $7,900 2013 $7,900 0.70 $18,714 6.30 $117,968 $121,794 $19,321 

P-450 1 1 D-450 Reflux pump 7,190,000 7,190,523 Btu/h 1.00 $9,400 2013 $18,800 0.80 $18,801 4.31 $81,005 $83,632 $19,411 

P-451 1 1 D-451 Reflux pump 7,436,000 7,436,530 Btu/h 1.00 $7,400 2013 $14,800 0.80 $14,801 3.96 $58,603 $60,504 $15,281 

S-450 1 1 D-450 Overhead accumulator 7,190,000 7,190,523 Btu/h 1.00 $39,100 2013 $78,200 0.70 $78,204 4.01 $313,416 $323,581 $80,740 

S-451 1 1 D-451 Overhead accumulator 7,436,000 7,436,530 Btu/h 1.00 $28,600 2013 $57,200 0.70 $57,203 4.34 $248,012 $256,056 $59,058 

A450 1 Pinch exchanger CAPEX 2008 $482,593 $482,593 2.64 $1,271,810 $1,294,576 $491,232 

Area A450: Oil Fractionation ↑ $1,660,593 $1,729,240 2.52 $4,360,117 $4,483,051 $1,778,313
84

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Equip 

ID

Required

Spares

Equipment Name

Design Flow 

(per unit)

Design Flow 

(total)

Actual Flow 

(total)

Units

Size Ratio

Original 

Equip Cost

(per unit)

Base Year

Total Orig 

Equip Cost 

(Req+Spare)

in Base Year

Scaling Exp.

Scaled Cost 

in Base Year

Install Factor

Installed 

Cost 

in Base Year

Installed 

Cost 

in 2011$

Scaled 

Uninstalled 

Cost in 2011$

H-460 1 Feed-effluent exchanger 1,395,356 1,395,356 Btu/h 1.00 $134,600 2013 $134,600 0.70 $134,600 3.37 $453,900 $468,622 $138,966 

H-461 1 Feed furnace 680,000 678,232 Btu/h 1.00 $142,800 2013 $142,800 0.60 $142,577 1.52 $216,861 $223,895 $147,202 

H-463A 1 HC product ACHE 1,000,000 573,607 Btu/h 0.57 $38,000 2013 $38,000 0.60 $27,224 2.05 $55,881 $57,693 $28,107 

H-463C 1 HC product Cooler 845,500 477,916 Btu/h 0.57 $45,300 2013 $45,300 0.70 $30,385 3.23 $98,065 $101,246 $31,371 

H-494 1 Quench hydrogen stage 2 cooler 215,000 57,559 Btu/h 0.27 $21,500 2013 $21,500 0.70 $8,547 7.10 $60,703 $62,672 $8,824 

H-495 1 Quench hydrogen stage 3 cooler 215,000 57,559 Btu/h 0.27 $21,500 2013 $21,500 0.70 $8,547 7.10 $60,703 $62,672 $8,824 

K-462 1 Hydrogen makeup compressor 1,051 495 hp 0.47 $1,890,000 2014 $1,890,000 0.64 $1,166,697 1.60 $1,866,716 $1,905,098 $1,190,686 

K-492 1 Hydrogen recycle compressor 146 42 hp 0.29 $1,200,000 2014 $1,200,000 0.90 $391,259 1.60 $626,014 $638,886 $399,304 

P-460 1 1 HC feed pump 135.0 56 gpm 0.42 $43,200 2013 $86,400 0.80 $42,912 3.58 $153,471 $158,449 $44,304 

R-460 1 Hydrocracker 24,000 24,000 18,293 lb/h 0.76 $2,615,800 2013 $2,615,800 1.00 $1,993,762 1.97 $3,920,984 $4,048,158 $2,058,428 

S-460 1 Vapor KO drum 56,193 16,654 lb/h 0.30 $48,500 2013 $48,500 0.70 $20,703 3.45 $71,414 $73,731 $21,374 

S-461 1 HP effluent flash: 3 phase 8,257 3,011 ACFH 0.36 $223,900 2013 $223,900 0.70 $110,515 2.15 $237,664 $245,372 $114,099 

S-462 1 LP effluent flash 2,520 2,851 ACFH 1.13 $8,100 2013 $8,100 0.70 $8,831 8.99 $79,366 $81,941 $9,117 

A460 1 Pinch exchanger CAPEX 2008 $115,488 $115,488 2.64 $304,354 $309,802 $117,555 

Area A460: Hydrocracking ↑ $6,457,288 $4,067,448 1.91 $7,752,196 $7,969,614 $4,179,196

H-568A 1 WGS Effluent ACHE 5,740,000 8,349,471 Btu/h 1.45 $76,300 2013 $76,300 0.60 $95,537 1.63 $155,389 $160,429 $98,636 

H-568C 1 WGS Effluent cooler 3,159,000 3,275,594 Btu/h 1.04 $32,600 2013 $32,600 0.70 $33,438 3.60 $120,211 $124,110 $34,522 

K-511 1 Pyrolysis offgas compressor to reformer 3,648 2,915 hp 0.80 $4,700,000 2014 $4,700,000 0.60 $4,108,302 1.60 $6,573,282 $6,708,436 $4,192,773 

K-545 1 Reformer combustor air blower INCLUDED

K-580 1 PSA Compressor multistage INCLUDED

M-575 1 PSA INCLUDED

P-576 1 Compressor condensate pump 50.0 38 gpm 0.75 $5,800 2013 $5,800 0.80 $4,619 4.38 $20,227 $20,883 $4,769 

R-530 1 Steam reformer package (PNNL) 49,000,000 27,420,513 SCFD 0.56 $66,875,000 2007 $34,830,729 0.65 $23,882,745 1.92 $45,854,870 $51,117,619 $26,623,760 

R-565 1 WGS reactor INCLUDED

R-566 1 LTS reactor 354,424 102,802 lb/h 0.29 $1,243,000 2013 $1,243,000 0.60 $591,504 1.42 $837,908 $865,085 $610,689 

S-575 1 Compressor suction KO drum INCLUDED

S-586 1 PSA Compressor discharge KO drum INCLUDED

T-576 1 Compressor condensate tank 1,000 302 ACFH 0.30 $48,000 2013 $48,000 0.70 $20,747 3.24 $67,255 $69,436 $21,420 

A500 Pinch exchanger CAPEX 2008 $2,868,877 $2,868,877 2.64 $7,560,543 $7,695,881 $2,920,232 

Area A500: Hydrogen Plant ↑ $43,805,306 $31,605,768 1.94 $61,189,686 $66,761,881 $34,506,800

H-601 1 Steam turbine condenser 1.00 6.00 Btu/h 6.00 $1,300,000 2010 $1,300,000 1.00 $7,800,000 1.40 $10,920,000 $11,611,917 $8,294,227 

H-603 1 Blowdown cooler 381,671 385,956 Btu/h 1.01 $16,780 2007 $16,780 0.65 $16,902 4.32 $73,028 $81,409 $18,842 

M-601 1 BFW EDI+polishing 300,000 323,747 Btu/h 1.08 $1,325,000 2010 $1,325,000 0.60 $1,386,968 2.00 $2,773,937 $2,949,700 $1,474,850 

M-602A 1 Steam turbine generator Stage 1 -40,418 -15,786 hp 0.39 $7,700,000 2010 $7,700,000 0.70 $3,987,202 1.80 $7,176,964 $7,631,713 $4,239,841 

M-602B 1 Steam turbine generator Stage 2 -40,418 -43,550 hp 1.08 $7,700,000 2010 $7,700,000 0.70 $8,112,934 1.80 $14,603,282 $15,528,581 $8,626,989 

M-603 1 Startup boiler 204,131 204,131 lb/h 1.00 $275,500 2013 $275,500 0.60 $275,500 1.69 $466,519 $481,650 $284,436 

P-601 1 1 Makeup pump 80,411 6,473 lb/h 0.08 $6,528 2007 $13,056 0.30 $6,131 4.72 $28,928 $32,248 $6,835 

P-602 1 1 Condensate pump 247,010 323,747 lb/h 1.31 $9,810 2007 $19,620 0.30 $21,279 4.61 $98,043 $109,295 $23,721 

P-603 1 1 EDI pump 247,010 323,747 lb/h 1.31 $9,810 2007 $19,620 0.30 $21,279 4.61 $98,043 $109,295 $23,721 

P-604 1 1 Boiler feed water pump 494,622 323,747 lb/h 0.65 $304,578 2007 $609,156 0.30 $536,424 1.35 $725,616 $808,895 $597,989 

P-605 1 1 Condensate collection pump 247,010 323,747 lb/h 1.31 $9,810 2007 $19,620 0.30 $21,279 4.61 $98,043 $109,295 $23,721 

S-601 1 Blowdown flash drum 9,892 6,475 lb/h 0.65 $47,205 2007 $47,205 0.65 $35,838 3.41 $122,384 $136,429 $39,951 

T-601 1 Condensate collection tank 500,400 323,747 lb/h 0.65 $28,505 2007 $28,505 0.65 $21,478 6.83 $146,704 $163,542 $23,943 

T-602 1 Condensate surge tank 500,400 323,747 lb/h 0.65 $27,704 2007 $27,704 0.65 $20,875 6.51 $135,930 $151,530 $23,270 

T-603 1 Deaerator 494,619 323,747 lb/h 0.65 $53,299 2007 $53,299 0.65 $40,465 5.07 $205,061 $228,595 $45,109 

T-603A 1 Deaerator packed column 494,619 323,747 lb/h 0.65 $18,405 2007 $18,405 0.65 $13,973 5.18 $72,352 $80,656 $15,577 

T-605 1 Steam drum 494,622 323,749 lb/h 0.65 $104,100 2007 $104,100 0.65 $79,033 2.28 $180,007 $200,666 $88,104 

T-606 1 Steam turbine condensate tank 500,400 323,747 lb/h 0.65 28,505 2007 $28,505 0.65 $21,478 6.83 $146,704 $163,542 $23,943 

A600 Pinch exchanger CAPEX 2008 $2,727,447 $2,727,447 2.64 $7,187,822 $7,316,488 $2,776,270 

Area A600: Steam System & Power Generation ↑ $22,033,522 $25,146,486 1.80 $45,259,365 $47,895,448 $26,651,339
85

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Equip 

ID

Required

Spares

Equipment Name

Design Flow 

(per unit)

Design Flow 

(total)

Actual Flow 

(total)

Units

Size Ratio

Original 

Equip Cost

(per unit)

Base Year

Total Orig 

Equip Cost 

(Req+Spare)

in Base YearScaling Exp.

Scaled Cost 

in Base Year

Install Factor

Installed 

Cost 

in Base Year

Installed 

Cost 

in 2011$

Scaled 

Uninstalled 

Cost in 2011$

K-701 2 1 Plant air compressor 262,454 204,131 lb/h 0.78 $87,922 2007 $263,766 0.30 $244,611 1.57 $383,656 $427,688 $272,685 

M-701 1 Cooling tower system 7,506,000 2,618,485 lb/h 0.35 $260,852 2010 $260,852 0.78 $114,724 2.47 $283,368 $301,323 $121,993 

M-702 1 Hydraulic truck dump with scale 367,437 204,131 lb/h 0.56 $80,000 1998 $80,000 0.60 $56,225 2.47 $138,875 $208,829 $84,546 

M-703 1 Flue gas scrubber 489,600 777,008 lb/h 1.59 $436,250 2010 $436,250 0.65 $589,000 2.47 $1,454,829 $1,547,010 $626,320 

M-704 1 Flue gas stack 939,119 777,008 lb/h 0.83 $169,187 2007 $169,187 0.65 $149,581 1.30 $194,328 $216,631 $166,748 

M-708 1 Chilled water system 28,200,000 23,226,800 Btu/h 0.82 $637,500 2011 $637,500 0.60 $567,446 1.80 $1,021,402 $1,021,402 $567,446 

M-710 1 Product loading rack 1 1 $25,000 2011 $25,000 1.00 $25,000 2.47 $61,750 $61,750 $25,000 

P-701 1 1 Cooling water pump 7,001,377 2,618,485 lb/h 0.37 $239,375 2007 $478,750 0.30 $356,426 2.14 $762,806 $850,354 $397,332 

P-702 1 1 Firewater pump 262,454 204,131 lb/h 0.78 $23,043 2007 $46,086 0.30 $42,739 3.70 $158,025 $176,162 $47,644 

P-703 1 1 Diesel pump 262,454 204,131 lb/h 0.78 $3,842 2007 $7,684 0.30 $7,126 5.39 $38,393 $42,800 $7,944 

P-704 1 1 Ammonia pump 262,454 204,131 lb/h 0.78 $3,842 2007 $7,684 0.30 $7,126 5.21 $37,095 $41,353 $7,944 

P-705 1 1 Caustic pump 1 1 $4,906 2007 $9,812 0.30 $9,812 4.30 $42,200 $47,043 $10,938 

P-707 1 1 BFW chemical pump 262,454 204,131 lb/h 0.78 $3,842 2007 $7,684 0.30 $7,126 5.21 $37,095 $41,353 $7,944 

P-708 1 1 Flue gas scrubber circulation pump 489,600 777,008 lb/h 1.59 $12,510 2007 $25,020 0.30 $28,738 4.12 $118,308 $131,886 $32,037 

P-790 1 1 Gasoline product pump 108.0 54 gpm 0.50 $7,400 2013 $14,800 0.80 $8,463 3.96 $33,508 $34,595 $8,737 

P-792 1 1 Diesel product pump 108.0 69 gpm 0.63 $7,400 2013 $14,800 0.80 $10,287 3.96 $40,730 $42,051 $10,620 

S-701 1 1 Instrument air dryer 262,454 204,131 lb/h 0.78 $8,349 2002 $16,698 0.60 $14,361 2.47 $35,471 $52,516 $21,262 

T-701 1 Plant air receiver 262,454 204,131 lb/h 0.78 $21,005 2007 $21,005 0.65 $17,839 5.44 $97,074 $108,215 $19,887 

T-702 1 Firewater storage tank 262,454 204,131 lb/h 0.78 $229,900 2007 $229,900 0.65 $195,252 1.46 $285,447 $318,207 $217,661 

T-703 1 Purchased diesel storage tank 262,454 204,131 lb/h 0.78 $104,674 2007 $104,674 0.65 $88,899 1.35 $119,665 $133,399 $99,102 

T-704 1 Ammonia storage tank 262,454 204,131 lb/h 0.78 $15,704 2007 $15,704 0.65 $13,337 5.39 $71,850 $80,096 $14,868 

T-705 1 Caustic storage tank 262,454 204,131 lb/h 0.78 $16,005 2007 $16,005 0.65 $13,593 3.01 $40,936 $45,634 $15,153 

T-708 1 BFW chemical storage tank 262,454 204,131 lb/h 0.78 $22,004 2007 $22,004 0.65 $18,688 6.70 $125,186 $139,553 $20,833 

T-790 1 1 Gasoline product storage tanks 50 54 gpm 1.07 $442,700 2013 $885,400 0.70 $885,400 1.75 $1,553,400 $1,603,784 $914,117 

T-792 1 1 Diesel product storage tank 50 69 gpm 1.37 $442,700 2013 $885,400 0.70 $885,400 1.75 $1,553,400 $1,603,784 $914,117 

Area A700: Cooling Water & Other Utilities ↑ $4,681,665 $4,357,197 1.99 $8,688,798 $9,277,418 $4,632,878

H-840 1 RTO Feed/Effluent exchanger INCLUDED

K-831 1 RTO blower 900 1,032 hp 1.15 $360,420 2009 $360,420 0.60 $391,180 1.60 $625,888 $702,400 $439,000 

M-805 1 Clarifier 220 220 $96,221 2007 $96,221 0.65 $96,221 2.41 $232,300 $258,961 $107,264 

M-806 1 Belt press 1 1 $135,000 2010 $135,000 0.65 $135,000 2.47 $333,450 $354,578 $143,554 

M-807 1 Sand filter 265 265 $120,400 2010 $120,400 0.65 $120,400 2.47 $297,388 $316,231 $128,029 

M-833 1 Aqueous regenerative thermal oxidizer 18,500 17,765 SCFM 0.96 $1,850,000 2002 $1,850,000 0.60 $1,805,560 2.40 $4,333,344 $6,415,672 $2,673,197 

M-861 1 Reverse osmosis unit 197,000 70,810 lb/h 0.36 $350,000 2012 $350,000 0.70 $171,005 1.15 $196,655 $197,025 $171,326 

P-801 1 1 Clarifier overflow pump 50 51 gpm 1.01 $4,500 2013 $9,000 0.80 $9,078 4.38 $39,742 $41,031 $9,373 

P-809 1 1 Slurry pump 1 1 $3,242 2007 $3,242 0.80 $3,242 3.10 $10,050 $11,204 $3,614 

P-810 1 1 Boiler charge pump 200 182 gpm 0.91 $6,500 2013 $13,000 0.80 $12,047 4.14 $49,854 $51,471 $12,437 

P-812 1 1 Condensate Pump 140 126 gpm 0.90 $5,100 2013 $10,200 0.80 $9,392 4.59 $43,094 $44,491 $9,697 

P-814 1 1 Boiler charge pump 145 132 gpm 0.91 $5,100 2013 $10,200 0.80 $9,434 4.59 $43,287 $44,691 $9,740 

P-815 1 1 Boiler makeup pump 5 5 gpm 0.90 $14,700 2013 $29,400 0.80 $27,048 1.84 $49,863 $51,481 $27,925 

P-822 1 1 Concentrated waste water pump 7 6 gpm 0.90 $4,900 2013 $9,800 0.80 $9,001 4.31 $38,759 $40,016 $9,293 

P-860 1 1 RO Feed pump 185 170 gpm 0.92 $6,400 2013 $12,800 0.80 $11,949 3.84 $45,931 $47,420 $12,337 

P-866 1 1 Clean water pump 140 127 gpm 0.91 $5,200 2013 $5,200 0.80 $4,820 4.35 $20,949 $21,629 $4,977 

T-801 1 Clarifier overflow tank 1 1 1.00 $85,800 2013 $85,800 0.65 $85,800 2.27 $195,000 $201,325 $88,583 

T-809 1 Slurry tank 1 1 1.00 $85,800 2013 $85,800 0.65 $85,800 2.27 $195,000 $201,325 $88,583 

T-810 1 Boiler Feed Tank 200 182 gpm 0.91 $24,600 2013 $24,600 0.70 $23,014 4.49 $103,375 $106,728 $23,760 

T-812 1 Steam drum 100,800 100,789 ACFH 1.00 $24,400 2013 $24,400 0.70 $24,398 4.46 $108,891 $112,423 $25,189 

T-814 1 Boiler feed tank 145 132 gpm 0.91 $24,400 2013 $24,400 0.70 $22,789 4.46 $101,712 $105,011 $23,529 

T-822 1 Steam drum 156,000 156,173 ACFH 1.00 $19,400 2013 $19,400 0.70 $19,415 5.23 $101,478 $104,770 $20,045 

T-860 1 RO Feed tank 185 170 gpm 0.92 $76,000 2013 $76,000 0.70 $71,562 2.24 $160,074 $165,265 $73,883 

T-866 1 Clean water tank 140 127 gpm 0.91 $194,200 2013 $194,200 0.70 $194,200 2.23 $434,000 $448,077 $200,499 

A800 1 Pinch exchanger CAPEX 2008 $1,070,377 $1,070,377 2.64 $2,820,835 $2,871,329 $1,089,537 

Area A800: Water Management ↑ $4,619,860 $4,412,732 2.40 $10,580,920 $12,914,554 $5,395,370

Plant Total $153,741,320 $134,468,631 2.26 $304,520,418 $317,542,004 $141,176,492
86

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Appendix C-1. Discounted Cash Flow Rate of Return 

and Operating Cost Summary (In Situ Case)
87

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications. Year

 

-2 -1 0 1 2 3 4 5 6 7 8 9 10

Fixed Capital Investment $18,248,867 $124,791,506 $66,555,470

Working Capital $25,998,230

Loan Payment $46,494,036 $46,494,036 $46,494,036 $46,494,036 $46,494,036 $46,494,036 $46,494,036 $46,494,036 $46,494,036 $46,494,036

 Loan Interest Payment $1,996,664 $16,971,645 $24,958,301 $24,958,301 $23,235,442 $21,374,755 $19,365,212 $17,194,907 $14,850,976 $12,319,532 $9,585,571 $6,632,894 $3,444,003

 Loan Principal $24,958,301 $212,145,560 $311,978,765 $290,443,030 $267,184,437 $242,065,156 $214,936,332 $185,637,203 $153,994,144 $119,819,640 $82,911,175 $43,050,033 $0

Fuel Product Sales $140,774,123 $187,698,830 $187,698,830 $187,698,830 $187,698,830 $187,698,830 $187,698,830 $187,698,830 $187,698,830 $187,698,830

 Byproduct Credit $1,770,680 $2,360,907 $2,360,907 $2,360,907 $2,360,907 $2,360,907 $2,360,907 $2,360,907 $2,360,907 $2,360,907

Total Annual Sales $142,544,803 $190,059,737 $190,059,737 $190,059,737 $190,059,737 $190,059,737 $190,059,737 $190,059,737 $190,059,737 $190,059,737

Annual Manufacturing Cost

Raw Materials $50,695,237 $57,937,413 $57,937,413 $57,937,413 $57,937,413 $57,937,413 $57,937,413 $57,937,413 $57,937,413 $57,937,413

Catalyst Costs $0 $0 $0 $7,433,882 $298,198 $5,185,172 $298,198 $5,185,172 $298,198 $5,185,172 $298,198 $5,185,172 $298,198

 Other Variable Costs $24,612,001 $28,128,001 $28,128,001 $28,128,001 $28,128,001 $28,128,001 $28,128,001 $28,128,001 $28,128,001 $28,128,001

 Fixed Operating Costs $25,406,303 $25,406,303 $25,406,303 $25,406,303 $25,406,303 $25,406,303 $25,406,303 $25,406,303 $25,406,303 $25,406,303

Total Product Cost $108,147,424 $111,769,916 $116,656,890 $111,769,916 $116,656,890 $111,769,916 $116,656,890 $111,769,916 $116,656,890 $111,769,916

Annual Depreciation

General Plant % Depreciation 14.3% 24.5% 17.5% 12.5% 8.9% 8.9% 8.9% 4.5%

General Plant Depreciation $58,755,822 $100,694,896 $71,913,178 $51,354,808 $36,717,249 $36,676,132 $36,717,249 $18,338,066

General Plant Remaining $352,411,579 $251,716,683 $179,803,504 $128,448,696 $91,731,447 $55,055,315 $18,338,066 $0

Steam Plant % Depreciation 3.75% 7.22% 6.68% 6.18% 5.71% 5.29% 4.89% 4.52% 4.46% 4.46%

Steam Plant Depreciation $4,079,895 $7,854,070 $7,264,390 $6,720,403 $6,215,584 $5,749,932 $5,318,007 $4,919,810 $4,854,531 $4,853,443

Steam Plant Remaining $104,717,312 $96,863,241 $89,598,852 $82,878,448 $76,662,864 $70,912,932 $65,594,924 $60,675,114 $55,820,583 $50,967,140

Total Depreciation $62,835,717 $108,548,967 $79,177,568 $58,075,212 $42,932,833 $42,426,065 $42,035,256 $23,257,876 $4,854,531 $4,853,443

Net Revenue -$53,396,639 -$53,494,588 -$27,149,476 $849,397 $13,275,107 $21,012,780 $19,048,059 $45,446,374 $61,915,422 $69,992,375

Losses Forward -$53,396,639 -$106,891,227 -$134,040,703 -$133,191,306 -$119,916,198 -$98,903,418 -$79,855,358 -$34,408,984 $0

Taxable Income -$53,396,639 -$106,891,227 -$134,040,703 -$133,191,306 -$119,916,198 -$98,903,418 -$79,855,358 -$34,408,984 $27,506,438 $69,992,375

Income Tax $0 $0 $0 $0 $0 $0 $0 $0 $9,627,253 $24,497,331

Annual Cash Income -$12,096,657 $31,795,785 $26,908,811 $31,795,785 $26,908,811 $31,795,785 $26,908,811 $31,795,785 $17,281,558 $7,298,454

Discount Factor 1.210 1.100 1.000 0.909 0.826 0.751 0.683 0.621 0.564 0.513 0.467 0.424 0.386

Annual Present Value $296,366,372 -$10,996,961 $26,277,509 $20,216,988 $21,716,949 $16,708,255 $17,947,892 $13,808,475 $14,832,969 $7,329,068 $2,813,870

Total Capital Investment + Interest $24,497,093 $155,939,466 $117,512,001

Net Present Worth $0

Year 11 12 13 14 15 16 17 18 19 20

Fixed Capital InvestmentWorking CapitalLoan Payment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

 Loan Interest Payment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

 Loan Principal $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

Fuel Product Sales $187,698,830 $187,698,830 $187,698,830 $187,698,830 $187,698,830 $187,698,830 $187,698,830 $187,698,830 $187,698,830 $187,698,830

 Byproduct Credit $2,360,907 $2,360,907 $2,360,907 $2,360,907 $2,360,907 $2,360,907 $2,360,907 $2,360,907 $2,360,907 $2,360,907

Total Annual Sales $190,059,737 $190,059,737 $190,059,737 $190,059,737 $190,059,737 $190,059,737 $190,059,737 $190,059,737 $190,059,737 $190,059,737

Annual Manufacturing Cost

Raw Materials $57,937,413 $57,937,413 $57,937,413 $57,937,413 $57,937,413 $57,937,413 $57,937,413 $57,937,413 $57,937,413 $57,937,413

Catalyst Costs $5,185,172 $298,198 $5,185,172 $298,198 $5,185,172 $298,198 $5,185,172 $298,198 $5,185,172 $298,198

 Other Variable Costs $28,128,001 $28,128,001 $28,128,001 $28,128,001 $28,128,001 $28,128,001 $28,128,001 $28,128,001 $28,128,001 $28,128,001

 Fixed Operating Costs $25,406,303 $25,406,303 $25,406,303 $25,406,303 $25,406,303 $25,406,303 $25,406,303 $25,406,303 $25,406,303 $25,406,303

Total Product Cost $116,656,890 $111,769,916 $116,656,890 $111,769,916 $116,656,890 $111,769,916 $116,656,890 $111,769,916 $116,656,890 $111,769,916

Annual Depreciation

General Plant % Depreciation

General Plant DepreciationGeneral Plant RemainingSteam Plant % Depreciation 4.46% 4.46% 4.46% 4.46% 4.46% 4.46% 4.46% 4.46% 4.46% 4.46%

Steam Plant Depreciation $4,854,531 $4,853,443 $4,854,531 $4,853,443 $4,854,531 $4,853,443 $4,854,531 $4,853,443 $4,854,531 $4,853,443

Steam Plant Remaining $46,112,608 $41,259,165 $36,404,633 $31,551,190 $26,696,659 $21,843,215 $16,988,684 $12,135,240 $7,280,709 $2,427,266

Total Depreciation $4,854,531 $4,853,443 $4,854,531 $4,853,443 $4,854,531 $4,853,443 $4,854,531 $4,853,443 $4,854,531 $4,853,443

Net Revenue $68,548,316 $73,436,378 $68,548,316 $73,436,378 $68,548,316 $73,436,378 $68,548,316 $73,436,378 $68,548,316 $73,436,378

Losses Forward $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

Taxable Income $68,548,316 $73,436,378 $68,548,316 $73,436,378 $68,548,316 $73,436,378 $68,548,316 $73,436,378 $68,548,316 $73,436,378

Income Tax $23,991,911 $25,702,732 $23,991,911 $25,702,732 $23,991,911 $25,702,732 $23,991,911 $25,702,732 $23,991,911 $25,702,732

Annual Cash Income $49,410,937 $52,587,089 $49,410,937 $52,587,089 $49,410,937 $52,587,089 $49,410,937 $52,587,089 $49,410,937 $52,587,089

Discount Factor 0.350 0.319 0.290 0.263 0.239 0.218 0.198 0.180 0.164 0.149

Annual Present Value $17,318,232 $16,755,867 $14,312,588 $13,847,824 $11,828,585 $11,444,483 $9,775,690 $9,458,250 $8,079,083 $7,816,736

Total Capital Investment + InterestNet Present Worth
88

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications. DCFROR Worksheet Year 21 22 23 24 25 26 27 28 29 30 Fixed Capital Investment Working Capital -$27,608,230 Loan Payment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Loan Interest Payment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Loan Principal $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Fuel Product Sales $187,698,830 $187,698,830 $187,698,830 $187,698,830 $187,698,830 $187,698,830 $187,698,830 $187,698,830 $187,698,830 $187,698,830 Byproduct Credit $2,360,907 $2,360,907 $2,360,907 $2,360,907 $2,360,907 $2,360,907 $2,360,907 $2,360,907 $2,360,907 $2,360,907 Total Annual Sales $190,059,737 $190,059,737 $190,059,737 $190,059,737 $190,059,737 $190,059,737 $190,059,737 $190,059,737 $190,059,737 $190,059,737 Annual Manufacturing Cost Raw Materials $57,937,413 $57,937,413 $57,937,413 $57,937,413 $57,937,413 $57,937,413 $57,937,413 $57,937,413 $57,937,413 $57,937,413 Catalyst Costs $5,185,172 $298,198 $5,185,172 $298,198 $5,185,172 $298,198 $5,185,172 $298,198 $5,185,172 $298,198 Other Variable Costs $28,128,001 $28,128,001 $28,128,001 $28,128,001 $28,128,001 $28,128,001 $28,128,001 $28,128,001 $28,128,001 $28,128,001 Fixed Operating Costs $25,406,303 $25,406,303 $25,406,303 $25,406,303 $25,406,303 $25,406,303 $25,406,303 $25,406,303 $25,406,303 $25,406,303 Total Product Cost $116,656,890 $111,769,916 $116,656,890 $111,769,916 $116,656,890 $111,769,916 $116,656,890 $111,769,916 $116,656,890 $111,769,916 Annual Depreciation General Plant % Depreciation General Plant Depreciation General Plant Remaining Steam Plant % Depreciation 2.23% Steam Plant Depreciation $2,427,266 Steam Plant Remaining $0 Total Depreciation $2,427,266 Net Revenue $70,975,582 $78,289,821 $73,402,847 $78,289,821 $73,402,847 $78,289,821 $73,402,847 $78,289,821 $73,402,847 $78,289,821 Losses Forward $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Taxable Income $70,975,582 $78,289,821 $73,402,847 $78,289,821 $73,402,847 $78,289,821 $73,402,847 $78,289,821 $73,402,847 $78,289,821 Income Tax $24,841,454 $27,401,437 $25,690,997 $27,401,437 $25,690,997 $27,401,437 $25,690,997 $27,401,437 $25,690,997 $27,401,437 Annual Cash Income $48,561,394 $50,888,384 $47,711,851 $50,888,384 $47,711,851 $50,888,384 $47,711,851 $50,888,384 $47,711,851 $50,888,384 Discount Factor 0.135 0.123 0.112 0.102 0.092 0.084 0.076 0.069 0.063 0.057 Annual Present Value $6,562,129 $6,251,433 $5,328,372 $5,166,474 $4,403,613 $4,269,813 $3,639,349 $3,528,771 $3,007,727 $2,916,340 Total Capital Investment + Interest -$1,582,188 Net Present Worth
89

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Operating Cost Summary In Situ

 Raw Material Scaling Flow Quoted Price 

 Year of 

Price 

Quote 

 2011 Cost 2011 Cost

($/h) 

 2011 Cost 

(MM$/yr) 

 2011 Cost 

(¢/GGE) 

Variable Operating Costs

Feedstock, Catalyst & Chemicals

 Feedstock - Wood Chips 102 US ton/h $ 72.00 /US ton 2011 $ 72.00 7,348.73 57.937 106.88 

 Sand Makeup - lb/h $ 0.21 /lb 2011 $ 0.21 - - - 

 VPU Zeolite Catalyst - lb/h $ 9.75 /lb 2011 $ 9.75 - - - 

 CFP Zeolite Catalyst 344 lb/h $ 9.75 /lb 2011 $ 9.75 3,358.11 26.475 48.84 

 Natural Gas to SMR 54 lb/h $ 0.12 /lb 2011 $ 0.12 6.40 0.050 0.09 

 50 wt% Caustic 291 lb/h $ 0.08 /lb 2010 $ 0.08 23.27 0.183 0.34 

 Boiler Chemicals 7,067 lb/h blowdn $ 75.00 /MM lb 2014 $ 66.73 0.47 0.004 0.01 

 Cooling Tower Chemicals 4,627 ton cool $ 33.84 /ton cool/yr 2014 $ 30.11 17.67 0.139 0.26 

 Regeneration Gas: FP - lb/h $ 0.12 /lb 2011 $ 0.12 - - - 

 Regeneration Gas: CFP 0 lb/h $ 0.12 /lb 2011 $ 0.12 0.00 0.000 0.00 

 Regeneration Gas: VPU - lb/h $ 0.12 /lb 2011 $ 0.12 - - - 

 Net Water Makeup 43,242 lb/h $ 0.20 /ton 2001 $ 0.31 6.79 0.054 0.10 

 Diesel Fuel 71 lb/h $ 0.40 /lb 2011 $ 0.40 28.56 0.225 0.42 

 Subtotal 10,790.01 85.068 156.93 

Waste Streams

 FP Purge - lb/h $ 0.016 /lb 1998 $ 0.027 - - - 

 CFP Purge 2,512 lb/h $ 0.016 /lb 1998 $ 0.027 68.77 0.542 1.00 

 VPU Purge - lb/h $ 0.016 /lb 1998 $ 0.027 - - - 

 Quench Filter Solids 43 lb/h $ 0.016 /lb 1998 $ 0.027 1.16 0.009 0.02 

 WWT Cost 21,410 lb/h $ 0.003 /lb 2011 $ 0.003 56.52 0.446 0.82 

 Subtotal 126.46 0.997 1.84 

Coproduct Credits

 Electricity 5,117 kW $ 0.0585 /kWh 2011 $ 0.059 (299) (2.36) (4.36)

 Subtotal (299.46) (2.36) (4.36)

Total Variable Operating Costs 10,617.01 83.705 154.41 

Fixed Operating Costs

 2007 Salary # Positions 2011 Cost 2011 Hourly Wage

 Plant Manager $ 147,000 1 $ 161,362 $ 70.67 

 Plant Engineer $ 70,000 1 $ 76,839 $ 33.65 

 Maintenance Supr $ 57,000 1 $ 62,569 $ 27.40 

 Lab Manager $ 56,000 1 $ 61,471 $ 26.92 

 Shift Supervisor $ 48,000 5 $ 263,448 $ 23.08 

 Lab Technician $ 40,000 2 $ 87,816 $ 19.23 

 Maintenance Tech $ 40,000 16 $ 702,527 $ 19.23 

 Shift Operators $ 48,000 20 $ 1,053,790 $ 23.08 

 Yard Employees $ 28,000 12 $ 368,827 $ 13.46 

 Clerks & Secretaries $ 36,000 3 $ 118,551 $ 17.31 

Total Salaries 62 $ 2,957,199 3.246 5.99 

Avg Salary (w/ Benefits)

 Overhead and Benefits & Supervison = 90.0% $2,921,501 $45.59 per Hour 2.922 5.39 

 Maintenance % of FCI = 3.0% $15,598,938 9,749,336 $94,818 per Year 15.599 28.78 

 Insurance & Taxes % of FCI = 0.7% $3,639,752 3,639,752 3.640 6.71 

Total Fixed Operating Costs 25.406 46.87 

Total Operating Costs 109.111 201.28 

Annual Capital Charge 91.514 168.82 
90

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Appendix C-2. Discounted Cash Flow Rate of Return 

and Operating Cost Summary (Ex Situ Case)
91

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications. Year

 

-2 -1 0 1 2 3 4 5 6 7 8 9 10

Fixed Capital Investment $19,579,672 $134,772,539 $71,878,688

Working Capital $28,077,612Loan Payment $50,212,707 $50,212,707 $50,212,707 $50,212,707 $50,212,707 $50,212,707 $50,212,707 $50,212,707 $50,212,707 $50,212,707

 Loan Interest Payment $2,156,361 $18,329,065 $26,954,508 $26,954,508 $25,093,852 $23,084,344 $20,914,075 $18,570,184 $16,038,782 $13,304,868 $10,352,241 $7,163,404 $3,719,460

 Loan Principal $26,954,508 $229,113,317 $336,931,348 $313,673,150 $288,554,295 $261,425,932 $232,127,300 $200,484,777 $166,310,853 $129,403,015 $89,542,549 $46,493,247 $0

Fuel Product Sales $140,387,007 $187,182,676 $187,182,676 $187,182,676 $187,182,676 $187,182,676 $187,182,676 $187,182,676 $187,182,676 $187,182,676

 Byproduct Credit $1,107,466 $1,476,621 $1,476,621 $1,476,621 $1,476,621 $1,476,621 $1,476,621 $1,476,621 $1,476,621 $1,476,621

Total Annual Sales $141,494,473 $188,659,297 $188,659,297 $188,659,297 $188,659,297 $188,659,297 $188,659,297 $188,659,297 $188,659,297 $188,659,297

Annual Manufacturing Cost

Raw Materials $50,695,237 $57,937,413 $57,937,413 $57,937,413 $57,937,413 $57,937,413 $57,937,413 $57,937,413 $57,937,413 $57,937,413

Catalyst Costs $0 $0 $0 $6,868,000 $272,954 $5,325,566 $272,954 $5,325,566 $272,954 $5,325,566 $272,954 $5,325,566 $272,954

 Other Variable Costs $17,056,575 $19,493,229 $19,493,229 $19,493,229 $19,493,229 $19,493,229 $19,493,229 $19,493,229 $19,493,229 $19,493,229

 Fixed Operating Costs $26,945,046 $26,945,046 $26,945,046 $26,945,046 $26,945,046 $26,945,046 $26,945,046 $26,945,046 $26,945,046 $26,945,046

Total Product Cost $101,564,858 $104,648,642 $109,701,254 $104,648,642 $109,701,254 $104,648,642 $109,701,254 $104,648,642 $109,701,254 $104,648,642

Annual Depreciation

General Plant % Depreciation 14.3% 24.5% 17.5% 12.5% 8.9% 8.9% 8.9% 4.5%

General Plant Depreciation $65,096,988 $111,562,298 $79,674,340 $56,897,227 $40,679,923 $40,634,369 $40,679,923 $20,317,184

General Plant Remaining $390,445,265 $278,882,967 $199,208,627 $142,311,400 $101,631,477 $60,997,108 $20,317,184 $0

Steam Plant % Depreciation 3.75% 7.22% 6.68% 6.18% 5.71% 5.29% 4.89% 4.52% 4.46% 4.46%

Steam Plant Depreciation $3,975,375 $7,652,862 $7,078,287 $6,548,237 $6,056,351 $5,602,628 $5,181,769 $4,793,772 $4,730,166 $4,729,106

Steam Plant Remaining $102,034,620 $94,381,758 $87,303,471 $80,755,234 $74,698,883 $69,096,254 $63,914,486 $59,120,714 $54,390,548 $49,661,442

Total Depreciation $69,072,363 $119,215,159 $86,752,627 $63,445,465 $46,736,274 $46,236,997 $45,861,692 $25,110,956 $4,730,166 $4,729,106

Net Revenue -$56,097,255 -$60,298,356 -$30,878,928 -$348,884 $13,651,585 $21,734,876 $19,791,483 $48,547,458 $67,064,473 $75,562,090

Losses Forward -$56,097,255 -$116,395,611 -$147,274,539 -$147,623,423 -$133,971,839 -$112,236,963 -$92,445,480 -$43,898,022 $0

Taxable Income -$56,097,255 -$116,395,611 -$147,274,539 -$147,623,423 -$133,971,839 -$112,236,963 -$92,445,480 -$43,898,022 $23,166,451 $75,562,090

Income Tax $0 $0 $0 $0 $0 $0 $0 $0 $8,108,258 $26,446,731

Annual Cash Income -$10,283,092 $33,797,949 $28,745,336 $33,797,949 $28,745,336 $33,797,949 $28,745,336 $33,797,949 $20,637,078 $7,351,217

Discount Factor 1.210 1.100 1.000 0.909 0.826 0.751 0.683 0.621 0.564 0.513 0.467 0.424 0.386

Annual Present Value $319,921,818 -$9,348,265 $27,932,189 $21,596,797 $23,084,454 $17,848,592 $19,078,061 $14,750,903 $15,766,993 $8,752,136 $2,834,213

Total Capital Investment + Interest $26,300,599 $168,411,765 $126,910,808

Net Present Worth $0

Year 11 12 13 14 15 16 17 18 19 20

Fixed Capital InvestmentWorking CapitalLoan Payment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

 Loan Interest Payment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

 Loan Principal $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

Fuel Product Sales $187,182,676 $187,182,676 $187,182,676 $187,182,676 $187,182,676 $187,182,676 $187,182,676 $187,182,676 $187,182,676 $187,182,676

 Byproduct Credit $1,476,621 $1,476,621 $1,476,621 $1,476,621 $1,476,621 $1,476,621 $1,476,621 $1,476,621 $1,476,621 $1,476,621

Total Annual Sales $188,659,297 $188,659,297 $188,659,297 $188,659,297 $188,659,297 $188,659,297 $188,659,297 $188,659,297 $188,659,297 $188,659,297

Annual Manufacturing Cost

Raw Materials $57,937,413 $57,937,413 $57,937,413 $57,937,413 $57,937,413 $57,937,413 $57,937,413 $57,937,413 $57,937,413 $57,937,413

Catalyst Costs $5,325,566 $272,954 $5,325,566 $272,954 $5,325,566 $272,954 $5,325,566 $272,954 $5,325,566 $272,954

 Other Variable Costs $19,493,229 $19,493,229 $19,493,229 $19,493,229 $19,493,229 $19,493,229 $19,493,229 $19,493,229 $19,493,229 $19,493,229

 Fixed Operating Costs $26,945,046 $26,945,046 $26,945,046 $26,945,046 $26,945,046 $26,945,046 $26,945,046 $26,945,046 $26,945,046 $26,945,046

Total Product Cost $109,701,254 $104,648,642 $109,701,254 $104,648,642 $109,701,254 $104,648,642 $109,701,254 $104,648,642 $109,701,254 $104,648,642

Annual Depreciation

General Plant % DepreciationGeneral Plant DepreciationGeneral Plant RemainingSteam Plant % Depreciation 4.46% 4.46% 4.46% 4.46% 4.46% 4.46% 4.46% 4.46% 4.46% 4.46%

Steam Plant Depreciation $4,730,166 $4,729,106 $4,730,166 $4,729,106 $4,730,166 $4,729,106 $4,730,166 $4,729,106 $4,730,166 $4,729,106

Steam Plant Remaining $44,931,276 $40,202,170 $35,472,004 $30,742,898 $26,012,732 $21,283,627 $16,553,461 $11,824,355 $7,094,189 $2,365,083

Total Depreciation $4,730,166 $4,729,106 $4,730,166 $4,729,106 $4,730,166 $4,729,106 $4,730,166 $4,729,106 $4,730,166 $4,729,106

Net Revenue $74,227,877 $79,281,549 $74,227,877 $79,281,549 $74,227,877 $79,281,549 $74,227,877 $79,281,549 $74,227,877 $79,281,549

Losses Forward $0 $0 $0 $0 $0 $0 $0 $0 $0 $0

Taxable Income $74,227,877 $79,281,549 $74,227,877 $79,281,549 $74,227,877 $79,281,549 $74,227,877 $79,281,549 $74,227,877 $79,281,549

Income Tax $25,979,757 $27,748,542 $25,979,757 $27,748,542 $25,979,757 $27,748,542 $25,979,757 $27,748,542 $25,979,757 $27,748,542

Annual Cash Income $52,978,286 $56,262,113 $52,978,286 $56,262,113 $52,978,286 $56,262,113 $52,978,286 $56,262,113 $52,978,286 $56,262,113

Discount Factor 0.350 0.319 0.290 0.263 0.239 0.218 0.198 0.180 0.164 0.149

Annual Present Value $18,568,566 $17,926,843 $15,345,922 $14,815,573 $12,682,580 $12,244,275 $10,481,471 $10,119,236 $8,662,373 $8,363,005

Total Capital Investment + InterestNet Present Worth
92

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications. Year 21 22 23 24 25 26 27 28 29 30 Fixed Capital Investment Working Capital -$29,687,612 Loan Payment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Loan Interest Payment $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Loan Principal $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Fuel Product Sales $187,182,676 $187,182,676 $187,182,676 $187,182,676 $187,182,676 $187,182,676 $187,182,676 $187,182,676 $187,182,676 $187,182,676 Byproduct Credit $1,476,621 $1,476,621 $1,476,621 $1,476,621 $1,476,621 $1,476,621 $1,476,621 $1,476,621 $1,476,621 $1,476,621 Total Annual Sales $188,659,297 $188,659,297 $188,659,297 $188,659,297 $188,659,297 $188,659,297 $188,659,297 $188,659,297 $188,659,297 $188,659,297 Annual Manufacturing Cost Raw Materials $57,937,413 $57,937,413 $57,937,413 $57,937,413 $57,937,413 $57,937,413 $57,937,413 $57,937,413 $57,937,413 $57,937,413 Catalyst Costs $5,325,566 $272,954 $5,325,566 $272,954 $5,325,566 $272,954 $5,325,566 $272,954 $5,325,566 $272,954 Other Variable Costs $19,493,229 $19,493,229 $19,493,229 $19,493,229 $19,493,229 $19,493,229 $19,493,229 $19,493,229 $19,493,229 $19,493,229 Fixed Operating Costs $26,945,046 $26,945,046 $26,945,046 $26,945,046 $26,945,046 $26,945,046 $26,945,046 $26,945,046 $26,945,046 $26,945,046 Total Product Cost $109,701,254 $104,648,642 $109,701,254 $104,648,642 $109,701,254 $104,648,642 $109,701,254 $104,648,642 $109,701,254 $104,648,642 Annual Depreciation General Plant % Depreciation General Plant Depreciation General Plant Remaining Steam Plant % Depreciation 2.23% Steam Plant Depreciation $2,365,083 Steam Plant Remaining $0 Total Depreciation $2,365,083 Net Revenue $76,592,960 $84,010,655 $78,958,043 $84,010,655 $78,958,043 $84,010,655 $78,958,043 $84,010,655 $78,958,043 $84,010,655 Losses Forward $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Taxable Income $76,592,960 $84,010,655 $78,958,043 $84,010,655 $78,958,043 $84,010,655 $78,958,043 $84,010,655 $78,958,043 $84,010,655 Income Tax $26,807,536 $29,403,729 $27,635,315 $29,403,729 $27,635,315 $29,403,729 $27,635,315 $29,403,729 $27,635,315 $29,403,729 Annual Cash Income $52,150,507 $54,606,926 $51,322,728 $54,606,926 $51,322,728 $54,606,926 $51,322,728 $54,606,926 $51,322,728 $54,606,926 Discount Factor 0.135 0.123 0.112 0.102 0.092 0.084 0.076 0.069 0.063 0.057 Annual Present Value $7,047,128 $6,708,241 $5,731,628 $5,544,001 $4,736,882 $4,581,819 $3,914,779 $3,786,627 $3,235,354 $3,129,444 Total Capital Investment + Interest -$1,701,354 Net Present Worth
93

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Operating Cost Summary Ex Situ

 Raw Material Scaling Flow Quoted Price 

 Year of 

Price 

Quote 

 2011 Cost 2011 Cost

($/h) 

 2011 Cost 

(MM$/yr) 

 2011 Cost 

(¢/GGE) 

A200.A211.217P:MA

Variable Operating Costs

Feedstock, Catalyst & Chemicals

 Feedstock - Wood Chips 102 US ton/h $ 72.00 /US ton 2011 $ 72.00 7,348.73 57.937 102.60 

 Sand Makeup 158 lb/h $ 0.21 /lb 2011 $ 0.21 32.79 0.259 0.46 

 VPU Zeolite Catalyst 229 lb/h $ 9.75 /lb 2011 $ 9.75 2,229.26 17.576 31.12 

 CFP Zeolite Catalyst - lb/h $ 9.75 /lb 2011 $ 9.75 - - - 

 Natural Gas to SMR 125 lb/h $ 0.12 /lb 2011 $ 0.12 14.88 0.117 0.21 

 50 wt% Caustic 294 lb/h $ 0.08 /lb 2010 $ 0.08 23.54 0.186 0.33 

 Boiler Chemicals 6,475 lb/h blowdn $ 75.00 /MM lb 2014 $ 66.73 0.43 0.003 0.01 

 Cooling Tower Chemicals 4,694 ton cool $ 33.84 /ton cool/yr 2014 $ 30.11 17.93 0.141 0.25 

 Regeneration Gas: FP 0 lb/h $ 0.12 /lb 2011 $ 0.12 0.00 0.000 0.00 

 Regeneration Gas: CFP - lb/h $ 0.12 /lb 2011 $ 0.12 - - - 

 Regeneration Gas: VPU 0 lb/h $ 0.12 /lb 2011 $ 0.12 0.00 0.000 0.00 

 Net Water Makeup 41,495 lb/h $ 0.20 /ton 2001 $ 0.31 6.52 0.051 0.09 

 Diesel Fuel 71 lb/h $ 0.40 /lb 2011 $ 0.40 28.56 0.225 0.40 

 Subtotal 9,702.64 76.496 135.46 

Waste Streams

 FP Purge 2,038 lb/h $ 0.016 /lb 1998 $ 0.027 55.78 0.440 0.78 

 CFP Purge - lb/h $ 0.016 /lb 1998 $ 0.027 - - - 

 VPU Purge 262 lb/h $ 0.016 /lb 1998 $ 0.027 7.17 0.056 0.10 

 Quench Filter Solids 36 lb/h $ 0.016 /lb 1998 $ 0.027 0.98 0.008 0.01 

 WWT Cost 20,708 lb/h $ 0.003 /lb 2011 $ 0.003 54.67 0.431 0.76 

 Subtotal 118.59 0.935 1.66 

Coproduct Credits

 Electricity 3,201 kW $ 0.0585 /kWh 2011 $ 0.059 (187) (1.48) (2.61)

 Subtotal (187.29) (1.48) (2.61)

Total Variable Operating Costs 9,633.94 75.954 134.50 

Fixed Operating Costs

 2007 Salary # Positions 2011 Cost 2011 Hourly Wage

 Plant Manager $ 147,000 1 $ 161,362 $ 70.67 

 Plant Engineer $ 70,000 1 $ 76,839 $ 33.65 

 Maintenance Supr $ 57,000 1 $ 62,569 $ 27.40 

 Lab Manager $ 56,000 1 $ 61,471 $ 26.92 

 Shift Supervisor $ 48,000 5 $ 263,448 $ 23.08 

 Lab Technician $ 40,000 2 $ 87,816 $ 19.23 

 Maintenance Tech $ 40,000 16 $ 702,527 $ 19.23 

 Shift Operators $ 48,000 20 $ 1,053,790 $ 23.08 

 Yard Employees $ 28,000 12 $ 368,827 $ 13.46 

 Clerks & Secretaries $ 36,000 3 $ 118,551 $ 17.31 

Total Salaries 62 $ 2,957,199 3.246 5.75 

Avg Salary (w/ Benefits)

 Overhead and Benefits f Labor & Supervison = 90.0% $2,921,501 $45.59 per Hour 2.922 5.17 

 Maintenance % of FCI = 3.0% $16,846,567 10,529,105 $94,818 per Year 16.847 29.83 

 Insurance & Taxes % of FCI = 0.7% $3,930,866 3,930,866 3.931 6.96 

Total Fixed Operating Costs 26.945 47.72 

Total Operating Costs 102.899 182.22 

Annual Capital Charge 98.833 175.02 
95

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Appendix D-1. Process Parameter and Operating 

Summary (In Situ Case)

Process Parameters and Operation Summary In Situ FEEDSTOCK VAPOR QUENCH SEPARATION FUEL PRODUCTION

Biomass total 204,131 lb/h Heavy Fraction condenser-absorber Gasoline column Gasoline density 6.215 lb/gal (1)

Feed Moisture 10% wt Temperature 348 °F Feed from hydrotreater 45,023 lb/h Oxygen content 0.69% wt%

Moisture flow 20,413 lb/h Pressure 114 psia Feed from hydrocracker 8,068 lb/h production 31,866 lb/h

Dry feed rate 183,718 lb/h Feed rate 329,131 lb/h Gasoline range product 31,866 lb/h 251.2 MMlb/yr

Feedstock %C 50.9% dry wt Recycle liquid flow 86,730 lb/h Light gases 547 lb/h actual volume 123,060 gal/day

Feedstock %H 6.0% dry wt Vapor product 396,315 lb/h Bottoms to diesel column 20,678 lb/h 40.4 MMgal/yr

Feedstock %O 41.9% dry wt Bottoms liquid flow 19,547 lb/h Diesel column 55.8 gal/dry ton

Feedstock %S 0.0% dry wt Light fraction condenser-absorber Feed from gasoline column 20,678 lb/h HHV (Aspen) 19,422 Btu/lb

Feedstock %N 0.2% dry wt Temperature 60 °F Diesel-range product 11,845 lb/h 120,705 Btu/gal

Feedstock %Ash 0.9% dry wt Pressure 101 psia Bottoms to hydrocracker 8,833 lb/h HHV equiv volume 39.2 MMGGE/yr

Specific LHV 7,989 Btu/lb Recycle liquid flow 964,869 lb/h Overall hydroprocess efficiency 54.2 GGE/dry ton

Specific HHV 8,578 Btu/lb Vapor product 199,763 lb/h Carbon efficiency % 91% LHV (Aspen) 18,180 Btu/lb

PYROLYSIS MAIN CFB 1 Bottoms liquid flow 1,161,420 lb/h Yield lb product/lb feed 84% 112,988 Btu/gal

Reactor Mole % H2 overhead 62% Oxygen content in feed/product 10.5%, 0.5% wt% LHV Vol Equiv 39.3 MMGGE/yr

Parallel trains (reactor+combustor) 2 Total aqueous phase HYDROTREATING RECYCLE COMPRESSOR 54.3 GGE/dry ton

Biomass feed per train 1000 dry MT/day Flow 77,273 lb/h Inlet pressure 1793 psia Diesel density 6.982 lb/gal (1)

Biomass moisture 10% wt% wt% carbon 2.6% Outlet pressure 1900 psia Oxygen content 0.00% wt%

Temperature 500°C 932°F % carbon loss to aq phase 2.1% Inlet mass flow 27085 lb/h production 11,845 lb/h

Pressure 121 psia 8.3 bar Total organic phase Inlet molecular weight 2 93.4 MMlb/yr

Bed solids material Catalyst (ZSM-5) Flow 52,053 lb/h Electrical consumption 176 kW actual volume 40,716 gal/day

Bed solids inventory 115 ton wt% C 80% HYDROCRACKING RECYCLE COMPRESSOR 13.4 MMgal/yr

Catalyst makeup (% rxr inventory) 2.00% wt% H 10% Inlet pressure 1893 psia 18.5 gal/dry ton

Ratio of bed solids to dry biomass 6.8 w/w wt% O 10% Outlet pressure 2000 psia HHV (Aspen) 19,792 Btu/lb

Number of cyclones per reactor 2 organic H/C 1.47 Inlet mass flow 5214 lb/h 138,185 Btu/gal

Stripping steam 3.0 lb/1000 lb cat carbon eff to organic phs 44% Inlet molecular weight 2 HHV equiv volume 14.86 MMGGE/yr

Fluidizing gases to dry biomass 0.77 w/w HYDROGEN RECYCLE Electrical consumption 32 kW 20.5 GGE/dry ton

H2 partial pressure in fluidizing gas 86 psia 5.9 bar Water gas shift HYDROTREATING MAKEUP COMPRESSOR LHV (Aspen) 18,477 Btu/lb

Combustor/Regenerator Gas flow rate 48,356 lb/h Inlet pressure 245 psia 129,006 Btu/gal

Temperature 650°C 1202°F Inlet temperature 464 °F Outlet pressure 1795 psia LHV Vol Equiv 14.86 MMGGE/yr

Pressure 117 psia 8.1 bar Outlet temperature 663 °F Inlet mass flow 3865 lb/h 20.5 GGE/dry ton

Excess air (%) 20% Pressure 88 psia Inlet molecular weight 2 Total production 43,711 lb/h

Upstream solids temperature 650°C 1202°F Steam flow rate 29,556 lb/h Electrical consumption 1765 kW 344.6 MMlb/yr

No. of cyclones per combustor 2 Temperature approach 35 °F HYDROCRACKING MAKEUP COMPRESSOR actual volume 53.8 MMgal/yr

VAPOR PHASE UPGRADING CFB 0 Wastewater (condensate) 19,648 lb/h Inlet pressure 245 psia 163,776 gal/day

Reactor Pressure swing adsorption (PSA) Outlet pressure 1995 psia 74.3 gal/dry ton

Parallel trains (reactor+combustor) N/A Inlet flow rate 58,265 lb/h Inlet mass flow 1068 lb/h HHV equiv volume 54.1 MMGGE/yy

Biomass feed per train N/A dry MT/day Inlet hydrogen mole % 67% Inlet molecular weight 2 LHV equiv volume 54.2 MMGGE/yr

Biomass moisture 10% wt% Hydrogen recovery % 84% Electrical consumption 516 kW % Gasoline 73%

Temperature N/A N/A Hydrogen purity % 99% HYDROGEN PLANT % Diesel 27%

Pressure N/A N/A Hydrogen product stream 5,462 lb/h Hydrogen production rate 29956483.7 MMscfd THEORETICAL PRODUCTION

Bed solids material N/A HYDROPROCESSING Supplemental natural gas 54 lb/h total HHV 1577 MMbtu/h

Bed solids inventory N/A ton Hydrotreater Hydrogen outlet purity 99 mol% HHV Theo. Volume 13,066 gge/h

Catalyst makeup (% rxr inventory) N/A Pressure 1,815 psia Hydrogen outlet pressure 266 psia HHV Theo. Yield 142 gal/ton

Ratio of bed solids to dry biomass N/A w/w Liquid feed 52,053 lb/h Hydrogen Balance ENERGY EFFICIENCY LHV HHV

Number of cyclones per reactor 2 Liquid feed C, H, O 80%, 10%, 10% wt% Pyrolysis Reactor Makeup 8,288 lb/h Inputs (MMBtu/h)

Stripping steam N/A lb/1000 lb cat Total H2 feed (pure) 11,229 lb/h Hydrotreating Makeup 3,865 lb/h Feedstock 1,468 1,576

Fluidizing gases to dry biomass N/A H2 purity 90% mol% Hydrocracking Makeup 1,068 lb/h Natural Gas 1 1

H2 partial pressure in fluidizing gas N/A N/A Makeup H2 (pure) 3,274 lb/h Total consumed 13,221 lb/h Outputs (MMBtu/h)

Combustor/Regenerator Product gas (HP flash) 28,548 lb/h Produced from recycle PSA 5,462 lb/h Gasoline product 579 619

Temperature N/A N/A Product gas (HP flash) H2 87% mol% Produced from reformer 7,759 lb/h Diesel product 219 234

Pressure N/A N/A Purge gas (HP flash) 5,327 lb/h Total produced 13,221 lb/h Electricity product 17 17

Excess air (%) 20% Purge gas (LP flash) 870 lb/h STEAM SYSTEM Fuel/Biomass Effic. 54.4% 54.1%

Upstream solids temperature N/A N/A Aqueous phase product 4,696 lb/h HP Turbine Brake Power -17228 hp Fuel/(Biomass+NG) 54.3% 54.1%

No. of cyclones per combustor 2 Organic phase product 45,023 lb/h IP Turbine Brake Power -21952 hp (Fuel+Elec)/(Biomass+NG) 55.5% 55.2%

UPGRADED PRODUCT COMPOSITION Organic phase C,H,O 87%, 12%, 1% wt% LP Turbine Brake Power -25578 hp CARBON EFFICIENCY

Hydrogen incorporated 1.3% wt% dry BM Hydrocracker POWER SUMMARY (kW) GENERATED CONSUMED Fuel yield, mass basis 23.8% wt% dry BM

Gas 22.9% wt% dry BM Liquid feed 8,833 lb/h Feed handling and drying 387 Fuel/Biomass Effic. 40.4%

Aqueous 28.7% wt% dry BM Liquid feed C, H, O 88%, 11%, 1% wt% Pyrolysis 22,619 Fuel/(Biomass+NG) Effic. 40.4%

Organic 28.3% wt% dry BM Total H2 feed (pure) 2,154 lb/h Condensation & separation 3,500

Coke 8.1% wt% dry BM H2 purity 90% mol% Hydroprocessing 2,951

Char 12.0% wt% dry BM Makeup H2 (pure) 905 lb/h Hydrogen production 6,083

Net Water 27.3% wt% dry BM Product gas (HP flash) 5,487 lb/h Steam & power 48,291 1,588

Product gas (HP flash) H2 84% mol% Cooling water & utilities 324

Purge gas (HP flash) 1,342 lb/h Wastewater management 1,798

Purge gas (LP flash) 412 lb/h Miscellaneous 3,925

Aqueous phase product 80 lb/h Balance to grid 5,117

Organic phase producth 8,068 lb/h Plant totals 48,291 48,291

Organic phase C,H,O 85%, 15%, 0% wt% HEAT INTEGRATION

Total Pinch Duty 848 MMBtu/h

(1) From: http://cta.ornl.gov/bedb/appendix_a/Lower_and_Higher_Heating_Values_of_Gas_Liquid_and_Solid_Fuels.pdf

Conventional gasoline 2,819 grams/gallon = 6.214831 lb/gal

US conventional diesel 3,167 grams/gallon = 6.98204 lb/gal
96

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Appendix D-2. Process Parameter and Operating 

Summary (Ex Situ Case)

Process Parameters and Operation Summary Ex Situ FEEDSTOCK VAPOR QUENCH SEPARATION FUEL PRODUCTION

Biomass total 204,131 lb/h Heavy Fraction condenser-absorber Gasoline column Gasoline density 6.215 lb/gal (1)

Feed Moisture 10% wt Temperature 358 °F Feed from hydrotreater 46,446 lb/h Oxygen content 0.78% wt%

Moisture flow 20,413 lb/h Pressure 110 psia Feed from hydrocracker 16,636 lb/h production 20,408 lb/h

Dry feed rate 183,718 lb/h Feed rate 310,342 lb/h Gasoline range product 20,408 lb/h 160.9 MMlb/yr

Feedstock %C 50.9% dry wt Recycle liquid flow 81,043 lb/h Light gases 1,281 lb/h actual volume 78,809 gal/day

Feedstock %H 6.0% dry wt Vapor product 371,714 lb/h Bottoms to diesel column 41,393 lb/h 25.9 MMgal/yr

Feedstock %O 41.9% dry wt Bottoms liquid flow 19,671 lb/h Diesel column 35.7 gal/dry ton

Feedstock %S 0.0% dry wt Light fraction condenser-absorber Feed from gasoline column 41,393 lb/h HHV (Aspen) 19,719 Btu/lb

Feedstock %N 0.2% dry wt Temperature 60 °F Diesel-range product 24,739 lb/h 122,549 Btu/gal

Feedstock %Ash 0.9% dry wt Pressure 97 psia Bottoms to hydrocracker 16,654 lb/h HHV equiv volume 25.5 MMGGE/yr

Specific LHV 7,989 Btu/lb Recycle liquid flow 901,601 lb/h Overall hydroprocess efficiency 35.2 GGE/dry ton

Specific HHV 8,578 Btu/lb Vapor product 182,444 lb/h Carbon efficiency % 94% LHV (Aspen) 18,386 Btu/lb

PYROLYSIS MAIN CFB 0 Bottoms liquid flow 1,090,871 lb/h Yield lb product/lb feed 90% 114,267 Btu/gal

Reactor Mole % H2 overhead 68% Oxygen content in feed/product 6.4%, 0.4% wt% LHV Vol Equiv 25.5 MMGGE/yr

Parallel trains (reactor+combustor) 2 Total aqueous phase HYDROTREATING RECYCLE COMPRESSOR 35.2 GGE/dry ton

Biomass feed per train 1000 dry MT/day Flow 77,811 lb/h Inlet pressure 1493 psia Diesel density 6.982 lb/gal (1)

Biomass moisture 10% wt% wt% carbon 1.6% Outlet pressure 1600 psia Oxygen content 0.00% wt%

Temperature 500°C 932°F % carbon loss to aq phase 1.3% Inlet mass flow 17528 lb/h production 24,739 lb/h

Pressure 121 psia 8.3 bar Total organic phase Inlet molecular weight 2 195.0 MMlb/yr

Bed solids material Sand Flow 50,051 lb/h Electrical consumption 134 kW actual volume 85,037 gal/day

Bed solids inventory 120 ton wt% C 83% HYDROCRACKING RECYCLE COMPRESSOR 27.9 MMgal/yr

Catalyst makeup (% rxr inventory) N/A wt% H 11% Inlet pressure 1893 psia 38.6 gal/dry ton

Ratio of bed solids to dry biomass 7.0 w/w wt% O 6% Outlet pressure 2000 psia HHV (Aspen) 19,752 Btu/lb

Number of cyclones per reactor 2 organic H/C 1.57 Inlet mass flow 4819 lb/h 137,910 Btu/gal

Stripping steam N/A lb/1000 lb cat carbon eff to organic phs 44% Inlet molecular weight 2 HHV equiv volume 30.98 MMGGE/yr

Fluidizing gases to dry biomass 0.69 w/w HYDROGEN RECYCLE Electrical consumption 31 kW 42.8 GGE/dry ton

H2 partial pressure in fluidizing gas 93 psia 6.4 bar Water gas shift HYDROTREATING MAKEUP COMPRESSOR LHV (Aspen) 18,444 Btu/lb

Combustor/Regenerator Gas flow rate 51,621 lb/h Inlet pressure 245 psia 128,779 Btu/gal

Temperature 720°C 1328°F Inlet temperature 464 °F Outlet pressure 1495 psia LHV Vol Equiv 30.99 MMGGE/yr

Pressure 117 psia 8.1 bar Outlet temperature 637 °F Inlet mass flow 2154 lb/h 42.8 GGE/dry ton

Excess air (%) 20% Pressure 84 psia Inlet molecular weight 2 Total production 45,146 lb/h

Upstream solids temperature 720°C 1328°F Steam flow rate 30,755 lb/h Electrical consumption 888 kW 355.9 MMlb/yr

No. of cyclones per combustor 2 Temperature approach 35 °F HYDROCRACKING MAKEUP COMPRESSOR actual volume 53.8 MMgal/yr

VAPOR PHASE UPGRADING CFB 1 Wastewater (condensate) 20,723 lb/h Inlet pressure 245 psia 163,846 gal/day

Reactor Pressure swing adsorption (PSA) Outlet pressure 1995 psia 74.3 gal/dry ton

Parallel trains (reactor+combustor) 1 Inlet flow rate 61,652 lb/h Inlet mass flow 764 lb/h HHV equiv volume 56.5 MMGGE/yy

Biomass feed per train 2000 dry MT/day Inlet hydrogen mole % 71% Inlet molecular weight 2 LHV equiv volume 56.5 MMGGE/yr

Biomass moisture 10% wt% Hydrogen recovery % 84% Electrical consumption 369 kW % Gasoline 45%

Temperature 500°C 932°F Hydrogen purity % 99% HYDROGEN PLANT % Diesel 55%

Pressure 119 psia 8.2 bar Hydrogen product stream 7,032 lb/h Hydrogen production rate 27420512.8 MMscfd THEORETICAL PRODUCTION

Bed solids material yst (ZSM-5) HYDROPROCESSING Supplemental natural gas 125 lb/h total HHV 1579 MMbtu/h

Bed solids inventory 77 ton Hydrotreater Hydrogen outlet purity 99 mol% HHV Theo. Volume 12,882 gge/h

Catalyst makeup (% rxr inventory) 2.00% Pressure 1,515 psia Hydrogen outlet pressure 266 psia HHV Theo. Yield 140 gal/ton

Ratio of bed solids to dry biomass 4.5 w/w Liquid feed 50,051 lb/h Hydrogen Balance ENERGY EFFICIENCY LHV HHV

Number of cyclones per reactor 2 Liquid feed C, H, O 83%, 11%, 6% wt% Pyrolysis Reactor Makeup 11,217 lb/h Inputs (MMBtu/h)

Stripping steam 3.0 lb/1000 lb cat Total H2 feed (pure) 7,249 lb/h Hydrotreating Makeup 2,154 lb/h Feedstock 1,468 1,576

Fluidizing gases to dry biomass N/A H2 purity 90% mol% Hydrocracking Makeup 764 lb/h Natural Gas 2 3

H2 partial pressure in fluidizing gas 73 psia 5.1 bar Makeup H2 (pure) 1,825 lb/h Total consumed 14,134 lb/h Outputs (MMBtu/h)

Combustor/Regenerator Product gas (HP flash) 17,435 lb/h Produced from recycle PSA 7,032 lb/h Gasoline product 375 402

Temperature 650°C 1202°F Product gas (HP flash) H2 87% mol% Produced from reformer 7,102 lb/h Diesel product 456 489

Pressure 113 psia 7.8 bar Purge gas (HP flash) 2,061 lb/h Total produced 14,134 lb/h Electricity product 11 11

Excess air (%) 20% Purge gas (LP flash) 787 lb/h STEAM SYSTEM Fuel/Biomass Effic. 56.7% 56.5%

Upstream solids temperature 341°C 645°F Aqueous phase product 2,912 lb/h HP Turbine Brake Power -15786 hp Fuel/(Biomass+NG) 56.6% 56.4%

No. of cyclones per combustor 2 Organic phase product 46,446 lb/h IP Turbine Brake Power -20114 hp (Fuel+Elec)/(Biomass+NG) 57.3% 57.1%

UPGRADED PRODUCT COMPOSITION Organic phase C,H,O 87%, 13%, 1% wt% LP Turbine Brake Power -23436 hp CARBON EFFICIENCY

Hydrogen incorporated 1.8% wt% dry BM Hydrocracker POWER SUMMARY (kW) GENERATED CONSUMED Fuel yield, mass basis 24.6% wt% dry BM

Gas 23.0% wt% dry BM Liquid feed 16,654 lb/h Feed handling and drying 298 Fuel/Biomass Effic. 41.5%

Aqueous 29.7% wt% dry BM Liquid feed C, H, O 88%, 11%, 1% wt% Pyrolysis 22,783 Fuel/(Biomass+NG) Effic. 41.5%

Organic 27.2% wt% dry BM Total H2 feed (pure) 2,109 lb/h Condensation & separation 3,914

Coke 8.0% wt% dry BM H2 purity 90% mol% Hydroprocessing 1,811

Char 12.0% wt% dry BM Makeup H2 (pure) 647 lb/h Hydrogen production 5,875

Net Water 28.9% wt% dry BM Product gas (HP flash) 4,353 lb/h Steam & power 44,247 1,461

Product gas (HP flash) H2 87% mol% Cooling water & utilities 327

Purge gas (HP flash) 298 lb/h Wastewater management 846

Purge gas (LP flash) 356 lb/h Miscellaneous 3,731

Aqueous phase product 129 lb/h Balance to grid 3,201

Organic phase producth 16,636 lb/h Plant totals 44,247 44,247

Organic phase C,H,O 86%, 14%, 0% wt% HEAT INTEGRATION

Total Pinch Duty 816 MMBtu/h

(1) From: http://cta.ornl.gov/bedb/appendix_a/Lower_and_Higher_Heating_Values_of_Gas_Liquid_and_Solid_Fuels.pdf

Conventional gasoline 2,819 grams/gallon = 6.214831 lb/gal

US conventional diesel 3,167 grams/gallon = 6.98204 lb/gal
97

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Appendix E. Assumptions and Analysis for Full LifeCycle GHG Emissions

To provide an initial estimate of life-cycle fuel GHGs associated with this conversion pathway, a 

preliminary life-cycle GHG analysis was performed for fuel produced via the in situ and ex situ

catalytic pyrolysis pathways using the model 2017 blended feedstock (45% pulpwood, 32% 

wood residues, 3% switchgrass, and 20% construction and demolition waste). The data and 

sources used for each of the life-cycle stages are described in the following paragraphs, along 

with the results of the analysis.

Feedstock Crop Establishment and Growing

For the production of the purpose-grown bioenergy crops, pulpwood and switchgrass, emissions 

calculations from the GREET 2014 model (GREET 2014) were aggregated and used in the 

SimaPro fuel life-cycle model. Poplar was used to represent pulpwood in the feedstock blend. 

Switchgrass and poplar farming emissions were taken from the “EtOH” worksheet in the 

GREET model. Information on the development of GREET crop production parameters from 

Wang et al. (2013) was used to subtract the harvesting energy (which is accounted for in the next 

stage) from the GREET model total farming energy values in order to calculate emissions for 

only the establishment and growing phase of farming operations. Table E-1 shows the total 

farming energy assumed in GREET (including harvesting) and the estimated energy value for 

establishment and growing operations (“Farming Energy Excluding Harvesting” in Table E-1)

used in this analysis. 

Table E-1. Farming Energy Values from GREET and Modified for this Analysis

GREET Farming Energy 

(including harvesting), Btu/dry 

ton

Farming Energy Excluding 

Harvesting (estimated from 

GREET), Btu/dry ton

Switchgrass* 201,995 (92.8% diesel;7.2% 

electricity)

56,870 (100% diesel)

Poplar 219,200 (100% diesel) 20,496 (100% diesel)

*Values include 14% dry matter loss.

The overall emissions from crop establishment and growing operations including fertilizer and 

herbicide application for switchgrass and poplar estimated from the GREET model data are 

107,434 g CO2-e/dry ton and 40,056 g CO2-e/dry ton, respectively. For the production of the 

remaining feedstocks, wood residues, and construction/demolition waste, it is assumed that these 

are strictly waste products. As such, their life cycle begins at the waste pile and they do not 

receive any energy or GHG burdens from the upstream processes from which they are generated.

Feedstock Harvesting, Preprocessing, and Transportation

Jacobson et al. (2014) has estimated the GHG emissions associated with the logistics required for 

production of a conversion reactor-ready 2017 design case feedstock blend at 75.91 kg CO2-

e/dry ton. This value includes energy and emissions associated with harvesting of purpose-grown 

crops (pulpwood, switchgrass), collection of waste (wood residues, construction and demolition

waste), preprocessing and handling required at the landing, centralized feedstock processing 
98

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

facility (depot) and the biorefinery, and transportation of biomass from the landing to the depot 

and from the depot to the biorefinery. About 70% of the feedstock logistics GHGs stems from 

preprocessing of the feedstock materials. The 2017 feedstock supply chain design incorporates 

several research advances that will significantly reduce energy use and cost compared to the 

current state of technology. More detail on the individual process steps and associated energy 

requirements for the feedstock supply system can be found in the recent design report published 

by INL (Jacobson et al. 2014). The aggregated value of 75.91 kg CO2-e/dry ton of conversion 

plant feedstock was used in the SimaPro model for calculation of the full fuel lifecycle 

emissions. 

Conversion

The inventory for the conversion stages of the life cycle are listed in Table 23 and Table 24. 

Assumptions for the conversion stage processes are given in Section 3.12.

Fuel Distribution and Consumption

Emissions associated with fuel distribution to the end user (fuel transportation and operation of 

storage tanks and fueling stations) are modeled using an EcoInvent database (2010) process 

(“petrol, unleaded, at refinery/kg/RER/U”). Emissions of biogenic methane and N2O from 

combustion of gasoline and diesel fuel in a vehicle are adapted from GREET (2014). 

Life Cycle GHG Results

Figure E-1 shows the full life-cycle GHGs for gasoline and diesel fuel via the catalytic pyrolysis 

and upgrading pathways (including electricity credits). For the in situ case, emissions are 

estimated at 9.2 g CO2e/MJ for gasoline and 9.3 g CO2e/MJ for diesel. Relative to the 2005 

petroleum baseline GHGs (93.08 g CO2e/MJ for gasoline and 91.94 g CO2e/MJ for diesel) (EPA 

2010), this is a GHG reduction of 90% and 89% for gasoline and diesel, respectively. For the ex 

situ case, emissions are estimated at 10.2 g CO2e/MJ for gasoline and 10.3 g CO2e/MJ for diesel, 

corresponding to a GHG reduction of 89% for both fuels. This preliminary analysis suggests that 

these fuels would meet the Energy Independence and Security Act Renewable Fuel Standard

cellulosic biofuel definition (60% GHG reduction); however, final qualification is made by the 

EPA based on their own analysis and determination. In addition, through collaboration with 

Argonne National Laboratory, conversion energy and materials inventory from this work will be 

integrated into the GREET model for more detailed analyses.
99

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Figure E-1. Life-cycle GHG emissions for fuels from catalytic pyrolysis using the INL 2017 blended 

feedstock (45% pulpwood, 32% wood residues, 3% switchgrass, and 20% construction and 

demolition waste) (Jacobson 2014)

Appendix E References

Ecoinvent, v.2.2. (2010). Duebendorf, Switzerland: Swiss Center for Life Cycle Inventories.

“GREET Model, The Greenhouse Gases, Regulated Emissions, and Energy Use in 

Transportation Model.” (2014). Argonne National Laboratory.

Jacobson, J.J.; Cafferty, K.; Roni, M.S.; Lamers, P.; Kenney, K. (2014). Feedstock and 

Conversion Supply System Design and Analysis - The Feedstock Logistics Design Case. 

INL/EXT-14-33227. Idaho Falls, ID: Idaho National Laboratory.

U.S. EPA. (2010). “Fuel-Specific Lifecycle Greenhouse Gas Emissions Results.” Docket # EPAHQ-OAR-2005-0161-3173. Washington, DC: U.S. Environmental Protection Agency. Accessed 

from: http://www.regulations.gov/#!documentDetail;D=EPA-HQ-OAR-2005-0161-3173.

Wang, Z.; Dunn, J.; Han, J.; Wang, M. (2013). Material and Energy Flows in the Production of 

Cellulosic Feedstocks for Biofuels for the GREET Model. ANL/ESD-13/9. Chicago, IL: Argonne 

National Laboratory.

InSitu

Gasoline InSitu Diesel ExSituGasoline

ExSitu

Diesel

Fuel Use 0.47 0.58 0.47 0.58

Fuel Distribution 0.75 0.74 0.74 0.74

Conversion -2.62 -2.62 -1.21 -1.21

Harvest, Collection and

Preprocessing 8.28 8.28 7.95 7.95

Crop Establishment and

Growing 2.3 2.3 2.2 2.2

Total 9.2 9.3 10.2 10.3

-6

-4

-2

0

2

4

6

8

10

12

GHGs, g CO2-e/MJ
100

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Appendix F. Compounds in Aspen Plus Simulation

This appendix provides information about compounds selected to represent the process in Aspen 

Plus. Note that these are model compounds used to represent a much more numerous and varied 

set that actually occurs in systems such as these.

Table F-1. Compounds in Aspen Plus Simulation

Argon 1,2-Benzenediol 1-Naphthalenol

Nitrogen Hydroxymethylfurfural Coniferyl Aldehyde

Oxygen 2,5-dimethylfuran Tetralin

SO2 Methyl Cyclopentenone Isoeugenol

NO2 Hydroxymethylcyclopentenone Decalin

Hydrogen Cyclohexanone 2,5-Dimethyloctane

Ammonia Levoglucosan 1-Methyl naphthalene

H2S 1-Hexanal 1-methyl decahydronaphthene

Water Dimethoxytetrahydrofuran Dibenzothiophene

Carbon Monoxide Cyclohexane Biphenyl

Carbon Dioxide N-Hexane 5-hexyl-O-cresol

Methane Hexanol n-Heptylcyclohexane

Methanol Toluene C14H20-N35

Formic Acid 2-Methylphenol C14H24-N5

Glyoxal 3-Methyl-phenol 3,5-Dimethyldodecane

Ethylene Guaiacol C15H26-N4

Acetaldehyde Methyl-Cyclohexane 6,8-Dimethyltridecane

Hydroxyacetaldehyde 2-Methylhexane 1,4-Dimethyl-Phenanthrene

Acetic Acid VinylPhenol N-Cetane

Ethane O-Xylene C18H26O

Propylene Ethylbenzne C18H28

1-Hydroxy-2-propanone 2,3-Dimethyl-phenol C21H26O2

Propionic Acid 2,6-dimethoxyphenol C21H34

Propane Vanillyl alcohol C22H28O2

Furan 2,4,6-Trimethylpyridine Carbon

1-Butene Cis-1,2-dimethyl cyclohexane Sulfur

Tetrahydrofuran Trans-1,2-dimethylcyclohexane Sand/Catalyst Solids

N-Butane Ethylcyclohexane Ash

Furfural 4-Methylheptane Wood

2-methylfuran 2-Methyl-Benzofuran Char

Furfuryl Alcohol Indane Coke

n-Pentane 2-methoxy-4-vinylphenol

Pentenone Syringaldehyde

Benzene n-Propylbenzene

Phenol Naphthalene
101

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Table F-2. Structures of Compounds Identified by Formula

C14H20-N35

C14H24-N5

C15H26-N4

C18H26O

C18H28

C21H26O2

C21H34

C22H28O2

Table F-3. Ultimate Analysis of Non-Conventional Components

Char Coke

Ash 7.67 0

Carbon 69.07 96.06

Hydrogen 4.66 0

Nitrogen 1.24 0

Chlorine 0 0

Sulfur 0.19 0

Oxygen 17.16 3.94
102

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Appendix G-1. Process Flow Diagrams and Stream 

Summary for the In Situ Case
Rev:

1

Project No: Drawing:

30482.00 PFD-61712-A101

THERMOCHEMICAL CONVERSION OF BIOMASS

TO HYDROCARBON FUEL

CATALYTIC FAST PYROLYSIS

PROCESS FLOW DIAGRAM

AREA 100: FEED HANDLING

Rev. Date By Description

J:\1A - Process Solutions\30482 NREL Thermochemical Conv - Design-Model\Drawings\ Plot date: 1/29/2015

BIOMASS

TO C-104

PFD-61712-A102

BIOMASS

T-103

101

METAL DEBRIS TO

DISPOSAL

CHIP PILE M-103

C-103

S-102

C-102

C-101

T-101

M-101

M-101

HYDRAULIC TRUCK

DUMP WITH SCALE

C-102

SCREENER FEEDER

CONVEYOR

C-101

HOPPER FEEDER

T-101

DUMP HOPPER

S-101

MAGNETIC

HEAD PULLEY

S-102

VIBRATORY

CONVEYOR

C-103

RADIAL STACKER

CONVEYOR

M-103

FRONT END

LOADERS

T-103

DRYER FEED

BIN

S-101

30482 Pyrolysis In-Situ PFDs 61712 150128.vsd

0 9/29/14 JAR ISSUED FOR DESIGN REPORT

NOTE: FEEDSTOCK HANDLING COSTS ARE INCLUDED IN THE TARGET FEEDSTOCK COST PROVIDED BY THE IDAHO NATIONAL

LABORATORY. ONLY A CROSS FLOW DRYER USING PROCESS FLUE GASES FOR FEED PREHEAT IS INCLUDED IN THE CONVERSION COST.

1 12/12/14 DMS UPDATED EQ NUMBERS

103
PFD‐61712‐A101 101 

Total Flow lb/h 204,131 000000000000000000000Temperature F 60 000000000000000000000Pressure Psia 15 000000000000000000000Vapor Fraction 0000000000000000000000Enthalpy Flow MMBtu/h ‐569 000000000000000000000Argon lb/h 0000000000000000000000Nitrogen lb/h 0000000000000000000000Oxygen lb/h 0000000000000000000000SO2 lb/h 0000000000000000000000NO2 lb/h 0000000000000000000000Hydrogen lb/h 0000000000000000000000Ammonia lb/h 0000000000000000000000H2S lb/h 0000000000000000000000Water lb/h 20,413 000000000000000000000Carbon Monoxide lb/h 0000000000000000000000Carbon Dioxide lb/h 0000000000000000000000Methane lb/h 0000000000000000000000Methanol lb/h 0000000000000000000000Formic Acid lb/h 0000000000000000000000Glyoxal lb/h 0000000000000000000000Ethylene lb/h 0000000000000000000000Acetaldehyde lb/h 0000000000000000000000Hydroxyacetaldehyde lb/h 0000000000000000000000Acetic Acid lb/h 0000000000000000000000Ethane lb/h 0000000000000000000000Propylene lb/h 00000000000000000000001‐Hydroxy‐2‐propanone lb/h 0000000000000000000000Propionic Acid lb/h 0000000000000000000000Propane lb/h 0000000000000000000000Furan lb/h 00000000000000000000001‐Butene lb/h 0000000000000000000000Tetrahydrofuran lb/h 0000000000000000000000N‐Butane lb/h 0000000000000000000000Furfural lb/h 00000000000000000000002‐methylfuran lb/h 0000000000000000000000Furfuryl Alcohol lb/h 0000000000000000000000n‐Pentane lb/h 0000000000000000000000Pentenone lb/h 0000000000000000000000Benzene lb/h 0000000000000000000000Phenol lb/h 00000000000000000000001,2‐Benzenediol lb/h 0000000000000000000000Hydroxymethylfurfural lb/h 00000000000000000000002,5‐dimethylfuran lb/h 0000000000000000000000Methyl Cyclopentenone lb/h 0000000000000000000000Hydroxymethylcyclopentenone lb/h 0000000000000000000000Cyclohexanone lb/h 0000000000000000000000Levoglucosan lb/h 00000000000000000000001‐Hexanal lb/h 0000000000000000000000Dimethoxytetrahydrofuran lb/h 0000000000000000000000Cyclohexane lb/h 0000000000000000000000N‐Hexane lb/h 0000000000000000000000Hexanol lb/h 0000000000000000000000Toluene lb/h 00000000000000000000002‐Methylphenol lb/h 00000000000000000000003‐Methyl‐phenol lb/h 0000000000000000000000Guaiacol lb/h 0000000000000000000000Methyl‐Cyclohexane lb/h 00000000000000000000002‐Methylhexane lb/h 0000000000000000000000VinylPhenol lb/h 0000000000000000000000O‐Xylene lb/h 0000000000000000000000Ethylbenzne lb/h 00000000000000000000002,3‐Dimethyl‐phenol lb/h 00000000000000000000002,6‐dimethoxyphenol lb/h 0000000000000000000000Vanillyl alcohol lb/h 00000000000000000000002,4,6‐Trimethylpyridine lb/h 0000000000000000000000Cis‐1,2‐dimethyl cyclohexane lb/h 0000000000000000000000Trans‐1,2‐dimethylcyclohexane lb/h 0000000000000000000000Ethylcyclohexane lb/h 00000000000000000000004‐Methylheptane lb/h 00000000000000000000002‐Methyl‐Benzofuran lb/h 0000000000000000000000Indane lb/h 00000000000000000000002‐methoxy‐4‐vinylphenol lb/h 0000000000000000000000Syringaldehyde lb/h 0000000000000000000000n‐Propylbenzene lb/h 0000000000000000000000Naphthalene lb/h 00000000000000000000001‐Naphthalenol lb/h 0000000000000000000000Coniferyl Aldehyde lb/h 0000000000000000000000Tetralin lb/h 0000000000000000000000Isoeugenol lb/h 0000000000000000000000Decalin lb/h 00000000000000000000002,5‐Dimethyloctane lb/h 00000000000000000000001‐Methyl naphthalene lb/h 00000000000000000000001‐methyl decahydronaphthene lb/h 0000000000000000000000Dibenzothiophene lb/h 0000000000000000000000Biphenyl lb/h 00000000000000000000005‐hexyl‐O‐cresol lb/h 0000000000000000000000n‐Heptylcyclohexane lb/h 0000000000000000000000C14H20‐N35 lb/h 0000000000000000000000C14H24‐N5 lb/h 00000000000000000000003,5‐Dimethyldodecane lb/h 0000000000000000000000C15H26‐N4 lb/h 00000000000000000000006,8‐Dimethyltridecane lb/h 00000000000000000000001,4‐Dimethyl‐Phenanthrene lb/h 0000000000000000000000N‐Cetane lb/h 0000000000000000000000C18H26O lb/h 0000000000000000000000C18H28 lb/h 0000000000000000000000C21H26O2 lb/h 0000000000000000000000C21H34 lb/h 0000000000000000000000C22H28O2 lb/h 0000000000000000000000Carbon lb/h 0000000000000000000000Sulfur lb/h 0000000000000000000000Sand/Catalyst Solids lb/h 0000000000000000000000Ash lb/h 0 000000000000000000000Wood lb/h 183,718 000000000000000000000Char lb/h 0 000000000000000000000Coke lb/h 0 000000000000000000000

104
BIOMASS

FROM T-103

PFD-61712-A101

Rev:

2

Project No: Drawing:

30482.00 PFD-61712-A102

THERMOCHEMICAL CONVERSION OF BIOMASS

TO HYDROCARBON FUEL

CATALYTIC FAST PYROLYSIS

PROCESS FLOW DIAGRAM

AREA 100: FEED HANDLING AND DRYING

Rev. Date By Description

J:\1A - Process Solutions\30482 NREL Thermochemical Conv - Design-Model\Drawings\ Plot date: 1/29/2015

FLUE GAS

TO M-703

PFD-61712-A701

C-104

FLUE GAS

FROM R-530

PFD-61712-A501

M-104

T-104

T-105

T-106

K-101

110

101 103

C-104

DRYER FEED SCREW

CONVEYOR

M-104

CROSS FLOW

PELLET DRYER

T-104

DRIED BIOMASS

HOPPER

T-105

LOCK

HOPPER

T-106

FEED

HOPPER

K-101

FLUE GAS

BLOWER

104

107

108

102

FLUE GAS

FROM H-838

PFD-61712-A802

549

841

30482 Pyrolysis In-Situ PFDs 61712 150128.vsd

0 9/29/14 JAR ISSUED FOR DESIGN REPORT

M-102

T-102

M-102

HAMMERMILL

T-102

HAMMERMILL

SURGE BIN

105

C-105

BIOMASS FEED

SCREW CONVEYOR

C-105

MILLED BIOMASS

TO R-201

PFD-61712-A201

FLUE GAS

FROM H-208

PFD-61712-A201

239

NOTE: FEEDSTOCK HANDLING COSTS ARE INCLUDED IN THE TARGET FEEDSTOCK COST PROVIDED BY THE IDAHO NATIONAL

LABORATORY. ONLY A CROSS FLOW DRYER USING PROCESS FLUE GASES FOR FEED PREHEAT IS INCLUDED IN THE CONVERSION COST.

PRESSURIZED INERT

GASES

W-K101

1 12/12/14 DMS UPDATED EQ NUMBERS 2 12/29/14 JAR MINOR UPDATES

105
PFD‐61712‐A102 101 102 103 104 105 107 108 110 239 297 549 841 

Total Flow lb/h 204,131 204,131 204,131 204,131 204,131 883,124 883,124 883,124 470,563 210,273 239,418 173,143 0000000000Temperature F 60 60 218 218 218 228 155 155 229 229 229 229 0000000000Pressure Psia 15 16 16 16 125 15 14 14 109 105 15 17 0000000000Vapor Fraction 00000 1111111 0000000000Enthalpy Flow MMBtu/h ‐569 ‐569 ‐553 ‐553 ‐553 ‐1039 ‐1056 ‐1056 ‐501 ‐213 ‐476 ‐63 0000000000Argon lb/h 00000 9,581 9,581 9,581 5,499 2,470 1,975 2,108 0000000000Nitrogen lb/h 00000 562,024 562,024 562,024 322,673 144,835 115,770 123,581 0000000000Oxygen lb/h 00000 57,307 57,307 57,307 16,464 7,396 7,234 33,609 0000000000SO2 lb/h 00000 106 106 106 85 0 21 00000000000NO2 lb/h 00000 13 13 13 0 0 13 00000000000Hydrogen lb/h 0000000000000000000000Ammonia lb/h 0000000000000000000000H2S lb/h 0000000000000000000000Water lb/h 20,413 20,413 20,413 20,413 20,413 49,518 49,518 49,518 17,679 3,817 23,478 8,361 0000000000Carbon Monoxide lb/h 0000000000000000000000Carbon Dioxide lb/h 00000 204,575 204,575 204,575 108,164 51,754 90,926 5,485 0000000000Methane lb/h 0000000000000000000000Methanol lb/h 0000000000000000000000Formic Acid lb/h 0000000000000000000000Glyoxal lb/h 0000000000000000000000Ethylene lb/h 0000000000000000000000Acetaldehyde lb/h 0000000000000000000000Hydroxyacetaldehyde lb/h 0000000000000000000000Acetic Acid lb/h 0000000000000000000000Ethane lb/h 0000000000000000000000Propylene lb/h 00000000000000000000001‐Hydroxy‐2‐propanone lb/h 0000000000000000000000Propionic Acid lb/h 0000000000000000000000Propane lb/h 0000000000000000000000Furan lb/h 00000000000000000000001‐Butene lb/h 0000000000000000000000Tetrahydrofuran lb/h 0000000000000000000000N‐Butane lb/h 0000000000000000000000Furfural lb/h 00000000000000000000002‐methylfuran lb/h 0000000000000000000000Furfuryl Alcohol lb/h 0000000000000000000000n‐Pentane lb/h 0000000000000000000000Pentenone lb/h 0000000000000000000000Benzene lb/h 0000000000000000000000Phenol lb/h 00000000000000000000001,2‐Benzenediol lb/h 0000000000000000000000Hydroxymethylfurfural lb/h 00000000000000000000002,5‐dimethylfuran lb/h 0000000000000000000000Methyl Cyclopentenone lb/h 0000000000000000000000Hydroxymethylcyclopentenone lb/h 0000000000000000000000Cyclohexanone lb/h 0000000000000000000000Levoglucosan lb/h 00000000000000000000001‐Hexanal lb/h 0000000000000000000000Dimethoxytetrahydrofuran lb/h 0000000000000000000000Cyclohexane lb/h 0000000000000000000000N‐Hexane lb/h 0000000000000000000000Hexanol lb/h 0000000000000000000000Toluene lb/h 00000000000000000000002‐Methylphenol lb/h 00000000000000000000003‐Methyl‐phenol lb/h 0000000000000000000000Guaiacol lb/h 0000000000000000000000Methyl‐Cyclohexane lb/h 00000000000000000000002‐Methylhexane lb/h 0000000000000000000000VinylPhenol lb/h 0000000000000000000000O‐Xylene lb/h 0000000000000000000000Ethylbenzne lb/h 00000000000000000000002,3‐Dimethyl‐phenol lb/h 00000000000000000000002,6‐dimethoxyphenol lb/h 0000000000000000000000Vanillyl alcohol lb/h 00000000000000000000002,4,6‐Trimethylpyridine lb/h 0000000000000000000000Cis‐1,2‐dimethyl cyclohexane lb/h 0000000000000000000000Trans‐1,2‐dimethylcyclohexane lb/h 0000000000000000000000Ethylcyclohexane lb/h 00000000000000000000004‐Methylheptane lb/h 00000000000000000000002‐Methyl‐Benzofuran lb/h 0000000000000000000000Indane lb/h 00000000000000000000002‐methoxy‐4‐vinylphenol lb/h 0000000000000000000000Syringaldehyde lb/h 0000000000000000000000n‐Propylbenzene lb/h 0000000000000000000000Naphthalene lb/h 00000000000000000000001‐Naphthalenol lb/h 0000000000000000000000Coniferyl Aldehyde lb/h 0000000000000000000000Tetralin lb/h 0000000000000000000000Isoeugenol lb/h 0000000000000000000000Decalin lb/h 00000000000000000000002,5‐Dimethyloctane lb/h 00000000000000000000001‐Methyl naphthalene lb/h 00000000000000000000001‐methyl decahydronaphthene lb/h 0000000000000000000000Dibenzothiophene lb/h 0000000000000000000000Biphenyl lb/h 00000000000000000000005‐hexyl‐O‐cresol lb/h 0000000000000000000000n‐Heptylcyclohexane lb/h 0000000000000000000000C14H20‐N35 lb/h 0000000000000000000000C14H24‐N5 lb/h 00000000000000000000003,5‐Dimethyldodecane lb/h 0000000000000000000000C15H26‐N4 lb/h 00000000000000000000006,8‐Dimethyltridecane lb/h 00000000000000000000001,4‐Dimethyl‐Phenanthrene lb/h 0000000000000000000000N‐Cetane lb/h 0000000000000000000000C18H26O lb/h 0000000000000000000000C18H28 lb/h 0000000000000000000000C21H26O2 lb/h 0000000000000000000000C21H34 lb/h 0000000000000000000000C22H28O2 lb/h 0000000000000000000000Carbon lb/h 0000000000000000000000Sulfur lb/h 0000000000000000000000Sand/Catalyst Solids lb/h 0000000000000000000000Ash lb/h 00000 00000000000000000Wood lb/h 183,718 183,718 183,718 183,718 183,718 00000000000000000Char lb/h 00000 00000000000000000Coke lb/h 00000 00000000000000000

106
R-201

Rev:

2

Project No: Drawing:

30482.00 PFD-61712-A201

THERMOCHEMICAL CONVERSION OF BIOMASS

TO HYDROCARBON FUEL

CATALYTIC FAST PYROLYSIS

PROCESS FLOW DIAGRAM

AREA 200: IN-SITU PYROLYSIS

MILLED BIOMASS

FROM C-105

PFD-61712-A102

S-201

T-201

J:\1A - Process Solutions\30482 NREL Thermochemical Conv - Design-Model\Drawings\

S-202

R-202

S-203

T-202

DEPLETED CATALYST/

ASH

TO DISPOSAL

PYROLYSIS VAPOR

TO H-310

PFD-61712-A301

FLUE GAS

TO M-104

PFD-61712-A102

COMBUSTION

AIR

S-204

30482 Pyrolysis In-Situ PFDs 61712 150316.vsd Plot date: 3/16/2015

Rev. Date By Description

0 9/29/14 JAR ISSUED FOR DESIGN REPORT

R-202C

LIFT AIR

FLUIDIZATION

AIR

MAKEUP CATALYST

FROM M-702

PFD-61712-A702

T-207

H-208

H-201

Q-H201

C-202

QC-M202

H-209

W-K202

Q-H209 Q-H208

223 224 225A

346

203

204

214

208

213

300

232

228

233

235

239

212

K-202

COMBUSTOR AIR

COMPRESSOR

H-209

AIR

PREHEATER

R-201

CATALYTIC FLUIDIZED

BED REACTOR

S-201

PRIMARY

CYCLONE

S-202

SECONDARY

CYCLONE

T-201

CATALYST

STEAM STRIPPER

R-202

CHAR COMBUSTOR

S-203

CHAR COMBUSTOR

PRIMARY CYCLONE

S-204

CHAR COMBUSTOR

SECONDARY CYCLONE

T-202

DEPLETED CATALYST AND

ASH STORAGE BIN

T-207

CATALYST

FEED BIN

H-208

FLUE GAS HEAT

RECOVERY

R-202C

CATALYST

COOLER

C-202

FINES PURGE

COOLER

105

K-201

FLUIDIZING GAS

RECYCLE COMPRESSOR

H-201

FLUIDIZING GAS

HEATER

STEAM

TO T-605

PFD-61712-A-603

CLEAN WATER

FROM P-802

PFD-61712-A804

QA-K202

Q-ST202A

H-210

210

Q-H210

210B

H-210C

STEAM STRIPPER

SUPERHEATER

H-210B

STEAM STRIPPER

BOILER

FLUIDIZING GAS

FROM M-385/M-575/H-315

PFD-61712-A302

K-202

W-K201

K-201

1 12/12/14 DMS UPDATED EQ NUMBERS

2 12/29/14 JAR MINOR UPDATES

NOTE: STREAM 217 FOR ATTRITION MAKEUP. ADDITIONAL MAKEUP TO

MAINTAIN ACTIVITY AS IN TABLE 4. 1

1

217

205

107
PFD‐61712‐A201 105 203 204 205 208 210 210B 212 213 214 216 217 223 224 225A 228 232 233 235 239 300 346 

Total Flow lb/h 204,131 157,697 157,697 1,383,822 1,745,651 4,151 4,151 1,749,802 330,867 1,418,935 1,736 152 435,390 435,390 435,390 472,391 470,563 1,828 2,032 470,563 329,131 157,697 Temperature F 218 149 800 0 932 555 61 931 931 000 90 288 600 1202 1202 0 209 229 931 96 Pressure Psia 125 127 123 125 121 135 150 121 120 120 119 129 15 125 121 115 115 115 15 109 119 99 Vapor Fraction 0 1 1 0 1 1 0 1 1 000 11111 0 0 111 Enthalpy Flow MMBtu/h ‐553 ‐279 ‐203 ‐8619 ‐9389 ‐23 ‐29 ‐9412 ‐691 ‐8722 ‐9 ‐1 ‐49 ‐28 7 ‐379 ‐378 ‐1 ‐3 ‐501 ‐682 ‐285 Argon lb/h 000000000000 5,499 5,499 5,499 5,499 5,499 0 0 5,499 00Nitrogen lb/h 000000000000 322,398 322,398 322,398 322,673 322,673 0 0 322,673 00Oxygen lb/h 000000000000 98,783 98,783 98,783 16,464 16,464 0 0 16,464 00SO2 lb/h 000000000000000 85 85 0 0 85 00NO2 lb/h 0000000000000000000000Hydrogen lb/h 0 20,716 20,716 0 18,312 0 0 18,312 18,312 00000000000 18,312 20,716 Ammonia lb/h 0000000000000000000000H2S lb/h 0000000000000000000000Water lb/h 20,413 457 457 0 71,025 4,151 4,151 75,176 75,176 000 8,495 8,495 8,495 17,679 17,679 0 203 17,679 75,176 457 Carbon Monoxide lb/h 0 57,939 57,939 0 76,820 0 0 76,820 76,820 00000000000 76,820 57,939 Carbon Dioxide lb/h 0 48,481 48,481 0 63,964 0 0 63,964 63,964 000 214 214 214 108,164 108,164 0 0 108,164 63,964 48,481 Methane lb/h 0 5,265 5,265 0 7,043 0 0 7,043 7,043 00000000000 7,043 5,265 Methanol lb/h 0000000000000000000000Formic Acid lb/h 0000000000000000000000Glyoxal lb/h 0000000000000000000000Ethylene lb/h 0 14,862 14,862 0 19,913 0 0 19,913 19,913 00000000000 19,913 14,862 Acetaldehyde lb/h 0000000000000000000000Hydroxyacetaldehyde lb/h 0000000000000000000000Acetic Acid lb/h 0000000000000000000000Ethane lb/h 0000000000000000000000Propylene lb/h 0 4,839 4,839 0 6,539 0 0 6,539 6,539 00000000000 6,539 4,839 1‐Hydroxy‐2‐propanone lb/h 0000000000000000000000Propionic Acid lb/h 0000000000000000000000Propane lb/h 0000000000000000000000Furan lb/h 0 528 528 0 873 0 0 873 873 00000000000 873 528 1‐Butene lb/h 0 2,338 2,338 0 3,282 0 0 3,282 3,282 00000000000 3,282 2,338 Tetrahydrofuran lb/h 0 398 398 0 1,022 0 0 1,022 1,022 00000000000 1,022 398 N‐Butane lb/h 0000000000000000000000Furfural lb/h 00000000000000000000002‐methylfuran lb/h 0 452 452 0 1,131 0 0 1,131 1,131 00000000000 1,131 452 Furfuryl Alcohol lb/h 0000000000000000000000n‐Pentane lb/h 0000000000000000000000Pentenone lb/h 0000000000000000000000Benzene lb/h 0000000000000000000000Phenol lb/h 0 15 15 0 3,570 0 0 3,570 3,570 00000000000 3,570 15 1,2‐Benzenediol lb/h 0 0 0 0 3,193 0 0 3,193 3,193 00000000000 3,193 0 Hydroxymethylfurfural lb/h 00000000000000000000002,5‐dimethylfuran lb/h 0 2 2 0 13 0 0 13 13 00000000000 13 2 Methyl Cyclopentenone lb/h 0000000000000000000000Hydroxymethylcyclopentenone lb/h 0000000000000000000000Cyclohexanone lb/h 0000000000000000000000Levoglucosan lb/h 00000000000000000000001‐Hexanal lb/h 0000000000000000000000Dimethoxytetrahydrofuran lb/h 0 1 1 0 38 0 0 38 38 00000000000 38 1 Cyclohexane lb/h 0 14 14 0 46 0 0 46 46 00000000000 46 14 N‐Hexane lb/h 0000000000000000000000Hexanol lb/h 0000000000000000000000Toluene lb/h 00000000000000000000002‐Methylphenol lb/h 0 5 5 0 2,385 0 0 2,385 2,385 00000000000 2,385 5 3‐Methyl‐phenol lb/h 0000000000000000000000Guaiacol lb/h 0 0 0 0 1 0 0 1 1 00000000000 1 0 Methyl‐Cyclohexane lb/h 0 194 194 0 991 0 0 991 991 00000000000 991 194 2‐Methylhexane lb/h 0000000000000000000000VinylPhenol lb/h 0 0 0 0 1 0 0 1 1 00000000000 1 0 O‐Xylene lb/h 0000000000000000000000Ethylbenzne lb/h 00000000000000000000002,3‐Dimethyl‐phenol lb/h 0 1 1 0 2,065 0 0 2,065 2,065 00000000000 2,065 1 2,6‐dimethoxyphenol lb/h 0 1 1 0 6,794 0 0 6,794 6,794 00000000000 6,794 1 Vanillyl alcohol lb/h 0 0 0 0 870 0 0 870 870 00000000000 870 0 2,4,6‐Trimethylpyridine lb/h 0 3 3 0 333 0 0 333 333 00000000000 333 3 Cis‐1,2‐dimethyl cyclohexane lb/h 0 529 529 0 5,174 0 0 5,174 5,174 00000000000 5,174 529 Trans‐1,2‐dimethylcyclohexane lb/h 0 635 635 0 5,138 0 0 5,138 5,138 00000000000 5,138 635 Ethylcyclohexane lb/h 00000000000000000000004‐Methylheptane lb/h 00000000000000000000002‐Methyl‐Benzofuran lb/h 0 1 1 0 463 0 0 463 463 00000000000 463 1 Indane lb/h 00000000000000000000002‐methoxy‐4‐vinylphenol lb/h 0 0 0 0 13 0 0 13 13 00000000000 13 0 Syringaldehyde lb/h 0000000000000000000000n‐Propylbenzene lb/h 0000000000000000000000Naphthalene lb/h 00000000000000000000001‐Naphthalenol lb/h 0 0 0 0 2,705 0 0 2,705 2,705 00000000000 2,705 0 Coniferyl Aldehyde lb/h 0 0 0 0 381 0 0 381 381 00000000000 381 0 Tetralin lb/h 0000000000000000000000Isoeugenol lb/h 0 0 0 0 13 0 0 13 13 00000000000 13 0 Decalin lb/h 0 16 16 0 2,102 0 0 2,102 2,102 00000000000 2,102 16 2,5‐Dimethyloctane lb/h 00000000000000000000001‐Methyl naphthalene lb/h 0 0 0 0 1,183 0 0 1,183 1,183 00000000000 1,183 0 1‐methyl decahydronaphthene lb/h 0 5 5 0 1,499 0 0 1,499 1,499 00000000000 1,499 5 Dibenzothiophene lb/h 0 0 0 0 73 0 0 73 73 00000000000 73 0 Biphenyl lb/h 00000000000000000000005‐hexyl‐O‐cresol lb/h 0 0 0 0 0 0 0 0 0 00000000000 0 0 n‐Heptylcyclohexane lb/h 0000000000000000000000C14H20‐N35 lb/h 0000000000000000000000C14H24‐N5 lb/h 0 0 0 0 917 0 0 917 917 00000000000 917 0 3,5‐Dimethyldodecane lb/h 0000000000000000000000C15H26‐N4 lb/h 0 0 0 0 984 0 0 984 984 00000000000 984 0 6,8‐Dimethyltridecane lb/h 00000000000000000000001,4‐Dimethyl‐Phenanthrene lb/h 0 0 0 0 427 0 0 427 427 00000000000 427 0 N‐Cetane lb/h 0000000000000000000000C18H26O lb/h 0 0 0 0 299 0 0 299 299 00000000000 299 0 C18H28 lb/h 0000000000000000000000C21H26O2 lb/h 0 0 0 0 3,424 0 0 3,424 3,424 00000000000 3,424 0 C21H34 lb/h 0 0 0 0 7,087 0 0 7,087 7,087 00000000000 7,087 0 C22H28O2 lb/h 0 0 0 0 2,855 0 0 2,855 2,855 00000000000 2,855 0 Carbon lb/h 0000000000000000000000Sulfur lb/h 0000000000000000000000Sand/Catalyst Solids lb/h 000 1,383,733 1,383,733 0 0 1,383,733 1,384 1,382,349 1,370 152 000 138 0 138 138 0 14 0Ash lb/h 0 0 0 89 89 0 0 89 1 88 1 0000 1,690 0 1,690 1,690 0 0 0Wood lb/h 183,718 000 0 0 0 0000 000000000 0 0Char lb/h 0 000 22,046 0 0 22,046 220 21,826 218 000000000 2 0Coke lb/h 0 000 14,820 0 0 14,820 148 14,672 147 000000000 1 0

108
Rev:

1

Project No: Drawing:

30482.00 PFD-61712-A301

THERMOCHEMICAL CONVERSION OF BIOMASS

TO HYDROCARBON FUEL

CATALYTIC FAST PYROLYSIS

PROCESS FLOW DIAGRAM

AREA 300: CONDENSATION STAGE 1

Rev. Date By Description

0

H-310

Q-H310

PYROLYSIS VAPOR 311

FROM S-202/T-201

PFD-61712-A201

300

J:\1A - Process Solutions\30482 NREL Thermochemical Conv - Design-Model\Drawings\ Plot date: 1/29/2015 30482 Pyrolysis In-Situ PFDs 61712 150128.vsd

H-312

D-301 VAPOR HEAT

RECOVERY

9/29/14 JAR ISSUED FOR DESIGN REPORT

H-310

PYROLYSIS VAPOR

HEAT RECOVERY

D-301

HEAVY FRACTION

CONDENSER ABSORBER

P-318

D-301 BOTTOMS

PUMP

H-318

D-301 BOTTOMS

HEAT RECOVERY

D-301

P-318

312

H-312

Q-H312 QA-H313

H-313 H-314

QC-H314

H-315

QX-H315

QCH-H316

313 314 315 316 VAPOR PHASE

TO D-302

PFD-61712-A302

317

H-318

Q-H318

SOLIDS

TO M-805

PFD-61712-A302

335A

320

S-319

318 319 320A

QA-H320

H-320

ORGANIC PHASE

TO T-328

PFD-61712-A302

RECYCLED ORGANICS

FROM S-324

PFD-61712-A302

P-332

332

T-332

W-P332

333

H-313

D-301 VAPOR ACHE

S-319

D-301 BOTTOMS

FILTER

H-314

D-302 FEED

COOLER

H-315

D-302 FEED/OVERHEAD

HEAT EXCHANGER

T-332

D-301 CIRCULATION

SURGE TANK

H-316

D-302 LIQUID FEED

CHILLER

P-332

QUENCH RECYCLE

PUMP

H-320

HEAVY FRACTION

ACHE

OFFGAS

FROM D-302

PFD-61712-A302

OFFGAS

TO

PFD-61712-A302

W-P318

321

340

CWS

CWR

H-316 CHWS

CHWR

1 12/12/14 DMS UPDATED EQ NUMBERS

109
PFD‐61712‐A301 300 311 312 313 314 315 316 317 318 319 320 320A 321 332 333 335A 340 

Total Flow lb/h 329,131 329,131 396,315 396,315 396,315 396,315 396,315 396,315 19,547 19,547 19,529 19,529 199,763 86,730 86,730 18 199,763 00000Temperature F 931 466 348 220 140 110 96 60 428 175 175 140 54 85 85 0 95 00000Pressure Psia 119 117 114 112 110 108 106 104 117 127 112 107 101 114 117 127 99 00000Vapor Fraction 111111110 0 0 0 1 000 1 00000Enthalpy Flow MMBtu/h ‐682 ‐773 ‐839 ‐881 ‐955 ‐966 ‐971 ‐981 ‐8 ‐10 ‐10 ‐10 ‐381 ‐73 ‐73 0 ‐376 00000Argon lb/h 0000000000000000000000Nitrogen lb/h 0000000000000000000000Oxygen lb/h 0000000000000000000000SO2 lb/h 0000000000000000000000NO2 lb/h 0000000000000000000000Hydrogen lb/h 18,312 18,312 18,315 18,315 18,315 18,315 18,315 18,315 1111 18,310 3 3 0 18,310 00000Ammonia lb/h 0000000000000000000000H2S lb/h 0000000000000000000000Water lb/h 75,176 75,176 75,716 75,716 75,716 75,716 75,716 75,716 63 63 63 63 611 603 603 0 611 00000Carbon Monoxide lb/h 76,820 76,820 76,842 76,842 76,842 76,842 76,842 76,842 3333 76,807 25 25 0 76,807 00000Carbon Dioxide lb/h 63,964 63,964 64,401 64,401 64,401 64,401 64,401 64,401 9999 63,785 447 447 0 63,785 00000Methane lb/h 7,043 7,043 7,050 7,050 7,050 7,050 7,050 7,050 1111 7,039 8 8 0 7,039 00000Methanol lb/h 0000000000000000000000Formic Acid lb/h 0000000000000000000000Glyoxal lb/h 0000000000000000000000Ethylene lb/h 19,913 19,913 20,015 20,015 20,015 20,015 20,015 20,015 3333 19,871 105 105 0 19,871 00000Acetaldehyde lb/h 0000000000000000000000Hydroxyacetaldehyde lb/h 0000000000000000000000Acetic Acid lb/h 0000000000000000000000Ethane lb/h 0000000000000000000000Propylene lb/h 6,539 6,539 6,715 6,715 6,715 6,715 6,715 6,715 2222 6,470 178 178 0 6,470 000001‐Hydroxy‐2‐propanone lb/h 0000000000000000000000Propionic Acid lb/h 0000000000000000000000Propane lb/h 0000000000000000000000Furan lb/h 873 873 1,317 1,317 1,317 1,317 1,317 1,317 1 1 1 1 705 445 445 0 705 000001‐Butene lb/h 3,282 3,282 3,692 3,692 3,692 3,692 3,692 3,692 2222 3,126 412 412 0 3,126 00000Tetrahydrofuran lb/h 1,022 1,022 2,319 2,319 2,319 2,319 2,319 2,319 2 2 2 2 533 1,299 1,299 0 533 00000N‐Butane lb/h 0000000000000000000000Furfural lb/h 00000000000000000000002‐methylfuran lb/h 1,131 1,131 2,530 2,530 2,530 2,530 2,530 2,530 2 2 2 2 604 1,400 1,400 0 604 00000Furfuryl Alcohol lb/h 0000000000000000000000n‐Pentane lb/h 0000000000000000000000Pentenone lb/h 0000000000000000000000Benzene lb/h 0000000000000000000000Phenol lb/h 3,570 3,570 12,661 12,661 12,661 12,661 12,661 12,661 36 36 36 36 20 9,127 9,127 0 20 000001,2‐Benzenediol lb/h 3,193 3,193 3,617 3,617 3,617 3,617 3,617 3,617 91 91 91 91 0 515 515 0 0 00000Hydroxymethylfurfural lb/h 00000000000000000000002,5‐dimethylfuran lb/h 13 13 42 42 42 42 42 42 0 0 0 0 2 29 29 0 2 00000Methyl Cyclopentenone lb/h 0000000000000000000000Hydroxymethylcyclopentenone lb/h 0000000000000000000000Cyclohexanone lb/h 0000000000000000000000Levoglucosan lb/h 00000000000000000000001‐Hexanal lb/h 0000000000000000000000Dimethoxytetrahydrofuran lb/h 38 38 136 136 136 136 136 136 0 0 0 0 1 98 98 0 1 00000Cyclohexane lb/h 46 46 117 117 117 117 117 117 0 0 0 0 19 71 71 0 19 00000N‐Hexane lb/h 0000000000000000000000Hexanol lb/h 0000000000000000000000Toluene lb/h 00000000000000000000002‐Methylphenol lb/h 2,385 2,385 8,592 8,592 8,592 8,592 8,592 8,592 35 35 35 35 7 6,242 6,242 0 7 000003‐Methyl‐phenol lb/h 0000000000000000000000Guaiacol lb/h 114444440000033 0 0 00000Methyl‐Cyclohexane lb/h 991 991 2,929 2,929 2,929 2,929 2,929 2,929 3 3 3 3 260 1,941 1,941 0 260 000002‐Methylhexane lb/h 0000000000000000000000VinylPhenol lb/h 115555550000033 0 0 00000O‐Xylene lb/h 0000000000000000000000Ethylbenzne lb/h 00000000000000000000002,3‐Dimethyl‐phenol lb/h 2,065 2,065 7,362 7,362 7,362 7,362 7,362 7,362 54 54 54 54 1 5,352 5,352 0 1 000002,6‐dimethoxyphenol lb/h 6,794 6,794 21,053 21,053 21,053 21,053 21,053 21,053 1,049 1,049 1,049 1,049 1 15,308 15,308 0 1 00000Vanillyl alcohol lb/h 870 870 484 484 484 484 484 484 738 738 738 738 0 352 352 0 0 000002,4,6‐Trimethylpyridine lb/h 333 333 1,197 1,197 1,197 1,197 1,197 1,197 4 4 4 4 4 868 868 0 4 00000Cis‐1,2‐dimethyl cyclohexane lb/h 5,174 5,174 16,966 16,966 16,966 16,966 16,966 16,966 30 30 30 30 708 11,822 11,822 0 708 00000Trans‐1,2‐dimethylcyclohexane lb/h 5,138 5,138 16,471 16,471 16,471 16,471 16,471 16,471 26 26 26 26 850 11,359 11,359 0 850 00000Ethylcyclohexane lb/h 00000000000000000000004‐Methylheptane lb/h 00000000000000000000002‐Methyl‐Benzofuran lb/h 463 463 1,656 1,656 1,656 1,656 1,656 1,656 10 10 10 10 1 1,203 1,203 0 1 00000Indane lb/h 00000000000000000000002‐methoxy‐4‐vinylphenol lb/h 13 13 48 48 48 48 48 48 0 0 0 0 0 35 35 0 0 00000Syringaldehyde lb/h 0000000000000000000000n‐Propylbenzene lb/h 0000000000000000000000Naphthalene lb/h 00000000000000000000001‐Naphthalenol lb/h 2,705 2,705 626 626 626 626 626 626 2,534 2,534 2,534 2,534 0 455 455 0 0 00000Coniferyl Aldehyde lb/h 381 381 0 0 0 0 0 0 381 381 381 381 0 0 0 0 0 00000Tetralin lb/h 0000000000000000000000Isoeugenol lb/h 13 13 38 38 38 38 38 38 3 3 3 3 0 28 28 0 0 00000Decalin lb/h 2,102 2,102 7,530 7,530 7,530 7,530 7,530 7,530 32 32 32 32 21 5,460 5,460 0 21 000002,5‐Dimethyloctane lb/h 00000000000000000000001‐Methyl naphthalene lb/h 1,183 1,183 4,041 4,041 4,041 4,041 4,041 4,041 80 80 80 80 0 2,938 2,938 0 0 000001‐methyl decahydronaphthene lb/h 1,499 1,499 5,334 5,334 5,334 5,334 5,334 5,334 38 38 38 38 7 3,874 3,874 0 7 00000Dibenzothiophene lb/h 73 73 0 0 0 0 0 0 73 73 73 73 0 0 0 0 0 00000Biphenyl lb/h 00000000000000000000005‐hexyl‐O‐cresol lb/h 000000000000000 0 0 00000n‐Heptylcyclohexane lb/h 0000000000000000000000C14H20‐N35 lb/h 0000000000000000000000C14H24‐N5 lb/h 917 917 2,958 2,958 2,958 2,958 2,958 2,958 110 110 110 110 0 2,151 2,151 0 0 000003,5‐Dimethyldodecane lb/h 0000000000000000000000C15H26‐N4 lb/h 984 984 3,317 3,317 3,317 3,317 3,317 3,317 79 79 79 79 0 2,412 2,412 0 0 000006,8‐Dimethyltridecane lb/h 00000000000000000000001,4‐Dimethyl‐Phenanthrene lb/h 427 427 0 0 0 0 0 0 427 427 427 427 0 0 0 0 0 00000N‐Cetane lb/h 0000000000000000000000C18H26O lb/h 299 299 0 0 0 0 0 0 299 299 299 299 0 0 0 0 0 00000C18H28 lb/h 0000000000000000000000C21H26O2 lb/h 3,424 3,424 000000 3,424 3,424 3,424 3,424 0 0 0 0 0 00000C21H34 lb/h 7,087 7,087 218 218 218 218 218 218 7,028 7,028 7,028 7,028 0 158 158 0 0 00000C22H28O2 lb/h 2,855 2,855 000000 2,855 2,855 2,855 2,855 0 0 0 0 0 00000Carbon lb/h 0000000000000000000000Sulfur lb/h 0000000000000000000000Sand/Catalyst Solids lb/h 14 14 000000 14 14 00000 14 000000Ash lb/h 0 0 000000 0 0 00000 0 000000Wood lb/h 0 0 000000 0 0 00000 0 000000Char lb/h 2 2 000000 2 2 00000 2 000000Coke lb/h 1 1 000000 1 1 00000 1 000000

110
Rev:

2

Project No: Drawing:

30482.00 PFD-61712-A302

THERMOCHEMICAL CONVERSION OF BIOMASS

TO HYDROCARBON FUEL

CATALYTIC FAST PYROLYSIS

PROCESS FLOW DIAGRAM

AREA 300: CONDENSATION STAGE 2

Rev. Date By Description

0

P-323

OFFGAS

TO H-366

PFD-61712-A303

SOLIDS

TO M-805

PFD-61712-A803

MAKEUP HYDROGEN

FROM M-385/M-575

PFD-61712-A504

PURGE GAS

TO H-513/K-511

PFD-61712-A501

ORGANIC PHASE

TO S-410

PFD-61712-A401

D-302

S-322

QCH-H326

335C

345

343

322

327

325

341

350 346

340

VAPOR PHASE

FROM H-316

PFD-61712-A301

317

J:\1A - Process Solutions\30482 NREL Thermochemical Conv - Design-Model\Drawings\ Plot date: 1/29/2015 30482 Pyrolysis In-Situ PFDs 61712 150128.vsd

321

D-302

LIGHT FRACTION

CONDENSER ABSORBER

9/29/14 JAR ISSUED FOR DESIGN REPORT

FLUIDIZING GAS

TO K-201

PFD-61712-A201

ORGANIC PHASE

FROM H-320

PFD-61712-A301

RECYCLED ORGANICS

TO T-332

PFD-61712-A301

W-P323

324

S-324

332

326

328

T-328

P-331

337

320A

P-329

329

S-329

335B

AQUEOUS PHASE

TO T-810

PFD-61712-A801

SOLIDS 334

FROM S-319

PFD-61712-A301

335A

335

H-326

D-302 QUENCH

CIRCULATION CHILLER

S-322

D-302 BOTTOMS

DECANTER

P-323

CIRCULATION FILTER

CHARGE PUMP

S-324

QUENCH

CIRCULATION FILTER

P-331

ORGANIC

PRODUCT PUMP

T-328

ORGANIC PRODUCT

SURGE TANK

P-329

AQUEOUS FILTER

CHARGE PUMP

S-329

AQUEOUS PHASE

FILTER

OFFGAS

TO H-315

PFD-61712-A301

OFFGAS

FROM H-315

PFD-61712-A301

W-P329

W-P331

CHWS

CHWR

H-326

1 12/12/14 DMS UPDATED EQ NUMBERS

2 12/29/14 JAR MINOR UPDATES

111
PFD‐61712‐A302 317 320A 321 322 323 324 325 326 327 328 329 332 334 335A 335B 335C 335 337 340 341 343 345 

Total Flow lb/h 396,315 19,529 199,763 1,161,420 1,084,143 1,084,143 1,084,123 964,869 964,869 32,524 77,278 86,730 77,273 18 5 20 43 52,053 199,763 149,409 48,356 1,998 Temperature F 60 140 54 85 85 85 85 85 50 85 85 85 85 0 85 85 90 103 95 95 95 95 Pressure Psia 104 107 101 104 104 129 114 114 104 114 104 114 104 127 104 114 104 117 99 99 99 99 Vapor Fraction 1010 000000000000 0 0 1111Enthalpy Flow MMBtu/h ‐981 ‐10 ‐381 ‐1430 ‐917 ‐917 ‐917 ‐816 ‐830 ‐28 ‐513 ‐73 ‐513 0 0 0 0 ‐38 ‐376 ‐281 ‐91 ‐4 Argon lb/h 0000000000000000000000Nitrogen lb/h 0000000000000000000000Oxygen lb/h 0000000000000000000000SO2 lb/h 0000000000000000000000NO2 lb/h 0000000000000000000000Hydrogen lb/h 18,315 1 18,310 40 40 40 40 36 36 1030 0 0002 18,310 13,695 4,432 183 Ammonia lb/h 0000000000000000000000H2S lb/h 0000000000000000000000Water lb/h 75,716 63 611 81,816 7,540 7,540 7,540 6,711 6,711 226 74,276 603 74,271 0 5 0 5 290 611 457 148 6 Carbon Monoxide lb/h 76,842 3 76,807 317 317 317 317 282 282 10 0 25 0 0 0 0 0 13 76,807 57,446 18,593 768 Carbon Dioxide lb/h 64,401 9 63,785 5,585 5,583 5,583 5,583 4,969 4,969 167 2 447 2 0 0 0 0 177 63,785 47,707 15,440 638 Methane lb/h 7,050 1 7,039 99 99 99 99 88 88 3080 0 0004 7,039 5,265 1,704 70 Methanol lb/h 0000000000000000000000Formic Acid lb/h 0000000000000000000000Glyoxal lb/h 0000000000000000000000Ethylene lb/h 20,015 3 19,871 1,316 1,316 1,316 1,316 1,171 1,171 39 0 105 0 0 0 0 0 43 19,871 14,862 4,810 199 Acetaldehyde lb/h 0000000000000000000000Hydroxyacetaldehyde lb/h 0000000000000000000000Acetic Acid lb/h 0000000000000000000000Ethane lb/h 0000000000000000000000Propylene lb/h 6,715 2 6,470 2,229 2,229 2,229 2,229 1,984 1,984 67 0 178 0 0 0 0 0 69 6,470 4,839 1,566 65 1‐Hydroxy‐2‐propanone lb/h 0000000000000000000000Propionic Acid lb/h 0000000000000000000000Propane lb/h 0000000000000000000000Furan lb/h 1,317 1 705 5,558 5,557 5,557 5,557 4,946 4,946 167 0 445 0 0 0 0 0 168 705 528 171 7 1‐Butene lb/h 3,692 2 3,126 5,146 5,146 5,146 5,146 4,580 4,580 154 0 412 0 0 0 0 0 156 3,126 2,338 757 31 Tetrahydrofuran lb/h 2,319 2 533 16,233 16,233 16,233 16,233 14,447 14,447 487 0 1,299 0 0 0 0 0 489 533 398 129 5 N‐Butane lb/h 0000000000000000000000Furfural lb/h 00000000000000000000002‐methylfuran lb/h 2,530 2 604 17,505 17,505 17,505 17,505 15,579 15,579 525 0 1,400 0 0 0 0 0 527 604 452 146 6 Furfuryl Alcohol lb/h 0000000000000000000000n‐Pentane lb/h 0000000000000000000000Pentenone lb/h 0000000000000000000000Benzene lb/h 0000000000000000000000Phenol lb/h 12,661 36 20 114,179 114,090 114,090 114,088 101,538 101,538 3,423 89 9,127 89 0 0 2 2 3,459 20 15 5 0 1,2‐Benzenediol lb/h 3,617 91 0 9,342 6,433 6,433 6,433 5,725 5,725 193 2,909 515 2,909 0 0 0 0 284 0 0 0 0 Hydroxymethylfurfural lb/h 00000000000000000000002,5‐dimethylfuran lb/h 42 0 2 362 362 362 362 322 322 11 0 29 0 0 0 0 0 11 2 2 1 0 Methyl Cyclopentenone lb/h 0000000000000000000000Hydroxymethylcyclopentenone lb/h 0000000000000000000000Cyclohexanone lb/h 0000000000000000000000Levoglucosan lb/h 00000000000000000000001‐Hexanal lb/h 0000000000000000000000Dimethoxytetrahydrofuran lb/h 136 0 1 1,228 1,228 1,228 1,228 1,093 1,093 37 0 98 0 0 0 0 0 37 1 1 0 0 Cyclohexane lb/h 117 0 19 891 891 891 891 793 793 27 0 71 0 0 0 0 0 27 19 14 5 0 N‐Hexane lb/h 0000000000000000000000Hexanol lb/h 0000000000000000000000Toluene lb/h 00000000000000000000002‐Methylphenol lb/h 8,592 35 7 78,022 78,021 78,021 78,019 69,437 69,437 2,341 1 6,242 1 0 0 1 1 2,376 75203‐Methyl‐phenol lb/h 0000000000000000000000Guaiacol lb/h 4 0 0 35 35 35 35 31 31 1 0 3 0 0 00010000Methyl‐Cyclohexane lb/h 2,929 3 260 24,266 24,266 24,266 24,266 21,596 21,596 728 0 1,941 0 0 0 0 0 731 260 194 63 3 2‐Methylhexane lb/h 0000000000000000000000VinylPhenol lb/h 5 0 0 41 41 41 41 37 37 1 0 3 0 0 00010000O‐Xylene lb/h 0000000000000000000000Ethylbenzne lb/h 00000000000000000000002,3‐Dimethyl‐phenol lb/h 7,362 54 1 66,897 66,896 66,896 66,895 59,536 59,536 2,007 1 5,352 1 0 0 1 1 2,061 11002,6‐dimethoxyphenol lb/h 21,053 1,049 1 191,357 191,357 191,357 191,353 170,305 170,305 5,741 0 15,308 0 0 0 4 4 6,790 1100Vanillyl alcohol lb/h 484 738 0 4,400 4,399 4,399 4,399 3,915 3,915 132 0 352 0 0 0 0 0 870 0 0 0 0 2,4,6‐Trimethylpyridine lb/h 1,197 4 4 10,852 10,852 10,852 10,852 9,658 9,658 326 0 868 0 0 0 0 0 330 4 3 1 0 Cis‐1,2‐dimethyl cyclohexane lb/h 16,966 30 708 147,784 147,784 147,784 147,781 131,525 131,525 4,433 0 11,822 0 0 0 3 3 4,463 708 529 171 7 Trans‐1,2‐dimethylcyclohexane lb/h 16,471 26 850 141,987 141,987 141,987 141,984 126,366 126,366 4,260 0 11,359 0 0 0 3 3 4,286 850 635 206 8 Ethylcyclohexane lb/h 00000000000000000000004‐Methylheptane lb/h 00000000000000000000002‐Methyl‐Benzofuran lb/h 1,656 10 1 15,042 15,042 15,042 15,042 13,387 13,387 451 0 1,203 0 0 0 0 0 461 1 1 0 0 Indane lb/h 00000000000000000000002‐methoxy‐4‐vinylphenol lb/h 48 0 0 433 433 433 433 385 385 13 0 35 0 0 0 0 0 13 0 0 0 0 Syringaldehyde lb/h 0000000000000000000000n‐Propylbenzene lb/h 0000000000000000000000Naphthalene lb/h 00000000000000000000001‐Naphthalenol lb/h 626 2,534 0 5,693 5,693 5,693 5,693 5,067 5,067 171 0 455 0 0 0 0 0 2,705 0000Coniferyl Aldehyde lb/h 0 381 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 381 0 0 0 0 Tetralin lb/h 0000000000000000000000Isoeugenol lb/h 38 3 0 348 348 348 348 310 310 10 0 28 0 0 0 0 0 13 0 0 0 0 Decalin lb/h 7,530 32 21 68,254 68,254 68,254 68,253 60,745 60,745 2,048 0 5,460 0 0 0 1 1 2,079 21 16 5 0 2,5‐Dimethyloctane lb/h 00000000000000000000001‐Methyl naphthalene lb/h 4,041 80 0 36,727 36,727 36,727 36,726 32,686 32,686 1,102 0 2,938 0 0 0 1 1 1,181 00001‐methyl decahydronaphthene lb/h 5,334 38 7 48,421 48,421 48,421 48,421 43,094 43,094 1,453 0 3,874 0 0 0 1 1 1,490 7520Dibenzothiophene lb/h 0 73 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 73 0 0 0 0 Biphenyl lb/h 00000000000000000000005‐hexyl‐O‐cresol lb/h 0002222220000 0 00000000n‐Heptylcyclohexane lb/h 0000000000000000000000C14H20‐N35 lb/h 0000000000000000000000C14H24‐N5 lb/h 2,958 110 0 26,887 26,887 26,887 26,887 23,929 23,929 807 0 2,151 0 0 0 0 0 916 0 0 0 0 3,5‐Dimethyldodecane lb/h 0000000000000000000000C15H26‐N4 lb/h 3,317 79 0 30,149 30,149 30,149 30,148 26,832 26,832 904 0 2,412 0 0 0 1 1 983 0 0 0 0 6,8‐Dimethyltridecane lb/h 00000000000000000000001,4‐Dimethyl‐Phenanthrene lb/h 0 427 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 427 0 0 0 0 N‐Cetane lb/h 0000000000000000000000C18H26O lb/h 0 299 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 299 0 0 0 0 C18H28 lb/h 0000000000000000000000C21H26O2 lb/h 0 3,424 00000000000 0 0 0 0 3,424 0000C21H34 lb/h 218 7,028 0 1,978 1,978 1,978 1,978 1,760 1,760 59 0 158 0 0 0 0 0 7,087 0000C22H28O2 lb/h 0 2,855 00000000000 0 0 0 0 2,855 0000Carbon lb/h 0000000000000000000000Sulfur lb/h 0000000000000000000000Sand/Catalyst Solids lb/h 0000000000000 14 0 0 14 00000Ash lb/h 0000000000000 0 0 0 0 00000Wood lb/h 0000000000000 0 0 0 0 00000Char lb/h 0000000000000 2 0 0 2 00000Coke lb/h 0000000000000 1 0 0 1 00000

112
R-365

LP STEAM

FROM T-812

PFD-61712-A801

H-367

OFFGAS

FROM H-315

PFD-61712-A302

H-369

H-372

Rev:

1

Project No: Drawing:

30482.00 PFD-61712-A303

THERMOCHEMICAL CONVERSION OF BIOMASS

TO HYDROCARBON FUEL

CATALYTIC FAST PYROLYSIS

PROCESS FLOW DIAGRAM

AREA 300: WATER GAS SHIFT

Rev. Date By Description

0

QA QC-H374 Q-H -H373 372

Q-H369

Q-H367

343

813 367

369 370

372 372B

J:\1A - Process Solutions\30482 NREL Thermochemical Conv - Design-Model\Drawings\ 30482 Pyrolysis In-Situ PFDs 61712 150128.vsd Plot date: 1/29/2015

374

H-367

WGS STEAM

SUPERHEATER

H-369

PRE-WGS HEAT

RECOVERY

R-365

HIGH-TEMPERATURE

WGS

H-372

POST-WGS HEAT

RECOVERY

H-373

POST-WGS ACHE

H-374

POST-WGS

COOLER

WGS PRODUCT

TO S-385

PFD-61712-A304

H-373

9/29/14 JAR ISSUED FOR DESIGN REPORT

H-366

Q-H366

366

H-366

WGS FEED

SUPERHEATER

CWS

CWR

H-374

1 12/12/14 DMS UPDATED EQ NUMBERS

113
PFD‐61712‐A303 343 366 367 369 370 372 372B 374 813 

Total Flow lb/h 48,356 48,356 29,556 77,912 77,912 77,912 77,912 77,912 29,556 0000000000000Temperature F 95 400 404 397 464 663 200 110 354 0000000000000Pressure Psia 99 95 135 95 93 88 86 82 140 0000000000000Vapor Fraction 111111111 0000000000000Enthalpy Flow MMBtu/h ‐91 ‐82 ‐166 ‐248 ‐245 ‐245 ‐275 ‐290 ‐167 0000000000000Argon lb/h 0000000000000000000000Nitrogen lb/h 0000000000000000000000Oxygen lb/h 0000000000000000000000SO2 lb/h 0000000000000000000000NO2 lb/h 0000000000000000000000Hydrogen lb/h 4,432 4,432 0 4,432 4,432 5,509 5,509 5,509 0 0000000000000Ammonia lb/h 0000000000000000000000H2S lb/h 0000000000000000000000Water lb/h 148 148 29,430 29,578 29,578 19,959 19,959 19,959 29,430 0000000000000Carbon Monoxide lb/h 18,593 18,593 0 18,593 18,593 3,637 3,637 3,637 0 0000000000000Carbon Dioxide lb/h 15,440 15,440 2 15,442 15,442 38,940 38,940 38,940 2 0000000000000Methane lb/h 1,704 1,704 0 1,704 1,704 1,704 1,704 1,704 0 0000000000000Methanol lb/h 0000000000000000000000Formic Acid lb/h 0000000000000000000000Glyoxal lb/h 0000000000000000000000Ethylene lb/h 4,810 4,810 0 4,810 4,810 4,810 4,810 4,810 0 0000000000000Acetaldehyde lb/h 0000000000000000000000Hydroxyacetaldehyde lb/h 0000000000000000000000Acetic Acid lb/h 0000000000000000000000Ethane lb/h 0000000000000000000000Propylene lb/h 1,566 1,566 0 1,566 1,566 1,566 1,566 1,566 0 00000000000001‐Hydroxy‐2‐propanone lb/h 0000000000000000000000Propionic Acid lb/h 0000000000000000000000Propane lb/h 0000000000000000000000Furan lb/h 171 171 0 171 171 171 171 171 0 00000000000001‐Butene lb/h 757 757 0 757 757 757 757 757 0 0000000000000Tetrahydrofuran lb/h 129 129 0 129 129 129 129 129 0 0000000000000N‐Butane lb/h 0000000000000000000000Furfural lb/h 00000000000000000000002‐methylfuran lb/h 146 146 0 146 146 146 146 146 0 0000000000000Furfuryl Alcohol lb/h 0000000000000000000000n‐Pentane lb/h 0000000000000000000000Pentenone lb/h 0000000000000000000000Benzene lb/h 0000000000000000000000Phenol lb/h 5 5 47 52 52 52 52 52 47 00000000000001,2‐Benzenediol lb/h 0 0 75 75 75 75 75 75 75 0000000000000Hydroxymethylfurfural lb/h 00000000000000000000002,5‐dimethylfuran lb/h 110111110 0000000000000Methyl Cyclopentenone lb/h 0000000000000000000000Hydroxymethylcyclopentenone lb/h 0000000000000000000000Cyclohexanone lb/h 0000000000000000000000Levoglucosan lb/h 00000000000000000000001‐Hexanal lb/h 0000000000000000000000Dimethoxytetrahydrofuran lb/h 000000000 0000000000000Cyclohexane lb/h 550555550 0000000000000N‐Hexane lb/h 0000000000000000000000Hexanol lb/h 0000000000000000000000Toluene lb/h 00000000000000000000002‐Methylphenol lb/h 221222221 00000000000003‐Methyl‐phenol lb/h 0000000000000000000000Guaiacol lb/h 000000000 0000000000000Methyl‐Cyclohexane lb/h 63 63 0 63 63 63 63 63 0 00000000000002‐Methylhexane lb/h 0000000000000000000000VinylPhenol lb/h 000000000 0000000000000O‐Xylene lb/h 0000000000000000000000Ethylbenzne lb/h 00000000000000000000002,3‐Dimethyl‐phenol lb/h 001111111 00000000000002,6‐dimethoxyphenol lb/h 000000000 0000000000000Vanillyl alcohol lb/h 000000000 00000000000002,4,6‐Trimethylpyridine lb/h 110111110 0000000000000Cis‐1,2‐dimethyl cyclohexane lb/h 171 171 0 171 171 171 171 171 0 0000000000000Trans‐1,2‐dimethylcyclohexane lb/h 206 206 0 206 206 206 206 206 0 0000000000000Ethylcyclohexane lb/h 00000000000000000000004‐Methylheptane lb/h 00000000000000000000002‐Methyl‐Benzofuran lb/h 000000000 0000000000000Indane lb/h 00000000000000000000002‐methoxy‐4‐vinylphenol lb/h 000000000 0000000000000Syringaldehyde lb/h 0000000000000000000000n‐Propylbenzene lb/h 0000000000000000000000Naphthalene lb/h 00000000000000000000001‐Naphthalenol lb/h 000000000 0000000000000Coniferyl Aldehyde lb/h 0 0 0 0 0 00000000000000000Tetralin lb/h 0000000000000000000000Isoeugenol lb/h 000000000 0000000000000Decalin lb/h 5 5 0 55555 000000000000002,5‐Dimethyloctane lb/h 00000000000000000000001‐Methyl naphthalene lb/h 000000000 00000000000001‐methyl decahydronaphthene lb/h 2 2 0 22222 00000000000000Dibenzothiophene lb/h 0 0 0 0 0 00000000000000000Biphenyl lb/h 00000000000000000000005‐hexyl‐O‐cresol lb/h 0 0 0 00000 00000000000000n‐Heptylcyclohexane lb/h 0000000000000000000000C14H20‐N35 lb/h 0000000000000000000000C14H24‐N5 lb/h 0 0 0 00000 000000000000003,5‐Dimethyldodecane lb/h 0000000000000000000000C15H26‐N4 lb/h 0 0 0 00000 000000000000006,8‐Dimethyltridecane lb/h 00000000000000000000001,4‐Dimethyl‐Phenanthrene lb/h 0 0 0 0 0 00000000000000000N‐Cetane lb/h 0000000000000000000000C18H26O lb/h 0 0 0 0 0 00000000000000000C18H28 lb/h 0000000000000000000000C21H26O2 lb/h 0 0 0 0 0 00000000000000000C21H34 lb/h 0 0 0 00000 00000000000000C22H28O2 lb/h 0 0 0 0 0 00000000000000000Carbon lb/h 0000000000000000000000Sulfur lb/h 0000000000000000000000Sand/Catalyst Solids lb/h 0000000000000000000000Ash lb/h 0000000000000000000000Wood lb/h 0000000000000000000000Char lb/h 0000000000000000000000Coke lb/h 0000000000000000000000

114
S-386

CONDENSATE

TO T-860

PFD-61712-A804

PSA OFFGAS

TO H-513/K-511

PFD-61712-A501

HYDROGEN

TO K-211/K-412/K-462

PFD-61712-A504

Rev:

2

Project No: Drawing:

30482.00 PFD-61712-A304

THERMOCHEMICAL CONVERSION OF BIOMASS

TO HYDROCARBON FUEL

CATALYTIC FAST PYROLYSIS

PROCESS FLOW DIAGRAM

AREA 300: PSA

Rev. Date By Description 0

WGS PRODUCT

FROM H-374

PFD-61712-A303

374

389

390

377

388

J:\1A - Process Solutions\30482 NREL Thermochemical Conv - Design-Model\Drawings\ 30482 Pyrolysis In-Situ PFDs 61712 150128.vsd Plot date: 1/29/2015

382

K-390

W-K390

S-385

377A

K-390

PSA COMPRESSOR:

MULTISTAGE

P-377

COMPRESSOR

CONDENSATE PUMP

S-385

PSA COMPRESSOR

SUCTION KO

S-386

PSA COMPR DISCH

KO

M-385

PSA

M-385

385

386

QC-K390

9/29/14 JAR ISSUED FOR DESIGN REPORT

P-377

W-P377

T-377

T-377

COMPRESSOR

CONDENSATE TANK

376

QA-K390

1 12/12/14 DMS UPDATED EQ NUMBERS

CWS

CWR

2 12/29/14 JAR MINOR UPDATES

115
PFD‐61712‐A304 374 376 377 377A 382 385 386 388 389 390 

Total Flow lb/h 77,912 58,915 19,648 18,997 500 58,415 151 58,265 52,802 5,462 000000000000Temperature F 110 110 110 110 110 110 110 110 110 110 000000000000Pressure Psia 82 82 87 82 82 227 225 225 22 215 000000000000Vapor Fraction 1 1 000 1 0 111 000000000000Enthalpy Flow MMBtu/h ‐290 ‐161 ‐134 ‐129 ‐3 ‐158 ‐1 ‐157 ‐155 ‐2 000000000000Argon lb/h 0000000000000000000000Nitrogen lb/h 0000000000000000000000Oxygen lb/h 0000000000000000000000SO2 lb/h 0000000000000000000000NO2 lb/h 0000000000000000000000Hydrogen lb/h 5,509 5,509 0 0 0 5,509 0 5,509 881 4,627 000000000000Ammonia lb/h 0000000000000000000000H2S lb/h 0000000000000000000000Water lb/h 19,959 1,057 19,552 18,902 500 557 150 407 407 0000000000000Carbon Monoxide lb/h 3,637 3,637 0 0 0 3,637 0 3,637 3,312 325 000000000000Carbon Dioxide lb/h 38,940 38,939 1 1 0 38,939 0 38,939 38,429 510 000000000000Methane lb/h 1,704 1,704 0 0 0 1,704 0 1,704 1,704 0000000000000Methanol lb/h 0000000000000000000000Formic Acid lb/h 0000000000000000000000Glyoxal lb/h 0000000000000000000000Ethylene lb/h 4,810 4,810 0 0 0 4,810 0 4,810 4,810 0000000000000Acetaldehyde lb/h 0000000000000000000000Hydroxyacetaldehyde lb/h 0000000000000000000000Acetic Acid lb/h 0000000000000000000000Ethane lb/h 0000000000000000000000Propylene lb/h 1,566 1,566 0 0 0 1,566 0 1,566 1,566 00000000000001‐Hydroxy‐2‐propanone lb/h 0000000000000000000000Propionic Acid lb/h 0000000000000000000000Propane lb/h 0000000000000000000000Furan lb/h 171 171 0 0 0 171 0 171 171 00000000000001‐Butene lb/h 757 757 0 0 0 757 0 757 757 0000000000000Tetrahydrofuran lb/h 129 129 0 0 0 129 0 129 129 0000000000000N‐Butane lb/h 0000000000000000000000Furfural lb/h 00000000000000000000002‐methylfuran lb/h 146 146 0 0 0 146 0 146 146 0000000000000Furfuryl Alcohol lb/h 0000000000000000000000n‐Pentane lb/h 0000000000000000000000Pentenone lb/h 0000000000000000000000Benzene lb/h 0000000000000000000000Phenol lb/h 52 33 19 18 0 33 0 33 33 00000000000001,2‐Benzenediol lb/h 75 0 75 75 0 0 0 0 0 0000000000000Hydroxymethylfurfural lb/h 00000000000000000000002,5‐dimethylfuran lb/h 110001011 0000000000000Methyl Cyclopentenone lb/h 0000000000000000000000Hydroxymethylcyclopentenone lb/h 0000000000000000000000Cyclohexanone lb/h 0000000000000000000000Levoglucosan lb/h 00000000000000000000001‐Hexanal lb/h 0000000000000000000000Dimethoxytetrahydrofuran lb/h 000000000 0000000000000Cyclohexane lb/h 550005055 0000000000000N‐Hexane lb/h 0000000000000000000000Hexanol lb/h 0000000000000000000000Toluene lb/h 00000000000000000000002‐Methylphenol lb/h 220002022 00000000000003‐Methyl‐phenol lb/h 0000000000000000000000Guaiacol lb/h 000000000 0000000000000Methyl‐Cyclohexane lb/h 63 63 0 0 0 63 0 63 63 00000000000002‐Methylhexane lb/h 0000000000000000000000VinylPhenol lb/h 000000000 0000000000000O‐Xylene lb/h 0000000000000000000000Ethylbenzne lb/h 00000000000000000000002,3‐Dimethyl‐phenol lb/h 110001011 00000000000002,6‐dimethoxyphenol lb/h 000000000 0000000000000Vanillyl alcohol lb/h 000000000 00000000000002,4,6‐Trimethylpyridine lb/h 110001011 0000000000000Cis‐1,2‐dimethyl cyclohexane lb/h 171 171 0 0 0 171 0 171 171 0000000000000Trans‐1,2‐dimethylcyclohexane lb/h 206 206 0 0 0 206 0 206 206 0000000000000Ethylcyclohexane lb/h 00000000000000000000004‐Methylheptane lb/h 00000000000000000000002‐Methyl‐Benzofuran lb/h 000000000 0000000000000Indane lb/h 00000000000000000000002‐methoxy‐4‐vinylphenol lb/h 000000000 0000000000000Syringaldehyde lb/h 0000000000000000000000n‐Propylbenzene lb/h 0000000000000000000000Naphthalene lb/h 00000000000000000000001‐Naphthalenol lb/h 000000000 0000000000000Coniferyl Aldehyde lb/h 0 0 0 0 0000 00000000000000Tetralin lb/h 0000000000000000000000Isoeugenol lb/h 000000000 0000000000000Decalin lb/h 550005055 00000000000002,5‐Dimethyloctane lb/h 00000000000000000000001‐Methyl naphthalene lb/h 000000000 00000000000001‐methyl decahydronaphthene lb/h 220002022 0000000000000Dibenzothiophene lb/h 0000000000000000000000Biphenyl lb/h 00000000000000000000005‐hexyl‐O‐cresol lb/h 000000000 0000000000000n‐Heptylcyclohexane lb/h 0000000000000000000000C14H20‐N35 lb/h 0000000000000000000000C14H24‐N5 lb/h 000000000 00000000000003,5‐Dimethyldodecane lb/h 0000000000000000000000C15H26‐N4 lb/h 000000000 00000000000006,8‐Dimethyltridecane lb/h 00000000000000000000001,4‐Dimethyl‐Phenanthrene lb/h 0000000000000000000000N‐Cetane lb/h 0000000000000000000000C18H26O lb/h 0000000000000000000000C18H28 lb/h 0000000000000000000000C21H26O2 lb/h 0000000000000000000000C21H34 lb/h 000000000 0000000000000C22H28O2 lb/h 0000000000000000000000Carbon lb/h 0000000000000000000000Sulfur lb/h 0000000000000000000000Sand/Catalyst Solids lb/h 0000000000000000000000Ash lb/h 0000000000000000000000Wood lb/h 0000000000000000000000Char lb/h 0000000000000000000000Coke lb/h 0000000000000000000000

116
S-410

RECYCLE GAS PURGE

TO M-575

PFD-61712-A503

ORGANIC PHASE

TO H-450

PFD-61712-A402

ORGANIC PHASE

FROM P-331

PFD-61712-A302

P-410 QX-H410

QC-H445

S-411

K-442

QA-H413

QC-H413

426

OFFGAS

TO K-511/H-513

PFD-61712-A501

MAKEUP HYDROGEN

FROM

PFD-61712-A504

AQUEOUS PHASE

TO M-805

PFD-61712-A804

QC-H444

H-410

H-412

Q-H412

Rev:

1

Project No: Drawing:

30482.00 PFD-61712-A401

THERMOCHEMICAL CONVERSION OF BIOMASS

TO HYDROCARBON FUEL

CATALYTIC FAST PYROLYSIS

PROCESS FLOW DIAGRAM

AREA 400: HYDROTREATING

Rev. Date By Description

435

432

443

444C

J:\1A - Process Solutions\30482 NREL Thermochemical Conv - Design-Model\Drawings\ 30482 Pyrolysis In-Situ PFDs 61712 150128.vsd Plot date: 1/29/2015

414

443A

415 417

418

444B

419

422

424

R-410

W-K412

431

429

337

411

W-P410

H-411

QF-H411

W-K442

420

421

S-410

VAPOR

KO DRUM

P-410

HT FEED

PUMP

H-444

QUENCH HYDROGEN

STAGE 2 COOLER

H-445

QUENCH HYDROGEN

STAGE 3 COOLER

H-410

FEED-EFFLUENT

EXCH

H-411

FEED

FURNACE

R-410

HYDROTREATER

H-412

HT PRODUCT

HEAT RECOVERY

H-413A

HT PRODUCT

ACHE

H-413C

HT PRODUCT

COOLER

K-412

HYDROGEN MAKEUP

COMPRESSOR

S-411

HP HT EFFLUENT

FLASH: 3 PHASE

K-442

HYDROGEN RECYCLE

COMPRESSOR

0 9/29/14 JAR ISSUED FOR DESIGN REPORT

QA-K412

H-413A

S-412

AQUEOUS PHASE

TO T-860

PFD-61712-A804

430

OFFGAS

TO K-511/H-513

PFD-61712-A501

S-412

LP HT EFFLUENT

FLASH: 3 PHASE

428

K-412

CWS

CWR

H-444

CWS

CWR

H-445

CWS

CWR

H-413C

1 12/12/14 DMS UPDATED EQ NUMBERS

1 NOTE: FUEL GAS AND COMBUSTION DUTY ASSOCIATED WITH H-411 ACCOUNTED FOR BY QF-H548 ON PFD-61712-A501

117
PFD‐61712‐A401 337 411 414 415 417 418 419 420 421 422 424 426 428 429 430 431 432 435 443 443A 444B 444C 

Total Flow lb/h 52,053 0 52,053 61,262 61,262 79,137 79,137 79,137 79,137 28,548 4,696 45,894 870 45,023 0 5,327 23,220 3,865 27,085 9,209 8,938 8,938 Temperature F 103 0 118 123 707 757 415 175 110 110 110 110 110 110 0 110 110 110 131 131 110 110 Pressure Psia 117 117 1900 1900 1845 1815 1810 1805 1795 1793 1793 1793 53 53 53 1793 1793 245 1900 1900 1895 1895 Vapor Fraction 000 1111111 0 0 1 0 0 1111111 Enthalpy Flow MMBtu/h ‐38 0 ‐37 ‐47 ‐17 ‐37 ‐64 ‐84 ‐89 ‐34 ‐32 ‐26 ‐1 ‐24 0 ‐6 ‐28 ‐1 ‐28 ‐10 ‐10 ‐10 Argon lb/h 0000000000000000000000Nitrogen lb/h 0000000000000000000000Oxygen lb/h 0000000000000000000000SO2 lb/h 0000000000000000000000NO2 lb/h 0000000000000000000000Hydrogen lb/h 2 0 2 3,820 3,820 9,855 9,855 9,855 9,855 9,779 0 75 74 1 0 1,825 7,955 3,274 11,229 3,818 3,705 3,705 Ammonia lb/h 000 6 6 63 63 63 63 20 36 7 3 4 0 4 16 0 16 6 5 5 H2S lb/h 000 9 9 39 39 39 39 32 0 8 4 4 0 6 26 0 26 9 8 8 Water lb/h 290 0 290 319 319 5,008 5,008 5,008 5,008 106 4,660 243 22 221 0 20 86 0 86 29 28 28 Carbon Monoxide lb/h 13 0 13 2,377 2,377 8,366 8,366 8,366 8,366 8,266 0 100 97 3 0 1,542 6,723 230 6,953 2,364 2,294 2,294 Carbon Dioxide lb/h 177 0 177 869 869 2,267 2,267 2,267 2,267 2,061 0 205 152 53 0 385 1,677 361 2,038 693 672 672 Methane lb/h 4 0 4 1,498 1,498 5,565 5,565 5,565 5,565 5,405 0 160 147 13 0 1,009 4,396 0 4,396 1,495 1,451 1,451 Methanol lb/h 0000000000000000000000Formic Acid lb/h 0000000000000000000000Glyoxal lb/h 0000000000000000000000Ethylene lb/h 43 0 43 59 59 65 65 65 65 59 0 6 4 1 0 11 48 0 48 16 16 16 Acetaldehyde lb/h 0000000000000000000000Hydroxyacetaldehyde lb/h 0000000000000000000000Acetic Acid lb/h 0000000000000000000000Ethane lb/h 000 179 179 736 736 736 736 649 0 87 58 29 0 121 528 0 528 179 174 174 Propylene lb/h 69 0 69 70 70 6 6 6 6 5 0 2 1 1 0 1 4 0 4111 1‐Hydroxy‐2‐propanone lb/h 0000000000000000000000Propionic Acid lb/h 0000000000000000000000Propane lb/h 000 34 34 170 170 170 170 124 0 47 18 29 0 23 101 0 101 34 33 33 Furan lb/h 168 0 168 168 168 000000000000000001‐Butene lb/h 156 0 156 158 158 14 14 14 14 7 0 7 1 5 0 1 6 0 6222 Tetrahydrofuran lb/h 489 0 489 489 489 00000000000000000N‐Butane lb/h 000 174 174 1,202 1,202 1,202 1,202 628 0 573 89 484 0 117 511 0 511 174 169 169 Furfural lb/h 00000000000000000000002‐methylfuran lb/h 527 0 527 527 527 00000000000000000Furfuryl Alcohol lb/h 0000000000000000000000n‐Pentane lb/h 000 43 43 588 588 588 588 154 0 434 25 409 0 29 125 0 125 43 41 41 Pentenone lb/h 0000000000000000000000Benzene lb/h 000 114 114 4,694 4,694 4,694 4,694 414 0 4,280 67 4,213 0 77 336 0 336 114 111 111 Phenol lb/h 3,459 0 3,459 3,459 3,459 54 54 54 54 0 0 54 0 54 0 0 0 0 0000 1,2‐Benzenediol lb/h 284 0 284 284 284 00000000000000000Hydroxymethylfurfural lb/h 00000000000000000000002,5‐dimethylfuran lb/h 11 0 11 11 11 0 0 0 0 0 0 0 0 0 0 0 0 0 0000 Methyl Cyclopentenone lb/h 0000000000000000000000Hydroxymethylcyclopentenone lb/h 0000000000000000000000Cyclohexanone lb/h 0000000000000000000000Levoglucosan lb/h 00000000000000000000001‐Hexanal lb/h 0000000000000000000000Dimethoxytetrahydrofuran lb/h 37 0 37 37 37 00000000000000000Cyclohexane lb/h 27 0 27 84 84 2,470 2,470 2,470 2,470 206 0 2,263 32 2,232 0 38 168 0 168 57 55 55 N‐Hexane lb/h 000 29 29 856 856 856 856 105 0 750 15 735 0 20 86 0 86 29 28 28 Hexanol lb/h 0000000000000000000000Toluene lb/h 000 24 24 1,818 1,818 1,818 1,818 88 0 1,730 9 1,721 0 16 72 0 72 24 24 24 2‐Methylphenol lb/h 2,376 0 2,376 2,376 2,376 000000000000000003‐Methyl‐phenol lb/h 0000000000000000000000Guaiacol lb/h 1 0 111 00000000000000000Methyl‐Cyclohexane lb/h 731 0 731 755 755 1,743 1,743 1,743 1,743 84 0 1,659 11 1,647 0 16 68 0 68 23 22 22 2‐Methylhexane lb/h 000 16 16 842 842 842 842 59 0 783 8 775 0 11 48 0 48 16 16 16 VinylPhenol lb/h 1 0 111 00000000000000000O‐Xylene lb/h 000 4 4 1,185 1,185 1,185 1,185 14 0 1,171 2 1,169 0 3 11 0 11 4 4 4 Ethylbenzne lb/h 000 1 1 138 138 138 138 2 0 136 0 135 0 0 2 0 2111 2,3‐Dimethyl‐phenol lb/h 2,061 0 2,061 2,061 2,061 000000000000000002,6‐dimethoxyphenol lb/h 6,790 0 6,790 6,790 6,790 00000000000000000Vanillyl alcohol lb/h 870 0 870 870 870 000000000000000002,4,6‐Trimethylpyridine lb/h 330 0 330 330 330 00000000000000000Cis‐1,2‐dimethyl cyclohexane lb/h 4,463 0 4,463 4,492 4,492 4,446 4,446 4,446 4,446 105 0 4,341 12 4,329 0 20 85 0 85 29 28 28 Trans‐1,2‐dimethylcyclohexane lb/h 4,286 0 4,286 4,325 4,325 5,054 5,054 5,054 5,054 141 0 4,913 17 4,896 0 26 115 0 115 39 38 38 Ethylcyclohexane lb/h 000 2 2 399 399 399 399 8 0 391 1 390 0 2 7 0 7222 4‐Methylheptane lb/h 000 3 3 319 319 319 319 10 0 309 1 308 0 2 8 0 8333 2‐Methyl‐Benzofuran lb/h 461 0 461 461 461 00000000000000000Indane lb/h 00000000000000000000002‐methoxy‐4‐vinylphenol lb/h 13 0 13 13 13 00000000000000000Syringaldehyde lb/h 0000000000000000000000n‐Propylbenzene lb/h 000 0 0 10 10 10 10 0 0 10 0 10 0 0 0 0 0000 Naphthalene lb/h 000 0 0 1,108 1,108 1,108 1,108 1 0 1,107 0 1,106 0 0 1 0 1000 1‐Naphthalenol lb/h 2,705 0 2,705 2,705 2,705 00000000000000000Coniferyl Aldehyde lb/h 381 0 381 381 381 00000000000000000Tetralin lb/h 000 0 0 461 461 461 461 1 0 460 0 460 0 0 1 0 1000 Isoeugenol lb/h 13 0 13 13 13 00000000000000000Decalin lb/h 2,079 0 2,079 2,082 2,082 3,005 3,005 3,005 3,005 8 0 2,996 1 2,996 0 2 7 0 7222 2,5‐Dimethyloctane lb/h 00000000000000000000001‐Methyl naphthalene lb/h 1,181 0 1,181 1,182 1,182 544 544 544 544 0 0 544 0 544 0 0 0 0 0000 1‐methyl decahydronaphthene lb/h 1,490 0 1,490 1,491 1,491 2,176 2,176 2,176 2,176 4 0 2,172 0 2,172 0 1 3 0 3111 Dibenzothiophene lb/h 73 0 73 73 73 00000000000000000Biphenyl lb/h 000 0 0 62 62 62 62 0 0 62 0 61 0 0 0 0 0000 5‐hexyl‐O‐cresol lb/h 0 0 000 00000000000000000n‐Heptylcyclohexane lb/h 000 00000000000 0 0 0 0 0000 C14H20‐N35 lb/h 000 0 0 1,390 1,390 1,390 1,390 0 0 1,390 0 1,390 0 0 0 0 0000 C14H24‐N5 lb/h 916 0 916 916 916 916 916 916 916 0 0 916 0 916 0 0 0 0 0000 3,5‐Dimethyldodecane lb/h 000 0 0 1,859 1,859 1,859 1,859 1 0 1,857 0 1,857 0 0 1 0 1000 C15H26‐N4 lb/h 983 0 983 983 983 880 880 880 880 0 0 880 0 880 0 0 0 0 0000 6,8‐Dimethyltridecane lb/h 00000000000000000000001,4‐Dimethyl‐Phenanthrene lb/h 427 0 427 427 427 427 427 427 427 0 0 427 0 427 0 0 0 0 0000 N‐Cetane lb/h 0000000000000000000000C18H26O lb/h 299 0 299 299 299 00000000000000000C18H28 lb/h 000 0 0 283 283 283 283 0 0 283 0 283 0 0 0 0 0000 C21H26O2 lb/h 3,424 0 3,424 3,424 3,424 685 685 685 685 0 0 685 0 685 0 0 0 0 0000 C21H34 lb/h 7,087 0 7,087 7,087 7,087 7,087 7,087 7,087 7,087 0 0 7,087 0 7,087 0 0 0 0 0000 C22H28O2 lb/h 2,855 0 2,855 2,855 2,855 286 286 286 286 0 0 286 0 286 0 0 0 0 0000 Carbon lb/h 0000000000000000000000Sulfur lb/h 0000000000000000000000Sand/Catalyst Solids lb/h 0000000000000000000000Ash lb/h 0000000000000000000000Wood lb/h 0000000000000000000000Char lb/h 0000000000000000000000Coke lb/h 0000000000000000000000

118
HEAVY KEY

TO S-460

PFD-61712-A403

Rev:

1

Project No: Drawing:

30482.00 PFD-61712-A402

THERMOCHEMICAL CONVERSION OF BIOMASS

TO HYDROCARBON FUEL

CATALYTIC FAST PYROLYSIS

PROCESS FLOW DIAGRAM

AREA 400: PRODUCT SEPARATION

Rev. Date By Description

H-450

H-452

H-456

DIESEL PRODUCT

TO T-792

PFD-61712-A703

GASOLINE PRODUCT

TO T-790

PFD-61712-A703

HYDROPR PURGE

TO R-530

PFD-61712-A501

ORGANIC PHASE

FROM S-462

PFD-61712-A403

ORGANIC PHASE

FROM S-412

PFD-61712-A401

QC-H454

Q-H456

QA-H457

QC-H457

Q-H450

Q-H452

429

452A

479

460

456B 456

452

453

QC-H459

454

J:\1A - Process Solutions\30482 NREL Thermochemical Conv - Design-Model\Drawings\ 30482 Pyrolysis In-Situ PFDs 61712 150128.vsd Plot date: 1/29/2015

451

480

H-450

GASOLINE COLUMN

HEAT RECOVERY

H-452

GASOLINE COLUMN

HEAT RECOVERY

D-450

GASOLINE

COLUMN

H-450C

D-450

CONDENSER

H-450R

D-450

REBOILER

P-450

D-450 REFLUX

PUMP

D-451

DIESEL

COLUMN

H-451C

D-451

CONDENSER

H-451R

D-451

REBOILER

H-459

D-450 OVERHEAD

VAPOR COOLER

S-451

D-451 OVERHEAD

ACCUMULATOR

H-456

DIESEL PRODUCT

HEAT RECOVERY

H-457A

DIESEL PRODUCT

ACHE

H-457C

DIESEL PRODUCT

COOLER

H-454

GASOLINE

PRODUCT COOLER

D-451

H-451R

H-451C

QC-H451

QR-H451

P-451

S-451

D-450

H-450R

H-450C

QCN-D450

QRB-D450

P-450

S-450

0 9/29/14 JAR ISSUED FOR DESIGN REPORT

H-457A

S-450

D-450 OVERHEAD

ACCUMULATOR

P-451

D-451 REFLUX

PUMP

CWS

CWR

H-454

CWS

CWR

H-457C

CWS

CWR

H-459

1 12/12/14 DMS UPDATED EQ NUMBERS

119
PFD‐61712‐A402 429 451 452 452A 453 454 456 456B 460 480 

Total Flow lb/h 45,023 45,023 547 547 31,866 20,678 11,845 11,845 8,833 8,068 000000000000Temperature F 110 450 110 200 60 599 60 463 733 550 000000000000Pressure Psia 53 43 33 35 15 40 15 35 20 43 000000000000Vapor Fraction 0 111 0000 0 1 000000000000Enthalpy Flow MMBtu/h ‐24 ‐13 ‐1 ‐1 ‐20 ‐6 ‐8 ‐5 ‐1 ‐4 000000000000Argon lb/h 0000000000000000000000Nitrogen lb/h 0000000000000000000000Oxygen lb/h 0000000000000000000000SO2 lb/h 0000000000000000000000NO2 lb/h 0000000000000000000000Hydrogen lb/h 1122000000 000000000000Ammonia lb/h 44112 00000000000000000H2S lb/h 44112 00000000000000000Water lb/h 221 221 22 22 217 0 0 0 0 19 000000000000Carbon Monoxide lb/h 3333000000 000000000000Carbon Dioxide lb/h 53 53 35 35 22 0 0 0 0 4 000000000000Methane lb/h 13 13 12 12 3 0 0 0 0 2 000000000000Methanol lb/h 0000000000000000000000Formic Acid lb/h 0000000000000000000000Glyoxal lb/h 0000000000000000000000Ethylene lb/h 1133200003 000000000000Acetaldehyde lb/h 0000000000000000000000Hydroxyacetaldehyde lb/h 0000000000000000000000Acetic Acid lb/h 0000000000000000000000Ethane lb/h 29 29 41 41 39 0 0 0 0 50 000000000000Propylene lb/h 110010 00000000000000001‐Hydroxy‐2‐propanone lb/h 0000000000000000000000Propionic Acid lb/h 0000000000000000000000Propane lb/h 29 29 9 9 21 0 0000000000000000Furan lb/h 00000000000000000000001‐Butene lb/h 551150 0000000000000000Tetrahydrofuran lb/h 0000000000000000000000N‐Butane lb/h 484 484 67 67 417 0 0000000000000000Furfural lb/h 00000000000000000000002‐methylfuran lb/h 0000000000000000000000Furfuryl Alcohol lb/h 0000000000000000000000n‐Pentane lb/h 409 409 27 27 383 0 0000000000000000Pentenone lb/h 0000000000000000000000Benzene lb/h 4,213 4,213 93 93 4,120 0 0000000000000000Phenol lb/h 54 54 0 0 54 0 0 0 0 00000000000001,2‐Benzenediol lb/h 0000000000000000000000Hydroxymethylfurfural lb/h 00000000000000000000002,5‐dimethylfuran lb/h 000000 0000000000000000Methyl Cyclopentenone lb/h 0000000000000000000000Hydroxymethylcyclopentenone lb/h 0000000000000000000000Cyclohexanone lb/h 0000000000000000000000Levoglucosan lb/h 00000000000000000000001‐Hexanal lb/h 0000000000000000000000Dimethoxytetrahydrofuran lb/h 0000000000000000000000Cyclohexane lb/h 2,232 2,232 45 45 2,214 0 0 0 0 28 000000000000N‐Hexane lb/h 735 735 50 50 1,685 0000 1,000 000000000000Hexanol lb/h 0000000000000000000000Toluene lb/h 1,721 1,721 16 16 1,706 0000 00000000000002‐Methylphenol lb/h 00000000000000000000003‐Methyl‐phenol lb/h 0000000000000000000000Guaiacol lb/h 0000000000000000000000Methyl‐Cyclohexane lb/h 1,647 1,647 19 19 1,628 0000 00000000000002‐Methylhexane lb/h 775 775 32 32 1,874 0000 1,131 000000000000VinylPhenol lb/h 0000000000000000000000O‐Xylene lb/h 1,169 1,169 4 4 1,165 0000 0000000000000Ethylbenzne lb/h 135 135 1 1 135 0 0 0 0 00000000000002,3‐Dimethyl‐phenol lb/h 00000000000000000000002,6‐dimethoxyphenol lb/h 0000000000000000000000Vanillyl alcohol lb/h 00000000000000000000002,4,6‐Trimethylpyridine lb/h 0000000000000000000000Cis‐1,2‐dimethyl cyclohexane lb/h 4,329 4,329 24 24 4,306 0000 0000000000000Trans‐1,2‐dimethylcyclohexane lb/h 4,896 4,896 31 31 4,864 0000 0000000000000Ethylcyclohexane lb/h 390 390 2 2 388 0 0 0 0 00000000000004‐Methylheptane lb/h 308 308 2 2 305 0 0 0 0 00000000000002‐Methyl‐Benzofuran lb/h 0000000000000000000000Indane lb/h 00000000000000000000002‐methoxy‐4‐vinylphenol lb/h 0000000000000000000000Syringaldehyde lb/h 0000000000000000000000n‐Propylbenzene lb/h 10 10 0 0 10 0 0 0 0 0000000000000Naphthalene lb/h 1,106 1,106 0 0 858 248 248 248 0 0 0000000000001‐Naphthalenol lb/h 0000000000000000000000Coniferyl Aldehyde lb/h 0000000000000000000000Tetralin lb/h 460 460 0 0 437 23 23 23 0 0 000000000000Isoeugenol lb/h 0000000000000000000000Decalin lb/h 2,996 2,996 2 2 3,035 7 7 7 0 49 0000000000002,5‐Dimethyloctane lb/h 0 0 0 0 116 1 1 1 0 116 0000000000001‐Methyl naphthalene lb/h 544 544 0 0 11 533 533 533 0 0 0000000000001‐methyl decahydronaphthene lb/h 2,172 2,172 1 1 1,696 476 476 476 0 0 000000000000Dibenzothiophene lb/h 0000000000000000000000Biphenyl lb/h 61 61 0 0 0 61 61 61 0 0 0000000000005‐hexyl‐O‐cresol lb/h 0000000000000000000000n‐Heptylcyclohexane lb/h 0000000000 000000000000C14H20‐N35 lb/h 1,390 1,390 0 0 1 1,389 1,388 1,388 1 0 000000000000C14H24‐N5 lb/h 916 916 0 0 0 918 916 916 2 2 0000000000003,5‐Dimethyldodecane lb/h 1,857 1,857 0 0 144 4,498 4,498 4,498 0 2,785 000000000000C15H26‐N4 lb/h 880 880 0 0 1 880 879 879 1 1 0000000000006,8‐Dimethyltridecane lb/h 0 0 0 0 0 2,263 2,263 2,263 0 2,263 0000000000001,4‐Dimethyl‐Phenanthrene lb/h 427 427 0 0 0 545 37 37 508 118 000000000000N‐Cetane lb/h 0 0 0 0 0 162 162 162 0 162 000000000000C18H26O lb/h 0000000000000000000000C18H28 lb/h 283 283 0 0 0 617 283 283 333 333 000000000000C21H26O2 lb/h 685 685 0 0 0 685 0 0 685 0000000000000C21H34 lb/h 7,087 7,087 0 0 0 7,087 71 71 7,016 0000000000000C22H28O2 lb/h 286 286 0 0 0 286 0 0 286 0000000000000Carbon lb/h 0000000000000000000000Sulfur lb/h 0000000000000000000000Sand/Catalyst Solids lb/h 0000000000000000000000Ash lb/h 0000000000000000000000Wood lb/h 0000000000000000000000Char lb/h 0000000000000000000000Coke lb/h 0000000000000000000000

120
S-460

RECYCLE GAS PURGE

TO M-575

PFD-61712-A503

HEAVY KEY

FROM D-451

PFD-61712-A402

P-460 QX-H460

QC-H495

S-461

K-492

QA-H463

QC-H463

475

OFFGAS

TO K-511/H-513

PFD-61712-A501

MAKEUP HYDROGEN

FROM M-385/M-575

PFD-61712-A504

AQUEOUS PHASE

TO M-805

PFD-61712-A804

ORGANIC PHASE

TO H-452

PFD-61712-A402

QC-H494

H-460

H-462

Q-H462

Project No: Drawing:

30482.00 PFD-61712-A403

THERMOCHEMICAL CONVERSION OF BIOMASS

TO HYDROCARBON FUEL

CATALYTIC FAST PYROLYSIS

PROCESS FLOW DIAGRAM

AREA 400: HYDROCRACKING

Rev. Date By Description

485

482

493

494C

J:\1A - Process Solutions\30482 NREL Thermochemical Conv - Design-Model\Drawings\ 30482 Pyrolysis In-Situ PFDs 61712 150128.vsd Plot date: 1/29/2015

464

493A

465 467

468

466

494B

469

472

474

R-460

W-K462

481

479

460

461

W-P460 QF-H461

W-K492

470

471

S-460

VAPOR

KO DRUM

P-460

HC FEED

PUMP

H-494

QUENCH HYDROGEN

STAGE 2 COOLER

H-495

QUENCH HYDROGEN

STAGE 3 COOLER

H-460

FEED-EFFLUENT

EXCH

H-461

FEED

FURNACE

R-460

HYDROCRACKER

H-462

HC PRODUCT

HEAT RECOVERY

H-463A

HC PRODUCT

ACHE

H-463C

HC PRODUCT

COOLER

K-462

HYDROGEN MAKEUP

COMPRESSOR

S-461

HP EFFLUENT

FLASH: 3 PHASE

K-492

HYDROGEN RECYCLE

COMPRESSOR

H-461

QA-K462

H-463A

0 9/29/14 JAR ISSUED FOR DESIGN REPORT

OFFGAS

TO K-511/H-513

PFD-61712-A501

S-462

478

S-462

LP EFFLUENT

FLASH

K-462

Rev:

2

CWS

CWR

H-494

CWS

CWR

H-463C

CWS

CWR

H-495

1 12/12/14 DMS UPDATED EQ NUMBERS

1 NOTE: FUEL GAS AND COMBUSTION DUTY ASSOCIATED WITH H-461 ACCOUNTED FOR BY QF-H548 ON PFD-61712-A501

2 12/29/14 JAR MINOR UPDATES

121
PFD‐61712‐A403 460 461 464 465 467 468 469 470 471 472 474 475 478 479 481 482 485 493 493A 494B 494C 

Total Flow lb/h 8,833 0 8,833 10,606 10,606 14,047 14,047 14,047 14,047 5,487 80 8,480 412 8,068 1,342 4,146 1,068 5,214 1,773 1,721 1,721 0Temperature F 733 733 767 543 738 787 688 175 110 110 110 110 110 110 110 110 110 132 132 110 110 0Pressure Psia 20 20 2000 2000 1945 1915 1910 1905 1895 1893 1893 1893 53 53 1893 1893 245 2000 2000 1995 1995 0Vapor Fraction 0 1 0 1111111 0 0 1 0 1111111 0Enthalpy Flow MMBtu/h ‐1 0 ‐1 ‐3 ‐1 ‐4 ‐5 ‐13 ‐14 ‐6 ‐1 ‐7 ‐1 ‐7 ‐1 ‐4 0 ‐5 ‐2 ‐2 ‐2 0Argon lb/h 0000000000000000000000Nitrogen lb/h 0000000000000000000000Oxygen lb/h 0000000000000000000000SO2 lb/h 0000000000000000000000NO2 lb/h 0000000000000000000000Hydrogen lb/h 0 0 0 732 732 1,673 1,673 1,673 1,673 1,653 0 20 20 0 404 1,249 905 2,154 732 711 711 0Ammonia lb/h 0000000000000000000000H2S lb/h 0000000000000000000000Water lb/h 0 0 0 5 5 126 126 126 126 20 80 26 7 19 5 15 0 15 5 5 5 0Carbon Monoxide lb/h 0 0 0 84 84 246 246 246 246 241 0 5 4 0 59 182 64 246 84 81 81 0Carbon Dioxide lb/h 0 0 0 106 106 313 313 313 313 282 0 31 27 4 69 213 100 313 106 103 103 0Methane lb/h 0 0 0 281 281 1,140 1,140 1,140 1,140 1,096 0 44 42 2 268 828 0 828 281 273 273 0Methanol lb/h 0000000000000000000000Formic Acid lb/h 0000000000000000000000Glyoxal lb/h 0000000000000000000000Ethylene lb/h 0 0 0 44 44 191 191 191 191 171 0 20 17 3 42 129 0 129 44 43 43 0Acetaldehyde lb/h 0000000000000000000000Hydroxyacetaldehyde lb/h 0000000000000000000000Acetic Acid lb/h 0000000000000000000000Ethane lb/h 0 0 0 444 444 1,992 1,992 1,992 1,992 1,729 0 264 213 50 423 1,306 0 1,306 444 431 431 0Propylene lb/h 00000000000000000000001‐Hydroxy‐2‐propanone lb/h 0000000000000000000000Propionic Acid lb/h 0000000000000000000000Propane lb/h 0000000000000000000000Furan lb/h 00000000000000000000001‐Butene lb/h 0000000000000000000000Tetrahydrofuran lb/h 0000000000000000000000N‐Butane lb/h 0000000000000000000000Furfural lb/h 00000000000000000000002‐methylfuran lb/h 0000000000000000000000Furfuryl Alcohol lb/h 0000000000000000000000n‐Pentane lb/h 0000000000000000000000Pentenone lb/h 0000000000000000000000Benzene lb/h 0000000000000000000000Phenol lb/h 0 0000000000000000000001,2‐Benzenediol lb/h 0000000000000000000000Hydroxymethylfurfural lb/h 00000000000000000000002,5‐dimethylfuran lb/h 0000000000000000000000Methyl Cyclopentenone lb/h 0000000000000000000000Hydroxymethylcyclopentenone lb/h 0000000000000000000000Cyclohexanone lb/h 0000000000000000000000Levoglucosan lb/h 00000000000000000000001‐Hexanal lb/h 0000000000000000000000Dimethoxytetrahydrofuran lb/h 0000000000000000000000Cyclohexane lb/h 0 0 0 1 1 33 33 33 33 4 0 29 1 28 1 3 0 3111 0N‐Hexane lb/h 0 0 0 46 46 1,230 1,230 1,230 1,230 178 0 1,052 51 1,000 44 135 0 135 46 44 44 0Hexanol lb/h 0000000000000000000000Toluene lb/h 0 0000000000000000000002‐Methylphenol lb/h 00000000000000000000003‐Methyl‐phenol lb/h 0000000000000000000000Guaiacol lb/h 0000000000000000000000Methyl‐Cyclohexane lb/h 0 0000000000000000000002‐Methylhexane lb/h 0 0 0 28 28 1,267 1,267 1,267 1,267 108 0 1,159 28 1,131 26 82 0 82 28 27 27 0VinylPhenol lb/h 0000000000000000000000O‐Xylene lb/h 0 000000000000000000000Ethylbenzne lb/h 0 0000000000000000000002,3‐Dimethyl‐phenol lb/h 00000000000000000000002,6‐dimethoxyphenol lb/h 0000000000000000000000Vanillyl alcohol lb/h 00000000000000000000002,4,6‐Trimethylpyridine lb/h 0000000000000000000000Cis‐1,2‐dimethyl cyclohexane lb/h 0 000000000000000000000Trans‐1,2‐dimethylcyclohexane lb/h 0 000000000000000000000Ethylcyclohexane lb/h 0 0000000000000000000004‐Methylheptane lb/h 0 0000000000000000000002‐Methyl‐Benzofuran lb/h 0000000000000000000000Indane lb/h 00000000000000000000002‐methoxy‐4‐vinylphenol lb/h 0000000000000000000000Syringaldehyde lb/h 0000000000000000000000n‐Propylbenzene lb/h 0 000000000000000000000Naphthalene lb/h 0000000000000000 0 0000 01‐Naphthalenol lb/h 0000000000000000000000Coniferyl Aldehyde lb/h 0000000000000000000000Tetralin lb/h 0000000000000000 0 0000 0Isoeugenol lb/h 0000000000000000000000Decalin lb/h 0 0 0 0 0 49 49 49 49 0 0 49 0 49 0 0 0 0000 02,5‐Dimethyloctane lb/h 0 0 0 0 0 118 118 118 118 1 0 117 0 116 0 1 0 1000 01‐Methyl naphthalene lb/h 0000000000000000 0 0000 01‐methyl decahydronaphthene lb/h 0000000000000000 0 0000 0Dibenzothiophene lb/h 0000000000000000000000Biphenyl lb/h 0000000000000000 0 0000 05‐hexyl‐O‐cresol lb/h 0000000000000000000000n‐Heptylcyclohexane lb/h 0000000000000000 0 0000 0C14H20‐N35 lb/h 1011100000000000 0 0000 0C14H24‐N5 lb/h 2022222220020200 0 0000 03,5‐Dimethyldodecane lb/h 00011 2,787 2,787 2,787 2,787 2 0 2,785 0 2,785 1 2 0 2111 0C15H26‐N4 lb/h 1011111110010100 0 0000 06,8‐Dimethyltridecane lb/h 00011 2,265 2,265 2,265 2,265 2 0 2,264 0 2,263 0 1 0 1000 01,4‐Dimethyl‐Phenanthrene lb/h 508 0 508 508 508 118 118 118 118 0 0 118 0 118 0 0 0 0000 0N‐Cetane lb/h 0 0 0 0 0 162 162 162 162 0 0 162 0 162 0 0 0 0000 0C18H26O lb/h 0000000000000000000000C18H28 lb/h 333 0 333 333 333 333 333 333 333 0 0 333 0 333 0 0 0 0000 0C21H26O2 lb/h 685 0 685 685 685 00000000000000000C21H34 lb/h 7,016 0 7,016 7,016 7,016 00000000000000000C22H28O2 lb/h 286 0 286 286 286 00000000000000000Carbon lb/h 0000000000000000000000Sulfur lb/h 0000000000000000000000Sand/Catalyst Solids lb/h 0000000000000000000000Ash lb/h 0000000000000000000000Wood lb/h 0000000000000000000000Char lb/h 0000000000000000000000Coke lb/h 0000000000000000000000

122
NATURAL GAS

FROM UTILITY

PSA OFFGAS

FROM M-385

PFD-61712-A304

H-511

H-513

H-514

Q-H511

Q-H514

Q-H513

Rev:

1

Project No: Drawing:

30482.00 PFD-61712-A501

THERMOCHEMICAL CONVERSION OF BIOMASS

TO HYDROCARBON FUEL

CATALYTIC FAST PYROLYSIS

PROCESS FLOW DIAGRAM

AREA 500: REFORMER

Rev. Date By Description

J:\1A - Process Solutions\30482 NREL Thermochemical Conv - Design-Model\Drawings\ 30482 Pyrolysis In-Situ PFDs 61712 150128.vsd Plot date: 1/29/2015

516

522

515

502

389

519

512

PURGE GAS

FROM H-315

PFD-61712-A302

345

LP STEAM

FROM T-822

PFD-61712-A801

823

HYDROPR PURGE

FROM H-459

PFD-61712-A402

PSA OFFGAS

FROM M-575

PFD-61712-A503

COMBUSTION AIR

589

452

542

W-K545

546

541

QF-H548 Q-H546

549 FLUE GAS

TO M-104

PFD-61712-A102

REFORMER PRODUCT

TO H-565

PFD-61712-A502

540

R-530

Q-H545

537

H-548

H-545

H-546

K-545

REFORMER COMBUSTOR

AIR BLOWER

H-511

HEAT

RECOVERY

K-511

PYROLYSIS OFFGAS

COMPRESSOR TO REFORMER

H-545

REFORMER COMBUSTOR

AIR HEAT RECOVERY

H-513

HEAT

RECOVERY

H-514

HEAT

RECOVERY

H-530

HEAT

RECOVERY

R-530

STEAM REFORMER

PACKAGE

H-548

HYDROPROCESSING

FURNACE HEAT EXCHANGER

H-546

REF COMBUSTOR FLUE

GAS HEAT RECOVERY

H-525

Q-H525

H-525

HEAT

RECOVERY

H-530

Q-H530

H-547

Q-H547

OFFGAS

FROM S-410

PFD-61712-A401

OFFGAS

FROM S-460

PFD-61712-A403

461

411

591

593

H-547

REF COMBUSTOR FLUE

GAS HEAT RECOVERY

0 9/29/14 JAR ISSUED FOR DESIGN REPORT

K-545

OFFGAS

FROM S-412

PFD-61712-A401

OFFGAS

FROM S-462

PFD-61712-A403

428

478

W-K511

K-511

1 12/12/14 DMS UPDATED EQ NUMBERS

1

NOTE: H-548 NOT PHYSICALLY PRESENT IN R-530 FLUE, BUT IS SHOWN TO

ACCOUNT FOR FLUE GASES AND COMBUSTION DUTIES OF H-411 AND H-461 1

123
PFD‐61712‐A501 345 389 411 428 452 461 478 502 512 515 516 519 522 537 540 541 542 546 549 589 591 593 

Total Flow lb/h 1,998 52,802 0 870 547 0 412 54 61,804 61,804 3,103 54 0 103,323 103,323 83,078 156,340 156,340 239,418 88,253 79,428 8,825 Temperature F 95 110 0 110 110 733 110 60 109 500 500 60 500 1400 1616 447 90 600 229 111 111 111 Pressure Psia 99 22 117 53 33 20 53 200 20 118 18 200 198 118 115 18 15 20 15 22 22 22 Vapor Fraction 1 1 0 1111111111111111111Enthalpy Flow MMBtu/h ‐4 ‐155 0 ‐1 ‐1 0 ‐1 0 ‐183 ‐175 ‐900 ‐360 ‐300 ‐284 ‐17 2 ‐476 ‐314 ‐283 ‐31 Argon lb/h 0000000000000000 1,975 1,975 1,975 000Nitrogen lb/h 0000000 100010143 115,767 115,767 115,770 430 Oxygen lb/h 00000000000000 0 0 35,471 35,471 7,234 000SO2 lb/h 00000000 000 0 0 000 0 0 21 0 0 0 NO2 lb/h 00000000000000 0 000 13 000Hydrogen lb/h 183 881 0 74 2 0 20 0 1,259 1,259 63 0 0 1,259 4,128 1,544 000 1,643 1,479 164 Ammonia lb/h 000 3 1 000 330 0 0 305 000 440 H2S lb/h 000 4 1 000 550 0 0 5 5 11 000 11 10 1 Water lb/h 6 407 0 22 22 0 7 0 467 467 23 0 0 41,308 31,037 472 3,050 3,050 23,478 474 427 47 Carbon Monoxide lb/h 768 3,312 0 97 3 0 4 0 4,552 4,552 229 0 0 4,552 30,667 5,617 000 5,984 5,385 598 Carbon Dioxide lb/h 638 38,429 0 152 35 0 27 0 44,745 44,745 2,247 0 0 44,745 37,159 71,996 77 77 90,926 77,460 69,714 7,746 Methane lb/h 70 1,704 0 147 12 0 42 47 2,022 2,022 102 47 0 2,069 323 1,554 000 1,600 1,440 160 Methanol lb/h 00000000 000 0 0 000 000 000 Formic Acid lb/h 00000000 000 0 0 000 000 000 Glyoxal lb/h 00000000 000 0 0 000 000 000 Ethylene lb/h 199 4,810 0 4 3 0 17 0 4,795 4,795 241 0 0 4,795 0 291 000 53 48 5 Acetaldehyde lb/h 00000000 000 0 0 000 000 000 Hydroxyacetaldehyde lb/h 00000000000000 0 0000000Acetic Acid lb/h 00000000 000 0 0 000 000 000 Ethane lb/h 000 58 41 0 213 3 310 310 16 3 0 313 0 546 000 544 489 54 Propylene lb/h 65 1,566 0 1 0 000 1,554 1,554 78 0 0 1,554 0 79 000 1101‐Hydroxy‐2‐propanone lb/h 00000000000000 0 0000000Propionic Acid lb/h 00000000000000 0 0000000Propane lb/h 000 18 9 0 0 1 19 19 1 1 0 20 0 30 000 23 21 2 Furan lb/h 7 171 000000 169 169 9 0 0 169 0 9 000000 1‐Butene lb/h 31 757 0 1 1 000 752 752 38 0 0 752 0 40 000 110Tetrahydrofuran lb/h 5 129 000000 128 128 6 0 0 128 0 6 000000 N‐Butane lb/h 000 89 67 0 0 1 96 96 5 1 0 97 0 178 000 117 106 12 Furfural lb/h 00000000000000 0 00000002‐methylfuran lb/h 6 146 000000 145 145 7 0 0 145 0 7 000000 Furfuryl Alcohol lb/h 00000000000000 0 0000000n‐Pentane lb/h 000 25 27 000 27 27 1 0 0 27 0 54 000 29 26 3 Pentenone lb/h 00000000000000 0 0000000Benzene lb/h 000 67 93 000 71 71 4 0 0 71 0 166 000 77 69 8 Phenol lb/h 0 33 0 0 0 000 31 31 2 0 0 69 0 2 000 0 0 0 1,2‐Benzenediol lb/h 0 0 000000 000 0 0 587 0 0 000000 Hydroxymethylfurfural lb/h 00000000000000 0 00000002,5‐dimethylfuran lb/h 0 1 0 0 0 000 110 0 0 100 000 000Methyl Cyclopentenone lb/h 00000000000000 0 0000000Hydroxymethylcyclopentenone lb/h 00000000000000 0 0000000Cyclohexanone lb/h 00000000000000 0 0000000Levoglucosan lb/h 00000000000000000000001‐Hexanal lb/h 00000000000000 0 0000000Dimethoxytetrahydrofuran lb/h 0 0 000000 000 0 0 0 0 0 000000Cyclohexane lb/h 0 5 0 32 45 0 1 0 40 40 2 0 0 40 0 83 000 39 35 4 N‐Hexane lb/h 000 15 50 0 51 0 69 69 3 0 0 69 0 110 000 63 57 6 Hexanol lb/h 00000000000000 0 0000000Toluene lb/h 000 9 16 000 10 10 0 0 0 10 0 31 000 16 15 2 2‐Methylphenol lb/h 0 2 000000 220 0 0 200 000000 3‐Methyl‐phenol lb/h 00000000000000 0 0000000Guaiacol lb/h 0 0 000000 000 0 0 000 000000 Methyl‐Cyclohexane lb/h 3 63 0 11 19 000 75 75 4 0 0 75 0 37 000 16 14 2 2‐Methylhexane lb/h 000 8 32 0 28 0 38 38 2 0 0 38 0 67 000 37 34 4 VinylPhenol lb/h 0 0 000000 000 0 0 000 000000 O‐Xylene lb/h 000 2 4 000 220 0 0 206 000 320 Ethylbenzne lb/h 000 0 1 000 000 0 0 001 000 000 2,3‐Dimethyl‐phenol lb/h 0 1 000000 110 0 0 100 000000 2,6‐dimethoxyphenol lb/h 0 0 000000 000 0 0 0 0 0 000000 Vanillyl alcohol lb/h 0 0 000000 000 0 0 0 0 0 000000 2,4,6‐Trimethylpyridine lb/h 0 1 000000 110 0 0 100 000000Cis‐1,2‐dimethyl cyclohexane lb/h 7 171 0 12 24 000 183 183 9 0 0 183 0 50 000 20 18 2 Trans‐1,2‐dimethylcyclohexane lb/h 8 206 0 17 31 000 222 222 11 0 0 222 0 66 000 26 24 3 Ethylcyclohexane lb/h 000 1 2 000 110 0 0 103 000 210 4‐Methylheptane lb/h 000 1 2 000 110 0 0 104 000 220 2‐Methyl‐Benzofuran lb/h 0 0 000000 000 0 0 0 0 0 000000 Indane lb/h 00000000000000 0 00000002‐methoxy‐4‐vinylphenol lb/h 0 0 000000 000 0 0 0 0 0 000000 Syringaldehyde lb/h 0000000000000000000000n‐Propylbenzene lb/h 000 0 0 000 000 0 0 000 000 000 Naphthalene lb/h 000 0000 0 000 0 0 001 000 000 1‐Naphthalenol lb/h 0 0 000000 000 0 0 000 000000 Coniferyl Aldehyde lb/h 0 0000000 000 0 0 0 0 0 000000Tetralin lb/h 000 0000 0 000 0 0 000 000 000 Isoeugenol lb/h 0 0 000000 000 0 0 0 0 0 000000 Decalin lb/h 0 5 0 1200 0 660 0 0 6 0 4 000 210 2,5‐Dimethyloctane lb/h 0000 000 0 000 0 0 0 0 1 000 000 1‐Methyl naphthalene lb/h 0 0 0 0000 0 000 0 0 000 000 0001‐methyl decahydronaphthene lb/h 0 2 0 0100 0 220 0 0 2 0 2 000 110 Dibenzothiophene lb/h 0 0000000 000 0 0 0 0 0 000000Biphenyl lb/h 000 0000 0 000 0 0 000 000 000 5‐hexyl‐O‐cresol lb/h 0 0 000000 000 0 0 0 0 0 000000n‐Heptylcyclohexane lb/h 000 0000 0 000 0 0 0 0 0 000 000 C14H20‐N35 lb/h 000 0000 0 000 0 0 0 0 0 000 000 C14H24‐N5 lb/h 0 0 0 0000 0 000 0 0 0 0 0 000 000 3,5‐Dimethyldodecane lb/h 000 0000 0 000 0 0 0 0 1 000 110 C15H26‐N4 lb/h 0 0 0 0000 0 000 0 0 0 0 0 000 000 6,8‐Dimethyltridecane lb/h 0000 000 0 000 0 0 0 0 0 000 000 1,4‐Dimethyl‐Phenanthrene lb/h 0 0 0 0000 0 000 0 0 0 0 0 000 000 N‐Cetane lb/h 0000 000 0 000 0 0 0 0 0 000 000 C18H26O lb/h 0 0000000 000 0 0 0 0 0 000000C18H28 lb/h 000 0000 0 000 0 0 0 0 0 000 000 C21H26O2 lb/h 0 0 0 000 0 0 000 0 0 0 0 0 000 000 C21H34 lb/h 0 0 0 000 0 0 000 0 0 0 0 0 000 000 C22H28O2 lb/h 0 0 0 000 0 0 000 0 0 0 0 0 000 000 Carbon lb/h 0000000000000000000000Sulfur lb/h 0000000000000000000000Sand/Catalyst Solids lb/h 0000000000000000000000Ash lb/h 0000000000000000000000Wood lb/h 0000000000000000000000Char lb/h 0000000000000000000000Coke lb/h 0000000000000000000000

124
Rev:

1

Project No: Drawing:

30482.00 PFD-61712-A502

THERMOCHEMICAL CONVERSION OF BIOMASS

TO HYDROCARBON FUEL

CATALYTIC FAST PYROLYSIS

PROCESS FLOW DIAGRAM

AREA 500: WATER GAS SHIFT

Rev. Date By Description

REFORMER PRODUCT

FROM R-530

PFD-61712-A501

Q-H565

H-565

R-565

Q-H566

H-566

R-566

Q-H567

H-567

QA-H568

QC-H568

WGS PRODUCT

TO S-575

PFD-61712-A503

540 566

568 569

572 573 574

H-565

HT WGS FEED

HEAT RECOVERY

R-565

WGS

REACTOR

R-566

LTS REACTOR

H-566

LTS FEED HEAT

RECOVERY

H-567

LTS EFFLUENT

HEAT RECOVERY

H-568A

WGS EFFLUENT

ACHE

H-568C

WGS EFFLUENT

COOLER

J:\1A - Process Solutions\30482 NREL Thermochemical Conv - Design-Model\Drawings\ 30482 Pyrolysis In-Situ PFDs 61712 150128.vsd Plot date: 1/29/2015

H-568A

0 9/29/14 JAR ISSUED FOR DESIGN REPORT

CWS

CWR

H-568C

1 12/12/14 DMS UPDATED EQ NUMBERS

125
PFD‐61712‐A502 540 566 568 569 572 573 574 

Total Flow lb/h 103,323 103,323 103,323 103,323 103,323 103,323 103,323 000000000000000Temperature F 1616 644 841 428 546 200 110 000000000000000Pressure Psia 115 113 108 106 101 99 97 000000000000000Vapor Fraction 1111111 000000000000000Enthalpy Flow MMBtu/h ‐300 ‐349 ‐349 ‐369 ‐369 ‐389 ‐404 000000000000000Argon lb/h 0000000000000000000000Nitrogen lb/h 4444444 000000000000000Oxygen lb/h 0 0 00000000000000000000SO2 lb/h 0000000 000000000000000NO2 lb/h 0 0 00000000000000000000Hydrogen lb/h 4,128 4,128 5,311 5,311 5,987 5,987 5,987 000000000000000Ammonia lb/h 0000000 000000000000000H2S lb/h 5555555 000000000000000Water lb/h 31,037 31,037 20,466 20,466 14,428 14,428 14,428 000000000000000Carbon Monoxide lb/h 30,667 30,667 14,232 14,232 4,844 4,844 4,844 000000000000000Carbon Dioxide lb/h 37,159 37,159 62,982 62,982 77,732 77,732 77,732 000000000000000Methane lb/h 323 323 323 323 323 323 323 000000000000000Methanol lb/h 0000000 000000000000000Formic Acid lb/h 0000000 000000000000000Glyoxal lb/h 0000000 000000000000000Ethylene lb/h 0000000 000000000000000Acetaldehyde lb/h 0000000 000000000000000Hydroxyacetaldehyde lb/h 0 0 00000000000000000000Acetic Acid lb/h 0000000 000000000000000Ethane lb/h 0000000 000000000000000Propylene lb/h 0000000 0000000000000001‐Hydroxy‐2‐propanone lb/h 0 0 00000000000000000000Propionic Acid lb/h 0 0 00000000000000000000Propane lb/h 0000000 000000000000000Furan lb/h 0 0 000000000000000000001‐Butene lb/h 0 0 00000000000000000000Tetrahydrofuran lb/h 0 0 00000000000000000000N‐Butane lb/h 0 0 00000000000000000000Furfural lb/h 0 0 000000000000000000002‐methylfuran lb/h 0 0 00000000000000000000Furfuryl Alcohol lb/h 0 0 00000000000000000000n‐Pentane lb/h 0 0 00000000000000000000Pentenone lb/h 0 0 00000000000000000000Benzene lb/h 0 0 00000000000000000000Phenol lb/h 0 0 000000000000000000001,2‐Benzenediol lb/h 0 0 00000000000000000000Hydroxymethylfurfural lb/h 0 0 000000000000000000002,5‐dimethylfuran lb/h 0 0 00000000000000000000Methyl Cyclopentenone lb/h 0 0 00000000000000000000Hydroxymethylcyclopentenone lb/h 0 0 00000000000000000000Cyclohexanone lb/h 0 0 00000000000000000000Levoglucosan lb/h 00000000000000000000001‐Hexanal lb/h 0 0 00000000000000000000Dimethoxytetrahydrofuran lb/h 0000000000000000000000Cyclohexane lb/h 0 0 00000000000000000000N‐Hexane lb/h 0 0 00000000000000000000Hexanol lb/h 0 0 00000000000000000000Toluene lb/h 0 0 000000000000000000002‐Methylphenol lb/h 0 0 000000000000000000003‐Methyl‐phenol lb/h 0 0 00000000000000000000Guaiacol lb/h 0 0 00000000000000000000Methyl‐Cyclohexane lb/h 0 0 000000000000000000002‐Methylhexane lb/h 0 0 00000000000000000000VinylPhenol lb/h 0 0 00000000000000000000O‐Xylene lb/h 0 0 00000000000000000000Ethylbenzne lb/h 0 0 000000000000000000002,3‐Dimethyl‐phenol lb/h 0 0 000000000000000000002,6‐dimethoxyphenol lb/h 0000000000000000000000Vanillyl alcohol lb/h 00000000000000000000002,4,6‐Trimethylpyridine lb/h 0 0 00000000000000000000Cis‐1,2‐dimethyl cyclohexane lb/h 0 0 00000000000000000000Trans‐1,2‐dimethylcyclohexane lb/h 0 0 00000000000000000000Ethylcyclohexane lb/h 0 0 000000000000000000004‐Methylheptane lb/h 0 0 000000000000000000002‐Methyl‐Benzofuran lb/h 0000000000000000000000Indane lb/h 0 0 000000000000000000002‐methoxy‐4‐vinylphenol lb/h 0000000000000000000000Syringaldehyde lb/h 0000000000000000000000n‐Propylbenzene lb/h 0 0 00000000000000000000Naphthalene lb/h 0 0 000000000000000000001‐Naphthalenol lb/h 0 0 00000000000000000000Coniferyl Aldehyde lb/h 0000000000000000000000Tetralin lb/h 0 0 00000000000000000000Isoeugenol lb/h 0000000000000000000000Decalin lb/h 00000000000000000000002,5‐Dimethyloctane lb/h 00000000000000000000001‐Methyl naphthalene lb/h 0 0 000000000000000000001‐methyl decahydronaphthene lb/h 0000000000000000000000Dibenzothiophene lb/h 0000000000000000000000Biphenyl lb/h 0 0 000000000000000000005‐hexyl‐O‐cresol lb/h 0000000000000000000000n‐Heptylcyclohexane lb/h 0000000000000000000000C14H20‐N35 lb/h 0000000000000000000000C14H24‐N5 lb/h 00000000000000000000003,5‐Dimethyldodecane lb/h 0000000000000000000000C15H26‐N4 lb/h 00000000000000000000006,8‐Dimethyltridecane lb/h 00000000000000000000001,4‐Dimethyl‐Phenanthrene lb/h 0000000000000000000000N‐Cetane lb/h 0000000000000000000000C18H26O lb/h 0000000000000000000000C18H28 lb/h 0000000000000000000000C21H26O2 lb/h 0000000000000000000000C21H34 lb/h 0000000000000000000000C22H28O2 lb/h 0000000000000000000000Carbon lb/h 0000000000000000000000Sulfur lb/h 0000000000000000000000Sand/Catalyst Solids lb/h 0000000000000000000000Ash lb/h 0000000000000000000000Wood lb/h 0000000000000000000000Char lb/h 0000000000000000000000Coke lb/h 0000000000000000000000

126
PSA OFFGAS

TO H-547/K-511/H-513

PFD-61712-A501

S-575

WGS PRODUCT

FROM H-568C

PFD-61712-A502

S-586

CONDENSATE

TO T-860

PFD-61712-A804

HYDROGEN

TO K-211/K-412/K-462

PFD-61712-A504

449

576

576A

590

589

588

586

574

Rev:

2

Project No: Drawing:

30482.00 PFD-61712-A503

THERMOCHEMICAL CONVERSION OF BIOMASS

TO HYDROCARBON FUEL

CATALYTIC FAST PYROLYSIS

PROCESS FLOW DIAGRAM

AREA 500: PSA

Rev. Date By Description

582

K-580

W-K580

577

S-586

PSA COMPRESSOR

DISCHARGE KO DRUM

S-575

COMPRESSOR

SUCTION KO DRUM

M-575

PSA

K-580

PSA COMPRESSOR

MULTISTAGE

J:\1A - Process Solutions\30482 NREL Thermochemical Conv - Design-Model\Drawings\ 30482 Pyrolysis In-Situ PFDs 61712 150128.vsd Plot date: 1/29/2015

M-575

587

585

RECYCLE GAS PURGE

FROM S-411

PFD-61712-A401

RECYCLE GAS PURGE

FROM S-461

PFD-61712-A403

431

481

P-576

W-P576

T-576

P-576

COMPRESSOR

CONDENSATE PUMP

T-576

COMRPESSOR

CONDENSATE TANK

QC-K580

0 9/29/14 JAR ISSUED FOR DESIGN REPORT

QA-K580

1 12/12/14 DMS UPDATED EQ NUMBERS

CWS

CWR

2 12/29/14 JAR MINOR UPDATES

127
PFD‐61712‐A503 431 449 481 574 576 576A 577 582 585 586 587 588 589 590 

Total Flow lb/h 5,327 6,669 1,342 103,323 13,980 13,346 89,977 520 89,457 89,343 114 96,012 88,253 7,759 00000000Temperature F 110 110 110 110 110 110 110 110 110 113 113 111 111 111 00000000Pressure Psia 1793 1793 1893 97 102 97 97 97 278 276 276 276 22 266 00000000Vapor Fraction 1111 0 0 1 0 1 1 0 111 00000000Enthalpy Flow MMBtu/h ‐6 ‐8 ‐1 ‐404 ‐95 ‐91 ‐313 ‐4 ‐310 ‐309 ‐1 ‐317 ‐314 ‐3 00000000Argon lb/h 0000000000000000000000Nitrogen lb/h 000 4004044044 000000000Oxygen lb/h 0000000000000000000000SO2 lb/h 000 0000000000 000000000NO2 lb/h 0000000000000000000000Hydrogen lb/h 1,825 2,229 404 5,987 0 0 5,987 0 5,987 5,987 0 8,216 1,643 6,573 00000000Ammonia lb/h 4 4 0 0000000044 000000000H2S lb/h 6 6 0 5 0 0 5 0 5 5 0 11 11 000000000Water lb/h 20 24 5 14,428 13,979 13,345 1,084 520 563 449 114 474 474 000000000Carbon Monoxide lb/h 1,542 1,601 59 4,844 0 0 4,844 0 4,844 4,844 0 6,445 5,984 461 00000000Carbon Dioxide lb/h 385 454 69 77,732 1 1 77,731 0 77,731 77,731 0 78,185 77,460 725 00000000Methane lb/h 1,009 1,277 268 323 0 0 323 0 323 323 0 1,600 1,600 000000000Methanol lb/h 000 0000000000 000000000Formic Acid lb/h 000 0000000000 000000000Glyoxal lb/h 000 0000000000 000000000Ethylene lb/h 11 53 42 0 0 0 0 0 0 0 0 53 53 000000000Acetaldehyde lb/h 000 0000000000 000000000Hydroxyacetaldehyde lb/h 0000000000000000000000Acetic Acid lb/h 000 0000000000 000000000Ethane lb/h 121 544 423 0 0 0 0 0 0 0 0 544 544 000000000Propylene lb/h 1 1 0 0000000011 0000000001‐Hydroxy‐2‐propanone lb/h 0000000000000000000000Propionic Acid lb/h 0000000000000000000000Propane lb/h 23 23 0 0 0 0 0 0 0 0 0 23 23 000000000Furan lb/h 00000000000000000000001‐Butene lb/h 1 1 000000000 1 1 000000000Tetrahydrofuran lb/h 0000000000000000000000N‐Butane lb/h 117 117 000000000 117 117 000000000Furfural lb/h 00000000000000000000002‐methylfuran lb/h 0000000000000000000000Furfuryl Alcohol lb/h 0000000000000000000000n‐Pentane lb/h 29 29 000000000 29 29 000000000Pentenone lb/h 0000000000000000000000Benzene lb/h 77 77 000000000 77 77 000000000Phenol lb/h 0 0 000000000 0 0 0000000001,2‐Benzenediol lb/h 0000000000000000000000Hydroxymethylfurfural lb/h 00000000000000000000002,5‐dimethylfuran lb/h 0 0 000000000 0 0 000000000Methyl Cyclopentenone lb/h 0000000000000000000000Hydroxymethylcyclopentenone lb/h 0000000000000000000000Cyclohexanone lb/h 0000000000000000000000Levoglucosan lb/h 00000000000000000000001‐Hexanal lb/h 0000000000000000000000Dimethoxytetrahydrofuran lb/h 0000000000000000000000Cyclohexane lb/h 38 39 1 00000000 39 39 000000000N‐Hexane lb/h 20 63 44 00000000 63 63 000000000Hexanol lb/h 0000000000000000000000Toluene lb/h 16 16 000000000 16 16 0000000002‐Methylphenol lb/h 00000000000000000000003‐Methyl‐phenol lb/h 0000000000000000000000Guaiacol lb/h 0000000000000000000000Methyl‐Cyclohexane lb/h 16 16 000000000 16 16 0000000002‐Methylhexane lb/h 11 37 26 00000000 37 37 000000000VinylPhenol lb/h 0000000000000000000000O‐Xylene lb/h 3 3 000000000 3 3 000000000Ethylbenzne lb/h 0 0 000000000 0 0 0000000002,3‐Dimethyl‐phenol lb/h 00000000000000000000002,6‐dimethoxyphenol lb/h 0000000000000000000000Vanillyl alcohol lb/h 00000000000000000000002,4,6‐Trimethylpyridine lb/h 0000000000000000000000Cis‐1,2‐dimethyl cyclohexane lb/h 20 20 000000000 20 20 000000000Trans‐1,2‐dimethylcyclohexane lb/h 26 26 000000000 26 26 000000000Ethylcyclohexane lb/h 2 2 000000000 2 2 0000000004‐Methylheptane lb/h 2 2 000000000 2 2 0000000002‐Methyl‐Benzofuran lb/h 0000000000000000000000Indane lb/h 00000000000000000000002‐methoxy‐4‐vinylphenol lb/h 0000000000000000000000Syringaldehyde lb/h 0000000000000000000000n‐Propylbenzene lb/h 0 0 000000000 0 0 000000000Naphthalene lb/h 000 00000000 0 0 0000000001‐Naphthalenol lb/h 0000000000000000000000Coniferyl Aldehyde lb/h 0000000000000000000000Tetralin lb/h 000 00000000 0 0 000000000Isoeugenol lb/h 0000000000000000000000Decalin lb/h 220 00000000 2 2 0000000002,5‐Dimethyloctane lb/h 0 0 0 00000000 0 0 0000000001‐Methyl naphthalene lb/h 000 00000000 0 0 0000000001‐methyl decahydronaphthene lb/h 110 00000000 1 1 000000000Dibenzothiophene lb/h 0000000000000000000000Biphenyl lb/h 000 00000000 0 0 0000000005‐hexyl‐O‐cresol lb/h 0000000000000000000000n‐Heptylcyclohexane lb/h 000 00000000 0 0 000000000C14H20‐N35 lb/h 000 00000000 0 0 000000000C14H24‐N5 lb/h 000 00000000 0 0 0000000003,5‐Dimethyldodecane lb/h 011 00000000 1 1 000000000C15H26‐N4 lb/h 000 00000000 0 0 0000000006,8‐Dimethyltridecane lb/h 0 0 0 00000000 0 0 0000000001,4‐Dimethyl‐Phenanthrene lb/h 000 00000000 0 0 000000000N‐Cetane lb/h 0 0 0 00000000 0 0 000000000C18H26O lb/h 0000000000000000000000C18H28 lb/h 000 00000000 0 0 000000000C21H26O2 lb/h 0 0 000000000 0 0 000000000C21H34 lb/h 0 0 000000000 0 0 000000000C22H28O2 lb/h 0 0 000000000 0 0 000000000Carbon lb/h 0000000000000000000000Sulfur lb/h 0000000000000000000000Sand/Catalyst Solids lb/h 0000000000000000000000Ash lb/h 0000000000000000000000Wood lb/h 0000000000000000000000Char lb/h 0000000000000000000000Coke lb/h 0000000000000000000000

128
Rev:

1

Project No: Drawing:

30482.00 PFD-61712-A504

THERMOCHEMICAL CONVERSION OF BIOMASS

TO HYDROCARBON FUEL

CATALYTIC FAST PYROLYSIS

PROCESS FLOW DIAGRAM

AREA 500: HYDROGEN DISTRIBUTION

Rev. Date By Description

J:\1A - Process Solutions\30482 NREL Thermochemical Conv - Design-Model\Drawings\ 30482 Pyrolysis In-Situ PFDs 61712 150128.vsd Plot date: 1/29/2015

0 9/29/14 JAR ISSUED FOR DESIGN REPORT

HYDROGEN

FROM M-575

PFD-61712-A503

HYDROGEN

FROM M-385

PFD-61712-A304

MAKEUP HYDROGEN

TO K-201

PFD-61712-A302

MAKEUP HYDROGEN

TO K-412

PFD-61712-A401

MAKEUP HYDROGEN

TO K-462

PFD-61712-A403

390

590

350

435

485

1 12/12/14 DMS UPDATED EQ NUMBERS

129
PFD‐61712‐A504 350 390 435 485 590 

Total Flow lb/h 8,288 5,462 3,865 1,068 7,759 00000000000000000Temperature F 100 110 110 110 111 00000000000000000Pressure Psia 110 215 245 245 266 00000000000000000Vapor Fraction 11111 00000000000000000Enthalpy Flow MMBtu/h ‐3 ‐2 ‐1 0 ‐3 00000000000000000Argon lb/h 0000000000000000000000Nitrogen lb/h 0000000000000000000000Oxygen lb/h 0000000000000000000000SO2 lb/h 0000000000000000000000NO2 lb/h 0000000000000000000000Hydrogen lb/h 7,021 4,627 3,274 905 6,573 00000000000000000Ammonia lb/h 0000000000000000000000H2S lb/h 0000000000000000000000Water lb/h 0000000000000000000000Carbon Monoxide lb/h 493 325 230 64 461 00000000000000000Carbon Dioxide lb/h 774 510 361 100 725 00000000000000000Methane lb/h 0000000000000000000000Methanol lb/h 0000000000000000000000Formic Acid lb/h 0000000000000000000000Glyoxal lb/h 0000000000000000000000Ethylene lb/h 0000000000000000000000Acetaldehyde lb/h 0000000000000000000000Hydroxyacetaldehyde lb/h 0000000000000000000000Acetic Acid lb/h 0000000000000000000000Ethane lb/h 0000000000000000000000Propylene lb/h 00000000000000000000001‐Hydroxy‐2‐propanone lb/h 0000000000000000000000Propionic Acid lb/h 0000000000000000000000Propane lb/h 0000000000000000000000Furan lb/h 00000000000000000000001‐Butene lb/h 0000000000000000000000Tetrahydrofuran lb/h 0000000000000000000000N‐Butane lb/h 0000000000000000000000Furfural lb/h 00000000000000000000002‐methylfuran lb/h 0000000000000000000000Furfuryl Alcohol lb/h 0000000000000000000000n‐Pentane lb/h 0000000000000000000000Pentenone lb/h 0000000000000000000000Benzene lb/h 0000000000000000000000Phenol lb/h 00000000000000000000001,2‐Benzenediol lb/h 0000000000000000000000Hydroxymethylfurfural lb/h 00000000000000000000002,5‐dimethylfuran lb/h 0000000000000000000000Methyl Cyclopentenone lb/h 0000000000000000000000Hydroxymethylcyclopentenone lb/h 0000000000000000000000Cyclohexanone lb/h 0000000000000000000000Levoglucosan lb/h 00000000000000000000001‐Hexanal lb/h 0000000000000000000000Dimethoxytetrahydrofuran lb/h 0000000000000000000000Cyclohexane lb/h 0000000000000000000000N‐Hexane lb/h 0000000000000000000000Hexanol lb/h 0000000000000000000000Toluene lb/h 00000000000000000000002‐Methylphenol lb/h 00000000000000000000003‐Methyl‐phenol lb/h 0000000000000000000000Guaiacol lb/h 0000000000000000000000Methyl‐Cyclohexane lb/h 00000000000000000000002‐Methylhexane lb/h 0000000000000000000000VinylPhenol lb/h 0000000000000000000000O‐Xylene lb/h 0000000000000000000000Ethylbenzne lb/h 00000000000000000000002,3‐Dimethyl‐phenol lb/h 00000000000000000000002,6‐dimethoxyphenol lb/h 0000000000000000000000Vanillyl alcohol lb/h 00000000000000000000002,4,6‐Trimethylpyridine lb/h 0000000000000000000000Cis‐1,2‐dimethyl cyclohexane lb/h 0000000000000000000000Trans‐1,2‐dimethylcyclohexane lb/h 0000000000000000000000Ethylcyclohexane lb/h 00000000000000000000004‐Methylheptane lb/h 00000000000000000000002‐Methyl‐Benzofuran lb/h 0000000000000000000000Indane lb/h 00000000000000000000002‐methoxy‐4‐vinylphenol lb/h 0000000000000000000000Syringaldehyde lb/h 0000000000000000000000n‐Propylbenzene lb/h 0000000000000000000000Naphthalene lb/h 00000000000000000000001‐Naphthalenol lb/h 0000000000000000000000Coniferyl Aldehyde lb/h 0000000000000000000000Tetralin lb/h 0000000000000000000000Isoeugenol lb/h 0000000000000000000000Decalin lb/h 00000000000000000000002,5‐Dimethyloctane lb/h 00000000000000000000001‐Methyl naphthalene lb/h 00000000000000000000001‐methyl decahydronaphthene lb/h 0000000000000000000000Dibenzothiophene lb/h 0000000000000000000000Biphenyl lb/h 00000000000000000000005‐hexyl‐O‐cresol lb/h 0000000000000000000000n‐Heptylcyclohexane lb/h 0000000000000000000000C14H20‐N35 lb/h 0000000000000000000000C14H24‐N5 lb/h 00000000000000000000003,5‐Dimethyldodecane lb/h 0000000000000000000000C15H26‐N4 lb/h 00000000000000000000006,8‐Dimethyltridecane lb/h 00000000000000000000001,4‐Dimethyl‐Phenanthrene lb/h 0000000000000000000000N‐Cetane lb/h 0000000000000000000000C18H26O lb/h 0000000000000000000000C18H28 lb/h 0000000000000000000000C21H26O2 lb/h 0000000000000000000000C21H34 lb/h 0000000000000000000000C22H28O2 lb/h 0000000000000000000000Carbon lb/h 0000000000000000000000Sulfur lb/h 0000000000000000000000Sand/Catalyst Solids lb/h 0000000000000000000000Ash lb/h 0000000000000000000000Wood lb/h 0000000000000000000000Char lb/h 0000000000000000000000Coke lb/h 0000000000000000000000

130
CONDENSATE

FROM P-602

PFD-61712-A602

Rev:

1

Project No: Drawing:

30482.00 PFD-61712-A601

THERMOCHEMICAL CONVERSION OF BIOMASS

TO HYDROCARBON FUEL

CATALYTIC FAST PYROLYSIS

PROCESS FLOW DIAGRAM

AREA 600: STEAM SYSTEM & POWER GENERATION

Rev. Date By Description

FLASH STEAM

FROM S-601

PFD-61712-A603

MAKE-UP WATER

FROM

PFD-61712-A701

BFW CHEMICALS

FROM P-707

PFD-61712-A702

STEAM

TO T-605

PFD-61712-A603

T-601

P-601

P-603

AMMONIA

FROM P-704

PFD-61712-A702

P-604

P-601

MAKE-UP

PUMP

T-601

CONDENSATE

COLLECTION TANK

T-602

CONDENSATE

SURGE TANK

P-603

EDI PUMP

P-604

BOILER

FEEDWATER PUMP

M-601

BFW ELECTRODEIONIZATION

(EDI) + POLISHING

T-603A

DEAERATOR

PACKED COLUMN

T-603

DEAERATOR

H-606

STEAM

GENERATOR

616

618

WP601

638

T-603A

WP603

T-603

WP604

J:\1A - Process Solutions\30482 NREL Thermochemical Conv - Design-Model\Drawings\ 30482 Pyrolysis In-Situ PFDs 61712 150128.vsd Plot date: 1/29/2015

T-602

H-605

QH605

H-630

M- QH630 601

H-630

DEAERATOR FEED

HEATER

H-620

CONDENSATE

HEATER

H-620

QH620

CONDENSATE

FROM USERS

0 9/29/14 JAR ISSUED FOR DESIGN REPORT

626

627

630 631

ATM

ATM

BOILER FEEDWATER

TO M-603

PFD-61712-A602

617

P-605

P-605

CONDENSATE

COLLECTION PUMP

H-606

QH606

639 644

H-605

BOILER FEEDWATER

PREHEATER

1 12/12/14 DMS UPDATED EQ NUMBERS

131
PFD‐61712‐A601 616 617 618 626 627 630 631 638 639 644 

Total Flow lb/h 346,272 346,272 7,064 7,064 353,336 353,336 353,336 353,338 353,338 353,338 000000000000Temperature F 136 136 60 212 138 138 232 232 235 581 000000000000Pressure Psia 25 15 15 15 15 25 22 22 1401 1336 000000000000Vapor Fraction 000 0 00000 1 000000000000Enthalpy Flow MMBtu/h ‐2342 ‐2342 ‐48 ‐47 ‐2389 ‐2389 ‐2355 ‐2355 ‐2353 ‐2014 000000000000Argon lb/h 0000000000000000000000Nitrogen lb/h 0000000000000000000000Oxygen lb/h 0000000000000000000000SO2 lb/h 0000000000000000000000NO2 lb/h 0000000000000000000000Hydrogen lb/h 0000000000000000000000Ammonia lb/h 0000000000000000000000H2S lb/h 0000000000000000000000Water lb/h 346,272 346,272 7,064 7,064 353,336 353,336 353,336 353,338 353,338 353,338 000000000000Carbon Monoxide lb/h 0000000000000000000000Carbon Dioxide lb/h 0000000000000000000000Methane lb/h 0000000000000000000000Methanol lb/h 0000000000000000000000Formic Acid lb/h 0000000000000000000000Glyoxal lb/h 0000000000000000000000Ethylene lb/h 0000000000000000000000Acetaldehyde lb/h 0000000000000000000000Hydroxyacetaldehyde lb/h 0000000000000000000000Acetic Acid lb/h 0000000000000000000000Ethane lb/h 0000000000000000000000Propylene lb/h 00000000000000000000001‐Hydroxy‐2‐propanone lb/h 0000000000000000000000Propionic Acid lb/h 0000000000000000000000Propane lb/h 0000000000000000000000Furan lb/h 00000000000000000000001‐Butene lb/h 0000000000000000000000Tetrahydrofuran lb/h 0000000000000000000000N‐Butane lb/h 0000000000000000000000Furfural lb/h 00000000000000000000002‐methylfuran lb/h 0000000000000000000000Furfuryl Alcohol lb/h 0000000000000000000000n‐Pentane lb/h 0000000000000000000000Pentenone lb/h 0000000000000000000000Benzene lb/h 0000000000000000000000Phenol lb/h 00000000000000000000001,2‐Benzenediol lb/h 0000000000000000000000Hydroxymethylfurfural lb/h 00000000000000000000002,5‐dimethylfuran lb/h 0000000000000000000000Methyl Cyclopentenone lb/h 0000000000000000000000Hydroxymethylcyclopentenone lb/h 0000000000000000000000Cyclohexanone lb/h 0000000000000000000000Levoglucosan lb/h 00000000000000000000001‐Hexanal lb/h 0000000000000000000000Dimethoxytetrahydrofuran lb/h 0000000000000000000000Cyclohexane lb/h 0000000000000000000000N‐Hexane lb/h 0000000000000000000000Hexanol lb/h 0000000000000000000000Toluene lb/h 00000000000000000000002‐Methylphenol lb/h 00000000000000000000003‐Methyl‐phenol lb/h 0000000000000000000000Guaiacol lb/h 0000000000000000000000Methyl‐Cyclohexane lb/h 00000000000000000000002‐Methylhexane lb/h 0000000000000000000000VinylPhenol lb/h 0000000000000000000000O‐Xylene lb/h 0000000000000000000000Ethylbenzne lb/h 00000000000000000000002,3‐Dimethyl‐phenol lb/h 00000000000000000000002,6‐dimethoxyphenol lb/h 0000000000000000000000Vanillyl alcohol lb/h 00000000000000000000002,4,6‐Trimethylpyridine lb/h 0000000000000000000000Cis‐1,2‐dimethyl cyclohexane lb/h 0000000000000000000000Trans‐1,2‐dimethylcyclohexane lb/h 0000000000000000000000Ethylcyclohexane lb/h 00000000000000000000004‐Methylheptane lb/h 00000000000000000000002‐Methyl‐Benzofuran lb/h 0000000000000000000000Indane lb/h 00000000000000000000002‐methoxy‐4‐vinylphenol lb/h 0000000000000000000000Syringaldehyde lb/h 0000000000000000000000n‐Propylbenzene lb/h 0000000000000000000000Naphthalene lb/h 00000000000000000000001‐Naphthalenol lb/h 0000000000000000000000Coniferyl Aldehyde lb/h 0000000000000000000000Tetralin lb/h 0000000000000000000000Isoeugenol lb/h 0000000000000000000000Decalin lb/h 00000000000000000000002,5‐Dimethyloctane lb/h 00000000000000000000001‐Methyl naphthalene lb/h 00000000000000000000001‐methyl decahydronaphthene lb/h 0000000000000000000000Dibenzothiophene lb/h 0000000000000000000000Biphenyl lb/h 00000000000000000000005‐hexyl‐O‐cresol lb/h 0000000000000000000000n‐Heptylcyclohexane lb/h 0000000000000000000000C14H20‐N35 lb/h 0000000000000000000000C14H24‐N5 lb/h 00000000000000000000003,5‐Dimethyldodecane lb/h 0000000000000000000000C15H26‐N4 lb/h 00000000000000000000006,8‐Dimethyltridecane lb/h 00000000000000000000001,4‐Dimethyl‐Phenanthrene lb/h 0000000000000000000000N‐Cetane lb/h 0000000000000000000000C18H26O lb/h 0000000000000000000000C18H28 lb/h 0000000000000000000000C21H26O2 lb/h 0000000000000000000000C21H34 lb/h 0000000000000000000000C22H28O2 lb/h 0000000000000000000000Carbon lb/h 0000000000000000000000Sulfur lb/h 0000000000000000000000Sand/Catalyst Solids lb/h 0000000000000000000000Ash lb/h 0000000000000000000000Wood lb/h 0000000000000000000000Char lb/h 0000000000000000000000Coke lb/h 0000000000000000000000

132
SUPERHEATED STEAM

FROM H-607

PFD-61712-A603

Rev:

1

Project No: Drawing:

30482.00 PFD-61712-A602

THERMOCHEMICAL CONVERSION OF BIOMASS

TO HYDROCARBON FUEL

CATALYTIC FAST PYROLYSIS

Rev. Date By Description

CONDENSATE

TO T-601

PFD-61712-A601

P-602

BOILER FEEDWATER

FROM P-604

PFD-61712-A601

M-603

LP STEAM

TO USERS

QAH601

WP602

607

614A

615

616

M-602

W-602A

M-602

TURBINE GENERATOR

M-603

STARTUP BOILER

P-602

CONDENSATE

PUMP

H-601

STEAM TURBINE

CONDENSER

J:\1A - Process Solutions\30482 NREL Thermochemical Conv - Design-Model\Drawings\ 30482 Pyrolysis In-Situ PFDs 61712 150128.vsd Plot date: 1/29/2015

PROCESS FLOW DIAGRAM

AREA 600: STEAM SYSTEM & POWER GENERATION

0 9/29/14 JAR ISSUED FOR DESIGN REPORT

H-601

T-606

T-606

STEAM TURBINE

CONDENSATE TANK

QH602B

1 12/12/14 DMS UPDATED EQ NUMBERS

133
PFD‐61712‐A602 607 614A 615 616 

Total Flow lb/h 346,272 346,272 346,272 346,272 000000000000000000Temperature F 1000 234 136 136 000000000000000000Pressure Psia 1321 4 3 25 000000000000000000Vapor Fraction 1 1 00000000000000000000Enthalpy Flow MMBtu/h ‐1860 ‐1974 ‐2342 ‐2342 000000000000000000Argon lb/h 0000000000000000000000Nitrogen lb/h 0000000000000000000000Oxygen lb/h 0000000000000000000000SO2 lb/h 0000000000000000000000NO2 lb/h 0000000000000000000000Hydrogen lb/h 0000000000000000000000Ammonia lb/h 0000000000000000000000H2S lb/h 0000000000000000000000Water lb/h 346,272 346,272 346,272 346,272 000000000000000000Carbon Monoxide lb/h 0000000000000000000000Carbon Dioxide lb/h 0000000000000000000000Methane lb/h 0000000000000000000000Methanol lb/h 0000000000000000000000Formic Acid lb/h 0000000000000000000000Glyoxal lb/h 0000000000000000000000Ethylene lb/h 0000000000000000000000Acetaldehyde lb/h 0000000000000000000000Hydroxyacetaldehyde lb/h 0000000000000000000000Acetic Acid lb/h 0000000000000000000000Ethane lb/h 0000000000000000000000Propylene lb/h 00000000000000000000001‐Hydroxy‐2‐propanone lb/h 0000000000000000000000Propionic Acid lb/h 0000000000000000000000Propane lb/h 0000000000000000000000Furan lb/h 00000000000000000000001‐Butene lb/h 0000000000000000000000Tetrahydrofuran lb/h 0000000000000000000000N‐Butane lb/h 0000000000000000000000Furfural lb/h 00000000000000000000002‐methylfuran lb/h 0000000000000000000000Furfuryl Alcohol lb/h 0000000000000000000000n‐Pentane lb/h 0000000000000000000000Pentenone lb/h 0000000000000000000000Benzene lb/h 0000000000000000000000Phenol lb/h 00000000000000000000001,2‐Benzenediol lb/h 0000000000000000000000Hydroxymethylfurfural lb/h 00000000000000000000002,5‐dimethylfuran lb/h 0000000000000000000000Methyl Cyclopentenone lb/h 0000000000000000000000Hydroxymethylcyclopentenone lb/h 0000000000000000000000Cyclohexanone lb/h 0000000000000000000000Levoglucosan lb/h 00000000000000000000001‐Hexanal lb/h 0000000000000000000000Dimethoxytetrahydrofuran lb/h 0000000000000000000000Cyclohexane lb/h 0000000000000000000000N‐Hexane lb/h 0000000000000000000000Hexanol lb/h 0000000000000000000000Toluene lb/h 00000000000000000000002‐Methylphenol lb/h 00000000000000000000003‐Methyl‐phenol lb/h 0000000000000000000000Guaiacol lb/h 0000000000000000000000Methyl‐Cyclohexane lb/h 00000000000000000000002‐Methylhexane lb/h 0000000000000000000000VinylPhenol lb/h 0000000000000000000000O‐Xylene lb/h 0000000000000000000000Ethylbenzne lb/h 00000000000000000000002,3‐Dimethyl‐phenol lb/h 00000000000000000000002,6‐dimethoxyphenol lb/h 0000000000000000000000Vanillyl alcohol lb/h 00000000000000000000002,4,6‐Trimethylpyridine lb/h 0000000000000000000000Cis‐1,2‐dimethyl cyclohexane lb/h 0000000000000000000000Trans‐1,2‐dimethylcyclohexane lb/h 0000000000000000000000Ethylcyclohexane lb/h 00000000000000000000004‐Methylheptane lb/h 00000000000000000000002‐Methyl‐Benzofuran lb/h 0000000000000000000000Indane lb/h 00000000000000000000002‐methoxy‐4‐vinylphenol lb/h 0000000000000000000000Syringaldehyde lb/h 0000000000000000000000n‐Propylbenzene lb/h 0000000000000000000000Naphthalene lb/h 00000000000000000000001‐Naphthalenol lb/h 0000000000000000000000Coniferyl Aldehyde lb/h 0000000000000000000000Tetralin lb/h 0000000000000000000000Isoeugenol lb/h 0000000000000000000000Decalin lb/h 00000000000000000000002,5‐Dimethyloctane lb/h 00000000000000000000001‐Methyl naphthalene lb/h 00000000000000000000001‐methyl decahydronaphthene lb/h 0000000000000000000000Dibenzothiophene lb/h 0000000000000000000000Biphenyl lb/h 00000000000000000000005‐hexyl‐O‐cresol lb/h 0000000000000000000000n‐Heptylcyclohexane lb/h 0000000000000000000000C14H20‐N35 lb/h 0000000000000000000000C14H24‐N5 lb/h 00000000000000000000003,5‐Dimethyldodecane lb/h 0000000000000000000000C15H26‐N4 lb/h 00000000000000000000006,8‐Dimethyltridecane lb/h 00000000000000000000001,4‐Dimethyl‐Phenanthrene lb/h 0000000000000000000000N‐Cetane lb/h 0000000000000000000000C18H26O lb/h 0000000000000000000000C18H28 lb/h 0000000000000000000000C21H26O2 lb/h 0000000000000000000000C21H34 lb/h 0000000000000000000000C22H28O2 lb/h 0000000000000000000000Carbon lb/h 0000000000000000000000Sulfur lb/h 0000000000000000000000Sand/Catalyst Solids lb/h 0000000000000000000000Ash lb/h 0000000000000000000000Wood lb/h 0000000000000000000000Char lb/h 0000000000000000000000Coke lb/h 0000000000000000000000

134
STEAM

FROM H-606

PFD-61712-A601

Rev:

1

Project No: Drawing:

30482.00 PFD-61712-A603

THERMOCHEMICAL CONVERSION OF BIOMASS

TO HYDROCARBON FUEL

CATALYTIC FAST PYROLYSIS

PROCESS FLOW DIAGRAM

AREA 600: STEAM SYSTEM & POWER GENERATION

Rev. Date By Description

SUPERHEATED STEAM

TO M-602

PFD-61712-A602

H-603

H-607

FLASH STEAM

TO T-603

PFD-61712-A601

BLOWDOWN

TO M-701

PFD-61712-A701

QH607

T-605

STEAM

DRUM

S-601

BLOWDOWN

FLASH DRUM

H-603

BLOWDOWN

COOLER

T-605

S-601

QCH603

603 600

606 607

H-602

604

J:\1A - Process Solutions\30482 NREL Thermochemical Conv - Design-Model\Drawings\ 30482 Pyrolysis In-Situ PFDs 61712 150128.vsd Plot date: 1/29/2015

H-607

STEAM

SUPERHEATER

H-602

STEAM TURBINE EXHAUST

HEAT RECOVERY

QH602

644

0 9/29/14 JAR ISSUED FOR DESIGN REPORT

STEAM

FROM R-202C

PFD-61712-A201

1 12/12/14 DMS UPDATED EQ NUMBERS

135
PFD‐61712‐A603 600 603 604 606 607 644 

Total Flow lb/h 7,067 7,067 7,067 346,272 346,272 353,338 0000000000000000Temperature F 113 170 581 580 1000 581 0000000000000000Pressure Psia 15 1326 1336 1326 1321 1336 0000000000000000Vapor Fraction 000 111 0000000000000000Enthalpy Flow MMBtu/h ‐48 ‐48 ‐44 ‐1970 ‐1860 ‐2014 0000000000000000Argon lb/h 0000000000000000000000Nitrogen lb/h 0000000000000000000000Oxygen lb/h 0000000000000000000000SO2 lb/h 0000000000000000000000NO2 lb/h 0000000000000000000000Hydrogen lb/h 0000000000000000000000Ammonia lb/h 0000000000000000000000H2S lb/h 0000000000000000000000Water lb/h 7,067 7,067 7,067 346,272 346,272 353,338 0000000000000000Carbon Monoxide lb/h 0000000000000000000000Carbon Dioxide lb/h 0000000000000000000000Methane lb/h 0000000000000000000000Methanol lb/h 0000000000000000000000Formic Acid lb/h 0000000000000000000000Glyoxal lb/h 0000000000000000000000Ethylene lb/h 0000000000000000000000Acetaldehyde lb/h 0000000000000000000000Hydroxyacetaldehyde lb/h 0000000000000000000000Acetic Acid lb/h 0000000000000000000000Ethane lb/h 0000000000000000000000Propylene lb/h 00000000000000000000001‐Hydroxy‐2‐propanone lb/h 0000000000000000000000Propionic Acid lb/h 0000000000000000000000Propane lb/h 0000000000000000000000Furan lb/h 00000000000000000000001‐Butene lb/h 0000000000000000000000Tetrahydrofuran lb/h 0000000000000000000000N‐Butane lb/h 0000000000000000000000Furfural lb/h 00000000000000000000002‐methylfuran lb/h 0000000000000000000000Furfuryl Alcohol lb/h 0000000000000000000000n‐Pentane lb/h 0000000000000000000000Pentenone lb/h 0000000000000000000000Benzene lb/h 0000000000000000000000Phenol lb/h 00000000000000000000001,2‐Benzenediol lb/h 0000000000000000000000Hydroxymethylfurfural lb/h 00000000000000000000002,5‐dimethylfuran lb/h 0000000000000000000000Methyl Cyclopentenone lb/h 0000000000000000000000Hydroxymethylcyclopentenone lb/h 0000000000000000000000Cyclohexanone lb/h 0000000000000000000000Levoglucosan lb/h 00000000000000000000001‐Hexanal lb/h 0000000000000000000000Dimethoxytetrahydrofuran lb/h 0000000000000000000000Cyclohexane lb/h 0000000000000000000000N‐Hexane lb/h 0000000000000000000000Hexanol lb/h 0000000000000000000000Toluene lb/h 00000000000000000000002‐Methylphenol lb/h 00000000000000000000003‐Methyl‐phenol lb/h 0000000000000000000000Guaiacol lb/h 0000000000000000000000Methyl‐Cyclohexane lb/h 00000000000000000000002‐Methylhexane lb/h 0000000000000000000000VinylPhenol lb/h 0000000000000000000000O‐Xylene lb/h 0000000000000000000000Ethylbenzne lb/h 00000000000000000000002,3‐Dimethyl‐phenol lb/h 00000000000000000000002,6‐dimethoxyphenol lb/h 0000000000000000000000Vanillyl alcohol lb/h 00000000000000000000002,4,6‐Trimethylpyridine lb/h 0000000000000000000000Cis‐1,2‐dimethyl cyclohexane lb/h 0000000000000000000000Trans‐1,2‐dimethylcyclohexane lb/h 0000000000000000000000Ethylcyclohexane lb/h 00000000000000000000004‐Methylheptane lb/h 00000000000000000000002‐Methyl‐Benzofuran lb/h 0000000000000000000000Indane lb/h 00000000000000000000002‐methoxy‐4‐vinylphenol lb/h 0000000000000000000000Syringaldehyde lb/h 0000000000000000000000n‐Propylbenzene lb/h 0000000000000000000000Naphthalene lb/h 00000000000000000000001‐Naphthalenol lb/h 0000000000000000000000Coniferyl Aldehyde lb/h 0000000000000000000000Tetralin lb/h 0000000000000000000000Isoeugenol lb/h 0000000000000000000000Decalin lb/h 00000000000000000000002,5‐Dimethyloctane lb/h 00000000000000000000001‐Methyl naphthalene lb/h 00000000000000000000001‐methyl decahydronaphthene lb/h 0000000000000000000000Dibenzothiophene lb/h 0000000000000000000000Biphenyl lb/h 00000000000000000000005‐hexyl‐O‐cresol lb/h 0000000000000000000000n‐Heptylcyclohexane lb/h 0000000000000000000000C14H20‐N35 lb/h 0000000000000000000000C14H24‐N5 lb/h 00000000000000000000003,5‐Dimethyldodecane lb/h 0000000000000000000000C15H26‐N4 lb/h 00000000000000000000006,8‐Dimethyltridecane lb/h 00000000000000000000001,4‐Dimethyl‐Phenanthrene lb/h 0000000000000000000000N‐Cetane lb/h 0000000000000000000000C18H26O lb/h 0000000000000000000000C18H28 lb/h 0000000000000000000000C21H26O2 lb/h 0000000000000000000000C21H34 lb/h 0000000000000000000000C22H28O2 lb/h 0000000000000000000000Carbon lb/h 0000000000000000000000Sulfur lb/h 0000000000000000000000Sand/Catalyst Solids lb/h 0000000000000000000000Ash lb/h 0000000000000000000000Wood lb/h 0000000000000000000000Char lb/h 0000000000000000000000Coke lb/h 0000000000000000000000

136
BLOWDOWN

FROM H-603

PFD-61712-A603

Rev:

2

Project No: Drawing:

30482.00 PFD-61712-A701

THERMOCHEMICAL CONVERSION OF BIOMASS

TO HYDROCARBON FUEL

CATALYTIC FAST PYROLYSIS

PROCESS FLOW DIAGRAM

AREA 700: COOLING WATER & FLUE GAS SCRUBBER

Rev. Date By Description

P-708

FLUE GAS SCRUBBER

CIRCULATION PUMP

M-703

FLUE GAS

SCRUBBER

P-701

COOLING TOWER

CHEMICALS

WP701

M-703

P-708

MAKE-UP WATER

FLUE GAS

FROM K-101

PFD-61712-A102

M-704

M-701

718

M-704

FLUE GAS

STACK

M-701

COOLING

TOWER SYSTEM

P-701

COOLING

WATER PUMP

J:\1A - Process Solutions\30482 NREL Thermochemical Conv - Design-Model\Drawings\ 30482 Pyrolysis In-Situ PFDs 61712 150128.vsd Plot date: 1/29/2015

0 9/29/14 JAR ISSUED FOR DESIGN REPORT

600

ATM

ATM

DRIFT

ATM

EVAP

WM701

110

MAKE-UP WATER

TO P-601

PFD-61712-A601

618

CT BLOWDOWN

TO T-860

PFD-61712-A804

713

BLOWDOWN

TO T-860

PFD-61712-A804

124

MAKE-UP WATER

TO P-815

PFD-61712-A801

815

1 12/12/14 DMS UPDATED EQ NUMBERS

715

CW USERS

H-314

H-374

K-390

K-580

M-708

CWS

TO HEADER

CWR

FROM HEADER

NAOH

FROM P-705

PFD-61712-A702

SAND FILTER FILTRATE

FROM M-807

PFD-61712-A803

2 12/29/14 JAR MINOR UPDATES

QM701

137
PFD‐61712‐A701 110 124 600 618 713 715 718 815 

Total Flow lb/h 883,124 22,360 7,067 7,064 10,788 2,581,093 2,581,093 0 00000000000000Temperature F 155 119 113 60 90 90 110 60 00000000000000Pressure Psia 14 14 15 15 15 75 60 15 00000000000000Vapor Fraction 1 000000000000000000000Enthalpy Flow MMBtu/h ‐1056 ‐152 ‐48 ‐48 ‐74 ‐17676 ‐17621 0 00000000000000Argon lb/h 9,581 0 00000000000000000000Nitrogen lb/h 562,024 0 00000000000000000000Oxygen lb/h 57,307 0 00000000000000000000SO2 lb/h 106 0 00000000000000000000NO2 lb/h 13 0 00000000000000000000Hydrogen lb/h 0000000000000000000000Ammonia lb/h 0000000000000000000000H2S lb/h 0000000000000000000000Water lb/h 49,518 22,360 7,067 7,064 10,788 2,581,093 2,581,093 0 00000000000000Carbon Monoxide lb/h 0000000000000000000000Carbon Dioxide lb/h 204,575 0 00000000000000000000Methane lb/h 0000000000000000000000Methanol lb/h 0000000000000000000000Formic Acid lb/h 0000000000000000000000Glyoxal lb/h 0000000000000000000000Ethylene lb/h 0000000000000000000000Acetaldehyde lb/h 0000000000000000000000Hydroxyacetaldehyde lb/h 0000000000000000000000Acetic Acid lb/h 0000000000000000000000Ethane lb/h 0000000000000000000000Propylene lb/h 00000000000000000000001‐Hydroxy‐2‐propanone lb/h 0000000000000000000000Propionic Acid lb/h 0000000000000000000000Propane lb/h 0000000000000000000000Furan lb/h 00000000000000000000001‐Butene lb/h 0000000000000000000000Tetrahydrofuran lb/h 0000000000000000000000N‐Butane lb/h 0000000000000000000000Furfural lb/h 00000000000000000000002‐methylfuran lb/h 0000000000000000000000Furfuryl Alcohol lb/h 0000000000000000000000n‐Pentane lb/h 0000000000000000000000Pentenone lb/h 0000000000000000000000Benzene lb/h 0000000000000000000000Phenol lb/h 00000000000000000000001,2‐Benzenediol lb/h 0000000000000000000000Hydroxymethylfurfural lb/h 00000000000000000000002,5‐dimethylfuran lb/h 0000000000000000000000Methyl Cyclopentenone lb/h 0000000000000000000000Hydroxymethylcyclopentenone lb/h 0000000000000000000000Cyclohexanone lb/h 0000000000000000000000Levoglucosan lb/h 00000000000000000000001‐Hexanal lb/h 0000000000000000000000Dimethoxytetrahydrofuran lb/h 0000000000000000000000Cyclohexane lb/h 0000000000000000000000N‐Hexane lb/h 0000000000000000000000Hexanol lb/h 0000000000000000000000Toluene lb/h 00000000000000000000002‐Methylphenol lb/h 00000000000000000000003‐Methyl‐phenol lb/h 0000000000000000000000Guaiacol lb/h 0000000000000000000000Methyl‐Cyclohexane lb/h 00000000000000000000002‐Methylhexane lb/h 0000000000000000000000VinylPhenol lb/h 0000000000000000000000O‐Xylene lb/h 0000000000000000000000Ethylbenzne lb/h 00000000000000000000002,3‐Dimethyl‐phenol lb/h 00000000000000000000002,6‐dimethoxyphenol lb/h 0000000000000000000000Vanillyl alcohol lb/h 00000000000000000000002,4,6‐Trimethylpyridine lb/h 0000000000000000000000Cis‐1,2‐dimethyl cyclohexane lb/h 0000000000000000000000Trans‐1,2‐dimethylcyclohexane lb/h 0000000000000000000000Ethylcyclohexane lb/h 00000000000000000000004‐Methylheptane lb/h 00000000000000000000002‐Methyl‐Benzofuran lb/h 0000000000000000000000Indane lb/h 00000000000000000000002‐methoxy‐4‐vinylphenol lb/h 0000000000000000000000Syringaldehyde lb/h 0000000000000000000000n‐Propylbenzene lb/h 0000000000000000000000Naphthalene lb/h 00000000000000000000001‐Naphthalenol lb/h 0000000000000000000000Coniferyl Aldehyde lb/h 0000000000000000000000Tetralin lb/h 0000000000000000000000Isoeugenol lb/h 0000000000000000000000Decalin lb/h 00000000000000000000002,5‐Dimethyloctane lb/h 00000000000000000000001‐Methyl naphthalene lb/h 00000000000000000000001‐methyl decahydronaphthene lb/h 0000000000000000000000Dibenzothiophene lb/h 0000000000000000000000Biphenyl lb/h 00000000000000000000005‐hexyl‐O‐cresol lb/h 0000000000000000000000n‐Heptylcyclohexane lb/h 0000000000000000000000C14H20‐N35 lb/h 0000000000000000000000C14H24‐N5 lb/h 00000000000000000000003,5‐Dimethyldodecane lb/h 0000000000000000000000C15H26‐N4 lb/h 00000000000000000000006,8‐Dimethyltridecane lb/h 00000000000000000000001,4‐Dimethyl‐Phenanthrene lb/h 0000000000000000000000N‐Cetane lb/h 0000000000000000000000C18H26O lb/h 0000000000000000000000C18H28 lb/h 0000000000000000000000C21H26O2 lb/h 0000000000000000000000C21H34 lb/h 0000000000000000000000C22H28O2 lb/h 0000000000000000000000Carbon lb/h 0000000000000000000000Sulfur lb/h 0000000000000000000000Sand/Catalyst Solids lb/h 0000000000000000000000Ash lb/h 0000000000000000000000Wood lb/h 0000000000000000000000Char lb/h 0000000000000000000000Coke lb/h 0000000000000000000000

138
Rev:

1

Project No: Drawing:

30482.00 PFD-61712-A702

THERMOCHEMICAL CONVERSION OF BIOMASS

TO HYDROCARBON FUEL

CATALYTIC FAST PYROLYSIS

PROCESS FLOW DIAGRAM

AREA 700: MATERIALS STORAGE

Rev. Date By Description

0

TO FIRE SUPPRESSION

SYSTEM

WATER

FRONT-END LOADERS

T-708

BFW CHEMICAL

STORAGE TANK

M-702

HYDRAULIC TRUCK DUMP

WITH SCALE

PURCHASED DIESEL

T-702

FIREWATER

STORAGE TANK

T-703

PURCHASED DIESEL

STORAGE TANK

T-705

CAUSTIC

STORAGE TANK

P-703

DIESEL

PUMP

P-702

FIREWATER

PUMP

T-702

P-702

AMMONIA

BFW CHEMICALS

T-703

P-703

T-704

P-704

AMMONIA

TO T-603

PFD-61712-A601

BFW CHEMICALS

TO T-603

PFD-61712-A601

CATALYST

M-702

T-708

P-707

NAOH T-705

P-705

NAOH

TO P-708

PFD-61712-A701

T-704

AMMONIA

STORAGE TANK

P-704

AMMONIA

PUMP

P-705

CAUSTIC

PUMP

P-707

BFW CHEMICAL

PUMP

J:\1A - Process Solutions\30482 NREL Thermochemical Conv - Design-Model\Drawings\ 30482 Pyrolysis In-Situ PFDs 61712 150128.vsd Plot date: 1/29/2015

9/29/14 JAR ISSUED FOR DESIGN REPORT

MAKEUP CATALYST

TO T-207

PFD-61712-A201

1 12/12/14 DMS UPDATED EQ NUMBERS

139
PFD‐61712‐A702 

Total Flow lb/h 0000000000000000000000Temperature F 0000000000000000000000Pressure Psia 0000000000000000000000Vapor Fraction 0000000000000000000000Enthalpy Flow MMBtu/h 0000000000000000000000Argon lb/h 0000000000000000000000Nitrogen lb/h 0000000000000000000000Oxygen lb/h 0000000000000000000000SO2 lb/h 0000000000000000000000NO2 lb/h 0000000000000000000000Hydrogen lb/h 0000000000000000000000Ammonia lb/h 0000000000000000000000H2S lb/h 0000000000000000000000Water lb/h 0000000000000000000000Carbon Monoxide lb/h 0000000000000000000000Carbon Dioxide lb/h 0000000000000000000000Methane lb/h 0000000000000000000000Methanol lb/h 0000000000000000000000Formic Acid lb/h 0000000000000000000000Glyoxal lb/h 0000000000000000000000Ethylene lb/h 0000000000000000000000Acetaldehyde lb/h 0000000000000000000000Hydroxyacetaldehyde lb/h 0000000000000000000000Acetic Acid lb/h 0000000000000000000000Ethane lb/h 0000000000000000000000Propylene lb/h 00000000000000000000001‐Hydroxy‐2‐propanone lb/h 0000000000000000000000Propionic Acid lb/h 0000000000000000000000Propane lb/h 0000000000000000000000Furan lb/h 00000000000000000000001‐Butene lb/h 0000000000000000000000Tetrahydrofuran lb/h 0000000000000000000000N‐Butane lb/h 0000000000000000000000Furfural lb/h 00000000000000000000002‐methylfuran lb/h 0000000000000000000000Furfuryl Alcohol lb/h 0000000000000000000000n‐Pentane lb/h 0000000000000000000000Pentenone lb/h 0000000000000000000000Benzene lb/h 0000000000000000000000Phenol lb/h 00000000000000000000001,2‐Benzenediol lb/h 0000000000000000000000Hydroxymethylfurfural lb/h 00000000000000000000002,5‐dimethylfuran lb/h 0000000000000000000000Methyl Cyclopentenone lb/h 0000000000000000000000Hydroxymethylcyclopentenone lb/h 0000000000000000000000Cyclohexanone lb/h 0000000000000000000000Levoglucosan lb/h 00000000000000000000001‐Hexanal lb/h 0000000000000000000000Dimethoxytetrahydrofuran lb/h 0000000000000000000000Cyclohexane lb/h 0000000000000000000000N‐Hexane lb/h 0000000000000000000000Hexanol lb/h 0000000000000000000000Toluene lb/h 00000000000000000000002‐Methylphenol lb/h 00000000000000000000003‐Methyl‐phenol lb/h 0000000000000000000000Guaiacol lb/h 0000000000000000000000Methyl‐Cyclohexane lb/h 00000000000000000000002‐Methylhexane lb/h 0000000000000000000000VinylPhenol lb/h 0000000000000000000000O‐Xylene lb/h 0000000000000000000000Ethylbenzne lb/h 00000000000000000000002,3‐Dimethyl‐phenol lb/h 00000000000000000000002,6‐dimethoxyphenol lb/h 0000000000000000000000Vanillyl alcohol lb/h 00000000000000000000002,4,6‐Trimethylpyridine lb/h 0000000000000000000000Cis‐1,2‐dimethyl cyclohexane lb/h 0000000000000000000000Trans‐1,2‐dimethylcyclohexane lb/h 0000000000000000000000Ethylcyclohexane lb/h 00000000000000000000004‐Methylheptane lb/h 00000000000000000000002‐Methyl‐Benzofuran lb/h 0000000000000000000000Indane lb/h 00000000000000000000002‐methoxy‐4‐vinylphenol lb/h 0000000000000000000000Syringaldehyde lb/h 0000000000000000000000n‐Propylbenzene lb/h 0000000000000000000000Naphthalene lb/h 00000000000000000000001‐Naphthalenol lb/h 0000000000000000000000Coniferyl Aldehyde lb/h 0000000000000000000000Tetralin lb/h 0000000000000000000000Isoeugenol lb/h 0000000000000000000000Decalin lb/h 00000000000000000000002,5‐Dimethyloctane lb/h 00000000000000000000001‐Methyl naphthalene lb/h 00000000000000000000001‐methyl decahydronaphthene lb/h 0000000000000000000000Dibenzothiophene lb/h 0000000000000000000000Biphenyl lb/h 00000000000000000000005‐hexyl‐O‐cresol lb/h 0000000000000000000000n‐Heptylcyclohexane lb/h 0000000000000000000000C14H20‐N35 lb/h 0000000000000000000000C14H24‐N5 lb/h 00000000000000000000003,5‐Dimethyldodecane lb/h 0000000000000000000000C15H26‐N4 lb/h 00000000000000000000006,8‐Dimethyltridecane lb/h 00000000000000000000001,4‐Dimethyl‐Phenanthrene lb/h 0000000000000000000000N‐Cetane lb/h 0000000000000000000000C18H26O lb/h 0000000000000000000000C18H28 lb/h 0000000000000000000000C21H26O2 lb/h 0000000000000000000000C21H34 lb/h 0000000000000000000000C22H28O2 lb/h 0000000000000000000000Carbon lb/h 0000000000000000000000Sulfur lb/h 0000000000000000000000Sand/Catalyst Solids lb/h 0000000000000000000000Ash lb/h 0000000000000000000000Wood lb/h 0000000000000000000000Char lb/h 0000000000000000000000Coke lb/h 0000000000000000000000

140
T-701

PLANT AIR

RECEIVER

S-701

INSTRUMENT

AIR DRYER

K-701

PLANT AIR

COMPRESSOR

Rev:

2

Project No: Drawing:

30482.00 PFD-61712-A703

THERMOCHEMICAL CONVERSION OF BIOMASS

TO HYDROCARBON FUEL

CATALYTIC FAST PYROLYSIS

PROCESS FLOW DIAGRAM

AREA 700: UTILITIES AND PRODUCT LOADOUT

Rev. Date By Description

0 9/29/14 JAR ISSUED FOR DESIGN REPORT

J:\1A - Process Solutions\30482 NREL Thermochemical Conv - Design-Model\Drawings\ 30482 Pyrolysis In-Situ PFDs 61712 150128.vsd Plot date: 1/29/2015

P-790

GASOLINE

T-790

GASOLINE PRODUCT

FROM H-454

PFD-61712-A402

M-710

DIESEL PRODUCT

FROM H-457C

PFD-61712-A402

T-792

P-792 DIESEL

K-701

S-701 T-701

INSTRUMENT AIR

TO DISTRIBUTION

PLANT AND INSTRUMENT AIR SYSTEM

PLANT AIR

TO DISTRIBUTION

453

456

T-792

DIESEL PRODUCT

STORAGE TANK

P-792

DIESEL PRODUCT

PUMP

T-790

GASOLINE PRODUCT

STORAGE TANK

M-710

PRODUCT

LOADING RACK

P-790

GASOLINE PRODUCT

PUMP

CHILLED WATER

RETURN FROM

HEADER

CHILLED WATER

SUPPLY TO

HEADER

M-708

CHILLED WATER

SYSTEM

M-708

CHILLED WATER SYSTEM

Q-M708

1 12/12/14 DMS UPDATED EQ NUMBERS

CHW USERS

H-316

H-326

2 12/29/14 JAR MINOR UPDATES

CWS

CWR

141
PFD‐61712‐A703 453 456 

Total Flow lb/h 31,866 11,845 00000000000000000000Temperature F 60 60 00000000000000000000Pressure Psia 15 15 00000000000000000000Vapor Fraction 0000000000000000000000Enthalpy Flow MMBtu/h ‐20 ‐8 00000000000000000000Argon lb/h 0000000000000000000000Nitrogen lb/h 0000000000000000000000Oxygen lb/h 0000000000000000000000SO2 lb/h 0000000000000000000000NO2 lb/h 0000000000000000000000Hydrogen lb/h 0 0 00000000000000000000Ammonia lb/h 2 000000000000000000000H2S lb/h 2 000000000000000000000Water lb/h 217 0 00000000000000000000Carbon Monoxide lb/h 0 0 00000000000000000000Carbon Dioxide lb/h 22 0 00000000000000000000Methane lb/h 3 0 00000000000000000000Methanol lb/h 0000000000000000000000Formic Acid lb/h 0000000000000000000000Glyoxal lb/h 0000000000000000000000Ethylene lb/h 2 0 00000000000000000000Acetaldehyde lb/h 0000000000000000000000Hydroxyacetaldehyde lb/h 0000000000000000000000Acetic Acid lb/h 0000000000000000000000Ethane lb/h 39 0 00000000000000000000Propylene lb/h 1 0000000000000000000001‐Hydroxy‐2‐propanone lb/h 0000000000000000000000Propionic Acid lb/h 0000000000000000000000Propane lb/h 21 000000000000000000000Furan lb/h 00000000000000000000001‐Butene lb/h 5 000000000000000000000Tetrahydrofuran lb/h 0000000000000000000000N‐Butane lb/h 417 000000000000000000000Furfural lb/h 00000000000000000000002‐methylfuran lb/h 0000000000000000000000Furfuryl Alcohol lb/h 0000000000000000000000n‐Pentane lb/h 383 000000000000000000000Pentenone lb/h 0000000000000000000000Benzene lb/h 4,120 000000000000000000000Phenol lb/h 54 0 000000000000000000001,2‐Benzenediol lb/h 0000000000000000000000Hydroxymethylfurfural lb/h 00000000000000000000002,5‐dimethylfuran lb/h 0 000000000000000000000Methyl Cyclopentenone lb/h 0000000000000000000000Hydroxymethylcyclopentenone lb/h 0000000000000000000000Cyclohexanone lb/h 0000000000000000000000Levoglucosan lb/h 00000000000000000000001‐Hexanal lb/h 0000000000000000000000Dimethoxytetrahydrofuran lb/h 0000000000000000000000Cyclohexane lb/h 2,214 0 00000000000000000000N‐Hexane lb/h 1,685 0 00000000000000000000Hexanol lb/h 0000000000000000000000Toluene lb/h 1,706 0 000000000000000000002‐Methylphenol lb/h 00000000000000000000003‐Methyl‐phenol lb/h 0000000000000000000000Guaiacol lb/h 0000000000000000000000Methyl‐Cyclohexane lb/h 1,628 0 000000000000000000002‐Methylhexane lb/h 1,874 0 00000000000000000000VinylPhenol lb/h 0000000000000000000000O‐Xylene lb/h 1,165 0 00000000000000000000Ethylbenzne lb/h 135 0 000000000000000000002,3‐Dimethyl‐phenol lb/h 00000000000000000000002,6‐dimethoxyphenol lb/h 0000000000000000000000Vanillyl alcohol lb/h 00000000000000000000002,4,6‐Trimethylpyridine lb/h 0000000000000000000000Cis‐1,2‐dimethyl cyclohexane lb/h 4,306 0 00000000000000000000Trans‐1,2‐dimethylcyclohexane lb/h 4,864 0 00000000000000000000Ethylcyclohexane lb/h 388 0 000000000000000000004‐Methylheptane lb/h 305 0 000000000000000000002‐Methyl‐Benzofuran lb/h 0000000000000000000000Indane lb/h 00000000000000000000002‐methoxy‐4‐vinylphenol lb/h 0000000000000000000000Syringaldehyde lb/h 0000000000000000000000n‐Propylbenzene lb/h 10 0 00000000000000000000Naphthalene lb/h 858 248 000000000000000000001‐Naphthalenol lb/h 0000000000000000000000Coniferyl Aldehyde lb/h 0000000000000000000000Tetralin lb/h 437 23 00000000000000000000Isoeugenol lb/h 0000000000000000000000Decalin lb/h 3,035 7 000000000000000000002,5‐Dimethyloctane lb/h 116 1 000000000000000000001‐Methyl naphthalene lb/h 11 533 000000000000000000001‐methyl decahydronaphthene lb/h 1,696 476 00000000000000000000Dibenzothiophene lb/h 0000000000000000000000Biphenyl lb/h 0 61 000000000000000000005‐hexyl‐O‐cresol lb/h 0000000000000000000000n‐Heptylcyclohexane lb/h 0 0 00000000000000000000C14H20‐N35 lb/h 1 1,388 00000000000000000000C14H24‐N5 lb/h 0 916 000000000000000000003,5‐Dimethyldodecane lb/h 144 4,498 00000000000000000000C15H26‐N4 lb/h 1 879 000000000000000000006,8‐Dimethyltridecane lb/h 0 2,263 000000000000000000001,4‐Dimethyl‐Phenanthrene lb/h 0 37 00000000000000000000N‐Cetane lb/h 0 162 00000000000000000000C18H26O lb/h 0000000000000000000000C18H28 lb/h 0 283 00000000000000000000C21H26O2 lb/h 0 0 00000000000000000000C21H34 lb/h 0 71 00000000000000000000C22H28O2 lb/h 0 0 00000000000000000000Carbon lb/h 0000000000000000000000Sulfur lb/h 0000000000000000000000Sand/Catalyst Solids lb/h 0000000000000000000000Ash lb/h 0000000000000000000000Wood lb/h 0000000000000000000000Char lb/h 0000000000000000000000Coke lb/h 0000000000000000000000

142
P-810

H-811

812

813

814

P-812

LP STEAM

TO H-367

PFD-61712-A303

W-P810

Q-H811

W-P812

Rev:

1

Project No: Drawing:

30482.00 PFD-61712-A801

THERMOCHEMICAL CONVERSION OF BIOMASS

TO HYDROCARBON FUEL

CATALYTIC FAST PYROLYSIS

PROCESS FLOW DIAGRAM

AREA 800: WASTEWATER MANAGEMENT

Rev. Date By Description

0 9/29/14 JAR ISSUED FOR DESIGN REPORT

P-810

BOILER

CHARGE PUMP

H-811

BOILER

PREHEATER

T-812

STEAM

DRUM

H-812

WGS STEAM

BOILER

J:\1A - Process Solutions\30482 NREL Thermochemical Conv - Design-Model\Drawings\ 30482 Pyrolysis In-Situ PFDs 61712 150128.vsd Plot date: 1/29/2015

AQUEOUS PHASE

FROM S-329

PFD-61712-A302

334

T-810

BOILER FEED TANK

T-810

P-815

W-P815

MAKEUP WATER

FROM

PFD-61712-A701

P-815

BOILER MAKEUP

PUMP

815

825

H-822

Q-H822

P-822

W-P822

T-814

822

P-814

W-P814

CONC WASTE WATER

TO K-831

PFD-61712-A802

LP STEAM

TO H-525

PFD-61712-A501

823

P-814

BOILER

CHARGE PUMP

T-822

STEAM

DRUM

P-822

CONCENTRATED

WASTEWATER PUMP

H-822

REFORMER

STEAM BOILER

T-814

BOILER FEED TANK

T-812

T-822

H-812

Q-H812

P-812

CONDENSATE

PUMP

1 12/12/14 DMS UPDATED EQ NUMBERS

143
PFD‐61712‐A801 334 812 813 814 815 822 823 825 

Total Flow lb/h 77,273 77,273 29,556 47,717 0 47,717 41,466 6,251 00000000000000Temperature F 85 359 354 354 60 354 356 356 00000000000000Pressure Psia 104 150 140 145 15 145 135 140 00000000000000Vapor Fraction 0 0 1 000 1 000000000000000Enthalpy Flow MMBtu/h ‐513 ‐490 ‐167 ‐297 0 ‐297 ‐232 ‐29 00000000000000Argon lb/h 0000000000000000000000Nitrogen lb/h 0000000000000000000000Oxygen lb/h 0000000000000000000000SO2 lb/h 0000000000000000000000NO2 lb/h 0000000000000000000000Hydrogen lb/h 0000 0 000 00000000000000Ammonia lb/h 0000000000000000000000H2S lb/h 0000000000000000000000Water lb/h 74,271 74,271 29,430 44,840 0 44,840 40,842 3,999 00000000000000Carbon Monoxide lb/h 0000 0 000 00000000000000Carbon Dioxide lb/h 2220 0 000 00000000000000Methane lb/h 0000 0 000 00000000000000Methanol lb/h 0000000000000000000000Formic Acid lb/h 0000000000000000000000Glyoxal lb/h 0000000000000000000000Ethylene lb/h 0000 0 000 00000000000000Acetaldehyde lb/h 0000000000000000000000Hydroxyacetaldehyde lb/h 0000000000000000000000Acetic Acid lb/h 0000000000000000000000Ethane lb/h 0000000000000000000000Propylene lb/h 0000 0 000 000000000000001‐Hydroxy‐2‐propanone lb/h 0000000000000000000000Propionic Acid lb/h 0000000000000000000000Propane lb/h 0000000000000000000000Furan lb/h 0000 0 000 000000000000001‐Butene lb/h 0000 0 000 00000000000000Tetrahydrofuran lb/h 0000 0 000 00000000000000N‐Butane lb/h 0000000000000000000000Furfural lb/h 00000000000000000000002‐methylfuran lb/h 0000 0 000 00000000000000Furfuryl Alcohol lb/h 0000000000000000000000n‐Pentane lb/h 0000000000000000000000Pentenone lb/h 0000000000000000000000Benzene lb/h 0000000000000000000000Phenol lb/h 89 89 47 42 0 42 37 5 000000000000001,2‐Benzenediol lb/h 2,909 2,909 75 2,833 0 2,833 587 2,247 00000000000000Hydroxymethylfurfural lb/h 00000000000000000000002,5‐dimethylfuran lb/h 0000 0 000 00000000000000Methyl Cyclopentenone lb/h 0000000000000000000000Hydroxymethylcyclopentenone lb/h 0000000000000000000000Cyclohexanone lb/h 0000000000000000000000Levoglucosan lb/h 00000000000000000000001‐Hexanal lb/h 0000000000000000000000Dimethoxytetrahydrofuran lb/h 0000 0 0 0000000000000000Cyclohexane lb/h 0000 0 000 00000000000000N‐Hexane lb/h 0000000000000000000000Hexanol lb/h 0000000000000000000000Toluene lb/h 00000000000000000000002‐Methylphenol lb/h 1110 0 000 000000000000003‐Methyl‐phenol lb/h 0000000000000000000000Guaiacol lb/h 0000 0 000 00000000000000Methyl‐Cyclohexane lb/h 0000 0 000 000000000000002‐Methylhexane lb/h 0000000000000000000000VinylPhenol lb/h 0000 0 000 00000000000000O‐Xylene lb/h 0000000000000000000000Ethylbenzne lb/h 00000000000000000000002,3‐Dimethyl‐phenol lb/h 1110 0 000 000000000000002,6‐dimethoxyphenol lb/h 0000 0 000 00000000000000Vanillyl alcohol lb/h 0000 0 000 000000000000002,4,6‐Trimethylpyridine lb/h 0000 0 0 0000000000000000Cis‐1,2‐dimethyl cyclohexane lb/h 0000 0 0 0000000000000000Trans‐1,2‐dimethylcyclohexane lb/h 0000 0 0 0000000000000000Ethylcyclohexane lb/h 00000000000000000000004‐Methylheptane lb/h 00000000000000000000002‐Methyl‐Benzofuran lb/h 0000 0 000 00000000000000Indane lb/h 00000000000000000000002‐methoxy‐4‐vinylphenol lb/h 0000 0 000 00000000000000Syringaldehyde lb/h 0000000000000000000000n‐Propylbenzene lb/h 0000000000000000000000Naphthalene lb/h 00000000000000000000001‐Naphthalenol lb/h 0000 0 000 00000000000000Coniferyl Aldehyde lb/h 0 0 00000000000000000000Tetralin lb/h 0000000000000000000000Isoeugenol lb/h 0000 0 000 00000000000000Decalin lb/h 0 0 000000000000000000002,5‐Dimethyloctane lb/h 00000000000000000000001‐Methyl naphthalene lb/h 0000 0 000 000000000000001‐methyl decahydronaphthene lb/h 0 0 00000000000000000000Dibenzothiophene lb/h 0 0 00000000000000000000Biphenyl lb/h 00000000000000000000005‐hexyl‐O‐cresol lb/h 0 0 00000000000000000000n‐Heptylcyclohexane lb/h 0000000000000000000000C14H20‐N35 lb/h 0000000000000000000000C14H24‐N5 lb/h 0 0 000000000000000000003,5‐Dimethyldodecane lb/h 0000000000000000000000C15H26‐N4 lb/h 0 0 000000000000000000006,8‐Dimethyltridecane lb/h 00000000000000000000001,4‐Dimethyl‐Phenanthrene lb/h 0 0 00000000000000000000N‐Cetane lb/h 0000000000000000000000C18H26O lb/h 0 0 00000000000000000000C18H28 lb/h 0000000000000000000000C21H26O2 lb/h 0 0 00000000000000000000C21H34 lb/h 0 0 00000000000000000000C22H28O2 lb/h 0 0 00000000000000000000Carbon lb/h 0000000000000000000000Sulfur lb/h 0000000000000000000000Sand/Catalyst Solids lb/h 0000000000000000000000Ash lb/h 0000000000000000000000Wood lb/h 0000000000000000000000Char lb/h 0000000000000000000000Coke lb/h 0000000000000000000000

144
Rev:

1

Project No: Drawing:

30482.00 PFD-61712-A802

THERMOCHEMICAL CONVERSION OF BIOMASS

TO HYDROCARBON FUEL

CATALYTIC FAST PYROLYSIS

PROCESS FLOW DIAGRAM

AREA 800: AQUEOUS RTO

Rev. Date By Description 0 9/29/14 JAR ISSUED FOR DESIGN REPORT

M-833

AQUEOUS REGENERATIVE

THERMAL OXIDIZER

K-831

RTO

BLOWER

H-838

HEAT

RECOVERY

H-840

RTO FEED/EFFLUENT

EXCHANGER

J:\1A - Process Solutions\30482 NREL Thermochemical Conv - Design-Model\Drawings\ 30482 Pyrolysis In-Situ PFDs 61712 150128.vsd Plot date: 1/29/2015

1 12/12/14 DMS UPDATED EQ NUMBERS

M-833

832

841 FLUE GAS

TO M-104

PFD-61712-A102

K-831

NATURAL GAS

FROM UTILITY

COMBUSTION AIR

825

W-K831

CONC WASTE WATER

FROM P-822

PFD-61712-A801

H-840

QH840

838

H-838

Q-H838

840A

145
PFD‐61712‐A802 825 832 838 840A 841 

Total Flow lb/h 6,251 166,893 173,143 173,143 173,143 00000000000000000Temperature F 356 90 862 270 229 00000000000000000Pressure Psia 140 15 22 19 17 00000000000000000Vapor Fraction 0 1111 00000000000000000Enthalpy Flow MMBtu/h ‐29 ‐19 ‐34 ‐61 ‐63 00000000000000000Argon lb/h 0 2,108 2,108 2,108 2,108 00000000000000000Nitrogen lb/h 0 123,581 123,581 123,581 123,581 00000000000000000Oxygen lb/h 0 37,865 33,609 33,609 33,609 00000000000000000SO2 lb/h 0000000000000000000000NO2 lb/h 0000000000000000000000Hydrogen lb/h 0 000000000000000000000Ammonia lb/h 0000000000000000000000H2S lb/h 0000000000000000000000Water lb/h 3,999 3,256 8,361 8,361 8,361 00000000000000000Carbon Monoxide lb/h 0 000000000000000000000Carbon Dioxide lb/h 0 82 5,485 5,485 5,485 00000000000000000Methane lb/h 0 000000000000000000000Methanol lb/h 0000000000000000000000Formic Acid lb/h 0000000000000000000000Glyoxal lb/h 0000000000000000000000Ethylene lb/h 0 000000000000000000000Acetaldehyde lb/h 0000000000000000000000Hydroxyacetaldehyde lb/h 0000000000000000000000Acetic Acid lb/h 0000000000000000000000Ethane lb/h 0000000000000000000000Propylene lb/h 0 0000000000000000000001‐Hydroxy‐2‐propanone lb/h 0000000000000000000000Propionic Acid lb/h 0000000000000000000000Propane lb/h 0000000000000000000000Furan lb/h 0 0000000000000000000001‐Butene lb/h 0 000000000000000000000Tetrahydrofuran lb/h 0 000000000000000000000N‐Butane lb/h 0000000000000000000000Furfural lb/h 00000000000000000000002‐methylfuran lb/h 0 000000000000000000000Furfuryl Alcohol lb/h 0000000000000000000000n‐Pentane lb/h 0000000000000000000000Pentenone lb/h 0000000000000000000000Benzene lb/h 0000000000000000000000Phenol lb/h 5 0000000000000000000001,2‐Benzenediol lb/h 2,247 000000000000000000000Hydroxymethylfurfural lb/h 00000000000000000000002,5‐dimethylfuran lb/h 0 000000000000000000000Methyl Cyclopentenone lb/h 0000000000000000000000Hydroxymethylcyclopentenone lb/h 0000000000000000000000Cyclohexanone lb/h 0000000000000000000000Levoglucosan lb/h 00000000000000000000001‐Hexanal lb/h 0000000000000000000000Dimethoxytetrahydrofuran lb/h 0000000000000000000000Cyclohexane lb/h 0 000000000000000000000N‐Hexane lb/h 0000000000000000000000Hexanol lb/h 0000000000000000000000Toluene lb/h 00000000000000000000002‐Methylphenol lb/h 0 0000000000000000000003‐Methyl‐phenol lb/h 0000000000000000000000Guaiacol lb/h 0 000000000000000000000Methyl‐Cyclohexane lb/h 0 0000000000000000000002‐Methylhexane lb/h 0000000000000000000000VinylPhenol lb/h 0 000000000000000000000O‐Xylene lb/h 0000000000000000000000Ethylbenzne lb/h 00000000000000000000002,3‐Dimethyl‐phenol lb/h 0 0000000000000000000002,6‐dimethoxyphenol lb/h 0 000000000000000000000Vanillyl alcohol lb/h 0 0000000000000000000002,4,6‐Trimethylpyridine lb/h 0000000000000000000000Cis‐1,2‐dimethyl cyclohexane lb/h 0000000000000000000000Trans‐1,2‐dimethylcyclohexane lb/h 0000000000000000000000Ethylcyclohexane lb/h 00000000000000000000004‐Methylheptane lb/h 00000000000000000000002‐Methyl‐Benzofuran lb/h 0 000000000000000000000Indane lb/h 00000000000000000000002‐methoxy‐4‐vinylphenol lb/h 0 000000000000000000000Syringaldehyde lb/h 0000000000000000000000n‐Propylbenzene lb/h 0000000000000000000000Naphthalene lb/h 00000000000000000000001‐Naphthalenol lb/h 0 000000000000000000000Coniferyl Aldehyde lb/h 0000000000000000000000Tetralin lb/h 0000000000000000000000Isoeugenol lb/h 0 000000000000000000000Decalin lb/h 00000000000000000000002,5‐Dimethyloctane lb/h 00000000000000000000001‐Methyl naphthalene lb/h 0 0000000000000000000001‐methyl decahydronaphthene lb/h 0000000000000000000000Dibenzothiophene lb/h 0000000000000000000000Biphenyl lb/h 00000000000000000000005‐hexyl‐O‐cresol lb/h 0000000000000000000000n‐Heptylcyclohexane lb/h 0000000000000000000000C14H20‐N35 lb/h 0000000000000000000000C14H24‐N5 lb/h 00000000000000000000003,5‐Dimethyldodecane lb/h 0000000000000000000000C15H26‐N4 lb/h 00000000000000000000006,8‐Dimethyltridecane lb/h 00000000000000000000001,4‐Dimethyl‐Phenanthrene lb/h 0000000000000000000000N‐Cetane lb/h 0000000000000000000000C18H26O lb/h 0000000000000000000000C18H28 lb/h 0000000000000000000000C21H26O2 lb/h 0000000000000000000000C21H34 lb/h 0000000000000000000000C22H28O2 lb/h 0000000000000000000000Carbon lb/h 0000000000000000000000Sulfur lb/h 0000000000000000000000Sand/Catalyst Solids lb/h 0000000000000000000000Ash lb/h 0000000000000000000000Wood lb/h 0000000000000000000000Char lb/h 0000000000000000000000Coke lb/h 0000000000000000000000

146
Rev:

2

Project No: Drawing:

30482.00 PFD-61712-A803

THERMOCHEMICAL CONVERSION OF BIOMASS

TO HYDROCARBON FUEL

CATALYTIC FAST PYROLYSIS

PROCESS FLOW DIAGRAM

AREA 800: CLARIFIER AND SAND FILTER

Rev. Date By Description

SOLIDS

FROM S-319/S-324/S-329

PFD-61712-A302

T-809

SLURRY

TANK

T-809

P-809

M-807

FLOCCULANT/

COAGULANT

M-806

M-805

M-805

CLARIFIER

M-807

SAND

FILTER

P-809

SLURRY

PUMP

M-806

BELT

PRESS

J:\1A - Process Solutions\30482 NREL Thermochemical Conv - Design-Model\Drawings\ 30482 Pyrolysis In-Situ PFDs 61712 150128.vsd Plot date: 1/29/2015

SOLIDS TO DISPOSAL

0 9/29/14 JAR ISSUED FOR DESIGN REPORT

335

T-801

P-801

P-801

CLARIFIER

OVERFLOW PUMP

T-801

CLARIFIER

OVERFLOW TANK

SAND FILTER FILTRATE

TO M-701/P-708

PFD-61712-A701

BACKWASH

WASTE WATER

FROM S-411/S-461/M-861

PFD-61712-A804

880

1 12/12/14 DMS UPDATED EQ NUMBERS 2 12/29/14 JAR MINOR UPDATES

147
PFD‐61712‐A803 335 880 

Total Flow lb/h 43 21,470 00000000000000000000Temperature F 90 111 00000000000000000000Pressure Psia 104 15 00000000000000000000Vapor Fraction 0 0 00000000000000000000Enthalpy Flow MMBtu/h 0 ‐146 00000000000000000000Argon lb/h 0 0 00000000000000000000Nitrogen lb/h 0 0 00000000000000000000Oxygen lb/h 0 0 00000000000000000000SO2 lb/h 0 0 00000000000000000000NO2 lb/h 0 0 00000000000000000000Hydrogen lb/h 0 0 00000000000000000000Ammonia lb/h 0 36 00000000000000000000H2S lb/h 0 0 00000000000000000000Water lb/h 5 21,410 00000000000000000000Carbon Monoxide lb/h 0 0 00000000000000000000Carbon Dioxide lb/h 0 1 00000000000000000000Methane lb/h 0 0 00000000000000000000Methanol lb/h 0 0 00000000000000000000Formic Acid lb/h 0 0 00000000000000000000Glyoxal lb/h 0 0 00000000000000000000Ethylene lb/h 0 0 00000000000000000000Acetaldehyde lb/h 0 0 00000000000000000000Hydroxyacetaldehyde lb/h 0000000000000000000000Acetic Acid lb/h 0 0 00000000000000000000Ethane lb/h 0 0 00000000000000000000Propylene lb/h 0 0 000000000000000000001‐Hydroxy‐2‐propanone lb/h 0000000000000000000000Propionic Acid lb/h 0000000000000000000000Propane lb/h 0 0 00000000000000000000Furan lb/h 0 0 000000000000000000001‐Butene lb/h 0 0 00000000000000000000Tetrahydrofuran lb/h 0 0 00000000000000000000N‐Butane lb/h 0 0 00000000000000000000Furfural lb/h 00000000000000000000002‐methylfuran lb/h 0 0 00000000000000000000Furfuryl Alcohol lb/h 0000000000000000000000n‐Pentane lb/h 0 0 00000000000000000000Pentenone lb/h 0000000000000000000000Benzene lb/h 0 0 00000000000000000000Phenol lb/h 2 5 000000000000000000001,2‐Benzenediol lb/h 0 19 00000000000000000000Hydroxymethylfurfural lb/h 00000000000000000000002,5‐dimethylfuran lb/h 0 0 00000000000000000000Methyl Cyclopentenone lb/h 0000000000000000000000Hydroxymethylcyclopentenone lb/h 0000000000000000000000Cyclohexanone lb/h 0000000000000000000000Levoglucosan lb/h 00000000000000000000001‐Hexanal lb/h 0000000000000000000000Dimethoxytetrahydrofuran lb/h 0 0 00000000000000000000Cyclohexane lb/h 0 0 00000000000000000000N‐Hexane lb/h 0 0 00000000000000000000Hexanol lb/h 0000000000000000000000Toluene lb/h 0 0 000000000000000000002‐Methylphenol lb/h 1 0 000000000000000000003‐Methyl‐phenol lb/h 0000000000000000000000Guaiacol lb/h 0 0 00000000000000000000Methyl‐Cyclohexane lb/h 0 0 000000000000000000002‐Methylhexane lb/h 0 0 00000000000000000000VinylPhenol lb/h 0 0 00000000000000000000O‐Xylene lb/h 0 0 00000000000000000000Ethylbenzne lb/h 0 0 000000000000000000002,3‐Dimethyl‐phenol lb/h 1 0 000000000000000000002,6‐dimethoxyphenol lb/h 4 0 00000000000000000000Vanillyl alcohol lb/h 0 0 000000000000000000002,4,6‐Trimethylpyridine lb/h 0 0 00000000000000000000Cis‐1,2‐dimethyl cyclohexane lb/h 3 0 00000000000000000000Trans‐1,2‐dimethylcyclohexane lb/h 3 0 00000000000000000000Ethylcyclohexane lb/h 0 0 000000000000000000004‐Methylheptane lb/h 0 0 000000000000000000002‐Methyl‐Benzofuran lb/h 0 0 00000000000000000000Indane lb/h 00000000000000000000002‐methoxy‐4‐vinylphenol lb/h 0 0 00000000000000000000Syringaldehyde lb/h 0000000000000000000000n‐Propylbenzene lb/h 0 0 00000000000000000000Naphthalene lb/h 0 0 000000000000000000001‐Naphthalenol lb/h 0 0 00000000000000000000Coniferyl Aldehyde lb/h 0 0 00000000000000000000Tetralin lb/h 0 0 00000000000000000000Isoeugenol lb/h 0 0 00000000000000000000Decalin lb/h 1 0 000000000000000000002,5‐Dimethyloctane lb/h 0 0 000000000000000000001‐Methyl naphthalene lb/h 1 0 000000000000000000001‐methyl decahydronaphthene lb/h 1 0 00000000000000000000Dibenzothiophene lb/h 0 000000000000000000000Biphenyl lb/h 0 0 000000000000000000005‐hexyl‐O‐cresol lb/h 0 0 00000000000000000000n‐Heptylcyclohexane lb/h 0 0 00000000000000000000C14H20‐N35 lb/h 0 0 00000000000000000000C14H24‐N5 lb/h 0 0 000000000000000000003,5‐Dimethyldodecane lb/h 0 0 00000000000000000000C15H26‐N4 lb/h 1 0 000000000000000000006,8‐Dimethyltridecane lb/h 0 0 000000000000000000001,4‐Dimethyl‐Phenanthrene lb/h 0 0 00000000000000000000N‐Cetane lb/h 0 0 00000000000000000000C18H26O lb/h 0 000000000000000000000C18H28 lb/h 0 0 00000000000000000000C21H26O2 lb/h 0 0 00000000000000000000C21H34 lb/h 0 0 00000000000000000000C22H28O2 lb/h 0 0 00000000000000000000Carbon lb/h 0000000000000000000000Sulfur lb/h 0000000000000000000000Sand/Catalyst Solids lb/h 14 000000000000000000000Ash lb/h 0 000000000000000000000Wood lb/h 0 000000000000000000000Char lb/h 2 000000000000000000000Coke lb/h 1 000000000000000000000

148
Rev:

1

Project No: Drawing:

30482.00 PFD-61712-A804

THERMOCHEMICAL CONVERSION OF BIOMASS

TO HYDROCARBON FUEL

CATALYTIC FAST PYROLYSIS

PROCESS FLOW DIAGRAM

AREA 800: WASTEWATER REVERSE OSMOSIS

Rev. Date By Description 0 9/29/14 JAR ISSUED FOR DESIGN REPORT

J:\1A - Process Solutions\30482 NREL Thermochemical Conv - Design-Model\Drawings\ 30482 Pyrolysis In-Situ PFDs 61712 150128.vsd Plot date: 1/29/2015

AQUEOUS PHASE

FROM S-411

PFD-61712-A401

CONDENSATE

FROM P-576

PFD-61712-A503

CONDENSATE

FROM P-377

PFD-61712-A304

AQUEOUS PHASE

FROM S-461

PFD-61712-A403

576

424

377

474

T-860

RO FEED TANK

AQUEOUS PHASE

FROM S-412

PFD-61712-A401

430

WASTE WATER

TO M-805

PFD-61712-A803

864

CT BLOWDOWN

FROM P-701

PFD-61712-A701

713

BLOWDOWN 124

FROM P-708

PFD-61712-A701

T-860

P-860

RO FEED PUMP

M-861

REVERSE OSMOSIS

UNIT

RO

M-861 P-860

W-P860

T-866

P-866

W-P866

CLEAN WATER

HEADER

T-866

CLEAN WATER

TANK

P-866

CLEAN WATER

PUMP

865

880

860

CLEAN WATER

TO R-202C/H-210B

PFD-61712-A201

RO BRINE

1 12/12/14 DMS UPDATED EQ NUMBERS

149
PFD‐61712‐A804 124 377 424 430 474 576 713 860 864 865 880 

Total Flow lb/h 22,360 19,648 4,696 0 80 13,980 10,788 66,776 16,694 50,082 21,470 00000000000Temperature F 119 110 110 0 110 110 90 110 110 110 111 00000000000Pressure Psia 14 87 1793 0 1893 102 15 14 15 15 15 00000000000Vapor Fraction 0000000 0000 00000000000Enthalpy Flow MMBtu/h ‐152 ‐134 ‐32 0 ‐1 ‐95 ‐74 ‐455 ‐114 ‐341 ‐146 00000000000Argon lb/h 0 000000 0000 00000000000Nitrogen lb/h 0 0000 0 0 0000 00000000000Oxygen lb/h 0 000000 0000 00000000000SO2 lb/h 0 0000 0 0 0000 00000000000NO2 lb/h 0 000000 0000 00000000000Hydrogen lb/h 0 0 0 0 0 0 0 0000 00000000000Ammonia lb/h 0 0 36 0 0 0 0 0 0 0 36 00000000000H2S lb/h 0 0 0 0 0 0 0 0000 00000000000Water lb/h 22,360 19,552 4,660 0 80 13,979 10,788 66,679 16,670 50,009 21,410 00000000000Carbon Monoxide lb/h 0 0 0 0 0 0 0 0000 00000000000Carbon Dioxide lb/h 010 0 0 1 0 3121 00000000000Methane lb/h 0 0 0 0 0 0 0 0000 00000000000Methanol lb/h 00000 0 0 0000 00000000000Formic Acid lb/h 00000 0 0 0000 00000000000Glyoxal lb/h 00000 0 0 0000 00000000000Ethylene lb/h 0 0 0 0 0 0 0 0000 00000000000Acetaldehyde lb/h 00000 0 0 0000 00000000000Hydroxyacetaldehyde lb/h 0000000000000000000000Acetic Acid lb/h 00000 0 0 0000 00000000000Ethane lb/h 0 0 0 0 0 0 0 0000 00000000000Propylene lb/h 0 0 0 0 0 0 0 0000 000000000001‐Hydroxy‐2‐propanone lb/h 0000000000000000000000Propionic Acid lb/h 0000000000000000000000Propane lb/h 0 0 0 0 0 0 0 0000 00000000000Furan lb/h 0 0 00000 0000 000000000001‐Butene lb/h 0 0 0 0000 0000 00000000000Tetrahydrofuran lb/h 0 0 00000 0000 00000000000N‐Butane lb/h 0 0 0 0000000 0 00000000000Furfural lb/h 00000000000000000000002‐methylfuran lb/h 0 0 00000 0000 00000000000Furfuryl Alcohol lb/h 0000000000000000000000n‐Pentane lb/h 0 0 0 0000000 0 00000000000Pentenone lb/h 0000000000000000000000Benzene lb/h 0 0 0 0000000 0 00000000000Phenol lb/h 0 19 0 0000 19 5 14 5 000000000001,2‐Benzenediol lb/h 0 75 00000 75 19 56 19 00000000000Hydroxymethylfurfural lb/h 00000000000000000000002,5‐dimethylfuran lb/h 0 0 0 0000 0000 00000000000Methyl Cyclopentenone lb/h 0000000000000000000000Hydroxymethylcyclopentenone lb/h 0000000000000000000000Cyclohexanone lb/h 0000000000000000000000Levoglucosan lb/h 00000000000000000000001‐Hexanal lb/h 0000000000000000000000Dimethoxytetrahydrofuran lb/h 0 0 00000 0000 00000000000Cyclohexane lb/h 0 0 0 0 0 0 0 0000 00000000000N‐Hexane lb/h 0 0 0 0 0 00000 0 00000000000Hexanol lb/h 0000000000000000000000Toluene lb/h 0 0 0 0000000 0 000000000002‐Methylphenol lb/h 0 0 00000 0000 000000000003‐Methyl‐phenol lb/h 0000000000000000000000Guaiacol lb/h 0 0 00000 0000 00000000000Methyl‐Cyclohexane lb/h 0 0 0 0000 0000 000000000002‐Methylhexane lb/h 0 0 0 0 0 00000 0 00000000000VinylPhenol lb/h 0 0 00000 0000 00000000000O‐Xylene lb/h 0 0 0 0000000 0 00000000000Ethylbenzne lb/h 0 0 0 0000000 0 000000000002,3‐Dimethyl‐phenol lb/h 0 0 00000 0000 000000000002,6‐dimethoxyphenol lb/h 0 0 00000 0000 00000000000Vanillyl alcohol lb/h 0 0 00000 0000 000000000002,4,6‐Trimethylpyridine lb/h 0 0 00000 0000 00000000000Cis‐1,2‐dimethyl cyclohexane lb/h 0 0 0 0000 0000 00000000000Trans‐1,2‐dimethylcyclohexane lb/h 0 0 0 0000 0000 00000000000Ethylcyclohexane lb/h 0 0 0 0000000 0 000000000004‐Methylheptane lb/h 0 0 0 0000000 0 000000000002‐Methyl‐Benzofuran lb/h 0 0 00000 0000 00000000000Indane lb/h 00000000000000000000002‐methoxy‐4‐vinylphenol lb/h 0 0 00000 0000 00000000000Syringaldehyde lb/h 0000000000000000000000n‐Propylbenzene lb/h 0 0 0 0000000 0 00000000000Naphthalene lb/h 0 0 0 0 0 00000 0 000000000001‐Naphthalenol lb/h 0 0 00000 0000 00000000000Coniferyl Aldehyde lb/h 0 0 00000 0000 00000000000Tetralin lb/h 0 0 0 0 0 00000 0 00000000000Isoeugenol lb/h 0 0 00000 0000 00000000000Decalin lb/h 0 0 0 0 0 0 0 0000 000000000002,5‐Dimethyloctane lb/h 0000 0 00000 0 000000000001‐Methyl naphthalene lb/h 0 0 0 0 0 0 0 0000 000000000001‐methyl decahydronaphthene lb/h 0 0 0 0 0 0 0 0000 00000000000Dibenzothiophene lb/h 0000000000000000000000Biphenyl lb/h 0 0 0 0 0 00000 0 000000000005‐hexyl‐O‐cresol lb/h 0 0 00000 0000 00000000000n‐Heptylcyclohexane lb/h 0 0 0 0 0 00000 0 00000000000C14H20‐N35 lb/h 0 0 0 0 0 00000 0 00000000000C14H24‐N5 lb/h 0 0 0 0 0 0 0 0000 000000000003,5‐Dimethyldodecane lb/h 0 0 0 0 0 00000 0 00000000000C15H26‐N4 lb/h 0 0 0 0 0 0 0 0000 000000000006,8‐Dimethyltridecane lb/h 0000 0 00000 0 000000000001,4‐Dimethyl‐Phenanthrene lb/h 0 0 0 0 0 00000 0 00000000000N‐Cetane lb/h 0000 0 00000 0 00000000000C18H26O lb/h 0000000000000000000000C18H28 lb/h 0 0 0 0 0 00000 0 00000000000C21H26O2 lb/h 0 0 0 0000000 0 00000000000C21H34 lb/h 0 0 0 0000 0000 00000000000C22H28O2 lb/h 0 0 0 0000000 0 00000000000Carbon lb/h 0000000000000000000000Sulfur lb/h 0000000000000000000000Sand/Catalyst Solids lb/h 0000000000000000000000Ash lb/h 0000000000000000000000Wood lb/h 0000000000000000000000Char lb/h 0000000000000000000000Coke lb/h 0000000000000000000000

150
151

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Appendix G-2. Process Flow Diagrams and Stream 

Summary for the Ex Situ Case, Including Detailed Heat 

Exchange Network
Rev:

1

Project No: Drawing:

30482.00 PFD-61712-A101

THERMOCHEMICAL CONVERSION OF BIOMASS

TO HYDROCARBON FUEL

FAST PYROLYSIS AND VAPOR PHASE UPGRADING

PROCESS FLOW DIAGRAM

AREA 100: FEED HANDLING

Rev. Date By Description

J:\1A - Process Solutions\30482 NREL Thermochemical Conv - Design-Model\Drawings\ Plot date: 1/29/2015

BIOMASS

TO C-104

PFD-61712-A102

BIOMASS

T-103

101

METAL DEBRIS TO

DISPOSAL

CHIP PILE M-103

C-103

S-102

C-102

C-101

T-101

M-101

M-101

HYDRAULIC TRUCK

DUMP WITH SCALE

C-102

SCREENER FEEDER

CONVEYOR

C-101

HOPPER FEEDER

T-101

DUMP HOPPER

S-101

MAGNETIC

HEAD PULLEY

S-102

VIBRATORY

CONVEYOR

C-103

RADIAL STACKER

CONVEYOR

M-103

FRONT END

LOADERS

T-103

DRYER FEED

BIN

S-101

30482 Pyrolysis Ex-Situ PFDs 61712 150128.vsd

0 9/29/14 JAR ISSUED FOR DESIGN REPORT

NOTE: FEEDSTOCK HANDLING COSTS ARE INCLUDED IN THE TARGET FEEDSTOCK COST PROVIDED BY THE IDAHO NATIONAL

LABORATORY. ONLY A CROSS FLOW DRYER USING PROCESS FLUE GASES FOR FEED PREHEAT IS INCLUDED IN THE CONVERSION COST.

1 12/12/14 DMS ADDED HX NETWORK

152
PFD‐61712‐A101 101 

Total Flow lb/h 204,131 000000000000000000000Temperature F 60 000000000000000000000Pressure Psia 15 000000000000000000000Vapor Fraction 0000000000000000000000Enthalpy Flow MMBtu/h ‐569 000000000000000000000Argon lb/h 0000000000000000000000Nitrogen lb/h 0000000000000000000000Oxygen lb/h 0000000000000000000000SO2 lb/h 0000000000000000000000NO2 lb/h 0000000000000000000000Hydrogen lb/h 0000000000000000000000Ammonia lb/h 0000000000000000000000H2S lb/h 0000000000000000000000Water lb/h 20,413 000000000000000000000Carbon Monoxide lb/h 0000000000000000000000Carbon Dioxide lb/h 0000000000000000000000Methane lb/h 0000000000000000000000Methanol lb/h 0000000000000000000000Formic Acid lb/h 0000000000000000000000Glyoxal lb/h 0000000000000000000000Ethylene lb/h 0000000000000000000000Acetaldehyde lb/h 0000000000000000000000Hydroxyacetaldehyde lb/h 0000000000000000000000Acetic Acid lb/h 0000000000000000000000Ethane lb/h 0000000000000000000000Propylene lb/h 00000000000000000000001‐Hydroxy‐2‐propanone lb/h 0000000000000000000000Propionic Acid lb/h 0000000000000000000000Propane lb/h 0000000000000000000000Furan lb/h 00000000000000000000001‐Butene lb/h 0000000000000000000000Tetrahydrofuran lb/h 0000000000000000000000N‐Butane lb/h 0000000000000000000000Furfural lb/h 00000000000000000000002‐methylfuran lb/h 0000000000000000000000Furfuryl Alcohol lb/h 0000000000000000000000n‐Pentane lb/h 0000000000000000000000Pentenone lb/h 0000000000000000000000Benzene lb/h 0000000000000000000000Phenol lb/h 00000000000000000000001,2‐Benzenediol lb/h 0000000000000000000000Hydroxymethylfurfural lb/h 00000000000000000000002,5‐dimethylfuran lb/h 0000000000000000000000Methyl Cyclopentenone lb/h 0000000000000000000000Hydroxymethylcyclopentenone lb/h 0000000000000000000000Cyclohexanone lb/h 0000000000000000000000Levoglucosan lb/h 00000000000000000000001‐Hexanal lb/h 0000000000000000000000Dimethoxytetrahydrofuran lb/h 0000000000000000000000Cyclohexane lb/h 0000000000000000000000N‐Hexane lb/h 0000000000000000000000Hexanol lb/h 0000000000000000000000Toluene lb/h 00000000000000000000002‐Methylphenol lb/h 00000000000000000000003‐Methyl‐phenol lb/h 0000000000000000000000Guaiacol lb/h 0000000000000000000000Methyl‐Cyclohexane lb/h 00000000000000000000002‐Methylhexane lb/h 0000000000000000000000VinylPhenol lb/h 0000000000000000000000O‐Xylene lb/h 0000000000000000000000Ethylbenzne lb/h 00000000000000000000002,3‐Dimethyl‐phenol lb/h 00000000000000000000002,6‐dimethoxyphenol lb/h 0000000000000000000000Vanillyl alcohol lb/h 00000000000000000000002,4,6‐Trimethylpyridine lb/h 0000000000000000000000Cis‐1,2‐dimethyl cyclohexane lb/h 0000000000000000000000Trans‐1,2‐dimethylcyclohexane lb/h 0000000000000000000000Ethylcyclohexane lb/h 00000000000000000000004‐Methylheptane lb/h 00000000000000000000002‐Methyl‐Benzofuran lb/h 0000000000000000000000Indane lb/h 00000000000000000000002‐methoxy‐4‐vinylphenol lb/h 0000000000000000000000Syringaldehyde lb/h 0000000000000000000000n‐Propylbenzene lb/h 0000000000000000000000Naphthalene lb/h 00000000000000000000001‐Naphthalenol lb/h 0000000000000000000000Coniferyl Aldehyde lb/h 0000000000000000000000Tetralin lb/h 0000000000000000000000Isoeugenol lb/h 0000000000000000000000Decalin lb/h 00000000000000000000002,5‐Dimethyloctane lb/h 00000000000000000000001‐Methyl naphthalene lb/h 00000000000000000000001‐methyl decahydronaphthene lb/h 0000000000000000000000Dibenzothiophene lb/h 0000000000000000000000Biphenyl lb/h 00000000000000000000005‐hexyl‐O‐cresol lb/h 0000000000000000000000n‐Heptylcyclohexane lb/h 0000000000000000000000C14H20‐N35 lb/h 0000000000000000000000C14H24‐N5 lb/h 00000000000000000000003,5‐Dimethyldodecane lb/h 0000000000000000000000C15H26‐N4 lb/h 00000000000000000000006,8‐Dimethyltridecane lb/h 00000000000000000000001,4‐Dimethyl‐Phenanthrene lb/h 0000000000000000000000N‐Cetane lb/h 0000000000000000000000C18H26O lb/h 0000000000000000000000C18H28 lb/h 0000000000000000000000C21H26O2 lb/h 0000000000000000000000C21H34 lb/h 0000000000000000000000C22H28O2 lb/h 0000000000000000000000Carbon lb/h 0000000000000000000000Sulfur lb/h 0000000000000000000000Sand/Catalyst Solids lb/h 0000000000000000000000Ash lb/h 0 000000000000000000000Wood lb/h 183,718 000000000000000000000Char lb/h 0 000000000000000000000Coke lb/h 0 000000000000000000000

153
BIOMASS

FROM T-103

PFD-61712-A101

Rev:

2

Project No: Drawing:

30482.00 PFD-61712-A102

THERMOCHEMICAL CONVERSION OF BIOMASS

TO HYDROCARBON FUEL

FAST PYROLYSIS AND VAPOR PHASE UPGRADING

PROCESS FLOW DIAGRAM

AREA 100: FEED HANDLING AND DRYING

Rev. Date By Description

J:\1A - Process Solutions\30482 NREL Thermochemical Conv - Design-Model\Drawings\ Plot date: 1/29/2015

FLUE GAS

TO M-703

PFD-61712-A701

C-104

FLUE GAS

FROM R-530

PFD-61712-A501-A

PRESSURIZED INERT

GASES

M-104

T-106

T-105

T-104

K-101

110

101 103

C-104

DRYER FEED SCREW

CONVEYOR

M-104

CROSS FLOW

PELLET DRYER

T-104

DRIED BIOMASS

HOPPER

T-105

LOCK

HOPPER

T-106

FEED

HOPPER

K-101

FLUE GAS

BLOWER

107

108

102

FLUE GAS

FROM H-BP-16

PFD-61712-A201

FLUE GAS

FROM H-BP-13

PFD-61712-A802

549

239P

841

30482 Pyrolysis Ex-Situ PFDs 61712 150128.vsd

0 9/29/14 JAR ISSUED FOR DESIGN REPORT

M-102

T-102

M-102

HAMMERMILL

T-102

HAMMERMILL

SURGE BIN

MILLED BIOMASS

TO R-211

PFD-61712-A201

105

C-105

BIOMASS FEED

SCREW CONVEYOR

C-105

VPU FLUE GAS

FROM H-BP-17

PFD-61712-A202

297

NOTE: FEEDSTOCK HANDLING COSTS ARE INCLUDED IN THE TARGET FEEDSTOCK COST PROVIDED BY THE IDAHO NATIONAL

LABORATORY. ONLY A CROSS FLOW DRYER USING PROCESS FLUE GASES FOR FEED PREHEAT IS INCLUDED IN THE CONVERSION COST.

W-K101

1 12/12/14 DMS ADDED HX NETWORK 2 12/29/14 JAR MINOR UPDATES

104

154
PFD‐61712‐A102 101 102 103 104 105 107 108 110 239P 297 549 841 

Total Flow lb/h 204,131 204,131 204,131 204,131 204,131 770,436 770,436 770,436 258,265 210,963 220,944 80,265 0000000000Temperature F 60 60 218 218 218 243 160 160 245 245 245 245 0000000000Pressure Psia 15 16 16 16 125 17 16 16 109 105 17 17 0000000000Vapor Fraction 00000 1111111 0000000000Enthalpy Flow MMBtu/h ‐569 ‐569 ‐553 ‐553 ‐553 ‐989 ‐1005 ‐1005 ‐284 ‐213 ‐463 ‐28 0000000000Argon lb/h 00000 8,183 8,183 8,183 3,005 2,478 1,721 979 0000000000Nitrogen lb/h 00000 480,047 480,047 480,047 176,443 145,311 100,912 57,382 0000000000Oxygen lb/h 00000 38,240 38,240 38,240 8,996 7,421 6,218 15,606 0000000000SO2 lb/h 00000 107 107 107 85 0 23 0 0000000000NO2 lb/h 00000 17 17 17 0 0 17 00000000000Hydrogen lb/h 0000000000000000000000Ammonia lb/h 0000000000000000000000H2S lb/h 0000000000000000000000Water lb/h 20,413 20,413 20,413 20,413 20,413 42,895 42,895 42,895 13,826 3,830 21,487 3,752 0000000000Carbon Monoxide lb/h 0000000000000000000000Carbon Dioxide lb/h 00000 200,947 200,947 200,947 55,910 51,924 90,566 2,547 0000000000Methane lb/h 0000000000000000000000Methanol lb/h 0000000000000000000000Formic Acid lb/h 0000000000000000000000Glyoxal lb/h 0000000000000000000000Ethylene lb/h 0000000000000000000000Acetaldehyde lb/h 0000000000000000000000Hydroxyacetaldehyde lb/h 0000000000000000000000Acetic Acid lb/h 0000000000000000000000Ethane lb/h 0000000000000000000000Propylene lb/h 00000000000000000000001‐Hydroxy‐2‐propanone lb/h 0000000000000000000000Propionic Acid lb/h 0000000000000000000000Propane lb/h 0000000000000000000000Furan lb/h 00000000000000000000001‐Butene lb/h 0000000000000000000000Tetrahydrofuran lb/h 0000000000000000000000N‐Butane lb/h 0000000000000000000000Furfural lb/h 00000000000000000000002‐methylfuran lb/h 0000000000000000000000Furfuryl Alcohol lb/h 0000000000000000000000n‐Pentane lb/h 0000000000000000000000Pentenone lb/h 0000000000000000000000Benzene lb/h 0000000000000000000000Phenol lb/h 00000000000000000000001,2‐Benzenediol lb/h 0000000000000000000000Hydroxymethylfurfural lb/h 00000000000000000000002,5‐dimethylfuran lb/h 0000000000000000000000Methyl Cyclopentenone lb/h 0000000000000000000000Hydroxymethylcyclopentenone lb/h 0000000000000000000000Cyclohexanone lb/h 0000000000000000000000Levoglucosan lb/h 00000000000000000000001‐Hexanal lb/h 0000000000000000000000Dimethoxytetrahydrofuran lb/h 0000000000000000000000Cyclohexane lb/h 0000000000000000000000N‐Hexane lb/h 0000000000000000000000Hexanol lb/h 0000000000000000000000Toluene lb/h 00000000000000000000002‐Methylphenol lb/h 00000000000000000000003‐Methyl‐phenol lb/h 0000000000000000000000Guaiacol lb/h 0000000000000000000000Methyl‐Cyclohexane lb/h 00000000000000000000002‐Methylhexane lb/h 0000000000000000000000VinylPhenol lb/h 0000000000000000000000O‐Xylene lb/h 0000000000000000000000Ethylbenzne lb/h 00000000000000000000002,3‐Dimethyl‐phenol lb/h 00000000000000000000002,6‐dimethoxyphenol lb/h 0000000000000000000000Vanillyl alcohol lb/h 00000000000000000000002,4,6‐Trimethylpyridine lb/h 0000000000000000000000Cis‐1,2‐dimethyl cyclohexane lb/h 0000000000000000000000Trans‐1,2‐dimethylcyclohexane lb/h 0000000000000000000000Ethylcyclohexane lb/h 00000000000000000000004‐Methylheptane lb/h 00000000000000000000002‐Methyl‐Benzofuran lb/h 0000000000000000000000Indane lb/h 00000000000000000000002‐methoxy‐4‐vinylphenol lb/h 0000000000000000000000Syringaldehyde lb/h 0000000000000000000000n‐Propylbenzene lb/h 0000000000000000000000Naphthalene lb/h 00000000000000000000001‐Naphthalenol lb/h 0000000000000000000000Coniferyl Aldehyde lb/h 0000000000000000000000Tetralin lb/h 0000000000000000000000Isoeugenol lb/h 0000000000000000000000Decalin lb/h 00000000000000000000002,5‐Dimethyloctane lb/h 00000000000000000000001‐Methyl naphthalene lb/h 00000000000000000000001‐methyl decahydronaphthene lb/h 0000000000000000000000Dibenzothiophene lb/h 0000000000000000000000Biphenyl lb/h 00000000000000000000005‐hexyl‐O‐cresol lb/h 0000000000000000000000n‐Heptylcyclohexane lb/h 0000000000000000000000C14H20‐N35 lb/h 0000000000000000000000C14H24‐N5 lb/h 00000000000000000000003,5‐Dimethyldodecane lb/h 0000000000000000000000C15H26‐N4 lb/h 00000000000000000000006,8‐Dimethyltridecane lb/h 00000000000000000000001,4‐Dimethyl‐Phenanthrene lb/h 0000000000000000000000N‐Cetane lb/h 0000000000000000000000C18H26O lb/h 0000000000000000000000C18H28 lb/h 0000000000000000000000C21H26O2 lb/h 0000000000000000000000C21H34 lb/h 0000000000000000000000C22H28O2 lb/h 0000000000000000000000Carbon lb/h 0000000000000000000000Sulfur lb/h 0000000000000000000000Sand/Catalyst Solids lb/h 0000000000000000000000Ash lb/h 00000 00000000000000000Wood lb/h 183,718 183,718 183,718 183,718 183,718 00000000000000000Char lb/h 00000 00000000000000000Coke lb/h 00000 00000000000000000

155
R-211

Rev:

2

Project No: Drawing:

30482.00 PFD-61712-A201

THERMOCHEMICAL CONVERSION OF BIOMASS

TO HYDROCARBON FUEL

FAST PYROLYSIS AND VAPOR PHASE UPGRADING

PROCESS FLOW DIAGRAM

AREA 200: FAST PYROLYSIS

MILLED BIOMASS

FROM C-105

PFD-61712-A102

S-211

T-211

S-212

R-212

S-213

T-212

DEPLETED MEDIA/ASH

TO DISPOSAL

FLUIDIZING GAS

FROM M-385/M-575/H-315

PFD-61712-A302

PYROLYSIS VAPOR

TO R-261

PFD-61712-A202

FLUE GAS

TO M-104

PFD-61712-A102

COMBUSTION

AIR

S-214

T-217

Rev. Date By Description

0 9/29/14 JAR ISSUED FOR DESIGN REPORT

R-212C

LIFT AIR

FLUIDIZATION

AIR

QC-M212

C-212

W-K211

W-K212

223P

224P 225P

228P

233P

235-P

346

203P 204P

212P

213P

214P

232P 239P

216P

261

K-212

COMBUSTOR AIR

COMPRESSOR

K-211

FLUIDIZING GAS RECYCLE

COMPRESSOR

R-211

FLUIDIZED BED

REACTOR

S-211

PRIMARY

CYCLONE

S-212

SECONDARY

CYCLONE

R-212

CHAR

COMBUSTOR

S-213

CHAR COMBUSTOR

PRIMARY CYCLONE

S-214

CHAR COMBUSTOR

SECONDARY CYCLONE

T-212

DEPLETED BED MEDIA

AND ASH STORAGE BIN

T-217

CHAR COMBUSTOR

BED MEDIA FEED BIN

R-212C

SAND

COOLER

105

OLIVINE

FROM M-702

PFD-61712-A702

C-212

FINES PURGE

COOLER

J:\1A - Process Solutions\30482 NREL Thermochemical Conv - Design-Model\Drawings\ Plot date: 3/16/2015 30482 Pyrolysis Ex-Situ PFDs 61712 150316.vsd

T-211

BED

MEDIA BIN

SATURATED STEAM

TO T-605

PFD-61712-A603

SATURATED WATER

FROM H-AP-51

PFD-61712-A603

QA-K212

K-212

K-211

COMBUSTION AIR

TO H-AP-17

PFD-61712-A203

COMBUSTION AIR

FROM H-AP-38

PFD-61712-A203

FLUIDIZING GAS

TO H-BP-36

PFD-61712-A203

FLUIDIZING GAS

FROM H-AP-8

PFD-61712-A203

FLUE GAS

TO H-AP-9

PFD-61712-A203

FLUE GAS

FROM H-BP-16

PFD-61712-A203

SATURATED STEAM

FROM T-605

PFD-61712-A603

H-AP-1

CHAR COMBUSTOR

SAND COOLER/

STEAM PRODUCTION

H-AP-2

CHAR COMBUSTOR

SAND COOLER/STEAM

SUPERHEAT

H-AP-1

H-AP-2

QHAP2

QHAP1

SUPERHEATED STEAM

TO M-602

PFD-61712-A603

1 12/12/14 DMS ADDED HX NETWORK

2 12/29/14 JAR MINOR UPDATES

217P

205P

156
PFD‐61712‐A201 105 203P 204P 205P 212P 213P 214P 216P 217P 223P 224P 225P 228P 232P 233P 235P 239P 261 346 

Total Flow lb/h 204,131 140,215 140,215 1,438,038 1,782,384 323,959 1,458,425 1,643 158 237,911 237,911 237,911 260,099 258,265 1,834 2,038 258,265 322,317 140,215 000Temperature F 218 160 800 0 932 932 000 90 287 600 1328 1328 0 210 245 932 96 000Pressure Psia 125 127 123 125 121 120 120 119 130 15 123 119 115 115 115 15 109 119 95 000Vapor Fraction 0 1 1 0 1 1 000 11111 0 0 111 000Enthalpy Flow MMBtu/h ‐553 ‐231 ‐152 ‐8896 ‐9616 ‐540 ‐9076 ‐9 ‐1 ‐27 ‐15 4 ‐209 ‐208 ‐1 ‐3 ‐284 ‐531 ‐239 000Argon lb/h 000000000 3,005 3,005 3,005 3,005 3,005 0 0 3,005 00000Nitrogen lb/h 000000000 176,169 176,169 176,169 176,443 176,443 0 0 176,443 00000Oxygen lb/h 000000000 53,978 53,978 53,978 8,996 8,996 0 0 8,996 00000SO2 lb/h 000000000000 85 85 0 0 85 00000NO2 lb/h 0000000000000000000000Hydrogen lb/h 0 24,531 24,531 0 24,531 24,531 00000000000 24,531 24,531 000Ammonia lb/h 0000000000000000000000H2S lb/h 0000000000000000000000Water lb/h 20,413 353 353 0 40,227 40,227 000 4,642 4,642 4,642 13,826 13,826 0 204 13,826 40,227 353 000Carbon Monoxide lb/h 0 47,501 47,501 0 56,944 56,944 00000000000 56,944 47,501 000Carbon Dioxide lb/h 0 40,152 40,152 0 53,301 53,301 000 117 117 117 55,910 55,910 0 0 55,910 53,301 40,152 000Methane lb/h 0 5,884 5,884 0 6,696 6,696 00000000000 6,696 5,884 000Methanol lb/h 0000000000000000000000Formic Acid lb/h 0000000000000000000000Glyoxal lb/h 0000 1,250 1,250 00000000000 1,250 0000Ethylene lb/h 0 11,780 11,780 0 12,187 12,187 00000000000 12,187 11,780 000Acetaldehyde lb/h 0000000000000000000000Hydroxyacetaldehyde lb/h 0000 5,688 5,688 00000000000 5,688 0000Acetic Acid lb/h 0000 9,247 9,247 00000000000 9,247 0000Ethane lb/h 0000000000000000000000Propylene lb/h 0 3,982 3,982 0 4,006 4,006 00000000000 4,006 3,982 0001‐Hydroxy‐2‐propanone lb/h 0000 2,082 2,082 00000000000 2,082 0000Propionic Acid lb/h 0000 924 924 00000000000 924 0000Propane lb/h 0000000000000000000000Furan lb/h 0 500 500 0 500 500 00000000000 500 500 0001‐Butene lb/h 0 1,975 1,975 0 2,004 2,004 00000000000 2,004 1,975 000Tetrahydrofuran lb/h 0 422 422 0 422 422 00000000000 422 422 000N‐Butane lb/h 0000000000000000000000Furfural lb/h 0000 3,195 3,195 00000000000 3,195 00002‐methylfuran lb/h 0 466 466 0 466 466 00000000000 466 466 000Furfuryl Alcohol lb/h 0000 5,829 5,829 00000000000 5,829 0000n‐Pentane lb/h 0000000000000000000000Pentenone lb/h 0000000000000000000000Benzene lb/h 0000000000000000000000Phenol lb/h 0 14 14 0 446 446 00000000000 446 14 0001,2‐Benzenediol lb/h 0 0 0 0 0 0 00000000000 0 0 000Hydroxymethylfurfural lb/h 0000 6,366 6,366 00000000000 6,366 00002,5‐dimethylfuran lb/h 0 2 2 0 2 2 00000000000 2 2 000Methyl Cyclopentenone lb/h 0000 3,212 3,212 00000000000 3,212 0000Hydroxymethylcyclopentenone lb/h 0000 3,118 3,118 00000000000 3,118 0000Cyclohexanone lb/h 0000 584 584 00000000000 584 0000Levoglucosan lb/h 0000 19,211 19,211 00000000000 19,211 00001‐Hexanal lb/h 0000 1,250 1,250 00000000000 1,250 0000Dimethoxytetrahydrofuran lb/h 0 1 1 0 8,521 8,521 00000000000 8,521 1 000Cyclohexane lb/h 0 1,673 1,673 0 1,673 1,673 00000000000 1,673 1,673 000N‐Hexane lb/h 0000000000000000000000Hexanol lb/h 0000000000000000000000Toluene lb/h 00000000000000000000002‐Methylphenol lb/h 0 0 0 0 0 0 00000000000 0 0 0003‐Methyl‐phenol lb/h 0000 324 324 00000000000 324 0000Guaiacol lb/h 0 0 0 0 0 0 00000000000 0 0 000Methyl‐Cyclohexane lb/h 0 191 191 0 191 191 00000000000 191 191 0002‐Methylhexane lb/h 0000000000000000000000VinylPhenol lb/h 0 0 0 0 13,119 13,119 00000000000 13,119 0 000O‐Xylene lb/h 0000000000000000000000Ethylbenzne lb/h 00000000000000000000002,3‐Dimethyl‐phenol lb/h 0 2 2 0 2 2 00000000000 2 2 0002,6‐dimethoxyphenol lb/h 0 0 0 0 0 0 00000000000 0 0 000Vanillyl alcohol lb/h 0 0 0 0 0 0 00000000000 0 0 0002,4,6‐Trimethylpyridine lb/h 0 3 3 0 333 333 00000000000 333 3 000Cis‐1,2‐dimethyl cyclohexane lb/h 0 295 295 0 295 295 00000000000 295 295 000Trans‐1,2‐dimethylcyclohexane lb/h 0 484 484 0 484 484 00000000000 484 484 000Ethylcyclohexane lb/h 00000000000000000000004‐Methylheptane lb/h 00000000000000000000002‐Methyl‐Benzofuran lb/h 0 1 1 0 1 1 00000000000 1 1 000Indane lb/h 00000000000000000000002‐methoxy‐4‐vinylphenol lb/h 0 0 0 0 0 0 00000000000 0 0 000Syringaldehyde lb/h 0000 9,901 9,901 00000000000 9,901 0000n‐Propylbenzene lb/h 0000000000000000000000Naphthalene lb/h 00000000000000000000001‐Naphthalenol lb/h 0 0 0 0 2,503 2,503 00000000000 2,503 0 000Coniferyl Aldehyde lb/h 0 0 0 0 21,188 21,188 00000000000 21,188 0 000Tetralin lb/h 0000000000000000000000Isoeugenol lb/h 0 0 0 0 0 0 00000000000 0 0 000Decalin lb/h 0 0 0 0 0 0 00000000000 0 0 0002,5‐Dimethyloctane lb/h 00000000000000000000001‐Methyl naphthalene lb/h 0 0 0 0 0 0 00000000000 0 0 0001‐methyl decahydronaphthene lb/h 0 0 0 0 0 0 00000000000 0 0 000Dibenzothiophene lb/h 0 0 0 0 73 73 00000000000 73 0 000Biphenyl lb/h 00000000000000000000005‐hexyl‐O‐cresol lb/h 0 0 0 0 0 0 00000000000 0 0 000n‐Heptylcyclohexane lb/h 0000000000000000000000C14H20‐N35 lb/h 0000000000000000000000C14H24‐N5 lb/h 0 0 0 0 0 0 00000000000 0 0 0003,5‐Dimethyldodecane lb/h 0000000000000000000000C15H26‐N4 lb/h 0 1 1 0 1 1 00000000000 1 1 0006,8‐Dimethyltridecane lb/h 00000000000000000000001,4‐Dimethyl‐Phenanthrene lb/h 0 0 0 000000000000000 0 000N‐Cetane lb/h 0000000000000000000000C18H26O lb/h 0 0 0 0 0 0 00000000000 0 0 000C18H28 lb/h 0000000000000000000000C21H26O2 lb/h 0 0 0 0 0 0 00000000000 0 0 000C21H34 lb/h 0 0 0 0 0 0 00000000000 0 0 000C22H28O2 lb/h 0 0 0 0 0 0 00000000000 0 0 000Carbon lb/h 0000000000000000000000Sulfur lb/h 0000000000000000000000Sand/Catalyst Solids lb/h 000 1,437,949 1,437,949 1,438 1,436,511 1,424 158 000 144 0 144 144 0 14 0000Ash lb/h 0 0 0 89 89 1 88 1 0000 1,690 0 1,690 1,690 0 0 0000Wood lb/h 183,718 000 0000 000000 0 0 0 0 0000Char lb/h 0 000 22,046 220 21,826 218 000000 0 0 0 2 0000Coke lb/h 0 000 0000 000000 0 0 0 0 0000

157
Rev:

1

Project No: Drawing:

30482.00 PFD-61712-A202

THERMOCHEMICAL CONVERSION OF BIOMASS

TO HYDROCARBON FUEL

FAST PYROLYSIS AND VAPOR PHASE UPGRADING

PROCESS FLOW DIAGRAM

AREA 200: VAPOR PHASE UPGRADING

S-261

T-261

J:\1A - Process Solutions\30482 NREL Thermochemical Conv - Design-Model\Drawings\

S-262

R-262

S-263

T-262

DEPLETED CATALYST/

ASH

TO DISPOSAL

PYROLYSIS VAPOR

TO H-AP-48

PFD-61712-A301

VPU FLUE GAS

TO M-104

PFD-61712-A102

COMBUSTION

AIR

S-264

MAKEUP CATALYST

FROM M-702

PFD-61712-A702

30482 Pyrolysis Ex-Situ PFDs 61712 150316.vsd Plot date: 3/16/2015

Rev. Date By Description

0 9/29/14 JAR ISSUED FOR DESIGN REPORT

R-262C

LIFT AIR

FLUIDIZATION

AIR

PYROLYSIS VAPOR

FROM S-212

PFD-61712-A201

R-261

T-267

W-K262

QC-M262

C-262

261

272

273

276

275

274

288

285A

293

292 297

295

300

K-262

REGENERATOR

AIR COMPRESSOR

S-261

PRIMARY

CYCLONE

R-261

CATALYTIC FLUIDIZED

BED REACTOR

S-262

SECONDARY

CYCLONE

T-261

CATALYST

STEAM STRIPPER

R-262

CATALYST

REGENERATOR

S-263

CHAR COMBUSTOR

PRIMARY CYCLONE

S-264

CHAR COMBUSTOR

SECONDARY CYCLONE

C-262

FINES PURGE

COOLER

T-262

DEPLETED CATALYST

AND ASH STORAGE BIN

T-267

CATALYST

FEED BIN

R-262C

CATALYST

COOLER

SATURATED STEAM

TO T-605

PFD-61712-A603

SATURATED WATER

FROM H-AP-51

PFD-61712-A603

QA-K262

283

284

285

STEAM

FROM H-AP-46

PFD-61712-A804

270

K-262

COMBUSTION AIR

TO H-AP-18

PFD-61712-A203

COMBUSTION AIR

FROM H-AP-39

PFD-61712-A203

VPU FLUE GAS

TO H-AP-49

PFD-61712-A203

VPU FLUE GAS

FROM H-BP-17

PFD-61712-A203

SATURATED STEAM

FROM T-605

PFD-61712-A603

SUPERHEATED STEAM

TO M-602

H-AP PFD-61712-A603 -3

H-AP-4

H-AP-3

EX-SITU CATALYST

REGEN COOLER/

STEAM PRODUCTION

H-AP-4

EX-SITU CATALYST

REGEN COOLER/

STEAM SUPERHEAT

H-AP-5

EX-SITU CATALYST

RETURN COOLER/

STEAM PRODUCTION

H-AP-6

EX-SITU CATALYST

RETURN COOLER

STEAM SUPERHEAT

1 12/12/14 DMS ADDED HX NETWORK

QHAP3

QHAP5

QHAP4

QHAP6

277

NOTE: STREAM 277 FOR ATTRITION MAKEUP. ADDITIONAL MAKEUP TO

MAINTAIN ACTIVITY AS IN TABLE 4. 1

1

268

265

287

H-AP-5

H-AP-6

R-262C-1

R-262C-1

CATALYST

COOLER

158
PFD‐61712‐A202 261 265 268 270 272 273 274 275 276 277 283 284 285 285A 287 288 289 292 293 295 297 300 

Total Flow lb/h 322,317 918,615 1,240,932 2,756 1,243,687 311,397 932,291 310,342 1,055 101 196,238 196,238 196,238 196,238 918,615 211,055 210,963 210,963 92 102 210,963 310,342 Temperature F 932 0 932 555 931 931 0 931 0 0 90 285 600 600 0 1202 1202 1202 0 213 245 931 Pressure Psia 119 120 117 135 117 116 116 115 115 129 15 119 115 115 120 111 111 111 111 15 105 115 Vapor Fraction 1 0 1111 0 1 0 0 1111 0 111 0 0 1 1 Enthalpy Flow MMBtu/h ‐531 ‐5869 ‐6407 ‐15 ‐6422 ‐643 ‐5779 ‐638 ‐6 ‐1 ‐22 ‐13 3 3 ‐5722 ‐161 ‐160 ‐160 ‐1 ‐1 ‐213 ‐638 Argon lb/h 0000000000 2,478 2,478 2,478 2,478 0 2,478 2,478 2,478 0 0 2,478 0Nitrogen lb/h 0000000000 145,311 145,311 145,311 145,311 0 145,311 145,311 145,311 0 0 145,311 0Oxygen lb/h 0000000000 44,523 44,523 44,523 44,523 0 7,421 7,421 7,421 0 0 7,421 0SO2 lb/h 000000000000000 000 0 0 0 0NO2 lb/h 0000000000000000000000Hydrogen lb/h 24,531 0 21,258 0 21,258 21,258 0 21,258 0000000000000 21,258 Ammonia lb/h 0000000000000000000000H2S lb/h 0000000000000000000000Water lb/h 40,227 0 73,915 2,756 76,670 76,670 0 76,670 0 0 3,829 3,829 3,829 3,829 0 3,830 3,830 3,830 0 10 3,830 76,670 Carbon Monoxide lb/h 56,944 0 66,248 0 66,248 66,248 0 66,248 0000000000000 66,248 Carbon Dioxide lb/h 53,301 0 55,426 0 55,426 55,426 0 55,426 0 0 97 97 97 97 0 51,924 51,924 51,924 0 0 51,924 55,426 Methane lb/h 6,696 0 8,325 0 8,325 8,325 0 8,325 0000000000000 8,325 Methanol lb/h 0000000000000000000000Formic Acid lb/h 0000000000000000000000Glyoxal lb/h 1,250 000000000000000000000Ethylene lb/h 12,187 0 16,692 0 16,692 16,692 0 16,692 0000000000000 16,692 Acetaldehyde lb/h 0000000000000000000000Hydroxyacetaldehyde lb/h 5,688 000000000000000000000Acetic Acid lb/h 9,247 000000000000000000000Ethane lb/h 0000000000000000000000Propylene lb/h 4,006 0 5,682 0 5,682 5,682 0 5,682 0000000000000 5,682 1‐Hydroxy‐2‐propanone lb/h 2,082 000000000000000000000Propionic Acid lb/h 924 000000000000000000000Propane lb/h 0000000000000000000000Furan lb/h 500 0 845 0 845 845 0 845 0000000000000 845 1‐Butene lb/h 2,004 0 2,919 0 2,919 2,919 0 2,919 0000000000000 2,919 Tetrahydrofuran lb/h 422 0 1,046 0 1,046 1,046 0 1,046 0000000000000 1,046 N‐Butane lb/h 0000000000000000000000Furfural lb/h 3,195 0000000000000000000002‐methylfuran lb/h 466 0 1,144 0 1,144 1,144 0 1,144 0000000000000 1,144 Furfuryl Alcohol lb/h 5,829 000000000000000000000n‐Pentane lb/h 0000000000000000000000Pentenone lb/h 0000000000000000000000Benzene lb/h 0000000000000000000000Phenol lb/h 446 0 2,161 0 2,161 2,161 0 2,161 0000000000000 2,161 1,2‐Benzenediol lb/h 0 0 1,872 0 1,872 1,872 0 1,872 0000000000000 1,872 Hydroxymethylfurfural lb/h 6,366 0000000000000000000002,5‐dimethylfuran lb/h 2 0 13 0 13 13 0 13 0000000000000 13 Methyl Cyclopentenone lb/h 3,212 000000000000000000000Hydroxymethylcyclopentenone lb/h 3,118 000000000000000000000Cyclohexanone lb/h 584 000000000000000000000Levoglucosan lb/h 19,211 0000000000000000000001‐Hexanal lb/h 1,250 000000000000000000000Dimethoxytetrahydrofuran lb/h 8,521 0 38 0 38 38 0 38 0000000000000 38 Cyclohexane lb/h 1,673 0 5,348 0 5,348 5,348 0 5,348 0000000000000 5,348 N‐Hexane lb/h 0000000000000000000000Hexanol lb/h 0000000000000000000000Toluene lb/h 00000000000000000000002‐Methylphenol lb/h 0 0000000000000000000003‐Methyl‐phenol lb/h 324 000000000000000000000Guaiacol lb/h 0 0 1 0 1 1 0 1 0000000000000 1 Methyl‐Cyclohexane lb/h 191 0 990 0 990 990 0 990 0000000000000 990 2‐Methylhexane lb/h 0000000000000000000000VinylPhenol lb/h 13,119 0 1 0 1 1 0 1 0000000000000 1 O‐Xylene lb/h 0000000000000000000000Ethylbenzne lb/h 00000000000000000000002,3‐Dimethyl‐phenol lb/h 2 0 2,627 0 2,627 2,627 0 2,627 0000000000000 2,627 2,6‐dimethoxyphenol lb/h 0 0 898 0 898 898 0 898 0000000000000 898 Vanillyl alcohol lb/h 0 0 870 0 870 870 0 870 0000000000000 870 2,4,6‐Trimethylpyridine lb/h 333 0 333 0 333 333 0 333 0000000000000 333 Cis‐1,2‐dimethyl cyclohexane lb/h 295 0 3,060 0 3,060 3,060 0 3,060 0000000000000 3,060 Trans‐1,2‐dimethylcyclohexane lb/h 484 0 4,153 0 4,153 4,153 0 4,153 0000000000000 4,153 Ethylcyclohexane lb/h 00000000000000000000004‐Methylheptane lb/h 00000000000000000000002‐Methyl‐Benzofuran lb/h 1 0 463 0 463 463 0 463 0000000000000 463 Indane lb/h 00000000000000000000002‐methoxy‐4‐vinylphenol lb/h 0 0 13 0 13 13 0 13 0000000000000 13 Syringaldehyde lb/h 9,901 000000000000000000000n‐Propylbenzene lb/h 0000000000000000000000Naphthalene lb/h 00000000000000000000001‐Naphthalenol lb/h 2,503 0 353 0 353 353 0 353 0000000000000 353 Coniferyl Aldehyde lb/h 21,188 0 381 0 381 381 0 381 0000000000000 381 Tetralin lb/h 0000000000000000000000Isoeugenol lb/h 0 0 13 0 13 13 0 13 0000000000000 13 Decalin lb/h 0 0 44 0 44 44 0 44 0000000000000 44 2,5‐Dimethyloctane lb/h 00000000000000000000001‐Methyl naphthalene lb/h 0 0 417 0 417 417 0 417 0000000000000 417 1‐methyl decahydronaphthene lb/h 0 0 62 0 62 62 0 62 0000000000000 62 Dibenzothiophene lb/h 73 0 73 0 73 73 0 73 0000000000000 73 Biphenyl lb/h 00000000000000000000005‐hexyl‐O‐cresol lb/h 0 0 4,709 0 4,709 4,709 0 4,709 0000000000000 4,709 n‐Heptylcyclohexane lb/h 0000000000000000000000C14H20‐N35 lb/h 0000000000000000000000C14H24‐N5 lb/h 0 0 3,313 0 3,313 3,313 0 3,313 0000000000000 3,313 3,5‐Dimethyldodecane lb/h 0000000000000000000000C15H26‐N4 lb/h 1 0 3,555 0 3,555 3,555 0 3,555 0000000000000 3,555 6,8‐Dimethyltridecane lb/h 00000000000000000000001,4‐Dimethyl‐Phenanthrene lb/h 0 0 427 0 427 427 0 427 0000000000000 427 N‐Cetane lb/h 0000000000000000000000C18H26O lb/h 0 0 4,923 0 4,923 4,923 0 4,923 0000000000000 4,923 C18H28 lb/h 0000000000000000000000C21H26O2 lb/h 0 0 3,421 0 3,421 3,421 0 3,421 0000000000000 3,421 C21H34 lb/h 0 0 7,754 0 7,754 7,754 0 7,754 0000000000000 7,754 C22H28O2 lb/h 0 0 1,788 0 1,788 1,788 0 1,788 0000000000000 1,788 Carbon lb/h 0000000000000000000000Sulfur lb/h 0000000000000000000000Sand/Catalyst Solids lb/h 14 918,615 918,629 0 918,629 919 917,711 9 909 101 0000 918,615 92 0 0 92 92 0 9 Ash lb/h 000 0 00000 00000 000 0 0 0 0 0 Wood lb/h 0 0 0 0 00000 000000000000 0 Char lb/h 2 0 2 0 20200 000000000000 0 Coke lb/h 0 0 14,725 0 14,725 147 14,578 1 146 000000000000 1 

159
FLUIDIZING GAS

FROM K-211

PFD-61712-A201

Rev:

0

Project No: Drawing:

30482.00 PFD-61712-A203

THERMOCHEMICAL CONVERSION OF BIOMASS

TO HYDROCARBON FUEL

FAST PYROLYSIS AND VAPOR PHASE UPGRADING

PROCESS FLOW DIAGRAM

AREA 200: A200 HEAT RECOVERY

Rev. Date By Description

203P

J:\1A - Process Solutions\30482 NREL Thermochemical Conv - Design-Model\Drawings\ 30482 Pyrolysis Ex-Situ PFDs 61712 150128.vsd Plot date: 1/29/2015

FLUE GAS

FROM S-214

PFD-61712-A201

H-AP-8

QHAP8

FLUIDIZING GAS

TO H-BP-36

PFD-61712-A303

FLUIDIZING GAS

FROM H-BP-36

PFD-61712-A303

FLUIDIZING GAS

TO H-BP-3

PFD-61712-A305

FLUIDIZING GAS

FROM H-BP-3

PFD-61712-A305

FLUIDIZING GAS

TO R-211/T-211

PFD-61712-A201

204P

232P FLUE GAS

TO H-AP-9

PFD-61712-A602

FLUE GAS

FROM H-AP-9

PFD-61712-A602

FLUE GAS

TO H-BP-21

PFD-61712-A605

FLUE GAS

FROM H-BP-21

PFD-61712-A605

FLUE GAS

TO H-BP-16

PFD-61712-A604

FLUE GAS

FROM H-BP-16

PFD-61712-A604

FLUE GAS

TO M-104

PFD-61712-A201

239P

COMBUSTION AIR

FROM K-212

PFD-61712-A201

224P

H-AP-17

QHAP17

H-AP-38

QHAP38

COMBUSTION AIR

TO R-212

PFD-61712-A201

VPU FLUE GAS

FROM S-264

PFD-61712-A202

VPU FLUE GAS

TO H-AP-49

PFD-61712-A603

289 VPU FLUE GAS

FROM H-AP-49

PFD-61712-A603

H-AP-39

QHAP39

VPU FLUE GAS

TO H-AP-37

PFD-61712-A605

VPU FLUE GAS

FROM H-AP-37

PFD-61712-A605

VPU FLUE GAS

TO H-BP-40

PFD-61712-A601

VPU FLUE GAS

TO H-BP-22

PFD-61712-A605

VPU FLUE GAS

TO H-BP-41

PFD-61712-A804

VPU FLUE GAS

TO H-BP-42

PFD-61712-A801

VPU FLUE GAS

FROM H-BP-40

PFD-61712-A601

VPU FLUE GAS

FROM H-BP-22

PFD-61712-A605

VPU FLUE GAS

FROM H-BP-41

PFD-61712-A804

VPU FLUE GAS

FROM H-BP-42

PFD-61712-A801

VPU FLUE GAS

TO H-BP-17

PFD-61712-A604

VPU FLUE GAS

TO M-104

PFD-61712-A202

VPU FLUE GAS

FROM H-BP-17

PFD-61712-A604

297

ABSORBER VAPOR

FROM D-301

PFD-61712-A305

ABSORBER VAPOR

TO H-BP-3/H-BP-20

PFD-61712-A305

COMBUSTION AIR

FROM K-262

PFD-61712-A202

284

H-AP-18

QHAP18

ABSORBER VAPOR

FROM D-301

PFD-61712-A305

ABSORBER VAPOR

TO H-BP-3/H-BP-20

PFD-61712-A305

H-AP-8

CHAR COMBUSTOR FLUE GAS

COOLER/FAST PYROLYSIS

FLUIDIZING GAS PREHEAT

H-AP-17

POST-ABSORBER 1 VAPOR

COOLER/CHAR COMBUSTOR

AIR PREHEAT

H-AP-18

POST-ABSORBER 1 VAPOR

COOLER/EX-SITU CATALYST

REGEN AIR PREHEAT

H-AP-38

EX-SITU CATALYST REGEN

FLUE GAS COOLER/CHAR

COMBUSTOR AIR PREHEAT

H-AP-39

EX-SITU CATALYST REGEN

FLUE GAS COOLER/EX-SITU

CATALYST REGEN AIR PREHEAT

0 12/12/14 DMS ADDED HX NETWORK

COMBUSTION AIR

TO R-262

PFD-61712-A202

285

225P

160
PFD‐61712‐A203 203P 204P 224P 225P 232P 239P 284 285 289 297 

Total Flow lb/h 140,215 140,215 237,911 237,911 258,265 258,265 196,238 196,238 210,963 210,963 000000000000Temperature F 160 800 287 600 1328 245 285 600 1202 245 000000000000Pressure Psia 127 123 123 119 115 109 119 115 111 105 000000000000Vapor Fraction 1111111111 000000000000Enthalpy Flow MMBtu/h ‐231 ‐152 ‐15 4 ‐208 ‐284 ‐13 3 ‐160 ‐213 000000000000Argon lb/h 0 0 3,005 3,005 3,005 3,005 2,478 2,478 2,478 2,478 000000000000Nitrogen lb/h 0 0 176,169 176,169 176,443 176,443 145,311 145,311 145,311 145,311 000000000000Oxygen lb/h 0 0 53,978 53,978 8,996 8,996 44,523 44,523 7,421 7,421 000000000000SO2 lb/h 0000 85 85 0 0 0 0 000000000000NO2 lb/h 0000000000000000000000Hydrogen lb/h 24,531 24,531 00000000000000000000Ammonia lb/h 0000000000000000000000H2S lb/h 0000000000000000000000Water lb/h 353 353 4,642 4,642 13,826 13,826 3,829 3,829 3,830 3,830 000000000000Carbon Monoxide lb/h 47,501 47,501 00000000000000000000Carbon Dioxide lb/h 40,152 40,152 117 117 55,910 55,910 97 97 51,924 51,924 000000000000Methane lb/h 5,884 5,884 00000000000000000000Methanol lb/h 0000000000000000000000Formic Acid lb/h 0000000000000000000000Glyoxal lb/h 0000000000000000000000Ethylene lb/h 11,780 11,780 00000000000000000000Acetaldehyde lb/h 0000000000000000000000Hydroxyacetaldehyde lb/h 0000000000000000000000Acetic Acid lb/h 0000000000000000000000Ethane lb/h 0000000000000000000000Propylene lb/h 3,982 3,982 000000000000000000001‐Hydroxy‐2‐propanone lb/h 0000000000000000000000Propionic Acid lb/h 0000000000000000000000Propane lb/h 0000000000000000000000Furan lb/h 500 500 000000000000000000001‐Butene lb/h 1,975 1,975 00000000000000000000Tetrahydrofuran lb/h 422 422 00000000000000000000N‐Butane lb/h 0000000000000000000000Furfural lb/h 00000000000000000000002‐methylfuran lb/h 466 466 00000000000000000000Furfuryl Alcohol lb/h 0000000000000000000000n‐Pentane lb/h 0000000000000000000000Pentenone lb/h 0000000000000000000000Benzene lb/h 0000000000000000000000Phenol lb/h 14 14 000000000000000000001,2‐Benzenediol lb/h 0 0 00000000000000000000Hydroxymethylfurfural lb/h 00000000000000000000002,5‐dimethylfuran lb/h 2 2 00000000000000000000Methyl Cyclopentenone lb/h 0000000000000000000000Hydroxymethylcyclopentenone lb/h 0000000000000000000000Cyclohexanone lb/h 0000000000000000000000Levoglucosan lb/h 00000000000000000000001‐Hexanal lb/h 0000000000000000000000Dimethoxytetrahydrofuran lb/h 1 1 00000000000000000000Cyclohexane lb/h 1,673 1,673 00000000000000000000N‐Hexane lb/h 0000000000000000000000Hexanol lb/h 0000000000000000000000Toluene lb/h 00000000000000000000002‐Methylphenol lb/h 0 0 000000000000000000003‐Methyl‐phenol lb/h 0000000000000000000000Guaiacol lb/h 0 0 00000000000000000000Methyl‐Cyclohexane lb/h 191 191 000000000000000000002‐Methylhexane lb/h 0000000000000000000000VinylPhenol lb/h 0 0 00000000000000000000O‐Xylene lb/h 0000000000000000000000Ethylbenzne lb/h 00000000000000000000002,3‐Dimethyl‐phenol lb/h 2 2 000000000000000000002,6‐dimethoxyphenol lb/h 0 0 00000000000000000000Vanillyl alcohol lb/h 0 0 000000000000000000002,4,6‐Trimethylpyridine lb/h 3 3 00000000000000000000Cis‐1,2‐dimethyl cyclohexane lb/h 295 295 00000000000000000000Trans‐1,2‐dimethylcyclohexane lb/h 484 484 00000000000000000000Ethylcyclohexane lb/h 00000000000000000000004‐Methylheptane lb/h 00000000000000000000002‐Methyl‐Benzofuran lb/h 1 1 00000000000000000000Indane lb/h 00000000000000000000002‐methoxy‐4‐vinylphenol lb/h 0 0 00000000000000000000Syringaldehyde lb/h 0000000000000000000000n‐Propylbenzene lb/h 0000000000000000000000Naphthalene lb/h 00000000000000000000001‐Naphthalenol lb/h 0 0 00000000000000000000Coniferyl Aldehyde lb/h 0 0 00000000000000000000Tetralin lb/h 0000000000000000000000Isoeugenol lb/h 0 0 00000000000000000000Decalin lb/h 0 0 000000000000000000002,5‐Dimethyloctane lb/h 00000000000000000000001‐Methyl naphthalene lb/h 0 0 000000000000000000001‐methyl decahydronaphthene lb/h 0 0 00000000000000000000Dibenzothiophene lb/h 0 0 00000000000000000000Biphenyl lb/h 00000000000000000000005‐hexyl‐O‐cresol lb/h 0 0 00000000000000000000n‐Heptylcyclohexane lb/h 0000000000000000000000C14H20‐N35 lb/h 0000000000000000000000C14H24‐N5 lb/h 0 0 000000000000000000003,5‐Dimethyldodecane lb/h 0000000000000000000000C15H26‐N4 lb/h 1 1 000000000000000000006,8‐Dimethyltridecane lb/h 00000000000000000000001,4‐Dimethyl‐Phenanthrene lb/h 0 0 00000000000000000000N‐Cetane lb/h 0000000000000000000000C18H26O lb/h 0 0 00000000000000000000C18H28 lb/h 0000000000000000000000C21H26O2 lb/h 0 0 00000000000000000000C21H34 lb/h 0 0 00000000000000000000C22H28O2 lb/h 0 0 00000000000000000000Carbon lb/h 0000000000000000000000Sulfur lb/h 0000000000000000000000Sand/Catalyst Solids lb/h 00000000 0 0000000000000Ash lb/h 00000000 0 0000000000000Wood lb/h 0000000000000000000000Char lb/h 0000000000000000000000Coke lb/h 0000000000000000000000

161
Rev:

1

Project No: Drawing:

30482.00 PFD-61712-A301

THERMOCHEMICAL CONVERSION OF BIOMASS

TO HYDROCARBON FUEL

FAST PYROLYSIS AND VAPOR PHASE UPGRADING

PROCESS FLOW DIAGRAM

AREA 300: CONDENSATION STAGE 1

Rev. Date By Description

0

PYROLYSIS VAPOR 311

FROM S-262/T-261

PFD-61712-A202

300

J:\1A - Process Solutions\30482 NREL Thermochemical Conv - Design-Model\Drawings\ Plot date: 1/29/2015 30482 Pyrolysis Ex-Situ PFDs 61712 150128.vsd

9/29/14 JAR ISSUED FOR DESIGN REPORT

D-301

HEAVY FRACTION

CONDENSER ABSORBER

P-318

D-301 BOTTOMS

PUMP

D-301

P-318

312

QA-H313

H-313 H-314

QC-H314

H-315

QX-H315

QCH-H316

313 314 315 316 VAPOR PHASE

TO D-302

PFD-61712-A302

317

SOLIDS

TO M-805

PFD-61712-A302

335A

320

S-319

318 319 320A

QA-H320

H-320

ORGANIC PHASE

TO T-328

PFD-61712-A302

RECYCLED ORGANICS

FROM S-324

PFD-61712-A302

P-332

332

T-332

W-P332

333

H-313

D-301 VAPOR ACHE

S-319

D-301 BOTTOMS

FILTER

H-314

D-302 FEED

COOLER

H-315

D-302 FEED/OVERHEAD

HEAT EXCHANGER

T-332

D-301 CIRCULATION

SURGE TANK

H-316

D-302 LIQUID FEED

CHILLER

P-332

QUENCH RECYCLE

PUMP

H-320

HEAVY FRACTION

ACHE

OFFGAS

FROM D-302

PFD-61712-A302

OFFGAS

TO

PFD-61712-A302

W-P318

321

340

CWS

CWR

H-316 CHWS

CHWR

PYROLYSIS VAPOR

TO H-AP-48

PFD-61712-A305

PYROLYSIS VAPOR

FROM H-AP-53/56/60

PFD-61712-A305

ABSORBER VAPOR

TO H-AP-17/18/31

PFD-61712-A305

ABSORBER VAPOR

FROM H-BP-3/H-BP-11

PFD-61712-A305

ABSORBER BOTTOMS

TO H-AP-23

PFD-61712-A305

ABSORBER BOTTOMS

FROM H-BP-44

PFD-61712-A305

1 12/12/14 DMS ADDED HX NETWORK

162
PFD‐61712‐A301 300 311 312 313 314 315 316 317 318 319 320 320A 321 332 333 335A 340 

Total Flow lb/h 310,342 310,342 371,714 371,714 371,714 371,714 371,714 371,714 19,671 19,671 19,660 19,660 182,444 81,043 81,043 11 182,444 00000Temperature F 931 466 358 220 140 110 95 60 461 175 175 140 53 86 86 0 95 00000Pressure Psia 115 113 110 108 106 104 102 100 113 123 108 103 97 110 113 123 95 00000Vapor Fraction 11111111 0 0 001 000 1 00000Enthalpy Flow MMBtu/h ‐638 ‐731 ‐786 ‐827 ‐904 ‐916 ‐921 ‐931 ‐7 ‐10 ‐10 ‐10 ‐336 ‐62 ‐62 0 ‐332 00000Argon lb/h 0000000000000000000000Nitrogen lb/h 0000000000000000000000Oxygen lb/h 0000000000000000000000SO2 lb/h 0000000000000000000000NO2 lb/h 0000000000000000000000Hydrogen lb/h 21,258 21,258 21,261 21,261 21,261 21,261 21,261 21,261 1111 21,256 4 4 0 21,256 00000Ammonia lb/h 0000000000000000000000H2S lb/h 0000000000000000000000Water lb/h 76,670 76,670 77,078 77,078 77,078 77,078 77,078 77,078 43 43 43 43 499 451 451 0 499 00000Carbon Monoxide lb/h 66,248 66,248 66,266 66,266 66,266 66,266 66,266 66,266 3333 66,238 21 21 0 66,238 00000Carbon Dioxide lb/h 55,426 55,426 55,716 55,716 55,716 55,716 55,716 55,716 7777 55,306 297 297 0 55,306 00000Methane lb/h 8,325 8,325 8,333 8,333 8,333 8,333 8,333 8,333 1111 8,321 8 8 0 8,321 00000Methanol lb/h 0000000000000000000000Formic Acid lb/h 0000000000000000000000Glyoxal lb/h 0000000000000000000000Ethylene lb/h 16,692 16,692 16,766 16,766 16,766 16,766 16,766 16,766 2222 16,661 76 76 0 16,661 00000Acetaldehyde lb/h 0000000000000000000000Hydroxyacetaldehyde lb/h 0000000000000000000000Acetic Acid lb/h 0000000000000000000000Ethane lb/h 0000000000000000000000Propylene lb/h 5,682 5,682 5,810 5,810 5,810 5,810 5,810 5,810 1111 5,632 129 129 0 5,632 000001‐Hydroxy‐2‐propanone lb/h 0000000000000000000000Propionic Acid lb/h 0000000000000000000000Propane lb/h 0000000000000000000000Furan lb/h 845 845 1,212 1,212 1,212 1,212 1,212 1,212 1 1 1 1 707 367 367 0 707 000001‐Butene lb/h 2,919 2,919 3,251 3,251 3,251 3,251 3,251 3,251 1111 2,793 333 333 0 2,793 00000Tetrahydrofuran lb/h 1,046 1,046 2,236 2,236 2,236 2,236 2,236 2,236 1 1 1 1 597 1,192 1,192 0 597 00000N‐Butane lb/h 0000000000000000000000Furfural lb/h 00000000000000000000002‐methylfuran lb/h 1,144 1,144 2,432 2,432 2,432 2,432 2,432 2,432 1 1 1 1 659 1,289 1,289 0 659 00000Furfuryl Alcohol lb/h 0000000000000000000000n‐Pentane lb/h 0000000000000000000000Pentenone lb/h 0000000000000000000000Benzene lb/h 0000000000000000000000Phenol lb/h 2,161 2,161 7,632 7,632 7,632 7,632 7,632 7,632 11 11 11 11 20 5,482 5,482 0 20 000001,2‐Benzenediol lb/h 1,872 1,872 2,049 2,049 2,049 2,049 2,049 2,049 20 20 20 20 0 197 197 0 0 00000Hydroxymethylfurfural lb/h 00000000000000000000002,5‐dimethylfuran lb/h 13 13 42 42 42 42 42 42 0 0 0 0 3 28 28 0 3 00000Methyl Cyclopentenone lb/h 0000000000000000000000Hydroxymethylcyclopentenone lb/h 0000000000000000000000Cyclohexanone lb/h 0000000000000000000000Levoglucosan lb/h 00000000000000000000001‐Hexanal lb/h 0000000000000000000000Dimethoxytetrahydrofuran lb/h 38 38 136 136 136 136 136 136 0 0 0 0 1 98 98 0 1 00000Cyclohexane lb/h 5,348 5,348 13,262 13,262 13,262 13,262 13,262 13,262 9999 2,367 7,922 7,922 0 2,367 00000N‐Hexane lb/h 0000000000000000000000Hexanol lb/h 0000000000000000000000Toluene lb/h 00000000000000000000002‐Methylphenol lb/h 0 0 00000000 0 0 000 0 0 000003‐Methyl‐phenol lb/h 0000000000000000000000Guaiacol lb/h 114444440000033 0 0 00000Methyl‐Cyclohexane lb/h 990 990 2,898 2,898 2,898 2,898 2,898 2,898 2 2 2 2 270 1,911 1,911 0 270 000002‐Methylhexane lb/h 0000000000000000000000VinylPhenol lb/h 115555550000033 0 0 00000O‐Xylene lb/h 0000000000000000000000Ethylbenzne lb/h 00000000000000000000002,3‐Dimethyl‐phenol lb/h 2,627 2,627 9,506 9,506 9,506 9,506 9,506 9,506 30 30 30 30 3 6,910 6,910 0 3 000002,6‐dimethoxyphenol lb/h 898 898 3,184 3,184 3,184 3,184 3,184 3,184 29 29 29 29 0 2,316 2,316 0 0 00000Vanillyl alcohol lb/h 870 870 3,063 3,063 3,063 3,063 3,063 3,063 32 32 32 32 0 2,225 2,225 0 0 000002,4,6‐Trimethylpyridine lb/h 333 333 1,203 1,203 1,203 1,203 1,203 1,203 2 2 2 2 4 872 872 0 4 00000Cis‐1,2‐dimethyl cyclohexane lb/h 3,060 3,060 10,060 10,060 10,060 10,060 10,060 10,060 12 12 12 12 417 7,012 7,012 0 417 00000Trans‐1,2‐dimethylcyclohexane lb/h 4,153 4,153 13,344 13,344 13,344 13,344 13,344 13,344 14 14 14 14 685 9,205 9,205 0 685 00000Ethylcyclohexane lb/h 00000000000000000000004‐Methylheptane lb/h 00000000000000000000002‐Methyl‐Benzofuran lb/h 463 463 1,673 1,673 1,673 1,673 1,673 1,673 55552 1,216 1,216 0 2 00000Indane lb/h 00000000000000000000002‐methoxy‐4‐vinylphenol lb/h 13 13 49 49 49 49 49 49 0 0 0 0 0 35 35 0 0 00000Syringaldehyde lb/h 0000000000000000000000n‐Propylbenzene lb/h 0000000000000000000000Naphthalene lb/h 00000000000000000000001‐Naphthalenol lb/h 353 353 1,236 1,236 1,236 1,236 1,236 1,236 16 16 16 16 0 898 898 0 0 00000Coniferyl Aldehyde lb/h 381 381 30 30 30 30 30 30 373 373 373 373 0 22 22 0 0 00000Tetralin lb/h 0000000000000000000000Isoeugenol lb/h 13 13 48 48 48 48 48 48 0 0 0 0 0 35 35 0 0 00000Decalin lb/h 44 44 158 158 158 158 158 158 0 0 0 0 0 114 114 0 0 000002,5‐Dimethyloctane lb/h 00000000000000000000001‐Methyl naphthalene lb/h 417 417 1,489 1,489 1,489 1,489 1,489 1,489 11 11 11 11 0 1,082 1,082 0 0 000001‐methyl decahydronaphthene lb/h 62 62 222 222 222 222 222 222 1 1 1 1 0 161 161 0 0 00000Dibenzothiophene lb/h 73 73 120 120 120 120 120 120 41 41 41 41 0 88 88 0 0 00000Biphenyl lb/h 00000000000000000000005‐hexyl‐O‐cresol lb/h 4,709 4,709 16,038 16,038 16,038 16,038 16,038 16,038 333 333 333 333 0 11,662 11,662 0 0 00000n‐Heptylcyclohexane lb/h 0000000000000000000000C14H20‐N35 lb/h 0000000000000000000000C14H24‐N5 lb/h 3,313 3,313 11,462 11,462 11,462 11,462 11,462 11,462 185 185 185 185 1 8,334 8,334 0 1 000003,5‐Dimethyldodecane lb/h 0000000000000000000000C15H26‐N4 lb/h 3,555 3,555 12,429 12,429 12,429 12,429 12,429 12,429 163 163 163 163 1 9,037 9,037 0 1 000006,8‐Dimethyltridecane lb/h 00000000000000000000001,4‐Dimethyl‐Phenanthrene lb/h 427 427 0 0 0 0 0 0 427 427 427 427 0 0 0 0 0 00000N‐Cetane lb/h 0000000000000000000000C18H26O lb/h 4,923 4,923 000000 4,923 4,923 4,923 4,923 0 0 0 0 0 00000C18H28 lb/h 0000000000000000000000C21H26O2 lb/h 3,421 3,421 000000 3,421 3,421 3,421 3,421 0 0 0 0 0 00000C21H34 lb/h 7,754 7,754 10 10 10 10 10 10 7,751 7,751 7,751 7,751 0 8 8 0 0 00000C22H28O2 lb/h 1,788 1,788 000000 1,788 1,788 1,788 1,788 0 0 0 0 0 00000Carbon lb/h 0000000000000000000000Sulfur lb/h 0000000000000000000000Sand/Catalyst Solids lb/h 9 9 000000 9 9 00000 9 000000Ash lb/h 0 0 000000 0 0 00000 0 000000Wood lb/h 0 0 000000 0 0 00000 0 000000Char lb/h 0 0 000000 0 0 00000 0 000000Coke lb/h 1 1 000000 1 1 00000 1 000000

163
Rev:

2

Project No: Drawing:

30482.00 PFD-61712-A302

THERMOCHEMICAL CONVERSION OF BIOMASS

TO HYDROCARBON FUEL

FAST PYROLYSIS AND VAPOR PHASE UPGRADING

PROCESS FLOW DIAGRAM

AREA 300: CONDENSATION STAGE 2

Rev. Date By Description

0

P-323

OFFGAS

TO H-BP-4

PFD-61712-A303

SOLIDS

TO M-805

PFD-61712-A803

MAKEUP HYDROGEN

FROM M-385/M-575

PFD-61712-A504

PURGE GAS

TO H-BP-9/K-511

PFD-61712-A501

ORGANIC PHASE

TO S-410

PFD-61712-A401

D-302

S-322

QCH-H326

335C

345

343

322 323

327

325

341

350 FLUIDIZING GAS

TO K-211

PFD-61712-A201

346

340

VAPOR PHASE

FROM H-316

PFD-61712-A301

317

J:\1A - Process Solutions\30482 NREL Thermochemical Conv - Design-Model\Drawings\ Plot date: 1/29/2015 30482 Pyrolysis Ex-Situ PFDs 61712 150128.vsd

321

D-302

LIGHT FRACTION

CONDENSER ABSORBER

9/29/14 JAR ISSUED FOR DESIGN REPORT

ORGANIC PHASE

FROM H-320

PFD-61712-A301

RECYCLED ORGANICS

TO T-332

PFD-61712-A301

W-P323

324

S-324

332

326

328

T-328

P-331

337

320A

P-329

329

S-329

335B

AQUEOUS PHASE

TO T-810

PFD-61712-A801

334

SOLIDS

FROM S-319

PFD-61712-A301

335A

335

H-326

D-302 QUENCH

CIRCULATION CHILLER

S-322

D-302 BOTTOMS

DECANTER

P-323

CIRCULATION FILTER

CHARGE PUMP

S-324

QUENCH

CIRCULATION FILTER

P-331

ORGANIC

PRODUCT PUMP

T-328

ORGANIC PRODUCT

SURGE TANK

P-329

AQUEOUS FILTER

CHARGE PUMP

S-329

AQUEOUS PHASE

FILTER

OFFGAS

TO H-315

PFD-61712-A301

OFFGAS

FROM H-315

PFD-61712-A301

W-P329

W-P331

CHWS

CHWR

H-326

1 12/12/14 DMS ADDED HX NETWORK

2 12/29/14 JAR MINOR UPDATES

164
PFD‐61712‐A302 317 320A 321 322 323 324 325 326 327 328 329 332 334 335A 335B 335C 335 337 340 341 343 

Total Flow lb/h 371,714 19,660 182,444 1,090,871 1,013,055 1,013,055 1,013,035 901,601 901,601 30,391 77,816 81,043 77,811 11 5 20 36 50,051 182,444 128,998 51,621 Temperature F 60 140 53 86 86 86 86 86 50 86 86 86 86 0 86 86 90 105 95 95 95 Pressure Psia 100 103 97 100 100 125 110 110 100 110 100 110 100 123 100 110 100 113 95 95 95 Vapor Fraction 101 0000000000000 0 0 111Enthalpy Flow MMBtu/h ‐931 ‐10 ‐336 ‐1296 ‐773 ‐773 ‐773 ‐688 ‐701 ‐23 ‐523 ‐62 ‐523 0 0 0 0 ‐33 ‐332 ‐234 ‐94 Argon lb/h 000000000000000000000Nitrogen lb/h 000000000000000000000Oxygen lb/h 000000000000000000000SO2 lb/h 000000000000000000000NO2 lb/h 000000000000000000000Hydrogen lb/h 21,261 1 21,256 44 44 44 44 39 39 1040 0 0002 21,256 15,029 6,014 Ammonia lb/h 000000000000000000000H2S lb/h 000000000000000000000Water lb/h 77,078 43 499 81,591 5,632 5,632 5,632 5,012 5,012 169 75,959 451 75,955 0 5 0 5 212 499 353 141 Carbon Monoxide lb/h 66,266 3 66,238 256 256 256 256 228 228 8 0 21 0 0 0 0 0 10 66,238 46,834 18,741 Carbon Dioxide lb/h 55,716 7 55,306 3,714 3,713 3,713 3,713 3,304 3,304 111 2 297 2 0 0 0 0 118 55,306 39,105 15,648 Methane lb/h 8,333 1 8,321 104 104 104 104 92 92 3080 0 0004 8,321 5,884 2,354 Methanol lb/h 000000000000000000000Formic Acid lb/h 000000000000000000000Glyoxal lb/h 000000000000000000000Ethylene lb/h 16,766 2 16,661 950 949 949 949 845 845 28 0 76 0 0 0 0 0 31 16,661 11,780 4,714 Acetaldehyde lb/h 000000000000000000000Hydroxyacetaldehyde lb/h 000000000000000000000Acetic Acid lb/h 000000000000000000000Ethane lb/h 000000000000000000000Propylene lb/h 5,810 1 5,632 1,616 1,616 1,616 1,616 1,438 1,438 48 0 129 0 0 0 0 0 50 5,632 3,982 1,594 1‐Hydroxy‐2‐propanone lb/h 000000000000000000000Propionic Acid lb/h 000000000000000000000Propane lb/h 000000000000000000000Furan lb/h 1,212 1 707 4,592 4,592 4,592 4,592 4,087 4,087 138 0 367 0 0 0 0 0 138 707 500 200 1‐Butene lb/h 3,251 1 2,793 4,164 4,164 4,164 4,164 3,706 3,706 125 0 333 0 0 0 0 0 126 2,793 1,975 790 Tetrahydrofuran lb/h 2,236 1 597 14,896 14,896 14,896 14,896 13,257 13,257 447 0 1,192 0 0 0 0 0 448 597 422 169 N‐Butane lb/h 000000000000000000000Furfural lb/h 0000000000000000000002‐methylfuran lb/h 2,432 1 659 16,115 16,115 16,115 16,115 14,342 14,342 483 0 1,289 0 0 0 0 0 485 659 466 187 Furfuryl Alcohol lb/h 000000000000000000000n‐Pentane lb/h 000000000000000000000Pentenone lb/h 000000000000000000000Benzene lb/h 000000000000000000000Phenol lb/h 7,632 11 20 68,598 68,525 68,525 68,524 60,986 60,986 2,056 73 5,482 73 0 0 1 1 2,067 20 14 6 1,2‐Benzenediol lb/h 2,049 20 0 4,241 2,463 2,463 2,463 2,192 2,192 74 1,778 197 1,778 0 0 0 0 94 0 0 0 Hydroxymethylfurfural lb/h 0000000000000000000002,5‐dimethylfuran lb/h 42 0 3 355 355 355 355 316 316 11 0 28 0 0 0 0 0 11 3 2 1 Methyl Cyclopentenone lb/h 000000000000000000000Hydroxymethylcyclopentenone lb/h 000000000000000000000Cyclohexanone lb/h 000000000000000000000Levoglucosan lb/h 0000000000000000000001‐Hexanal lb/h 000000000000000000000Dimethoxytetrahydrofuran lb/h 136 0 1 1,229 1,229 1,229 1,229 1,094 1,094 37 0 98 0 0 0 0 0 37 1 1 0 Cyclohexane lb/h 13,262 9 2,367 99,032 99,032 99,032 99,030 88,137 88,137 2,971 0 7,922 0 0 0 2 2 2,980 2,367 1,673 670 N‐Hexane lb/h 000000000000000000000Hexanol lb/h 000000000000000000000Toluene lb/h 0000000000000000000002‐Methylphenol lb/h 0 0 0 000000 0000 0 00000003‐Methyl‐phenol lb/h 000000000000000000000Guaiacol lb/h 4 0 0 35 35 35 35 31 31 1 0 3 0 0 0001000Methyl‐Cyclohexane lb/h 2,898 2 270 23,888 23,888 23,888 23,887 21,260 21,260 717 0 1,911 0 0 0 0 0 719 270 191 76 2‐Methylhexane lb/h 000000000000000000000VinylPhenol lb/h 5 0 0 42 42 42 42 37 37 1 0 3 0 0 0001000O‐Xylene lb/h 000000000000000000000Ethylbenzne lb/h 0000000000000000000002,3‐Dimethyl‐phenol lb/h 9,506 30 3 86,372 86,371 86,371 86,369 76,869 76,869 2,591 1 6,910 1 0 0 2 2 2,621 3212,6‐dimethoxyphenol lb/h 3,184 29 0 28,944 28,944 28,944 28,944 25,760 25,760 868 0 2,316 0 0 0 1 1 897 0 0 0 Vanillyl alcohol lb/h 3,063 32 0 27,819 27,816 27,816 27,816 24,756 24,756 834 3 2,225 3 0 0 1 1 867 0 0 0 2,4,6‐Trimethylpyridine lb/h 1,203 2 4 10,902 10,902 10,902 10,902 9,702 9,702 327 0 872 0 0 0 0 0 329 4 3 1 Cis‐1,2‐dimethyl cyclohexane lb/h 10,060 12 417 87,651 87,651 87,651 87,649 78,008 78,008 2,629 0 7,012 0 0 0 2 2 2,641 417 295 118 Trans‐1,2‐dimethylcyclohexane lb/h 13,344 14 685 115,062 115,062 115,062 115,059 102,403 102,403 3,452 0 9,205 0 0 0 2 2 3,466 685 484 194 Ethylcyclohexane lb/h 0000000000000000000004‐Methylheptane lb/h 0000000000000000000002‐Methyl‐Benzofuran lb/h 1,673 5 2 15,195 15,195 15,195 15,195 13,523 13,523 456 0 1,216 0 0 0 0 0 461 2 1 0 Indane lb/h 0000000000000000000002‐methoxy‐4‐vinylphenol lb/h 49 0 0 443 443 443 443 394 394 13 0 35 0 0 0 0 0 13 0 0 0 Syringaldehyde lb/h 000000000000000000000n‐Propylbenzene lb/h 000000000000000000000Naphthalene lb/h 0000000000000000000001‐Naphthalenol lb/h 1,236 16 0 11,230 11,230 11,230 11,230 9,994 9,994 337 0 898 0 0 0 0 0 353 0 0 0 Coniferyl Aldehyde lb/h 30 373 0 270 270 270 270 240 240 8 0 22 0 0 0 0 0 381 0 0 0 Tetralin lb/h 000000000000000000000Isoeugenol lb/h 48 0 0 434 434 434 434 387 387 13 0 35 0 0 0 0 0 13 0 0 0 Decalin lb/h 158 0 0 1,429 1,429 1,429 1,429 1,272 1,272 43 0 114 0 0 0 0 0 43 0 0 0 2,5‐Dimethyloctane lb/h 0000000000000000000001‐Methyl naphthalene lb/h 1,489 11 0 13,530 13,530 13,530 13,530 12,042 12,042 406 0 1,082 0 0 0 0 0 417 0 0 0 1‐methyl decahydronaphthene lb/h 222 1 0 2,013 2,013 2,013 2,013 1,791 1,791 60 0 161 0 0 0 0 0 61 0 0 0 Dibenzothiophene lb/h 120 41 0 1,094 1,094 1,094 1,094 974 974 33 0 88 0 0 0 0 0 73 0 0 0 Biphenyl lb/h 0000000000000000000005‐hexyl‐O‐cresol lb/h 16,038 333 0 145,776 145,776 145,776 145,773 129,738 129,738 4,373 0 11,662 0 0 0 3 3 4,706 000n‐Heptylcyclohexane lb/h 000000000000000000000C14H20‐N35 lb/h 000000000000000000000C14H24‐N5 lb/h 11,462 185 1 104,182 104,182 104,182 104,180 92,720 92,720 3,125 0 8,334 0 0 0 2 2 3,310 1003,5‐Dimethyldodecane lb/h 000000000000000000000C15H26‐N4 lb/h 12,429 163 1 112,967 112,967 112,967 112,965 100,539 100,539 3,389 0 9,037 0 0 0 2 2 3,552 1106,8‐Dimethyltridecane lb/h 0000000000000000000001,4‐Dimethyl‐Phenanthrene lb/h 0 427 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 427 0 0 0 N‐Cetane lb/h 000000000000000000000C18H26O lb/h 0 4,923 00000000000 0 0 0 0 4,923 000C18H28 lb/h 000000000000000000000C21H26O2 lb/h 0 3,421 00000000000 0 0 0 0 3,421 000C21H34 lb/h 10 7,751 0 94 94 94 94 84 84 3080 0 0 0 0 7,754 000C22H28O2 lb/h 0 1,788 00000000000 0 0 0 0 1,788 000Carbon lb/h 000000000000000000000Sulfur lb/h 000000000000000000000Sand/Catalyst Solids lb/h 0000000000000 9 0 0 9 0000Ash lb/h 0000000000000 0 0 0 0 0000Wood lb/h 0000000000000 0 0 0 0 0000Char lb/h 0000000000000 0 0 0 0 0000Coke lb/h 0000000000000 1 0 0 1 0000

165
R-365

LP STEAM

FROM T-812

PFD-61712-A801

H-AP-53

OFFGAS

FROM H-315

PFD-61712-A302

H-AP-15

Rev:

1

Project No: Drawing:

30482.00 PFD-61712-A303

THERMOCHEMICAL CONVERSION OF BIOMASS

TO HYDROCARBON FUEL

FAST PYROLYSIS AND VAPOR PHASE UPGRADING

PROCESS FLOW DIAGRAM

AREA 300: WATER GAS SHIFT

Rev. Date By Description

0

QA-H373 QC-H374

QHAP15

QHAP53

343

813 367

369 370

372

372B

J:\1A - Process Solutions\30482 NREL Thermochemical Conv - Design-Model\Drawings\ 30482 Pyrolysis Ex-Situ PFDs 61712 150128.vsd Plot date: 1/29/2015

374

R-365

HIGH-TEMPERATURE

WGS

H-373

POST-WGS ACHE

H-374

POST-WGS

COOLER

WGS PRODUCT

TO S-385

PFD-61712-A304

H-373

9/29/14 JAR ISSUED FOR DESIGN REPORT

366

CWS

CWR

H-374

H-AP-14

H-AP-32

H-BP-14 H-BP-4

H-BP-36

H-AP-53

PRE-ABSORBER UPGRADED

VAPOR COOLER/A300 WGS

STEAM SUPERHEAT

PYROLYSIS VAPOR

FROM H-AP-51

PFD-61712-A305

PYROLYSIS VAPOR

TO D-301

PFD-61712-A305

WGS OUTLET

TO H-AP-52

PFD-61712-A605

WGS OUTLET

FROM H-AP-52

PFD-61712-A605

H-AP-15

A300 WGS OUTLET

COOLER/A300 WGS

FEED PREHEAT

H-AP-14

A300 WGS OUTLET

COOLER/A300 PYROLYSIS

OFFGAS TO WGS PREHEAT

H-AP-32

A300 WGS OUTLET

COOLER/WW PREHEAT

FOR STEAM PRODUCTION

H-BP-4

A300 WGS OUTLET COOLER/

PYROLYSIS OFFGAS FEED

TO WGS PREHEAT

H-BP-14

A300 WGS OUTLET COOLER/

PYROLYSIS OFFGAS FEED

TO WGS PREHEAT

H-BP-36

A300 WGS OUTLET COOLER/

FAST PYROLYSIS

FLUIDIZING GAS PREHEAT

WASTEWATER

FROM H-BP-33/H-BP-26

PFD-61712-A805

WASTEWATER

TO H-AP-59/61/62

PFD-61712-A805

WGS OUTLET

TO H-AP-33

PFD-61712-A605

WGS OUTLET

FROM H-AP-33

PFD-61712-A605

WGS OUTLET

TO H-BP-35

PFD-61712-A604

WGS OUTLET

FROM H-BP-27

PFD-61712-A604

WGS OUTLET

TO H-BP-1

PFD-61712-A604

WGS OUTLET

FROM H-BP-1

PFD-61712-A604

FLUIDIZING GAS

FROM K-211

PFD-61712-A203

FLUIDIZING GAS

TO H-BP-3

PFD-61712-A203

1 12/12/14 DMS ADDED HX NETWORK

QHAP14 QHBP14 QHBP4

QHAP32

QHBP36

203P

166
PFD‐61712‐A303 203P 343 366 367 369 370 372 372B 374 813 

Total Flow lb/h 140,215 51,621 51,621 30,755 82,376 82,376 82,376 82,376 82,376 30,755 000000000000Temperature F 160 95 400 404 397 464 637 185 110 354 000000000000Pressure Psia 127 95 91 135 91 89 84 82 78 140 000000000000Vapor Fraction 1111111111 000000000000Enthalpy Flow MMBtu/h ‐231 ‐94 ‐83 ‐173 ‐256 ‐253 ‐253 ‐288 ‐301 ‐174 000000000000Argon lb/h 0000000000000000000000Nitrogen lb/h 0000000000000000000000Oxygen lb/h 0000000000000000000000SO2 lb/h 0000000000000000000000NO2 lb/h 0000000000000000000000Hydrogen lb/h 24,531 6,014 6,014 0 6,014 6,014 7,092 7,092 7,092 0 000000000000Ammonia lb/h 0000000000000000000000H2S lb/h 0000000000000000000000Water lb/h 353 141 141 30,663 30,804 30,804 21,172 21,172 21,172 30,663 000000000000Carbon Monoxide lb/h 47,501 18,741 18,741 0 18,741 18,741 3,766 3,766 3,766 0 000000000000Carbon Dioxide lb/h 40,152 15,648 15,648 2 15,650 15,650 39,180 39,180 39,180 2 000000000000Methane lb/h 5,884 2,354 2,354 0 2,354 2,354 2,354 2,354 2,354 0 000000000000Methanol lb/h 0000000000000000000000Formic Acid lb/h 0000000000000000000000Glyoxal lb/h 0000000000000000000000Ethylene lb/h 11,780 4,714 4,714 0 4,714 4,714 4,714 4,714 4,714 0 000000000000Acetaldehyde lb/h 0000000000000000000000Hydroxyacetaldehyde lb/h 0000000000000000000000Acetic Acid lb/h 0000000000000000000000Ethane lb/h 0000000000000000000000Propylene lb/h 3,982 1,594 1,594 0 1,594 1,594 1,594 1,594 1,594 0 0000000000001‐Hydroxy‐2‐propanone lb/h 0000000000000000000000Propionic Acid lb/h 0000000000000000000000Propane lb/h 0000000000000000000000Furan lb/h 500 200 200 0 200 200 200 200 200 0 0000000000001‐Butene lb/h 1,975 790 790 0 790 790 790 790 790 0 000000000000Tetrahydrofuran lb/h 422 169 169 0 169 169 169 169 169 0 000000000000N‐Butane lb/h 0000000000000000000000Furfural lb/h 00000000000000000000002‐methylfuran lb/h 466 187 187 0 187 187 187 187 187 0 000000000000Furfuryl Alcohol lb/h 0000000000000000000000n‐Pentane lb/h 0000000000000000000000Pentenone lb/h 0000000000000000000000Benzene lb/h 0000000000000000000000Phenol lb/h 14 6 6 40 45 45 45 45 45 40 0000000000001,2‐Benzenediol lb/h 0 0 0 49 49 49 49 49 49 49 000000000000Hydroxymethylfurfural lb/h 00000000000000000000002,5‐dimethylfuran lb/h 2110111110 000000000000Methyl Cyclopentenone lb/h 0000000000000000000000Hydroxymethylcyclopentenone lb/h 0000000000000000000000Cyclohexanone lb/h 0000000000000000000000Levoglucosan lb/h 00000000000000000000001‐Hexanal lb/h 0000000000000000000000Dimethoxytetrahydrofuran lb/h 1000000000 000000000000Cyclohexane lb/h 1,673 670 670 0 670 670 670 670 670 0 000000000000N‐Hexane lb/h 0000000000000000000000Hexanol lb/h 0000000000000000000000Toluene lb/h 00000000000000000000002‐Methylphenol lb/h 0000000000 0000000000003‐Methyl‐phenol lb/h 0000000000000000000000Guaiacol lb/h 0000000000 000000000000Methyl‐Cyclohexane lb/h 191 76 76 0 76 76 76 76 76 0 0000000000002‐Methylhexane lb/h 0000000000000000000000VinylPhenol lb/h 0000000000 000000000000O‐Xylene lb/h 0000000000000000000000Ethylbenzne lb/h 00000000000000000000002,3‐Dimethyl‐phenol lb/h 2111222221 0000000000002,6‐dimethoxyphenol lb/h 0000000000 000000000000Vanillyl alcohol lb/h 0000000000 0000000000002,4,6‐Trimethylpyridine lb/h 3110111110 000000000000Cis‐1,2‐dimethyl cyclohexane lb/h 295 118 118 0 118 118 118 118 118 0 000000000000Trans‐1,2‐dimethylcyclohexane lb/h 484 194 194 0 194 194 194 194 194 0 000000000000Ethylcyclohexane lb/h 00000000000000000000004‐Methylheptane lb/h 00000000000000000000002‐Methyl‐Benzofuran lb/h 1000000000 000000000000Indane lb/h 00000000000000000000002‐methoxy‐4‐vinylphenol lb/h 0000000000 000000000000Syringaldehyde lb/h 0000000000000000000000n‐Propylbenzene lb/h 0000000000000000000000Naphthalene lb/h 00000000000000000000001‐Naphthalenol lb/h 0000000000 000000000000Coniferyl Aldehyde lb/h 0000000000 000000000000Tetralin lb/h 0000000000000000000000Isoeugenol lb/h 0000000000 000000000000Decalin lb/h 000 0 00000 00000000000002,5‐Dimethyloctane lb/h 00000000000000000000001‐Methyl naphthalene lb/h 0000000000 0000000000001‐methyl decahydronaphthene lb/h 000 0 00000 0000000000000Dibenzothiophene lb/h 0000000000 000000000000Biphenyl lb/h 00000000000000000000005‐hexyl‐O‐cresol lb/h 000 0 00000 0000000000000n‐Heptylcyclohexane lb/h 0000000000000000000000C14H20‐N35 lb/h 0000000000000000000000C14H24‐N5 lb/h 000 0 00000 00000000000003,5‐Dimethyldodecane lb/h 0000000000000000000000C15H26‐N4 lb/h 100 0 00000 00000000000006,8‐Dimethyltridecane lb/h 00000000000000000000001,4‐Dimethyl‐Phenanthrene lb/h 000 0 0 0 0000000000000000N‐Cetane lb/h 0000000000000000000000C18H26O lb/h 000 0 00000 0000000000000C18H28 lb/h 0000000000000000000000C21H26O2 lb/h 000 0 00000 0000000000000C21H34 lb/h 000 0 00000 0000000000000C22H28O2 lb/h 000 0 00000 0000000000000Carbon lb/h 0000000000000000000000Sulfur lb/h 0000000000000000000000Sand/Catalyst Solids lb/h 0000000000000000000000Ash lb/h 0000000000000000000000Wood lb/h 0000000000000000000000Char lb/h 0000000000000000000000Coke lb/h 0000000000000000000000

167
S-386

CONDENSATE

TO T-860

PFD-61712-A804

PSA OFFGAS

TO H-BP-9/K-511

PFD-61712-A501

HYDROGEN

TO K-211/K-412/K-462

PFD-61712-A504

Rev:

2

Project No: Drawing:

30482.00 PFD-61712-A304

THERMOCHEMICAL CONVERSION OF BIOMASS

TO HYDROCARBON FUEL

FAST PYROLYSIS AND VAPOR PHASE UPGRADING

PROCESS FLOW DIAGRAM

AREA 300: PSA

Rev. Date By Description 0

WGS PRODUCT

FROM H-374

PFD-61712-A303

374

389

390

377

388

J:\1A - Process Solutions\30482 NREL Thermochemical Conv - Design-Model\Drawings\ 30482 Pyrolysis Ex-Situ PFDs 61712 150128.vsd Plot date: 1/29/2015

382

K-390

W-K390

S-385

377A

K-390

PSA COMPRESSOR:

MULTISTAGE

P-377

COMPRESSOR

CONDENSATE PUMP

S-385

PSA COMPRESSOR

SUCTION KO

S-386

PSA COMPR DISCH

KO

M-385

PSA

M-385

385

386

QC-K390

9/29/14 JAR ISSUED FOR DESIGN REPORT

P-377

W-P377

T-377

T-377

COMPRESSOR

CONDENSATE TANK

376

QA-K390

1 12/12/14 DMS ADDED HX NETWORK

CWS

CWR

2 12/29/14 JAR MINOR UPDATES

168
PFD‐61712‐A304 374 376 377 377A 382 385 386 388 389 390 

Total Flow lb/h 82,376 62,478 20,723 19,898 634 61,844 191 61,652 54,620 7,032 000000000000Temperature F 110 110 110 110 110 110 110 110 110 110 000000000000Pressure Psia 78 78 83 78 78 214 212 212 22 202 000000000000Vapor Fraction 1 1 000 1 0 111 000000000000Enthalpy Flow MMBtu/h ‐301 ‐165 ‐141 ‐135 ‐4 ‐162 ‐1 ‐160 ‐158 ‐3 000000000000Argon lb/h 0000000000000000000000Nitrogen lb/h 0000000000000000000000Oxygen lb/h 0000000000000000000000SO2 lb/h 0000000000000000000000NO2 lb/h 0000000000000000000000Hydrogen lb/h 7,092 7,092 0 0 0 7,092 0 7,092 1,135 5,957 000000000000Ammonia lb/h 0000000000000000000000H2S lb/h 0000000000000000000000Water lb/h 21,172 1,338 20,658 19,834 634 705 191 514 514 0000000000000Carbon Monoxide lb/h 3,766 3,766 0 0 0 3,766 0 3,766 3,348 418 000000000000Carbon Dioxide lb/h 39,180 39,179 1 1 0 39,179 0 39,179 38,522 657 000000000000Methane lb/h 2,354 2,354 0 0 0 2,354 0 2,354 2,354 0000000000000Methanol lb/h 0000000000000000000000Formic Acid lb/h 0000000000000000000000Glyoxal lb/h 0000000000000000000000Ethylene lb/h 4,714 4,714 0 0 0 4,714 0 4,714 4,714 0000000000000Acetaldehyde lb/h 0000000000000000000000Hydroxyacetaldehyde lb/h 0000000000000000000000Acetic Acid lb/h 0000000000000000000000Ethane lb/h 0000000000000000000000Propylene lb/h 1,594 1,594 0 0 0 1,594 0 1,594 1,594 00000000000001‐Hydroxy‐2‐propanone lb/h 0000000000000000000000Propionic Acid lb/h 0000000000000000000000Propane lb/h 0000000000000000000000Furan lb/h 200 200 0 0 0 200 0 200 200 00000000000001‐Butene lb/h 790 790 0 0 0 790 0 790 790 0000000000000Tetrahydrofuran lb/h 169 169 0 0 0 169 0 169 169 0000000000000N‐Butane lb/h 0000000000000000000000Furfural lb/h 00000000000000000000002‐methylfuran lb/h 187 187 0 0 0 187 0 187 187 0000000000000Furfuryl Alcohol lb/h 0000000000000000000000n‐Pentane lb/h 0000000000000000000000Pentenone lb/h 0000000000000000000000Benzene lb/h 0000000000000000000000Phenol lb/h 45 31 15 14 0 31 0 31 31 00000000000001,2‐Benzenediol lb/h 49 0 49 49 0 0 0 0 0 0000000000000Hydroxymethylfurfural lb/h 00000000000000000000002,5‐dimethylfuran lb/h 110001011 0000000000000Methyl Cyclopentenone lb/h 0000000000000000000000Hydroxymethylcyclopentenone lb/h 0000000000000000000000Cyclohexanone lb/h 0000000000000000000000Levoglucosan lb/h 00000000000000000000001‐Hexanal lb/h 0000000000000000000000Dimethoxytetrahydrofuran lb/h 000000000 0000000000000Cyclohexane lb/h 670 670 0 0 0 670 0 670 670 0000000000000N‐Hexane lb/h 0000000000000000000000Hexanol lb/h 0000000000000000000000Toluene lb/h 00000000000000000000002‐Methylphenol lb/h 000000000 00000000000003‐Methyl‐phenol lb/h 0000000000000000000000Guaiacol lb/h 000000000 0000000000000Methyl‐Cyclohexane lb/h 76 76 0 0 0 76 0 76 76 00000000000002‐Methylhexane lb/h 0000000000000000000000VinylPhenol lb/h 000000000 0000000000000O‐Xylene lb/h 0000000000000000000000Ethylbenzne lb/h 00000000000000000000002,3‐Dimethyl‐phenol lb/h 220002022 00000000000002,6‐dimethoxyphenol lb/h 000000000 0000000000000Vanillyl alcohol lb/h 000000000 00000000000002,4,6‐Trimethylpyridine lb/h 110001011 0000000000000Cis‐1,2‐dimethyl cyclohexane lb/h 118 118 0 0 0 118 0 118 118 0000000000000Trans‐1,2‐dimethylcyclohexane lb/h 194 194 0 0 0 194 0 194 194 0000000000000Ethylcyclohexane lb/h 00000000000000000000004‐Methylheptane lb/h 00000000000000000000002‐Methyl‐Benzofuran lb/h 000000000 0000000000000Indane lb/h 00000000000000000000002‐methoxy‐4‐vinylphenol lb/h 000000000 0000000000000Syringaldehyde lb/h 0000000000000000000000n‐Propylbenzene lb/h 0000000000000000000000Naphthalene lb/h 00000000000000000000001‐Naphthalenol lb/h 000000000 0000000000000Coniferyl Aldehyde lb/h 000000000 0000000000000Tetralin lb/h 0000000000000000000000Isoeugenol lb/h 000000000 0000000000000Decalin lb/h 000000000 00000000000002,5‐Dimethyloctane lb/h 00000000000000000000001‐Methyl naphthalene lb/h 000000000 00000000000001‐methyl decahydronaphthene lb/h 000000000 0000000000000Dibenzothiophene lb/h 000000000 0000000000000Biphenyl lb/h 00000000000000000000005‐hexyl‐O‐cresol lb/h 000000000 0000000000000n‐Heptylcyclohexane lb/h 0000000000000000000000C14H20‐N35 lb/h 0000000000000000000000C14H24‐N5 lb/h 000000000 00000000000003,5‐Dimethyldodecane lb/h 0000000000000000000000C15H26‐N4 lb/h 000000000 00000000000006,8‐Dimethyltridecane lb/h 00000000000000000000001,4‐Dimethyl‐Phenanthrene lb/h 0000000000000000000000N‐Cetane lb/h 0000000000000000000000C18H26O lb/h 000000000 0000000000000C18H28 lb/h 0000000000000000000000C21H26O2 lb/h 000000000 0000000000000C21H34 lb/h 000000000 0000000000000C22H28O2 lb/h 000000000 0000000000000Carbon lb/h 0000000000000000000000Sulfur lb/h 0000000000000000000000Sand/Catalyst Solids lb/h 0000000000000000000000Ash lb/h 0000000000000000000000Wood lb/h 0000000000000000000000Char lb/h 0000000000000000000000Coke lb/h 0000000000000000000000

169
Rev:

0

Project No: Drawing:

30482.00 PFD-61712-A305

THERMOCHEMICAL CONVERSION OF BIOMASS

TO HYDROCARBON FUEL

FAST PYROLYSIS AND VAPOR PHASE UPGRADING

PROCESS FLOW DIAGRAM

AREA 300: A300 HEAT RECOVERY

Rev. Date By Description

0

J:\1A - Process Solutions\30482 NREL Thermochemical Conv - Design-Model\Drawings\ 30482 Pyrolysis Ex-Situ PFDs 61712 150128.vsd Plot date: 1/29/2015

PYROLYSIS VAPOR

FROM S-262/T-261

PFD-61712-A301

300 PYROLYSIS VAPOR

TO H-AP-48

PFD-61712-A603

PYROLYSIS VAPOR

FROM H-AP-51

PFD-61712-A605

PYROLYSIS VAPOR

TO H-AP-53

PFD-61712-A303

PYROLYSIS VAPOR

TO H-AP-56

PFD-61712-A605

PYROLYSIS VAPOR

TO H-AP-60

PFD-61712-A805

PYROLYSIS VAPOR

FROM H-AP-53

PFD-61712-A303

PYROLYSIS VAPOR

FROM H-AP-56

PFD-61712-A605

PYROLYSIS VAPOR

FROM H-AP-60

PFD-61712-A805

PYROLYSIS VAPOR

TO D-301

PFD-61712-A301

311

H-AP-23

ABSORBER 1 BOTTOMS

COOLER/WW PREHEAT FOR

STEAM PRODUCTION

H-BP-3

POST-ABSORBER 1 VAPOR

COOLER/FAST PYROLYSIS

FLUIDIZING GAS PREHEAT

ABSORBER VAPOR

FROM D-301

PFD-61712-A301

ABSORBER VAPOR

TO H-AP-17

PFD-61712-A203

ABSORBER VAPOR

TO H-AP-18

PFD-61712-A203

ABSORBER VAPOR

TO H-AP-31

PFD-61712-A605

ABSORBER VAPOR

FROM H-AP-17

PFD-61712-A203

ABSORBER VAPOR

FROM H-AP-18

PFD-61712-A203

ABSORBER VAPOR

FROM H-AP-31

PFD-61712-A605

312 ABSORBER VAPOR

TO H-BP-20

PFD-61712-A605

ABSORBER VAPOR

FROM H-BP-11

PFD-61712-A604

ABSORBER VAPOR

TO H-313

PFD-61712-A301

313

H-BP-3

FLUIDIZING GAS

FROM H-BP-36

PFD-61712-A203

FLUIDIZING GAS

TO H-AP-8

PFD-61712-A203

H-AP-23

WASTEWATER

FROM H-BP-26/H-BP-33

PFD-61712-A805

WASTEWATER

TO H-AP-59/61/62

PFD-61712-A805

ABSORBER BOTTOMS

FROM D-301

PFD-61712-A301

318 ABSORBER BOTTOMS

TO H-BP-43

PFD-61712-A805

ABSORBER BOTTOMS

TO H-BP-34

PFD-61712-A604

ABSORBER BOTTOMS

FROM H-BP-43

PFD-61712-A805

ABSORBER BOTTOMS

FROM H-BP-34

PFD-61712-A604

ABSORBER BOTTOMS

TO H-BP-31

PFD-61712-A604

ABSORBER BOTTOMS

FROM H-BP-31

PFD-61712-A604

ABSORBER BOTTOMS

TO H-BP-44

PFD-61712-A601

ABSORBER BOTTOMS

FROM H-BP-44

PFD-61712-A601

ABSORBER BOTTOMS

TO S-319

PFD-61712-A301

12/12/14 DMS ADDED HX NETWORK

QHAP23

QHBP3

319

170
PFD‐61712‐A305 300 311 312 313 318 319 

Total Flow lb/h 310,342 310,342 371,714 371,714 19,671 19,671 0000000000000000Temperature F 931 466 358 220 461 175 0000000000000000Pressure Psia 115 113 110 108 113 123 0000000000000000Vapor Fraction 1111 000000000000000000Enthalpy Flow MMBtu/h ‐638 ‐731 ‐786 ‐827 ‐7 ‐10 0000000000000000Argon lb/h 0000000000000000000000Nitrogen lb/h 0000000000000000000000Oxygen lb/h 0000000000000000000000SO2 lb/h 0000000000000000000000NO2 lb/h 0000000000000000000000Hydrogen lb/h 21,258 21,258 21,261 21,261 1 1 0000000000000000Ammonia lb/h 0000000000000000000000H2S lb/h 0000000000000000000000Water lb/h 76,670 76,670 77,078 77,078 43 43 0000000000000000Carbon Monoxide lb/h 66,248 66,248 66,266 66,266 3 3 0000000000000000Carbon Dioxide lb/h 55,426 55,426 55,716 55,716 7 7 0000000000000000Methane lb/h 8,325 8,325 8,333 8,333 1 1 0000000000000000Methanol lb/h 0000000000000000000000Formic Acid lb/h 0000000000000000000000Glyoxal lb/h 0000000000000000000000Ethylene lb/h 16,692 16,692 16,766 16,766 2 2 0000000000000000Acetaldehyde lb/h 0000000000000000000000Hydroxyacetaldehyde lb/h 0000000000000000000000Acetic Acid lb/h 0000000000000000000000Ethane lb/h 0000000000000000000000Propylene lb/h 5,682 5,682 5,810 5,810 1 1 00000000000000001‐Hydroxy‐2‐propanone lb/h 0000000000000000000000Propionic Acid lb/h 0000000000000000000000Propane lb/h 0000000000000000000000Furan lb/h 845 845 1,212 1,212 1 1 00000000000000001‐Butene lb/h 2,919 2,919 3,251 3,251 1 1 0000000000000000Tetrahydrofuran lb/h 1,046 1,046 2,236 2,236 1 1 0000000000000000N‐Butane lb/h 0000000000000000000000Furfural lb/h 00000000000000000000002‐methylfuran lb/h 1,144 1,144 2,432 2,432 1 1 0000000000000000Furfuryl Alcohol lb/h 0000000000000000000000n‐Pentane lb/h 0000000000000000000000Pentenone lb/h 0000000000000000000000Benzene lb/h 0000000000000000000000Phenol lb/h 2,161 2,161 7,632 7,632 11 11 00000000000000001,2‐Benzenediol lb/h 1,872 1,872 2,049 2,049 20 20 0000000000000000Hydroxymethylfurfural lb/h 00000000000000000000002,5‐dimethylfuran lb/h 13 13 42 42 0 0 0000000000000000Methyl Cyclopentenone lb/h 0000000000000000000000Hydroxymethylcyclopentenone lb/h 0000000000000000000000Cyclohexanone lb/h 0000000000000000000000Levoglucosan lb/h 00000000000000000000001‐Hexanal lb/h 0000000000000000000000Dimethoxytetrahydrofuran lb/h 38 38 136 136 0 0 0000000000000000Cyclohexane lb/h 5,348 5,348 13,262 13,262 9 9 0000000000000000N‐Hexane lb/h 0000000000000000000000Hexanol lb/h 0000000000000000000000Toluene lb/h 00000000000000000000002‐Methylphenol lb/h 0 0 0000 00000000000000003‐Methyl‐phenol lb/h 0000000000000000000000Guaiacol lb/h 114400 0000000000000000Methyl‐Cyclohexane lb/h 990 990 2,898 2,898 2 2 00000000000000002‐Methylhexane lb/h 0000000000000000000000VinylPhenol lb/h 115500 0000000000000000O‐Xylene lb/h 0000000000000000000000Ethylbenzne lb/h 00000000000000000000002,3‐Dimethyl‐phenol lb/h 2,627 2,627 9,506 9,506 30 30 00000000000000002,6‐dimethoxyphenol lb/h 898 898 3,184 3,184 29 29 0000000000000000Vanillyl alcohol lb/h 870 870 3,063 3,063 32 32 00000000000000002,4,6‐Trimethylpyridine lb/h 333 333 1,203 1,203 2 2 0000000000000000Cis‐1,2‐dimethyl cyclohexane lb/h 3,060 3,060 10,060 10,060 12 12 0000000000000000Trans‐1,2‐dimethylcyclohexane lb/h 4,153 4,153 13,344 13,344 14 14 0000000000000000Ethylcyclohexane lb/h 00000000000000000000004‐Methylheptane lb/h 00000000000000000000002‐Methyl‐Benzofuran lb/h 463 463 1,673 1,673 5 5 0000000000000000Indane lb/h 00000000000000000000002‐methoxy‐4‐vinylphenol lb/h 13 13 49 49 0 0 0000000000000000Syringaldehyde lb/h 0000000000000000000000n‐Propylbenzene lb/h 0000000000000000000000Naphthalene lb/h 00000000000000000000001‐Naphthalenol lb/h 353 353 1,236 1,236 16 16 0000000000000000Coniferyl Aldehyde lb/h 381 381 30 30 373 373 0000000000000000Tetralin lb/h 0000000000000000000000Isoeugenol lb/h 13 13 48 48 0 0 0000000000000000Decalin lb/h 44 44 158 158 0 0 00000000000000002,5‐Dimethyloctane lb/h 00000000000000000000001‐Methyl naphthalene lb/h 417 417 1,489 1,489 11 11 00000000000000001‐methyl decahydronaphthene lb/h 62 62 222 222 1 1 0000000000000000Dibenzothiophene lb/h 73 73 120 120 41 41 0000000000000000Biphenyl lb/h 00000000000000000000005‐hexyl‐O‐cresol lb/h 4,709 4,709 16,038 16,038 333 333 0000000000000000n‐Heptylcyclohexane lb/h 0000000000000000000000C14H20‐N35 lb/h 0000000000000000000000C14H24‐N5 lb/h 3,313 3,313 11,462 11,462 185 185 00000000000000003,5‐Dimethyldodecane lb/h 0000000000000000000000C15H26‐N4 lb/h 3,555 3,555 12,429 12,429 163 163 00000000000000006,8‐Dimethyltridecane lb/h 00000000000000000000001,4‐Dimethyl‐Phenanthrene lb/h 427 427 0 0 427 427 0000000000000000N‐Cetane lb/h 0000000000000000000000C18H26O lb/h 4,923 4,923 0 0 4,923 4,923 0000000000000000C18H28 lb/h 0000000000000000000000C21H26O2 lb/h 3,421 3,421 0 0 3,421 3,421 0000000000000000C21H34 lb/h 7,754 7,754 10 10 7,751 7,751 0000000000000000C22H28O2 lb/h 1,788 1,788 0 0 1,788 1,788 0000000000000000Carbon lb/h 0000000000000000000000Sulfur lb/h 0000000000000000000000Sand/Catalyst Solids lb/h 9 9 0 0 9 9 0000000000000000Ash lb/h 0 0 0 0 0 0 0000000000000000Wood lb/h 0 0 0 0 0 0 0000000000000000Char lb/h 0 0 0 0 0 0 0000000000000000Coke lb/h 1 1 0 0 1 1 0000000000000000

171
S-410

RECYCLE GAS PURGE

TO M-575

PFD-61712-A503

ORGANIC PHASE

FROM P-331

PFD-61712-A302

P-410 QX-H410

QC-H445

S-411

K-442

QA-H413

QC-H413

426

OFFGAS

TO K-511/H-BP-9

PFD-61712-A501

MAKEUP HYDROGEN

FROM

PFD-61712-A504

AQUEOUS PHASE

TO M-805

PFD-61712-A804

QC-H444

H-410

Rev:

0

Project No: Drawing:

30482.00 PFD-61712-A401

THERMOCHEMICAL CONVERSION OF BIOMASS

TO HYDROCARBON FUEL

FAST PYROLYSIS AND VAPOR PHASE UPGRADING

PROCESS FLOW DIAGRAM

AREA 400: HYDROTREATING

Rev. Date By Description

435

432

443

444C

J:\1A - Process Solutions\30482 NREL Thermochemical Conv - Design-Model\Drawings\ 30482 Pyrolysis Ex-Situ PFDs 61712 150128.vsd Plot date: 1/29/2015

414

443A

415 417

418

444B

419

422

424

R-410

W-K412

431

429

337

411

W-P410

H-411

QF-H411

W-K442

420

421

S-410

VAPOR

KO DRUM

P-410

HT FEED

PUMP

H-444

QUENCH HYDROGEN

STAGE 2 COOLER

H-445

QUENCH HYDROGEN

STAGE 3 COOLER

H-410

FEED-EFFLUENT

EXCH

H-411

FEED

FURNACE

R-410

HYDROTREATER

H-413A

HT PRODUCT

ACHE

H-413C

HT PRODUCT

COOLER

K-412

HYDROGEN MAKEUP

COMPRESSOR

S-411

HP HT EFFLUENT

FLASH: 3 PHASE

K-442

HYDROGEN RECYCLE

COMPRESSOR

0 9/29/14 JAR ISSUED FOR DESIGN REPORT

QA-K412

H-413A

S-412

AQUEOUS PHASE

TO T-860

PFD-61712-A804

430

OFFGAS

TO K-511/H-BP-9

PFD-61712-A501

S-412

LP HT EFFLUENT

FLASH: 3 PHASE

428

K-412

CWS

CWR

H-444

CWS

CWR

H-445

CWS

CWR H-413C

HT EFFLUENT

TO H-AP-12/H-AP-24

PFD-61712-A404

HT EFFLUENT

FROM H-BP-5/47/48/49

PFD-61712-A404

ORGANIC PHASE

TO H-BP-30

PFD-61712-A404

1 12/12/14 DMS ADDED HX NETWORK

1 NOTE: FUEL GAS AND COMBUSTION DUTY ASSOCIATED WITH H-411 ACCOUNTED FOR BY QF-H548 ON PFD-61712-A501-A

1

172
PFD‐61712‐A401 337 411 414 415 417 418 419 420 421 422 424 426 428 429 430 431 432 435 443 443A 444B 444C 

Total Flow lb/h 50,051 0 50,051 56,010 56,010 67,579 67,579 67,579 67,579 17,435 2,912 47,232 787 46,446 0 2,061 15,374 2,154 17,528 5,959 5,784 5,784 Temperature F 105 0 117 122 707 757 415 175 110 110 110 110 110 110 0 110 110 110 132 132 110 110 Pressure Psia 113 113 1600 1600 1545 1515 1510 1505 1495 1493 1493 1493 53 53 53 1493 1493 245 1600 1600 1595 1595 Vapor Fraction 000 1111111 0 0 1 0 0 1111111 Enthalpy Flow MMBtu/h ‐33 0 ‐33 ‐39 ‐14 ‐27 ‐49 ‐65 ‐68 ‐21 ‐20 ‐30 ‐1 ‐28 0 ‐2 ‐18 ‐1 ‐18 ‐6 ‐6 ‐6 Argon lb/h 0000000000000000000000Nitrogen lb/h 0000000000000000000000Oxygen lb/h 0000000000000000000000SO2 lb/h 0000000000000000000000NO2 lb/h 0000000000000000000000Hydrogen lb/h 2 0 2 2,467 2,467 6,209 6,209 6,209 6,209 6,152 0 57 56 1 0 727 5,424 1,825 7,249 2,465 2,392 2,392 Ammonia lb/h 000 7 7 66 66 66 66 23 34 9 4 5 0 3 20 0 20 7 7 7 H2S lb/h 000 10 10 42 42 42 42 33 0 10 5 5 0 4 29 0 29 10 9 9 Water lb/h 212 0 212 234 234 3,151 3,151 3,151 3,151 73 2,877 201 18 183 0 9 65 0 65 22 21 21 Carbon Monoxide lb/h 10 0 10 1,104 1,104 3,555 3,555 3,555 3,555 3,502 0 53 51 2 0 414 3,088 128 3,216 1,093 1,061 1,061 Carbon Dioxide lb/h 118 0 118 642 642 1,713 1,713 1,713 1,713 1,521 0 192 139 53 0 180 1,341 201 1,543 524 509 509 Methane lb/h 4 0 4 1,011 1,011 3,485 3,485 3,485 3,485 3,358 0 126 115 12 0 397 2,961 0 2,961 1,007 977 977 Methanol lb/h 0000000000000000000000Formic Acid lb/h 0000000000000000000000Glyoxal lb/h 0000000000000000000000Ethylene lb/h 31 0 31 67 67 137 137 137 137 122 0 15 11 4 0 14 107 0 107 37 35 35 Acetaldehyde lb/h 0000000000000000000000Hydroxyacetaldehyde lb/h 0000000000000000000000Acetic Acid lb/h 0000000000000000000000Ethane lb/h 000 398 398 1,553 1,553 1,553 1,553 1,326 0 227 147 80 0 157 1,169 0 1,169 398 386 386 Propylene lb/h 50 0 50 51 51 5 5 5 5 3 0 2 1 1 0 0 3 0 3111 1‐Hydroxy‐2‐propanone lb/h 0000000000000000000000Propionic Acid lb/h 0000000000000000000000Propane lb/h 000 25 25 123 123 123 123 83 0 41 14 26 0 10 73 0 73 25 24 24 Furan lb/h 138 0 138 138 138 000000000000000001‐Butene lb/h 126 0 126 128 128 12 12 12 12 5 0 7 1 6 0 1 5 0 5222 Tetrahydrofuran lb/h 448 0 448 448 448 00000000000000000N‐Butane lb/h 000 135 135 1,000 1,000 1,000 1,000 451 0 549 80 469 0 53 398 0 398 135 131 131 Furfural lb/h 00000000000000000000002‐methylfuran lb/h 485 0 485 485 485 00000000000000000Furfuryl Alcohol lb/h 0000000000000000000000n‐Pentane lb/h 000 33 33 522 522 522 522 109 0 413 22 391 0 13 96 0 96 33 32 32 Pentenone lb/h 0000000000000000000000Benzene lb/h 000 32 32 1,548 1,548 1,548 1,548 108 0 1,440 22 1,418 0 13 96 0 96 32 32 32 Phenol lb/h 2,067 0 2,067 2,067 2,067 18 18 18 18 0 0 18 0 18 0 0 0 0 0000 1,2‐Benzenediol lb/h 94 0 94 94 94 00000000000000000Hydroxymethylfurfural lb/h 00000000000000000000002,5‐dimethylfuran lb/h 11 0 11 11 11 0 0 0 0 0 0 0 0 0 0 0 0 0 0000 Methyl Cyclopentenone lb/h 0000000000000000000000Hydroxymethylcyclopentenone lb/h 0000000000000000000000Cyclohexanone lb/h 0000000000000000000000Levoglucosan lb/h 00000000000000000000001‐Hexanal lb/h 0000000000000000000000Dimethoxytetrahydrofuran lb/h 37 0 37 37 37 00000000000000000Cyclohexane lb/h 2,980 0 2,980 3,058 3,058 4,040 4,040 4,040 4,040 263 0 3,777 51 3,726 0 31 232 0 232 79 76 76 N‐Hexane lb/h 000 20 20 734 734 734 734 68 0 666 12 653 0 8 60 0 60 20 20 20 Hexanol lb/h 0000000000000000000000Toluene lb/h 000 5 5 477 477 477 477 17 0 460 2 458 0 2 15 0 15 5 5 5 2‐Methylphenol lb/h 0 0 000 000000000000000003‐Methyl‐phenol lb/h 0000000000000000000000Guaiacol lb/h 1 0 111 00000000000000000Methyl‐Cyclohexane lb/h 719 0 719 729 729 898 898 898 898 33 0 866 6 860 0 4 29 0 29 10 9 9 2‐Methylhexane lb/h 000 6 6 405 405 405 405 21 0 384 4 380 0 2 19 0 19 6 6 6 VinylPhenol lb/h 1 0 111 00000000000000000O‐Xylene lb/h 000 4 4 1,533 1,533 1,533 1,533 13 0 1,519 2 1,517 0 2 12 0 12 4 4 4 Ethylbenzne lb/h 000 0 0 139 139 139 139 2 0 137 0 137 0 0 1 0 1000 2,3‐Dimethyl‐phenol lb/h 2,621 0 2,621 2,621 2,621 000000000000000002,6‐dimethoxyphenol lb/h 897 0 897 897 897 00000000000000000Vanillyl alcohol lb/h 867 0 867 867 867 000000000000000002,4,6‐Trimethylpyridine lb/h 329 0 329 329 329 00000000000000000Cis‐1,2‐dimethyl cyclohexane lb/h 2,641 0 2,641 2,654 2,654 2,620 2,620 2,620 2,620 45 0 2,575 7 2,569 0 5 39 0 39 13 13 13 Trans‐1,2‐dimethylcyclohexane lb/h 3,466 0 3,466 3,492 3,492 4,343 4,343 4,343 4,343 88 0 4,255 14 4,242 0 10 78 0 78 26 26 26 Ethylcyclohexane lb/h 000 2 2 398 398 398 398 6 0 391 1 391 0 1 5 0 5222 4‐Methylheptane lb/h 000 2 2 317 317 317 317 7 0 310 1 309 0 1 6 0 6222 2‐Methyl‐Benzofuran lb/h 461 0 461 461 461 00000000000000000Indane lb/h 00000000000000000000002‐methoxy‐4‐vinylphenol lb/h 13 0 13 13 13 00000000000000000Syringaldehyde lb/h 0000000000000000000000n‐Propylbenzene lb/h 000 0 0 10 10 10 10 0 0 10 0 10 0 0 0 0 0000 Naphthalene lb/h 000 0 0 147 147 147 147 0 0 147 0 147 0 0 0 0 0000 1‐Naphthalenol lb/h 353 0 353 353 353 00000000000000000Coniferyl Aldehyde lb/h 381 0 381 381 381 00000000000000000Tetralin lb/h 000 0 0 61 61 61 61 0 0 61 0 61 0 0 0 0 0000 Isoeugenol lb/h 13 0 13 13 13 00000000000000000Decalin lb/h 43 0 43 43 43 160 160 160 160 0 0 159 0 159 0 0 0 0 0000 2,5‐Dimethyloctane lb/h 00000000000000000000001‐Methyl naphthalene lb/h 417 0 417 417 417 196 196 196 196 0 0 195 0 195 0 0 0 0 0000 1‐methyl decahydronaphthene lb/h 61 0 61 61 61 299 299 299 299 0 0 298 0 298 0 0 0 0 0000 Dibenzothiophene lb/h 73 0 73 73 73 00000000000000000Biphenyl lb/h 000 0 0 61 61 61 61 0 0 61 0 61 0 0 0 0 0000 5‐hexyl‐O‐cresol lb/h 4,706 0 4,706 4,706 4,706 00000000000000000n‐Heptylcyclohexane lb/h 000 0 0 4,463 4,463 4,463 4,463 1 0 4,463 0 4,462 0 0 1 0 1000 C14H20‐N35 lb/h 000 0 0 934 934 934 934 0 0 934 0 934 0 0 0 0 0000 C14H24‐N5 lb/h 3,310 0 3,310 3,311 3,311 3,311 3,311 3,311 3,311 0 0 3,310 0 3,310 0 0 0 0 0000 3,5‐Dimethyldodecane lb/h 000 0 0 1,312 1,312 1,312 1,312 1 0 1,312 0 1,312 0 0 0 0 0000 C15H26‐N4 lb/h 3,552 0 3,552 3,552 3,552 3,179 3,179 3,179 3,179 0 0 3,179 0 3,179 0 0 0 0 0000 6,8‐Dimethyltridecane lb/h 00000000000000000000001,4‐Dimethyl‐Phenanthrene lb/h 427 0 427 427 427 427 427 427 427 0 0 427 0 427 0 0 0 0 0000 N‐Cetane lb/h 0000000000000000000000C18H26O lb/h 4,923 0 4,923 4,923 4,923 00000000000000000C18H28 lb/h 000 0 0 4,656 4,656 4,656 4,656 0 0 4,656 0 4,656 0 0 0 0 0000 C21H26O2 lb/h 3,421 0 3,421 3,421 3,421 1,026 1,026 1,026 1,026 0 0 1,026 0 1,026 0 0 0 0 0000 C21H34 lb/h 7,754 0 7,754 7,754 7,754 7,754 7,754 7,754 7,754 0 0 7,754 0 7,754 0 0 0 0 0000 C22H28O2 lb/h 1,788 0 1,788 1,788 1,788 536 536 536 536 0 0 536 0 536 0 0 0 0 0000 Carbon lb/h 0000000000000000000000Sulfur lb/h 0000000000000000000000Sand/Catalyst Solids lb/h 0000000000000000000000Ash lb/h 0000000000000000000000Wood lb/h 0000000000000000000000Char lb/h 0000000000000000000000Coke lb/h 0000000000000000000000

173
HEAVY KEY

TO S-460

PFD-61712-A403

Rev:

0

Project No: Drawing:

30482.00 PFD-61712-A402

THERMOCHEMICAL CONVERSION OF BIOMASS

TO HYDROCARBON FUEL

FAST PYROLYSIS AND VAPOR PHASE UPGRADING

PROCESS FLOW DIAGRAM

AREA 400: PRODUCT SEPARATION

Rev. Date By Description

DIESEL PRODUCT

TO T-792

PFD-61712-A703

GASOLINE PRODUCT

TO T-790

PFD-61712-A703

HYDROPR PURGE

TO R-530

PFD-61712-A501

HC ORGANIC PHASE

FROM H-AP-43

PFD-61712-A404

QC-H454

QA-H457

QC-H457

460

456

452

453

QC-H459

454

J:\1A - Process Solutions\30482 NREL Thermochemical Conv - Design-Model\Drawings\ 30482 Pyrolysis Ex-Situ PFDs 61712 150128.vsd Plot date: 1/29/2015

451

480

D-450

GASOLINE

COLUMN

H-BP-26

NAPHTHA COLUMN

CONDENSER/WW PREHEAT

FOR STEAM PRODUCTION

P-450

D-450 REFLUX

PUMP

D-451

DIESEL

COLUMN

H-459

D-450 OVERHEAD

VAPOR COOLER

S-451

D-451 OVERHEAD

ACCUMULATOR

H-457A

DIESEL PRODUCT

ACHE

H-457C

DIESEL PRODUCT

COOLER

H-454

GASOLINE

PRODUCT COOLER

D-451

H-AP-58

P-451

S-451

D-450

H-BP-26

P-450

S-450

0 9/29/14 JAR ISSUED FOR DESIGN REPORT

H-457A

S-450

D-450 OVERHEAD

ACCUMULATOR

P-451

D-451 REFLUX

PUMP

CWS

CWR

H-454

CWS

CWR

H-457C

CWS

CWR

H-459

WASTEWATER

FROM H-BP-10

PFD-61712-A805

WASTEWATER

TO H-AP-23/24/25/32

PFD-61712-A805

D-450 BOTTOMS

FROM H-AP-28

PFD-61712-A501-A

D-450 BOTTOMS

TO H-AP-28

PFD-61712-A501-A

D-451 BOTTOMS

FROM H-AP-27

PFD-61712-A501-A

D-451 BOTTOMS

TO H-AP-27

PFD-61712-A501-A

DIESEL PRODUCT

TO H-AP-16/H-AP-25

PFD-61712-A404

DIESEL PRODUCT

FROM H-BP-30

PFD-61712-A404

H-AP-13

CONC WASTEWATER

FROM P-814

PFD-61712-A805

CONC WASTEWATER

TO T-822

PFD-61712-A805

H-AP-58

DISTILLATE COLUMN

CONDENSER/STEAM

PRODUCTION FROM WW

FOR REFORMER

H-AP-13

DISTILLATE COLUMN

CONDENSER/HT PRODUCT TO

NAPHTHA COLUMN PREHEAT

HT ORGANIC PHASE

FROM H-AP-12

PFD-61712-A404

1 12/12/14 DMS ADDED HX NETWORK

QHBP26

QHAP58

QHAP13 Q-H450C

CWS

CWR

H-450C

H-450C

D-450

CONDENSER

Q-H451C

CWS

CWR

H-451C

H-451C

D-451

CONDENSER

Q-H450R

LPS

CND

H-450R

H-450R

D-450

REBOILER

Q-H451R

LPS

CND

H-451R

H-451R

D-451

REBOILER

1 FOR STARTUP ONLY

1

1

1

1

174
PFD‐61712‐A402 451 452 453 454 456 460 480 

Total Flow lb/h 46,446 1,281 20,408 41,393 24,739 16,654 16,636 000000000000000Temperature F 450 110 60 627 60 713 550 000000000000000Pressure Psia 43 33 15 40 15 20 43 000000000000000Vapor Fraction 1 1 000 0 1 000000000000000Enthalpy Flow MMBtu/h ‐18 ‐1 ‐15 ‐11 ‐16 ‐2 ‐6 000000000000000Argon lb/h 0000000000000000000000Nitrogen lb/h 0000000000000000000000Oxygen lb/h 0000000000000000000000SO2 lb/h 0000000000000000000000NO2 lb/h 0000000000000000000000Hydrogen lb/h 1200000 000000000000000Ammonia lb/h 5320 000000000000000000H2S lb/h 5320 000000000000000000Water lb/h 183 55 168 0 0 0 40 000000000000000Carbon Monoxide lb/h 2200000 000000000000000Carbon Dioxide lb/h 53 53 11 0 0 0 10 000000000000000Methane lb/h 12 15 1 0 0 0 5 000000000000000Methanol lb/h 0000000000000000000000Formic Acid lb/h 0000000000000000000000Glyoxal lb/h 0000000000000000000000Ethylene lb/h 4510002 000000000000000Acetaldehyde lb/h 0000000000000000000000Hydroxyacetaldehyde lb/h 0000000000000000000000Acetic Acid lb/h 0000000000000000000000Ethane lb/h 80 94 28 0 0 0 42 000000000000000Propylene lb/h 1100 0000000000000000001‐Hydroxy‐2‐propanone lb/h 0000000000000000000000Propionic Acid lb/h 0000000000000000000000Propane lb/h 26 15 11 0 000000000000000000Furan lb/h 00000000000000000000001‐Butene lb/h 6240 000000000000000000Tetrahydrofuran lb/h 0000000000000000000000N‐Butane lb/h 469 158 311 0 000000000000000000Furfural lb/h 00000000000000000000002‐methylfuran lb/h 0000000000000000000000Furfuryl Alcohol lb/h 0000000000000000000000n‐Pentane lb/h 391 70 321 0 000000000000000000Pentenone lb/h 0000000000000000000000Benzene lb/h 1,418 96 1,321 0 0 0 0000000000000000Phenol lb/h 18 0 18 0 0 0 00000000000000001,2‐Benzenediol lb/h 0000000000000000000000Hydroxymethylfurfural lb/h 00000000000000000000002,5‐dimethylfuran lb/h 0000 000000000000000000Methyl Cyclopentenone lb/h 0000000000000000000000Hydroxymethylcyclopentenone lb/h 0000000000000000000000Cyclohexanone lb/h 0000000000000000000000Levoglucosan lb/h 00000000000000000000001‐Hexanal lb/h 0000000000000000000000Dimethoxytetrahydrofuran lb/h 0000000000000000000000Cyclohexane lb/h 3,726 230 3,526 0 0 0 29 000000000000000N‐Hexane lb/h 653 180 1,942 0 0 0 1,470 000000000000000Hexanol lb/h 0000000000000000000000Toluene lb/h 458 13 445 0 0 0 00000000000000002‐Methylphenol lb/h 00000000000000000000003‐Methyl‐phenol lb/h 0000000000000000000000Guaiacol lb/h 0000000000000000000000Methyl‐Cyclohexane lb/h 860 31 829 0 0 0 00000000000000002‐Methylhexane lb/h 380 88 1,645 1 1 0 1,353 000000000000000VinylPhenol lb/h 0000000000000000000000O‐Xylene lb/h 1,517 16 1,501 0 0 0 0000000000000000Ethylbenzne lb/h 137 2 135 0 0 0 00000000000000002,3‐Dimethyl‐phenol lb/h 00000000000000000000002,6‐dimethoxyphenol lb/h 0000000000000000000000Vanillyl alcohol lb/h 00000000000000000000002,4,6‐Trimethylpyridine lb/h 0000000000000000000000Cis‐1,2‐dimethyl cyclohexane lb/h 2,569 44 2,524 0 0 0 0000000000000000Trans‐1,2‐dimethylcyclohexane lb/h 4,242 86 4,156 0 0 0 0000000000000000Ethylcyclohexane lb/h 391 6 384 0 0 0 00000000000000004‐Methylheptane lb/h 309 7 301 0 0 0 00000000000000002‐Methyl‐Benzofuran lb/h 0000000000000000000000Indane lb/h 00000000000000000000002‐methoxy‐4‐vinylphenol lb/h 0000000000000000000000Syringaldehyde lb/h 0000000000000000000000n‐Propylbenzene lb/h 10 0 10 0 0 0 0000000000000000Naphthalene lb/h 147 0 120 26 26 0 0 0000000000000001‐Naphthalenol lb/h 0000000000000000000000Coniferyl Aldehyde lb/h 0000000000000000000000Tetralin lb/h 61 0 58 3 3 0 0 000000000000000Isoeugenol lb/h 0000000000000000000000Decalin lb/h 159 1 200 9 9 0 50 0000000000000002,5‐Dimethyloctane lb/h 0 1 114 3 3 0 117 0000000000000001‐Methyl naphthalene lb/h 195 0 5 191 191 0 0 0000000000000001‐methyl decahydronaphthene lb/h 298 0 222 76 76 0 0 000000000000000Dibenzothiophene lb/h 0000000000000000000000Biphenyl lb/h 61 0 0 61 61 0 0 0000000000000005‐hexyl‐O‐cresol lb/h 0000000000000000000000n‐Heptylcyclohexane lb/h 4,462 0 22 4,441 4,440 1 1 000000000000000C14H20‐N35 lb/h 934 0 1 933 933 1 0 000000000000000C14H24‐N5 lb/h 3,310 0 1 3,316 3,309 7 7 0000000000000003,5‐Dimethyldodecane lb/h 1,312 0 65 4,632 4,632 0 3,385 000000000000000C15H26‐N4 lb/h 3,179 0 2 3,180 3,177 3 3 0000000000000006,8‐Dimethyltridecane lb/h 0 0 0 2,947 2,946 0 2,947 0000000000000001,4‐Dimethyl‐Phenanthrene lb/h 427 0 0 547 34 512 120 000000000000000N‐Cetane lb/h 0 0 0 163 162 0 163 000000000000000C18H26O lb/h 0000000000000000000000C18H28 lb/h 4,656 0 0 11,547 4,656 6,890 6,890 000000000000000C21H26O2 lb/h 1,026 0 0 1,026 0 1,026 0000000000000000C21H34 lb/h 7,754 0 0 7,754 78 7,677 0000000000000000C22H28O2 lb/h 536 0 0 536 0 536 0000000000000000Carbon lb/h 0000000000000000000000Sulfur lb/h 0000000000000000000000Sand/Catalyst Solids lb/h 0000000000000000000000Ash lb/h 0000000000000000000000Wood lb/h 0000000000000000000000Char lb/h 0000000000000000000000Coke lb/h 0000000000000000000000

175
S-460

RECYCLE GAS PURGE

TO M-575

PFD-61712-A503

HEAVY KEY

FROM D-451

PFD-61712-A402

P-460 QX-H460

QC-H495

S-461

K-492

QA-H463

QC-H463

475

OFFGAS

TO K-511/H-BP-9

PFD-61712-A501

MAKEUP HYDROGEN

FROM M-385/M-575

PFD-61712-A504

AQUEOUS PHASE

TO M-805

PFD-61712-A804

HC ORGANIC PHASE

TO H-BP-6

PFD-61712-A404

QC-H494

H-460

Project No: Drawing:

30482.00 PFD-61712-A403

THERMOCHEMICAL CONVERSION OF BIOMASS

TO HYDROCARBON FUEL

FAST PYROLYSIS AND VAPOR PHASE UPGRADING

PROCESS FLOW DIAGRAM

AREA 400: HYDROCRACKING

Rev. Date By Description

485

482

493

494C

J:\1A - Process Solutions\30482 NREL Thermochemical Conv - Design-Model\Drawings\ 30482 Pyrolysis Ex-Situ PFDs 61712 150128.vsd Plot date: 1/29/2015

464

493A

465 467

468

494B

469

472

474

R-460

W-K462

481

479

460

461

W-P460 QF-H461

W-K492

470

471

S-460

VAPOR

KO DRUM

P-460

HC FEED

PUMP

H-494

QUENCH HYDROGEN

STAGE 2 COOLER

H-495

QUENCH HYDROGEN

STAGE 3 COOLER

H-460

FEED-EFFLUENT

EXCH

H-461

FEED

FURNACE

R-460

HYDROCRACKER

H-463A

HC PRODUCT

ACHE

H-463C

HC PRODUCT

COOLER

K-462

HYDROGEN MAKEUP

COMPRESSOR

S-461

HP EFFLUENT

FLASH: 3 PHASE

K-492

HYDROGEN RECYCLE

COMPRESSOR

H-461

QA-K462

H-463A

0 9/29/14 JAR ISSUED FOR DESIGN REPORT

OFFGAS

TO K-511/H-BP-9

PFD-61712-A501

S-462

478

S-462

LP EFFLUENT

FLASH

K-462

Rev:

2

CWS

CWR

H-494

CWS

CWR

H-463C

CWS

CWR

H-495

HC EFFLUENT

TO H-AP-43/H-AP-57

PFD-61712-A404

HC EFFLUENT

FROM H-BP-6/H-BP-46

PFD-61712-A404

1 12/12/14 DMS ADDED HX NETWORK

1

1 NOTE: FUEL GAS AND COMBUSTION DUTY ASSOCIATED WITH H-461 ACCOUNTED FOR BY QF-H548 ON PFD-61712-A501-A

2 12/29/14 JAR MINOR UPDATES

176
PFD‐61712‐A403 460 461 464 465 467 468 469 470 471 472 474 475 478 479 481 482 485 493 493A 494B 494C 494C 

Total Flow lb/h 16,654 0 16,654 18,293 18,293 21,473 21,473 21,473 21,473 4,353 129 16,992 356 16,636 298 4,055 764 4,819 1,639 1,590 1,590 1,590 Temperature F 713 0 739 605 738 787 717 175 110 110 110 110 110 110 110 110 110 130 130 110 110 110 Pressure Psia 20 20 2000 2000 1945 1915 1910 1905 1895 1893 1893 1893 53 53 1893 1893 245 2000 2000 1995 1995 1995 Vapor Fraction 0 0 0 1111111 0 0 1 0 11111111 Enthalpy Flow MMBtu/h ‐2 0 ‐1 ‐3 ‐1 ‐4 ‐6 ‐17 ‐18 ‐5 ‐1 ‐12 ‐1 ‐11 0 ‐5 0 ‐5 ‐2 ‐2 ‐2 ‐2 Argon lb/h 0000000000000000000000Nitrogen lb/h 0000000000000000000000Oxygen lb/h 0000000000000000000000SO2 lb/h 0000000000000000000000NO2 lb/h 0000000000000000000000Hydrogen lb/h 0 0 0 717 717 1,597 1,597 1,597 1,597 1,569 0 28 27 0 107 1,462 647 2,109 717 696 696 696 Ammonia lb/h 0000000000000000000000H2S lb/h 0000000000000000000000Water lb/h 0 0 0 5 5 195 195 195 195 17 129 49 9 40 1 16 0 16 5 5 5 5 Carbon Monoxide lb/h 0 0 0 164 164 483 483 483 483 470 0 13 13 0 32 438 45 483 164 159 159 159 Carbon Dioxide lb/h 0 0 0 111 111 327 327 327 327 274 0 53 42 10 19 255 71 327 111 108 108 108 Methane lb/h 0 0 0 370 370 1,243 1,243 1,243 1,243 1,167 0 75 70 5 80 1,087 0 1,087 370 359 359 359 Methanol lb/h 0000000000000000000000Formic Acid lb/h 0000000000000000000000Glyoxal lb/h 0000000000000000000000Ethylene lb/h 0 0 0 15 15 56 56 56 56 47 0 9 7 2 3 44 0 44 15 14 14 14 Acetaldehyde lb/h 0000000000000000000000Hydroxyacetaldehyde lb/h 0000000000000000000000Acetic Acid lb/h 0000000000000000000000Ethane lb/h 0 0 0 194 194 774 774 774 774 613 0 161 118 42 42 571 0 571 194 189 189 189 Propylene lb/h 00000000000000000000001‐Hydroxy‐2‐propanone lb/h 0000000000000000000000Propionic Acid lb/h 0000000000000000000000Propane lb/h 0000000000000000000000Furan lb/h 00000000000000000000001‐Butene lb/h 0000000000000000000000Tetrahydrofuran lb/h 0000000000000000000000N‐Butane lb/h 0000000000000000000000Furfural lb/h 00000000000000000000002‐methylfuran lb/h 0000000000000000000000Furfuryl Alcohol lb/h 0000000000000000000000n‐Pentane lb/h 0000000000000000000000Pentenone lb/h 0000000000000000000000Benzene lb/h 0 000000000000000000000Phenol lb/h 0 0000000000000000000001,2‐Benzenediol lb/h 0000000000000000000000Hydroxymethylfurfural lb/h 00000000000000000000002,5‐dimethylfuran lb/h 0000000000000000000000Methyl Cyclopentenone lb/h 0000000000000000000000Hydroxymethylcyclopentenone lb/h 0000000000000000000000Cyclohexanone lb/h 0000000000000000000000Levoglucosan lb/h 00000000000000000000001‐Hexanal lb/h 0000000000000000000000Dimethoxytetrahydrofuran lb/h 0000000000000000000000Cyclohexane lb/h 0 0 0 1 1 32 32 32 32 2 0 30 1 29 0 2 0 21111 N‐Hexane lb/h 0 0 0 41 41 1,644 1,644 1,644 1,644 128 0 1,516 46 1,470 9 119 0 119 41 39 39 39 Hexanol lb/h 0000000000000000000000Toluene lb/h 0 0000000000000000000002‐Methylphenol lb/h 00000000000000000000003‐Methyl‐phenol lb/h 0000000000000000000000Guaiacol lb/h 0000000000000000000000Methyl‐Cyclohexane lb/h 0 0000000000000000000002‐Methylhexane lb/h 0 0 0 20 20 1,437 1,437 1,437 1,437 63 0 1,374 21 1,353 4 59 0 59 20 19 19 19 VinylPhenol lb/h 0000000000000000000000O‐Xylene lb/h 0 000000000000000000000Ethylbenzne lb/h 0 0000000000000000000002,3‐Dimethyl‐phenol lb/h 00000000000000000000002,6‐dimethoxyphenol lb/h 0000000000000000000000Vanillyl alcohol lb/h 00000000000000000000002,4,6‐Trimethylpyridine lb/h 0000000000000000000000Cis‐1,2‐dimethyl cyclohexane lb/h 0 000000000000000000000Trans‐1,2‐dimethylcyclohexane lb/h 0 000000000000000000000Ethylcyclohexane lb/h 0 0000000000000000000004‐Methylheptane lb/h 0 0000000000000000000002‐Methyl‐Benzofuran lb/h 0000000000000000000000Indane lb/h 00000000000000000000002‐methoxy‐4‐vinylphenol lb/h 0000000000000000000000Syringaldehyde lb/h 0000000000000000000000n‐Propylbenzene lb/h 0 000000000000000000000Naphthalene lb/h 0 0 00000000000000 0 00000 1‐Naphthalenol lb/h 0000000000000000000000Coniferyl Aldehyde lb/h 0000000000000000000000Tetralin lb/h 0 0 00000000000000 0 00000 Isoeugenol lb/h 0000000000000000000000Decalin lb/h 0 0 0 0 0 50 50 50 50 0 0 50 0 50 0 0 0 00000 2,5‐Dimethyloctane lb/h 0 0 0 0 0 118 118 118 118 1 0 117 0 117 0 1 0 10000 1‐Methyl naphthalene lb/h 0 0 00000000000000 0 00000 1‐methyl decahydronaphthene lb/h 0 0 00000000000000 0 00000 Dibenzothiophene lb/h 0000000000000000000000Biphenyl lb/h 0 0 00000000000000 0 00000 5‐hexyl‐O‐cresol lb/h 0000000000000000000000n‐Heptylcyclohexane lb/h 1 0 11111110010100 0 00000 C14H20‐N35 lb/h 1 0 11100000000000 0 00000 C14H24‐N5 lb/h 7 0 77777770070700 0 00000 3,5‐Dimethyldodecane lb/h 0 0 0 1 1 3,387 3,387 3,387 3,387 1 0 3,386 0 3,385 0 1 0 10000 C15H26‐N4 lb/h 3 0 33333330030300 0 00000 6,8‐Dimethyltridecane lb/h 0 0 0 1 1 2,948 2,948 2,948 2,948 1 0 2,947 0 2,947 0 1 0 10000 1,4‐Dimethyl‐Phenanthrene lb/h 512 0 512 512 512 120 120 120 120 0 0 120 0 120 0 0 0 00000 N‐Cetane lb/h 0 0 0 0 0 163 163 163 163 0 0 163 0 163 0 0 0 00000 C18H26O lb/h 0000000000000000000000C18H28 lb/h 6,890 0 6,890 6,890 6,890 6,890 6,890 6,890 6,890 0 0 6,890 0 6,890 0 0 0 00000 C21H26O2 lb/h 1,026 0 1,026 1,026 1,026 00000000000000000C21H34 lb/h 7,677 0 7,677 7,677 7,677 00000000000000000C22H28O2 lb/h 536 0 536 536 536 00000000000000000Carbon lb/h 0000000000000000000000Sulfur lb/h 0000000000000000000000Sand/Catalyst Solids lb/h 0000000000000000000000Ash lb/h 0000000000000000000000Wood lb/h 0000000000000000000000Char lb/h 0000000000000000000000Coke lb/h 0000000000000000000000

177
Rev:

0

Project No: Drawing:

30482.00 PFD-61712-A404

THERMOCHEMICAL CONVERSION OF BIOMASS

TO HYDROCARBON FUEL

FAST PYROLYSIS AND VAPOR PHASE UPGRADING

PROCESS FLOW DIAGRAM

AREA 400: A400 HEAT RECOVERY

Rev. Date By Description

0

J:\1A - Process Solutions\30482 NREL Thermochemical Conv - Design-Model\Drawings\ 30482 Pyrolysis Ex-Situ PFDs 61712 150128.vsd Plot date: 1/29/2015

HC EFFLUENT

FROM H-460

PFD-61712-A403

469

H-AP-57

HYDROTREATER

OUTLET COOLER/STEAM

PRODUCTION FROM WW

FOR REFORMER

DIESEL PRODUCT

FROM P-451

PFD-61712-A402

456B

12/12/14 DMS ADDED HX NETWORK

H-AP-43

HYDROTREATER

OUTLET COOLER/HC

PRODUCT TO NAPHTHA

COLUMN PREHEAT

H-AP-25

DISTILLATE

PRODUCT COOLER/

WW PREHEAT FOR

STEAM PRODUCTION

H-AP-16

DISTILLATE PRODUCT

COOLER/HC PRODUCT

TO NAPHTHA COLUMN

PREHEAT

H-AP-12

HYDROTREATER

OUTLET COOLER/HT

PRODUCT TO NAPHTHA

COLUMN PREHEAT

H-AP-24

HYDROTREATER

OUTLET COOLER/WW

PREHEAT FOR STEAM

PRODUCTION

H-BP-5

HYDROTREATER

OUTLET COOLER/HT

PRODUCT TO NAPHTHA

COLUMN PREHEAT

H-BP-6

HYDROCRACKER

OUTLET COOLER/HC

PRODUCT TO NAPHTHA

COLUMN PREHEAT

H-BP-30

DISTILLATE PRODUCT

COOLER/HT PRODUCT

TO NAPHTHA COLUMN

PREHEAT

H-BP-47

HYDROTREATER OUTLET

COOLER/RECYCLED

BOILER FEEDWATER

PREHEAT

H-BP-48

HYDROTREATER OUTLET

COOLER/CATALYST

STRIPPER WATER

PREHEAT FOR STEAM

H-BP-49

HYDROTREATER

OUTLET COOLER/WATER

PREHEAT FOR MIX WITH

WW FOR STEAM

H-AP-57

H-AP-43

CONC WASTEWATER

FROM P-814

PFD-61712-A805

CONC WASTEWATER

TO T-822

PFD-61712-A805

QHAP57

QHAP43

HC EFFLUENT

TO H-AP-41

PFD-61712-A605

HC EFFLUENT

FROM H-AP-34

PFD-61712-A605

H-BP-6

QHBP6

HC EFFLUENT

TO H-463A

PFD-61712-A403

H-AP-16

QHAP16

HC ORGANIC PHASE

TO D-450

PFD-61712-A402

480

470

HC ORGANIC PHASE

FROM S-462

PFD-61712-A403

479

H-AP-25

DIESEL PRODUCT

TO H-BP-29

PFD-61712-A604

DIESEL PRODUCT

FROM H-BP-29

PFD-61712-A604 H-BP-30

QHAP25 QHBP30

DIESEL PRODUCT

TO H-457A

PFD-61712-A402

456C

HT ORGANIC PHASE

FROM S-412

PFD-61712-A401

429

HC EFFLUENT

TO H-BP-24

PFD-61712-A604

HC EFFLUENT

FROM H-BP-46

PFD-61712-A601

WASTEWATER

FROM H-BP-26/H-BP-33

PFD-61712-A805

WASTEWATER

TO H-AP-59/61/62

PFD-61712-A805

H-AP-12 H-BP-5

HT EFFLUENT

TO H-413A

PFD-61712-A401

HT EFFLUENT 420

FROM H-410

PFD-61712-A401

419

QHAP12 QHBP5

H-AP-24

QHAP24

HT EFFLUENT

TO H-BP-23

PFD-61712-A604

HT EFFLUENT

FROM H-BP-18

PFD-61712-A604

WASTEWATER

FROM H-BP-26/H-BP-33

PFD-61712-A805

WASTEWATER

TO TO H-AP-59/61/62

PFD-61712-A805

H-BP-47

QHBP47

MAKEUP WATER

FROM P-601

PFD-61712-A601

MAKEUP WATER

TO H-BP-32/H-BP-40

PFD-61712-A601

H-BP-48

QHBP48

CLEAN WATER

FROM P-866

PFD-61712-A804

CLEAN WATER

TO H-BP-39/H-BP-41

PFD-61712-A804

H-BP-49

MAKEUP WATER

FROM P-815

PFD-61712-A801 QHBP49

MAKEUP WATER

TO H-BP-42/H-BP-43

PFD-61712-A801

HT ORGANIC PHASE

TO H-AP-13

PFD-61712-A402

178
PFD‐61712‐A404 419 420 429 456B 456C 469 470 479 480 

Total Flow lb/h 67,579 67,579 46,446 24,739 24,739 21,473 21,473 16,636 16,636 0000000000000Temperature F 415 175 110 491 175 717 175 110 550 0000000000000Pressure Psia 1510 1505 53 35 25 1910 1905 53 43 0000000000000Vapor Fraction 1 1 000 1 1 0 1 0000000000000Enthalpy Flow MMBtu/h ‐49 ‐65 ‐28 ‐11 ‐15 ‐6 ‐17 ‐11 ‐6 0000000000000Argon lb/h 0000000000000000000000Nitrogen lb/h 0000000000000000000000Oxygen lb/h 0000000000000000000000SO2 lb/h 0000000000000000000000NO2 lb/h 0000000000000000000000Hydrogen lb/h 6,209 6,209 1 0 0 1,597 1,597 0 0 0000000000000Ammonia lb/h 66 66 5 0000000000000000000H2S lb/h 42 42 5 0000000000000000000Water lb/h 3,151 3,151 183 0 0 195 195 40 40 0000000000000Carbon Monoxide lb/h 3,555 3,555 2 0 0 483 483 0 0 0000000000000Carbon Dioxide lb/h 1,713 1,713 53 0 0 327 327 10 10 0000000000000Methane lb/h 3,485 3,485 12 0 0 1,243 1,243 5 5 0000000000000Methanol lb/h 0000000000000000000000Formic Acid lb/h 0000000000000000000000Glyoxal lb/h 0000000000000000000000Ethylene lb/h 137 137 4 0 0 56 56 2 2 0000000000000Acetaldehyde lb/h 0000000000000000000000Hydroxyacetaldehyde lb/h 0000000000000000000000Acetic Acid lb/h 0000000000000000000000Ethane lb/h 1,553 1,553 80 0 0 774 774 42 42 0000000000000Propylene lb/h 551 00000000000000000001‐Hydroxy‐2‐propanone lb/h 0000000000000000000000Propionic Acid lb/h 0000000000000000000000Propane lb/h 123 123 26 0000000000000000000Furan lb/h 00000000000000000000001‐Butene lb/h 12 12 6 0000000000000000000Tetrahydrofuran lb/h 0000000000000000000000N‐Butane lb/h 1,000 1,000 469 0000000000000000000Furfural lb/h 00000000000000000000002‐methylfuran lb/h 0000000000000000000000Furfuryl Alcohol lb/h 0000000000000000000000n‐Pentane lb/h 522 522 391 0000000000000000000Pentenone lb/h 0000000000000000000000Benzene lb/h 1,548 1,548 1,418 0 0 00000000000000000Phenol lb/h 18 18 18 0 0 000000000000000001,2‐Benzenediol lb/h 0000000000000000000000Hydroxymethylfurfural lb/h 00000000000000000000002,5‐dimethylfuran lb/h 000 0000000000000000000Methyl Cyclopentenone lb/h 0000000000000000000000Hydroxymethylcyclopentenone lb/h 0000000000000000000000Cyclohexanone lb/h 0000000000000000000000Levoglucosan lb/h 00000000000000000000001‐Hexanal lb/h 0000000000000000000000Dimethoxytetrahydrofuran lb/h 0000000000000000000000Cyclohexane lb/h 4,040 4,040 3,726 0 0 32 32 29 29 0000000000000N‐Hexane lb/h 734 734 653 0 0 1,644 1,644 1,470 1,470 0000000000000Hexanol lb/h 0000000000000000000000Toluene lb/h 477 477 458 0 0 000000000000000002‐Methylphenol lb/h 00000000000000000000003‐Methyl‐phenol lb/h 0000000000000000000000Guaiacol lb/h 0000000000000000000000Methyl‐Cyclohexane lb/h 898 898 860 0 0 000000000000000002‐Methylhexane lb/h 405 405 380 1 1 1,437 1,437 1,353 1,353 0000000000000VinylPhenol lb/h 0000000000000000000000O‐Xylene lb/h 1,533 1,533 1,517 0 0 00000000000000000Ethylbenzne lb/h 139 139 137 0 0 000000000000000002,3‐Dimethyl‐phenol lb/h 00000000000000000000002,6‐dimethoxyphenol lb/h 0000000000000000000000Vanillyl alcohol lb/h 00000000000000000000002,4,6‐Trimethylpyridine lb/h 0000000000000000000000Cis‐1,2‐dimethyl cyclohexane lb/h 2,620 2,620 2,569 0 0 00000000000000000Trans‐1,2‐dimethylcyclohexane lb/h 4,343 4,343 4,242 0 0 00000000000000000Ethylcyclohexane lb/h 398 398 391 0 0 000000000000000004‐Methylheptane lb/h 317 317 309 0 0 000000000000000002‐Methyl‐Benzofuran lb/h 0000000000000000000000Indane lb/h 00000000000000000000002‐methoxy‐4‐vinylphenol lb/h 0000000000000000000000Syringaldehyde lb/h 0000000000000000000000n‐Propylbenzene lb/h 10 10 10 0 0 00000000000000000Naphthalene lb/h 147 147 147 26 26 0 0 0 0 00000000000001‐Naphthalenol lb/h 0000000000000000000000Coniferyl Aldehyde lb/h 0000000000000000000000Tetralin lb/h 61 61 61 3 3 0 0 0 0 0000000000000Isoeugenol lb/h 0000000000000000000000Decalin lb/h 160 160 159 9 9 50 50 50 50 00000000000002,5‐Dimethyloctane lb/h 000 3 3 118 118 117 117 00000000000001‐Methyl naphthalene lb/h 196 196 195 191 191 0 0 0 0 00000000000001‐methyl decahydronaphthene lb/h 299 299 298 76 76 0 0 0 0 0000000000000Dibenzothiophene lb/h 0000000000000000000000Biphenyl lb/h 61 61 61 61 61 0 0 0 0 00000000000005‐hexyl‐O‐cresol lb/h 0000000000000000000000n‐Heptylcyclohexane lb/h 4,463 4,463 4,462 4,440 4,440 1111 0000000000000C14H20‐N35 lb/h 934 934 934 933 933 0 0 0 0 0000000000000C14H24‐N5 lb/h 3,311 3,311 3,310 3,309 3,309 7777 00000000000003,5‐Dimethyldodecane lb/h 1,312 1,312 1,312 4,632 4,632 3,387 3,387 3,385 3,385 0000000000000C15H26‐N4 lb/h 3,179 3,179 3,179 3,177 3,177 3333 00000000000006,8‐Dimethyltridecane lb/h 000 2,946 2,946 2,948 2,948 2,947 2,947 00000000000001,4‐Dimethyl‐Phenanthrene lb/h 427 427 427 34 34 120 120 120 120 0000000000000N‐Cetane lb/h 000 162 162 163 163 163 163 0000000000000C18H26O lb/h 0000000000000000000000C18H28 lb/h 4,656 4,656 4,656 4,656 4,656 6,890 6,890 6,890 6,890 0000000000000C21H26O2 lb/h 1,026 1,026 1,026 0 0 00000000000000000C21H34 lb/h 7,754 7,754 7,754 78 78 00000000000000000C22H28O2 lb/h 536 536 536 0 0 00000000000000000Carbon lb/h 0000000000000000000000Sulfur lb/h 0000000000000000000000Sand/Catalyst Solids lb/h 0000000000000000000000Ash lb/h 0000000000000000000000Wood lb/h 0000000000000000000000Char lb/h 0000000000000000000000Coke lb/h 0000000000000000000000

179
NATURAL GAS

FROM UTILITY

PSA OFFGAS

FROM M-385

PFD-61712-A304

H-BP-37

QHBP37

Rev:

1

Project No: Drawing:

30482.00 PFD-61712-A501

THERMOCHEMICAL CONVERSION OF BIOMASS

TO HYDROCARBON FUEL

FAST PYROLYSIS AND VAPOR PHASE UPGRADING

PROCESS FLOW DIAGRAM

AREA 500: REFORMER

Rev. Date By Description

J:\1A - Process Solutions\30482 NREL Thermochemical Conv - Design-Model\Drawings\ 30482 Pyrolysis Ex-Situ PFDs 61712 150128.vsd Plot date: 1/29/2015

516

522

515

502 521

389

519

512

PURGE GAS

FROM H-315

PFD-61712-A302

345

389B

LP STEAM

FROM H-AP-44

PFD-61712-A502

HYDROPR PURGE

FROM H-459

PFD-61712-A402

PSA OFFGAS

FROM M-575

PFD-61712-A503

589

452 541

536

H-BP-37

BOILER FEEDWATER

BLOWDOWN COOLER/NATURAL

GAS TO REFORMER PREHEAT

K-511

PYROLYSIS OFFGAS

COMPRESSOR TO REFORMER

OFFGAS

FROM S-410

PFD-61712-A401

OFFGAS

FROM S-460

PFD-61712-A403

461

411

591

593

0 9/29/14 JAR ISSUED FOR DESIGN REPORT

526

OFFGAS

FROM S-412

PFD-61712-A401

OFFGAS

FROM S-462

PFD-61712-A403

428

478

W-K511

K-511

1 12/12/14 DMS ADDED HX NETWORK

BLOWDOWN

FROM H-AP-10/11/35

PFD-61712-A603

BLOWDOWN

TO H-BP-32

PFD-61712-A603

H-AP-21

QHAP21

LTS EFFLUENT

FROM R-566

PFD-61712-A505

LTS EFFLUENT

TO H-AP-19/H-AP-20

PFD-61712-A505

REFORMER COMB GAS

TO H-BP-9

PFD-61712-A505

REFORMER COMB GAS

FROM H-AP-22

PFD-61712-A505

PSA OFFGAS

TO H-BP-7

PFD-61712-A505

PSA OFFGAS

FROM H-AP-19

PFD-61712-A505

REFORMER FEED GAS

TO H-AP-7

PFD-61712-A501-A

REFORMER COMB GAS

TO R-530

PFD-61712-A501-A

592

REFORMER FEED GAS

TO H-AP-30

PFD-61712-A501-A

REFORMER FEED GAS

TO H-AP-30

PFD-61712-A501-A

H-AP-21

A500 LOW TEMP WGS

COOLER/NATURAL GAS

TO REFORMER PREHEAT

180
PFD‐61712‐A501 345 389 389B 411 428 452 461 478 502 512 515 516 519 526 536 541 589 591 592 593 

Total Flow lb/h 1,824 54,620 57,669 0 787 1,281 0 356 125 56,467 56,467 1,203 125 46,210 102,802 84,672 82,271 82,189 82,189 82 00Temperature F 95 110 109 0 110 110 0 110 60 109 500 500 60 556 526 438 109 109 450 109 00Pressure Psia 95 22 22 113 53 33 20 53 200 22 118 20 200 130 118 20 22 22 20 22 00Vapor Fraction 111 0 1 1 0 1111111111111 00Enthalpy Flow MMBtu/h ‐3 ‐158 ‐163 0 ‐1 ‐1 0 ‐1 0 ‐160 ‐152 ‐3 0 ‐254 ‐405 ‐294 ‐298 ‐298 ‐290 0 00Argon lb/h 0000000000000000000000Nitrogen lb/h 0 0 0 00000 20002 0 255550 00Oxygen lb/h 0000000000000000000000SO2 lb/h 0 0 0 000000 000 0 0 000000 00NO2 lb/h 0000000000000000000000Hydrogen lb/h 213 1,135 1,432 0 56 2 0 27 0 1,402 1,402 30 0 0 1,402 1,534 1,504 1,503 1,503 2 00Ammonia lb/h 0 0 4 0 4 3 000 440 0 0 463330 00H2S lb/h 0 0 5 0 5 3 000 550 0 0 5 12 9 9 9 0 00Water lb/h 5 514 546 0 18 55 0 9 0 535 535 11 0 45,491 46,027 508 442 441 441 0 00Carbon Monoxide lb/h 662 3,348 4,078 0 51 2 0 13 0 3,993 3,993 85 0 0 3,993 4,539 4,457 4,452 4,452 4 00Carbon Dioxide lb/h 553 38,522 39,331 0 139 53 0 42 1 38,511 38,511 820 1 0 38,512 75,367 74,569 74,494 74,494 75 00Methane lb/h 83 2,354 2,624 0 115 15 0 70 109 2,569 2,569 55 109 0 2,679 966 897 896 896 1 00Methanol lb/h 0 0 0 000000 000 0 0 000000 00Formic Acid lb/h 0 0 0 000000 000 0 0 000000 00Glyoxal lb/h 0 0 0 000000 000 0 0 000000 00Ethylene lb/h 167 4,714 4,899 0 11 5 0 7 0 4,797 4,797 102 0 0 4,797 125 18 18 18 0 00Acetaldehyde lb/h 0 0 0 000000 000 0 0 000000 00Hydroxyacetaldehyde lb/h 0000000000000000000000Acetic Acid lb/h 0 0 0 000000 000 0 0 000000 00Ethane lb/h 0 0 265 0 147 94 0 118 7 260 260 6 7 0 267 299 199 199 199 0 00Propylene lb/h 56 1,594 1,650 0 1 1 000 1,616 1,616 34 0 0 1,616 35 0000 001‐Hydroxy‐2‐propanone lb/h 0000000000000000000000Propionic Acid lb/h 0 0 0 000000 000 0 0 000000 00Propane lb/h 0 0 14 0 14 15 0 0 3 14 14 0 3 0 17 25 10 10 10 0 00Furan lb/h 7 200 207 000000 203 203 4 0 0 203 4 0000001‐Butene lb/h 28 790 819 0 1 2 000 802 802 17 0 0 802 20 1 1 1 0 00Tetrahydrofuran lb/h 6 169 175 000000 171 171 4 0 0 171 4 000000N‐Butane lb/h 0 0 80 0 80 158 0 0 2 79 79 2 2 0 80 213 53 53 53 0 00Furfural lb/h 00000000000000000000002‐methylfuran lb/h 7 187 193 000000 189 189 4 0 0 189 4 000000Furfuryl Alcohol lb/h 0000000000000000000000n‐Pentane lb/h 0 0 22 0 22 70 000 22 22 0 0 0 22 83 13 13 13 0 00Pentenone lb/h 0000000000000000000000Benzene lb/h 0 0 22 0 22 96 000 22 22 0 0 0 22 110 13 13 13 0 00Phenol lb/h 0 31 31 0 0 0 000 30 30 1 0 31 61 1 0 0 0 0 001,2‐Benzenediol lb/h 000 000000 000 0 686 686 0 000000Hydroxymethylfurfural lb/h 00000000000000000000002,5‐dimethylfuran lb/h 011 0 0 0 000 110 0 0100000 00Methyl Cyclopentenone lb/h 0000000000000000000000Hydroxymethylcyclopentenone lb/h 0000000000000000000000Cyclohexanone lb/h 0000000000000000000000Levoglucosan lb/h 00000000000000000000001‐Hexanal lb/h 0000000000000000000000Dimethoxytetrahydrofuran lb/h 000 000000 000 0 0 0 0 000000Cyclohexane lb/h 24 670 745 0 51 230 0 1 0 729 729 16 0 0 729 276 31 31 31 0 00N‐Hexane lb/h 0 0 59 0 12 180 0 46 0 58 58 1 0 0 58 198 17 17 17 0 00Hexanol lb/h 0000000000000000000000Toluene lb/h 0 0 2 0 2 13 000 220 0 0 2 15 2 2 2 0 002‐Methylphenol lb/h 000 000000 000 0 000 0000003‐Methyl‐phenol lb/h 0000000000000000000000Guaiacol lb/h 000 000000 000 0 000 000000Methyl‐Cyclohexane lb/h 3 76 85 0 6 31 000 83 83 2 0 0 83 36 4 4 4 0 002‐Methylhexane lb/h 0 0 24 0 4 88 0 21 0 24 24 1 0 0 24 95 7 7 7 0 00VinylPhenol lb/h 000 000000 000 0 000 000000O‐Xylene lb/h 0 0 2 0 2 16 000 220 0 0 2 18 2 2 2 0 00Ethylbenzne lb/h 0 0 0 0 0 2 000 000 0 0 020000 002,3‐Dimethyl‐phenol lb/h 022 000000 220 0 020 0000002,6‐dimethoxyphenol lb/h 000 000000 000 0 000 000000Vanillyl alcohol lb/h 000 000000 000 0 220 0000002,4,6‐Trimethylpyridine lb/h 011 000000 110 0 0 1 0 000000Cis‐1,2‐dimethyl cyclohexane lb/h 4 118 129 0 7 44 000 126 126 3 0 0 126 52 5 5 5 0 00Trans‐1,2‐dimethylcyclohexane lb/h 7 194 214 0 14 86 000 210 210 4 0 0 210 101 10 10 10 0 00Ethylcyclohexane lb/h 0 0 1 0 1 6 000 110 0 0 171110 004‐Methylheptane lb/h 0 0 1 0 1 7 000 110 0 0 181110 002‐Methyl‐Benzofuran lb/h 000 000000 000 0 000 000000Indane lb/h 00000000000000000000002‐methoxy‐4‐vinylphenol lb/h 000 000000 000 0 000 000000Syringaldehyde lb/h 0000000000000000000000n‐Propylbenzene lb/h 0 0 0 0 0 0 000 000 0 0 000000 00Naphthalene lb/h 0 0 0 0 0 0 0 0 0 000 0 0 000000 001‐Naphthalenol lb/h 000 000000 000 0 000 000000Coniferyl Aldehyde lb/h 000 000000 000 0 000 000000Tetralin lb/h 0 0 0 0 0 0 0 0 0 000 0 0 000000 00Isoeugenol lb/h 000 000000 000 0 000 000000Decalin lb/h 000 0 0 1 0 0 0 000 0 0 010000 002,5‐Dimethyloctane lb/h 0 0 0 0 0 1 0 0 0 000 0 0 010000 001‐Methyl naphthalene lb/h 000 0 0 0 0 0 0 000 0 0000000 001‐methyl decahydronaphthene lb/h 000 0 0 0 0 0 0 000 0 0 000000 00Dibenzothiophene lb/h 000 000000 000 0 000 000000Biphenyl lb/h 0 0 0 0 0 0 0 0 0 000 0 0 000000 005‐hexyl‐O‐cresol lb/h 000 000000 000 0 0 0 0 000000n‐Heptylcyclohexane lb/h 0 0 0 0 0 0 0 0 0 000 0 0 000000 00C14H20‐N35 lb/h 0 0 0 0 0 0 0 0 0 000 0 0 000000 00C14H24‐N5 lb/h 000 0 0 0 0 0 0 000 0 0 000000 003,5‐Dimethyldodecane lb/h 0 0 0 0 0 0 0 0 0 000 0 0 000000 00C15H26‐N4 lb/h 000 0 0 0 0 0 0 000 0 0 000000 006,8‐Dimethyltridecane lb/h 0 0 0 0 0 0 0 0 0 000 0 0 000000 001,4‐Dimethyl‐Phenanthrene lb/h 0 0 0 0 0 0 0 0 0 000 0 0 000000 00N‐Cetane lb/h 0 0 0 0 0 0 0 0 0 000 0 0 000000 00C18H26O lb/h 000 000000 000 0 0 0 0 000000C18H28 lb/h 0 0 0 0 0 0 0 0 0 000 0 0 000000 00C21H26O2 lb/h 000 0 0 0 000 000 0 0 000000 00C21H34 lb/h 000 0 0 0 000 000 0 0 000000 00C22H28O2 lb/h 000 0 0 0 000 000 0 0 000000 00Carbon lb/h 0000000000000000000000Sulfur lb/h 0000000000000000000000Sand/Catalyst Solids lb/h 0000000000000000000000Ash lb/h 0000000000000000000000Wood lb/h 0000000000000000000000Char lb/h 0000000000000000000000Coke lb/h 0000000000000000000000

181
Rev: Project No: Drawing:

30482.00

THERMOCHEMICAL CONVERSION OF BIOMASS

TO HYDROCARBON FUEL

FAST PYROLYSIS AND VAPOR PHASE UPGRADING

PROCESS FLOW DIAGRAM

AREA 500: REFORMER

Rev. Date By Description

J:\1A - Process Solutions\30482 NREL Thermochemical Conv - Design-Model\Drawings\ 30482 Pyrolysis Ex-Situ PFDs 61712 150128.vsd Plot date: 1/29/2015

0 12/12/14 DMS ADDED HX NETWORK 1

QHAP7

H-AP-7

QHAP26

H-AP-26

QHAP27

H-AP-27

R-530

QHAP28

H-AP-28

QHAP29

H-AP-29

QHAP30

H-AP-30

QHAP54

H-AP-54

QHAP42

H-AP-42

QHAP36

H-AP-36 QHBP2

H-BP-2

PFD-61712-A501-A

549 FLUE GAS

TO M-104

PFD-61712-A102

REFORMER PRODUCT

TO R-565/H-AP-47/50

PFD-61712-A502

540

COMBUSTION AIR

542

W-K545

543

K-545

COMBUSTION AIR

TO H-AP-20

PFD-61712-A505

COMBUSTION AIR

TO H-BP-12

PFD-61712-A505

537

K-545

REFORMER

COMBUSTOR AIR

BLOWER

R-530

STEAM REFORMER

PACKAGE

REFORMER FEED GAS

FROM

PFD-61712-A501

536

REFORMER FEED GAS

FROM K-511

PFD-61712-A501

REFORMER FEED GAS

TO R-530

PFD-61712-A501

514

515

H-AP-7

REFORMER FLUE

GAS COOLER/

REFORMER FEED

HIGH TEMP PREHEAT

H-AP-26

REFORMER FLUE

GAS COOLER/

INTER-TURBINE

STEAM REHEAT

H-AP-27

REFORMER FLUE GAS

COOLER/DISTILLATE

COLUMN REBOILER

H-AP-28

REFORMER FLUE GAS

COOLER/NAPHTHA

COLUMN REBOILER

H-AP-29

REFORMER FLUE GAS

COOLER/REFORMER

COMBUSTOR AIR

PREHEAT

H-AP-30

REFORMER FLUE GAS

COOLER/REFORMER

FEED GAS PREHEAT

H-AP-54

REFORMER FLUE GAS

COOLER/BOILER

FEEDWATER PREHEAT

H-AP-42

REFORMER FLUE GAS

COOLER/BOILER

FEEDWATER PREHEAT

H-AP-36

REFORMER FLUE GAS

COOLER/BOILER

FEEDWATER PREHEAT

H-BP-2

REFORMER FLUE GAS

COOLER/REFORMER

COMBUSTOR AIR

PREHEAT

D-450 BOTTOMS

TO D-450

PFD-61712-A402

D-450 BOTTOMS

FROM D-450

PFD-61712-A402

COMBUSTION AIR

FROM H-AP-20

PFD-61712-A505

SATURATED WATER

TO H-AP-40/41/42/55/56

PFD-61712-A605

SATURATED WATER

FROM H-BP-20/21/22

PFD-61712-A605

SATURATED WATER

FROM H-AP-31/33/34/35/36/37

PFD-61712-A605

SATURATED WATER

TO H-AP-51

PFD-61712-A605

SATURATED WATER

FROM H-AP-55/H-AP-56

PFD-61712-A605

SATURATED WATER

TO H-AP-52

PFD-61712-A605

546

REFORMER COMB GAS

FROM H-AP-19/22/H-459

PFD-61712-A501

541

STEAM

FROM M-602

PFD-61712-A602

STEAM

TO M-602

PFD-61712-A602

D-451 BOTTOMS

FROM D-451

PFD-61712-A402

D-451 BOTTOMS

TO D-451

PFD-61712-A402

NOTE: H-548 NOT PHYSICALLY PRESENT IN R-530 FLUE, BUT IS SHOWN TO

ACCOUNT FOR FLUE GASES AND COMBUSTION DUTIES OF H-411 AND H-461 1

QF-H548

H-548

1

1 12/29/14 JAR MINOR UPDATES

182
PFD‐61712‐A501A 514 515 536 537 540 541 542 543 546 549 

Total Flow lb/h 56,467 56,467 102,802 102,802 102,802 84,672 136,272 136,272 136,272 220,944 000000000000Temperature F 467 500 526 1400 1616 438 90 173 600 245 000000000000Pressure Psia 120 118 118 118 115 20 15 21 20 17 000000000000Vapor Fraction 1111111111 000000000000Enthalpy Flow MMBtu/h ‐152 ‐152 ‐405 ‐362 ‐295 ‐294 ‐15 ‐12 2 ‐463 000000000000Argon lb/h 000000 1,721 1,721 1,721 1,721 000000000000Nitrogen lb/h 002255 100,907 100,907 100,907 100,912 000000000000Oxygen lb/h 0000 0 0 30,918 30,918 30,918 6,218 000000000000SO2 lb/h 000000 000 23 000000000000NO2 lb/h 0000 0 0000 17 000000000000Hydrogen lb/h 1,402 1,402 1,402 1,402 4,803 1,534 0000000000000000Ammonia lb/h 444406 0000000000000000H2S lb/h 5 5 5 5 5 12 0000000000000000Water lb/h 535 535 46,027 46,027 33,046 508 2,659 2,659 2,659 21,487 000000000000Carbon Monoxide lb/h 3,993 3,993 3,993 3,993 30,596 4,539 0000000000000000Carbon Dioxide lb/h 38,511 38,511 38,512 38,512 33,927 75,367 67 67 67 90,566 000000000000Methane lb/h 2,569 2,569 2,679 2,679 420 966 0000000000000000Methanol lb/h 000000 0000000000000000Formic Acid lb/h 000000 0000000000000000Glyoxal lb/h 000000 0000000000000000Ethylene lb/h 4,797 4,797 4,797 4,797 0 125 0000000000000000Acetaldehyde lb/h 000000 0000000000000000Hydroxyacetaldehyde lb/h 0000 0 00000000000000000Acetic Acid lb/h 000000 0000000000000000Ethane lb/h 260 260 267 267 0 299 0000000000000000Propylene lb/h 1,616 1,616 1,616 1,616 0 35 00000000000000001‐Hydroxy‐2‐propanone lb/h 0000 0 00000000000000000Propionic Acid lb/h 000000 0000000000000000Propane lb/h 14 14 17 17 0 25 0000000000000000Furan lb/h 203 203 203 203 0 4 00000000000000001‐Butene lb/h 802 802 802 802 0 20 0000000000000000Tetrahydrofuran lb/h 171 171 171 171 0 4 0000000000000000N‐Butane lb/h 79 79 80 80 0 213 0000000000000000Furfural lb/h 0000 0 000000000000000002‐methylfuran lb/h 189 189 189 189 0 4 0000000000000000Furfuryl Alcohol lb/h 0000 0 00000000000000000n‐Pentane lb/h 22 22 22 22 0 83 0000000000000000Pentenone lb/h 0000 0 00000000000000000Benzene lb/h 22 22 22 22 0 110 0000000000000000Phenol lb/h 30 30 61 61 0 1 00000000000000001,2‐Benzenediol lb/h 0 0 686 686 0 0 0000000000000000Hydroxymethylfurfural lb/h 0000 0 000000000000000002,5‐dimethylfuran lb/h 111100 0000000000000000Methyl Cyclopentenone lb/h 0000 0 00000000000000000Hydroxymethylcyclopentenone lb/h 0000 0 00000000000000000Cyclohexanone lb/h 0000 0 00000000000000000Levoglucosan lb/h 00000000000000000000001‐Hexanal lb/h 0000 0 00000000000000000Dimethoxytetrahydrofuran lb/h 0000 0 0 0000000000000000Cyclohexane lb/h 729 729 729 729 0 276 0000000000000000N‐Hexane lb/h 58 58 58 58 0 198 0000000000000000Hexanol lb/h 0000 0 00000000000000000Toluene lb/h 2 2 2 2 0 15 00000000000000002‐Methylphenol lb/h 000000 00000000000000003‐Methyl‐phenol lb/h 0000 0 00000000000000000Guaiacol lb/h 000000 0000000000000000Methyl‐Cyclohexane lb/h 83 83 83 83 0 36 00000000000000002‐Methylhexane lb/h 24 24 24 24 0 95 0000000000000000VinylPhenol lb/h 000000 0000000000000000O‐Xylene lb/h 2 2 2 2 0 18 0000000000000000Ethylbenzne lb/h 000002 00000000000000002,3‐Dimethyl‐phenol lb/h 222200 00000000000000002,6‐dimethoxyphenol lb/h 0000 0 0 0000000000000000Vanillyl alcohol lb/h 0022 0 0 00000000000000002,4,6‐Trimethylpyridine lb/h 111100 0000000000000000Cis‐1,2‐dimethyl cyclohexane lb/h 126 126 126 126 0 52 0000000000000000Trans‐1,2‐dimethylcyclohexane lb/h 210 210 210 210 0 101 0000000000000000Ethylcyclohexane lb/h 111107 00000000000000004‐Methylheptane lb/h 111108 00000000000000002‐Methyl‐Benzofuran lb/h 000000 0000000000000000Indane lb/h 0000 0 000000000000000002‐methoxy‐4‐vinylphenol lb/h 0000 0 0 0000000000000000Syringaldehyde lb/h 0000000000000000000000n‐Propylbenzene lb/h 000000 0000000000000000Naphthalene lb/h 000000 00000000000000001‐Naphthalenol lb/h 000000 0000000000000000Coniferyl Aldehyde lb/h 0000 0 0 0000000000000000Tetralin lb/h 000000 0000000000000000Isoeugenol lb/h 0000 0 0 0000000000000000Decalin lb/h 0000 0 1 00000000000000002,5‐Dimethyloctane lb/h 0000 0 1 00000000000000001‐Methyl naphthalene lb/h 000000 00000000000000001‐methyl decahydronaphthene lb/h 0000 0 0 0000000000000000Dibenzothiophene lb/h 0000 0 0 0000000000000000Biphenyl lb/h 000000 00000000000000005‐hexyl‐O‐cresol lb/h 0000 0 0 0000000000000000n‐Heptylcyclohexane lb/h 0000 0 0 0000000000000000C14H20‐N35 lb/h 0000 0 0 0000000000000000C14H24‐N5 lb/h 0000 0 0 00000000000000003,5‐Dimethyldodecane lb/h 0000 0 0 0000000000000000C15H26‐N4 lb/h 0000 0 0 00000000000000006,8‐Dimethyltridecane lb/h 0000 0 0 00000000000000001,4‐Dimethyl‐Phenanthrene lb/h 0000 0 0 0000000000000000N‐Cetane lb/h 0000 0 0 0000000000000000C18H26O lb/h 0000 0 0 0000000000000000C18H28 lb/h 0000 0 0 0000000000000000C21H26O2 lb/h 0000 0 0 0000000000000000C21H34 lb/h 0000 0 0 0000000000000000C22H28O2 lb/h 0000 0 0 0000000000000000Carbon lb/h 0000000000000000000000Sulfur lb/h 0000000000000000000000Sand/Catalyst Solids lb/h 0000000000000000000000Ash lb/h 0000000000000000000000Wood lb/h 0000000000000000000000Char lb/h 0000000000000000000000Coke lb/h 0000000000000000000000

183
Rev:

1

Project No: Drawing:

30482.00 PFD-61712-A502

THERMOCHEMICAL CONVERSION OF BIOMASS

TO HYDROCARBON FUEL

FAST PYROLYSIS AND VAPOR PHASE UPGRADING

PROCESS FLOW DIAGRAM

AREA 500: WATER GAS SHIFT

Rev. Date By Description

REFORMER PRODUCT

FROM R-530

PFD-61712-A501-A

R-565

QHAP59

H-AP-59

R-566

QHAP44

QA-H568

QC-H568

WGS PRODUCT

TO S-575

PFD-61712-A503

540 566

568 569

572 573 574

R-565

WGS

REACTOR

R-566

LTS REACTOR

H-568A

WGS EFFLUENT

ACHE

H-568C

WGS EFFLUENT

COOLER

J:\1A - Process Solutions\30482 NREL Thermochemical Conv - Design-Model\Drawings\ 30482 Pyrolysis Ex-Situ PFDs 61712 150128.vsd Plot date: 1/29/2015

H-568A

0 9/29/14 JAR ISSUED FOR DESIGN REPORT

CWS

CWR

H-568C

1 12/12/14 DMS ADDED HX NETWORK

REFORMER PRODUCT

TO H-AP-47

PFD-61712-A602

REFORMER PRODUCT

FROM H-AP-47

PFD-61712-A602

REFORMER PRODUCT

TO H-AP-50

PFD-61712-A603

REFORMER PRODUCT

FROM H-AP-50

PFD-61712-A603

REFORMER PRODUCT

TO H-AP-46

PFD-61712-A804

REFORMER PRODUCT

FROM H-AP-45

PFD-61712-A804 H-AP-44

LP STEAM

FROM T-822

PFD-61712-A801

LP STEAM

TO H-AP-7

PFD-61712-A501

526

823

WASTEWATER

FROM H-AP-23/24/25/32

PFD-61712-A805

WASTEWATER

TO T-812

PFD-61712-A805

H-AP-59

A500 HIGH TEMP WGS

OUTLET COOLER/

STEAM PRODUCTION

FROM WW FOR WGS

H-AP-44

REFORMER OUTLET

COOLER/REFORMER

STEAM SUPERHEAT

LTS EFFLUENT

TO H-AP-61/21/22

PFD-61712-A505

LTS EFFLUENT

FROM H-BP-7/H-BP-8

PFD-61712-A505

184
PFD‐61712‐A502 526 540 566 568 569 572 573 574 823 

Total Flow lb/h 46,210 102,802 102,802 102,802 102,802 102,802 102,802 102,802 46,210 0000000000000Temperature F 556 1616 644 835 428 540 185 110 356 0000000000000Pressure Psia 130 115 113 108 106 101 99 97 135 0000000000000Vapor Fraction 111111111 0000000000000Enthalpy Flow MMBtu/h ‐254 ‐295 ‐347 ‐347 ‐368 ‐368 ‐393 ‐405 ‐258 0000000000000Argon lb/h 0000000000000000000000Nitrogen lb/h 0 5555555 00000000000000Oxygen lb/h 0 0 0 0000000000000000000SO2 lb/h 0 0000000 00000000000000NO2 lb/h 0 0 0 0000000000000000000Hydrogen lb/h 0 4,803 4,803 6,011 6,011 6,686 6,686 6,686 0 0000000000000Ammonia lb/h 0 0000000 00000000000000H2S lb/h 0 5555555 00000000000000Water lb/h 45,491 33,046 33,046 22,252 22,252 16,218 16,218 16,218 45,491 0000000000000Carbon Monoxide lb/h 0 30,596 30,596 13,815 13,815 4,433 4,433 4,433 0 0000000000000Carbon Dioxide lb/h 0 33,927 33,927 60,294 60,294 75,035 75,035 75,035 0 0000000000000Methane lb/h 0 420 420 420 420 420 420 420 0 0000000000000Methanol lb/h 0 0000000 00000000000000Formic Acid lb/h 0 0000000 00000000000000Glyoxal lb/h 0 0000000 00000000000000Ethylene lb/h 000000000 0000000000000Acetaldehyde lb/h 0 0000000 00000000000000Hydroxyacetaldehyde lb/h 0 0 0 0000000000000000000Acetic Acid lb/h 0 0000000 00000000000000Ethane lb/h 0 0000000 00000000000000Propylene lb/h 000000000 00000000000001‐Hydroxy‐2‐propanone lb/h 0 0 0 0000000000000000000Propionic Acid lb/h 0 0000000 00000000000000Propane lb/h 0 0000000 00000000000000Furan lb/h 000 00000 0 00000000000001‐Butene lb/h 000 00000 0 0000000000000Tetrahydrofuran lb/h 000 00000 0 0000000000000N‐Butane lb/h 0 0 0 0000000000000000000Furfural lb/h 0 0 0 00000000000000000002‐methylfuran lb/h 000 00000 0 0000000000000Furfuryl Alcohol lb/h 0 0 0 0000000000000000000n‐Pentane lb/h 0 0 0 0000000000000000000Pentenone lb/h 0 0 0 0000000000000000000Benzene lb/h 0 0 0 0000000000000000000Phenol lb/h 31 0 0 00000 31 00000000000001,2‐Benzenediol lb/h 686 0 0 00000 686 0000000000000Hydroxymethylfurfural lb/h 0 0 0 00000000000000000002,5‐dimethylfuran lb/h 000 00000 0 0000000000000Methyl Cyclopentenone lb/h 0 0 0 0000000000000000000Hydroxymethylcyclopentenone lb/h 0 0 0 0000000000000000000Cyclohexanone lb/h 0 0 0 0000000000000000000Levoglucosan lb/h 00000000000000000000001‐Hexanal lb/h 0 0 0 0000000000000000000Dimethoxytetrahydrofuran lb/h 0000000000000000000000Cyclohexane lb/h 000 00000 0 0000000000000N‐Hexane lb/h 0 0 0 0000000000000000000Hexanol lb/h 0 0 0 0000000000000000000Toluene lb/h 0 0 0 00000000000000000002‐Methylphenol lb/h 000 00000 0 00000000000003‐Methyl‐phenol lb/h 0 0 0 0000000000000000000Guaiacol lb/h 000 00000 0 0000000000000Methyl‐Cyclohexane lb/h 000 00000 0 00000000000002‐Methylhexane lb/h 0 0 0 0000000000000000000VinylPhenol lb/h 000 00000 0 0000000000000O‐Xylene lb/h 0 0 0 0000000000000000000Ethylbenzne lb/h 0 0 0 00000000000000000002,3‐Dimethyl‐phenol lb/h 000 00000 0 00000000000002,6‐dimethoxyphenol lb/h 0 0000000 0 0000000000000Vanillyl alcohol lb/h 2 0000000 2 00000000000002,4,6‐Trimethylpyridine lb/h 0 0 0 0000000000000000000Cis‐1,2‐dimethyl cyclohexane lb/h 0 0 0 0000000000000000000Trans‐1,2‐dimethylcyclohexane lb/h 0 0 0 0000000000000000000Ethylcyclohexane lb/h 0 0 0 00000000000000000004‐Methylheptane lb/h 0 0 0 00000000000000000002‐Methyl‐Benzofuran lb/h 000 00000 0 0000000000000Indane lb/h 0 0 0 00000000000000000002‐methoxy‐4‐vinylphenol lb/h 0 0000000 0 0000000000000Syringaldehyde lb/h 0000000000000000000000n‐Propylbenzene lb/h 0 0 0 0000000000000000000Naphthalene lb/h 0 0 0 00000000000000000001‐Naphthalenol lb/h 000 00000 0 0000000000000Coniferyl Aldehyde lb/h 0 0000000 0 0000000000000Tetralin lb/h 0 0 0 0000000000000000000Isoeugenol lb/h 0 0000000 0 0000000000000Decalin lb/h 00000000000000000000002,5‐Dimethyloctane lb/h 00000000000000000000001‐Methyl naphthalene lb/h 000 00000 0 00000000000001‐methyl decahydronaphthene lb/h 0000000000000000000000Dibenzothiophene lb/h 0 0000000 0 0000000000000Biphenyl lb/h 0 0 0 00000000000000000005‐hexyl‐O‐cresol lb/h 0000000000000000000000n‐Heptylcyclohexane lb/h 0000000000000000000000C14H20‐N35 lb/h 0000000000000000000000C14H24‐N5 lb/h 00000000000000000000003,5‐Dimethyldodecane lb/h 0000000000000000000000C15H26‐N4 lb/h 00000000000000000000006,8‐Dimethyltridecane lb/h 00000000000000000000001,4‐Dimethyl‐Phenanthrene lb/h 0000000000000000000000N‐Cetane lb/h 0000000000000000000000C18H26O lb/h 0000000000000000000000C18H28 lb/h 0000000000000000000000C21H26O2 lb/h 0000000000000000000000C21H34 lb/h 0000000000000000000000C22H28O2 lb/h 0000000000000000000000Carbon lb/h 0000000000000000000000Sulfur lb/h 0000000000000000000000Sand/Catalyst Solids lb/h 0000000000000000000000Ash lb/h 0000000000000000000000Wood lb/h 0000000000000000000000Char lb/h 0000000000000000000000Coke lb/h 0000000000000000000000

185
PSA OFFGAS

TO K-511/H-BP-7/9

PFD-61712-A501

S-575

WGS PRODUCT

FROM H-568C

PFD-61712-A502

S-586

CONDENSATE

TO T-860

PFD-61712-A804

HYDROGEN

TO K-211/K-412/K-462

PFD-61712-A504

576

576A

590

589

588

586

574

Rev:

2

Project No: Drawing:

30482.00 PFD-61712-A503

THERMOCHEMICAL CONVERSION OF BIOMASS

TO HYDROCARBON FUEL

FAST PYROLYSIS AND VAPOR PHASE UPGRADING

PROCESS FLOW DIAGRAM

AREA 500: PSA

Rev. Date By Description

582

K-580

W-K580

577

S-586

PSA COMPRESSOR

DISCHARGE KO DRUM

S-575

COMPRESSOR

SUCTION KO DRUM

M-575

PSA

K-580

PSA COMPRESSOR

MULTISTAGE

J:\1A - Process Solutions\30482 NREL Thermochemical Conv - Design-Model\Drawings\ 30482 Pyrolysis Ex-Situ PFDs 61712 150128.vsd Plot date: 1/29/2015

M-575

587

585

RECYCLE GAS PURGE

FROM S-411

PFD-61712-A401

RECYCLE GAS PURGE

FROM S-461

PFD-61712-A403

431

481

P-576

W-P576

T-576

P-576

COMPRESSOR

CONDENSATE PUMP

T-576

COMRPESSOR

CONDENSATE TANK

QC-K580

0 9/29/14 JAR ISSUED FOR DESIGN REPORT

QA-K580

1 12/12/14 DMS ADDED HX NETWORK

CWS

CWR

2 12/29/14 JAR MINOR UPDATES

186
PFD‐61712‐A503 431 481 574 576 576A 577 582 585 586 587 588 589 590 

Total Flow lb/h 2,061 298 102,802 15,788 15,077 87,725 550 87,176 87,014 162 89,373 82,271 7,102 000000000Temperature F 110 110 110 110 110 110 110 110 110 110 109 109 109 000000000Pressure Psia 1493 1893 97 102 97 97 97 278 276 276 276 22 266 000000000Vapor Fraction 111 0 0 1 0 1 1 0 111 000000000Enthalpy Flow MMBtu/h ‐2 0 ‐405 ‐108 ‐103 ‐302 ‐4 ‐299 ‐298 ‐1 ‐301 ‐298 ‐3 000000000Argon lb/h 0000000000000000000000Nitrogen lb/h 0 0 5005055055 0000000000Oxygen lb/h 0000000000000000000000SO2 lb/h 0 0 0000000000 0000000000NO2 lb/h 0000000000000000000000Hydrogen lb/h 727 107 6,686 0 0 6,686 0 6,686 6,686 0 7,520 1,504 6,016 000000000Ammonia lb/h 3 0 0000000033 0000000000H2S lb/h 4 0 5005055099 0000000000Water lb/h 9 1 16,218 15,786 15,075 1,143 550 593 432 162 442 442 0000000000Carbon Monoxide lb/h 414 32 4,433 0 0 4,433 0 4,433 4,433 0 4,879 4,457 422 000000000Carbon Dioxide lb/h 180 19 75,035 1 1 75,033 0 75,033 75,033 0 75,232 74,569 663 000000000Methane lb/h 397 80 420 0 0 420 0 420 420 0 897 897 0000000000Methanol lb/h 0 0 0000000000 0000000000Formic Acid lb/h 0 0 0000000000 0000000000Glyoxal lb/h 0 0 0000000000 0000000000Ethylene lb/h 14 3 0 0 0 0 0 0 0 0 18 18 0000000000Acetaldehyde lb/h 0 0 0000000000 0000000000Hydroxyacetaldehyde lb/h 0000000000000000000000Acetic Acid lb/h 0 0 0000000000 0000000000Ethane lb/h 157 42 0 0 0 0 0 0 0 0 199 199 0000000000Propylene lb/h 0 0 0000000000 00000000001‐Hydroxy‐2‐propanone lb/h 0000000000000000000000Propionic Acid lb/h 0 0 0000000000 0000000000Propane lb/h 10 0 0 0 0 0 0 0 0 0 10 10 0000000000Furan lb/h 00000000000000000000001‐Butene lb/h 1 000000000 1 1 0000000000Tetrahydrofuran lb/h 0000000000000000000000N‐Butane lb/h 53 000000000 53 53 0000000000Furfural lb/h 00000000000000000000002‐methylfuran lb/h 0000000000000000000000Furfuryl Alcohol lb/h 0000000000000000000000n‐Pentane lb/h 13 000000000 13 13 0000000000Pentenone lb/h 0000000000000000000000Benzene lb/h 13 000000000 13 13 0000000000Phenol lb/h 0 000000000 0 0 00000000001,2‐Benzenediol lb/h 0000000000000000000000Hydroxymethylfurfural lb/h 00000000000000000000002,5‐dimethylfuran lb/h 0 000000000 0 0 0000000000Methyl Cyclopentenone lb/h 0000000000000000000000Hydroxymethylcyclopentenone lb/h 0000000000000000000000Cyclohexanone lb/h 0000000000000000000000Levoglucosan lb/h 00000000000000000000001‐Hexanal lb/h 0000000000000000000000Dimethoxytetrahydrofuran lb/h 0000000000000000000000Cyclohexane lb/h 31 0 00000000 31 31 0000000000N‐Hexane lb/h 8 9 00000000 17 17 0000000000Hexanol lb/h 0000000000000000000000Toluene lb/h 2 000000000 2 2 00000000002‐Methylphenol lb/h 00000000000000000000003‐Methyl‐phenol lb/h 0000000000000000000000Guaiacol lb/h 0000000000000000000000Methyl‐Cyclohexane lb/h 4 000000000 4 4 00000000002‐Methylhexane lb/h 2 4 00000000 7 7 0000000000VinylPhenol lb/h 0000000000000000000000O‐Xylene lb/h 2 000000000 2 2 0000000000Ethylbenzne lb/h 0 000000000 0 0 00000000002,3‐Dimethyl‐phenol lb/h 00000000000000000000002,6‐dimethoxyphenol lb/h 0000000000000000000000Vanillyl alcohol lb/h 00000000000000000000002,4,6‐Trimethylpyridine lb/h 0000000000000000000000Cis‐1,2‐dimethyl cyclohexane lb/h 5 000000000 5 5 0000000000Trans‐1,2‐dimethylcyclohexane lb/h 10 000000000 10 10 0000000000Ethylcyclohexane lb/h 1 000000000 1 1 00000000004‐Methylheptane lb/h 1 000000000 1 1 00000000002‐Methyl‐Benzofuran lb/h 0000000000000000000000Indane lb/h 00000000000000000000002‐methoxy‐4‐vinylphenol lb/h 0000000000000000000000Syringaldehyde lb/h 0000000000000000000000n‐Propylbenzene lb/h 0 000000000 0 0 0000000000Naphthalene lb/h 0 0 00000000 0 0 00000000001‐Naphthalenol lb/h 0000000000000000000000Coniferyl Aldehyde lb/h 0000000000000000000000Tetralin lb/h 0 0 00000000 0 0 0000000000Isoeugenol lb/h 0000000000000000000000Decalin lb/h 0 0 00000000 0 0 00000000002,5‐Dimethyloctane lb/h 0 0 00000000 0 0 00000000001‐Methyl naphthalene lb/h 0 0 00000000 0 0 00000000001‐methyl decahydronaphthene lb/h 0 0 00000000 0 0 0000000000Dibenzothiophene lb/h 0000000000000000000000Biphenyl lb/h 0 0 00000000 0 0 00000000005‐hexyl‐O‐cresol lb/h 0000000000000000000000n‐Heptylcyclohexane lb/h 0 0 00000000 0 0 0000000000C14H20‐N35 lb/h 0 0 00000000 0 0 0000000000C14H24‐N5 lb/h 0 0 00000000 0 0 00000000003,5‐Dimethyldodecane lb/h 0 0 00000000 0 0 0000000000C15H26‐N4 lb/h 0 0 00000000 0 0 00000000006,8‐Dimethyltridecane lb/h 0 0 00000000 0 0 00000000001,4‐Dimethyl‐Phenanthrene lb/h 0 0 00000000 0 0 0000000000N‐Cetane lb/h 0 0 00000000 0 0 0000000000C18H26O lb/h 0000000000000000000000C18H28 lb/h 0 0 00000000 0 0 0000000000C21H26O2 lb/h 0 000000000 0 0 0000000000C21H34 lb/h 0 000000000 0 0 0000000000C22H28O2 lb/h 0 000000000 0 0 0000000000Carbon lb/h 0000000000000000000000Sulfur lb/h 0000000000000000000000Sand/Catalyst Solids lb/h 0000000000000000000000Ash lb/h 0000000000000000000000Wood lb/h 0000000000000000000000Char lb/h 0000000000000000000000Coke lb/h 0000000000000000000000

187
Rev:

1

Project No: Drawing:

30482.00 PFD-61712-A504

THERMOCHEMICAL CONVERSION OF BIOMASS

TO HYDROCARBON FUEL

FAST PYROLYSIS AND VAPOR PHASE UPGRADING

PROCESS FLOW DIAGRAM

AREA 500: HYDROGEN DISTRIBUTION

Rev. Date By Description

J:\1A - Process Solutions\30482 NREL Thermochemical Conv - Design-Model\Drawings\ 30482 Pyrolysis Ex-Situ PFDs 61712 150128.vsd Plot date: 1/29/2015

0 9/29/14 JAR ISSUED FOR DESIGN REPORT

HYDROGEN

FROM M-575

PFD-61712-A503

HYDROGEN

FROM M-385

PFD-61712-A304

MAKEUP HYDROGEN

TO K-211

PFD-61712-A302

MAKEUP HYDROGEN

TO K-412

PFD-61712-A401

MAKEUP HYDROGEN

TO K-462

PFD-61712-A403

390

590

350

435

485

1 12/12/14 DMS ADDED HX NETWORK

188
PFD‐61712‐A504 350 390 435 485 590 

Total Flow lb/h 11,217 7,032 2,154 764 7,102 00000000000000000Temperature F 100 110 110 110 109 00000000000000000Pressure Psia 110 202 245 245 266 00000000000000000Vapor Fraction 11111 00000000000000000Enthalpy Flow MMBtu/h ‐4 ‐3 ‐1 0 ‐3 00000000000000000Argon lb/h 0000000000000000000000Nitrogen lb/h 0000000000000000000000Oxygen lb/h 0000000000000000000000SO2 lb/h 0000000000000000000000NO2 lb/h 0000000000000000000000Hydrogen lb/h 9,502 5,957 1,825 647 6,016 00000000000000000Ammonia lb/h 0000000000000000000000H2S lb/h 0000000000000000000000Water lb/h 0000000000000000000000Carbon Monoxide lb/h 667 418 128 45 422 00000000000000000Carbon Dioxide lb/h 1,048 657 201 71 663 00000000000000000Methane lb/h 0000000000000000000000Methanol lb/h 0000000000000000000000Formic Acid lb/h 0000000000000000000000Glyoxal lb/h 0000000000000000000000Ethylene lb/h 0000000000000000000000Acetaldehyde lb/h 0000000000000000000000Hydroxyacetaldehyde lb/h 0000000000000000000000Acetic Acid lb/h 0000000000000000000000Ethane lb/h 0000000000000000000000Propylene lb/h 00000000000000000000001‐Hydroxy‐2‐propanone lb/h 0000000000000000000000Propionic Acid lb/h 0000000000000000000000Propane lb/h 0000000000000000000000Furan lb/h 00000000000000000000001‐Butene lb/h 0000000000000000000000Tetrahydrofuran lb/h 0000000000000000000000N‐Butane lb/h 0000000000000000000000Furfural lb/h 00000000000000000000002‐methylfuran lb/h 0000000000000000000000Furfuryl Alcohol lb/h 0000000000000000000000n‐Pentane lb/h 0000000000000000000000Pentenone lb/h 0000000000000000000000Benzene lb/h 0000000000000000000000Phenol lb/h 00000000000000000000001,2‐Benzenediol lb/h 0000000000000000000000Hydroxymethylfurfural lb/h 00000000000000000000002,5‐dimethylfuran lb/h 0000000000000000000000Methyl Cyclopentenone lb/h 0000000000000000000000Hydroxymethylcyclopentenone lb/h 0000000000000000000000Cyclohexanone lb/h 0000000000000000000000Levoglucosan lb/h 00000000000000000000001‐Hexanal lb/h 0000000000000000000000Dimethoxytetrahydrofuran lb/h 0000000000000000000000Cyclohexane lb/h 0000000000000000000000N‐Hexane lb/h 0000000000000000000000Hexanol lb/h 0000000000000000000000Toluene lb/h 00000000000000000000002‐Methylphenol lb/h 00000000000000000000003‐Methyl‐phenol lb/h 0000000000000000000000Guaiacol lb/h 0000000000000000000000Methyl‐Cyclohexane lb/h 00000000000000000000002‐Methylhexane lb/h 0000000000000000000000VinylPhenol lb/h 0000000000000000000000O‐Xylene lb/h 0000000000000000000000Ethylbenzne lb/h 00000000000000000000002,3‐Dimethyl‐phenol lb/h 00000000000000000000002,6‐dimethoxyphenol lb/h 0000000000000000000000Vanillyl alcohol lb/h 00000000000000000000002,4,6‐Trimethylpyridine lb/h 0000000000000000000000Cis‐1,2‐dimethyl cyclohexane lb/h 0000000000000000000000Trans‐1,2‐dimethylcyclohexane lb/h 0000000000000000000000Ethylcyclohexane lb/h 00000000000000000000004‐Methylheptane lb/h 00000000000000000000002‐Methyl‐Benzofuran lb/h 0000000000000000000000Indane lb/h 00000000000000000000002‐methoxy‐4‐vinylphenol lb/h 0000000000000000000000Syringaldehyde lb/h 0000000000000000000000n‐Propylbenzene lb/h 0000000000000000000000Naphthalene lb/h 00000000000000000000001‐Naphthalenol lb/h 0000000000000000000000Coniferyl Aldehyde lb/h 0000000000000000000000Tetralin lb/h 0000000000000000000000Isoeugenol lb/h 0000000000000000000000Decalin lb/h 00000000000000000000002,5‐Dimethyloctane lb/h 00000000000000000000001‐Methyl naphthalene lb/h 00000000000000000000001‐methyl decahydronaphthene lb/h 0000000000000000000000Dibenzothiophene lb/h 0000000000000000000000Biphenyl lb/h 00000000000000000000005‐hexyl‐O‐cresol lb/h 0000000000000000000000n‐Heptylcyclohexane lb/h 0000000000000000000000C14H20‐N35 lb/h 0000000000000000000000C14H24‐N5 lb/h 00000000000000000000003,5‐Dimethyldodecane lb/h 0000000000000000000000C15H26‐N4 lb/h 00000000000000000000006,8‐Dimethyltridecane lb/h 00000000000000000000001,4‐Dimethyl‐Phenanthrene lb/h 0000000000000000000000N‐Cetane lb/h 0000000000000000000000C18H26O lb/h 0000000000000000000000C18H28 lb/h 0000000000000000000000C21H26O2 lb/h 0000000000000000000000C21H34 lb/h 0000000000000000000000C22H28O2 lb/h 0000000000000000000000Carbon lb/h 0000000000000000000000Sulfur lb/h 0000000000000000000000Sand/Catalyst Solids lb/h 0000000000000000000000Ash lb/h 0000000000000000000000Wood lb/h 0000000000000000000000Char lb/h 0000000000000000000000Coke lb/h 0000000000000000000000

189
Rev:

0

Project No: Drawing:

30482.00 PFD-61712-A505

THERMOCHEMICAL CONVERSION OF BIOMASS

TO HYDROCARBON FUEL

FAST PYROLYSIS AND VAPOR PHASE UPGRADING

PROCESS FLOW DIAGRAM

AREA 500: A500 HEAT RECOVERY

Rev. Date By Description

0

J:\1A - Process Solutions\30482 NREL Thermochemical Conv - Design-Model\Drawings\ 30482 Pyrolysis Ex-Situ PFDs 61712 150128.vsd Plot date: 1/29/2015

LTS EFFLUENT

TO H-AP-61

PFD-61712-A805

592

12/12/14 DMS ADDED HX NETWORK

H-AP-22

QHAP22

H-AP-19

A500 LOW TEMP WGS OUTLET

COOLER/PSA OFFGAS TO

REFORMER COMBUSTOR PREHEAT

H-AP-20

A500 LOW TEMP WGS OUTLET

COOLER/REFORMER COMBUSTOR

AIR PREHEAT

H-AP-22

A500 LOW TEMP WGS

OUTLET COOLER/REFORMER

COMBUSTOR GAS PREHEAT

572

516

LTS EFFLUENT

FROM R-566

PFD-61712-A502

LTS EFFLUENT

FROM H-AP-61

PFD-61712-A805

LTS EFFLUENT

TO H-AP-21

PFD-61712-A501

LTS EFFLUENT

FROM H-AP-21

PFD-61712-A501

H-AP-20

QHAP20

REFORMER COMB GAS

TO R-530

PFD-61712-A501

REFORMER COMB GAS

FROM HEADER

PFD-61712-A501

513

H-BP-9

QHBP9

H-BP-12 H-BP-7

573 LTS EFFLUENT

TO H-568A

PFD-61712-A502

H-BP-15

H-AP-19

PSA OFFGAS

TO R-530

PFD-61712-A501

591 PSA OFFGAS

FROM M-575

PFD-61712-A501

COMBUSTION AIR

FROM K-545

PFD-61712-A501-A

COMBUSTION AIR

FROM H-BP-2

PFD-61712-A501-A

QHAP19

COMBUSTION AIR

TO H-AP-29

PFD-61712-A501-A

QHBP12

QHBP15

QHBP7

LTS EFFLUENT

TO H-BP-25

PFD-61712-A604

LTS EFFLUENT

FROM H-BP-28

PFD-61712-A604

LTS EFFLUENT

TO H-BP-8

PFD-61712-A604

LTS EFFLUENT

FROM H-BP-8

PFD-61712-A604

H-BP-15

LOW TEMP WGS OUTLET

COOLER/PSA EXH TO

REFORMER COMB PREHEAT

H-BP-9

LOW TEMP WGS OUTLET

COOLER/REFORMER COMB

GAS PREHEAT

H-BP-12

LOW TEMP WGS OUTLET

COOLER/REFORMER COMB

AIR PREHEAT

H-BP-7

LOW TEMP WGS OUTLET

COOLER/REFORMER

COMBUSTOR AIR PREHEAT

190
PFD‐61712‐A505 513 516 572 573 591 592 

Total Flow lb/h 1,203 1,203 102,802 102,802 82,189 82,189 0000000000000000Temperature F 109 500 540 185 109 450 0000000000000000Pressure Psia 22 20 101 99 22 20 0000000000000000Vapor Fraction 111111 0000000000000000Enthalpy Flow MMBtu/h ‐3 ‐3 ‐368 ‐393 ‐298 ‐290 0000000000000000Argon lb/h 0000000000000000000000Nitrogen lb/h 005555 0000000000000000Oxygen lb/h 0000000000000000000000SO2 lb/h 000000 0000000000000000NO2 lb/h 0000000000000000000000Hydrogen lb/h 30 30 6,686 6,686 1,503 1,503 0000000000000000Ammonia lb/h 000033 0000000000000000H2S lb/h 005599 0000000000000000Water lb/h 11 11 16,218 16,218 441 441 0000000000000000Carbon Monoxide lb/h 85 85 4,433 4,433 4,452 4,452 0000000000000000Carbon Dioxide lb/h 820 820 75,035 75,035 74,494 74,494 0000000000000000Methane lb/h 55 55 420 420 896 896 0000000000000000Methanol lb/h 000000 0000000000000000Formic Acid lb/h 000000 0000000000000000Glyoxal lb/h 000000 0000000000000000Ethylene lb/h 102 102 0 0 18 18 0000000000000000Acetaldehyde lb/h 000000 0000000000000000Hydroxyacetaldehyde lb/h 0000000000000000000000Acetic Acid lb/h 000000 0000000000000000Ethane lb/h 6 6 0 0 199 199 0000000000000000Propylene lb/h 34 34 0 0 0 0 00000000000000001‐Hydroxy‐2‐propanone lb/h 0000000000000000000000Propionic Acid lb/h 000000 0000000000000000Propane lb/h 0 0 0 0 10 10 0000000000000000Furan lb/h 4 4 000000000000000000001‐Butene lb/h 17 17 0 0 1 1 0000000000000000Tetrahydrofuran lb/h 4 4 00000000000000000000N‐Butane lb/h 2 2 0 0 53 53 0000000000000000Furfural lb/h 00000000000000000000002‐methylfuran lb/h 4 4 00000000000000000000Furfuryl Alcohol lb/h 0000000000000000000000n‐Pentane lb/h 0 0 0 0 13 13 0000000000000000Pentenone lb/h 0000000000000000000000Benzene lb/h 0 0 0 0 13 13 0000000000000000Phenol lb/h 1 1 0 0 0 0 00000000000000001,2‐Benzenediol lb/h 0 0 00000000000000000000Hydroxymethylfurfural lb/h 00000000000000000000002,5‐dimethylfuran lb/h 0 0 0 0 0 0 0000000000000000Methyl Cyclopentenone lb/h 0000000000000000000000Hydroxymethylcyclopentenone lb/h 0000000000000000000000Cyclohexanone lb/h 0000000000000000000000Levoglucosan lb/h 00000000000000000000001‐Hexanal lb/h 0000000000000000000000Dimethoxytetrahydrofuran lb/h 0 0 00000000000000000000Cyclohexane lb/h 16 16 0 0 31 31 0000000000000000N‐Hexane lb/h 1 1 0 0 17 17 0000000000000000Hexanol lb/h 0000000000000000000000Toluene lb/h 0 0 0 0 2 2 00000000000000002‐Methylphenol lb/h 0 0 000000000000000000003‐Methyl‐phenol lb/h 0000000000000000000000Guaiacol lb/h 0 0 00000000000000000000Methyl‐Cyclohexane lb/h 2 2 0 0 4 4 00000000000000002‐Methylhexane lb/h 1 1 0 0 7 7 0000000000000000VinylPhenol lb/h 0 0 00000000000000000000O‐Xylene lb/h 0 0 0 0 2 2 0000000000000000Ethylbenzne lb/h 0 0 0 0 0 0 00000000000000002,3‐Dimethyl‐phenol lb/h 0 0 000000000000000000002,6‐dimethoxyphenol lb/h 0 0 00000000000000000000Vanillyl alcohol lb/h 0 0 000000000000000000002,4,6‐Trimethylpyridine lb/h 0 0 00000000000000000000Cis‐1,2‐dimethyl cyclohexane lb/h 3 3 0 0 5 5 0000000000000000Trans‐1,2‐dimethylcyclohexane lb/h 4 4 0 0 10 10 0000000000000000Ethylcyclohexane lb/h 0 0 0 0 1 1 00000000000000004‐Methylheptane lb/h 0 0 0 0 1 1 00000000000000002‐Methyl‐Benzofuran lb/h 0 0 00000000000000000000Indane lb/h 00000000000000000000002‐methoxy‐4‐vinylphenol lb/h 0 0 00000000000000000000Syringaldehyde lb/h 0000000000000000000000n‐Propylbenzene lb/h 0 0 0 0 0 0 0000000000000000Naphthalene lb/h 0 0 0 0 0 0 00000000000000001‐Naphthalenol lb/h 0 0 00000000000000000000Coniferyl Aldehyde lb/h 0 0 00000000000000000000Tetralin lb/h 0 0 0 0 0 0 0000000000000000Isoeugenol lb/h 0 0 00000000000000000000Decalin lb/h 0 0 0 0 0 0 00000000000000002,5‐Dimethyloctane lb/h 0 0 0 0 0 0 00000000000000001‐Methyl naphthalene lb/h 0 0 0 0 0 0 00000000000000001‐methyl decahydronaphthene lb/h 0 0 0 0 0 0 0000000000000000Dibenzothiophene lb/h 0 0 00000000000000000000Biphenyl lb/h 0 0 0 0 0 0 00000000000000005‐hexyl‐O‐cresol lb/h 0 0 00000000000000000000n‐Heptylcyclohexane lb/h 0 0 0 0 0 0 0000000000000000C14H20‐N35 lb/h 0 0 0 0 0 0 0000000000000000C14H24‐N5 lb/h 0 0 0 0 0 0 00000000000000003,5‐Dimethyldodecane lb/h 0 0 0 0 0 0 0000000000000000C15H26‐N4 lb/h 0 0 0 0 0 0 00000000000000006,8‐Dimethyltridecane lb/h 0 0 0 0 0 0 00000000000000001,4‐Dimethyl‐Phenanthrene lb/h 0 0 0 0 0 0 0000000000000000N‐Cetane lb/h 0 0 0 0 0 0 0000000000000000C18H26O lb/h 0 0 00000000000000000000C18H28 lb/h 0 0 0 0 0 0 0000000000000000C21H26O2 lb/h 0 0 0 0 0 0 0000000000000000C21H34 lb/h 0 0 0 0 0 0 0000000000000000C22H28O2 lb/h 0 0 0 0 0 0 0000000000000000Carbon lb/h 0000000000000000000000Sulfur lb/h 0000000000000000000000Sand/Catalyst Solids lb/h 0000000000000000000000Ash lb/h 0000000000000000000000Wood lb/h 0000000000000000000000Char lb/h 0000000000000000000000Coke lb/h 0000000000000000000000

191
CONDENSATE

FROM P-602

PFD-61712-A602

Rev:

1

Project No: Drawing:

30482.00 PFD-61712-A601

THERMOCHEMICAL CONVERSION OF BIOMASS

TO HYDROCARBON FUEL

FAST PYROLYSIS AND VAPOR PHASE UPGRADING

PROCESS FLOW DIAGRAM

AREA 600: STEAM SYSTEM & POWER GENERATION

Rev. Date By Description

FLASH STEAM

FROM S-601

PFD-61712-A603

MAKEUP WATER

FROM

PFD-61712-A701

BFW CHEMICALS

FROM P-707

PFD-61712-A702

T-601

P-601

P-603

AMMONIA

FROM P-704

PFD-61712-A702

P-604

P-601

MAKE-UP

PUMP

T-601

CONDENSATE

COLLECTION TANK

T-602

CONDENSATE

SURGE TANK

P-603

EDI PUMP

P-604

BOILER

FEEDWATER PUMP

T-603A

DEAERATOR

PACKED COLUMN

T-603

DEAERATOR

616

618

WP601

638

T-603A

WP603

T-603

WP604

J:\1A - Process Solutions\30482 NREL Thermochemical Conv - Design-Model\Drawings\ 30482 Pyrolysis Ex-Situ PFDs 61712 150128.vsd Plot date: 1/29/2015

T-602

M-601

CONDENSATE

FROM USERS

0 9/29/14 JAR ISSUED FOR DESIGN REPORT

626

627

630 631

ATM

ATM

BOILER FEEDWATER

TO M-603

PFD-61712-A602

617

P-605

P-605

CONDENSATE

COLLECTION PUMP

639

1 12/12/14 DMS ADDED HX NETWORK

POLISHED COND

TO H-BP-1/H-BP-8

PFD-61712-A604

BOILER FEEDWATER

TO H-BP-20/21/22

PFD-61712-A605

H-BP-44

ABSORBER 1 BOTTOMS

COOLER/RECYCLED

BFW PREHEAT

H-BP-45

BFW BLOWDOWN

COOLER/RECYCLED

BFW PREHEAT

H-BP-46

HC OUTLET COOLER/

RECYCLED BFW

PREHEAT

H-BP-32

BFW BLOWDOWN

COOLER/RECYCLED

BFW PREHEAT

H-BP-40

EX-SITU CAT REGEN FLUE

GAS COOLER/RECYCLED

BFW PREHEAT

H-BP-44

QHBP44

H-BP-45

H-BP-46

MAKEUP WATER

TO H-BP-47

PFD-61712-A404

MAKEUP WATER

FROM H-BP-47

PFD-61712-A404

H-BP-32

H-BP-40

ABSORBER BOTTOMS

FROM H-BP-31

PFD-61712-A305

ABSORBER BOTTOMS

TO S-319

PFD-61712-A305

BLOWDOWN

TO M-701

PFD-61712-A701

HC EFFLUENT

FROM H-BP-19

PFD-61712-A604

HC EFFLUENT

TO H-463A

PFD-61712-A404

QHBP45

QHBP46

QHBP32

QHBP40

BLOWDOWN

FROM H-BP-33/37/39

PFD-61712-A603

VPU FLUE GAS

FROM H-AP-37

PFD-61712-A203

VPU FLUE GAS

TO H-BP-17

PFD-61712-A203

600

319

POLISHED COND

FROM

PFD-61712-A604

CWS

CWR

H-603

QH603

H-603

BLOWDOWN

COOLER

M-601

BFW ELECTRODEIONIZATION

(EDI) + POLISHING

192
PFD‐61712‐A601 319 600 616 617 618 626 627 630 631 638 639 

Total Flow lb/h 19,671 6,475 317,274 317,274 6,473 6,473 323,747 323,747 323,747 323,749 323,749 00000000000Temperature F 175 113 136 136 60 212 138 138 232 232 235 00000000000Pressure Psia 123 15 25 15 15 15 15 25 22 22 1401 00000000000Vapor Fraction 00000 0 0000000000000000Enthalpy Flow MMBtu/h ‐10 ‐44 ‐2145 ‐2145 ‐44 ‐43 ‐2189 ‐2189 ‐2158 ‐2158 ‐2156 00000000000Argon lb/h 0000000000000000000000Nitrogen lb/h 0000000000000000000000Oxygen lb/h 0000000000000000000000SO2 lb/h 0000000000000000000000NO2 lb/h 0000000000000000000000Hydrogen lb/h 1 000000000000000000000Ammonia lb/h 0000000000000000000000H2S lb/h 0000000000000000000000Water lb/h 43 6,475 317,274 317,274 6,473 6,473 323,747 323,747 323,747 323,749 323,749 00000000000Carbon Monoxide lb/h 3 000000000000000000000Carbon Dioxide lb/h 7 000000000000000000000Methane lb/h 1 000000000000000000000Methanol lb/h 0000000000000000000000Formic Acid lb/h 0000000000000000000000Glyoxal lb/h 0000000000000000000000Ethylene lb/h 2 000000000000000000000Acetaldehyde lb/h 0000000000000000000000Hydroxyacetaldehyde lb/h 0000000000000000000000Acetic Acid lb/h 0000000000000000000000Ethane lb/h 0000000000000000000000Propylene lb/h 1 0000000000000000000001‐Hydroxy‐2‐propanone lb/h 0000000000000000000000Propionic Acid lb/h 0000000000000000000000Propane lb/h 0000000000000000000000Furan lb/h 1 0000000000000000000001‐Butene lb/h 1 000000000000000000000Tetrahydrofuran lb/h 1 000000000000000000000N‐Butane lb/h 0000000000000000000000Furfural lb/h 00000000000000000000002‐methylfuran lb/h 1 000000000000000000000Furfuryl Alcohol lb/h 0000000000000000000000n‐Pentane lb/h 0000000000000000000000Pentenone lb/h 0000000000000000000000Benzene lb/h 0000000000000000000000Phenol lb/h 11 0000000000000000000001,2‐Benzenediol lb/h 20 000000000000000000000Hydroxymethylfurfural lb/h 00000000000000000000002,5‐dimethylfuran lb/h 0 000000000000000000000Methyl Cyclopentenone lb/h 0000000000000000000000Hydroxymethylcyclopentenone lb/h 0000000000000000000000Cyclohexanone lb/h 0000000000000000000000Levoglucosan lb/h 00000000000000000000001‐Hexanal lb/h 0000000000000000000000Dimethoxytetrahydrofuran lb/h 0 000000000000000000000Cyclohexane lb/h 9 000000000000000000000N‐Hexane lb/h 0000000000000000000000Hexanol lb/h 0000000000000000000000Toluene lb/h 00000000000000000000002‐Methylphenol lb/h 0 0000000000000000000003‐Methyl‐phenol lb/h 0000000000000000000000Guaiacol lb/h 0 000000000000000000000Methyl‐Cyclohexane lb/h 2 0000000000000000000002‐Methylhexane lb/h 0000000000000000000000VinylPhenol lb/h 0 000000000000000000000O‐Xylene lb/h 0000000000000000000000Ethylbenzne lb/h 00000000000000000000002,3‐Dimethyl‐phenol lb/h 30 0000000000000000000002,6‐dimethoxyphenol lb/h 29 000000000000000000000Vanillyl alcohol lb/h 32 0000000000000000000002,4,6‐Trimethylpyridine lb/h 2 000000000000000000000Cis‐1,2‐dimethyl cyclohexane lb/h 12 000000000000000000000Trans‐1,2‐dimethylcyclohexane lb/h 14 000000000000000000000Ethylcyclohexane lb/h 00000000000000000000004‐Methylheptane lb/h 00000000000000000000002‐Methyl‐Benzofuran lb/h 5 000000000000000000000Indane lb/h 00000000000000000000002‐methoxy‐4‐vinylphenol lb/h 0 000000000000000000000Syringaldehyde lb/h 0000000000000000000000n‐Propylbenzene lb/h 0000000000000000000000Naphthalene lb/h 00000000000000000000001‐Naphthalenol lb/h 16 000000000000000000000Coniferyl Aldehyde lb/h 373 000000000000000000000Tetralin lb/h 0000000000000000000000Isoeugenol lb/h 0 000000000000000000000Decalin lb/h 0 0000000000000000000002,5‐Dimethyloctane lb/h 00000000000000000000001‐Methyl naphthalene lb/h 11 0000000000000000000001‐methyl decahydronaphthene lb/h 1 000000000000000000000Dibenzothiophene lb/h 41 000000000000000000000Biphenyl lb/h 00000000000000000000005‐hexyl‐O‐cresol lb/h 333 000000000000000000000n‐Heptylcyclohexane lb/h 0000000000000000000000C14H20‐N35 lb/h 0000000000000000000000C14H24‐N5 lb/h 185 0000000000000000000003,5‐Dimethyldodecane lb/h 0000000000000000000000C15H26‐N4 lb/h 163 0000000000000000000006,8‐Dimethyltridecane lb/h 00000000000000000000001,4‐Dimethyl‐Phenanthrene lb/h 427 000000000000000000000N‐Cetane lb/h 0000000000000000000000C18H26O lb/h 4,923 000000000000000000000C18H28 lb/h 0000000000000000000000C21H26O2 lb/h 3,421 000000000000000000000C21H34 lb/h 7,751 000000000000000000000C22H28O2 lb/h 1,788 000000000000000000000Carbon lb/h 0000000000000000000000Sulfur lb/h 0000000000000000000000Sand/Catalyst Solids lb/h 9 000000000000000000000Ash lb/h 0 000000000000000000000Wood lb/h 0 000000000000000000000Char lb/h 0 000000000000000000000Coke lb/h 1 000000000000000000000

193
SUPERHEATED STEAM

FROM H-AP-2/4/6/49/50

PFD-61712-A603

Rev:

1

Project No: Drawing:

30482.00 PFD-61712-A602

THERMOCHEMICAL CONVERSION OF BIOMASS

TO HYDROCARBON FUEL

FAST PYROLYSIS AND VAPOR PHASE UPGRADING

Rev. Date By Description

CONDENSATE

TO T-601

PFD-61712-A601

P-602

BOILER FEEDWATER

FROM P-604

PFD-61712-A601

M-603

LP STEAM

TO USERS

QAH601

WP602

607

614A

616

M-602

W-602A

M-602

TURBINE

GENERATOR

M-603

STARTUP BOILER

P-602

CONDENSATE

PUMP

H-601

STEAM TURBINE

CONDENSER

J:\1A - Process Solutions\30482 NREL Thermochemical Conv - Design-Model\Drawings\ 30482 Pyrolysis Ex-Situ PFDs 61712 150128.vsd Plot date: 1/29/2015

PROCESS FLOW DIAGRAM

AREA 600: STEAM SYSTEM & POWER GENERATION

0 9/29/14 JAR ISSUED FOR DESIGN REPORT

H-601

T-606

T-606

STEAM TURBINE

CONDENSATE TANK

QH602B

1 12/12/14 DMS ADDED HX NETWORK

H-AP-9

CHAR COMBUSTOR FLUE

GAS COOLER/INTERTURBINE STEAM REHEAT

H-AP-47

REFORMER OUTLET

COOLER/INTER-TURBINE

STEAM REHEAT

H-BP-10

STEAM TURBINE EXHAUST

COOLER/WW PREHEAT

FOR STEAM PRODUCTION

H-AP-9

QHAP9

FLUE GAS

FROM S-214

PFD-61712-A203

232P

FLUE GAS

TO H-AP-8

PFD-61712-A203

STEAM

TO H-AP-26

PFD-61712-A501-A

STEAM

FROM H-AP-26

PFD-61712-A501-A

H-AP-47

QHAP47

REFORMER PRODUCT

FROM R-530

PFD-61712-A502

REFORMER PRODUCT

TO H-AP-46

PFD-61712-A502

H-BP-10

QHBP10

WASTEWATER

FROM P-810

PFD-61712-A805

WASTEWATER

TO H-BP-26/H-BP-33

PFD-61712-A805

811

194
PFD‐61712‐A602 232P 607 614A 615 616 811 

Total Flow lb/h 258,265 317,274 317,274 317,274 317,274 77,811 0000000000000000Temperature F 1328 1000 234 136 136 86 0000000000000000Pressure Psia 115 1321 4 3 25 160 0000000000000000Vapor Fraction 111 0000000000000000000Enthalpy Flow MMBtu/h ‐208 ‐1704 ‐1809 ‐2145 ‐2145 ‐523 0000000000000000Argon lb/h 3,005 000000000000000000000Nitrogen lb/h 176,443 000000000000000000000Oxygen lb/h 8,996 000000000000000000000SO2 lb/h 85 000000000000000000000NO2 lb/h 0000000000000000000000Hydrogen lb/h 00000 0 0000000000000000Ammonia lb/h 0000000000000000000000H2S lb/h 0000000000000000000000Water lb/h 13,826 317,274 317,274 317,274 317,274 75,955 0000000000000000Carbon Monoxide lb/h 00000 0 0000000000000000Carbon Dioxide lb/h 55,910 0000 2 0000000000000000Methane lb/h 00000 0 0000000000000000Methanol lb/h 0000000000000000000000Formic Acid lb/h 0000000000000000000000Glyoxal lb/h 0000000000000000000000Ethylene lb/h 00000 0 0000000000000000Acetaldehyde lb/h 0000000000000000000000Hydroxyacetaldehyde lb/h 0000000000000000000000Acetic Acid lb/h 0000000000000000000000Ethane lb/h 0000000000000000000000Propylene lb/h 00000 0 00000000000000001‐Hydroxy‐2‐propanone lb/h 0000000000000000000000Propionic Acid lb/h 0000000000000000000000Propane lb/h 0000000000000000000000Furan lb/h 00000 0 00000000000000001‐Butene lb/h 00000 0 0000000000000000Tetrahydrofuran lb/h 00000 0 0000000000000000N‐Butane lb/h 0000000000000000000000Furfural lb/h 00000000000000000000002‐methylfuran lb/h 00000 0 0000000000000000Furfuryl Alcohol lb/h 0000000000000000000000n‐Pentane lb/h 0000000000000000000000Pentenone lb/h 0000000000000000000000Benzene lb/h 0000000000000000000000Phenol lb/h 00000 73 00000000000000001,2‐Benzenediol lb/h 00000 1,778 0000000000000000Hydroxymethylfurfural lb/h 00000000000000000000002,5‐dimethylfuran lb/h 00000 0 0000000000000000Methyl Cyclopentenone lb/h 0000000000000000000000Hydroxymethylcyclopentenone lb/h 0000000000000000000000Cyclohexanone lb/h 0000000000000000000000Levoglucosan lb/h 00000000000000000000001‐Hexanal lb/h 0000000000000000000000Dimethoxytetrahydrofuran lb/h 00000 0 0000000000000000Cyclohexane lb/h 00000 0 0000000000000000N‐Hexane lb/h 0000000000000000000000Hexanol lb/h 0000000000000000000000Toluene lb/h 00000000000000000000002‐Methylphenol lb/h 00000 0 00000000000000003‐Methyl‐phenol lb/h 0000000000000000000000Guaiacol lb/h 00000 0 0000000000000000Methyl‐Cyclohexane lb/h 00000 0 00000000000000002‐Methylhexane lb/h 0000000000000000000000VinylPhenol lb/h 00000 0 0000000000000000O‐Xylene lb/h 0000000000000000000000Ethylbenzne lb/h 00000000000000000000002,3‐Dimethyl‐phenol lb/h 00000 1 00000000000000002,6‐dimethoxyphenol lb/h 00000 0 0000000000000000Vanillyl alcohol lb/h 00000 3 00000000000000002,4,6‐Trimethylpyridine lb/h 00000 0 0000000000000000Cis‐1,2‐dimethyl cyclohexane lb/h 00000 0 0000000000000000Trans‐1,2‐dimethylcyclohexane lb/h 00000 0 0000000000000000Ethylcyclohexane lb/h 00000000000000000000004‐Methylheptane lb/h 00000000000000000000002‐Methyl‐Benzofuran lb/h 00000 0 0000000000000000Indane lb/h 00000000000000000000002‐methoxy‐4‐vinylphenol lb/h 00000 0 0000000000000000Syringaldehyde lb/h 0000000000000000000000n‐Propylbenzene lb/h 0000000000000000000000Naphthalene lb/h 00000000000000000000001‐Naphthalenol lb/h 00000 0 0000000000000000Coniferyl Aldehyde lb/h 00000 0 0000000000000000Tetralin lb/h 0000000000000000000000Isoeugenol lb/h 00000 0 0000000000000000Decalin lb/h 00000 0 00000000000000002,5‐Dimethyloctane lb/h 00000000000000000000001‐Methyl naphthalene lb/h 00000 0 00000000000000001‐methyl decahydronaphthene lb/h 00000 0 0000000000000000Dibenzothiophene lb/h 00000 0 0000000000000000Biphenyl lb/h 00000000000000000000005‐hexyl‐O‐cresol lb/h 00000 0 0000000000000000n‐Heptylcyclohexane lb/h 0000000000000000000000C14H20‐N35 lb/h 0000000000000000000000C14H24‐N5 lb/h 00000 0 00000000000000003,5‐Dimethyldodecane lb/h 0000000000000000000000C15H26‐N4 lb/h 00000 0 00000000000000006,8‐Dimethyltridecane lb/h 00000000000000000000001,4‐Dimethyl‐Phenanthrene lb/h 00000 0 0000000000000000N‐Cetane lb/h 0000000000000000000000C18H26O lb/h 00000 0 0000000000000000C18H28 lb/h 0000000000000000000000C21H26O2 lb/h 00000 0 0000000000000000C21H34 lb/h 00000 0 0000000000000000C22H28O2 lb/h 00000 0 0000000000000000Carbon lb/h 0000000000000000000000Sulfur lb/h 0000000000000000000000Sand/Catalyst Solids lb/h 0000000000000000000000Ash lb/h 0000000000000000000000Wood lb/h 0000000000000000000000Char lb/h 0000000000000000000000Coke lb/h 0000000000000000000000

195
Rev:

1

Project No: Drawing:

30482.00 PFD-61712-A603

THERMOCHEMICAL CONVERSION OF BIOMASS

TO HYDROCARBON FUEL

FAST PYROLYSIS AND VAPOR PHASE UPGRADING

PROCESS FLOW DIAGRAM

AREA 600: STEAM SYSTEM & POWER GENERATION

Rev. Date By Description

SUPERHEATED STEAM

TO M-602

PFD-61712-A602

FLASH STEAM

TO T-603

PFD-61712-A601

BLOWDOWN

TO H-AP-55

PFD-61712-A605

T-605

STEAM

DRUM

S-601

BLOWDOWN

FLASH DRUM

T-605

S-601

607

J:\1A - Process Solutions\30482 NREL Thermochemical Conv - Design-Model\Drawings\ 30482 Pyrolysis Ex-Situ PFDs 61712 150128.vsd Plot date: 1/29/2015

644

0 9/29/14 JAR ISSUED FOR DESIGN REPORT

SATURATED STEAM

FROM H-AP-1

PFD-61712-A201

1 12/12/14 DMS ADDED HX NETWORK

SATURATED WATER

FROM H-AP-51

PFD-61712-A605

SATURATED WATER

TO H-AP-1

PFD-61712-A201

SATURATED WATER

TO H-AP-3/H-AP-5

PFD-61712-A202

SATURATED STEAM

FROM H-AP-3/H-AP-5

PFD-61712-A202

SATURATED STEAM

TO H-AP-2

PFD-61712-A201

SATURATED STEAM

TO H-AP-4/H-AP-6

PFD-61712-A202

H-AP-48

QHAP48

PYROLYSIS VAPOR

FROM S-262/T-261

PFD-61712-A305

PYROLYSIS VAPOR

TO H-AP-51

PFD-61712-A605

H-AP-48

PRE-ABSORBER UPGRADED

VAPOR COOLER/STEAM

SUPERHEAT

H-AP-49

EX-SITU CATALYST REGEN

FLUE GAS COOLER/STEAM

SUPERHEAT

H-AP-50

REFORMER OUTLET

COOLER/STEAM

SUPERHEAT

H-AP-49

QHAP49

VPU FLUE GAS

FROM S-264

PFD-61712-A203

VPU FLUE GAS

TO H-AP-38/H-AP-39

PFD-61712-A203

H-AP-50

QHAP50

REFORMER PRODUCT

FROM R-530

PFD-61712-A502

REFORMER PRODUCT

TO H-AP-46

PFD-61712-A502

300 289

SUPERHEATED STEAM

FROM H-AP-2

PFD-61712-A201

SUPERHEATED STEAM

FROM H-AP-4/H-AP-6

PFD-61712-A202

H-AP-10

QHAP10

CLEAN WATER

FROM H-BP-39/H-BP-41

PFD-61712-A804

CLEAN WATER

TO H-AP-45

PFD-61712-A804

H-AP-10

BOILER FEEDWATER

BLOWDOWN COOLER/

CATALYST STRIPPER WATER

PREHEAT FOR STEAM

H-AP-11

BOILER FEEDWATER

BLOWDOWN COOLER/

WATER PREHEAT FOR MIX

WITH WW FOR STEAM

H-BP-33

BOILER FEEDWATER

BLOWDOWN COOLER/

WASTEWATER PREHEAT FOR

STEAM PRODUCTION

H-BP-39

BOILER FEEDWATER

BLOWDOWN COOLER/

CATALYST STRIPPER WATER

PREHEAT FOR STEAM

H-AP-11

QHAP11

MAKEUP WATER

FROM H-BP-42/H-BP-43

PFD-61712-A801

MAKEUP WATER

TO T-814

PFD-61712-A801

BLOWDOWN

FROM H-AP-35

PFD-61712-A605

H-BP-33

QHBP33

WASTEWATER

FROM H-BP-10

PFD-61712-A805

WASTEWATER

TO H-AP-23/24/25/32

PFD-61712-A805

H-BP-39

QHBP39

CLEAN WATER

FROM H-BP-48

PFD-61712-A804

CLEAN WATER

TO H-AP-10

PFD-61712-A804

BLOWDOWN

TO H-BP-37

PFD-61712-A501

BLOWDOWN

FROM H-BP-37

PFD-61712-A501

BLOWDOWN

TO H-BP-32

PFD-61712-A601

641

196
PFD‐61712‐A603 289 300 607 641 644 

Total Flow lb/h 210,963 310,342 317,274 323,749 323,749 00000000000000000Temperature F 1202 931 1000 582 581 00000000000000000Pressure Psia 111 115 1321 1346 1336 00000000000000000Vapor Fraction 111 0 1 00000000000000000Enthalpy Flow MMBtu/h ‐160 ‐638 ‐1704 ‐2031 ‐1845 00000000000000000Argon lb/h 2,478 000000000000000000000Nitrogen lb/h 145,311 000000000000000000000Oxygen lb/h 7,421 000000000000000000000SO2 lb/h 0 000000000000000000000NO2 lb/h 0000000000000000000000Hydrogen lb/h 0 21,258 00000000000000000000Ammonia lb/h 0000000000000000000000H2S lb/h 0000000000000000000000Water lb/h 3,830 76,670 317,274 323,749 323,749 00000000000000000Carbon Monoxide lb/h 0 66,248 00000000000000000000Carbon Dioxide lb/h 51,924 55,426 00000000000000000000Methane lb/h 0 8,325 00000000000000000000Methanol lb/h 0000000000000000000000Formic Acid lb/h 0000000000000000000000Glyoxal lb/h 0000000000000000000000Ethylene lb/h 0 16,692 00000000000000000000Acetaldehyde lb/h 0000000000000000000000Hydroxyacetaldehyde lb/h 0000000000000000000000Acetic Acid lb/h 0000000000000000000000Ethane lb/h 0000000000000000000000Propylene lb/h 0 5,682 000000000000000000001‐Hydroxy‐2‐propanone lb/h 0000000000000000000000Propionic Acid lb/h 0000000000000000000000Propane lb/h 0000000000000000000000Furan lb/h 0 845 000000000000000000001‐Butene lb/h 0 2,919 00000000000000000000Tetrahydrofuran lb/h 0 1,046 00000000000000000000N‐Butane lb/h 0000000000000000000000Furfural lb/h 00000000000000000000002‐methylfuran lb/h 0 1,144 00000000000000000000Furfuryl Alcohol lb/h 0000000000000000000000n‐Pentane lb/h 0000000000000000000000Pentenone lb/h 0000000000000000000000Benzene lb/h 0000000000000000000000Phenol lb/h 0 2,161 000000000000000000001,2‐Benzenediol lb/h 0 1,872 00000000000000000000Hydroxymethylfurfural lb/h 00000000000000000000002,5‐dimethylfuran lb/h 0 13 00000000000000000000Methyl Cyclopentenone lb/h 0000000000000000000000Hydroxymethylcyclopentenone lb/h 0000000000000000000000Cyclohexanone lb/h 0000000000000000000000Levoglucosan lb/h 00000000000000000000001‐Hexanal lb/h 0000000000000000000000Dimethoxytetrahydrofuran lb/h 0 38 00000000000000000000Cyclohexane lb/h 0 5,348 00000000000000000000N‐Hexane lb/h 0000000000000000000000Hexanol lb/h 0000000000000000000000Toluene lb/h 00000000000000000000002‐Methylphenol lb/h 00000000000000000000003‐Methyl‐phenol lb/h 0000000000000000000000Guaiacol lb/h 0 1 00000000000000000000Methyl‐Cyclohexane lb/h 0 990 000000000000000000002‐Methylhexane lb/h 0000000000000000000000VinylPhenol lb/h 0 1 00000000000000000000O‐Xylene lb/h 0000000000000000000000Ethylbenzne lb/h 00000000000000000000002,3‐Dimethyl‐phenol lb/h 0 2,627 000000000000000000002,6‐dimethoxyphenol lb/h 0 898 00000000000000000000Vanillyl alcohol lb/h 0 870 000000000000000000002,4,6‐Trimethylpyridine lb/h 0 333 00000000000000000000Cis‐1,2‐dimethyl cyclohexane lb/h 0 3,060 00000000000000000000Trans‐1,2‐dimethylcyclohexane lb/h 0 4,153 00000000000000000000Ethylcyclohexane lb/h 00000000000000000000004‐Methylheptane lb/h 00000000000000000000002‐Methyl‐Benzofuran lb/h 0 463 00000000000000000000Indane lb/h 00000000000000000000002‐methoxy‐4‐vinylphenol lb/h 0 13 00000000000000000000Syringaldehyde lb/h 0000000000000000000000n‐Propylbenzene lb/h 0000000000000000000000Naphthalene lb/h 00000000000000000000001‐Naphthalenol lb/h 0 353 00000000000000000000Coniferyl Aldehyde lb/h 0 381 00000000000000000000Tetralin lb/h 0000000000000000000000Isoeugenol lb/h 0 13 00000000000000000000Decalin lb/h 0 44 000000000000000000002,5‐Dimethyloctane lb/h 00000000000000000000001‐Methyl naphthalene lb/h 0 417 000000000000000000001‐methyl decahydronaphthene lb/h 0 62 00000000000000000000Dibenzothiophene lb/h 0 73 00000000000000000000Biphenyl lb/h 00000000000000000000005‐hexyl‐O‐cresol lb/h 0 4,709 00000000000000000000n‐Heptylcyclohexane lb/h 0000000000000000000000C14H20‐N35 lb/h 0000000000000000000000C14H24‐N5 lb/h 0 3,313 000000000000000000003,5‐Dimethyldodecane lb/h 0000000000000000000000C15H26‐N4 lb/h 0 3,555 000000000000000000006,8‐Dimethyltridecane lb/h 00000000000000000000001,4‐Dimethyl‐Phenanthrene lb/h 0 427 00000000000000000000N‐Cetane lb/h 0000000000000000000000C18H26O lb/h 0 4,923 00000000000000000000C18H28 lb/h 0000000000000000000000C21H26O2 lb/h 0 3,421 00000000000000000000C21H34 lb/h 0 7,754 00000000000000000000C22H28O2 lb/h 0 1,788 00000000000000000000Carbon lb/h 0000000000000000000000Sulfur lb/h 0000000000000000000000Sand/Catalyst Solids lb/h 0 9 00000000000000000000Ash lb/h 0 0 00000000000000000000Wood lb/h 0 0 00000000000000000000Char lb/h 0 0 00000000000000000000Coke lb/h 0 1 00000000000000000000

197
Rev:

1

Project No: Drawing:

30482.00 PFD-61712-A604

THERMOCHEMICAL CONVERSION OF BIOMASS

TO HYDROCARBON FUEL

FAST PYROLYSIS AND VAPOR PHASE UPGRADING

PROCESS FLOW DIAGRAM

AREA 600: BOILER FEEDWATER PREHEAT 1

Rev. Date By Description

J:\1A - Process Solutions\30482 NREL Thermochemical Conv - Design-Model\Drawings\ 30482 Pyrolysis Ex-Situ PFDs 61712 150128.vsd Plot date: 1/29/2015

0 12/12/14 DMS ADDED HX NETWORK

H-BP-1

A300 WGS OUTLET

COOLER/CONDENSER/

BOILER FEEDWATER

PREHEAT 1

H-BP-8

LOW TEMP WGS

OUTLET COOLER/

CONDENSER/BOILER

FEEDWATER PREHEAT 1

H-BP-1

QHBP1

WGS OUTLET

FROM H-BP-14/H-BP-27

PFD-61712-A303

WGS OUTLET

TO H-373

PFD-61712-A303

POLISHED COND

FROM M-601C

PFD-61712-A601

630

H-BP-8

QHBP8

LTS EFFLUENT

FROM H-BP-12/15/28/9

PFD-61712-A505

LTS EFFLUENT

TO H-568A

PFD-61712-A505

H-BP-16

QHBP16

FLUE GAS

FROM H-BP-21

PFD-61712-A203

FLUE GAS

TO M-104

PFD-61712-A203

H-BP-25

QHBP25

LTS EFFLUENT

FROM H-AP-19/H-AP-20

PFD-61712-A505

H-BP-28

QHBP28

LTS EFFLUENT

TO H-BP-7/H-BP-8

PFD-61712-A505

H-BP-35

QHBP35

WGS OUTLET

FROM H-AP-14/32/33

PFD-61712-A303

H-BP-27

QHBP27

WGS OUTLET

TO H-BP-4/36/1

PFD-61712-A303

239P

POLISHED COND

TO T-603

PFD-61712-A601

H-BP-23

QHBP23

HT EFFLUENT

FROM H-AP-12/H-AP-24

PFD-61712-A404

H-BP-18

QHBP18

H-BP-24

QHBP24

HC EFFLUENT

TO H-BP-46

PFD-61712-A601

H-BP-19

QHBP19

HC EFFLUENT

FROM H-AP-34

PFD-61712-A404

H-BP-11

QHBP11

ABSORBER VAPOR

TO H-313

PFD-61712-A305

HT EFFLUENT

TO H-BP-47/48/49

PFD-61712-A404

ABSORBER VAPOR

FROM H-BP-20

PFD-61712-A605

631

H-BP-13

QHBP13

FLUE GAS

FROM H-840

PFD-61712-A802

H-BP-17

QHBP17

H-BP-34

QHBP34

ABSORBER BOTTOMS

TO H-BP-44

PFD-61712-A305

H-BP-31

QHBP31

ABSORBER BOTTOMS

FROM H-AP-23

PFD-61712-A305

H-BP-29

QHBP29

DIESEL PRODUCT

TO H-BP-30

PFD-61712-A404

VPU FLUE GAS

TO M-104

PFD-61712-A203

DIESEL PRODUCT

FROM H-AP-16/H-AP-25

PFD-61712-A404

VPU FLUE GAS

FROM H-BP-40/22/41/42

PFD-61712-A203

ABSORBER BOTTOMS

FROM H-BP-34/H-BP-43

PFD-61712-A305

ABSORBER BOTTOMS

TO H-BP-31

PFD-61712-A305

FLUE GAS

TO M-104

PFD-61712-A802

840

841

297

H-BP-16

CHAR COMBUSTOR

FLUE GAS COOLER/

BOILER FEEDWATER

PREHEAT 1

H-BP-25

LOW TEMP WGS

OUTLET COOLER/

BOILER FEEDWATER

PREHEAT 1

H-BP-28

LOW TEMP WGS

OUTLET COOLER/

BOILER FEEDWATER

PREHEAT 1

H-BP-35

A300 WGS OUTLET

COOLER/BOILER

FEEDWATER

PREHEAT 1

H-BP-27

A300 WGS OUTLET

COOLER/BOILER

FEEDWATER

PREHEAT 1

H-BP-23

HYDROTREATER

OUTLET COOLER/

BOILER FEEDWATER

PREHEAT 1

H-BP-18

HYDROTREATER

OUTLET COOLER/

BOILER FEEDWATER

PREHEAT 1

H-BP-24

HYDROCRACKER

OUTLET COOLER/

BOILER FEEDWATER

PREHEAT 1

H-BP-19

HYDROCRACKER

OUTLET COOLER/

BOILER FEEDWATER

PREHEAT 1

H-BP-11

POST-ABSORBER 1

VAPOR COOLER/

BOILER FEEDWATER

PREHEAT 1

H-BP-13

RTO LOW TEMP

EXHAUST COOLER/

BOILER FEEDWATER

PREHEAT 1

H-BP-17

EX-SITU CATALYST

REGEN FLUE GAS

COOLER/BOILER

FEEDWATER PREHEAT 1

H-BP-34

ABSORBER 1

BOTTOMS COOLER/

BOILER FEEDWATER

PREHEAT 1

H-BP-31

ABSORBER 1

BOTTOMS COOLER/

BOILER FEEDWATER

PREHEAT 1

H-BP-29

DISTILLATE

PRODUCT COOLER/

BOILER FEEDWATER

PREHEAT 1

1 12/29/14 JAR MINOR UPDATES

198
PFD‐61712‐A604 239P 297 630 631 840 841 

Total Flow lb/h 258,265 210,963 323,747 323,747 80,265 80,265 0000000000000000Temperature F 245 245 138 232 269 245 0000000000000000Pressure Psia 109 105 25 22 19 17 0000000000000000Vapor Fraction 1 1 0 0 1 1 0000000000000000Enthalpy Flow MMBtu/h ‐284 ‐213 ‐2189 ‐2158 ‐28 ‐28 0000000000000000Argon lb/h 3,005 2,478 0 0 979 979 0000000000000000Nitrogen lb/h 176,443 145,311 0 0 57,382 57,382 0000000000000000Oxygen lb/h 8,996 7,421 0 0 15,606 15,606 0000000000000000SO2 lb/h 85 0 0 0 0 0 0000000000000000NO2 lb/h 0000000000000000000000Hydrogen lb/h 0000000000000000000000Ammonia lb/h 0000000000000000000000H2S lb/h 0000000000000000000000Water lb/h 13,826 3,830 323,747 323,747 3,752 3,752 0000000000000000Carbon Monoxide lb/h 0000000000000000000000Carbon Dioxide lb/h 55,910 51,924 0 0 2,547 2,547 0000000000000000Methane lb/h 0000000000000000000000Methanol lb/h 0000000000000000000000Formic Acid lb/h 0000000000000000000000Glyoxal lb/h 0000000000000000000000Ethylene lb/h 0000000000000000000000Acetaldehyde lb/h 0000000000000000000000Hydroxyacetaldehyde lb/h 0000000000000000000000Acetic Acid lb/h 0000000000000000000000Ethane lb/h 0000000000000000000000Propylene lb/h 00000000000000000000001‐Hydroxy‐2‐propanone lb/h 0000000000000000000000Propionic Acid lb/h 0000000000000000000000Propane lb/h 0000000000000000000000Furan lb/h 00000000000000000000001‐Butene lb/h 0000000000000000000000Tetrahydrofuran lb/h 0000000000000000000000N‐Butane lb/h 0000000000000000000000Furfural lb/h 00000000000000000000002‐methylfuran lb/h 0000000000000000000000Furfuryl Alcohol lb/h 0000000000000000000000n‐Pentane lb/h 0000000000000000000000Pentenone lb/h 0000000000000000000000Benzene lb/h 0000000000000000000000Phenol lb/h 00000000000000000000001,2‐Benzenediol lb/h 0000000000000000000000Hydroxymethylfurfural lb/h 00000000000000000000002,5‐dimethylfuran lb/h 0000000000000000000000Methyl Cyclopentenone lb/h 0000000000000000000000Hydroxymethylcyclopentenone lb/h 0000000000000000000000Cyclohexanone lb/h 0000000000000000000000Levoglucosan lb/h 00000000000000000000001‐Hexanal lb/h 0000000000000000000000Dimethoxytetrahydrofuran lb/h 0000000000000000000000Cyclohexane lb/h 0000000000000000000000N‐Hexane lb/h 0000000000000000000000Hexanol lb/h 0000000000000000000000Toluene lb/h 00000000000000000000002‐Methylphenol lb/h 00000000000000000000003‐Methyl‐phenol lb/h 0000000000000000000000Guaiacol lb/h 0000000000000000000000Methyl‐Cyclohexane lb/h 00000000000000000000002‐Methylhexane lb/h 0000000000000000000000VinylPhenol lb/h 0000000000000000000000O‐Xylene lb/h 0000000000000000000000Ethylbenzne lb/h 00000000000000000000002,3‐Dimethyl‐phenol lb/h 00000000000000000000002,6‐dimethoxyphenol lb/h 0000000000000000000000Vanillyl alcohol lb/h 00000000000000000000002,4,6‐Trimethylpyridine lb/h 0000000000000000000000Cis‐1,2‐dimethyl cyclohexane lb/h 0000000000000000000000Trans‐1,2‐dimethylcyclohexane lb/h 0000000000000000000000Ethylcyclohexane lb/h 00000000000000000000004‐Methylheptane lb/h 00000000000000000000002‐Methyl‐Benzofuran lb/h 0000000000000000000000Indane lb/h 00000000000000000000002‐methoxy‐4‐vinylphenol lb/h 0000000000000000000000Syringaldehyde lb/h 0000000000000000000000n‐Propylbenzene lb/h 0000000000000000000000Naphthalene lb/h 00000000000000000000001‐Naphthalenol lb/h 0000000000000000000000Coniferyl Aldehyde lb/h 0000000000000000000000Tetralin lb/h 0000000000000000000000Isoeugenol lb/h 0000000000000000000000Decalin lb/h 00000000000000000000002,5‐Dimethyloctane lb/h 00000000000000000000001‐Methyl naphthalene lb/h 00000000000000000000001‐methyl decahydronaphthene lb/h 0000000000000000000000Dibenzothiophene lb/h 0000000000000000000000Biphenyl lb/h 00000000000000000000005‐hexyl‐O‐cresol lb/h 0000000000000000000000n‐Heptylcyclohexane lb/h 0000000000000000000000C14H20‐N35 lb/h 0000000000000000000000C14H24‐N5 lb/h 00000000000000000000003,5‐Dimethyldodecane lb/h 0000000000000000000000C15H26‐N4 lb/h 00000000000000000000006,8‐Dimethyltridecane lb/h 00000000000000000000001,4‐Dimethyl‐Phenanthrene lb/h 0000000000000000000000N‐Cetane lb/h 0000000000000000000000C18H26O lb/h 0000000000000000000000C18H28 lb/h 0000000000000000000000C21H26O2 lb/h 0000000000000000000000C21H34 lb/h 0000000000000000000000C22H28O2 lb/h 0000000000000000000000Carbon lb/h 0000000000000000000000Sulfur lb/h 0000000000000000000000Sand/Catalyst Solids lb/h 0000000000000000000000Ash lb/h 0000000000000000000000Wood lb/h 0000000000000000000000Char lb/h 0000000000000000000000Coke lb/h 0000000000000000000000

199
Rev:

1

Project No: Drawing:

30482.00 PFD-61712-A605

THERMOCHEMICAL CONVERSION OF BIOMASS

TO HYDROCARBON FUEL

FAST PYROLYSIS AND VAPOR PHASE UPGRADING

PROCESS FLOW DIAGRAM

AREA 600: BOILER FEEDWATER PREHEAT 2

Rev. Date By Description

J:\1A - Process Solutions\30482 NREL Thermochemical Conv - Design-Model\Drawings\ 30482 Pyrolysis Ex-Situ PFDs 61712 150128.vsd Plot date: 1/29/2015

0 12/12/14 DMS ADDED HX NETWORK

H-BP-20

QHBP20

ABSORBER VAPOR

FROM H-AP-17/18/31

PFD-61712-A305

ABSORBER VAPOR

TO H-BP-11

PFD-61712-A604

BOILER FEEDWATER

FROM P-604

PFD-61712-A601

639

H-BP-21

QHBP21

FLUE GAS

TO H-BP-16

PFD-61712-A203

H-AP-31

QHAP31

ABSORBER VAPOR

FROM D-301

PFD-61712-A305

ABSORBER VAPOR

TO H-BP-20/H-BP-3

PFD-61712-A305

H-AP-33

QHAP33

WGS OUTLET

FROM H-AP-15

PFD-61712-A303

H-AP-34

HC EFFLUENT

TO H-BP-6

PFD-61712-A404

H-AP-35

QHAP35

H-AP-37

QHAP37

VPU FLUE GAS

TO H-BP-40/22/41/42

PFD-61712-A203

FLUE GAS

FROM H-AP-8

PFD-61712-A203

H-BP-22

VPU FLUE GAS

TO H-BP-17

PFD-61712-A203

VPU FLUE GAS

FROM H-AP-37

PFD-61712-A203

QHBP22

QHAP34

WGS OUTLET

TO H-BP-14/H-BP-35

PFD-61712-A303

BLOWDOWN

TO H-BP-33/37/39

PFD-61712-A603

VPU FLUE GAS

TO H-AP-38/H-AP-39

PFD-61712-A203

SATURATED WATER

TO H-AP-36

PFD-61712-A501-A

SATURATED WATER

FROM H-AP-36

PFD-61712-A501-A

H-AP-40

QHAP40

H-AP-51

QHAP51

H-AP-41

QHAP41

H-AP-55

QHAP55

H-AP-56

QHAP56

SATURATED WATER

TO H-AP-42

PFD-61712-A501-A

SATURATED WATER

FROM H-AP-42

PFD-61712-A501-A

BLOWDOWN

FROM S-601

PFD-61712-A603

HC EFFLUENT

FROM H-AP-57/H-AP-43

PFD-61712-A404

PYROLYSIS VAPOR

FROM H-AP-51

PFD-61712-A305

PYROLYSIS VAPOR

TO D-301

PFD-61712-A301

SATURATED WATER

TO H-AP-54

PFD-61712-A501-A

SATURATED WATER

FROM H-AP-54

PFD-61712-A501-A

H-AP-52

SATURATED WATER

TO H-AP-1/3/5

PFD-61712-A603

641

WGS OUTLET 372

FROM R-365

PFD-61712-A303

WGS OUTLET

TO H-AP-15

PFD-61712-A303

PYROLYSIS VAPOR

FROM H-AP-48

PFD-61712-A603

PYROLYSIS VAPOR

TO H-AP-53/56/60

PFD-61712-A305

H-BP-20

POST-ABSORBER 1

VAPOR COOLER/

BOILER FEEDWATER

PREHEAT 2

H-BP-21

CHAR COMBUSTOR

FLUE GAS COOLER/

BOILER FEEDWATER

PREHEAT 2

H-BP-22

EX-SITU CATALYST

REGEN COOLER/

BOILER FEEDWATER

PREHEAT 2

H-AP-31

POST-ABSORBER 1

VAPOR COOLER/

BOILER FEEDWATER

PREHEAT

H-AP-33

A300 WGS OUTLET

COOLER/BOILER

FEEDWATER

PREHEAT

H-AP-34

HYDROTREATER

OUTLET COOLER/

BOILER FEEDWATER

PREHEAT

H-AP-35

BOILER FEEDWATER

BLOWDOWN COOLER/

BOILER FEEDWATER

PREHEAT

H-AP-37

EX-SITU CATALYST

REGEN FLUE GAS

COOLER/BOILER

FEEDWATER PREHEAT

H-AP-40

BOILER FEEDWATER

BLOWDOWN COOLER/

BOILER FEEDWATER

PREHEAT

H-AP-41

HYDROTREATER

OUTLET COOLER/

BOILER FEEDWATER

PREHEAT

H-AP-55

BOILER FEEDWATER

BLOWDOWN COOLER/

BOILER FEEDWATER

PREHEAT

H-AP-56

PRE-ABSORBER

UPGRADED VAPOR

COOLER/BOILER

FEEDWATER PREHEAT

H-AP-52

A300 WGS OUTLET

COOLER/BOILER

FEEDWATER

PREHEAT

H-AP-51

PRE-ABSORBER

UPGRADED VAPOR

COOLER/BOILER

FEEDWATER PREHEAT

QHAP52

1 12/29/14 JAR MINOR UPDATES

200
PFD‐61712‐A605 372 639 641 

Total Flow lb/h 82,376 323,749 323,749 0000000000000000000Temperature F 637 235 582 0000000000000000000Pressure Psia 84 1401 1346 0000000000000000000Vapor Fraction 1 000000000000000000000Enthalpy Flow MMBtu/h ‐253 ‐2156 ‐2031 0000000000000000000Argon lb/h 0000000000000000000000Nitrogen lb/h 0000000000000000000000Oxygen lb/h 0000000000000000000000SO2 lb/h 0000000000000000000000NO2 lb/h 0000000000000000000000Hydrogen lb/h 7,092 000000000000000000000Ammonia lb/h 0000000000000000000000H2S lb/h 0000000000000000000000Water lb/h 21,172 323,749 323,749 0000000000000000000Carbon Monoxide lb/h 3,766 000000000000000000000Carbon Dioxide lb/h 39,180 000000000000000000000Methane lb/h 2,354 000000000000000000000Methanol lb/h 0000000000000000000000Formic Acid lb/h 0000000000000000000000Glyoxal lb/h 0000000000000000000000Ethylene lb/h 4,714 000000000000000000000Acetaldehyde lb/h 0000000000000000000000Hydroxyacetaldehyde lb/h 0000000000000000000000Acetic Acid lb/h 0000000000000000000000Ethane lb/h 0000000000000000000000Propylene lb/h 1,594 0000000000000000000001‐Hydroxy‐2‐propanone lb/h 0000000000000000000000Propionic Acid lb/h 0000000000000000000000Propane lb/h 0000000000000000000000Furan lb/h 200 0000000000000000000001‐Butene lb/h 790 000000000000000000000Tetrahydrofuran lb/h 169 000000000000000000000N‐Butane lb/h 0000000000000000000000Furfural lb/h 00000000000000000000002‐methylfuran lb/h 187 000000000000000000000Furfuryl Alcohol lb/h 0000000000000000000000n‐Pentane lb/h 0000000000000000000000Pentenone lb/h 0000000000000000000000Benzene lb/h 0000000000000000000000Phenol lb/h 45 0000000000000000000001,2‐Benzenediol lb/h 49 000000000000000000000Hydroxymethylfurfural lb/h 00000000000000000000002,5‐dimethylfuran lb/h 1 000000000000000000000Methyl Cyclopentenone lb/h 0000000000000000000000Hydroxymethylcyclopentenone lb/h 0000000000000000000000Cyclohexanone lb/h 0000000000000000000000Levoglucosan lb/h 00000000000000000000001‐Hexanal lb/h 0000000000000000000000Dimethoxytetrahydrofuran lb/h 0 000000000000000000000Cyclohexane lb/h 670 000000000000000000000N‐Hexane lb/h 0000000000000000000000Hexanol lb/h 0000000000000000000000Toluene lb/h 00000000000000000000002‐Methylphenol lb/h 0 0000000000000000000003‐Methyl‐phenol lb/h 0000000000000000000000Guaiacol lb/h 0 000000000000000000000Methyl‐Cyclohexane lb/h 76 0000000000000000000002‐Methylhexane lb/h 0000000000000000000000VinylPhenol lb/h 0 000000000000000000000O‐Xylene lb/h 0000000000000000000000Ethylbenzne lb/h 00000000000000000000002,3‐Dimethyl‐phenol lb/h 2 0000000000000000000002,6‐dimethoxyphenol lb/h 0 000000000000000000000Vanillyl alcohol lb/h 0 0000000000000000000002,4,6‐Trimethylpyridine lb/h 1 000000000000000000000Cis‐1,2‐dimethyl cyclohexane lb/h 118 000000000000000000000Trans‐1,2‐dimethylcyclohexane lb/h 194 000000000000000000000Ethylcyclohexane lb/h 00000000000000000000004‐Methylheptane lb/h 00000000000000000000002‐Methyl‐Benzofuran lb/h 0 000000000000000000000Indane lb/h 00000000000000000000002‐methoxy‐4‐vinylphenol lb/h 0 000000000000000000000Syringaldehyde lb/h 0000000000000000000000n‐Propylbenzene lb/h 0000000000000000000000Naphthalene lb/h 00000000000000000000001‐Naphthalenol lb/h 0 000000000000000000000Coniferyl Aldehyde lb/h 0 000000000000000000000Tetralin lb/h 0000000000000000000000Isoeugenol lb/h 0 000000000000000000000Decalin lb/h 0 0000000000000000000002,5‐Dimethyloctane lb/h 00000000000000000000001‐Methyl naphthalene lb/h 0 0000000000000000000001‐methyl decahydronaphthene lb/h 0 000000000000000000000Dibenzothiophene lb/h 0 000000000000000000000Biphenyl lb/h 00000000000000000000005‐hexyl‐O‐cresol lb/h 0 000000000000000000000n‐Heptylcyclohexane lb/h 0000000000000000000000C14H20‐N35 lb/h 0000000000000000000000C14H24‐N5 lb/h 0 0000000000000000000003,5‐Dimethyldodecane lb/h 0000000000000000000000C15H26‐N4 lb/h 0 0000000000000000000006,8‐Dimethyltridecane lb/h 00000000000000000000001,4‐Dimethyl‐Phenanthrene lb/h 0000000000000000000000N‐Cetane lb/h 0000000000000000000000C18H26O lb/h 0 000000000000000000000C18H28 lb/h 0000000000000000000000C21H26O2 lb/h 0 000000000000000000000C21H34 lb/h 0 000000000000000000000C22H28O2 lb/h 0 000000000000000000000Carbon lb/h 0000000000000000000000Sulfur lb/h 0000000000000000000000Sand/Catalyst Solids lb/h 0000000000000000000000Ash lb/h 0000000000000000000000Wood lb/h 0000000000000000000000Char lb/h 0000000000000000000000Coke lb/h 0000000000000000000000

201
BLOWDOWN

FROM H-603

PFD-61712-A601

Rev:

2

Project No: Drawing:

30482.00 PFD-61712-A701

THERMOCHEMICAL CONVERSION OF BIOMASS

TO HYDROCARBON FUEL

FAST PYROLYSIS AND VAPOR PHASE UPGRADING

PROCESS FLOW DIAGRAM

AREA 700: COOLING WATER & FLUE GAS SCRUBBER

Rev. Date By Description

P-708

FLUE GAS SCRUBBER

CIRCULATION PUMP

M-703

FLUE GAS

SCRUBBER

P-701

COOLING TOWER

CHEMICALS

WP701

M-703

P-708

MAKE-UP WATER

FLUE GAS

FROM K-101

PFD-61712-A102

NAOH

FROM P-705

PFD-61712-A702

M-704

715

M-701

718

M-704

FLUE GAS

STACK

M-701

COOLING

TOWER SYSTEM

P-701

COOLING

WATER PUMP

J:\1A - Process Solutions\30482 NREL Thermochemical Conv - Design-Model\Drawings\ 30482 Pyrolysis Ex-Situ PFDs 61712 150128.vsd Plot date: 1/29/2015

0 9/29/14 JAR ISSUED FOR DESIGN REPORT

600

ATM

ATM

DRIFT

ATM

EVAP

WM701

110

MAKE-UP WATER

TO P-601

PFD-61712-A601

618

CT BLOWDOWN

TO T-860

PFD-61712-A804

713

BLOWDOWN

TO T-860

PFD-61712-A804

124

SAND FILTER FILTRATE

FROM M-807

PFD-61712-A803

MAKE-UP WATER

TO P-815

PFD-61712-A801

815

1 12/12/14 DMS ADDED HX NETWORK

CW USERS

H-314

H-374

K-390

H-413C

H-444

H-445

H-454

H-457C

H-459

H-463C

H-494

H-495

H-568C

K-580

H-603

M-708

CWS

TO HEADER

CWR

FROM HEADER

2 12/29/14 JAR MINOR UPDATES

QM701

202
PFD‐61712‐A701 110 124 600 618 713 715 718 815 

Total Flow lb/h 770,436 23,429 6,475 6,473 10,937 2,618,485 2,618,485 1,926 00000000000000Temperature F 160 123 113 60 90 90 110 60 00000000000000Pressure Psia 16 15 15 15 15 75 60 15 00000000000000Vapor Fraction 1 000000000000000000000Enthalpy Flow MMBtu/h ‐1005 ‐160 ‐44 ‐44 ‐75 ‐17932 ‐17876 ‐13 00000000000000Argon lb/h 8,183 0 00000000000000000000Nitrogen lb/h 480,047 0 00000000000000000000Oxygen lb/h 38,240 0 00000000000000000000SO2 lb/h 107 0 00000000000000000000NO2 lb/h 17 0 00000000000000000000Hydrogen lb/h 0000000000000000000000Ammonia lb/h 0000000000000000000000H2S lb/h 0000000000000000000000Water lb/h 42,895 23,429 6,475 6,473 10,937 2,618,485 2,618,485 1,926 00000000000000Carbon Monoxide lb/h 0000000000000000000000Carbon Dioxide lb/h 200,947 0 00000000000000000000Methane lb/h 0000000000000000000000Methanol lb/h 0000000000000000000000Formic Acid lb/h 0000000000000000000000Glyoxal lb/h 0000000000000000000000Ethylene lb/h 0000000000000000000000Acetaldehyde lb/h 0000000000000000000000Hydroxyacetaldehyde lb/h 0000000000000000000000Acetic Acid lb/h 0000000000000000000000Ethane lb/h 0000000000000000000000Propylene lb/h 00000000000000000000001‐Hydroxy‐2‐propanone lb/h 0000000000000000000000Propionic Acid lb/h 0000000000000000000000Propane lb/h 0000000000000000000000Furan lb/h 00000000000000000000001‐Butene lb/h 0000000000000000000000Tetrahydrofuran lb/h 0000000000000000000000N‐Butane lb/h 0000000000000000000000Furfural lb/h 00000000000000000000002‐methylfuran lb/h 0000000000000000000000Furfuryl Alcohol lb/h 0000000000000000000000n‐Pentane lb/h 0000000000000000000000Pentenone lb/h 0000000000000000000000Benzene lb/h 0000000000000000000000Phenol lb/h 00000000000000000000001,2‐Benzenediol lb/h 0000000000000000000000Hydroxymethylfurfural lb/h 00000000000000000000002,5‐dimethylfuran lb/h 0000000000000000000000Methyl Cyclopentenone lb/h 0000000000000000000000Hydroxymethylcyclopentenone lb/h 0000000000000000000000Cyclohexanone lb/h 0000000000000000000000Levoglucosan lb/h 00000000000000000000001‐Hexanal lb/h 0000000000000000000000Dimethoxytetrahydrofuran lb/h 0000000000000000000000Cyclohexane lb/h 0000000000000000000000N‐Hexane lb/h 0000000000000000000000Hexanol lb/h 0000000000000000000000Toluene lb/h 00000000000000000000002‐Methylphenol lb/h 00000000000000000000003‐Methyl‐phenol lb/h 0000000000000000000000Guaiacol lb/h 0000000000000000000000Methyl‐Cyclohexane lb/h 00000000000000000000002‐Methylhexane lb/h 0000000000000000000000VinylPhenol lb/h 0000000000000000000000O‐Xylene lb/h 0000000000000000000000Ethylbenzne lb/h 00000000000000000000002,3‐Dimethyl‐phenol lb/h 00000000000000000000002,6‐dimethoxyphenol lb/h 0000000000000000000000Vanillyl alcohol lb/h 00000000000000000000002,4,6‐Trimethylpyridine lb/h 0000000000000000000000Cis‐1,2‐dimethyl cyclohexane lb/h 0000000000000000000000Trans‐1,2‐dimethylcyclohexane lb/h 0000000000000000000000Ethylcyclohexane lb/h 00000000000000000000004‐Methylheptane lb/h 00000000000000000000002‐Methyl‐Benzofuran lb/h 0000000000000000000000Indane lb/h 00000000000000000000002‐methoxy‐4‐vinylphenol lb/h 0000000000000000000000Syringaldehyde lb/h 0000000000000000000000n‐Propylbenzene lb/h 0000000000000000000000Naphthalene lb/h 00000000000000000000001‐Naphthalenol lb/h 0000000000000000000000Coniferyl Aldehyde lb/h 0000000000000000000000Tetralin lb/h 0000000000000000000000Isoeugenol lb/h 0000000000000000000000Decalin lb/h 00000000000000000000002,5‐Dimethyloctane lb/h 00000000000000000000001‐Methyl naphthalene lb/h 00000000000000000000001‐methyl decahydronaphthene lb/h 0000000000000000000000Dibenzothiophene lb/h 0000000000000000000000Biphenyl lb/h 00000000000000000000005‐hexyl‐O‐cresol lb/h 0000000000000000000000n‐Heptylcyclohexane lb/h 0000000000000000000000C14H20‐N35 lb/h 0000000000000000000000C14H24‐N5 lb/h 00000000000000000000003,5‐Dimethyldodecane lb/h 0000000000000000000000C15H26‐N4 lb/h 00000000000000000000006,8‐Dimethyltridecane lb/h 00000000000000000000001,4‐Dimethyl‐Phenanthrene lb/h 0000000000000000000000N‐Cetane lb/h 0000000000000000000000C18H26O lb/h 0000000000000000000000C18H28 lb/h 0000000000000000000000C21H26O2 lb/h 0000000000000000000000C21H34 lb/h 0000000000000000000000C22H28O2 lb/h 0000000000000000000000Carbon lb/h 0000000000000000000000Sulfur lb/h 0000000000000000000000Sand/Catalyst Solids lb/h 0000000000000000000000Ash lb/h 0000000000000000000000Wood lb/h 0000000000000000000000Char lb/h 0000000000000000000000Coke lb/h 0000000000000000000000

203
Rev:

1

Project No: Drawing:

30482.00 PFD-61712-A702

THERMOCHEMICAL CONVERSION OF BIOMASS

TO HYDROCARBON FUEL

FAST PYROLYSIS AND VAPOR PHASE UPGRADING

PROCESS FLOW DIAGRAM

AREA 700: MATERIALS STORAGE

Rev. Date By Description

0

TO FIRE SUPPRESSION

SYSTEM

WATER

FRONT-END LOADERS

T-708

BFW CHEMICAL

STORAGE TANK

M-702

HYDRAULIC TRUCK DUMP

WITH SCALE

OLIVINE

TO T-217

PFD-61712-A201

PURCHASED DIESEL

T-702

FIREWATER

STORAGE TANK

T-703

PURCHASED DIESEL

STORAGE TANK

T-705

CAUSTIC

STORAGE TANK

P-703

DIESEL

PUMP

P-702

FIREWATER

PUMP

T-702

P-702

AMMONIA

BFW CHEMICALS

T-703

P-703

T-704

P-704

AMMONIA

TO T-603

PFD-61712-A601

MAKEUP CATALYST

TO T-267

PFD-61712-A202

BFW CHEMICALS

TO T-603

PFD-61712-A601

OLIVINE + CATALYST

M-702

T-708

P-707

NAOH T-705

P-705

NAOH

TO P-708

PFD-61712-A701

T-704

AMMONIA

STORAGE TANK

P-704

AMMONIA

PUMP

P-705

CAUSTIC

PUMP

P-707

BFW CHEMICAL

PUMP

J:\1A - Process Solutions\30482 NREL Thermochemical Conv - Design-Model\Drawings\ 30482 Pyrolysis Ex-Situ PFDs 61712 150316.vsd Plot date: 3/16/2015

9/29/14 JAR ISSUED FOR DESIGN REPORT

1 12/12/14 DMS ADDED HX NETWORK

217P

277

204
PFD‐61712‐A702 

Total Flow lb/h 0000000000000000000000Temperature F 0000000000000000000000Pressure Psia 0000000000000000000000Vapor Fraction 0000000000000000000000Enthalpy Flow MMBtu/h 0000000000000000000000Argon lb/h 0000000000000000000000Nitrogen lb/h 0000000000000000000000Oxygen lb/h 0000000000000000000000SO2 lb/h 0000000000000000000000NO2 lb/h 0000000000000000000000Hydrogen lb/h 0000000000000000000000Ammonia lb/h 0000000000000000000000H2S lb/h 0000000000000000000000Water lb/h 0000000000000000000000Carbon Monoxide lb/h 0000000000000000000000Carbon Dioxide lb/h 0000000000000000000000Methane lb/h 0000000000000000000000Methanol lb/h 0000000000000000000000Formic Acid lb/h 0000000000000000000000Glyoxal lb/h 0000000000000000000000Ethylene lb/h 0000000000000000000000Acetaldehyde lb/h 0000000000000000000000Hydroxyacetaldehyde lb/h 0000000000000000000000Acetic Acid lb/h 0000000000000000000000Ethane lb/h 0000000000000000000000Propylene lb/h 00000000000000000000001‐Hydroxy‐2‐propanone lb/h 0000000000000000000000Propionic Acid lb/h 0000000000000000000000Propane lb/h 0000000000000000000000Furan lb/h 00000000000000000000001‐Butene lb/h 0000000000000000000000Tetrahydrofuran lb/h 0000000000000000000000N‐Butane lb/h 0000000000000000000000Furfural lb/h 00000000000000000000002‐methylfuran lb/h 0000000000000000000000Furfuryl Alcohol lb/h 0000000000000000000000n‐Pentane lb/h 0000000000000000000000Pentenone lb/h 0000000000000000000000Benzene lb/h 0000000000000000000000Phenol lb/h 00000000000000000000001,2‐Benzenediol lb/h 0000000000000000000000Hydroxymethylfurfural lb/h 00000000000000000000002,5‐dimethylfuran lb/h 0000000000000000000000Methyl Cyclopentenone lb/h 0000000000000000000000Hydroxymethylcyclopentenone lb/h 0000000000000000000000Cyclohexanone lb/h 0000000000000000000000Levoglucosan lb/h 00000000000000000000001‐Hexanal lb/h 0000000000000000000000Dimethoxytetrahydrofuran lb/h 0000000000000000000000Cyclohexane lb/h 0000000000000000000000N‐Hexane lb/h 0000000000000000000000Hexanol lb/h 0000000000000000000000Toluene lb/h 00000000000000000000002‐Methylphenol lb/h 00000000000000000000003‐Methyl‐phenol lb/h 0000000000000000000000Guaiacol lb/h 0000000000000000000000Methyl‐Cyclohexane lb/h 00000000000000000000002‐Methylhexane lb/h 0000000000000000000000VinylPhenol lb/h 0000000000000000000000O‐Xylene lb/h 0000000000000000000000Ethylbenzne lb/h 00000000000000000000002,3‐Dimethyl‐phenol lb/h 00000000000000000000002,6‐dimethoxyphenol lb/h 0000000000000000000000Vanillyl alcohol lb/h 00000000000000000000002,4,6‐Trimethylpyridine lb/h 0000000000000000000000Cis‐1,2‐dimethyl cyclohexane lb/h 0000000000000000000000Trans‐1,2‐dimethylcyclohexane lb/h 0000000000000000000000Ethylcyclohexane lb/h 00000000000000000000004‐Methylheptane lb/h 00000000000000000000002‐Methyl‐Benzofuran lb/h 0000000000000000000000Indane lb/h 00000000000000000000002‐methoxy‐4‐vinylphenol lb/h 0000000000000000000000Syringaldehyde lb/h 0000000000000000000000n‐Propylbenzene lb/h 0000000000000000000000Naphthalene lb/h 00000000000000000000001‐Naphthalenol lb/h 0000000000000000000000Coniferyl Aldehyde lb/h 0000000000000000000000Tetralin lb/h 0000000000000000000000Isoeugenol lb/h 0000000000000000000000Decalin lb/h 00000000000000000000002,5‐Dimethyloctane lb/h 00000000000000000000001‐Methyl naphthalene lb/h 00000000000000000000001‐methyl decahydronaphthene lb/h 0000000000000000000000Dibenzothiophene lb/h 0000000000000000000000Biphenyl lb/h 00000000000000000000005‐hexyl‐O‐cresol lb/h 0000000000000000000000n‐Heptylcyclohexane lb/h 0000000000000000000000C14H20‐N35 lb/h 0000000000000000000000C14H24‐N5 lb/h 00000000000000000000003,5‐Dimethyldodecane lb/h 0000000000000000000000C15H26‐N4 lb/h 00000000000000000000006,8‐Dimethyltridecane lb/h 00000000000000000000001,4‐Dimethyl‐Phenanthrene lb/h 0000000000000000000000N‐Cetane lb/h 0000000000000000000000C18H26O lb/h 0000000000000000000000C18H28 lb/h 0000000000000000000000C21H26O2 lb/h 0000000000000000000000C21H34 lb/h 0000000000000000000000C22H28O2 lb/h 0000000000000000000000Carbon lb/h 0000000000000000000000Sulfur lb/h 0000000000000000000000Sand/Catalyst Solids lb/h 0000000000000000000000Ash lb/h 0000000000000000000000Wood lb/h 0000000000000000000000Char lb/h 0000000000000000000000Coke lb/h 0000000000000000000000

205
T-701

PLANT AIR

RECEIVER

S-701

INSTRUMENT

AIR DRYER

K-701

PLANT AIR

COMPRESSOR

Rev:

2

Project No: Drawing:

30482.00 PFD-61712-A703

THERMOCHEMICAL CONVERSION OF BIOMASS

TO HYDROCARBON FUEL

FAST PYROLYSIS AND VAPOR PHASE UPGRADING

PROCESS FLOW DIAGRAM

AREA 700: UTILITIES AND PRODUCT LOADOUT

Rev. Date By Description

0 9/29/14 JAR ISSUED FOR DESIGN REPORT

J:\1A - Process Solutions\30482 NREL Thermochemical Conv - Design-Model\Drawings\ 30482 Pyrolysis Ex-Situ PFDs 61712 150128.vsd Plot date: 1/29/2015

P-790

GASOLINE

T-790

GASOLINE PRODUCT

FROM H-454

PFD-61712-A402

M-710

DIESEL PRODUCT

FROM H-457C

PFD-61712-A402

T-792

P-792 DIESEL

K-701

S-701 T-701

INSTRUMENT AIR

TO DISTRIBUTION

PLANT AND INSTRUMENT AIR SYSTEM

PLANT AIR

TO DISTRIBUTION

453

456

T-792

DIESEL PRODUCT

STORAGE TANK

P-792

DIESEL PRODUCT

PUMP

T-790

GASOLINE PRODUCT

STORAGE TANK

M-710

PRODUCT

LOADING RACK

P-790

GASOLINE PRODUCT

PUMP

M-708

CHILLED WATER

SYSTEM

CHILLED WATER SYSTEM

1 12/12/14 DMS ADDED HX NETWORK

CHILLED WATER

RETURN FROM

HEADER

CHILLED WATER

SUPPLY TO

HEADER

M-708

Q-M708 CHW USERS

H-316

H-326

2 12/29/14 JAR MINOR UPDATES

CWS

CWR

206
PFD‐61712‐A703 453 456 

Total Flow lb/h 20,408 24,739 00000000000000000000Temperature F 60 60 00000000000000000000Pressure Psia 15 15 00000000000000000000Vapor Fraction 0000000000000000000000Enthalpy Flow MMBtu/h ‐15 ‐16 00000000000000000000Argon lb/h 0000000000000000000000Nitrogen lb/h 0000000000000000000000Oxygen lb/h 0000000000000000000000SO2 lb/h 0000000000000000000000NO2 lb/h 0000000000000000000000Hydrogen lb/h 0 0 00000000000000000000Ammonia lb/h 2 000000000000000000000H2S lb/h 2 000000000000000000000Water lb/h 168 0 00000000000000000000Carbon Monoxide lb/h 0 0 00000000000000000000Carbon Dioxide lb/h 11 0 00000000000000000000Methane lb/h 1 0 00000000000000000000Methanol lb/h 0000000000000000000000Formic Acid lb/h 0000000000000000000000Glyoxal lb/h 0000000000000000000000Ethylene lb/h 1 0 00000000000000000000Acetaldehyde lb/h 0000000000000000000000Hydroxyacetaldehyde lb/h 0000000000000000000000Acetic Acid lb/h 0000000000000000000000Ethane lb/h 28 0 00000000000000000000Propylene lb/h 0 0000000000000000000001‐Hydroxy‐2‐propanone lb/h 0000000000000000000000Propionic Acid lb/h 0000000000000000000000Propane lb/h 11 000000000000000000000Furan lb/h 00000000000000000000001‐Butene lb/h 4 000000000000000000000Tetrahydrofuran lb/h 0000000000000000000000N‐Butane lb/h 311 000000000000000000000Furfural lb/h 00000000000000000000002‐methylfuran lb/h 0000000000000000000000Furfuryl Alcohol lb/h 0000000000000000000000n‐Pentane lb/h 321 000000000000000000000Pentenone lb/h 0000000000000000000000Benzene lb/h 1,321 0 00000000000000000000Phenol lb/h 18 0 000000000000000000001,2‐Benzenediol lb/h 0000000000000000000000Hydroxymethylfurfural lb/h 00000000000000000000002,5‐dimethylfuran lb/h 0 000000000000000000000Methyl Cyclopentenone lb/h 0000000000000000000000Hydroxymethylcyclopentenone lb/h 0000000000000000000000Cyclohexanone lb/h 0000000000000000000000Levoglucosan lb/h 00000000000000000000001‐Hexanal lb/h 0000000000000000000000Dimethoxytetrahydrofuran lb/h 0000000000000000000000Cyclohexane lb/h 3,526 0 00000000000000000000N‐Hexane lb/h 1,942 0 00000000000000000000Hexanol lb/h 0000000000000000000000Toluene lb/h 445 0 000000000000000000002‐Methylphenol lb/h 00000000000000000000003‐Methyl‐phenol lb/h 0000000000000000000000Guaiacol lb/h 0000000000000000000000Methyl‐Cyclohexane lb/h 829 0 000000000000000000002‐Methylhexane lb/h 1,645 1 00000000000000000000VinylPhenol lb/h 0000000000000000000000O‐Xylene lb/h 1,501 0 00000000000000000000Ethylbenzne lb/h 135 0 000000000000000000002,3‐Dimethyl‐phenol lb/h 00000000000000000000002,6‐dimethoxyphenol lb/h 0000000000000000000000Vanillyl alcohol lb/h 00000000000000000000002,4,6‐Trimethylpyridine lb/h 0000000000000000000000Cis‐1,2‐dimethyl cyclohexane lb/h 2,524 0 00000000000000000000Trans‐1,2‐dimethylcyclohexane lb/h 4,156 0 00000000000000000000Ethylcyclohexane lb/h 384 0 000000000000000000004‐Methylheptane lb/h 301 0 000000000000000000002‐Methyl‐Benzofuran lb/h 0000000000000000000000Indane lb/h 00000000000000000000002‐methoxy‐4‐vinylphenol lb/h 0000000000000000000000Syringaldehyde lb/h 0000000000000000000000n‐Propylbenzene lb/h 10 0 00000000000000000000Naphthalene lb/h 120 26 000000000000000000001‐Naphthalenol lb/h 0000000000000000000000Coniferyl Aldehyde lb/h 0000000000000000000000Tetralin lb/h 58 3 00000000000000000000Isoeugenol lb/h 0000000000000000000000Decalin lb/h 200 9 000000000000000000002,5‐Dimethyloctane lb/h 114 3 000000000000000000001‐Methyl naphthalene lb/h 5 191 000000000000000000001‐methyl decahydronaphthene lb/h 222 76 00000000000000000000Dibenzothiophene lb/h 0000000000000000000000Biphenyl lb/h 0 61 000000000000000000005‐hexyl‐O‐cresol lb/h 0000000000000000000000n‐Heptylcyclohexane lb/h 22 4,440 00000000000000000000C14H20‐N35 lb/h 1 933 00000000000000000000C14H24‐N5 lb/h 1 3,309 000000000000000000003,5‐Dimethyldodecane lb/h 65 4,632 00000000000000000000C15H26‐N4 lb/h 2 3,177 000000000000000000006,8‐Dimethyltridecane lb/h 0 2,946 000000000000000000001,4‐Dimethyl‐Phenanthrene lb/h 0 34 00000000000000000000N‐Cetane lb/h 0 162 00000000000000000000C18H26O lb/h 0000000000000000000000C18H28 lb/h 0 4,656 00000000000000000000C21H26O2 lb/h 0 0 00000000000000000000C21H34 lb/h 0 78 00000000000000000000C22H28O2 lb/h 0 0 00000000000000000000Carbon lb/h 0000000000000000000000Sulfur lb/h 0000000000000000000000Sand/Catalyst Solids lb/h 0000000000000000000000Ash lb/h 0000000000000000000000Wood lb/h 0000000000000000000000Char lb/h 0000000000000000000000Coke lb/h 0000000000000000000000

207
P-810

811

813

814

P-812

LP STEAM

TO H-AP-53

PFD-61712-A303

W-P810

W-P812

Rev:

1

Project No: Drawing:

30482.00 PFD-61712-A801

THERMOCHEMICAL CONVERSION OF BIOMASS

TO HYDROCARBON FUEL

FAST PYROLYSIS AND VAPOR PHASE UPGRADING

PROCESS FLOW DIAGRAM

AREA 800: WASTEWATER MANAGEMENT

Rev. Date By Description

0 9/29/14 JAR ISSUED FOR DESIGN REPORT

P-810

BOILER

CHARGE PUMP

T-812

STEAM

DRUM

J:\1A - Process Solutions\30482 NREL Thermochemical Conv - Design-Model\Drawings\ 30482 Pyrolysis Ex-Situ PFDs 61712 150128.vsd Plot date: 1/29/2015

AQUEOUS PHASE

FROM S-329

PFD-61712-A302

334

T-810

BOILER FEED TANK

T-810

P-815

W-P815

MAKEUP WATER

FROM

PFD-61712-A701

P-815

BOILER MAKEUP

PUMP

815

825

P-822

W-P822

T-814

822

P-814

W-P814

CONC WASTEWATER

TO K-831

PFD-61712-A802

LP STEAM

TO H-AP-44

PFD-61712-A502

823

P-814

BOILER

CHARGE PUMP

T-822

STEAM

DRUM

P-822

CONCENTRATED

WASTEWATER PUMP

T-814

BOILER FEED TANK

T-812

T-822

P-812

CONDENSATE

PUMP

1 12/12/14 DMS ADDED HX NETWORK

MAKEUP WATER

TO H-BP-49

PFD-61712-A404

816B

WASTEWATER

TO H-BP-10

PFD-61712-A805

WASTEWATER

FROM H-AP-59/61/62

PFD-61712-A805

BOILER FEEDWATER

TO H-AP-57/58/60/63

PFD-61712-A805

BOILER FEEDWATER

FROM H-AP-57/58/60/63

PFD-61712-A805

MAKEUP WATER

FROM H-BP-49

PFD-61712-A404

H-BP-42

QHBP42

H-BP-43

QHBP43

MAKEUP WATER

TO H-AP-11

PFD-61712-A603

MAKEUP WATER

FROM H-AP-11

PFD-61712-A603

VPU FLUE GAS

FROM H-AP-37

PFD-61712-A203

VPU FLUE GAS

TO H-BP-17

PFD-61712-A203

ABSORBER BOTTOMS

FROM H-AP-23

PFD-61712-A305

ABSORBER BOTTOMS

TO H-BP-31

PFD-61712-A305

H-BP-42

EX-SITU CATALYST REGEN

FLUE GAS COOLER/WATER

PREHEAT FOR MIX WITH

WW FOR STEAM

H-BP-43

ABSORBER 1 BOTTOMS

COOLER/WATER PREHEAT

FOR MIX WITH WW FOR

STEAM

208
PFD‐61712‐A801 334 811 812 813 814 815 816B 822 823 825 

Total Flow lb/h 77,811 77,811 77,811 30,755 47,057 1,926 1,926 48,983 46,210 2,772 000000000000Temperature F 86 86 359 354 354 60 350 354 356 356 000000000000Pressure Psia 100 160 150 140 145 15 150 145 135 140 000000000000Vapor Fraction 0 0 0 1 0000 1 0000000000000Enthalpy Flow MMBtu/h ‐523 ‐523 ‐500 ‐174 ‐299 ‐13 ‐13 ‐312 ‐258 ‐13 000000000000Argon lb/h 0000000000000000000000Nitrogen lb/h 0000000000000000000000Oxygen lb/h 0000000000000000000000SO2 lb/h 0000000000000000000000NO2 lb/h 0000000000000000000000Hydrogen lb/h 00000 0 0 000 000000000000Ammonia lb/h 0000000000000000000000H2S lb/h 0000000000000000000000Water lb/h 75,955 75,955 75,955 30,663 45,292 1,926 1,926 47,218 45,491 1,727 000000000000Carbon Monoxide lb/h 00000 0 0 000 000000000000Carbon Dioxide lb/h 22220 0 0 000 000000000000Methane lb/h 00000 0 0 000 000000000000Methanol lb/h 0000000000000000000000Formic Acid lb/h 0000000000000000000000Glyoxal lb/h 0000000000000000000000Ethylene lb/h 00000 0 0 000 000000000000Acetaldehyde lb/h 0000000000000000000000Hydroxyacetaldehyde lb/h 0000000000000000000000Acetic Acid lb/h 0000000000000000000000Ethane lb/h 0000000000000000000000Propylene lb/h 00000 0 0 000 0000000000001‐Hydroxy‐2‐propanone lb/h 0000000000000000000000Propionic Acid lb/h 0000000000000000000000Propane lb/h 0000000000000000000000Furan lb/h 00000 0 0 000 0000000000001‐Butene lb/h 00000 0 0 000 000000000000Tetrahydrofuran lb/h 00000 0 0 000 000000000000N‐Butane lb/h 0000000000000000000000Furfural lb/h 00000000000000000000002‐methylfuran lb/h 00000 0 0 000 000000000000Furfuryl Alcohol lb/h 0000000000000000000000n‐Pentane lb/h 0000000000000000000000Pentenone lb/h 0000000000000000000000Benzene lb/h 0000000000000000000000Phenol lb/h 73 73 73 40 33 0 0 33 31 2 0000000000001,2‐Benzenediol lb/h 1,778 1,778 1,778 49 1,729 0 0 1,729 686 1,043 000000000000Hydroxymethylfurfural lb/h 00000000000000000000002,5‐dimethylfuran lb/h 00000 0 0 000 000000000000Methyl Cyclopentenone lb/h 0000000000000000000000Hydroxymethylcyclopentenone lb/h 0000000000000000000000Cyclohexanone lb/h 0000000000000000000000Levoglucosan lb/h 00000000000000000000001‐Hexanal lb/h 0000000000000000000000Dimethoxytetrahydrofuran lb/h 00000 0 0 0 00000000000000Cyclohexane lb/h 00000 0 0 000 000000000000N‐Hexane lb/h 0000000000000000000000Hexanol lb/h 0000000000000000000000Toluene lb/h 00000000000000000000002‐Methylphenol lb/h 00000 0 0 000 0000000000003‐Methyl‐phenol lb/h 0000000000000000000000Guaiacol lb/h 00000 0 0 000 000000000000Methyl‐Cyclohexane lb/h 00000 0 0 000 0000000000002‐Methylhexane lb/h 0000000000000000000000VinylPhenol lb/h 00000 0 0 000 000000000000O‐Xylene lb/h 0000000000000000000000Ethylbenzne lb/h 00000000000000000000002,3‐Dimethyl‐phenol lb/h 11110 0 0 000 0000000000002,6‐dimethoxyphenol lb/h 00000 0 0 000 000000000000Vanillyl alcohol lb/h 33302 0 0 221 0000000000002,4,6‐Trimethylpyridine lb/h 00000 0 0 0 00000000000000Cis‐1,2‐dimethyl cyclohexane lb/h 00000 0 0 0 00000000000000Trans‐1,2‐dimethylcyclohexane lb/h 00000 0 0 0 00000000000000Ethylcyclohexane lb/h 00000000000000000000004‐Methylheptane lb/h 00000000000000000000002‐Methyl‐Benzofuran lb/h 00000 0 0 000 000000000000Indane lb/h 00000000000000000000002‐methoxy‐4‐vinylphenol lb/h 00000 0 0 000 000000000000Syringaldehyde lb/h 0000000000000000000000n‐Propylbenzene lb/h 0000000000000000000000Naphthalene lb/h 00000000000000000000001‐Naphthalenol lb/h 00000 0 0 000 000000000000Coniferyl Aldehyde lb/h 00000 0 0 000 000000000000Tetralin lb/h 0000000000000000000000Isoeugenol lb/h 00000 0 0 000 000000000000Decalin lb/h 000 00000000000000000002,5‐Dimethyloctane lb/h 00000000000000000000001‐Methyl naphthalene lb/h 00000 0 0 000 0000000000001‐methyl decahydronaphthene lb/h 000 0000000000000000000Dibenzothiophene lb/h 00000 0 0 000 000000000000Biphenyl lb/h 00000000000000000000005‐hexyl‐O‐cresol lb/h 000 0000000000000000000n‐Heptylcyclohexane lb/h 0000000000000000000000C14H20‐N35 lb/h 0000000000000000000000C14H24‐N5 lb/h 000 00000000000000000003,5‐Dimethyldodecane lb/h 0000000000000000000000C15H26‐N4 lb/h 000 00000000000000000006,8‐Dimethyltridecane lb/h 00000000000000000000001,4‐Dimethyl‐Phenanthrene lb/h 000 0000000000000000000N‐Cetane lb/h 0000000000000000000000C18H26O lb/h 000 0000000000000000000C18H28 lb/h 0000000000000000000000C21H26O2 lb/h 000 0000000000000000000C21H34 lb/h 000 0000000000000000000C22H28O2 lb/h 000 0000000000000000000Carbon lb/h 0000000000000000000000Sulfur lb/h 0000000000000000000000Sand/Catalyst Solids lb/h 0000000000000000000000Ash lb/h 0000000000000000000000Wood lb/h 0000000000000000000000Char lb/h 0000000000000000000000Coke lb/h 0000000000000000000000

209
M-833

832

841 FLUE GAS

TO M-104

PFD-61712-A102

K-831

NATURAL GAS

FROM UTILITY

COMBUSTION AIR

825

W-K831

Rev:

1

Project No: Drawing:

30482.00 PFD-61712-A802

THERMOCHEMICAL CONVERSION OF BIOMASS

TO HYDROCARBON FUEL

FAST PYROLYSIS AND VAPOR PHASE UPGRADING

PROCESS FLOW DIAGRAM

AREA 800: AQUEOUS RTO

Rev. Date By Description

0 9/29/14 JAR ISSUED FOR DESIGN REPORT

M-833

AQUEOUS REGENERATIVE

THERMAL OXIDIZER

K-831

RTO

BLOWER

J:\1A - Process Solutions\30482 NREL Thermochemical Conv - Design-Model\Drawings\ 30482 Pyrolysis Ex-Situ PFDs 61712 150128.vsd Plot date: 1/29/2015

CONC WASTE WATER

FROM P-822

PFD-61712-A801

1 12/12/14 DMS ADDED HX NETWORK

H-840

QH840

FLUE GAS

TO H-AP-62/H-AP-63

PFD-61712-A805

FLUE GAS

FROM H-AP-62/H-AP-63

PFD-61712-A805

838

FLUE GAS

TO H-BP-13

PFD-61712-A604

FLUE GAS

FROM H-BP-13

PFD-61712-A604

840

H-840

RTO FEED/EFFLUENT

EXCHANGER

210
PFD‐61712‐A802 825 832 838 840 841 

Total Flow lb/h 2,772 77,492 80,265 80,265 80,265 00000000000000000Temperature F 356 90 863 269 245 00000000000000000Pressure Psia 140 15 22 19 17 00000000000000000Vapor Fraction 0 1111 00000000000000000Enthalpy Flow MMBtu/h ‐13 ‐9 ‐15 ‐28 ‐28 00000000000000000Argon lb/h 0 979 979 979 979 00000000000000000Nitrogen lb/h 0 57,382 57,382 57,382 57,382 00000000000000000Oxygen lb/h 0 17,582 15,606 15,606 15,606 00000000000000000SO2 lb/h 0 0 000 00000000000000000NO2 lb/h 0000000000000000000000Hydrogen lb/h 0 000000000000000000000Ammonia lb/h 0000000000000000000000H2S lb/h 0000000000000000000000Water lb/h 1,727 1,512 3,752 3,752 3,752 00000000000000000Carbon Monoxide lb/h 0 000000000000000000000Carbon Dioxide lb/h 0 38 2,547 2,547 2,547 00000000000000000Methane lb/h 0 000000000000000000000Methanol lb/h 0000000000000000000000Formic Acid lb/h 0000000000000000000000Glyoxal lb/h 0000000000000000000000Ethylene lb/h 0 000000000000000000000Acetaldehyde lb/h 0000000000000000000000Hydroxyacetaldehyde lb/h 0000000000000000000000Acetic Acid lb/h 0000000000000000000000Ethane lb/h 0000000000000000000000Propylene lb/h 0 0000000000000000000001‐Hydroxy‐2‐propanone lb/h 0000000000000000000000Propionic Acid lb/h 0000000000000000000000Propane lb/h 0000000000000000000000Furan lb/h 0 0000000000000000000001‐Butene lb/h 0 000000000000000000000Tetrahydrofuran lb/h 0 000000000000000000000N‐Butane lb/h 0000000000000000000000Furfural lb/h 00000000000000000000002‐methylfuran lb/h 0 000000000000000000000Furfuryl Alcohol lb/h 0000000000000000000000n‐Pentane lb/h 0000000000000000000000Pentenone lb/h 0000000000000000000000Benzene lb/h 0000000000000000000000Phenol lb/h 2 0000000000000000000001,2‐Benzenediol lb/h 1,043 000000000000000000000Hydroxymethylfurfural lb/h 00000000000000000000002,5‐dimethylfuran lb/h 0 000000000000000000000Methyl Cyclopentenone lb/h 0000000000000000000000Hydroxymethylcyclopentenone lb/h 0000000000000000000000Cyclohexanone lb/h 0000000000000000000000Levoglucosan lb/h 00000000000000000000001‐Hexanal lb/h 0000000000000000000000Dimethoxytetrahydrofuran lb/h 0000000000000000000000Cyclohexane lb/h 0 000000000000000000000N‐Hexane lb/h 0000000000000000000000Hexanol lb/h 0000000000000000000000Toluene lb/h 00000000000000000000002‐Methylphenol lb/h 0 0000000000000000000003‐Methyl‐phenol lb/h 0000000000000000000000Guaiacol lb/h 0 000000000000000000000Methyl‐Cyclohexane lb/h 0 0000000000000000000002‐Methylhexane lb/h 0000000000000000000000VinylPhenol lb/h 0 000000000000000000000O‐Xylene lb/h 0000000000000000000000Ethylbenzne lb/h 00000000000000000000002,3‐Dimethyl‐phenol lb/h 0 0000000000000000000002,6‐dimethoxyphenol lb/h 0 000000000000000000000Vanillyl alcohol lb/h 1 0000000000000000000002,4,6‐Trimethylpyridine lb/h 0000000000000000000000Cis‐1,2‐dimethyl cyclohexane lb/h 0000000000000000000000Trans‐1,2‐dimethylcyclohexane lb/h 0000000000000000000000Ethylcyclohexane lb/h 00000000000000000000004‐Methylheptane lb/h 00000000000000000000002‐Methyl‐Benzofuran lb/h 0 000000000000000000000Indane lb/h 00000000000000000000002‐methoxy‐4‐vinylphenol lb/h 0 000000000000000000000Syringaldehyde lb/h 0000000000000000000000n‐Propylbenzene lb/h 0000000000000000000000Naphthalene lb/h 00000000000000000000001‐Naphthalenol lb/h 0 000000000000000000000Coniferyl Aldehyde lb/h 0 000000000000000000000Tetralin lb/h 0000000000000000000000Isoeugenol lb/h 0 000000000000000000000Decalin lb/h 00000000000000000000002,5‐Dimethyloctane lb/h 00000000000000000000001‐Methyl naphthalene lb/h 0 0000000000000000000001‐methyl decahydronaphthene lb/h 0000000000000000000000Dibenzothiophene lb/h 0 000000000000000000000Biphenyl lb/h 00000000000000000000005‐hexyl‐O‐cresol lb/h 0000000000000000000000n‐Heptylcyclohexane lb/h 0000000000000000000000C14H20‐N35 lb/h 0000000000000000000000C14H24‐N5 lb/h 00000000000000000000003,5‐Dimethyldodecane lb/h 0000000000000000000000C15H26‐N4 lb/h 00000000000000000000006,8‐Dimethyltridecane lb/h 00000000000000000000001,4‐Dimethyl‐Phenanthrene lb/h 0000000000000000000000N‐Cetane lb/h 0000000000000000000000C18H26O lb/h 0000000000000000000000C18H28 lb/h 0000000000000000000000C21H26O2 lb/h 0000000000000000000000C21H34 lb/h 0000000000000000000000C22H28O2 lb/h 0000000000000000000000Carbon lb/h 0000000000000000000000Sulfur lb/h 0000000000000000000000Sand/Catalyst Solids lb/h 0000000000000000000000Ash lb/h 0000000000000000000000Wood lb/h 0000000000000000000000Char lb/h 0000000000000000000000Coke lb/h 0000000000000000000000

211
Rev:

2

Project No: Drawing:

30482.00 PFD-61712-A803

THERMOCHEMICAL CONVERSION OF BIOMASS

TO HYDROCARBON FUEL

FAST PYROLYSIS AND VAPOR PHASE UPGRADING

PROCESS FLOW DIAGRAM

AREA 800: CLARIFIER AND SAND FILTER

Rev. Date By Description

SOLIDS

FROM S-319/S-324/S-329

PFD-61712-A302

T-809

SLURRY

TANK

T-809

P-809

M-807

FLOCCULANT/

COAGULANT

M-806

M-805

M-805

CLARIFIER

M-807

SAND

FILTER

P-809

SLURRY

PUMP

M-806

BELT

PRESS

J:\1A - Process Solutions\30482 NREL Thermochemical Conv - Design-Model\Drawings\ 30482 Pyrolysis Ex-Situ PFDs 61712 150128.vsd Plot date: 1/29/2015

SOLIDS TO DISPOSAL

0 9/29/14 JAR ISSUED FOR DESIGN REPORT

335

T-801

P-801

P-801

CLARIFIER

OVERFLOW PUMP

T-801

CLARIFIER

OVERFLOW TANK

SAND FILTER FILTRATE

TO M-701/P-708

PFD-61712-A701

BACKWASH

WASTE WATER

FROM S-411/S-461/M-861

PFD-61712-A804

880

1 12/12/14 DMS ADDED HX NETWORK 2 12/29/14 JAR MINOR UPDATES

212
PFD‐61712‐A803 335 880 

Total Flow lb/h 36 20,759 00000000000000000000Temperature F 90 112 00000000000000000000Pressure Psia 100 15 00000000000000000000Vapor Fraction 0 0 00000000000000000000Enthalpy Flow MMBtu/h 0 ‐141 00000000000000000000Argon lb/h 0 0 00000000000000000000Nitrogen lb/h 0 0 00000000000000000000Oxygen lb/h 0 0 00000000000000000000SO2 lb/h 0 0 00000000000000000000NO2 lb/h 0 0 00000000000000000000Hydrogen lb/h 0 0 00000000000000000000Ammonia lb/h 0 35 00000000000000000000H2S lb/h 0 0 00000000000000000000Water lb/h 5 20,708 00000000000000000000Carbon Monoxide lb/h 0 0 00000000000000000000Carbon Dioxide lb/h 0 1 00000000000000000000Methane lb/h 0 0 00000000000000000000Methanol lb/h 0 0 00000000000000000000Formic Acid lb/h 0 0 00000000000000000000Glyoxal lb/h 0 0 00000000000000000000Ethylene lb/h 0 0 00000000000000000000Acetaldehyde lb/h 0 0 00000000000000000000Hydroxyacetaldehyde lb/h 0000000000000000000000Acetic Acid lb/h 0 0 00000000000000000000Ethane lb/h 0 0 00000000000000000000Propylene lb/h 0 0 000000000000000000001‐Hydroxy‐2‐propanone lb/h 0000000000000000000000Propionic Acid lb/h 0 0 00000000000000000000Propane lb/h 0 0 00000000000000000000Furan lb/h 0 0 000000000000000000001‐Butene lb/h 0 0 00000000000000000000Tetrahydrofuran lb/h 0 0 00000000000000000000N‐Butane lb/h 0 0 00000000000000000000Furfural lb/h 00000000000000000000002‐methylfuran lb/h 0 0 00000000000000000000Furfuryl Alcohol lb/h 0000000000000000000000n‐Pentane lb/h 0 0 00000000000000000000Pentenone lb/h 0000000000000000000000Benzene lb/h 0 0 00000000000000000000Phenol lb/h 1 4 000000000000000000001,2‐Benzenediol lb/h 0 12 00000000000000000000Hydroxymethylfurfural lb/h 00000000000000000000002,5‐dimethylfuran lb/h 0 0 00000000000000000000Methyl Cyclopentenone lb/h 0000000000000000000000Hydroxymethylcyclopentenone lb/h 0000000000000000000000Cyclohexanone lb/h 0000000000000000000000Levoglucosan lb/h 00000000000000000000001‐Hexanal lb/h 0000000000000000000000Dimethoxytetrahydrofuran lb/h 0 0 00000000000000000000Cyclohexane lb/h 2 0 00000000000000000000N‐Hexane lb/h 0 0 00000000000000000000Hexanol lb/h 0000000000000000000000Toluene lb/h 0 0 000000000000000000002‐Methylphenol lb/h 0 0 000000000000000000003‐Methyl‐phenol lb/h 0000000000000000000000Guaiacol lb/h 0 0 00000000000000000000Methyl‐Cyclohexane lb/h 0 0 000000000000000000002‐Methylhexane lb/h 0 0 00000000000000000000VinylPhenol lb/h 0 0 00000000000000000000O‐Xylene lb/h 0 0 00000000000000000000Ethylbenzne lb/h 0 0 000000000000000000002,3‐Dimethyl‐phenol lb/h 2 0 000000000000000000002,6‐dimethoxyphenol lb/h 1 0 00000000000000000000Vanillyl alcohol lb/h 1 0 000000000000000000002,4,6‐Trimethylpyridine lb/h 0 0 00000000000000000000Cis‐1,2‐dimethyl cyclohexane lb/h 2 0 00000000000000000000Trans‐1,2‐dimethylcyclohexane lb/h 2 0 00000000000000000000Ethylcyclohexane lb/h 0 0 000000000000000000004‐Methylheptane lb/h 0 0 000000000000000000002‐Methyl‐Benzofuran lb/h 0 0 00000000000000000000Indane lb/h 00000000000000000000002‐methoxy‐4‐vinylphenol lb/h 0 0 00000000000000000000Syringaldehyde lb/h 0000000000000000000000n‐Propylbenzene lb/h 0 0 00000000000000000000Naphthalene lb/h 0 0 000000000000000000001‐Naphthalenol lb/h 0 0 00000000000000000000Coniferyl Aldehyde lb/h 0 0 00000000000000000000Tetralin lb/h 0 0 00000000000000000000Isoeugenol lb/h 0 0 00000000000000000000Decalin lb/h 0 0 000000000000000000002,5‐Dimethyloctane lb/h 0 0 000000000000000000001‐Methyl naphthalene lb/h 0 0 000000000000000000001‐methyl decahydronaphthene lb/h 0 0 00000000000000000000Dibenzothiophene lb/h 0 0 00000000000000000000Biphenyl lb/h 0 0 000000000000000000005‐hexyl‐O‐cresol lb/h 3 0 00000000000000000000n‐Heptylcyclohexane lb/h 0 0 00000000000000000000C14H20‐N35 lb/h 0 0 00000000000000000000C14H24‐N5 lb/h 2 0 000000000000000000003,5‐Dimethyldodecane lb/h 0 0 00000000000000000000C15H26‐N4 lb/h 2 0 000000000000000000006,8‐Dimethyltridecane lb/h 0 0 000000000000000000001,4‐Dimethyl‐Phenanthrene lb/h 0 0 00000000000000000000N‐Cetane lb/h 0 0 00000000000000000000C18H26O lb/h 0 0 00000000000000000000C18H28 lb/h 0 0 00000000000000000000C21H26O2 lb/h 0 0 00000000000000000000C21H34 lb/h 0 0 00000000000000000000C22H28O2 lb/h 0 0 00000000000000000000Carbon lb/h 0000000000000000000000Sulfur lb/h 0000000000000000000000Sand/Catalyst Solids lb/h 9 000000000000000000000Ash lb/h 0 000000000000000000000Wood lb/h 0 000000000000000000000Char lb/h 0 000000000000000000000Coke lb/h 1 000000000000000000000

213
Rev:

2

Project No: Drawing:

30482.00 PFD-61712-A804

THERMOCHEMICAL CONVERSION OF BIOMASS

TO HYDROCARBON FUEL

FAST PYROLYSIS AND VAPOR PHASE UPGRADING

PROCESS FLOW DIAGRAM

AREA 800: WASTEWATER REVERSE OSMOSIS

Rev. Date By Description

0 9/29/14 JAR ISSUED FOR DESIGN REPORT

J:\1A - Process Solutions\30482 NREL Thermochemical Conv - Design-Model\Drawings\ 30482 Pyrolysis Ex-Situ PFDs 61712 150128.vsd Plot date: 1/29/2015

AQUEOUS PHASE

FROM S-411

PFD-61712-A401

CONDENSATE

FROM P-576

PFD-61712-A503

CONDENSATE

FROM P-377

PFD-61712-A304

AQUEOUS PHASE

FROM S-461

PFD-61712-A403

576

424

377

474

T-860

RO FEED TANK

AQUEOUS PHASE

FROM S-412

PFD-61712-A401

430

WASTE WATER

TO M-805

PFD-61712-A803

864

CT BLOWDOWN

FROM P-701

PFD-61712-A701

713

BLOWDOWN 124

FROM P-708

PFD-61712-A701

T-860

P-860

RO FEED PUMP

M-861

REVERSE

OSMOSIS UNIT

RO

M-861 P-860

W-P860

T-866

P-866

W-P866

CLEAN WATER

HEADER

T-866

CLEAN WATER

TANK

P-866

CLEAN WATER

PUMP

865

880

860

RO BRINE

1 12/12/14 DMS ADDED HX NETWORK

CLEAN WATER

TO H-BP-48

PFD-61712-A404

CLEAN WATER

FROM H-BP-48

PFD-61712-A404

CLEAN WATER

TO H-BP-39

PFD-61712-A603

CLEAN WATER

FROM H-BP-39

PFD-61712-A603

H-BP-41

QHBP41

VPU FLUE GAS

FROM H-AP-37

PFD-61712-A203

CLEAN WATER

TO H-AP-10

PFD-61712-A603

CLEAN WATER

FROM H-AP-10

PFD-61712-A603

H-AP-45

QHAP45

H-AP-46

QHAP46

REFORMER PRODUCT

TO H-AP-44

PFD-61712-A502

REFORMER PRODUCT

FROM H-AP-47/H-AP-50

PFD-61712-A502

STEAM

TO T-261

PFD-61712-A202

270

H-BP-41

EX-SITU CATALYST REGEN

COOLER/CATALYST

STRIPPER WATER

PREHEAT FOR STEAM

H-AP-45

REFORMER OUTLET

COOLER/CATALYST

STRIPPER STEAM

PRODUCTION

H-AP-46

REFORMER OUTLET

COOLER/CATALYST

COOLER STEAM

PRODUCTION

VPU FLUE GAS

TO H-BP-17

PFD-61712-A203

2 12/29/14 JAR MINOR UPDATES

214
PFD‐61712‐A804 124 270 377 424 430 474 576 713 860 864 865 880 

Total Flow lb/h 23,429 2,756 20,723 2,912 0 129 15,788 10,937 70,877 17,719 53,158 20,759 0000000000Temperature F 123 555 110 110 0 110 110 90 111 112 112 112 0000000000Pressure Psia 15 135 83 1493 0 1893 102 15 15 15 15 15 0000000000Vapor Fraction 0 1 000000 0000 0000000000Enthalpy Flow MMBtu/h ‐160 ‐15 ‐141 ‐20 0 ‐1 ‐108 ‐75 ‐483 ‐121 ‐363 ‐141 0000000000Argon lb/h 0 0000000 0000 0000000000Nitrogen lb/h 0 00000 0 0 0000 0000000000Oxygen lb/h 0 0000000 0000 0000000000SO2 lb/h 0 00000 0 0 0000 0000000000NO2 lb/h 0 0000000 0000 0000000000Hydrogen lb/h 0 0 0 0 0 0 0 0 0000 0000000000Ammonia lb/h 000 34 0 0 0 0 0 0 0 35 0000000000H2S lb/h 000 0 0 0 0 0 0000 0000000000Water lb/h 23,429 2,756 20,658 2,877 0 129 15,786 10,937 70,810 17,702 53,107 20,708 0000000000Carbon Monoxide lb/h 0 0 0 0 0 0 0 0 0000 0000000000Carbon Dioxide lb/h 0 0 1 0 0 0 1 0 2121 0000000000Methane lb/h 0 0 0 0 0 0 0 0 0000 0000000000Methanol lb/h 000000 0 0 0000 0000000000Formic Acid lb/h 000000 0 0 0000 0000000000Glyoxal lb/h 000000 0 0 0000 0000000000Ethylene lb/h 0 0 0 0 0 0 0 0 0000 0000000000Acetaldehyde lb/h 000000 0 0 0000 0000000000Hydroxyacetaldehyde lb/h 0000000000000000000000Acetic Acid lb/h 000000 0 0 0000 0000000000Ethane lb/h 000 0 0 0 0 0 0000 0000000000Propylene lb/h 0 0 0 0 0 0 0 0 0000 00000000001‐Hydroxy‐2‐propanone lb/h 0000000000000000000000Propionic Acid lb/h 000000 0 0 0000 0000000000Propane lb/h 000 0 0 0 0 0 0000 0000000000Furan lb/h 0 0 0 00000 0000 00000000001‐Butene lb/h 0 0 0 0 0000 0000 0000000000Tetrahydrofuran lb/h 0 0 0 00000 0000 0000000000N‐Butane lb/h 000 0 0000000 0 0000000000Furfural lb/h 00000000000000000000002‐methylfuran lb/h 0 0 0 00000 0000 0000000000Furfuryl Alcohol lb/h 0000000000000000000000n‐Pentane lb/h 000 0 0000000 0 0000000000Pentenone lb/h 0000000000000000000000Benzene lb/h 000 0 0000000 0 0000000000Phenol lb/h 0 0 15 0 0000 15 4 11 4 00000000001,2‐Benzenediol lb/h 0 0 49 00000 49 12 37 12 0000000000Hydroxymethylfurfural lb/h 00000000000000000000002,5‐dimethylfuran lb/h 0 0 0 0 0000 0000 0000000000Methyl Cyclopentenone lb/h 0000000000000000000000Hydroxymethylcyclopentenone lb/h 0000000000000000000000Cyclohexanone lb/h 0000000000000000000000Levoglucosan lb/h 00000000000000000000001‐Hexanal lb/h 0000000000000000000000Dimethoxytetrahydrofuran lb/h 0 0 0 00000 0000 0000000000Cyclohexane lb/h 0 0 0 0 0 0 0 0 0000 0000000000N‐Hexane lb/h 000 0 0 0 00000 0 0000000000Hexanol lb/h 0000000000000000000000Toluene lb/h 000 0 0000000 0 00000000002‐Methylphenol lb/h 0 0 0 00000 0000 00000000003‐Methyl‐phenol lb/h 0000000000000000000000Guaiacol lb/h 0 0 0 00000 0000 0000000000Methyl‐Cyclohexane lb/h 0 0 0 0 0000 0000 00000000002‐Methylhexane lb/h 000 0 0 0 00000 0 0000000000VinylPhenol lb/h 0 0 0 00000 0000 0000000000O‐Xylene lb/h 000 0 0000000 0 0000000000Ethylbenzne lb/h 000 0 0000000 0 00000000002,3‐Dimethyl‐phenol lb/h 0 0 0 00000 0000 00000000002,6‐dimethoxyphenol lb/h 0 0 0 00000 0000 0000000000Vanillyl alcohol lb/h 0 0 0 00000 0000 00000000002,4,6‐Trimethylpyridine lb/h 0 0 0 00000 0000 0000000000Cis‐1,2‐dimethyl cyclohexane lb/h 0 0 0 0 0000 0000 0000000000Trans‐1,2‐dimethylcyclohexane lb/h 0 0 0 0 0000 0000 0000000000Ethylcyclohexane lb/h 000 0 0000000 0 00000000004‐Methylheptane lb/h 000 0 0000000 0 00000000002‐Methyl‐Benzofuran lb/h 0 0 0 00000 0000 0000000000Indane lb/h 00000000000000000000002‐methoxy‐4‐vinylphenol lb/h 0 0 0 00000 0000 0000000000Syringaldehyde lb/h 0000000000000000000000n‐Propylbenzene lb/h 000 0 0000000 0 0000000000Naphthalene lb/h 000 0 0 0 00000 0 00000000001‐Naphthalenol lb/h 0 0 0 00000 0000 0000000000Coniferyl Aldehyde lb/h 0 0 0 00000 0000 0000000000Tetralin lb/h 000 0 0 0 00000 0 0000000000Isoeugenol lb/h 0 0 0 00000 0000 0000000000Decalin lb/h 0 0 0 0 0 0 0 0 0000 00000000002,5‐Dimethyloctane lb/h 00000 0 00000 0 00000000001‐Methyl naphthalene lb/h 0 0 0 0 0 0 0 0 0000 00000000001‐methyl decahydronaphthene lb/h 0 0 0 0 0 0 0 0 0000 0000000000Dibenzothiophene lb/h 0 0 0 00000 0000 0000000000Biphenyl lb/h 000 0 0 0 00000 0 00000000005‐hexyl‐O‐cresol lb/h 0 0 0 00000 0000 0000000000n‐Heptylcyclohexane lb/h 000 0 0 0 00000 0 0000000000C14H20‐N35 lb/h 000 0 0 0 00000 0 0000000000C14H24‐N5 lb/h 0 0 0 0 0 0 0 0 0000 00000000003,5‐Dimethyldodecane lb/h 000 0 0 0 00000 0 0000000000C15H26‐N4 lb/h 0 0 0 0 0 0 0 0 0000 00000000006,8‐Dimethyltridecane lb/h 00000 0 00000 0 00000000001,4‐Dimethyl‐Phenanthrene lb/h 000 0 0 0 00000 0 0000000000N‐Cetane lb/h 00000 0 00000 0 0000000000C18H26O lb/h 0 0 0 00000 0000 0000000000C18H28 lb/h 000 0 0 0 00000 0 0000000000C21H26O2 lb/h 0 0 0 0 0000 0000 0000000000C21H34 lb/h 0 0 0 0 0000 0000 0000000000C22H28O2 lb/h 0 0 0 0 0000 0000 0000000000Carbon lb/h 0000000000000000000000Sulfur lb/h 0000000000000000000000Sand/Catalyst Solids lb/h 0000000000000000000000Ash lb/h 0000000000000000000000Wood lb/h 0000000000000000000000Char lb/h 0000000000000000000000Coke lb/h 0000000000000000000000

215
Rev:

0

Project No: Drawing:

30482.00 PFD-61712-A805

THERMOCHEMICAL CONVERSION OF BIOMASS

TO HYDROCARBON FUEL

FAST PYROLYSIS AND VAPOR PHASE UPGRADING

PROCESS FLOW DIAGRAM

AREA 800: A800 HEAT RECOVERY

Rev. Date By Description

0 12/12/14 DMS ADDED HX NETWORK

J:\1A - Process Solutions\30482 NREL Thermochemical Conv - Design-Model\Drawings\ 30482 Pyrolysis Ex-Situ PFDs 61712 150128.vsd Plot date: 1/29/2015

WASTEWATER

FROM P-810

PFD-61712-A801

WASTEWATER

TO H-BP-10

PFD-61712-A602

WASTEWATER

FROM H-BP-10

PFD-61712-A602

WASTEWATER

TO H-BP-33

PFD-61712-A603

H-AP-61

QHAP61

H-AP-63

RTO HIGH TEMP EXHAUST

COOLER/STEAM PRODUCTION

FROM WW FOR REFORMER

H-AP-60

PRE-ABSORBER UPGRADED VAPOR

COOLER/STEAM PRODUCTION

FROM WW FOR REFORMER

H-AP-61

A500 LOW TEMP WGS OUTLET

COOLER/STEAM PRODUCTION

FROM WW FOR WGS

H-AP-62

RTO HIGH TEMP EXHAUST

COOLER/STEAM PRODUCTION

FROM WW FOR WGS

811 WASTEWATER

FROM H-BP-33

PFD-61712-A603

WASTEWATER

TO H-BP-26

PFD-61712-A402

WASTEWATER

FROM H-BP-26

PFD-61712-A402

WASTEWATER

TO H-AP-23

PFD-61712-A305

WASTEWATER

TO H-AP-24

PFD-61712-A404

WASTEWATER

TO H-AP-25

PFD-61712-A404

WASTEWATER

TO H-AP-32

PFD-61712-A303

WASTEWATER

FROM H-AP-23

PFD-61712-A305

WASTEWATER

FROM H-AP-24

PFD-61712-A404

WASTEWATER

FROM H-AP-25

PFD-61712-A404

WASTEWATER

FROM H-AP-32

PFD-61712-A303

WASTEWATER

TO H-AP-59

PFD-61712-A502

LTS EFFLUENT

FROM R-566

PFD-61712-A505

LTS EFFLUENT

TO H-AP-19/H-AP-20

PFD-61712-A505

H-AP-62

QHAP62

WASTEWATER

FROM H-AP-59

PFD-61712-A502

WASTEWATER

TO T-812

PFD-61712-A801

812

FLUE GAS

FROM M-833

PFD-61712-A802

838

H-AP-63

QHAP63

BOILER FEEDWATER

FROM P-814

PFD-61712-A801

BOILER FEEDWATER

TO T-822

PFD-61712-A801

FLUE GAS

TO H-840

PFD-61712-A802

839

CONC WASTEWATER

TO H-AP-57

PFD-61712-A404

CONC WASTEWATER

FROM H-AP-57

PFD-61712-A404

CONC WASTEWATER

TO H-AP-58

PFD-61712-A402

CONC WASTEWATER

FROM H-AP-58

PFD-61712-A402

H-AP-60

QHAP60

PYROLYSIS VAPOR

FROM H-AP-51

PFD-61712-A305

PYROLYSIS VAPOR

TO D-301

PFD-61712-A305

822

216
PFD‐61712‐A805 811 812 822 838 839 

Total Flow lb/h 77,811 77,811 48,983 80,265 80,265 00000000000000000Temperature F 86 359 354 863 437 00000000000000000Pressure Psia 160 150 145 22 20 00000000000000000Vapor Fraction 0 0 0 1 1 00000000000000000Enthalpy Flow MMBtu/h ‐523 ‐500 ‐312 ‐15 ‐24 00000000000000000Argon lb/h 000 979 979 00000000000000000Nitrogen lb/h 000 57,382 57,382 00000000000000000Oxygen lb/h 000 15,606 15,606 00000000000000000SO2 lb/h 000 0 0 00000000000000000NO2 lb/h 0000000000000000000000Hydrogen lb/h 000 0000000000000000000Ammonia lb/h 0000000000000000000000H2S lb/h 0000000000000000000000Water lb/h 75,955 75,955 47,218 3,752 3,752 00000000000000000Carbon Monoxide lb/h 000 0000000000000000000Carbon Dioxide lb/h 2 2 0 2,547 2,547 00000000000000000Methane lb/h 000 0000000000000000000Methanol lb/h 0000000000000000000000Formic Acid lb/h 0000000000000000000000Glyoxal lb/h 0000000000000000000000Ethylene lb/h 000 0000000000000000000Acetaldehyde lb/h 0000000000000000000000Hydroxyacetaldehyde lb/h 0000000000000000000000Acetic Acid lb/h 0000000000000000000000Ethane lb/h 0000000000000000000000Propylene lb/h 000 00000000000000000001‐Hydroxy‐2‐propanone lb/h 0000000000000000000000Propionic Acid lb/h 0000000000000000000000Propane lb/h 0000000000000000000000Furan lb/h 000 00000000000000000001‐Butene lb/h 000 0000000000000000000Tetrahydrofuran lb/h 000 0000000000000000000N‐Butane lb/h 0000000000000000000000Furfural lb/h 00000000000000000000002‐methylfuran lb/h 000 0000000000000000000Furfuryl Alcohol lb/h 0000000000000000000000n‐Pentane lb/h 0000000000000000000000Pentenone lb/h 0000000000000000000000Benzene lb/h 0000000000000000000000Phenol lb/h 73 73 33 00000000000000000001,2‐Benzenediol lb/h 1,778 1,778 1,729 0000000000000000000Hydroxymethylfurfural lb/h 00000000000000000000002,5‐dimethylfuran lb/h 000 0000000000000000000Methyl Cyclopentenone lb/h 0000000000000000000000Hydroxymethylcyclopentenone lb/h 0000000000000000000000Cyclohexanone lb/h 0000000000000000000000Levoglucosan lb/h 00000000000000000000001‐Hexanal lb/h 0000000000000000000000Dimethoxytetrahydrofuran lb/h 000 0000000000000000000Cyclohexane lb/h 000 0000000000000000000N‐Hexane lb/h 0000000000000000000000Hexanol lb/h 0000000000000000000000Toluene lb/h 00000000000000000000002‐Methylphenol lb/h 000 00000000000000000003‐Methyl‐phenol lb/h 0000000000000000000000Guaiacol lb/h 000 0000000000000000000Methyl‐Cyclohexane lb/h 000 00000000000000000002‐Methylhexane lb/h 0000000000000000000000VinylPhenol lb/h 000 0000000000000000000O‐Xylene lb/h 0000000000000000000000Ethylbenzne lb/h 00000000000000000000002,3‐Dimethyl‐phenol lb/h 110 00000000000000000002,6‐dimethoxyphenol lb/h 000 0000000000000000000Vanillyl alcohol lb/h 332 00000000000000000002,4,6‐Trimethylpyridine lb/h 000 0000000000000000000Cis‐1,2‐dimethyl cyclohexane lb/h 000 0000000000000000000Trans‐1,2‐dimethylcyclohexane lb/h 000 0000000000000000000Ethylcyclohexane lb/h 00000000000000000000004‐Methylheptane lb/h 00000000000000000000002‐Methyl‐Benzofuran lb/h 000 0000000000000000000Indane lb/h 00000000000000000000002‐methoxy‐4‐vinylphenol lb/h 000 0000000000000000000Syringaldehyde lb/h 0000000000000000000000n‐Propylbenzene lb/h 0000000000000000000000Naphthalene lb/h 00000000000000000000001‐Naphthalenol lb/h 000 0000000000000000000Coniferyl Aldehyde lb/h 000 0000000000000000000Tetralin lb/h 0000000000000000000000Isoeugenol lb/h 000 0000000000000000000Decalin lb/h 0 0 000000000000000000002,5‐Dimethyloctane lb/h 00000000000000000000001‐Methyl naphthalene lb/h 000 00000000000000000001‐methyl decahydronaphthene lb/h 0 0 00000000000000000000Dibenzothiophene lb/h 000 0000000000000000000Biphenyl lb/h 00000000000000000000005‐hexyl‐O‐cresol lb/h 0 0 00000000000000000000n‐Heptylcyclohexane lb/h 0000000000000000000000C14H20‐N35 lb/h 0000000000000000000000C14H24‐N5 lb/h 0 0 000000000000000000003,5‐Dimethyldodecane lb/h 0000000000000000000000C15H26‐N4 lb/h 0 0 000000000000000000006,8‐Dimethyltridecane lb/h 00000000000000000000001,4‐Dimethyl‐Phenanthrene lb/h 0 0 00000000000000000000N‐Cetane lb/h 0000000000000000000000C18H26O lb/h 0 0 00000000000000000000C18H28 lb/h 0000000000000000000000C21H26O2 lb/h 0 0 00000000000000000000C21H34 lb/h 0 0 00000000000000000000C22H28O2 lb/h 0 0 00000000000000000000Carbon lb/h 0000000000000000000000Sulfur lb/h 0000000000000000000000Sand/Catalyst Solids lb/h 0000000000000000000000Ash lb/h 0000000000000000000000Wood lb/h 0000000000000000000000Char lb/h 0000000000000000000000Coke lb/h 0000000000000000000000

217
218

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Appendix H. Heat Exchanger Costs for the Ex Situ

Case
HX 

Name Description

Belongs 

to Area Hot In Hot Out Cold In Cold Out LMTD Duty Pres. Stream 1 Pres. Stream 2 Shell Tube Shell Material Tube Material Shell Design Pres. Tube Design Pres. U 

Stream 1 /Stream 2 F F F F ∆T Btu/h (psia) (psia)

psig 

(20% Excess, Min. = 50 psig)

psig 

(20% Excess, Min. = 50 psig)

Btu/r ft2 

°F) 

Network Above Pinch

H-AP-7

Reformer Flue Gas Cooler / Reformer Feed High Temp Preheat A500 1804.2 1134.2 525.6 1400.0 499.5 43,837,566 19 118

Reformer Flue Gas 

Cooler 

 Reformer Feed 

High Temp CS CS 130 50 10 

H-AP-8

Char Combustor Flue Gas Cooler / Fast Pyrolysis Fluidizing Gas Preheat A211 1212.4 309.9 285.0 800.0 138.0 64,162,490 115 125

Char Combustor FG 

Cooler FP Fluidizing Gas CS CS 140 120 10 

H-AP-9

Char Combustor Flue Gas Cooler / InterTurbine Steam Reheat A600 1328.0 1212.4 698.3 1000.0 414.1 8,222,305 115 350 Char Combustor FG Cooler Inter-Turbine Steam Preheat CS CS 410 120 10 

H-AP-10

Boiler Feed Water Blowdown Cooler / Catalyst Stripper Water Preheat for Steam A600 581.0 309.9 285.0 356.0 90.9 225,383 1336 145

Catalyst Stripper 

Water Preheat 

BFW Blowdown 

Cooler CS SS304L 1,590 160 10

H-AP-11

Boiler Feed Water Blowdown Cooler / Water Preheat for Mix with WW for Steam A600 581.0 309.9 285.0 350.0 92.5 143,809 1336 155

Water Preheat for 

Mix 

BFW Blowdown 

Cooler CS SS304L 1,590 170 10

H-AP-12

Hydrotreater Outlet Cooler / HT Product to Naphtha Column Preheat A450 415.5 309.9 285.0 375.0 32.1 3,492,816 1510 48 HT Product Hydrotreater SS316

 A199-T22 

or A199D 

(2.5 Cr-1 

Mo) 1,800 50 80 

H-AP-13

Distillate Column Condenser / HT Product to 

Naphtha Column Preheat A450 550.3 490.9 375.0 450.0 107.9 2,912,097 15 48

Distillate Column 

Condenser HT Product SS316 CS 50 5 

50 

H-AP-14

A300 WGS Outlet Cooler / A300 Pyrolysis OffGas to WGS Preheat A360 425.0 309.9 285.0 400.0 25.0 4,039,336 84 93 A300 WGS Outlet Cooler A300 Pyrolysis Off- Gas A204C CS 100 90 10 

H-AP-15

A300 WGS Outlet Cooler / A300 WGS Feed Preheat A360 490.4 425.0 396.8 464.0 27.3 3,382,516 84 91

A300 WGS Outlet 

Cooler 

A300 WGS Feed 

Preheat A204C CS 90 90 10 

H-AP-16

Distillate Product Cooler / HC Product to Naphtha Column Preheat A450 491.1 309.9 285.0 466.1 25.0 2,373,485 35 48

Distillate product 

cooler HC Product SS316 CS 50 50 80 

H-AP-17

Post-Absorber 1 Vapor Cooler / Char Combustor Air Preheat A310 358.2 309.9 287.2 336.2 22.4 2,934,814 110 123

Post Absorber 1 

Vapor Cooler 

Char Combustor 

Air Preheat CS CS 130 120 10 

H-AP-18

Post-Absorber 1 Vapor Cooler / Ex Situ Catalyst Regen Air Preheat A310 358.2 309.9 285.0 336.2 23.4 2,528,606 110 117

Post Absorber 1 

Vapor Cooler 

Ex Situ Catalyst 

Regen Air Preheat CS CS 130 120 10 

H-AP-19

A500 Low Temp WGS Outlet Cooler / PSA OffGas to Reformer Combustor Preheat A500 503.0 309.9 285.0 450.0 37.2 4,124,363 101 21 PSA Off-Gas A500 Low Temp WGS Outlet CS CS 110 50 10 

H-AP-20

A500 Low Temp WGS Outlet Cooler / Reformer Combustor Air Preheat A500 503.0 309.9 285.0 450.0 37.2 5,634,861 101 21

Combustor Air 

Preheat 

A500 Low Temp 

WGS Outlet CS CS 110 50 10 

H-AP-21

A500 Low Temp WGS Outlet Cooler / Natural Gas to Reformer Preheat A500 540.0 503.0 285.0 500.0 105.0 17,663 101 198

A500 Low Temp 

WGS Outlet 

 Natural Gas to 

Reformer A204C CS 220 110 10 

H-AP-22

A500 Low Temp WGS Outlet Cooler / Reformer Combustor Gas Preheat A500 540.0 503.0 285.0 500.0 105.0 100,164 101 21

Reformer 

Combustor Gas 

A500 Low Temp 

WGS Outlet CS CS 110 50 10 

H-AP-23

Absorber 1 Bottoms Cooler / WW Preheat for Steam Production A310 461.2 309.9 285.0 358.6 54.9 1,597,418 133 155 Absorber 1 Bottoms WW Preheat CS SS316 170 140 80 

H-AP-24

Hydrotreater Outlet Cooler / WW Preheat for Steam Production A500 415.5 309.9 285.0 358.6 38.7 3,230,771 1510 155 WW Preheat 

Hydrotreater Outlet 

Cooler SS316

 A199-T22 

or A199D 

(2.5 Cr-1 

Mo) 1,800 170 80 

H-AP-25

Distillate Product Cooler / WW Preheat for Steam Production A450 491.1 309.9 285.0 358.6 64.4 384,860 35 155

Distillate Product 

Cooler WW Preheat CS SS316 170 50 80 

H-AP-26

Reformer Flue Gas Cooler / Inter-Turbine Steam Reheat A600 1134.2 911.6 698.3 1000.0 170.7 14,562,462 19 350

Reformer Flue Gas 

Cooler 

 Inter-Turbine 

Steam Reheat CS CS 410 50 10 

H-AP-27

Reformer Flue Gas Cooler / Distillate Column Reboiler A450 911.6 819.0 705.0 711.6 153.0 6,062,749 19 20

Reformer Flue Gas 

Cooler 

Distillate Column 

Reboiler CS CS 50 50 35 

H-AP-28

Reformer Flue Gas Cooler / Naphtha Column Reboiler A450 819.0 741.5 595.8 626.5 168.0 5,072,974 19 40

Reformer Flue Gas 

Cooler 

Naphtha Column 

Reboiler CS CS 50 50 35 

H-AP-29

Reformer Flue Gas Cooler / Reformer Combustor Air Preheat A500 741.5 663.1 450.0 600.0 174.9 5,123,961 19 21

Reformer Flue Gas 

Cooler 

 Reformer 

Combustor Air CS CS 50 50 5 

H-AP-30

Reformer Flue Gas Cooler / Reformer Feed Gas Preheat A500 663.1 651.6 466.8 500.0 173.7 757,539 19 120

Reformer Flue Gas 

Cooler 

 Reformer Feed 

Gas Preheat CS CS 130 50 10 

219
HX 

Name Description

Belongs 

to Area Hot In Hot Out Cold In Cold Out LMTD Duty Pres. Stream 1 Pres. Stream 2 Shell Tube Shell Material Tube Material Shell Design Pres. Tube Design Pres. U 

Stream 1 /Stream 2 F F F F ∆T Btu/h (psia) (psia)

psig 

(20% Excess, Min. = 50 psig)

psig 

(20% Excess, Min. = 50 psig)

Btu/r ft2 

°F) 

H-AP-31

Post-Absorber 1 Vapor Cooler / Boiler Feed Water Preheat A310 358.2 309.9 285.0 340.0 21.4 9,708,179 110 1346

Post Absorber 1 

Vapor Cooler 

Boiler Feed Water 

Preheat CS SS304L 1,600 120 40 

H-AP-32

A300 WGS Outlet Cooler / WW Preheat for Steam Production A360 425.0 309.9 285.0 358.6 42.3 1,437,623 84 155

A300 WGS Outlet 

Cooler WW Preheat A204C SS316 170 90 35 

H-AP-33

A300 WGS Outlet Cooler / Boiler Feed Water Preheat A360 425.0 309.9 285.0 340.0 49.0 477,847 84 1346

A300 WGS Outlet 

Cooler BFW Preheat A204C SS304L 1,600 90 40 

H-AP-34

Hydrotreater Outlet Cooler / Boiler Feed Water Preheat A410 360.0 309.9 285.0 340.0 22.4 1,055,021 1910 1346 BFW Preheat 

Hydrotreater Outlet 

Cooler SS304L

 A199-T22 

or A199D 

(2.5 Cr-1 

Mo) 2,280 1,600 80 

H-AP-35

Boiler Feed Water Blowdown Cooler / Boiler Feed Water Preheat A600 360.0 309.9 285.0 340.0 22.4 300,243 1336 1336 BFW Preheat 

BFW Blowdown 

Cooler SS304L SS304L 1,590 1,590 10

H-AP-36

Reformer Flue Gas Cooler / Boiler Feed Water Preheat A600 380.0 309.9 285.0 340.0 31.9 4,583,506 19 1346

Reformer Flue Gas 

Cooler BFW Preheat CS SS304L 1,600 50 35 

H-AP-37

Ex Situ Catalyst Regen Flue Gas Cooler / Boiler Feed Water Preheat A261 380.5 309.9 285.0 340.0 32.1 3,939,780 111 1346

Ex Situ Catalyst 

Regen FG Cooler BFW Preheat CS SS304L 1,600 120 35 

H-AP-38

Ex Situ Catalyst Regen Flue Gas Cooler / Char Combustor Air Preheat A261 897.2 380.5 336.2 600.0 132.9 15,809,168 111 123

Ex Situ Catalyst 

Regen FG Cooler Char Combustor Air CS CS 130 120 10 

H-AP-39

Ex Situ Catalyst Regen Flue Gas Cooler / Ex Situ Catalyst Regen Air Preheat A261 897.2 380.5 336.2 600.0 132.9 13,035,111 111 117

Ex Situ Catalyst 

Regen FG Cooler

Ex Situ Catalyst 

Regen CS CS 130 120 10 

H-AP-40

Boiler Feed Water Blowdown Cooler / Boiler Feed Water Preheat A600 500.0 360.0 340.0 465.0 26.8 839,835 1336 1346 BFW Blowdown BFW Preheat SS304L SS304L 1,600 1,590 10

H-AP-41

Hydrotreater Outlet Cooler / Boiler Feed Water Preheat A410 520.0 360.0 340.0 465.0 34.6 3,372,674 1910 1346 BFW Preheat

Hydrotreater Outlet 

Cooler SS304L

A199-T22 

or A199D 

(2.5 Cr-1 

Mo) 2,280 1,600 80 

H-AP-42

Reformer Flue Gas Cooler / Boiler Feed Water Preheat A600 520.0 380.0 340.0 465.0 47.1 9,160,429 19 1346

Reformer Flue Gas 

Cooler BFW Preheat CS SS304L 1,600 50 35 

H-AP-43

Hydrotreater Outlet Cooler / HC Product to Naphtha Column Preheat A410 717.4 520.0 466.1 550.0 100.1 1,099,410 1910 48 HC Product

Hydrotreater Outlet 

Cooler CS

A199-T22 

or A199D 

(2.5 Cr-1 

Mo) 2,280 50 80 

H-AP-44

Refomer Outlet Cooler / Reformer Steam Superheat A500 728.9 644.0 356.2 556.2 225.4 4,505,467 115 135

Reformer Outlet 

Cooler

Reformer Steam 

Superheat CS SS316 150 120 10 

H-AP-45

Refomer Outlet Cooler / Catalyst Stripper Steam Production A261 775.4 728.9 356.0 356.0 395.7 2,467,430 115 145

Reformer Outlet 

Cooler

Catalyst Stripper 

Steam CS CS 160 120 35 

H-AP-46

Refomer Outlet Cooler / Catalyst Cooler Steam Superheat A261 780.5 775.4 355.0 555.0 312.9 269,714 115 140

Reformer Outlet 

Cooler

Catalyst Cooler 

Steam CS CS 150 120 10 

H-AP-47

Refomer Outlet Cooler / Inter-Turbine Steam Reheat A600 1616.0 780.5 698.3 1000.0 265.0 27,890,753 115 350

Reformer Outlet 

Cooler

Inter-Turbine Steam 

Reheat CS CS 410 120 10 

H-AP-48

Pre-Absorber Upgraded Vapor Cooler / Steam Superheat A600 930.9 902.5 580.0 641.3 305.8 5,711,881 115 1326

Pre-Absorber 

Upgraded Vapor 

Cooler Steam Superheat CS SS304L 1,580 120 50 

H-AP-49

Ex Situ Catalyst Regen Flue Gas Cooler / Steam Superheat A600 1202.0 897.2 641.3 1000.0 227.9 17,014,851 111 1326

Ex-Situ Catalyst

Regen Flue Gas 

Cooler Steam Superheat CS SS304L 1,580 120 50 

H-AP-50 Refomer Outlet Cooler / Steam Superheat A600 1616.0 780.5 641.3 1000.0 320.6 16,442,228 115 1326

Reformer Outlet 

Cooler Steam Superheat CS SS304L 1,580 120 50 

H-AP-51

Pre-Absorber Upgraded Vapor Cooler / Boiler Feed Water Preheat A310 902.5 690.4 465.0 582.0 270.2 42,704,554 115 1346

Upgraded Vapor 

Cooler BFW Preheat CS SS304L 1,600 120 40 

H-AP-52

A300 WGS Outlet Cooler / Boiler Feed Water Preheat A360 637.0 490.4 435.6 465.0 102.4 7,591,348 84 1346

A300 WGS Outlet 

Cooler BFW Preheat A204C SS304L 1,600 90 40 

220
HX 

Name Description

Belongs 

to Area Hot In Hot Out Cold In Cold Out LMTD Duty Pres. Stream 1 Pres. Stream 2 Shell Tube Shell Material Tube Material Shell Design Pres. Tube Design Pres. U 

Stream 1 /Stream 2 F F F F ∆T Btu/h (psia) (psia)

psig 

(20% Excess, Min. = 50 psig)

psig 

(20% Excess, Min. = 50 psig)

Btu/r ft2 

°F) 

H-AP-53

Pre-Absorber Upgraded Vapor Cooler / A300 WGS Steam Superheat A310 690.4 466.4 353.8 403.8 186.2 760,513 115 140

Upgraded Vapor 

Cooler

A300 WGS Steam 

Superheat CS SS316 150 120 10 

H-AP-54

Reformer Flue Gas Cooler / Boiler Feed Water Preheat A600 651.6 520.0 402.2 435.6 161.9 8,608,504 19 1346

Reformer Flue Gas 

Cooler BFW Preheat CS SS304L 1,600 50 40 

H-AP-55

Boiler Feed Water Blowdown Cooler / Boiler Feed Water Preheat A600 581.0 500.0 340.0 402.2 169.2 485,893 1336 1346

BFW Blowdown 

Cooler BFW Preheat SS304L SS304L 1,600 1,590 10

H-AP-56

Pre-Absorber Upgraded Vapor Cooler / Boiler Feed Water Preheat A310 690.4 466.4 340.0 402.2 196.3 15,578,969 115 1346

Pre-Absorber 

Upgraded Vapor 

Cooler BFW Preheat CS SS304L 1,600 120 40 

H-AP-57

Hydrotreater Outlet Cooler / Steam Production from WW for Reformer A800 717.4 520.0 353.7 361.5 249.2 3,061,157 1910 145 Steam Production HT Outlet Cooler CS

A199-T22 

or A199D 

(2.5 Cr-1 

Mo) 2,280 160 80 

H-AP-58

Distillate Column Condenser / Steam Production from WW for Reformer A800 550.3 490.9 353.7 361.5 161.6 4,524,433 15 145

Distillate Column 

Condenser

Steam Production 

from WW CS SS316 160 50 35 

H-AP-59

A500 High Temp WGS Outlet Cooler / Steam Production from WW for WGS A500 835.4 428.0 358.6 359.1 211.2 20,869,597 108 150

A500 High Temp 

WGS Outlet

Steam Production 

from WW A204C SS316 170 110 35 

H-AP-60

Pre-Absorber Upgraded Vapor Cooler / Steam Production from WW for Reformer A310 690.4 466.4 353.7 361.5 201.9 28,749,167 115 145

Upgraded Vapor 

Cooler

Steam Production 

from WW CS SS316 160 120 35 

H-AP-61

A500 Low Temp WGS Outlet Cooler / Steam Production from WW for WGS A500 540.0 503.0 358.6 359.1 162.0 1,752,794 101 150

A500 Low Temp 

WGS Outlet

Steam Production 

from WW A204C SS316 170 110 35 

H-AP-62

RTO High Temp Exhaust Cooler / Steam Production from WW for WGS A800 863.4 436.7 358.6 359.1 228.5 4,331,122 22 150

RTO High Temp 

Exhaust Cooler

Steam Production 

from WW CS SS316 170 50 35 

H-AP-63

RTO High Temp Exhaust Cooler / Steam 

Production from WW for Reformer A800 863.4 436.7 353.7 361.5 232.8 4,695,177 22 145

RTO High Temp 

Exhaust Cooler

Steam Production 

from WW CS SS316 160 50 35 

Network Below Pinch

H-BP-1

A300 WGS Outlet Cooler/Condenser / Boiler Feed Water Preheat 1 A360 218.7 185.0 138.1 175.6 44.9 4,911,418 25 83 WGS Outlet BFW Preheat 1 A204C CS 50 80 35 

H-BP-2

Reformer Flue Gas Cooler / Reformer Combustor Air Preheat A500 309.9 244.8 173.1 285.0 44.3 3,736,136 21 18 Air Preheat Reformer Flue Gas CS CS 50 50 5 

H-BP-3

Post-Absorber 1 Vapor Cooler / Fast Pyrolysis Fluidizing Gas Preheat A211 309.9 220.0 200.7 285.0 22.0 10,024,571 127 109 FG Preheat 

Post Absorber 1 

Vapor CS SS304L 120 140 10 

H-BP-4

A300 WGS Outlet Cooler/Condenser / Pyrolysis 

Off-Gas Feed to WGS Preheat A360 218.7 185.0 95.0 200.7 44.7 3,585,841 95 83 WGS Outlet 

Pyrolysis Off Gas 

Feed A204C CS 100 80 10 

H-BP-5

Hydrotreater Outlet Cooler / HT Product to Naphtha Column Preheat A450 309.9 175.0 120.4 285.0 37.8 3,812,615 1,508 53 HT Product HT Outlet Cooler SS316

A199-T22 

or A199D 

(2.5 Cr-1 

Mo) 1,790 50 70 

H-BP-6

Hydrocracker Outlet Cooler / HC Product to Naphtha Column Preheat A450 309.9 175.0 110.0 285.0 41.8 1,527,541 1,908 53 HC Product HC Outlet Cooler SS316

 A199-T22 

or A199D 

(2.5 Cr-1 

Mo) 2,270 50 70 

H-BP-7

Low Temp WGS Outlet Cooler/Condenser / PSA Exh. to Ref. Comb. Preheat A500 213.3 185.0 109.4 199.3 36.5 2,116,466 100 21 PSA Exchanger Low Temp WGS CS

 A209 (C - 

0.5 Mo) 110 50 10 

H-BP-8

Low Temp WGS Outlet Cooler/Condenser / Boiler Feed Water Preheat 1 A500 213.3 185.0 138.1 175.6 42.1 7,255,229 100 25 BFW Preheat 1 Low Temp WGS CS

 A209 (C - 

0.5 Mo) 110 50 35 

H-BP-9

Low Temp WGS Outlet Cooler / Reformer Combustor Gas Preheat A500 309.9 213.3 108.8 285.0 55.5 74,879 100 22

Reformer 

Combustor Gas Low Temp WGS CS

 A209 (C - 

0.5 Mo) 110 50 10 

H-BP-10

Steam Turbine Exhaust Cooler / WW Preheat 

for Steam Production A600 234.3 170.0 86.5 174.7 70.9 9,250,080 160 4

Steam Turbine 

Exhaust WW Preheat CS SS316 180 50 15

H-BP-11

Post-Absorber 1 Vapor Cooler / Boiler Feed Water Preheat 1 A310 250.0 220.0 175.6 232.3 29.0 5,196,218 109 25 BFW Preheat 1 

Post Absorber 1 

Vapor CS SS304L 120 50 35 

H-BP-12

Low Temp WGS Outlet Cooler / Reformer Combustor Air Preheat A360 309.9 213.3 173.1 285.0 31.9 19,735 100 21

Reformer 

Combustor Air Low Temp WGS CS CS 110 50 10 

221
HX 

Name Description

Belongs 

to Area Hot In Hot Out Cold In Cold Out LMTD Duty Pres. Stream 1 Pres. Stream 2 Shell Tube Shell Material Tube Material Shell Design Pres. Tube Design Pres. U 

Stream 1 /Stream 2 F F F F ∆T Btu/h (psia) (psia)

psig 

(20% Excess, Min. = 50 psig)

psig 

(20% Excess, Min. = 50 psig)

Btu/r ft2 

°F) 

H-BP-13

RTO Low Temp Exhaust Cooler / Boiler Feed Water Preheat 1 A800 269.1 244.8 175.6 232.3 51.3 490,867 19 25 BFW Preheat 1 RTO Low Temp EC CS SS304L 50 50 35 

H-BP-14

A300 WGS Outlet Cooler / Pyrolysis Off-Gas Feed to WGS Preheat A360 309.9 218.7 200.7 285.0 21.3 2,862,490 95 83 WGS Outlet 

Pyrolysis Off-Gas 

Feed CS CS 100 80 10 

H-BP-15

Low Temp WGS Outlet Cooler / PSA Exh. to Ref. Comb. Preheat A500 309.9 213.3 199.3 285.0 18.9 2,019,392 25 83 BFW Preheat A300 WGS O/L CS

 A209 (C - 

0.5 Mo) 80 50 35 

H-BP-16

Char Combustor Flue Gas Cooler / Boiler Feed Water Preheat 1 A211 255.0 244.8 175.6 232.3 41.7 676,950 112 25 BFW Preheat 1 

Char Combustor 

FG CS CS 120 50 35 

H-BP-17

Ex Situ Catalyst Regen Flue Gas Cooler / Boiler Feed Water Preheat 1 A261 255.0 244.8 175.6 232.3 41.7 534,946 245 25 BFW Preheat 1 

Ex-situ Catalyst 

Regen FG CS CS 280 50 40 

H-BP-18

Hydrotreater Outlet Cooler / Boiler Feed Water Preheat 1 A410 250.3 193.6 175.6 232.3 18.0 1,937,436 1,508 25 BFW Preheat 1 HT Outlet Cooler CS

A199-T22 

or A199D 

(2.5 Cr-1 

Mo) 1,790 50 10

H-BP-19

Hydrocracker Outlet Cooler / Boiler Feed Water Preheat 1 A460 250.3 193.6 175.6 232.3 18.0 346,619 1,908 25 BFW Preheat 1 HC Outlet Cooler CS

 A199-T22 

or A199D 

(2.5 Cr-1 

Mo) 2,270 50 12

H-BP-20

Post-Absorber 1 Vapor Cooler / Boiler Feed Water Preheat 2 A310 309.9 250.0 235.2 285.0 19.4 10,383,723 1,351 109 PA 1 Vapor Cooler BFW Preheat 2 CS SS304L 1,610 120 40 

H-BP-21

Char Combustor Flue Gas Cooler / Boiler Feed Water Preheat 2 A211 309.9 255.0 235.2 285.0 22.2 3,635,193 1,351 112 Char Combustor FG BFW Preheat 2 CS SS304L 1,610 120 40 

H-BP-22

Ex Situ Catalyst Regen Flue Gas Cooler / Boiler Feed Water Preheat 2 A261 309.9 255.0 235.2 285.0 22.2 2,261,634 1,351 108 Regen Flue Gas BFW Preheat 2 CS SS304L 1,610 110 40 

H-BP-23

Hydrotreater Outlet Cooler / Boiler Feed Water Preheat 1 A410 309.9 250.3 175.6 232.3 76.1 2,039,539 1,508 25 BFW Preheat 1 HT Outlet Cooler CS

 A199-T22 

or A199D 

(2.5 Cr-1 

Mo) 1,790 50 10

H-BP-24

Hydrocracker Outlet Cooler / Boiler Feed Water Preheat 1 A460 309.9 250.3 175.6 232.3 76.1 364,886 1,908 25 BFW Preheat 1 HC Outlet Cooler CS

 A199-T22 

or A199D 

(2.5 Cr-1 

Mo) 2,270 50 10

H-BP-25

Low Temp WGS Outlet Cooler / Boiler Feed Water Preheat 1 A500 309.9 250.0 175.6 232.3 76.0 1,641,492 25 83 A300 WGS Outlet BFW Preheat 1 A204C CS 50 80 35 

H-BP-26

Naphtha Column Condenser / WW Preheat for Steam Production A450 298.0 200.2 174.7 285.0 18.5 7,190,523 160 35 WW Preheat Naphtha Column SS316 SS316 180 35 

50 

H-BP-27

A300 WGS Outlet Cooler / Boiler Feed Water Preheat 1 A360 250.0 218.7 175.6 232.3 28.5 573,334 83 25 A300 WGS BFW Preheat 1 A204C CS 50 80 35 

H-BP-28

Low Temp WGS Outlet Cooler / Boiler Feed Water Preheat 1 A500 250.0 213.3 175.6 232.3 26.4 1,005,597 100 25 BFW Preheat 1 Low T WGS CS

 A209 (C - 

0.5 Mo) 110 35 

50 

H-BP-29

Distillate Product Cooler / Boiler Feed Water Preheat 1 A450 309.9 193.6 175.6 232.3 40.8 1,500,727 25 30 BFW Preheat 1 Distillate Product CS SS316 50 50 80 

H-BP-30

Distillate Product Cooler / HT Product to Naphtha Column Preheat A450 193.6 175.0 110.0 120.4 69.0 240,551 30 53 Distillate Product HT product SS316 SS316 50 50 80 

H-BP-31

Absorber 1 Bottoms Cooler / Boiler Feed Water Preheat 1 A310 255.0 193.6 175.6 232.3 20.3 556,211 129 25 BFW Preheat 1 Absorber 1 CS SS316 50 80 140 

H-BP-32

Boiler Feed Water Blowdown Cooler / Recycled Boiler Feed Water Preheat A600 255.0 193.6 153.4 239.4 26.0 400,090 1,326 30 Recycled BFW 

BFW Blowdown 

Cooler CS SS304L 1,580 50 10

H-BP-33

Boiler Feed Water Blowdown Cooler / WW Preheat for Steam Production A600 309.9 255.0 174.7 285.0 47.3 203,262 1,326 160 WW Preheat 

BFW Blowdown 

Cooler SS316 SS304L 1,580 180 10

H-BP-34

Absorber 1 Bottoms Cooler / Boiler Feed Water Preheat 1 A310 309.9 255.0 175.6 232.3 78.5 419,621 128 25 BFW Preheat 1 Absorber 1 CS SS304L 140 50 80 

H-BP-35

A300 WGS Outlet Cooler / Boiler Feed Water Preheat 1 A360 309.9 250.0 175.6 232.3 76.0 1,097,460 25 83 BFW Preheat 1 A300 WGS Outlet CS

 A209 (C - 

0.5 Mo) 80 50 35 

H-BP-36

A300 WGS Outlet Cooler/Condenser / Fast Pyrolysis Fluidizing Gas Preheat A360 218.7 185.0 159.7 200.7 21.4 4,868,699 82.84 127 WGS Outlet Cooler FP Fluidizing Gas A204C CS 80 140 10 

222
HX 

Name Description

Belongs 

to Area Hot In Hot Out Cold In Cold Out LMTD Duty Pres. Stream 1 Pres. Stream 2 Shell Tube Shell Material Tube Material Shell Design Pres. Tube Design Pres. U 

Stream 1 /Stream 2 F F F F ∆T Btu/h (psia) (psia)

psig 

(20% Excess, Min. = 50 psig)

psig 

(20% Excess, Min. = 50 psig)

Btu/r ft2 

°F) 

H-BP-37

Boiler Feed Water Blowdown Cooler / Natural Gas to Reformer Preheat A500 309.9 255.0 60.0 285.0 82.7 15,859 1331 200 Natural Gas BFW Blowdown CS SS304L 230 1580 40 

H-BP-39

Boiler Feed Water Blowdown Cooler / Catalyst Stripper Water Preheat for Steam A600 309.9 255.0 153.4 285.0 54.6 139,187 1331 150

Catalyst Stripper 

WW BFW Blowdown CS SS304L 170 1580 40 

H-BP-40

Ex Situ Catalyst Regen Flue Gas Cooler / Recycled Boiler Feed Water Preheat A261 309.9 255.0 153.4 239.4 85.2 156,535 107.84 29.696 Recycled BFW

Ex-Situ Catalyst 

Regen CS CS 50 110 35 

H-BP-41

Ex Situ Catalyst Regen Flue Gas Cooler / Catalyst Stripper Water Preheat for Steam A261 309.9 255.0 153.4 285.0 54.6 256,387 107.84 150 Ex Situ Regen Flue

Catalyst Stripper 

WW CS CS 110 170 35 

H-BP-42

Ex Situ Catalyst Regen Flue Gas Cooler / Water Preheat for Mix with WW for Steam A261 309.9 255.0 153.4 285.0 54.6 198,081 107.84 160 Ex Situ Regen Flue Water preheat CS SS316 110 180 35 

H-BP-43

Absorber 1 Bottoms Cooler / Water Preheat for Mix with WW for Steam A310 309.9 255.0 153.4 285.0 54.6 78,505 127.84 160 Water Preheat Absorber 1 Bottoms SS316 SS304L 180 140 80 

H-BP-44

Absorber 1 Bottoms Cooler / Recycled Boiler Feed Water Preheat A310 193.6 175.0 60.1 153.4 71.2 168,999 123 29.696 Recycled BFW Absorber 1 Bottoms CS SS304L 50 130 80 

H-BP-45

Boiler Feed Water Blowdown Cooler / Recycled Boiler Feed Water Preheat A600 193.6 170.0 60.1 153.4 69.3 154,167 1331 29.696 Recycled BFW

Boiler Feedwater 

Blowdown CS SS304L 50 1580 10

H-BP-46

Hydrocracker Outlet Cooler / Recycled Boiler Feed Water Preheat A460 193.6 175.0 60.1 153.4 71.2 114,047 1907.5 29.696 Recycled BFW HC Outlet CS

A199-T22 

or A199D 

(2.5 Cr-1 

Mo) 50 2270 10

H-BP-47

Hydrotreater Outlet Cooler / Recycled Boiler Feed Water Preheat A410 193.6 175.0 60.1 153.4 71.2 166,633 1507.5 29.696 Recycled BFW HT Outlet CS

A199-T22 

or A199D 

(2.5 Cr-1 

Mo) 50 1790 10

H-BP-48

Hydrotreater Outlet Cooler / Catalyst Stripper Water Preheat for Steam A410 193.6 175.0 61.1 153.4 70.8 277,242 1507.5 150

Catalyst Stripper 

WW HT Outlet CS

A199-T22 

or A199D 

(2.5 Cr-1 

Mo) 170 1790 10

H-BP-49

Hydrotreater Outlet Cooler / Water Preheat for Mix with WW for Steam A410 193.6 175.0 61.2 153.4 70.8 193,593 1507.5 160

Water Preheat for 

Mix HT Outlet SS316

A199-T22 

or A199D 

(2.5 Cr-1 

Mo) 180 1790 10

Total 568,440,588 

General Guidelines Used:1. Steam Turbine Exhaust / WW Preheat considered a water/steam heat exchange and allocated a U of 150 BTU/hr ft2 F2. High pressure gas heat exchange , U = 10 BTU/hr ft2 F3. Low Pressure gas heat exchange , U=5 Btu/hr ft 2 F4. Water / Gas (100 psi) heat exchange , U =35 Btu/hr ft2 F5. High pressure liquid-liquid heat exchange(~1000 psi), U = 100 Btu/hr ft2 F6. Water and distillate product (~100 psi) , U = 80 Btu/hr ft2 F7. Pressures (<800 psig: CS; 800-1400 psig: SS304L; >1400 psig A199-T22 or A199D (2.5 Cr-1 Mo))8. Default Corrosion allowance for Tube (CS): 0.0025 inches(0.06 mm) and Shell (CS) :0.125 inches (3 mm) in ASPEN ICARUS 

223
224

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Appendix I. Plant Footprint and Land Cost Calculation 

From Harris Group Inc.
225

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Table I-1. Plant Footprint and Land Cost Calculation From Harris Group Inc.

Width Length Area

Area ft ft ft2 acre

1 Truck staging, scales, scale shack, guard shack, etc. 250 500 125,000 2.9

2 Feedstock handling and storage: x2-truck 

dumps/hoppers, x2 scalping screens/hogs, x2-400’ 

diameter stacker reclaimers, and conveyors

800 1,000 800,000 18.4

3 Feedstock drying and storage: x2-dryers/WESPs/RTOs 

and x2-dry feedstock silos 200 500 100,000 2.3

4 Pyrolysis island: x2-reactors, x2-regenerators, 

bed/sorbent media handling w/ silos, ash handling w/ 

silo(s), air compressors, solids cooler, instrument air 

system, etc.

125 150 18,750 0.4

5 Vapor phase upgrading island: reactor, regenerator, bed 

media handling w/ silos, air compressor, solids cooler, 

steam stripper, instrument air system, etc.

75 100 7,500 0.2

6 Condensers: two absorber condensers, decanters, 

filters, WGS reactor, PSA, compressor 100 100 10,000 0.2

7 Hydrotreating/hydrocracking reactors, hydrogen 

compressors

50 100 5,000 0.1

8 Product separation: distillation columns 75 100 7,500 0.2

9 SMR: reformer and PSA 200 200 40,000 0.9

10 Wastewater treatment, boiler water treatment, 

condensate treatment, DA, steam distribution, power 

generation, reboiler stripper, RTO, etc.

200 250 50,000 1.1

11 Cooling towers, pumps, etc. 100 150 15,000 0.3

12 Tank farm: product tanks, fuel, chemicals, fire water, 

process water, etc. 500 500 250,000 5.7

13 Air separation plant, compressors, tanks, etc. 50 50 2,500 0.1

14 Storm water system: retention pond, etc. 200 200 40,000 0.9

15 Electrical feed, transformers, etc. 100 100 10,000 0.2

16 Electrical building 25 100 2,500 0.1

17 Control room 25 50 1,250 0.0

18 Offices, etc. 100 100 10,000 0.2

19 Maintenance shop, maintenance warehouse/yard 200 200 40,000 0.9

20 Parking, roads, etc. 500 500 250,000 5.7

21 Buffer 871,200 20.0

22 Unusable land (topography and environmentally) 1,306,800 30.0

23 Other: space in-between process areas, etc. (10% of 

process areas and buildings) 153,500 3.5

24 Easement (10% of all above) 411,650 9.5

25 Contingency (10% of all above) 452,815 10.4

Total 4,980,965 114.3

Specific Land Cost* $/acre 14,000 

Site Area acres 114.3

Total Land Cost $ 1,600,861 

*Specific land cost assumption based on USDA (2012) and Dutta et al. (2011). Basis: 2,000 dry metric tons/day feedstock basis or 

2,205 dry short tons/day. Most estimates derived from Dutta et al. (2011). 
226

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Appendix I References

Dutta, A.; Talmadge, M.; Hensley, J.; Worley, M.; Dudgeon, D.; Barton, D.; Groendijk, P.; 

Ferrari, D.; Stears, B.; Searcy, E.M.; Wright, C.T.; Hess, J.R. (2011). Process Design and 

Economics for Conversion of Lignocellulosic Biomass to Ethanol: Thermochemical Pathway by 

Indirect Gasification and Mixed Alcohol Synthesis. NREL/TP-5100-51400. Golden, CO: 

National Renewable Energy Laboratory.

U.S. Department of Agriculture. (2012). “Trends in U.S. Farmland Values and Ownership.” 

Economic Information Bulletin No. (EIB-92). Washington, DC: U.S. Department of Agriculture. 
227

This report is available at no cost from the National Renewable Energy Laboratory (NREL) at www.nrel.gov/publications.

Appendix J. Reviewer Comments on Draft Design 

Report and Responses

This appendix presents a summary of reviewer comments from draft versions of the report, 

issued for peer review in June 2014 and in August 2014. Comments from the peer review panel 

are summarized below and followed by a response from the authors. Some of the comments are 

paraphrased along with added context for clarity. Comments were combined when there were

commonalities among observations from multiple reviewers. Minor/editorial comments were 

addressed, but left out of this appendix. The responses also describe any actions taken to address 

the comments in this final version.

Area A100: Feed Handling and Drying

1. Comment: Feedstock handling capital, including drying and sizing, should be included in 

the analysis. The $80/dry ton cost may be too low.

Response: Details about feedstock logistics and cost breakdown are included in Jacobson et 

al. (2014). All the above costs are included in the $80/dry ton. This report focuses on the 

conversion aspects and includes the feedstock cost input as an operating expense. Sensitivity 

analysis showing the impact of more expensive feedstock is included in Figure 15.

2. Comment: Use of blended feedstock material can be a challenge in actual plants from a 

handling perspective. Additional equipment may be necessary.

Response: Further experiments and validation efforts led by the Idaho National Laboratory

will study the details of feed systems for the blended material.

3. Comment: For grinding to 2mm, what portion of it happens within the plant? What is the 

form of the feedstock and which operations happen onsite. The effect of particle size on 

conversion needs to be studied.

Response: The assumption of the particle size in this report is consistent with Jones et al. 

(2013). For the 2022 target case presented in this report, it is anticipated that pelletized 

material will be brought to the plant and crushed on-site before feeding to the reactor. An 

additional cross-flow dryer for warming up the feed using waste heat is included within plant 

operations in this design.

4. Comment: The low cost of feedstock at $80/dry ton is partially justified by the use of 

substantial residue (30%) and waste materials (20%). Such biomass materials come with 

significant quality/consistency issues that impact operating efficiency. These issues the 

authors abstract away using the nth plant framework. More fundamentally, by assuming that a 

mature industry with multiple operating plants has been achieved, the authors should 

recognize that within such a context there will be competition for biomass resources. Such 

competition implies that the availability of residue/waste at low cost is very questionable. 

The authors would be on more solid ground in assuming a mature industry uses plantation 

wood dedicated to feed these plants.

Response: As observed by the reviewer, the assumption of diversified material was 

deliberate for cost reduction purposes. The cost impacts of the inclusion of the various 

constituents of the blend, at different volumes, were also included by Jacobson et al. (2014). 
228

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The marginal cost of each constituent is shown to go up for higher volume demands. The 

cost of large volumes of plantation wood is expected to be higher than the blended material.

5. Comment: One of the startups using catalytic fast pyrolysis technology stated in their public 

report that their wood yard design were a significant part of their inability to achieve target 

rates. This area should not be neglected.

Response: We included areas for “Feedstock handling and storage” and “Feedstock drying 

and storage” in our design (shown in Appendix I).

6. Comment: I was surprised to see C&D waste as 20 % of the blended feed. C&D waste 

usually contains significant metal and ash contamination (e.g., iron from nails, gypsum from 

sheetrock). Is the INL blended feedstock clean of contaminants? If not, those contaminants 

should be mentioned as a risk to Area 200. Multiple reviewers questioned the impacts of 

contaminants and additional ash in the blended material (usually much higher than wood), 

along the same lines as this comment; they expressed their concerns about the impacts of 

mineral matter/ash on the organic yields.

Response: The feedstock logistics design proposed by the Idaho National Laboratory has 

specifications for ash. They discuss operations for ash removal in order to meet the elemental 

analysis specifications of the feedstock in Jacobson et al. (2014). In addition there are 

experimental plans to quantify the impacts of using the blended material on the yields from 

the various conversion pathways (including those detailed in this report). Findings from these 

experiments will be factored into future techno-economic assessments.

Area A200: Fast Pyrolysis and Vapor Upgrading

7. Comment: What was the reason for the choice of 120 psia (~8 bars) with a hydrogen partial 

pressure of approximately 75-95 psia (5-6.6 bars) in the inlet fluidizing gas for the fast 

pyrolysis reactors? These are not conventional fast pyrolysis or hydropyrolysis conditions. 

This assumption should be emphasized upfront, otherwise people do not see that there is a 

deviation from conventional pyrolysis at near atmospheric conditions.

Response: Based on this and similar comments, we made these assumptions very 

conspicuous in the Executive Summary and the Introduction sections, as well as Section 

3.2.1.5 dedicated to this aspect.

8. Comment: The liquid yield and oxygen content for the organic phase in this report do not 

coincide with Figure 1. For that oxygen content the yield would be near 20% and here your 

yield is near 30%. I understand you are looking at a process that uses hydrogen and elevated 

pressure, but it would be great if you could state where these yields came from, either 

experimental data or a projection, somewhere clearly in the Area 200 description. Figure 11

shows that >50% of the LHV is recovered as fuel-range hydrocarbon products in each case. 

Again, this is very dependent on process yields, so it is good to be very clear on where you 

obtain those.

Response: We have since made it very clear that this design report details target cases for 

2022. Figure 1 is reflective of the current state of technology. We have separately developed 

a state of technology assessment, and initial annual targets leading up to 2022, based on the 

process designs detailed in this report; those results are expected to be published in BETO’s

Multi-Year Program Plan.
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9. Comment: There were several comments about Figure 1, including (a) reasons for 

differences among data points and whether they were caused by differences in catalysts or 

different reaction conditions, (b) the draft version had a discussion using catalyst to biomass 

ratios, while the figure shows the inverse (biomass to catalyst ratio) on the x-axis, (c) 

whether the results are for in situ or ex situ, (d) more clarity in the text surrounding the 

discussion of the figure.

Response: Figure 1 was previously published in a journal article. Details about the individual 

data points are available in the cited literature. We have modified some of the text around the 

figure based on reviewer comments. The main purpose of the figure is to show that we tend

to lower yields as we deoxygenate the organic product. This is a key challenge for us in 

meeting our 2022 goals with both high yields and significant deoxygenation. This figure 

highlights the need for catalyst research and exploring new catalyst materials and chemistry 

to accomplish our goals.

10. Comment: Many comments reflected that the draft version did not sufficiently emphasize 

that we are showing designs for target cases, rather than the current state of research.

Response: Please see the response to Comment 8. Based on this recommendation, the title of 

this report was modified to include “Research Pathways,” and key table captions were also 

modified to state that these are 2022 targets.

11. Comment: Multiple reviewers of the draft report wanted to see more discussion about 

catalysts. Their comments included (a) the likely necessity to use catalysts with different 

functionality compared to zeolites like ZSM-5, which produce aromatics, (b) mentioning new 

chemistries that can promote lower oxygen at higher yield, (c) queries whether 

confidentiality constraints were stopping the authors from disclosing more about the 

catalysts, (d) requests for the inclusion of some catalyst background for the reader to be able 

to appreciate the relevance of these conversion pathways.

Response: Section 3.2.1.6 was added to discuss some of these aspects. Since this report is 

focused on the process design and techno-economics, we limited the discussion and pointed 

out review articles as additional resources on this topic.

12. Comment: The use of a hot gas filter (HGF) may be necessary, even in the case of a 

circulating fluidized bed (CFB) ex situ reactor. The two preceding cyclones may not be 

sufficient to remove finer entrained mineral matter that can deactivate catalysts. The current 

design assumes two cyclones prior to the CFB ex situ reactor. It was pointed out that the 

statement in the draft version about “only a small proportion of fine solids” needed to be 

qualified.

Response: Irreversible deactivation from contaminants is mentioned in the current version. 

We also mention that an HGF may be necessary based on future experimental data.

13. Comment: The draft report used the term ash to refer to all biomass inorganic content. It was 

pointed out that there is a difference between mineral matter and ash. Ash is the product after 

biomass combustion.

Response: We adopted the suggestion and made changes to the text to reflect this. However, 

it should be noted that much of the literature on this subject uses the term ash for biomass 

inorganic content in all contexts, because ash is the eventual measurement of inorganic 

content.
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14. Comment: It should be pointed out that mineral matter is contained in the char from the 

pyrolysis reactor.

Response: We added this to the text in Section 3.2.1.

15. Comment: Call out the content of char entering the char combustor and mention that the 

char/sand mixture flowrate has been adjusted to maintain thermal balance so that the heat 

supplied by char combustion is equal (more or less) to the heat required for the pyrolysis 

step.

Response: In order to further convey this point we added text to say that pyrolysis is 

endothermic. Char and all other component flow rates are included in the stream summary 

tables in Appendix G. Percent char produced is shown in Table ES-1.

16. Comment: How much coke is deposited on the catalyst in the in situ case? FCC catalysts 

come out of the riser with 1-2% coke.

Response: In the 2022 target case there is 1.1% coke on the catalyst leaving the in situ

catalytic fast pyrolysis reactor. Details are available in the steam summaries in Appendix G.

17. Comment: Attrition rates assumed in the draft report were too low.

Response: We feel the catalyst replacement rates assumed in the final draft cover this 

concern adequately. A total of 3.6% of the catalyst inventory is assumed to be replaced per 

day in both the in situ and ex situ cases.

18. Comment: It was noted that some of the key catalyst performance goals are competing. For 

example, increased coupling may lead to more liquids, but may also lead to more coke 

formation. Furthermore, increased liquid yield may decrease hydrogen efficiency.

Response: The goal of the research is to overcome these obstacles. Also, the use of separate 

reactors operating with different catalysts and different reaction conditions will be considered 

as we consider additional process options in the future.

19. Comment: The catalyst cost at $6,500/ton in the draft seemed 3 to 8 times low.

Response: We increased the unit cost of the catalyst three times to $19,500/ton or $9.75/lb. 

Note that the actual cost will depend on modifications made to the catalyst based on research. 

This unit cost is higher than FCC catalyst costs, which was the basis of our initial assumption 

of $6,500/ton or $3.25/lb. We also allow for 3.6% of the catalyst inventory to be replaced per 

day. This leaves room for the research to develop less expensive catalysts with higher losses,

or more expensive catalysts with lower losses to meet the cost targets.

20. Comment: With the recent commercial challenges, it may be difficult to accept the 

utilization of FCC upgrading equipment (circulating fluidized bed reactors).

Response: The research will have to experimentally justify and demonstrate achieving some 

of the target metrics using circulating fluidized bed reactors. This technology has been 

successfully scaled up for biomass fast pyrolysis; we chose this option in our design for that 

reason. The ex situ upgrading case will have additional fixed bed options as mentioned in the 

text.
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21. Comment: Total capital costs in the initial draft seemed high in both the in situ and ex situ

cases. Some Catalytic Fast Pyrolysis systems have been reported for 50% of the costs shown 

in the draft report.

Response: The equipment costs were since adjusted in the final version, especially for the 

use of higher than ambient pressures. There were savings from the use of 120 psia pressures 

because of reduced reactor volumes (estimated by the Harris Group). We were careful to not 

underestimate the costs, and used higher installation factors of ~

4 for the reactor and the 

regenerator in the final version.

22. Comment: For the ex situ case the benefit of adding hydrogen to the fast pyrolysis reactor is 

negligible, so why not add hydrogen only to the ex situ vapor upgrading reactor?

Response: The reason we chose to add hydrogen to the front end instead of the ex situ

reactor only was because of concerns about the dilution of hydrogen and lowering the partial 

pressure. We do need a certain amount of fluidizing gases, so inclusion of hydrogen in the 

mix allows us to not add other gases for fluidization in the fast pyrolysis reactor.

23. Comment: The initial design specified a pressurized (~120 psia) reactor and a near 

atmospheric combustor, with intermediate lock hoppers in order to lower compression costs 

for air fed to the combustor. There were many comments about this design, especially with 

respect to costs and reliability of such a system, and it was recommended that the system 

should be designed with similar reactor and combustor pressures.

Response: The recommendation to operate the reactor and combustor at comparable 

pressures was adopted in the final design. The electricity credit was reduced because of 

higher compression requirements, but we agreed that this is a more reliable design.

24. Comment: The simplified flow diagrams in the report do not adequately reflect the 

complexity of the systems described such as solids coolers and lock hoppers (in the previous 

draft). More details should be presented.

Response: Appendix G includes detailed process flow diagrams along with stream tables.

25. Comment: How was the 5:1 catalyst to biomass ratio concluded?

Response: This is an initial assumption, and will likely be modified with more experimental 

results. This ratio will depend on the steady state activity of the catalyst, which is affected 

significantly by the reactor configuration and whether the system is a truly circulating 

fluidized bed system. Although Figure 1 shows results from different experimental 

configurations, it indicates that ~

6% oxygen content oil can be produced with an approximate 

5:1 catalyst to biomass ratio (0.2 biomass to catalyst ratio). As mentioned in this report,

significant yield improvements will be necessary via catalyst research to achieve our 2022 

yield targets, even as we achieve an oxygen content of 6%. Our choice for this design was 

influenced by this consideration. 

26. Comment: In both cases, stripping steam is used to recover additional product. How much 

extra yield is assumed? How was this concluded? And is it really worth the extra yield to add 

this extra unit operation? 

Response: This assumption was consistent with FCC systems where steam helps recover 

additional hydrocarbons from the catalyst before regeneration. The tradeoff between capital 
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costs, product recovery, and impacts on catalyst maintenance will need to be assessed 

experimentally for biomass systems during our research.

27. Comment: What is the organic yield and composition (CHON) for both the in situ and ex 

situ cases? What is the basis for this yield?

Response: The organic liquid yields are shown in Table ES-1, and mass percent C, H, O are 

shown in Table 6 under Area 300. These are targets to achieve cost-competitive fuels 

production from biomass by 2022. The yield bases for 2022 were derived using these 

considerations: (1) organic yield maximization while still allowing reasonable coke and gas 

losses, (2) the yields needed to be in the range where the process was economically feasible, 

and (3) the ex situ case had the added target for higher diesel-range product.

28. Comment: What is the non-condensable gas composition from the in situ and ex situ

reactors?

Response: We have included detailed flow diagrams and stream summaries in Appendix G, 

where the gas composition information is also included.

29. Comment: What is the hydrogen consumption in the in situ and ex situ process?

Response: Hydrogen consumption by difference of reactor inlet and outlet gas composition 

in the in situ and ex situ 2022 target cases are 1.3 and 1.8 wt.% of dry biomass, respectively. 

Please note that this consumption can be significantly impacted by water gas shift 

assumptions. The other metrics such as H/C ratio, oxygen content, and organic liquid yields 

provided in Table ES-1 are more reflective of the extent of desirable reactions involving 

hydrogen.

30. Comment: Why is the ex situ case bio-oil oxygen content lower than in the in situ case?

Response: The catalyst performance assumptions are more aggressive for the ex situ case, 

based on some of the potential advantages outlined in Table 3.

31. Comment: Why is the in situ yield (75 gge/ton) lower than the ex situ yield (78 gge/ton)? 

Response: In this 2022 target design, the yield differences are primarily because of the 

higher losses during the hydrotreating of the in situ process bio-oil. The in situ process biooil has higher oxygen content and losses are estimated based on Figure 8.

32. Comment: Why is the catalyst loss rate lower for ex situ compared to in situ? 

Response: Although both the in situ and ex situ cases assume total catalyst replacement rates 

of 3.6% of the inventory per day, the catalyst (bed solids) inventory itself is assumed to be 

larger for the in situ case (Table 4) because of the disadvantages of the catalyst mixing with 

bulk solids such as biomass, char, and mineral matter/ash within the reactor, as outlined in

Table 3.

33. Comment: Add a sensitivity case for 20% oxygen content in the organic liquid with 

atmospheric pressure and 5 bars pressure, using hydrogen only downstream. Outline the 

impact on capital costs (because of larger volumes) in such a case.

Response: We will consider adding such a case during our future analysis. We could not 

include the case in this report because of time constraints. We did add a discussion about 

hydrogen and pressure in Section 3.2.1.5. Even without any consideration of potential 
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benefits to the chemistry (which will need to be experimentally proven with future catalyst 

development), we anticipate some negative impacts on the economics because of larger 

reactors.

34. Comment: Show how you can bring down the cost further from less than $3.5/GGE to 

$3/GGE.

Response: Figure 15 shows sensitivity cases and the key areas where we can make further 

impacts. As pointed out by another reviewer, we can optimize the operating scales and 

related handling of intermediates after some maturation of the technology, and our nth-plant 

assumption in this regard may be sub-optimal; economies of scale alone can bring down the 

cost significantly. There is some conservatism in the assumption of catalyst losses of 3.6% of 

the inventory per day (especially for the ex situ case); this may be another area of further cost 

reduction.

35. Comment: Show sensitivity to the modeled dew point in the condensation train and how 

much of an impact changes in this temperature impact the process and economics. 

Response: The reviewer’s comment was based on the assumption in the initial design that 

we can have indirect heat exchange down to the dew point of the pyrolysis vapors. In the 

final design we assumed direct quench below the dew point to avoid fouling heat exchangers. 

The impact is shown in sensitivity Case 22 in Figure 15.

36. Comment: Discuss the basis for sizing and scaling of the combustor. Parameters that should 

be discussed include superficial velocity, % of stoichiometric air used, scaling variable used 

(should be related to superficial velocity).

Response: We have added this discussion in Section 3.2.

37. Comment: From the perspective of solids carryover to the quench system, it may not be 

necessary to have a hot gas filter (HGF) provided the cyclone efficiencies match the Particle 

Size Distribution (PSD) of the catalyst. In this context it may be useful to remove fines from 

fresh catalyst before introducing into the reactor. Granted some char will carry over, 

especially for the in situ case, but that alone will not necessitate a hot gas filter.

Response: Thank you for your valuable insights.

38. Comment: Hydrogen embrittlement considerations for the reactors should be mentioned in 

the text.

Response: We have included this along with a reference.

39. Comment: It is important to pay close attention to siting, economies of scale, use of 

merchant hydrogen taking advantage of economies of scale to reduce costs.

Response: This is a generic design for a standalone plant at a U.S. location. We do 

understand that there are numerous advantages to be had from an optimal location, but we 

did not want to make this design too specific and tied to other considerations; those factors

will likely be leveraged more efficiently by commercial entities.

40. Comment: The incentives for ex situ should be bigger than the in situ case, leveraging 

hydrogen addition; it is less clear whether hydrogen addition will be possible in the in situ

case. For a yield of 29%, the trend line in Figure 1 in the study design would suggest a 

pyrolysis oil oxygen level closer to 20 % vs. 10.8% assumed in the study; if these numbers 
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are confirmed then it seems that the benefits in this process are derived primarily from the 

introduction of hydrogen.

Response: The anticipated benefits from hydrogen addition are larger for the ex situ case, as 

reflected by the more aggressive 2022 targets compared to the in situ case. It has been further 

clarified in this final version of this report that the cases shown here reflect target cases, and 

not the current state of catalyst performances as reflected by Figure 1. The 2022 case is 

targeted to significantly improve on the performances shown in Figure 1. The benefits 

through research is expected from not just the introduction of hydrogen, but also through the 

use of developed catalysts that are capable of beneficially using the hydrogen at the reaction 

conditions during vapor upgrading.

41. Comment: It is not at all clear why the two cases produce such differing amounts of gasoline 

vs. diesel. This raises questions about the product distillation curve and the hydrocracker 

design. 

Response: Targeted coupling reactions will be one of the objectives of ex situ catalyst 

development. Coupling reactions are expected to allow the production of larger molecules, 

including more molecules in the diesel range. This is the reason for a larger proportion of 

diesel in the ex situ product as the 2022 target.

42. Comment: Is the distillation curve for the 10.5 % oxygen (in situ) product assumed to be 

significantly different than for the 6.4 % (ex situ) product? Data from previous work 

suggested that significant boiling point changes occur below 5% oxygen in the case of fast 

pyrolysis. Here the oxygen level for the hydrocarbon feed is assumed to be higher than for 

the hydrotreated product (in the previous cases with 5% oxygen after hydrotreating of raw 

pyrolysis oil). Why is this assumption made? Is there data to support this? 

Response: Note that we are not aiming to directly blend the material targeted at 10.5% and 

6.4% oxygen for the in situ and ex situ 2022 cases, respectively, into fuel products. The 

downstream hydroprocessing is aimed to further reduce the oxygen content to below 1% 

before it can be considered for blending into gasoline and diesel. The 2022 targets for the 

final product in this report are close to the low oxygen content (LOC) products characterized 

by Christensen et al. (2011), which were considered blendable into gasoline and diesel.

43. Comment: It is noted that the design calls for the diesel fraction from the hydrotreater to be 

sent to the diesel pool. Given what is known about the poor quality of pyrolysis oil diesel, we 

would think it will require upgrading via hydrocracking. Specific data about diesel product 

quality should be provided, given that a substantial portion of ex situ economic advantage 

derives from producing more diesel and less gasoline range material.

Response: As noted in the Conclusions section, product characterization and quality 

specifications specific to these processes will become important with advances in the 

research for these pathways. We expect that in the post-2017 timeframe significant attention 

will be paid to quality aspects and the development of associated targets for refinery 

integration. This may include targeting the hydrocracking operations, already included in this 

design, toward better quality products, including the possibility of ring-opening chemistry.

44. Comment: The riser diameter on the ex-situ pyrolysis reactor was limited to 1000 tons/day. 

What limits the riser diameter?
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Response: The limitation of 1,000 tons/day per fast pyrolysis reactor train was based on 

biomass feeding constraints and not the riser diameter.

45. Comment: FCC units that can operate with only two cyclones on their regenerators do not 

usually meet U.S. emissions standards for particulate matter. Typically, a wet-gas scrubber 

(preferred), electrostatic precipitator, or baghouse is required. Perhaps a tertiary separation is 

not necessary for sand, but one will be required for ZSM-5. A flue-gas scrubber was 

mentioned with a reverse-osmosis system for the water product, but there was no other 

description of the equipment.

Response: We do not describe the system in the main report because it is mature technology, 

but have included the source of the scrubber information used for our costs in Appendix A. 

The information was originally obtained for use in Dutta et al. (2011).

46. Comment: Will the regenerators handling ZSM-5 be operated in full or partial-burn mode? 

Partial burn requires a separate CO boiler.

Response: We assumed full burn with 20% excess air, along with an associated catalyst 

cooler.

47. Comment: In the draft version it was mentioned that the ex situ catalyst operates in a “more 

benign reaction environment”. It should be further stated that irreversible catalyst 

deactivation from impurities such as alkali can be reduced by the upstream removal of solids. 

In addition it is important to point out the flexibility to operate at different conditions 

compared to the fast pyrolysis reactor in the ex situ approach; this can have advantages in 

carbon efficiency, higher selectivity to target products and reduced deactivation.

Response: Thank you for the valuable comments. All the points were included in this final 

version.

48. Comment: It was not clear if there was a continuous feed of steam (mentioned for stripping 

the catalyst) to the reactors or a feed to the regeneration cycle.

Response: In this conceptual design the stripping steam is fed after the catalyst is separated 

from the vapors, similar to FCC units. The function is to strip out any volatiles from the 

catalyst that would otherwise go to the regenerator and be combusted. 

49. Comment: In terms of deoxygenation, does your model suggest that hydrodeoxygenation 

pathways would be preferred to decarboxylation / decarbonylation reactions.

Response: Carbon efficiency is of prime importance for increasing fuel yields. Unlike in 

syngas-based processes, any carbon not already incorporated in liquid-range molecules after 

vapor upgrading (in these in situ and ex situ conceptual process designs) cannot be 

reincorporated into liquid phase products. Thus hydrodeoxygenation is the preferred route for 

deoxygenation to avoid carbon losses as CO and CO2.

50. Comment: What is meant by “more favorable reaction chemistry” in the context of ex situ

vapor upgrading?

Response: We meant desirable reactions such as hydrodeoxygenation, hydrogenation, and 

coupling. We have added this to the text.
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51. Comment: What are the purported benefits of reducing oxygen content to 6.4% in the ex situ

case? Does this allow dropping into an existing refinery, or does it allow removing extra 

hydrodeoxygenation units?

Response: Compared to raw pyrolysis oil hydrotreating (Jones et al. 2013) where three

hydrotreating steps are included in the design, this conceptual process assumes a single step 

hydrotreater, which is assumed to be made possible by the lower oxygen content in the biooil; this will be experimentally verified with progress in research. The 6.4% oil is not deemed 

suitable for blending into refinery products; it may however be possible to feed this 

intermediate into a petroleum refinery for further processing (Christensen et al. 2011).

52. Comment: Inclusion of a comparison between in situ and ex situ will be useful.

Response: We included this in this final version (Table 3).

53. Comment: Need to be consistent with the use of the terms “vapor upgrading” and “vapor 

phase upgrading”. At one point it says “vapor phase upgrading” is for ex situ.

Response: We made them consistent in the final version.

54. Comment: It was mentioned that the pyrolysis reactor has sizing constraints due to biomass 

feeding. It is unclear why those constraints are gone just by switching to an ex situ

configuration. The system is still using a pyrolysis reactor upstream of the ex situ reactor. 

Are you saying 2 pyrolysis reactors feed into 1 upgrading reactor? If so, you have 3 total 

reactors for ex situ and 2 for in situ...how does that reduce cost for the ex situ system? Please 

make this clearer.

Response: The reviewer correctly pointed out that there are more reactors in the ex situ

system, hence the total capital costs are higher compared to the in situ system. However, the 

single larger ex situ reactor is less expensive compared to the combined cost of two-train 

reactors necessary for fast pyrolysis (Table 5). The language in the text was modified in an 

attempt to make this more apparent.

55. Comment: Is the inclusion of metals factored into the catalyst costs?

Response: We did factor the inclusion of metals into the cost. Also, based on reviewer 

comments we made significant upward revisions to the assumed catalyst costs for in situ and 

ex situ vapor upgrading.

56. Comment: The regeneration temperature for zeolites is typically < 650°C. 

Response: We reduced the regeneration temperature in the versions after the June 2014 draft. 

The temperature was higher in the June 2014 draft version, based on FCC catalyst 

regeneration temperatures from literature.

57. Comment: Do you have any olefins in the gases? Are they all utilized in coupling reactions? 

Typically quite significant fractions of olefins are formed. 

Response: We did not use coupling reactions for light olefins in the gases for the 2022 cases. 

Additional coupling of olefins can be beneficial to yields.

58. Comment: Why is the assumed heat loss lower for the ex situ reactor compared to the fast 

pyrolysis reactors? Is it because of the assumption of a single train for the ex situ reactor?
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Response: Yes, the rationale was lower losses in the single train ex situ reactor compared to 

two trains for the fast pyrolysis reactor.

59. Comment: When mentioning “better quality oil” in Figure 1, it should be mentioned that 

oxygen content alone does not dictate the quality of oil. It is a function of functional groups. 

For example phenols are preferable to acids. Some catalytic pyrolysis oils still contain some 

of the reactive species.

Response: We added the mention of reactive functional groups to the section around Figure 

1.

60. Comment: “Efficient hydrogen utilization, which ties into reduced aromatics in the product, 

reduced coke formation, and greater hydrodeoxygenation to allow higher carbon efficiency”. 

How is hydrogen efficiency measured?

Response: The effectiveness of hydrogen use during vapor upgrading is measured by the 

combination of the three metrics: H/C ratio, oxygen content, and yield of the organic liquid 

product.

61. Comment: Is there a problem of having hydrogen in the reactor of the circulating fluidized 

bed (CFB) system with the presence of oxygen in the combustor?

Response: Gases and vapors from the reactor do not flow into the combustor side of the CFB 

system. In a typical system, solids such as char are separated in a cyclone and then sent to the 

combustor, with a seal created by the solids in a standpipe. The oxygen reacts with the solids 

and the hydrogen-rich gases on the reactor side should not flow into the combustor.

62. Comment: Is stripping supposed to be within the continuous process or is it separate? It 

doesn’t appear on the process flow diagram. 

Response: Stripping steam is part of the continuous process. It is not shown in the simplified 

process flow diagrams in the main report. However the detailed process flow diagrams and 

stream summaries in Appendix G include this information.

63. Comment: What types of reactions cause the heat balance in the ex situ reactor to be 

exothermic?

Response: Hydrogenation and hydrodeoxygenation reactions are typically exothermic. 

Product distributions before and after the ex situ upgrading reactor can be found in Appendix 

G.

64. Comment: Explain how the capital cost of the fast pyrolysis reactor compares with Ensyn’s 

published values; those were used by Jones et al., 2013. 

Response: Please see comment 21 for a related response. The costs of the systems in this 

design are lower because of smaller volumetric flow rates as a result of higher pressures (~6 

times Jones et al. 2013). Although a direct comparison is not possible without going back and 

modifying the design by the Harris Group, a quick check by changing the cost by a factor of 

6 (for the larger volume) to the power of 0.5 (scaling exponent) for the reactor and combustor 

gave an installed cost very close to the one in the Jones et al. 2013 report.

65. Comment: “The fluidizing gases are rich in hydrogen because of a deliberate attempt to 

create a hydrogen-rich atmosphere to impact the chemistry favorably.” Please explain what is 
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meant by favorable. Is it to reduce coking? At these conditions it is unlikely to cause 

hydrogenation. 

Response: Favorable chemistry includes hydrodeoxygenation and reduced coking as nearterm targets. Hydrogenation, although difficult, is not impossible. Hydrogenation will be one 

of the longer-term targets.

66. Comment: It is worth adding more information about the chemistry of all the processes 

considered, especially of the catalytic pyrolysis and catalytic vapor cracking. What kind of 

products and with what yields can be obtained from those processes. Mass balances for all 

the stages should be better visible, in addition to tables within the text; suggest providing 

stream sizes in the process flowsheets.

Response: The processes represent 2022 targets. We will develop further understanding of 

the chemistry with research progress and modify the chemistry accordingly; some of the 

chemistry assumptions will be specific to catalysts being used. In the simulation we used 

conversion blocks to represent the key functionalities of hydrodeoxygenation, hydrogenation,

and coupling. Detailed stream information is provided in Appendix G of this final version; 

products and the assumed chemistry can be seen in those stream summaries. 

67. Comment: It is not quite clear how the size of the pyrolyzers and the vapor cracker were 

calculated. In Table 4 the weight ratio of the fluidizing gas to biomass is equal to 0.86, which 

may be too low. Even bubbling beds usually operate at the ratio >2; the entrainment of solids 

requires significantly more gas (Ut/Umf=72).

Response: Note that the reactor conditions, especially the slightly elevated pressure and gas 

properties such as density, and drag coefficient (because of the presence of hydrogen) are 

different from typical fast pyrolysis systems. In addition the reactor dimension has an impact 

on the velocities. Based on the reviewer’s observation, Anna Trendewicz conducted 

simulations using the model described in Trendewicz et al. (2014) to validate whether the 

reactor was in entrained flow mode for the conditions assumed for the model in this report; 

her results showed that we are in the correct regime.

68. Comment: Organic yield of 64 wt % (fast pyrolysis intermediate in ex situ case) is certainly 

high, considering you feedstock ash content. My correlation with the ash content of 0.9 wt% 

gives me 54.2 wt% (based on dry ash free feed).

Response: The feedstock ultimate analysis specifications we used are based on woody 

biomass, and the yield assumption is based on yields reported for such systems and 

mentioned by Jones et al. (2013). We understand that there are variations in ash within 

woody biomass samples, which can affect yields. With progress in research the impacts of 

ash and blended material based on experimental results will need to be factored into the 

analysis.

69. Comment: In the draft report a reference was provided for the design of the combustion 

section, which is very secondary. A source of the reactor design criteria should be provided.

Response: Information about superficial velocity and residence time assumptions for the 

reactor section was added to the text. The tool described in Worley and Yale (2012) was used 

by the Harris Group for the reactor design.
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Area A300: Pyrolysis Vapor Quench and Product Recovery

70. Comment: The initial draft had an indirect heat exchanger condensation train; multiple 

reviewers questioned the feasibility of such a design because of potential fouling problems. It 

was called out that even with 6% oxygen content the product may not be stable enough to 

allow indirect heat exchange.

Response: We modified the conceptual design to include direct cooling using two 

absorber/condensers (shown as the high temperature absorber/condenser and low temperature 

absorber/condenser in Figure 6). Indirect cooling was limited to the portion prior to the onset 

of vapor condensation, and the section after most of the heavy material was removed from 

vapor stream. Lighter fraction bio-oil was used for condensing the heavy fractions in the first 

absorber/condenser. The final cooling of the entire lighter fraction occurs in a second

absorber/condenser.

71. Comment: Pyrolysis vapor fractions condense at different temperatures. The heavier the 

fraction the higher the temperature. See some of Professor Robert Brown’s work for specific 

fractions. That means that staged coolers upstream of the flash tank will foul. (Note that the 

initial draft had a flash tank instead of the first absorber/condenser used to knock out the 

heavy organic material; this comment was based on the initial draft.) Inherent is an 

assumption that if you add catalyst (in situ) or upgrade the vapors (ex situ), the product will 

be more uniform with respect to condensation temperatures; I don’t think this will happen.

Response: This and other comments were the reason for us to move toward a design with 

two separate absorber/condensers, first for the heavy fraction and the second for recovering 

the lighter fraction (shown as the high temperature absorber/condenser and low temperature 

absorber/condenser in Figure 6).

72. Comment: The chilled water heat exchanger cools the process permanent gases. These gases 

are split into 3 streams (that seems very difficult to accurately control), and the stream 

directed into the water gas shift reactor with an inlet temperature of 464°F, gases compressed 

to 214 psia (note temperature and pressure are for the ex situ case, and were slightly different 

in previous draft version). Where does the heat come from for this reactor, is it from steam? 

The non-condensable gases are also cooled compressed and re-heated. How is the heat 

provided?

Response: The non‐condensable gases are split into three streams. One of them is a purge of 

1%, which will be a bleed and does not need accurate control. In practice this will be a two‐

way split between water gas shift (WGS) and recycle, after an initial bleed. This should be 

doable, especially because you can allow a range of pressure drops on the WGS side because 

that operation is not affected to any significant extent by slight variations in operating 

pressure. The heat for the WGS preheat comes from process heat exchange (exchanger 

network for the ex situ case is provided in Appendix H of this final version). The gases are 

cooled in the absorber/condenser and reheated for WGS; recompression to 214 psia happens 

before the PSA after cooling of the WGS outlet.

73. Comment: (This comment was based on the design in the draft version where the first 

absorber/condenser for recovering the heavy fraction was not present; instead there was a 

flash drum after indirect heat exchange.) The dew point of water at 116 psia is 339°F per 

references. Water will be condensing long before reaching the flash drum temperature of 
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110°F. Later it is pointed out that there are issues with heavy hydrocarbons present in the 

Area 200 effluent vapor. “I think you need to plan to cool the effluent to no less than 350°F, 

which will, unfortunately, push a substantial cooling load into the absorber, adding 

exchanger surface area and tower diameter. The higher condensation temperature is another 

challenge introduced in the design by the desire to add hydrogen (at pressure) to the 

upgrader.”

Response: The dew point consideration was the primary reason for changes in the design and 

the inclusion of two absorber/condensers as mentioned in response to some of the previous 

comments. The Aspen Plus model predicts a condensation temperature of 466°F for the 

vapor stream prior to the high temperature absorber/condenser in Figure 6. Note that this is 

the dew point of the mixture, and not the pure component dew point of any specific 

compound; condensation is affected by partial pressures of all constituents. Very little water 

is condensed in the first absorber/condenser (included for knocking out the heavier 

components); it has a bottom stream temperature of 461°F (ex situ 2022 target case). Less 

indirect heat recovery is now possible because of the inclusion of this design change with a 

high cut-off temperature (466°F) on indirect heat recovery (as pointed out by the reviewer: 

“push a substantial cooling load into the absorber”).

74. Comment: The filter for removing particulate matter from the liquid hydrocarbon should be 

placed in front of the oil/water separator, which will increase its size significantly (the draft 

report for review had the filter only for the organic phase product stream after condensation 

of the vapor upgraded stream). Otherwise, particulate matter in the oil/water separator will 

likely form a stable emulsion (rag layer) and prove exceptionally difficult to separate. The 

oil/water separator might also require pH control, depending on the presence of residual 

acidic oxygenates and for emulsion control. Process chemicals for such need to be included 

in your off-sites basis if not already required for water and wastewater treatment.

Response: Per this recommendation the entire condensed liquid stream is filtered in this

updated final design. Wastewater treatment was significantly modified in the final design, 

with a separate section (Area 800) for the destruction of organics in the water from the 

condensers in Area 300. Also, assumed costs for wastewater for the rest of the plant 

operations were conservative (based on a unit treatment cost for streams that are more 

difficult to treat). Any additional chemical costs (if necessary) can be absorbed within those 

treatment costs. Also, from our current experimental results, carboxylic acids are expected to 

be negligible for organic liquid products with oxygen contents of 15% or less. We assumed 

stainless steel for most of the equipment to handle anticipated acidity (Appendix A).

75. Comment: An understanding of the impurity profile into the water gas shift (WGS) reactor 

will be important in specifying the catalyst and hence the operating temperature (and hence 

determining equilibrium limitation on conversion). Copper catalysts are the commercial 

standard for low temperature water gas shift, but experience short lifetimes in the presence of 

inorganic impurities such as S and Cl. If impurity levels are high there is the option to use 

guard beds to absorb these impurities (additional cost). Alternatively, a non‐copper catalyst 

(e.g. iron‐based high temperature shift) may be more appropriate, but this would require 

higher operating temperatures to compensate for the lower activity.
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Response: The design was modified to have a single step “dirty shift” or sour water gas shift 

catalyst as mentioned Section 3.3.1 of this version. Operating temperature was higher than a 

low temperature shift reactor, and a positive 35°F approach to equilibrium was assumed.

76. Comment: Are there one or two organic phases? Usually you will form two organic phases, 

with a top fraction (s.g. < 1) and bottom fraction (s.g. > 1). This is the case even with highly 

deoxygenated product, although there is less of the bottom phase and maybe better catalysts 

and processes can eliminate the heavy compounds.

Response: The model does not have the capability to predict three liquid phases (two

organics and one aqueous with dissolved hydrocarbons). Hence we are working with the total 

organic liquid predicted. There is potential for improvements in this area with the progress in 

research.

77. Comment: Was there water in the predicted organic phase?

Response: There was some water predicted in the organic phase (~0.4% in the ex situ

version of the simulation). Again this is an area for improvement and we are working on 

phase equilibrium prediction methods as part of our research.

78. Comment: How much steam is fed to the water gas shift reactor in A300?

Response: A steam to gas (after subtracting hydrogen) molar ratio of 1.2 was assumed for 

this sour gas shift design. Appendix G shows stream flows.

79. Comment: Effective filtering is needed to prevent fines carryover into downstream organic 

liquid upgrading.

Response: As noted in response to comment 74, filters were included in all liquid streams. 

We added a note in the text to emphasize their importance.

80. Comment: The possibility of fouling the heat exchangers may also be due to physically 

entrained aerosols sticking on the surface, not just reacting pyrolysis oils.

Response: This is another reason we switched to a direct quench absorber/condenser at a 

relatively high temperature (see comment 73) for the first vapor condensation step.

81. Comment: In the previous draft with a flash tank (instead of a heavy organics 

absorber/condenser in this final version) 92% of the bottoms product was being cooled and 

pumped in the single absorber/condenser. A reviewer pointed out that one should be aware of 

the potential high viscosity and the difficulty of pumping the liquid after cooling.

Response: In the updated design we only use the light organic liquid from the second 

absorber/condenser as the quench stream in both the heavy and light fraction

absorber/condensers (also called the high temperature and low temperature 

absorber/condenser in Figure 6 to alleviate this concern). The heavy organic fraction is 

maintained at a relatively high temperature of 140°F until it is mixed with the lighter organic 

portion.

Area A400: Hydroprocessing and Product Separation

82. Comment: “85% carbon efficiency for 20% oxygen content, and 98.5% carbon efficiency 

for negligible oxygen content as is usually the case in petroleum refineries.” Is the yield for 

the 20% oxygen content feed consistent with current data in the literature?
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Response: There is limited data currently available for large-scale hydrotreating of organic 

products in the range of oxygen content of interest in this report. As described in Figure 8, 

we interpolated carbon efficiencies using the oxygen contents in the feed. Additional data 

points will become available with further experiments in the coming years. Also, note that 

the carbon efficiency assumption is consistent (and conservative), with respect to 

hydrotreating of intermediate oxygen content products within the interpolated range in Figure 

8 for products obtained from hydrothermal liquefaction of woody biomass, as interpreted 

from the data made available by Zhu et al. (2014).

83. Comment: “A WHSV of 0.5 h-1 usually translates to a lower LHSV for most feedstock and 

catalyst combinations with an example of such conversion provided by Elliott et al.” Are the 

catalysts used in this work along with yields used in the design basis? If not, what are the 

catalysts? Multiple reviewers wanted to see specific mention of the types of catalysts 

assumed for hydrotreating and hydrocracking.

Response: Catalyst assumption information was added in Section 3.4.1. Non-precious metal 

catalysts were assumed for hydrotreating. The preliminary data point from PNNL shown in 

Figure 8 was obtained using a non-precious metal catalyst.

84. Comment: In Section 3.4 of the draft version the introduction of sulfur was mentioned. Do 

you talk about this anywhere later in the report?

Response: Further discussion was added to Section 3.4.

85. Comment: Do the number of hydrotreating reactors include swing reactors? This should be 

stated.

Response: Swing reactors were not used in the base case. However, cost sensitivity when 

using swing reactors for hydrotreating is shown in Case 25 of Figure 15.

86. Comment: In the draft version it was mentioned in Section 2.2 that the product was “easier 

to hydrotreat”. This is presumably true. But the remaining O when oxygen content gets to 

low levels is actually more difficult to hydrotreat compared to the “easy” O removed early 

on. The effect of this O on HDN and HDS is unknown (but is probably not good).

Response: Based on this and other reviewer comments the assumed hydrotreating severity, 

both temperature and pressure, were increased in subsequent drafts of this report. Sulfur and 

nitrogen do not have significant presence in the woody feedstock assumed in this report.

87. Comment: Bio-feeds are often high in N, producing NH3. Is this considered?

Response: We understand that some biomass feedstocks, such as algae, can contain 

significant amounts of nitrogen. Woody feedstocks have lower nitrogen content (Table 2

shows our assumption). Ammonia is shown as a product of hydrotreating. Most of the 

ammonia produced in the pyrolysis and vapor upgrading sections (small amounts may be 

present, although not included in this report) will likely be removed with the aqueous phase 

after scrubbing operations in Area 300.

88. Comment: Why were the hydrotreating pressures chosen?

Response: It was assumed, for the 2022 target cases shown, that the in situ case would 

require higher severity (1,800 psia) and the ex situ case 1,500 psia based on their oxygen 

contents of 10.5% and 6.4%, respectively. These pressures are slightly lower than the 
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assumption of 2,000 psia in Jones et al. (2013), noting that raw pyrolysis oil has a much

higher oxygen content. It is also understood that the pressures may need to be adjusted based 

on future experimental results. We included sensitivity Case 27 in Figure 15 to show the 

impact of a higher hydrotreating pressure; the impact is negligible because hydrotreating is a 

relatively lower cost operation compared to the upstream vapor upgrading (Area 200) in this 

particular conceptual process design.

89. Comment: The amount of hydrogen consumption assumed in the pyrolysis step for both 

cases is not trivial and seem to be counter to what is intended with this technology. To put 

these numbers in perspective by expressing them as wt. % hydrogen of pyoil, they would be 

2.3 for the in-situ case and 3 for the ex situ case. This is compared to about 5.8 for treating 

fast pyrolysis pyoil to the 0.5% oxygen level.

Response: In the final version of this report the values of the weight of makeup hydrogen to 

the weight of bio-oil feed for the hydrotreating reactor in the in situ and ex situ cases are 

6.3% and 3.6%, respectively; this is based on the pure hydrogen makeup. For hydrocracking, 

the corresponding values are 10.2% and 3.9% for in situ and ex situ, respectively. It should 

be noted that the feed to the hydroprocessing reactors are nearly water free. The aqueous 

fraction is >50% of the liquid products in Area 300. If the aqueous portion was included in 

the calculation (for a more direct comparison with the hydrotreating of raw pyrolysis oil from 

non-catalytic fast pyrolysis, where the reaction water is not removed) then the makeup 

hydrogen to condensation product ratios for hydrotreating are 2.5% for in situ and 1.4% for 

ex situ. We included the ratio of the weight of chemical hydrogen consumption to the weight 

of bio-oil feed to the hydroprocessing reactor in Section 3.4.2; the chemical consumptions 

(shown in Table 9 for hydrotreating and Table 10 for hydrocracking) are lower than the 

makeup ratios mentioned above because the makeup ratios factor purge streams required to 

maintain the 90 mole % hydrogen purity. All the chemical consumption values are on a 

water-free basis, and the inclusion of (previously removed) water in the calculations would 

further lower the ratios. The values shown indicate potentially significant hydroprocessing 

savings (in the 2022 target case) compared to the 5.8% chemical hydrogen consumption 

shown for raw pyrolysis oil in Jones et al. 2013; this is to be expected because that was the 

purpose of vapor upgrading with upstream hydrogen utilization.

90. Comment: The basis for the hydrotreater operating conditions selected in the study need to 

be defined more clearly with respect to the choice of pressures, temperatures and space 

velocity. 

Response: As mentioned, we show the values for 2022 target cases in this report. The

operating parameters chosen for this design are relatively severe with respect to conventional 

hydrotreating, although less so compared to the hydrotreating of oils from non-catalytic fast 

pyrolysis. We will modify assumptions as further data becomes available. Cost sensitivities 

to some of these parameters are shown in Figure 15.

91. Comment: Catalytic Fast Pyrolysis (CFP) will be “easier to treat” by causing less 

hydrotreating catalyst deactivation and fouling. There are several independent studies 

asserting that CFP can be processed with significantly less HT catalyst fouling/coking (this 

has not been quantified however). We agree that this supports the approach in this study i.e. 

specifically that of deleting the investments for the stabilizer and 1st reactor in the current 

PNNL fast pyrolysis + HT configuration (successfully operated for 60 days). It is less clear 
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that one can also reduce the pressure because of this lower coking/fouling property, or argue 

that the ex situ material can be operated at an even lower pressure. In the absence of more 

specific test data, we would recommend staying with 2000 psia at this stage and treating the 

option for lower pressures as an optimization opportunity. Also the assumption of a two year 

catalyst life may be optimistic even in an nth plant analysis. 

Response: We included sensitivity cases for higher pressure, use of swing reactors, and 

catalyst costs in Figure 15 to allow the reader to assess the impacts of variations suggested by 

the reviewers.

92. Comment: We would recommend that the target product oxygen level from the 

hydrotreaters be the same for both the in situ and ex situ cases by adjusting the space 

velocity. This keeps the hydrocracker design the same for both cases except for volume, and 

avoids having to make some assumptions about the hydrocracker design. By the time the 

material is hydrotreated to near 1% oxygen its properties are “petroleum like,” and no 

unusual hydrocracking conditions should be needed. Another reviewer commented on the 

higher oxygen content in the feed to the hydrocracker in the previous draft: “I would expect 

the oxygen content in the resid fraction to be lower than this, and certainly lower than the 

output of the unit operation above. We have seen the unremoved oxygen from the HT to 

follow the lower molecular weight species (phenolic oxygen) as some of the higher MW 

species are formed by condensation where the oxygen is removed as water.”

Response: We made this change in the final design per the reviewers’ inputs. The oxygen 

content at the hydrotreater outlets are 1 wt %.

93. Comment: In the case of the hydrotreaters there appears to be a constraint put on the weight 

and length of the reactors due to logistics. This drives the design to multiple parallel trains of 

small hydrotreaters. It is not clear what sets these constraints. Single high pressure reactors of 

significantly larger size are common in the petroleum industry. If this is driven by the vision 

of remote plants, these plants could be located where these length and weight restrictions 

would not apply e.g. on a river. Using parallel small reactors sacrifices significant economies 

of scale that this study could use to improve the economics. A study design with this large 

number of tiny reactors would not have much credibility with a refiner. Another reviewer 

stated that the added commentary about transportation limitations to justify the use of smaller 

reactors was a good addition, given our design decision in the initial draft.

Response: We used this feedback to move to single large hydrotreaters in the final design. 

Multiple smaller hydrotreaters in the initial draft is no longer used. We also removed the 

commentary about transportation limitations because of this decision.

94. Comment: You might want to mention what impurities are expected to be in the purge 

stream from the hydrotreater. 

Response: We provided detailed stream summaries in Appendix G of the final version of the 

report. Assumptions about light gases formed, which constitute the impurities from the 

hydrotreating and hydrocracking reactors in both the in situ and ex situ cases, can be gathered 

from the information provided.

95. Comment: You might want to mention that the hydrocracker recycles to extinction any gas 

oil (heavier than distillate, e.g., three- and four-ring aromatics) fraction. 

Response: We added this to the text per this suggestion.
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96. Comment: Both hydrotreater and hydrocracker have two-stage flashes on the reactor 

effluent. Where does the low-pressure flash vapor go?

Response: We included detailed process flow diagrams in Appendix G. All stream 

destinations can now be traced by the interested reader. In this particular case the highpressure (HP) flash purge streams go to the pressure swing adsorption (PSA) and the low 

pressure (LP) one goes to the reformer.

97. Comment: A low rate of irreversible catalyst deactivation would make the option for a fixed 

bed reactor more feasible (assuming this reactor set up would cope with rates of reversible 

deactivation by carbon laydown). Note also that the use of guard beds may be a strategy in 

fixed bed operation to minimize the effects of poisoning. 

Response: Note that we included a sensitivity case in Figure 15 showing the cost impact of 

using swing reactors. This case should capture the impact of more frequent maintenance 

activities for reversible deactivation (coke laydown).

98. Comment: Hydrotreating catalyst: I’m assuming at some point that a sulfided NiMo (or 

CoMo) catalyst will be used in this stage of the process. Will there be sufficient sulfur 

species present in the feed to this reactor to maintain the catalyst in a sulfided state, or do you 

envisage having to add a sulfiding agent?

Response: We have included justification in the text based on the Aspen Plus simulation 

predictions, which show that we will have sufficient sulfur at steady state to keep the catalyst 

sulfided. 

99. Comment: Hydrotreating catalyst: “Price: $20/lb (2011) based on NREL calculations using 

metals pricing and costs for manufacturing processes.” This cost is a bit on the high side.

Response: We retained the $20/lb in the final report to allow for any cost escalations because 

of catalyst modifications to handle the quality of oil after vapor upgrading.

100.Comment: For hydroprocessing add information about makeup hydrogen, make clear that 

purge gas goes to the PSA and not reforming, both lb/lb and Carbon/Carbon yields.

Response: All these are included in the final version of the report. A related response is 

included after comment 96.

101.Comment: Compare hydrocracker and hydrotreater costs with Jones et al. (2013) report 

after scaling. Provide sensitivity analysis to show impact of capital cost escalation.

Response: A quick comparison was made between the first stage hydrotreater in Jones et al. 

(2013) and the hydrotreater cost assumed in the ex situ case of this report using the ratios of 

the mass flow rates and a scaling exponent of 0.65 (based on Jones et al. 2013). The reactor 

cost was higher in the ex situ case. It is understood that the two cases are not directly 

comparable because of differences in the quality of feed to the reactors and also the 

conversion strategies. Sensitivity Cases 19 and 25 in Figure 15 of this report show the 

impacts of changes in assumptions.

102.Comment: The hydrotreater is modeled to operate at 340°C (inlet temperature). This 

temperature is low for the material being processed. What is the temperature rise in the 

hydrocracker given an inlet temperature of 380°C? Usually they get to 400-410°C as the max 

temperature needed for really low deoxygenation (even with low O&N HTL oil from algae). 
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I am not sure that you can back off on that temperature even starting with lower oxygen 

content because of the remaining type of oxygen is just harder to remove.

Response: This temperature was increased to 375°C at the inlet with an outlet temperature of 

403°C at the outlet. The hydrocracker inlet temperature was also increased to 392°C, with an 

outlet temperature of 420°C.

103.Comment: What is the chemical consumption across the reactor? This is a key metric and 

difficult to back calculate from the text. Add this to the table. Also, state the basis for 

hydrogen consumption.

Response: Chemical hydrogen consumption per feed to the reactor (on a weight basis) for 

the hydrotreater is 2.1% for ex situ and 2.6% for the in situ case; for the hydrocracker it is 

3.1% for ex situ and 5.4% for the in situ case. This was added to the tables in Section 3.4.2. 

The basis for hydrogen consumption is discussed in Section 3.4.

104.Comment: The hydrogen feed to the reactor was 14,174 scf/bbl for the in situ case and 

9,161 scf/bbl (these numbers reflect updates for this final version for context). How was this 

chosen?

Response: The key factors are reactor temperature control and maintaining 90 mole% purity 

of the hydrogen feed gas (treat gas). This is discussed in detail in Section 3.4.

105.Comment: In the draft version: Process model flow information for hydrotreater based on 

CHO yields reported: Predicting a 96% carbon yield to the organic liquid product seems too 

high. Typically a 60 to 65% yield has been achieved with regular (non-catalytic) fast 

pyrolysis oil that is already a higher average molecular weight. It is possible that catalytic 

fast pyrolysis oil could have higher yield to non-condensables.

Response: The interpretation of 96% based on the information provided in the draft version 

may not be accurate (because sufficient information was not provided and some gases were 

included in the reported stream). This assumption was revisited and modified as shown in 

Figure 8 for the entire hydroprocessing unit (carbon efficiencies of 91% for in situ and 94% 

for ex situ). Individual carbon efficiencies for the hydrotreaters can be derived from CHO 

analysis and mass flow rates provided in Table 8.

106.Comment: In the draft version: Hydrocracker yield in Table 8, based on CHO calcs: 99% 

carbon yield to the organic is also too high. Very unlikely to achieve this with the best of oils. 

What is the basis for the yields?

Response: Similar to previous response for the hydrotreater: The interpretation of 99% based 

on the information provided in the draft version may not be accurate (because sufficient 

information was not provided and gases were included in the reported stream). Also, 

assumptions in this regard were subsequently modified as shown in Figure 8 for the entire 

hydroprocessing unit (carbon efficiencies of 91% for in situ and 94% for ex situ). Individual 

carbon efficiencies for the hydrocracker can be derived from CHO analysis and mass flow 

rates provided in Table 8.

107.Comment: Flow rate to hydrocracker: Is there a reference for this estimate? I would expect 

that the product from the HT would have less resid type material, due to the tendency for 

CFP to make smaller molecule hydrocarbons rather than the high MW that comes out of 

HTL and FP. 
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Response: The 2022 targets in this design reflect intended research improvements to increase 

diesel-range molecules via coupling reactions. Research efforts will include catalyst 

development to move toward these targets. As noted in the text the 2022 target for dieselrange molecules are significantly lower for the in situ case.

108.Comment: Mass of catalyst in the hydrotreating reactor (Table 9): What is meant by 

“design” and “actual”? and why is actual>design? 

Response: There is a 70% overdesign as noted in this latest version.

109.Comment: Hydroprocessing catalyst price in Table 30: $10-12/lb (2011) based on NREL 

calculations using metals pricing and costs for manufacturing processes (comment based on 

June 2014 draft). This is rather low for hydrotreating catalyst – perhaps should be ~$20/lb

Response: We increased the cost to $20/lb, although another reviewer pointed out that $20/lb 

may be on the high side for catalysts without precious metals.

110.Comment: If you could get to 5-10% oxygen in catalytic pyrolysis then the hydrotreating 

likely would work similarly to hydrotreating HTL. I just wonder what kind of carbon 

recovery you get through the catalytic pyrolysis step when you have only 5-10% oxygen left. 

Carbon recovery of hydrotreating of CFP oil with 5-10 wt% O would be similar to that of 

HTL oil, which could reach 0.92-0.98 g carbon in oil per g carbon in feed. That was observed 

recently with algae HTL oils. The lower end of that range (0.92) is what is seen with lower 

lipid algae biocrudes. Since the CFP feedstocks won’t have lipid, I’d suggest aiming for the 

0.92 g/g yield (or maybe even lower). 

Response: In the latest version we have a 91% and 94% carbon recovery for the in situ and 

ex situ cases with 6.4% and 10.5% oxygen contents, respectively. This is in line with the 

reviewer comments. Hydroprocessing carbon recovery targets for 2022 for the in situ and ex 

situ cases are outlined in Table ES-1.

Area A500: Hydrogen Plant

111.Comment: The hydrogen plant investment costs seem out of line WRT the cost of the 

hydroprocessing: the ratio of H2 plant cost/Hydroprocessing cost seems much too high, 

which again provides a pretty significant economic penalty.

Response: The cost was changed to make consistent with Jones et al. (2013). Our initial 

source had a higher cost estimate.

112.Comment: If I read correctly, you’re using fuel gas to fire the SMR rather than natural gas. 

Did you check the adiabatic flame temperature of the fuel gas to ensure that it is capable of 

providing the radiant heat necessary? My understanding from steam cracking is that high-CO 

gases cannot provide sufficient temperature to operate a cracking furnace, which runs only a 

little hotter than an SMR. 

Response: Aspen Plus predicts that the adiabatic temp can support the SMR. Historically, we 

have used a minimum fuel combustor temperature of 1,700°F or higher in our simulations 

(design specification). However, the temperature is higher than 1,750°F for both the in situ

and ex situ cases. There is hydrogen present in the fuel gas mix. Preheating the combustion 

air after the air blower helps to raise the temperature significantly. 
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113.Comment: PSA – Not all PSA processes for air separation require 6-7 bar pressure. Is the 

16-18 bar PSA pressure for H2 firmly established? Also, it does not appear that hydrogen 

recycle is required...assumption or based on rigorous review of the process for these 

conditions?

Response: Here is some information from Miller and Stoecker (1989). It is not the most 

recent publication, but we assume that the general premise for PSAs has not changed. “The 

driving force for the separation is the impurity partial pressure difference between the feed 

and the tail gas. A minimum pressure ratio of approximately 4:1 between the feed and tail 

gas pressure is usually required for hydrogen separations. However, the absolute pressures of 

the feed and tail gas are also important, particularly to hydrogen recovery. The optimum feed 

pressure range for PSA units in refinery applications is 200-400 psig. The optimum tail gas 

pressure is as low as possible. Since vacuum is normally avoided, tail gas pressures between 

2 and 5 psig are typically used when high recovery is needed. The 2 psig pressure can be 

used when the tail gas is to be compressed, and 5 psig can be used when the tail gas is sent 

directly to fuel burners, as in steam reforming applications.” Our design has ~65% and ~70% 

hydrogen (volume basis) in the streams fed to the PSA. Recycle is required for low hydrogen 

concentrations.

Area A600: Steam System and Power Generation

114.Comment: From initial draft version: A portion of the economics is dependent on high 

electricity production with credit of 21 cents (per kW‐hr?), which is too high ... probably 

closer to 5 cents in most areas where this plant could be located.

Response: To clarify the reviewer’s interpretation, the 21 cents credit was per GGE of 

product and not 21 cents/kWh. The unit credit is 5.85 cents/kWh. The per GGE electricity 

credit has since been reduced after process modifications to address reviewer comments; the 

reduction was primarily from the removal of lock hoppers in the circulating fluidized bed 

reactor systems.

115.Comment: You should list the pressure levels for the steam headers. I’m not an expert by 

any means, but I was surprised at the super-high pressure level of 1321 psia. It might just be 

my personal experience, but I’m used to seeing levels like 900 or 1500 psig. Steam cracker 

transfer-line exchangers will produce up at the 1500 psig range. FCC waste-heat boilers and 

catalyst coolers tend to run more like 900 psig. Regardless, some explanation of the 

determinant of the SHP header level would be nice.

Response: This was used to maximize electricity generation. We had quotes from the mixed 

alcohol process (Dutta et al. 2011) for these conditions, so we did not want to go any higher 

since cost quotes are difficult to get. We did not want to go lower because we have sufficient 

delta T to operate at 1,321 psia in the catalyst coolers. We requested Harris Group to make 

sure that the catalyst cooler costs reflect this steam pressure.

116.Comment: In the previous draft: I found intra-process heat exchangers listed in the 

equipment lists of Area 600 for both cases but no mention of its need or specifications in the 

narrative and no listing of the reformer itself.

Response: We have provided detailed heat exchanger network information for the ex situ

case. The heat exchange network is included in Appendix G-2, and details of heat exchangers 

and costs in Appendix H. The pinch analysis heat exchanger cost line items in the equipment 
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list in Appendix B were prorated based on duties in specific areas, given that cross exchanges 

occur across areas and assignment of exchangers to one specific area would be arbitrary. The 

in situ case was scaled from the ex situ case using total duty, which we deemed reasonable 

because the processes are similar.

117.Comment: Power Gen – Why 350 psia extraction pressure for the low pressure turbine 

(LPT)? Was there any sensitivity analysis to this parameter? My experience would have 

thought this to be significantly lower (<270 psia) in order to max steam cycle thermal 

efficiency. Nevertheless, no explanation was given as to the 1st stage expansion pressure. 

The steam cycle efficiency may not change by more than 1% by going lower in extraction 

stage pressure, but it really depends on how flat the net efficiency vs. LPT inlet pressure 

curve is. Are the high pressure turbine (HPT) and LPT turbine expansion efficiencies 

different? They are in real systems.

Response: We will study the impact via sensitivity analysis in the future. It was not included 

in this report because of time constraints; the reviewer pointed out the benefit may be 

marginal. We do not assume different efficiencies for HPT and LPT; it is good to be made 

aware of this. We will keep the existing specifications for this report, but retain this comment 

for future use and modifications. 

118.Comment: Electricity credit seems to influence also somewhat substantially. Would make 

sense to evaluate Power Gen cycle efficiency more closely as well as evaluate (if you haven’t 

already) other cycle technology options that might fit. 

Response: This can be done in the future. However, since the focus of the process is fuels 

production, most of the biomass energy is targeted toward fuels rather than power and the 

overall impact of electricity is not as significant. The electricity credit was further reduced to 

~4 cents/GGE since the draft version that was reviewed.

Area A700: Cooling Water and Other Utilities

119.Comment: Chilled water is mentioned as a utility for Area 200, and I found the equipment 

in the equipment list. I found no discussion of the equipment specifications in the narrative, 

however. 

Response: We added information in Appendix A. It was derived from Humbird et al. (2011) 

and the same electricity consumption basis was used in this report.

Area A800: Wastewater Management and Recycle

120.Comment: We were pleased to see that the design includes more definition to the utilities 

part of the plant. In our view, past studies underestimated these costs, particularly for water 

treatment.

Response: Thank you for the comment.

121.Comment: Comment based on previous draft: I think you need a loading rack for 

wastewater, or at least a pump, pad, and flex hose, since your plan includes shipping 

wastewater offsite. Additionally the logistics and costs of shipping so much wastewater 

offsite is significant. The offsite wastewater treatment number of $0.48/T seems optimistic.

Response: Clarification is now provided that we were not planning to ship the wastewater. 

The portion of wastewater that is most challenging will be handled by the regenerative 
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thermal oxidizer (RTO). Other wastewater that has known methods of treatment is expected 

to be treated in the plant vicinity. We assumed an operating cost for this treatment; the 

assumed cost of $0.022/gallon was conservative (high) and based on Humbird et al. (2011).

122.Comment: Comment based on first draft in June: Discuss what will be the fate of 

wastewater, aerobic digestion (discuss assumed it will not be toxic). Is this discharged to 

POTW (publicly owned treatment works)? Please specify type of treatment and amount to be 

treated. 9% carbon is very high.

Response: The wastewater treatment (WWT) strategy was since modified to use an RTO, as 

described in this version of the report. The wastewater is not sent to POTW; please see 

discussion in this version about using an RTO for the challenging streams, and on-site WWT 

for the rest of the wastewater.

Miscellaneous

123.Comment: Is it reasonable to provide costs with the precision of five digits if the 

uncertainty of yields is more than 20%? Another reviewer suggested reducing the number of 

significant figures reported.

Response: This was done in a few of the tables. Please understand that the report and all the 

numbers needed to be updated multiple times. We found it easier and less error prone to keep 

all the figures. We do understand the large uncertainties in our analysis, and the inclusion of 

significant figures is not a reflection of extreme certainty.

124.Comment: A reviewer questioned 0% contributions presented in the energy balance pie 

charts (Figure 11). 

Response: We have since included one place of decimal in that pie chart. The numbers 

presented still reflect rounding to the nearest tenth.

125.Comment: A significant amount (~30%) is lost through air-cooled exchangers. Where will 

the energy come from for the coolers?

Response: The air cooled exchangers are driven by electricity and accounted within our 

simulation. The air cooled exchangers were used to save on water usage, and used for 

cooling needs down to 140°F, but no lower. Cooling water was used for cooling below 

140°F.

126.Comment: In the sustainability section there was mention of ZnO and HDS as catalysts in 

the previous draft. Are they state of the art?

Response: We changed the nomenclature to indicate that these are not catalysts for 

hydroprocessing. They are used for sulfur removal from off-gases prior to the reformer.

127.Comment: A reviewer was interested in having enough details to reproduce and model 

some of the operations in the process.

Response: We had not included the detailed stream tables in the review draft. They are now 

available in Appendix G. We believe the significant details provided in Appendix G will help 

answer the reviewer’s questions.

128.Comment: For the sustainability section providing the SimaPro categories applied to the 

inputs will help with reproducibility of results. 
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Response: The information is provided in Table 25 of this version.

129.Comment: It will be helpful to know the assumed composition of all these catalysts for 

sustainability calculations. Provide the caustic identity.

Response: Most of the catalysts are proprietary in nature and company specific. 

Approximate composition information can be gleaned from the literature. The SimaPro 

assumptions (including for caustic) are listed in Table 25.

130.Comment: Can you provide the boiler feed water chemicals used?

Response: Chemicals utilized for boiler feed water and/or steam condensate treatment are an 

oxygen scavenger like sodium sulfite (Na2SO3) or hydrazine (N2H4) and corrosion

inhibitor/neutralizing amine like morpholine (C4H9NO). Reference Betz Dearborn Water 

Management Group, 1998.

131.Comment: Can you provide the cooling tower treatment chemical used?

Response: Chemicals utilized for cooling tower water treatment generally contain 

proprietary combinations of corrosion inhibitor, oxygen scavenger, pH control and biological 

fouling mitigation. Typical compounds used in treatment programs are phosphates, azoles, 

copolymers and zinc. Reference Betz Dearborn Water Management Group, 1998.

132.Comment: An additional table showing the fossil energy consumption and GHG emissions 

breakdown will be relevant for this work.

Response: The information is provided in graphical form (Figure 12).

133.Comment: On an energy basis and with electricity credits, the GHG emissions at the 

conversion stage for the in situ and ex situ cases are negative 2.6 kg CO2e/GJ and negative 

1.2 kg CO2e/GJ. It’s not clear to me if this includes total HDO to produce a finished fuel. It 

would be worth comparing this number against the fossil fuel baseline emissions to show that 

it meets the 60% reduction target for qualification as an advanced cellulosic biofuel.

Response: The conversion step includes all operations included in this process including 

HDO to finished fuels. The negative values or significant reductions are derived primarily 

from offsetting electricity from other sources. Comparisons with fossil baseline emissions are 

also included in this report, with further details in Appendix E.

134.Comment: What is the impact of depreciating your plant over 20 years rather than 30? This 

may find broader acceptance.

Response: The impact is shown (included in this version) in Figure 15 as sensitivity Case 12. 

There is a 4.1% increase in the 2022 target MFSP for the ex situ case.

135.Comment: The conclusion of in situ and ex situ selling price being nearly equal at 

~$3.5/GGE is reasonable.

Response: Thank you for the comment.

136.Comment: Cold biomass can potentially be used for temperature control instead of 

preheating it. Is it worth the CapEx to heat it? Provide a sensitivity case.

Response: While we did not include a sensitivity case, the use of low grade process heat for 

heating the biomass has positive impacts on the overall process efficiency. The cost of 
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additional cross flow pellet dryer and a blower are marginal compared to the gains in energy 

efficiency. This low grade heat would otherwise have no consumers in the process. 

137.Comment: The title should more accurately reflect the content. These design cases are 

objectives and not achieved yet.

Response: We tried to make it clear in multiple places within the text that these design cases 

reflect 2022 targets. We also changed the title to say that these are research pathways.

138.Comment: A reviewer did not agree with definitive statements in the draft version saying 

that we can achieve cost-competitiveness based on this design report.

Response: We have since modified the statements to make clear that the design case is an 

outlined pathway, and achievement of catalyst performances outlined in this report is one 

way to move toward cost-competitiveness of biomass-derived hydrocarbon fuels.

139.Comment: Assessment of cost-competitiveness should include consideration of distribution 

and marketing costs, before the MFSP can be compared to retail pump prices and for claims 

of cost competitiveness should be advanced. Additional costs are incurred for blending to 

meet product specifications.

Response: We understand the necessity of considering additional costs for marketing, 

distribution, and blending. The research goals presented are for 2022. We anticipate careful 

consideration of quality specifications and associated penalties/credits as we develop further 

understanding via research and obtain experimental results. The aspect of blending is 

expected to be covered as part of future work. We also show that there are options, such as 

economies of scale, to significantly improve costs beyond the 2022 target cases outlined 

here, and some of the other significant impacts shown in Figure 15 can be leveraged to 

further reduce our minimum fuel selling price (MFSP) and offset additional distribution and 

marketing costs.

140.Comment: The design does not leverage economies of scale that can bring significant 

benefits. Nth plant assumptions should also include performance at an efficient scale.

Response: We understand that economies of scale can have major impacts as depicted in the 

sensitivity analysis shown in Figure 15. However, we maintained the design at 2000 dry 

metric tonnes per day for our base case for consistency and comparison across other pathway 

design reports funded by BETO. The interested reader can gauge the benefits derived from 

economies of scale from Case 10 in Figure 15. We also included the reviewers’ 

recommendations for the inclusion of references related to economies of scale.

141.Comment: Even with nth plant assumptions, capital costs for the process are 6-8 times the 

cost of new petroleum refinery capacity. Capital efficiency should be significantly improved. 

It is understood that further contingencies were not included, and favorable process 

assumptions (e.g. 2 year catalyst life, 90% capacity utilization) were made because of the 

assumption of nth plants. Inclusion of additional contingencies would further reduce capital 

efficiencies, and contingencies for the current state of CFP development should be 50% 

more.

Response: Biomass conversion processes involve solids handling, use low energy density 

feedstocks, and are less mature; hence the economics are difficult at this stage. The 

significant learnings of the petroleum industry through operational improvements for nearly a 
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century can be achieved only through actual implementations of these technologies by 

industry. While economies of scale are one way to leverage future improvements in capital 

efficiency, other significant areas of potential improvements include catalyst and yields, 

process intensification and performance, and optimization of intermediate streams; these 

opportunities are even beyond those outlined in this report. Hence the nth-plant performance 

outlined here is one potential way toward feasibility, but many other opportunities remain for 

further improvements in capital efficiency through actual implementation and learnings. For 

contingencies, we do understand that pioneer plants require significant additional costs; we 

have not included pioneer plant analysis in this report because we are studying the potential 

of the process in a mature stage of development. We agree that pioneer plant studies should 

include higher contingencies.

142.Comment: The authors attribute only a 10% return to invested capital. Moreover, it appears 

that even this low investment return is “leveraged” – via the use of 60% debt whose interest 

expense is tax deductible. These assumptions are not attractive to companies. The sensitivity 

analysis shows that a 15% investment return would raise the MFSP by 15.4% (was slightly 

higher in the draft for review). Venture capital/private equity will likely seek 20+% returns to 

offset risks. Studies should include returns which industry would require pushing pioneer 

scale plants to a mature industry.

Response: The financial assumptions for the base case are consistent with other design 

reports funded by the Bioenergy Technologies Office (BETO), and allow comparison across 

conversion pathways; they outline a basis for cost-improvement based research. Sensitivities 

to changes in these financial assumptions are captured in Figure 15. Sensitivity analysis in 

Figure 15 also shows options to offset the demands for higher returns via further 

improvements in other areas. We have conducted pioneer plant analysis separately in the 

past; the purpose of such studies is to address the push toward commercialization and 

understanding of risks, rather than understanding where the research and development can 

lead us.

143.Comment: It is not clear that the “leveraged economics” have been done correctly – the 

authors need to provide more detailed and accessible spreadsheets.

Response: Detailed discounted cash flow rate of return (DCFROR) and other financial 

assumptions are included in the appendices of this report. Note that the financial methods 

have been used in other detailed reports over the years, and have been reviewed by multiple 

entities, including academic institutions that use our design reports in some of their courses 

as examples. We believe any major errors in our methods would be noticed and brought to 

our attention; we do receive comments (including about correctness) from varied sources 

after the publication of our reports, and we address them. Some of our spreadsheets are 

available online, and thus have been used and vetted by others.

144.Comment: The search for savings on this order of magnitude should drive researchers to 

look at different and more specific plant locations. The authors’ in-situ and ex-situ plants 

reside at some generic location geared to Idaho National Lab’s (INL) recent 

feedstock/logistics work. The location seems to be consistent with “distributed pyrolysis 

plants” found in other literature, seeing as the plant design self-manufactures hydrogen. It is 

unclear whether this location permits large scale water-borne transport of chipped biomass. It 

clearly does not allow co-processing product at an adjacent refinery. This leads the authors to 
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incorporate a sub-scale 1.4 kbd hydrocracker into the process design. Feeding CFP heavy 

fractions to a hydrocracker may be the right process solution, but this probably needs to 

happen within a co-processing approach for CFP to have a reasonable chance at 

commercialization.

Response: We have not considered the co-location scenario in this particular report. With 

progress in the research we will become better informed about the quality and feasibility of 

co-processing. An expansion of the scope for location and specific feedstock transportation 

was not feasible within the time available. Please note that such integrated studies have been 

conducted in the past (typically after the conversion-specific design report is released). As an 

example please see Muth et al. (2014).

145.Comment: Follow-up work should focus on process designs and locations which facilitate 

refinery co-processing, large scale/low cost water transport of biomass, and use of the 

refinery infrastructure e.g. merchant hydrogen. Ex-situ CFP may be well suited to such an

approach, seeing as it may produce higher quality blendstocks that still retain some oxygen. 

Arbogast et al. (2012) contains information about such locations and the economics of and 

technical requirements for co-processing.

Response: Thank you for pointing out the reference. We added a limited discussion for this 

report based on your comment, mostly alluding to this as potential future work for cost 

reduction. We do plan to leverage the current study for other scenarios as more data becomes 

available from the research. We feel that this study is a start within the time we had available 

to prepare this report, mainly focusing on building process model-based scenarios outlining a 

potential pathway to feasibility of the technology via research in the coming years.

146.Comment: We look forward to seeing the data supporting the very promising CFP yields 

and oxygen removal assumed in the study. If confirmed, these could significantly improve 

the overall economics of biomass pyrolysis to fuels. This study design should be very 

valuable in formulating and monitoring progress of your forward program. It might be useful 

as part of this study design to: (a) Identify the most economically attractive areas for focus 

and what “killer” factors need to be overcome. Examples of potential “killer” variables are: 

(i) Catalyst life & equipment fouling, (ii) Metallurgy corrosion, (iii) Yields derived from 

batch experiments extrapolated to a continuous process with scaled up reactors, (iv) Product 

quality and necessary further processing required for introduction into refinery equipment 

and/or final fuel products, (b) Estimate probabilities of success in key research areas & 

derived benefits, (c) Provide a single, more extensive summary of key assumptions in the 

study and a sense of how well they are backed up with data.

Response: Thank you for these valuable comments. We are at the early stages of research for 

these pathways. We will consider these points as more data becomes available; some of these 

may be futile at this point because of the lack of data and early stages of research. We 

conduct annual state of technology assessments to track the progress of research. The 2014 

assessments, along with our annual improvement targets leading to 2022 are expected to be 

published soon in BETO’s Multi-Year Program Plan (MYPP). All your points are candidates 

for consideration with further maturity.

147.Comment: In the draft version for review: The error bands quoted in the design write up 

regarding the AACE classification system were a bit misleading.
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Response: We removed references to the AACE classification in the final version of the 

report based on this comment.

148.Comment: Could you mention how many model compounds you used?

Response: The list of compounds used is available in Appendix F of this version of the 

report.

149.Comment: Based on June 2014 draft: Suggest adding sensitivity analysis for: (a) Upgrading 

yield, (b) Losses to different products (coke, light gases) (which would give better results), 

(c) Catalyst cost and cat:biomass ratio, residence time in upgrader, (d) Hydrotreating 

severity.

Response: Sensitivity analyses related to the above were added to the August 2014 and 

subsequent drafts.

150.Comment: How did you calculate the theoretical GGE production and yield (Table ES‐2)? 

Did you just take into account the C and H in the feedstock and calculate how much gasoline 

and diesel could be made?

Response: Section 4.5 describes how we use LHV from the simulation to come up with the 

GGE values.

151.Comment: What composition did you assume for the upgraded products?

Response: Stream tables in Appendix G of this version show the compositional (surrogate 

compounds) assumptions.

152.Comment: Given the importance of catalyst performance, it may have been valuable to 

include a dedicated section devoted to catalyst design.

Response: We included a short section (3.2.1.6) on potential vapor upgrading catalysts, 

primarily referring the reader to other articles. Assumptions regarding hydroprocessing 

catalysts were also added in Section 3.4. We feel that this design report is focused on technoeconomics and we should not interfere with the catalyst researchers’ ongoing publications of 

their work.

153.Comment: The sustainability section could benefit from a chart. For example, the chart 

could compare carbon input/output in the form of feedstock, fuel, char, flue gas.

Response: This specific chart for carbon flow is not provided. However, information about 

biomass energy distribution upon processing (LHV basis) is provided in Figure 11. The 

carbon efficiencies to products are shown in Figure ES-1 and the information about char is 

available in the stream tables (Appendix G), along with flue gas information. Almost all the 

carbon not converted to fuel will eventually show up in the flue gas in the current process 

design, because excess gases, char, coke, and aqueous carbon are all combusted.

154.Comment: Some discussion of potential planned (scheduled maintenance, feedstock supply

schedules, planned holidays...) and unplanned (equipment failure, supply disruptions) would 

be helpful. In particular, there may be interest in knowing whether there are safety/reliability 

differences between in situ/ex situ fast pyrolysis and other technologies. A qualitative 

assessment of reliability concerns specific to these technologies (coking, reactor operation) 

would be sufficient. 
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Response: We did not include this discussion in this report. However we will address some 

of these topics in the future, especially with the maturing of the technology.

155.Comment: The PSA hydrogen stream in the figures can be labeled as Excess or Export 

Hydrogen unless it is also utilized in the process.

Response: All hydrogen produced is utilized within the process. Natural gas is imported and 

steam-reformed when additional hydrogen is required. Surplus process fuel gas, if available, 

is converted to electricity. 

156.Comment: Discuss oxygenated species types (phenols are preferred to acids, etc.) after 

vapor upgrading and condensation.

Response: Details about species and stream compositions are included in Appendices F and 

G of this version of the report.

157.Comment: We notice in both this study and the recent PNNL/NREL fast pyrolysis study 

that the upper size limit for the pyrolysis reactors is set at 1000t/ day due to “biomass feeding 

constraints”. In our previous (pre-2010) discussions there were considerations of 2000 t/d or 

larger reactors. What has changed? Is this believed to be a hard upper limit? This will have a 

significant impact on the economic benefits of economies of scale as we try to move this 

technology to larger, more economic plants.

Response: As mentioned earlier, we have limited this to 1,000 TPD because of anticipated 

biomass feeding constraints. We have not seen any information thus far about confidence in 

building larger reactors than this. We also made the same assumption for our indirect 

gasification studies (Dutta et al. 2011). However, this does not negate future possibility of 

further scale-up of biomass reactor systems. Note that all the rest of the equipment beyond 

the initial fast pyrolysis reactor are assumed to have no scaling constraints.

158.Comment: We think additional sensitivities and a fuller discussion of what they reveal 

about where progress is needed, is the way to go. In addition to scale, we think the biomass 

cost and capital/contingency/return sensitivity discussion is very important to framing the 

economics and the progress that needs to be made. Framing this properly will spur more 

aggressive thinking about research possibilities and ultimately more progress.

Response: We feel we show many of these sensitivities in Figure 15. Additional sensitivities 

and providing options around specific (or anticipated) challenges encountered in the future 

will also be keys to the success of the research on these conversion pathways. As outlined in 

the Conclusions and Future TEA Work sections of this report, looking into further 

conversion variations and options will be the next focus of the TEA team.

159.Comment: Ultimately, we also think this discussion will drive pyrolysis oil plants away 

from generic distributed locations with hydrogen self‐sufficiency towards larger plants 

integrated logistically or co‐located with refineries. Our 2010 study saw big potential savings 

from such an approach, and we think researchers and techno‐economic analysts should favor 

this model or say why they choose not to do so.

Response: This is definitely an option. However, we feel that it will be premature to propose 

that as a base case without first gaining a deeper understanding of quality aspects and 

acceptability of intermediates by petroleum refiners.
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160.Comment: There seems to be a number of omissions in the offsites. These include: (a) 

Wood yard or other storage area for feedstock, (b) Warehouse for catalysts, (c) Product 

tankage for gasoline and diesel, (d) Loading racks (rail or truck) for finished products, (e) 

Administration building and laboratory. I looked through the equipment lists and didn’t see 

anything like these. I don’t think your factors for direct equipment costs cover these. If the 

feedstock will be supplied in a weatherproof form, then perhaps you need only plot space. If 

the fresh and spent catalysts are stored in some kind of bulk containers, then perhaps you 

need only plot space. If you assume colocation at an existing refinery or biorefinery, then you 

don’t need an administration building, laboratory, or loading racks. All of these assumptions 

need to be stated if valid.

Response: The current version provides information about most of these items: (1) we 

included plant footprint calculations by the Harris Group in Appendix I showing area for 

storage, (2) warehouse for catalysts is not mentioned specifically; however bed media 

handling with silos are included in the pyrolysis island and within the equipment list 

(Appendices A and B), (3) product tanks are included in the equipment list, and land 

allocated under plant footprint, (4) loading racks are factored into the footprint and included 

in the equipment list under Area 700, and (5) administrative buildings are included within 

indirect costs (Table 28) and space is allocated within the footprint. Laboratory space is not 

specifically mentioned, but will be covered under the category “Offices, etc.” in Appendix I. 

The inclusion of Appendix I should answer most of the remaining queries. We do not assume 

co-location.

161.Comment: I did not find a location basis. Construction in the Midwest will have a different 

cost than in the Gulf Coast. If you feel the difference is insignificant, then just say so.

Response: An average U.S. location is appropriate, given many of our costs are derived from 

that setup within ACCE.

162.Comment: In looking at a number of the variable costs, the base-year data are significantly 

out of date (BFW chemicals were quoted 23 years ago!). Simply inflating these numbers is 

risky. I do recognize that VOC rarely drive the sensitivity of the economics, but more 

contemporary quotations are probably in order

Response: We updated most of the costs mentioned (Table 30). 

163.Comment: Wage rates seem low, especially given the recent run-up in starting salaries for 

chemical engineers. Given all of the present and anticipated construction on the Gulf Coast, I 

suspect even the non-professional wages are low.

Response: We included a 10% escalation, shown in Table 32. 

164.Comment: It would be nice to have a comparison basis for the nth-plant assumption of 90 % 

on-stream factor (same as a gasifier or FCC unit?).

Response: Refiners have made tremendous improvements in operating reliability of refinery 

applications as the technologies have matured. John S. Magee states, “It is not uncommon 

today to have FCC units complete three-to-four-year runs between major turnarounds with 

nearly 100 percent stream factor” (Magee 1993). Given that solids handling is more 

challenging, we believe that 90% on-stream factors for an nth plant with our conceptual 

design is not unreasonable.
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165.Comment: The steam plant was depreciated on a 20-year, 150 % declining balance basis. 

There is a MACRS schedule for the 20-year asset class. The two are not quite the same since 

the MACRS schedule reverts to straight-line in year 9.

Response: We switched to the 20-year MACRS schedule for the steam plant.

166.Comment: I realize that you have been using a leveraged financial basis (debt financing at a 

lower rate than the IRR) for other studies. Nevertheless, such a basis gives a slight 

improvement to the economics that has nothing to do with the technology. I don’t propose 

you change it, but perhaps recognizing it in the narrative has merit.

Response: Although not mentioned in the main report, we do recognize the slight 

improvement in the economics over 100% equity with 10% IRR. In the past we provided 

sensitivity cases showing the impact of the assumption (see Dutta et al. 2011, Figure 16, Case 

20). Since we have maintained the same assumption in following BETO-funded reports, we 

did not explicitly discuss the impact in this report. 

167.Comment: Calling the discount rate the IRR bothers me a little. Given you are accounting 

for debt financing separately, it’s more like a cost of equity. This is a minor detail, of course.

Response: We qualified the text (in this version) in places where IRR was mentioned to also 

say that this is the discount rate.

168.Comment: I realize that you had to use a relatively sparse set of model compounds for the 

mass and energy balances. Nevertheless, it would have been nice to see some compositional 

data for selected streams, especially the inputs and outputs of each of the reactors. I would’ve 

liked to be able to follow the relative production and destruction of aromatics, in particular.

Response: Detailed stream tables and flow diagrams are provided in Appendix G showing 

model compound flow rates for the 2022 target cases.

169.Comment: I found no discussion of product specifications for the gasoline or distillate 

products. Even if the plant provides only blendstocks and not finished products, the 

manufacturing targets should be discussed. Since you were hydrotreating the product to 

remove aromatics, I assume you must’ve had a target of some kind.

Response: Since we are at the early stages of our research, we deliberately limited quality 

specifications to oxygen content and H/C ratios. Trying to be more specific at this stage 

without more experimental data would be misleading. We anticipate that there will be 

significant focus on quality specifications around the 2017 timeframe and beyond with more 

maturation of the technology.

170.Comment: Over time, many chemical processes get optimized to consume (or contain) their 

byproducts because finding long-term, steady-value dispositions for those byproducts is 

difficult. This process, given its lack of maturity, carries significant market exposure to 

placing the electricity and to disposing of wastewater.

Response: We agree that these will be important considerations in the future, and our 

research plans include some of these aspects.

171.Comment: The onsites and offsites are around 50/50 of the TIC, depending on case. Given 

that I think some offsites are missing, the balance will tip decidedly to offsites, which fits for 

a greenfield project. To be economical, subsequent evolutions of the design will need to 
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focus on making the design more self-contained. A breakthrough in wastewater treatment is 

probably required. 

Response: We tried to include all the major costs, both on-site and off-site. Wastewater 

treatment was not modeled in detail, but a conservative (high) operating cost was added for 

that operation. As mentioned in response to another comment, we will have on-site 

wastewater treatment and there will not be any off-site wastewater shipping requirements. 

172.Comment: The assumption of using stainless steel in the oil/water separator is probably 

okay. 

Response: Thank you for the feedback. 

173.Comment: Based on personal experience with similar systems, Area 300 will require 

demonstration at some scale to resolve all of the potential fouling and corrosion issues. 

Response: We agree that this needs further vetting as experimental results become available.

174.Comment: If the RTO technology for wastewater handling finds common and effective use 

with the kinds of wastewater streams you are producing, then perhaps it will work. If you can 

cite similar applications where the technology is effective, that would be a good addition. 

Response: We were able to contact a reputable vendor to talk about the general feasibility of 

the stream going to the RTO. We changed the concentration based on their initial reluctance 

to comment on a much more dilute stream going into the RTO. 

175.Comment: Power requirement tables: An “additional cross-flow dryer” is described in 

section 3.1 as being within the plant. To avoid questions and confusion, the power 

consumption should be listed here. The foot note then explains why it’s small. Same 

comment applies to table 16. 

Response: Text was added as recommended by the reviewer.

176.Comment: Carbon conversion efficiency in reactors is significant. That makes sense 

relative to Fischer-Tropsch. How aggressive are the reactor performance assumptions on this 

parameter?

Response: The carbon conversion efficiency on the vapor upgrading portion is based on 

research targets for 2022 (and not the current state of technology). For this process to be 

successful we have to get to high process efficiencies to justify the capital. This is theoretically 

feasible because of direct versus indirect liquefaction. However, doing the right chemistry 

during vapor upgrading using catalysts will be the key to success. We provided a planned 

trajectory for achieving the targets for inclusion in BETO’s Multi-Year Program Plan 

document. The hydrotreating efficiency assumptions are shown in Table ES-1 and Figure 8. 

177.Comment: It will be nice to broaden the work to include technology risk assessment. 

Response: While technology risk assessments were not part of our goals for this design 

report, we are mindful of that aspect. We separately did some high level assessments in that 

regard; advancements in technology readiness are expected with advances in our research.

178.Comment: Pinch Analysis: This section seems to report results, not improvements to the 

heat exchange network (HEN) design. Certainly one immediate conclusion is that higher 

pressure cold streams would lower HX irreversibility. Are the cold stream phase change 
260 

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streams in the composite diagrams primarily associated with the steam cycle? If so, certainly 

more could be done to improve cycle efficiency. Utility HX duties were mentioned but not 

shown (called out) in the composite curve figures. What are their magnitudes and how are 

they provided? Was there any attempt at HEN redesign?

Response: Higher pressure in the steam system would help, but we decided to settle on the 

1,350 psia for the steam production based on quotes we had from previous reports. We 

understand that steam turbine system designs/fabrication change and costs get significantly 

higher with much higher pressures. As you probably inferred, the near horizontal line on the 

cold side is associated with phase change for steam and moving this up can improve process 

efficiency at the cost of capital associated with larger heat transfer area requirements, as well 

as any changes in costs of the steam turbines. There are other cold streams in the process 

such as air preheat (where going to a very high temperature may not be recommended). We 

did change the air preheat and reformer preheat temperatures to some extent and saw changes 

in efficiencies, hydrogen production, natural gas requirement, electricity production, etc. 

Most of the other streams are pegged to process requirements for specific unit operations. So 

any optimization will be limited by these constraints. We typically take out the utilities to 

balance the hot and cold streams. The utilities use is usually determined by the pinch point 

and approach temperatures on the side below the pinch. We keep adding utilities until the 

side below the pinch appears feasible. We provided duties for all exchangers (see Appendices 

G and H).

179.Comment: Follow-up to previous comment and response: Okay, seems like you have the 

right price point vs. steam pressure picked out. But at some point in the future, it might be 

good to know what the marginal cost of increasing pressure is, as the net benefit might be 

worth it. Further, given the temperature differences in the composite diagram, I think there is 

room there for an economic lowering of the pinch in the phase change HX section(s). The 

main point is that there is an optimal tradeoff between HX surface area and life cycle costs. 

Huge dT’s don’t necessarily pay off, since operating efficiency gains are very important to 

operating cost reductions (vs. capital) over the life cycle of the plant. Here a true Pinch 

Analysis effort with HEN re-design (or exergy analysis) might make a difference. 

Response: We do the heat exchanger network (HEN) at the end of the project after we freeze 

the models because of the very high levels of effort required for processes of this size. 

Results are shown in Appendix H. However, we do not modify the steam pressure in an 

iterative fashion, primarily because we do not have the resources to get actual quotes for 

various turbine systems to do detailed cost sensitivity with steam pressure. Also, since 

electricity is not our primary product, we anticipate a minimal impact. Also, we do the HEN 

manually to avoid proposing a spaghetti and physically infeasible network, usually created 

by commercial software (unless they are well constrained). As mentioned earlier, we decided 

to go with a steam pressure which we felt was reasonable and for which we had costs 

available. We would definitely like to bump up the efficiencies since this is very apparent in 

the sections where the hot and cold curves diverge significantly, and the steam system is the 

only major operation where we can change specifications without violating process condition 

requirements. Again, the objective of this design is to focus on the biomass conversion 

aspects with reasonable recovery of process heat, which we believe we have accomplished 

here. Pushing for optimization to higher efficiencies in the steam system with increased 

pressure will be a different exercise if further resources are available.
261 

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Appendix J References

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