Thermochemical Processing of Biomass: Conversion Into Fuels, Chemicals and Power

Thermochemical Processing of Biomass

Thermochemical Processing of Biomass: Conversion into Fuels, Chemicals and Power, First Edition . Edited by Robert C. Brown © 2011 John Wiley & Sons, Ltd. Published 2011 by John Wiley & Sons, Ltd. ISBN: 978-0-470-72111-7

Wiley Series in Renewable Resources Series Editor Christian V. Stevens – Faculty of Bioscience Engineering, Ghent University, Ghent, Belgium

Titles in the Series Wood Modification – Chemical, Thermal and Other Processes Callum A. S. Hill Renewables-Based Technology: Sustainability Assessment Jo Dewulf & Herman Van Langenhove Introduction to Chemicals from Biomass James H. Clark & Fabien E.I. Deswarte Biofuels Wim Soetaert & Erick Vandamme Handbook of Natural Colorants Thomas Bechtold & Rita Mussak Surfactants from Renewable Resources Mikael Kjellin & Ingeg€ard Johansson Industrial Applications of Natural Fibres - Structure, Properties and Technical Applications J€ org M€ ussig

Forthcoming Titles Introduction to Wood and Natural Fibre Composites Douglas Stokke, Qinglin Wu & Guangping Han Biorefinery Co-Products: Phytochemicals, Lipids and Proteins Danielle Julie Carrier, Shri Ramaswamy & Chantal Bergeron Pretreatment of Plant Biomass for Biological and Chemical Conversion to Fuels and Chemicals Charles E. Wyman Bio-based Plastics: Materials and Applications Stephen Kabasci Cellulosic Energy Cropping Systems David Bransby

Thermochemical Processing of Biomass Conversion into Fuels, Chemicals and Power

Edited by ROBERT C. BROWN Department of Mechanical Engineering, Iowa State University, USA

This edition first published 2011 Ó 2011 John Wiley & Sons, Ltd Registered office John Wiley & Sons Ltd, The Atrium, Southern Gate, Chichester, West Sussex, PO19 8SQ, United Kingdom For details of our global editorial offices, for customer services and for information about how to apply for permission to reuse the copyright material in this book please see our website at www.wiley.com. The right of the author to be identified as the author of this work has been asserted in accordance with the Copyright, Designs and Patents Act 1988. All rights reserved. No part of this publication may be reproduced, stored in a retrieval system, or transmitted, in any form or by any means, electronic, mechanical, photocopying, recording or otherwise, except as permitted by the UK Copyright, Designs and Patents Act 1988, without the prior permission of the publisher. Wiley also publishes its books in a variety of electronic formats. Some content that appears in print may not be available in electronic books. Designations used by companies to distinguish their products are often claimed as trademarks. All brand names and product names used in this book are trade names, service marks, trademarks or registered trademarks of their respective owners. The publisher is not associated with any product or vendor mentioned in this book. This publication is designed to provide accurate and authoritative information in regard to the subject matter covered. It is sold on the understanding that the publisher is not engaged in rendering professional services. If professional advice or other expert assistance is required, the services of a competent professional should be sought. The publisher and the author make no representations or warranties with respect to the accuracy or completeness of the contents of this work and specifically disclaim all warranties, including without limitation any implied warranties of fitness for a particular purpose. This work is sold with the understanding that the publisher is not engaged in rendering professional services. The advice and strategies contained herein may not be suitable for every situation. In view of ongoing research, equipment modifications, changes in governmental regulations, and the constant flow of information relating to the use of experimental reagents, equipment, and devices, the reader is urged to review and evaluate the information provided in the package insert or instructions for each chemical, piece of equipment, reagent, or device for, among other things, any changes in the instructions or indication of usage and for added warnings and precautions. The fact that an organization or Website is referred to in this work as a citation and/or a potential source of further information does not mean that the author or the publisher endorses the information the organization or Website may provide or recommendations it may make. Further, readers should be aware that Internet Websites listed in this work may have changed or disappeared between when this work was written and when it is read. No warranty may be created or extended by any promotional statements for this work. Neither the publisher nor the author shall be liable for any damages arising herefrom. Library of Congress Cataloging-in-Publication Data Thermochemical processing of biomass: conversion into fuels, chemicals, and power / editor, Robert C. Brown. p. cm. – (Wiley Series in Renewable Resources) Includes bibliographical references and index. ISBN 978-0-470-72111-7 (hardback) 1. Biomass energy. 2. Thermochemistry. 3. Energy conversion. I. Brown, Robert C. (Robert Clinton) TP339.T476 2011 6620 .88–dc22 2010050378

A catalogue record for this book is available from the British Library. Print ISBN: 9780470721117 ePDF ISBN: 9781119990857 oBook ISBN: 9781119990840 ePub ISBN: 9781119990994 Set in 10/12pt Times Roman by Thomson Digital, Noida, India Printed in Great Britain by Antony Rowe Ltd, Chippenham, Wiltshire

This book is dedicated to the staff and students who helped build the thermochemical processing programs of the Center for Sustainable Environmental Technologies and the Bioeconomy Institute at Iowa State University.

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Contents Series Preface Acknowledgements List of Contributors 1 Introduction to Thermochemical Processing of Biomass into Fuels, Chemicals, and Power Robert C. Brown 1.1 Introduction 1.2 Direct Combustion 1.3 Gasification 1.4 Fast Pyrolysis 1.5 Hydrothermal Processing 1.6 Hydrolysis to Sugars 1.7 Technoeconomic Analysis References 2 Biomass Combustion Bryan M. Jenkins, Larry L. Baxter and Jaap Koppejan Nomenclature Introduction Combustion Systems 2.2.1 Fuels 2.2.2 Types of Combustor 2.3 Fundamentals of Biomass Combustion 2.3.1 Combustion Properties of Biomass 2.3.2 Combustion Stoichiometry 2.3.3 Equilibrium 2.3.4 Rates of Reaction 2.4 Pollutant Emissions and Environmental Impacts 2.4.1 Oxides of Nitrogen and Sulfur 2.4.2 Products of Incomplete Combustion 2.4.3 Particulate Matter 2.4.4 Dioxin-like Compounds 2.4.5 Heavy Metals 2.4.6 Radioactive Species 2.4.7 Greenhouse Gas Emissions References 2.1 2.2

xiii xv xvii

1 1 5 6 7 8 9 10 10 13 13 14 15 15 18 23 23 29 32 33 35 36 38 38 38 40 40 40 41

viii

Contents

3 Gasification Richard L. Bain and Karl Broer 3.1 3.2

Introduction Fundamentals of Gasification 3.2.1 Heating and Drying 3.2.2 Pyrolysis 3.2.3 Gas–Solid Reactions 3.2.4 Gas-phase Reactions 3.3 Feed Properties 3.4 Classifying Gasifiers According to Method of Heating 3.4.1 Air-blown Gasifiers 3.4.2 Steam/Oxygen-blown Gasifiers 3.4.3 Indirectly Heated Gasifiers 3.5 Classifying Gasifiers According to Transport Processes 3.5.1 Fixed Bed 3.5.2 Bubbling Fluidized Bed 3.5.3 Circulating Fluidized Bed (CFB) 3.5.4 Entrained Flow 3.6 Pressurized Gasification 3.7 Product Composition 3.7.1 Char and Tar 3.8 System Applications 3.8.1 Process Heat 3.8.2 Combined Heat and Power (CHP) 3.8.3 Synthetic Fuels References 4 Syngas Cleanup, Conditioning, and Utilization David C. Dayton, Brian Turk and Raghubir Gupta 4.1 4.2

Introduction Syngas Cleanup and Conditioning 4.2.1 Particulates 4.2.2 Sulfur 4.2.3 Ammonia Decomposition and HCN Removal 4.2.4 Alkalis and Heavy Metals 4.2.5 Chlorides 4.2.6 Tars 4.3 Syngas Utilization 4.3.1 Syngas to Gaseous Fuels 4.3.2 Syngas to Liquid Fuels 4.4 Summary and Conclusions References

47 47 48 48 49 50 50 51 54 54 56 56 58 58 60 61 62 63 64 67 68 68 68 74 74 78 78 79 81 83 84 85 85 86 89 90 98 111 115

Contents

5 Fast Pyrolysis Robbie H. Venderbosch and Wolter Prins 5.1

Introduction 5.1.1 Fundamentals of Pyrolysis 5.1.2 Effect of Ash 5.2 Bio-oil Properties 5.2.1 Composition and Stability 5.3 Fast Pyrolysis Process Technologies 5.3.1 Entrained Downflow 5.3.2 Ablative Reactor 5.3.3 Bubbling Fluidized Bed 5.3.4 Circulating Fluidized Bed (CFB) 5.3.5 Moving-grate Vacuum Pyrolysis 5.3.6 Rotating-cone Pyrolyzer 5.4 Bio-oil Fuel Applications 5.4.1 Gas Turbines 5.4.2 Gasification 5.4.3 Transportation Fuels 5.5 Chemicals from Bio-oil 5.5.1 Whole Bio-oil 5.5.2 Fractions of Bio-oil 5.6 Concluding Remarks Acknowledgements References 6 Upgrading Fast Pyrolysis Liquids Anthony V. Bridgwater 6.1

6.2 6.3

6.4 6.5

Introduction to Fast Pyrolysis and Bio-oil 6.1.1 Introduction 6.1.2 Bio-oil General Characteristics Liquid Characteristics and Quality Significant Factors Affecting Characteristics 6.3.1 Feed Material 6.3.2 Reactors Norms and Standards Bio-oil Upgrading 6.5.1 Acidity or Low pH 6.5.2 Aging 6.5.3 Alkali Metals 6.5.4 Char 6.5.5 Chlorine 6.5.6 Color 6.5.7 Contamination of Feed 6.5.8 Distillability 6.5.9 High Viscosity

ix

124 124 125 128 128 131 134 135 135 138 141 142 142 143 148 149 149 150 150 151 152 153 153 157 157 157 157 159 159 159 164 165 165 165 165 166 166 167 167 168 168 168

x

Contents

6.5.10 Inhomogeneity 6.5.11 Low H:C Ratio 6.5.12 Low pH 6.5.13 Materials Incompatibility 6.5.14 Miscibility with Hydrocarbons 6.5.15 Nitrogen 6.5.16 Other Solid Particulates, Excluding Char 6.5.17 Oxygen Content 6.5.18 Phase Separation or Inhomogeneity 6.5.19 Smell 6.5.20 Structure of Bio-oil 6.5.21 Sulfur 6.5.22 Temperature Sensitivity 6.5.23 Toxicity 6.5.24 Viscosity 6.5.25 Water Content 6.6 Chemical and Catalytic Upgrading of Bio-oil 6.6.1 Physical Upgrading of Bio-oil 6.6.2 Catalytic Upgrading of Bio-oil 6.6.3 Other Methods for Chemical Upgrading of Bio-oil 6.6.4 Hydrogen 6.6.5 Chemicals 6.7 Conclusions References 7 Hydrothermal Processing Douglas C. Elliott 7.1 7.2

7.3

7.4

7.5

Introduction Background 7.2.1 Why Hydrothermal Processing? 7.2.2 History of Hydrothermal Liquefaction Process Development 7.2.3 History of Hydrothermal Gasification Process Development Fundamentals 7.3.1 Subcritical Processing in the Liquid Phase 7.3.2 Supercritical Processing in the Vapor Phase Hydrothermal Liquefaction 7.4.1 State of Technology 7.4.2 Process Descriptions 7.4.3 Product Evaluation 7.4.4 Product Utilization 7.4.5 Process Mechanism Evaluations 7.4.6 Recent Fundamental Evaluations 7.4.7 Conclusions Relative to Hydrothermal Liquefaction Hydrothermal Gasification 7.5.1 State of Technology

169 169 169 169 169 170 170 170 170 170 171 171 171 172 172 172 172 172 174 180 182 182 187 188 200 200 202 202 202 203 203 204 204 205 205 205 207 212 213 216 216 217 217

Contents

7.5.2 Process Description 7.5.3 Catalytic Hydrothermal Gasification 7.5.4 Hydrothermal Gasification in Supercritical Water 7.5.5 Conclusions Relative to Hydrothermal Gasification 7.6 Pumping Biomass into Hydrothermal Processing Systems 7.7 Conclusions of Hydrothermal Processing References 8 Catalytic Conversion of Sugars to Fuels Geoffrey A. Tompsett, Ning Li and George W. Huber 8.1

xi

217 218 221 223 223 226 226 232

Introduction 8.1.1 Overview 8.1.2 Desired Targets and Overall Reactions 8.1.3 Thermodynamics of Chemistry Conversion 8.2 Chemistry of Sugars 8.3 Hydrogen from Sugars 8.3.1 Overall Reaction and Thermodynamics 8.3.2 Reaction Mechanism 8.3.3 Aqueous-Phase Reforming 8.3.4 Supercritical Reactions – Reforming of Sugars 8.4 Sugar to Light Alkanes 8.4.1 Overall Reaction and Thermodynamics 8.4.2 Dehydration of Sugars 8.4.3 Hydrogenation Reactions of Sugars 8.4.4 Combined Dehydration/Hydrogenation 8.5 Sugars to Oxygenates 8.5.1 Targeted Products and Thermodynamics 8.5.2 Biphasic Dehydration Reactions (HMF and Furfural Production) 8.5.3 Hydrogenation 8.5.4 Other Oxygenate Fuels from Sugars 8.6 Sugars to Larger Alkanes 8.6.1 Overall Reaction and Chemistry 8.6.2 C–C Bond Formation 8.6.3 Hydrogenation/Dehydration 8.7 Sugar Conversion to Aromatics 8.7.1 Overall Reaction and Thermodynamics 8.7.2 Catalytic Fast Pyrolysis 8.7.3 Aromatics from Sugar Fragments in the Aqueous Phase 8.8 Conclusions and Summary Acknowledgements References

232 232 233 235 238 242 242 244 244 246 249 249 251 252 254 254 254 255 256 258 261 261 266 268 269 269 270 271 271 272 272

9 Hybrid Processing DongWon Choi, Alan A. DiSpirito, David C. Chipman and Robert C. Brown

280

9.1

Introduction

280

xii

Contents

9.1.1 Biorefineries 9.1.2 Hybrid Thermochemical/Biochemical Processing 9.2 Syngas Fermentation 9.2.1 Catalytic Conversions of Syngas: Chemical Versus Biological 9.2.2 Fermentation of Syngas 9.2.3 Microbial CO Metabolism 9.2.4 Microbial H2 Metabolism 9.2.5 Microbial CH4 Metabolism 9.2.6 Photosynthetic CO2 Metabolism 9.2.7 Current Industrial Progress of Syngas Fermentation 9.2.8 Problems and Future Perspectives 9.3 Bio-oil Fermentation 9.3.1 Levoglucosan Utilizers 9.3.2 Current Status of Levoglucosan Fermentation 9.3.3 Future Perspectives References 10 Costs of Thermochemical Conversion of Biomass to Power and Liquid Fuels Mark M. Wright and Robert C. Brown 10.1 10.2

Introduction Electric Power Generation 10.2.1 Direct Combustion to Power 10.2.2 Gasification to Power 10.2.3 Fast Pyrolysis to Power 10.3 Liquid Fuels via Gasification 10.3.1 Gasification to Hydrogen 10.3.2 Gasification to Methanol 10.3.3 Gasification to Mixed Alcohols 10.3.4 Gasification to Fischer–Tropsch Liquids 10.3.5 Gasification and Syngas Fermentation to PHA and Co-Product Hydrogen 10.4 Liquid Fuels via Fast Pyrolysis 10.4.1 Bio-oil Fermentation to Ethanol 10.4.2 Bio-oil Upgrading to Gasoline and Diesel 10.4.3 Bio-oil Gasification to Liquid Fuels 10.5 Summary and Conclusions References Index

280 281 282 282 282 283 288 289 290 291 292 295 296 297 298 299

307 307 308 308 308 309 309 309 311 312 313 315 316 316 316 318 319 321 323

Series Preface Renewable resources, their use and modification are involved in a multitude of important processes with a major influence on our everyday lives. Applications can be found in the energy sector, chemistry, pharmacy, the textile industry, paints and coatings, to name but a few. The area interconnects several scientific disciplines (agriculture, biochemistry, chemistry, technology, environmental sciences, forestry, etc.), which makes it very difficult to have an expert view on the complicated interaction. Therefore, the idea to create a series of scientific books, focusing on specific topics concerning renewable resources, has been very opportune and can help to explain some of the underlying connections in this area. In a very fast changing world, trends are characteristic not only for fashion and political standpoints. Even science is not free from hypes and buzzwords. The use of renewable resources is again more important nowadays; however, it is not part of a hype or a fashion. As the lively discussions among scientists continue about how many years we will still be able to use fossil fuels, with opinions ranging from 50 to 500 years, they do agree that the reserve is limited and that it is essential not only to search for new energy carriers but also for new material sources. In this respect, renewable resources are a crucial area in the search for alternatives for fossil-based raw materials and energy. In the field of energy supply, biomass and renewable resources will be part of the solution alongside other alternatives such as solar energy, wind energy, hydraulic power, hydrogen technology and nuclear energy. In the field of material sciences, the impact of renewable resources will probably be even bigger. Integral utilization of crops and the use of waste streams in certain industries will grow in importance, leading to a more sustainable way of producing materials. Although our society was much more (almost exclusively) based on renewable resources centuries ago, this disappeared in the Western world in the 19th century. Now it is time to focus again on this field of research. However, it should not mean a retour a la nature, but it should be a multidisciplinary effort on a highly technological level to perform research towards new opportunities, to develop new crops and products from renewable resources. This will be essential to guarantee a level of comfort for a growing number of people living on our planet. It is ‘the’ challenge for the coming generations of scientists to develop more sustainable ways to create prosperity and to fight poverty and hunger in the world. A global approach is certainly favoured. This challenge can only be dealt with if scientists are attracted to this area and are recognized for their efforts in this interdisciplinary field. It is therefore also essential that consumers recognize the fate of renewable resources in a number of products. Furthermore, scientists do need to communicate and discuss the relevance of their work. The use and modification of renewable resources may not follow the path of the genetic

xiv

Series Preface

engineering concept in view of consumer acceptance in Europe. Related to this aspect, the series will certainly help to increase the awareness of the importance of renewable resources. Being convinced of the value of the renewables approach for the industrial world, as well as for developing countries, I was delighted to collaborate on this series of books focusing on different aspects of renewable resources. I hope that readers become aware of the complexity, the interaction and interconnections, and the challenges of this field and that they will help to communicate the importance of renewable resources. I certainly want to thank the people from the Chichester office of Wiley, especially David Hughes, Jenny Cossham and Lyn Roberts, for seeing the need for such a series of books on renewable resources, for initiating and supporting it and for helping to carry the project to the end. Last but not least, I want to thank my family, especially my wife Hilde and children Paulien and Pieter-Jan, for their patience and for giving me the time to work on the series when other activities seemed to be more inviting. Christian V. Stevens Faculty of Bioscience Engineering Ghent University, Belgium Series Editor Renewable Resources June 2005

Acknowledgements The genesis of this book was an invitation by Christian Stevens to describe the ‘thermochemical option’ for biofuels production at the Third International Conference on Renewable Resources and Biorefineries at Ghent University in 2007. At that time, many people working in the biofuels community viewed thermochemical processing as little more than an anachronism in the age of biotechnology. I was very appreciative of Chris’ interest in exploring alternative pathways. After the conference, he followed up with an invitation to submit a book proposal on thermochemical processing to the Wiley Series in Renewable Resources, for which he serves as Series Editor. At the time I was busy with other responsibilities and declined his invitation. A year later Chris repeated his offer and I agreed to edit a volume on thermochemical production of biofuels, biobased chemicals, and biopower. I am very grateful that several prominent colleagues in the field agreed to contribute chapters: Bryan Jenkins, Richard Bain, David Dayton, Wolter Prins, Tony Bridgwater, Douglas Elliott, George Huber, Mark Wright, and DongWon Choi. The project editors at Wiley were extremely helpful and patient during the 2 years that my colleagues and I struggled to find time to write on a subject that was rapidly moving from obscurity to prominence and was presenting us with a variety of distractions. These steadfast project editors include Richard Davies, Jon Peacock, and Sarah Hall. I am also indebted to several people who helped me with administrative and management responsibilities at the Bioeconomy Institute (BEI) and the Center for Sustainable Environmental Technologies (CSET) at Iowa State University while this book was being prepared: Jill Euken, deputy director of the BEI; Ryan Smith, deputy director of CSET; Becky Staedtler, business manager of the BEI and CSET; and Diane Meyer, manager of the BEI proposal office. Finally, I wish to acknowledge my wife, Carolyn, who has been the most steadfast of all during the preparation of this book.

List of Contributors Richard L. Bain, National Renewable Energy Laboratory, Colorado, USA Larry L. Baxter, Brigham Young University, Utah, USA Anthony V. Bridgwater, Bioenergy Research Group, Aston University, UK Karl Broer, Department of Mechanical Engineering, Iowa State University, USA Robert C. Brown, Department of Mechanical Engineering, Iowa State University, USA David C. Chipman, Center for Sustainable Environmental Technologies and Department of Mechanical Engineering, Iowa State University, USA DongWon Choi, Department of Biological and Environmental Sciences, Texas A&M University – Commerce, Commerce, TX 75429, USA David C. Dayton, Center for Energy Technology, RTI International, North Carolina, USA Alan A. DiSpirito, Department of Biochemistry, Biophysics and Molecular Biology, Iowa State University, USA Douglas C. Elliott, Pacific Northwest National Laboratory, Washington, USA Raghubir Gupta, Center for Energy Technology, RTI International, North Carolina, USA George W. Huber, Department of Chemical Engineering, University of Massachusetts– Amherst, USA Bryan M. Jenkins, University of California, Davis, California, USA Jaap Koppejan, Procede Biomass BV, The Netherlands Ning Li, Department of Chemical Engineering, University of Massachusetts–Amherst, USA Wolter Prins, Faculty of Bioscience Engineering, Ghent University, Belgium Geoffrey A. Tompsett, Department of Chemical Engineering, University of Massachusetts–Amherst, USA Brian Turk, Center for Energy Technology, RTI International, North Carolina, USA Robbie H. Venderbosch, Biomass Technology Group B.V., The Netherlands Mark M. Wright, Department of Mechanical Engineering, Iowa State University, USA

1 Introduction to Thermochemical Processing of Biomass into Fuels, Chemicals, and Power Robert C. Brown Iowa State University, Department of Mechanical Engineering, Ames, IA 50011, USA

1.1

Introduction

Thermochemical processing of biomass uses heat and catalysts to transform plant polymers into fuels, chemicals, or electric power. This contrasts with biochemical processing of biomass, which uses enzymes and microorganisms for the same purpose. Although biochemical processing is often touted as a fundamentally new approach to converting plant materials into useful products and thermochemical processing is often described as “mature” technology with little scope for improvement, in fact both have been employed by humankind for millennia. Fire for warmth, cooking, and production of charcoal were the first thermal transformations of biomass controlled by humans, while fermentation of fruits, honey, grains, and vegetables was practiced before recorded time. Despite their long records of development, neither is mature, as the application of biotechnology to improving biochemical processes for industrial purposes has revealed [1]. The petroleum and petrochemical industries have accomplished similar wonders in thermochemical processing of hydrocarbon feedstocks, although the more complicated chemistries of plant molecules have not been fully explored. Ironically, the domination of thermochemical processing in commercial production of fuels, chemicals, and power from fossil resources for well over a century may explain why it is sometimes overlooked as a viable approach to biobased products. Smokestacks belching Thermochemical Processing of Biomass: Conversion into Fuels, Chemicals and Power, First Edition . Edited by Robert C. Brown © 2011 John Wiley & Sons, Ltd. Published 2011 by John Wiley & Sons, Ltd. ISBN: 978-0-470-72111-7

2

Introduction to Thermochemical Processing of Biomass into Fuels, Chemicals, and Power

pollutants from thermochemical processing of fossil fuels is an indelible icon from the twentieth century that no one wishes to replicate with biomass. However, as described in a report released by the US Department of Energy in 2008 [2], thermal and catalytic sciences also offer opportunities for dramatic advances in biomass processing. Thermochemical processing has several advantages relative to biochemical processing. As detailed in Table 1.1, these include the ability to produce a diversity of oxygenated and hydrocarbon fuels, reaction times that are several orders of magnitude shorter than biological processing, lower cost of catalysts, the ability to recycle catalysts, and the fact that thermal systems do not require the sterilization procedures demanded for biological processing. The data in Table 1.1 also suggest that thermochemical processing can be done with much smaller plants than is possible for biological processing of cellulosic biomass. Although this may be true for some thermochemical options (such as fast pyrolysis), other thermochemical options (such as gasification-to-fuels) are likely to be built at larger scales than biologically based cellulosic ethanol plants when the plants are optimized for minimum fuel production cost [3]. The first-generation biofuels industry, launched in the late 1970s, was based on biochemically processing sugar or starch crops (mostly sugar cane and maize respectively) into ethanol fuel and oil seed crops into biodiesel. These industries grew tremendously in the first decade of the twenty-first century, with worldwide annual production reaching almost 19 billion gallons (
72  109 L) of ethanol and 4.4 billion gallons (
16.7  109 L) of biodiesel in 2008 [4]. This has not been achieved without controversy, including criticism of crop and biofuel subsidies, concerns about using food crops for fuel production, and debate over the environmental impact of biofuels agriculture, including uncertainties about the role of biofuels in reducing greenhouse gas emissions [5]. Many of these concerns would be mitigated by developing advanced biofuels that utilize high-yielding nonfood crops that can be grown on marginal or waste lands. These alternative crops are of two types: lipids from alternative crops and cellulosic biomass. Lipids are a large group of hydrophobic, fat-soluble compounds produced by plants and animals for high-density energy storage. Triglycerides, commonly known as vegetable oils, are among the most familiar form of lipids and have been widely used in recent years for the production of biodiesel. As illustrated in Figure 1.1, triglycerides consist of three long-chain fatty acids attached to a backbone of glycerol. It is relatively easy to hydrotreat triglycerides to yield liquid alkanes suitable as transportation fuels and propane gas. The hydrogenation of vegetable oils has already been proven technically feasible using conventional distillate Table 1.1 Comparison of biochemical and thermochemical processing. Adapted from NSF, 2008, Breaking the Chemical and Engineering Barriers to Lignocellulosic Biofuels: Next Generation Hydrocarbon Biorefineries, Ed. George W. Huber, University of Massachusetts Amherst. Courtesy: National Science Foundation

Products Reaction conditions Residence time Selectivity Catalyst/biocatalyst cost Sterilization Recyclability Size of plant (biomass input)

Biochemical processing

Thermochemical processing

Primarily alcohols Less than 70 C, 1 atm 2–5 days Can be made very selective $0.50/gallon ethanol Sterilize all feeds Difficult 2000–8000 tons/day

Range of fuels 100–1200 C, 1–250 atm 0.2 s–1 h Depends upon reaction $0.01/gallon gasoline No sterilization needed Possible with solid catalysts 5–200 tons/day (fast pyrolysis)

Introduction triglyceride

propane

3

alkanes

O R1

C O

R1 ' H

CH3

CH2

O C O

R2

CH

+

CH2

n H2

+

+

R2 ' H

3 CO2

O R3

C O

R3 ' H

CH3

CH2

R1, R2, R3 = fatty acid chain

R1', R2', R3' = alkane chain

Figure 1.1 Simplified representation of hydrogenation of triglyceride during hydrotreating

hydrotreaters at petroleum refineries [6], although the high price of traditional vegetable oils has discouraged companies from producing transportation fuels in this manner. Commercial deployment will require alternatives to traditional seed crops, which only yield 50–130 gal/ acre (467.5–1215.5 L/ha) [7]. Suggestions have included jatropha [8] (200–400 gal/acre (1870–3740 L/ha)) and palm oil [9] (up to 600 gal/acre (5610 L/ha)), but the most promising alternative is microalgae, which can be highly productive in natural ecosystems with oil yields as high as 2000 gal/acre (18 700 L/ha) in field trials and 15 000 gal/acre (140 250 L/ ha) in laboratory trials [10]. This promise requires considerable engineering development to reduce capital costs, which are estimated to be $100 000 to $1 million per acre ($250 000 to $2.5 million per hectare), and production costs, which exceed $10–$50 per gallon (about $2.60–$13 per liter) [10, 11]. Thus, the challenge of lipid-based biofuels is producing large quantities of inexpensive lipids rather than upgrading them. Cellulose, on the other hand, is the most abundant form of biomass on the planet. In the form of lignocellulose, a composite of cellulose, hemicellulose, and lignin [12], it dominates most natural ecosystems and is widely managed as sources of timber and animal forage. As illustrated in Figure 1.2, cellulose is a structural polysaccharide consisting of a long chain of glucose molecules linked by glycosidic bonds. Breaking these bonds releases the glucose

Glucose Unit

OH

O OH

CH2OH

OH

CH2OH

OH O

Glycosidic Bonds

O

O

O OH

CH2OH

O OH

OH O

O OH

CH2OH

OH

CH2OH

O

OH

OH

O

OH

CH2OH

O OH

O

O OH

CH2OH

Cellulose Chain

Figure 1.2 Cellulose is a long chain of glucose units connected by glycosidic bonds

4

Introduction to Thermochemical Processing of Biomass into Fuels, Chemicals, and Power

and makes it available for either food or fuel production. A variety of microorganisms secrete enzymes that hydrolyze the glycosidic bonds of cellulose (and hemicellulose). Many animals, like cattle and other ruminants, have developed symbiotic relationships with these microorganisms to allow them to digest cellulose. However, cellulose is usually found in nature as lignocellulose, a composite of cellulose fibers in a matrix of hemicellulose and lignin. The lignin, which few microorganisms are able to digest, protects the carbohydrate against biological attack. Thus, even ruminant animals that have evolved on diets of lignocellulosic biomass, such as grasses and forbs, can only extract 50–80% of the energy content of this plant material because some of the polysaccharides and all of the lignin pass through the gut undigested. Biochemical processing has many similarities to the digestive system of ruminant animals. Physical and chemical pretreatments release cellulose fibers from the composite matrix, making them more susceptible to enzymatic hydrolysis, which releases simple sugars that can be fermented or otherwise metabolized [13]. Biochemical processes occur at only a few tens of degrees Celsius above ambient temperature, with the result that they can take hours or even days to complete even in the presence of biocatalysts. Thermochemical processing occurs at temperatures that are at least several hundred degrees Celsius and sometimes over 1000 C above ambient conditions. At these temperatures, thermochemical processes occur very rapidly whether catalysts are present or not. Although thermochemical processing might be characterized as voracious in the pace of reaction and the variety of materials it can consume (not only carbohydrate, but lignin, lipids, proteins, and other plant compounds), its selectivity is not necessarily as indiscriminate as is sometimes attributed to it. Thermal depolymerization of cellulose in the absence of alkali or alkaline earth metals produces predominately levoglucosan, an anhydrosugar of the monosaccharide glucose [14]. Under certain conditions, it appears that lignin depolymerizes to monomeric phenolic compounds [15]. Under conditions of high-temperature combustion and gasification, chemical equilibrium among products is attained. Thus, thermochemical processing offers opportunities for rapid processing of diverse feedstocks, including recalcitrant materials and unique intermediate feedstocks, for production of fuels, chemicals, and power. As shown in Figure 1.3, thermochemical routes can be categorized as combustion, gasification, fast pyrolysis, hydrothermal processing, and hydrolysis to sugars. Direct combustion of biomass produces moderate- to high-temperature thermal energy (800–1600 C) suitable for electric power generation. Gasification generates both moderatetemperature thermal energy (700–1000 C) and a flammable gas mixture known commonly as producer gas or syngas, which can be used to generate either electric power or to synthesize fuels or other chemicals using catalysts or even microorganisms (syngas fermentation) [16]. Fast pyrolysis occurs at moderate temperatures (450–550 C) in the absence of oxygen to produce mostly condensable vapors and aerosols that are recovered as an energy-rich liquid known as bio-oil. Fast pyrolysis also produces smaller amounts of flammable gas (syngas) and solid charcoal, known as char or sometimes biochar [17]. Bio-oil can be burned for electric power generation or processed into hydrogen via steam reforming or into liquid hydrocarbons via hydroprocessing. Whereas fast pyrolysis requires relatively dry feedstocks (around 10 wt% moisture), hydrothermal processing is ideal for wet feedstocks that can be handled as slurries with solids loadings in the range of 5–20 wt%. Hydrothermal processing occurs at pressures of 50–250 atm (
5–25 MPa) to prevent

Direct Combustion

Figure 1.3

5

Thermochemical options for production of fuels, chemicals, and power

boiling of the water in the slurry and at temperatures ranging from 200 to 500 C, depending upon whether the desired products are fractionated plant polymers [18], a partially deoxygenated liquid product known as biocrude [19], or syngas [20]. Finally, hydrolysis of plant polysaccharides yields simple sugars that can be catalytically or biocatalytically converted into fuels. Concentrated acid or the combined action of dilute acid and heat are well known to hydrolyze polysaccharides to monosaccharides. The biotechnology revolution has encouraged the use of enzymes to more efficiently hydrolyze sugars from biomass, but the high cost of enzymes has slowed commercial introduction of so-called cellulosic biofuels by this biochemical route [21]. Although acid hydrolysis qualifies as thermochemical processing, more direct thermal interventions can also yield sugars from biomass. Hydrothermal processing at modest temperatures fractionates biomass into cellulose fibers, hemicellulose dehydration products, and lignin [18]. Further hydrothermal processing of the cellulose can produce glucose solutions. Fast pyrolysis also yields significant quantities of sugars and anhydrosugars under suitable processing conditions [22]. These “thermolytic sugars” can either be fermented or catalytically upgraded to fuel molecules.

1.2

Direct Combustion

Much of the focus on bioenergy in the USA has been production of liquid transportation fuels in an effort to displace imported petroleum. Recently, it has been argued that a better use of biomass would be to burn it for the generation of electricity to power battery electric vehicles (BEVs) [23]. Well-to-wheels analyses indicate that BEVs are superior to biofuelspowered internal combustion engine vehicles in terms of primary energy consumed, greenhouse gas emissions, lifecycle water usage, and cost when evaluated on the basis of kilometers driven [24]. Combustion is the rapid reaction of fuel and oxygen to obtain thermal energy and flue gas, consisting primarily of carbon dioxide and water. Depending on the heating value and moisture content of the fuel, the amount of air used to burn the fuel, and the construction of the furnace, flame temperatures can exceed 1650 C. Direct combustion has the advantage that it employs commercially well-developed technology. It is the foundation of much of the

6

Introduction to Thermochemical Processing of Biomass into Fuels, Chemicals, and Power

electric power generation around the world. In principle, existing power plants could be quickly and inexpensively retrofitted to burn biomass, compared with greenfield construction of advanced biorefineries, which would be based upon largely unproven technologies. Plug-in hybrid electric vehicles will soon be widely available to utilize this biopower. In the long term, high efficiency combined-cycle power plants based on gasified or pyrolyzed biomass will provide power for long-range electric vehicles based on advanced battery technology [25]. However, combustion is burdened by three prominent disadvantages. These include penalties associated with burning high-moisture fuels, agglomeration and ash fouling due to alkali compounds in biomass, and difficulty of providing and safeguarding sufficient supplies of bulky biomass to modern electric power plants. Chapter 2 is devoted to a description of biomass combustion as a thermochemical technology.

1.3

Gasification

Thermal gasification is the conversion of carbonaceous solids at elevated temperatures and under oxygen-starved conditions into syngas, a flammable gas mixture of carbon monoxide, hydrogen, methane, nitrogen, carbon dioxide, and smaller quantities of hydrocarbons [26]. Gasification has been under development for almost 200 years, beginning with the gasification of coal to produce so-called “manufactured gas” or “town gas” for heating and lighting. Coal gasification has also been used for large-scale production of liquid transportation fuels, first in Germany during World War II and then later in South Africa during a period of worldwide embargo as a result of that country’s apartheid policies. Gasification can be used to convert any carbonaceous solid or liquid to low molecular weight gas mixtures. In fact, the high volatile matter content of biomass allows it to be gasified more readily than coal. Biomass gasification has found commercial application where waste wood was plentiful or fossil resources were scarce. An example of the former was Henry Ford’s gasification of wood waste derived from shipping crates at his early automotive plants [27]. An example of the latter was the employment of portable wood gasifiers in Europe during World War II to power automobiles. With a few exceptions, gasification in all its forms gradually declined over the twentieth century due to the emergence of electric lighting, the development of the natural gas industry, and the success of the petroleum industry in continually expanding proven reserves of petroleum. In the twenty-first century, as natural gas and petroleum become more expensive, gasification of both coal and biomass is likely to be increasingly employed. As illustrated in Figure 1.4, one of the most attractive features of gasification is its flexibility of application, including thermal power generation, hydrogen production, and synthesis of fuels and chemicals. This offers the prospect of gasification-based energy refineries, producing a mix of energy and chemical products or allowing the staged introduction of technologies as they reach commercial viability. The simplest application of gasification is production of heat for kilns or boilers. Often the syngas can be used with minimal clean-up because tars or other undesirable compounds are consumed when the gas is burned and process heaters are relatively robust to dirty gas streams. The syngas can be used in internal combustion engines if tar loadings are not too high and after removal of the greater part of particulate matter entrained in the gas leaving

Fast Pyrolysis

7

Figure 1.4 Gasification offers several options for processing biomass into power, chemicals, and fuels

the gasifier. Gas turbines offer prospects for high-efficiency integrated gasification–combined-cycle power, but they require more stringent gas cleaning [28]. As the name implies, syngas can also be used to synthesize a wide variety of chemicals, including organic acids, alcohols, esters, and hydrocarbon fuels, but the catalysts for this synthesis are even more sensitive to contaminants than are gas turbines. Chapter 3 describes gasification technologies, Chapter 4 covers gas stream clean-up and catalytic upgrading to fuels and chemicals, and Chapter 9, which covers hybrid thermochemical–biochemical processing, includes a description of syngas fermentation [16].

1.4

Fast Pyrolysis

Fast pyrolysis is the rapid thermal decomposition of organic compounds in the absence of oxygen to produce liquids, gases, and char [17]. The distribution of products depends on the biomass composition and rate and duration of heating. Liquid yields as high as 72% are possible for relatively short residence times (0.5–2 s), moderate temperatures (400–600 C), and rapid quenching at the end of the process. The resulting bio-oil is a complex mixture of oxygenated organic compounds, including carboxylic acids, alcohols, aldehydes, esters, saccharides, phenolic compounds, and lignin oligomers. It has been used as fuel for both boilers and gas turbine engines, although its cost, corrosiveness, and instability during storage have impeded its commercial deployment. Its great virtues are the simplicity of generating bio-oil and the attractiveness of a liquid feedstock compared with either gasified or unprocessed biomass. Bio-oil can be upgraded to transportation fuels through a combination of steam reforming [29] of light oxygenates in the bio-oil to provide hydrogen and hydrocracking lignin oligomers and carbohydrate to synthetic diesel fuel or gasoline [30, 31]. Recent technoeconomic analysis [32] indicating that bio-oil could be upgraded to synthetic gasoline and diesel for $2–$3 per gallon (about $0.53–$0.79 per liter) gasoline equivalent has spurred interest in fast pyrolysis and bio-oil upgrading.

8

Introduction to Thermochemical Processing of Biomass into Fuels, Chemicals, and Power

Hydroprocessing bio-oil into hydrocarbons suitable as transportation fuel is similar to the process for refining petroleum. Hydroprocessing was originally developed to convert petroleum into motor fuels by reacting it with hydrogen at high pressures in the presence of catalysts. Hydroprocessing includes two distinct processes. Hydrotreating is designed to remove sulfur, nitrogen, oxygen, and other contaminants from petroleum. When adapted to bio-oil, the main contaminant to be removed is oxygen. Thus, hydrotreating bio-oil is primarily a process of deoxygenation, although nitrogen can be significant in some bio-oils. Hydrocracking is the reaction of hydrogen with organic compounds to break long-chain molecules into lower molecular weight compounds. Although fast pyrolysis attempts to depolymerize plant molecules, a number of carbohydrate and lignin oligomers are found in bio-oil, which hydrocracking can convert into more desirable paraffin or naphthene molecules. Some researchers are attempting to add catalysis to the pyrolysis reactor to yield hydrocarbons directly. Similar to the process of fluidized catalytic cracking used in the petroleum industry, the process occurs at atmospheric pressure over acidic zeolites. A yield of 17% of C5–C10 hydrocarbons has been reported in a study of upgrading of pyrolytic liquids from poplar wood [33]. Although superior to conventional bio-oil, this product still needs refining to gasoline or diesel fuel. Fast pyrolysis of biomass to bio-oil is described in Chapter 5. Upgrading of bio-oil to transportation fuels is discussed in Chapter 6.

1.5

Hydrothermal Processing

Hydrothermal processing describes the thermal treatment of wet biomass at elevated pressures to produce carbohydrate, liquid hydrocarbons, or gaseous products depending upon the reaction conditions. As illustrated in Figure 1.5, processing temperature must be

Figure 1.5 Temperature/pressure regimes of hydrothermal processing

Hydrolysis to Sugars

9

increased as reaction temperature increases to prevent boiling of water in the wet biomass. At temperatures around 100 C, extraction of high-value plant chemicals such as resins, fats, phenolics, and phytosterols is possible. At 200 C and 20 atm (
2 MPa), fibrous biomass undergoes a fractionation process to yield cellulose, lignin, and hemicelluloses degradation products such as furfural. Further hydrothermal processing can hydrolyze the cellulose to glucose. At 300–350 C and 120–180 atm (
12.2–18.2 MPa), biomass undergoes more extensive chemical reactions, yielding a hydrocarbon-rich liquid known as biocrude. Although superficially resembling bio-oil, it has lower oxygen content and is less miscible in water, making it more amenable to hydrotreating. At 600–650 C and 300 atm (30.4 MPa) the primary reaction product is gas, including a significant fraction of methane. Continuous feeding of biomass slurries into high-pressure reactors and efficient energy integration represent engineering challenges that must be overcome before hydrothermal processing results in a commercially viable technology. Chapter 7 is devoted to hydrothermal processing of biomass.

1.6

Hydrolysis to Sugars

Although biochemical processing is sometimes referred to as the “sugar platform,” it is possible to thermally depolymerize biomass into monosaccharides and catalytically synthesize fuel molecules from these carbohydrate building blocks. Thus, the so-called sugar platform can be a pure play in biochemical processing (enzymatic hydrolysis of plant carbohydrates to sugar followed by fermentation), a hybrid thermochemical–biochemical process (thermally or chemically induced hydrolysis followed by fermentation of the released sugar), a hybrid biochemical–thermochemical process (enzymatic hydrolysis followed by catalytic synthesis of the sugar to hydrocarbons), or a pure play in thermochemical processing (thermal depolymerization followed by catalytic upgrading of the sugar to fuel molecules). As described in Chapter 9, fast pyrolysis can produce both anhydrosugars and fermentable sugar from biomass, the yield of which is significantly enhanced if the biomass is washed or otherwise treated to eliminate the catalytic activity of naturally occurring alkali and alkaline earth metals [22]. Limited technoeconomic analysis of the process suggests that fermentation of sugar extracted from bio-oil could yield ethanol at costs competitive with cellulosic ethanol derived from either acid or enzymatic hydrolysis [34]. Similarly, hydrothermal processing under mild conditions can produce aqueous solutions of fermentable sugar [18]. These sugars can also be catalytically converted to fuels. Sugars that exist as five-member rings, like the five-carbon sugar xylose or the six-carbon sugar fructose, are readily dehydrated to the five-member rings of furan compounds [35], some examples of which are illustrated in Figure 1.6. Furans are colorless, water-insoluble flammable liquids with volatility comparable to hydrocarbons of similar molecular weight. Some kinds of furans have heating values and octane numbers comparable to gasoline, making them potential transportation fuel [36]. Catalysts can improve yields by making furan-producing pathways more selective among the large number of competing reactions that can occur during pyrolysis of biomass. 2,5-Dimethyl furan in particular has received recent interest because new catalytic synthesis routes from sugars have been developed [37, 38]. Neither the fuel

10

Introduction to Thermochemical Processing of Biomass into Fuels, Chemicals, and Power

Figure 1.6 Furans relevant to the production of transportation fuels by thermochemical processing of sugars. Source: Ref. [36]

properties nor the toxicity of these compounds have been much studied, raising questions as to their ultimate practicality as transportation fuel. A more promising approach known as aqueous-phase processing reacts monomeric sugar or sugar-derived compounds in the presence of heterogeneous catalysts at 200–260 C and 10–50 bar (1–5 MPa) to produce alkanes, the same hydrocarbons found in gasoline [39, 40]. Catalytic conversion of sugars would have several advantages over fermentation, including higher throughputs, ready conversion of a wide range of sugars, and the immiscible hydrocarbon products could be recovered without the expensive distillations required in ethanol plants. Chapter 8 explores the possibilities of catalytically converting sugars to fuel molecules.

1.7

Technoeconomic Analysis

Of the several technologies explored in this book, only a few are in commercial operation. Although a number of thermochemical technologies have been demonstrated with biomass feedstocks, very limited information on economic performance based on actual construction or operating costs is available in the literature. In the absence of such information, technoeconomic analyses are useful in estimating capital and operating costs for commercial-scale facilities, despite the well-known limitations of such analysis. Although by no means comprehensive, Chapter 10 provides cost estimates for a wide range of thermochemical processes, ranging from electric power generation to the production of biopolymers and hydrogen via syngas fermentation. Although differences in basis years, feedstock costs, financing options, and granularity of the analyses make it difficult to make comparisons among the various technology options, these analyses provide a useful starting point for exploring the feasibility of different approaches to thermochemical processing.

References [1] US Department of Energy (2006) Breaking the biological barriers to cellulosic ethanol – a joint research agenda. DOE/SC-0095, US Department of Energy Office of Science and Office of Energy Efficiency and Renewable Energy, http://www.doegenomestolife.org/biofuels/ (accessed 19 September 2010). [2] Huber, G. (ed.) (2008) Breaking the Chemical and Engineering Barriers to Lignocellulosic Biofuels: Next Generation Hydrocarbon Biorefineries,US Department of Energy, http://www. ecs.umass.edu/biofuels/Images/Roadmap2-08.pdf (accessed 19 September 2010).

References

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[3] Wright, M. and Brown, R.C. (2007) Establishing the optimal sizes of different kinds of biorefineries. Biofuels, Bioprocessing, and Biorefineries, 1, 191–200. [4] US Energy Information Agency (2008) International Energy Statistics, Renewables, http://tonto. eia.gov/cfapps/ipdbproject/IEDIndex3.cfm?tid¼79&pid¼79&aid¼1 (accessed 28 November 2010) [5] Farrell, A.E., Plevin, R.J., Turner, B.T. et al. (2006) Ethanol can contribute to energy and environmental goals. Science, 311, 506–508. [6] Kram, J.W. (2009) Aviation alternatives. Biodiesel Magazine (January), http://www.biodieselmagazine.com/article.jsp?article_id¼3071 (accessed 25 May 2009). [7] Klass, D.L. (1998) Biomass for Renewable Energy, Fuels, and Chemicals, Academic Press, San Diego, CA, p. 340. [8] Trabucco, A., Achten, W.M.J., Bowe, C. et al. (2010) Global mapping of Jatropha curcas yield based on response of fitness to present and future climate. GCB Bioenergy, 2, 139–151. [9] Basiron, Y. (2007) Palm oil production through sustainable plantations. European Journal of Lipid Science and Technology, 109, 289–295. [10] Sheehan, J., Dunahay, T., Benemann, J., and Roessler, P. (1998) A look back at the U.S. Department of Energy’s Aquatic Species program, US DOE National Renewable Energy Laboratory Report, NREL/TP-580-24190, July. [11] Lundquist, T.J., Woertz, I.C., Quinn, N.W.T., and Benemann, J.R. (2008) A realistic technology and engineering assessment of algal biofuel production, Technical Report, Energy Biosciences Institute, University of California, Berkeley, CA, October. [12] Sjostrom, E. (1993) Wood Chemistry: Fundamentals and Applications, second edition, Academic Press, San Diego, CA. [13] Brown, R.C. (2003) Biorenewable Resources: Engineering New Products from Agriculture, Iowa State Press, Ames, IA pp. 169–179. [14] Patwardhan, P.R., Satrio, J.A., Brown, R.C., and Shanks, B.H. (2009) Product distribution from fast pyrolysis of glucose-based carbohydrates. Journal of Analytical and Applied Pyrolysis, 86, 323–330. [15] Patwardhan, P.R., Johnston, P.A., Brown, R.C., and Shanks, B.H. (2010) Understanding fast pyrolysis of lignin. Preprint Papers – American Chemical Society, Division of Fuel Chemistry, 55 (2), 104. [16] Brown, R.C. (2005) Biomass Refineries based on hybrid thermochemical/biological processing – an overview, in Biorefineries, Biobased Industrial Processes and Products (eds B. Kamm, P.R. Gruber, and M. Kamm), Wiley-VCH Verlag GmbH, Weinheim. [17] Bridgwater, A.V. and Peacocke, G.V.C. (2000) Fast pyrolysis processes for biomass. Renewable and Sustainable Energy Reviews, 4, 1–73. [18] Allen, S.G., Kam, L.C., Zemann, A.J., and Antal, M.J., Jr., (1996) Fractionation of sugar cane with hot, compressed, liquid water. Industrial & Engineering Chemistry Research, 35, 2709–2715. [19] Elliott, D.C., Beckman, D., Bridgwater, A.V. et al. (1991) Developments in direct thermochemical liquefaction of biomass: 1983–1990. Energy and Fuels, 5 (3), 399–410. [20] Elliott, D.C., Neuenschwander, G.G., Hart, T.R. et al. (2004) Chemical processing in highpressure aqueous environments. 7. Process development for catalytic gasification of wet biomass feedstocks. Industrial & Engineering Chemistry Research, 43, 1999–2004. [21] Service, R.F. (2010) Is there a road ahead for cellulosic ethanol? Science, 329, 784–785. [22] Brown, R.C., Radlein, D., and Piskorz, J. (2001) Pretreatment processes to increase pyrolytic yield of levoglucosan from herbaceous feedstocks, in Chemicals and Materials from Renewable Resources (ed. J.J. Bozell), ACS Symposium Series No. 784, American Chemical Society, Washington, DC, pp. 123–132. [23] Campbell, J.E., Lobell, D.B., and Field, C.B. (2009) Greater transportation energy and GHG offsets from bioelectricity than ethanol. Science, 324, 1055–1057. [24] Gifford, J. and Brown, R.C., personal communication, December 2, 2010. [25] Brown, R.C. and Wright, M. (2009) Biomass conversion to fuels and electric power, in Biofuels: Environmental Consequences and Interactions with Changing Land Use, Proceedings of the

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[26] [27] [28] [29] [30] [31]

[32] [33] [34] [35] [36] [37] [38] [39] [40]

Introduction to Thermochemical Processing of Biomass into Fuels, Chemicals, and Power Scientific Committee on Problems of the Environment (SCOPE) International Biofuels Project Rapid Assessment, 22–25 September 2008 Gummersbach, Germany (eds R.W. Howarth and S. Bringezu), Cornell University, Ithaca, NY (http://cip.cornell.edu/biofuels/). Rezaiyan, J. and Cheremisinoff, N.P. (2005) Gasification Technologies: A Primer for Engineers and Scientists, Taylor & Francis, Boca Raton, FL. Reigel, E.R. (1933) Industrial Chemistry, 2nd edn, The Chemical Catalog Company, Inc., New York, p. 253. Cummer, K. and Brown, R.C. (2002) Ancillary equipment for biomass gasification. Biomass and Bioenergy, 23, 113–128. Czernik, S., French, R., Feik, C., and Chornet, E. (2002) Hydrogen by catalytic steam reforming of liquid byproducts from biomass thermoconversion processes. Industrial & Engineering Chemistry Research, 41, 4209–4215. Elliott, D.C. (2007) Historical development in hydroprocessing bio-oils. Energy and Fuels, 21, 1792–1815. Marker, T.L., Petri, J., Kalnes, T. et al. (2005) Opportunities for Biorenewables in Oil Refineries, Final Technical Report, US Department of Energy, Prepared by UOP, Inc., 12 December, http:// www.osti.gov/bridge/purl.cover.jsp;jsessionid¼CE524ACAABE8C174BD29C25416E6C780? purl¼/861458-Wv5uum/ (accessed 28 November 2010). Wright M.M., Daugaard D.E., Satrio J.A., and Brown R. C. (2010) Techno-economic analysis of biomass fast pyrolysis to transportation fuels. Fuel, 89 (Supplement 1), S2-S10. DOI: 10.1016/j. fuel.2010.07.029. Carlson, T., Vispute, T., and Huber, G. (2008) Green gasoline by catalytic fast pyrolysis of solid biomass derived compounds. ChemSusChem, 1, 397–400. So, K.S. and Brown, R.C. (1999) Economic analysis of selected lignocellulose-to-ethanol conversion technologies. Applied Biochemistry and Biotechnology, 77, 633–640. Lewkowski, J. (2001) Synthesis, chemistry and applications of 5-hydroxymethylfurfural and its derivatives. ARKIVOC, 1, 17–54. Bayan, S. and Beati, E. (1941) Furfural and its derivatives as motor fuels. Chimica e Industria, 23, 432–434. Roman-Leshkov, Y., Barrett, C.J., Liu, Z.Y., and Dumesic, J.A. (2007) Production of dimethylfuran for liquid fuels from biomass-derived carbohydrates. Nature, 447, 982–986. Zhao, H., Holladay, J.E., Brown, H., and Zhang, Z.C. (2007) Metal chlorides in ionic liquid solvents convert sugars to 5-hydroxymethyl-furfural. Science, 316, 1597–1600. Huber, G.W., Chheda, J.N., Christopher, B., and Dumesic, J.A. (2005) Production of liquid alkanes by aqueous-phase processing of biomass-derived carbohydrates. Science, 308, 1446–1450. Kunkes, E.L., Simonetti, D.A., West, R.M. et al. (2008) Catalytic conversion of biomass to monofunctional hydrocarbons and targeted liquid-fuel classes. Science, 322, 417–421.

2 Biomass Combustion Bryan M. Jenkins,1 Larry L. Baxter2 and Jaap Koppejan3 1

University of California, Davis, CA, USA 2 Brigham Young University, UT, USA 3 Procede Biomass BV, Enschede, Netherlands

Nomenclature Parameter a, b Cp e fi,j H h hfg Mdb mp,j mr,i mw Mwb Ql Qph Qvh T ufg Wi f l n

Units J kg
1 K
1, J mol
1 K
1 kg kg
1 kg kg
1 kJ kmol
1, kJ kJ kmol
1 kJ kg
1 kg kg
1 kg kg kg kg kg
1 kJ kJ kg
1 kJ kg
1 K kJ kg
1 kg kmol
1

Description constant coefficients of linearized enthalpy functions mass or molar specific heat excess oxidant or air in reactants mass fraction of fuel constituent i in product j enthalpy, total enthalpy molar enthalpy enthalpy of vaporization dry basis moisture content of feedstock mass of the product species j mass of the reactant species i mass of water as moisture in feedstock wet basis moisture content of feedstock heat transfer to reaction system (negative for heat loss) higher heating value at constant pressure higher heating value at constant volume absolute temperature internal energy of vaporization molar mass of species i fuel/air equivalence ratio air/fuel equivalence ratio, air factor stoichiometric coefficient

Thermochemical Processing of Biomass: Conversion into Fuels, Chemicals and Power, First Edition . Edited by Robert C. Brown © 2011 John Wiley & Sons, Ltd. Published 2011 by John Wiley & Sons, Ltd. ISBN: 978-0-470-72111-7

14

2.1

Biomass Combustion

Introduction

Since humans first learned to manage fire a quarter of a million years ago or more [1], the burning of fuels has served as a defining phenomenon for the development of societies. Releasing the energy needed for large-scale land clearing and agricultural expansion, combustion also provided the means for industrial growth, rapid transportation, the increase and concentration of populations, the waging of world wars, and the globalization of trade and culture. As the world population continues to expand, the environmental impacts of current fuel burning practices cannot be sustained into the future. Continuing evolution of heat and power generation is likely to see dramatic transformations toward low- and zeroemission alternatives, and the future design of combustion systems will be heavily challenged to adapt to more stringent regulations affecting environmental performance while maintaining economic competitiveness. Biomass resources of wood and straw supported early industrialization efforts until largely supplanted by fossil energy resources – coal, petroleum, and natural gas – and hydroelectric and nuclear power. Ancient uses of fire are still employed by a large fraction of the world’s population that is without access to more expensive fuels or electricity. Firewood gathering constitutes a significant burden of work and environmental harm, and uncontrolled emissions are responsible for high levels of respiratory and other diseases mostly among women and children [2]. Firewood use in fireplaces and woodstoves for heating purposes is a major demand sector for biomass. These uses of biomass are typically associated with low conversion efficiency and high pollutant emissions. Although the sustainability of biomass production and conversion to fuels and power has recently seen increasing scrutiny due to indirect land use change and other effects associated with global food and energy markets [3], as a well-managed renewable resource biomass has the potential to contribute more substantially to the development of a sustainable economy. The combined processes of plant photosynthesis and respiration produce in biomass a chemically complex resource supporting a wide range of uses. Emulating these processes in manufacturing fuels and chemicals from sunlight but without the need of life processes is now viewed as one of the scientific grand challenges [4]. The energy storage in biomass also enables its use as a renewable resource for baseload power generation, an integral component in managing electricity distribution systems as generating capacity increases among more intermittent solar and wind energy resources. Historically, and still so today, the most widely applied conversion method for biomass is combustion. The chemical energy of the fuel is converted via combustion into heat which is useful in and of itself, and which may be transformed by heat engines of various types into mechanical and, hence, electrical energy. Direct conversion of biomass to electricity by magnetohydrodynamic energy conversion has been investigated, but the technology is still speculative at this time. Burning of wood and agricultural materials in open fires and simple stoves for cooking and space heating is common around the world and a vital source of heat, although less desirable than advanced conversion techniques from the perspective of atmospheric pollution and undue health impacts from incomplete combustion. Electricity generation using biomass fuels expanded rapidly in the USA following legislation changing utility regulatory policy in 1978, but stalled for economic and environmental reasons after the mid 1990s. US generating capacity at present is

Combustion Systems

15

approximately 10 GWe of electricity, with global capacity about five times that amount [5]. Combustion plays a major role in waste disposal, complementing other waste management practices. Incentives for future expansion exist in the form of renewable portfolio standards, such as that enacted in California in 2002 calling for 20% renewable electricity by 2010 and 33% by 2020 [6]. Integration of power and heat generation in biorefinery operations will also lead to capacity expansions for biomass combustion and related systems. Meeting environmental and economic performance requirements into the future will prove challenging, however, and there continues to be the need for targeted research in advanced system design. This chapter outlines technologies and performance issues in biomass combustion, summarizing system designs, feedstock properties, and environmental impacts. Combustion fundamentals are also briefly reviewed, including combustion stoichiometry, equilibrium, and kinetics. As highlighted by the simple burning of logwood, combustion is a complex process involving multiple simultaneous phenomena. More detailed predictive capability facilitating analysis, design, operation, control, and regulation remains a goal for further research and development.

2.2 2.2.1

Combustion Systems Fuels

Combustor design and selection are dictated both by fuel type and end use. Within the class of biomass fuels are solids, gases, and liquids, the latter two being derived by physical, chemical, or biological conversion of the parent feedstock. Comparative properties of selected fuel types are listed in Table 2.1. 2.2.1.1 Solids Solids constitute the primary class of biomass fuels, including woody and herbaceous materials such as wood and bark, lumber mill residues, grasses, cereal straws and stovers, other agricultural and forest residues, and energy crops such as switchgrass, Miscanthus, poplar, willow, and numerous others. Manures and other animal products include a fraction of solids that are also used as fuels. Municipal solid waste (MSW) is used in waste-to-energy (WTE) systems to provide volume reduction along with useful heat and electricity. Depending on location and local policies, WTE units may employ mass burning of unseparated wastes or combustion of separated wastes in which recyclables and other constituents have first been sorted from the waste stream. Properties of biomass feedstocks are reviewed in Section 2.3.1. Other solids derived from biomass include torrefied materials and charcoal. Torrefaction is a light pyrolysis of the feedstock and results in a partially carbonized fuel with a lower moisture and volatile content than the original feedstock. Charcoal production is an ancient technology in which a large fraction of the volatile matter in biomass is first driven off by heating and pyrolysis. Charcoal yields from traditional processes are often below 10% of the biomass dry matter, with industrial charcoal making in the range up to about 30%, although more modern techniques can increase this substantially [7]. Charcoal is widely used throughout the world as a “smokeless” cooking and heating fuel, although pollutant

LHV: lower heating value.

110 16 16 32 46 74 2 2 200 292

Gasoline (l) Methane (g) LNG (l) Methanol (l) Ethanol (l) Butanol (l) Hydrogen (g) Hydrogen (l) Diesel no. 2 (l) Biodiesel (soyB100) (l)

a

Approx. molar mass

Fuel

0.750 0.000 65 0.424 0.792 0.785 0.810 0.000 08 0.070 0.850 0.880

Mass density (kg L
1)

Table 2.1 Properties of selected fuels

44.0 50.0 49.5 20.0 26.9 33.0 120.0 120.0 42.8 38.3

Mass energy density (MJ kg
1) 33.0 0.033 21.0 15.8 21.1 26.7 0.010 8.4 36.4 33.7

Volume energy density (MJ L
1) 14.6 17.2 17 6.5 9.0 11.2 34.3 34.3 14.4 13.8

Stoichiometric air/fuel ratio (kg kg
1)

2.8 2.7 2.7 2.7 2.7 2.7 3.4 3.4 2.8 2.6

LHVa of stoichiometric mixture (MJ kg
1)

87–94 120 120 99 98 104 H130 H130

Octane no.

40–55 48–60

Cetane no.

16 Biomass Combustion

Combustion Systems

17

emissions are still high in most applications using open fires and simple stoves. Traditional charcoal making as practiced in many countries is a heavily polluting process due to uncontrolled venting of volatiles to the atmosphere. In some applications, charcoal has advantages over crude biomass in terms of handling, storage, gasification, and combustion, but unless the manufacturing process includes energy recovery, a large fraction of the energy in biomass goes unutilized. 2.2.1.2 Gases Gaseous fuels can be produced from biomass by anaerobic digestion, pyrolysis, gasification, and various fuel synthesis pathways using intermediates from these processes. The biological conversion of biomass through anaerobic digestion generates a biogas consisting primarily of methane (CH4) and carbon dioxide (CO2) with much smaller amounts of hydrogen sulfide (H2S), ammonia, and other products. The CH4 concentration typically ranges from 40 to 70% by volume, depending on the types of feedstock and reactor. Anaerobic digesters are employed for conversion of animal manures, MSWs, food wastes, and many other feedstocks, and have long been used in waste-water treatment operations. Incentives such as feed-in tariffs for renewable power have stimulated wider use of digesters for grain, energy crop, and other agricultural biomass in addition to wastes, especially in Europe. The anaerobic conditions in landfills also result in the production of a similar biogas. Biogas or landfill gas can be burned directly or treated to remove contaminants such as H2S to improve fuel value for reciprocating engines, microturbines, fuel cells, boilers, and other devices. Sulfur removal is important to avoid catalyst deactivation where stringent nitrogen oxides (NOx) emission limits must be met and post-combustion catalysts employed, a common problem for reciprocating engines used for power generation. Scrubbing of the biogas to remove CO2 and contaminants generates biomethane (or renewable natural gas), which in some cases is suitable for injection into utility natural gas pipelines. Pyrolysis and gasification produce fuel gases, although pyrolysis is more generally optimized for solids or liquids production. Gasifiers generate fuel gases of variable composition depending on the type of feedstock and oxidant used and the reactor design. Air-blown units make a producer gas consisting of carbon monoxide (CO), H2, CO2, H2O along with hydrocarbons (HCs) and a large fraction of N2. Oxygen-blown units incur the cost of oxygen separation but eliminate nitrogen dilution in the gas to produce a synthesis quality gas, or syngas, useful for burning as well as chemical synthesis or electrochemical conversion via fuel cells after reforming to hydrogen (some fuel cells are internally reforming). Steam gasifiers also produce low nitrogen syngas, and several dual reactor designs have been developed to provide heat demand and energy for steam raising through residual char combustion. Syngas can be used to make substitute natural gas (SNG), another type of biomethane, and reformed to produce hydrogen. Details on gasification processes are described elsewhere. 2.2.1.3 Liquids Liquid fuels from biomass include bio-oils produced by thermochemical processes, particularly pyrolysis; HCs, alcohols, and other fuels produced by chemical synthesis (e.g. Fischer–Tropsch) using syngas from gasification; ethanol, butanol, and other alcohols produced by fermentation of sugars derived from biomass; and lipids extracted from oil

18

Biomass Combustion

seeds, algae, and other oil-containing species. The latter can be refined to produce biodiesels through transesterification or enzyme-mediated reactions, or through hydrotreating to make HCs similar to petroleum-based fuels with higher heating value than the oxygenated biodiesels. Black liquor from chemical pulping is commonly burned in recovery boilers for chemical recycling and supply of heat and power to paper mills. 2.2.2

Types of Combustor

Biomass combustion involves a range of technologies from primitive open fires and traditional cooking stoves to highly controlled furnaces used for power generation and combined heat and power (CHP) applications. These span a wide range of scales, from kilowatt-size stoves to multi-megawatt furnaces and boilers. Current estimates of the energy in biomass used annually for traditional and modern combustion applications are 33.5 EJ and 16.6 EJ respectively [8]. The largest use of biomass by combustion is still in traditional cooking, heating, and lighting applications, mostly in developing nations. Pollutant emissions from these systems are a major health concern [2, 9] and contribute to greenhouse gas emissions. More modern uses for power generation and CHP are roughly equally deployed around the world among developed and developing nations. Cofiring of biomass with coal and other fuels is also expanding the industrial use of biomass for power and heat. 2.2.2.1 Small-scale Systems Considerable effort is focused on the development of clean and efficient wood burning and other biomass combustion appliances for heating and cooking, both to reduce fuel demand and emissions. Developments in stove design for these types of application are the subject of active discussion and debate around the world [10]. More sophisticated stoves have been developed for residential and small commercial and industrial heating applications. These often involve automatic control and the use of preprocessed fuels, such as pellets, to maintain good control over the combustion and reduce emissions. Despite many improvements in combustor design, biomass remains one of the most difficult heating fuels to burn cleanly [11]. Small biomass systems typically emit considerable amounts of CO, particulate matter (PM), polycyclic aromatic hydrocarbons (PAHs), and other products of incomplete combustion. These emissions are exacerbated by heat control schemes that limit air supply to reduce the rate of heat output and the frequency of manually stoking new fuel to the stove. The ability to automatically fire more uniform fuels such as pellets provides substantially greater control over heat output rates while maintaining adequate air supply with reduced emissions compared with stick- or log-wood-fueled furnaces. The inclusion of a catalytic combustor in some designs improves emissions performance by continuing to react combustion products to lower temperatures (around 260 C) than would occur otherwise outside the primary firebox. Reductions in emissions have accompanied improvements in stove design, test standards, flue gas cleaning systems, system installation, and better education of users on stove operations [9]. Average emissions of CO, for example, have been reduced by half over the last decade. PM emissions from advanced pellet stoves now range from 15 to 25 mg MJ
1 compared with log-wood boilers and stoves that commonly exceed 300 mg MJ
1. Electrostatic precipitators and cloth baghouses are now being deployed for emission control on small systems in addition to their more conventional use on large-scale biomass combustors. The International Energy Agency (IEA) coordinates research and

Combustion Systems

19

Stack Exhaust

Emission Control

Fly ash Superheated Steam Steam Turbine Boiler

Generator Electricity

Fuel Water

Air

Bottom Ash

Condensor Boiler Feedwater Pump Cooling Medium

Figure 2.1 Schematic Rankine cycle

outreach on these and other combustion technologies through its Task 32, Biomass combustion and cofiring [9, 11, 12]. 2.2.2.2 Large-scale Systems for Power and Heat Generation Total installed capacity in biomass power generation around the world is approaching 50 000 MWe including large-scale solid fuel combustion as well as smaller scale digester and landfill gas applications [12]. In many regions of the world, Asia being an exception, biomass utilization is below the sustainable resource capacity and potential exists to increase uses for fuels, heat, and power [13]. The most common type of biomass-fueled power plant today utilizes the conventional Rankine or steam cycle (Figure 2.1). The fuel is burned in a boiler, which consists of a combustor with one or more heat exchangers used to make steam. Typical mediumefficiency units designed for biomass fuels utilize steam temperatures and pressures of up to 540 C and 6–10 MPa, although installed systems include pressures up to 17 MPa [14]. The steam is expanded through one or more turbines (or multistage turbines) that drive an electrical generator. In smaller systems, reciprocating and screw-type steam engines are sometimes used in place of the steam turbine. The steam from the turbine exhaust is condensed and the water recirculated to the boiler through feedwater pumps. Combustion products exit the combustor, are cleaned, and vented to the atmosphere. Typical cleaning devices include wet or dry scrubbers for control of sulfur and chlorine compounds, especially with WTE units burning MSW, cyclones (or other inertial separation devices), baghouses (high-temperature cloth filters), and/or electrostatic precipitators for PM

20

Biomass Combustion

Figure 2.2 Ash fouling on superheaters in biomass-fueled boilers. Left: flame impingement on a superheater pendant and incipient ash deposition during cofiring of energy cane biomass and coal. Center: ash deposits on a superheater in a wood-fired power boiler. Right: characteristic deposits along the leading edges of superheaters in a power boiler fueled with agricultural residues (wood, shells, and pits)

removal. Selective catalytic reduction (SCR) or selective non-catalytic reduction (SNCR) of NOx may also be included. Low CO and HC emissions are generally maintained by proper control of air/fuel ratio in the furnace and boiler. Organic fluids can also be used with the Rankine cycle instead of water, in which case the system is referred to as an organic Rankine cycle (ORC). These are typically applied to lower temperature operations such as waste heat recovery or solar thermal systems. Fireside fouling of steam superheaters and other heat exchange equipment in boilers by ash is a particular concern with biomass fuels (Figure 2.2), and larger boiler designs frequently incorporate soot-blowing capacity for intermittent cleaning. Severe fouling may require an outage (shutdown) of the plant to remove deposits more aggressively. Such outages reduce operating time and thus increase the cost of delivered energy. Corrosion is also an issue with many biomass types, especially those containing higher concentrations of chlorine. Feedstock pretreatment to remove chlorine prior to firing has distinct advantages in reducing corrosion and fouling, but also increases cost. Individual Rankine cycle power plants principally using biomass fuels typically range up to about 50 MWe electrical generating capacity, which is reasonably small in comparison with coal-fired power plants more typically in the 500 MWe region. Larger sizes are possible, and size selection is accomplished through an analysis of fuel resource availability, plant design and economy, electricity and heat markets, and local regulations. The distributed nature of biomass fuels and the limited economy of scale associated with plants of this type have kept the size of individual facilities relatively small in comparison with coal or nuclear generating stations. A 350 MWe biomass power plant has been proposed for Wales burning wood from North America [15], and optimization studies have suggested larger sizes are feasible than most currently built [16, 17]. The efficiencies of biomass power plants are generally lower than comparable fossil-fueled units because of higher fuel moisture content, lower steam temperatures and pressures to control fouling at higher combustion gas temperatures, and to some extent the smaller sizes, with a proportionately

Combustion Systems

21

higher parasitic power demand needed to run the pumps, fans, and other components of the power station. Biomass integrated gasification combined cycles (BIGCCs) are projected to exceed 35% electrical efficiency. Cofiring biomass in higher capacity, higher efficiency fossil (e.g. coal) stations can also lead to higher efficiency in biomass-fueled power generation [12]. CHP applications realize much higher efficiencies (80% or better) due to the use of much of the heat that is otherwise rejected in power-only applications. Power boilers utilize three principal types of combustor: grate burners, suspension burners, and fluidized beds [18]. The differences in these units relate primarily to the relative velocities of fuel particles and gas and the presence of an intervening heat transfer medium as in the fluidized bed. They also differ in their abilities to handle fouling-type fuels, their levels of emissions, and a number of other operating considerations. 2.2.2.3 Cofiring Cofiring is the simultaneous burning of two or more fuels in the same combustor [5]. Cofiring is an attractive option for reducing greenhouse gas emissions associated with the combustion of coal and for utilizing biomass at higher efficiencies than in most biomassdedicated power plants. Cofiring has advanced rapidly in a number of countries, with more than 230 operations around the world at present [9]. Roughly half of these are in pulverized coal facilities, with the rest principally in bubbling and circulating fluidized beds along with a few grate-fired units. Typical biomass cofiring rates without derating the plant are 5–10% of total fuel input energy. Even at these fractions, cofiring in a large coal plant requires a substantial biomass supply, similar to a 25–50 MWe biomass plant or larger. Moderate investments are needed for storage and handling equipment until the fraction of biomass begins to exceed about 10%. Beyond this, or if the biomass is fired separately into the furnace, changes are needed to mills, burners, dryers, and other equipment which increase cost. New pulverized coal units now cofire up to about 40% biomass [9]. Biomass can be added in a cofiring application by pre-mixing with the coal prior to injection into the furnace, by direct injection with the coal, or by burning separately in the same furnace [19]. A special case is that of firing biomass in the upper levels of the furnace as a reburning fuel to help control NOx emissions. Reburning is a multistage (normally two) fuel-injection technique which uses fuel as a reducing agent to react with and remove NOx [20]. Metal oxide promoters (Na-, K-, Ca-containing additives) can be injected with or downstream of the reburning fuel to enhance the NOx reduction, although modeling studies have shown that neither of these locations is as effective as co-injection with the main fuel [21]. Gasification of biomass and cofiring of producer gas have also been tested for reburning purposes [22]. Various technical concerns associated with biomass cofiring in coal facilities include fuel preparation, storage, handling, and supply, ash deposition, fuel conversion, pollutant formation, corrosion, ash utilization, impacts on SCR systems for emission control, and formation of striated flows in the boiler, and research is directed toward understanding and mitigating adverse impacts [23]. Addition of biomass ash may also influence the value of coal fly ash used for construction and other materials, such as concrete additives [12], although there appear to have been few quality concerns with cofired wood fuels [11]. Higher concentrations of alkali metals and chlorine in straw and other herbaceous fuels may be of more concern, but most impacts

22

Biomass Combustion

appear to be manageable [23]. Restrictions on comingled ash in various standards for concrete admixtures pose significant penalties on cofiring operations, and research is continuing on this issue [24]. New standards have been developed that include testing procedures to ensure quality of comingled ash is not reduced compared with coal ash for these applications. 2.2.2.4 Alternative Combustion and Power Generation Concepts Steam Rankine cycles are the dominant power generation concept employed at present for solid biomass fuels. Alternatives to the conventional steam cycle include various enhancements, including supercritical Rankine cycles which operate at higher temperatures and pressures (above the critical point of water at 22.1 MPa, 647 K), and are more commonly used with coal and other fossil fuels and for biomass cofiring. Ash fouling and superheater corrosion are a primary concern with higher temperature systems, so most biomassdedicated plants remain subcritical. ORCs operate on the same cycle as steam power stations, but they replace water with another working fluid such as ammonia or an HC like propane or butane. Operating temperatures are generally lower for ORC units that are now being deployed with biomass at scales of around 400 to 1500 kWe with efficiencies of up to 20 % [25]. ORC units can also be deployed to take advantage of waste heat in cogeneration applications to improve overall efficiency. Conversion of biomass by gasification to make producer gas is another alternative for power generation using conventional spark-ignited or dual-fuel compression-ignited reciprocating engines. The technology has a long history of use and development, and typically suffers from inadequate gas purification for small distributed and transportationrelated applications. New designs are emerging, however, that offer improved performance and longer service. Other cycles used with solid biomass fuels include Brayton (gas turbine) and Stirling engines. Attempts have also been made to direct-fire powdered biomass into Diesel engines [26], but success is limited due to scoring of the cylinder walls and other problems in handling solids and ash. Of these, the most advanced for use with solid fuels is the Stirling engine, although this class of engines remains mostly developmental in this application. Direct-fired gas-turbine engines have received considerable attention, but cleaning the combustion products sufficiently to run through the turbine blading has proved difficult [27]. Indirect-fired (hot air) turbines have also been investigated, but in these engines hightemperature heat exchange becomes a limiting issue. Compression-ignited (Diesel), sparkignited (Otto), and Brayton engines, especially microturbines, are currently used with biogas and landfill gas, biomethane, biodiesel, and alcohols, and should also be compatible with HCs, mixed alcohols, SNG, and other clean fuels made from syngas by Fischer– Tropsch synthesis and other techniques. Pyrolysis oils (bio-oils) and vegetable oils can also be used after hydrotreating or other refining to improve viscosity and stability, remove oxygen, and reduce corrosivity. BIGCCs, in which biomass is gasified to generate a fuel gas (producer gas or syngas) that can be used in a combined gas-turbine–steam cycle (combined cycle), similar to the use of coal in an integrated gasification combined cycle, have been under active investigation for improving power plant efficiency and potentially repowering existing steam plants [28, 29]. The V€arnamo BIGCC plant demonstrated in Sweden was designed for a net electrical efficiency of 32% (lower heating value) while simultaneously

Fundamentals of Biomass Combustion

23

generating 6 MWe of electricity and 9 MWt of heat for district heating. Overall efficiency was rated at 83% in cogeneration mode [28]. Other advanced power generation options include fuel cells, in which the oxidation is carried out electrochemically rather than thermally or thermocatalytically. Five major types of fuel cell have been developed, with all practical fuel cells at present using hydrogen as the energy carrier. Alkaline, acid, and the solid polymer (or polymer electrolyte membrane)-type fuel cells require any HC, syngas, or biomass feed to first be reformed to hydrogen. Molten carbonate and solid oxide fuel cells are higher temperature types and internally reforming, so that a reforming stage upstream of the fuel cell may not be needed when using biomethane, biogas, or syngas from biomass as long as purity is high. The solid oxide fuel cell operates at temperatures in the range of 600 to 1000 C and could be used to replace the gas turbine in a combined cycle operation. In such cases, the peak net electrical efficiency might be improved from about 50% to close to 70% at low loads, including parasitic demands of the cell operation, and from 30% to about 55% at high loads [30]. Significant research remains for biomass integrated fuel cell applications and many other advanced options.

2.3

Fundamentals of Biomass Combustion

Combustion is a complex phenomenon involving simultaneous coupled heat and mass transfer with chemical reaction and fluid flow. For the purposes of design and control, thorough knowledge is required of fuel properties and the manner in which these properties influence the outcome of the combustion process. Combustion conditions must also be specified, including type of oxidant (air, oxygen, oxygen-enrichment), oxidant-to-fuel ratio (stoichiometry), type of combustor (e.g., pile, grate, suspension, fluidized bed), emission limits, and many other factors. Fully detailed models of the combustion process include pyrolysis and gasification of solid feedstock along with homogeneous and heterogeneous oxidation involving a substantial number of reactions and reaction intermediates. Comprehensive models have been developed for combustion of fuels such as hydrogen and CH4, but have not so far been completed for more complex fuels such as biomass. Fortunately, simpler approaches involving more global reaction processes can be used to account for specific feedstock properties and combustion conditions. 2.3.1

Combustion Properties of Biomass

Combustion of biomass is heavily influenced by the properties of the feedstock and the reaction conditions (e.g., air/fuel ratio). The amount of heat released during combustion depends on the energy content of the fuel along with the conversion efficiency of the reaction. The organic matter assembled by photosynthesis and plant respiration contains the majority of the energy in biomass, but the inorganic fraction also has importance for the design and operation of the combustion system, particularly in regards to ash fouling, slagging, and in the case of fluidized bed combustors, agglomeration of the bed medium. 2.3.1.1 Composition of Biomass Photosynthesis and plant respiration result in the production of a diverse and chemically complex array of structural and nonstructural carbohydrates and other compounds,

24

Biomass Combustion

including cellulose, hemicelluloses, lignin, lipids, proteins, simple sugars, starches, HCs, and ash, which along with water comprise the majority of the biomass. The concentration of each class of compound varies depending on species, type of plant tissue, stage of growth, and growing conditions. Cellulose is a linear polysaccharide of b-D-glucopyranose units linked with (1–4) glycosidic bonds. Hemicelluloses are polysaccharides of variable composition including both five- and six-carbon monosaccharide units. The lignin is an irregular polymer of phenylpropane units [31–35]. Plants producing large amounts of free sugars, such as sugar cane and sweet sorghum, are attractive as feedstock for fermentation, as are starch crops such as maize (corn) and other grains. Lignins are not yet generally considered fermentable, although research is active in this regard, and thermochemical means such as combustion are frequently proposed for their conversion. Combustion can be applied either to the direct conversion of the whole biomass or to portions remaining following biochemical separation, such as by fermentation. Combustion, unlike the biochemical and some other thermochemical conversion strategies, is essentially nonselective in its use of the biomass and reduces the whole fuel to products of CO2 and water along with generally smaller amounts of other species, depending on feedstock composition and process efficiency. However, the complex structure of biomass still has a significant influence on its combustion behavior. Owing to its carbohydrate structure, biomass is highly oxygenated in comparison with conventional fossil fuels. Typically, 30–40 wt% of the dry matter in biomass is oxygen (Table 2.2). The principal constituent of biomass is carbon, making up from 30 to 60 wt% of dry matter depending on ash content, and most woods are about half carbon when dry. Of the organic component, hydrogen is the third major constituent, comprising typically 5–6% dry matter. Nitrogen, sulfur, and chlorine can also be found in quantity, usually in concentrations less than 1% dry matter, but occasionally well above this. These are important in the formation of criteria and hazardous air pollutant emissions and in other design and operating considerations, including materials selection. Nitrogen is a macronutrient for plants, and critical to growth, but is also involved in NOx and nitrous oxide (N2O) formation during combustion. Sulfur and chlorine contribute to fouling, slagging, corrosion, and emissions of important air pollutants. Inorganic elements can also be found in high concentrations. In annual growth tissues, concentrations of the macronutrient potassium frequently exceed 1% dry matter. Like sodium, another alkali metal, potassium is involved in slag formation and ash fouling in combustion systems. Sodium is toxic to most plants other than the halophytes, and so in many cases is found in lower concentrations than potassium. In at least trace amounts, virtually every element can be found in biomass and many have important consequences for the design, operation, and environmental performance of combustion facilities [37, 38]. Elemental properties of biomass have been determined for a wide range of fuel types [11, 39–44]. Databases of biomass properties are also maintained online (e.g., http://www.ecn.nl/phyllis/). These properties include moisture content, heating value, elemental composition, bulk density, specific gravity, thermal conductivity, and mechanical, acoustic, and electrical properties. Biomass is similar to other fuel types in the need for standardized methods of analysis leading to accurate and consistent evaluations of fuel properties. Standards have been developed for many properties, although this is still an area of active development. ASTM (http://www.astm.org/), ISO (http://www.iso.org/), and other organizations maintain standards for analyzing chemical composition, heating value, density, ash fusibility, and

Fundamentals of Biomass Combustion

25

Table 2.2 Properties of selected biomass feedstocks [36]. Reprinted from Fuel Processing Technology, 54, B.M. Jenkins, L.L Baxter, T.R. Miles Jr and T.R. Miles, Combustion Properties of Biomass, 17–6, Copyright (1998), with permission from Elsevier Hybrid poplar wood

RDFa

Rice straw

Proximate analysis (% dry matter) Fixed carbon Volatile matter Ash Total

12.49 84.81 2.7 100

0.47 73.4 26.13 100

15.86 65.47 18.67 100

11.95 85.61 2.44 100

16.07 82.22 1.71 100

Ultimate analysis (% dry matter) Carbon Hydrogen Oxygen (by difference) Nitrogen Sulfur Chlorine Ash Total

50.18 6.06 40.43 0.6 0.02 0.01 2.7 100

39.7 5.78 27.24 0.8 0.35 26.13 100

38.24 5.2 36.26 0.87 0.18 0.58 18.67 100

48.64 5.87 42.82 0.16 0.04 0.03 2.44 100

49.9 5.9 41.8 0.61 0.07 G0.01 1.71 100

Elemental composition (% ash) SiO2 Al2O3 TiO2 Fe2O3 CaO MgO Na2O K2O SO3 P2O5 CO2 Total Undetermined Higher heating value (MJ kg
1) Alkali index (kg GJ
1) Stoichiometric air:fuel (kg kg
1) Enthalpy of formation (kJ kg
1) Adiabatic flame temperatureb (K)

5.9 0.84 0.3 1.4 49.92 18.4 0.13 9.64 2.04 1.34 8.18 100 1.91 19.02 0.14 6.10
5995 2211

33.81 12.71 1.66 5.47 23.44 5.64 1.19 0.2 2.63 0.67

74.67 1.04 0.09 0.85 3.01 1.75 0.96 12.3 1.24 1.41

46.61 17.69 2.63 14.14 4.47 3.33 0.79 0.15 2.08 2.72

100 100 12.58 2.68 15.54 15.09 0.23 1.64 5.38 4.61
5662
4796 2016 2192

100 1.39 18.99 0.06 5.75
5266 2301

2.35 1.41 0.05 0.73 41.2 2.47 0.94 15 1.83 7.4 18.24 100 8.38 19.59 0.14 5.96
5113 2313

Property

a b

Sugar cane bagasse

Willow wood

Refuse-derived fuel. Linearized estimate.

other properties, many of which are summarized in a number of more detailed references [11, 36]. Standards for similar types of analysis, but developed for coal and other fuels, should be used only when biomass-specific standards are not available, and then with caution, recognizing that differences in the chemistry of the feedstock may lead to difficulties in analysis. The molar ratios of oxygen and hydrogen to carbon for a wide range of biomass feedstock do not vary substantially. Glucose (C6H12O6), a primary product of photosynthesis, has these three main elements in the molar ratios C:H2:O. Cellulose (C6H10O5)n, a polymer built

26

Biomass Combustion

from glucose, yields CH1.67O0.83 with H:O still in the ratio of 2. Averaging across many types of biomass yields more generally CH1.41O0.64 for the CHO fraction, indicating the presence of lignin and other less-oxygenated species [40]. This is also seen in properties such as the theoretical air/fuel ratio for complete combustion, equal to 6.0 kg of dry air per kilogram of dry organic (CHO) matter for the generalized biomass, 5.1 kg kg
1 for cellulose, and 4.6 kg kg
1 for glucose. By comparison, the theoretical air/fuel ratio for carbon is 11.4 kg kg
1. Increasing carbonization occurs in the transformation of biomass to coals of increasing rank [45]. Black liquor produced during pulping also exhibits increased lignification in the reduction of the O:C ratio while retaining a roughly equal H:C ratio to the parent biomass. Inorganic material in biomass can be divided into two fractions, one of which is inherent in the feedstock and the other is added to the fuel through collection and processing. The latter, adventitious material, such as soil accumulated during harvesting, often makes up a major fraction of the ash content of wood fuels used in power plants and originates from skidding and other operations used to move trees and slash (branches and tops) from the forest. Its composition is typically different from that of the inherent materials, as is the mode of occurrence of the elements (e.g., crystalline silicates and aluminum arising from the incorporation of sands, clays, and other soil particles and potassium incorporated in feldspars with relatively little contribution to alkali reactions leading to fouling other than by inertial impaction and sticking of particles). The inherent inorganic matter is more intimately distributed throughout the fuel, and is sometimes referred to as atomically dispersed material. Elements including Si, K, Na, S, Cl, P, Ca, Mg, Fe are involved in reactions leading to ash fouling and slagging, and the principal mechanisms describing these phenomena in biomass combustors are now reasonably well understood [11, 43–47]. Descriptions of the detailed chemistry and means to control or mitigate these processes other than by fuel selection are the subjects of much research [38, 48–54]. The impacts on the fouling and slagging behavior of biomass by removing certain elements, such as potassium and chlorine, confirm much of what is perceived about the mechanisms involved [55–59]. Herbaceous fuels, such as grasses and straws, contain silicon and potassium as their principal ash-forming constituents. They are also commonly high in chlorine relative to other biomass fuels. These properties portend potentially severe ash deposition problems at high or moderate combustion temperatures. The primary sources of these problems arise from the reaction of alkali with silica to form alkali silicates that melt or soften at low temperatures, and the reaction of alkali with sulfur to form alkali sulfates on combustor heat transfer surfaces. Sugar cane bagasse is substantially depleted in potassium relative to the parent material due to the washing of the cane that occurs during sugar extraction. Similar results have been obtained for solid–liquid extraction of biomass [56]. The composition of rice straw ash, for example, is remarkably similar in respect to alkali metal and silica concentrations in an ordinary soda-lime glass except that potassium is the major element rather than the sodium predominantly used for glass making [36]. A substantial fraction (H80% typically) of potassium can be extracted from straw and other biomass by simple water leaching, yielding an inorganic fraction enriched in silica with a much higher melting temperature. Chemical fractionation of the feedstock using different solvents to detect the form of the ash constituents indicates the mobility of inorganic elements during combustion [36, 44].

Fundamentals of Biomass Combustion

27

2.3.1.2 Moisture Content Moisture content is highly variable in biomass and has a large influence on the combustion chemistry and energy balance. Moisture concentration is defined in two principal ways: dry basis and wet basis. The dry basis moisture Mdb expresses the mass of water in the feedstock per unit mass of dry matter. The wet basis Mwb relates the water to the total wet weight, dry matter plus water. Mdb ¼

mw mf;d

Mwb ¼

mw mf;d þ mw

Mwb ¼

Mdb 1 þ Mdb

Mdb ¼

Mwb 1
Mwb

ð2:1Þ

The oven-dry (also known as bone-dry) state achieved after heating in an air-oven at temperatures below about 104 C is generally defined to be the zero moisture datum, although bound moisture may still be present and other light volatiles such as alcohols may be lost during drying. The dry basis moisture has no upper bound; the wet basis is bounded by 100%. Feedstock will vary in moisture when in contact with air of variable humidity. Equilibrium moisture in biomass ranges typically above 25% wet basis as the relative humidity exceeds 90–95%. 2.3.1.3 Heating Value The energy content or heating value of biomass is defined as the heat released by combustion under specific conditions. For measurement purposes, the reaction is carried out either at constant pressure or constant volume, the latter being the more commonly reported for solid biomass feedstock when analyzed using a bomb calorimeter. For feedstocks that contain hydrogen, the water formed by oxidation (refer to Section 2.3.2) may be either in vapor or liquid phase when the reaction completes. If in the vapor phase, the amount of heat released as measured by the calorimeter will be less by the heat of vaporization than if the water is condensed. The higher heating value (also referred to as the gross calorific value), either at constant pressure or constant volume, is measured with product water condensed. The lower heating value (or net calorific value) measures the heat release with water in the vapor phase. Reporting the basis of the measurement is important for the purposes of comparing analyses and system performance. For example, boiler or power plant efficiency is by convention commonly reported using the lower heating value of the fuel in some countries, while in others the higher heating value is used. For the same facility, the efficiency will be greater when reported on the basis of the lower heating value of the fuel. The as-fired higher heating value of a moist fuel is directly related to the dry basis higher heating value and the moisture content as Qh ¼ Qh;0 ð1
Mwb Þ

ð2:2Þ

The as-fired lower heating value can be determined from the higher heating value, hydrogen concentration H (kg kg
1) in the dry feedstock, and the moisture content: 
 WH2 O H ð2:3Þ Qv;l ¼ ð1
Mwb Þ Qv;h;0
ufg Mdb þ 2WH The internal energy of vaporization ufg (kJ kg
1), in Equation (2.3) is used for the case of constant-volume combustion (no flow work). If the reaction is instead carried out at constant

28

Biomass Combustion 100 90 80 Residual Energy (%)

70 60 50 40 30 20 10 0 -10 0

10

20

30

40

50

60

70

80

90

100

-20 -30 -40 Moisture Content (% wb)

Figure 2.3 Sensible energy available from combustion after evaporating moisture in feedstock (Qv,h,0 ¼ 20 MJ kg
1, ufg ¼ 2.3 MJ kg
1)

pressure, ufg is replaced by hfg (kJ kg
1), the enthalpy of vaporization. The Wi are the molar masses (molecular weights, kg kmol
1) of water and hydrogen. The maximum temperature achieved by combustion is dependent in part on the amount of sensible heat (that capable of raising temperature in a system) available for heating reaction products and vaporizing feedstock moisture. The greater the moisture content of the feedstock, the greater the fraction of heat needed to evaporate water (Figure 2.3):   ufg Mwb Qresidual ð%Þ ¼ 100 1
ð2:4Þ ð1
Mwb ÞQv;h;0 Beyond about 90% moisture for most biomass, the energy needed to vaporize water exceeds the heating value of the feedstock. The autothermal limit below which the fire is self-sustaining is typically in the vicinity of 70–80% [60], and flame stability becomes poor in most combustion systems above 50–55% moisture wet basis. Natural gas and other fuels are often cofired for flame stabilization when fuel moisture is high. The heating value can be partially correlated with ash concentration. Woods with less than 1% ash typically have heating values near 20 MJ kg
1. Each 1% increase in ash translates roughly into a decrease of 0.2 MJ kg
1 [39] because the ash does not contribute substantially to the overall heat released by combustion, although elements in ash may be catalytic to the thermal decomposition. Heating values can also be correlated to carbon concentration, with each 1% increase in carbon elevating the heating value by approximately 0.39 MJ kg
1 [39], a result that is identical to that found by Shafizadeh [61] for woods and wood pyrolysis products. The heating value relates to the amount of oxygen required for complete combustion, with 14 022 J released for each gram of oxygen consumed [61].

Fundamentals of Biomass Combustion

29

Cellulose has a smaller heating value (17.3 MJ kg
1) than lignin (26.7 MJ kg
1) because of its higher degree of oxidation. Various efforts have also been made to correlate heating value with the ultimate elemental composition of biomass, similar to correlations developed for coal. One correlation is that of Gaur and Reed [62] for Qv,h,0 (MJ kg
1): Qv;h;0 ðMJ kg
1 Þ ¼ 0:3491  C þ 1:1783  H þ 0:1005  S
0:1034  O
0:0151  N
0:0211  Ash

ð2:5Þ

where C, H, S, O, N, and Ash are the weight percent (dry basis) of carbon, hydrogen, sulfur, oxygen, nitrogen, and ash in the feedstock. For the generalized biomass (CH1.41O0.64) noted above, the correlation of Equation (2.5) yields a heating value equal to 20.31 MJ kg
1. As with other models of this type, the agreement with analytical data is variable and often poor, overestimating by up to about 2 MJ kg
1 in some cases. Estimations should not be used in place of measurements for critical design considerations.

2.3.1.4 Density, Particle Size, and Other Properties Biomass density and particle size influence feedstock handling and combustion rates and efficiencies. Density is affected by moisture content due both to the change in feedstock mass and the volume change (e.g. swelling) accompanying changes in moisture content. Densification, such as briquetting or pelleting, increases the bulk density, but may also alter the apparent density of particles (excluding interstitial volumes between particles). True density (excluding pore volumes in particles) for cellulose from wood has been reported as 1580 kg m
3, with lignin in the range 1380–1410 kg m
3 [63]. Bulk densities are highly variable and range from about 20 to 80 kg m
3 for loose or loose chopped materials to above 700 kg m
3 for pelleted materials. The latter can in some cases exceed the density of water. Particle size, size distribution, and particle morphology are also highly variable, depending on the type of processing used to prepare biomass for firing, if any. These influence aerodynamic properties, surface area, and conversion rates along with a number of other factors. In general, the process energy needed to reduce the particle size increases as mean particle size decreases. Many other chemical, electrical, mechanical, and thermal properties of the feedstock influence the handling, processing, and combustion of biomass [11, 39, 40]. Detailed design should rely on specific analyses of intended feedstocks rather than more general literature data, although the latter are useful for preliminary assessments.

2.3.2

Combustion Stoichiometry

2.3.2.1 Simplified Global Reaction A simplified global combustion reaction for biomass is represented by the mass balance of Equation (2.6), in which the mass coefficients mr,i designate the masses of the reactant species and the mp,j designate the product species. In this case the biomass is divided into two fractions: an organic phase and an ash phase. The feedstock elemental mass fractions described by the coefficients yi arise from the analysis of the dry feedstock for C, H, O, N, S,

30

Biomass Combustion

and Cl. Moisture in biomass is represented by a separate liquid water fraction, even though water may be held differently in the biomass. The oxidation medium (e.g., air) is considered to consist of O2, CO2, H2O, and N2, all in the gas or vapor phase. The reaction is here prescribed to result in 11 main gas-phase products and a residual mass containing ash and unreacted portions of the other element masses from the biomass. The residual can consist of solids such as PM, carbon in ash as charcoal or carbonates, and chlorides and sulfates in furnace deposits. Liquids and gases can also result in practice and be represented in the reaction given appropriate property data. Equation (2.6) is reasonably general, in that it can equally be used to describe the combustion of other fuels such as (bio)methane, biodiesel, Fischer–Tropsch liquids and other HCs, bio-oils from pyrolysis, and many others. ! X mr;1 yi j C;H;O;N;S;Cl;Ash þ mr;2 H2 OðlÞþmr;3 O2 þmr;4 CO2 þmr;5 H2 OðgÞþmr;6 N2 i

¼ mp;1 CH4 þmp;2 COþmp;3 CO2 þmp;4 H2 þmp;5 H2 Oþmp;6 HCl þ mp;7 N2 þmp;8 NOþmp;9 NO2 þmp;10 O2 þmp;11 SO2 þmresidual ð2:6Þ The reactant masses in Equation (2.6) are specified by reaction conditions and properties of the feedstock or fuel. Except in the case of complete oxidation, where a number of the product masses are taken as zero, Equation (2.6) is not determinate for the product masses by elemental mass balances alone, as there are more unknowns than element balances for C, H, O, N, S, and Cl along with the overall mass balance. To determine the product masses, other information must be given or another solution technique employed, such as an equilibrium solution. If the fractions of feedstock elements, fi,j, converted to certain product species, such as fuel N to NO and NO2, sulfur to SO2, and Cl to HCl are known a priori or otherwise assumed, the reaction is then determinate. Nitrogen is problematical in this regard, as for any oxidant containing nitrogen and oxygen, such as air, thermal and prompt oxides of nitrogen (NOx) can also be produced in addition to those from fuel nitrogen. In such a case the conveniently prescribed fraction of fuel N converted to NOx could exceed unity, although the mass balance of Equation (2.6) remains applicable. In addition to the product composition, Equation (2.6) allows for the estimation of other properties of the reaction, such as the flame temperature, although additional information may be needed, such as the heat loss from the reaction if not adiabatic. 2.3.2.2 Air/Fuel Ratio Equation (2.6) also specifies the oxidant-to-fuel ratio, or in the case of air as the source of oxygen, the air/fuel ratio, along with the equivalence ratios often used to specify the combustion conditions. The air/fuel ratio AF defines the mass of air added relative to the mass of feedstock, expressed on either a wet or dry basis. The stoichiometric value AFs defines the special case in which only the amount of air theoretically needed to completely burn the feedstock is added to the reaction. The fuel/air equivalence ratio f, the air/fuel equivalence ratio, or air-factor l, and the excess air e are related as f¼

AFs AF

l¼

1 f

e¼

1
1 f

ð2:7Þ

Fundamentals of Biomass Combustion

31

The combustion regimes are defined by the value of f with f ¼ 1 (e ¼ 0) the stoichiometric combustion, f H 1 the fuel-rich regime (insufficient air), and f G 1 the fuel-lean regime (excess air). For fuel-rich conditions, concentrations increase for products of incomplete combustion, such as HCs, CO, and PM. Other pollutant species not included in Equation (2.6) are also produced in varying amounts under all three combustion regimes. 2.3.2.3 Flame Temperature The reaction temperature associated with Equation (2.6) is found through application of the energy balance. For the constant-pressure reaction, the enthalpy of the products is equal to the sum of the reactant enthalpies and any heat transfer to the system: Hp ¼ Hr þ Ql

ð2:8Þ

or X mp;j j

Wj

hp;j


X mr;i i hr;i
Ql ¼ 0 Wi

ð2:9Þ

where Hp is the total enthalpy of the products, Hr the total enthalpy of the reactants, and Ql the external heat transfer to the reaction, which is negative for heat loss. The enthalpies of formation for all species other than the biomass are known, and the latter can be solved by energy balance on the reaction in oxygen carried out in determining the heating value. The other species’ enthalpies hi and hj are in most cases nonlinear functions of temperature. Reference values of the molar enthalpies (kJ mol
1) have been compiled in the NIST database for 298.15 G T (K) G 6000 (for steam, the lower temperature bound is 500 K [64]). Owing to the nonlinear behavior with temperature of the enthalpies, a solution for the flame temperature generally involves a root-finding or similar technique. As noted by Jenkins and Ebeling [65], the enthalpy functions are nearly linear over a fairly large range of temperature, including the flame temperatures in air for many fuels. Fitting the enthalpies to linear functions allows for a direct approximation of the flame temperature. Based on the data of Linstrom and Mallard [64], functions of the form h ¼ aT
b were fit over the temperature range 500–3000 K, where a and b are regression coefficients and T (K) is the absolute temperature. Coefficients of the functions are listed in Table 2.3, along with the correlation coefficients indicating quality of fit. For higher temperatures, such as achieved in oxy-fuel combustion, dissociation reactions must also be considered. Enthalpies for the solid phases including ash and char, among other products, also appear in Equation (2.9). For ash, the correlation of Kirov [66], as attributed by Hanrot et al. [67], gives the specific heat (J kg
1 K
1) as a function of temperature (0 G T G 1200) for T in Celsius: Cp;ash ¼ 752 þ 0:293T

ð2:10Þ

From the definition of the enthalpy and extrapolating and linearizing over the temperature range 500–3000 K (227 to 2727 C), the ash enthalpy is approximated as above with a ¼ 1.5510 and b ¼ 856, but for h on a mass basis (kJ kg
1). For carbon black as a residual solid, NIST specifies a constant Cp,c ¼ 10.68 J mol
1 K
1 over the temperature range 300 G T (K) G 1800. The enthalpy of product carbon at the flame temperature Tf is

32

Biomass Combustion

Table 2.3 Kelvin

Linearized enthalpies (kJ kmol
1) of selected gases, (500–3000 K), h ¼ aT
b, T in

CH4 CO CO2 H2 H2O HCl N2 NO NO2 O2 SO2

a

b

r2

87.7017 35.3301 58.5288 33.1795 48.3409 34.4741 34.8555 35.8551 55.1040 36.8906 57.0826

123 160 123 988 418 206 12 508 263 954 105 620 13 041
76 847
10 755 13 996 319 166

0.994 542 9 0.999 381 7 0.999 054 1 0.998 743 1 0.996 427 3 0.998 966 9 0.999 217 1 0.999 529 9 0.999 432 4 0.999 346 8 0.999 573 2

calculated from h ¼ Cp,cT
h298.15, where the specific heat is referenced to the temperature 298.15 K and extrapolated for temperatures above 1800 K. Enthalpies of other solid species depend on the form in which they appear in the products, although if the masses are small they may be simply lumped with the ash. Solid products may achieve temperatures considerably different from the flame temperature in actual combustors, so an assumption of a uniform temperature for all products constitutes a special case. Note that the range in specific heat computed for ash from 25 to 1200 C (0.76–1.10 kJ kg
1 K
1) also includes the specific heat for carbon black (0.89 kJ kg
1 K
1). Using the linearized enthalpy equations, h ¼ aT
b, the product enthalpy can be written thus: X X X Hp ¼ mj ðaT
bÞj ¼ aj Tmj
bj m j ð2:11Þ j

j

j

With the reactant inlet temperatures specified (e.g., with air preheat), the flame temperature can be directly estimated: P Hr þ Ql þ j bj mj P ð2:12Þ T¼ j aj mj The use of this equation is illustrated in Figure 2.4 for the case of hybrid poplar wood combustion in air for 0–100% excess air and the same feedstock moisture range (dry basis). Adiabatic flame temperatures are compared for inlet air temperatures of 298 and 500 K. Heat loss equal to 10% of fuel heating value is sufficient to drop the peak flame temperature by approximately 200 K. 2.3.3

Equilibrium

Only in the case of simple reactions or where conversion fractions are already known will element balances be sufficient to determine the reaction products. When more species and phases are present, the element balances alone may not yield a sufficient number of equations to make the system determinate. More detailed kinetic analyses may be required,

Fundamentals of Biomass Combustion 2400

(a)

Temperature (K)

2200 2000 1800 1600 1400 1200 1000 0

(b)

33 (c)

e=0 e=0

e=0

0.2 0.2

0.4 0.6 0.8 1.0

0.4 0.6 0.8 1.0

0.2 0.4 0.6 0.8 Moisture fraction (db)

10

0.2 0.4 0.6 0.8 Moisture fraction (db)

0.2 0.4 0.6 0.8 1.0

10

0.2 0.4 0.6 0.8 Moisture fraction (db)

1

Figure 2.4 Estimated flame temperatures for combustion of hybrid poplar wood in air (e is the fraction of excess air, moisture given on a dry basis). (a) Adiabatic, inlet air temperature is 298 K. (b) Adiabatic, inlet air temperature is 500 K. (c) With heat loss, inlet air temperature is 298 K, heat loss is 10% of fuel higher heating value

or if the reactions proceed rapidly enough, an assumption of equilibrium can be employed to solve the stoichiometry. A number of species are not adequately predicted from equilibrium, however, including important pollutant species such as NOx. The equilibrium composition can be determined from the state at which the Gibbs free energy of the system reaches a minimum at a given temperature T and pressure P. A number of sophisticated computer-based equilibrium solvers are available, and the thermodynamic basis for determining the equilibrium is detailed elsewhere (e.g., [68]). 2.3.4

Rates of Reaction

The rate of combustion is also important to the design of combustion systems. Underdesigned furnaces, boilers, and other combustion units lead to reduced capacity and poor economy of operation. Ash fouling and slagging can also be exacerbated in underdesigned units when forced to meet design capacity. Typical design heat release rates (expressed per unit grate area) for stoker-fired traveling grate combustors are in the range 2–4 MWt m
2. Design for a conceptual whole-tree combustion concept using a deep bed of fuel estimated a heat release rate of 6 MWt m
2, but this was not confirmed [69]. Some circulating fluidized bed furnaces firing biomass have heat release rates approaching 10 MWt m
2 [36]. The rate at which biomass burns depends predominantly on the rate of heat transfer and the kinetic rates of reaction [70]. Particle size and morphology dominate the influence of heat transfer. Combustion occurs both in the gas phase, with the burning of volatile materials released through pyrolysis and gasification of the fuel, and heterogeneously in the solid phase as char oxidation. The burning of volatiles is generally quite rapid and follows as fast as volatiles are released; the oxidation of the char occurs much more slowly. The residence time of the particle in the furnace and the environment of the particle are important, therefore, to the total conversion attained through combustion, as well as the emissions from the combustor.

34

Biomass Combustion

Fundamental to the combustion rate are the rates of fuel pyrolysis and char oxidation. The standard method of measuring these rates is via dynamic thermogravimetric analysis, whereby a small sample of the fuel is heated at a controlled rate in a controlled atmosphere while simultaneously recording weight, time, and temperature. Evolved-gas analysis also monitors the composition of products during reaction and provides additional information. The thermogram has a characteristic shape for biomass heated and burned in air (Figure 2.5). Starting from room temperature with a dry sample, the sample is observed to dry (even if initially oven dried, biomass being hygroscopic) with a small weight loss up to about 150 C. Between about 200 and 400 C there is a rapid loss of weight due to the evolution of volatile material, which in an oxidative environment (e.g., air) at high enough temperature will ignite and burn. A slow loss of weight accompanies the residual char burning after the release of volatiles. Kinetic parameters can be determined from the thermogram, allowing prediction of the overall rate of reaction. Although there is no fundamental basis for the kinetic model used, Arrhenius kinetics are frequently employed [71]. Metals in biomass are known to have an effect on reaction rates and are thought to be catalytic to pyrolysis. Leaching biomass in water results in a distinct effect on the conversion kinetics [55]. The result is consistent with what is known about the effects of alkali-chlorides on the pyrolysis rates of biomass [72]. Under isothermal heating, the emission rate for volatiles has been observed to terminate earlier with the leached material than for the untreated material [73], and leached straw has been observed to ignite more readily than

Figure 2.5 Thermogram produced under a constant heating ramp of 100 K min
1 for 60-mesh particle size rice straw in air [71]. Reprinted with permission from Bining, A.S. and Jenkins, B. M., 1992, Thermochemical Reaction Kinetics for Rice Straw from an Approximate Integral Technique. ASAE Paper 926029, ASAE, St. Joseph, MI.

Pollutant Emissions and Environmental Impacts

35

untreated straw. Chlorine is known to retard flame propagation by terminating free-radical chain reactions. Chlorine is leached from biomass by water in solid–liquid extraction [56], which, therefore, has an effect on ignition and burning in addition to formation of hazardous emissions. Biomass particle morphology varies widely depending on type of feedstock (e.g., straw, wood) and level and type of processing (e.g., knife milling, hammer milling). Biomass particles generally exhibit large aspect ratios and more commonly resemble cylinders or plates than spheres, with corresponding differences in surface area-to-volume ratio that influence the burning rates. Larger sized biomass particles also develop thicker boundary layers, with the result that some or all of the flame may be contained within the thermal and mass transfer boundary layers. The particle, therefore, experiences an increase in surface temperature during most of the oxidation stage, although this constitutes a small fraction of the total reaction time [74]. Isothermal particle models normally employed for predicting combustion of small coal particles do not capture the effects of large temperature gradients that develop in biomass particles, an important feature in modeling biomass cofiring in pulverized coal boilers. More comprehensive models that account for drying, devolatilization, recondensation, char gasification and oxidation, and gas phase combustion have been developed for predicting single particle combustion of variable geometry and properties [75].

2.4

Pollutant Emissions and Environmental Impacts

Environmental impacts are of primary importance for the design of combustion systems at any scale. Modern biomass combustion power plants are often zero discharge for wastewater (treated or evaporated on site) or reduce waste-water discharges to levels that are accommodated within the local municipal sewer system. Water supply and water quality are, however, critical issues for plant siting and operations, and most boiler facilities include a water treatment plant to produce high-purity water for the boiler. The largest fraction of solid waste is typically the bottom and fly ashes from the furnace and emission control equipment. With the exception of metals-contaminated feedstock, such as some urban and industrial wastes, ash often has value in secondary markets, such as land application as agricultural fertilizer, as admixtures for concrete, and in the steel-making industry. Air emissions generally constitute the largest environmental concern for most combustion systems and have become a principal inhibitor to expanded development in many regions with poor air quality due to the high cost of stringent emission control or emission offsets. Smoke emissions from uncontrolled fires and stoves have long been recognized as major contributors to human respiratory and other disease. Increasing use of small biomass combustion systems for distributed power generation will similarly be of concern for increased risk of exposure to pollutant emissions among other environmental factors, such as noise, odors, and fugitive emissions (e.g., dust and debris). Despite these concerns, progress has been made in reducing emissions from combustion systems and improving emissions measurement and monitoring. Environmental issues in biomass combustion, including emission control devices, are reviewed in greater detail by van Loo and Koppejan [11].

36

Biomass Combustion

Primary pollutants formed during biomass combustion include PM, CO, HCs, oxides of nitrogen (NOx, principally NO and NO2), and oxides of sulfur (SOx, principally as SO2). Other acid gases, such as HCl, accompany the use of halogenated feedstock, such as MSW and straw. Elevated halogen concentrations can also lead to the formation and emission of hazardous air pollutants in addition to accelerated corrosion in the combustion system. Of particular concern for chlorinated fuels is the formation of dioxins and furans, especially with waste fuels, although new emission standards for WTE facilities have greatly reduced dioxin contamination from this source [76, 77]. The presence of heavy metals, such as lead, cadmium, selenium, and zinc, in the fuel leads to their concentration in ash, sometimes to levels above the hazardous waste thresholds as measured by the toxicity characteristic leaching procedure and related methods [38, 78], or, as in the case of mercury (Hg), release as vapor to the atmosphere with subsequent downwind condensation or reaction and deposition. Heavy metals can be present in high concentration in certain urban and refuse-derived fuels, especially if treated or painted woods are present [79]. Control of heavy metals is generally by fuel selection to exclude contaminated feedstock, unless the facility is specifically designed and permitted for such use. Research into oxy-fuel combustion processes that replace air with oxygen holds promise for reducing emissions of greenhouse gases, especially CO2, in addition to products of incomplete combustion and thermal NOx, but still must contend with environmental concerns over fuel NOx and metals, in addition to added costs for oxygen production. Advanced systems such as BIGCC integrated with downstream oxy-fuel, electrochemical, and other process options suggest the need for expanded research in this area. Greenhouse gas emissions are of less concern for biomass conversion than with fossil fuels when biomass is produced on a renewable basis. Fossil fuel use, especially diesel fuel used in biomass production, harvesting, collection, and transport, means that the use of biomass is not completely carbon neutral unless an additional increment of biomass is continuously grown to offset the fossil greenhouse gas emissions, or carbon from the biomass is sequestered. Other greenhouse gases, such as CH4 and N2O emitted during biomass processing or combustion also make biomass systems less than carbon neutral due to the higher global warming potential (GWP) associated with these species in comparison with the CO2 taken up by plants and used in photosynthesis. Combustion of biomass and waste in various small systems has been found to lead to higher emissions of N2O in addition to CO [80]. Indirect effects leading to deforestation and agricultural expansion with high greenhouse gas emissions elsewhere in the world when biomass is produced as an energy crop may further reduce the sustainability of bioenergy and potentially increase exposures to criteria and other pollutants. Nonetheless, the use of biomass in properly designed systems has the potential to radically reduce the release of greenhouse gases relative to the use of fossil fuels. 2.4.1

Oxides of Nitrogen and Sulfur

One of the largest concerns for many areas in the USA and elsewhere around the world is emissions of NOx due to already high emissions from existing industries and vehicles. Increasingly stringent NOx emission standards in California, for example, reduce the economic feasibility of dairy biogas systems with on-site power generation and make siting of new solid fuel and other biomass systems more difficult [81, 82]. NOx emissions have also been of concern in the use of biodiesel as vehicle fuel, where a number of studies have

Pollutant Emissions and Environmental Impacts

37

yielded NOx increases compared with petroleum diesel [83], although this is an issue of continuing research. Emissions of sulfur oxides are associated with sulfur in the fuel unless some other source of sulfur is available, such as H2S in a cofired waste or process gas stream. Sulfur oxides are respiratory irritants and their effects are enhanced in the presence of PM due to transport deep within the lung. Both sulfur and nitrogen oxides contribute to acid precipitation. In addition to sulfur oxides, some sulfur remains in the ash or is deposited in the furnace. Some may also be released as salts or H2S [11]. SOx emissions can be reduced through dry or wet scrubbing. Removal of sulfur upstream of post-combustion catalysts is important to avoid catalyst fouling and deactivation. Inadequate sulfur control has been a consistent problem with engines burning digester or landfill gas and using catalytic after-treatment of combustion gases for NOx control [84, 85]. Limestone or dolomite injection in fluidized bed combustors has been a primary control measure for SOx, in addition to reducing fireside fouling from sulfates in boilers [11, 86]. Emissions of NOx and other nitrogenous species, such as N2O (a strong greenhouse gas), in biomass combustion systems arise mostly from fuel N concentrations. NO is the primary species (H90%) formed during combustion and is later oxidized to NO2 in the atmosphere [11]. The latter compound typically serves as the reporting basis for NOx emissions. NOx formation is associated with three principal mechanisms: fuel NOx stemming from nitrogen in the fuel, thermal NOx resulting from high-temperature reactions between nitrogen and oxygen mostly from the air, and prompt NOx due to reactions of nitrogen in air with HC radicals to form HCN that then follows the fuel NOx formation route [11, 86]. For biomass, the fuel NOx mechanism is presently the most important in most commercial systems due to relatively low flame temperatures. NO is also formed from residual N during char combustion, but is reduced via a fast heterogeneous char reaction to N2 [11]. NO formation from fuel nitrogen occurs on time-scales comparable to HC oxidation, and is known to be sensitive to equivalence ratio, with fuel-lean conditions producing higher yields and fuel-rich conditions producing lower yields [87, 88]. Under fuel-rich conditions, the relatively fast conversion of fuel carbon to CO competes for oxygen, leading to a reduced availability of oxygen for NOx formation. The fractional conversion of fuel nitrogen to NOx has been shown to decrease with increasing fuel N concentration for hydrocarbon fuels and coal [87–89]. Data obtained from commercial biomass-fueled fluidized bed combustors [86] and laboratory experiments with fir and birch wood [90] also suggest declining fuel N conversion with increasing fuel N concentration. N2O also results from fuel N oxidation, but is generally produced in much lower amounts. The high GWP of this species – a factor 310 greater than CO2 with N2O having a similar lifetime to CO2 in the atmosphere [91] – makes even small emissions important from a climate change perspective [11]. NOx photochemically reacts with volatile organic compounds (VOCs) to form ozone, a lung and eye irritant and a major air pollutant in many urban environments. NOx also participates in the formation of fine particles in the presence of other species, such as ammonia to form ammonium nitrate [92]. Although most of the NOx involved in ozone formation in many regions originates from other sources, including vehicles, stringent NOx emission regulations increase the cost of control for any new generators, including biomass power plants which might provide other benefits, such as greenhouse gas emission reductions. No satisfactory regulatory process yet exists for aggregating multiple emission impacts to achieve optimal overall environmental performance, an area in need of substantial research.

38

2.4.2

Biomass Combustion

Products of Incomplete Combustion

CO and HCs, including VOCs and PAHs, are products of incomplete combustion. These species are largely controlled by proper management of combustion stoichiometry and fuel moisture to ensure sufficient temperature and more complete burning [93, 94]. Increased emission of these species is linked to inadequate mixing in the combustion chamber, overall lack of oxygen, low combustion temperatures, short residence times, or low radical concentrations, especially in the final stages of batch combustion processes [11]. The PAHs include a large number of environmentally persistent aromatic compounds of variable toxicity [93]. The US Department of Health and Human Services has classified a number of these as known animal carcinogens. Benzo[a]pyrene is listed by the International Agency for Research on Cancer (IARC) as a known human carcinogen [94, 95]. PAHs, including benzo[a]pyrene and others, are found in smoke from cigarettes and open burning of biomass [96–98] and are partitioned to both the gas and particle phase [99]. PAHs, like most other products of incomplete combustion, can be reduced by proper management of combustion conditions to provide adequate oxygen, residence time, and temperature. 2.4.3

Particulate Matter

PM includes soot, ash, condensed fumes (tars/oils), and sorbed materials such as VOCs and PAHs [87, 100, 101]. Most combustion-generated particles are in the size range below 1 mm aerodynamic particle diameter. Respirable particles 10 mm or smaller (PM10) are breathing hazards, due to their retention deep in the alveoli of the lung. Mechanically generated PM, including carry-over fuel fines and ash particles, tend to be fairly large compared with combustion aerosols and are more readily controlled by filters and other emission control equipment. Biogenic silica in some materials, such as rice straw, is partly released as fibrous particles and has become of concern recently for lung disease [102]. Mutagenicity of PM extracts has been found to increase from engines burning biodiesel blends, with a maximum occurring at around 20% biodiesel (B20) in the blend [103]. PM can be controlled by a combination of proper management of combustion conditions, to ensure more complete combustion, and post-combustion control equipment, such as cyclones, baghouses, scrubbers, and electrostatic precipitators, in some cases specified by regulation [11, 86, 104–108]. 2.4.4

Dioxin-like Compounds

The class of dioxin-like compounds includes a large number of chemicals having similar structure, physical–chemical properties, and common toxic responses and includes the polychlorinated dibenzo-p-dioxins (CDDs), polychlorinated dibenzofurans (CDFs), polybrominated dibenzo-p-dioxins, polybrominated dibenzofurans, and polychlorinated biphenyls (PCBs) [77]. Polybrominated biphenyls are likely to have similar properties to the PCBs. Of the 629 cogeners of these various species, 47 are thought to exhibit dioxin-like toxicity varying in extent relative to the most toxic and widely studied of these compounds, 2,3,7,8-tetrachlorodibenzo-p-dioxin (TCDD), for which sufficient evidence now exists that the IARC classifies it as a known human carcinogen [95]. Toxicity of the other compounds is referred to that of TCDD in terms of toxic equivalence (TEQ), with values ranging from 10
5 to 1.0, the latter equal to the toxicity of TCDD. Different schemes for measuring the TEQ

Pollutant Emissions and Environmental Impacts

39

have emerged including the international scheme adopted by the US EPA and those of the World Health Organization [77]. Mixtures of dioxin-like compounds are assigned TEQ values on the basis of a mass weighted average. Prior to 1995, MSW combustion was listed as the leading source of dioxin emissions in the USA [76, 77]. Since 1995, regulations have been promulgated by the US EPA to limit CDD/CDF emissions from numerous sources. Installation of maximum achievable control technology (MACT) on MSW combustors with aggregate combustion capacities greater than 227 t/day (250 tons/day) and retirement of facilities for which retrofit was infeasible have led to large reductions in emissions of dioxins and furans from this source [76, 77, 109]. Total environmental releases of dioxin-like compounds declined 90% in the USA between 1987 and 2000 (Table 2.4). Reductions in emissions from MSW combustion exceed 99% since 1987. Emissions from industrial wood burning increased 36% over the same period due to a 58% increase in firing capacity and wood demand without a concurrent requirement to meet MACT standards but with enhancements in best available control technology requirements. Total air emissions from industrial burning of 51  106 t of wood and 0.8  106 t of salt-laden wood in 2000 were about half those from the 31  106 t of MSW burned in the USA during the same year [109]. At present, backyard refuse burning is the largest single source of dioxin-like compounds. No federal standards exist to regulate this source, although state and local standards apply in some locations. Additional sources not incorporated in the total environmental release listed in Table 2.4 include wildfire and prescribed burning for land clearing or residue disposal. Estimates for releases from wildfires range up to 4560 g TEQ/year depending on year and area burned, but are highly uncertain. Although chlorine must be present in the system in order to form CDDs and CDFs, chlorine concentration in the feedstock has not been observed to be a dominant factor in the emission of dioxin-like compounds from commercial waste incinerators [77]. Other factors appear to have more control over their formation and emission, including overall combustion

Table 2.4 Releases of dioxin-like compounds (g TEQ/year) in the USA 1987–2000 [109]. Reproduced from EPA, 2005, An Inventory of Sources and Environmental Releases of Dioxin-like Compounds in the United States for the Years 1987, 1995 and 2000, EPA/600/P-03/002F Release category Total environmental releases of dioxin-like compounds Municipal waste combustion Medical waste/pathological incineration Wastewater treatment sludge (land application and incineration) Open (backyard) refuse burning Residential wood burning Industrial wood combustion Coal-fired utility boilers Hazardous waste incineration Hazardous waste combustion in cement kilns Cigarette burning a

Not including wildland and prescribed fires.

a

1987

1995

2000

13 965 8 905 2 570 85

3 444 1 394 487 133

1 422 84 378 90

604 22 27 51 5 118 1.0

628 16 26 60 6 156 0.8

499 11 42 70 3 19 0.4

40

Biomass Combustion

efficiency, flue gas residence times and temperatures in emission control equipment downstream of the furnace, and opportunistic catalysis supporting CDD/CDF synthesis. Emissions of dioxins from chlorine-containing herbaceous feedstock, such as straw, have generally been low, possibly as a result of the simultaneous formation of KCl, NaCl, and other salts that reduce the levels of chlorine available for reaction. Sufficient oxygen is also required for the destruction of dioxins, as is enhanced turbulence to promote good mixing, eliminate cold spots in the furnace, and provide adequate residence time at high temperature [108]. Individual combustor designs may vary substantially in terms of the dependence of dioxin emissions on chlorine concentration in the feed, and chlorine concentration may be more of an issue for open or uncontrolled burning of biomass [11, 77]. 2.4.5

Heavy Metals

Hg is strongly released to the flue gas during combustion and can be classified as a highly volatile element together with Cl, F, and Se [38, 108]. Some Hg removal occurs during the control of other species, such as SOx and NOx, and Hg can be strongly concentrated in fly ash, but for fuels containing higher concentrations of Hg, active control such as activated carbon injection as a sorbent may be required [110]. Water leaching of the feedstock to remove alkali metals and chlorine does not appear to alter Hg mobility in biomass [38]. Other less volatile metals, such as copper and zinc, are enriched in slag and bottom ash, while cadmium, selenium, and more volatile elements vaporize in the combustion zone, condense downstream on fine particles, and are either captured in flyash or escape to the atmosphere [108]. Lead and chromium exhibit enrichment factors of three or more in incinerator bottom ash [37], but are also enriched in flyash [108]. 2.4.6

Radioactive Species

Radioactive constituents may also be present in biomass and become enriched in ash or released to the atmosphere. Incineration of medical waste and human or animal tissues containing radioisotopes is a direct source [108]. In addition to naturally occurring radionuclides found in soil, artificial radionuclides occur in wood and other biomass as a result of deposition from atmospheric testing of nuclear weapons, the Chernobyl nuclear reactor accident, and other radioactive contamination [111, 112]. Wood samples collected in Croatia after the Chernobyl accident contained levels of 137 Cs, 214 Bi, and 40 K in the range 1.6–37.3 Bq kg
1, 0.2–27.1 Bq kg
1, and 21.5–437.1 Bq kg
1 respectively (1 Bq ¼ 1 nuclear decay/s ¼ 2.7  10
11 Ci) [112]. Both 214 Bi and 40 K are naturally occurring and so are always found in biomass, 214 Bi being a decay product of uranium contained in soil and 40 K a natural isotope of potassium in the environment. 137 Cs is an artificial isotope and indicative of radioactive contamination. Combustion results in enrichment in ash as radionuclides evaporate and recondense on flyash particles. 2.4.7

Greenhouse Gas Emissions

Using sustainably grown biomass as fuel is one means of displacing fossil fuel to aid in stabilizing atmospheric greenhouse gas concentrations. CO2 released to the atmosphere by biomass conversion is offset by that taken up by plants in producing new biomass. Although the use of biomass for energy is often said to be carbon neutral – that is, as much carbon is

References

41

taken up in the growth of new biomass as is released in its conversion – on a lifecycle basis this is not at present entirely true. The use of diesel fuel, gasoline, natural gas, coal-fired electricity, and other fossil-based energy in the production, harvesting, processing, and conversion of biomass is not offset when biomass is grown on a purely replacement basis. An additional amount of biomass would need to be grown and the carbon sequestered to offset the fossil carbon release from biomass handling. CH4, N2O, and other pollutants released during biomass production and conversion also have larger GWPs than CO2. Combustion of biomass, therefore, results in an imbalance in greenhouse gas emission and uptake. The large displacement of fossil-derived CO2 through the substitution of biomass in well-controlled systems, however, still results in a substantial decrease in net greenhouse gas emissions. Advanced biomass conversion technologies reduce the emission of CO2 per unit of product energy by increasing efficiency and reducing the fuel consumption. For biomass utilization to be effective in managing atmospheric CO2, it must be produced on a renewable and sustainable basis, including indirect effects associated with global marketmediated impacts [113]. Carbon capture and storage, currently under development for use with fossil fuels, and a number of other techniques to sequester carbon have the potential to achieve a net reduction in atmospheric carbon when applied to sustainable biomass conversion systems. Achieving substantially lower levels of pollutant emissions and realizing potential carbon benefits remain important objectives for biomass combustion research and development.

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3 Gasification Richard L. Bain1 and Karl Broer2 1

National Renewable Energy Laboratory, Golden, CO, USA Department of Mechanical Engineering, Iowa State University, Ames, IA, USA

2

3.1

Introduction

Gasification is defined as thermal conversion of organic material to combustible gases under reducing conditions with oxygen added in sub-stoichiometric amounts compared with the amount needed for complete combustion to carbon dioxide and water. Gasification may be accomplished through the direct addition of oxygen, using exothermic oxidation reactions to provide the energy necessary for gasification, or by pyrolysis through the addition of sensible heat in the absence of added oxygen. In both cases, water, in the form of steam, may be added to promote additional production of hydrogen via the water-gas shift reaction. Through gasification of biomass, a heterogeneous solid material is converted into a gaseous fuel intermediate of consistent quality that can be used reliably for heating, industrial process applications, electricity generation, and liquid fuels production. Gasification has been the subject of several reviews, including those by Johnson [1], Reed [2], Probstein and Hicks [3], Higman and van der Burgt [4], Knoef [5], Rezaiyan and Cheremisinoff [6], and Bain [7]. The nomenclature of gasification is sometimes not clearly defined. Producer gas refers to the low heating value gas mixture of carbon monoxide (CO), hydrogen (H2), carbon dioxide (CO2), methane (CH4) and other low molecular weight hydrocarbons and nitrogen (N2) produced from gasification of carbonaceous feedstocks in air. Historical applications of producer gas have included heat and electricity production, as well as the production of synthetic liquid fuels. Synthesis gas (syngas) refers to a gas mixture of predominantly CO and H2 produced from gasification of carbonaceous feedstocks in oxygen and steam Thermochemical Processing of Biomass: Conversion into Fuels, Chemicals and Power, First Edition . Edited by Robert C. Brown © 2011 John Wiley & Sons, Ltd. Published 2011 by John Wiley & Sons, Ltd. ISBN: 978-0-470-72111-7

48

Gasification

followed by gas separation to remove CO2. This H2-rich mixture was developed for synthesis of fuels and chemicals. Although not strictly correct, the term syngas is widely used to describe the gaseous product from any kind of gasification process. In this discussion, the term syngas will be used in this broader meaning. The cold gas efficiency (CGE) of a gasification operation is the ratio of the chemical energy in the gas produced to the chemical energy in the feedstock. Typical CGE values range from 60 to 80%. Because gasification occurs at high temperatures, freshly produced syngas from most types of reactors is hot and contains significant sensible energy. In applications where this sensible energy can be exploited, hot gas efficiency (HGE) should be calculated, which includes both sensible energy and chemical energy of the product gas. Typical HGE values range from 80 to 95%. The spread between CGE and HGE will increase as syngas exit temperature increases. Gasifier performance can also be characterized by carbon conversion. Carbon conversion is the percentage of the carbon in the feed that is converted to syngas products. Typical carbon conversion values range from 60 to 99%, with lower values representative of indirectly heated systems and higher values representative of partial oxidation systems. Equivalence ratio is the fractional amount of oxygen supplied to the oxidation process compared with the amount required for complete stoichiometric combustion. The stoichiometric amount of oxygen and the amount of oxygen provided in a gasification process are calculated as air-to-fuel ratios, which can be based on either moles or masses of reactants. The advantage of using the equivalence ratio to describe a gasification process is that its value does not depend upon whether the air-to-fuel ratio is based on moles or masses. For the purposes of useful estimates of equivalence ratio, the generic formula for biomass can be assumed to be CH1.4O0.6. Stoichiometric combustion would require 1.05 mol of O2: CH1:4 O0:6 þ 1:05O2 ! CO2 þ 0:7H2

ð3:1Þ

Thus, the molar stoichiometric air/fuel ratio for combustion of biomass is 1.05. The optimal equivalence ratio for gasification is approximately 0.25 or a molar air-to-fuel ratio of about 0.26.

3.2

Fundamentals of Gasification

The steps by which biomass is converted into syngas are partially shared with combustion. As shown in Figure 3.1, these steps include heating and drying, pyrolysis, gas–solid reactions, and gas-phase reactions [8]. These steps can occur in rapid succession (approximately 1 s) if biomass particles of small size are fed into a gasification reactor capable of high heat transfer rates. 3.2.1

Heating and Drying

Heating and drying is the first step of gasification, transforming biomass moisture content from 20–50 wt% to bone dry matter at about 300 C [8]. As the biomass is heated, moisture contained in the biomass is converted to steam, which can react with biomass and volatiles released during combustion given sufficient time and temperature. Both sensible energy and latent energy must be supplied to heat the biomass and evaporate the moisture respectively.

Fundamentals of Gasification

49

Figure 3.1 The process of thermal gasification [8]. Reproduced from R.C. Brown, 2003, Biorenewable Resources: Engineering New Products from Agriculture. With permission from John Wiley and Sons

Although it is possible to gasify wet feedstocks, such as manure and greenwood, the energy required to remove this extra moisture comes at the expense of the chemical enthalpy of the product gas. Thus, some drying of biomass before feeding into gasification equipment is highly desirable. The process of heating and drying begins on the outside surface of a biomass particle and then progresses toward the center. A thermal front forms, with the temperature of the outside surface rising immediately after entering the reactor, with the temperature at the center of the particle lagging behind. The larger the particle of biomass that is inserted into the reactor, the more delay there will be before heating and drying has been completed at the center of the particle. 3.2.2

Pyrolysis

Rapid thermal decomposition of biomass in the absence of oxygen is known as pyrolysis [8]. Although some reactions commence at temperatures as low as 225 C, the process becomes progressively more rapid and complete as temperatures reach 400–500 C. The process is accompanied by the release of volatiles, which includes produced water (arising from chemical decomposition of the biomass), permanent gases (those that do not condense upon cooling), and tarry vapors (those that condense upon cooling), and formation of a porous, carbonaceous solid known as char. Permanent gases include CO, CO2, H2, and light hydrocarbons, particularly methane. Tarry vapors immediately released upon pyrolysis consist of anhydrosugars and other highly oxygenated compounds from the decomposition of cellulose and hemicelluloses in biomass and phenolic monomers and oligomers from the depolymerization of lignin. Exposed to high temperatures, these compounds can crack to smaller compounds or condense to larger compounds, including polyaromatic hydrocarbons, which can be a major constituent of condensed tar. Pyrolysis can convert up to 80 wt% of the biomass into vapors and gases, depending upon the kind of biomass and process

50

Gasification

conditions. It leaves behind a porous solid containing a residual of carbon and inorganic compounds (ash) that do not volatilize at gasification temperatures. 3.2.3

Gas–Solid Reactions

Pyrolysis is followed by the gas–solid reactions between the residual char and the oxygen and steam admitted to the gasifier and gases and vapors released during pyrolysis. There are four major reactions by which solid carbon is converted to gaseous products [8]: the carbon–oxygen reaction, the Boudouard reaction, the carbon–water reaction, and the carbon hydrogenation reaction: carbon--oxygen reaction

C þ 12 O2 $ CO

DHR ¼ 110:5 MJ kmol1

Boudouard reaction

C þ CO2 $ 2CO

DHR ¼ 172:4 MJ kmol1

carbon--water reaction

C þ H2 O $ H2 þ CO

DHR ¼ 131:3 MJ kmol1

hydrogenation reaction

C þ 2H2 $ CH4

DHR ¼ 74:8 MJ kmol1

The highly exothermic carbon–oxygen reaction is important for supplying energy to drive the endothermic processes of heating and drying and pyrolysis. It also provides thermal energy to drive the Boudouard and carbon–water reactions, which are important in gasifying char into CO and H2. The hydrogenation reaction also helps to provide some energy for the endothermic reactions, although the relatively low concentration of H2 in the gasification environment makes it a small contribution compared with the carbon– oxygen reaction. If chemical equilibrium were attained under the process conditions of gasification, all the carbon in char would be converted to gaseous products. In practice, the contact time between char and gaseous reactants at elevated temperatures is usually insufficient to achieve equilibrium, with the result that up to 10 wt% of the biomass appears as char in the gasification products. 3.2.4

Gas-phase Reactions

Volatiles released during pyrolysis participate in gas-phase reactions as long as they remain at high temperatures. Two of the most important in terms of determining the final composition of the gas are the water-gas shift and methanation reactions [8]: water-gas shift reaction

CO þ H2 O $ H2 þ CO2

DHR ¼ 41:1 MJ kmol1

methanation

CO þ 3H2 $ CH4 þ H2 O

DHR ¼ 206:1 MJ kmol1

The water-gas shift reaction is important in increasing the H2 content of syngas (important for synfuels production), while the methanation reaction can strongly influence the CH4 content of syngas (important for production of synthetic natural gas). Both of these reactions are exothermic, which means they are thermodynamically favored at low temperatures. However, low temperatures reduce the rates at which these reactions occur. Thus, a better strategy for promoting hydrogen formation is to add steam to the gasifier, while methane formation can be promoted by increasing partial pressures of hydrogen in the gasifier.

Feed Properties

3.3

51

Feed Properties

In evaluating biomass gasification feedstocks, it is necessary to perform proximate and ultimate analyses, heats of combustion, and ash analyses. These data provide information on volatility of the feedstock, its elemental analysis, heat content, and potential for slagging/fouling. The proximate analysis [9] classifies the fuel in terms of the contents of moisture M, volatile matter VM, ash, and fixed carbon FC. In the test procedure, the volatile material is driven off in an inert atmosphere at high temperatures (950 C) using a slow heating rate (rapid heating yields more volatile matter, as occurs in rapid pyrolysis). Moisture measured by proximate analysis represents physically bound water only; water released by chemical reactions during pyrolysis is classified as being part of the volatiles. The ash content is determined by combustion of the volatile and fixed-carbon fractions. The resulting ash fraction is not representative of the original ash, more appropriately termed mineral matter, because of the oxidation process employed in its determination. In the most exact analysis, small corrections to the ash weight are necessary to correct it to a mineral matter basis. The fixed-carbon content of an as received sample is calculated by material balance. Thus: FC ¼ 1MAshVM

ð3:2Þ

The fixed carbon is considered to be a polynuclear aromatic hydrocarbon residue resulting from the condensation reactions which occur in the pyrolysis step. Typical proximate analyses for solid fuels are given in Table 3.1, from which it is evident that common biomass materials are more readily devolatilized (pyrolyzed) than lignite and bituminous coals, yielding considerably less fixed-carbon residue. This is due to the much more aromatic structure of the coals produced by the geological coalification process. The higher volatile content of biomass materials makes them potentially useful feedstocks for indirect gasification processes. In general, the ash content of biomass materials is considerably lower than for coals. Proximate analyses are useful in screening gasifier suitability for converting particular feedstocks. In general, feeds with low volatile contents are more suitable for partial oxidation gasification. Ultimate analyses [9] generally report C, H, N, S, and O (by difference) in the solid fuel. Care must be exercised in using ultimate analyses for fuels containing high moisture content, because moisture is indicated in the ultimate analysis as additional hydrogen and oxygen. To avoid confusion and to give a good representation of the fuel itself, ultimate analyses should be performed and reported on a dry basis. This ensures that all hydrogen determined is truly a constituent of the fuel. For biomass materials, especially municipal solids and animal waste, the determination of chlorine is important because it represents a possible pollutant and corrosive agent in gasification and combustion systems. In evaluating gasification systems, the sulfur level is important because of its potential impact on downstream gas conditioning and fuel synthesis operations. The nitrogen content of a potential feedstock is important because the nitrogen typically is converted to ammonia during gasification and needs to be removed during cleanup operations. Typical ultimate analyses for biomass and coals are given in Table 3.2.

52

Gasification

Table 3.1 Proximate analysis data (dry weight basis) for selected solid fuels and biomass [9]. Reprinted from Biomass Gasification: Principles and Technology, M. Graboski and R. Bain, Properties of biomass relevant to gasification, Copyright (1981), with permission from Elsevier Analysis (wt%) Volatile matter (VM) Coals Pittsburgh seam 33.9 Wyoming Elkol 44.4 Lignite 43.0 Oven-dry woods Western hemlock 84.8 Douglas fir 86.2 White fir 84.4 Ponderosa pine 87.0 Redwood 83.5 Cedar 77.0 Oven-dry barks Western hemlock 74.3 Douglas fir 70.6 White fir 73.4 Ponderosa pine 73.4 Redwood 71.3 Cedar 86.7 Municipal refuse and major components Nat¼l Ave. Waste 65.9 Newspaper (9.4%) 86.3 Paper boxes (23.4%) 81.7 Magazine paper (6.8%) 69.2 Brown paper (5.6%) 89.1 Selected biomass Almond wood 77.28 Red oak sawdust 86.22 Hybrid poplar 84.81 Alfalfa stems 78.92 Wheat straw, Denmark 69.80 Wheat straw, OR 81.24 Rice straw 65.47 Willow 85.23 Sugar cane bagasse 85.61 Switchgrass, MN 82.94 Bana Grass 73.44

Ref.

Fixed carbon (FC)

Ash

55.8 51.4 46.6

10.3 4.2 10.4

[10]

15.0 13.7 15.1 12.8 16.1 21.0

0.2 0.1 0.5 0.2 0.4 2.0

[11]

24.0 27.2 24.0 25.9 27.9 13.1

1.7 2.2 2.6 0.7 0.8 0.2

[11]

9.1 12.2 12.9 7.3 9.8

25.0 1.5 5.4 23.4 1.1

[12]

15.94 13.47 12.49 15.81 12.29 17.06 15.86 13.82 11.95 14.37 16.68

6.78 0.31 2.70 5.27 10.78 4.32 18.67 0.95 2.44 2.69 9.88

[13]

The composition of ash in feedstocks is also important to gasification performance. Inorganic components normally analyzed are silica, aluminum, titanium, iron, calcium, potassium, magnesium, sodium, and phosphorus. These components are reported as the highest oxide form and normalized as a weight percent of ash. SO3, chlorine, and CO2 may also be reported. In evaluating ash composition for gasification, alkali and phosphorus contents are important because of their potential to cause slagging and fouling

Feed Properties

53

Table 3.2 Ultimate analysis (dry basis) of selected biomass and coals Material West Kentucky No. 11 coal Wyoming Elkol coal Lignite Rice straw Wheat straw Animal waste Bagasse Sudan grass Switchgrass, Columbus, OH Switchgrass, Krutsinger 2 Alfalfa pellets Oak, tan Poplar, hybrid Willow – SV1-1yr Pine, ponderosa Pine bark Lignin, mulberry Lignin, poplar Corn stover DDGSb

C

H

N

74.4 71.5 64.0 39.2 43.20 42.7 44.80 44.58 46.68 44.97 45.60 48.67 50.18 47.94 49.25 52.3 61.00 63.40 49.62 50.29

5.1 5.3 4.2 5.1 5.00 5.5 5.35 5.35 5.82 5.10 5.50 6.03 6.06 5.84 5.99 5.8 5.20 5.70 5.35 6.47

1.5 1.2 0.9 0.6 0.61 2.4 0.38 1.21 0.77 0.69 2.70 0.06 0.60 0.63 0.06 0.2 1.5

S

3.8 0.9 1.3 0.1 0.11 0.3 0.01 0.01 0.19 0.09 0.21 0.04 0.02 0.06 0.03 0.0 0.60 1.57 0.80 0.05 3.63 0.67

O

Cl

7.9 — 16.9 — 19.2 — 35.8 39.40 31.3 39.55 39.18 37.57 0.03 42.43 0.024 36.99 0.39 44.99 40.44 0.01 44.43 G0.01 44.36 38.8 27.50 27.20 38.13 0.12 34.69 0.16

Ash

HHVa (MJ/kg)

7.3 4.2 10.4 19.2 8.90 17.8 11.27 8.65 8.97 6.72 9.00 0.20 2.70 1.10 0.29 2.9 1.90 1.60 5.99 4.25

31.24 29.50 24.86 15.18 16.71 17.13 17.33 17.39 18.02 18.13 18.29 18.93 18.98 19.32 19.66 20.38 25.23 25.99 18.40 20.68

a

Higher heating value. Distiller’s dried grains with solubles.

b

in the gasifier and in downstream operations, such as gas coolers and tar reformers. When investigating slagging and fouling, total alkali is typically reported on a lb/MMBtu (1 kg/MJ  2325 lb/MMBtu) basis. Although most of the historical analyses of ash composition have been performed for combustion systems, the same general guidelines hold true in evaluating gasification feedstock suitability. Quoting from the recent EPRI Renewable energy Technical Assessment Guide [14] for combustion systems: The consequence of the high alkali metal concentrations in the herbaceous materials and manures is the potential for slagging and fouling deposits. Miles et al. 1995 [13] posit a useful measure of slagging and fouling for biomass fuels as follows: . . .

G0.4 lb alkali (K2O þ Na2O)/MMBtu, low slagging and fouling potential 0.4–0.8 lb alkali/MMBtu, probable slagging and fouling H0.8 lb alkali/MMBtu, certain slagging and fouling.

Potassium is of special concern because, in combination with silica, it can form a low melting point eutectic at gasification temperatures. The impact may be more severe for partial oxidation gasifiers, especially fixed-bed gasifiers. In many cases the fouling may be alleviated by an additive that changes the solid–liquid phase behavior. A common additive is magnesia. Partial-oxidation gasifiers that use limestone as a bed medium may also see sequential conversion from carbonate to oxide to carbonate that may lead to fouling.

54

3.4

Gasification

Classifying Gasifiers According to Method of Heating

Although there are many ways to classify gasifiers, the manner in which energy is provided to the process is probably the most common and useful classification scheme. The conversion of carbonaceous solids into flammable gas mixtures is a high-temperature, endothermic process. Thus, energy must be generated within or conveyed to the gasification vessel at high temperatures. Partial-oxidation gasifiers, also referred to as air-blown, oxygen-blown, or directly heated gasifiers, use the exothermic reaction between oxygen and carbonaceous feedstocks to provide the heat necessary for gasification. When air is used as the oxidant, the resulting product gas is diluted with nitrogen and typically has a relatively low dry-basis calorific value of about 5–6 MJ/Nm3 (where Nm3 is normal cubic meters). The calorific value of the product gas can be increased to 13–14 MJ/Nm3 by using oxygen instead of air, although this adds to processing costs due to the additional capital and operating expenses of an air separation system. Indirectly heated gasifiers convey heat to the gasifier through heat transfer surfaces or heat transfer media. Since neither oxygen nor air is added, the product gas is not diluted with nitrogen or significant carbon dioxide. As a result, the gas has a significantly higher heating value, on the order of 18–20 MJ/Nm3. 3.4.1

Air-blown Gasifiers

Different combinations of air, nitrogen, steam, and oxygen have been used for partial oxidation gasification of biomass, but the simplest and cheapest option is air. As a result, air-blown biomass gasification has been the most thoroughly explored, and has been most frequently employed for commercial-scale gasification projects to date. Air-blown gasification can be conducted in fixed-bed, bubbling fluidized-bed (BFB), and circulating fluidized-bed (CFB) reactors. Because of the quantities of air required to achieve equivalence ratios around 0.25, the final syngas composition produced by an airblown gasifier is dominated by nitrogen. The nitrogen content of the biomass entering the reactor does not significantly contribute to the nitrogen content of the syngas. Nitrogen in syngas is generally regarded as undesirable, since it does not contribute to the energy content of the syngas. Despite this disadvantage, syngas from air-blown gasification has been successfully used in furnaces, boilers, and internal combustion (IC) engines. The nitrogen becomes more problematic if the syngas is to be used for chemical or fuel synthesis applications, because processing vessels and purge gas volumes must be significantly larger to accommodate the nitrogen’s unreactive gas volume. In the case of Fischer–Tropsch liquid synthesis, nitrogen has a negative effect on the production of hydrocarbons with chain lengths suitably long for liquid fuel production [15]. Other constituents of syngas that are of foremost importance are CO, H2, CO2, and CH4. Ethylene, acetylene, ethane, and other light hydrocarbons are commonly found in syngas in smaller amounts, on the order of 3% molar basis or less. Syngas can also be expected to contain at least some tar and char, which are undesirable, and often must be removed before the syngas can be used. Syngas composition for a number of air-blown gasification projects, which used a variety biomass feedstocks, equivalence ratios, and reactor types, are shown in Table 3.3. Despite the differences among these projects, nitrogen is always the largest component of the syngas as a result of air being used as the oxidizing agent. The factors influencing syngas composition for air-blown gasification include

SAFI Babcock & Wilcox V€ arnamo Tech. University of Denmark CIEMAT University of Maine University of Seville University of Complutense ECN EPI Iowa State University Gas Technology Institute Southern Electric Intl. Tampella Power, Inc.

Organization

CFB BFB BFB BFB BFB BFB

CFB BFB BFB BFB

CFB Updraft CFB Downdraft

Gasifier type

51.4 51.9 55.9 40.3 47.9 48.8

45.0

0.31 0.32 0.275

59.46

50.6 40.7 48–52 33.3

N2

0.41

Equiv. ratio

Table 3.3 Gas composition from various air-blown gasifiers

16.4 15.8 12.8 22.39 15.9 15.7

21.7 5.1–14.9 16 13.5

17.3 11.9 14.4–17.5 15.4

CO2

14.2 17.5 23.9 11.7 15.5 16.4

8.6 6.9–17.7 14 18.0

9.7 22.8 16–19 19.6

CO

11.9 5.8 4.1 14.8 12.7 13.7

5.4 5.2–8.3 9 9.5

9.5 19 9.5–12 30.5

H2

Gas species (% v/v dry basis)

4 4.65 3.1 10.8 5.72 5.8

3 0.95–1.35 5 4.5

7.2 5.3 5.8–7.5 1.2

CH4

0.13 2.27

1.45 2.58

1.9

5.4

CxHy

[21] [22] [22] [22] [22] [22]

[17] [18] [19] [20]

[16] [16] [16] [16]

Ref.

Classifying Gasifiers According to Method of Heating 55

56

Gasification

reaction temperature, equivalence ratio, residence time, type of reactor, and feedstock composition. 3.4.2

Steam/Oxygen-blown Gasifiers

The diluent affect of the nitrogen content of the air can be avoided by using steam and oxygen as fluidizing agents instead. The resulting syngas contains much higher concentrations of H2 and CO, which give it higher energy content and make it more suitable for downstream chemical processes such as Fischer–Tropsch liquid synthesis. Syngas composition data for representative steam/oxygen gasification projects are shown in Table 3.4. There are ways that oxygen- and steam-blown gasifiers can be operated to achieve very high rates of carbon conversion. Pilot-scale gasification systems blown with oxygen and steam have been operated by Siemens and Shell. The gasifiers operated by Siemens are downdraft reactors operated at very high temperatures (1300–1800 C). These temperatures are high enough to make the residual ash melt into a hot liquid slag within the reactor. In the region near where oxidant enters the reactor, tubes with cooling water lining the walls of the reactor cool the slag. Slag initially condenses on the tubes, forming a solid, protective, and thermally insulting layer. Molten slag flows downward over the solid slag layer until it reaches a slag pot at the bottom of the gasifier where it can be collected. This unique design allows the reactor to withstand the extreme temperatures without the use of refractory material to protect the reactor walls. The absence of refractory in this design means that the reactor can be started up and shut down quickly. High ash content fuels are tolerated well by this design. The high temperatures of operation are sufficient to drive the gasification reactions close to thermodynamic equilibrium, resulting in syngas which contains very little tar, char, or light hydrocarbons [26]. 3.4.3

Indirectly Heated Gasifiers

Indirect gasifiers might better be described as high-temperature pyrolyzers, since no oxidant is admitted to the reaction vessel. The primary reactions of indirect gasification are devolatilization of the feedstock to produce permanent gases, condensable vapors, and char. Depending on the reaction medium and residence time, secondary gas-phase reactions such as the water-gas shift reaction may influence the final gas composition. The range of temperatures of operation for indirectly heated gasifiers is broader than for partial-oxidation reactors, with temperature ranging from 600 to 1500 C, although the majority of systems operate in the 600–850 C range because of the difficulty of transferring high-temperature heat into the reactor. Table 3.4

Composition of typical syngas from oxygen/steam gasification

Organization

Gasifier type

Equiv. ratio

Gas species (% v/v dry basis) CO2

Guangzhou Institute Downdraft University of Hawaii BFB at Manoa University of Saragossa BFB

0.24 0.2

24.5 32 14–37

CO 39 30

H2

CH4

29 6.0 25 9.5

Ref. CxHy

1.3 2.5

[23] [24]

30–50 13–29 5.0–7.5 2.3–3.8 [25]

Classifying Gasifiers According to Method of Heating

57

A number of indirectly heated gasification systems have been developed that use heat transfer from a hot divided solid, such as crushed olivine or sand. Notable systems are the REPOTEC gasifier in Austria, the Silvagas gasifier in the USA, and the Melina gasifier in the Netherlands. These biomass gasifiers are based on fluid coking technology developed in the petroleum industry for processing heavy refinery residuals and employ a combination of fluidized-bed and CFB technologies for the indirectly heated gasifier and the associated combustor that typically burns the residual char. Other systems are being developed that introduce heat through the reactor wall. The TRI gasifier in the USA combusts a portion of the product gas in a pulse combustor and transfers heat to a fluidizedbed gasifier through tubular heat exchangers suspended in the bed. Other systems, such as the Pearson gasifier, use producer gas or natural gas to heat a fire box enclosing an entrained-flow gasifier. These gasifiers typically have longer residence times to minimize char production. The Range Fuels technology is a variation on this concept. Other variations of indirect heating exist, such as the Pyromex technology from Germany that uses inductive heating of the reactor walls to produce temperatures representative of slagging gasification. Because of the heating mechanism, the product gas from indirect gasification contains much less nitrogen and CO2 than air- or oxygen-blown gasifiers do. Gas compositions typical of a generic indirect gasifier (NREL PDU) are given in Table 3.5. Table 3.5 Average gas compositions for NREL indirectly-heated gasification pilot plant.a Reprinted with permission from D.L. Carpenter et al., Pilot-scale gasification of corn stover, switchgrass, wheat straw, and wood: 1. Parametric study and comparison with literature, Industrial and Engineering Chemistry Research, 2010, 49, 1859. Copyright 2010 American Chemical Society Corn stover

Vermont wood

Wheat straw

Switchgrass

H2 CO CO2 CH4 He (tracer) C2H4 C2H2 C3H8 C3H6 1-C4H8 2-cis-C4H8 2-trans-C4H8 H2S

26.9 24.7 23.7 15.3 1.6 4.2 0.45 0.40 0.12 0.08 0.02 0.00 —

28.6 23.5 24.0 15.5 1.2 3.9 0.38 0.61 0.09 0.06 0.00 0.01 0.00

25.4 27.5 22.0 16.3 1.6 4.3 0.31 0.81 0.10 0.08 0.00 0.00 0.08

23.5 33.2 19.4 17.0 1.6 5.1 0.34 0.82 0.10 0.08 0.00 0.00 0.02

% mass closure (dry gas) H2:CO Gas yieldb (kg/kg-feed) CO yield (kg/kg-feed) Gas mol. wt (kg/kmol)

97.5 1.09 0.54

97.9 1.21 0.74 0.22 21.8

98.5 0.92 0.54 0.19 21.8

101.1 0.71 0.62

22.0

23.1

a Gas compositions were measured with gas chromatography. These results were gathered with a steam-to-biomass ratio of 1.0 a fluidized bed reactor temperature of 650 C and a thermal cracker temperature of 875 C. The gas compositions are given in volume percent on a dry nitrogen-free basis. b

Gas yield is weight of dry gas produced per weight of feedstock.

58

3.5

Gasification

Classifying Gasifiers According to Transport Processes

Most gasifiers are designed as steady-flow processes rather than batch operations. Flow of feedstock through a reactor and mixing it with air and oxygen (for partial-oxidation gasifiers) or with a heat carrier (for indirectly heated gasifiers) can be accomplished in many ways. Four distinct gasifier designs based on transport phenomena are generally recognized: fixed-bed reactors, BFB reactors, CFB reactors, and entrained-flow reactors. Among the most prominent differences among these gasifiers is tar content of the syngas, as shown in Table. 3.6. 3.5.1

Fixed Bed

In fixed-bed gasifiers, biomass is processed in bulk, flowing through consecutive zones of drying, pyrolysis, and char combustion. Fixed-bed gasifiers are the oldest types of gasifier and have historically been developed for smaller scale applications. Developed before modern computer control systems, they are relatively simple systems to operate and maintain. Because of the high temperatures attained in the char combustion zones, fixed-bed gasifiers have a high potential for ash slagging, which impacts their reliability. Fixed-bed gasifiers include updraft and downdraft designs. These have distinctive operating characteristics. Updraft gasifiers are the oldest and simplest gasifiers. As illustrated in Figure 3.2, fuel enters the top of an updraft gasifier by means of a lock hopper or rotary valve. As it moves in counterflow to air or oxygen, it goes through stages of drying, devolatilizing, and char combustion, with unburned char and ash exiting via a rotating grate at the bottom of the gasifier. Air or oxygen entering the bottom of the gasifier reacts with char in the combustion zone to form CO, CO2, and H2O at temperatures as high as 1200 C. This hot gas provides the energy to drive heating, drying, and pyrolysis of the biomass. In the pyrolysis zone, these gases contact dry biomass in the temperature range 400–800 C and devolatilize the biomass to produce pyrolysis products and residual char. Above this zone, the gases and pyrolytic vapors dry the entering biomass. Typical product exit temperatures are relatively low (80–100 C). The counterflow design of the updraft gasifier results in large quantities of tars in the product gas, which are susceptible to plugging the syngas pipe exiting the gasifier. For this reason, syngas from updraft gasifiers is usually directed straight into a furnace or boiler to produce steam or hot water, since this setup is relatively tolerant of tars. Updraft gasifiers require tight control of feedstock particle size to assure a fixed bed of uniform voidage. Certain feedstocks containing low melting-point ash can form slag in an updraft gasifier. As illustrated in Figure 3.3, feedstock and gases flow in the same direction in downdraft gasifiers. The advantage of this concurrent arrangement is that volatiles released during the gradual heating of the biomass must pass through a high-temperature char combustion zone Table 3.6 Approximate tar contents that can be expected for three different common types of gasifier Reactor type

Ref.

Updraft Indirect BFB and CFB Downdraft

[27] [27] [27] [28]

Tar content (mg/Nm3) 50 000 48 000–83 000 10 000 1 000

Classifying Gasifiers According to Transport Processes

59

Figure 3.2 Updraft gasifier [7]. Reproduced from Overview of Biomass Gasification, R.L. Bain, Conference Proceedings of the 2004 AIChE Spring National Meeting, NREL Report No. CP-510-35798

Figure 3.3 Downdraft gasifier [7]. Reproduced from Overview of Biomass Gasification, R.L. Bain, Conference Proceedings of the 2004 AIChE Spring National Meeting, NREL Report No. CP-510-35798

60

Gasification

(800–1200 C) where tars are rapidly and efficiently cracked. Tar conversion rates of 99% or greater can be achieved. The hot char also reacts with CO2 and H2O released during combustion to produce CO and H2. The exit gas temperatures are generally high (700 C). Like updraft gasifiers, feedstock for downdraft gasifiers needs to be fairly uniform in size with few fines. Feedstock with low ash content and high ash fusion temperature is important to prevent slagging in the high-temperature combustion zone. Downdraft gasifiers must also have fuel with moisture content less than about 20% in order to achieve temperatures high enough to crack tars. A variation of the downdraft gasifier is the crossflow gasifier, in which air is introduced tangentially into a throat located near the bottom of the gasifier to form a char oxidation zone. 3.5.2

Bubbling Fluidized Bed

In a bubbling fluidized bed (BFB) gasifier, as illustrated in Figure 3.4, gas flows upward through a bed of free-flowing granular materials at gas velocity high enough to agitate the material into a churning emulsion of levitated particles and gas bubbles [29]. The BFB resembles a boiling liquid and has many of the same physical properties as a fluid. Commonly used bed materials include sand, olivine, limestone, dolomite, or alumina. The beds are fluidized with air, oxygen, and/or steam. In a BFB gasifier, the superficial velocity (volume/unit cross-sectional area) of the gas in the bottom zone is controlled to maintain the bed in a fluidized state. In the upper portion of the gasifier the cross-sectional area is often increased to lower the superficial gas velocity below fluidization velocity to help return particles to the bed to maintain solids inventory. The larger cross-sectional area zone is

Figure 3.4 Fluid-bed gasifier [7]. Reproduced from Overview of Biomass Gasification, R.L. Bain, Conference Proceedings of the 2004 AIChE Spring National Meeting, NREL Report No. CP-510-35798

Classifying Gasifiers According to Transport Processes

61

extended to obtain the total desired gas-phase residence time for complete devolatilization and is usually referred to as the freeboard. A gas distribution manifold or series of sparge tubes is used to introduce fluidization gas to the bed [30]. Biomass is introduced into the bed either through a feed chute above the bed or an auger into the bed. In-bed introduction is advantageous because it provides residence time for fines which would otherwise be entrained in the fluidizing gas and not converted in the bed. In-bed introduction also promotes more uniform biomass heating through better mixing of the biomass and bed material. Biomass entering the hot BFB is almost instantly devolatilized. Tars may partially crack and char may be partially gasified, but residence time for both the gases and the char particles is relatively short and the gas composition does not closely approach equilibrium. In partial-oxidation fluidized-bed gasifiers, combustion of char in the bed provides the heat to maintain the bed temperature and devolatilize biomass. In indirectly heated fluidized-bed gasifiers, heat is introduced by heat exchange through the walls of the gasifier, or through heat exchanger tubes in the bed. Fluidized-bed gasifiers have the advantage of being extremely well mixed and having high rates of heat transfer, resulting in very uniform bed conditions. For partial-oxidation systems, gasification is very efficient, and 95–99% carbon conversion is typical. For indirectly heated fluidized-bed steam-blown gasifiers, carbon conversion is typically lower, in the range 60–75%. In many indirectly heated gasifiers, the residual carbon is combusted in an external char combustor which generates heat that is returned to the gasifier. This effectively results in carbon conversion rates comparable to partial-oxidation systems. The notable difference is that the CO2 formed in char combustion is not included in the syngas. BFB gasifiers are normally designed for complete ash carryover, necessitating the use of cyclones or other types of inertial separator for particulate control. In general, fluidized-bed systems have higher syngas tar and particulate loadings than fixed-bed systems do. BFB reactors can be scaled to very large sizes, limited only by the ability to distribute feedstock entering the reactor evenly. This can be addressed by the use of multiple feeding locations or by increasing reactor pressure, which allows more biomass throughput to occur for the same fluidized-bed cross-sectional area. BFB gasifiers are usually operated between 790 and 870 C. Higher bed temperatures would result in higher carbon conversion and increased tar cracking, but the fluidized-bed reactor temperature must be kept below the ash-fusion temperature of the biomass ash in order to prevent bed particle agglomeration, which results in defluidization of the bed. 3.5.3

Circulating Fluidized Bed (CFB)

As gas flow through a fluidized bed is increased, the voidage of the bed material increases and the solids loading in the freeboard increases. As the interface between the fluidized bed and the freeboard becomes difficult to discern, the reactor is said to be a turbulent fluidized bed [31]. As gas flow is further increased, elutriation of particles becomes significant enough that the bed would quickly become depleted of particles unless a cyclone is employed to return particles via a downcomer to the bottom of the reactor. Under this circumstance, the reactor is said to be a circulating fluidized bed, as illustrated in Figure 3.5. Superficial gas velocities are typically three to five times higher than for BFBs [31]. CFBs can be used for both partial-oxidation and indirectly heated gasifiers. In partialoxidation systems, the oxidation zone is normally in the return leg of the gasifier, and partial oxidation gaseous products become part of the syngas. In indirect CFB systems, the char is

62

Gasification

Figure 3.5 Circulating fluid-bed gasifier [7]. Reproduced from Overview of Biomass Gasification, R.L. Bain, Conference Proceedings of the 2004 AIChE Spring National Meeting, NREL Report No. CP-510-35798

combusted externally, flue gases are separated from the solids, and only heated solids are returned to the gasifier. This changes the composition of the syngas, in that the oxidation products are not mixed back into the syngas. The solids circulation rate in a CFB is governed by the amount of energy needed to gasify the biomass and to maintain the maximum temperature below slagging conditions. Typical heat transfer solids to biomass ratios are 15:1 to 30:1. Circulating bed gasifiers have the advantages of high mass flow rates, feed flexibility, and scalability. In comparison with the other types of gasifiers, they produce moderate levels of tars and particulates. 3.5.4

Entrained Flow

As illustrated in Figure 3.6, entrained-flow gasifiers inject finely divided solids or atomized liquids into high-velocity streams of oxygen or steam, where they are rapidly gasified at temperatures in the range of 1300–1400 C. This temperature is high enough to melt most inorganic matter in the biomass, which flows from the reaction zone as a liquid slag. The extremely high temperatures result in almost complete destruction of tars, and the gas composition typically approaches an equilibrium composition and contains very low levels of CH4 and other light hydrocarbons. These gasifiers have been developed for coal, but only

Pressurized Gasification

63

Figure 3.6 Entrained-flow slagging gasifier

very limited operation with biomass has been performed. There are a number of reasons for the lack of application to biomass, but the high cost of feed preparation to reduce moisture content to low levels and reduce the particle size (100 mm to 1 mm) are the primary concerns [32]. Hybrid systems, such as the Choren process that uses low-temperature pyrolysis to produce vapor and solids suitable for entrained-flow operation, have been developed to address these concerns. Pyrolysis oil and pyrolysis oil/char slurries are also being investigated as feed for slagging gasifiers. Entrained-flow reactors have been developed for coal by Shell, Texaco (GE), Conoco Phillips, and others. There is another type of entrained-flow system that has been developed for indirectly heated gasification. As shown in Figure 3.7, finely divided biomass (less than 3 mm diameter) is entrained in steam or steam/nitrogen mixtures and injected into tubular reactors operated at 700–950 C. The biomass rapidly pyrolyzes into product gas. The tubular reactors are installed in furnaces fired with product gas or natural gas to provide the energy to pyrolyze the biomass. These indirectly heated entrained-flow gasifiers have considerable flexibility in operating conditions, which allows better control of char and tar yields. The size of these reactors is limited by the rate that heat can be transferred into the reactor, which can be improved by installing multiple tubular reactors in the furnace.

3.6

Pressurized Gasification

Gasification under high pressure has several advantages compared with atmosphericpressure operation. For a given mass throughput, gas volumes are smaller, resulting in smaller process vessels and piping. Many reactions are accelerated under pressurized conditions, which can more closely approach the equilibrium products. A pressurized

64

Gasification

Figure 3.7 Indirectly heated entrained-flow gasifier [7]. Reproduced from Overview of Biomass Gasification, R.L. Bain, Conference Proceedings of the 2004 AIChE Spring National Meeting, NREL Report No. CP-510-35798

gasifier can also have strong advantages from a systems perspective, since it generates pressurized gas that can be directly fed into a gas turbine combustor or a fuel synthesis reactor, which minimizes or eliminates syngas compression requirements. High-pressure gasification of biomass faces many challenges. The most prominent challenge is the difficulty of conveying solid feedstocks into a pressurized reactor. Gases and liquids can be readily pressurized for injection into a pressure vessel, but solids need to be moved through lock hoppers, rotary valves, or other suitable mechanical devices which are susceptible to plugging, back-flowing, or leaking. Coal has been successfully slurried with water to allow it to be handled as a fluid. Unfortunately, raw biomass is too hydroscopic to produce slurries of reasonable solids loading. The second issue with pressurized gasification is that there is considerable additional complexity associated with designing, constructing, and operating pressure vessels, which present unique operational and safety challenges. Third, gas cleaning systems able to operate at high temperatures and pressures need to be developed for use with pressurized gasification systems. The advantages of pressurized gasification systems do not overcome their high capital and operating costs for biomass applications.

3.7

Product Composition

Product gas composition is important in evaluating the suitability of syngas for different applications. Gas composition is a function of feed elemental composition, inlet gas composition (air, oxygen, or steam), and gasifier type. Chemical equilibrium calculations can be used to estimate expected gas composition. In general, low-temperature systems, such as indirect gasifiers and dry ash gasifiers, do not reach chemical equilibrium conditions, while high-temperature slagging gasifiers closely approach equilibrium. A dry equilibrium estimate (CO, CO2, H2, and CH4, only) for a hypothetical biomass feedstock at a steam to biomass ratio of 1.0 is given by Figure 3.8. The ideal chemical equilibrium composition was estimated using

Product Composition

65

0.7 0.6

Mole Fraction

0.5

CO CO2 H2 CH4

0.4 0.3 0.2 0.1 0.0 550

600

650

700

750

800

850

900

950

Temperature, ºC

Figure 3.8 Equilibrium dry gas composition, steam gasification (steam/biomass ¼ 1)

STANJAN [33] for a low-pressure system. Figure 3.9 gives comparable values for air-blown gasification (CO, CO2, H2, CH4, H2O, and N2) assuming a steam-to-biomass ratio of 0.5 and use of 30% of the stoichiometric amount of oxygen. The dry composition values are those normally reported when comparing syngas compositions. Figure 3.10 gives comparable values for a dry, nitrogen-free gas, which is comparable to the gas composition for oxygenblown gasification. Additional estimates can be made by looking at the impact of variables on gas composition. Figure 3.11 shows the effect of steam/biomass in indirect steam gasification. 0.6

Mole Fraction

0.5

CO CO2 H2 CH4 N2

0.4

0.3

0.2

0.1

0.0 600

700

800

900

1000

1100

1200

1300

Temperature, ºC

Figure 3.9 Equilibrium air gasification composition, H2O free

1400

66

Gasification 0.5

Mole Fraction

0.4

0.3

0.2

CO CO2 H2 CH4

0.1

0.0 600

700

800

900

1000

1100

1200

1300

1400

Temperature, ºC

Figure 3.10 Equilibrium oxygen gasification composition, H2O free

The H2 to CO ratio is a strong function of the steam to biomass ratio, and H2/CO ratios from G1 to H2 can be obtained by varying steam rate. In actual gasifiers the gas composition produced is much more complicated because the product distribution normally does not reach equilibrium. Steam gasification produces CO, H2, CO2, CH4, light hydrocarbons, tar, and char. The gasification mechanism involves an initial pyrolysis step to produce primary pyrolysis products that are then converted to 0.7

0.6

Mole Fraction

0.5

CO CO2 H2 CH4

0.4

0.3

0.2

0.1

0.0 0.2

0.4

0.6

0.8

1.0

1.2

Steam to Biomass Ratio (S/B)

Figure 3.11 Steam gasification, effect of steam/biomass, dry gas

Product Composition

67

Table 3.7 Examples of char concentrations in producer gas reported in literature from three air-blown gasification studies Reactor type CFB BFB Downdraft

Char content (g/Nm3)

Ref.

1.7–13.1 1.04–43.61 9.3–30

[34] [35] [36]

intermediates (permanent gases and condensed aromatics) and finally to permanent equilibrium gases. At equilibrium the gas composition is primarily controlled by the water-gas shift reaction. Although the equilibrium C:H:O ratios are based on biomass composition without accounting for C and H in the char and tar, the calculations illustrate that the product gas is far from equilibrium. 3.7.1

Char and Tar

The syngas produced by most types of air-blown, oxygen-blown, and indirectly heated gasifiers can be expected to contain significant amounts of tar and char particulates. Table 3.6 provides approximate tar content of syngas for partial oxidation gasifiers [27] and indirect gasifiers [28]. Table 3.7 provides approximate char content for partial-oxidation gasifiers [27]. Tar and char content are high enough in all cases to justify gas cleaning before use in IC engines, gas turbines, or Fischer–Tropsch liquid synthesis (see Table 3.8). Many studies have investigated the effect of operating conditions on char and tar production. Increasing the temperature of the reactor, using calcined dolomite as bed material in a fluidized-bed gasifier, and adding steam have all demonstrated some benefit. Gasifiers operated above 1200–1300 C are very effective at reducing tar and char yields [22], but they are significantly more expensive to construct and operate. Dolomite can be used as an ingredient in the bed of fluidized-bed gasifiers to catalytically crack tar, but it rapidly breaks into fines that elutriate from a fluidized bed. The use of steam may impact gasification efficiency if heat load for vaporization and sensible heat changes are larger than the heat recovery available from gas coolers. Nevertheless, these strategies can be utilized to an appropriate extent, and used in combination to reduce tar production. Equivalence ratio, typically represented by l, is another parameter that can be used to control tar and char production. As equivalence ratio is increased, the process becomes more oxidizing and hotter, conditions which promote the destruction of tar and char. It also means that the gas products are more highly oxidized, which reduces the CGE of the gasifier. Table 3.8 Maximum levels of contaminants that are acceptable in producer gas that is to be used in an IC engine [37] Contaminant Particulate Tar Acids

Max. level (mg/m3) 50 50 50

68

Gasification

The char and tar that are unavoidably produced during gasification can be removed by a number of gas cleaning technologies, often used in series. Gas cyclones are able to remove most particulate matter above about 10 mm in size. The remaining particulate matter and tars must be removed by barrier filters, electrostatic precipitators, or wet scrubbers.

3.8

System Applications

Gasification plants in demonstration or commercially developed have found a variety of applications (see Table 3.9). Applications can be generally categorized as process heat, combined heat and power (CHP), or liquid fuel/chemical synthesis. 3.8.1

Process Heat

Process heat is used for a variety of industrial applications, including drying, distilling, or steam raising. It is among the lowest value applications of syngas because it often substitutes for coal or other relatively low-cost fuels. However, it is among the least expensive gasification applications to implement because syngas quality requirements are often very modest. Nexterra of British Columbia has completed projects where syngas is burned directly for wood drying and lime kilns. The syngas produced by the gasifier is used in place of, or alongside, natural gas in otherwise conventional wood drying kilns [38]. Gasifiers have also been used in developing countries such as India and China to provide syngas for use in cooking and heating homes as an alternative to open fires in the home, although with some difficulties in reliability [39]. 3.8.2

Combined Heat and Power (CHP)

Biomass gasification can be used to generate electricity and waste heat suitable for steam for industrial process heat or for a district heating. Projects of this type tend to be relatively small scale (less than 10 MW electric or 65 MJ/h thermal). A number of CHP projects have been developed in the USA and Europe. For small-scale power projects, the syngas is typically combusted in a stationary IC engine equipped with a generator and provisions for heat recovery. This mode of electricity generation is simple, and IC engines are moderately robust to syngas impurities (Table 3.8), allowing the syngas cleanup equipment to be relatively simple compared with other power generation options. The major disadvantage of power generation using IC engines is high NOx emissions and high engine maintenance costs. There are several companies around the world that have developed gasification power projects based on IC engines which are used to generate both heat and electricity. Community Power Corporation of Littleton, CO, markets 90–260 kWt modular gasifiers for custom applications [40]. Babcock and Wilcox have a demonstration plant in Harboøre, Denmark, where wood chips are gasified to fuel IC engines which generate electrical power production for a municipality [41]. Similar projects are reported by Carbona in Skive, Denmark [42], and REPOTEC in G€ ussing, Austria [43].

TRI

Cleaning, 5 cm minus

200 minus

Freeboard 2 bar Syngas for power and biorefineries

Drying to 20% Drying optional moisture Lock hoppers and Lock hoppers and Positive displacement rotary valves rotary valves feeder – TK Energy with additive with additive with MgO or limestone(?)

Cleaning, 5 cm minus screening Drying to 20% moisture

Feed preparation

CHP

Combustor 950 C Combustor 980 C 1 bar 1 bar Bottom 4.4 bar

CHP and biofuels

Feed introduction

Taylor Energy

Repotech GmbH

Power generation using a gas engine. Pilot production of SNG, FTL research Hammer mill, screening

Enerkem (Biosyn)

Unknown –

Unknown

Unknown

Biofuels – methanol and mixed alcohols

(continued )

“Front-end feeding system.” No need for pelletization

Heterogeneous biomass including MSW to produce green fuels and chemicals Drying, sorting, shredding (300 minus), drying (20%)

30 psi

750 C (1382 F)

Bubbling sand Gasification media fluidized technology is bed using O2 proprietary – two-stage indienriched air rect gasification and steam

Range Fuels

Near atmospheric Unknown

Indirectly heated Indirectly heated Fluidized bed steam Indirectly heated two-stage reforming with twin circulating twin circulating fluidized bed pulse combustors fluidized bed – fluidized bed – medium BTU followed by a char medium BTU medium gas reduction stage – gas calorific gas medium BTU gas Gasifier 815 C Gasifier 815 C 600 C Gasifier – 850 C

Intended Use

Operating pressure

Operating temperature

Gasifier type

Rentech Silvagas

Table 3.9 Representative gasification technologies

System Applications 69

Demonstration

Size

Advantages and disadvantages

Rentech Silvagas

Taylor Energy

TRI

Repotech GmbH

8 MWe demonstration in Burlington, VT

Gas cyclones followed by gas quench scrubber

24 MWe project at Whitecourt, Alberta, Canada

Unknown

Range Fuels

Feedstock flexible, integrated tar capture and destruction

Cyclones, carbon/ tar conversion, heat recovery, carbon/tar reinjection

Enerkem (Biosyn)

First plant 1.3 MM Scale up to progal ETOH cessing 700 dry (Westbury, tons/day of Quebec – feedstock using 2010) multiple trains Projects under Extensive commercial Commercial oper- 10 000 000 gal/ development year ethanol/ ation in Guesdemonstration on in Edmonton methanol plant sing, Austria spent pulping li(2011) and under conquor. Commercial Pontotoc, MS struction in the biofuels projects (2013) Soperton, under developGeorgia ment at Flambeau River and Wisconsin Rapids, WI

HRSG, venturi scrub- Biodiesel Integrated gas ber, tar capture conditioning scrubbing and recycling, reactor, heat water removal, recovery, polH2S and ammonia ishing scrubber scrubbing 7 years’ commerSame as SilvaGas Medium BTU gas, Gasifier demoncial operation customized comwith addition of strated at comat 2 MWe position, feedstock conditioning mercial scale flexibility reactor to Medium calorific reduce tars value gas; integrated operation for boiler feed 25–50 MWe 20–25 MWe Up to 60 MWe 2 MWe and 4.5 MWt

(Continued )

Gas cleanup

Table 3.9

70 Gasification

Feed introduction

Feed preparation

Intended use

Operating pressure

Operating temperature

Gasifier type

1380–1560 F Near atmospheric

1560–1650 F 21 bar (300 psi) for GE 2 bar (29 psi) Frame 6B Cofiring/repowering – Combined cycle power CHP – small to Production of automoderate capacity 60 MWt unit generation stand motive fuels from using IC engines, alone or repowering biomass using a running in Lahti, e.g. 5.4 MWe, condensing plant Fischer–Tropsch Finland, since synthesis 1998 – H96% 11.5 MWt available Wood pellets and/or Cleaned and screened Cleaning, crushing 200 Drying to 15–20% wood chips woodchips and water followed by minus, drying to (10–30% waste fuels carbonization at 20% (hot gas – 70 C moisture) 400–500 C, – belt dryer) and buffer storage cooling and pulverization Two lock hoppers Feed blown in from Metering bins folAtmospheric storage/ followed by above lowed by screw weigh silo, lock hopfeeding screws feeders pers, surge hopper, metering screw and feeding screw

2550–2900 F 5 bar (72 psi)

850 C (1562 F)

850–900 C

(continued )

Feed is prepared remotely at small satellite pyrolysis units close to the source, then shipped as a slurry Biosyncrude is heated to 80 C, pressurized and pumped through a spray nozzle into the gasifier

30–80 bar (435–1160 psi) Production of liquid fuels that sell for under $2.50 a US gallon

1200 C (2192 F)

Oxygen blown MPG entrained flow gasifier with cooling shield

Bubbling fluid bed – IC engines – low BTU gas

Pressurized bubbling fluidized bed – combined cycle – low BTU gas

Carbo-V pyrolyzer – Atmospheric Circulating Fluidized oxygen enriched Bed biochar entrained flow gasifier – fluidized bed chemical quench 1400–1600 C 750–850 C

Lurgi-Air Liquide-KIT

Carbona-Andritz (near atmospheric)

Carbona-Andritz (pressurized)

Foster Wheeler

CHOREN

System Applications 71

(Continued ) Foster Wheeler

Carbona-Andritz (near atmospheric)

Lurgi-Air Liquide-KIT

Air-blown fluidized-bed gasifier – low BTU gas

Unknown Atmospheric

2000 F Near atmospheric?

Operating temperature Operating pressure

Frontline BioEnergy

926 C (1700 F) Pressurized

Hydrothemal reformer (HEHTR). Based on technology developed by Pearson

ClearFuels

Sand media bubbling fluidized bed staged where low BTU gas is subsequently oxidized in same vessel 1000–1800 F Atmospheric

EPI

Lurgi has extensive Hot gas filtering at Tar reformer (cataexperience with 250–400 C (allows lyst), two gas gas cleanup for coolers, fly ash filalkali metals to confuel production ter, water scrubdense on dust partiber, gas buffer tank cles and tars to remain and into engines in gas phase) Long history of finding The remote pyrolysis Technology concept could solve feedand solving scalebased on extensive stock issues up and operating piloting and engiproblems. neering design Commercial-scale plant successfully operating Modular 63–67 MWe 1–15 MWt 5 MWt being built 110 dtpd biomass to produce 5.4 MWe and 11.5 MWt at Skive, Denmark – operating

Carbona-Andritz (pressurized)

Fixed bed with plasmaassisted cupola

Alter NRG

Cooling followed by a Gas coolers and hot gas filters with fabric filter, water sorbent feeding scrubbing, water washing and gas conditioning for fuel production Several years of exVery clean gas but perience with process is explants operating tremely complex at Lahti, Ruien, and likely to be Belgium, and expensive Varkaus, Finland H60 MWt A 4.2 million gallon Commercial experience per year demonstration plant is operating in Freiburg, Germany

CHOREN

Gasifier type

Size Demonstration

Advantages

Gas cleanup

Table 3.9

72 Gasification

Fuel fed with metallurgic coke and lime (ash fluxing agent) Cooling, particulate – mercury – sulfur filters, & carbon capture

Significant reduction of mercury, SO2, NOx, and CO2, feedstock flexibility, low tars

Feed introduction

Advantages and disadvantages

Demonstration

Size

Operating 40 000 gal/ year ethanol plant at Madison, PA with Coskata

Appears to be minor

Feed preparation

Gas cleanup

MSW, power plant retrofits, biomass to ethanol

Intended use

35 to 70 tons/day (unclear if dry or wet) – Chippewa Valley Ethanol Co., Benson, MN Above commercial unit now running. Plans to expand to 250 t/day

Commercial experience (Chippewa Valley Ethanol, Benson, MN)

Demonstration facility ($23 000 000 DOE) being built at Rentech, Colorado

Five commercial projects initiated (2015 goal)

Clear focus on fuels

Multiple step gas cleaning to prepare for catalytic conversion

Proprietary CLEANGAS technology

Proprietary conditioning system

Unknown

Production of alcohols for fuel use via catalytic conversion of adjusted syngas by manipulating residence time Cleaning, screening, size reduction to 3/1600 , drying to 9–15% moisture See above

Repowering small power boilers

Small pilot gasifier. 200 million Btu/h unit being fabricated Dec. 2009

Refractory lined cyclones remove 70–80% particulate. Char is combusted in a char conversion cell supplying preheated air to staged gasifier. Simple, proven at small to medium scale

Metering bin and rotary feeder

Inert removal, sizing and for best operation drying to 15–25% moisture

Repowering of coal-fired power boilers as well as other applications that can utilize hot gas

System Applications 73

74

Gasification

For larger scale operations, electricity and heat can be generated by integrated gasification/combined cycle (IGCC) power [44]. The system consists of an air separation plant to generate pressurized oxygen, a pressurized gasifier, a high-temperature gas-cleaning system, a gas turbine topping cycle, a heat recovery steam generator, and a steam turbine bottoming cycle. A demonstration plant of an IGCC fired with biomass was successfully operated in Varnamo, Sweden, from 1996 to 2000, and had an output of 6 MW electric [45]. The economic viability of the production of power via IGCC is currently weak, but could become stronger if electricity prices increase, or if the price of carbon emission allowances becomes a significant factor in selecting power options [45, 46]. 3.8.3

Synthetic Fuels

Perhaps the most technically challenging application for biomass gasification is synthesis of synthetic fuels. Despite these technical challenges, companies such as CHORAN in Freiburg, Germany, have created demonstration plants. The ability to create synfuels from biomass using gasification is important because it provides a way to convert all components of biomass, including the lignin fraction, into the final fuel product. Provided that syngas can be purified into a clean mixture of CO and H2, it can be processed catalytically to make diesel fuel, gasoline, jet fuel, methanol, ethanol, larger alcohols, pure hydrogen, aldehydes, and dimethyl ether [47]. The difficulty lies in cleaning the raw syngas emerging from the gasification reactor to a standard of cleanliness high enough to not poison the chemical catalysts, which are often sensitive to the ammonia and sulfur compounds which are present in the syngas. It is also possible to use microorganisms to synthesize fuels from syngas [48]. In a process known as syngas fermentation, bacteria metabolize CO and H2 to a wide variety of molecules suitable for fuel. The first efforts by companies like Bioengineering Resources Inc. and Coskata to commercialize syngas fermentation focused on producing ethanol. More recently, LanzaTech has used syngas fermentation to produce 2,3-butanediol, a key building block in the production of polymers, plastics, and hydrocarbon fuels. Syngas fermentation has several advantages compared with enzymatic hydrolysis to produce fermentable sugars: deconstruction of biomass does not require expensive enzymes; gasification is robust to different kinds of feedstock and the presence of contaminants; both carbohydrate and lignin are utilized; and production costs are projected to be lower. Syngas fermentation also has advantages compared with Fischer–Tropsch synthesis or other catalytic synthesis routes: the microorganisms are insensitive to sulfur in the syngas and the process does not require high pressures or temperatures. Disadvantages of syngas fermentation include rate-limiting gas–liquid exchange rates in aqueous fermentation media; toxicity of microorganisms to some tarry compounds in syngas; and relatively little development of the technology.

References [1] Johnson, J.L. (1979) Kinetics of Coal Gasification, John Wiley and Sons, Inc., New York, NY (ISBN 0-471-05575-1). [2] Reed, T.B. (1981) Biomass Gasification: Principles and Technology (ed. T. Reed), Noyes Data Corporation, Park Ridge, NJ (ISBN 0-8185-0852-2).

References

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[3] Probstein, R.F. and Hicks, R.E. (1982) Synthetic Fuels, McGraw-Hill, New York, NY (ISBN 0-07-050908-5). [4] Higman, C. and van der Burgt, M. (2003) Gasification, Elsevier Science, New York, NY (ISBN 0-7506-7707-4). [5] Knoef, H.A.M. (ed.) (2005) Handbook Biomass Gasification, BTG Biomass Technology Group BV, Enschede, Netherlands (ISBN 90-810068-1-9). [6] Rezaiyan, J. and Cheremisinoff, N.P. (2005) Gasification Technologies, CRC Press, Boca Raton, FL (ISBN 10-0-8247-2247-7). [7] Bain, R.L. (2004) Overview of biomass gasification, in Conference Proceedings of the 2004 AIChE Spring National Meeting, 25–29 April 2004, New Orleans, LA (CD-ROM), American Institute of Chemical Engineers (AIChE), New York, NREL Report No. CP-51035798, 6 pp. [8] Brown, R.C. (2003) Biorenewable Resources: Engineering New Products from Agriculture, Blackwell Publishing, Ames, IA. [9] Graboski, M. and Bain, R. (1981) Properties of biomass relevant to gasification, in Biomass Gasification: Principles and Technology (ed. T. Reed), Noyes Data Corporation, Park Ridge, NJ, pp. 41–71 (ISBN 0-8185-0852-2). [10] Bituminous Coal Research, Inc. (1974) Gas Generator Research and Development, Phase II. Process and Equipment Development, OCR-20-F; PB-125530/3GI. [11] Howlett, K. and Gamache, A. (1977) Forest and mill residues as potential sources of biomass, Vol. VI, Final Report, McLean, VA, The MITRE Corporation/Metrek Division, ERDA Contract No. E(49-18) 2081, MTR 7347. [12] Klass D.L. and Ghosh, S. (1973) Fuel gas from organic wastes. Chemical Technology, 3 (11), 689–698. [13] Miles, T.R., Miles, T.R., Jr., Baxter, L.L. et al. (1995) Alkali deposits found in biomass power plants; a preliminary investigation of their extent and nature, NREL/TP-433-8142, National Renewable Energy Laboratory, Golden, CO. [14] McGowin, C. (2008) Renewable Energy Technical Assessment Guide – TAG-RE: 2007, Electric Power Research Institute, Palo, Alto, CA, March. [15] Tijmensen, A., Faaij, A., Hamelinck, C., and van Hardeveld, M. (2002) Exploration of the possibilities for production of Fisher Tropsch liquids and power via biomass gasification, Biomass and Bioenergy, 23, 129–152. [16] Ahrenfeldt, J. (2005) CO and PAH emissions from engines operating on producer gas, in Handbook Biomass Gasification (ed. H.A.M. Knoef), BTG Biomass Technology Group BV, Enschede, Netherlands (ISBN 90-810068-1-9). [17] Garcia-Ibanez, P., Cabanillas, A., and Sanchez, J.M. (2004) Gasification of leached orujillo (olive oil waste) in a pilot plant circulating fluidised bed reactor. Biomass and Bioenergy, 27 (2), 183–194. [18] Zeng, L. and Van Heiningen, A. R. P. (2000) Carbon gasification of kraft black liquor solids in the presence of TiO2 in a fluidized bed. Energy and Fuels, 14, 83–88. [19] Gomez-Barea, A., Arjona, R., and Ollero, P. (2005) Pilot-plant gasification of olive stone: a technical assessment. Energy and Fuels, 19 (2), 598–605. [20] Narvaez, I., Orio, A., Aznar, M., and Corella, J. (1996) Biomass gasification with air in an atmospheric bubbling fluidized bed: effect of six operational variables on the quality of the produced raw gas. Industrial and Engineering Chemistry Research, 35 (7), 2110–2120. [21] Kersten, S., Prins, W., van der Drift, A., and van Swaaij, W.P.M. (2003) Experimental fact-finding in CFB biomass gasification for ECN’s 500 kWth pilot plant. Chemical Engineering Science, 58 (3–6), 725–731. [22] Ciferno, J. and Marano, J. (2002) Benchmarking biomass gasification technologies for fuels, chemicals, and hydrogen production, National Energy Technology Laboratory of the US Department of Energy. [23] Lv, P. Yuan, Z., Ma, L. et al. (2007) Hydrogen rich gas production from biomass air and oxygen/ steam gasification in a downdraft gasifier. Renewable Energy, 32, 2173–2185.

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[24] Wang, Y. and Kinishita, C. (1992) Experimental analysis of biomass gasification with steam and oxygen. Solar Energy, 49 (3), 153–158. [25] Gil, J., Aznar, M.P., Caballero, M.A. et al. (1997) Biomass gasification in fluidized bed at pilot scale with steam–oxygen mixtures. Product distribution for very different operating conditions, Energy and Fuels, 11 (6), 1109–1118. [26] Siemens AG (2008) Siemens Fuel Gasification Technology, http://www.energy.siemens.com/ hq/pool/hq/power-generation/fuel-gasifier/downloads/brochure_fuel_gasifier_en.pdf (accessed 24 August 2010). [27] Milne, T., Evans, R., and Abatzoglou, N. (1998) Biomass gasifier “tars”: their nature, formation, and conversion, National Energy Technology Laboratory of the US Department of Energy, Golden, CO. [28] Carpenter, D.L., Bain, R.L., Davis, R.E. et al. (2010) Pilot-scale gasification of corn stover, switchgrass, wheat straw, and wood: 1. Parametric study and comparison with literature. Industrial and Engineering Chemistry Research, 49 (4), 1859–1871. [29] Perry, R.H. and Chilton C.H. (1973) Chemical Engineers’ Handbook, fifth edn, McGraw-Hill, New York, NY. [30] Hansen, J.L. (1992) Fluidized bed combustion of biomass: an overview, in Biomass Combustion Conference, Reno, Nevada, US DOE Western Regional Biomass Energy Program, 28–30 January. [31] Babcock & Wilcox (1992) Atmospheric pressure fluidized-bed boilers, in Steam: Its Generation and Use (eds S.C. Stultz and J. B. Kitto), 40th edn, Babcock & Wilcox, Barberton, OH, Chapter 16. [32] Larson, E.D. and Katofsky, R.E. (1992) Production of hydrogen and methanol from biomass, Princeton, NJ, Report No. PU/CES 271, July. [33] Colorado State University (2010) Chemical Equilibrium Calculation, http://navier.engr.colostate.edu/tools/equil.html (accessed 9 March 2010). [34] Van der Drift, B., van Doorn, J., and Vermeulen, J. (2001) Ten residual biomass fuels for circulating fluidized-bed gasification. Biomass and Bioenergy, 20, 45–56. [35] Meehan, P. (2009) Investigations into the fate and behavior of selected inorganic compounds during biomass gasification, Iowa State University Master of Science Thesis, Ames, IA. [36] Wander, P., Altafini, C., and Barreto, R. (2004) Assessment of a small sawdust gasification unit. Biomass and Bioenergy, 27, 467–476. [37] Banapurmath, N.R., Tewari, P.G., and Yaliwal, V.S. (2009) Producer gas and vegetable oils operated compression ignition engines for rural applications, in Biomass Gasification: Chemistry, Processes and Applications (eds J. Badeau and A. Levi), Nova Science Publishers, New York, NY. [38] Rodden, G. (2009) Looking beyond the forest products industry. Pulp & Paper International, 51 (9), 26–31. [39] Smeenk, J., Brown, R.C., Yang, H. et al. (2000) Development of a fluidized bed gasifier system for cooking gas in rural China, in Proceedings of the Ninth Biennial Bioenergy Conference, Buffalo, NY, 15–19 October. [40] Community Power Corporation (2009) Product specifications (metric units), http://www.gocpc. com/products.html (accessed 19 May 2010). [41] Flanigan, V.J., Sitton, O.C., and Huang, W.E. (1988) The development of a 20-inch indirect fired fluidized bed gasifier, University of Missouri-Rolla for Pacific Northwest Laboratory, PNL-6520, Richland, WA, March. [42] Salo, K. and Horvath, A. (2009) Biomass gasification in Skive: opening doors in Denmark, Renewable Energy World, 13 January, http://www.renewableenergyworld.com/rea/news/article/ 2009/01/biomass-gasification-in-skive-opening-doors-in-denmark-54341 (accessed 29 August 2010). [43] Tirone, J. (2007) ‘Dead-end’ Austrian town blossoms with green energy, New York Times, 28 August, http://www.nytimes.com/2007/08/28/business/worldbusiness/28iht-carbon.4.7290268. html (accessed 13 September 2010). [44] Larson, E.D., Williams, R.H., and Leal, M.R. (2001) A review of biomass integrated-gasifier/gas turbine combined cycle technology and its application in sugarcane industries, with an analysis for Cuba. Energy for Sustainable Development, V (1) 54–76.

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[45] Klimantos, P., Koukouzas, N., Katsiadakis, A., and Kakaras, E. (2009) Air-blown biomass gasification combined cycles (BGCC): system analysis and economic assessment. Energy, 34, 708–714. [46] Bridgwater, A.V., Toft, A.J., and Brammer, J.G. (2002) A techno-economic comparison of power production by biomass fast pyrolysis with gasification and combustion. Renewable and Sustainable Energy Reviews, 6, 181–248. [47] Huber, G.W., Iborra, S., and Corma, A. (2006) Synthesis of transporation fuels from biomass: chemistry, catalysts, and engineering. Chemical Reviews, 106 (9), 4044–4098. [48] Brown, R.C. (2005) Biomass refineries based on hybrid thermochemical/biological processing – an overview, in Biorefineries, Biobased Industrial Processes and Products, (eds B. Kamm, P.R. Gruber, and M. Kamm), Wiley–VCH Verlag, Weinheim.

4 Syngas Cleanup, Conditioning, and Utilization David C. Dayton, Brian Turk and Raghubir Gupta Center for Energy Technology, RTI International,1 3040 Cornwallis Road, Research Triangle Park, NC 27709, USA

4.1

Introduction

Biomass gasification can be used to effectively convert a very heterogeneous material into a consistent gaseous fuel intermediate that can be used reliably for heating, industrial process applications, electricity generation, and liquid fuels production. Biomass gasification is a complex thermochemical process that consists of a number of elementary chemical reactions, beginning with the thermal decomposition of a lignocellulosic fuel, followed by partial oxidation of the fuel with a gasifying agent, usually air, oxygen, or steam [1]. The volatile matter that is released as the biomass fuel is heated partially oxidizes to yield the combustion products H2O and CO2, plus heat to continue the endothermic gasification process. Water vaporizes and biomass pyrolysis continues as the fuel is heated. Thermal decomposition and partial oxidation of the pyrolysis vapors occur at higher temperatures and yield a product gas composed of CO, CO2, H2O, H2, CH4, other gaseous hydrocarbons (including oxygenated hydrocarbons from some processes), tars, char, volatile inorganic constituents, and ash. A generalized reaction describing biomass gasification is as follows: biomass þ O2 ðor H2 OÞ ! CO þ CO2 þ H2 O þ H2 þ CH4 þ other hydrocarbons þ tar þ char þ ash þ HCN þ NH3 þ HCl þ H2 S þ other sulfur gases 1

RTI International is a trade name for Research Triangle Institute.

Thermochemical Processing of Biomass: Conversion into Fuels, Chemicals and Power, First Edition . Edited by Robert C. Brown © 2011 John Wiley & Sons, Ltd. Published 2011 by John Wiley & Sons, Ltd. ISBN: 978-0-470-72111-7

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The actual amount of CO, CO2, H2O, H2, tars, and hydrocarbons depends on the partial oxidation of the volatile products:
n m m þ Cn Hm þ O2 ! nCO þ H2 O 2 4 2 The char yield in a gasification process can be optimized to maximize carbon conversion, or the char can be thermally oxidized to provide heat for the process. Char is partially oxidized or gasified according to the following reactions: Cþ

1 O2 ! CO 2

C þ H2 O ! CO þ H2 C þ CO2 ! 2CO

ðBoudouard reactionÞ

The gasification product gas composition, particularly the H2/CO ratio, can be further adjusted by reforming and shift chemistry. Additional hydrogen is formed when CO reacts with excess water vapor according to the water-gas shift (WGS) reaction: CO þ H2 O $ CO2 þ H2 Reforming the light hydrocarbons and tars formed during biomass gasification also produces hydrogen. Steam reforming and so-called “dry” or CO2 reforming occur according to the following reactions and are usually promoted by the use of catalysts: 0 1 m Cn Hm þ nH2 O ! nCO þ @n þ AH2 2 Cn Hm þ nCO2 ! ð2nÞCO þ

m H2 2

The actual composition of the biomass gasification product gas depends heavily on the gasification process, the gasifying agent, and the feedstock composition [2, 3].

4.2

Syngas Cleanup and Conditioning

Syngas cleanup is a general term for removing the unwanted impurities from biomass gasification product gas and generally involves an integrated, multistep approach that depends on the end use of the product gas [4–7]. Gas-phase impurities in syngas include NH3, HCN, other nitrogen-containing gases, H2S, other sulfur gases, HCl, alkali metals, organic hydrocarbons (including tar), and particulates. The concentration of these nonsyngas components strongly depends on the feedstock composition. Gasification of biomass containing high levels of nitrogen and sulfur yields high levels of NH3 and H2S in the syngas stream, and HCl concentration in biomass-derived syngas directly correlates with the chlorine content of the feedstock. Alkali metal (mostly potassium) in syngas is related to the alkali content in the biomass ash. Likewise, ash particles entrained in syngas affect the alkali metal content in syngas. The concentration of alkali vapors or aerosols in syngas depends on the ash chemistry of the selected biomass feedstock and the temperature of the gasification process.

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The organic impurities in syngas range from low molecular weight hydrocarbons to high molecular weight polynuclear aromatic hydrocarbons. The lower molecular weight hydrocarbons can be used as fuel in gas turbine or engine applications, but they are undesirable products in fuel cell applications and liquid fuel synthesis. The higher molecular weight hydrocarbons are collectively known as “tar.” Tar yields in biomass-derived syngas can range from 0.1% (downdraft) to 20% (updraft) or greater (in pyrolysis) in the product gases. For the most part, “tars” are considered to be the condensable fraction of the organic gasification products and are largely aromatic hydrocarbons, including benzene. The diversity in the operational definitions of “tars” usually comes from the variable product gas compositions required for a particular end-use application and how the “tars” are collected and analyzed. Tar sampling protocols are being developed [8–10] to help standardize the way tars are collected; however, these methods are not yet widely established. The extremely heterogeneous nature of solid carbonaceous feedstocks used to produce syngas by gasification presents a very complex and technically challenging situation for any comprehensive syngas cleaning and conditioning system. These challenges include the following: . .

.

. .

Effectively treating multiple contaminants present at significantly different concentrations. Effectively treating syngas with varying contaminant concentrations associated with . natural variations in feedstock composition; . different gasification processes. Effectively treating syngas to meet different product requirements for various syngas utilization processes (catalytic fuel synthesis, chemical production, fuel cells, combustion turbine, etc.). Developing treatment processes to simultaneously remove multiple contaminants, including trace elements. Designing treatment systems in spite of large variation in published or predicted concentrations of trace metals in syngas, resulting from inaccurate and imprecise measurement techniques.

The net result of these challenges is that syngas cleaning is a complex and potentially costly process. Previous attempts to minimize cost and maximize efficiency in coal gasification processes have relied on well-known commercial technologies, with the results of reduced thermal efficiency and increased capital and operating costs. The current commercial basis for syngas cleaning in integrated coal gasification processes involves cooling the syngas for treatment in a liquid scrubbing/absorption system based on either chemical (methyl diethanolamine, or MDEA) or physical (Selexol and Rectisol) absorption. All current syngas desulfurization systems cool the syngas significantly below its dewpoint, resulting in water condensation. As mentioned for the gasification designs using a quench process, this effectively removes most of the HCl and a majority of NH3 from the syngas, depending upon the cooling temperature. The liquid scrubbing/absorption systems treat the water-free syngas stream to remove the H2S and COS species (a COS hydrolysis unit may be necessary to effectively remove COS). The H2S-rich streams from these absorption systems are sent to a Claus plant for final conversion into elemental sulfur. The commercial status of these syngas cleaning systems also reflects a large degree of integration in coal gasification systems that have minimized the capital and operating costs and maximized plant efficiency. In spite of this integration, the syngas cooling requirements

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result in a significant loss of thermal efficiency. Because the regeneration temperature for these systems is significantly less than 300 F (149 C), there is no potential to raise the operating temperature of these systems to achieve better thermal efficiency. Furthermore, these systems are primarily desulfurization systems and are not designed to remove other contaminants, including trace metals. The Rectisol process removes HCN, NH3, and trace metals, including mercury. However, a mercury carbon trap is typically installed upstream of the Rectisol process to eliminate the formation of metal amalgams with mercury in the low-temperature sections of the Rectisol process.

4.2.1

Particulates

Particulate matter in gasification product gas streams originates from several sources, depending on the reactor types, feedstock, and process conditions. Particle carryover from fluidized-bed reactors consists of attrited bed material and char that becomes entrained in the gas flow. The particle size distribution of this particulate matter is a function of the initial size of the bed material. The char tends to be more friable and less dense than the bed material and typically has a smaller particle size distribution. The smallest particles exiting a gasifier tend to be alkali metal vapor condensation aerosols. The concentration of these particles is a strong function of the ash content and ash chemistry of the feedstock. The requirements for particulate removal depend on the end use of the gas. Gasification coupled with gas engines for stationary power applications requires particulate loadings below 50 mg/Nm3 (Nm3 is normal cubic meters). Particulate loadings less than 15 mg/Nm3 with a maximum particle size of 5 mm are required to protect gas turbines in integrated gasification combined cycle processes. The most stringent requirements for particulate removal are for fuel synthesis applications that require particulate loadings of less than 0.02 mg/Nm3 to protect syngas compressors and minimize catalyst poisoning by alkali fumes and ash mineral matter. Several technologies have been developed and are commercially available for particulate removal from high-temperature gas streams. Choosing the most appropriate technology for biomass gasification applications depends on the desired particle separation efficiency for expected particle size distribution to achieve the ultimate particulate loading based on the end use of the syngas. Pressure drop through the particle removal unit operation and thermal integration are also key design parameters to be considered. Tars produced during biomass gasification also have a significant impact on particulate removal strategies. Operating temperatures of most particulate removal devices should be above the tar dewpoint to avoid tar condensation and prevent the particulate matter from becoming sticky and agglomerating. Conventional cyclones for particulate removal are a well-known and proven technology. A dirty gas stream enters a cyclone separator with a high tangential velocity and angular momentum forces the particles close to the walls of the cyclone so that they no longer follow the gas stream lines. The separationefficiency is a function of the particle size, gas flow, temperature, and pressure. Cyclones can be designed for optimum removal of particles of a specific size distribution, usually down to a lower size limit. Multiple cyclones of different design can be used in series to achieve near sub-micrometer particle removal with high efficiency. Barrier filters are another technology option for high-temperature particulate removal. Filter housing design and filter media selection are keys for optimizing particle capture

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efficiency within a manageable window of pressure drop across the filter. The initial pore size of the filter medium is the design basis for pressure drop and particulate removal; however, the filtration efficiency improves as particles collect on the surface to produce a filter cake, and the pressure drop across the filter increases as the thickness of the filter cake increases. Pulsing inert or clean product gas back through the filters dislodges the filter cake, and the pressure drop across the filter can be restored to approaching its original performance. Filter housings need to accommodate regular backpulsing to remove the filter cake and be designed so that the particulate matter can be removed before the filter element is brought back online after the backpulse. Improper design and operation can cause the material that was removed to immediately recoat the surface such that the near original pressure drop is not restored. Operating temperature and product gas composition are the primary process parameters that need to be considered in selecting the appropriate filter medium. Ceramic candles are being developed for high-temperature gas filtration (500 C) applications. Thermal shock from repeated backpulsing can cause filters to break, and pore blinding over extended operation can reduce long-term filter performance. Sulfur, chlorine, and alkali metal salts can be present in the product gases generated from certain feedstocks. When these impurities contact the ceramic filters or supports, hightemperature reactions can lead to morphological changes and embrittlement, which can also reduce long-term filter performance. Optimizing the seal between the ceramic candle and the metal support plate has been a key technical challenge to overcome for the success of this technology. Sintered metal filter elements are an alternative to ceramic candles. The operating temperature of sintered metal filters is typically lower than that for ceramic filters to minimize sintering. At the appropriate operating temperature, sintered metal filters are more robust than ceramic candles, as the risk for rupture or cracking is much lower. Fabric filters, such as flexible ceramic bags, are another alternative filter medium that has been commercially proven at lower temperatures, but materials and mechanical compatibility have limited use of these materials for high-temperature syngas filtration. Electrostatic precipitators (ESPs) have been used commercially for particulate removal in the electric power industry for many years and have found wide application in petroleum refineries for capturing catalyst dust from fluid catalytic cracking (FCC) units. Electric charge is induced on the surfaces of particles, which are then removed from the gas stream as they follow the electric field lines to a grounded collector plate. ESPs can be applied to particulate removal in high-temperature and high-pressure gas streams. However, maintaining the stability of the corona discharge for reliable, steady-state operation is a technical challenge. Another technical challenge is ensuring materials compatability of the highvoltage discharge electrode and other metal internal components with the syngas inpurities. The overall size and capital cost of ESPs tend to make them best suited for large-scale operation. Wet scrubbing systems use liquid sprays, either water or chilled condensate from the process, to remove particulates that collide with liquid droplets. The droplets are then removed from the gas stream in a demister. Venturi scrubbers are the most common wet scrubbers but often require a relatively high pressure drop to circulate quench liquid to be sprayed into the gas stream. Because wet scrubbing requires a liquid quench medium, operating temperatures need to be less than 100 C, often requiring significant gas cooling

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for removing the sensible heat from the product gases. Heat loss from wet scrubbing systems can adversely affect the energy efficiency of the overall process. On the other hand, for indirect gasification systems, the excess steam that is used as the gasifying agent needs to be quenched and recovered. Wet scrubbing systems are inevitable in indirect gasification systems to remove excess water vapor prior to compression and downstream syngas utilization. 4.2.2

Sulfur

Oxides of many metals in the periodic table and, specifically, the transition metals will react with H2S, as described by MeO þ H2S $ MeS þ H2O, where MeO represents a metal oxide and MeS represents a metal sulfide, effectively reducing the H2S concentrations in the syngas [11–14]. The minimum H2S concentration in the treated syngas is determined by the equilibrium concentration based on the syngas composition and metal oxide. Reaction kinetics determine how rapidly the H2S reacts to reach this equilibrium concentration. ZnO possesses one of the highest thermodynamic efficiencies for H2S removal and the most favorable reaction kinetics of all the active oxide materials within the 149 to 371 C temperature range. Although a number of ZnO-based guard bed materials are commercially available, the low sulfur capacity of these materials given the large amount of sulfur to be processed makes them very costly for a once-through disposable material. However, the economics become more attractive if the ZnO-based materials can be regenerated and used for multiple cycles. A number of regenerable ZnO-based sorbents have been developed by various organizations for this purpose, as shown in Table 4.1. RTI’s transport reactor desulfurization system offers significant advantages over fixed-bed and fluidized-bed desulfurization systems. These include higher throughput and smaller footprints, resulting in lower cost and excellent control of the highly exothermic regeneration reaction, which allows the use of neat air for regeneration. ZnO-based materials are typically regenerated using oxygen and nitrogen mixtures according to the reaction ZnS þ 1.5O2 ! ZnO þ SO2. The concentration of the SO2 in the regeneration off-gas depends on the sorbent and reactor configuration. The possible SO2 concentration ranges from about 1 to 14% by volume, depending upon the O2 concentration used in the regeneration inlet gas. This SO2 off-gas must be further treated to produce a sulfuric acid product or an elemental sulfur product in either a Claus plant or in RTI’s direct sulfur recovery process. RTI’s experience with ZnO-based materials has demonstrated that these materials can effectively remove large amounts of H2S, ranging from 500 ppmv to as high as 30 000 ppmv to effluent concentrations typically below 10 ppmv [14]. The actual effluent concentration Table 4.1 Various ZnO-based desulfurization sorbents available commercially Sorbent

Organization

Desulfurization system

RVS-1 Z-Sorb EX-S03 RTI-3

DOE/NETL ConocoPhillips RTI RTI

Fixed bed Fixed and fluidized beds Transport reactor Transport reactor

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appears to have a temperature dependence that is related to both the thermodynamic equilibrium concentration and reaction kinetics. At lower temperatures, thermodynamics become more favorable, but reaction kinetics, specifically diffusion of the H2S through the ZnS product layer, drop off rapidly below about 232 C. RTI has also demonstrated that ZnO materials, in addition to reacting with H2S, also react with COS and CS2. The thermodynamics and kinetics for the reactions with COS and CS2 are similar to those with H2S. RTI has observed that, at temperatures below 232 C, the COS concentration in the effluent gas treated with ZnO-based materials increases. This appears to be a combination of a decrease in desulfurization kinetics and an increase in the rate of conversion to COS via the reaction CO þ H2S ! COS þ H2.

4.2.3

Ammonia Decomposition and HCN Removal

  O Although NH3 is a not a highly stable molecule (DG f ¼ 0 kJ=mol at 175 C), its dissociation requires a very high temperature because of high activation energy (92 kcal/mol). Krishnan et al. [15] studied the removal of fuel-bound nitrogen compounds in simulated coal gas streams using a laboratory-scale reactor and simulated coal gas compositions representative of several types of gasifier. HTSR-1, a catalyst proprietary to Haldor-Topsøe A/S, Copenhagen, Denmark, exhibited excellent activity (even in the presence of 2000 ppm of H2S) and high temperature stability. G-65, an SRI catalyst, demonstrated superior activity in the temperature range 550–650 C at H2S levels below 10 ppm. The presence of impurities such as HCl and HCN did not affect the catalyst performance in the temperature range studied. A wide variety of metals and metal oxides/carbides/nitrides can catalyze the decomposition of ammonia. Group VIII metals (Fe, Co, Ni, Ru, Rh, Pd, Os, Ir, Pt) seem to be active mainly in the metallic state [16, 17]. Even though reaction is noted for oxides of Group VIII metals, in a reducing atmosphere of gases containing H2 or CO, the metal oxide is likely reduced, creating a metallic surface. Activity for ammonia decomposition on smooth metal surfaces has been reported to fall in the following order: Co H Ni H Cu H Zr. Although the Group VIII metals tend to be more active than many other elements, carbides and nitrides of Groups Va (V, Nb) and VIa (Cr, Mo, W) can be especially active for ammonia decomposition [14, 18–24]. For example, Mo2C is about twice as active as the vanadium carbides, which are two to three times more active than Pt/C [25]. Vanadium nitrides were found to be comparable or superior catalytically to Ni supported on silica–alumina [26]. LaNi alloys are also very active due to the formation of a nitride phase [27]. CaO [28], MgO [29], and dolomite (CaO–MgO) are all active. MgO will decompose ammonia to N2 and H2 at temperatures as low as 300 C. Gas-phase composition can significantly impact catalyst activity. For example, CaO is deactivated almost totally when CO, CO2, and H2 are present [28, 30], probably due to the reaction of CO2 with the CaO. Ni, on the other hand, does not seem to be affected by the presence of such gases [7]. Small quantities (G2000 ppm) of H2S were not found to lead to severe poisoning of calcined dolomite, CaO, or, surprisingly, Fe for decomposition of parts per million (ca 2000) quantities of ammonia [30, 31]. Because ammonia synthesis is highly structure-sensitive, the ammonia decomposition activity of Fe is highly dependent on particle size (20 to 50 nm) [30].

Syngas Cleanup and Conditioning

4.2.4

85

Alkalis and Heavy Metals

Compared with sulfur, chlorine, ammonia, and particulate matter, technologies for removing mercury, arsenic, selenium, and cadmium from coal-derived syngas are not as advanced. Available commercial technologies for removing trace metals are limited to mercury and arsenic. Mercury control technologies for the natural gas industry were developed to limit metallurgical failures resulting from the formation of amalgams with aluminum and other metals during gas processing. Adsorbents for mercury control in natural gas processing developed by UOP LLC are based on type X and Y zeolites that have been coated with elemental silver. To regenerate, the material is heated and purged with a sweep gas to remove the mercury. Since the maximum regeneration temperature is below the target warm syngas temperature for trace metal removal, this technology cannot be adapted or modified for warm syngas cleaning. Various forms of activated carbon have also been used to remove mercury from natural gas. A mercury removal unit based on a fixed bed of sulfurimpregnated activated carbon has been designed to reduce the concentration of mercury in water-saturated natural gas [32] from 1000 mg/m3 to less than 5 mg/m3. In their product marketing brochures, Synetix describes a process for removing mercury from natural gas using metal sulfides on inorganic supports. In this application, a fixed-bed reactor maintained at 15 C is used to reduce the concentration of mercury from 5.0 to 0.01 mg/m3. Both of these processes operate at temperatures below the target temperatures for warm syngas cleaning. 4.2.5

Chlorides

For bulk removal of HCl vapor, different sorbent materials and processes have been studied and different technologies are being developed. In the two-stage “Ultra-Clean Process” [33], different sorbents, like synthetic dawsonite, nahcolite, and trona (Na2CO3NaHCO32H2O), have been tested. The HCl exit concentration from their Stage I polishing at 449 C was below 3 ppm. Trona was found to be the best sorbent for HCl. Krishnan et al. [15] evaluated several alkali minerals for removal of HCl (at 300 ppm of inlet HCl concentration) from hot syngas at atmospheric pressure in the temperature range 550–650 C. All of the sorbents reacted rapidly with the HCl and reduced its concentration to about 1 ppm. The performance of nahcolite was superior with respect to absorption capacity; the spent sorbent contained up to 54% chloride by weight. In a subsequent study conducted by a team of SRI International (SRI), RTI, and General Electric (GE) Corporate Research and Development, the HCl removal in syngas streams was demonstrated in bench- and pilot-scale reactors [34]. The results of bench-scale experiments in fixed- and fluidized-bed reactors demonstrated that nahcolite pellets and granules were capable of reducing HCl levels to less than 1 ppm in syngas streams in the temperature range 400–650 C. Tests conducted with the product gas of a pilot-scale, fixed-bed gasifier confirmed that nahcolite effectively reduced HCl to less than the 15 ppm detection limit of the analyzer with a high degree of sorbent utilization (H70%), when operated in a circulating fluidized-bed reactor. The equilibrium level of HCl in the presence of sodium carbonate-based sorbents depends on process conditions, especially temperature and partial pressure of steam. Thermodynamic equilibrium calculations show that the concentrations of HCl in equilibrium with an Na2CO3–NaCl system vary from 0.003 to 0.16 ppb (GE non-quench gasifier gas composition

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at 600 psi (4.14 MPa)). These sub-parts per million concentrations of HCl indicate that extremely low HCl concentrations are thermodynamically achievable. Reaction kinetics considerations indicate that the diffusion through the product layer NaCl will be the ratelimiting step for achieving these extremely low equilibrium HCl concentrations. Hence, high surface-area sorbents are necessary to achieve both higher reactivity and reasonable sorbent capacities. In fact, commercially available chloride guards achieve sub-parts per million levels of HCl in petroleum refinery streams, but are relatively expensive. SRI observed that an HCl level of 0.3 ppm could be achieved at 550 C using Katalco Chloride Guard 59-3 [15]. In an HCl removal process, the highly reactive HCl reacts with all treatment materials to produce stable chloride materials that cannot be regenerated. Thus, HCl treatment materials are assumed to be once-through disposable materials. A number of alkali minerals have been shown to be very effective for HCl removal at temperatures between 550 and 650 C with real coal-derived syngas. Because these alkali minerals are available as natural deposits, these materials can be converted into HCl sorbents with minimal processing cost. Their primary disadvantage is that they are less reactive than commercially produced materials, particularly at lower temperatures. These minerals typically have lower surface areas that rapidly become covered with an NaCl product layer, reducing the reactivity of the sorbent. Although the commercial materials are more reactive, they are also significantly more expensive. 4.2.6

Tars

Tar removal, conversion, or destruction is seen as one of the greatest technical challenges to overcome for the successful development of commercial advanced biomass gasification technologies [35]. Tars can condense in exit pipes and on particulate filters, leading to blockages and clogged filters. Tars also have varied impacts on other downstream processes. Tars can clog fuel lines and injectors in internal combustion engines. Luminous combustion and erosion from soot formation can occur in pressurized combined-cycle systems where the product gases are burned in a gas turbine. The product gas from an atmospheric-pressure gasification process needs to be compressed before it is burned in a gas turbine, and tars can condense in the compressor or in the transfer lines as the product gas cools. Tar mitigation methods can be classified as physical, thermal, or catalytic processes. If the end use of the gas requires cooling to near-ambient temperatures, it is possible to use a number of physical removal methods, including wet scrubbing and filtration, to remove tars. Wet scrubbing to condense the tars out of the product gas is an effective gas conditioning technology that is commercially available and can be optimized for tar removal. A disadvantage of wet scrubbing for product gas conditioning is the formation and accumulation of wastewater. This technique does not eliminate tars, but merely transfers the problem from the gas phase to the condensed phase. Wastewater minimization and treatment are important considerations when wet scrubbing is used for tar removal. Also, when tar is removed from the product gas stream, its fuel value is lost, and the overall energy efficiency of the integrated gasification process is reduced. If the end use requires that the product gas remains at high temperature, at or slightly below the gasifier exit temperature, then some method of hot gas cleaning will be needed for tar elimination. Hot gas conditioning eliminates tars by converting them into desired

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product gas components and, thus, retains their chemical energy in the product gas and avoids treatment of an additional waste stream. Thermal cracking is a hot gas conditioning option, but to achieve high tar conversion efficiencies it requires temperatures higher than typical gasifier exit temperatures (H1100 C). Increased temperatures for thermal cracking of tars can come from adding oxygen to the process and consuming some of the product gas to provide additional heat. Thermal destruction of tars may also produce soot, which is an unwanted impurity in the product gas stream. 4.2.6.1 Thermal Cracking Thermal cracking of hydrocarbons is a well-established technology using solid acid catalysts such as silica–alumina and zeolites. In fact, any catalyst with strong acid sites will crack hydrocarbons at temperatures above 200 C. Aromatics present during hydrocarbon cracking usually lead to higher molecular weight hydrocarbons and coke [36]. Gil et al. [37] have studied the use of spent FCC catalyst in the gasifier as a way of reducing tar content of the effluent gas. They found that use of the spent FCC catalyst resulted in a reduction of tar from 20 to 8.5 g/Nm3 at 800–820 C, compared with a reduction of tars from 20 to 2 g/Nm3 at the same temperature when dolomite was used. Fresh or equilibrium FCC catalyst was much more active for cracking than spent FCC catalyst. Even so, the results were not conclusive. Because of the small particle size (70 mm), the spent FCC catalyst was quickly elutriated out of the gasifier. Elutriation did not occur as fast for the larger (400–1000 mm) dolomite particles. Tar cracking occurred with the spent and fresh FCC catalysts, whereas steam reforming was the apparent process with the dolomite. Because tars are polycyclic aromatics or their precursors, cracking the tars would be expected to deposit coke on the catalyst extensively. The coke would be burned in a regenerator and provide process heat to recover activity before the catalyst is returned to the cracker. 4.2.6.2 Hydrogenation An alternate way of tar elimination could be by hydrogenolysis, or ring opening, of the polyaromatics. Unfortunately, hydrogenolysis, or ring-opening activity, is thermodynamically limited, with conversion decreasing with increasing temperature. However, at temperatures as low as 200 C, catalysts such as Rh, Pt, Ir, and Ru have shown little ring-opening activity for naphthalene, suggesting that hydrogenolysis for tar elimination is not a technically viable option [38, 39]. 4.2.6.3 Steam Reforming An attractive hot gas conditioning method for tar destruction is catalytic steam reforming [31, 40–46]. This technique offers several advantages: catalyst reactor temperatures can be thermally integrated with the gasifier exit temperature, the composition of the product gas can be catalytically adjusted, and steam can be added to the catalyst reactor to ensure complete reforming of tars. Catalytic tar destruction has been studied for several decades [47–50], and a number of reviews have been written on biomass gasification hot gas cleanup [35, 40, 44, 45, 51]. Numerous catalysts have been tested for tar destruction activity at a broad range of scales, and novel catalyst formulations have been sought to increase the activity and lifetime of tar-reforming catalysts. Different approaches have been investigated for integrating catalytic tar destruction into biomass gasification systems.

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Steam reforming of hydrocarbons to produce CO þ H2 is highly endothermic and usually incorporates nickel supported catalysts on thermal-resistant, silicon-free supports such as a-alumina, MgAl spinel, or ZrO2. Such nickel catalysts are poisoned by sulfur, thus requiring the level of sulfur to be kept at less than 10–20 ppmv. Nickel catalysts may contain promoters such as iron, ruthenium, manganese, potassium, or barium. Selective steam reforming can be done on aromatic hydrocarbons. Mainly alkyl groups are split off by steam; thus, the process is also called steam dealkylation. Use of dolomite (CaO–MgO), either in the biomass gasifier or in a reactor downstream from the gasifier, decreases tar concentration in the effluent stream. Gil et al. [37] found that adding dolomite to the gasifier reduced tar from 20 g/m3 to 2 g/m3 at 800–820 C. They hypothesized that dolomite acts as a base catalyst and catalyzes steam reforming of the tars. CaO also appears to catalyze steam reforming of higher hydrocarbons [7]. Calcined dolomites are the most widely used nonmetallic catalysts for tar conversion in biomass gasification processes [52–58]. They are relatively inexpensive and are considered disposable; however, they are not very robust and quickly undergo attrition in fluidized-bed reactors. Consequently, dolomites find most use in fixed-bed catalytic reactors. Tar conversion efficiency is high when calcined dolomites are operated at high temperatures (900 C) with steam. Olivine, another naturally occurring mineral, has also demonstrated tar conversion activity similar to that of calcined dolomite [55, 59]. Olivine is a much more robust material than calcined dolomite and has been applied as a primary catalyst to reduce the output tar levels from fluidized-bed biomass gasifiers. Commercial nickel catalysts are designed for use in fixed-bed applications and are not robust enough for fluidized-bed applications; therefore, they are not useful as primary, inbed catalysts. These catalysts, however, have been extensively used for biomass gasification tar conversion as secondary catalysts in separate fixed-bed reactors operated independently to optimize performance [60–62]. They have high tar destruction activity with the added advantages of completely reforming methane and WGS activity that allows the H2:CO ratio of the product gas to be adjusted. Some studies have also shown that nickel catalyzes the reverse ammonia reaction, thus reducing the amount of NH3 in gasification product gas. A limitation of nickel catalyst use for hot gas conditioning of biomass gasification product gases is rapid deactivation, which leads to limited catalyst lifetimes [63]. Causes of nickel catalyst deactivation include sintering, coke formation, and poisoning. Sulfur, chlorine, and alkali metals that may be present in gasification product gases are catalyst poisons. Coke formation on the catalyst surface can be substantial when tar levels in product gases are high. Coke can be removed by regenerating the catalyst; however, repeated high-temperature processing of nickel catalysts can lead to sintering, phase transformations, and volatilization of the nickel. Using fixed dolomite guard beds to lower the input tar concentration can extend nickel catalyst lifetimes. Adding various promoters and support modifiers has been demonstrated to improve catalyst lifetime by reducing catalyst deactivation that occurs through coke formation, sulfur and chlorine poisoning, and sintering. Several novel, nickel-based catalyst formulations have been developed that show excellent tar reforming activity, improved mechanical properties for fluidized-bed applications, and enhanced lifetimes. Hot gas conditioning using current or future commercially available catalysts offers a promising solution for mitigating biomass gasification tars. Tars are eliminated, methane can be reformed if desired, and the H2:CO ratio can be adjusted in a single step. The best

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currently available tar reforming process consists of a calcined dolomite guard bed followed by a fixed-bed nickel catalyst reforming reactor operating at about 800 C. Selection of the ideal nickel catalyst is somewhat premature. Commercially available steam-reforming catalysts have been demonstrated; however, several of the novel research catalysts appear to have the potential of longer lifetimes [64, 65]. This dual-bed hot gas conditioning concept has been demonstrated and can be used to condition the product gas from any developing gasification process. A proprietary nickel monolith catalyst has also shown considerable promise for biomass gasification tar destruction [31, 66, 67].

4.3

Syngas Utilization

In its simplest form, syngas is composed of two diatomic molecules, CO and H2, that provide the building blocks upon which an entire field of fuel science and technology is based [68–73]. The synthesis of hydrocarbons from CO hydrogenation was discovered in 1902 by Sabatier and Sanderens, who produced methane by passing CO and H2 over nickel, iron, and cobalt catalysts. At about the same time, the first commercial hydrogen from syngas produced from steam methane reforming was commercialized. Haber and Bosch discovered the synthesis of ammonia from H2 and N2 in 1910, and the first industrial ammonia synthesis plant was commissioned in 1913. The production of liquid hydrocarbons and oxygenates from syngas conversion over iron catalysts was discovered in 1923 by Franz Fischer and Hans Tropsch. Variations on this synthesis pathway were soon to follow for the selective production of methanol, mixed alcohols, and isosynthesis products. Another outgrowth of Fischer–Tropsch synthesis (FTS) was the hydroformylation of olefins discovered in 1938. The syngas composition, most importantly the H2:CO ratio, varies as a function of production technology and feedstock. Steam methane reforming yields H2:CO ratios of 3:1, while coal and biomass gasification yield ratios closer to unity or lower. Conversely, the required properties of the syngas are a function of the synthesis process. Fewer moles of product almost always occur when H2 and CO are converted to fuels and chemicals. Consequently, syngas conversion processes are more thermodynamically favorable at higher H2 and CO partial pressures. The optimum pressure depends on the specific synthesis process. Catalytic syngas conversion processes are exothermic and generate large excesses of heat. This highlights the specific need for removing this heat of reaction to carefully control reaction temperatures and maintain optimized process conditions. Maximizing product yields, minimizing side or competing reactions, and maintaining catalyst integrity dictate optimum synthesis reaction temperatures. Since the genesis of syngas conversion to fuels and chemicals, a tremendous amount of research and development have been devoted to optimizing product yields and process efficiencies. This includes the discovery of catalysts with optimized formulations containing the most active metals in combination with appropriate additives to improve activity and selectivity in a given process. Mechanistic studies have been conducted to interpret the fundamentals of specific conversion processes and measure the kinetic rates of key chemical reactions. Reactor design and engineering is another active research and development area of syngas conversion technology. Temperature control and stability in conversion reactors

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Syngas Cleanup, Conditioning, and Utilization

are critical process parameters because of the large excess heat from the reaction. Detailed process engineering and integration (with respect to heat integration and syngas recycle to improve conversion efficiencies) are used to optimize commercial synthesis processes. Given the rich history of syngas conversion and the extensive research and development efforts devoted to this field of study, it is not surprising that a vast amount of literature is available that tracks the scientific and technological advancements in syngas chemistry. A summary of some of the relevant syngas conversion processes follows, with references to recent literature. 4.3.1

Syngas to Gaseous Fuels

4.3.1.1 Hydrogen Steam methane reforming accounts for 95% of the hydrogen produced in the USA [74], and this hydrogen is often consumed captively for ammonia production, in oil refineries, and by methanol producers. Hydrogen can also be produced by reforming other hydrocarbon feedstocks, including naphtha, heavy residues from petrochemical processes, coke oven gas, and coal. Partial oxidation and autothermal reforming of hydrocarbons are alternative technologies to steam methane reforming. Presently, 77% of the worldwide hydrogen production comes from petrochemicals, 18% from coal, 4% from water electrolysis, and 1% from other sources [75]. Renewable hydrogen technologies are becoming increasingly more attractive as greenhouse gas emissions are regulated to reduce the impact of energy use on global climate change. Water electrolysis for hydrogen production can have a very small carbon footprint if renewable electricity (wind or solar power) or nuclear power is used to generate the electricity. Bio-hydrogen processes are also being developed and include biomass gasification, aqueous-phase reforming of biomass-derived sugars, and biological hydrogen production (fermentation and photolysis). A recent review summarizes these fossil and renewable hydrogen production technologies and others [76]. As mentioned, the dominant technology for hydrogen production today is steam methane reforming. The process can be divided into the following four steps: feed pretreatment, steam reforming, CO shift conversion, and hydrogen purification. For natural gas the only pretreatment required is desulfurization, which usually consists of a hydrogenator followed by a zinc oxide bed. After desulfurization, natural gas is fed to a reformer reactor, where it reacts with steam to produce CO, CO2, and H2. The reformer reactor is comprised of catalyst-filled tubes, surrounded by a firebox that provides the heat necessary for the endothermic reforming reaction, which operates at about 850 C and between 1.5 and 3 MPa. The gas exiting the reformer is cooled to about 350 C to maximize the WGS reaction in a high -temperature shift (HTS) converter. The gas can be further cooled to about 220 C and introduced into a low-temperature shift (LTS) converter, followed by CO2 scrubbing (e.g., monoethanolamine or hot potash). A methanation reactor is used to remove trace amounts of CO and CO2 (CO þ 3H2 ! CH4 þ H2O). The final hydrogen product has a purity of 97–99%. For higher purity hydrogen production, a pressure swing adsorption (PSA) unit is used downstream of the HTS converter. The PSA unit can easily remove CO and other components to produce a high purity (99.99%) hydrogen stream. The PSA off-gas – which contains unreacted CH4, CO, and CO2, plus unrecovered hydrogen – is used to fuel the

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91

Heat Pre-heater Natural Gas

Recovery Syngas (H2, CO, CO2)

Steam Reforming

Shift Reactors (High and Low T)

Compressor Sulfur Removal Oxygen Steam

Pressure Swing Absorption

Hydrogen

PSA Purge Gas

Figure 4.1 Block flow diagram of hydrogen via steam methane reforming

reformer. This stream usually supplies 80–90% of the reformer heat duty, supplemented by natural gas to balance the remaining heat requirement. Figure 4.1 shows a process flow diagram of this process. Chemistry. Steam reforming hydrocarbons involves the catalytic conversion of a hydrocarbon feedstock and steam to hydrogen and carbon oxides. Generally speaking, the chemical process for steam reforming of hydrocarbons is described by the following equation [75]: Cn Hm þ nH2 O ! ðn þ m2 ÞH2 þ nCO WGS is another important reaction that occurs in the reformer. For steam methane reforming, the following two reactions occur in the reformer: CH4 þ H2 O ! 3H2 þ CO

DHr ¼ 49:3 kcal=mol

CO þ H2 O ! H2 þ CO2

DHr ¼ 9:8 kcal=mol

Therefore, in this case 50% of the hydrogen comes from the steam. The reforming reaction is highly endothermic and is favored by high temperatures and low pressures. Higher pressures tend to lower the methane conversion. In industrial reformers, the reforming and shift reactions result in a product composition that closely approaches equilibrium. The following side reactions produce carbon in the steam reformer: 2CO ! CðsÞ þ CO2

ðBoudouard cokingÞ

CO þ H2 ! CðsÞ þ H2 O

ðCO reductionÞ

CH4 ! CðsÞ þ 2H2

ðmethane crackingÞ

The reformer molar steam to carbon ratio is usually 2:6, depending on the feedstock and process conditions. Excess steam is used to prevent coking in the reformer tubes. The shift reaction is exothermic and favors low temperatures. Since it does not approach completion in the reformer (usually there is 10–15% by volume CO, dry basis, in the reformer effluent), further conversion of CO is performed using shift conversion catalysts.

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Catalysts. Conventional steam reforming catalysts are 10–33% by weight NiO on a mineral support (alumina, cement, or magnesia). Reforming catalyst suppliers include BASF, Dycat International, Haldor Topsøe, Johnson Matthey Synetix (formerly ICI Katalco), and S€ ud Chemie (formerly United Catalysts). Heavy feedstocks tend to coke the reforming catalyst, but promoters (potassium, lanthanum, ruthenium, and cerium) may be used to help this problem. These promoters increase steam gasification of solid carbon, thereby reducing coke formation but also reducing the reforming activity of the catalyst. For feedstocks heavier than naphtha, nickel-free catalysts containing mostly strontium, aluminum, and calcium oxides have been successfully tested [75]. However, the methane content in the exiting gas is high, requiring a secondary reformer. HTS catalyst has an iron oxide–chromium oxide basis, while the major component in the LTS catalyst is copper oxide usually mixed with zinc oxide [75]. The HTS reactor operates in the temperature range 300–450 C,while the LTS is in the range 180–270 C. Often, the LTS reactor operates near condensation conditions. Typical catalyst lifetimes for both HTS and LTS catalysts are 3–5 years. Sulfur-tolerant or “sour shift” catalysts have also been developed that have high activity with larger concentrations of sulfur in the reactant gas. ICI Katalco makes dirty shift conversion catalysts that consist of cobalt and molybdenum oxides. They operate over a temperature range of 230–500 C. The controlling factors are the ratio of steam to sulfur in the feed gas and the catalyst temperature. Pressure Swing Adsorption. About 65–75% of the CO and steam in the feed stream to the HTS reactor are converted to additional H2 and CO2. When an LTS reactor is used to convert additional CO to H2, about 80–90% of the remaining CO is converted to H2, increasing the H2 yield about 5%. For the PSA unit, the minimum pressure ratio between the feed and purge gas is about 4:1, and the purge gas pressure is typically between 17 and 20 psi (0.12–0.14 MPa) to obtain a high recovery of hydrogen. Hydrogen recovery is usually 85–90% at these conditions and drops to 60–80% at high purge gas pressures (55–95 psi, 0.38–0.66 MPa). The PSA efficiency is also affected by adsorption temperature. Fewer impurities are adsorbed at higher temperatures, because the equilibrium capacity of the molecular sieves decreases with increasing temperature. Additionally, nitrogen is weakly adsorbed onto the adsorbent bed in the PSA unit, reducing the hydrogen recovery rate for the same purity. The hydrogen recovery may be reduced by as much as 2.5% for a 10 ppm nitrogen concentration in the PSA feed stream. Membrane Separation (Palladium and Polymers). Research into in situ H2 membranes has focused primarily on three types of membrane: microporous membranes [77], palladium-based membranes [78–82], and dense ceramic membranes [83, 84]. The primary challenges faced by these membrane materials include . . . .

maximizing H2 selectivity; maximizing H2 flux; minimizing membrane failure caused by thermal cycling or chemical interactions; and minimizing membrane cost.

Table 4.2 summarizes the particular advantages and disadvantages for these three types of membrane.

300–600 H90 100 High, tolerant to sulfur, some form carbonates with CO2 at high temperatures High

Low

Temperature ( C) H2 purity (%) H2 fluxa Chemical stability

Cost

Pd, Pd–Cu, Pd–Ag on stainless steel or ceramic 300–750 100 36 Low, Pd easily poisoned by sulfur and CO, alloy causes defects and side reactions Low, embrittled by H2 at G300  C; phase change at high temperature reduces H2 flux; Pd alloys preferred High (pure Pd) to medium (alloy)

Metallic and metallic alloy membrane

H2 flux is expressed as cubic feet of hydrogen per square foot of membrane area per 100 lbs (psi) of pressure drop.

a

Thermal stability

Silica on ceramic, zeolites

Typical materials

Microporous membrane

Table 4.2 Comparison of membrane technologies for hydrogen separation

Medium

Medium, phase change inhibited

Low

High

900 100 2 High

Perovskite, silica

Pd mixed with dense ceramic 400–600 100 36 Medium, tolerant to impurities

Dense ceramic membrane

Ceramic membrane

Syngas Utilization 93

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Syngas Cleanup, Conditioning, and Utilization

One generic disadvantage of all these in situ H2 membrane systems is that the H2-rich product is recovered at low pressure. Although this might be acceptable for fuel-cell applications, it is not particularly attractive for other applications where a high-pressure H2 product is necessary. A reasonable solution would simply be to compress the H2-rich product to the desired pressure. However, because of its small molecular size, H2 requires significantly more effort to compress. Thus, the cost and advantages of in situ H2 membranes must outweigh the associated energy and capital costs for compressing a highly H2-rich product to a useful operating pressure. Because the primary function of the membrane is to remove H2, allowing more complete shift of the CO into H2 in a single reactor, this additional shift activity will also result in additional heat release. Thus, to avoid excessive temperature rise in the catalyst bed that would cause sintering and rapid deactivation of the catalyst, the membrane reactor design will require the ability to remove heat effectively. This represents a significant challenge in a fixed-bed reactor system, since typical fixed-bed systems tend to have hot spots that result from less-than-ideal mixing of the gases, subtle variations in the catalyst activity, and natural heat flow in the system. 4.3.1.2 Substitute Natural Gas During the 1970s, ExxonMobil conducted an R&D program aimed at producing substitute natural gas (SNG) from coal. The equilibrium methane yields for the SNG process as a function of temperature and pressure are shown in Figure 4.2. Coal impregnated with an

Figure 4.2 Equilibrium methane yields for the SNG process as a function of temperature and pressure

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95

alkali metal salt catalyst (typically K2CO3) was introduced into a fluidized bed reactor [85] operating at temperatures between 593 and 815 C. The coal was gasified in the presence of steam and recycled H2 and CO to produce a product gas composed primarily of CH4, CO2, H2, and CO. This product gas was separated in a cryogenic separation train into an SNG product stream and a recycle stream, containing H2 and CO. The char from the gasification reactor was washed to recover the alkali metal catalyst for reuse. The ability to catalyze the conversion of coal into CH4 and CO2 at this lower temperature range had several benefits. The first was that CH4 was one of the most abundant components in the raw gasifier effluent. The second was that cheaper and more conventional materials of construction could be used instead of the more costly and exotic alloys required by competing gasification technologies. However, operating in this temperature range also had disadvantages. The alkali metal catalyst reacted with the mineral ash in the coal and reduced the amount of catalyst that was recovered. This required a more complex and costly recovery processes for the alkali metal catalyst. Ultimately, the catalyst recovery and replacement costs could not be reduced enough to make the process economically competitive. Although the lower operating temperatures favor a CH4-rich product gas, the lower temperatures also result in slower reaction kinetics. Increasing the operating temperature would increase the carbon conversion rate, but this would also increase the rate of the competing reaction between the catalyst and ash, resulting in greater catalyst losses. Similarly, adding more active catalyst would improve the coal conversion reaction rate, but this also increases the amount of catalyst that is available to react with the coal ash, hindering the catalyst recovery process even more. ExxonMobil determined that the optimum catalyst concentration was about 15–20% by weight. Furthermore, additional R&D demonstrated that coal type and origin significantly influenced the coal conversion process. Sub-bituminous western coals, generally with high moisture content, were identified as the most reactive for this process. ExxonMobil was able to demonstrate this process successfully at the pilot-plant scale. However, unfavorable process economics prevented any further scale up and commercialization. The measured catalyst losses due to reaction with the coal ash and the high cost associated with cryogenic separation of the SNG product and the recycle stream made the process too costly compared with traditional natural gas recovery. The dramatic increase in the price of natural gas in the late 1990s prompted a renewed interest in the production of SNG. A summary of the various coal-based technologies available is shown in Table 4.3. Many of these technologies were demonstrated at the pilot scale in the 1970s but were abandoned, as declining natural gas prices eliminated any cost benefit associated with these alternative technologies. Higher and fluctuating natural gas prices and growing concerns about the impact of fossil CO2 emissions on global climate change have also prompted interest in producing SNG from renewable biomass resources [93–97]. Conventional catalytic biomass gasification is a technology option that builds on the development experience with coal-based gasification processes [97]. Hydrothermal treatment processes are also being developed to convert higher moisture content biomass feedstocks and waste materials into methane-rich product gases. Nickel or ruthenium catalysts are co-mixed with biomass and water. The mixture is heated to around 300–400 C at high pressure (sub- or super-critical water pressures) to produce a methane-rich gas.

Gasifier operation

Moving bed

Low temperature (700 C); 500 psig; catalytic fluidized bed; H2 and CO recycled

Low temperature (700 C); 300 psig; catalytic gas; H2 and CO recycled

900 C; 1,000 psig; entrained flow hydrogasification; H2 recycled

H1000 psig; 800  C; two-stage fluidized bed

Process

Lurgi (Dakota Gasification Company) [86]

Exxon Mobile catalytic gasification [87]

Nahas Process [88]

ARCH hydrogasification [89]

HYGAS (IGT) [90, 91]

Table 4.3 Comparison of SNG production technologies

Slurry feed using by-product oil

Produces approximately 12% methane in gasifier; CO shifted to H2 before methanation; CO2 removal by Rectisol Catalyst added to coal; must be recovered from ash; cryogenic separation of H2 and CO required Only suitable for no-ash materials (e.g., petroleum residues or coal pyrolysis products) “Dense phase” pulverized coal feed

Key elements

Requires separate “partial combustion gasifier” to produce syngas, which is shifted to supply H2 for the hydrogasifier Requires imported hydrogen (e.g., from steam–iron process); caking coals require pretreatment.

Incomplete separation of the relatively expensive catalyst from the ash affected process economics Conceptual design, but no experimental data to prove the concept.

Gas cooling (with energy recovery, prior to Rectisol); extensive commercial experience

Notes

96 Syngas Cleanup, Conditioning, and Utilization

Produces syngas for feed to methanation reactor; no WGS required Syngas must be shifted somewhat prior to methanation; char combusted to produce steam Requires shift and methanation

150 psig; 800  C; fluidized bed; heat supplied by hot dolomite

500–1000 psig; 1000  C; dense-phase fluidized bed

Two-stage reactor: entrained coal devolatilization in upper stage at 900  C; slagging combustion in lower stage at 1500  C

CO2 acceptor (Conoco) [92]

Synthane [92]

Bi-Gas [92]

Rapid devolatilization in upper reactor produces methane; char separated in cyclone for return to lower stage

Applicable to lignite; requires separate char combustor to heat and regenerate dolomite Caking coals require (inline) fluidized bed pretreatment at gasifier pressure

Syngas Utilization 97

98

4.3.2

Syngas Cleanup, Conditioning, and Utilization

Syngas to Liquid Fuels

4.3.2.1 Fischer–Tropsch Synthesis In 1923, Fischer and Tropsch reported the use of alkalized iron catalysts, in what was termed the Synthol process, to produce liquid hydrocarbons rich in oxygenated compounds. Following these initial discoveries, considerable effort went into developing catalysts for this process. A precipitated cobalt catalyst with 100 parts by weight Co, 5 parts ThO2, 8 parts MgO, and 200 parts kieselguhr (siliceous diatomaceous earth) became known as the “standard” atmospheric-pressure process catalyst. In 1936, Fischer and Pilcher developed the medium pressure (10–15 bar, 0.07–0.10 MPa) FTS process. Following this development, alkalized iron catalysts were implemented into the medium-pressure FTS process. Collectively, the process of converting CO and H2 mixtures to liquid hydrocarbons over a transition metal catalyst has become known as the FTS. Two main characteristics of FTS are the unavoidable production of a wide range of hydrocarbon products and the liberation of a large amount of heat from the highly exothermic synthesis reactions. Consequently, reactor design and process development have focused heavily on heat removal and temperature control. The focus of catalyst development is on improved catalyst lifetimes, activity, and selectivity. Single-pass FTS always produces a wide range of olefins, paraffins, and oxygenated products, such as alcohols, aldehydes, acids, and ketones, with water as a by-product. Product distributions are influenced by temperature, feed gas composition (H2/CO), pressure, catalyst type, and catalyst composition. Product selectivity can also be improved using multiple-step processes to upgrade the FTS products. In a review by Frohning et al. [98], it was cited that, by 1954, upwards of 4000 publications and a similar number of patents dealing with FTS could be found in the literature. Since then, FTS has attracted an enormous amount of research and development effort. A comprehensive bibliography of FTS literature, including journal and conference articles, books, government reports, and patents can be found in the Fischer–Tropsch Archive at www.fischer-tropsch.org. This website is sponsored by Syntroleum Corporation in cooperation with Dr. Anthony Stranges, Professor of History at Texas A&M University, and contains more than 7500 references and citations. This site has collected a bibliography of the large body of documents (from the 1920s through to the 1970s), which are important for researching the history and development of FTS and related processes, as well as an upto-date listing of the latest publications in this field. Many excellent reviews of FTS are available [99–101], and this section attempts to summarize, the chemistry [98], catalyst development [102, 103], commercial processes [100, 104–106], reactor development [101, 107–109], and economics [110, 111] of FTS. There are four main steps to producing Fischer–Tropsch products: syngas generation, gas purification, Fischer–Tropsch synthesis, and product upgrading. See Figure 4.3 for a generic process flow diagram. When using natural gas as the feedstock, many authors [112–114] have recommended autothermal reforming or autothermal reforming in combination with steam reforming as the best option for syngas generation. This is primarily because of the resulting H2 to CO ratio and the more favorable economy of scale for air separation units than for tubular steam reforming reactors. If the feedstock is coal, the syngas is produced via high-temperature gasification in the presence of oxygen and steam. Depending on the types and quantities of Fischer–Tropsch products desired, either

Syngas Utilization Air Oxygen Steam

Syngas Production

99

Low T FTS Particulate Removal Tar Conversion (Cracking or Reforming) Wet Scrubbing Gas Cleanup and Conditioning

Slurry Phase or Tubular Reactors Cobalt or Iron Catalysts

Diesel

Olefins (C3-C11) Oligomerization Isomerization Hydrogenation

Gasoline

Clean Syngas (H2 and CO)

Sulfur Removal Water Gas Shift

High T FTS Circulating or Fast Fluid Bed Reactors Iron Catalysts

Natural Gas Coal Biomass

Figure 4.3

Wax (> C20) Hydroprocessing

FTS general process flow diagram

low-temperature (200–240 C) or high-temperature (300–350 C) synthesis is used with either an iron or cobalt catalyst. FTS temperatures are usually kept below 400 C to minimize CH4 production. Generally, cobalt catalysts are used only at low temperatures, because at higher temperatures a significant amount of methane is produced. Low temperatures yield high molecular mass linear waxes, while high temperatures produce gasoline and low molecular weight olefins. If maximizing the gasoline product fraction is desired, then it is best to use an iron catalyst at a high temperature in a fixed fluid-bed reactor. If maximizing the diesel product fraction is preferred, then a slurry reactor with a cobalt catalyst is the best choice. The Fischer–Tropsch reactors are operated at pressures ranging from 10 to 40 bar (145–580 psi, 1–4 MPa). Upgrading usually means a combination of hydrotreating, hydrocracking, and hydroisomerization in addition to product separation. Chemistry. FTS has long been recognized as a polymerization reaction with the basic steps of (1) reactant (CO) adsorption on the catalyst surface, (2) chain initiation by CO dissociation followed by hydrogenation, (3) chain growth by insertion of additional CO molecules followed by hydrogenation, (4) chain termination, and (5) product desorption from the catalyst surface. Chemisorbed methyl species are formed by dissociation of absorbed CO molecules and stepwise addition of hydrogen atoms. These methyl species can further hydrogenate to form methane or act as initiators for chain growth. Chain growth occurs via sequential addition of CH2 groups, while the growing alkyl chain remains chemisorbed to the metal surface at the terminal methylene group. Chain termination can occur at any time during the chain growth process to yield either an a-olefin or an n-paraffin once the product desorbs. The following is the FTS reaction [106]: CO þ 2H2 ! CH2  þ H2 O

DHr ð227  CÞ ¼ 165 kJ=mol

The WGS reaction is a secondary reaction that readily occurs when iron catalysts are used. The required H2 to CO ratio for the cobalt catalyst is 2:1, but since the iron catalyst performs

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Syngas Cleanup, Conditioning, and Utilization

WGS in addition to the Fischer–Tropsch reaction, the H2 to CO ratio can be slightly lower (0.7:1) for the iron catalyst. Specific FTS products are synthesized according to the following reactions: CO þ 3H2 ! CH4 þ H2 O

ðmethanationÞ

nCO þ ð2n þ 1ÞH2 ! Cn H2n þ 2 þ nH2 O

ðparaffinsÞ

nCO þ 2nH2 ! Cn H2n þ nH2 O

ðolefinsÞ

nCO þ 2nH2 ! Cn H2n þ 1 OH þ ðn1ÞH2 O

ðalcoholsÞ

Another competing reaction that becomes important in FTS is the Boudouard reaction that leads to carbon deposition on the catalyst surface, causing deactivation. FTS is kinetically controlled, and the intrinsic kinetics is stepwise chain growth, in effect the polymerization of CH2 groups on a catalyst surface. FTS product selectivities are determined by the ability to catalyze chain propagation versus chain termination reactions. The polymerization rates, and therefore kinetics, are independent of the products formed. The probability of chain growth and chain termination is independent of chain length. Therefore, selectivities of various hydrocarbons can be predicted based on simple statistical distributions calculated from chain growth probability and carbon number. The chain polymerization kinetics model known as the Anderson–Shulz–Flory (ASF) model is represented by the following equation: Wn ¼ nð1aÞ2 an1 where Wn is the weight percent of a product containing n carbon atoms and a is the chain growth probability. This equation is represented graphically in Figure 4.4 and displays the predicted distributions for several products and product ranges of particular interest. The Fischer–Tropsch reaction produces a range of olefins, paraffins, and oxygenated compounds (alcohols, aldehydes, acids, and ketones) that are predominantly linear with a high percentage of olefinic hydrocarbons. In fact, the paraffin-to-olefin ratio is lower than thermodynamically predicted. The olefins that do form are predominantly terminal (alpha).

Figure 4.4 (a) Weight fraction of hydrocarbon products as a function of chain growth (propagation) probability during FTS. (b) Percentage of different hydrocarbon product cuts as a function of chain growth (propagation) probability showing a range of operation for classical and developing Fischer–Tropsch catalysts and synthesis

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A considerable amount of monomethyl chain branches form, and the degree of branching decreases as the chain length increases. Theoretically, only methane can be produced with 100% selectivity. The only other product that can be produced with high selectivity is heavy paraffin wax. The gasoline product fraction has a maximum selectivity of 48%, and the maximum diesel product fraction selectivity is closer to 40% and varies depending on the range of carbon numbers in the product cut. The variables that influence the distribution of these products are reactor temperature, pressure, feed gas composition, catalyst type, and promoters. Catalysts. Group VIII transition metal oxides are generally regarded as good CO hydrogenation catalysts. The relative activity of these metals for FTS, in decreasing order of activity, is Ru H Fe H Ni H Co H Rh H Pd H Pt [108]. Nickel is basically a methanation catalyst and does not have the broad selectivity of other Fischer–Tropsch catalysts. Ruthenium has very high activity and quite high selectivity for producing high molecular weight products at low temperatures. Iron is also very active and has WGS activity. Iron readily forms carbides, nitrides, and carbonitrides with metallic character that also have FTS activity. Iron also has a stronger tendency than nickel or cobalt to produce carbon that deposits on the surface and deactivates the catalyst. Cobalt tends to have a longer lifetime than iron catalysts and does not have WGS activity, which leads to improved carbon conversion to products because CO2 is not formed. Cobalt catalysts in FTS yield mainly straight-chain hydrocarbons (no oxygenates like iron). Although ruthenium is the most active FTS catalyst, it is 3  105 times more expensive than iron. Iron is by far the cheapest FTS catalyst of all of these metals. Cobalt catalysts are 230 times more expensive than iron but are still an alternative to iron catalysts for FTS because they demonstrate activity at lower synthesis pressures – so higher catalyst costs can be offset by lower operating costs. The three key properties of Fischer–Tropsch catalysts are lifetime, activity, and product selectivity. Optimizing these properties for desired commercial application has been the focus of Fischer–Tropsch catalyst research and development since the processes were first discovered. Each one of these properties can be affected by a variety of strategies, including the use of promoters (chemical and structural), catalyst preparation and formulation, pretreatment and reduction, selective poisoning, and shape selectivity with zeolites. The performance of cobalt catalysts is not very sensitive to the addition of promoters. Early work demonstrated that the addition of ThO2 improved wax production at atmospheric pressure but had little effect at higher pressures. With iron catalysts, however, promoters and supports are essential catalyst components. Since the discovery of FTS, potassium has been used as a promoter for iron catalysts to effectively increase the basicity of the catalyst surface. The objective is to increase the adsorption of CO to the metal surface, which tends to withdraw electrons from the metal by providing an electron donor. Potassium oxide addition to iron catalysts also tends to decrease hydrogenation of adsorbed carbon species, so chain growth is enhanced, resulting in a higher molecular weight product distribution that is more olefinic. Potassium promotion also tends to increase WGS activity and lead to a faster rate of catalyst deactivation because of the increased rate of carbon deposition on the surface of the catalyst. Copper has also been successfully used as a promoter in iron FTS catalysts. Although it increases the rate of FTS more effectively than potassium, it decreases the rate of the WGS reaction. Copper has also been shown to facilitate iron reduction. The average molecular

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weight of the products increases in the presence of copper, but not as much as when potassium is used. (Potassium promotion is not effective for cobalt catalysts.) Catalyst preparation impacts the performance of iron and cobalt catalysts. Iron catalysts can be prepared by precipitation onto catalyst supports such as SiO2 or Al2O3 or as fused iron, where formulations are prepared in molten iron, then cooled and crushed. The role of supports in cobalt catalysts is also important. Since cobalt is more expensive than iron, precipitating the ideal concentration of metal onto a support can help reduce catalyst costs while maximizing activity and durability. The combination of light transition metal oxides such as MnO with iron increases the selectivity of light olefins in FTS. Iron/manganese/potassium catalysts have shown selectivity for C2–C4 olefins as high as 85–90%. Noble metal addition to cobalt catalysts increases FTS activity but not selectivity. 4.3.2.2 Methanol Research and development efforts at the beginning of the twentieth century involving the conversion of syngas to liquid fuels and chemicals led to the discovery of a methanol synthesis process concurrently with the development of the FTS. In fact, methanol is a byproduct of FTS when alkali-metal-promoted catalysts are used. Methanol synthesis is now a well-developed commercial catalytic process with high activity and very high selectivity (H99%). The lowest cost process includes natural gas reforming to produce syngas followed by methanol synthesis (90% of the worldwide methanol [115]). However, a variety of feedstocks other than natural gas can be used. The long-time interest in methanol is due to its potential fuel and chemical uses. In particular, methanol can be used directly or blended with other petroleum products as a clean-burning transportation fuel. Methanol is also an important chemical intermediate used to produce formaldehyde, dimethyl ether (DME), methyl tert-butyl ether, acetic acid, olefins, methyl amines, and methyl halides, to name a few. Currently, the majority of methanol is synthesized from syngas that is produced via steam reforming of natural gas. It can also be reformed using autothermal reforming or a combination of steam methane reforming and autothermal reforming. Once the natural gas is reformed, the resulting synthesis gas is fed to a reactor vessel in the presence of a catalyst to produce methanol and water vapor. This crude methanol – which usually contains up to 18% water, plus ethanol, higher alcohols, ketones, and ethers – is fed to a distillation plant that consists of a unit that removes the volatiles and a unit that removes the water and higher alcohols. The unreacted syngas is recirculated back to the methanol converter, resulting in an overall conversion efficiency of over 99%. A generic methanol synthesis process flow diagram is shown in Figure 4.5. One of the challenges associated with commercial methanol synthesis is removing the large excess heat of reaction. Methanol synthesis catalyst activity increases at higher temperatures, but so does the chance for competing side reactions [116]. By-products of methanol formation are CH4, DME, methyl formate, higher alcohols, and acetone. Catalyst lifetimes are also reduced by continuous high-temperature operation, and process temperatures are typically maintained below 300 C to minimize catalyst sintering. Overcoming the thermodynamic constraint is another challenge in commercial methanol synthesis. The maximum per-pass conversion efficiency of syngas to methanol is limited to

Syngas Utilization

Pre-heater Natural Gas

Syngas (H2, CO, CO2)

103

Gas Cooling

Cooling and Distillation

Steam Reforming Compressor Compressor Desulfurization

Methanol Converter

Oxygen

Methanol

Syngas Recycle

Steam

Purge

Figure 4.5

Simplified methanol synthesis process flow diagram

25% [72]. Higher conversion efficiencies per pass can be realized at lower temperatures where the methanol equilibrium is shifted towards products; however, catalyst activities generally decrease as the temperature is lowered. Removing the methanol as it is produced is another strategy used for overcoming the thermodynamic limitations and improving the perpass conversion process efficiencies. Methanol is either physically removed (condensed out or physisorbed onto a solid) or converted to another product like DME, methyl formate, or acetic acid. Controlling and dissipating the heat of reaction and overcoming the equilibrium constraint to maximize the per-pass conversion efficiency are the two main process features that are considered when designing a methanol synthesis reactor, commonly referred to as a methanol converter. Numerous methanol converter designs have been commercialized over the years, and these can be roughly separated into two categories: adiabatic or isothermal reactors. Adiabatic reactors often contain multiple catalyst beds separated by gas-cooling devices, either direct heat exchange or injection of cooled, fresh, or recycled syngas. Axial temperature profiles often have a sawtooth pattern that is low at the point of heat removal and increases linearly between the heat exchange sections. The isothermal reactors are designed to remove the heat of reaction continuously, so they operate essentially like a heat exchanger with an isothermal axial temperature profile. A description of some of the many methanol converter designs can be found in the literature [73]. Chemistry. Catalytic methanol synthesis from syngas is a classic high-temperature, highpressure, exothermic, equilibrium-limited synthesis reaction. The chemistry of methanol synthesis is as follows [117]: CO þ 2H2 ! CH3 OH

DHr ¼ 90:64 kJ/mol

CO2 þ 3H2 ! CH3 OH þ H2 O

DHr ¼ 49:67 kJ/ mol

CO þ H2 O ! CO2 þ H2

DHr ¼ 41:47 kJ/ mol

For methanol synthesis, a stoichiometric ratio, defined as (H2CO2)/(CO þ CO2), of about 2 is preferred. This means that there will be just the stoichiometric amount of hydrogen

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needed for methanol synthesis. For kinetic reasons, and in order to control by-products, a value slightly above 2 is normally preferred [118]. Although methanol is made from mixtures of H2 and CO, the reaction is about 100 times faster when CO2 is present [72]. Until as recently as the 1990s, the role of CO2 in methanol synthesis was not clear. The WGS activity of copper catalysts is so high that it was difficult to deconvolute the role of CO and CO2 in methanol synthesis. Isotopic labeling studies have unequivocally proved that CO2 is the source of C in methanol [72, 119]. CO is involved in the reverse WGS reaction to make H2 and CO2. CO2 is also thought to keep the catalyst in an intermediate oxidation state Cu0/Cuþ, preventing ZnO reduction followed by brass formation [119]. The proposed mechanism for catalytic methanol synthesis is believed to proceed through a long-lived formate intermediate. CO2 is adsorbed on a partially oxidized metal surface as a carbonate and hydrogenated. This intermediate is then hydrogenated in the rate-limiting step. The copper catalyst sites have high activity for splitting the first C–O bond in CO2 that helps maintain the oxidation state of the active copper sites. At high concentrations, however, CO2 actually reduces catalyst activity by inhibiting methanol synthesis. The feed gas composition for methanol synthesis is typically adjusted to contain 4–8% CO2 for maximum activity and selectivity. Even though copper has WGS activity, excessive amounts of H2O also lead to active site blocking, which is poor for activity but improves selectivity by reducing by-product formation by 50% [120]. Catalysts. The first high-temperature, high-pressure methanol synthesis catalysts were ZnO/Cr2O3 and were operated at 350 C and 250–350 bar (25–35 MPa). Catalyst compositions contained 20–75% (atomic) zinc. These catalysts demonstrated high activity and selectivity for methanol synthesis and proved robust enough to resist sulfur poisoning inherent when generating syngas from coal gasification. Over the years, as gas purification technologies improved (i.e., removal of impurities such as sulfur, chlorine, and metals), interest in the easily poisoned copper catalysts for methanol synthesis was renewed. In 1966, ICI introduced a new, more active Cu/ZnO/Al2O3 catalyst that began a new generation of methanol production by a low-temperature (220–275 C), low-pressure (50–100 bar, 5–10 MPa) process. The last high-temperature methanol synthesis plant closed in the mid 1980s [121]; presently, low-temperature, low-pressure processes based on copper catalysts are used for all commercial production of methanol from syngas. The synthesis process has been optimized to the point that modern methanol plants yield 1 kg of MeOH per liter of catalyst per hour with H99.5% selectivity for methanol. Commercial methanol synthesis catalysts have lifetimes on the order of 3–5 years under normal operating conditions. The copper crystallites in methanol synthesis catalysts have been identified as the active catalytic sites, although the actual state (oxide, metallic, etc.) of the active copper site is still being debated. The most active catalysts all have high copper content; optimum 60% copper is limited by the need to have enough refractory oxide to prevent sintering of the copper crystallites. The ZnO in the catalyst formulation creates a high copper metal surface area; it is suitably refractory at methanol synthesis temperatures and hinders the agglomeration of copper particles. ZnO also interacts with Al2O3 to form a spinel that provides a robust catalyst support. Acidic materials like alumina are known to catalyze methanol dehydration reactions to produce DME. By interacting with the Al2O3 support

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Table 4.4 Commercial methanol synthesis catalyst formulations. Reproduced from P. L. Spath and D.C. Dayton, 2003, Preliminary Screening — Technical and Economic Assessment of Synthesis Gas to Fuels and Chemicals with Emphasis on the Potential for Biomass-Derived Syngas, NREL/TP-510-34929 Manufacturer

Cu (at.%)

Zn (at.%)

Al (at.%)

IFP ICI BASF Shell

45–70 20–35 38.5 71

15–35 15–50 48.8 24

4–20 4–20 12.9

S€ ud Chemie Dupont United Catalysts Haldor Topsøe MK-121

65 50 62 H55

22 19 21 21–25

12 31 17 8–10

Other Zr, 2–18 at.% Mg Rare earth oxide, 5 at.%

Patent date 1987 1965 1978 1973 1987 None found None found None found

material, the ZnO effectively improves methanol selectivity by reducing the potential for DME formation. Table 4.4 shows catalyst formulations provided by several commercial manufacturers. Additional catalyst formulations have been presented in the literature with the purpose of improving per-pass methanol yields [122]. The addition of cesium to Cu/ZnO mixtures has shown improved methanol synthesis yields. This holds true only for the heavier alkali metals, as the addition of potassium to methanol synthesis catalysts tends to enhance higher alcohol yields. Cu/ThO2 intermetallic catalysts have also been investigated for methanol synthesis [122]. These catalysts have demonstrated high activity for forming methanol from CO2free syngas. Thoria-based methanol catalysts deactivate very rapidly in the presence of CO2. Cu/Zr catalysts have proven active for methanol synthesis in CO-free syngas at 5 atm (0.5 MPa) and 160–300 C [123]. Supported palladium catalysts have also demonstrated methanol synthesis activity in CO2-free syngas at 5–110 atm (0.5–111 MPa) at 260–350 C. 4.3.2.3 Methanol to Gasoline The methanol to gasoline (MTG) process developed by ExxonMobil involves the conversion of methanol to hydrocarbons over zeolite catalysts. The MTG process, although considered the first major new synthetic fuel development since FTS, was discovered by accident in the 1970s by two independent groups of ExxonMobil scientists trying to convert methanol to ethylene oxide and attempting to methylate isobutene with methanol over a ZSM-5 zeolite catalyst [124]. The MTG process occurs in two steps. First, crude methanol (17% water) is superheated to 300 C and partially dehydrated over an alumina catalyst at 27 atm (2.7 MPa) to yield an equilibrium mixture of methanol, DME, and water (75% of the methanol is converted). This effluent is then mixed with heated recycled syngas and introduced into a reactor containing ZSM-5 zeolite catalyst at 350–366 C and 19–23 atm (1.9–2.3 MPa) to produce hydrocarbons (44%) and water (56%) [125]. The overall MTG process usually contains multiple gasoline conversion reactors in parallel because the zeolites have to be regenerated frequently to burn off the coke formed during the reaction. The reactors are then cycled so that individual reactors can be regenerated without stopping the process, usually every 2–6 weeks [126].

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The MTG reactions may be summarized as follows [72]: 2CH3 OH ! CH3 OCH3 þ H2 O

DH ¼ 5:6 kcal / mol

CH3 OCH3 ! C2 C5 olefins C2 C5 olefins ! paraffins; cycloparaffins; aromatics The selectivity to gasoline-range hydrocarbons is greater than 85%, with the remainder of the product being primarily liquefied petroleum gas [72]. Nearly 40% of the gasoline produced from the MTG process is aromatic hydrocarbons with the following distribution: 4% benzene, 26% toluene, 2% ethylbenzene, 43% xylenes, 14% trimethylsubstituted benzenes, plus 12% other aromatics [72]. The shape selectivity of the zeolite catalyst results in a relatively high durene (1,2,4,5-tetramethylbenzene) concentration, 3–5% of the gasoline produced [127]. Therefore, MTG gasoline is usually distilled, and the heavy fraction is processed in the heavy gasoline treating unit to reduce the durene concentration to below 2%. This results in a high-quality gasoline with a high octane number. The first commercial MTG plant came onstream in 1985 in New Zealand (ExxonMobil’s Motunui plant) producing both methanol and high-octane gasoline from natural gas. The plant produced 14 500 BPD of gasoline, and then in 1997 the gasoline manufacturing was abandoned and the plant produced only methanol. Today, this plant, along with a nearby methanol plant at Waitara, produces 2.43  106 t/year of chemical-grade methanol for export (http://www.teara.govt.nz/en/oil-and-gas/5). A fluid-bed MTG plant was jointly designed and operated near Cologne, Germany, by ExxonMobil Research and Development Corp., Union Rheinische Braunkohlen Kraftstoff AG, and Uhde Gmb [124]. A demonstration plant (15.9 m3/day) operated from 1982 to 1985. Although, no commercial plants have been built, the fluid-bed technology is ready for commercialization. 4.3.2.4 TIGAS (Topsøe Integrated Gasoline Synthesis) The Topsøe integrated gasoline synthesis (TIGAS) process was developed by Haldor Topsøe with the intent of minimizing capital and energy costs by integrating methanol synthesis with the MTG step into a single loop without isolation of methanol as an intermediate [124, 128, 129]. This process was developed with the idea that future plants would be constructed in remote areas for recovery of low-cost natural gas. In ExxonMobil’s MTG process, different pressures are preferred for syngas production, methanol synthesis, and the fixed-bed MTG step. These pressures are 15–20 atm (221–294 psig, 1.5–2.0 MPa), 50–100 atm (735–1470 psig, 5–10 MPa), and 15–25 atm (221–368 psig, 1.5–2.5 MPa) respectively [72]. The TIGAS process involves modified catalysts and conditions so that the system pressure levels out and separate compression steps are not required. To do this, a mixture of methanol and DME is made prior to gasoline synthesis, and then there is only one recycle loop, which goes from the gasoline synthesis step back to the MeOH/DME synthesis step. A 1000 TPD demonstration plant was built in Houston, Texas, in 1984 and operated for 3 years [129]. The gasoline yield for the TIGAS process, defined as the amount of gasoline produced divided by the amount of natural gas feed and fuel, was shown to be 56.5% by weight [129].

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4.3.2.5 Methanol to Olefins and Methanol to Gasoline and Diesel Along with the MTG process, ExxonMobil developed several other processes for converting methanol to hydrocarbons based on zeolite catalysts. Since light olefins are intermediates in the MTG process, it is possible to optimize the methanol-to-olefins (MTO) synthesis. Higher reaction temperatures (500 C), lower pressures, and lower catalyst (acidity) activity favor light olefin production [124]. The rate of olefin production could be modified so that 80% of the product consists of C2 to C5 olefins rich in propylene (32%) and butenes (20%) with an aromatic-rich C5þ gasoline fraction (36%) [72, 127]. The process can also be modified for high ethylene and propylene yield (H60%). ExxonMobil also developed a methanol-to-gasoline-and-diesel (MOGD) process. Oligimerization, disproportionation, and aromatization of the olefins produced in the MTO synthesis are the basis for the MOGD process. In the MOGD process, the selectivity of gasoline and distillate from olefins is greater than 95% [124]. One source gives the gasoline product from MOGD to be 3% (by weight) paraffins, 94% olefins, 1% napthenes, and 2% aromatics [130]. Neither the MTO nor the MOGD process is currently in commercial practice [72]; however, UOP and HYDRO of Norway license their own methanol-to-olefins process where the primary products are ethylene and propylene [124]. They use a fluidized-bed reactor at 400–450 C and achieve roughly 80% carbon selectivity to olefins at nearly complete methanol conversion [131]. The operating parameters can be adjusted so that either more ethylene is produced (48% by weight ethylene, 31% propylene, 9% butenes, and 1.5% other olefins) or else more propylene (45% by weight propylene, 34% ethylene, 12% butenes, and 0.75% other olefins). 4.3.2.6 Dimethyl Ether DME is industrially important as the starting material in the production of the methylating agent dimethyl sulfate and is also used as an aerosol propellant. DME has the potential to be used as a diesel or cooking fuel, a refrigerant, or a chemical feedstock [132–134]. Commercial production of DME originated as a by-product of high-pressure methanol production. DME is formed in a two-step process where methanol is first synthesized and then dehydrated over an acid catalyst such as g-alumina at methanol synthesis conditions. The DME reaction scheme is as follows [135, 136]: CO þ 2H2 ! CH3 OH

ðmethanol synthesisÞ

2CH3 OH ! CH3 OCH3 þ H2 O

ðmethanol dehydrationÞ DH ¼ 5:6 kcal/ mol

H2 O þ CO ! H2 þ CO2 Net reaction :

ðWGSÞ

3H2 þ 3CO ! CH3 OCH3 þ CO2

DH ¼ 21:6 kcal/ mol DH ¼ 9:8 kcal/ mol DH ¼ 58:6 kcal/ mol

Note that one product in each reaction is consumed by another reaction. Because of the synergy between these reactions, syngas conversion to DME gives higher conversions than syngas conversion to methanol [133]. Table 4.5 gives the per-pass and total conversion for the synthesis of methanol, methanol/DME, and DME. The optimum H2 to CO ratio for DME synthesis is lower than that for methanol synthesis and ideally should be around 1:1 [132, 133, 136]. Recent improvements to the DME

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Table 4.5 Conversions for methanol, methanol/DME, and DME. Reproduced from P. L. Spath and D.C. Dayton, 2003, Preliminary Screening — Technical and Economic Assessment of Synthesis Gas to Fuels and Chemicals with Emphasis on the Potential for Biomass-Derived Syngas, NREL/TP-510-34929 Conversion

MeOH

MeOH/DME

DME

Per pass (%) Total (%)

14 77

18 85

50 95

synthesis process involve the development of bifunctional catalysts to produce DME in a single gas-phase step (i.e., one reactor) [132, 137] and the use of a slurry reactor for liquidphase DME synthesis [138, 139]. 4.3.2.7 Ethanol and Mixed Alcohols The production of higher alcohols from syngas has been known since the beginning of the last century. There are several processes that can be used to make mixed alcohols from CO and H2, including isosynthesis, variants of FTS, oxosynthesis involving the hydroformylation of olefins, and homologation of methanol and lower molecular weight alcohols to make higher alcohols. With the development of various gas-to-liquid processes such as Fischer– Tropsch and methanol synthesis, it was recognized that higher alcohols were by-products of these processes when catalysts or conditions were not optimized. Modified Fischer–Tropsch or methanol synthesis catalysts can be promoted with alkali metals to shift the products towards higher alcohols. Higher alcohol synthesis (HAS) is also optimized at higher temperatures and lower space velocities than methanol synthesis is and with an H2 to CO ratio of around 1:1 instead of 2:1 or greater. While other syngas-to-liquids processes were being commercialized, the commercial success of HAS has been limited by poor selectivity and low product yields. Single-pass yields of HAS are on the order of 10% syngas conversion to alcohols, with methanol typically being the most abundant alcohol produced [72, 140]. Methanol can be recycled to produce more higher alcohols or removed and sold separately. Despite these shortcomings, in 1913 BASF patented a process to synthesize a mixture of alcohols, aldehydes, ketones, and other organic compounds from CO and H2 over an alkalized cobalt oxide catalyst at 10–20 MPa and 300–400 C [141]. Fisher and Tropsch developed the “Synthol” process for alcohol production in 1923. They used an alkalized iron catalyst to convert syngas to alcohols at H10 MPa and 400–450 C. Between 1935 and 1945, commercial mixed alcohol synthesis was performed with alkalized ZnO/Cr2O3 catalysts. The demand for mixed alcohol production from syngas decreased after 1945 with the increasing availability of petroleum and the desire for neat alcohols for manufacturing chemicals [142]. Much of this early work on HAS is detailed in the review by Natta et al. [143]. The conversion of syngas to ethanol via direct synthesis and methanol homologation pathways has been performed using a wide range of homogeneous and heterogeneous catalysts. For the direct synthesis of ethanol from syngas, two types of catalyst currently hold promise: rhodium-based and copper-based catalysts. For rhodium-based catalysts, there are reports in the literature of selectivities as high as 50% at higher pressure [144]. However, most often, this high selectivity is obtained at the expense of conversion; that is, high selectivities are seen only at very low conversions. Depending on the type of catalyst

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used, both the direct synthesis and indirect synthesis via methanol homologation are accompanied by a host of side reactions leading to methane, C2–C5 alkanes and olefins, ketones, aldehydes, esters, and acetic acid. Methanation can be particularly significant via hydrogenation of CO. To increase ethanol selectivity, the catalyst and the reaction conditions need to be better designed to suppress methanation activity. A review of the literature on the conversion of syngas into ethanol and higher alcohols [145] indicates that higher selectivity may be achieved with homogeneous catalysts, but commercial processes based on these catalysts require extremely high operating pressures. Rhodium-based heterogeneous catalysts preferentially produce ethanol over other alcohols. However, the high cost of rhodium and low ethanol yield make such catalysts less attractive for commercial application, especially if high metal loadings are required. Modified methanol synthesis catalysts based on CuZn, CuCo, and Mo have been developed and demonstrated in pilot plant testing. Alcohol production rates are significantly less compared with methanol synthesis, requiring significant improvements of at least twoto three-fold in alcohol production rate for commercial viability. Reactor designs employed in the HAS catalyst R&D have typically adapted standard fixedbed reactor technology with specialized cooling designs used for methanol synthesis or FTS of hydrocarbons. Improved product yield and selectivity could be achieved by performing the reactions in slurry reactors with efficient heat removal and temperature control. A review of more than 220 recent publications and patents on syngas-to-ethanol conversion can be found in the literature [145]. The review looked at various routes and chemistries of converting syngas to ethanol. Thermodynamic calculations were also presented to understand the limits on various reactions as a function of process parameters. Past research efforts in developing catalysts and reactor designs were extensively discussed to finally summarize the R&D needs in commercializing syngas conversion to ethanol. Chemistry. The mechanism for HAS involves a complex set of numerous reactions with multiple pathways leading to a variety of products that are impacted by kinetic and thermodynamic constraints. No kinetic analysis of HAS has been published that is capable of globally predicting product compositions over ranges of operating conditions [146]. Depending on the process conditions and catalysts used, the most abundant products are typically methanol and CO2. The first step in HAS is the formation of a C–C bond by CO insertion into CH3OH. Linear alcohols are produced in a stepwise fashion involving the synthesis of methanol followed by its successive homologation to ethanol, propanol, butanol, etc. [147]. Therefore, the HAS catalyst should have methanol synthesis activity because methanol can be considered a recurrent C1 reactant. Branched higher alcohols are typically formed from modified methanol synthesis and modified FTS catalysts, and straight-chain alcohols are formed when alkalized MoS2 catalysts are used. The mechanism for HAS over modified high-temperature methanol synthesis catalysts has been described as a unique carbon-chain growth mechanism that is referred to as oxygen retention reversal (ORR) aldol condensation with b-carbon (adjacent to the alcohol oxygen) addition [140]. Individual reactions in HAS can be grouped into several distinct reaction types [148]: . .

linear chain growth by C1 addition at the end of the chain to yield primary linear alcohols; beta addition between the C1 and Cn (n  2) to yield, for example, 1-propanol and branched primary alcohols such as 2-methyl-1-propanol (isobutanol) for n ¼ 2;

110 . . .

Syngas Cleanup, Conditioning, and Utilization

beta addition between Cm (m ¼ 2 or 3) and Cn (n  2); methyl ester formation via carboxylic acids formed from synthesized alcohols; carbonylation of methanol to yield methyl formate.

Linear alcohols can proceed along the reaction path, but branched alcohols are terminal products of the aldol condensation pathways because they lack the two a-hydrogen atoms required for chain growth [149]. The general HAS reaction mechanism has the following overall stoichiometry [150, 151]: nCO þ 2nH2 ! Cn H2n þ 1 OH þ ðn1ÞH2 O

DHr ¼ 61:2 kcal/ mol

with n typically ranging from 1 to 8 [142]. The reaction stoichiometry suggests that the optimum H2 to CO ratio is 2:1; however, the simultaneous occurrence of the WGS reaction means that the optimum ratio is closer to 1:1. The major reactions in HAS are methanol synthesis, Fischer–Tropsch reactions, HAS reactions, and the WGS reaction [152]. The following is a list of some of these more important reactions described above that are associated with HAS: CO þ 2H2 $ CH3 OH

methanol synthesis

CO þ H2 O $ CO2 þ H2 CH3 OH þ CO $ CH3 CHO þ H2 OCO

WGS beta addition -- aldehydes

CH3 OH þ CO þ 2H2 $ CH3 CH2 OH þ H2 O

ethanol homologation

Cn H2n1 OH þ CO þ 2H2 $ CH3 ðCH2 Þn OH þ H2 O 2CH3 OH $ CH3 CH2 OH þ H2 O

HAS homologation condensation/ dehydration

2CH3 OH $ ðCH3 Þ2 CO þ H2 O ðCH3 Þ2 CO þ H2 $ ðCH3 Þ2 CHOH

DME formation branched iso-alcohols

2CH3 CHO $ CH3 COOCH2 CH3

methyl ester synthesis

Competing reactions: nCO þ 2nH2 ! Cn H2n þ nH2 O

olefins

nCO þ ð2n þ 1ÞH2 ! Cn H2n þ 2 þ nH2 O

paraffins

Methanol formation is favored at low temperatures and high pressures [153]. At high pressures, HAS increases as the temperature is increased at the expense of methanol formation and minimizing hydrocarbon formation. To maximize higher alcohols, the H2 to CO ratio should be close to the usage ratio, which is about 1. Lower H2 to CO ratios favor CO insertion and C–C chain growth. In general, the reaction conditions for HAS are more severe than those for methanol production. To increase the yield of higher alcohols, methanol can be recycled for subsequent homologation, provided the catalyst shows good hydrocarbonylation activity [147, 153] Unavoidably, the main reactions stated above produce H2O and CO2 as by-products. WGS plays a major role, and, depending on the catalyst’s shift activity, some chemical dehydration of alcohols can be undertaken in situ to produce higher alcohols, esters, and ethers [153]. Secondary reactions also produce hydrocarbons, including aldehydes and ketones [153, 154]. Also, frequently, substantial quantities of methane are formed [155]. Thermodynamic constraints limit the theoretical yield of HAS and, as in other syngas-to-liquids processes, one of the most important limitations to HAS is removing the

Summary and Conclusions

111

considerable heat of reaction to maintain control of process temperatures [154]. Compared with methanol, less alcohol product is made per mole of CO, more by-product is made per mole of alcohol product, and the heat release is greater. Catalysts. HAS catalysts are essentially bifunctional base-hydrogenation catalysts and are typically categorized into several groups based on their composition. Common to all HAS catalysts is the addition of alkali metals to the formulation. The activating character of alkali metal promoters is a function of their basicity. Alkali metals provide a basic site to catalyze the aldol condensation reaction by activating surface-adsorbed CO and enhancing the formation of the formate intermediate. Information pertaining to the four primary groups of catalysts used for HAS is summarized in Tables 4.6 and 4.7. The catalyst groups include [141]: . . . .

modified high-pressure methanol synthesis catalysts – alkali-doped ZnO/Cr2O3; modified low-pressure methanol synthesis catalysts – alkali-doped Cu/ZnO and Cu/ZnO/ Al2O3; modified Fischer–Tropsch catalysts – alkali-doped CuO/CoO/Al2O3; ALKALI-doped sulfides, mainly MoS2.

Table 4.6 summarizes the typical range of process conditions for each catalyst and a measure of catalyst performance in terms of CO conversion and product selectivity. Table 4.7 details the compositions of typical catalyst materials in each group and highlights key research findings reported in the literature. One of the major hurdles to overcome before HAS becomes an economically feasible commercial process is the development of improved catalysts that increase the productivity and selectivity to higher alcohols [176]. To date, modified methanol and modified Fischer–Tropsch catalysts have been more effective in the production of mixed alcohols; the sulfide-based catalysts tend to be less active than the oxide-based catalysts [140]. Rhodium-based catalysts are another group of catalysts that are not specifically used for HAS but have been developed for selective ethanol synthesis. Other C2 oxygenates (i.e., acetaldehyde and acetic acid), as well as increased levels of methane production, are also synthesized over rhodium-based catalysts [177]. The high cost and limited availability of rhodium for ethanol synthesis catalysts will impact any commercialization of these synthetic processes for converting syngas to ethanol [152].

4.4

Summary and Conclusions

This chapter provides a summary of the R&D efforts focused on syngas cleanup, conditioning, and conversion that will enable the effective use of syngas generated from biomass gasification. Throughout the discussion, the primary objective has been to describe the technical challenges that need to be overcome to enable the commercial deployment of biomass gasification technologies for power, fuels, and chemicals production. The high capital cost of biomass conversion technologies also makes economic feasibility a significant challenge for commercial deployment. The capital cost savings that can be gained through economies of scale often do not apply for biomass conversion technologies. The lower energy content and bulk density of biomass feedstocks – compared to coal, for example – limits the amount of biomass that can be

Modified hightemperature/highpressure methanol synthesis Modified lowtemperature/ low-pressure methanol synthesis Modified Fischer–Tropsch Alkali-doped sulfides

Catalyst

5–10

6–20 3–17.5

275–310

260–340

260–350

Linear alcohols

Linear alcohols

Primary alcohols

12.5–30 Branched primary alcohols

Products

300–425

Temperature Pressure ( C) (MPa)

Operating conditions

Table 4.6 Process and performance summary for HAS catalysts

10% CO [123]

5–30% CO and CO2

21–29% CO

5–20% CO

Conversion

Lurgi/Sud Chemie

Institut Fran¸cais du Petrol Dow Chemical, Union Carbide 30–50% for higher alcohols 75–90% for higher alcohols [123]

Company

29–45% for C2 17–25% CO2 [152]

Selectivity

112 Syngas Cleanup, Conditioning, and Utilization

1. Methanol is most abundant product (80%) 2. Average carbon number of oxygenated products is lower than products from modified high-temperature methanol catalysts [152] 3. Additional literature on catalyst effectiveness [148, 165–167]

25–40 wt% CuO 10–18 wt% Al2O3 30–45 wt% ZnO 1.7–2.5 wt% K2O 0.4–1.9 Cu/Zn ratio 3–18 wt% promoter (Cr, Ce, La, Mn or Th) [152]

10–50% Cu 5–25% Co 5–30% Al 10–70% Zn (on elemental basis) 0–0.2 alkali/Zn ratio 0.4–2.0 Zn/Al ratio 0.2–0.75 Co/Al ratio 1–3.0 Cu/Al ratio [152]

Modified low-temperature/ low-pressure methanol synthesis catalyst

Modified Fischer–Tropsch catalyst

(continued)

1. CO2 is reactant [152] 2. Anderson–Schultz–Flory (ASF) distribution for chain growth observed in alcohol and hydrocarbon products 3. Good catalyst activity correlates with catalyst homogeneity 4. Cu and Co are active components which have been modified with Zn and alkali 5. Low activity and lack of long-term stability hinders commercial application 6. Little deactivation observed during an 8000 h pilot plant test. Observed deactivation was caused by coke formation and sintering that decreased homogeneity of catalyst [152] 7. Additional available catalyst literature [153, 154, 168–170]

1. 15–21 wt% Cr optimized HAS yields for non-alkalized Cu–Zn–Cr oxides 2. Chromia acts as a structural promoter increasing surface area and inhibiting Cu sintering [156] 3. Threefold decrease in C2 alcohol production observed with 6% CO2 at 400  C [157] 4. 0.3–0.5 mol% Cs addition maximized HAS product yields [148] 5. Cs addition increases ethanol synthesis rate [148] 6. Systematic description of properties and effectiveness of Zn/Cr HAS catalysts by Hoflund and his group [158–164]

Alkalized Cu–Zn–Cr oxides

Modified high-temperature/ high-pressure methanol synthesis catalyst

Comments

Composition

Catalyst

Table 4.7 HAS catalyst composition and key research findings

Summary and Conclusions 113

Alkali-doped sulfides

Catalyst

Table 4.7 (Continued )

Alkali-doped MoS2 or CoMoS2

Composition

1. Alkali additions suppress hydrogenation activity of Mo and provide additional sites for alcohol synthesis 2. Cs is most effective alkali promoter [140] 3. Higher alcohols and hydrocarbon products have ASF molecular weight distribution 4. H30% CO2 retards catalyst activity, whereas moderate to low concentrations do not significantly impact catalyst activity [123] 5. Higher alcohol selectivity is reduced even in the presence of low CO2 concentrations [123] 6. Co promotes the homologation of methanol to ethanol resulting in higher production of ethanol and other higher alcohols [142] 7. Activity of sulfide catalysts depends on catalyst support materials [171–175] 8. 50 to 100 ppm sulfur in the feed gas is required to maintain sulfidity of catalyst 9. H2S in the feed gas moderates hydrogenation and improves selectivity for higher alcohols by reducing methanol production

Comments

114 Syngas Cleanup, Conditioning, and Utilization

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economically collected, prepared, and transported to a large centralized location. As the scale of biomass conversion facilities increases, biomass must be transported over longer distances to meet the feedstock needs of the plant; however, the infrastructure for transporting large quantities of biomass over long distances is not widely available. Consequently, feedstock costs are a major contribution to the operating cost of a biomass conversion facility. In fact, recent technoeconomic assessments of thermochemical biomass conversion technologies estimate that feedstock costs represent nearly 50% of the cost of production of biofuels in a biomass-to-liquids process [178]. Syngas cleanup, conditioning, and conversion represent a large fraction (50%) of the total capital costs for a biomass gasification to liquid fuels process. Consequently, implicit in the efforts to overcome the technical barriers is the need reduce capital costs by developing processes with higher conversion efficiencies at less severe conditions (temperature and pressure) to improve product yields. Capital cost reductions can also be achieved by combining or eliminating process steps to reduce the number of unit operations. Clearly, the entire value chain – from biomass production, collection, and delivery; through biomass conversion; through power, fuels, or chemicals production; through product end use – needs to be integrated and optimized to commercialize biomass thermochemical conversion technologies successfully. The extensive research and development efforts devoted to syngas cleanup, conditioning, and conversion to fuels and chemicals are documented in a vast amount of literature that tracks the scientific and technological advancements in syngas chemistry. In many cases, multiple, integrated approaches are being actively pursued to find the most technically robust and economically feasible solutions. This wealth of information and technical experience can be leveraged to accelerate the commercial deployment of biomass thermochemical conversion technologies, but the ultimate test will be market acceptance on a cost competitive basis.

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5 Fast Pyrolysis Robbie H. Venderbosch1 and Wolter Prins1,2 1

Biomass Technology Group B.V. P.O.Box 835, 7500 AV Enschede, The Netherlands 2 Ghent University, Coupure Links 653, B-9000, Gent, Belgium

5.1

Introduction

Pyrolysis processes are carried out in the absence of oxygen, at atmospheric pressure, and at temperatures ranging from 300 to 600
C. Charcoal is the main product of the traditional slow pyrolysis process, in which the biomass (usually wood) is heated slowly to temperatures between 300 and 400
C. Fast pyrolysis, on the other hand, involves very high heating rates to temperatures around 500
C followed by rapid cooling and condensation of the vapors produced. This yields a maximum quantity of dark-brown mobile liquid with a heating value roughly equal to that of wood, which is approximately half the heating value of fossil fuel oil. The earliest recorded use of this technique was in Egypt, where the product was used for sealing boats. In more recent times, a number of chemicals were derived from the liquids as well (e.g. methanol, acetic acids, etc., and liquid smoke). The interest in the production of bio-oil from biomass has grown rapidly in recent years, due to the possibilities of: . . . . .

decoupling liquid fuel production (scale, time, and location) from its utilization; minerals separation on the site of liquid fuel production (to be recycled to the soil as a nutrient); producing a renewable fuel for boilers, engines, turbines, power stations, and gasifiers; secondary conversion to motor fuels, additives, or special chemicals (biomass refinery); and primary separation of the carbohydrate-derived and lignin-derived fractions in biomass (biomass refinery).

Thermochemical Processing of Biomass: Conversion into Fuels, Chemicals and Power, First Edition . Edited by Robert C. Brown © 2011 John Wiley & Sons, Ltd. Published 2011 by John Wiley & Sons, Ltd. ISBN: 978-0-470-72111-7

Introduction

125

An interesting aspect here is that pyrolysis could connect (conventional) agricultural business to (petro)chemical processes. In addition, fast pyrolysis can be integrated with biological processes in various ways, resulting in dedicated biorefineries (e.g., conversion of lignin residues to bio-oil (and biochar), fermentation of the fast pyrolysis sugar fraction, etc.) Many reviews on pyrolysis can be found in literature; for example, see Bridgwater [1, 2]. More detailed information can also be found in the three handbooks edited by Bridgwater [1, 3, 4] and on the PyNe website (www.pyne.co.uk), established by a network of researchers in and developers of fast pyrolysis. Reviews should be read with some care, however, as the published literature includes much that is poorly characterized in terms of feedstocks employed, processing conditions, and statistical significance. While the function of slow pyrolysis is to produce mainly charcoal and gas, fast pyrolysis is meant to convert biomass into a maximum quantity of liquids. Bio-oil has several advantages compared with the original biomass: . . .

lower transport costs; smaller storage requirements; and ease of conveyance into reactors.

In this chapter, the fundamentals of fast pyrolysis and the typical bio-oil properties will be discussed, followed by a historical review of the major technologies, and concluding with a description of possible product applications. 5.1.1

Fundamentals of Pyrolysis

Thermal decomposition of biomass results in the production of char and noncondensable gas (the main slow pyrolysis products) and condensable vapors (the liquid product aimed at in fast pyrolysis) [5]. It is realized by rapid convection or radiation of heat to the surface of a biomass particle and subsequent heat penetration into the particle by conduction. Under fast pyrolysis conditions, the temperature development inside the particle and the corresponding intrinsic reaction kinetics dominate the decomposition rate and product distribution. Principally, biomass is decomposed to a mixture of defragmented lignin, (hemi)cellulose and extractives (if present). The intention of fast pyrolysis is to prevent the primary decomposition products (i) being cracked thermally or catalytically (over char formed already) to small noncondensable gas molecules on the one hand or (ii) being recombined/ polymerized to char (precursors) on the other hand. Such conditions would then lead to a maximum yield of condensable vapors and include the rapid heating of small biomass feed particles. It is also essential to create a short residence time for the primary products, both inside the decomposing particle and in the equipment before the condenser. Early process developers adopted the concept of flash pyrolysis in which small particles (G1 mm) were used to achieve high oil yields. Later research (for example, see Wang and co-workers [6, 7]) showed that the oil yield is much less dependent on biomass particle size and vapor residence times than originally assumed. The composition of the oil however, is still sensitive to these parameters. High external heat transfer to the biomass particles can be realized by mixing the cold biomass feed stream intensively with an excess of preheated, inert, heat carrier (e.g., hot sand). A number of reactor designs have been explored that may be capable of achieving

126

Fast Pyrolysis

high heat transfer rates, such as fluidized beds and mechanical mixing devices. For an efficient heat transfer through the biomass particle, though, a relatively small heat penetration depth is required, which limits the size of biomass particles to less than 2 mm [8]. Size here reflects the actual (heat) penetration depth of the particle. For such particles the decomposition rate is controlled by a combination of intra-particle heat conduction and the decomposition kinetics. Bio-oil yields from woody feedstock for continuously operated laboratory reactors and pilot plants are usually in the range of 60–70 wt% (dry-feed basis). Although generally reported in reviews, oil yields over 70% are exceptional and only for well-defined feedstocks, such as cellulose. If the objective is to derive chemicals from bio-oil, then it is essential to operate the process under the proper conditions (temperature, residence time, feedstock type, and feedstock pretreatment) in order to maximize the yield of the desired compounds. When boiler fuel is desired, less-stringent criteria must be met; the conversion of as much as possible biomass energy to the liquid product is then decisive. Until recently, most development work in fast pyrolysis has focused on maximizing bio-oil yield rather than product composition and quality. The major components of biomass are: . . .

cellulose with a composition roughly according to (C6H10O5)n, where n ¼ 500–4000; hemicellulose (mostly xylans), with an average composition according to (C5H8O4)n, where n ¼ 50–200; and lignin, consisting of highly branched, substituted, mononuclear aromatic polymers, often bound to adjacent cellulose and hemicellulose fibers to form a lignocellulosic complex.

Cellulose, hemicellulose, and lignin have different thermal decomposition behavior, which depends upon heating rates and the presence of contaminants [9]. A typical temperature dependence of the decomposition through thermogravimetric analysis (TGA) for reed is given in Figure 5.1. TGA data are plotted versus the temperature on the left-hand side (solid line), while on the right hand side the TGA data are interpreted in terms of cellulose (38%), hemicellulose (30%), and lignin (12%). The differential plot for these fractions is given on the left-hand side against the original biomass data. Hemicellulose is the first to decompose, starting at about 220
C and completed around 400
C. Cellulose

1 total biomass

Mass Loss Rate (wt%/ºC)

Mass Loss Rate (wt% / ºC)

1

0.8

0.6

0.4

0.2

actual biomass

cellulose 0.8

0.6 hemicellulose 0.4

0.2 lignin

0 100

200

300

Temperature (ºC)

400

500

0 100

200

300

400

500

Temperature (ºC)

Figure 5.1 TGA curve for reed (left-hand side) and the differential plot interpreted in terms of hemicellulose, cellulose, and lignin (right-hand side)

Introduction

127

appears to be stable up to 310
C, after which almost all cellulose is converted to noncondensable gas and condensable organic vapors at 320–420
C. Although lignin may begin to decompose at temperatures as low as 160
C, it appears to be a slow, steady process extending up to 800–900
C. Below fast pyrolysis temperatures of around 500
C, a limited conversion is likely (up to 40%). In general, solid residues remain (char, not shown in Figure 5.1), mainly derived from lignin and some hemicellulose, 40 wt% and 20 wt% respectively of the original sample (see also Yang et al. [10]). A conclusion from such TGA data is that most of the cellulose is converted to bio-oil, while hemicellulose and lignin also yield substantial quantities of gas and tar and char. A possible explanation is the linkage through covalent bonds of lignin and hemicellulose, which prevents their ready release during pyrolysis. Although cellulose and hemicellulose are also linked, these are much weaker hydrogen bonds (e.g., see Vaca Garcia [11]). Indirect evidence is given by the composition of the pyrolysis-derived char, which has an elemental composition close to that of the lignin. The pyrolysis of biomass can be endothermic or exothermic, depending on the feedstock and temperature of reaction. For holocellulosic materials, pyrolysis is endothermic at temperatures below about 450
C and exothermic at higher temperatures [12]. Vapors formed inside the pores of a decomposing biomass particle are subject to further cracking, leading to the formation of additional gas and/or (stabilized) tars. In particular, the sugarlike fractions can be readily repolymerized, increasing the overall char yield. This may be desired for slow pyrolysis, but it should be avoided in fast pyrolysis. For the small particles used in fast pyrolysis, secondary cracking inside the particles is relatively unimportant due to a lack of residence time. However, when the vapor products enter the surrounding gas phase, they will still decompose further, if they are not condensed quickly enough [8]. Figure 5.2 shows a possible reaction pathway for biomass pyrolysis, although other mechanisms have also been proposed. Upon sufficiently fast heating, the biomass particle is first decomposed to char (10–15 wt%) and pyrolysis vapors, which contain both permanent gases (CO, CO2, CH4) and condensable liquids. Apart from all organics, the condensable fraction of the pyrolysis vapors also includes the biomass moisture and the water produced during decomposition. The large organic molecules (up to a molecular weight

Gas (g) (CO,CO2,CH4)

bio-oil (l)

Wood (s) Char (s)

Char (s) + gas (CO2) + ‘bio-oil (l)’

Bio-oil (g)* Gas (g) (CO,CO2,CH4)

Primary phase decomposition reactions 450 – 550oC <1s

Secondary phase Repolymerization cracking + condensation 400 – 500oC >1s

atmospheric weeks / months

Figure 5.2 Representation of the reaction paths for wood pyrolysis

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Fast Pyrolysis

of approximately 20 000) in the vapor are subject to secondary thermal cracking, which may be enhanced by direct contact with the pyrolysis char. Fine char particles are readily entrained from the pyrolysis reactor and carried by the vapor stream to the condenser and collect with the bio-oil. During storage of the condensed bio-oil over a longer period, repolymerization reactions could occur, which is often suggested to be accompanied by production of water and possibly CO2. The pathway of Figure 5.2, originally proposed by Shafizadeh and co-workers [13, 14], is characterized by three steps. The process begins with biomass decomposition, assumed to be a first-order reaction. Reported reaction rates vary widely even for a “single” biomass type like wood. Published rate and selectivity expressions (for instance, see Wagenaar and co-workers [15] and Di Blasi [16]) may be useful in describing trends, but they can hardly be used for reliable quantitative predictions [6]. Despite the wide variation in biomass composition and structure and the complexity of pyrolysis, many scientists still propose single-particle models based on fundamental chemical and physical phenomena taking place inside the particles. Kinetic data are proposed for the pyrolysis of wood, but a small variation in ash content seriously affects these reaction rates, and probably the pyrolysis pathways themselves. As noted by Radlein et al. [17], “it should not be expected that any simple one-step kinetic scheme can account for all the facts concerning the pyrolytic behaviour of carbohydrates.” Although the predictive power is, consequently, limited, modeling is still useful in attaining a conceptual understanding of pyrolysis. For a recent review, refer to Di Blasi [16]. 5.1.2

Effect of Ash

The maximum possible oil yield depends on several parameters, including feedstock composition and water content, pyrolysis temperature, and vapor residence time. In addition, ash in the biomass has a dominant effect on the oil yield and composition, as illustrated in Figure 5.3 [18]; the trend line is based on data points from Chiaramonti et al. [19]). Sodium and potassium will have a large impact, but data from Di Blasi et al. [20] also show that sulfur- and phosphorus-containing ammonium salts dramatically affect oil yields and promote char formation [21]. The fundamental mechanisms behind these effects are poorly understood. More than 20 years ago Scott et al. [21] observed that demineralization of woody feedstock prior to pyrolysis results in a significant change in the composition of the resulting bio-oil. They recognized that alkali and alkaline earth metals in the biomass serve as a catalyst in degrading lignocellulosic materials to char and gas. If these cations are removed before pyrolysis, then the lignocellulose is depolymerized primarily to anhydrosugars, with levoglucosan yield in bio-oil increasing from 3 wt% to over 30 wt%. For biomass with high ash content, the oil yield can drop to below 50 wt% [18]. Further research is justified on this important phenomenon.

5.2

Bio-oil Properties

As illustrated in Figure 5.4, bio-oil is a dark red–brown to almost black liquid, the color dependent upon the chemical composition and the amount of fine char present in the liquid. Representative values of yields, elemental composition, and physical properties of

Bio-oil Properties

129

80 oil

70

Oil and char yield wt%

60 50 40 Trendline oil [19] 30 char 20 gas 10 0 0

1

2

3

4

5

6

7

8

Ash content wt%

Figure 5.3 Relationship between oil yield and ash content in the biomass. The solid lines represent trend lines taken from Table 4 in Fahmi et al. [18] for various feedstocks, while the broken line is a trend line based upon more than 20 data points presented by Chiaramonti et al. [19] for wood

Figure 5.4 Flash pyrolysis oil

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Fast Pyrolysis

Table 5.1 The range of elemental composition and properties for wood-derived bio-oil (taken from Bridgwater [1], Freel et al. [23], and Piskorz et al. [22]) Physical properties water content (wt%) pH density (kg/m3)

15–30 2.8–3.8 10 500–1250

Elemental analysis (wt% moisture free) C 55–65 H 5–7 N 0.1–0.4 S 0.00–0.05 O Balance Ash 0.01–0.30 HHV (MJ/kg) 16–19 Viscosity (315 K, cP) 25–1000 ASTM vacuum distillation (wt%) 430 K 10 466 K 20 492 K 40 distillate 50

Pyrolysis conditions temperature (K) gas residence time (s) particle size (mm) moisture (wt%) cellulose (wt%) ash (wt%)

750–825 0.5–2 200–2000 2–12 45–55 0.5–3

Yields (wt%) organic liquid water char gas

60–75 10–15 10–15 10–20

Solubility (wt%) hexane toluene acetone acetic acid

1 15–20 H95 H95

wood-derived bio-oil are listed in Table 5.1 [1, 22, 23]. The density of the liquid is about 1200 kg/m3, which is significantly higher than of fuel oil. It has a distinctive acidic, smoky odor and the vapors can irritate the eyes. The viscosity of the oil varies from 25 up to 1000 cP, depending on the water content and the amount of light components in the oil. It is important to note that oil properties may change during storage, a process known as “ageing,” which is usually measured as an increase in oil viscosity and its tendency to separate into a watery phase and a viscous, organic phase. Owing to the presence of large amounts of oxygenated components, the oil has a polar nature and does not mix readily with hydrocarbons. In general, it contains less nitrogen than petroleum products, and almost no metal and sulfur components [24]. However, nitrogen in biomass can appear in the bio-oil [25]. Degradation products from the biomass constituents include carboxylic acids (especially formic and acetic acids), which results in a pH in the range 2–4. The oil attacks mild steel, and storage of the oils should be in acid-proof materials like stainless steel or poly-olefins. Bio-oil includes significant water content, ranging between 15 and 35 wt%, which represents a serious drawback for many potential applications. For example, this water content reduces the higher heating value (HHV) of bio-oil to below 19 MJ/kg compared with 42–44 MJ/kg for conventional fuel oils, which limits its application as a substitute for fuel oil. Unless biomass is dried below about 10 wt% before pyrolysis, water content can range as high as 30–45 wt%, which can cause spontaneous phase separation of the bio-oil. Water in bio-oil cannot be removed by conventional methods like distillation, since the heated oil tends to polymerize. Thus, careful control of moisture content of the bio-oil prior to pyrolysis is important for assuring high-quality bio-oil.

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131

The water content of bio-oil also has beneficial effects. It lowers the viscosity of the oil, which facilitates transport, pumping, and atomization. In combustion applications, it lowers flame temperature, which is thought to favor lower NOx emissions [26]. 5.2.1

Composition and Stability

The mechanism by which biomass thermally decomposes to bio-oil is not fully understood. Biomass consists of sugar polymers (cellulose and hemicelluloses) and phenolbased polymers (lignin). Upon pyrolysis, a combination of depolymerization and decomposition reactions deconstructs these plant polymers into much smaller molecules, although there remain relatively large molecules, including oligomers. The largest product molecules have molecular masses that are far too high for it to vaporize even at pyrolysis temperatures around 500
C. These nonvolatile compounds exist as liquid aerosols in the vapor stream exiting a pyrolyzer [27], which manifest themselves as the visible smoke plume emanating from pyrolyzing biomass. Although the mechanism by which nonvolatile compounds produced during pyrolysis are transformed into aerosol has never been definitely demonstrated, it is widely thought that depolymerized plant molecules liquefy and in the presence of shearing forces are ejected as droplets into the gas flow. Another possibility is that plant materials depolymerize to monomers that have sufficient vapor pressure to vaporize, which is followed by chemical condensation and nucleation to aerosols in the gas stream. This liquid product collected in condensers or quenchers downstream of the pyrolyzer includes a wide spectrum of oxygenated compounds, with molecular weight ranging from 18 to over 10 000 g/mol, some probably produced by repolymerization reactions in the biooil after its recovery. Whereas some researchers think the oil is a micro-emulsion of these components, there is also reason to believe the oil is a mixture of soluble components, likely with water as the solvent and polar sugar constituents behaving as bridging agents in the dissolution of hydrophilic lignin material [28]. Gas chromatography (GC) analysis (including two-dimensional GC, GC–mass spectrometry (MS), etc.) is widely used in the measurement of oil quality. However, the usefulness of GC data is limited due to the presence of nonvolatile constituents in bio-oil and the potentially destructive effect of the technique on oil composition. GC injection includes vaporization of the feed, which is known to be very difficult for bio-oil and sometimes results in coke forming in the injection part of the system. Moreover, chemical reactions occurring in the GC column cannot be excluded, and it is sometimes questioned whether the components actually detected are really present in the feed oil. Other techniques under development for pyrolysis-oil analysis include gel-permeation chromatography and highperformance liquid chromatography (HPLC). Fortunately, development of new techniques to identify the constituents of bio-oil is ongoing: As the oil cannot be distilled very well, a solvent fractionation technique, illustrated in Figure 5.5, has been developed by Oasmaa and Kuoppala [29] to analyze the oil in an alternative way and reveal the presence of certain fractions present in the oil, including: . . .

water solubles (acids, alcohols, diethylethers); ether solubles (aldehydes, ketones, lignin monomers, etc.); ether insolubles ((anhydo)sugars, hydroxyl acids);

132

Fast Pyrolysis Water (by KF titration) Solids (by MeOH-DCM extraction)

BIO-OIL water extraction n-HEXANE SOLUBLES Extractives

WATER-SOLUBLES

WATER INSOLUBLES DCM extraction

ether extraction DCM SOLUBLES

DCM INSOLUBLES

LMM lignin (low molecular lignins, extractives)

ETHER SOLUBLES

ETHER INSOLUBLES

Ether solubles: (Aldehydes, ketons, lignin monomers)

Sugars (anhydrosugars, anhydro-oligomers, Hydroxyacids (C<10))

HMM lignin (high molecular lignins, solids)

Figure 5.5 Fractionation scheme for chemical characterization (derived from Oasmaa and Kuoppala [29])

. . .

n-hexane solubles (fatty acids, extractives, etc.); dichloromethane (DCM) solubles (low molecular weight lignin fragment, extractives); and DCM insolubles (degraded lignins, high molecular weight lignin fragments, including solids).

Table 5.2 [29] shows the combined results of solvent extraction, GC/mass selective detection, and CHN analyses for reference pine liquid. The majority of GC-eluted compounds are found in the ether-soluble fraction of the fractionation scheme. In particular, the ether insolubles (a syrup-like saccharide fraction) appear to have high oxygen contents (up to 50%) when compared with the DCM-soluble and -insoluble fractions (25–30% oxygen). It can also be seen in Table 5.2 that the quantitative identification of the various compounds in the sugars (ether insoluble) and lignin fractions (DCM soluble and insoluble) is poor. Research ongoing is aimed at revealing the various components in each fraction, and the effects of them on storage, stability, and upgrading. Although the proposed fractionation method may not be the future standard for bio-oil analysis, it could be an important technique relevant to understanding the oil’s oxygen functionalities. An important property of the bio-oil is its changing characteristics over time. Such an “instability” can be observed by a viscosity increase during storage, some formation of CO2, and an increased water content, but mainly by phase separation [29]. Definitions to address this unstable character are lacking. The detailed mechanism of this “ageing,” the causes for it, and the consequences for further use are still unclear and will depend highly on the various oxygen functionalities in the oil (and, therefore, feedstock (type), operating conditions, initial quality, storage temperatures, etc.). At room temperature the ageing of bio-oil occurs over periods of months or years, depending on the type of feedstock and its “initial quality.” However, at elevated temperatures the polymerization reactions are enhanced significantly and, therefore, it is recommended to avoid (long) storage at temperatures above 50
C.

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133

Table 5.2 Chemical composition of reference pine oil and its fractions Composition (wt%)

Water Acids Formic acid Acetic acid Propionic acid Glycolic acid Alcohols Ethylene glycol Isopropanol Aldehydes and ketones Nonaromatic aldehydes Aromatic aldehydes Nonaromatic ketones Furans Pyrans Sugars 1,5-Anhydro-b-D-arabino-furanose, Anhydro-b-D-glucopyranose (levoglucosan) 1,4:3,6-Dianhydro-a-D-glucanpyranose, LMM lignin Catechols Lignin-derived phenols Guaiacols (methoxy phenols) HMM lignin Extractives

Wet

Dry

23.9 4.3

0 5.6 1.5 3.4 0.2 0.6 2.9 0.3 2.6 20.3 9.72 0.009 5.36 3.37 1.10 45.3 0.27 4.01 0.17 17.7 0.06 0.09 3.82 2.6 5.7

2.23

15.41

34.44

13.44

1.950 4.35

C

H

N

O

40.0

6.7

0

53.3

60.0

13.3

0

26.7

59.9

6.5

0.1

33.5

44.1

6.6

0.1

25.2

68

6.7

0.1

25.2

63.5 75.4

5.9 9.0

0.3 0.2

30.3 15.4

Recent work indicates that recombination/polymerization of oil fragments in combination with evaporation of small molecules (including CO and CO2) could be an important cause of bio-oil ageing [29]. Although the reasons for instability may be unclear, it was also shown that the major chemical change in wood-derived oil is due to an increase in the DCM-insoluble fraction and a significant decrease in the ether-insoluble constituents. The increase in the average molecular weight in time, the viscosity (of the organic fraction) and pour point, and/or changes in the molecular structure cause phase separation. The instability of the oil and the varying quality of oils produced worldwide could be hurdles to further development in oil applications. Much depends on the eventual end application: although technologies are being already demonstrated at a significant scale (up to a 100 ton biomass throughput per day), standards and specifications are still underdeveloped. Some progress has, however, been made in recent years. Various physical and chemical methods for the characterization and analysis of bio-oil in relation to their future applications have now been identified. This applies to properties such as the viscosity, water content, pH, density, elemental composition, lower heating value (LHV), ash content, char content, surface tension, solubility in different solvents, ageing characteristics, and pour and flash points.

134

Fast Pyrolysis

5.3

Fast Pyrolysis Process Technologies

The aim of slow pyrolysis is to produce mainly charcoal, whereas fast pyrolysis is intended to convert biomass into a maximum quantity of liquid. Both processes have in common that the energy in the biomass feedstock is concentrated in a smaller volume by which transport costs and storage space can be reduced. Also beneficial is that a more uniform, stable, and cleaner-burning product is obtained that could serve as an intermediate energy carrier and feedstock for subsequent processing. In an industrial process, the by-products char or gas (both 10–20 wt%) would be used primarily as a fuel for the generation of the required process heat (including feedstock drying). The balance of char product could be used in the production of activated carbon, carbon black, pelletized fuel, soil amendment, or even carbon sequestration agent. The ash in the original biomass will be largely concentrated in the char product and is separated when the char is combusted in the process for drying and heating of the biomass feed stream. It allows recycling of the minerals as a natural fertilizer to the site where the biomass was grown originally. The gaseous by-product could also be used for electricity production in an engine, if properly cleaned. Essentially, there are no waste streams from the fast pyrolysis of biomass. The essential characteristics of fast pyrolysis for maximal oil production include very rapid heating of the biomass, operating temperature around 500
C, and rapid quenching of the vapors produced. Crucial is high rates of heating of the solid biomass particles. The energy to pyrolyze biomass depends upon the feedstock and the yield of bio-oil. Values from the literature are in the range 0.8–1.5 MJ/kg [30]. Moreover, the time and temperature profiles of the vapors produced affect the composition of the oil as well. In small laboratory reactors, where very rapid transfer rates are achieved and where vapor residence times of only a few tenths of a second can be realized, oil yield can be maximized. For heat-transferlimited systems and longer residence times of the pyrolysis vapors at higher temperatures, occurring especially in industrial-scale installations, the consequences of secondary cracking can become quite significant. In practice, high sand-to-biomass-particle heat transfer rates are required (on the order of 500 W/(m2 K)), intra-particle biomass heat transfer limitation should be avoided (requiring small biomass particles and a heat penetration depth of typically less than 2 mm), and vapour-phase residence times should be kept below a few seconds in order to maintain the oil yield [8]. Under such conditions, the biomass particles will be devolatilized within 10–30s. Where a pyrolysis plant is meant to produce a liquid fuel for combustion or gasification, the process could be designed in a way that maximizes the energy conversion to the liquid product. However, as shall be subsequently described, when the bio-oil product is meant to be used to derive transportation fuels or chemicals, factors other than the vapor residence time should also be considered. The composition of the oil can be steered by process conditions, equipment dimensions, and the application of catalysts. Although the thermal decomposition of various organic substances have been exploited for hundreds or even thousands of years, the emergence of fast pyrolysis occurred less than 30 years ago. During the 1980s and the early 1990s, research was focused on the development of special reactors, such as the vortex reactor, rotating blades reactor, rotating cone reactor, cyclone reactor, entrained flow, vacuum reactor, bubbling fluid-bed reactor, and circulating fluid-bed reactor. In the late 1990s this resulted in the construction of pilot plants in Spain (Union Fenosa), Italy (Enel), UK (Wellman), Canada (Pyrovac,

Fast Pyrolysis Process Technologies

135

Dynamotive), Finland (Fortum), and the Netherlands (BTG). In the USA and Canada, Ensyn’s circulating-bed process has been applied at a scale of around 1 ton/h for commercial production of a food ingredient called “liquid smoke.” Dynamotive and BTG designed and operate demonstration installations of 2–4 tons biomass per hour throughput for utilization of bio-oil in energy production. At the time of writing, the plants of Union Fenosa, Enel, Wellman, Fortum, and Pyrovac’s large-scale installation in Jonquiere, Canada, are not in operation any more. The reasons for this situation are various, but are driven by a lack of confidence in the economic prospects for bio-oil as boiler fuel or refinery feedstock, which will only be overcome by further improvement in the stability, physical properties, and chemical composition of bio-oil. The state of the art in the development of pyrolysis can be compared to the situation of the petrochemical industry in 1936, when demonstration of fluidized catalytic cracker (FCC) at a scale of 2000 barrels per day expanded the prospects for petroleum refining. Today, advances in the understanding of fast pyrolysis and catalytic processes to upgrade bio-oil are increasing interest in this technology. Petroleum companies and food/feed industries are building biofuel departments and look for existing knowledge matching their strategies and targets regarding renewable resources. Also, new developers of fast pyrolysis technology are showing their intentions with the construction of pilot plants based on proprietary technology. ForschungsZentrum Karlsruhe (now Karlsruhe Institute of Technology KIT) is constructing a plant of 5 tons/day in their laboratories based on a twin-screw reactor technology [31]. Since 2006, Pytec has been testing a small pilot plant based on ablative pyrolysis technology near Hamburg, and plans to construct a 50 tons/day installation in Mecklenburg-Vorpommern [32, 33]. TNO is operating a 30 kg/h pilot plant at the University of Twente in the Netherlands, based on cyclone reactor technology with integrated particle separation (”PyRos”). VTT in Finland has a well-equipped circulating fluid-bed pilot plant in operation (20 kg/h) for research purposes; it was erected in the mid 1990s on basis of the technology developed by Ensyn, Canada. A selection of historical developments will be discussed hereafter. 5.3.1

Entrained Downflow

Early attempts at fast pyrolysis were carried out in entrained-flow reactors, where biomass particles (1–5 mm) were fed into a stream of hot, inert gas. Reaction was thought to be complete within a residence time of a few seconds, if the reactor tube was held at temperatures between 700 and 800
C. Unlike many other fast pyrolysis reactors, no extra hot solid material was used to transport and heat the biomass particles. An early process was developed at Georgia Institute of Technology (USA) and a first unit transferred to Egemin in Belgium for further development and scale-up in a project funded partly by the EC. In pilotscale tests it appeared that the feedstock was incompletely pyrolyzed, particularly at the high feeding rates. Insufficient heat transfer to the solid biomass particles during their short travel in the reactor was the likely cause. The plant was dismantled in 1993. 5.3.2

Ablative Reactor

Ablative pyrolysis was then considered as a possible alternative to entrained-flow reactors. The principle of various pyrolysis technologies (including ablative) is given in Figure 5.6.

136

Fast Pyrolysis (a) biomass oil hot disc gas

char

air

oil

gas excess char/sand loop

biomass sand

char combustion air recycle gas

gas air biomass

molten salt

oil

vacuum vessel char

Figure 5.6 (a) Ablative, CFB, and vacuum technologies. (b) Fluid bed, screw (auger), and rotating cone technologies

The surface, heated by hot flue gas, rotates while biomass is pressed onto the hot surface (600
C). The flue gas is produced by combustion of pyrolysis gases/and or produced char. In the 1990s, BBC in Canada demonstrated an ablative flash pyrolysis technique for the disposal of tires at a 10–25 kg/h capacity. The process was licensed to Castle Capital for the

Fast Pyrolysis Process Technologies

137

(b) oil gas char

excess exces

fluid bed air

biomass

recycle gas

air

sand loop

gas sand

biomass

oil

char

air

char combustion sand

char/sand loop

biomass oil

gas air

Figure 5.6

(Continued )

erection of a 50 t/day plant in Halifax, Nova Scotia, using solid wastes. The project was never completed. Much of the pioneering work on ablative pyrolysis was carried out by the National Renewable Energy Laboratory (NREL) in the USA. In their approach, centrifugal forces

138

Fast Pyrolysis

were used to press the biomass onto the hot wall of the so-called vortex reactor [34]. The biomass, though, appeared to be insufficiently converted, requiring the recycling of solids. In 1989, NREL entered a consortium with Interchem Industries Inc. (USA) to develop and exploit NREL’s ablative pyrolysis for the production of phenol adhesives and alternative fuels. However, the construction of a demonstration plant was never completed. NREL abandoned the vortex design concept in 1997. In the 1990s, Aston University (Birmingham, UK) built and tested a prototype rotating blade reactor for ablative pyrolysis on a small scale of 3 kg/h. Oil samples were produced in yields of up to 80 wt%. At present, the German company Pytec is the only company developing ablative pyrolysis technology, with a pilot plant of 250 kg/h in operation near Hamburg [32] and plans for demonstration of a 2 t/h unit in MecklenburgVorpommern [33]. In general, ablative pyrolysis has two major limitations. First is the difficulty of getting sufficient heat transfer from hot gases to the ablative surface. Both the temperature difference between the hot flue gas (around 800
C) and the pyrolysis reactor (500
C), and the value of the heat transfer coefficient are relatively small. Second are difficulties in contacting feedstock of diverse morphologies (particle shape, structure, and density) with the ablative surface. In practice, relatively few feedstocks would be suitable for ablative pyrolysis. 5.3.3

Bubbling Fluidized Bed

Among the most successful methods for rapid heating of biomass particles is processing in bubbling fluidized beds. The principle of bubbling fluidized-bed pyrolysis is shown in Figure 5.6. Gas is injected vertically upward through a bed of granular material, such as sand, at sufficient velocity to cause a violent mixing of gas and solid into an emulsion that resembles a fluid. Fluidized beds are characterized by high heat and mass transfer rates between gas and particles and objects immersed in the bed. These conditions are very favorable for fast pyrolysis, as the biomass is rapidly heated and the vapors released are rapidly transported from the reactor. The bed is heated by externally combusting the produced gas and/or char and transferring this heat via direct heat transfer (hot solids added to the fluidized bed) or indirect heat transfer (hot gas or steam passed through tubes in the bed). While the sand-to-biomass heat transfer may be excellent (over 500 W/(m2 K)), the heat transfer from the heating coils to the fluid bed will be low, due to thermal resistance inside the coils (gas-to-coil wall heat transfer estimated 100–200 W/(m2 K)), and the limiting driving force of around 300
C as a maximum (600–800
C in coils versus 500–550
C in the fluid bed). In an optimistic scenario, at least 10–20 m2 surface area is required per ton/hour of biomass fed. The University of Waterloo in Canada began investigations of fluidized-bed pyrolyzers in the early 1980s. In 1990, a 200 kg/h demonstration plant was built by Union Fenosa, a utility company in Spain, for generation, transmission, and distribution of electricity, although this plant is no longer in operation. The Canadian company Dynamotive Corporation commercialized the fluidized-bed technology of the University of Waterloo. The design and development of the first commercial plant at West Lorne began in 2002. The plant started operations in early

Fast Pyrolysis Process Technologies

139

Figure 5.7 ForesteraTM pilot: reactor and product storage area (Reproduced from PyNe Newsletter)

February 2005 with a design capacity of 100 tons/day of waste sawdust. At the beginning of 2008 the plant was not in full production and did not reach the designed bio-oil production capacity, presumably due to mechanical and design difficulties. The company built a second plant in Guelph in 2006 with a design capacity of 200 tons/day. Operational performances for both plants are not available in the open literature The oil of the West Lorne facility was meant originally for combustion in Orenda’s GT 2500 gas turbine to produce electricity. A project description and update can be found in a PyNe newsletter [35]. Figure 5.7 shows a photograph of the West Lorne plant. The Orenda turbine is an industrial Mashproekt-designed engine, with nine axial and one radial stage compressor. Due to variations in the oil quality and a limited supply of oil, the turbine has limited hours of operation on bio-oil. Scale-up of bubbling fluidized-bed pyrolyzers is limited by the amount of heat that can be transferred through tubes submerged in the fluidized beds. Direct heat transfer by mixing inert hot solids into the reactor can overcome the limitations of indirect heat transfer. One manifestation of direct heat transfer is the use of twin fluidized beds to convey hot solids heated by combustion of gas and char in one bed into the second bed where pyrolysis occurs. Such a twin-bed system has been designed and constructed by Wellman Process Engineering in an EU-sponsored project coordinated by Aston University in Birmingham. Here, the fluidized bed was surrounded by a char combustor, with heat transfer through the separating wall and by exchange of solids. The construction of the pilot plant was completed in 1999, but owing to permit problems it was never started. Vapo Oil and Fortum Oil together undertook a similar project in 2001 [36], which is illustrated in Figure 5.8. The project was abandoned, presumably because of economic reasons.

140

Fast Pyrolysis

Figure 5.8 The Dynamotive’s West Lorne plant: wood feed hopper on left, char product hopper on right

Although fluidized-bed pyrolysis is thought to be well understood [2, 16], a number of improvements could be made: 1. Although the heat demand for pyrolysis is relatively modest, transferring heat by way of submerged tubes may limit the scale of pyrolyzers. Alternatives, such as direct heat transfer, deserve investigation. 2. Although char is conveniently separated from the fluidization media (sand) by elutriation of fine char from the bed, this requires a delicate control of fluidization gas velocity and operating temperatures in relation to the physical properties of the fluidized-bed particles and char. This requires a better understanding of the influence of biomass properties and operating conditions on the attrition and elutriation of char. 3. Char is suspected to catalyze secondary reactions during pyrolysis. Because char is entrained in the flow of pyrolysis vapors and gases, gas-solid contacting time needs to be minimized. Char accumulation in the fluid-bed reactor could also contribute to undesirable secondary reactions of pyrolysis vapors. 4. Owing to the entrainment of all char fines by the pyrolysis vapors, the solids loading in the gas is significant. This requires high-performance solids separators to avoid large quantities of char ending up in the bio-oil. Char fines in the bio-oil cause increased

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141

instability, problems in pumping, and, more importantly, difficulties in the end-use applications (turbines, engines, boilers). Perhaps because of the difficulties in char separation, Dynamotive now deliberately leaves the char in the bio-oil to produce a boiler fuel called BioOil Plus. 5. The gas used for fluidization of the reactor is recycled noncondensable gases from pyrolysis. This gas needs to be reheated and compressed, which requires careful cleaning to avoid blockage of heat exchangers, blowers, valves, and piping. 5.3.4

Circulating Fluidized Bed (CFB)

Circulating fluidized beds (CFBs) differ from bubbling fluidized beds in the amount of gas used to fluidize the bed. In circulating beds this gas flow is intentionally set high enough to transport particles out of the bed, which are recovered by gas cyclones and returned to the fluidized bed. Although this allows implementation of directly heating the fluidization media, the system is more complicated to design and operate than a bubbling fluidized-bed reactor. The first CFB process was developed at the University of Western Ontario in the late 1970s and early 1980s. Biomass could be converted to bio-oil at yields of over 70 wt%. As shown in Figure 5.6, biomass is screwed into the riser section of the CFB reactor, where rapid mixing of bed material (sand) and biomass takes place. Both char and sand are entrained in the gas flow, with heat transfer and pyrolysis occurring in the rising gas flow. At the exit of the riser, a gas cyclone separates the char and sand from the gas flow. The particulate matter enters a combustion chamber where the char is burned in air, heating the bed media, which is returned to the bottom of the riser. The gas flow passes to an oil recovery system, which uses a combination of devices to remove pyrolysis vapors and aerosols from the noncondensable gases. The Canadian company Ensyn Technologies Inc. (ETI) developed industrial applications for their rapid thermal processing (RTP) technology. Commercialization was enabled through the granting in 1990 of an exclusive license to Red Arrow Food Products Company Ltd of Wisconsin for production of liquid smoke and browning agents for the food industry. By 1996, there were four RTPÔ plants in commercial operation. In 2001, an RTPÔ biomass refining plant was built and commissioned to produce annually over 1800 tons of natural resin products from the existing bio-oil plants. In 2002, Ensyn increased its total capacity to 100 tons/day by taking into operation another RTPÔ plant. A sixth commercial RTPÔ biomass plant, designed to produce specialty chemical products, was built and put into service in 2003. Ensyn’s largest RTPÔ biomass refinery is established in Renfrew, Ontario, converting up to 200 tons of wood per day into natural resin products, co-polymers, other chemicals, liquid fuel, and green electricity. A photograph of an Ensyn plant is found in Freel [37]. Ensyn recently went into a joint venture with UOP, under the name Envergent Technologies LCC, to commercialize the pyrolysis technology for fuel substitution and electricity generation [38]. Another joint venture has been established by Finnish companies Metso and UPM to develop bio-oil production in combination with (existing) CFB biomass combustion units. The technology is based on the integration of conventional biomass-based fluidized-bed boilers with a (nondisclosed) pyrolysis reactor (in cooperation with VTT). The pyrolysis

142

Fast Pyrolysis

unit utilizes the circulating hot sand from the boiler as a heat source. The first production was accomplished at Metso’s test unit in Tampere (Finland) in 2010. Like bubbling fluidized beds, CFB technology is relatively well developed [1], but a number of operational problems remain. These include erosion of reactor internals and relatively complicated operation, especially the movement of hot solids from one reactor to another. These problems have been solved by the chemical industry in the development of fluid catalytic cracking, which employs a similar circulating solids system. The challenge for fast pyrolysis is sufficiently cleaning the noncondensable gases from fast pyrolysis to allow them to be reheated and compressed. Finally, for realizing the rather low solids holdup in riser systems at solid fluxes of 100–200 kg/(m2 s), the gas flow rate in the riser should be high, in the order of 1000 m3/h (tons/h biomass). 5.3.5

Moving-grate Vacuum Pyrolysis

The Universit
e de Sherbrooke and the Universit
e Laval, both in Canada, developed the socalled vacuum pyrolysis between 1981 and 1985. The process includes a combination of slow and fast pyrolysis conditions. Coarse solids are heated relatively slowly to temperatures higher than that of slow pyrolysis, while the gas is removed from the hot temperature zone relatively quickly by applying a reduced pressure of 2–20 kPa in the process. An attempt to commercialize it was carried out by Pyrovac International in the late 1990s. In the concept, biomass material was conveyed over horizontal grates, which were heated indirectly by a mixture of molten salts composed of potassium nitrate, sodium nitrite, and sodium nitrate [39] (see also Figure 5.9). The salt was heated by a gas burner fed with the noncondensable gases produced by the pyrolysis process. Limitations in heat transfer required the bed of particles to be agitated, but obviously internal heat transfer limitations cannot be avoided. A 3.5 t/h demonstration plant for bark pyrolysis was erected in Jonquiere Quebec, Canada, and taken into operation in 1998. For operational reasons, including limitations of heat transfer from a molten salt bath to the biomass, plant operation ceased in 2002. 5.3.6

Rotating-cone Pyrolyzer

Researchers at Twente University (Netherlands) developed rotating cone technology as a means of achieving the intense mixing and heat transfer between biomass and heat carrier characteristic of fluidized beds but without the large amounts of fluidizing gas. As shown in Figure 5.6, the rotating cone mechanically mixes biomass and hot sand without the aid of an inert gas. Similar to CFB operation, sand and char are separated from the pyrolysis vapors and transported to fluidized bed combustor where the char is burned to heat the sand before it is conveyed back to the rotating cone. The system is characterized by high solids throughput and short vapor residence times. BTG Biomass Technology Group in Enschede, the Netherlands, scaled up the rotating cone technology, first to about 50 kg/h. Figures 5.10 and 5.11 show the overall process scheme and a picture of the first pilot-plant version. A cone reactor was integrated in a circulating sand system composed of a riser, a fluid-bed char combustor, the rotating cone reactor, and a down-comer. In 2001 the system was further scaled up to 250 kg/h. From 2000 to 2010, about 100 tons of bio-oil was produced from over 50 different materials with

Bio-oil Fuel Applications

143

Figure 5.9 The Pyrovac installation in Jonqui ere, Canada (Reproduced with permission from Christian Roy)

particle sizes ranging from 1 to 5 mm. This development program culminated in a 50 t/day commercial unit in Malaysia (Figure 5.10) operated on empty fruit bunches from palm oil processing. From mid 2005 until 2008, the plant was operated daily. For an overview of the main achievements and shortcomings the reader is referred to a recent review by Venderbosch and Prins [40]. Meanwhile BTG is preparing the erection of a plant for fast pyrolysis of 5 tons of (clean and waste) wood per hour at the premises of Akzo Nobel in Hengelo, the Netherlands. The project is supported by the European Commission Construction and should be completed in 2012.

5.4

Bio-oil Fuel Applications

As an illustration, Table 5.3 shows the mass and heat flows in a large-scale fluid-bed fast pyrolysis process. A key advantage of producing liquids from biomass is that its production

144

Fast Pyrolysis bucket elevator

Flue gas

EFB

Flue gas combustor st

1 shredder feeding

ash

press reactor

flare air

air

wet air oil nd

oil cooling

2 shredder condensor

storage

water

drier

air

boiler

air

Figure 5.10 Process scheme of the Malaysian plant for fast pyrolysis of empty fruit bunches (EFB), including the complete chain from EFB reception, storage, pretreatment, and conversion

can be decoupled in time, scale, and place from the final application. The current status of subsequent secondary and tertiary processing of bio-oil is presented in Table 5.4. Owing to its high oxygen contents and the presence of a significant portion of water, the heating value of bio-oil is much lower than for fossil fuel. Nevertheless, combustion tests show that bio-oil from fast pyrolysis can replace heavy and light fuel oils in industrial boiler applications. In its combustion characteristics, the oil is more similar to light fuel oil, although significant differences in ignition, viscosity, energy content, stability, pH, and emission levels are observed. Problems identified in flame combustion of bio-oil are related to these deviating characteristics, but can be overcome in practice. Meanwhile, bio-oil has been used commercially to co-fire a coal utility boiler for power generation at Manitowoc Public Utilities in Wisconsin (USA). It has also been approved as a fuel for utility boilers in Swedish district heating applications. A successful co-firing test with 15 tons of bio-oil was conducted in 2002 in a 350 MWe natural-gas fired power station in the Netherlands [42]. Additional data are presented in Figure 5.12 and Table 5.5. A 4 h cofiring session was carried at a bio-oil throughput of 1.6 m3/h, or an equivalent of 8 MWth. While co-firing bio-oil power output of the plant remained constant at about 250 MWe. Natural gas flow to the boiler was reduced to compensate for the thermal energy of the bio-oil, which corresponded to 8 MWLHV. Oil from the Malaysian plant was routinely used to replace expensive diesel for start-up purposes of a fluidized-bed combustor near Kuala Lumpur International Airport. No results are reported in open literature. Since 2006, BTG has been actively involved in the combustion of the bio-oil in a standard 250 kW hot water generation unit, to replace diesel

Bio-oil Fuel Applications

Figure 5.11

145

BTG’s pyrolysis plant

and/or natural gas. For this purpose, sufficient quantities of palm-derived oil from Malaysia were transported to the Netherlands, and a dedicated oil lance was developed. Generally, the production of electricity is more attractive than process heat because of the higher added value of electricity, and its ease of distribution and marketing. Diesel engines are relatively insensitive to the contaminants present in bio-oil, especially in the case of large- and medium-scale engines, and bio-oil may be used. Tests have been performed by diesel engine companies like Ormrod Diesels and W€artsil€a Diesel, in collaboration with research institutes such as Aston University, VTT, MIT, and the University of Rostock [43–45]. A complete review was prepared by Venderbosch and van Helden [46]. In general, diesel engine development and tests suffer from insufficient quantities of available bio-oil. Nevertheless, the results obtained indicate that engine deterioration can

Stream no. Organics Water O2 N2 CO2 Pyrolysis gas Char Ash Sand Total Temp. (K) Pressure (bar) Chem. heat (MW) Heat (MW)

2 2000 200

20 2220 291 1 10.4

20

2920 291 1 10.4

Reactor feed

1 2000 900

Input

3000 291 1

600 2400

3

Air

1000 326 1.2 2.1

1000

4

Inert carrier gas

Table 5.3 Mass and energy balances for 2000 kg/h (daf) fluid-bed pyrolysis

200 304 1 0.42

200

5

Pyrolysis vapours

66 600 66 755 804 1 1.3 7.41

155

6

Heat carrier

1600 317 1 6.6

7 1200 400

Bio-oil

257 804 1 2.1 0.05

245 12

8

Surplus char

0.33

3868 400 1

8

740 250 2400 470

9

Flue gas

146 Fast Pyrolysis

Bio-oil Fuel Applications

147

Table 5.4 The status of primary, secondary and tertiary processing of pyrolysis products. Indices: 1 ¼ conceptual, 2 ¼ laboratory, 3 ¼ pilot, 4 ¼ demonstration, and 5 ¼ commercial. Indicated in bold are the most promising options on a short time-scale. (Reproduced from Reference [41] with permission from CPL Press) Primary product

Secondary processing

Secondary product

Tertiary processing

Final product

Liquid

transport5 combustion2 engine/turbine1 stabilisation1 upgrading1 extraction1,5 conversion3 conversion2 combustion5 engine/turbine3 fuel cell1 transport5 combustion5 slurrying2

fuel heat/steam electricity stabilised oil hydrocarbons chemicals chemicals gas heat/steam electricity electricity fuel heat/power liquid fuel

combustion5 steam turbine5 engine/turbine1 refining2 refining1,5 refining1,2 fuel cell1

heat/steam/electricity electricity electricity diesel/gasoline chemicals chemicals electricity

steam turbine5

electricity

combustion5 combustion3

heat/steam/electricity heat/power

Gas

Char

be a serious problem. However, traditional diesel engines are designed to operate on an acidfree diesel, and all engine components are manufactured in such a way and with such steel materials as to comply with traditional fossil fuels only. Severe wear and erosion was observed in the injection needles, due to the fuel’s acidity and the presence of abrasive particles. Nozzles lasted longer when filtered oil was used, but it is clear that standard nozzle materials are not adequate (see also Chiaramonti et al. [19]).

Figure 5.12 Mass and energy balances of Harculo power station

148

Fast Pyrolysis

Table 5.5 Power settings of Harculo station and the mass and energy balance as indicated in Figure 5.12 Input a

Natural gas (MWth)

Output Heat (MWth)

Power (MWe)

Efficiency (%)

Heat (MWth)

Gas turbine HC62 293.5 Steam turbine HC61 264.8 Total plant HC60 558.3

0 133.8 0

89.6 161.5 251.0

203.9 @ 520
C 30.5 237.2 @ 30
C 40.5 307.2 @ 30
C 45.0

Stream ID

1

2

3

4

5

T (
C) P (bar) Flow (kg/s) LHV (MWth) Heat (MWth)

Air 16 1.00 358 0 0

Natural gas Flue gas 16 520 8.45 1.06 6.67 365 293.45 0 0 203.88

Flue gas 520 1.02 123 0 70.05

Natural gas Flue gas 16 97 1.2 1.00 6.02 371 264.80 0 0 32.65

6

a

Natural gas LHV: 35.57 MJ/Nm3; 0.808 kg/Nm3 (Nm3: normal cubic metres).

High viscosity and loss of stability with rising temperatures are major problems with bio-oil as it is presently produced. Damage to nozzles and injection systems and buildup of carbon deposits in the combustion chamber and the exhaust valves are reported. Engines with larger cylinder bores (that is, medium- and low-speed engines) are expected to be the most suitable because of less stringent construction tolerances. For smaller bore engines, reduction of oil viscosity is likely required. Injection modification and/or a highturbulence combustion chamber are required. Because the bio-oil has bad ignition properties (cetane index), it should be enriched by addition of cetane improvers, and application of a dual fuel system is most appropriate. Self-cleaning injectors are possibly required [47]. At the end of the 1990s W€artsila stopped development work on bio-oil-fired engines, mainly due to the quality and quantity of bio-oils at that time. In spite of all these problems, it has also been reported that modifications of both the bio-oil and the engine can make bio-oils quite acceptable for diesels. This would not only offer prospects for standalone electricity production units, but in the future potentially for the application of bio-oil in the transportation sector (ships, trucks, tractors, buses). A substantial research and technology development effort with involvement of manufacturers is required to realize this application. 5.4.1

Gas Turbines

Experience with bio-oil combustion in gas turbines is limited, but R&D projects have been carried out by Orenda Division of Magellan Aerospace Corporation (Canada), ENEL Thermal Research Center (Italy), and Rostock University (Germany). Orenda is now actively seeking opportunities to run their Orenda GT2500 gas turbine engine on bio-oil. The GT2500 uses diesel oil and/or kerosene. Unlike aero-derived turbines, the GT2500 uses an external silo-type combustor, which permits easier modification for combustion of biooil. Several modifications are reported necessary for bio-oil combustion [19]. These include a low-pressure bio-oil supply system that preheats and filters the bio-oil, an improved nozzle

Bio-oil Fuel Applications

149

design to allow larger fuel flows and dual fuel operation, the redesign of the hot section, including section vanes and blades, and finally the use of stainless steel parts and modification of polymeric components. A 75 kWe nominal gas turbine was tested in dual fuel mode by Rostock University in 2001, showing deposits in the combustion chamber and turbine blades, and higher emissions of CO and hydrocarbons. 5.4.2

Gasification

Bio-oil may have another suitable end application, namely its use as a fuel for gasification. It should be noted here that, in refineries, gasification (next to combustion) is merely an endof-pipe technique, using (cheap) feedstocks that cannot be used elsewhere in the process. Regarding co-gasification of biomass residues, pyrolysis could play an important role as a pretreatment technique, facilitating the cheaper transport and handling of biomass feedstocks from origin to the site of gasification, over distances that biomass can never be shipped economically. Residue gasifiers can indeed be fed on bio-oil (e.g., see Higman and van der Burgt [48]), and issues of concern are mainly the pH (feed train) and alkaline ash content. Actual data on the (small-scale) entrained-flow gasification of bio-oil have been reported by Venderbosch et al. [49]. Entrained-flow experiments have been performed by BTG in UET’s (now Choren) entrained-flow gasifier in Freiberg (Germany) at about 500 kWth with pure oxygen, but no results have been reported so far. 5.4.3

Transportation Fuels

Bio-oil can also provide fuels for transportation. Initially, it was thought that bio-oil could be directly fired in diesel engines, but the acidity, viscosity, and presence of particulate matter make it unsuitable even for stationary diesel engines. Thus, bio-oil must be upgraded to fuels suitable for transportation. In general, bio-oils are upgraded in FCC reactors at atmospheric pressure or in high-pressure hydrotreating reactors. Some researchers advocate co-refining of partially upgraded bio-oil together with crude oil [50, 51]. A possible scheme for co-refining in standard refineries is illustrated in Figure 5.13 [52]. Upgrading of OVERALL BIOREFINERY CONCEPT incorporating fractionation with liquefaction Hydrocarbon-rich bio-liquid

Biomass residues

Primary fractionation and liquefaction

Co-processing in conventional petroleum refinery

Lignin-rich bio-liquid

Conventional fuels and chemicals

De-oxygenation (blending) Derivatives of hemicelluloses and celluloses

Conversion

Oxygenated products

Process residues Energy production

Figure 5.13 Biocoup’s concept of co-refining bio-oil in existing refineries

150

Fast Pyrolysis

bio-oil to transportation fuels is further discussed by Venderbosch et al. [53] and Wildschut et al. [54].

5.5

Chemicals from Bio-oil

Hundreds of compounds have been identified in GC analysis as fragments from lignin (amongst others phenols, eugenols, and guaiacols) and holocellulose (sugars, acetaldehyde, and formic acids). Large fractions of acetic acid, acetol, and hydroxyacetaldehyde are identified (see also Table 5.2). Until now, approximately 40–50% of the oil’s identity (excluding the water) has been revealed, but the large, less severely cracked or depolymerized molecules (derived from the cellulose and the lignin) in the oils are not identified. Figure 5.5 shows that all types of (oxygen) functionalities are present: acids, sugars, alcohols, ketones, aldehydes, phenols and their derivatives, furans, and other mixed oxygenates. Also (poly)phenols are present, sometimes in rather high concentrations. These phenolic fractions include phenol, eugenol, guaiacols and their derivatives, and the so-called pyrolytic lignin (poly-phenols) representing the water-insoluble components derived mostly from lignin. Carbohydrate derivatives of potential interest to the chemical industry are several types of anhydrosugars and oligosaccharides, formaldehyde, furfural alcohols, and hydroxyacetaldehyde to name a few. Owing to the principle of GC analysis, in which only the “distillable” components in the oil can be identified and quantified, levoglucosan is usually referred to as an important type of sugar to be isolated. However, much of the unidentified fraction of biooil commonly reported in the literature, up to 30 wt% of the oil, is likely to be saccharides, which were not detectable by the GC analytical methods commonly employed in the past (see Figure 5.5). The chemical composition of the bio-oil is influenced by feedstock properties and pyrolysis and bio-oil recovery operating conditions. Pretreatment of biomass may also dramatically influence yields of various compounds. Any discussion of chemicals from bio-oil must acknowledge the difficulties of analyzing bio-oil. In 1997, Milne et al. [55] remarked that among the over 100 compounds identified by 10 laboratories, not a single compound had been identified by all of the laboratories. Although this situation has improved, even recent round-robin testing showed little ability to replicate bio-oil analysis at different laboratories [56]. GC analysis does not reveal the identity or quantity of components that do not evaporate in the injection system. Part of the “discrepancy” in analysis results of the various laboratories is also caused by the continuous improvements in methodology during the last few years (increased use of GC–MS, HPLC) and the reliable identification of the various components. In the following sections, applications for bio-oil are further detailed. 5.5.1

Whole Bio-oil

5.5.1.1 Resins for the Production of Particle or Plywood Boards The use of bio-oil has been investigated for the replacement of phenol-formaldehyde resins in the manufacture of particleboard. Due to the higher cross-linking of the lignin-derived compounds in the bio-oil, a polymer with an improved strength can be obtained when mixed

Chemicals from Bio-oil

151

with conventional urea-formaldehyde resins. Research published in 2000 concluded that bio-oils can be used in the manufacture of resins in phenol substitution rates up to 50% [57]. A review on the production of renewable phenol resins based on pyrolysis products was recently published by Effendi et al. [58], in which the authors report considerable progress, but conclude that still none of the phenol production and fractionation techniques available allows complete substitution of the resin. 5.5.1.2 Fertilizers and Soil Conditioners Reaction of bio-oil with ammonia, urea, or other amino compounds produces stable amides, amines, and other nitrogen-rich compounds. These compounds are nontoxic to plants and can be used as slow-release organic fertilizers. Additional benefits are that the lignin degradation products and their reaction products are good for soil conditioning, control of soil acidity, amelioration of the effects of excess Al and Fe, increasing availability of phosphate, and crop stimulation. Furthermore, they are excellent complexing agents for nutrient metals such as Mo, Fe, B, Zn, Mn, and Cu. Other functional groups in the bio-oilderived fertilizers contain nutrients such as Ca, K, and P [59]. Pure bio-oil can be mixed with lime to form BioLimeÔ, a trademark of Dynamotive Technologies Corporation in Canada [60]. Injection of the mixture into flue-gas tunnels results in almost complete removal of sulfur oxides and a significant reduction of nitrogen oxides. This product does not appear to have been commercially developed at this time. 5.5.2

Fractions of Bio-oil

In wood-derived bio-oil, specific oxygenated compounds are present in substantial amounts. The recovery of such pure compounds from the complex bio-oil may be technically feasible but is probably economically unattractive because of the high costs for the recovery of the chemical and its low concentration in the oil. In the following, the relevant chemical components are presented. 5.5.2.1 Wood Flavors The only commercial application of wood-derived bio-oil to date is that of wood flavor or liquid smoke. A number of companies produce these liquids by adding water to the bio-oil. A red-colored product is obtained that can be sprayed over meat before cooking. The taste, color, and smell of the meat are thus created “artificially.” A range of food flavoring products, based upon bio-oil, has been patented and commercialized by Red Arrow Products Company (USA) and by Chemviron (Germany). One patent is given here as an example [61]. 5.5.2.2 Phenolic Compounds The lignin-derived fraction of bio-oil consists of phenol, eugenol, cresols, and xylenols, and larger quantities of alkylated (poly-) phenols (the so-called water-insoluble pyrolytic lignin). Recoveries of phenolic compounds up to 50 wt% have been reported, but this is from specific feedstocks only. The amount of the smaller, more expensive, phenolic components in bio-oil is usually limited, either because the original lignin in the biomass only partially depolymerizes or lignin-derived monomers are highly reactive in the pyrolysis environment [10] (see also Section 1.1).

152

Fast Pyrolysis

5.5.2.3 Resins In nature, lignin acts as an adhesive to bind cellulose fibers, which suggests the use of ligninderived compounds in bio-oil as biomass-based adhesive resins [2, 62]. Using its RTPÔ technology, Ensyn is reported to have produced more than 1800 tons of natural resin products in 2001, although no additional information is available. Phenolics from bio-oil have also been proposed for use as an alternative wood preservative to replace creosotes [63]. 5.5.2.4 Sugars Levoglucosan (mono-dehydrated glucose) and other anhydrosugars, which are slightly volatile, are commonly detected in bio-oil using GC analysis. Other sugars are not directly detectable via GC without derivatization and are less frequently reported in the pyrolysis literature, although HPLC is increasingly being performed on bio-oil, which should correct this deficiency. Extensive overviews on levoglucosan are given elsewhere, in particular two papers written separately by Dobele and by Radlein, both published in Bridgwater [2]. Levoglucosenone, which is doubly dehydrated glucose, is reportedly applicable in the synthesis of antibiotics/pheromones, rare sugars, butenolide, immunosuppressive agents, whisky lactones, and so on and is reportedly present in amounts up to 24 wt% [64]. Progress in recent years to valorize bio-oil on the basis of these two interesting products is limited though. 5.5.2.5 Hydroxyacetaldehyde This aldehyde is present in bio-oil in concentrations as high as 17 wt% [64]. It is a commercially significant molecule, used as browning agent for cheese, meat, sausages, poultry, and fish. Another possible application is use as a precursor for glyoxal OHC–CHO synthesis, which is an important chemical produced by oxidation of ethylene glycol [65]. 5.5.2.6 Calcium Carboxylates These salts of carboxylic acids include calcium acetate and calcium formate [66]. In the aqueous fraction of the bio-oil these acids are usually present in modest concentrations (up to 3 wt%). They have potential applications in areas such as road or runway deicing, sulfur dioxide removal during fossil fuel combustion, or as a catalyst during coal combustion. 5.5.2.7 Furfural Derivatives Pavlath and Gregorski [67] pyrolyzed five carbohydrate products (glucose, maltose, cellobiose, amylase, and cellulose) and showed that furfural and furfuryl alcohol up to 30 wt% and 12–30 wt% respectively were produced. These compounds have commercially significant applications.

5.6

Concluding Remarks

Fast pyrolysis has intriguing prospects for rapidly and inexpensively depolymerizing plant molecules. Commercial processes have been developed by several companies, including BTG (Malaysia), DynaMotive (Canada) and Ensyn (USA and Canada). Further growth in the industry requires full-scale plants (H2 t/h) providing bio-oil to a variety of applications

References

153

in steady operation (H8000 h/year). Although transportation fuels and high-value chemicals are attractive long-term goals for bio-oil, more immediate targets are process heat and electricity. Once the process (and peripherals) is proven, larger amounts of oil will become available for the development and commercial-scale demonstration of a wide range of biooil applications. Immediate challenges for the pyrolysis industry are improving the reliability of plant operations, including heat transfer, heat integration, and bio-oil recovery. Within the research community, improvements in bio-oil analysis and improvement of bio-oil properties for various applications should be addressed. Despite almost 30 years of experience with bio-oil, analysis is often incomplete or cannot be replicated in other laboratories. Today, it is recognized that GC analysis does not give a complete picture of bio-oil composition. Improving bio-oil will require not only better understanding of the fundamental chemistry of fast pyrolysis, but the chemistry of the bio-oil product. One particular issue to be addressed is the exact role of the various oxygen functionalities in the oil, and to establish which functionalities are preferred.

Acknowledgements We would like to thank Erik Heeres and Agnes Ardiyanti from the University of Groningen for carrying out the TGA experiments reported in Figure 5.1 and Dietrich Meier from the von Thu¨nen Institute, Hamburg, for allowing us to use his presentation of pyrolysis technologies to prepare Figure 5.6.

References [1] Bridgwater, A.V. (ed.) (1999) Fast Pyrolysis of Biomass: A Handbook, volume 1, CPL Press, Newbury (ISBN 1-872691-07-2). [2] Bridgwater, A.V. (2007) Biomass pyrolysis, Report IEA Bioenergy, T34:2007:01. [3] Bridgwater, A.V. (ed.) (2002) Fast Pyrolysis of Biomass: A Handbook, volume 2, CPL Press, Newbury (ISBN 1-872691-47-1). [4] Bridgwater, A.V. (ed.) (2005) Fast Pyrolysis of Biomass: A Handbook, volume 3, CPL Press, Newbury (ISBN 1-872691-92-7). [5] Antal, M.J. (1983) Biomass pyrolysis: a review of the literature, part 1, carbohydrate pyrolysis. Advances in Solar Energy, 1, 61. [6] Wang, X., Kersten, S.R.A., Prins, W., and van Swaaij, W.P.M. (2005) Biomass pyrolysis in a fluidized bed reactor. Part 2: experimental validation of model results. Industrial & Engineering Chemistry Research, 44 (23), 8786–8795. [7] Wang, X. (2006) Biomass fast pyrolysis in a fluidized bed, Thesis, University of Twente. [8] Kersten, S.R.A., Wang, X., Prins, W., and Van Swaaij, W.P.M. (2005) Biomass pyrolysis in a fluidized bed reactor. Part 1: literature review and model simulations 2005. Industrial & Engineering Chemistry Research, 44 (23), 8773–8785. [9] Gupta, A.K. and Lilley, D.G. (2003) Thermal destruction of wastes and plastics, in Plastics and the Environment (ed. A.L. Andrady), Wiley-Interscience, pp. 629–696. [10] Yang, H., Yan, R., Chen, H. et al. (2007) Characteristics of hemicellulose, cellulose and lignin pyrolysis. Fuel, 86, 1781–1788. [11] Vaca Garcia, C. (2008) Biomaterials, in Introduction to Chemicals from Biomass (eds J. Clark and F. Deswarte), John Wiley & Sons (ISBN 978-0-470-05805-3). [12] Rath, J., Wolfinger, M.G., Steiner, G. et al. (2003) Heat of wood pyrolysis. Fuel, 82 (1), 81–91.

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[13] Shafizadeh, F. and Chin, P.P.S. (1977) Thermal deterioration of wood, in Wood Technology: Chemical Aspects (ed. I.S. Goldstein), ACS Symposium Series, vol. 43, American Chemical Society, pp. 57–81. [14] Shafizadeh F. (1985) Pyrolytic reactions and products of biomass, in Proceedings: Fundamentals of Thermochemical Biomass Conversion (eds R.P. Overend, T.A. Milne, and L.K. Mudge), Elsevier Applied Science, pp. 183–217. [15] Wagenaar, B.N., Prins, W., and Van Swaaij, W.P.M. (1994) Pyrolysis of biomass in the rotating cone reactor: modeling and experimental justification. Chemical Engineering Science, 49 (24B), 5109–5126. Wagenaar, B. (1994) The rotating cone reactor for rapid thermal solids processing. Thesis, University of Twente. [16] Di Blasi, C. (2008) Modelling chemical and physical processes of wood and biomass pyrolysis. Progress in Energy and Combustion Science, 34, 47–90. [17] Radlein, D., Piskorz, J., and Scott, D.S. (1991) Fast pyrolysis of natural polysaccharides as a potential industrial process. Journal of Analytical and Applied Pyrolysis, 19, 41–63. [18] Fahmi, R., Bridgwater, A.V., Donnison, I., and Yates, N. (2008) The effect of lignin and inorganic species in biomass on pyrolysis oil yield, quality and stability. Fuel, 87, 1230–1240. [19] Chiaramonti, D., Oasmaa, A., and Solantausta, Y. (2007) Power generation using fast pyrolysis liquids from biomass. Renewable and Sustainable Energy Reviews, 11, 1056–1086. [20] Di Blasi, C., Branca, C., and Galgano, A. (2008) Thermal and catalytic decomposition of wood impregnated with sulfur- and phosphorus-containing ammonium salts. Polymer Degradation and Stability, 93, 335–346. [21] Scott, D.S., Czernik, S., Piskorz, J., and Radlein, D. (1989) Sugars from biomass cellulose by a thermal conversion process, in Proceedings of IGT’s Energy from Biomass and Waste XII, 13-17 February, New Orleans. [22] Piskorz, J., Radlein, D., Scott, D.S., and Czernik, S. (1988) Liquid products from the fast pyrolysis of wood and cellulose, in Research in Thermochemical Biomass Conversion (eds A.V. Bridgwater and J.L. Kuester), Elsevier Applied Science, London, pp. 557–571. [23] Freel, B.A., Graham, R.G., Huffman, D.R., and Vogiatzis, A.J. (1993) Rapid thermal processing of biomass (RTP): development, demonstration, and commercialization. Energy Biomass Wastes, 16, 811–826. [24] Oasmaa, A. (1999) Fuel oil quality properties of wood-based pyrolysis liquids. Thesis, University of Jyvaskyla, Finland. [25] BTG (2007) SimCrude: Simultane Productie Biocrude en Pyrolyse Olie, Report for SenterNovem, number 0268-05-04-04-001 (in Dutch). [26] Diebold, J.P. and Bridgwater, A.V. (1997) Overview of fast pyrolysis of biomass for the production of liquid fuels, in Developments in Thermochemical Biomass Conversion (eds A. V. Bridgwater and D.G.B. Boocock), Blackie Academic & Professional, London. [27] Daugaard, D.E. and Brown, R.C. (2004) The transport phase of pyrolytic oil exiting a fast fluidized bed reactor, in Proceedings of the Science of Thermal and Chemical Biomass Conversion Conference, Victoria, BC, Canada, 30 August–2 September. [28] Diebold, J.P. (2002) A review of the chemical and physical mechanisms of the storage stability of fast pyrolysis bio-oils, in Fast Pyrolysis of Biomass: A Handbook, Vol. 2, (ed. A.V. Bridgwater), CPL Press, Newbury. [29] Oasmaa, A. and Kuoppala, E. (2003) Fast pyrolysis of forestry residue. 3. Storage stability of liquid fuel. Energy and Fuels, 17 (4), 1075–1084. [30] Daugaard, D.E. and Brown, R.C. (2003) Enthalpy for pyrolysis for several types of biomass. Energy and Fuels, 17, 934–939. [31] Dahmen, N., Dinjus, E., Henrich, E. et al. (2007) Fast pyrolysis by a twin scale mixing reactor. Status of the FZK research facilities, in Success and Vision for Bioenergy: A European Workshop on Success and Visions in Thermal Processing for Bioenergy, Biofuels and Bioproducts, Salzburg, Austria, 22-23 March. [32] Sch€oll, S., Klaubert, H., and Meier, D. (2004) Wood liquefaction by flash-pyrolysis with an innovative pyrolysis system, in DGMK proceeding 2004-1 contributions to DGMK-meeting, “Energetic Utzilization to Bio masses”, 19–21 April, Velen/Westf.

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6 Upgrading Fast Pyrolysis Liquids Anthony V. Bridgwater Bioenergy Research Group, Aston University, Birmingham B4 7ET, UK

6.1 6.1.1

Introduction to Fast Pyrolysis and Bio-oil Introduction

Pyrolysis is thermal decomposition occurring in the absence of oxygen. Lower process temperatures and longer vapor residence times favor the production of charcoal; high temperatures and longer residence times increase biomass conversion to gas; and moderate temperatures and short vapor residence time are optimum for producing liquids which are widely referred to a bio-oil. Three products are always produced, but the proportions can be varied over a wide range by adjustment of the process parameters. Fast pyrolysis for liquids production is of particular interest, as high yields of a liquid are obtained which can be stored and transported, and used for energy, chemicals or as an energy carrier. The principles and technology of fast pyrolysis are reviewed by Venderbosch and Prins in Chapter 5. Bio-oil, the main product from fast pyrolysis at moderate temperatures of around 500
C, is obtained in yields of up to 75 wt% on a dry-feed basis, together with by-product char and gas, which can be used within the process to provide the process heat requirements; so, there are no waste streams other than flue gas and ash. Liquid yield and quality depend on many factors, which are described below. 6.1.2

Bio-oil General Characteristics

Crude pyrolysis liquid or bio-oil is dark brown and approximates to biomass in elemental composition. It is composed of a very complex mixture of oxygenated hydrocarbons with an appreciable proportion of water from both the original moisture and reaction product. Solid Thermochemical Processing of Biomass: Conversion into Fuels, Chemicals and Power, First Edition . Edited by Robert C. Brown © 2011 John Wiley & Sons, Ltd. Published 2011 by John Wiley & Sons, Ltd. ISBN: 978-0-470-72111-7

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Upgrading Fast Pyrolysis Liquids Table 6.1

Typical properties of wood-derived crude bio-oil

Physical property Moisture content (%) pH Specific gravity Elemental analysis C (%) H (%) O (%) N (%) HHVa as produced (MJ/kg) Miscibility with hydrocarbons Viscosity (40
C and 25 % water) (cP) Solids (char) (%) Stability Vacuum distillation residue (%)

Typical value 25 2.5 1.20 56 6 38 0–0.1 17 Very low 40–100 0.1 Poor up to 50

a

HHV: higher heating value.

char may also be present. The liquid is formed by rapid quenching of the vapors and aerosols which are thus prevented from secondary reactions. The product, therefore, is not as stable as many liquid fuels and has a tendency to slowly change some physical and chemical characteristics over time. This is referred to as aging. Fast-pyrolysis liquid has a higher heating value of about 17 MJ/kg as produced with about 25 wt%. water that cannot readily be separated. There are some important characteristics of this liquid that are summarized in Table 6.1 and discussed below. The liquid is formed by rapidly quenching, and thus “freezing,” of the intermediate products of flash degradation of hemicellulose, cellulose, and lignin. The liquid thus contains many reactive species, which contribute to its unusual attributes. Bio-oil can be considered a microemulsion in which the continuous phase is an aqueous solution of holocellulose decomposition products, which stabilizes the discontinuous phase of pyrolytic lignin macromolecules through mechanisms such as hydrogen bonding. The dispersed
phase is micelles of pyrolytic lignin of around 500 A in diameter and the microemulsion is maintained by naturally derived surfactants. Aging or instability is believed to result from a breakdown in this emulsion. In some ways it is analogous to asphaltenes found in petroleum. The liquid has a distinctive odor, an acrid smoky smell due to the low molecular weight aldehydes and acids, which can irritate the eyes on prolonged exposure. The liquid contains several hundred different chemicals in widely varying proportions, ranging from formaldehyde and acetic acid to complex high molecular weight phenols, anhydrosugars, and other oligosaccharides. The liquid contains varying quantities of water, which forms a stable single-phase mixture, ranging from about 15 wt% to an upper limit of about 35 wt% water, depending on the feed material and how it was produced and subsequently collected. A typical feed material specification is a maximum of 10% moisture in the dried feed material, as both this feed moisture and the water of reaction from pyrolysis, typically about 12% based on dry feed, report to the liquid product. The density of the liquid is very high at around 1.2 kg/L, compared with light fuel oil at around 0.85 kg/L. This means that the liquid has about 42% of the energy content of fuel oil

Significant Factors Affecting Characteristics

159

on a weight basis, but 61% on a volumetric basis. This has implications for the design and specification of equipment such as pumps and atomizers in boilers and engines. Viscosity is important in many fuel applications [1]. The viscosity of the bio-oil as produced can vary from as low as 25 cSt (1 cSt ¼ 1 mm2/s) to as high as 1000 cSt (measured at 40
C) or more depending on the feedstock, the water content of the oil, the amount of light ends collected, and the extent to which the oil has aged. Pyrolysis liquids cannot be completely vaporized once they have been recovered from the vapor phase. If the liquid is heated to 100
C or more to try to remove water or distil off lighter fractions, it rapidly reacts and eventually produces a solid residue of around 50 wt% of the original liquid and some distillate containing volatile organic compounds, including cracked compounds and water. While bio-oil has been successfully stored for several years in normal storage conditions in steel and plastic drums without any deterioration that would prevent its use in any of the applications tested to date, it does change slowly with time; most noticeably there is a gradual increase in viscosity. More recent samples that have been distributed for testing have shown substantial improvements in consistency and stability, demonstrating the improvement in process design and control as the technology develops.

6.2

Liquid Characteristics and Quality

The objective or purpose of upgrading bio-oil is to improve its quality; that is, to reduce or remove one or more of its undesirable characteristics or properties. This requires a thorough appreciation of the characteristics or properties of bio-oil, which are listed in Table 6.2 with causes, effects, and solutions. More important is the definition of the term “quality,” since different applications have different requirements in terms of characteristics, some of which have been reviewed [2]. Each of these characteristics is described in more detail later in this chapter, with an emphasis on those aspects that have attracted most interest and attention in recent years and which are of potentially greater significance. This includes biofuels by hydrotreatment, biofuels by zeolite cracking, biofuels by gasification and synthesis, hydrogen production by steam reforming, chemicals recovery, and stability improvement.

6.3 6.3.1

Significant Factors Affecting Characteristics Feed Material

The composition of the biomass feed has a significant effect on both the yield and quality of the resulting bio-oil. The main parameters are ash, water content of biomass, composition of biomass, and contamination of biomass. Each of these is discussed in Section 6.5. 6.3.1.1 Ash Content and Composition Biomass contains a variety of metals that are necessary for the movement of nutrients within the plant, of which the most significant are potassium and sodium. Both are catalytically active in fast pyrolysis through cracking to water and CO2 in the vapor phase, and ash contents above around 2.5 wt% often lead to a phase-separated product in significantly

Nearly all alkali metals report to char so not a big problem. High ash feed.

3. Alkali metals

Incomplete char separation in process

Contaminants in biomass feed

Cracking of biopolymers and char

4. Char

5. Chlorine

6. Color

Incomplete solids separation

Continuation of secondary reactions, including polymerization

2. Aging

Cause

Organic acids from biopolymer degradation

1. Acidity or low pH

Characteristic

Table 6.2 Characteristics of bio-oil Effect

Discoloration of some products such as resins

Deposition of solids in combustion. Erosion and corrosion. Slag formation. Damage to turbines Aging of oil. Sedimentation. Filter blockage. Catalyst blockage. Engine injector blockage. Alkali metal poisoning Catalyst poisoning in upgrading

Slow increase in viscosity from secondary reactions such as condensation. Potential phase separation Catalyst poisoning

Corrosion of vessels and pipework

Solution

Include suitable cleaning processes either upstream or downstream Efficient char filtration. Deoxygenation

Improved cyclones. Multiple cyclones. Hot vapor filtration

Process oil. Modify application

Hot vapor filtration.

Careful materials selection, such as polyolefins or stainless steel Do not store for long periods. Avoid exposure to air. Add water. Add co-solvents Pretreat feed to remove ash.

Comments

Only important where visible, such as resins or blended products

Important for biofuel production

Almost all alkali metals report to char, so good char separation minimizes alkali metals in oil

Important

Important in all applications

160 Upgrading Fast Pyrolysis Liquids

Reactive mixture of degradation products

8. Distillability is poor

15. Nitrogen

13. Materials incompatibility 14. Miscibility with hydrocarbons is very low

Contaminants in biomass feed. High-nitrogen feed, such as proteins in wastes

Highly oxygenated nature of bio-oil

See Acidity (Section 6.5.1) Phenolics and aromatics

12. Low pH

11. Low H:C ratio

See Phase Separation (Section 6.5.18) Biomass has low H:C ratio

10. Inhomogeneity

9. High viscosity

Poor harvesting practice

7. Contamination of feed

Destruction of seals and gaskets Will not mix with any hydrocarbons, so integration into a refinery is more difficult Unpleasant smell. Catalyst poisoning in upgrading. NOx in combustion

Upgrading to hydrocarbons is more difficult

Bio-oil cannot be distilled – maximum 50% typically. Liquid begins to react at below 100
C and substantially decomposes above 100
C Gives high pressure drop, increasing equipment cost. High pumping cost. Poor atomization

Contaminants, notably soil, act as catalysts and can increase particulate carryover

Careful feed selection Feed blending. Include suitable cleaning processes. Add NOx removal in combustion applications

Careful materials selection Upgrading by hydrotreating or cracking with zeolites

Add hydrogen and/or remove oxygen

Careful heating up to 50
C; rapid in-line heating to 80
C is also possible. Add water. Add co-solvents

Wash biomass None known

Improve harvesting practice.

(continued)

Important for biofuel production

See Upgrading to Biofuels (Section 6.6.2.2)

See Upgrading to Biofuels (Section 6.6.2.2)

Important in heat and power applications

Important for biofuel production and refinery integration

Significant Factors Affecting Characteristics 161

High feed water. High ash in feed. Poor char separation

Aldehydes and other volatile organics, many from hemicellulose

See also char (also Section 6.5.4). Particulates from reactor such as sand. Particulates from feed contamination The unique structure is caused by the rapid depolymerization and rapid quenching of the vapors and aerosols Contaminants in biomass feed Incomplete reactions

18. Phase separation or inhomogeneity

19. Smell

20. Solids

23. Temperature sensitivity

22. Sulfur

21. Structure

See smell (Section 6.4.19) Biomass composition

Cause

16. Odour 17. Oxygen content is very high

Characteristic

Table 6.2 (Continued )

Catalyst poisoning in upgrading Irreversible decomposition of liquid into two phases H100
C. Potential phase separation H60
C

Susceptibility to aging, such as viscosity increase and phase separation

Sedimentation. Erosion and corrosion. Blockage

Nonmiscibility with hydrocarbons Phase separation. Partial phase separation. Layering. Poor mixing. Inconsistency in handling, storage and processing While not toxic, the smell is often objectionable

Poor stability.

Effect

Include suitable cleaning processes Store liquids at room temperature, preferably in absence of air

None known

Better process design and management. Reduction in hemicelluloses content of feed. Containment and/or venting to flare Filtration of vapor or liquid

Modify or change process. Modify or change feedstock. Add co-solvents. Control water content

Reduce oxygen thermally and/or catalytically

Solution

Important for biofuel production Important for all applications

See Aging (Section 6.5.2)

May be important for biofuel production

Important for biofuel production

Comments

162 Upgrading Fast Pyrolysis Liquids

Nature of bio-oil

Pyrolysis reactions.

25. Viscosity

26. Water content

Feed water

Biopolymer degradation products

24. Toxicity

Affects catalysts

Human toxicity is positive but small. Eco-toxicity is negligible Fairly high and variable with time. Greater temperature influence than hydrocarbons Complex effect on viscosity and stability: increased water lowers heating value, density, stability, and increase pH. Optimize for application

Control water in feed. Optimize at 25% for consistency and miscibility.

Water and/or solvent addition reduces viscosity

Health and safety precautions

Important in biofuel production

Important for heat and power

Significant Factors Affecting Characteristics 163

164

Upgrading Fast Pyrolysis Liquids

lower yields [3]. Ash and inorganics can also arise from contamination during harvesting, as discussed below. 6.3.1.2 Water Content of Prepared Biomass As bio-oil is oleophobic, all feed water reports to the bio-oil. Water is also formed from fast pyrolysis reactions; so, to maintain a reasonable water level in bio-oil, feed water is usually limited to 10 wt%. This typically gives water content of 25 wt% in the bio-oil. This level minimizes the potential for phase separation and gives a manageable viscosity. 6.3.1.3 Composition of Biomass In addition to hemicellulose, cellulose, and lignin, biomass can contain other components, including ash and water (as discussed above), contaminants (discussed below), and minor organic components (such as extractives, oils, and proteins). The extractives and oils can lead to a separate phase developing at the top of the bio-oil. Proteins have high nitrogen content and lead to a distinctive and unpleasant odor. 6.3.1.4 Contamination of Biomass Biomass can be contaminated in many ways, such as: chlorine from seaside locations and biocide applications; sulfur from fertilizer applications; metals and inorganic compounds from soil during harvesting, such as mud splashing during rain and accumulation from dragging over soil. All contaminants will have an influence on the yield and quality of the bio-oil produced, as discussed below. 6.3.2

Reactors

At the heart of a fast-pyrolysis process is the reactor. Although it probably represents only one stage in the overall fast-pyrolysis system, most research and development has focused on the reactor, although increasing attention is now being paid to control and improvement of liquid quality and improvement of collection systems. The rest of the process consists of biomass reception, storage and handling, biomass drying and grinding, product collection, storage, and, when relevant, upgrading. Several comprehensive reviews of fast-pyrolysis processes for liquids production are available; for example, see Refs [2, 4–8]. 6.3.2.1 Temperature Both the time–temperature profile of the gases and vapors and the char and the liquid collection system influence the quality of bio-oil. Temperatures below 400
C result in fractional condensation of high molecular weight oigomers derived from lignin. While the removal of these oligomers reduces the viscosity and stability of the remaining bio-oil, control of this fractionation is difficult and usually results in blockage. Temperatures above 550
C promote secondary cracking reactions, resulting in lower liquid yields and higher water and gas yields. This increases the propensity of the oil to age and phase separate. Systems with sand recycle thus need to balance the hot sand flow rate of hot sand with sand temperature to minimize these effects. Entrained-flow reactors require such a high temperature gradient between gas and pyrolysis to affect the necessary heating rates and reaction temperature that the liquid yield and quality suffer.

Bio-oil Upgrading

165

6.3.2.2 Char Separation The significance, efficiency, and effectiveness of char separation are discussed in Section 6.5.4.

6.4

Norms and Standards

For bio-oil to successfully become a traded commodity, norms and standards are required. The first attempts at defining quality were carried out in 1995 by an international group from North America and Europe [1]. This was developed subsequently with exploration and development of standard tests for bio-oil [9–12] up to certification by CEN in Europe and ASTM in North America [13, 14]. The evaluation and development of test methods is very important in defining quality and setting standards for definition and marketing.

6.5

Bio-oil Upgrading

Bio-oil can be upgraded in a number of ways: physically, chemically, and catalytically. This has been extensively reviewed [15–19]. Some aspects are particularly significant and have attracted more extensive attention, including: . . . . . .

stability improvement, reviewed in Section 6.5.2; biofuels by gasification and synthesis, reviewed in Section 6.6.2.2; biofuels by hydrotreatment, reviewed in Section 6.6.2.3; biofuels by zeolite cracking, reviewed in Section 6.6.2.4; hydrogen production by steam reforming, reviewed in Section 6.6.3.5; chemicals recovery, reviewed in Section 6.6.5.

These have dedicated sections as indicated. 6.5.1

Acidity or Low pH

Bio-oil has a typical pH of around 2.5 from the organic acids formed by degradation or cracking of the biopolymers that make up biomass, particularly the cellulose and hemicellulose. Hemicellulose can be preferentially reduced by washing in hot water or dilute acid and by torrefaction (see Section 6.5.19). Neither method is very effective, since cellulose is also affected in both methods. There has been only a little work on corrosion of metals in biooil [20]. The general view is that polyolefins and stainless steel are acceptable materials of construction. High acidity can be managed in several ways, including esterification (see Section 6.6.3.3) and addition of magnesium powder, an alloy or a magnesium compound [21]. 6.5.2

Aging

Aging or instability is a known problem that affects most bio-oils. It is caused by continued reaction of the decomposition products from fast pyrolysis [15]. Polar solvents have been used for many years to homogenize and reduce the viscosity of biomass oils. The addition of solvents, especially methanol, showed a significant effect on the oil stability. Diebold and

166

Upgrading Fast Pyrolysis Liquids

Czernik [22] found that the rate of viscosity increase (“aging”) for the oil with 10 wt% of methanol was almost 20 times less than for the oil without additives. A stability test based on changes in viscosity is described in Section 6.5.24. 6.5.3

Alkali Metals

All biomass contains ash in which alkali metals, notably potassium and sodium, dominate. Potassium, in particular, and other alkali metals are catalytically active and enhance secondary cracking reactions. This results in loss of liquid yield, higher water (and carbon dioxide) production, and potential phase separation from higher water content and loss of naturally derived surfactants that maintain the microemulsion of bio-oil. Woody feeds typically contain up to 1 wt% ash, while grasses can range up to 8 wt% ash. The amount of ash in perennial crops depends upon harvesting time, since a significant proportion of the nutrients in above-ground plant matter returns to the rhizome at the end of the growing season. In addition, ash will be leached from the standing crop during winter from rainfall to potentially give ash contents below 2.5 wt%. The limiting value of ash content to reduce or avoid this effect is believed to be around 2.5 wt%, although this depends on other process parameters and the composition of the ash. Washing biomass with water or dilute acid is feasible to remove ash, but it is costly in financial and energy terms both for washing and subsequent drying. However, a further advantage of acid washing is the potential removal of hemicelluloses, from which are derived aldehydes and related degradation products that contribute an unpleasant odor to bio-oil and are partially responsible for the aging effect. So, as with many other characteristics of bio-oil, effects are complex and can be difficult to evaluate comprehensively. 6.5.4

Char

Char acts as a vapor cracking catalyst, so rapid and effective separation from the pyrolysis product vapors is essential. Cyclones are the usual method of char removal; however, some fines always pass through the cyclones and collect in the liquid product, where they accelerate aging and exacerbate the instability problem, which is described below. A more effective, but more difficult, method is hot-vapor filtration, which is also described below. 6.5.4.1 Cyclones It is important to separate char as quickly as possible to minimize vapor cracking reactions. This is conventionally carried out in two or more cyclones, with the first, higher capacity cyclone removing coarse particles and the second removing fines. However, cyclones are not efficient with very small char particles, so these are usually carried over to the liquid collection system. 6.5.4.2 Filtration Hot-vapor filtration can reduce the ash content of the oil to less than 0.01% and the alkali content to less than 10 ppm, much lower than reported for biomass oils produced in systems using only cyclones. There is limited information available on the performance or operation of hot-vapor filters, but they can be specified and perform similar to hot-gas filters in gasification processes [23]. An alternative approach is insertion of the filter medium in the

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fluid bed [24]. This gives a higher quality product with lower char [25]; however, the liquid yield is reduced by about 10–20% due to the char accumulating on the filter surface that cracks the vapors which is countered to some extent by preferential cracking of pyrolytic lignin in aerosol form on the char cake. More recent work using state-of-the-art filter elements reported similar results, with lower viscosities and reduced yields [23]. Diesel engine tests performed on crude and on hot-filtered oil showed a substantial increase in burning rate and a lower ignition delay for the latter, due to the lower average molecular weight for the filtered oil [26]. Hot-gas filtration has not yet been demonstrated over a longterm process operation. Despite its promise, only a few institutions have investigated hotvapor filtration, including NREL [25] and VTT and Aston University [23]. Pressure filtration of the liquid for substantial removal of particulates (down to G1 mm) is very difficult because of the complex interaction of the char and pyrolytic lignin, which appears to form a gel-like phase that rapidly blocks the filter. Filtration down to 10 mm is not so difficult, but it increases process complexity and cost, as well as potentially leading to lower liquids yields due to losses. Modification of the liquid microstructure by addition of solvents, such as methanol or ethanol, that solubilize the less-soluble constituents can improve this problem and contribute to improvements in liquid stability, as described below. 6.5.4.3 Slurries An alternative approach to separation of char is to deliberately leave all of it in the bio-oil to create a bio–oil–char slurry. KIT (which used to be known as FZK) in Karlsruhe, Germany, has developed and promoted the production and processing of slurries made from bio-oil and char [27–29]. The liquid from straw pyrolysis in a twin-screw reactor is phase separated, but a homogeneous slurry from this separated liquid and the char is claimed. The slurry has been gasified by what was Future Energy (now Siemens) in Freiberg, Germany, in a pressurized oxygen-blown gasifier [30]. There are unresolved questions over the source of energy for the pyrolysis reaction if all the char is used in the slurry, over the separation of char and sand from the reactor, and over the long-term stability of the slurry and its suitability for oxygen pressure gasification. Dynamotive has also produced a bio–oil–char slurry known as Intermediate Bio-oil [31] that has been tested at the Future Energy gasifier unit in Germany (now Siemens) [32]. 6.5.5

Chlorine

Use of chlorine biomass, such as straw, will result in a high chlorine bio-oil from the hydrochloric acid formed in pyrolysis which is dissolved in the bio-oil. There is little work reported on measurement and control, but the levels rarely affect the low pH of the bio-oil, which is mostly due to organic acids. Combustion of a higher chlorine bio-oil will result in hydrogen chloride formation, which can be removed in conventional emissions control. The absence of alkali metals in a relatively char-free bio-oil would not be expected to lead to ash deposition and chlorine mobility. 6.5.6

Color

The dark brown color of bio-oil is only noticeable and potentially problematic in applications where it is visible. For example, use of whole bio-oil or fractionated bio-oil as a

168

Upgrading Fast Pyrolysis Liquids

substitute for phenol in wood panel resins gives a dark brown-colored resin. In many applications this is not a real problem, but it may cause customer concern from an esthetic viewpoint. A similar problem of adverse consumer or customer reaction could arise in any application where the conventional “white” material is replaced by a dark brown material; for example, diesel–bio-oil emulsions for engine fuel. Even hydrotreated bio-oil with greater than 99% deoxygenation that is water white when produced has been observed to blacken and thicken with time. 6.5.7

Contamination of Feed

Biomass can be contaminated by soil, etc. from the harvesting process. Forest residues that are removed by dragging over ground and energy grasses that are cut and recovered later by ground collection will accrete soil. Soil often contains a variety of metals, such as iron, that can be catalytically active in fast pyrolysis [33]. The solution is either improved harvesting techniques and/or washing to remove contamination. An example is hog fuel washing experiments in Canada [34]. However, there is an energy and financial cost of washing which is difficult to justify in most cases unless more valuable chemical products are produced. 6.5.8

Distillability

Pyrolysis liquids cannot be completely vaporized once they have been recovered from the vapor phase. If the liquid is heated to 100
C or more to try to remove water or distill off lighter fractions, it rapidly reacts and eventually produces a solid residue of around 50 wt% of the original liquid and some distillate containing volatile organic compounds and water. The distillate contains those compounds that are volatile, together with thermally cracked products from higher temperatures. 6.5.9

High Viscosity

While bio-oil has been successfully stored for several years in normal storage conditions in steel and plastic drums without any deterioration that would prevent its use in any of the applications tested to date, it does change slowly with time; most noticeably, there is a gradual increase in viscosity. More recent samples that have been distributed for testing in round-robin exercises have shown substantial improvements in consistency and stability, demonstrating the improvement in process design and control as the technology develops. Bio-oil viscosity is important particularly for direct combustion applications, where it needs to be atomized, such as in burners, engines, and turbines. There is quite extensive testing of bio-oil in engines reviewed in [2, 35, 36] and in burners in [2, 37, 38]. For engines, the preferred maximum viscosity is 17 cSt, above which the pressure requirements become excessive. Conventional fuels can be preheated to reduce viscosity, but above around 55
C there is an irreversible change in the bio-oil properties; thus, preheating can only be used on a once through, very short residence time basis, as used in combustion tests by Canmet and MIT (reviewed in Ref. [3]). Viscosity is most affected by water content and temperature and is thoroughly covered in Diebold’s review [15].

Bio-oil Upgrading

6.5.10

169

Inhomogeneity

See phase separation in Section 6.5.18. 6.5.11

Low H:C Ratio

The poor C:H ratio for bio-oil conversion to hydrocarbons means that either hydrogen needs to be added and/or carbon lost. This is considered more fully in Section 6.6. 6.5.12

Low pH

See Section 6.5.1. 6.5.13

Materials Incompatibility

The complex nature of bio-oil and the many different oxygenated compounds present mean that materials selection needs to be carefully considered. Polyolefins and stainless steel are acceptable materials for vessels and pipelines. Seals and gaskets can be sensitive to some of the organics, such as phenolics, and careful compatibility testing is needed for many polymers used as seals and gaskets. For example, synthetic rubber has been known to swell to three times its thickness when in contact with bio-oil. 6.5.14

Miscibility with Hydrocarbons

Pyrolysis oils are not miscible with hydrocarbon fuels, so co-utilization applications that require mixing are unsuitable without further processing, such as upgrading, blending, and emulsification. 6.5.14.1 Blending As bio-oil is not miscible in any proportions with hydrocarbons, blending is only possible with polar compounds or mixtures, such as alcohols. This has been used to improve viscosity and reduce aging, as reviewed by Diebold [15]. Some blending with slow-pyrolysis oil, diesel, and alcohols has been reported [39], although the bio-oil used is quoted as having a heating value of nearly 40 MJ/kg, which suggests that it is quite dissimilar to usual fastpyrolysis bio-oil. 6.5.14.2 Emulsions Bio-oil can be emulsified with diesel oil with the aid of surfactants. A process for producing stable microemulsions with 5–30% of bio-oil in diesel has been developed at CANMET [40]. The University of Florence, Italy, has been working on emulsions of 5–95% bio-oil in diesel [41, 42] to make either a transport fuel or a fuel for power generation in engines that does not require engine modification to dual-fuel operation. There is limited experience of using such fuels in engines or burners, but significantly higher levels of corrosion/erosion were observed in engine applications compared with bio-oil or diesel alone. A further drawback of this approach is the cost of surfactants and the high energy required for emulsification.

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6.5.15

Nitrogen

Biomass contains relatively small quantities of nitrogen which report to bio-oil. In most applications this is not a problem. However, some wastes with a high protein content, such as vegetable oil cake (e.g., rape or colza-meal), can have nitrogen contents above 5 wt% from the proteins in the waste. Two problems result from use of such feedstocks. The first is the very noxious smell of high-nitrogen bio-oils from the extensive nitrogen-containing degradation products. This is substantially worse than wood- or grass-derived bio-oil. Second, much of the nitrogen reports to the liquid, meaning that most applications will need to consider nitrogen pretreatment for its removal (hydrodenitrogenation) or post-use emissions control if the bio-oil is combusted or gasified. An interesting solution is recovery of the high-value proteins prior to pyrolysis, which becomes an embryonic biorefinery. 6.5.16

Other Solid Particulates, Excluding Char

The inert solids in fluid beds and circulating fluid beds, usually sand, will suffer from slow attrition and the fines are likely to substantially bypass cyclones. While not significant in terms of concentration [43], the solids could accumulate over time and create handling, pumping, and erosion problems. Solids are likely to be easier to filter than char, which seems to create a complex with bio-oil, but char would usually be the dominant solid contaminant compared with sand. A potentially more significant problem is catalyst fines from fluid-bed and circulatingfluid-bed catalytic reactors. There is insufficient evidence that attrition is a serious problem, but the mechanical properties of catalysts need to be considered carefully. 6.5.17

Oxygen Content

Bio-oil approximates biomass in elemental composition with typically 40–45 wt% oxygen from the diverse oxygenated organic compounds. This means that it is not miscible with hydrocarbons, but miscible with polar solvents like methanol, ethanol, acetone, and so on. Upgrading to hydrocarbons for transport fuels or biofuels in Sections 6.6.2.3 and 6.6.2.4, while recovery of chemicals is covered in Section 6.6.5. Hydrocarbon biofuel production thus requires the removal of oxygen, and there are many methods reviewed in these sections. 6.5.18

Phase Separation or Inhomogeneity

The microstructure of bio-oil is briefly discussed in Section 6.5.20. Diebold has provided a thorough review of storage instability and methods for upgrading bio-oil [15]. 6.5.19

Smell

The liquid has a distinctive odor, an acrid smoky smell due to the low molecular weight aldehydes and acids, which can irritate the eyes on prolonged exposure. This characteristic smoky smell is exploited in the production of liquid smokes by several companies around the world. Pretreatment of biomass to reduce hemicelluloses, the source of the noxious components, will reduce the problem, but at the expense of lower yields, a more viscous product, and a significant energetic and/or financial cost. Pretreatment includes acid

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washing to preferentially hydrolyze hemicelluloses [44] and torrefaction [45–47] to pyrolyze the hemicelluloses preferentially. Neither is very efficient, as some cellulose is also converted by both methods, resulting in loss of yield and significant emissions control problems. 6.5.20

Structure of Bio-oil

Bio-oil is a complex mixture of water-soluble derivates of cellulose and hemicellulose degradation and water-insoluble pyrolytic lignin. It is believed to be a microemulsion of
pyrolytic lignin micelles around 500 A in diameter maintained as an emulsion by a surfactant derived from the cracking reactions that create the liquid. This is a poorly researched area with few publications [48]. Dilution of the aqueous phase by adding water reduces the surfactant concentration to a level when it is no longer effective, resulting in phase separation. This is discussed further in Section 6.6.3. The complex aqueous–oil surfactant relationship can be destroyed by a number of other circumstances, including cooling, heating, addition of emulsion-breaking additives, shear, etc. Phase separation is one of the consequences of aging (see Sections 6.5.2 and 6.5.18). 6.5.21

Sulfur

Biomass usually contains little sulfur. Wood is typically 0.05–0.1% S and some crops and wastes or residues can be higher. Sulfur levels in bio-oil have invariably been quoted in trace quantities (for example, 0.03 mg/kg [43]) and have attracted little attention in utilization activities. Sulfur in biomass feed would mostly report to the gas product. For synfuel applications, parts per million or even parts per billion levels would typically be required, which would normally be met by guard beds, such as zinc oxide.

6.5.22

Temperature Sensitivity

Bio-oil is formed by rapid freezing of a complex degradation process and the resultant liquid is therefore inherently unstable and wanting to continue reacting. This is the cause of the instability discussed previously. Raising the temperature, therefore, will increase the tendency for chemical reactions to continue. Up to around 55
C the changes are reversible, so preheating to 50
C or less will have no adverse effects on oil quality or behavior. Above around 55
C the changes are increasingly less reversible, and prolonged exposure to higher temperatures causes increased viscosity and an increased propensity for phase separation. Around 100
C, bio-oil separates into a light bitumen-type phase mostly from the pyrolytic lignin and a low-viscosity aqueous fraction, but both are different to phaseseparated bio-oil at ambient conditions. The heavier material will hinder heat transfer and as temperatures increase will eventually carbonize to form a coke layer. This is what happens in attempts at distillation. Temperature is widely used to control viscosity in combustion applications, but for biooil this needs to be carefully considered. In-line preheating immediately prior to combustion works well, but recirculation of a heated bio-oil, for example, in some engine designs needs to be managed carefully.

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6.5.23

Toxicity

As bio-oil becomes more widely available, attention will be increasingly placed on environment, health, and safety aspects. A study was completed in 2005 to assess the ecotoxicity and toxicity of 21 bio-oils from most commercial producers of bio-oil around the world in a screening study, with a complete assessment of a representative bio-oil. The study included a comprehensive evaluation of transportation requirements as an update of an earlier study [49] and an assessment of the biodegradability [50]. The results are complex and require more comprehensive analysis, but the overall conclusion is that bio-oil offers no significant health, environment, or safety risks. 6.5.24

Viscosity

Viscosity is important in many fuel applications [51]. The viscosity of the bio-oil as produced can vary from as low as 25 cSt to as high as 1000 cSt (measured at 40
C) or more, depending on the feedstock, the water content of the oil, the amount of light ends collected, and the extent to which the oil has aged. An accelerated aging or stability test was introduced to provide an index of stability that represents the effect of long-term storage at ambient conditions. This is known as a stability or aging index [52] and is measured by heating the sample to 80
C for 24 h and comparing the increase in viscosity with the original viscosity. This is believed to approximate to 12 months’ storage and is an indication of the propensity for viscosity increase and possible phase separation. 6.5.25

Water Content

Pyrolysis liquids can tolerate the addition of some water, but there is a limit to the amount of water which can be added to the liquid before phase separation occurs; in other words, the liquid cannot be dissolved in water. Water addition reduces viscosity, which is useful; it reduces heating value, which means that more liquid is required to meet a given duty; and it can improve stability. The effect of water, therefore, is complex and important. Bio-oil is miscible with polar solvents, such as methanol, ethanol, acetone, etc., but totally immiscible with petroleum-derived fuels.

6.6

Chemical and Catalytic Upgrading of Bio-oil

Bio-oil can be upgraded in a number of ways: physically, chemically and catalytically. This has been extensively reviewed [2, 17, 18, 53, 54] and only the more significant features and recent developments are reported here. A summary of the main methods for upgrading fast pyrolysis products and the products is shown in Figure 6.1. 6.6.1

Physical Upgrading of Bio-oil

The most important properties that may adversely affect bio-oil fuel quality are incompatibility with conventional fuels from the high oxygen content of the bio-oil, high solids content, high viscosity, and chemical instability.

Chemical and Catalytic Upgrading of Bio-oil

173

Biomass Fast pyrolysis Gasification Syngas

Syngas Methanol synthesis

Alcohol synthesis

Methan ation

Zeolite cracking

Syngas

MTG MOGD

MtSynfuels

Fischer Tropsch synthesis

Liquid bio-oil Hydrotreating

Refining Alcohols

Figure 6.1

Methane, gasoline, diesel, kerosene

Overview of fast pyrolysis upgrading methods

6.6.1.1 Filtration Hot-vapor filtration can reduce the ash content of the oil to less than 0.01% and the alkali content to less than 10 ppm, much lower than reported for biomass oils produced in systems using only cyclones. This gives a higher quality product with lower char [25]; however, the liquid yield is reduced by about 10–20% due to the char accumulating on the filter surface that cracks the vapors. There is limited information available on the performance or operation of hot-vapor filters, but they can be specified and perform similar to hot-gas filters in gasification processes. Diesel engine tests performed on crude and on hot-filtered oil showed a substantial increase in burning rate and a lower ignition delay for the latter, due to the lower average molecular weight for the filtered oil [26]. Hot-gas filtration has not yet been demonstrated over a long-term process operation. A consequence of hot-vapor filtration to remove char is the catalytic effect of the accumulated char on the filter surface, which potentially cracks the vapors, reduces yield by up to 20%, reduces viscosity, and lowers the average molecular weight of the liquid product. A little work has been done in this area by NREL [25] and VTT and Aston University [23], but very little has been published. Liquid filtration to very low particle sizes of below around 5 mm is very difficult due to the physico-chemical nature of the liquid and usually requires very high pressure drops and selfcleaning filters. 6.6.1.2 Solvent Addition Polar solvents have been used for many years to homogenize and reduce the viscosity of biomass oils. The addition of solvents, especially methanol, showed a significant effect on the oil stability. Diebold and Czernik [22] found that the rate of viscosity increase (“aging”) for the oil with 10 wt% of methanol was almost 20 times less than for the oil without additives.

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Upgrading Fast Pyrolysis Liquids

6.6.1.3 Emulsions Pyrolysis oils are not miscible with hydrocarbon fuels, but they can be emulsified with diesel oil with the aid of surfactants. A process for producing stable microemulsions with 5–30% of bio-oil in diesel has been developed at CANMET [55]. The University of Florence, Italy, has been working on emulsions of 5–95% bio-oil in diesel [41, 42] to make either a transport fuel or a fuel for power generation in engines that does not require engine modification to dual-fuel operation. There is limited experience of using such fuels in engines or burners, but significantly higher levels of corrosion/erosion were observed in engine applications compared with bio-oil or diesel alone. A further drawback of this approach is the cost of surfactants and the high energy required for emulsification. 6.6.2

Catalytic Upgrading of Bio-oil

6.6.2.1 Natural Ash in Biomass Before considering catalytic upgrading of bio-oil, it is important to appreciate first that biomass contains very active catalysts within its structure. These are the alkali metals that form ash and which are essential for nutrient transfer and growth of the biomass. The most active is potassium, followed by sodium. These act by causing secondary cracking of vapors and reducing liquid yield and liquid quality. Ash can be managed to some extent by selection of crops and harvesting time, but it cannot be eliminated from growing biomass. Ash can be reduced by washing in water or dilute acid, and the more extreme the conditions in both temperature and concentration, the more complete the ash removal. However, as washing conditions become more extreme, first hemicellulose and then cellulose are lost through hydrolysis. This reduces liquid yield and quality. In addition, washed biomass needs to have any acid removed as completely as possible and recovered or disposed of and the wet biomass has to be dried. So, washing is not often considered a viable possibility, unless there are some unusual circumstances, such as removal of contaminants. Another consequence of high ash removal is the increased production of levoglucosan, which can reach levels in bio-oil where recovery becomes an interesting proposition, although, commercially, markets need to be identified and/or developed. 6.6.2.2 Upgrading to Biofuels Upgrading bio-oil to a conventional transport fuel such as diesel, gasoline, kerosene, methane and LPG requires full deoxygenation and conventional refining, which can be accomplished either by integrated catalytic pyrolysis, as discussed above, or by decoupled operation, as summarized below and depicted in Figure 6.2. There is also interest in partial upgrading to a product that is compatible with refinery streams in order to take advantage of the economy of scale and experience in a conventional refinery. Integration into refineries by upgrading through cracking and/or hydrotreating has been reviewed by Huber and Corma [56]: . . . .

hydrotreating; catalytic vapour cracking; esterification and related processes; gasification to syngas followed by synthesis to hydrocarbons or alcohols.

Chemical and Catalytic Upgrading of Bio-oil

175

Biomass Fast pyrolysis Zeolite cracking

Gasification Syngas

Syngas Methanol synthesis

Alcohol synthesis

Syngas

Syngas

Fischer Tropsch MTG, MOGD Metha- synthesis Mt-Synfuels nation

Alcohols

Figure 6.2

Liquid bio-oil Hydrotreating

Hydrocarbons: methane, gasoline, diesel, kerosene

Upgrading of bio-oil to biofuels and chemicals

6.6.2.3 Hydrotreating Hydro-processing rejects oxygen as water by catalytic reaction with hydrogen. This is usually considered as a separate and distinct process to fast pyrolysis that can, therefore, be carried out remotely. The process is typically high pressure (up to 200 bar) and moderate temperature (up to 400
C) and requires a hydrogen supply or source [57]. Full hydrotreating gives a naphtha-like product that requires orthodox refining to derive conventional transport fuels. This would be expected to take place in a conventional refinery to take advantage of know-how and existing processes. A projected typical yield of naphtha equivalent from biomass is about 25 wt% or 55% in energy terms, excluding provision of hydrogen [18]. Inclusion of hydrogen production by gasification of biomass reduces the yields to around 15 wt% or 33% in energy terms. The process can be depicted by the following conceptual reaction: C1 H1:33 O0:43 þ 0:77H2 ! CH2 þ 0:43H2 O The catalysts originally tested in the 1980s and 1990s were based on sulfided CoMo or NiMo supported on alumina or aluminosilicate and the process conditions are similar to those used in the desulfurization of petroleum fractions. However, a number of fundamental problems arose, including that the catalyst supports of typically alumina or aluminosilicates were found to be unstable in the high-water-content environment of bio-oil and the sulfur was stripped from the catalysts requiring constant resulfurization. The main activities were based at Pacific Northwest National Laboratory (PNNL), USA, by Elliott and co-workers (e.g. [58–60]) and at UCL in Louvain la Neuve in Belgium by Maggi and co-workers (e.g. [61, 62]). This area has been thoroughly reviewed [53]. A recent design study of this technology for a biomass input of 2000 t/d (dry) for production of gasoline and diesel has been carried out by PNNL [63]. A comprehensive review of unsupported metal sulfide hydrotreating catalysts was published in 2007 providing an up-to-date view [64]. More recently, attention turned to precious metal catalysts on less susceptible supports, and considerable academic and industrial research has been initiated in the last few years. Of

176

Upgrading Fast Pyrolysis Liquids

note is the work by UOP in Chicago with PNNL in the USA to address the scientific and technical challenges and develop a cost-effective process [65]. Model compounds were used initially to understand the basic processes [66] and both whole oil and fractions have been evaluated. Tests have been carried out on both batch and continuous-flow processes and work to date has been based on low-temperature (up to 380
C) catalytic hydrogenation of bio-oil using different metal catalysts and processing conditions to give a range of products, including petroleum refinery feedstock. Groningen University in the Netherlands is also active in fundamental research on hydrotreating bio-oils and model compounds using ruthenium on carbon [67, 68]. Different levels of upgrading are being studied from stabilization with low levels of oxygen removal through mild hydrotreating to two-stage hydrotreatment with substantial oxygen removal [69]. At the Technical University of Munich, Lercher proposed a “one-pot” approach which is based on aqueous-phase hydro-deoxygenation of phenolic monomers using bifunctional catalysis that couples precious-metal-catalyzed hydrogenation and acid-catalyzed hydrolysis and dehydration [70]. There is still a significant hydrogen requirement which could, in principle, be derived from the aqueous phase after hydrotreatment. A more complex process involving hydrotreatment, esterification and cracking in supercritical ethanol using a palladium on zirconium with an SBA15 catalyst, has been researched in China [71]. A significant improvement in many properties was reported. A number of other organizations are active in hydrotreating, as summarized in Table 6.3. There is a substantial hydrogen requirement in all hydrotreating processes to hydrogenate the organic constituents of bio-oil and remove the oxygen as water. The hydrogen requirement can be represented by processing an additional amount of biomass to provide the hydrogen, by gasification for example. This is about 80% of that required to produce the bio-oil. The process is thus less efficient than the simple performance figures often presented. If only the organic fraction of bio-oil after phase separation is hydrotreated, then the hydrogen required can be produced by steam reforming the aqueous phase. There has been extensive research on reforming the aqueous fraction of bio-oil, as discussed below. There is also a high cost from the high-pressure requirement [63, 89]. Catalyst deactivation remains a concern from coking due to the poor C/H ratio. In all cases the upgraded product needs conventional refining to produce marketable products, and this would be expected to take place in a conventional refinery. 6.6.2.4 Zeolite Cracking Zeolite cracking rejects oxygen as CO2, as summarized in the following conceptual overall reaction: C1 H1:33 O0:43 þ 0:26O2 ! 0:65CH1:2 þ 0:34CO2 þ 0:27H2 O There are several ways in which this can be carried out, as summarized in Figure 6.3. The zeolite upgrading can operate on the liquid or vapors within or close-coupled to the pyrolysis process, or they can be decoupled to upgrade either the liquids or revaporized liquids. All these have been examined, as summarized in Table 6.4.

Chemical and Catalytic Upgrading of Bio-oil

177

Table 6.3 Organizations involved in catalytic upgrading of pyrolysis by hydrotreatment and related processes since 2000 Organization

Catalyst

Dynamotive, Canada East China University of Science and Technology, Shanghai, China East China University of Science and Technology, Shanghai, China Guangzhou Institute of Energy Conversion, China Groningen University, Netherlands IRCELYON CNRS Universit
e Lyon 1 Mississippi State University, USA

Pacific Northwest Laboratory (PNNL), USA REHydrogen State University of Iowa, USA Technical University of Munich, Germany University of Jyv€askyl€a, Finland/VTT University of Kentucky, USA University of Maine, USA University of Oklahoma, USA University of Twente, Netherlands UOP, USA

Latest known activity

Example Ref.

nk CoMo-P sulfided

2009 2004

[72] [73, 74]

Pd on ZrO2 with SBA15 NiMo on Al2O3

2009

[71]

2009

[75]

Ru and homogeneous Ru CoMo/Al2O3 NiMo/g-Al2O3 CoMo/g-Al2O3 HZSM-5, SUZ-4 Precious metal Pd, Ru

2010

[67, 76]

2008 2009

[77] [78, 79]

2010

[66, 80, 81]

nk nk Pd on C

2010 2009 2009

[82] [57, 70]

Ru on C

2003

[83]

Pt nk Pd on carbon nanotubes Precious metal

2008 2007 2010 2006

[84] [85] [86] [87]

Precious metal

2010

[65, 88]

Biomass

Fast pyrolysis Liquid

Volatilisation

Catalysis

Vapour

Integrated catalytic fast pyrolysis

Liquid

Catalysis

Catalysis

Upgraded product

Figure 6.3

Methods of upgrading fast-pyrolysis products with cracking catalysts

178

Upgrading Fast Pyrolysis Liquids

Table 6.4 Organizations involved in catalytic upgrading of pyrolysis liquids since 2000 by zeolite-based cracking processes Organization Integrated catalytic pyrolysis Anadolu University BioECon, Netherlands, and Kior, USA CPERI, Greece East China University of Science and Technology, Shanghai, China Exelus Georgia Institute of Technology, USA Michigan State University, USA Sichuan University, China Southeast University of Nanjing, China University of Leeds, UK University of Massachusetts, USA Virginia Tech, USA Close coupled vapor upgrading East China University of Science and Technology Instituto Superior T
ecnico, Portugal þ Kior þ Petrobras Norwegian University of Science and Technology þ CPERI (Greece) þ SINTEF (Norway) University of Science and Technology of China, Anhui, China University of Seoul, Kongju National University, Kangwon National University, Korea

Catalyst

Latest known activity

Example Ref.

clinoptilolite (natural zeolite, NZ), ZSM-5, H-Y nk

2009

[90]

2009

[91]

MCM-41 HZSM-5

2008 2009

[92, 93] [73, 74, 94]

nk H-Y zeolites

2010 2009

[95] [96]

nk Na/Y zeolite FCC

2009 2006 2009

[97] [98] [99]

ZSM-5 ZSM-5 H-ZSM-5 Zr-based superacids

2000 2009 2009

[100] [101, 102] [103, 104]

HZSM-5

2008

[94]

FCC and FCC þ ZSM-5

2009

[105]

Al-MCM-41, FCC, SBA-15

2006

[106]

HZSM-5, HY, ZrO2 & TiO2, SBA-15, Al/SBA-15. Spent HZSM-5

2009

[107, 108]

2010

[109, 110]

Decoupled vapor upgrading by volatilization of bio-oil and decoupled liquid bio-oil upgrading University of the Basque Country, H ZSM-5, Ni-HZSM-5 2004 [107, 111] Spain University of Pisa, Italy H-ZSM-5 2000 [112] Other approaches Zheijiang University, China

HZSM-5 in sub- and super-critical ethanol

2009

[113]

Chemical and Catalytic Upgrading of Bio-oil

179

A report by Hydrocarbon Publishing for the future of fluid catalytic cracking (FCC) and hydroprocessing in modern refineries [114] states that Biomass-derived oils are generally best upgraded by HZSM-5 or ZSM-5, as these zeolitic catalysts promote high yields of liquid products and propylene. Unfortunately, these feeds tend to coke easily, and high TANs [total acid numbers] and undesirable byproducts such as water and CO2 are additional challenges.

Integrated Catalytic Pyrolysis. There is increasing interest in improving the quality of bio-oil, and there have been a number of developments in the last few years that integrate or combine catalysis with pyrolysis. These combined pyrolysis–catalysis reaction systems have been studied by a number of organizations, including several commercial developments. Huber from the University of Massachusetts Amhurst has also worked in this area and developed a process that pyrolyzes biomass in the presence of ZSM-5 into gasoline, and also diesel fuel, heating oil, and renewable chemicals, including benzene, toluene, and xylenes, in a one-step process [101, 115]. High heating rates and catalyst-to-feed ratios are necessary to ensure that the pyrolysis vapors enter the catalyst pores and that thermal decomposition is avoided. The entire process was completed in under 2 min using relatively moderate amounts of heat [101]. The compounds that formed in the single step, such as naphthalene and toluene, make up 25% of the suite of chemicals found in gasoline. The product is referred to as Grassoline, and a spin-out company has been formed – Anellotech [116]. Anellotech has already demonstrated commercially relevant production not only of gasoline and biofuel precursors, but also of benzene, toluene, and xylene in milligram- and gramscale bench-top reactors. The “one-pot” concept has also been developed by the Technical University of Munich, which is described above in the Section 6.6.2.3. BioECon has formed a joint venture with KIOR [117] to exploit their technology. Little information is available other than that modified clays are some of the materials studied and that one approach is impregnation of the biomass with nano-catalysts prior to reaction [118]. Success is claimed at temperatures as low as 230
C [91]. CPERI in Greece has carried out a number of projects on catalytic pyrolysis of biomass in a circulating-fluid-bed reactor using zeolites and mesoporous catalysts. There was clear evidence of upgrading, but incomplete deoxygenation [92, 93]. Agblevor at Virginia Polytechnic Institute & State University has developed a fractional pyrolysis process based on in-bed catalysis [103] that has been patented [104]. Exelus claims a low-temperature (200
C), long residence time (20 min) catalytic thermochemical process to convert biomass into gasoline. While it is unlikely to be considered pyrolysis, it well illustrates the increasing innovation being applied to this field. Other work on integrated catalytic pyrolysis has been carried out by a number of laboratories with limited success. One problem often encountered is the declared objective of improving bio-oil quality without defining what this means and what characteristics are being addressed. Integration of catalysis and pyrolysis requires operation at a single temperature and sufficiently robust catalyst to withstand the temperature and mechanical environment. There is, therefore, less flexibility in operating conditions, suggesting that catalytic systems will need to be quite sophisticated. Since coking is a recognized problem and is the mechanism

180

Upgrading Fast Pyrolysis Liquids

by which oxygen is rejected from the bio-oil, catalyst regeneration is an essential aspect of a reactor design. Close-coupled Vapor Upgrading. Catalytic vapor cracking over acidic zeolite catalysts provides deoxygenation by simultaneous dehydration–decarboxylation producing mostly aromatics [119] at 450
C and atmospheric pressure. Oxygen is ultimately rejected as CO2 and CO from a secondary oxidizing reactor to burn off the coke deposited on the catalyst. This would operate much as an FCC in a refinery. The low H/C ratio in the bio-oils imposes a relatively low limit on the hydrocarbon. A projected typical yield of aromatics suitable for gasoline blending from biomass is about 20% by weight or 45% in energy terms [120]. The crude aromatic product would be sent for refining in a conventional refinery. A key feature of this route is the absence of a hydrogen requirement and operation at atmospheric pressure. Some of the earlier work was carried out at NREL in a close-coupled reactor with their ablative fast pyrolysis process [121]. The process was modeled technically and economically by an IEA Bioenergy Task [120]. Catalyst deactivation remains a concern for both routes, although the coking problem with zeolites can in principle be overcome by a conventional FCC arrangement with continuous catalyst regeneration by oxidation of the coke. Some concern has been expressed over the poor control of molecular size and shape with orthodox zeolites and the propensity for formation of more noxious hydrocarbons [122]. The processing costs are high and the products are not competitive with fossil fuels [123]. The approach has only been studied at the basic research level and considerably more development is necessary. Decoupled Vapor Upgrading from Volatilization of Bio-oil. This approach was extensively investigated at the University of Saskatchewan in the 1990s and widely reported and reviewed (e.g. [17, 18]). Decoupled Liquid Bio-oil Upgrading. The University of the Basque Country has investigated a close-coupled liquid bio-oil preheated fluid-bed zeolite cracking reactor [107]. Separation of thermal pretreatment from catalytic upgrading was found to reduce coking, but then the proposal for secondary upgrading of thermally degraded products in the pretreatment section suggests potential for blockage. This is analogous to the work at Saskatchewan. 6.6.3

Other Methods for Chemical Upgrading of Bio-oil

This section includes nonphysical methods and those catalytic processes not covered in hydrotreating and zeolite-related processes. Research activities are summarized in Table 6.5 and the main areas are described below. 6.6.3.1 Aqueous-phase Processing This is a relatively new approach that was first proposed by Dumesic and co-workers, who produced hydrogen and alkanes from aqueous solutions of oxygenated hydrocarbons through aqueous-phase reforming and dehydration–hydrogenation [136, 140, 141]. A large fraction of bio-oil is water soluble and the compounds present in its aqueous fraction are mainly oxygenated hydrocarbons. This shows that the concept of aqueous-phase processing can be used to produce hydrogen and alkanes from the aqueous fraction of bio-oil.

Chemical and Catalytic Upgrading of Bio-oil

181

Table 6.5 Organizations involved in other methods for chemical upgrading of pyrolysis liquid since 2000 Organization

Method

Example Latest Ref. known activity

Groningen University, Netherlands Guangzhou Institute of Energy Conversion, China Helsinki University of Technology Institute of Chemical Industry of Forest Products, Nanjing, China South China University of Technology University of Georgia, USA University of Kentucky, USA

Reactive distillation and acid catalyst

2007

[124]

Solid acid 40SiO2/TiO2SO42 solid base 30K2CO3/Al2O3NaOH Zinc oxide Reactive distillation

2009

[125, 126]

2000 2008

[127] [128]

Solid acid and solid base catalysts

2008

[129]

Esterification of pyrolysis vapor ZnO, MgO and Zn-Al and Mg–Al mixed oxides; Dicationic ionic liquid C6(mim)2HSO4

nk 2007

[130] [131]

2009

[132, 133]

C12A7-O

2006

[134]

Steam reforming in two-step process

2009

[135]

Aqueous-phase reforming þ dehydration þ hydrogenation

2009

[136, 137]

Acid cracking in supercritical ethanol Hydrogenationesterification over bifunctional Pt catalysts

2008 2008

[138] [139]

University of Science and Technology of China, Hefei University of Science and Technology of China, Hefei University of Twente, Netherlands University of Wisconsin and University of Massachusetts, USA Zhejiang University Zhejiang University

6.6.3.2 Mild Cracking An alternative to orthodox zeolite-based cracking is mild cracking over base catalysts that addresses only the cellulose- and hemicellulose-derived products and aims to minimize coke and gas formation. Crofcheck at the University of Kentucky [131] has explored ZnO and freshly calcined Zn/Al and Mg/Al layered double hydroxides to upgrade a synthetic biooil based on earlier work in Finland [127]. These are summarized in Table 6.5. 6.6.3.3 Esterification and Other Processes An increasing number of methods, which are summarized in Table 6.5, are being investigated and developed for improving the quality of bio-oil without substantial deoxygenation. Properties that are mostly addressed are water content, acidity, stability, and reactivity. 6.6.3.4 Aqueous-phase Reforming The concept was first proposed by Dumesic at the University of Wisconsin for upgrading the aqueous fraction of bio-oil for hydrogen and alkanes [137], and was subsequently supported by others [136]. 6.6.3.5 Steam Reforming As referred to above, the water-soluble (carbohydrate-derived) fraction of bio-oil can be processed to hydrogen [142, 143] by steam reforming. This has been accomplished in a fluidized-bed process by several researchers using commercial, nickel-based catalysts

182

Upgrading Fast Pyrolysis Liquids

under conditions similar to those for reforming natural gas. The process depends on a viable use for the organic lignin-derived fraction of bio-oil; for example, use as a phenol replacement in phenol-formaldehyde resins [144] or for upgrading this organic fraction. 6.6.3.6 Model Compounds and Model Bio-oil Many new and interesting techniques for upgrading bio-oil are being investigated, and this is very encouraging and interesting. But some of the laboratory work and particularly newer methods are based on model compounds or a selection of model compounds that purports to represent bio-oil. While scientifically credible and providing a consistent and wellcharacterized fed material, there are dangers in relying too much on synthetic bio-oil, since no mixture can adequately represent the complex composition of fast pyrolysis liquid. 6.6.4

Hydrogen

Hydrogen is produced in the syngas from gasification of bio-oil and bio-oil/char slurries as described above. There are also activities in both noncatalytic partial oxidation and catalytic partial oxidation and catalytic steam reforming of both whole bio-oil and the aqueous fraction after phase separation, particularly to meet the hydrogen demands of a hydrotreating process as described above. Catalysts are usually based on nickel or precious metals. These are summarized in Table 6.6 which shows catalysts employed and model compounds used to represent bio-oil. 6.6.5

Chemicals

Since the empirical chemical composition of biomass, approximately (CH2O)n, is quite different from that of petroleum, (CH2)n, the range of primary chemicals that can be easily derived from biomass and oil are quite different. Hence, any biomass-based chemical industry will necessarily be constructed on quite a different selection of simple “platform” chemicals than those currently used in the petrochemical industry. Given the chemical complexity of biomass, there is some choice of which platform chemicals to produce, since, within limits, different processing strategies of the same biomass can lead to different breakdown products. However, once a set of platform chemicals has been chosen for biobased chemical production and the appropriate network of production plants is established, it will become increasingly difficult to change that choice without disrupting the whole manufacturing infrastructure. Since the available biomass will inevitably show major regional differences, it is quite possible that the choice of platform chemicals derived from biomass will show much more geographical variation than in petrochemical production. Examples of chemicals derived from bio-oil are listed in Table 6.7. 6.6.5.1 Chemical Composition of Bio-oil The chemicals in bio-oil are derived from random thermal decomposition of hemicellulose, cellulose, and lignin. Over 400 individual chemicals have been identified in bio-oil, and this area has been reviewed by Diebold [15]. There are many papers that provide details of biooil analyses, as analytical techniques have developed rapidly. Strategies for separation or recovery of any of these chemicals need to consider market, value, costs, and process. The natural first step is to evaluate components with the highest

Queens University, Belfast, UK Tokyo Institute of Technology Japan and University of Twente, Netherlands

East China University of Science and Technology, Shanghai, China East China University of Science and Technology, Shanghai, China Guangzhou Institute of Energy Conversion, China NREL, USA NREL, USA

Aqueous phase reforming University of Pittsburgh, USA University of Wisconsin, USA Catalytic steam reforming Aristotle University of Thessaloniki, Greece Aristotle University of Thessaloniki, Greece

Noncatalytic partial oxidation Colorado School of Mines, USA, and NREL, USA Siemens (Future Energy), Germany

Organization

2002 2004

Ni/Mg/K on Al2O3 Ni–C11-NK from S€ udChemie; Ni/Cr Al2O3 Noble metals Pt/ZrO2

2005 2006

2008

Nk

acetic acid

2007

Ni/Al2O3

2008

2009

2008

acetic acid, acetone, ethylene glycol acetic acid, acetone

Ni/olivine

2008 2005

Nickel (5 wt%) and noble metal (0.5 wt% Rh or Ir) catalysts on CaO/Al2O3 and 12CaO/Al2O3 Ni/MgO

glycerol, sorbitol, glucose ethanol

Pt/Al2O3 Pd, Pt, Ni, Ru, Rh

2007

None

Latest known activity 2008

Model compounds

None

Catalyst

Table 6.6 Organizations involved in reforming bio-oil for hydrogen since 2000

(continued)

[158] [159, 160]

[155] [143, 156, 157]

[154]

[153]

[152]

[151]

[149, 150]

[148] [137]

[146, 147]

[145]

Example Ref.

Chemical and Catalytic Upgrading of Bio-oil 183

Two-stage catalytic steam reforming East China University of Science and Technology, Shanghai 200237, China

University of Zaragoza, Spain

University of Patras, Greece University of Science & Technology of China, Hefei; U University of Tokyo; Oxy Japan Corporation University of Science & Technology of China, Hefei, Oxy Japan Corporation, Japan University of Science and Technology of China, Hefei, China University of Science and Technology of China, Hefei, China University of Twente, Netherlands

Dolomite þ Ni/MgO

Pd, Rh, Ru, Pt, Ni, Al2O3, CeZrO2, La2O3 Coprecipitated Ni–Al catalysts

(Ca24Al28O64)4þ4O/Mg (C12A7-Mg) Ni–Cu–Zn–Al2O3

C12A7/15%Mg, 12%Ni/ g-Al2O3, 1%Pt/g-Al2O3

NiG-90, Rh-ZDC, 20NiSi, Ni/a-Al2O3, Ni-La2O3/ a-Al2O3, Ni–Co–La2O3/ a-Al2O3 and Co/ZnO Pt/Al2O3, Pt/TiO2, Pt/ZrO2, Pt/CeO2, Pt/Ce0.7 Zr0.3O2, Rh/Al2O3, Rh/SiO2–Al2O3 and Rh/ZrO2 Ru/MgO/Al2O3 CNTs-supported Ni

University of the Basque Country, Spain

University of Kentucky, USA

Catalyst

Organization

Table 6.6 (Continued )

acetic acid

acetic acid

acetic acid

Model compounds

2008

2005

[170]

[168, 169]

[167]

[166]

2009 2004

[134]

[165]

[163] [164]

[162]

[161]

Example Ref.

2006

2007

2007 2009

2007

2009

Latest known activity

184 Upgrading Fast Pyrolysis Liquids

[173–175]

[176]

2009

2009 2008

Cracking and steam reforming IRCELYON, UMR-CNRS, France

[178]

[177]

[172]

2003

Rh/Ce0.5Zr0.5O2 and Pt/Ce0.5Zr0.5O2 Aqueous phase reforming and hydrodeoxygenation Auburn University, USA

[145, 171]

2007

Combined non-catalytic partial oxidation and catalytic steam reforming Colorado School of Mines, USA, POx þ 0.5% rhodium, and NREL, USA ruthenium, platinum, and palladium (all supported on alumina) and alumina Combined reforming processes University of Hawaii, USA Steam reforming þ CO2 removal with CaO Electrochemical University of Science & Technolþ NiO–Al2O3 ogy of China, Hefei; Oxy Japan Corporation, Japan; University of Tokyo Japan Washington State University, USA Plasma þ Ni

Chemical and Catalytic Upgrading of Bio-oil 185

186

Upgrading Fast Pyrolysis Liquids

Table 6.7

Chemicals recovery

Organization

Chemical

Acetic acid Groningen University Latvian State Institute of Wood Chemistry Michigan State University

Latest known activities

Refs

2008 2004

[179] [180]

2010

[181, 182]

1994 1991

[183] [184]

1998 1994 1996

[185] [186, 187] [180, 188, 189]

1995 2004

[190] [191]

2010 2001

— [189, 192]

2010 2010

[193] [193, 194]

2009

[195]

1980 2010 1994 2010 1997

[196] [197–199] [200, 201] — [202–205] [206]

2002

[207–210]

2010 1997 2010 2007 2009

[211] [212] [202] [213] [214]

Hydrogen See Section 6.6.4 Hydroxyacetaldehyde BC Research Red Arrow, USA Levoglucosan Aston University BC Research Latvian State Institute of Wood Chemistry Moens, L. University of Waterloo Levoglucosenone Ensyna Latvian State Institute of Wood Chemistry Liquid smoke and related products Ensyna Red Arrow Phenol and phenolics National Institute of Chemistry, Ljubljana, Slovenia, Resins and adhesives American Can Chimarb CPERI, Greece Ensyna NREL University of Quebec, Canada University of Laval Synthesis gas See hydrogen production in Section 6.6.4 Mixed and miscellaneous Aston University Dynamotive Ensyn Ensyn Iowa State University

Slow-release fertilizers Biolime Pharmaceuticals Preservative Asphalt

Conclusions

187

Table 6.7 (Continued ) Organization Latvian State Institute of Wood Chemistry Mississippi State University Mississippi State University Patent RTI UOP

Chemical

Latest known activities

Refs

Furfural, acetic acid, levoglucosan, fiber materials, plastics Anhydrosugars

2004

[180]

2009

[78]

Wood preservative

2010

[215, 216]

Preservative Slow-release fertilizers Aldehydes, organic acids, phenols, ketones, non-aromatic alcohols

2002 1995 2009

[217] [218] [219]

a

See www.ensyn.com. See www.chimarhellas.com.

b

concentration, since the processing will be easier and the costs lower. However, this may not prove the best strategy, and methodologies need to carefully consider capital and operating costs, product values, and residue or waste utilization or disposal. The opportunities for optimization are considerable and challenging, and are likely to involve a range of process generation, evaluation, and optimization tools, including process synthesis and linear programming. 6.6.5.2 Production of Chemicals For many centuries wood pyrolysis liquids were a major source of chemicals, such as methanol, acetic acid, turpentine, tars, etc. At present, most of these compounds can be produced at a lower cost from fossil fuel feedstocks. Although over 300 compounds have been identified in wood fast pyrolysis oil, their concentrations are usually too low to consider separation and recovery. Up to now, therefore, the development of technologies for producing products from the whole bio-oil or from its major, relatively easily separable fractions is the most developed. A more detailed review on this subject, including consideration of higher value products, was published by Radlein [220] and a thorough review of the literature on production of chemicals utilizing whole oil, fractions of bio-oil, and specific chemicals was published in 2004 [16]. A comprehensive review of phenolics recovery and utilization has been published by Amen-Chen et al. [206]. Chemicals are always attractive commercial possibilities owing to their much higher added value compared with fuels and energy products. This suggests a bio-refinery concept in which the optimum combinations of fuels and chemicals are produced.

6.7

Conclusions

There has been a very considerable expansion of activity in the last 7–8 years exploring novel processes for production of more useful and valuable products from bio-oil. This is due to the recognition of the value of a crude liquid that can be more easily handled, stored,

188

Upgrading Fast Pyrolysis Liquids

and transported than solid or gas with the potential for enhanced bioenergy and biofuel chains. Attention has focused on two main areas: . .

Improving the quality of bio-oil to reduce or avoid problems in direct use, which requires identification and specification of the qualities concerned. Upgrading to a more conventional product that can be more readily assimilated into existing fuel infrastructures. This includes transport fuels, synthesis gas for transport fuels and chemicals, hydrogen, and commodity and speciality chemicals.

Quality can be defined in terms of any combination of over 25 characteristics of bio-oil that affect its usage, so it is important to identify which characteristic or characteristics require modification and then address those properties. There is increasing interest in higher value and more orthodox products, such as transport fuels and hydrogen, which has seen considerable growth of R&D activity. The latter can be partly explained by the requirement for significant amounts of hydrogen for some upgrading processes for production of hydrocarbon fuels and also for decentralized production of hydrogen for fuels cells, as hydrogen is costly to store and transport. The relatively low hydrogen content of bio-oil invariably results in coking of catalysts in catalytic upgrading processes. Some solutions have been sought in more sophisticated catalyst systems that require less severe conditions and also in multistage upgrading where bio-oil is processed in a series of steps to give a progressively upgraded product. Liquid processing is generally preferred to avoid problems of vaporizing bio-oil with consequent loss of carbon as coke unless oxidative processing is included to oxidize any carbon that is formed. The use of model compounds makes for easier fundamental science, but it is doubtful if any single chemical or even small number of chemicals can adequately reproduce the complexity of whole bio-oil with interactions between the constituent chemicals. The considerable growth in activity around the world reported in this review demonstrates the exciting opportunities and future for fast pyrolysis which will move from laboratory to commercial reality in a surprisingly short time.

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7 Hydrothermal Processing Douglas C. Elliott Pacific Northwest National Laboratory, USA

7.1

Introduction

The term “hydrothermal” used here refers to the processing of biomass in water slurries at elevated temperature and pressure to facilitate the chemical conversion of the organic structures in biomass into useful fuels or chemicals. The process is meant to provide a means for treating wet biomass materials without drying and to access ionic reaction conditions by maintaining a liquid water processing medium. Typical hydrothermal processing conditions are temperatures of 523–647 K and pressures from 4 to 22 MPa. The temperature is sufficient to initiate pyrolytic mechanisms in the biopolymers, while the pressure is sufficient to maintain a liquid water processing phase. Closely related processing in supercritical water conditions (H647 K and H22 MPa) will also be discussed in this chapter. Within the regime of hydrothermal processing there are two main process groups: hydrothermal liquefaction and wet gasification. Hydrothermal liquefaction (also known as direct liquefaction) is accomplished at the lower end of the process temperature range. It is a version of pyrolysis liquefaction. As such, it does not require a catalyst, but a significant amount of research and development on catalytic methods in hydrothermal liquefaction has been undertaken. The most commonly considered “catalyst” has been the use of alkali to modify the ionic medium to favor certain base-catalyzed condensation reactions, which can lead to aromatic oil formation, in preference to acid-catalyzed polymerization reactions, which lead to solid product formation. The second category of processing within hydrothermal treating is wet gasification. Wet gasification is accomplished at the upper end of the process temperature range. It can be Thermochemical Processing of Biomass: Conversion into Fuels, Chemicals and Power, First Edition . Edited by Robert C. Brown © 2011 John Wiley & Sons, Ltd. Published 2011 by John Wiley & Sons, Ltd. ISBN: 978-0-470-72111-7

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considered an extension of the liquefaction mechanisms with subsequent decomposition of large molecules to smaller molecules and eventually to gas. Typically, wet gasification requires an active catalyst to accomplish reasonable rates of gas formation from biomass. Processing in supercritical water is a reasonable extension of wet gasification. In fact, the earliest publications suggested that supercritical water conditions were a prerequisite for effective gasification of biomass, but later work has shown that effective catalysts can allow lower temperature gasification operations. This chapter will address the formation of fuel products in hydrothermal processing systems. Related work at lower temperatures with carbohydrates, called aqueous-phase reforming, is covered in a subsequent chapter. Hydrothermal processing can also be considered to include oxidation systems, such as wet air oxidation and supercritical water oxidation. These technologies are more inclined to waste treatment as alternatives to incineration. They can produce heat and power but do not produce fuels or chemicals and will not be discussed here. Even the treatment systems for biomass processing to produce, for example, sugar monomers or organic acids can be considered hydrothermal treatment, but will not be discussed here. Nor will this chapter address the further catalytic treatment of these monomers to value-added products, such as levulinic acid to methyltetrahydrofuran or glucose to sorbitol or glycols. The use of hydrothermal processing conditions introduces a number of limitations or barriers resulting from the use of water. In order to perform hydrothermal processing, a pressurized system is required to minimize the vaporization of the water and the resulting energy requirement. Pumping of the wet biorefinery residues at these pressures is a key technical challenge to utilization. Slurry pumping at high pressure is an important requirement for hydrothermal processing. The feeding of the biomass is different from other biomass processing systems, which more typically include dry particulate (solid) feeding systems of biomass at low or near-atmospheric pressure. In order to achieve slurry pumping, the biomass material is needed in small particle size. Size reduction can be accomplished in wet medium in order to minimize energy requirements for drying. In order to feed at high pressure, these size reduction requirements become more stringent. Although it is generally considered that high-pressure slurry feeding can be accomplished more easily at larger scale, most process development to date has been at the smaller laboratory scale. High-pressure pumping of biomass slurries required for hydrothermal processing at large scale is not well developed. Drying of wet biomass before use in a thermochemical conversion process can have a large negative impact on the overall process efficiency. An advantage of the use of hydrothermal conditions is that it avoids the drying step. The use of water in hydrothermal systems also allows ionic reaction conditions. Ionic chemical reaction mechanisms provide interesting product formation routes from biomass, but they also lead to higher levels of corrosion in the processing systems, wherein high-pressure requirements dictate the use of heavy-walled metallic reactor systems. The hydrothermal transformation of biopolymers in biomass into a range of oxygenated fragments invariably produces organic acids, such as acetic acid and formic acid. Both of these products generate a low-pH medium in the water, which can lead to metal corrosion. The use of water as the processing medium in hydrothermal processing results in a large water handling requirement. The process input of water is often met by the water in the wet biomass feedstock, but additional water may also be required. Recycle and reuse

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of the water becomes a major consideration in the design of hydrothermal processes. Depending on the effectiveness of the process for organic transformation to fuel products and their recovery, a significant waste or recycle water treatment load may result from the process.

7.2

Background

Hydrothermal processing of biomass has been an active research topic since the first Arab oil embargo in the mid 1970s. Work in both liquefaction and gasification process development began at that time [1]. Supercritical water processing has also been the subject of research since that time. A recent review [2] has appeared in the open literature which discusses hydrothermal processing from a more fundamental viewpoint including science and engineering issues, as opposed to the more applied focus of this chapter. 7.2.1

Why Hydrothermal Processing?

Hydrothermal processing is envisioned as a means to process high-moisture biomass without preliminary drying of the biomass. The drying process is inherently an energy sink, and even if accomplished with low-temperature excess process heat, it will be a capital cost and will reduce overall energy efficiency. Hydrothermal processing is suitable for processing very wet feedstocks, such as algae or water hyacinth. Wet wastes from food processing or other agricultural processing systems can be utilized efficiently and effectively in hydrothermal systems. It is estimated that there are millions of tons of wet biomass residues generated as sludges each year. These include grain wet-milling by-products, foodprocessing sludge, paper-mill sludge (not counting black liquor from pulping), animal manures, and wastewater treatment sludges. One specific example is vinasse from sugar cane ethanol production – there is 13 m3 of vinasse produced for each cubic meter of ethanol. The vinasse contains about 3 wt% organic material; such a stream has no value as a fuel [3]. Animal manures in the USA alone amount to 35 million (dry) tons (31.75 t) per year [4]. 7.2.2

History of Hydrothermal Liquefaction Process Development

Direct biomass liquefaction was the terminology used for hydrothermal liquefaction in the 1970s–1980s. The source of the early process development work was the Pittsburgh Energy Research Center, the former Bureau of Mines facility at Bruceton, Pennsylvania. Their process for biomass liquefaction was based on the coal liquefaction technology developed for lignite coal, the CO–steam process [5]. The process centered on alkali-catalyzed reduction utilizing a carbon monoxide atmosphere. The chemistry was based on the water-gas shift reaction such that “nascent” hydrogen was produced to react with the organic substrate. Comparative tests have shown that carbon monoxide in the presence of aqueous alkali was a more active reducing agent than hydrogen gas alone [6]. This early work led to the construction of 1 ton/day (
0.91 t/day) pilot plant for direct liquefaction of Douglas fir wood chips at Albany, Oregon [7]. Supporting efforts at the Pacific Northwest National Laboratory (PNNL) in bench-scale testing developed a better understanding of several processing parameters [8]. The use of either recycled bio-oil or water was developed within

Fundamentals

203

the Department of Energy (DOE) program and demonstrated at the Albany plant [9]. The lower yields with the water-based system led to its de-emphasis [10]. Further development of an extruder feeder to handle higher concentrations of biomass in an oil carrier was also supported by the DOE and was demonstrated in a process development unit at the University of Arizona [11]. At the same time there were other efforts outside the USA. At the Royal Institute in Stockholm, Sweden, the effort focused on an oil slurry vehicle [12], as it did at VTT in Espoo, Finland [13]. In Canada there were several universities who were funded to study hydrothermal liquefaction concepts. At the University of Toronto, the technology was given the name of hydropyrolysis to indicate pyrolysis in water [14]. The University of Saskatchewan developed a small auger unit to perform alkali-catalyzed hydrothermal liquefaction [15]. The University of Sherbrooke also tested some ideas related to hydrothermal processing using shear energy as a pretreatment [16]. More recently, an outgrowth from Shell has led to the effort to commercialize hydrothermal upgrading (HTUÒ ). This version of the process was built at a small pilot scale and operated to provide some limited data [17]. 7.2.3

History of Hydrothermal Gasification Process Development

Initial efforts in hydrothermal gasification reported the use of catalysts. These early tests at the Massachusetts Institute of Technology (MIT) were predicated on the need for supercritical water conditions for effective gasification, without which significant char formation resulted [18]. However, later studies at PNNL showed that with adequate catalyst activity the gasification could be accomplished in hot, pressurized water at conditions less severe than supercritical [19]. The PNNL work demonstrated the high activity, but long-term shortcomings, of nickel metal as a catalyst [20], as well as the superior qualities of ruthenium metal as a catalyst in this system [21]. Subsequent studies in Japan [22] and at the Paul Scherrer Institut (PSI) in Switzerland [23] have confirmed the catalytic gasification under subcritical hydrothermal conditions. For additional details, see also reviews by Elliott [24] and Tester’s group [2]. The use of supercritical water as a hydrothermal gasification medium has continued. Although Modell’s efforts at MIT were diverted into supercritical water oxidation, MIT has more recently returned to the gasification arena in collaboration with PSI [25]. The Karlsruhe laboratory in Germany has also investigated the supercritical water gasification (see Kruse’s review [26]), both at laboratory scale [27] and in a pilot-plant operation [28]. The University of Hawaii has developed the use of carbon catalysts for gasification at supercritical water conditions [29]. The University of Twente in the Netherlands has also been investigating supercritical water gasification [30].

7.3

Fundamentals

Hydrothermal processing can be subdivided into two processing environments: subcritical and supercritical. The differentiation is based on the critical temperature of water at 647 K. The critical temperature is the limit beyond which the water vapor phase can no longer be compressed to form a liquid phase. In fact, this point is not so much a barrier as an inflection point for several of the properties of water. The density of liquid water varies with temperature and actually changes rather dramatically as the temperature approaches the

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critical point. At the critical point the vapor pressure of liquid water reaches 22.1 MPa, while the density of the liquid phase has been reduced to only 0.31 g/mL. Above the critical temperature, the density of the vapor phase is dependent on the pressure, but a separate liquid phase ceases to exist. The surface tension and the ionization potential of the water also change dramatically as the water temperature approaches the critical point. As a result, the solvent properties also change significantly. The liquid water at subcritical conditions is an effective polar solvent, while the supercritical water vapor has solvating properties more akin to an organic solvent. 7.3.1

Subcritical Processing in the Liquid Phase

At subcritical conditions the vapor pressure of water is a direct function of the temperature. In order to maintain liquid water in the processing environment, the operating pressure must be maintained above the vapor pressure. If the operating pressure is allowed to drop below the vapor pressure, the water will boil to regenerate sufficient water vapor to increase the pressure back to the vapor pressure. In this manner a hydrothermal process system can “boil dry” if allowed to depressurize. Near the critical temperature, changes in vapor pressure, liquid density, dielectric constant, and solvating power happen quickly with small changes in temperature. For example, with a temperature increase from 573 K to 647 K, the operating pressure must be increased by 13.5 MPa in order to maintain the liquid phase [31]. In addition, the volume of the liquid water will have expanded by 230% because of the drop in density of the liquid phase. Although the actual solubilities of inorganic materials in water have not been extensively determined near the critical point of water, it is clear from the available data, e.g. that for sodium carbonate [32], that they will have only limited solubility in water near the critical point. In the case of sodium carbonate, its solubility drops significantly over the range from 512 K to 621 K, from 18.7 wt% to G2.0 wt%. A final important consideration is that the liquid water is an ionic reaction environment. The ion product of liquid water near its critical temperature is much higher than at ambient conditions. Ionizable compounds will be present as ions and able to react via ionic mechanisms. The ionic medium facilitates mass transfer. Hydroxyl and hydronium ions are present for reacting with the substrates such that both acid-catalyzed and base-catalyzed reactions can be facilitated. Siskin and Katritzky [33] have provided examples of many organic molecules previously considered unreactive in liquid water that undergo chemical reactions when the water temperature was increased from 523 K to 623 K. Similar mechanisms can also have deleterious effects when considering corrosion of the reactor metallurgy and structure. The pressurized operating environment requires a high-pressure reactor system, typically constructed of steel. Because of corrosion concerns, stainless steel (typically 300 series) appears to be required for this processing environment. Attack of the metals by the ionic species is a significant concern in designing and specifying materials of construction for such processes. 7.3.2

Supercritical Processing in the Vapor Phase

There are important differences in chemical processing in water at supercritical conditions versus subcritical. Kruse [26] states, “In no other solvent can the properties near and above the critical point be changed more strongly as a function of pressure and temperature than in

Hydrothermal Liquefaction

205

water.” At supercritical conditions the dielectric constant of water moves toward one, after dropping from over 80 at ambient conditions to less than 20 at the critical temperature, 647 K. The drop in dielectric constant also favors free radical reactions over ionic mechanisms. As a result of the drop in the dielectric constant, the solubility of salts decreases while that of organic substances and permanent gases, like nitrogen and hydrogen, increases. In fact, water can be mixed with these gases in all ratios at supercritical conditions. At supercritical water conditions, the density of the processing environment is a function of pressure and temperature, as in the gas phase. Both the change in solubilities and density affect mass transfer rates. In the early 1980s many researchers expected altered and enhanced rates of chemical reaction to occur in supercritical solvents. It has been shown that this is not the case – there is no dramatic inflection in reaction rates in passing into the supercritical region. This was first pointed out in the early work on catalytic hydrothermal gasification [19], but has been confirmed numerous times since, as recently as a cellobiose decomposition study in 1998 [34].

7.4

Hydrothermal Liquefaction

Hydrothermal liquefaction of biomass is the thermochemical conversion of biomass into liquid fuels and chemicals by processing in a hot, pressurized water environment for sufficient time to break down the solid biopolymeric structure to mainly liquid components. 7.4.1

State of Technology

Hydrothermal liquefaction has only been demonstrated on a small scale for short time periods. The largest demonstration of a version of the technology was the operation of the Biomass Liquefaction Experimental Facility at Albany, Oregon (1 ton/day), producing 52 bbls (barrels – 1 bbl  117 L) of product over the life of the facility. Most of the rest of the development has been undertaken in laboratory systems using both batch and continuousfeed systems. 7.4.2

Process Descriptions

There are several versions of hydrothermal liquefaction which have been developed. The original design of the Albany plant was based on the research at the Pittsburgh Energy Research Center, hence the PERC process [9]. Figure 7.1 shows the process flow both asbuilt and after some modifications to eliminate the original scraped-surface preheater and introduce a fired tubular preheater and replace the stirred-tank reactor with a simple standpipe reactor. It was successfully operated in a test that lasted over a 35-day period with a 68% on-line availability. It required the addition of both reducing gas in the form of syngas (60% carbon monoxide–40% hydrogen) and an alkali catalyst (10 wt% on wood basis) as an aqueous solution. Although anthracene oil (a coal tar distillate) was used as the start-up slurry medium, recycle of a portion of the product oil allowed make up the feed slurry of 7.5 wt% dried wood flour from Douglas fir wood chips and displacement of the anthracene oil over time. The average wood feed was given as 38.4 lb/h (
17.4 kg/h), which is about 46% of the original design capacity of 1 ton/day. The oil yield was 53 wt% of wood feed.

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Figure 7.1 PERC process schematic [37]. Reproduced from D.C. Elliott, 1982, Thermochemical Production of Liquids from Biomass, Solar World Forum: Solar Technology in the Eighties, D.O. Hall and J. Morton (Eds), 1286–1291. With permission from the International Solar Energy Society

In the final long-term run, 30 bbls of product oil were produced with a minimum of 90% wood-derived oil. The derivative version of the technology demonstrated in the Albany plant [9] used an acid prehydrolysis of the Douglas fir wood flour to form essentially an 18 wt% wood slurry in water (12% wood solids). This concept, shown in Figure 7.2, was developed at the Lawrence Berkeley Laboratory, hence the LBL process. Neither the product oil nor the water was recycled in the short demonstration of the LBL process in the Albany Facility. Both the reducing gas (60% carbon monoxide–40% hydrogen syngas) and alkali catalyst (sodium carbonate at 13 wt% on wood basis for both acid neutralization and as the catalyst) were added in the demonstration. This process was operated over a 45-day period at about 45% on-line. The product split was about a 22% oil yield from wood feed and the by-product aqueous fraction contained about 2 wt% organic carbon. Oil product amounted to a total of 5 bbls over the operating period. The third substantial demonstration of hydrothermal liquefaction was performed in the HTUÒ system, shown in Figure 7.3, over a 19-day period using onion waste feedstock [35]. The unit was on-line 100% for the first 2 days, 75% for the next 3 days, about 60% for the next 4 days, then down for 8 days, and finally at 60% for the last 2 days for an overall capacity factor of 66% for the 10 days on-line. A total of 15.2 tons of wet feed was

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207

Figure 7.2 LBL process schematic [43]. From Description and Utilization of Product from Direct Liquefaction of Biomass, Third Symposium On Biotechnology in Energy Production and Conservation Biotechnoloy and Bioengineering Symposium, D. C. Elliott, Copyright 1981, John Wiley and Sons, Inc. Reprinted with permission

processed compared with the design capacity of 100 kg/h or about 33% of design capacity. The product split from the 1.6 dry tons of feed was 38% oil, 31% gas, and the balance in the residual water stream. About 3.5 bbl of oil product was produced during the operating period. Neither reducing gas nor alkali catalyst was added. Recycle of the water was not attempted either. 7.4.3

Product Evaluation

The products produced from Douglas fir wood in the US DOE program were analyzed in great detail by PNNL and LBL. The analyses included in Thigpen’s Final Report [9] from Albany are a combination of the detailed work from PNNL and some near-real-time analyses completed as part of the plant monitoring and operation. These analyses show a fairly consistent composition for the oil produced over a range of operating parameters of temperature, pressure, flowrate, and catalysis. The oil product is clearly not a petroleum analog. It is a complex mixture of oxygenated compounds extending over a wide range of molecular weight. Some typical analytical results from PNNL for several of the Albany products (as indicated by test run number) are found in Table 7.1 [36]. An important consideration is that the results presented in the table are for the whole raw oil as recovered from the plant. On a moisture-free basis, the oxygen content can be calculated to range

208

Hydrothermal Processing Start-up N2

CO2 gas Condenser Condensate

Gas-liquid separator

CO2 gas

Cooler 1

Condenser

Start-up water pump

Pressure release system

Product vessel Reactor

Cooler 2

Biomass feed pump

Biocrude/water

Figure 7.3 Schematic diagram of the HTUÒ pilot plant [35]. Adapted from R. H. Berends, J.A. Zeevalkink et al., Results of the First Long Duration Run of the HTU Pilot Plant at TNO-MEP, Proceedings of 2nd World Conference on Biomass for Energy, Industry, and Climate Protection, 2004, ETA-Florence, Italy

from 6.6 wt% and 6.9 wt% respectively in the TR8 and TR9 oils, which still contain startup anthracene oil, to 11.1 to 15.3 wt% for the more pure wood oils. More detailed analyses of distillate fractions of the product oils can be found also for the LBL oil product [37]. Vacuum distillation of the oil using an ASTM D-1160 system gave 68% distillates at up to 705 K. The fractions varied in color from clear white through yellow,

Table 7.1 Analysis of Albany wood-derived oils [38]. Reprinted from D. C. Elliott, Analysis and Comparison of Products from Wood Liquefaction, in Fundamentals of Thermochemical Biomass Conversion, 1003–1018, Copyright (1985), with permission from Elsevier Analysis

TR7a

TR8b

TR9b

TR11a

TR12b

Elemental Carbon (wt%) Hydrogen (wt%) Oxygen (wt%) Nitrogen (wt%) Moisture (ASTM D-95) Solids (HOAc soluble) HHVc (MJ/kg) Percent distillable (ASTM D-1160, 10 mmHg)

72.3 8.6 17.6 0.2 8.5 1.0 33.7 68

82.0 8.8 9.2 0.5 3.1 10.8 36.7 56.1

76.6 8.2 14.1 0.0 8.9 17.8 34.9 46

67.2 6.8 25.1 0.0 13.5 2.2 28.8 42.6

72.6 8.0 16.3 — 5.1 3.7 33.0 46

a

LBL oil. PERC oil. Higher heating value.

b c

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209

Table 7.2 Vacuum fractional distillation (ASTM-D1160) LBL oil [37]. Adapted from D. C. Elliott, 1981, Process Development for Direct Liquefaction of Biomass, in Fuels from Biomass and Wastes, D. L. Klass and G. H. Emert (Eds), pp. 435–450, Ann Arbor Science Publishers Fraction

1 2 3 4 5 Residue

Actual amount 8 ml light oil 23 ml water 45 ml 35 ml 40 ml 20 g 86.6 g

Relative amount (%) 3 8 18 14 16 8 32

Color

Boiling point (K) at 1 atm

10 mmHg

Clear white

to 411

to 283

Clear to yellow Green to orange Orange Orange to brown Dark brown

411–539 539–589 589–655 655–705 H705

283–415 415–449 449–526 526–549 H549

green, orange, and then brown (see Table 7.2). The oxygen content of the distillates ranged from 9.7 to 13.4 wt%, in the mid range, and back down 10.4 wt% in the residue. Aliphatic to aromatic carbon ratios, as determined by 13C nuclear magnetic resonance (NMR), ranged from 12 in the light distillate, with a hydrogen-to-carbon (H:C) atomic ratio of 1.81 to 1.0 in the medium and heavier distillates, which had H:C ratios of 1.52 down to 1.19 (see Table 7.3). The use of gas chromatography (GC) with a mass-selective detector allowed identification of a large number of the components in the distillate fractions. As expected, the light distillate contained many hydrocarbons, but also some ketones. In heavier fractions, furans as well as phenolics and methoxyphenolics were found. The latter would be expected lignin-derived products. Naphthols also became prevalent in the heaviest distillates. It was also reported that the LBL whole-oil product was only 3.25% pentane soluble. It had 0.227 kg of inorganic salt per cubic meter (or 79.4 lb/1000 bbl). Its specific gravity at 60 F (15.6 C) was 1.12 with an API gravity at 60 F of 4.93. Detailed analysis of the PERC oil was also reported [38]. The PERC oil was found to be 46% distillable under vacuum. Oxygen contents of the fractions ranged from 10.8 wt% in the light distillate, as high as 17.2 wt% in the mid range, and back down to 10.8 wt% in the residue. Similar to the LBL oil, the light distillate had a high H:C atomic ratio of over 2, while the other distillates steadily decreased in that ratio, to 1.1 H:C in the highly aromatic residue. Table 7.3 Analytical data for distillation fractions from LBL oil [37]. Adapted from D. C. Elliott, 1981, Process Development for Direct Liquefaction of Biomass, in Fuels from Biomass and Wastes, D. L. Klass and G. H. Emert (Eds), pp. 435–450, Ann Arbor Science Publishers Fraction

C (wt%)

H (wt%)

N (wt%)

O (wt%)

Atomic H:C

HHV (MJ/kg)

1 (oil) 2 3 4 5 Residue Whole oil

78.8 77.2 77.1 79.2 79.4 82.3 72.3

12.0 9.9 8.9 8.9 7.9 6.5 8.6

0.0 0.0 0.0 0.5 0.2 0.0 0.2

9.7 13.3 13.4 12.1 12.3 10.4 17.6

1.81 1.52 1.37 1.33 1.19 0.94 1.41

37.2 35.4 35.1 36.8 35.1 34.7 33.7

13

1

C NMR Ali/Aro C

H NMR Ali/Aro H

12 1.1 1.0 1.2 1.0 — 0.53

30 10 7.3 6.6 5.3 — —

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Hydrothermal Processing

Table 7.4 Group summary of GC–MS data for Albany oilsa [38]. Reprinted from D. C. Elliott, Analysis and Comparison of Products from Wood Liquefaction, in Fundamentals of Thermochemical Biomass Conversion, R.P. Overend, T.A. Milne, L.K. Mudge, 1003–1018, Copyright (1985), with permission from Elsevier Chemical group C2–C5 acids C5–C6 alcohols High MW guaiacols High MW oxygenates Guaiacols Cyclopentanones C8–C9 (¼) cyclic ketones Cyclopentanones C7–C9 cyclic ketones Unsaturated phenols Phenols Dihydroxybenzenes Methylnaphthols Dihydroindenes C8 alkylbenzenes PAHs Benzofurans Other heterocyclics No. of peaks identified No. of total peaks Quantity identified (%) Total chromatographed (%)

TR7 — — — — 1.6 (3) 2.1 (10) 2.0 (15) 1.3 (11) 0.7 (9) 0.7 (2) 3.3 (22) 4.7 (9) 2.8 (6) — — 1.0 (3) — — 90 360 28.4 77.4

TR8 — 0.1 — — 0.1 0.1 — 0.3 0.2 0.6 6.5 — 0.6 0.1 0.6 23.6 0.9 1.5 110 380 38.2 82.7

(2) (1) (2) (9) (5) (2) (40) (2) (2) (3) (37) (3) (2)

TR9 — 0.1 — — 0.1 0.2 — 0.4 0.4 0.5 6.8 — 0.4 0.1 0.5 14.2 0.7 0.9 110 390 34.1 61.4

(2) (1) (2) (9) (5) (2) (40) (2) (2) (3) (37) (3) (2)

TR11 — — 0.4 (2) 0.8 (3) 2.3 (6) 0.7 (9) 0.5 (8) 0.4 (7) 0.1 (4) — 0.6 (8) 0.2 (2) — — — — 0.1 (1) — 50 290 19.6 25.5

TR12 0.5 (4) — — 0.1 (1) 0.7 (3) 0.3 (2) 0.3 (2) 0.4 (4) 0.3 (4) 0.5 (2) 4.5 (24) 3.8 (13) — — — 0.6 (1) — — 61 — 19.7 51.7

a

Data listed as percentages and numbers in parentheses indicate number of individual chemicals.

A collection of GC–mass spectrometry (MS) data for several of the PERC and LBL whole oils from Albany are presented in Table 7.4. The data show the oil products are a complex mixture of oxygenated organics. They included acids, alcohols, cyclic ketones, phenols, methoxy-phenols (guaiacols from softwood lignin), and more condensed structures, like naphthols and benzofuran. The high polycyclic aromatic hydrocarbon (PAH) numbers for the TR8 and TR9 PERC oils showed that they were produced in short-term operations, such that the start-up carrier oil (anthracene oil, coal tar distillate) had not been displaced, while the TR12 product, from the long-term operation, was nearly free of PAH. The amount of oil chromatographed reflects the amount of distillate product. A large fraction of the chromatographed oil was not included in the quantified identified peaks, either because of poor resolution and peak overlap or because the complex, oxygenated isomers were not found in the standard MS libraries. A modified sequential elution by solvents-chromatography (SESC) was also applied to the Albany products [39]. Since this oil product contained almost no aliphatics, the initial hexane solvent was omitted. Essentially all hydrocarbons, aliphatic and aromatic, were recovered together in a 15% benzene–hexane solvent (fractions 1 and 2). The balance of the solvents used were chloroform (fraction 3), 6% ether–chloroform (fraction 4), 4% ethanol–ether (fraction 5), methanol (fraction 6), 4% ethanol–chloroform (fraction 7), 4% ethanol–tetrahydrofuran (fraction 8), and acetic acid (fraction 9). Table 7.5

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211

Table 7.5 Characterization of the fractions derived from an LBL oil. Reproduced from Fundamentals of Thermochemcial Biomass Conversion, 1985, 1027–1037, The Products of Direct Liquefaction of Biomass, H. G. Davis, M. A. Eames et al., Table II, with kind permission from Springer ScienceþBusiness Media B.V. Fraction

Wt%

Number-average molecular weight

Weight-average molecular weight

O (%)

1, 2 3 4 5 6 7 8 9

0–6 1–20 5–45 5–55 5–35 1–3 2–20 0–10

140 170 170 210 350 180 690 —

160 210 210 290 600 210 900 —

5 11 16 21 23 46 — —

Average molecular formula C11H14O0.5 C13H15O1.3 C12H14O2 C15H16.5O3.3 C30H30O7 — — —

shows characterization of the fractions derived from an LBL oil. Fraction 3 appeared to be functionalized phenolics like anisole, guaiacol or eugenol. Fraction 4 was composed of the simple phenols. Fraction 5 contained the naphthols and fraction 6 the higher molecular weight phenolics. Fractions 7, 8, and 9 were complex solid components. Table 7.6 shows the fraction distribution for several of the Albany oils. The authors concluded that the small amount of fractions 1–3 suggested that wood liquefaction was not a reasonable route for direct production of transportation fuels. However, the distribution of the phenolics among fractions 4–6 (the monomers and dimers and polyphenols) may be affected by processing and a more useful goal could be to produce lower molecular weight phenolics. The aqueous phase by-product has undergone limited analysis [40]. The same components found in the oil product were also seen at low concentration in the aqueous stream, due to their slight solubility in water. A suite of organic acids was found, as listed in Table 7.7. Although the authors were puzzled by this acid formation under reducing conditions, Krochta et al. studied the formation of these acids from cellulose in the presence of alkali in the same temperature range [41]. He found significant yields (5–30% in 10 min) of formic, lactic, and glycolic acids at 473–553 K, with these being displaced by formation of acetic and propionic at 593–633 K. Table 7.6 SESC profiles of Albany wood oils. Adapted from Fundamentals of Thermochemcial Biomass Conversion, 1985, 1027–1037, The Products of Direct Liquefaction of Biomass, H. G. Davis, M. A. Eames et al., Table III, with kind permission from Springer ScienceþBusiness Media B.V. Fraction

TR-7

TR-10

TR-12

1, 2 3 4 5 6 7, 8, 9 1–4 4–6

4 17 44 21 6 8 65 71

1 7 19 40 21 11 27 80

4 14 14 38 18 12 32 70

212

Hydrothermal Processing Table 7.7 Some acidic components in aqueous by-product from LBL process. From Chemistry and Stoichiometry of Wood Liquefaction, Third Symposium On Biotechnology in Energy Production and Conservation Biotechnology and Bioengineering Symposium; H. G. Davis, D. J. Kloden and L. L. Schaleger, Copyright 1981, John Wiley and Sons, Inc. Reprinted with permission Monocarboxylic acids

Dicarboxylic acids

Oxo- or hydroxy-acids

Acetic Propionic Butyric Isobutyric Palmitic

Succinic Methylsuccinic Glutaric 2-Methylglutaric Adipic

Levulinic (4-oxopentanoic) 2,3-Dihydroxybenzoic 4-Oxohexanoic

The Dutch developers of the HTUÒ technology provided some limited analysis of their oil products by way of generalizations, such as [35]: Many lignocellulosic biomass streams have been tested in autoclaves and prove to give similar quality biocrude independent of the sources: waste streams from (food) industry, like onion waste, sugar beet pulp, alperujo, waste streams from sugar industry, and many other, like verge grass, pectine, fruit-vegetable-garden waste (GFT), coir dust, hemp, fluff, etc.

Additionally [42]: The biocrude product is an organic mixture that readily separates from water. At room temperature it is a solid, and it becomes a liquid at about 80 C. It contains 10–15%w (DAF) of oxygen. The atomic H/C ratio is generally 1.0–1.3 and the average molar mass is around 600 g/mol. The nitrogen and sulphur contents depend on those of the feedstock. The LHV (lower heating value) of the biocrude is 30–35 MJ/kg DAF.

7.4.4

Product Utilization

The oil product from hydrothermal liquefaction can be used directly as a heavy fuel oil. Alternatively, it can be upgraded through catalytic hydroprocessing, primarily to remove oxygen, to produce hydrocarbon fuels similar to the currently marketed petroleum products. Boiler firing tests were undertaken with Albany oil products produced from Douglas fir wood. In these tests a distillate derived from the PERC process product oil handled and fired similar to a distillate #2 fuel oil. A whole-oil produced in the LBL process version handled and fired similar to a #6 residual fuel oil, requiring preheating to 410 K to perform satisfactorily. Fuel oil burn test data are provided in Table 7.8 to compare hydrothermal liquefaction oil with petroleum products [43]. The individual components in the oil product from hydrothermal liquefaction of wood might also be used directly as chemical products. Elliott [43] suggested several potential uses, such as phenolic resin production (phenolic fractions at up to 50% replacement of phenol in phenol-formaldehyde resins or whole oils to a lesser degree), gasoline octane booster (phenols or aromatic ethers) and antioxidants (stoichiometrically hindered phenolics). Hydroprocessing of hydrothermal liquefaction oils has been demonstrated in the laboratory. A recent review describes the extent of development [44]. The oil product from hydrothermal liquefaction of wood was readily hydroprocessed using conventional petroleum hydrotreating technologies. In effect, hydrodeoxygenation was substituted for

Hydrothermal Liquefaction

213

Table 7.8 Fuel oil burn test data. From Description and Utilization of Product from Direct Liquefaction of Biomass, Third Symposium On Biotechnology in Energy Production and Conservation Biotechnology and Bioengineering Symposium, D. C. Elliott, Copyright 1981, John Wiley and Sons, Inc. Reprinted with permission Fuels No. 2 distillate oil No. 6 residual oil PERC oil distillate LBL oil

Excess air (%)

NO (ppm)a

CO2 (ppm)a

CO (ppm)a

Efficiencyb (%)

26.0 23.0 22.5 19.0

193 331 258 169

272 364 196 120

28 14 32 281c

74.8 78.7 75.9 81.7

a

Average value over duration of test, corrected to 0% EA, 0% moisture. Heat loss method. c CO values were generally below 100 ppm throughout the tests, with several large spikes in the concentration level which led to the high average value. The reason for the concentration spikes is unknown, but may be related to particulates with different burning properties. b

hydrodesulfurization, which is usually required for petroleum utilization. Similar catalysts and conditions were used. Oxygen contents were reduced to near zero and the resulting hydrocarbon mixtures were readily analyzed using normal petroleum product tests, such as PONA (paraffins–olefins–napthenes–aromatics) chromatography and octane number measurements for gasoline range distillates. Table 7.9 shows some of the results for hydrotreating Albany product oils. [45] 7.4.5

Process Mechanism Evaluations

Other bench-scale research efforts over the years have provided needed insights into the understanding of hydrothermal liquefaction. In Elliott’s work [8] it was concluded that Table 7.9 Hydrotreating Albany product oils. Reproduced from Thermochemcial Biomass Conversion, 1988, 883–895, Upgrading of Biomass Pyrolysis Oils, E. G. Baker and D. C. Elliott, Table 9, with kind permission from Springer ScienceþBusiness Media B. V. Processing conditions Feed oil Catalyst Temperature (K) Pressure (MPa) LHSVa (volume oil/(volume catalyst h))

TR7 CoMo-S/Al2O3 671 13.84 0.10

TR12 CoMo-S/Al2O3 670 14.00 0.11

Yields Total oil (L/L feed oil) Aqueous phase (L/L feed oil) C5–498 K (distillate L/L feed oil) Hydrogen consumption (L/L feed oil) Carbon conversion to gas (wt%) Carbon in aqueous phase (wt%)

0.99 0.20 H0.86 616 14.1 0.1

0.92 0.20 0.34 548 9.0 —

Product inspections Oxygen (wt%) H:C ratio (atom/atom) Specific gravity (kg/L) C5–498 K (distillate vol.%)

0.0 1.65 0.84 H87

0.8 1.5 0.91 37

a

LHSV: liquid hourly space velocity.

214

Hydrothermal Processing

the presence of liquid water is a key factor for biomass liquefaction, from several points of view: . . .

water is the hydrogen source for alkali-catalyzed water-gas shift/formate reduction; water maintains the alkali catalyst in an ionized active form and allows ionic chemical mechanisms to occur, which favor oil formation; and water is the means to introduce the alkali catalyst into the system and facilitates the interaction of the alkali with the solid biomass; without liquid water, the alkali will precipitate and plug the system.

The form of the alkali catalyst was also found to have little bearing on the liquefaction results, in that sodium as carbonate, bicarbonate, hydroxide, or formate all showed nearly equal activity, as did the same potassium compounds. Lithium forms, which are slightly less soluble, appeared to be slightly less active. Calcium and magnesium exhibited reduced, but still significant, activity. From these results, it was concluded that the mechanism of alkali catalysis is related to base-catalyzed chemistry [46]. Of course, formate synthesis is a hydroxide-based chemistry, as is the water-gas shift reaction, under hydrothermal conditions in the presence of carbon monoxide [47]. Boocock and co-workers studied what they called aqueous thermolysis, which was the noncatalytic hydrothermal liquefaction of poplar wood. Electron microscopic images show the wood structure undergoing liquefaction at 553 K [48]. Although only a small fraction of the wood was liquefied at 573 K, poplar wood powder or chips could, in fact, be converted completely to acetone-soluble liquid within 1–2 min at 603 K [49], as shown dramatically in Figure 7.4. The poplar wood stick remains apparently unchanged at temperatures up to 523 K. Above that temperature the wood darkens, absorbs water, shrinks (as the

Figure 7.4 Degradation of wood to oil (figure 4 in Boocock et al. [49]). Reproduced with permission from D.G.B. Boocock et al., 1985, Liquefaction of Poplar Chips by Aqueous Thermolysis, Energy from Biomass and Wastes IX, Institute of Gas Technology

Hydrothermal Liquefaction

215

hollocellulose decomposes and dissolves, according to the authors), and, finally, a soft tar remains at temperatures above 603 K. The mass yield of such tar is 55 wt% (on a dry feed basis) and the tar contains 25% oxygen with an H:C ratio of 1.12. These studies also confirmed the value of a liquid water phase to retard the conversion of oil to gas and char. Eager et al. studied the use of alkali in hydrothermal liquefaction [50]. They concluded it had a beneficial nature, with or without carbon monoxide reducing gas, in directing the chemical mechanisms toward oil formation reactions as opposed to char solids. They also compared wood and wood-component conversion with that of sugars and polyols and concluded that an active aldose group was necessary for liquefaction to occur. Fructose resulted in char formation, and neither sorbitol nor glycerol resulted in much oil formation. The lignin-derived product was a solid at room temperature, but it was projected by the authors to be dissolved in the wood-derived oil product, causing the higher viscosity of the whole-wood product oil. The process results showed an oil yield of up to 50% from poplar feedstock in water with alkali with about one-third driven off as gas products. They also concluded that the water-to-wood ratio was an important process parameter, more so than temperature, time, nature, and amount of alkali catalyst and hydrogen-to-carbon-monoxide ratio, within the range of study of those parameters [51]. Yokoyama’s group has studied alkali-catalyzed hydrothermal liquefaction of a range of biomass feedstocks. Their early work compared the results with 11 different hardwoods and softwoods, three softwood barks and sugar cane bagasse and found all to be liquefied in a similar manner [52]. Oil yields (acetone soluble) from the whole woods ranged from 37 to 55%, the barks 20–27%, and the bagasse was 49%. The oxygen contents of the oils ranged from 25 to 35%. Later work [53] showed that distillation stillages from ethanol fermentation could be similarly liquefied to a heavy oil (49.2% dichloromethane soluble) whose oxygen content was only 13.5%. The oil also contained 5.8% nitrogen and 0.8% sulfur owing to the 5.9% nitrogen and 0.8% sulfur contents in the stillage. Subsequent work by this group showed that the heavy oil product could be upgraded by catalytic hydroprocessing to produce a finished oil product containing nearly no oxygen, but the nitrogen remained around 4% and the sulfur at 0.1% [54]. More recently, Fang et al. published results from both a small batch reactor and a high-pressure diamond anvil reactor in which they compared liquefaction of cellulose with and without a sodium carbonate catalyst. They concluded that high heating rate (H2.2 C/s) and formation of a homogeneous aqueous phase condition facilitated liquid product formation and avoided solid char [55]. Elliott et al. performed a more detailed study of the oil products from a range of biomass feedstocks [56]. They assessed that the claims in the literature of paraffinic and cycloparaffinic oil production from cellulosic wastes are misleading [57]. Their data for a collection of biomass sources ranging from kelp and water hyacinth, to napier grass and sorghum, to brewer’s spent grain confirmed the liquefaction of these biomasses at 623 K with alkali. The oil products were highly dependent on the biomass sources, with nitrogen contents in the oil products ranging from near zero from a low-nitrogen feedstock like napier grass to around 4% for feedstocks like spent grain and hyacinth with nitrogen contents of 3.4–5.6%. Nitrogen-containing components were mostly cyclic in nature and included alkylpyrrolidinones, alkylpyrroles, and alkylindoles. The oxygen contents of the oil products ranged from 30 to 42%. The oxygen-containing components were composed of the usual types, including phenolics and cyclic ketones. The oil yield seemed to be inversely proportional to the ash content of the feedstock. The ash contents of the feedstocks ranged from 38.4% in

216

Hydrothermal Processing

kelp down to 3.4% in spent grain, while the oil yield (on an ash-free basis) ranged from 19.2% for kelp up to 34.7% for spent grain. Another group at PNNL focused on the liquefaction chemistry of the carbohydrate fraction of the biomass [58]. Their studies elucidated some of the chemistry required in the breakdown of the cellulose structure and the condensation reactions which transformed the small carbonyl-containing products into oil components such as aromatics and cyclic ketones [59]. Others have studied Maillard reactions between simple sugars and amino acids under these conditions [60]. 7.4.6

Recent Fundamental Evaluations

Karagoz’s group at Okayama University in Japan has recently been working in the hydrothermal liquefaction field. They have focused on a lower temperature operating range, typically 15 min at 553 K, and as a result have reported lower biomass conversions and oil yields. In these tests, conversion of pine sawdust varied from 40% to 96% and the oil yield (acetone and ether soluble) from 9% to 34%. Their work confirms the activity of alkali compounds for improving the oil and minimizing the residual solids formation. They studied calcium, rubidium, and cesium, as well as sodium and potassium. As seen in earlier studies, the more soluble bases were more active, such that potassium was found to be somewhat better than sodium. Cesium and rubidium were less active [61] and calcium much less so, but still significantly better than the thermal reaction alone [62]. They compared several biomass feedstocks [63] and confirmed that cellulose is most easily liquefied and lignin is less so, while actual biomass materials (pine sawdust and rice husk), which contain both, were found to have an intermediate level of reactivity. They applied analytical techniques of GC–MS and NMR to the product oils and confirmed much of what was reported about the composition in earlier days [64]. Xu and Lad of the Lakeland University in Canada also recently published a study of hydrothermal liquefaction of pine sawdust at 573–653 K in which they evaluated calcium and barium hydroxides and iron sulfate as catalysts [65]. Calcium and barium both showed notable increases in oil yield (water soluble and acetone soluble), whereas the iron did not. The acetone-soluble oils (with or without catalyst) contained 17  2% oxygen, except the iron-catalyzed test, which resulted in an oil containing 23% oxygen. The water-soluble oils ranged from 36 to 45% oxygen. Song et al., at Dalian University of Technology, reported liquefaction studies of corn stalk, including comparative tests of cellulose, hemicellulose, and lignin models, and comparison of simple thermal decomposition (thermal gravimetric analysis) with the liquefaction results [66]. Van Swaaij’s group at the University of Twente have reported complementary results using wood, glucose, and pyrolysis bio-oil [67], while Kami et al., from the Hachinohe Institute of Technology, report mechanistic details of cellulose decomposition under hydrothermal conditions [68]. 7.4.7

Conclusions Relative to Hydrothermal Liquefaction

The main conclusions of this developmental work can be summarized as follows: .

Hydrothermal liquefaction of biomass can be accomplished with careful consideration of time, temperature, and pressure with potential for catalysis and use of reducing gases.

Hydrothermal Gasification .

.

217

The process is technically manageable, but several issues related to the multiphase environment need to be addressed, including mass and heat transfer with an emphasis on heat recovery, rheology, and phase stability. Long-term operation in a commercial-scale system remains to be accomplished, and such a unit will be complicated and expensive to build and operate.

7.5

Hydrothermal Gasification

Hydrothermal gasification of biomass is the thermochemical conversion of biomass into gases by processing in a hot, pressurized water environment for sufficient time to break down the solid biopolymeric structure to liquid components, which are subsequently gasified. 7.5.1

State of Technology

Hydrothermal gasification has been practiced over a range of operating temperatures and pressures. Early work identified supercritical water as an important operating medium, with the supercritical condition being the overriding parameter. Later work has shown that subcritical water can also be useful for highly effective gasification when performed with active catalysts. Laboratory-scale reactors in both batch and continuous-flow mode have been used in both operating regimes. The process has been scaled up to small engineering development units. 7.5.2

Process Description

Figure 7.5 is a flow diagram of the basic system for continuous-flow hydrothermal gasification. The diagram suggests the importance of heat recovery in efficient operation. The only input is the biomass/water slurry, and a simple separation of fuel gas and water follows. The temperature used in the operation of hydrothermal gasification of biomass can have several significant effects. In the review by Osada et al. [69], three temperature regions for hydrothermal gasification are identified: .

Region I (773–973 K supercritical water) – biomass decomposes and activated carbon catalyst is used to avoid char formation.

Chemical use Wet Biomass

Hydrothermal Gasifier, 600-950K 20-60MPa

Heat Recovery

heater

Gas Product

Process Heat Electricity

Gas/Liquid Separation

Pressure Letdown

Electricity

Clean Water

Figure 7.5 Hydrothermal gasification process schematic

218 . .

Hydrothermal Processing

Region II (647–773 K, supercritical water) – biomass hydrolyzes and metal catalysts facilitate gasification. Region III (below 647 K, subcritical water) – biomass hydrolysis is slow and catalysts are required for gas formation.

When operating in a system which reaches thermodynamic equilibrium, the resulting gas product composition will be determined by the pressure and temperature. Operation at subcritical temperature results in a product gas high in methane and less hydrogen [70], while operations at supercritical temperatures will produce more hydrogen and less methane. A confounding factor is that the relative amount of water in the system will also affect the gas product composition, in that lower biomass concentration in the reactor system (and, therefore, higher water content) will move the equilibrium toward hydrogen and away from methane by known steam reforming mechanisms. The use of low temperature will also impact the mechanical systems for containing the reaction. Lower temperature operation allows lower operating pressures, which result in lower capital costs because of lower requirements for containment structure and less severe corrosive attack on the reactor walls, which allows the use of less costly alloys. A useful update of the work in several laboratories using conditions on both sides of the critical point of water was published in 2005 demonstrating the extent of interest in the concept [71]. The specific use of catalysts in hydrothermal gasification of biomass is the subject of Elliott’s review [24]. A companion review by Kruse [26] provides a review of hydrothermal gasification biomass without the use of heterogeneous metal catalysts. 7.5.3

Catalytic Hydrothermal Gasification

Modell’s group were among the first to describe catalytic hydrothermal gasification [72]. Their work suggested a dramatic result of operation above the critical point of water; that is, that no solid by-products were produced. The results from batch tests with a range of catalysts (see Table 7.10) showed little effect of catalyst. Particularly noteworthy is that Table 7.10 Hydrothermal gasification of carbohydratesa. Reproduced from D. C. Elliott, 2008, Catalytic Hydrothermal Gasification of Biomass, Biofuels, Bioproducts and Biorefining, 2, 254–265. With permission from John Wiley and Sons Feedstock Catalyst Temp. Press. Time (K) (MPa) (h) Glucose Glucose Glucose Glucose Glucose Glucose Glucose Glucose Glucose Glucose Cellulose a

None Ni Ni None Ni Ni None Ni Mixed Mixed Mixed

ND: not detected. On a carbon basis.

b

473 473 523 573 573 623 647 647 647 647 647

1.38 1.38 4.07 8.44 8.44 16.8 22.2 22.2 22.2 22.2 22.2

2 2 2 2 2 1 1 1 0.5 0.5 0.5

Yieldb (mass%) Liquid

Gas

Solid

69.1 61.6 74.2 33.9 47.3 ND 77.8 86.8 65.0 70.8 77.47

0.03 ND 0.2 0.3 0.3 ND 8.2 10.0 20.2 23.2 18.31

29.8 ND ND 39.0 28.3 11.0 ND ND ND ND ND

Gas composition (vol.%) H2

25.8 30 45.1 43.1 14.5

CH4 CO2 CO CH2 Not Not Not Not Not Not 1.3 1.5 3.2 2.9 1.5

analyzed analyzed analyzed analyzed analyzed analyzed 34.4 38.5 42 27 38.5 12.5 40.6 12.6 19.7 64.2

ND ND 0.7 0.8 0.1

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219

very little methane synthesis was reported, despite commentary claiming high-Btu gas production and the authors’ understanding that higher methane content was suggested by thermodynamic equilibrium calculations [73]. Below the critical point of water (at 623 K) the gas yield was insignificant, with or without nickel catalyst. The nickel catalyst listed was commercially produced in an oxide form. It is apparent from the low methane yield and gasification result that the catalyst was not active. Subsequent work by Elliott and co-workers demonstrated that the use of active catalysts can facilitate the hydrothermal gasification of biomass, even below the critical point of water. Their initial work compared biomass hydrothermal gasification below and above the critical point of water and with and without catalysts [74]. In batch tests using a nickel catalyst with and without added sodium carbonate co-catalyst, the effect of temperature from 623 to 723 K was evaluated. Significant improvements when using the nickel metal catalyst were noted, including higher gas yields and higher levels of methane in the product gas. Table 7.11 presents results showing much higher gasification and methane levels and reduced levels of carbon monoxide compared with that reported by Modell. The higher gasification is notable because it is accomplished with wood, a more complex feedstock and less reactive feedstock than glucose or cellulose. The authors reported no remarkable transformation in the system in passing the critical point of water, but only the expected increased rate in gasification as a result of higher temperature. The Sealock and Elliott [75] patent further describes results with a number of biomass feedstocks, which can be gasified at these temperatures in the presence of a nickel metal or alkali-promoted nickel catalyst. The patent claims the formation of a fuel gas composed primarily of methane, carbon dioxide, and hydrogen. The results of this work suggest that a useful catalyst for gasification of biomass structures will also be a useful catalyst for methane synthesis. Of course, the use of a catalyst can allow low-temperature operation while maintaining useful kinetics. An additional significant development underlying the development of catalytic hydrothermal gasification was the understanding of stable formulations of high-surface-area support materials for the catalysts that are useful in hydrothermal systems. In order for catalysis to be effective for hydrothermal gasification, materials with long-term stability in hot liquid water needed to be identified and utilized in catalyst formulations. Elliott et al. [76] were the first to identify the problem and provide solutions for hydrothermal gasification. As shown in their research, a range of alumina- and silica-based materials, commonly used for catalyst formulations in the petroleum and gas processing industries, Table 7.11 Catalytic hydrothermal gasification of wood flour [24]. Reproduced from D. C. Elliott, 2008, Catalytic Hydrothermal Gasification of Biomass, Biofuels, Bioproducts and Biorefining, 2, 254–265. With permission from John Wiley and Sons Feedstock

Wood flour Wood flour Wood flour Wood flour Wood flour Wood flour

Catalyst

None Ni/Na Ni/Na Ni/Na None Ni/Na

Temp. (K)

623 623 643 653 673 673

Time (h)

1 1 1 1 1 1

Gas (% of C fed)

15 42 Not reported Not reported 19 67

Gas composition (vol.%) H2

CH4

39 38 34

12 15 16

35

CO2

CO

Not analyzed 49 0 46 0 49 0 Not analyzed 24 41 0

CH2 1 1 1 1

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were less useful for hydrothermal gasification. By using a number of commercial catalysts in their research they found that silica, aluminas (other than a-alumina), various ceramic supports, minerals (such as kieselguhr), and other silica–aluminas were physically and chemically unstable in a hot liquid water environment. Mechanisms such as dissolution, phase transition, and hydrolysis were identified. Of the many materials tested, the useful supports identified included carbon, monoclinic zirconia or titania, and a-alumina. Engineering of systems to allow the use of catalysts for the hydrothermal processing environment in the presence of potential catalyst poisons and fouling agents has also been an important factor in making this processing technology viable. Previous reports of continuous reactor tests with biomass feedstocks provided preliminary processing results, but also showed the problems of long-term operation of the process with the contaminants inherent in biomass [21] Attempts to pretreat biomass by removing certain components, like alkaline earths, to allow extended use with catalysts, have also been documented [77]. Further development of in situ treatment [78] led to placement of a vessel in the process line between the preheater and the reactor to capture and remove the solids before they reached the catalyst bed, where, in the previous tests, they collected and caused flow plugging. An alternate strategy for collecting concentrated brines for mineral removal has also been under development, primarily for use in supercritical water gasification systems [79]. A sulfur scrubber trap incorporated a chemical trap for reduced-sulfur forms. The sulfur components reacted with the trap material to form insoluble sulfide, which prevented their passing into the catalyst bed where they would combine with the ruthenium metal of the catalyst and destroy its catalytic capability. Bench-scale continuous-flow reactor tests were successfully completed with stillage from corn ethanol production and with insoluble solids following starch extraction from wheat millfeed (wheat flour by-product) using the modified reactor incorporating the mineral and sulfur removal technologies. The results are provided in Table 7.12. Approximately 10 h runs were completed with each. The stillage run ended when the feedstock was exhausted. The LHSV, reported as liters of feed slurry per liters of catalyst bed per hour, was 1.5 L/(L h). The conversion of 99.9% was reported in terms of chemical oxygen demand (COD) reduction. Gas produced was a medium-Btu gas with over 50% methane in carbon dioxide. The mineral recovery system recovered a solid with 91% ash content and which accounted for less than 1% of the carbon in the feedstock. Phosphate in the feedstock at about 2700 ppm was found to be absent (G1 ppm) following the processing. Table 7.12

Catalytic hydrothermal gasification of biorefinery residues

Feedstock Time on stream (h) LHSV (L/(L h)) COD conversion (%) Gas yield (L/g dry solids) Gas composition Methane (vol.%) Carbon dioxide (vol.%) Hydrogen (vol.%) Carbon loss with minerals (%)

Corn ethanol stillage

Destarched wheat millfeed

10.1 1.5 99.9 0.84

9.5 1.5 99.9 0.80

57 41 2 G1

56 42 2 1–2

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A run undertaken with the processed wheat millfeed ended when the catalyst was showing significant deactivation. The same LHSV was used and the conversion of COD was similarly high at 99.9% through most of the test. The gas product was nearly identical. The mineral recovery system recovered a solid with 70–80% ash content and which accounted for 1–2% of the carbon in the feedstock. Phosphate in the feedstock at about 940 ppm was found to be absent (G1 ppm) following the processing. Sulfate was also present in the feed at 35 ppm, but was found in the 2–10 ppm range in the effluent. Further analysis of the catalyst and scrubber beds provided additional information. Because significant levels of sulfur were found downstream in the bottom of the ruthenium catalyst bed, it was concluded that the sulfur scrubber material used in these tests did not provide adequate capture of sulfur. The potential for sulfur poisoning from either sulfide from protein or sulfate was an issue. Although the sulfur scrubber was intended to capture reduced sulfur, sulfate has the potential to be reduced to sulfide at any point within the catalytic reaction bed and to be irreversibly captured by metal catalyst at the point of reduction. Others have investigated the sulfate poisoning in a supercritical system and suggested a mechanism involving reaction of sulfate with the RuIII form during redox cycles of gasification [80]. Mineral (Ca, Mg, P, Fe) capture appeared to be much more successful. Capture of phosphate precipitates provided the major removal mechanism. Iron carryover into the ruthenium catalyst bed was noted and may have played a minor role in the catalyst deactivation. Subsequent batch reactor tests of the used catalyst showed that the sample from the top (product exit) of the bed maintained most of its activity, while the sample from the bottom portion (feed end) had been more deactivated. Detailed analysis of these materials by scanning electron microscopy and X-ray dispersion elemental mapping showed a relatively clean catalyst in the outlet side, but a catalyst contaminated on the inlet side with sulfur, which was highly associated with the ruthenium. Scattered particles of mineral matter (Ca, Mg, Si) did not appear to cause a significant amount of coverage; therefore, it is unlikely that they would impact catalyst activity. Several micro-reactor tests were performed to evaluate sulfur trap materials using feedstock composed of chemical models of biomass. The chemical models consisted of sucrose in water with added amounts of glycine and methionine to represent protein content (including reduced sulfur) and phenol to represent lignin content. These tests confirmed the usefulness of nickel in a stable, high-surface-area form, such as the G1-80 form from BASF or as alkali-leached nickel aluminum alloy (Raney nickel) for sulfur capture, while zinc oxide, manganese oxide, or copper–zinc oxide formulations were found to be not useful (not stable) in this processing medium. 7.5.4

Hydrothermal Gasification in Supercritical Water

The main goal of researchers in the field of supercritical water gasification has been to produce hydrogen as the primary product gas. Early work by Antal predicted a hydrogenrich product gas from gasification of cellulose in water at temperatures above 873 K [81], although the use of high pressure was counterintuitive to Antal’s reasoning for gasification. More recent thermodynamic calculations have confirmed that high hydrogen yield is expected in high-pressure (25 MPa) gasification as well [82].

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The rate of heating up the feedstock through the subcritical region to attain supercritical temperature has been found to be an important process parameter. Studies of the heatup rate found that extended time in the subcritical region resulted in reduced gasification at supercritical conditions [83]. The explanation was based on the formation of intermediates which polymerized to less easily gasified components. Alternatively, high gasification yields could be maintained given that the intermediates might be readily gasified over a catalyst at subcritical conditions (as described above) before they polymerized. Corrosion of the reactor metallurgy at supercritical water temperatures in gasification applications is a significant issue, but it is less of a problem than seen in supercritical water oxidation. The formation of hydrogen as the primary product could be considered a potential corrosion contributor through hydrogen embrittlement of the metal. However, no evidence of such has been identified. Hydrothermal gasification of methanol at supercritical conditions proceeded for over 1000 h without corrosions problems [84]. The reactor was constructed of 625 nickel alloy. With the introduction of actual biomass feedstocks, trace contaminants in the feedstock have been linked to corrosion problems. Sulfur in proteins was blamed for severe corrosion in a continuous-flow stirred-tank reactor system [27]. Potassium was linked to corrosion in hydrothermal gasification of glucose using a K2CO3 catalyst in supercritical conditions [83]. Antal’s group identified corrosion of the reactor walls as a major factor in catalytic hydrothermal gasification at supercritical conditions. Antal’s group also identified activated carbon as a catalyst for hydrothermal gasification at supercritical water (873 K) conditions. Xu et al. [85] described the use of several charcoals as catalysts for gasification of biomass and chemical wastewater feedstocks. With 1.2 M glucose, a 34 s residence time (22.2 WHSV– weight hourly space velocity) resulted in 80% carbon gasification without catalyst and 103% gasification with the carbon catalyst. At a 16 WHSV, the carbon gasification efficiency at 873 K was independent of operating pressure, with 99% achieved at either 34.5 or 25.5 MPa. However, the gasification dropped from 98% at 873 K to only 51% at 773 K with a 1.0 M glucose feedstock processed at 13.5 WHSV. Deactivation of the carbon catalyst toward gasification was observed after less than 4 h of operation. Operation with a swirl at the feed entrance allowed operation at near 100% for up to 6 h. Tests with more complex biomass streams [86] showed reduced rates of reaction. Higher temperatures (923–988 K) were used to achieve high conversions (91–106%) with corn starch and sawdust in corn starch slurries. In these experiments, flow of feed was eventually halted by build up of coke and ash in the heatup zone of the reactor. Metals present in the nickel-based HasteloyÒ reactor metallurgy appeared to catalyze the reactions. Thus, it appears that nickel alloys are not suitable long-term for use with these processing conditions. Corrosion metals derived from the reactor wall were found on the activated carbon catalyst. More recent work reported by Matsumura’s group shows results with a suspended activated carbon catalyst with a pretreated chicken manure feedstock [87]. In this processing mode, the plugging in the reactor was avoided for up to 4 h of operation at 873 K and 25 MPa. Recovery and reuse of the catalyst is perceived as a simple process step. Although corrosion of the reactor wall can lead to catalysis of the gasification reactions by the metal components, metal catalysis of gasification under supercritical conditions has also been confirmed. Potic [88] used quartz reactors and verified the high activity of ruthenium

Pumping Biomass into Hydrothermal Processing Systems

223

on rutile titania support for gasification of glucose in supercritical hydrothermal gasification, similar to earlier reports for subcritical conditions. Under subcritical conditions, no corrosion of 300-series stainless steel reactor systems has been found under a variety of conditions and feeds. 7.5.5

Conclusions Relative to Hydrothermal Gasification

The main conclusions of this developmental work are similar to those for hydrothermal liquefaction and can be stated as follows: .

.

.

Hydrothermal gasification of biomass can be accomplished with careful consideration of time, temperature and pressure with potential for catalysis under both subcritical and supercritical water conditions. The process is technically manageable, but several issues related to the multiphase environment need to be addressed, including control of mineral components and recycle of water and nutrients. Long-term operation in a commercial-scale system remains to be accomplished, and such a unit will be complicated and expensive to build and operate.

7.6

Pumping Biomass into Hydrothermal Processing Systems

Pumpingofwet biomass slurriesiswellknown. Forexample,the pulpand paper industry moves slurries through their facilities, but only at lower pressures. The use of pressurized systems at higher pressures and temperatures leads into processing territory with limited commercial experience and, thus, remains a technological challenge [73]. When considering capital costs for such systems, it is obvious that more concentrated feedstock slurries should require smaller processing systems for equivalent throughput and resulting lower capital costs. Similarly, higher temperature will lead to higher reaction rate, also resulting in reduced reactor size and cost. However, higher temperature will require higher pressure to maintain a liquid water phase for slurry transport in the hydrothermal system. Therefore, the economic drivers for capital cost reduction in hydrothermal processes are higher slurry concentrations and higher operating pressures, both of which lead to increasing difficulties for pumping. High-pressure feeding systems for biomass slurries have been recognized as a process development issue at least as long as the modern biomass conversion systems have been under development. That is, since the Arab oil embargo of 1973. Pumping biomass slurries was accomplished at the laboratory scale at several sites, but in all cases the slurry concentration was limited. Early work at the Pittsburgh Energy Research Center (PERC) suggests, “Perhaps the areas (sic) of greatest operational difficulty in the bench-scale plant involves the pumping of the waste slurry.” [89]. As a result, PERC could only process at up to 15% dry solids of municipal solid waste in water slurry. Yet, “This pumping problem is not anticipated in large-scale operation.” But, “It is doubtful, however, because of the low bulk density of dried organic refuse, that slurries containing greater than 30 weight percent solids can be pumped (even in commercial installations).” Similar results were reported in the larger scale plant operated for the DOE at Albany, Oregon, for the production of oil from wood flour. In the final report [9] it is disclosed that wood flour (60 mesh, 0.42 mm) could be pumped at up to 10% in either oil or water. Attempts to prehydrolyze the wood at

224

Hydrothermal Processing

concentrations up to 23% were accomplished (with either flour or chips), but the prehydrolyzed feed needed to be diluted back to 12% in water for high-pressure pumping in order to avoid plugging. Both of these cases used progressing cavity pumps for low-pressure pumping and reciprocating plunger pumps with ball check valves for high-pressure pumping. Subsequently, other pumping methods were tested at the bench scale in laboratories around the world. At the University of Toronto a hydraulic plunger design was used. This design functioned at bench scale using 60 mesh wood flour at 9% concentration in water when feeding into orifices at 13 mm [90]. In this case, the high-pressure pump only pumped water to force an amount of slurry into the pressurized reactor. Lignocellulosics could be effectively slurried at up to 30% solids by researchers at the University of Sherbrooke, but only when “mechano-chemical effects could be used advantageously to desaggregate (defibrate) the cell wall structure” by processing through a high-shear device using a creosote or bio-oil carrier [16]. Results with a water carrier are not reported. At the Royal Institute of Technology (RIT) in Stockholm, peat could be pumped at high pressure at 10–14% dry solids in water after preprocessing through a meat mincer to cut the fibers [12]. RIT used a Moyno pump to feed slurry to a “standard” piston pump with “rather big check-valves,” the ball being 11 mm in diameter. The pump included an internal filter with 1 mm slots to allow capture and removal of sand particles. Pumping test results have also been reported by the Technical Research Centre in Espoo, Finland [91]. Tests were performed in a pumping rig that included a low-pressure Moyno pump and a high-pressure plunger pump with 9.5 mm balls in its check valves. Both wood flour (hammer-milled to80 mesh, G0.18 mm) and milled peat were tested in water and anthracene oil carriers. Whereas peat could be pumped at up to 43% solids in anthracene oil and 25% in water, the wood flour could only be pumped at 15–18% in anthracene oil and not at all in water slurry. These results suggest that the feeding of wet biomass to hydrothermal processing systems is a barrier to implementation. Whereas the earlier strategy was to form slurries with smallparticle biomass feeds, the size reduction costs (dry grinding) were high and effective drying of the biomass was also required, with a resulting high energy cost penalty. The strategy was driven by the process assumption that a recycle oil carrier would be more economical to use for biomass liquefaction processes, based on: a higher concentration slurry potential would allow higher throughput and lower recycle; a lower vapor pressure of carrier required a lower operating pressure; and, possibly the most important, loss of organics into a water phase was a serious shortcoming. However, if gasification is the chosen processing option, then oil formation is to be avoided and water should be chosen as the slurry carrier. In the application where a gaseous product is formed, issue (3) is no longer a concern. The operating pressure issue remains, and the reduced slurry concentration can result in reduced throughput, but the recycle issue disappears, as clean water is a process by-product. By using wet biomass as the feed, size reduction can be accomplished in a lower cost wet grinding process step. Such results have been reported wherein sorghum stalks were chopped and processed through a wet ball mill and filtered through an 18-mesh screen to produce a slurry pumpable at up to 21 MPa [92]. The pump was a reciprocating plunger pump with 9.5 mm ball check valves, which was operated at 0.5–2.0 L/h. The sorghum slurry was produced at 4–6% dry solids and was a stable slurry, which did not settle out. Similar stable slurries of microcrystalline cellulose in water could not be formed and would always settle out, even with the addition of corn starch. Pumpable slurries of brewer’s spent

Pumping Biomass into Hydrothermal Processing Systems

225

grain were also produced by this method, wherein the final percentage of dry solids was 7.5–9.2% [93]. Subsequently, tests were also performed with potato crumbs from a french fry manufacturing operation. These could be pumped following the wet milling operation at 14% dry solids slurry content [94]. More recent tests have been made using this same preprocessing system to produce pumpable feed from the screened solids from dairy manure (at 3.5% dry solids) and Distillers dried grain and solubles (DDG&S) (rewetted to 5–9.5% dry solids slurries). In these tests a progressing cavity (Moyno) pump was used as the lowpressure feed to the high-pressure reciprocating plunger pump. Similar DDG&S slurries (at 2.5–5.5% dry solids) were pumped in a larger scale system with reciprocating plunger pump (16 mm ball check valve) without the low-pressure Moyno pump at rates from 5 to 12 L/h. However, there were some inconsistencies in the pumping rates (which would probably have been overcome by the use of the Moyno) [21]. Most recently a high-pressure syringe pump (Isco) has been used to feed biomass slurries. The pump can feed at up to 10 L/h at 21 MPa with a dual-piston arrangement, which allows automatic refilling for uninterrupted feeding; however, the uninterrupted feed rate is limited to only 8 L/h because of the fill rate. This pump has been used to feed wastewater treatment biosludge at 1.5–5% dry solids. The biosludge was initially recovered as a 1.5% slurry or a dewatered sludge with about 14% dry solids, which was remixed with the dilute slurry to form the 5% dry solids material. Corn ethanol stillage (10.8% dry solids), which has been homogenized with an in-line shear mixer unit (Arde Barinco), has also been effectively pumped with the syringe pump. Similarly, a wheat millfeed (dry mill by-product) was also pumped at a concentration of 7.6 wt% dry solids in water slurry after wet ball milling. Others have also reported pumping of biomass slurries at high pressure in the laboratory. The University of Hawaii reported that biomass slurries were fed to high-pressure reactor systems; in the two cases the pump used water as a hydraulic medium to push the biomass slurry, such that the pump only pumped water and not slurry. In one unit, water was pumped into a balloon inside a vessel filled with biosludge to force the biosludge out of the vessel and into a reactor system [86]. In the second, water was filled into a tube on one side of a movable piston with slurry on the other side. Water was pumped into the water side to push the piston and force the slurry out of the tube and into the high-pressure reactor (a so-called “cement pump”). Slurries fed in this manner (0.6–2.5 L/h) included starch gel slurries of wood, bagasse, and potato waste at 9–18% dry solids at 28–34.5 MPa [29]. This type of pump, a dual-piston version, was also operated at Hiroshima University to process a biomass slurry at 25 MPa [87]. The biomass slurry in these tests was a preprocessed cabbage at about 6 wt% dry solids. The preprocessing step consisted of hydrothermal pulping at 423 K for 60 min that produced a low-viscosity slurry, which did not separate with standing [95]. A similar piston pump system for supercritical water gasification was recently reported from Germany [96]. That system could operate at 0.3–1.6 L/h at up to 25 MPa. It was used to feed 5 wt% slurries of corn silage or clover after particle size reduction to G1 mm. It was also noted that a peristaltic hose pump could be used to pump these same slurries at low pressure to fill the feed vessel. In other work at Karlsruhe, they have described an innovative “boxer-type” (opposed pistons) screw press, which fed the biomass slurries at up to 30 MPa for supercritical water gasification. The biomass was a finely chopped mixture of carrots and potatoes at 1.8–5.4 wt % dry solids [97]. This system was also used to feed “zoo mass,” which consisted of a finely chopped mixture of cooked rice and chicken meat at 1 or 5 wt% dry solids [27]. This type of

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Hydrothermal Processing

pump functioned by filling the first side while emptying the other through a transit of the centrally linked pistons along a screw. Upon reversing the screw, the empty side refilled while feeding from the first side. No difficulty in feeding such materials is mentioned, though it was related that therewere some difficulties with the valves used to direct the flows in the filling and feeding operations. The pump operated at a scale of 250–750 mL/h. A larger scale demonstration has been made at up to 100 kg/h [98]. In the VERENA pilot plant, a two-step process was used to reduce particle size while diluting the dry solids content of corn silage to a pumpable level. A cutting mill was used first to reduce particle size to a few millimeters followed by a colloid mill which produced a slurry with 84% of the mass at less than 0.5 mm and an organic carbon content of 3.96 wt %. This system could be operated at up to 35 MPa, but the details of the pump are not given. As related earlier, the high-pressure feeding of biomass slurries should be more readily achieved at larger flow rates, wherein the fibrous nature of the biomass would not be expected to bridge and plug the orifices and valves.

7.7

Conclusions of Hydrothermal Processing

Hydrothermal processing has been under development for use in both liquefaction and gasification applications. Hydrothermal processing systems for biomass conversion allow an efficient means to produce fuels and chemicals from high-moisture biomass without the intermediary drying step. Bench-scale and small-scale operations have shown that the systems can be operated, but these are high-pressure systems which require careful overall design and careful operational control with consideration of time, temperature, and pressure. The processes are technically manageable, but several issues related to the multiphase environment need to be addressed in further developmental research. Longterm operation at commercial scale remains to be accomplished, and such a unit will be complicated and expensive to build and operate.

References [1] Sealock, L.J. Jr., Elliott, D.C., Baker, E.G., and Butner, R.S. (1993) Chemical processing in highpressure aqueous environments: 1. Historical perspective and continuing development. Industrial & Engineering Chemistry Research, 32, 1535–1541. [2] Peterson, A.A., Vogel, F., Lachance, R.P. et al. (2008) Thermochemical biofuel production in hydrothermal media: a review of sub- and supercritical water technologies. Energy & Environmental Science, 1, 32–65. [3] Serikawa, R.M., Funazukuri, T., and Wakao, N. (1992) Oil conversion of vinasses with highdensity water. Fuel, 71, 283–287. [4] Ro, K.S., Cantrell, K., Elliott, D., and Hunt, P.G. (2007) Catalytic wet gasification of municipal and animal wastes, Industrial & Engineering Chemistry Research, 46, 8839–8845. [5] Appell, H.R., Wender, I., and Miller, R.D. (1969) Solubilization of low rank coal with carbon monoxide and water. Chemistry & Industry, 47, 1703. [6] Appell, H.R. (1977) The production of oil from wood waste, in Fuels from Waste (eds L.L. Anderson and D.A. Tillman), Academic Press, New York, pp. 121–140. [7] Lindemuth, T.E. (1981) Carboxylolysis of biomass, in Biomass Conversion Processes for Energy and Fuels (eds S.S. Sofer and O.R. Zaborsky), Plenum Press, New York, pp. 187–200.

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[8] Elliott, D.C. (1980) Bench scale research in biomass liquefaction by the CO–steam process. Canadian Journal of Chemical Engineering, 58, 730–734. [9] Thigpen, P.L. (1981) Final Report of Operations at the Albany, Oregon, Biomass Liquefaction Experimental Facility, final report to US Department of Energy under contract #B-B2471-A-G. [10] Schaleger, L.L., Figueroa, C., and Davis, H.G. (1982) Direct liquefaction of biomass: results from operation of continuous bench scale unit in liquefaction of water slurries of Douglas fir wood. Biotechnology and Bioengineering Symposium 12, 3–14. [11] White D.H. and Wolf, D. (1988) Advances in direct biomass liquefaction by the extruderfeeder method, in Research in Thermochemcial Biomass Conversion (eds A.V. Bridgwater and J.L. Kuester), Elsevier Applied Science, London, pp. 827–842. [12] Bergstrom, A., Kannel, A., and Sylwan, C. (1983) The RIT high pressure direct liquefaction experience, in Comptes Rendus de l’Atelier de Travail sur la Liqu
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8 Catalytic Conversion of Sugars to Fuels Geoffrey A. Tompsett, Ning Li and George W. Huber Department of Chemical Engineering, 159 Goessmann Laboratory, University of Massachusetts–Amherst, Amherst, MA 01003, USA

8.1 8.1.1

Introduction Overview

Modern society is heavily dependent on liquid fuels for transport and energy needs. The vast majority of our liquids fuels are derived from a single source – petroleum oil. The demand for oil has increased rapidly over the last century, causing a significant increase in the price of liquid fuels. Environmental and political concerns have also shown the importance of finding an alternative feedstock for liquid fuels besides petroleum oil. A range of liquid fuels are currently in use that are specifically made for different types of engine. These fuels include gasoline, jet fuel (kerosene), and diesel. In this respect, the only form of renewable carbon is plant biomass. Technologies are currently being developed that will allow us to convert the plant biomass into gasoline, jet fuel, and diesel. Replacing petroleum-derived fuels with the gasoline, jet fuel, and diesel derived from biomass will allow the use of the current infrastructure. Gasoline, jet fuel, and diesel fuel are mixtures of smaller alkanes, branched alkanes, aromatics, and larger alkanes. Photosynthesis takes CO2 from the air and combines it with water to produce a carbohydrate structure. The carbohydrate structure is available as simple sugars, disaccharides, or more complex polymers, like cellulose and hemicellulose. First-generation biofuels use these simple sugars to produce ethanol. The next generation of biofuels will convert the more complicated form of carbohydrates, like cellulose and hemicellulose. In both cases carbohydrates must be efficiently converted into a range of different compounds that can be used to make gasoline, jet fuel, and diesel fuel. The purpose of this review is to discuss new technologies that will allow us to convert carbohydrates into the full suite of Thermochemical Processing of Biomass: Conversion into Fuels, Chemicals and Power, First Edition . Edited by Robert C. Brown © 2011 John Wiley & Sons, Ltd. Published 2011 by John Wiley & Sons, Ltd. ISBN: 978-0-470-72111-7

Introduction

233

molecules that are found in petroleum oil. These exciting new advances are moving from the academic setting to the pilot-plant stage. These approaches use heterogeneous catalysts, which are the same catalysts that are used to make petroleum fuels today. Some of the advantages of this approach include inexpensive catalysts, short residence times, improved thermal efficiencies, and that little downstream distillation steps are required. This chapter sets out to demonstrate that there are significantly more ways to make fuels from carbohydrates besides fermentation. Section 8.1 discusses the overall reactions for this approach. Section 8.2 discusses sugar chemistry, as this provides a basis for how to convert the sugars. A number of these schemes require the addition of hydrogen, which can come from the sugar. Hydrogen itself is a candidate fuel. Therefore, Section 8.3 addresses the conversion of sugars to hydrogen. Section 8.4 discusses how sugars can be converted into light alkanes (C6 and smaller), which can be used as gasoline. Section 8.5 explains how sugars can be used to produce targeted oxygenates which could be blended with gasoline or diesel. Section 8.6 considers routes to produce larger alkanes (ranging from C7 to C15), which can be used as diesel or jet fuel. Section 8.7 describes the production of aromatics from sugars, which can be used in gasoline, jet fuel, and diesel fuel. Section 8.8 is a summary and conclusions for this chapter. Importantly, this article describes the fundamental chemistry of each of the reactions, the catalysis, and the needs for future development. 8.1.2

Desired Targets and Overall Reactions

The desired products are conventional fuel molecules that are already in petroleum-derived fuels. Figure 8.1 shows the target fuel types and the general reaction classes that will be discussed in this review. The fuel types consist of hydrogen and the three main liquid fuel fractions: gasoline, kerosene/jet fuel and diesel. Hydrogen is a primary product of reforming, but it is also required in many reactions as a reactant, specifically hydrogenation reactions. Hydrogen could be utilized as a fuel directly in devices such as fuel cells for the production of electricity. However, it is more likely that hydrogen is used directly in the production of liquid fuels in an integrated biorefinery. The recycling of hydrogen is not shown in Figure 8.1 for clarity; however, this is discussed in the literature [1, 2]. Gasoline is comprised of mainly short-chain alkanes and aromatics. It is desired to have more branched hydrocarbons in gasoline because they have a higher octane rating. Jet fuels consist mainly of C12–C15 hydrocarbons with a boiling point range of 150–275
C. Diesel is a fuel with a high boiling point (200–350
C) and is composed of long-chain alkanes (C10–C15) and aromatics. For diesel fuel, straight-chain alkanes are more desirable than branched alkanes because they have higher cetane ratings. Sugar feedstocks can be derived from direct extraction of sugars and starches from plants, e.g. corn kernels, or from processing of lignocellulosic biomass, e.g. hydrolysis of corn stover. The sugar feedstocks consist of both C5 and C6 carbohydrates. In order to produce the various fuel molecules for the four fuel ranges, many reaction pathways have been identified, including hydrogenation, hydrogenolysis, dehydration, aldol condensation, reforming, and pyrolysis. Hydrogen can be produced from direct reforming of the sugars, including supercritical reforming or lower temperature aqueous-phase reforming (APR). Similarly, light alkanes can be formed using APR of the sugar solutions. As shown in Figure 8.1, the conversion of sugars to fuels is a multistep process. Typically, the sugar is first converted to another platform molecule which is then transformed into

Bio-oil Aromatics H2 and CO

Pyrolysis/ liqufaction CFP Gasification

Levulinic acid

Fischer-Tropsch

hydrogenation

Dehydration

Etherification/Esterification

Large organics

C8-C12 fraction

alkanes, intermediates

Dehydration/ hydrogenation

C-C hydrogenolysis

Condensation

Acid dehydration

Aqueous phase reforming

Hydrogen

HMF or furfural

Acids, alcohols, ketones, heterocyclics

Supercritical Reforming

Acid dehydration

Isomerization & Biphasic dehydration

Hydrogenolysi

Hydrogenation

Reduction, HI

Aromatics

esterification

Dehydration/ Hydrogenation via GVL

Dehydration/ hydrogenation

Dehydration/ hydrogenation

Dehydration/ hydrogenation

Base Condensation

Dehydration/ hydrogenation

Acid Cat (zeolite) upgrading

C7-C13 alkanes

Aromatics, alkanes

C9-C15 alkanes

alkanes

Alkanes, aromatics

Levulinic acid esters

alkanes

Furan ethers and esters (furanics)

C9-C15 alkanes

H2, alkanes

C1-C6 alkanes, aromatics, isoparafins

C4-C12 alkanes

H2, light HCs

Alkane saturation

Reforming/FischerTropsch

Alkane Oligomerization

polyols

H2

Gasoline

Kerosene Jet-Fuel

Diesel

Figure 8.1 Chemistries involved in the production of fuels and chemicals from carbohydrate-based feedstocks. HMF: 5-hydroxymethylfurfural; CFP: catalytic fast pyrolysis

C5 and C6 Sugars

Saccharides from plant extraction eg. starch from corn kernel, sucrose form sugar cane

Polysaccharide Feedstock from biomass

Sugar Alcohols

234 Catalytic Conversion of Sugars to Fuels

Introduction

235

a fuel. For example, the dehydration of sugars produces furfural or HMF, which can then be converted into a range of fuels. Alternatively, sugars can be hydrogenated to form the more stable sugar alcohols, e.g. sorbitol. Sugar alcohols can be used in various reactions, including reforming or C–C hydrogenolysis to form polyols. These polyols can then be transformed into a range of other compounds. In order to form larger chain-length alkanes, C–C bond formation reactions are required to increase the C5/C6 carbon backbone before hydrogenation/dehydration. Chheda and Dumesic [3] utilize primarily base-catalyzed aldol condensation with a ketone (acetone) to form larger C9–C15-range fuel molecules. Aromatics from sugars are typically produced inside zeolite-based catalysts [4]. The aliphatic hydrocarbons and aromatics produced from the various reactions described above can then be blended to obtain the fuel fractions with specific properties, namely boiling point, viscosity, octane/cetane number. This forms the backbone processes for biorefineries to produce renewable fuels from biomass. In this sense, the biorefinery of the future will most likely consist of a series of reaction steps. For this biorefinery to be economically viable, all these reactions must be optimized, integrated, and be at high yields. 8.1.3

Thermodynamics of Chemistry Conversion

The conversion of sugars to fuels (hydrogen and alkanes) is achieved through a series of at least 11 different fundamental reactions, including hydrolysis, dehydration, reforming (including supercritical reforming), C–C hydrogenolysis, C–O hydrogenolysis, hydrogenation, aldol condensation, isomerization, selective oxidation, water-gas shift, and oligomerazation [1]. Multiple reactions can occur in one single reactor with bifunctional catalysts or alternatively one reaction in one single reactor. These reactions are combined to make targeted products. Thus, it is helpful to understand the overall thermochemistry of the specific reactions. Figure 8.2 shows the change in enthalpy of many of these processes at 300 K at 1 atm (101 kPa). Exothermic reactions (negative enthalpy change) are represented as moving toward the bottom of the scheme and endothermic reactions (positive enthalpy change) are represented as moving toward the top. The thermodynamics of each reaction type are now discussed. 8.1.3.1 Hydrolysis Reactions Sugars such as glucose, shown in Figure 8.2, are typically formed from hydrolysis of polysaccharides; for example, cellulose in biomass conversion. Hydrolysis is energetically almost neutral (e.g. 5 kcal mol1 sucrose to glucose and fructose). Goldberg et al.5 have reported the enthalpy changes accompanying the hydrolysis of glucose–glucose (a,1 ! 4), glucose–glucose (a,1 ! 6), and glucose–fructose (1 ! 6) linkages as 1.1 kcal mol1, 1.4 kcal mol1, and 3.6 kcal mol1 respectively. Goldberg and coworkers [5–10] have extensively studied the thermodynamics of carbohydrate hydrolysis. The thermodynamic quantities for disaccharides and oligosaccharides are shown in Table 8.1. It can be seen that the change in enthalpy for the hydrolysis of most disaccharides is almost neutral except for sucrose. Each linkage in an oligosaccharide between glucose molecules corresponds to 1 kcal mol1 from the difference in enthalpy change between maltose and maltotriose, for example.

Figure 8.2 Schematic representation of enthalphic energy changes at 300 K and 1 atm for principal reactions involved in the conversion of carbohydrates to fuels. Exothermic reactions are represented as moving toward the bottom of the figure, and endothermic reactions are represented as moving toward the top of the figure [1]. (Adapted from J.N. Chheda, G.W. Huber and J.A. Dumesic, Liquid-phase catalytic processing of biomassderived oxygenated hydrocarbons to fuels and chemicals, Angewandte Chemie International Edition, 2007, 46, 7164. Copyright Wiley-VCH Verlag GmbH & Co, KGaA, reproduced with permission)

236 Catalytic Conversion of Sugars to Fuels

Introduction

237

Table 8.1 Thermodynamic quantities for the hydrolysis of disaccharides and oligosaccharides (adapted from Refs [5–10]) K Disaccharide Cellobiose Gentibiose Isomaltose Lactose Lactulose Maltose a-D-Melibiose Palatinose Sucrose D-Trehalose D-Turanose Oligosaccharide Maltose Maltotriose Maltotetraose Maltopentaose Maltohexaose Maltoheptaose

H155 17.6 17.3 35 128 H513 123 4.44  104 119

DrG0(kcal mol1)

DrH0(kcal mol1)

DrS0(cal K1 mol1)

G3.0 1.7 1.7 2.1 2.9 3.7 2.8

0.58 0.62 1.33 0.11 0.53 1.09 0.21 1.06 3.58 1.13 0.63

H8.1 7.9 10.3 7.4 11.5 H8.8 8.8

5.9 2.8

7.6 13.4

1.09 2.16 3.29 4.33 5.35 6.40

8.1.3.2 Dehydration of Sugars Dehydration of sugars involves the loss of water to form furan-based compounds, such as HMF from glucose. This reaction is relatively thermodynamically neutral at only 5 kcal mol1 change in enthalpy (Figure 8.2) [1]. This reaction occurs readily with an acid or base catalyst. From kinetic studies, Qi et al. [11] determined that the activation energy for dehydration of fructose to HMF was 103.4 kJ mol1 (24 kcal mol1), using ion-exchange resin catalysts. This was in good agreement with Bicker et al. [12], who reported an activation energy of 23.6 kcal mol1 for the fructose dehydration using 3 mmol L1 sulfuric acid as catalyst at a pressure of 20 MPa. Furthermore, Antal et al. [13] obtained 23.8 kcal mol1 for the dehydration of glucose under sulfuric acid. 8.1.3.3 Reforming – Formation of Hydrogen In contrast to hydration/dehydration reactions, reforming processes give rise to a large increase in enthalpy in converting sugars to CO2 and H2. Hence, these reactions require significant energy (150 kcal mol1 of glucose for reforming with the water-gas shift reaction) to break down the highly functional carbohydrate structures to CO2 and H2 [1]. The change in the Gibbs free energy for the overall reforming reaction is favorable at modest temperatures and above (e.g.50 kcal mol1 for glucose at 400 K) because of the large increase in entropy for the reaction. Similarly, syn-gas from reforming of glycerol is endothermic (80 kcal mol1). Syn-gas reforming differs by minimizing the amount of water present and hence the water-gas shift reaction. If the Fischer–Tropsch process is used with reforming of the carbohydrates, to form alkanes from CO and H2, the process is exothermic with an enthalpy change of about 30 kcal mol1 of glycerol, since the Fischer–Tropsch

238

Catalytic Conversion of Sugars to Fuels

process is highly exothermic (e.g.110 kcal mol1) [14]. A third type of reforming reaction involves supercritical water. Tang and Kitagawa15 reported the thermodynamic analysis of supercritical water reforming of biomass, using glucose as the model compound. A change in enthalpy of 142 kcal mol1 was calculated for glucose conversion to CO and H2. 8.1.3.4 Hydrogenation – Formation of Sugar Alcohols In comparison with reforming, hydrogenation reactions are typically exothermic. For example, the hydrogenation of glucose to sorbitol has a change in enthalpy of approximately 10 kcal mol1. The hydrogenation of HMF to 2,5-di(hydroxymethyl)furan (DHMF) has an enthalpy change of around20 kcal mol1; and the hydrogenation of the furan ring in DHMF to produce 2,5-di(hydroxymethyl)tetrahydrofuran (DHM-THF) is about35 kcal mol1 (or about 18 kcal mol1 of H2) [1]. From kinetic studies, Crezee et al. [16] reported the activation energy for hydrogenation of glucose to sorbitol of 21 kcal mol1. Similarly, Baudel et al. [17] reported an activation energy of 20 kcal mol1 for the hydrogenation of xylose to xylitol at 90
C using Ru 2%/C catalyst. 8.1.3.5 Hydrogenolysis – Cleavage of C–C and C–O Bonds Cleavage of C–C bonds in the presence of hydrogen is termed C–C hydrogenolysis. This type of hydrogenolysis reaction is almost energetically neutral (e.g. 5 kcal mol1 for the hydrogenolysis of sorbitol to produce two molecules of glycerol). C–O hydrogenolysis reactions, however, are highly exothermic. The enthalpy change for C–O hydrogenolysis of glycerol (an important polyol platform) to produce propanediol and water is 25 kcal mol1 [1]. 8.1.3.6 Aldol Condensation – Formation of Longer Chain Oxygenates In order to increase the carbon chain length of subsequent alkane fuels forming from sugars, aldol condensation is the typical reaction method used [18]. For example, the aldol condensation of HMF with acetone forms (3-hydroxybutenyl)-hydroxymethylfuran (BH-HMF), hence increasing the carbon chain length from C6 to C9, which in turn can be converted to alkanes via hydrogenation/hydrogenolysis reactions. The aldol condensation is slightly exothermic with enthalpy change of 10 kcal mol1 of HMF [1]. 8.1.3.7 Hydrogenation and Hydrogenolysis – Formation of Alkanes Subsequent hydrogenation and hydrogenolysis reactions to convert BH-HMF to C9 alkane are exothermic at60 kcal mol1 and50 kcal mol1 respectively (or20 kcal and25 kcal per mole of H2) [1]. Hence, this process is significantly thermodynamically favorable.

8.2

Chemistry of Sugars

Plants capture solar energy as fixed carbon, from carbon dioxide and water in a carbohydrate building block represented as (CH2O)x, as shown in Equation (8.1): CO2 þ H2 O þ light ! chlorophyll þ ðCH2 OÞx þ O2

ð8:1Þ

Chemistry of Sugars

239

Plants store this energy as carbohydrates in three main types of molecule: sugars or starches, cellulose, and hemicellulose. This stored carbohydrate is nature’s building block for plants and the most abundant organic molecule on Earth. Hence, biomass is a significant resource for utilizing that stored energy as fuels. The starches and sugars can be directly extracted from some plants types, e.g. sugar cane and corn kernels, while extracting sugars from the hemicellulose and cellulose components of woody biomass requires a chemical processing step, namely hydrolysis. Sugars are typically C5 or C6 saccharides; for example, xylose and glucose respectively. Starches are polysaccharides consisting of chains of glucose units joined together by glycosidic bonds. Cellulose is a polymeric chain (polysaccharide) of glucose molecules and b-1,4 glycoside linkages, while hemicellulose is the polysaccharide of C5 and C6 sugars, including xylose, mannose, galactose, rhamnose, and arabinose. Cellulose is crystalline, while hemicellulose is amorphous. Hemicellulose is amorphous because of its branched nature, and it is relatively easy to hydrolyze to its monomer sugars compared with cellulose [19]. Woody biomass (lignocellulosic) materials are typically composed of three main components: cellulose, hemicellulose, and lignin. The cellulose and hemicellulose make up the carbohydrate portion of the lignocellulose. Upon partial acid hydrolysis, cellulose can be broken down into cellobiose (glucose dimer), cellotriose (glucose trimer), and cellotetrose (glucose tetramer), whereas upon complete acid hydrolysis it is broken down into glucose. Starches are a polysaccharide of glucose, but in contrast to cellulose have a-1,4 glycoside linkages [19]. Woody, biomass typically also contains a third component, lignin, at 10–25 wt%, consisting of highly branched, substituted, mononuclear aromatic polymers found in the cell walls. Lignin does not break down to sugars and, therefore, will not be considered in this review; however, this is a significant biomass resource [19]. Lignocellulose is difficult to convert to sugars because of the high crystallinity of the cellulose, low surface area of the material, protection of cellulose by lignin, the heterogeneous character of biomass particles, and the cellulose sheathing by hemicellulose. In order to convert lignocellulosic materials to sugars, an effective pretreatment process is required to break the lignin cell wall and disrupt the crystallinity of the cellulose. Pretreatment methods used for lignocellulose include: noncatalytic steam explosion, treatment in liquid hot water or pH-controlled hot water, flow through liquid hot water or dilute acid, flowthrough acid, treatment with lime, and treatment with ammonia. Following pretreatment, biomass can be broken down in to sugars using acid or enzymatic hydrolysis [20]. Cellulose is converted to the six-carbon sugar C6 glucose, while hemicellulose is based on C5 sugars, mainly xylose and arabinose, as well as C6 sugars, including mannose, galactose, and rhamnose. It is important to visualize these complex sugar molecules and the interrelation between their structures. Figure 8.3 shows the general scheme of aldose sugars (in the acyclic form for clarity) from the simplest three-carbon glycerose, two four-carbon aldoses, four tetroses (ribose, arabinose, xylose, and lyose) and eight hexoses (allose, altrose, glucose, mannose, gulose, idose, galctose, and talose). Aldoses can exist in different isomeric forms, namely ketoses, where the carbonyl groups are at the second carbon position rather than the first. For example, glucose can convert to fructose. Isomerization of sugars is typically carried out in the presence of base catalysts at mild temperatures and in different solvents; for example, magnesium–aluminum

240

Catalytic Conversion of Sugars to Fuels O OH OH

Glyceraldehyde (glycerose) O

O OH

HO

OH

OH

OH

OH

Erythrose

Threose O

O

OH

OH

OH

OH

O

OH

Xylose

O

O

O

HO

OH

OH

OH OH

OH

OH

OH OH

OH OH

OH OH

OH OH

Altrose

Glucose

HO

OH

OH

Arabinose

HO

OH

OH

OH

Allose

HO

HO

OH

OH

O

HO

OH

OH

Ribose

O

O

HO

OH

Mannose

HO

OH OH

HO OH OH

Gulose

HO

Idose

HO HO HO

HO OH OH

O

O

O HO

OH

HO

Lyxose

OH OH

Glactose

OH OH

Talose

Figure 8.3 Acyclic forms of the D-series of aldoses [21]. (Adapted from P. Collins and R. Ferrier, Monosaccharides, 1995, with permission from Wiley-Blackwell)

hydrotalcites at temperatures ranging from 310 to 350 K [22]. The conversion of glucose into fructose is widely practiced for production of high-fructose corn syrup. Carbohydrates in solution are present as either open-chain (acyclic) or as ring structures, such as a-furanose, b-furanose, a-pyranose, and b-pyranose in varying proportions [21]. Figure 8.4 shows the isomers of glucose in solution which convert via the process mutarotation. Table 8.2 shows the relative proportions of typical sugars from biomass: xylose, glucose, and fructose in solution at equilibrium. Cyclic forms are clearly favored over the acyclic and pyranoses are favored over furanoses. The mutarotation equilibrium is temperature dependent and the relative percentages are important for reactions such as the conversion of the sugar alcohols by hydrogenation. For example, the different tautomeric forms of fructose have differing adsorption strengths on surfaces of hydrogenation catalysts and also different hydrogenation rates. Hydrogenation occurs selectively with ring forms, but not the acyclic form, while the furanose forms have been found to be more reactive than the pyranose forms [23]. Isomerization of sugars involves the formation of an intermediate enolate species through open-chain forms to transform aldohexoses to ketohexoses (Figure 8.5). The rate of glucose isomerization is thus dictated by the fraction of the glucose molecules that are in the openchain form, which is governed by the solvent used and the reaction temperature. Solid base catalysts used for glucose isomerization include alkali-metal-exchanged zeolite (LiX, NaX, KX, CsX), as well as ion-exchanged resins. The zeolite catalysts have the advantage over

Chemistry of Sugars

α-pyranose

OH

OH

O

O

OH

OH

β-pyranose

OH

OH

HO

241

HO

OH

OH

OH OH OH

O OH

HO

OH OH

OH HO

HO

O OH

OH

O

β-furanose

OH

α-furanose OH OH

OH

Figure 8.4 Isomers of D-glucose in solution

resins (and enzymes) of being able to operate at higher temperatures and glucose concentrations [24]. Recently, Lima et al. [25] reported the use of titanosilicates ETS-10, ETS-4, and AM-4, a sodium yttrium silicate analog of the mineral montregianite, an alkali calcium silicate analogue of the mineral rhodesite, and a calcium silicate analog of the mineral tobermorite, as solid base catalysts for the isomerization of glucose to fructose. These catalysts performed similar or better (20–40% fructose yield in 2 h at 100
C) than NaX and aqueous NaOH [25]. Table 8.2 Percentage compositions of sugars in aqueous solution at equilibrium (31
C) [21]. (Reproducecd from Collins, P. and Ferrier, R., Monosaccharides, 1995. With permission from John Wiley & Sons Ltd) Sugar

Xylose Glucose Fructose

a-Pyranose (%)

b-Pyranose (%)

a-Furanose (%)

b-Furanose (%)

Acyclic carbonyl form (%)

36.5 38 2.5

63 62 65

G1 — 6.5

G1 0.14 25

0.02 0.02 0.8

242

Catalytic Conversion of Sugars to Fuels

Figure 8.5 Reaction scheme for the isomerization of glucose

Sucrose is a sugar typically used in the food industry. Sucrose can be converted to glucose and fructose by hydrolysis. Therefore, sucrose can be used as a carbohydrate feedstock for biofuels. Hydrolysis can be achieved using solid acid catalysts; for example, zeolites under mild conditions (75–95
C, using HY zeolite) [26]. In turn, glucose can be converted into HMF as described above, for use as a platform molecule for biofuel synthesis.

8.3

Hydrogen from Sugars

The formation of hydrogen from sugars is achieved by reforming reactions in either the aqueous phase (APR), in supercritical fluids (supercritical reforming), or at high temperature by gasification. The overall reaction in each of these three cases is the same. The first step in the process is the decomposition of sugars to syn-gas (CO þ H2). The CO in the syn-gas can react further with water to form more hydrogen and CO2 by the water-gas shift reaction. Undesired reactions can lead to lighter alkanes, like methane. 8.3.1

Overall Reaction and Thermodynamics

Davda et al. [27] have reviewed the thermodynamics of carbohydrates reforming. Carbohydrates are thermodynamically more favorable for hydrogen production at lower temperature than alkanes (including methane) are. For example, hydrogen can be produced by the steam reforming of alkanes to form CO and H2 (Equation (8.2)) and the water-gas shift reaction to form CO2 and H2 from CO (Equation (8.3)). Figure 8.6 shows the changes in the standard Gibbs free energy (DG
/RT) associated with Equation (8.2) for a series of alkanes (CH4, C2H6, C3H8, C6H14), normalized per mole of CO produced. Steam reforming of alkanes is only thermodynamically favorable (i.e. negative values of DG
/RT) at temperatures higher than 675 K (and higher than 900 K for methane reforming). Carbohydrates produce hydrogen according to Equation (8.3) and (8.4). Carbohydrates typically have a C:O ratio of 1:1. Relevant oxygenated hydrocarbons having a C:O ratio of 1:1 are methanol (CH3OH), ethylene glycol (C2H4(OH)2), glycerol (C3H5(OH)3), and sorbitol (C6H8(OH)6). Figure 8.6 shows that steam reforming of these oxygenated hydrocarbons to produce CO and H2 is thermodynamically favorable at significantly lower

Hydrogen from Sugars

243

Figure 8.6 DG
/RT versus temperature for production of CO and H2 from vapour-phase reforming of CH4, C2H6, C3H8, and C6H14; CH3(OH), C2H4(OH)2, C3H5(OH)3, and C6H8(OH)6; and water-gas shift. Dotted lines show values of ln(P) for the vapor pressures versus temperature of CH3(OH), C2H4(OH)2, C3H5(OH)3, and C6H8(OH)6 (pressure in atmospheres; 1 atm  101 kPa) [28]. (Reprinted from Applied Catalysis B: Environmental, 56, R.R. Davda, J.W. Shabaker, G.W. Huber, R.D. Cortright, and J.A. Dumesic, A review of catalytic issues and process conditions for renewable hydrogen and alkanes by aqueous-phase reforming of oxygenated hydrocarbons over supported metal catalysts, 171, Copyright (2005), with permission from Elsevier)

temperatures than those required for alkanes. Accordingly, the steam reforming of oxygenated hydrocarbons having a C:O ratio of 1:1 offers a low-temperature route for the formation of CO and H2. Furthermore, the value of DG
/RT for the water-gas shift of CO and H2O to CO2 and H2 is more favorable at lower temperatures. Therefore, by these principles, a single-step catalytic process for reforming of oxygenates to CO and H2 was developed by Dumesic and coworkers, known as APR [27]. Cn H2n þ 2 þ nH2 O ! nCO þ ð2n þ 1ÞH2

ð8:2Þ

CO þ H2 O ! CO2 þ H2

ð8:3Þ

Cn H2y On ! nCO þ yH2

ð8:4Þ

244

8.3.2

Catalytic Conversion of Sugars to Fuels

Reaction Mechanism

APR of biomass-derived oxygenates, such as sugars to hydrogen and carbon dioxide, requires breaking of C–C bonds as well as C–H and/or O–H bonds to form adsorbed species on the catalyst surface, shown in Figure 8.7. Nobel metal catalysts have been typically employed for C–C bond cleavage, including Pt, Pd, and Rh. More recently, new catalysts have been developed that are more cost effective, including Sn–Ni [30]. A general reaction scheme was proposed by Dumesic and coworkers for the reforming of ethylene glycol with Pt/Al2O3 catalyst [31, 32], as shown in Figure 8.7. In this reaction mechanism, ethylene glycol is adsorbed into the catalyst where it first undergoes dehydration followed by C–C bond cleavage and water-gas shift to give CO2 and H2 (pathway III). Undesired reactions can also occur, namely C–O cleavage followed by hydrogenation to produce ethanol, leading to the formation of methane and ethane (pathway II). Methanation and Fischer–Tropsch reactions can produce undesired alkanes (pathway IV). For the production of hydrogen, pathways II and IV need to be minimized by tuning the reaction conditions and catalytic properties. 8.3.3

Aqueous-Phase Reforming

APR is a process in which oxygenate molecules in an aqueous solution can be converted to hydrogen and/or alkanes using a catalyst under moderate temperatures (i.e. 200–250
C) and pressures (10–55 bar (1–5 MPa)). Sugars such as glucose can be directly reformed to hydrogen using APR; however, this occurs with low hydrogen selectivity due to the fact that undesired competing reactions can also occur. These reactions include homogeneous

Figure 8.7 Schematic representation of reaction pathways and selectivity challenges for production of H2 from conversion of ethylene glycol with water. Pathway I is the desired C–C cleavage to form adsorbed CO. Pathway II represents the undesired C–O cleavage followed by hydrogenation to produce ethanol, leading to formation of methane and ethane. Pathway III is the desired water-gas shift reaction. Pathway IV represents the undesired methanation and Fischer–Tropsch reactions to produce alkanes [29]. (Reprinted from Catalysis Today, 111, G.W. Huber and J.A. Dumesic, An overview of aqueous-phase catalytic processes for production of hydrogen and alkanes in a biorefinery, 119, Copyright (2006), with permisison from Elsevier)

Hydrogen from Sugars

245

Table 8.3 Catalysts for APR and conversions Catalyst

Feedstock (wt%)

Pt/Al2O3

Ethylene glycol 10 wt% Pt1Co5/Al2O3 Ethylene glycol 10 wt% 6%Pd/Fe2O3 Ethylene glycol 5 wt% Raney Ni Ethylene glycol 5 wt% Raney Ni14Sn Ethylene glycol (5 wt%)

Conditions

Ref. Conversion Selectivity TOF,a H2 (min1) (%) to H2

483K, 25.4 bar 498K, 29.3 bar 483 K, 25.4 bar 498 K, 29.3 bar 483 K, 19.5 bar 498 K, 25.8 bar 498 K, 25.8 bar

1.4 5.4 3.8 8.4 27.0 41.4 13.7

92.3 87.1 93.9 88.2 95.3 95.7 46.9

1.87 6.72 5.06 10.39 39.1 60.1 1.1

498 K, 25.8 bar

13.2

93.2

1.4

[34] [34] [34] [35] [35]

a

TOF: turnover frequency.

decomposition to form organic acids, aldehydes, and carbonaceous deposits, as well as heterogeneous reaction to form alkanes. These homogeneous decomposition reactions are first order in glucose concentration, whereas the desirable reforming reactions on the catalyst surface are fractional order; therefore, high concentrations of glucose lead to low hydrogen selectivities. Sugars need to be converted to polyols (e.g. glucose to sorbitol) before reforming [33], otherwise large amounts of coke form, because glucose has a low thermal stability. Catalyst development for APR has been undertaken in three primary areas, namely single metal catalysts, bimetallic Pt and Pd catalysts and bimetallic Ni–Sn catalysts. Table 8.3 summarizes the activity and selectivity of different catalysts for APR of ethylene glycol. 8.3.3.1 Single-Metal Catalysts Huber and coworkers [30, 36] studied APR using supported metal catalysts. Over 500 different mono and bi-metallic catalytic materials were trialed using a high-throughput reactor. Ni, Pd, Pt, Ir, Ru, and Rh catalysts were identified as the most promising. Detailed kinetics studies were carried out using APR of ethylene glycol at low temperatures (483 and 498 K) and moderate pressures (22 bar (2.2 MPa)) over silica-supported Ni, Pd, Pt, Ir, Ru, and Rh catalysts. The catalytic activity was found to follow the following order: Pt  Ni H Ru H Rh  Pd H Ir The activity of metallic catalysts could be further improved by changing the support material to TiO2, carbon, or Al2O3, with the highest TOF for production of H2 are Pt on TiO2, carbon, and Al2O3 [31]. Supports must be chosen which are hydrothermally stable. A large number of supports (including SiO2, Al2O3, and silica–alumnia) degrade under these aqueous reaction conditions. Supports which are hydrothermally stable include TiO2, carbon, and ZrO2. Recently, Lehnert and Claus [37] reported APR of glycerol with Pt/Al2O3 catalyst. The reaction selectivity to hydrogen increased with increasing Pt particle size from 78% to 95%, while the conversion of glycerol remained nearly constant at 20%. Also, variation of the

246

Catalytic Conversion of Sugars to Fuels

support material from g-alumina to a mixture of g-, d-, and u-phases led to an increase in hydrogen production. 8.3.3.2 Pt and Pd Bimetallic Catalysts The activity of Pt catalysts can be significantly improved with addition of Ni, Co, or Fe to Pt/Al2O3. For example, PtNi/Al2O3 and PtCo/Al2O3 catalysts at 483 K were 2.1–3.5 times more active than the Pt catalyst per gram of catalyst [36]. While a catalyst consisting of Pd supported on a high surface area Fe2O3 had the highest intrinsic activity of any catalyst tested with values of TOF of H2 equal to 14.6 min1, 39.1 min1 and 60.1 min1 at temperatures of 453 K, 483 K, and 498 K respectively [36]. Metals such as Fe are water-gas shift promoters. Therefore, it is thought that the water-gas shift is the rate-determining step on Pd-based catalysts. Bai et al. [38] reported that Pt catalysts supported on g-Al2O3 modified with Ce or Mg show higher activity than the Pt/g-Al2O3 catalyst, for the APR of ethylene glycol to hydrogen. They concluded that Ce increases the dispersion of Pt on the surface of g-Al2O3 and improves the adsorption-cracking of ethylene glycol on Pt and water-gas shift reaction, whereas the presence of Mg neutralizes the acidity of g-Al2O3, influences the dispersion of PtCl62, and inhibits the dehydration of ethylene glycol. Recently, Liu et al. [39] reported increased reaction rate using a mixed FeCr-oxide support for Pt catalyst for the APR of ethylene glycol to hydrogen, compared with pure Fe2O3-supported Pt catalysts. 8.3.3.3 Ni–Sn Bimetallic Catalysts Huber and coworkers [30, 35] developed an NiSn-based catalyst for APR. Monometallic Ni catalysts are active for APR, but produce undesired methane. The methane reaction can be decreased by addition of tin. Raney NiSn has comparable activity and selectivity to those for Pt/Al2O3 for production of hydrogen from polyols such as ethylene glycol and glycerol. The main advantage is the relative inexpense of the NiSn catalyst. 8.3.4

Supercritical Reactions – Reforming of Sugars

Supercritical reforming of sugars can also produce hydrogen as shown by Equation (8.5): C6 O6 H14 þ 6H2 O ! 6CO2 þ 13H2

ð8:5Þ

Supercritical water conditions occur at conditions above the supercritical point of water (temperatures above 375
C and pressures above 217 atm (22 MPa)). Figure 8.8 shows the sub- and super-critical regions for water and the related hydrothermal conversion processes. Subcritical and supercritical reactions for biofuel production have been recently reviewed by Peterson et al. [40]. At temperatures in the vicinity of 600
C in pressurized vessels, a variety of biomass feedstocks, including sugars, can be gasified using supercritical water. Near-complete conversion can be achieved to the main product gases CO2 and H2. Studies have been conducted with and without catalysts; common catalysts include activated carbon and alkali salts. Homogeneous catalysts, such as alkali salts, have been shown to maximize hydrogen yields from biomass feedstocks. For example, Schmieder et al. [41] and Kruse et al. [42] demonstrated complete gasification to primarily H2 (and CO2) at 600
C and 25 MPa from

Hydrogen from Sugars

247

Figure 8.8 Hydrothermal processing regions referenced to the pressure–temperature phase diagram of water [40]. (From A.A. Peterson et al., Thermochemical biofuel production in hydrothermal media: a review of sub- and supercritical water technologies, Energy and Environmental Science, 2008, 1, 32. Reproduced with permission of the Royal Society of Chemistry)

a range of feedstocks, employing batch and continuous tubular-flow reactors. The addition of potassium as KOH or K2CO3 was found to drastically increase the yield of H2. Modell et al. [43] were the first to report that biomass (wood) could be gasified in supercritical water without the formation of tars and char, but the conversion to gaseous products was low. Later, Modell [44] studied the effect of adding different catalysts (five different Ni/Al2O3 catalysts, one Co/Mo catalyst, and one Pt/Al2O3 catalyst) on the gasification of glucose, cellulose, hexanoic acid, and polyethylene. According to Modell [44], the key for avoiding the formation of tars and char was the rapid introduction of the reactants into the hot pressurized water. In 1995, the Antal group showed that activated carbons and charcoal could completely gasify high concentrations (22 wt%) of glucose into a hydrogen-rich gas at 600
C and 34.5 MPa (340 atm) [45]. Sinag et al. [46] investigated the influence of Raney nickel on the degradation chemistry of glucose in supercritical water at 500
C and 30 MPa (296 atm) in a tumbling autoclave. The yield of both intermediates, phenols and furfurals, was decreased and the gas yield increased by the presence of the catalyst.

248

Catalytic Conversion of Sugars to Fuels

Antal [47] performed thermodynamic calculations for the reforming of glucose at temperatures between 200 and 800
C and at a pressure of 1 atm (101 kPa), as shown in Figure 8.9. The products from the reaction include CO2, CO, H2, and carbon (as tar). At 300
C, the equilibrium products are CO2, CH4, and carbon. As the temperature is increased, the carbon and methane equilibrium decrease, and the CO and H2 equilibrium increase. No carbon is obtained at temperatures above 600
C. Large amounts of both thermal and catalytic coke where formed with steam reforming of glucose at atmospheric pressure. High reaction temperatures, above 600
C, are needed to reform the coke. Overall, supercritical reactions can be used to efficiently gasify glucose (and other biomass components) without coke formation. Antal and coworkers [48] studied the supercritical gasification of glucose without a catalyst as a function of temperature, pressure, and concentration. With increasing reaction temperature, the product gas yield increased. The reaction pressure had little effect on the product gas, while the glucose concentration had a significant effect. Increasing the glucose concentration decreased the yield of gas products.

Figure 8.9 Thermodynamic calculations for reaction of glucose (1 mol) with water (7 mol) as a function of temperature at 1 atm [47]. (From Antal, Michael J., Jr. Synthesis gas production from organic wastes by pyrolysis/steam reforming. Energy from Biomass and Wastes; Symposium Papers; Presented August 14–18, 1978, Washington, D.C. Symposium chairman, Donald L. Klass. Chicago, Illinois, Institute of Gas Technology, 1978, Pp 495–523 in print edition; paper EBW-3-1-28 in digital edition (copyright 2004). Reproduced with permission)

Sugar to Light Alkanes

249

Heterogeneous catalysts have been used in supercritical reforming reactions and have been shown to greatly change the product selectivity [48–51]. Furthermore, Xu et al. [50] showed that activated carbon is an efficient catalyst for supercritical gasification of glucose. Almost 100% of the glucose feed was gasified with a molar gas composition of 22% H2, 34% CO, 21% CO2, 15% CH4, 6% C2H6, and 2% C3H8, at a weight hourly space velocity of around 20 h1 Supercritical reforming is an excellent method to produce product gases from aqueous biomass mixtures. The advantages of supercritical reforming include the high reaction rates, tolerance of impure feedstocks, aqueous feedstocks can be processed with high thermal efficiencies, and the product gas is produced in a single reactor and is available at high pressure. Disadvantages of supercritical reforming include the high capital cost to construct the high-pressure reactor and hydrogen can only be selectively produced at high temperatures, where large amounts of CO are also produced.

8.4 8.4.1

Sugar to Light Alkanes Overall Reaction and Thermodynamics

Aqueous-phase processing can also be used to produce light alkanes, as shown by Dumesic and coworkers [52]. This involves bifunctional catalysts containing both a noble metal (e.g. Pt or Pd) catalyst and acidic sites (e.g. SiO2–Al2O3 or homogeneous acids). The metal sites catalyze reforming, water-gas shift, and hydrogenation reactions. The acid sites catalyze the dehydration reaction. The overall reaction is called aqueous-phase dehydration/hydrogenation (APD/H), and the purpose of it is to remove oxygen from the carbohydrate feed. The chemistry involved with the APD/H of sorbitol (C6O6H14) is shown in Equations (8.6)–(8.8). The net reaction (Equation (8.8)) is exothermic, in which 1 mol of hexane can be produced from approximately 1.5 mol of sorbitol.

19 13

C6 O6 H14 þ 6H2 ! C6 H14 þ 6H2 O

ð8:6Þ

C6 O6 H14 þ 6H2 O ! 6CO2 þ 13H2

ð8:7Þ

C6 O6 H14 ! C6 H14 þ 36 CO2 þ 42 H O 13 13 2

ð8:8Þ

As illustrated in Figure 8.10, the production of alkanes from sorbitol follows a bifunctional reaction scheme. First, sorbitol is dehydrated over acid sites into ring compounds (e.g. isosorbide) or enolic species [53], which migrate to metal sites where they undergo hydrogenation reactions. Hydrogen needed for the hydrogenation can be cofed with the sorbitol or produced in situ on the metal by cleavage of C–C bonds followed by the water-gas shift reaction. Repeated cycling of dehydration and hydrogenation reactions in the presence of H2 leads to heavier alkanes (such as hexane) from sorbitol. The byreactions (i.e. the formation of lighter alkanes, CH4, C2H6, C3H8, C4H10, and C5H12) are also generated by the cleavage of C–C bonds compared with hydrogenation of dehydration reaction intermediates. The selectivities for the production of various alkanes by APR depend on the relative rates of C–C bond cleavage, dehydration, and hydrogenation reactions. These rates can be varied by changing the catalyst composition (metal and acid

250

Catalytic Conversion of Sugars to Fuels

Figure 8.10 Reaction pathways for production of alkanes from sorbitol over catalysts with metal and acidic components [29]. (Reprinted from Catalysis Today, 111, G.W. Huber and J.A. Dumesic, An overview of aqueous-phase catalytic processes for production of hydrogen and alkanes in a biorefinery, 119, Copyright (2006), with permisison from Elsevier)

sites ratio), the acidity and acidic strength distribution of the support, the reaction conditions (e.g. the total pressure, flow rate of hydrogen and/or sorbitol solution, reaction temperature, and sorbitol concentration), and the reactor design [52]. The overall energy balance for alkane production by APD/H is shown in Figure 8.11. The energy content of the liquid alkane products (3900 kJ mol1) represents 90% of the energy content of the carbohydrate and the H2 reactants (4300 kJ mol1). The conversion of glucose and H2 to hexane is an exothermic reaction, which liberates 380 kJ mol1. OH H H HO HO H

O

-380 kJ/mol H2O

H

OH OH

6 O2 -2600 kJ/mol 6 CO 2 6 H2O

+ 7 H2

3.5 O 2 -1700 kJ/mol 7 H2O

Energy

9.5 O 2 -3900 kJ/mol 6 CO2 7 H2O

Figure 8.11 Energy balance for glucose and hydrogen conversion [29]. (Reprinted from Catalysis Today, 111, G.W. Huber and J.A. Dumesic, An overview of aqueous-phase catalytic processes for production of hydrogen and alkanes in a biorefinery, 119, Copyright (2006), with permisison from Elsevier)

Sugar to Light Alkanes

8.4.2

251

Dehydration of Sugars

Dehydration reactions of carbohydrates and carbohydrate-derived molecules comprise an important class of reactions in the field of sugar chemistry. As seen in Figure 8.12, sugars can be dehydrated to form furan compounds such as furfural and HMF that can subsequently be converted into many different fuels and chemicals, including: 1. 2. 3. 4. 5.

diesel fuel additives (by aldol condensation and APD/H) [54]; industrial solvents (e.g. furan, tetrahydrofurfuryl alcohol (THFA), furfuryl alcohol) [55]; various bio-derived polymers (by conversion of HMF into FDCA) [56]; P-series fuel (by subsequent hydrogenolysis of furfural) [57]; and furanic diesel fuel additives [58, 59].

Polysaccharides Starch (Polyglucan) O

Additional Dehydration and Fragmentation Products

O

O

O

O O

O

O

HO

HO O

OH

O

OH

O

HO

O O

OH

Rehydration Products

n

Inulin (polyfructan)

Formic Acid

Levulinic Acid O

O

Acid Hydrolysis H

HO

D-glucose

CHO

CHO OH

-H2O

H CHOH OH HO

H

OH

H

OH

OH

H

OH

+ 2H2O

H H H

OH

CH2OH

H

H

O O

-H2O

OH

O

OH

-H2O

CH2OH

O

Acyclic Intermediates H2 C

CH2OH

O

OH

HO H

D-fructose

H

OH

OH

H

CH2 OH

H2 C -H2 O HO H

H HO OH

HMF

H2 C

O

H

CH

HO -H2O

H

OH

O H

CHO

OH H

Fructofuranosyl Intermediates

Isomerization -2H2O OH O

CH2 OH

O HO

HO O

HO

O

OH

Reversion Products

Soluble Polymers and Insoluble Humins Condensation Products

Figure 8.12 Schematic representation of reaction pathways for acid-catalyzed dehydration of polysaccharides (containing hexose monomer units) to HMF. Structures in brackets correspond to representative species [1]. (From J.N. Chheda, G.W. Huber, and J.A. Dumesic, Liquid-phase catalytic processing of biomass-derived oxygenated hydrocarbons to fuels and chemicals, Angewandte Chemie International Edition, 2007, 46, 7164. Copyright Wiley-VCH Verlag GmbH & Co. KGaA. Adapted with permission)

252

Catalytic Conversion of Sugars to Fuels

Furfural is an industrially useful chemical [60]. However, HMF is not produced in significant volume at present due to the high cost involved, although many researchers have demonstrated promising results for the use of HMF in a wide range of potential applications [61–64]. The selective formation of furfural and HMF from sugars is a key step in the conversion process of biomass to fuels. Table 8.4 shows the different heterogeneous catalysts used for the dehydration of sugars. Dehydration of hexoses has been studied in water, organic solvents, biphasic systems, ionic liquids, and near- or super-critical water, using a variety of catalysts such as mineral and organic acids, organocatalysts, salts, and solid acid catalysts such as ion-exchange resins [71] and zeolites [65] in the temperature range 370–470 K. It can be seen that many heterogeneous catalysts give high conversions and selectivities for saccharides to HMF. Figure 8.12 shows the reaction pathways for acid-catalyzed dehydration of polysaccharides (containing hexose monomer units) to HMF. Monosaccharides such as glucose, formed from the hydrolysis of polysaccharides, undergo dehydration to form HMF via several intermediate structures. Although evidence exists that supports both the open-chain and the cyclic fructofuransyl intermediate pathways (Figure 8.12), it is clear that the reaction intermediates and HMF can degrade by means of various processes to form fragmentation of polymeric products [13, 65, 72, 73]. 8.4.3

Hydrogenation Reactions of Sugars

The hydrogenation of sugars and sugar derivatives is carried out over a series of metal catalysts such as Pd, Pt, Ru, Ni, CoNiB or poly(1-vinyl-2-pyrrolidinone) (PVP)–CoNiB at moderate temperatures from 370 to 420 K and moderate pressures (10–30 bar (1–3 MPa)) by two kinds of reaction. On the one hand, the selective hydrogenation of the C¼C bonds in the furan ring of furfural can be used to produce the tetrahydrofurfural (THF2A) (which can be converted into a diesel fuel component by self-aldol condensation) [54] or methyltetrahydrofuran (2-Me-THF) (a component of P-series fuel) [57]. These reactions can be used to make fuels from sugars. On the other hand, selective hydrogenation of the C¼O bond of furfural or HMF leads to furfuryl alcohol (e.g. for furanic resins, plastics) [74] or 2,5dihydroxymethylfuran (a monomer used in the production of new polymeric materials) [61]. Many parameters, such as solvent, partial pressure of hydrogen, and the nature of the catalyst, influence the hydrogenation reaction. For example, methanol is preferable in the hydrogenation of furfuryl alcohol to THFA over Pd/C because of its higher solubility of hydrogen. Analogously, the presence of methanol can also significantly promote the reaction on the Ru/C catalyst (inactive without solvent) because of stronger adsorption of aliphatic aldehydes/ketones. This phenomenon indicates that the solvent can also affect the hydrogenation by modifying the adsorption–desorption characteristics of furfural on the catalyst [75]. However, for the hydrogenation of furfural to THFA on a Ni-based catalyst, the presence of methanol will react with furfural and lead to the formation of byproducts [75]. For hydrogenation of glucose to sorbitol in a trickle-bed reactor, Ru/C has been found to be better than Raney Ni because of its higher selective (99.3%) and lower leaching (better stability) into the aqueous phase [76]. Likewise, lactic acid can also be converted into propylene glycol with Ru catalysts in the liquid phase [77] or Cu catalysts in the vapor phase [78].

Fructose

—

Sucrose

Inulin

85%,

69%

98

90
C, 18 h 4:6 W: NMP MIBK 90
C 21 h 4:6 W: NMP MIBK 120
C, 6.5 h 5:5 W: DMSO DCM

71%, 20 min 88.6%, 60 min 86%, 60 min 84.1%, 60 min 100%, 30 min 31 38 (6 h)

60

98 99 46.8 52 72 28.8 60 97 (6 h)

100
C, 25 h 150
C, 20 min 100
C, 60 min 100
C, 60 min 80
C, 60 min 100
C, 30 min 160
C, 30 min

92%, 30 min

61%

76

165
C, 60 min

Selectivity

100

Conversion to HMF (%)

Reaction conditions

103.4 TN ¼ 3.5 TN ¼ 4.5 TOF up to 376 TN ¼ 4.6 TOF ¼ 8

141 (formation) 64 (disappearance)

Rate and Ea (kJ mol1)

NMP: N-methylpyrrolidone; MIBK: methyl isobutyl ketone; DMSO: dimethylsulfoxide; DCM: dichloromethane; TN: turnover number; TOF: turnover frequency.

a

Sucrose Fructose Fructose Fructose Fructose Fructose Xylose

15 — — — — — —

HY Dowex 50wx8-100 Titanium phosphate Zirconium phosphate Vanadyl phosphate Niobium phosphate Meso Nb silicate Nb25-MCM-41 Ion-exchange resin (DIAION1 PK216) Ion-exchange resin (DIAION1 PK216) Ion-exchange resin (DIAION1 PK216)

Fructose

10

HMordenite

Saccharide/ poly-saccharide

Si/Al

Catalyst

Table 8.4 Heterogeneous acid catalysts for the dehydration of sugarsa

[73]

[70]

[70]

[24] [24] [66] [66] [67] [68] [69]

[65]

Ref.

Sugar to Light Alkanes 253

254

8.4.4

Catalytic Conversion of Sugars to Fuels

Combined Dehydration/Hydrogenation

In the work of Dumesic and coworkers [52] they demonstrated how APD/H can produce light alkanes from sugar alcohols. The selectivity of methane over a Pt/Al2O3 catalyst decreases from 43% to 6% when the pH of the aqueous sorbitol feed is lowered from 7 to 2 by addition of HCl. Similarly, the selectivity also shifts to heavier alkanes (the H2 selectivity decreases from 43% to 11%) as more solid acid sites are added to a Pt/Al2O3 catalyst by physically mixing Pt/Al2O3 with SiO2/Al2O3. Thus, alkanes are formed by a combination of metal and acidic catalyst components. The alkanes formed were mainly composed of straight-chain compounds with only minor amounts of branched isomers (less than 5%). The catalyst also works well when platinum was loaded directly onto the SiO2/Al2O3 support [52]. The reaction temperature was found to have little effect on the activity of the catalyst; no major difference was observed in the alkane distribution as the temperature is increased from 498 to 538 K. The carbon selectivities for the Pt/ SiO2–Al2O3 catalyst and the physical mixture of Pt/Al2O3 with SiO2–Al2O3 were similar, indicating that the Pt sites do not need to be in close contact with the acid sites. The selectivity for production of hexane increases when H2 is co-fed with the aqueous sorbitol stream, indicating that the increase of the H2 partial pressure in the reactor leads to the rate of hydrogenation compared with C–C bond cleavage on the metal catalyst surface. When H2 was co-fed to the reactor, high-carbon alkane selectivity (up to 91% of carbon in the alkane products) can be realized with the other 9% of the carbon leaving the reactor as CO2. The carbon balance is close to 100%, indicating that negligible amounts of coke were deposited on the catalyst surface. The Pt/ SiO2–Al2O3 catalyst is very stable, with no deactivation observed over 2 weeks’ time on stream.

8.5

Sugars to Oxygenates

Sugars can be converted to oxygenate molecules such as furfural and HMF via dehydration or to polyols such as sorbitol via hydrogenation. These oxygenates can in turn be utilized as platform molecules in a variety of reactions to form fuels and chemicals. Aldose sugars are unstable and can react further to form decomposition products during hydrolysis of polysaccharides; therefore, polyols are a preferred platform due to their relative stability [79]. 8.5.1

Targeted Products and Thermodynamics

8.5.1.1 Dehydration/Hydrogenation As shown in Section 8.1.3, the dehydration of sugars to oxygenates (e.g. HMF) has a relatively neutral change in enthalpy at 5 kcal mol1 for glucose to HMF. Hydrogenation of sugars, such as glucose, forms polyols (sugar alcohols), such as sorbitol. This reaction also has a very low change in enthalpy, being slightly exothermic at 10 kcal mol1. Polyols and oxygenates, such as HMF, are more stable platform molecules compared with sugar solutions and can be stored and converted to fuels when required.

Sugars to Oxygenates

8.5.2

255

Biphasic Dehydration Reactions (HMF and Furfural Production)

The dehydration of sugars to furfural and HMF is typically carried out using a single solvent and acid catalyst. This has been discussed in Section 8.4.2; therefore, this section will focus on the dehydration using a biphasic system. The reactions involved in producing HMF from glucose and fructose are shown in Figure 8.12. C5 and C6 sugars are produced from the hydrolysis of polysaccharide biomass feedstocks. These sugars can isomerize in several forms. The acid dehydration of sugars produces furan-based oxygenates, such as HMF from fructose. HMF can, however, undergo further reactions, such as rehydration and condensation. Fructose can also form fragmentation and other dehydration by-products. Dumesic and coworkers [3, 70, 80, 81] have developed a biphasic system in order to improve the selectivity of HMF formation from fructose. By adding an organic phase to the aqueous acid reaction phase the HMF product is extracted from the reactive aqueous phase avoiding secondary reactions. Modifiers are also added to each layer; for example, the reactive aqueous phase containing the catalyst and the sugar was modified with polar aprotic molecules DMSO or NMP and a hydrophilic polymer PVP, while the water-immiscible organic phase MIBK used during the reaction to extract HMF was modified with 2butanol [80]. The immiscible organic and aqueous layers can be easily separated after reaction for efficient product retrieval. Figure 8.13 shows the schematic for the batch process

Batch Reactor

Organic phase

CH

CH

O

Evaporator

O

HMF(org)

HWF

fructose CH

H H H

O

OH OH

H HO OH

CH CH2

O O

Extractor

O O

HMF(aq)

H

By-products

Aqueous phase

Figure 8.13 Batch process for production of HMF from fructose with simulated countercurrent extraction and evaporation steps. The aqueous phase (white) contains fructose, DMSO, PVP, and the acid catalyst and is represented in the bottom half of the batch reactor. The organic phase (gray) contains MIBK or MIBK:2-butanol and is represented in the top half of the batch reactor [80]. (From Y. Roman-Leshkov, J.N. Chheda, and J.A. Dumesic, Phase modifiers promote efficient production of hydroxymethylfurfural from fructose, Science, 2006, 312, 1933. Reprinted with permission from AAAS)

256

Catalytic Conversion of Sugars to Fuels

for production of HMF from fructose with simulated countercurrent extraction and evaporation steps. Both homogeneous and heterogeneous catalysts have been trialed with this system, including HCl, H2SO4, H3PO4, and ion-exchange resins. Of the catalysts, HCl produced the highest selectivity to HMF. Heterogeneous catalysts are more desirable owing to the relative ease of separation. For example, Roman-Leshkov et al. [80] used a niobium phosphate catalyst at 453 K and obtained promising results of 73% HMF selectivity at 62% conversion. Dumesic and coworkers [70] studied the production of HMF and furfural by dehydration of a range of carbohydrate feedstocks, including fructose, glucose, and xylose, using a biphasic reactor system. 8.5.3

Hydrogenation

Hydrogenation of sugars such as glucose, fructose and mannose forms sugar alcohols (or polyols) by the saturation of the C¼O bond. For example, Figure 8.14 shows the routes of sugar hydrogenation to the polyols sorbitol and mannitol. Hydrogenation can also be used to saturate C¼C and C–O–C bonds. Hydrogenation reactions are carried out in the presence of a metal catalyst such as Pd, Pt, Ni, Ru, or Cu at moderate temperatures (370–420 K) and moderate pressures (10–30 bar (1–3 MPa)) [1, 16, 17, 76, 82, 83]. For example, Gallezot et al. [76] reported the high

D-glucose

D-fructose

CHO H HO

CH2 OH

OH

CHO

O

H

HO

H

OH

H

H

OH

H

CH2OH

D-mannose

H2

H2

H

HO

Figure 8.14

H

OH

H

CH2 OH

H2

H2

OH OH CH2OH

CH2OH HO

H

H

HO

H

H

OH

H

OH

H

OH

H

OH

sorbitol

HO H

OH

CH2OH

H

OH

CH2OH H

HO

CH2OH mannitol

Hydrogenation routes to sorbitol and mannitol

Sugars to Oxygenates

257

conversion (99.3% yield) of glucose to sorbitol over Ru/C catalyst. The solvent used and the hydrogen partial pressure have been shown to play an important role in the selectivity of these metal catalyst [1]. The catalyst support also plays an important role; for example, Pan et al. [84] reported that carbon-nanotube-supported Ru catalysts showed higher activity than alumina- or silica-supported catalyst (62.5% compared with 47.9% and 41.7% conversion respectively). Hydrogenation can be utilized to saturate other oxygenate compounds, such as furfural to form THF2A, which can be converted into diesel fuel [57]. In 2006, Robinson et al. [79] discussed the use of polyols as an alternative sugar platform for the conversion of biomass to fuels. Polyols can be produced directly from biomass by intercepted dilute acid hydrolysis and hydrogenation of the sugars, the so called IDAHH method. Complete conversions have been obtained in 4–6 h with 0.8% H3PO4 and Ru catalysts, and a cost of $0.12–0.16/lb (1 lb  0.45 kg) has been estimated [79]. C5 and C6 polyols, mainly xylitol and sorbitol, are formed from the hemicellulose and cellulose components of biomass respectively. Polyols are stable sugar platform molecules that can in turn be converted to fuels such as hydrogen and hydrocarbons. A method for the formation of alkane fuels from polyols was discussed by Robinson et al. [79] using, first, reduction of the polyols in boiling hydriodic acid (with phosphorous acid) to form liquid hydrocarbons. The hydrocarbons phase separate and the aqueous acid is recycled. Step 2 converts the remaining halocarbons into alkanes. In this process, HI is oxidized to I2 while reducing sorbitol to hydrocarbons. The I2 formed during the reduction is immediately reacted and recycled in situ with the completely dissolved phosphorous acid (H3PO3) or hypophosphorous acid (H3PO2) to regenerate HI. C6–C18 hydrocarbons can be produced which can be utilized in gasoline and kerosene fuels. Figure 8.15 shows the general reaction for the conversion of biomass to sorbitol to alkanes. It should be noted that Virent’s Bioforming process also utilizes polyols from the hydrogenation of sugars as part of the process. The polyols are subsequently used in the APR process (see Section 8.6.1).

CHO H HO

OH H

H

OH

H

OH CH2OH

e–

Polyols IDAHH Hydrolysis

H

OH

OH

OH

Hydrogenation

I

Reduction

HO OH

C6-C18 Hydrocarbons

OH

Glucitol

H3PO3

H3PO4

Halogen Removal

C18H32 + e–

KI

Figure 8.15 Polyols to alkanes process

Heat 0.5h

KOH

I

258

8.5.4

Catalytic Conversion of Sugars to Fuels

Other Oxygenate Fuels from Sugars

The following sections will discuss the conversion of sugars to other types of oxygenate molecules, namely g-valerolactone (GVL), levulinic acid, and furanics. These are relatively recent processes that are currently under development. 8.5.4.1 g-Valerolactone Horvath and coworkers proposed that g-valerolactone (GVL), a naturally occurring compound in fruits, could be used as a biofuel and for the production of chemicals [85]. The dehydration of sugars, under acidic conditions, produces furans, in particular HMF, which can be further dehydrated to form levulinic acid. Hydrogenation of levulinic acid with a catalyst forms GVL. Recently, Mehdi et al. [86] reported the integration of homogeneous and heterogeneous catalytic processes for a multistep conversion process of biomass to oxygenates. They demonstrated the conversion of sucrose to various C5-oxygenates (such as GVL) and alkanes. A scheme for the catalytic conversion of sucrose to oxygenates and fuels that was developed is shown in Figure 8.16, with the catalysts described in the caption. First, the dehydration of sucrose to levulinic and formic acids, via HMF, is carried out in the presence of H2SO4, HCl, or Nafion NR50 in water. Levulinic acid can be hydrogenated to

Figure 8.16 Multistep conversion of sucrose to various C5-oxygenates (including GVL) and alkanes by integrating various homogeneous and heterogeneous catalytic systems. (a) H2SO4/ H2O or Nafion-NR50/H2O, (b) H2/Ru(acac)3/TPPTS/H2O, (c) H2/Ru(acac)3/PBu3/NH4PF6, (d) HCOONa/[(h6-C6Me6) Ru(bpy)(H2O)][SO4], (e) H2/Ru(acac)3/PBu3, and (f) H2/Pt (acac)2/CF3SO3H [86]. (Adapted from H. Mehdi, Integration of homogeneous and heterogeneous catalytic processes for a multi-step conversion of biomass: from sucrose to levulinic acid, g-valerolactone, 1,4-pentanediol, 2-methyl-tetrahydrofuran and alkanes, Topics in Catalysis, 2008, 48, 49. With permission from Springer)

Sugars to Oxygenates

259

GVL by using P(m-C6H4SO3Na)3 modified ruthenium catalyst in water or Ru(acac)3/PBu3/ NH4PF6 catalyst, while the formic acid can be converted to carbon dioxide and hydrogen, the latter which can be used for the hydrogenation of levulinic acid to GVL. GVL can in turn be converted to alkane fuels by further hydrogenation to 1,4-pentanediol followed by dehydration to 2-Me-THF and finally hydrogenation of the 2-Me-THF to alkanes using a Pt(acac)2 catalyst. The combustion of the alkanes as transportation fuels, for example, produces CO2 and water, which in turn is recaptured by plants. GVL has many desirable properties, including good stability, easily and safely stored, more globally in large quantities, and has a low melting point (31
C) and a high boiling point (207
C). GVL was tested as a fuel additive to gasoline [86]. Using a mixture of 10% v/v GVL 90% v/v 95-octane gasoline, GVL showed very similar properties to ethanol used as an additive at the same level. 8.5.4.2 Levulinic Acid Levulinic acid is the product formed from the acid-catalyzed dehydration of sugars or cellulose, with formic acid and water as co-products. For example, levulinic acid can be formed from glucose and fructose via the acid dehydration of HMF, as shown in Figure 8.17 [87]. Levulinic acid provides a useful platform to produce fuel additives. Namely, levulinic esters and 2-Me-THF, which can be used as oxygenated diesel and gasoline fuel additives, respectively, can be produced by esterification and hydrogenation of levulinic acid (Figure 8.18). Further fuel additives, such as 2-Me-THF, can be produced by a dehydration/hydrogenation pathway of levulinic acid. Leo Manzer of Dupont has estimated that levulinic esters could be produced on a large scale at less than $0.50/L [89].

Figure 8.17 Mechanism for formation of levulinic acid from HMF [87]. (Reprinted from Tetrahedron Letters, 26, J. Hovart, B. Klaic, B. Metelko, and V. S´unji
c, Mechanism of levulinic acid formation, 2111, Copyright (1985), with permission from Elsevier)

260

Catalytic Conversion of Sugars to Fuels

Figure 8.18 Pathways for production of fuels from levulinic acid [88]. (Reprinted with permission from G.W. Huber, S. Iborra, and A. Corma, Synthesis of transportation fuels from biomass: chemistry, catalysts and engineering, Chemical Reviews, 2006, 106, 4044. Copyright 2006 American Chemical Society)

Angelica lactone is the dehydration product of levulinic acid and is reversible when water is added. Hydrogenation of angelica lactone forms GVL and then 1,4-pentanediol using PdRe/carbon catalysts at 200–250
C and 100 atm H2. 1,4-Pentanediol can further be converted to 2-Me-THF by dehydration (Figure 8.18). In addition, angelica lactone can also form levulinic esters by reaction with an alcohol in the presence of acid or base catalysts [90]. It has also been shown that, levulinic esters can be produced by reaction of angelica lactone with olefins using homogeneous or solid acid catalysts [91]. 8.5.4.3 Furanics Avantium Technologies BV, in the Netherlands, has developed a further process for the conversion of sugars to a next-generation biofuel, so-called “furanics” [92, 93]. The “furanics” oxygenate molecules consist of furan derivatives, namely esters and ethers of HMF, as shown in Figure 8.19. HMF is derived from sugars (hexoses, such as glucose and fructose) typically using acid dehydration, as shown above. The furanics process converts the sugars to esters and ethers using a combination of the organic acid (or alcohol respectively) and an acid catalyst (e.g. H2SO4). The furanics have been successfully blended with regular diesel fuel with significant reduction in soot and sulfur emissions in the exhaust [58]. Further, furanics, such as ethoxymethylfurfural (EMF), have been shown to have a similar energy content to regular fuels, such as gasoline (8.7 kWh/L compared with 8.8 kWh/L respectively) [59]. Furanics can also be used for the production of renewable polymers and other chemicals.

Sugars to Larger Alkanes

261

OH OH OH

O

O

H H H OH

OH

H

HO

OH H

OH

H

H

OH

HO

Hexoses +

H

H O

–3 H2O

O

HO

H+

O

OH

+ 2H 2O

O

5-Hydroxymethylfurfural (HMF) ROH, Catalyst

Levulinic acid

+ HCOOH Formic acid

RCOOH, Catalyst O

R

O O

R

Ethers

O

O

Esters

Figure 8.19 Two families of furan derivatives (furanics) formed using the Avantium Technologies process

8.6 8.6.1

Sugars to Larger Alkanes Overall Reaction and Chemistry

The APD/H process (see Section 8.4) can be used to produce directly alkanes form sugar alcohols; however, the limitation of the carbon number of the sugar (typically five or six carbon atoms) makes alkane products which are not directly useable for fuel applications owing to their high volatility. In order to produce higher boiling point fuels, especially the kerosene and diesel type, it is still desirable to find some new process for the production of longer chain alkanes from biomass feedstocks. As a further development to their initial APD/H process, Dumesic and coworkers [54] described another process which can produce liquid alkanes, ranging from C7 to C15, by the combination of aldol condensation and APD/H processing of biomass-derived carbohydrates. The liquid alkane products ranging from C5 to C9 can complement the development of P-series fuel by substituting the pentane-plus components of this fuel [57], and the oxygenated form of saturated molecules or heavier liquid alkanes (C13–C15) can serve as diesel-fuel additives. As shown in Figure 8.20, the production of heavier liquid-phase alkanes from carbohydrates is a multistep process. The first step is the acid hydrolysis of polysaccharides, such as cellulose, hemicellulose, and starch, to make monosaccharides, such as glucose, fructose, and xylose. Then, these monosaccharides can be further acid-catalytically dehydrated to form carbonyl-containing furan compounds such as HMF and furfural (as outlined in Section 8.5.2). These carbonyl-containing compounds undergo a base catalytic aldol condensation reaction to produce larger organic molecules (HC6) by C–C bond formation. The reaction is typically carried out in polar solvents such as water or water–methanol in the

O

O

H

OH H

HO

OH

D-Fructose

(β-pyranose)

n

Dehydration (acid)

3H2O OH

HMF

O

O

OH O

Aldol crossedcondensation (base)

H2O

Aldol selfcondensation (base)

HMTHFA

2H2 O O

O

HMTHFA

Selective Hydrogenation (metal)

OH O

O

H2 O

HMF

O

OH

O

O

O

OH

OH

OH

Hydrogenation (metal)

4H2

OH

Hydrogenation (metal)

H2

Hydrogenation (metal)

7H 2

Aldol crossedcondensation (base)

O

OH

O

OH

OH O

OH

O

OH

OH O

O

OH

6H2O

3 H2 O

Dehydration/ Hydrogenation (metal-acid)

C 15-alkane

C 9-alkane

C 12-alkane

5H2O

Dehydration/ Hydrogenation (metal-acid)

4H2

Dehydration/ Hydrogenation (metal-acid)

8H2

OH 7H2

OH

Figure 8.20 Reaction pathways for conversion of polysaccharides into liquid alkanes. Analogous chemistry can be depicted for conversion of C5 polysaccharides to C10, C8, and C13 alkanes via furfural as reaction intermediate [1] (From J.N. Chheda, G.W. Huber, and J.A. Dumesic, Liquid-phase catalytic processing of biomass-derived oxygenated hydrocarbons to fuels and chemicals, Angewandte Chemie International Edition, 2007, 46, 7164. Copyright Wiley-VCH Verlag GmbH & Co. KGaA. Adapted with permission)

H

OH CH2 HO OH HO OH OH H

H

H

D-Glucose

β-pyranose

H

H OH

HO HO

O

O

Hydrolysis (acid)

Inulin (polyfructan)

O

O

(Polyglucan)

Starch

Biomass-derived Carbohydrates

262 Catalytic Conversion of Sugars to Fuels

Sugars to Larger Alkanes

263

presence of either a homogeneous base (e.g. NaOH) or solid base catalysts, such as mixed Mg–Al oxides or MgO–ZrO2 at low temperatures [94]. As shown in Figure 8.20, acetone can form an intermediate carbanion species and react with one HMF to form a C9 species or two HMF molecules to form a C15 species. Subsequently, these molecules are then converted into liquid alkanes (C7–C15) by hydrogenation (using, for example, a Pd catalyst) followed by APD/H over a bifunctional catalyst (Pt/SiO2–Al2O3) in a four-phase flow reactor. The H2 and acetone needed in this process can be produced by APR and fermentation of sugars respectively. On the other hand, the acetone itself can also undergo retro-aldol condensation to form smaller carbonyl-containing compounds, such as dihydroxyacetone and glyceraldehyde, which can be cross-condensed with furfural and HMF. Another possible route proposed by Dumesic et al. [1] for the production of liquid alkanes is to convert HMF and furfural into 5-hydroxymethyltetrahydrofurfural (HMTHFA) and THF2A respectively by any of the following reactions: 1. selective hydrogenation of the C¼C bonds in the furan ring; 2. complete hydrogenation of these compounds, followed by preferential dehydrogenation of the primary –C–OH group to form an aldehyde; or 3. complete hydrogenation followed by selective oxidation of the primary –C–OH group upon reaction with O2 to form an aldehyde. HMTHFA and THF2A can also be self-condensed to form C12 and C10 species respectively. Overall, the essential concept of conversion of carbohydrates into liquid alkane fuel molecules is changing the functionality of the sugars through a series of continuous selective reactions, including dehydration, hydrogenation/dehydrogenation, and oxidation, followed by increasing the carbon number through aldol condensation (with acetone or self-condensation). The distribution of liquid alkanes from C7 to C15 can be controlled using the molar ratio of reactants such as HMF and acetone [54]. Recently, Dumesic and coworkers [95] have outlined another strategy for production of a range of alkane and aromatic fuels from sugar or polyol feedstocks (Figure 8.21). The alternative process does not require the separate formation of HMF because the ketones produced can undergo self-coupling reactions. As the first step, sugars and polyols were converted over a Pt–Re catalyst to form primarily hydrophobic alcohols, ketones, carboxylic acids, and heterocyclic compounds. For example, sorbitol and glucose can be converted over a carbon-supported Pt–Re catalyst at temperatures near 500 K to a well-defined mixture of hydrophobic organic liquid containing alcohols, ketones, carboxylic acids, and alkanes containing four, five, or six carbon atoms, as well as heterocyclic tetrahydrofuran and tetrahydropyran compounds. During this step, more than 80% of the oxygen contained in the carbohydrate was removed, allowing subsequent upgrading processes to operate at reduced capacity and with increased efficiency. Hydrogen required to partially deoxygenate the remainder of the feed to monofunctional hydrocarbons can be supplied by the reforming reaction of polyol or sugar feed over the Pt–Re/C catalyst. Endothermic reforming reactions are coupled with exothermic deoxygenation reactions in the same reactor. In this way, the overall conversion is mildly exothermic and in excess of 90% of the energy content of the polyol or sugar feed is retained in the reaction products. The monofunctional hydrocarbons as prepared can undergo further conversion to alkanes. Moreover, Dumesic and coworkers [95] have demonstrated additional catalytic processes to convert the carbohydrate-derived organic liquid stream to liquid alkanes,

264

Catalytic Conversion of Sugars to Fuels

Figure 8.21 Schematic representation of reactor sequence used to generate monofunctional organic compounds from catalytic processing of sorbitol or glucose, providing a platform for the production of liquid transport fuels [95]. (From E.L. Kunkes, et al., Catalytic conversion of biomass to monofunctional hydrocarbons and targeted liquid-fuel classes, Science, 2008, 322, 417. Reprinted with permission from AAAS)

olefins, and/or aromatics with molecular weights and structures appropriate for use as transportation fuels. During these processes, some high-octane components in the gasoline range (e.g. highly branched alkanes and olefins, as well as alkylated aromatics) can be produced. For example, the organic liquid from sorbitol can be converted to aromatic compounds by first hydrogenating the ketone to an alcohol, followed by being aromatized over H-ZSM-5 at 433 K. The branched C4 to C6 compounds can be produced by the dehydration of secondary pentanols and hexanols over niobium oxide catalyst and also by oligomerization of these olefins combined with a cracking reaction over H-ZSM-5 to form a distribution of branched olefins centered at C12. C8 to C12 hydrocarbons containing primarily a single carbon branch were achieved by C–C coupling of C4 to C6 ketones and secondary alcohols by aldol condensation over a bifunctional CuMg10Al7Ox catalyst or successive ketonization reaction and aldol condensation of carboxylic acid over CeZrOx and Pd/CeZrOx, and then hydrodeoxygenation over Pt/NbOPO4 catalyst. A similar technology platform called BioForming was developed by Virent Energy Systems Inc., as shown in Figure 8.22 [2]. Using proprietary catalysts and operating at moderate temperatures (450–575 K) and pressures (10–90 bar, 1–9 MPa), the process converts water-soluble carbohydrate-derived compounds (e.g. polysaccharides, monosaccharides, polyhydric alcohols, mono-alcohols) into a combination of water, hydrogen, gaseous fuels, and liquid hydrocarbons. The water, fuel gases, and any excess hydrogen are easily separated from the liquid hydrocarbons in a simple three-phase separator, and can be recycled or collected for use in other applications. The key feature of this BioForming

Sugars to Larger Alkanes

265

Figure 8.22 Virent’s BioForming process to produce conventional liqud transport fuels from biomass feedstocks. APR enables the process to partially defunctionalize carbohydrate feedstocks for further catalytic upgrading [2]. (Reproduced from P.G. Blommel and R.D. Cortright, Production of conventional liquid fuels from sugars, Virent Energy Systems, Inc., Madison, WI, 2008, Online Whitepaper. Reproduced with permission from Virent Energy Systems, Inc.)

process is the in situ use of the generated hydrogen. Depending on the process configuration, hydrocarbon mixtures can be produced with characteristics and properties that are virtually identical to gasoline, jet fuel, diesel fuel, and other chemicals. C2–C4 hydrocarbons can also be produced. Stoichiometric analysis shows that the product hydrocarbons capture 64% of the carbon from the carbohydrates and more than 94% of the sugar’s lower heating value. The biogasoline has a higher energy content than ethanol or butanol and delivers better fuel efficiency [2]. In the BioForming process, the feedstocks are aqueous solutions of carbohydrate fractions (e.g. sugars, sugar alcohols, saccharides, and polyhydric alcohols) which have been extracted from biomass resources and pretreated. These carbohydrates then undergo hydrogenolysis and/or hydrogenation to produce oxygenates or polyols respectively. The oxygenates and polyols form the platform molecules for further processing. APR is then used to form hydrogen, alkanes, and further oxygenates (polysaccharides, C5 and C6 sugars, furans, phenolics, and acids). The hydrogen from the APR process is utilized in the various other processes, including hydrogenation, hydrogenolysis, and satuation. The products of APR can react with either an acid catalyst (e.g. ZSM-5) to form aromatics and alkanes, a base catalyst for condensation followed by hydrodeoxygenation (HDO) to form alkanes, or undergo dehydration, oligomerizationa, and saturation to form the different hydrocarbon fractions required for gasoline, kerosene, or diesel fuels. Finally, lignin from lignocellulosic feedstocks can be burned for process heat.

266

8.6.2

Catalytic Conversion of Sugars to Fuels

C–C Bond Formation

In order to increase the carbon chain length of the desired fuel molecules for higher boiling point fuels, C–C bond forming reactions are required. 8.6.2.1 Aldol Condensation Formation of larger alkanes (HC6) from carbohydrates requires C–C bond formation reactions. Aldol condensation is an important process to form large organic molecules using carbohydrate-derived carbonyl compounds in the presence of a base or acid catalyst. In this reaction, various carbohydrate-derived carbonyl compounds, such as furfural, HMF, dihydroxyacetone, acetone, and THF2A, can be condensed in aqueous and organic solvents to form larger molecules (C7–C15) that can subsequently be converted into components of diesel fuel [96]. During the aldol condensation reaction, the base catalyst abstracts the a-hydrogen from the carbonyl compound to form an intermediate carbanion (enolate ion) species. These intermediate carbanion (enolate ion) species can then attack the carbon atom of a carbonyl group from another molecule to form a C–C bond. The aldol adduct can further undergo dehydration to form an unsaturated aldehyde or ketone. Factors such as reaction temperature, solvent, reactant molar ratio, structure of reactant molecules, and the nature of the catalyst determine the selectivity of the process towards heavier compounds. In initial studies, aldol condensation reactions were carried out over an Mg/Al mixed-oxide catalyst derived from hydrotalcite synthesis followed by a hydrogenation step in a batch reactor over a Pd/Al2O3 catalyst. However, owing to the irreversible structural changes, the mixed Mg/Al oxide catalyst lost almost 70% of its activity upon subsequent recycling [94]. In subsequent studies, a stable magnesia–zirconia (MgO–ZrO2) support and a bifunctional metal base (Pd/MgO–ZrO2) catalyst were developed for the aldol condensation and subsequent hydrogenation in a singlereactor [3]. 8.6.2.2 Other C–C Bond-Forming Reactions Alkylation with Various Agents. Alkylation can also be used to form carbon–carbon bonds. Alkylation is the process where an alkyl group is transferred from one molecule to another. The alkyl group may be transferred typically as an alkyl carbocation, a free radical, a carbanion, or a carbine. Some examples of alkaylation are shown in Table 8.5. These alkaylation reactions can form alkyl furans which can potentially be added into gasoline as octane additives. Acidic catalysts are typically used for alkylation including metal chlorides [99, 108], BF3 [103–105], inorganic acid (such as H3PO4, H3PO4–kieselguhr [98, 101–103], and Amberlyst 15 [97, 110]) were also developed. Shuikin et al. [101, 102] studied the alkylation of furan by isobutene over H3PO4–kieselguhr in a rotating autoclave using an excess of furan. A mixture of 2- (I) and 3-tert-butylfurans (II) is formed, the proportion of which depends on the reaction conditions. With rising temperature, the ratio of I to II increases. Increasing the amount of catalyst also decreased the ratio of II to III (2,5-di-tertbutylfuran). Hþ cation exchangers have also been used, whose acid strength also works for the production of alkylation products in heterocyclic compounds. Iovel and Lukevics [110] investigated the reaction of furan with tert-butanol in the presence of the cation exchanger Amberlyst 15. It was found that when the reaction was carried out in an excess of furan

Sugars to Larger Alkanes

267

Table 8.5 Examples of alkylation reactions and catalysts Reactant

Catalyst

OH +

O

R +

O

+

O

Temperature

Time, yield

Ref.

Amberlyst 15

Room temperature 24 h, 75%

[97]

H3PO4/supports

100
C

3 h, 78%

[98]

Fe2O3 and FeCl3

23%

[99]

Mo(CO)6 and carbonyl 130
C (unsaturated hydrocarbon) molybdenums

24h

[100]

Cl

in CH2Cl2 Cl

+

O

O H3PO4–kieselguhr

+

+

O

Kieselguhr

75–150
C

50–150
C

[101]

1–7h

[102]

19%

[103]

in H3PO4

+

O BF3 etherate and

+

O BF3 etherate and

tetrahydropyran

BF3 etherate and tetrahydropyran

[105]

O

BF3 etherate

[106]

O

BF3Et2O

11–34.8
C

ZnCl2 or MgCl2

100–300
C

+

+

+

O

R +

[104]

tetrahydropyran

O

0.22–2h

[107]

[108, 109]

268

Catalytic Conversion of Sugars to Fuels

compound, 2-tert-butylfuran was obtained with a yield of 80% (according to gas–liquid chromatography) calculated on the tert-butanol. Guerbet Reactions. The Guerbet reaction is another form of C–C bond formation reaction. This involves condensation between alcohols promoted by bifunctional catalysts that contain a basic component and a metal species. This reaction is characterized by the following three steps (see below). Equation (8.9): dehydrogenation of alcohols to the corresponding aldehydes; Equation (8.10): aldol condensation of the resulting aldehydes; and Equation (8.11): hydrogenation of the unsaturated condensation products to give the higher alcohols. Ueda et al. [111] investigated the condensation of various primary alcohols (C2–C5) with methanol over different metal oxide solid-base catalysts. MgO was found to be the most active and also selective (selectivity H80%) for the reaction. Carlini et al. [112] also studied the synthesis of isobutyl alcohol (a gasoline additive) over a series of metals (Pd, Rh, Ni, or Cu) and a basic Mg–Al mixed oxide. Only the copper-based system showed appreciable performance. In particular, the Cu/Mg/Al mixed oxides prepared by a coprecipitation method offered the best results in terms of activity (79.3%) and selectivity (79.3%). Recently, plant-derived ethanol was also effectively converted to n-butanol [113] and biogasoline [114] in a one-step process over a highly active nonstoichiometric hydroxyapatite (Ca10(PO4)6(OH)2) catalyst. The biogasoline as prepared comprised chiefly of hydrocarbons from C6 to C10 as well as oxygenates and has an octane number of up to 99. This method offers another feasible route for the production of liquid fuels using alcohols such as ethanol which can be formed by the fermentation of cellulose, starch, and sugars. The Guerbet reaction may also be applied to the conversion of other biofuel intermediates containing alcohol groups.

(8.9)

(8.10)

(8.11) 8.6.3

Hydrogenation/Dehydration

The final step in the conversion of larger oxygenates from aldol condensation (or other processes) to alkanes is dehydration/hydrogenation [42]. The remaining oxygen in the molecules is removed as water and hydrogen saturates the molecules. In the initial work on hydrogenated aldol adducts over a Pt/SiO2–Al2O3 catalyst, extensive amounts of coke formed on the catalyst surface (20–50% of the reactant converts to coke) during the APH/D reaction [54]. As a solution, a special four-phase reactor system consisting of (i) an aqueous inlet stream, which contains the large water-soluble organic

Sugar Conversion to Aromatics

269

reactant, (ii) a hexadecane alkane inlet stream; (iii) an H2 inlet gas stream, and (iv) a solid catalyst (Pt/SiO2–Al2O3) was developed in which the hexadecane alkane stream removes hydrophobic reaction product from the catalyst before it goes on further to form coke. In the recent work of Dumesic and coworkers [115], NbPO5 as a new acidic support for the Pt catalyst was used for hydrogenation. This catalyst did not require the special four-phase reactor and no coke formed on the catalyst surface. The high reactivity of Pt/NbPO5 eliminated the need for the organic sweep stream, such as hexadecane used previously, and allowed for operation at higher weight hourly space velocities than previously reported.

8.7

Sugar Conversion to Aromatics

Aromatics, such as toluene, comprise a significant fraction of gasoline, kerosene, and diesel fuels. Processes to convert biomass-derived feedstocks, such as sugars, to aromatics are required in order to produce renewable surrogates of these fuels. Biomass typically undergoes liquefaction to form bio-oil. The bio-oil can then be further upgraded to aromatic molecules using catalysts such as ZSM-5. However, carbohydrates can also be directly converted to aromatics using catalytic pyrolysis [116–118]. Bio-oil conversion with catalysts is described in Chapter 6 and, therefore, will not be described here. 8.7.1

Overall Reaction and Thermodynamics

Figure 8.23 shows the general mechanism for the conversion of carbohydrates to aromatics in catalytic pyrolysis [118]. This mechanism first involves pyrolysis of solid biomass

Figure 8.23 Reaction chemistry for the catalytic fast pyrolysis of cellulose on solid acid catalyst. (Reproduced from Ref. [118]. With kind permission from Springer ScienceþBusiness Media: Topics in Catalysis, Aromatic Production from Catalytic Fast Pyrolysis of Biomass-Derived Feedstocks, 52, 2009, 241, Carlson, T.R., Tompsett, G.A., Conner, W.C. and Huber, G.W.)

270

Catalytic Conversion of Sugars to Fuels

(e.g. cellulose, sugars) into volatile organics, gases, and solid coke. The volatile organics undergo dehydration reactions to produce water and the dehydrated species. These reactions can occur in either the heterogeneous catalyst or in the homogeneous gas phase. These dehydrated species then enter into the zeolite catalyst where they are converted into aromatics, carbon monoxide, carbon dioxide, water, and coke. Inside the zeolite catalyst, the volatile species undergo a series of reactions, including dehydration, decarbonylation, decarboxylation, isomerization, oligomerization, and dehydrogenation, leading to aromatics, CO, CO2, and water. The challenge with selectively producing aromatics is minimizing the undesired coke formation. Coke formation comes from homogeneous gas -phase thermal decomposition reactions and from heterogeneous reactions on the catalyst. The coke can form from the biomass feedstock, the volatile oxygenates, the dehydrated species, or the aromatics. The overall reaction for aromatic formation from glucose can be given as follows: C6 O6 H12 ! 12 C H ð64 % carbon yieldÞ þ 48 CO ð36 % carbon yieldÞ þ 84 H O 22 7 8 22 22 2

ð8:12Þ

Equation (8.12) involves transformation of glucose to toluene, CO, and H2O. The maximum theoretical molar carbon yield of toluene from glucose is 64% when CO and H2O are produced as by-products. The heat of reaction for the conversion of glucose to toluene (Equation (8.12)) was estimated to be 18 kcal mol1, indicating that this reaction is exothermic. 8.7.2

Catalytic Fast Pyrolysis

Fast pyrolysis involves rapidly heating biomass (H500
C s1) to intermediate temperatures (400–600
C) followed by rapid cooling (vapor residence times 1–2 s) [119]. The importance of pyrolysis heating rate is well known [120, 121]. One of the main advantages of fast pyrolysis is that liquid fuels, called bio-oils or pyrolysis oils, are directly produced from solid biomass. However, the bio-oils are of poor quality and they are thermally unstable, degrading with time, acidic, have a low heating value, and are not compatible with existing petroleum-derived oils [122]. As previously shown, the introduction of zeolite catalysts into the pyrolysis process can convert oxygenated compounds generated from pyrolysis into aromatics [118]. The first work reported on the conversion of biomass feedstocks over zeolite catalysts was by researchers at Mobil [123], who showed that ZSM-5 could be used to convert biomass feedstocks such as latex and seed oils to hydrocarbons. A high degree of conversion (H74 wt%) of these biomass feedstocks over ZSM-5 to form hydrocarbons (predominately gasoline and liquid-petroleum-gas range molecules) was achieved in hydrogen flow. They also showed that aqueous glucose feedstocks can also be converted to aromatics. Since this early report, there have been an increasing number of publications using zeolite catalysts, predominately ZSM-5, to upgrade biomass and carbohydrate feedstocks. For example, Dao and coworkers [124–128] carried out several studies on aqueous fructose and glucose feeds with ZSM-5 catalysts and metal-doped ZSM-5 catalysts (ZnZSM-5 and MnZSM-5) in a fixed-bed reactor at 350–500
C. They found that increased yields of aromatics were realized using ZnZSM-5 and MnZSM-5 compared with undoped ZSM-5 catalysts with fructose and glucose feeds. Many other types of catalyst have been investigated for the catalytic pyrolysis of biomass and derivatives to aromatics, including metal-exchanged

Conclusions and Summary

271

zeolites [129–131], catalytic cracking catalysts [132], aluminas [129–131, 133–135], and mesoporous materials [133–135]. Catalytic pyrolysis of biomass to biofuels has been recently reviewed by Carlson et al. [118]. We [116, 118] have reported the catalytic fast pyrolysis (CFP) of biomass model compounds, including glucose, cellulose, cellobiose, and xylitol, to aromatics. Several parameters were found to be important in CFP; namely, the heating rate, the reaction temperature, the catalyst type, and the catalyst-to-reactant ratio. For example, for optimum glucose to aromatic conversion, heating rates of H1000
C s1, to 600
C reaction temperature, ZSM-5 catalyst and catalyst-to-reactant of H19 was determined [118]. The catalyst that had the highest aromatic yield was ZSM-5. When no catalyst is used the primary product is coke. The catalytic parameters that have an effect on the product distribution are pore structure and the types of acid site. Silicalite and ZSM-5 have the same pore structure, but a different number of acid sites. ZSM-5 contains Brønsted acid sites, while silicalite does not. Silica–alumina contains Brønsted acid sites, but is an amorphous material with no pore structure. Silicalite produces primarily coke, indicating that Brønsted acid sites are needed for aromatic production. Silica–alumina also produces mainly coke, indicating that the pore structure of the zeolite is also needed to produce aromatics selectively. The carbon yields for CFP of different feedstocks, including xylitol, glucose, cellobiose, and cellulose, with catalyst ZSM-5 at 600
C was measured by Carlson et al. [118]. The major products included aromatics, CO, CO2, and coke. No olefins were detected during CFP in their reactor system. Olefins have, however, have been observed when glycerol and sugars were passed over ZSM-5 catalysts in previous studies [136, 137]. The aromatic yields of these reactions are about half the theoretical yield given by Equation (8.12). The yield of coke is over 30% for all catalysts used. 8.7.3

Aromatics from Sugar Fragments in the Aqueous Phase

Aromatics and other gasoline-range molecules can also be produced from the aqueousphase pathway, via acid condensation of sugar fragments such as alcohols, ketones, aldehydes, and carboxylic acids. This is based on the methanol-to-gasoline and methanol-to-olefins processes. Solid acid catalysts, such as ZSM-5, SAPO-34, and solid phosphoric acid, have been used for these processes [138–142]. In the case of the ZSM-5 catalyst, a series of reactions takes place, including dehydration of oxygenates to alkenes, oligomerization of the alkenes, catalytic cracking, cyclization and dehydration of larger alkenes to form aromatics, alkane isomerization, and hydrogen transfer [142–145]. Dumesic and coworkers and Virent Energy Systems Inc. have demonstrated the integration of this acid condensation process coupled with APR to produce hydrocarbons for gasoline fuels [1, 2, 95, 115].

8.8

Conclusions and Summary

Currently, carbohydrates are converted to fuels primarily by fermentation reactions. However, as reviewed in this chapter, new catalytic technologies are being developed that will allow us to convert carbohydrates into a range of alkanes and aromatics. These alkanes and aromatics are the same compounds that are used to make diesel fuel, jet fuel, and

272

Catalytic Conversion of Sugars to Fuels

gasoline. In effect, these catalytic technologies will allow us to convert carbohydrates into the same compounds that are produced from petroleum oil. There are several advantages of these catalytic technologies compared with fermentation reactions. Products can be made which easily separate from the aqueous phase. These catalytic technologies have shorter residence times (30–60 min) than fermentation reactions (1–3 days). The catalysts are in a separate phase (i.e. solids) than the reactants and products and, therefore, can be easily recycled. These are also the catalytic materials that are used today to make the vast majority of liquid fuels and chemicals in the petroleum and chemical industry. It is likely that the future of carbohydrate conversion will use the types of catalytic process discussed in this chapter. There are, however, several challenges with the carbohydrate chemistry discussed here. The majority of these reactions are just beginning to be studied. Some of these processes have multiple steps. For them to become industrial processes requires a high yield for each step in the process. The fundamental reactions involved in the conversion of sugars to fuels includes dehydration, isomerization, hydrogenolysis, aldol condensation, C–C bond forming, C–C bond cleavage, water-gas shift, oligomerization, reforming, hydrogenation, and pyrolysis. These key reaction pathways can be combined using multifunctional catalysts to produce an even wider range of products from carbohydrate-based feedstocks. Clearly, more advances need to continue to be made in the field of catalytic carbohydrate conversion. However, a wide variety of tools are available to quickly advance this field. Modern chemical and spectroscopic tools combined with advances in developing new catalysts make this an exciting time to study carbohydrate conversion.

Acknowledgements We would like to thank the National Science Foundation (Grant # 747996) and John and Elizabeth Armstrong for the generous funding.

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9 Hybrid Processing DongWon Choi,1 Alan A. DiSpirito,2 David C. Chipman3,4 and Robert C. Brown3,4 1

Department of Biological and Environmental Sciences, Texas A&M University – Commerce, Commerce, TX 75429, USA 2 Department of Biochemistry, Biophysics and Molecular Biology, Iowa State University, Ames, IA 50010, USA 3 Center for Sustainable Environmental Technologies, Iowa State University, Ames, IA 50010, USA 4 Department of Mechanical Engineering, Iowa State University, Ames, IA 50010, USA

9.1 9.1.1

Introduction Biorefineries

The Biomass Research and Development Technical Advisory Committee [1, 2] of the US Department of Energy and the US Department of Agriculture defines a biorefinery as “a processing and conversion facility that efficiently separates its biomass into individual components and converts these components into marketplace products, including biofuel, biopower, and conventional and new bioproducts.” The underlying assumption in this conventional definition is that agricultural crops, especially grains, are fractionated into starch and/or free fatty acids. Lignocellulosic by-product materials are fractionated into cellulose, hemicellulose, and lignin before the components are converted into final market products. This approach shares a similar, if not identical, conceptual basis with the technologies utilized in conventional wet corn milling and wood pulp and paper milling processes [1–4].

Thermochemical Processing of Biomass: Conversion into Fuels, Chemicals and Power, First Edition . Edited by Robert C. Brown © 2011 John Wiley & Sons, Ltd. Published 2011 by John Wiley & Sons, Ltd. ISBN: 978-0-470-72111-7

Introduction

281

Figure 9.1 Metabolic pathways for the conversion of biomass (conventional biological process) or carbonaceous material including biomass (hybrid thermochemical/biological process) into liquid fuels and bio-plastics. The pathways are divided into conventional biological processing, hybrid thermochemical/biological processing ( ) and shared pathways by both processes ( )

Once fractionated, carbohydrate polymer fractions, such as starch, cellulose, and hemicelluloses, are physicochemically or biochemically hydrolyzed to fermentable sugars. These fermentable sugars are then converted to biobased fuels and other chemicals (sugar fermentation, Figure 9.1). However, most lignocellulosic biomass, such as straw and wood, contains a large proportion of material that cannot be converted to fermentable sugars, limiting the potential of biomass utilization into only fraction of stored energy. 9.1.2

Hybrid Thermochemical/Biochemical Processing

An alternative approach available for the biorefinery is the thermochemical processing of biomass into uniform intermediate products that can be biochemically converted to fuels and other chemicals [1, 3–6], called hybrid thermochemical/biological processing or simply hybrid processing. This emerging approach is not only applicable to lignocellulosic biomass utilization, but also applicable to virtually any carbonaceous material, such as biogases, organic waste products, agricultural waste material, and industrial and municipal wastes, enabling the utilization of a wide range of feedstocks for the production of biofuels and other bioproducts [7].

282

Hybrid Processing

There are two distinct approaches to the hybrid processing: (i) gasification of the carbonaceous waste material into a volatile gaseous mixture called synthesis gas or syngas, followed by fermentation; (ii) fast pyrolysis of the waste material into bio-oil, followed by hydrolysis and/or fermentation of the anhydrosugar found in bio-oil [6]. In this chapter, microorganisms capable of utilizing syngas or bio-oil for their growth and their potential applications in syngas fermentation and bio-oil fermentation will be discussed.

9.2 9.2.1

Syngas Fermentation Catalytic Conversions of Syngas: Chemical Versus Biological

Gasification is the oxygen-limited thermochemical conversion of carbonaceous material, including lignocellulosic biomass, into flammable gas mixtures, known as synthesis gas or syngas. Syngas is generally composed of CO, CO2, CH4, H2, and trace amount of hydrocarbons [3, 4, 6, 7]. Syngas can be used for the generation of heat and power and also can be used as feedstock for the production of fuels and other commodity chemicals. Because of this flexibility, gasification has been proposed as the basis for refineries that would provide a variety of energy and chemical products [4, 6]. Syngas can be converted to fuels and chemicals via two different routes: catalytic and biocatalytic. Catalytic routes include steam reforming with Ni catalysts for hydrocarbon production, the water-gas shift reaction with Fe–Cd or Cu–Zn catalysts for H2 production, and the Fisher–Tropsch reaction with Fe or Cr catalysts for hydrocarbon production. Molecular hydrogen and the one-carbon compounds found in syngas can also be used by a variety of microorganisms as sole carbon and/or energy sources and converted into alternative energy or platform chemicals [8–18]. The biocatalytic, or biological, route via syngas fermentation offers several potential advantages over catalytic routes: 1. Inorganic catalysts used in syngas conversions are readily poisoned by trace sulfurcontaining gases. In contrast, biocatalysts are comparatively sulfur tolerant [11]. Thus, expensive sulphur-containing-gas cleanup steps can be eliminated. 2. An inorganic-catalysis-mediated reaction often requires precise CO/H2 ratios. Water-gas shift reactors (Equation (9.1)) are often required to reduce CO levels and increase H2 levels in order to meet specific CO/H2 ratios. Biocatalytic reactors do not require specific CO/H2 ratios [6]. Moreover, most of CO-oxidizing bacteria are capable of catalyzing the water-gas shift reaction. 3. Reactions mediated by inorganic catalysts typically require high temperatures and pressures to be effective, whereas biocatalytic reactions proceed at near-ambient conditions [6, 7]. 4. Biocatalysts tend to be more product specific than inorganic catalysts. CO þ H2 O ! H2 þ CO2 9.2.2

ð9:1Þ

Fermentation of Syngas

Syngas fermentation is a two-stage process consisting of biomass gasification followed by bacterial fermentation to produce valuable fuel and chemical products. Chemicals produced

Syngas Fermentation

283

from syngas fermentation can include hydrogen, methane, acetic acid, butyric acid, ethanol, butanol, and biopolymers [19]. Whereas traditional fermentations rely on carbohydrates as the carbon and energy source for the microbial growth and commercially valuable metabolites production, syngas fermentation utilizes microorganisms capable of metabolizing a less expensive substrate, syngas, for the production of the valuable chemicals [4, 6, 20]. All of the major gases found in synthesis gas can serve as the sole energy, reductant, carbon, and/or nitrogen source for the growth of a number of diverse microorganisms [9, 11, 21–25]. Table 9.1 is a list of the better-characterized microorganisms that can utilize the major gaseous compounds in syngas. These microorganisms can be categorized into aerobic and anaerobic CO-oxidizing eubacteria and archaea (CO oxidizers), methanogens, methanotrophs, methylotrophs, and photosynthetic microorganisms. Chemicals produced from syngas fermentation include hydrogen, methane, acetic acid, butyric acid, ethanol, butanol, and biopolymers (Table 9.2). In contrast to traditional fermentations that rely on carbohydrates as the carbon and energy source, microorganisms involved in syngas fermentataion utilize less expensive substrate, syngas, for the production of commercially valuable metabolites [4, 6, 20]. 9.2.3

Microbial CO Metabolism

CO is metabolized by a variety of microorganisms as their sole carbon and energy source where the energy-driving reaction is the oxidation of CO (Table 9.1). These microorganisms fall into two major groups: aerobic CO eubacteria or carboxydotrophic bacteria and anaerobic archaea/eubacteria [6, 22, 24, 26]. Carboxydotrophs oxidize CO as a sole carbon and energy source and utilize O2 as terminal electron acceptor [20]. While CO-grown carboxydotrophs produce biomass and have the potential of producing genetically engineered products, the basic end product of this oxidation is CO2. Anaerobic CO metabolism is more complex and has the potential to produce a variety of valuable end products, such as hydrogen and ethanol (Table 9.1). Anaerobic CO-oxidizing microorganisms can be further divided into different physiological groups: acetogens, methanogens, sulfate reducers, elemental sulfur reducers, and anoxygenic photosynthetic eubacteria [20, 90]. Acetogens have attracted the most attention because they offer the several promising routes to chemicals and fuels production. 9.2.3.1 Acetogens Acetogens utilize CO as a sole carbon and energy source and produce a variety of products, including acetate, ethanol, butyrate, and butanol (syngas fermentation, Figure 9.1 and Table 9.1). As shown in Figure 9.2, the acetogenic CO metabolism starts with anaerobic CO oxidation via CO dehydrogenase (CODH) mediating the watergas shift reaction, resulting in the production of CO2 and H2. CODH is linked to the reductive acetyl-CoA pathway, also known as Wood–Ljungdahl pathway or acetyl-CoA pathway, which plays an essential role in acetogenic CO metabolism [22, 24, 90]. In this pathway, CO2 is the terminal electron acceptor with the reduction of two CO2 to the central metabolic intermediate, acetyl-Coenzyme A (acetyl-CoA). The reducing equivalents are usually derived from H2 and, in some cases, from CO [20, 22, 91]. Further conversion of acetyl-CoA to acetate provides a net energy gain via a chemiosmotic process [22, 24, 26].

CO/H2utilizers Acetoanaerobium noterae Acetobacterium woodii Acetobacterium bakii Acetobacterium carbinolicum Acetobacterium dehalogenans Acetobacterium tundrae Archaeoglobus fulgidus Butyribacterium methylotrophicum Caldanaerobacter subterraneus Carboxydibrachium pacificus Carboxydocella sproproducens Carboxydocella thermoautotrophica Carboxydothermus hydrogenoformans Citrobacter sp. Y19 Clostridium autoethanogenum Clostridium carboxidovorans Clostridium ljungdahlii Clostridium pasteurianum Clostridium thermoaceticum Clostridium thermoautotrophicum Clostridium magnum Desulfotomaculum geothermicum Desulfotomaculum kuznetsovii Desulfotomaculum thermobenzoicum Eubacterium aggregans Eubacterium limosum

Microorganism

CO, H2/CO, CO2 CO, H2/CO, CO2

CO2 CO2

Acetate Acetate, butyrate

Hydrogen Acetate, ethanol Acetate, ethanol, butanol Acetate, ethanol Ethanol Acetate Acetate, hydrogen Acetate Acetate Acetate Acetate, H2S

CO CO, H2/CO, CO, H2/CO, CO, H2/CO, CO, H2/CO, CO, H2/CO, CO, H2/CO, CO, H2/CO, H2/CO2 CO, H2/CO, CO, H2/CO, CO2 CO2 CO2 CO2 CO2 CO2 CO2

Hydrogen

CO

Acetate Acetate Acetate Acetate Acetate Acetate Acetate, formate, H2S Acetate, ethanol, butanol Acetate, butyrate Hydrogen Hydrogen Hydrogen

CO2 CO2 CO2 CO2 CO2 CO2 CO2

Product

CO, H2/CO, CO2 CO CO CO

H2/CO2 CO, H2/CO, CO, H2/CO, CO, H2/CO, CO, H2/CO, CO, H2/CO, CO, H2/CO, CO, H2/CO,

e/carbon source

Table 9.1 Potential syngas utilizing anaerobic and photoautotrophic microorganisms

35 38–39

35 37 38 37 37 55–58 55–60 30–33 54 19–21 55

71

65 70 60 58

35 30 19–21 19–21 25 19–21 83 37

Topta ( C)

7.2 7.0–7.2

6.5 5.8–6.0 6.2 6.0 6.8 6.0 5.7 7.2–7.4 7.3–7.5 7.5 7.0

6.9

7.5 6.8–7.1 6.8 7.0

7.6–7.8 6.8 7.5 7.5 7.5 7.5 6.4 6.0

pHoptb

O2 O2

O2 O2 O2 O2 O2 O2 O2 O2 O2 O2 O2

O2

O2 O2 O2 O2

O2 O2 O2 O2 O2 O2 O2 O2

Inhibitors

[50] [51]

[39] [40] [41] [42] [43] [44] [45] [46] [47] [48] [49]

[38]

[34] [35] [36] [37]

[26] [27] [28] [29] [30] [31] [32] [33]

Ref.

284 Hybrid Processing

Methanosarcina acetivorans strain C2A Methanosarcina barkeri Methanothermobacter thermoautotrophicus Moorella HUC22-1 Natroniella acetigena Oxobacter pfennigii Peptostreptococcus productus Rhodopseudomonas palustris strain P4 Rhodospirillum rubrum Rubrivivax gelatinosus Ruminococcus hydrogenotrophicus Ruminococcus schinkii Sporomusa acidovorans Sporomusa aerivorans Sporomusa malonica Sporomusa ovata Sporomusa paucivorans Sporomusa silvacetica Sporomusa termitida Syntrophococcus sucromutans Thermincola carboxydiphila Thermincola ferriacetica Thermoacetogenium phaeum Thermoanaerobacter kivui Thermolithobacter carboxydivorans Thermosinus carboxydivorans Tindallia californiensis Treponema azotonutricium Treponema primitia

Acetate, formate, CH4 CH4 CH4 Acetate, ethanol Acetate Acetate, butyrate Acetate Hydrogen Hydrogen, PHA Hydrogen Acetate Acetate Acetate Acetate Acetate Acetate Acetate Acetate Acetate Acetate Hydrogen Hydrogen Acetate Acetate Hydrogen Hydrogen, acetate Acetate Acetate Acetate

CO, H2/CO, CO2 CO, H2/CO, CO2 CO, H2/CO, CO2 H2/CO2 CO, H2/CO, CO2 CO, H2/CO, CO2 CO, H2/CO, CO2 Light, CO/CO, CO2 Light, CO/CO, CO2 CO, H2/CO, CO2 H2/CO2 H2/CO2 H2/CO2 H2/CO2 H2/CO2 H2/CO2 H2/CO2 H2/CO2 H2/CO2 H2/CO2 CO, H2/CO, CO2 CO, H2/CO, CO2 H2/CO2 H2/CO2 H2/CO2 CO CO, H2/CO, CO2 H2/CO2 H2/CO2

60 28–30 30 30

39 28–30 35 28–30 30 37 30 30 35 55 57–60 58 66 70

30 34 37

55 37 36–38 37 30

37 65

37

6.8–7.0 9.5 7.2 7.2

6.5–7.0 7.2–7.4 8.5 7.2–7.4 7.2 7.0–7.2 6.8–7.0 6.2 6.4 8.0 7.0–7.2 6.8 6.4 7.0

6.8 6.7–6.9 7.0

6.5–6.8 9.7–10.0 7.3 7.0 6.8–7.0

7.4 7.4

7.0

O2 O2 O2 O2

O2 O2 O2 O2 O2 O2 O2 O2 O2 O2 O2 O2 O2 O2

O2 O2 O2

O2 O2 O2 O2 O2

O2 O2

O2

[76] [77] [78] [78] (continued)

[62] [63] [64] [65] [66] [67] [68] [69] [70] [71] [72] [73] [74] [75]

[11] [60] [61]

[55] [56] [57] [58] [59]

[53] [54]

[52]

Syngas Fermentation 285

b

Optimal cell growth temperature. Optimal cell growth pH. c b-1,2-Glucan. d b-1,3-Glucan. e a-1,4-Glucan and a-1,6-glucan. f Glycerol-galactoside. g Single-cell protein.

a

Photosynthetic CO2 utilizers Cyanobacteria Chlorophyta (green algae) Chrysophyta (diatoms) Euglenophyta (euglenoids) Dinoflagellata Phaeophyta (brown algae) Rhodophyta (red algae) CH4 utilizers Methanotroph

Microorganism

Table 9.1 (Continued )

Various Various Various Various Various Various Various Various

SCP,g lipids

CH4/CH4

Topta ( C)

Starch, lipids Starch, Lipids, H2 Lipids Paramylonc Starch Laminarin,d mannitol Floridean,e fluoridosidef

Product

Light/CO2 Light/CO2 Light/CO2 Light/CO2 Light/CO2 Light/CO2 Light/CO2

e/carbon source

Various

Various Various Various Various Various Various Various

pHoptb

CO, C2H2

CO CO CO CO CO CO CO

Inhibitors

[88, 89]

[79, 80] [81] [82] [83, 84] [82] [85] [86, 87]

Ref.

286 Hybrid Processing

Syngas Fermentation

287

Table 9.2 Syngas compositions from the gasification of different carbonaceous source feedstocks. The compositions presented represent gas composition after quenching and purification. Syngas composition varies depending on source material, gasification temperatures, and gasifier design Source

Fossil Biomass

Composition (vol%, dry basis) CO

CO2

H2

CH4

C2H4

NH3

H2S

6–59 30–45

1–16 10–25

29–76 25–35

0–28 4–14

0–1 0–2

0–0.1 0–0.1

0–0.3 0–0.7

Othersa 0–5 0–3

a

Includes phenolic compounds and other unidentified trace volatile hydrocarbons.

Figure 9.2 Metabolic pathways for acetogenic CO utilizers (Wood–Ljungdahl pathway). (1) A series of enzymatic reactions reducing formate (HCOOH) to methyl moiety. The reduction of formate is initiated by formate binding to a coenzyme called tetrahydrofolate (H4F). This process requires one ATP per CO reduction in addition to reducing equivalents. (2) Reactions mediated by acetyl-CoA synthase. (3) Coenzyme A is replaced by inorganic phosphate, forming acetyl phosphate, followed by the production of ATP and acetate. (4) Variety of cellular anabolic reactions

9.2.3.2 Methanogens Methanogenic archaea, also called methanogens, are a phylogenetically diverse group of strict anaerobic microorganisms characterized by the reduction of CO or CO2 to CH4 [54].

288

Hybrid Processing

Methanogens produce CH4 under strictly anoxic conditions by cleavage of acetate to CH4 and CO2 or by the reduction of C1 compounds such as CO and CO2. For syngas fermentation, methane production from the C1 reduction route is of interest because both CO and CO2/H2 comprise a major portion of syngas composition. The C1-utilizing methanogens produce methane mainly from CO2/H2 or from CO via methanogenic reactions shown below [54]: CO2 þ 4H2 ! CH4 þ 2H2 O

ð9:2Þ

4CO þ 2H2 O ! CH4 þ 3CO2

ð9:3Þ

As shown in Equation (9.2), reduction of CO2 to CH4 is generally H2 dependent, meaning that the electrons for methanogenesis are driven from H2. However, some methanogens are capable of utilizing CO as the sole source of energy, where CO acts as an electron donor in methanogenesis (Equation (9.3)). So far, only three representative methanogens capable of CO reduction to methane have been identified: Methanosarcina barkeri, Methanosarcina acetivorans, and Methanothermobacter thermoautotrophicus. Msa. acetovorans strains have shown the highest growth rate amongst them indicating better capability of methane production from CO [20]. Although utilization of methanogens in syngas fermentation has not been well recognized, methanogens are a potential candidate for syngas fermentation because conversion of CO and CO2 to methane can improve the fuel value of syngas. 9.2.4

Microbial H2 Metabolism

Hydrogen metabolism with respect to metabolism of syngas can be considered as either the oxidation of H2 (Equation (9.4)), with the electrons entering the respiratory chain, or as the reduction of 2Hþ (Equation (9.5)) to H2 production in the terminal reaction of anaerobic respiration. Both reactions are catalyzed by a hydrogenase [92], which are classified into three groups: the [NiFe]-hydrogenases, the [Fe]-hydrogenases, and the metal-free hydrogenases. Hydrogenases are further subdivided into: (i) uptake hydrogenases (Equation (9.4)); (ii) evolution hydrogenases (Equation (9.5)); (iii) bidirectional hydrogenases (Equation (9.6)), and (iv) cytoplasmic hydrogen sensors. Hydrogenases in groups (i), (ii), and (iii) are of potential commercial interest in bioconversions of syngas. H2 ! 2H þ þ 2e

ð9:4Þ

2H þ þ 2e ! H2

ð9:5Þ

H2 $ 2H þ þ 2e

ð9:6Þ

9.2.4.1 Uptake Hydrogenase Uptake hydrogenases are [NiFe]-hydrogenases that allow microorganisms to use H2 as an electron and energy source. Depending on the organism, the enzyme is found in either the cytoplasmic membrane or in the periplasm and transfers electrons to the respiratory chain at the cytochrome bc1 complex or cytochrome c level respectively. The energy from hydrogen oxidation is recovered by the vectorial transport of protons across the cytoplasmic

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289

membrane. Depending on the microorganism, the terminal electron acceptor of hydrogen oxidation is O2, HNO3, HNO2, SO42, CO2, or fumarate [92–94]. H2 has a high fuel value and, as such, is a commercially valued end product of gasification [3, 16, 25, 95]. Thus, little interest has been shown in culturing microorganisms on H2 from synthesis gas. However, future studies may consider coupling H2 oxidation to drive methanogenesis for CH4 production. In addition, a number of H2-oxidizing chemolithotrophs have well-developed genetic systems and could be cultured on H2 from syngas for the production of specialty products. 9.2.4.2 H2-evolving Hydrogenases H2-evolving hydrogenases are complex multi-subunit enzymes. This group of hydrogenases is expressed and functions under anaerobic conditions and is generally coupled to the anaerobic oxidation of one-carbon compounds such as CO and formate [23, 96, 97]. These enzymes generally reduce protons as a means of eliminating excess, reducing equivalents from substrate oxidations [98]. The majority of H2-evolving hydrogenases are found in methanogens [29, 31, 99, 100]. The hydrogenases in the methanogens may be of interest in commercial applications in the enrichment of both hydrogen and methane in syngas. Of particular interest to syngas fermentation is the CO-induced H2-evolving hydrogenase of Rhodospirillum rubrum [101, 102]. This coupled enzyme system can be used to enrich the hydrogen content of syngas at the expense of CO [11]. The hydrogenase is co-induced with the CO-dehydrogenase and is a critical component of the CO oxidizing system that allows growth of this bacterium on CO. In this co-oxidation system the electrons from CO are shuttled to protons, resulting in H2 production, with the subsequent reoxidation of hydrogen providing energy for the growth [23, 99]. In cells cultured on syngas, approximately 75% of the electrons from CO result in H2 evolution and 25% of the H2 is reoxidized by the cells to provide growth energy [11]. 9.2.4.3 Bidirectional Hydrogenase Bidirectional hydrogenases are a diverse group of enzymes [92, 94]; those found in methanogens and cyanobacteria may prove of interest in synthesis gas conversions [103, 104]. The role of the enzyme in cyanobacteria is still in question, but in methanogens the enzyme funnels electrons into the electron transport systems. 9.2.5

Microbial CH4 Metabolism

Methanotrophs are a group of bacteria characterized by the utilization of CH4 as their sole carbon and energy source (CH4 oxidation, Figure 9.3). Like H2, the methane component in synthesis gas has a high fuel value and generally not considered a feedstock for microorganisms. However, future studies may consider the conversion of methane in syngas to methanol and possibly to biodiesel. Some methanotrophs build an intensive intracytoplasmic membrane structure, which consists mainly of phospholipids when sufficient (approximately 1 mM) Cu is available for their metabolism [105]. This Cu-controlled overproduction of phospholipids by methanotrophs opens another possibility of syngas fermentation. Microorganisms produce free fatty acids as a precursor for the phospholipids component of membranes. Those free fatty acids are then esterified to glycerol or analogous polyols [106–108]. Fatty acid production is tightly regulated by catabolic and anabolic processes in

290

Hybrid Processing

Figure 9.3 Proposed biodiesel production pathway using methanotrophic metabolism: " indicates up-regulation and # indicates down-regulation

microorganisms and high concentration of free fatty acids does not occur in eubacteria. Because phospholipids are considered to be a “gummy” contaminating mass in biodiesel production process from vegetable oil and that “degumming” of crude vegetable oil is essential process for quality feed stock preparation [106, 107]. Thus, overproduction of bacterial phospholipids would not be favored for fuel production purposes. However, genetic engineering may be able to overcome the above-stated problems related to methanotrophic biodiesel production. For example, Lu et al. [109] have shown that genetic engineering via genotypic alterations can make Escherichia coli overproduce free fatty acids that can be further processed to biodiesel. They achieved this by (i) knocking out the first step of the fatty acid degradation pathway and by (ii) increasing the supply of malonyl CoA by overexpressing acetyl CoA carboxylase (Figure 9.3). The resulting genetically engineered E. coli produced about 3 g/L final titers of free fatty acids from sugar metabolism. Although E. coli produced free fatty acids from sugar metabolism in this study, a similar approach would be applicable to methanotrophic metabolism, because methanotrophs share similar cellular fatty acids synthesis and degradation pathways to E. coli. A potential pathway of free fatty acid production from the methane fermentation is described in Figure 9.3. 9.2.6

Photosynthetic CO2 Metabolism

Lipids from higher plants, such as palm trees and soybeans, can be easily extracted and converted to biodiesel. It is one of the most widely used technologies for biofuels production and about 225 million gallons of biodiesel were produced in the USA alone in 2006 [110]. The major obstacle that stops wider adoption of this technology is the insufficient availability of low-cost feedstock. Lipid production by microalgae may have potential to get around the current feedstock limitations.

Syngas Fermentation

291

Microalgae comprise a diverse group of organisms (Table 9.1) characterized by their ability of trapping the energy in light to generate reducing equivalents from water, thus allowing the fixation of CO2 as a growth substrate ultimately producing carbohydrates [106, 110, 111]. The overall balance equation of this photosynthetic reaction is 6CO2 þ 12H2 O þ Photons ! C6 H12 O6 þ 6O2 þ 6H2

ð9:7Þ

The photosynthetic CO2 fixation is through the reductive pentose phosphate pathway, also known as the Calvin cycle. The key enzyme in this pathway, RuBisCO (ribulose-1, 5-bisphosphate carboxylase/oxygenase), catalyzes the fixation of CO2 using ribulose-1, 5-bisphosphate as the CO2-accepting molecule and generates to two triose molecules, 3-phosphoglycerate. The energy driving this catalytic reaction comes from the lightharvesting pigments in photosynthetic organisms allowing the capture of photons with wavelengths ranged between 400 and 700 nm [110]. All known RuBisCOs have one intrinsic problem, as indicated in their name; they exhibit both carboxylase and oxygenase activities. Owing to this dual role, RuBisCOs have a relatively low affinity for CO2 and less than half of their population is saturated under atmospheric CO2 levels [112]. RuBisCOs still provide enough efficiency to support the life of microalgae in nature. However, when lipid production from this microorganism is of interest, the competitive nature of the dual role of RuBisCOs becomes problematic because microalgae utilize lipids as a means of excess energy and carbon storage. Hence, anoxic feedstock with high concentrations of CO2 would be favored for the high-yield lipid production from microalgae. Because the flue gas from syngas fermentation for CO utilization is CO2 rich and anoxic, the CO2-rich flue gas can be coupled to microalgae fermentation. Utilization of CO2 in syngas by autotrophic microorganisms currently has little if any commercial interest. However, future syngas fermentation plants may be required to remove this greenhouse gas. If the CO in synthesis gas is removed before this final fermentation stage, then photosynthetic microorganisms capable of oxygenic photosynthesis would be an ideal microbial choice. 9.2.7

Current Industrial Progress of Syngas Fermentation

To help develop industrial cellulosic ethanol production, the USs Department of Energy awarded $385 million to six cellulosic feedstock-based biorefineries in 2007 with a total expected capacity of 130 MGPY of ethanol [113]. Of the six selected biorefineries, three biorefineries, Abengoa Bioenergy Biomass of Kansas, LLC (Chesterfield, MO), Alico, Inc. (LaBelle, FL), and Range Fuels (Broomfield, CO) planned to utilize thermochemical conversion of cellulosic feedstock solely or in combination with biochemical processing [113]. Abengoa Bioenergy Biomass, LLC, has plans for a hybrid thermochemical/ biochemical cellulosic ethanol facility to be operational in Hugoton, KS, by later 2010 or early 2011 (C. Standlee, personal communication, Abengoa Bioenergy Biomass, LLC, 2008). The Alico, Inc. facility (LaBelle, FL) changed their plan to a hybrid thermochemical/ biological biorefinery using syngas fermentation to produce ethanol in June of 2008, abandoning their original plan to produce cellulosic ethanol [114]. The project is now taken over by New Planet Energy (NPE Florida) in LaBelle, FL [115]. Iogen Biorefinery Partners, LLC, also withdrew from the grant; however, they are still pursuing cellulosic ethanol production in Saskatchewan, Canada.

292

Hybrid Processing

The syngas fermentation route of the hybrid thermochemical/biological approach to lignocellulosic biomass conversion is being explored on the commercial scale. Bioengineering Resources, Inc. (Fayetteville, AR) was a participant in the Alico project (now controlled by NPE Florida) and had their own demonstration plant in Fayetteville, Arkansas [116–118]. In 2008, Bioengineering Resources, Inc. was acquired by INEOS Bio (Lisle, IL) [119]. INEOS plans to build off of the fermentation technology developed and patented by BioEngineering Resources, Inc. They are planning to use an anaerobic acetogenic bacteria Clostridium ljungdahlii (ATCC 49587) to ferment CO in the syngas stream into ethanol and acetate [119, 120]. Syngas fermentation is also being explored by Coskata, Inc., at Warrenville, IL. They have a partnership with General Motors to produce ethanol via syngas fermentation [121]. Coskata operating costs (excluding capital charges) of less than $1 per gallon. It is operating a 40,000 gallon/year demonstration plant in Madison, PA [121, 122]. Coskata also plans to commission a 50–100 MGPY plant in 2011. However, Coskata predicts that commercialscale 100 MGPY plants would require $3–$4 per gallon in capital costs. It plans to licence technology to larger companies [123]. For their process, plasma gasification is followed by fermentation by a proprietary CO- and/or H2-utilizing microorganism with high resistance to bacteriophage infections and predatory bacterial contaminants. With their proprietary organism and fibrous reactor design, Coskata boasts the highest industry feedstock conversion rate to ethanol [124]. They can yield over 100 gallons of ethanol per dry ton of carbonaceous feedstock [125]. Vapor permeation membrane separation technology is used to reduce the energy required for ethanol purification. Analysis by Agronne National Laboratory shows that the ratio of energy used per energy generated is 1 : 7.7. The Coskata process also uses less than one gallon of water per gallon of ethanol produced [126]. Other hybrid thermochemical/biological cellulosic ethanol commercial projects in the works include Syngas Biofuels Energy, Inc., and LanzaTech. Limited information is available on their processes, but Syngas Biofuels Energy, Inc. (Houston, TX), claims to be able to produce butanol or ethanol via syngas fermentation [127]. Similar to syngas fermentation technology, New Zealand-based LanzaTech NZ Ltd plans to produce ethanol by fermenting carbon monoxide off of waste flue gases [128]. 9.2.8

Problems and Future Perspectives

9.2.8.1 Gas–liquid Mass Transfer In general, the productivity of a biocatalyzed process in a bioreactor is directly related to the cell density. However, this general rule does not apply when the primary substrate in the bioreactor is a gas. Instead, gas–liquid mass transfer becomes the rate-limiting factor that governs the productivity of a bioreactor. One example of this would be synthesis gas utilization by Rhodospirillum rubrum for the production of hydrogen and biodegradable plastics [7, 11]. This microorganism utilizes CO in synthesis gas as a sole carbon and energy source. However, in typical stirred-tank reactors, the maximal hydrogen production occurs well before the culture has reached maximal density [7, 11]. Thus, the biocatalysis falls well short of the capacity of the bioreactors and hampers the economic feasibility of the bioconversion process. Considering its high conversion efficiency (approximately 70–80% of total biomass can be converted to synthesis gas, while enzymatic cellulose hydrolysis can only convert 20–30% of total biomass [129]), gasification is a very attractive

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pretreatment technology for the bio-production of fuels and other commodity chemicals from biomass. Unfortunately, the utilization of synthesis gas has been limited due to the gas–liquid mass transfer problem stated above. A common strategy to overcome this mass transfer problem in conventional stirred-tank reactors is increasing the ratio of the agitator’s power to volumetric gas feeding. In this strategy, increased agitator power input results in better gas bubble break-up, hence increasing the interfacial area available for mass transfer. However, this is not an economically feasible strategy for large, commercial-scale reactors because of excessive power costs. Multiple unique research projects are in progress to overcome this mass transfer problem at Iowa State University (ISU). Zhu and coworkers evaluated the effect of functionalized nanoparticle addition in the syngas fermentation by R. rubrum [130]. The addition of the nanoparticle with mercaptopropyl surface group enhanced the enzyme-catalyzed water-gas shift reaction, resulting in up to 200% increase in H2 production due to the better mass transfer efficiency without increasing power input. This study suggests that the addition of the nanoparticle may be a solution to overcome the mass transfer problem. Alternatively, Sung and coworkers at ISU are examining the efficiency of a hollow-fiber membrane reactor. Their preliminary study has shown that this reactor could raise mass transfer efficiency by at least 300% under optimized reaction conditions (data not shown). Results also have shown that a high mass transfer rate was achievable even with low gaseous substrate feeding rates, indicating that complete utilization of syngas with a low energy cost may be possible with this fermentation system (data not shown). 9.2.8.2 Potentially Toxic Intermediates Hydrogen sulfide, nitric oxide, and volatile organic compounds (VOCs) are the commonly reported, potentially toxic, trace contaminants present in syngas [21, 131, 132]. The presence of these compounds and whether they are toxic to the microorganisms involved in fermentation depends on the gasification process and the fermentative microorganism(s) respectively. For example, hydrogen sulfide is generally considered a toxic trace contaminant in syngas. However, H2S appears to stimulate the CO-dehydrogenase in R. rubrum cultured on syngas [132]. Toxicity due to VOCs is also difficult to predict and depends on the material being gasified as well as on the microorganism involved. Initial studies on VOC composition in syngas were variable even when similar biomass was gasified. This potential problem may require strain selection for tolerance to VOCs, as discussed in Section 9.3.3.2. 9.2.8.3 Co-Production Strategy Recent results from a techno-economic assessment study have suggested that a coproduction strategy could be a way to reduce production costs [7]. A techno-economic analysis was conducted to investigate the feasibility of a gasification-based hybrid biorefinery producing both hydrogen and polyhydroxyalkanoates (PHAs), biodegradable bio-plastics that can be an attractive substitute for conventional petrochemical plastics [7]. The syngas fermentation utilized R. rubrum for the co-production of hydrogen and PHA. The operating cost of the biorefinery was heavily subsidized by the production and the sale of hydrogen gas; without hydrogen gas co-production, the PHA production cost was more

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than $8.00/kg. With the co-production strategy, the production cost was reduced to less than $2.00/kg [7]. The co-production strategy can be adapted to other biorefineries, such as microalgae fermentation and methanotroph fermentation for biodiesel productions. Microalgae have drawn attention for their ability of producing highly energy-dense lipids that can be readily converted to bio-diesel [110, 111]. However, the productivity of microalgae has been limited. Thus, improving the productivity is still an important metabolic and genetic engineering goal at the current stage. Besides the attempts to improve the lipid productivity of microalgae itself, an alternative solution may be found from the above-stated study. Since microalgae are capable of the water-gas shift reaction for hydrogen production, each mole of CO2 assimilation can be coupled to the production of equimolar H2 production. The coproduction of H2 coupled to lipid production may be considered to reduce the bio-diesel production cost. This may require an additional initial investment, because the recovery of photosynthetically produced H2 requires closed reactor systems rather than current outdoor open-pond systems. However, the closed photobioreactor design has additional advantages, such as: 1. higher yield – up to 10 times higher average yield was reported when compared with the outdoor pond operation; 2. higher productivity per land and water resources; 3. higher efficiency in substrate utilization where O2 is the only emitting gas under the optimal operational condition; and 4. low dependency on environmental factors, such as temperature fluctuations, that can significantly hamper the productivity of microalgae fermentation [133]. Similarly, methanotrophic fermentation can be operated for the co-production of singlecell protein (SCP) and lipids. Imperial Chemical Industries (ICI), UK, developed SCP fermentation from C1 compounds [134]. Later, in 1995, another bacterial SCP was developed by the Danish firm Dansk BioProtein and approved by the EU for use in animal and fish feed. BioProtein was produced by a group of methanotrophic bacteria cultured using natural gas as the source of energy and carbon [135]. The use of methanotrophs as a source of SCP has advantages, such as fast growth, high protein content, and protein quality [135]. Screening studies required for making a bacterial SCP approved for animal consumption are expensive. The fact that SCP production from methanotrophs is already proven safe may be another merit for the SCP co-production with methanotrophic bio-diesel production. 9.2.8.4 Complete Utilization of Syngas Currently, syngas utilization for fuels and chemicals productions is mainly focusing on H2 and CO utilization for alcohol production. This is mainly because both substrates are abundant in syngas (comprises up to 75% of total syngas composition) and not fully oxidized. Because of the reduced nature of these substrates, they can serve as carbon and energy sources of bacterial metabolism. Therefore, the fermentation does not require additional expensive substrates to support the energy-generating metabolism. However, other substrates in syngas, such as CH4 and CO2, can also be included for the complete utilization of syngas. The in-series connection of different substrate utilizers can theoretically result in truly environmental-friendly fuels and chemicals production biorefinery

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Figure 9.4 Conceptual schematic of syngas fermentation focusing on complete utilization of syngas. Note that O2 is the only emitting gas after the completion of syngas utilization. HTP stands for hydrothermal processing, also known as liquefaction. aBiomass: whole or fractional microbial biomass from fermentation processes

(Figure 9.4). The proposed biorefinery will not only recover all gasified carbon and transform it to fuels and commodity chemicals, increasing the efficiency of energy input for the gasification process, but also emit only pure oxygen to the environment as photosynthetic organisms do in nature. This refinery could potentially be carbon neutral by itself, similar to nature’s carbon recycling activity.

9.3

Bio-oil Fermentation

Pyrolysis of lignocellulosic biomass results in a highly viscous liquid called bio-oil, along with char and a volatile gas mixture [6, 7]. Although the composition of bio-oil differs depending on the condition of pyrolysis and also on the nature of the raw material, it is possible to produce levoglucosan (1,6-anhydro-b-D-glucopyranose) in a high yield under optimal conditions [6, 7]. From the aspect of lignocellulosic biomass utilization, levoglucosan production from biomass by pyrolysis is now considered as a way of saccharification. Because levoglucosan is an anhydrosugar of glucose and is readily hydrolyzed to glucose with mild acid treatment, pyrolytic levoglucosan production was originally thought to be a thermochemical alternative for the enzymatic hydrolysis of the biomass [136]. In this concept, the thermochemical treatment of the biomass for the production of levoglucosan was followed by an acidic hydrolysis of levoglucosan to glucose, the most common fermentation substrate. The resulting glucose was then introduced to a conventional sugar fermentation platform for the production of useful

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products. However, the acidic hydrolysis may be avoided if microorganisms are capable of utilizing levoglucosan directly. 9.3.1

Levoglucosan Utilizers

Levoglucosan is not an abundant substrate in nature because it is not a biological metabolic by-product [137]. However, studies have shown that several strains of fungus can use levoglucosan as their sole carbon and energy source [136–140]. Microorganisms capable of utilizing levoglucosan directly are listed in Table 9.3. Because levoglucosan is readily hydrolyzed with mild acid treatment, it was believed that the hydrolytic conversion of levoglucosan to glucose might be the first step of the metabolism [136, 138]. However, no levoglucosan dehydrogenases were isolated in initial studies [136, 138]. Instead, initial studies showed that the microorganisms converted levoglucosan directly to glucose6-phosphate via a specific enzyme called levoglucosan kinase [136, 138]. As shown in Figure 9.5A, levoglucosan kinase enables these fungi to utilize levoglucosan by the direct phosphorylation of this anhydrosugar. A recent study suggested that there might be another enzymatic reaction converting levoglucosan to glucose. A bacterium tentatively name Arthrobacter sp. I-552 was able to utilize levoglucosan in the absence of levoglucosan kinase. A novel enzyme isolated in this study was able to convert levoglucosan to glucose via a three-step reaction: (i) NADHgenerating levoglucosan dehydrogenation, (ii) intramolecular hydrolysis of 3-keto levoglucosan, and (iii) NADH-dependent reduction of 3-keto glucose [138–140]. This possible reaction scheme is described in Figure 9.5B. Table 9.3 Levoglucosan-utilizing microorganisms and their specific enzymes for levoglucosan metabolism. Depending on the enzymatic activity, levoglucosan is converted to either D-glucose or glucose-6-phosphate Microorganism

Specific enzyme

Converted to

Arthrobacter sp. I-552 Aspergillus awamori Aspergillus fonsecaeus Aspergillus luchuensis Aspergillus niger CBX-209 Aspergillus oryzae Aspergillus sojae Aspergillus terreus K-26 Cryptococcus albidus Fusarium solani Neurospora crassa Penicillium citrinum Penicillium cyclopium Penicillium expansum Penicillium granulatum Penicillium griseolum Penicillium italicum Rhizopus niveus Rhizopus oryzae Sprobolomyces salmonicolor

Dehydrogenase Kinase Kinase Kinase Kinase Kinase Kinase Kinase Kinase Kinase Kinase Kinase Kinase Kinase Kinase Kinase Kinase Kinase Kinase Kinase

D-Glucose Glucose-6-phosphate Glucose-6-phosphate Glucose-6-phosphate Glucose-6-phosphate Glucose-6-phosphate Glucose-6-phosphate Glucose-6-phosphate Glucose-6-phosphate Glucose-6-phosphate Glucose-6-phosphate Glucose-6-phosphate Glucose-6-phosphate Glucose-6-phosphate Glucose-6-phosphate Glucose-6-phosphate Glucose-6-phosphate Glucose-6-phosphate Glucose-6-phosphate Glucose-6-phosphate

Ref. [139] [136] [136] [137] [137] [137] [137] [136] [137] [137] [137] [136] [137] [137] [137] [137] [137] [137] [136] [137]

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Figure 9.5 Enzymatic reactions for the levoglucosan conversions to glucose-6-phosphate (A) and to D-glucose (B). Modified from Refs [137] and [138] respectively

9.3.2

Current Status of Levoglucosan Fermentation

Presently, only two different products from direct levoglucosan fermentation have been reported [136, 140]. Aspergilus terreus K26 was able to produce itaconic acid (methylenesuccinic acid) from levoglucosan fermentation [136]. In the other study, Aspergillus niger CBX 209 produced citric acid from levoglucosan fermentation [140]. In both studies, the yield and the rate of fermentative productions from levoglucosan were similar to those from glucose fermentation, indicating that the conversion of levoglucosan to either glucose-6-phosphate or glucose is not the rate-limiting step. These findings suggest levoglucosan can be fermented as effectively as conventional hexoses, such as glucose or fructose.

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Future Perspectives

9.3.3.1 Searching for New Microorganisms In spite of its rare occurrence in nature, it has been shown that levoglucosan can be utilized as a sole carbon and energy source by many microorganisms. However, very few metabolic pathways capable of converting levoglucosan to fuels and other commodity chemicals have been identified. In fact, only two kinds of organic acid production have been reported. The thermochemical saccharification of cellulosic biomass, i.e. pyrolysis, was only recently recognized as an effective alternative to enzymatic hydrolysis of cellulosic materials. Thus, the potential of levoglucosan in fermentation processes has yet to be explored [4]. To expand the potential of levoglucosan fermentation, isolation of new microorganisms capable of converting levoglucosan into those valuable substances would be necessary. The search is promising. Kitamura et al. have successfully isolated a large number of levoglucosan utilizers in a comparatively short period of time and their study suggests that levoglucosan utilizers are ubiquitous in nature [137]. 9.3.3.2 Inhibitory Pyrolytic Substances Although high in levoglucosan content, pyrolytic bio-oil contains other tarry organic hydrocarbons that can be potentially harmful to the levoglucosan-utilizing microorganisms [4]. To minimize this unwelcomed harmful effect of the bio-oil, isolation of microorganisms that are tolerant to the inhibitory substances may be required. Alternatively, one can expose the isolated or existing levoglucosan utilizers to a low dose of the bio-oil initially and slowly increase bio-oil concentrations in the media over a large number of generations while continuously applying selection power. This approach is called “directed evolution” because it utilizes and accelerates the natural Darwinian selection process, survival of the fittest [141]. It is a widely accepted strategy to select adapted microorganisms favorable for high productivity and stability in fermentation processes. The directed-evolution approach typically consists of three steps: (i) diversification, (ii) selection, and (iii) amplification [142]. In the first step, mutagenesis is often coupled to accelerate the diversification process. Depending on the availability of genetic information of a given microorganism, random mutagenesis or site-directed mutagenesis can be used [142, 143]. During the second step, the mutated microorganism is subjected to a screening and selection process to select mutants possessing the desired property; in this case, tolerance to the inhibitory substances in bio-oil [142, 143]. For the last step, the selected microorganism will be replicated into a large population for the maintenance and characterization. These three steps are often repeated several times in order to achieve microorganisms with desired characteristics [142]. 9.3.3.3 Genetic Engineering Approach Researchers in this field should also notice that only a few products are available via the levoglucosan fermentation route. However, a gene responsible for the conversion of levoglucosan to a more biologically accessible substrate, glucose-6-phosphate, has been recently identified, cloned, and expressed in E. coli [139]. The transformed E. coli was able to use levoglucosan as a sole carbon and energy source, demonstrating that similar genetic engineering approaches may be utilized to construct genetically modified microorganisms

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from existing glucose-fermenting microorganisms. Because this approach can utilize existing sugar-fermenting microorganisms, it may help diversifying the product portfolio of bio-oil fermentation in a short period of time with minimal efforts.

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10 Costs of Thermochemical Conversion of Biomass to Power and Liquid Fuels Mark M. Wright and Robert C. Brown Department of Mechanical Engineering, Iowa State University, Ames, IA, USA

10.1

Introduction

This chapter provides an overview of the capital and operating costs associated with the production of thermochemical biofuels. Costs should be considered as approximations of actual costs, since many of these technologies have either not been built at commercial scales or have not been operated with biomass feedstocks. Detailed information regarding the following featured processes can be found in the published literature. Scenarios considered include thermochemical production of electricity, hydrogen, alcohols, Fischer–Tropsch liquids (FTL), and synthetic diesel and gasoline from biomass. This analysis has not been corrected for different basis years, plant scales, or assumed rates of return among the different sources of data, which can strongly affect cost estimates. Other assumptions that vary widely in the literature include the cost of feedstock, equipment, and utilities. An improved comparison would adjust results found in the literature for the appropriate cost basis year, plant capacity, and depreciation method among other considerations [1].

Thermochemical Processing of Biomass: Conversion into Fuels, Chemicals and Power, First Edition . Edited by Robert C. Brown © 2011 John Wiley & Sons, Ltd. Published 2011 by John Wiley & Sons, Ltd. ISBN: 978-0-470-72111-7

308

Costs of Thermochemical Conversion of Biomass to Power and Liquid Fuels

10.2

Electric Power Generation

10.2.1

Direct Combustion to Power

Figure 10.1 shows a general schematic for a biomass combustion power plant. Typically, hot gases exiting the combustion reactors exchange heat with a water cycle to raise steam, which in turn drives a steam turbine that generates electricity. This process is relatively simple and economical. The literature contains few detailed economic data on direct biomass power generation, although techno-economic analyses have been reported [2, 3]. Specific investment costs for various biomass to power systems have been reported to vary between $600 and $1300 per kilowatt of capacity for plant sizes of more than 50 MW (E1 ¼ $1.25) [4]. The lowest electricity cost for these systems was estimated at $0.075/kWh with costs of more than $0.18/kWh for combined heat-and-power biomass plants. Investment costs for power plants follow the well-known economies of scale law, which favors the construction of large plants with capacities of more than 1000 MW. Unfortunately, biomass availability and logistic costs severely limit the cost-effective size of direct biomass combustion plants to capacities of less than 400 MW. At capacities of less than 50 MW, investment costs can surpass $1800/kW output. Small-scale plants are well suited for scenarios where low-cost biomass is available, albeit in limited quantities. An example of such a scenario is waste wood from logging activities. 10.2.2

Gasification to Power

Biomass gasification provides better overall thermodynamic efficiency than combustion power systems when used as part of an integrated gasification combined cycle (IGCC) power system. The topping cycle combusts synthetic gas from the gasifier in a gas turbine, and the bottoming cycle takes advantage of the high exiting gas temperatures to drive a steam turbine, as shown in Figure 10.2.

Steam Turbine Electricity

Steam

Exit Gas

Biomass Drying

Grinding

Heat Exchanger Combustion Gas Cleaning

Figure 10.1 Process diagram for direct combustion to power

Hot Gas

Steam Electricity

Heat Exchanger

Biomass

Electricity Drying

Grinding

Steam Turbine

Gasification Gas Cleaning Gas Turbine

Figure 10.2

Process diagram for gasification to power

Liquid Fuels via Gasification

309

At capacities of less than 50 MW, biomass gasification plants are considerably more expensive than direct combustion plants. At about 25 MW, an atmospheric IGCC would cost between $1600/kW and $2300/kW of capacity, while a similarly sized combustion system using a steam turbine would cost between $1000/kW and $1500/kW and require similar investment costs. The main advantage of gasification technology over biomass direct combustion is a higher energy conversion efficiency, which results in lower operating costs. Fluidized-bed combustion systems can achieve about 35% conversion efficiency to electricity. Gasification systems, on the other hand, can have efficiencies surpassing 45%. A 50 MW biomass gasification plant can achieve operating costs that are about 20% cheaper than a similarly sized combustion system. The total operating cost for a 50 MW biomass gasification power plant is about $21 million per year or $0.05/kWh. 10.2.3

Fast Pyrolysis to Power

Pyrolysis vapors can be directly combusted in a gas turbine, as illustrated in Figure 10.3. Alternatively, these vapors can be condensed to liquid bio-oil that can power a conventional diesel engine to generate electricity. The combination of small diesel engines with biomass pyrolysis is a promising alternative for distributed power generation. Current commercial applications dedicated to bio-oil production are few and small in scale. Available cost estimates evaluate biomass power systems with less than 20 MW capacities. Capital costs for a coupled biomass fast pyrolysis reactor and diesel engine generation plant vary from $6200/kW for a 1 MW plant to $2400/kW for a 20 MW plant [5]. The advantage of employing bio-oil to feed a power generating system is reduced transportation costs. Furthermore, it is well suited for scenarios where biomass supply does not warrant a large-scale system. Operating costs for bio-oil to power systems range from $0.25/kWh to about $0.08/kWh for 1 MW and 20 MW systems respectively.

10.3

Liquid Fuels via Gasification

10.3.1

Gasification to Hydrogen

Hydrogen is actually one of the simplest fuels to produce by thermochemical biomass processing. Figure 10.4 illustrates the unit operations required, consisting of: fuel drying and comminution; gasification; gas-stream cleaning; steam reforming of tar and other hydrocarbons to CO and H2; water-gas shift reaction to increase the amount of H2 in the gas stream, and separation of H2. Heat integration includes generation of electric power from waste heat. Hamelinck and Faaij [6] have evaluated the economics of a biomass-to-hydrogen plant of Gas Turbine Hot Gas Electricity

Bio-oil

Biomass Drying

Grinding Pyrolysis

Figure 10.3

Oil Recovery Gas Cleaning

Electricity Diesel Engine

Process diagram for fast pyrolysis to power

310

Costs of Thermochemical Conversion of Biomass to Power and Liquid Fuels Hydrogen

Biomass Compression Drying

Grinding

Gasification

Gas Cleaning

Reforming Pressure Swing Adsorption (Shift)

Steam Electricity Gas/Steam Turbine

Figure 10.4

Process diagram for gasification to hydrogen

182 million gallons annual capacity (MMGPY) for liquefied hydrogen production. They estimate plant capital cost to be $282 million (2001 basis) and plant operating costs of $0.29 per gallon. Biomass gasification to produce hydrogen employs equipment that is common to many thermochemical processes. The gasifier can account for over 25% of the capital costs, as shown in Table 10.1. Inclusion of a power generation section can add a significant capital cost, but provides for a major source of by-product revenue. The relatively low number of unit operations involved in generating hydrogen is one of the main reasons for the high-energy conversion efficiency of biomass to hydrogen plants (about 50%). The implication of this is that for the same energy input hydrogen plants can yield a greater amount of fuel energy than corn grain ethanol for example (35% efficiency). This results in a lower feedstock cost per gallon of product due to a lower feed input requirement. Operation and management costs are small and in some cases completely accounted for through by-product revenues. Hydrogen plants can be designed to produce heat or electricity from excess methanol production. A breakdown of operating costs is included in Table 10.2. The literature includes several studies on the cost of hydrogen from biomass. Variations in the capital and operating cost estimates are typically due to differences in assumptions on the type of gasifier employed, extent of gas conditioning, and feedstock cost. Particularly important is the selection of air, oxygen, or even steam gasification. Air gasification dilutes the gas stream with inert nitrogen, which increases the size requirement of equipment downstream from the gasifier. On the other hand, oxygen-blown gasification requires an expensive oxygen separation tank. These are only a few of the economic trade-offs faced during the design of gasification-based plant, and are generally solved on a case-by-case basis. Table 10.1

Capital costs for 182 MMGPY gasification-to-hydrogen plant

Section (1920 dry tonnes/day) Pretreatment Gasifier (IGT) Oxygen separation Gas cleaning Syngas processing Methanol production Hydrogen production Power generation Total

Capital cost (US$ million) 38.2 73.0 27.7 12.4 13.3 0.00 53.3 64.8 282

Liquid Fuels via Gasification Table 10.2

311

Operating costs for 182 MMGPY gasification-to-hydrogen plant

Operating costs (1920 dry tonnes/day)

Annual cost (US$ million)

Capital Operation and management Biomass Power credit

33.6 11.3 24.7 17.4

Total

52.1

As shown in Table 10.2, revenue from sale of excess power can exceed half the cost of biomass feedstock. Of course, this is dependent on the availability of low-cost biomass, but the implication is that power generation is an important consideration for a hydrogen plant, especially when significant amounts of methanol are produced from this process. 10.3.2

Gasification to Methanol

Figure 10.5 shows the main equipment involved in the production of methanol from biomass. This process is similar to the hydrogen system previously described. Methanol production substitutes the hydrogen pressure swing adsorption unit with a gas reformer unit. The methanol gas generated can be expensive to compress. Therefore, researchers are pursuing advances in liquid-phase methanol synthesis that can significantly reduce the need to compress methanol. Production costs for methanol are identical within a 30% uncertainty to those of a hydrogen plant. For an 87 MMGPY methanol plant, Hamelinck and Faaij [6] estimate capital costs to be $224 million with fuel production cost of $0.70 per gallon (2001 basis). Methanol plants include much of the same equipment as hydrogen production plants and incur similar costs. Energy conversion efficiencies are similarly high, reaching up to 45% biomass-to-fuel efficiency. Methanol is a liquid at room temperature, which means that the large capital and operating expenses required for the compression of hydrogen are not necessary for methanol production. It is possible to produce both methanol and hydrogen from a single plant and optimize the product distribution based on market conditions. The methanol concept featured here generates just enough power to meet plant requirements, and does not receive a power credit. Compared with the similarly sized hydrogen scenario included above, this methanol plant has lower capital and operation and management costs, as shown in Tables 10.3 and 10.4. Methanol Biomass Drying

Grinding

Gasification

Gas Cleaning

Reforming Methanol Production (Shift)

Steam Electricity Gas/Steam Turbine

Figure 10.5 Process diagram for gasification to methanol

312

Costs of Thermochemical Conversion of Biomass to Power and Liquid Fuels Table 10.3

Capital costs for 87 MMGPY gasification-to-methanol plant

Section (1920 dry tonnes/day)

Capital cost (US$ million)

Pretreatment Gasifier (BCL) Gas cleaning Syngas processing Methanol production Power generation

38.2 30.4 38.1 62.8 41.3 13.9

Total

224

Table 10.4 Operating costs for 87 MMGPY gasification-to-methanol plant Operating costs (1920 dry tonnes/day)

10.3.3

Annual cost (US$ million)

Capital Operation and management Biomass Power credit

26.7 9.00 24.9 0.00

Total

60.6

Gasification to Mixed Alcohols

Mixed-alcohol synthesis follows the processing steps indicated in Figure 10.6. Alcohol synthesis is a catalytic process that requires a distillation column to separate its products. It is possible to generate excess electricity from a gas turbine powered by combustible gases exiting the alcohol synthesis reactors. In April of 2005, there were no commercial plants dedicated to the production of mixed alcohols with hydrocarbon chains of six carbons or less [7]. Conclusions made by researchers at the National Renewable Energy Laboratory (NREL) suggest that ethanol and mixed-alcohol synthesis could be cost competitive with corn ethanol by 2012 (Phillips, Aden A. et al. 2007[8]. Their estimates show capital costs of $137 million and operating costs of $1.01 per gallon for a 72.6 MMGPY mixed-alcohol biomass plant (2005 basis).

Ethanol Higher Alcohols

Biomass Drying

Grinding

Gasification

Gas Cleaning

Alcohol Synthesis

Alcohol Separation

Steam Electricity Gas/Steam Turbine

Figure 10.6 Process diagram for gasification to methanol

Liquid Fuels via Gasification Table 10.5

313

Capital costs for 72.6 MMGPY gasification-to-mixed-alcohols plant

Section (2000 dry tonnes/day) Feed handling and drying Gasification Tar reforming and quench Acid gas and sulfur removal Alcohol synthesis – compression Alcohol synthesis – other Alcohol separation Steam system and power generation Cooling water and other utilities Total

Capital cost (US$ million) 23.2 12.9 38.4 14.5 16.0 4.60 7.20 16.8 3.60 137

Table 10.6 Operating costs for 72.6 MMGPY gasification-to-mixed-alcohols plant Operating costs (2000 dry tonnes/day)

Annual cost (US$ million)

Feedstock Catalysts Olivine Other raw materials Waste disposal Electricity Fixed costs Co-product credits Capital depreciation Average income tax Average return on investment

27.0 0.20 0.40 0.30 0.30 0.00 12.1 (12.8) 9.50 7.30 17.6

Total

34.9

Natural gas is the primary feedstock for commercial production of mixed alcohols due to economic reasons, but syngas from biomass gasification can be employed to catalytically produce mixed alcohols. Economic and environmental considerations make biomass an attractive feedstock for mixed-alcohol production. Cost estimates for a 2012 target system are shown in Tables 10.5 and 10.6, and they represent future technology that may not be currently available at the given costs. Mixed alcohols include significant portions of alcohols with longer chain lengths than ethanol. These higher alcohols can be marketed as by-products and generate revenues of almost half the cost of feedstock, as shown in Table 10.6. Thus, the profitability of a mixedalcohol biorefinery would depend on its ability to market the generated co-products. 10.3.4

Gasification to Fischer–Tropsch Liquids

Fischer–Tropsch synthesis is very similar to mixed-alcohol production, as shown in Figure 10.7. Reforming and Fischer–Tropsch synthesis units replace the alcohol synthesis and separation units. The main difference between these units is the choice of catalyst. As with mixed-alcohol synthesis, Fischer–Tropsch generates a mixture of products that require

314

Costs of Thermochemical Conversion of Biomass to Power and Liquid Fuels Fischer-Tropsch Liquids

Biomass Drying

Grinding

Gasification

Gas Cleaning

(Reforming) (Shift) (CO2 Removal)

FT Synthesis

Steam Electricity Gas/Steam Turbine

Figure 10.7

Process diagram for gasification to FTL

separation. Combustible gases can be fed to a gas turbine or recycled to the Fischer–Tropsch synthesis reactors. Gas recycling improves the overall liquid yield. Cost estimates for biomass to FTL are typically based on established Fischer–Tropsch commercial plants employing fossil fuels such as coal-to-liquids plants. Published studies for biomass to FTL found capital costs of $341 million and operating costs of $1.45 per gallon for a 35 MMGPY biomass plant [9] (2000 basis). The use of biomass as a substitute for natural gas or coal in the conventional Fischer–Tropsch process adds additional cost and some complexity, primarily due to pretreatment considerations. Capital cost estimates by Sasol for a two-train gas-to-liquids plant with 30 000 barrels per day slurry-phase reactors equal about $25 000 per barrel per day capacity [10]. This is equivalent to $1.65 per gallon of capacity, which compares with $9.74 per gallon of capacity for the biomass plant shown here (about 2500 barrels per day capacity). Fischer–Tropsch plants also share various processing units with hydrogen and methanol plants, as shown in Table 10.7. Downstream from the gasifier is the Fischer–Tropsch reactor, which is not only expensive, but also requires additional equipment upstream to meet strict feed requirements. Gas cleaning can contribute as high an investment cost as the gasifier. The Fischer–Tropsch process is a relatively complicated process, as reflected by the high operation and management cost shown in Table 10.8. The example employed here maximizes the production of FTL, but this process generates valuable by-products in the form of heat, power, and even chemicals. In fact, successful marketing of the chemical products is necessary for this process to be economical. Current biomass Fischer–Tropsch products do not compete economically with commodities derived from fossil fuels. Table 10.7 Capital costs for 35 MMGPY gasification-to-FTL plant Section (2000 dry tonnes/day)

Capital cost (US$ million)

Pretreament Gasifier Oxygen plant Cleaning Shift Fischer–Tropsch Gas turbine Heat recovery steam generator Others

71.6 61.4 51.2 61.4 3.41 20.5 23.9 37.5 10.2

Total

341

Liquid Fuels via Gasification Table 10.8

315

Operating costs for 35 MMGPY gasification-to-FTL plant

Operating costs (2000 dry tonnes/day)

Annual cost (US$ million)

Capital Operation and management Biomass

34.1 16.8 34.2

Total

50.8

Biomass

Hydrogen PSA Drying

Grinding

Gasification

Reforming

Fermentation

Separation

Figure 10.8 Process diagram for gasification and syngas fermentation to PHA and co-product hydrogen

10.3.5

Gasification and Syngas Fermentation to PHA and Co-Product Hydrogen

Syngas fermentation is a hybrid thermochemical/biochemical process that can produce a variety of biobased products [11]. Although it is being commercially developed for biofuels production by several companies, the published literature contains very little on the costs of the process. One prominent exception is a techno-economic study by Choi et al. [12] that considers the use of Rhodospirillum rubrum, a purple non-sulfur bacterium, to simultaneously convert the carbon monoxide in syngas to the biopolymer polyhydroxyalkonate (PHA) and enrich the hydrogen content of the gas through a biologically mediated water-gas shift reaction. The process of gasifying biomass followed by steam reforming to remove organic contaminants and syngas fermentation to PHA and co-product hydrogen is illustrated in Figure 10.8. Choi et al. [12] assumed the syngas fermentation biorefinery would have a daily production output of 12 Mg of PHA and 50 Mg of hydrogen gas. Grassroots capital for the plant was estimated to be $55.5 million, with annual net operating cost of $6.7 million based on a credit of $2.00/kg for hydrogen co-product. Assuming a plant capacity factor of 93%, the unit cost of PHA was estimated to be $1.65/kg (see Table 10.9). Co-production of hydrogen was essential to this attractive production cost. Table 10.9 Operating costs for 40 MTPY gasification and syngas fermentation-to-PHA and co-product hydrogen plant Operating costs Raw materials Credit for H2 Labor, utilities, maintenance Indirect costs Annual capital charges Total PHA production costs

Annual costs (US$ million) 16.1 (32.3) 9.1 6.4 7.4 6.7 $1.65/kg

316

Costs of Thermochemical Conversion of Biomass to Power and Liquid Fuels

Biomass

Ethanol

Acid Prehydrolysis Drying

Grinding

Pyrolysis Extraction Pentose/Hexose Ethanol Hydrolysis Fermentation Distillation

Figure 10.9 Process diagram for bio-oil fermentation to ethanol

10.4

Liquid Fuels via Fast Pyrolysis

10.4.1

Bio-oil Fermentation to Ethanol

In the absence of inorganic contaminants, especially alkali and alkaline earth metals, thermal depolymerization of cellulose and hemicelluloses yields anhydrosugars [13], which can be hydrolyzed to fermentable sugars [14]. Pretreating biomass prior to pyrolysis to either remove or otherwise deactivate alkali and alkaline earth metals can increase yields of fermentable sugars in bio-oil to over 25% [15]. A scheme for accomplishing this so-called bio-oil fermentation is illustrated in Figure 10.9. In many respects it resembles conventional biochemical production of cellulosic ethanol production, including an acid pretreatment step, except that acid or enzymatic hydrolysis is replaced with pyrolysis for the purpose of depolymerizing plant carbohydrates. So and Brown [16] have performed one of the only techno-economic analyses of biooil fermentation. Tables 10.10 and 10.11 summarize the capital and operating costs for bio-oil fermentation for 50 MMGPY production. Total capital investment was estimated to be $142 million in 1997 dollars. Annual operating costs were estimated to be $118 million. Assuming a plant capacity factor of 90%, this translates to a unit cost of production of $2.35 per gallon. Costs can be expected to be significantly higher in 2010 dollars.

10.4.2

Bio-oil Upgrading to Gasoline and Diesel

Figure 10.10 shows the main processes required to convert biomass into gasoline and diesel using fast pyrolysis and hydroprocessing. Although not apparent in the figure, hydroprocessing can be conducted at a remote site from the pyrolysis facility and this scenario is

Gasoline Diesel

Biomass Drying

Grinding

Figure 10.10

Pyrolysis

Gas Cleaning

Oil Collection Hydrotreating Hydrocracking

Diesel and gasoline production from bio-oil upgrading

Liquid Fuels via Fast Pyrolysis Table 10.10

317

Capital costs of 50 MMGPY bio-oil fermentation-to-ethanol plant

Section

Capital costs (US$ million)

Pretreatment/pyrolysis/sugar recovery Fermentation Ethanol recovery Utilities Off-site tankage Fixed capital Start-up costs Working capital

22.8 56.1 7.01 26.2 6.03 118 5.9 17.7

Total

142

Table 10.11 Production costs of 50 MMGPY bio-oil fermentation-to-ethanol plant Operating costs Biomass feedstock Other material costs (including comminution/drying) Utilities, labor, and maintenance Indirect costs General expenses Annual capital charges Total Unit price of ethanol

Annual costs (US$ millions) 26.4 15.0 13.7 19.5 14.6 28.4 118 $2.35/gal

under consideration as a means to alleviate the difficulties in transporting biomass to large facilities. Estimates for bio-oil production costs vary between $0.41 and $2.46 per gallon [17, 18]. Synthetic gasoline and diesel can be generated from the upgrading of bio-oil; recent cost estimates for producing gasoline from bio-oil are $1.80 and $2.01 per gallon from corn stover and wood respectively [19]. Detailed analysis for a 2000 ton/day corn stover fast pyrolysis and bio-oil upgrading facility found the fuel cost for naphtha and diesel to be $3.04 per gallon [20] (2007 basis). A summary of the capital and operating costs is shown in Tables 10.12 and 10.13. An important advantage of biomass pyrolysis is its potential application for distributed biomass processing. The bulky nature of biomass results in high transportation costs that limit the size of large biomass facilities. Various processes have been proposed to preprocess biomass into a higher energy density material that can be delivered at a reduced cost. Preliminary analysis suggests that small-scale distributed pyrolysis could be employed to densify biomass prior to shipping to a large centralized upgrading facility. Reduced

318

Costs of Thermochemical Conversion of Biomass to Power and Liquid Fuels Table 10.12 Capital costs for 35 MMGPY fast pyrolysis and bio-oil upgrading plant Section

Capital costs (US$ million)

Hydroprocessing Combustion Pyrolysis & oil recovery Pretreatment Utilities Storage Installed equipment cost

48.7 47.3 28.0 20.2 9.1 5.8 159.1

Total

276.6

Table 10.13

Operating costs for 35 MMGPY fast pyrolysis and bio-oil upgrading plant

Operating costs

Annual costs (US$ million)

Feedstock Electricity Solids disposal Catalyst Fixed costs Co-product credits Capital depreciation Average income tax Average return on investment

54.4 5.8 1.8 1.8 11.2 (11.3) 11.9 9.3 22.5

Total

107.4

transportation costs and improved economies of scale at the centralized facility result in lower fuel production costs at large output capacities [21]. 10.4.3

Bio-oil Gasification to Liquid Fuels

Bio-oil production can serve as a distributed pretreatment step for gasification processes to produce renewable fuels. The notion of distributed biomass processing is described in Figure 10.11. It assumes that multiple small-scale plants supply a large centralized facility with pretreated biomass material such as bio-oil. Wright et al. [21] conducted a production-scale analysis of the costs to produce FTL using a distributed biomass processing system. This study estimates higher capital costs than a conventional single-facility system, but the capital costs are offset by lower fuel costs due to reduced feedstock transportation costs. Capital and operating costs for a 550 MMGPY FTL scenario are estimated at $4.03 billion and $852 million respectively (2007 basis).

Summary and Conclusions

319

Figure 10.11 Distributed bio-oil production and centralized gasification upgrading to FTL [21] (Reproduced from Wright, M.M., Brown, R.C., and Boateng, A.A. (2008) Distributed processing of biomass to bio-oil for subsequent production of Fischer–Tropsch Liquids, Biofuels, Bioproducts, and Biorefining, 2, 229. With permission from John Wiley and Sons)

10.5

Summary and Conclusions

Table 10.14 summarizes capital and operating costs for the thermochemical technologies described in this chapter. Direct comparisons among the technologies are not possible because of differences in cost basis and underlying assumptions. Capital costs are a strong function of plant capacity, and feedstock costs can have a major impact on the final cost of fuel from biomass. Also, comparisons of different kinds of fuels on a volumetric basis, which is common in the techno-economic literature on biofuels, can be misleading because

320

Costs of Thermochemical Conversion of Biomass to Power and Liquid Fuels

Table 10.14

Summary of costs for thermochemical biomass conversion technologies

Technology Direct combustion to power Gasification to power Pyrolysis to power

Gasification to hydrogen Gasification to methanol Gasification to mixed alcohols Gasification to FTL Gasification and fermentation to PHA with co-product H2 Bio-oil fermentation to ethanol Bio-oil upgrading to diesel and gasoline Bio-oil gasification to liquid fuels

Capital cost (US$/kW)

Operating cost (US$/kWh)

600

0.075

1600

0.05

2400

0.08

Capital cost (US$ million)

Operating cost (US$ million)

282 224 137

52.10 60.60 34.90

$0.29/gal $0.70/gal $1.01/gal

341 103

50.80 18.20

$1.45/gal $2.80/kg PHA

69

39.20

$1.57/gal

Product cost (US$)

277

107

$3.04/gal

4029

852

$1.55/gal

of the different energy content of fuels. For example, methanol and ethanol have only 50% and 66% of the energy content of gasoline on a volumetric basis, which affects the range of vehicles fueled on these alcohols. Similarly, liquefied hydrogen has only 25% of the energy content of gasoline. Finally, many of the gasification scenarios appear to assume very high capacity factors (90% or higher) without including sufficient equipment redundancy to assure this level of operational reliability. In practice, the capacity factors for gasifiers can be as low as 70%; thus, plant capacity factors of 90% would require two gasifiers with one serving as back-up. Similar redundancy would be required for gas compressors, which at the scale of these plants are custom manufactured [22]. There are numerous pathways to the production of biorenewable fuels. Projected economic costs are an important factor in the selection of biomass conversion technologies for investment in further research or commercial enterprises. Given the relative scarcity of established commercial data for biomass thermochemical processes, techno-economic analysis will continue to play a major role in the research of these technologies. Investigations into new pathways for the conversion of biomass into fuel continue to discover intriguing possibilities for the use of biomass as a renewable source of energy. Unfortunately, some of these efforts have yet to publish detailed economic analysis. There are various key opportunities and bottlenecks inherent in the different biomass conversion pathways. All biomass conversion technologies present attractive environmental benefits, and technological breakthroughs can provide the economic incentive for widespread consumer adoption. Therefore, it is important to continue exploring all potential pathways to the utilization of biomass for power and fuel applications.

References

321

References [1] Wright, M.M. and Brown, R.C. (2007) Comparative economics of biorefineries based on the biochemical and thermochemical platforms. Biofuels, Bioproducts and Biorefining Journal, 1, 49–56. [2] Larson E.I. and Marrison C.I. (1997) Economic scales for first-generation biomass-gasifier/gas turbine combined cycles fueled from energy plantations. Journal of Engineering for Gas Turbines and Power, 119, 285–290. [3] Solantausta, Y., Bridgwater T., and Beckman D. (1997) Electricity production by advanced biomass power systems. VTT Research Notes 1729. [4] Dornburg, V. and Faaij, A. (2001) Efficiency and economy of wood-fired biomass energy systems in relation to scale regarding heat and power generation using combustion and gasification technologies. Biomass and Bioenergy, 21 (2), 91–108. [5] Bridgwater, A., Toft, A., and Brammer, J. (2002) A techno-economic comparison of power production by biomass fast pyrolysis with gasification and combustion. Renewable and Sustainable Energy Reviews, 6 (3), 181–246. [6] Hamelinck, C. and Faaij, A. (2002) Future prospects for production of methanol and hydrogen from biomass. Journal of Power Sources, 111 (1), 1–22. [7] NREL (2005) Equipment design and cost estimation for small modular biomass systems, synthesis gas cleanup, and oxygen separation equipment. Task 9: mixed alcohols from syngas – state of technology, Nexant for NREL/SR-510-39946, National Renewable Energy Laboratory (NREL), Golden, CO. [8] Phillips, S., Aden, A., Jechura, J. et al. (2007) Thermochemical ethanol via indirect gasification and mixed alcohol synthesis of lignocellulosic biomass, National Renewable Energy Laboratory. [9] Tijmensen, M., Faaij, A., Hamelinck, C., and van Hardeveld, M. (2002) Exploration of the possibilities for production of Fischer Tropsch liquids and power via biomass gasification. Biomass and Bioenergy, 23 (2), 129–152. [10] Lutz, B. (2001) New age gas-to-liquids processing. Hydrocarbon Engineering, 6 (11), 23. [11] Brown, R.C. (2007) Hybrid thermochemical/biological processing. Applied Biochemistry and Biotechnology, 137–140 (1) 947–956. [12] Choi, D.W., Chipman, D.C., Bents, S.C., and Brown, R.C. (2010) A techno-economic analysis of polyhydroxyalkanoate and hydrogen production from syngas fermentation of gasified biomass, Applied Biochemistry and Biotechnology, 160, 1032–1046. [13] Patwardhan, P.R., Satrio, J.A., Brown, R.C., and Shanks, B.H. (2009) Product distribution from fast pyrolysis of glucose-based carbohydrates. Journal of Analytical and Applied Pyrolysis, 86, 323–330. [14] Scott, D.S., Paterson, L., Piskorz, J., and Radlein, D. (2001) Pretreatment of poplar wood for fast pyrolysis: rate of cation removal. Journal of Analytical and Applied Pyrolysis, 57, 169–176. [15] Brown, R.C., Radlein, D., and Piskorz, J. (2001) Pretreatment processes to increase pyrolytic yield of levoglucosan from herbaceous feedstocks, chemicals and materials from renewable resources, in Chemicals and Materials from Renewable Resources (ed. J.J. Bozell), ACS Symposium Series, vol. 784, American Chemical Society, Washington, DC, pp. 123–132. [16] So, K.S. and Brown, R.C. (1999) Economic analysis of selected lignocellulose-to-ethanol conversion technologies. Applied Biochemistry and Biotechnology, 77, 633–640. [17] Anon. (1991) Feasibility study: one thousand tons per day feedstock wood to crude pyrolysis oils plant 542,000 pounds per year using fast pyrolysis biomass process. Prepared for Solar Energy Research Institute, Arthur J. Power and Associates, Inc. [18] Solantausta, Y., Beckman, D., Bridgwater, A. et al. (1992) Assessment of liquefaction and pyrolysis systems. Biomass and Bioenergy, 2 (1), 279–297. [19] Holmgren, J., Nair, P., Elliot, D. et al. (2008) Converting pyrolysis oils to renewable transport fuels: processing challenges & opportunities, in National Petrochemical & Refiners Association Annual Meeting, San Diego, CA, pp. 9–11. [20] Wright, M.M., Daugaard, D.E., Satrio, J.A., and Brown, R.C. (2009) Techno-economic analysis of biomass fast pyrolysis to transportation fuels. Fuel, Iowa State University.

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[21] Wright, M.M., Brown, R.C., and Boateng, A.A. (2008) Distributed processing of biomass to bio-oil for subsequent production of Fischer–Tropsch liquids. Biofuels, Bioproducts, and Biorefining, 2 (3), 229–238. [22] Swanson, R.M., Platon, A., Satrio, J.A., and Brown, R.C. (2010) Technoeconomic analysis of biomass-to-liquids production based on gasification, Fuel, 89, S11–S19. DOI: 10.1016/j. fuel.2010.07.027.

Index References to figures are given in italic type. References to tables are given in bold type. ablative pyrolysis, 135–8 Acetobacterium spp., 284 activated carbon, 222 alcohols see ethanol; higher alcohol synthesis; methanol aldol condensation, 238, 266 algae, 3 Alico, Inc., 291 alkalis, 85 in bio-oil, 160, 166 alkanes, 2–3, 233–5 from polyols, 257 large, from sugars, 261–6 light, 249–54 alkylation, 266–8 Alter NRG, 72–3 ammonia, 84 aqueous thermolysis, 214 aqueous-phase dehydration/hydrogenation, 249–50, 261–2 aqueous-phase reforming, 181, 244–5 ARCH hydrogasification, 96 archaea, 287–8 aromatics from aqueous-phase sugar fragments, 271 from sugars, 269–71 Arthrobacter spp., 296 ash content, 26, 35 bio-oil and, 128, 129, 174 effect on product quality, 159–64 combustor fouling, 20 gasification feedstocks, 52–3 Aspergillus spp., 296 Avantium Technologies, 260–1 bacterial digestion see microbial conversion bagasse, 25

barks, 52 barrier filters, 81–2 battery electric vehicles, 5–6 bio-oil, 281 advantages, 125 applications, 124–5, 143–8 ash content, 128, 159–64, 174–5 biorefining, future applications, 298–9 char, 166–7 chemical products, 150–2, 182–7, 183–6 color, 167–8 composition, 131–3, 133 contamination, 161, 164, 167, 168 elemental composition, 130 fermentation, 295–8 filtration, 173 in gas turbines, 148–9 gasification, 149 as gasification feedstock, 149–50 hydrothermal processing, 7–8 hydrotreating, 175–6 mild cracking, 181 miscibility, 169, 174 nitrogen, 170 oxygen content, 170 pH, 160, 165 physical properties, 128–30, 157–9, 160–3, 171 smell, 170–1 stability, 132–3, 165–6, 171 standards, 165 toxicity, 172 upgrading catalytic, 174–80 costs, 316–18 physical, 173–4 viscosity, 159, 172 zeolite cracking, 176–9

Thermochemical Processing of Biomass: Conversion into Fuels, Chemicals and Power, First Edition . Edited by Robert C. Brown © 2011 John Wiley & Sons, Ltd. Published 2011 by John Wiley & Sons, Ltd. ISBN: 978-0-470-72111-7

324

Index

bio-oil (Continued) see also pyrolysis biocrude, 5 biodiesel see diesel Bioforming, 264–5, 265 biogas, 17 biomass combustion equilibria, 32–3 components, 2–3 composition, 23–6, 25, 29 effect on bio-oil products, 160–4 oxygen content, 24 density, 29 drying, 201 heating value, 27–9 moisture content, 27 particle characteristics see particles biomass integrated gasification combined cycles (BIGCC), 21 biorefineries, 280–1 hydrothermal gasification of residues, 220–1, 220 industrial, 291–2 mass transfer problems, 292–5 boilers, 6–7 boron trifluoride etherate, 267 Brayton engines, 22 briquettes, 29 bubbling fluidized bed pyrolysis, 138–41 butanol, 17 Butyribacterium spp., 284 C-C bond formation, 266–8 calcium carboxylates, 152 calcium oxide, 84 California, 36 Calvin cycle, 291 carbon dioxide, 40–1 microbial metabolism, 290–1 carbon monoxide, 18, 288 microbial metabolism, 283–8 Carbona-Andritz, 71–2 carboxydotrophs, 283–4 catalysts, 9–10 alkylation, 266–8, 267 dehydration, 253 fast pyrolysis, 270–1 Fischer-Tropsch synthesis, 101–2 higher alcohol synthesis, 108–9, 110–14, 111–13

hydrogenation, 256–7 hydrothermal gasification, 217–19, 222 for steam reforming, 91–3 sugar reforming, 248–9 supercritical gasification, 222–3, 248–9 syngas cleaning, 88 catalytic fast pyrolysis, 270–1 cellobiose, 237 cellulose, 3–4, 3, 24, 239 C/H molar ratio, 25–6 heating value, 29 hydrothermal gasification, 217 thermal decomposition behavior, 126–7 see also hemicellulose ceramic candles, 82 char bio-oil, 160, 166–7 from gasification, 67–8 characterization techniques, 24–6 charcoal, 15–16 chlorides, 85–6 chlorine, in bio-oil, 160, 167 CHOREN gasifier, 71–2 chromium, 40 circulating fluidized bed (CFB) pyrolysis, 141–2 Clear Fuels, 72–3 Clostridium spp., 284, 292 coal, 98 fuel cofiring, 21–2 gasification, 6, 62, 98 coals, 52, 53 cobalt catalysts, 101 cofiring, 21–2 coke, 88–9 cold gas efficiency, 48 combined heat and power (CHP), 68–74 combustion, 4, 5–6 air/fuel ratio, 30–1 annual biomass energy use, 18 cleaning units, 19–20 cofiring, 21–2 composition equilibria, 32–3 costs, 308 flame temperature, 31–2 gases, 17 history, 14–15 incomplete, 38 liquids, 17–18 pollutant output, 35–41, 36–7 greenhouse gases, 40–1

Index power generation, 14–15 reaction rates, 33–5 solid fuels, 15–17, 22 stoichiometry, 29–32 system types, 18–23 temperature, 28–9 commercialization, 10 contamination, 161, 164 copper catalysts, 101–2, 104 corn starch, 222 corrosion, reactor walls in supercritical gasification, 222 Coskata, Inc., 292 costs, 10, 320 alcohols production, 312–13 economic feasibility, 10 Fischer-Tropsch synthesis, 313–14 fuel upgrading, 316–18 higher alcohol synthesis, 312–13 hydrogen production, 309–11 methanol production, 311–12 power generation, 308–9 critical temperature, 203–4 Cryptococcus albidus, 296 cyclones, 81, 166 dehydration, 237–8, 255–6 Department of Energy (US), 2, 280, 291 Desulfotomaculum spp., 284 diesel, 17 bio-oil, 145–7 from methanol, 106–7 dimethyl ether (DME), 107 2,5-dimethyl furan, 9–10 dioxins, 38–40 direct combustion see combustion Distillers dried grain & solubles (DDG&S), 225 dolomite, 88 Douglas fir, hydrothermal processing, 207–8 downdraft gasifiers, 58, 59 Dynamotive Corporation, 138–9 economics see costs economies of scale, 308 electric vehicles, 5–6 electricity generation see power generation electrostatic precipitators, 82 emulsification, 169, 174 energy content, 27–9, 144 Enerkem gasifiers, 69–71

Ensyn Technologies, 141 entrained-flow gasification, 62–3 Envergent Technologies, 141 enzymes reactions, 296–7 uptake hydrogenases, 288–9 ethanol, 317 from syngas, 108–9 as fuel, 17 production costs, 316–18 ethoxymethylfurfural, 260–1 Eubacterium spp., 284 European Committee for Standardization (CEN), 165 Exxon catalytic gasification, 96 ExxonMobil, 94, 105–7 fast pyrolysis, 270–1 feedstocks see biomass fermentation see microbial conversion fertilizers, 151 filtration systems, 166–7, 173 fire, 14 Fischer-Tropsch archive, 98 Fischer-Tropsch synthesis, 54, 89, 98–101 catalysts, 101–2 chemistry, 99–100 costs, 313–14 methanol, 102 process overview, 99 fixed-bed gasifiers, 58–60 flame temperatures, 31–2, 33 fluid catalytic cracking (FCC), 135 use of spent catalysts, 87 fluidized bed gasification, 60–2 fluidized bed pyrolysis, 137 bubbling, 138–41 circulating, 141–2 mass-energy balances, 146 fly ash, 21–2 Ford, Henry, 6 Forestera, 139 Foster Wheeler gasifier, 71–2 fouling, 20, 26, 52–3 fractionation, 8, 9 bio-oil, 151–2 Frontline BioEnergy, 72–3 fructose, 9 fuel cells, 23 fuel oils, 212–13

325

326

Index

fuels, 17 bio-oil, 149–50 from hydrothermal liquefaction, 212–13 from methanol, 105–7 gasification synthesis, 74 metabolic pathways, 281 upgrading costs, 316–18 see also diesel; ethanol; fuel oils; gasoline; hydrogen furanics, 260 furans, 9–10 furfurals, 152, 252 from sugars, 261–9 see also hydroxymethylfurfural Fusarium solani, 296 gas chromatography, 131, 209 gas turbines, 7 bio-oil, 148–9 gases, combustion, 17 see also synthesis gas gasification, 4, 6–7, 18, 47–8 process overview, 49–51 advantages, 6 applications, 6–7, 68–74 char and tar production, 67–8 circulating fluidized bed, 61–2 coal, 6 costs, 308–9 efficiency measures, 48 entrained-flow, 62–3 feedstock properties, 51–3, 52, 80 Fischer-Tropsch liquids from, 313–14, 314 fixed-bed, 58–60 fluidized bed, 60–2 fuel synthesis, 74 heating and drying, 48–9 hydrogen from, 309–11 hydrothermal see hydrothermal gasification methanol from, 311–12 nomenclature, 47–8 particulates, 81–3 plants operating, 69–73 power generation, 68–74, 308–9 pressurized, 63–4 product gas composition, 64–7 reaction scheme, 78–9 system types, 17 air-blown, 54–6 indirectly heated, 56–7

steam/oxygen-blown, 56 using bio-oil, 149 see also synthesis gas gasoline, 17, 316–18 from methanol, 105–7 TIGAS synthesis, 106 genetic engineering, 298–9 gentibiose, 237 global warming potential, 36 glucose, 25 hydrolysis, 235–6 hydrothermal gasification, 217 supercritical gasification, 248 greenhouse gases, 36, 40–1 Guerbert reactions, 268 GVL, 258–9 Harculo power station, 147 Hawaii University, 225 heating value, 27–9 bio-oil, 144 heavy metals, 36, 40, 84 hemicellulose, 126–7 higher alcohol synthesis, 108–9 catalysts, 108–9, 110–14, 111–14 costs, 312–13 from syngas, 109–14 reaction scheme, 109–10 hot gas efficiency, 48 HTU process, 206–7, 212 H2-evolving hydrogenases, 289 hybrid processing see biorefineries hydrocracking, 8 hydrogen, 17 costs of production, 309–11 from bio-oil, 181–2, 182 from sugars, 242–6 catalysts, 245–6 supercritical reactions, 246–9 from syngas, 90–4 liquid, 17 membrane separation, 92–4, 93 microbial metabolism, 288–9 hydrogen chloride, 85–6 hydrogen cyanide, 84 hydrogenation sugars, 252–3, 256–7 for tar removal, 87 hydrogenolysis, 238 hydrolysis, 9–10

Index hydrothermal gasification, 200–1, 246–9 catalysts, support, 219 catalytic, 218–21 cellulose, 218 glucose, 218 history, 203 process overview, 217–18 in supercritical water, 221–3 hydrothermal liquefaction, 200 fundamental evaluations, 216 process evaluation, 213–14 process overview, 205–12, 206 product evaluation, 207–12 product utilization, 212–13 hydrothermal processing, 4–5, 8, 8–9 bio-oil, 175–6 gasification see hydrothermal gasification history, 202–3 process overview, 203–5 pumping, 222–6 subcritical, 204 supercritical, 204–5, 246–9 temperature regimes, 8 water requirements, 201–2 see also hydrothermal gasification; hydrothermal liquefaction hydroxyacetaldehyde, 152, 186 hydroxymethylfurfural (HMF), 238, 260–1, 263 conversion to levulinic acid, 259–60 5-hydroxymethyltetrahydrofurfural (HMTHFA), 263 HYGAS process, 96 hyrolysis, 235 integrated gasification combined cycle (IGCC), 21, 68–74, 308–9 International Energy Agency, 18–19 Iowa State University, 293 iron catalysts, 84, 101 isomaltose, 237 jatropha, 3 kilns, 6–7 lactose, 237 lactulose, 237 landfill gas, 17 LBL process, 206, 207

327

leaching, 34–5 lead, 40 levoglucosan, 4, 150, 152, 296–8, 297 metabolism, 296 levulinic acid, 259–60 lignin, 152, 239 thermal decomposition behavior, 126–7 lignocellulose, 4, 239 lipids, 2–3 liquid natural gas (LNG), 17 liquids, 17–18 Lurgi gasification, 71–2, 96 maltose, 237 Manitowoc Public Utilities, 144 mature technologies, 1–2 maximum achievable control technology (MACT), 39 a-D-melibiose, 237 membrane separation, 92–4 mercury, 36, 40 metals as catalysts, 84 effect on combustion rate, 34–5 methane, 41 bacterial metabolism, 289–90 as fuel, 17 steam reforming, 90–4 methanol, 17 conversion to dimethyl ether, 107 conversion to gasoline, 105–6 conversion to olefins, 107 costs of production, 311–12 formation in higher alcohol synthesis, 110 synthesis, 102–5 catalysts, 104–5 Methanosarcina spp., 287–8 methanotrophs, 289–90 microbial conversion, 17, 74, 289–90 bio-oil, 295–8 carbon dioxide, 290–1 hydrogen, 288–9 levoglucosan, 296–7 syngas, 282–3 see also fermentation model compounds, 182 moisture content, 27 Motonui plant, 106 MTG process, 105–6 Munich Technical University, 176

328

Index

municipal solid waste (MSW), 15–17 dioxin emission, 39 gasification properties, 52 National Renewable Energy Laboratory, 312–13 natural gas substitutes, 94–5 nickel, 84 nitrogen, in bio-oil, 161, 170 nitrogen oxides (NOx), 18, 20, 37 from cofiring, 21 nitrous oxide, 37 oil see bio-oil olefins, from methanol, 106–7 organic Rankine cycle (ORC), 22 oxygen, in biomass, 24 Pacific National Northwest National Laboratory, 202–3 palatinose, 237 palladium catalysts, 246 palm oil, 3 particle boards, 150–1 particles morphology, 34–5 size, 29 see also particulate matter particulate matter (PM), 18, 38 in synthesis gas, 81–3 Pearson gasifier, 57 pellets, 29 Penicillium spp., 296 PERC process, 205–7, 206 phenolic compounds, 151 phosphates, 221 photosynthesis, 232, 238–9, 290–1 pine oil, 133 Pittsburgh Energy Research Center, 202–3, 205, 223 see also PERC process platinum catalysts, 246 plywood boards, 150–1 pollutants, 18, 35–41 polychlorinated biphenyls (PCB), 38–9 polycyclic aromatic hydrocarbons (PAH), 18, 38 polyhydroxyalkanoate (PHA), 315–16 polyols, 257 poplar wood, 25, 33 potassium, 24, 53, 79

power generation, 19–20, 144–5 alternatives to Rankine cycle plants, 22 bio-oil, 144–5 biomass combustion, 20–1 cofiring, 21–2 combustion, 14–15, 308 costs, 308–9 fuel cofiring, 21–2 gasification, 69–73, 308 historical, 14–15 pyrolysis, 144–7, 309 pressure swing adsorption, 92 pressurized gasification, 63–4 process heat, pyrolysis, 144–5 producer gas, 47, 64–7 pyrolysis, 4, 7–8 process overview, 125–8 ablative, 135–8 in combustion, 34 effect of ash, 128 fast, 270–1 gas products, 17 gas-phase reactions, 50 gas-solid reactions, 50 in gasification, 49–50 process technologies, 134–5 auger, 137 circulating fluidized bed, 136, 141–2 entrained-flow reactors, 135 fluidized bed, 137 rotating cone, 137, 142–3 vacuum, 137, 142 reaction pathways, 127–8 reactor temperature, 164 to fuel gases, 18 see also bio-oil Pyrovac International, 142 quicklime, 84 radioactive species, 40 Range Fuels gasifier, 69–71 Rankine cycle, 19–20 rapid thermal processing (RTP), 141 refuse-derived fuel (RDF), composition, 25 Rentech Silvagas, 69–71 Repotech gasifiers, 69–71 resins, 150–1, 152 Rhizopus spp., 296 Rhodospirillum rubrum, 292–5, 315

Index rice straw, 26 composition, 25 Royal Institute of Technology, 224 RuBisCO, 291 sequential elution by solvents chromatography (SESC), 209–10 slagging, 26, 52–3, 60 slow pyrolysis see pyrolysis slurries, 167, 222–6 sodium, 24 soil conditioners, 151 solid fuels, gasification, 51–2 sorbitol, 249–50, 256, 257 sorghum, 224–5 sour shift catalysts, 92 Sporomusa spp., 285 Sporobolomyces spp., 296 standards, bio-oil, 165 starches, 239 conversion to alkanes, 261–3, 262 steam methane reforming, 90–1 steam reforming, 87–8, 181–2 bio-oil, 181–2 to hydrogen, 181–2, 237–8 to methanol, 102–3 steam superheaters, fouling, 20 stoichiometry, combustion, 29–32 straw, 21, 52 rice, 25 sucrose, 237 sugar cane, 25 sugars, 9–10, 152, 238–42 aldol condensation, 238 alkylation, 266–8 C-C bond formation, 266–8 catalytic conversion, 9–10, 234 dehydration, 253 enthalpy changes, 236 reactions, 235–8 supercritical reforming, 246–9 targets, 233–5 to aromatics, 269–71 to heavy alkanes, 261–9 to light alkanes, 249–54 to oxygenates, 254–61 dehydration, 237, 251–2, 255–6 hydrogenation, 252–3 hydrolysis, 235 see also starches

329

sulfur, 221 in bio-oil, 171 in synthesis gas, 83–4, 220 sulfur oxides, 37 supercritical gasification, 221–3 supercritical reforming, 246–9 Synthane, 97 synthesis gas (syngas), 4, 5, 6–7, 47–8, 54–5 ammonia decomposition, 84 applications, 89–90 cleanup, 79–81, 220–1 costs, 115 heavy metal removal, 85 sulfur removal, 83–4 tar removal, 86–9 complete utilization, 294–5, 295 conversion catalytic, 282–3 industrial progress, 291–2 microbial, 283, 291–2 process costs, 315–16 process summary, 111 to alcohols, 108–15 to dimethyl ether, 107–8 to liquid fuels see Fischer-Tropsch synthesis to methanol and mixed alcohols, 108–9 to natural gas substitute, 94–5 feedstock composition, 80 Fischer-Tropsch synthesis, 98–101 hydrogen microbial metabolism, 288–9 impurities, 80 process heat, 68 production see gasification synthetic natural gas (SNG), 94–5, 96–7 Synthol process, 108 syringe pumps, 225 tar, 80 from gasification, 67–8, 81 removal from syngas, 86–7 2,3,7,8-tetrachlorodibenzo-p-dioxin (TCDD), 38 tetrahydrofurfural, 252–3 thermal cracking, 87 thermochemical processing history, 1–2 overview of techniques, 4–5 TIGAS process, 106 torrefaction, 15 toxic equivalence, 38–9

330

Index

toxicity (bio-oil), 172 transition metal catalysts, 101 D-trehalose, 237 TRI, 69–71 triglycerides, 2 D-turanose, 237 updraft gasifiers, 58, 59 uptake hydrogenases, 288–9 vacuum pyrolysis, 137, 142 g-valerolactone, 258–9 vaporization energy, 27–8 vegetable oils, 2–3 VERENA, 226 volatile organic compounds (VOC), 37, 38 waste see municipal solid waste waste disposal, 15 water in bio-oil, 172

critical point, 203–4 supercritical, 221–3 water supply and treatment, 35, 86 water-gas shift (WGS) reaction, 90, 91 Waterloo university, 138–9 West Lorne pyrolysis plant, 138–9 wet scrubbing systems, 82–3, 86 willow wood, 25 wood ash content, 28–9 composition, 25 gasification properties, 52 hydrothermal gasification, 219 poplar, 25, 31 wood flavors, 151 xylitol, 256, 257 xylose, 9 zeolites, 270–1 zinc oxides, 83