Energy Resources and Systems
Tushar K. Ghosh
Mark A. Prelas
Energy Resources and Systems Volume 2: Renewable Resources
123
Tushar K. Ghosh Nuclear Science & Engineering Institute University of Missouri, Columbia Lafferre Hall E 2434 65211 Columbia Missouri USA
[email protected] Mark A. Prelas Nuclear Science & Engineering Institute University of Missouri, Columbia Lafferre Hall E 2434 65211 Columbia Missouri USA
[email protected] ISBN 978-94-007-1401-4 e-ISBN 978-94-007-1402-1 DOI 10.1007/978-94-007-1402-1 Springer Dordrecht Heidelberg London New York Library of Congress Control Number: 2009928307 c Springer Science+Business Media B.V. 2011 No part of this work may be reproduced, stored in a retrieval system, or transmitted in any form or by any means, electronic, mechanical, photocopying, microfilming, recording or otherwise, without written permission from the Publisher, with the exception of any material supplied specifically for the purpose of being entered and executed on a computer system, for exclusive use by the purchaser of the work. Cover design: eStudio Calamar S.L. Printed on acid-free paper Springer is part of Springer Science+Business Media (www.springer.com)
Preface
Energy is the lifeblood of civilization. Access to relatively inexpensive and plentiful energy has been and will continue to be its driving force. In the past few years, the reality of the fragile nature of an oil dominated energy infrastructure has become apparent. Civilization is engaged in a life and death struggle to redefine its primary energy resources and to find transitional solutions without invoking chaos. Time is relatively short and it will be in the hands of the current generation of students to solve. The authors began working on Energy Resources and Systems in 1996. The goal of the authors was to provide a comprehensive series of texts on the interlinking of the nature of energy resources, the systems that utilize them, the environmental effects, the socioeconomic impact, the political aspects and governing policies. Volume 1 on Fundamentals and Non Renewable Resources was published in 2009. It blends fundamental concepts with an understanding of the non-renewable resources that dominate today’s society. The second volume of Energy Resources and Systems is focused on renewable energy resources. Renewable energy mainly comes from wind, solar, hydropower, geothermal, ocean, bioenergy, ethanol and hydrogen. Each of these energy resources is important and growing. For example, high-head hydroelectric energy is a well established energy resource and already contributes about 20% of the world’s electricity. Some countries have significant high-head resources and produce the bulk of their electrical power by this method (e.g., Norway-over 98%, Paraguay100% and Brazil-85%). However, the bulk of the world’s high-head hydroelectric resources have not been exploited, particularly by the underdeveloped countries. Low-head hydroelectric is unexploited and has the potential to be a growth area. Wind energy is the fastest growing of the renewable energy resources for the electricity generation. Solar energy is a popular renewable energy resource. About 891015 watt (W) of solar energy is absorbed annually by the earth’s land mass and oceans. However, this only translates to around 1,000 W m2 spread over the earth’s surface area. The diffuse nature of solar energy has limited its growth because it is difficult to base systems on resources with a low energy density. v
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Geothermal energy is viable near volcanic areas. Iceland for example has taken advantage of its geothermal resources in that it produces 24% of its electricity and heats 87% of its buildings with it. Bioenergy and ethanol have grown in recent years primarily due to changes in public policy meant to encourage its usage. Energy policies stimulated the growth of ethanol, for example, with the unintended side effect of rise in food prices. Hydrogen has been pushed as a transportation fuel. The chapters on advanced energy resources were included in Volume 2 in the initial outline. However, the size of Volume 2 became too large, so it was decided to split renewable energy resources and advanced energy resources into separate volumes. The new Volume 3, on nuclear advanced energy resources and nuclear batteries, consists of fusion, space power systems, nuclear energy conversion, nuclear batteries and advanced power, fuel cells and energy storage. Volume 4 will cover environmental effects, remediation and policy. Solutions to providing long term, stable and economical energy is a complex problem, which links social, economical, technical and environmental issues. It is the goal of the four volume Energy Resources and Systems series to tell the whole story and provide the background required by students of energy to understand the complex nature of the problem and the importance of linking social, economical, technical and environmental issues. One thing is for certain, the business as usual model is losing favor. The historic positions of political parties and environmental groups of supporting only a selective group of energy resources have significantly changed. Even public attitude has changed with a widespread acceptance of renewable resources and nuclear energy. Part of this change is due to a more analytical approach to assessing the broad based risks of each type of energy resource and having confidence in risk management approaches. There appears to be a universal recognition that the future mix of energy resources will have to be diverse thus mitigating the risks associated with each individual energy resource. We would like to acknowledge the assistance of our students Jason B. Rothenberger, Daniel E. Montenegro, and Eric D. Lukosi, who read, edited, and commented upon various parts of the manuscript. Columbia, Missouri, USA May 12, 2010
Tushar K. Ghosh Mark A. Prelas
Contents
1
Wind Energy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 1.1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 1.2 Harvesting Energy from Wind . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 1.3 Wind Resource Map .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 1.4 Land Area Requirement . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 1.5 Energy and Power from Wind. . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 1.5.1 Betz Limit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 1.6 Capacity Factor for a Wind Turbine . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 1.7 Energy Production .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 1.8 Turbine Types .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 1.8.1 Horizontal Axis Wind Turbines (HAWTs) . . . . . . . . . . . . . . . . . 1.8.2 Vertical Axis Wind Turbines (VAWTs) .. . . . . . . . . . . . . . . . . . . . 1.9 Comparison Between Turbines . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 1.10 Cost of Electricity from Wind Energy . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 1.10.1 Payback Time for Wind Energy Systems . . . . . . . . . . . . . . . . . . . 1.10.2 Cost Reduction Efforts.. . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 1.11 Effect of Capacity Factor .. . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 1.12 Industrial Wind Turbines . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 1.13 Basic Principles of Wind Resource Evaluation . .. . . . . . . . . . . . . . . . . . . . 1.14 Wind Farm . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 1.14.1 Offshore Wind Farm . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 1.15 Small Wind Systems. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 1.16 Low Frequency Noise form Wind Turbines . . . . . .. . . . . . . . . . . . . . . . . . . . 1.16.1 Sound Intensity.. . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 1.16.2 Sound Pressure .. . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 1.16.3 The Sound Pressure Level . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 1.17 Wind Energy and Intermittency .. . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 1.18 Summary .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . .
1 1 6 8 16 20 21 23 24 25 26 32 35 38 43 45 47 48 48 51 53 58 61 63 64 64 66 67 69 vii
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2 Solar Energy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 2.1 Energy from the Sun .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 2.2 Energy Transfer to the Earth . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 2.2.1 Seasonal Variation . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 2.2.2 Height of the Sun in the Sky.. . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 2.3 Energy and the Sun . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 2.4 Use of Solar Energy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 2.4.1 Solar Thermal Energy . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 2.5 Concentrating Solar Power (CSP) . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 2.5.1 Trough Systems . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 2.5.2 Power Tower Systems . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 2.5.3 Dish/Engine Systems . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 2.6 Solar Thermal Molten Salt Technology . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 2.7 Photovoltaics .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 2.7.1 PV Theory .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 2.7.2 The Efficiency of Photovoltaic Cells . . . .. . . . . . . . . . . . . . . . . . . . 2.7.3 The “Sun” Value . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 2.7.4 Effect of Thickness of the Cell . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 2.7.5 The Effect of Temperature .. . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 2.7.6 Effect of Dopant Concentration . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 2.8 From Cells to Arrays . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 2.9 Solar Cell Materials . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 2.9.1 Semiconducting Materials for Solar Cell . . . . . . . . . . . . . . . . . . . 2.10 Multijunction Cells . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 2.11 Hybrid Power Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 2.12 Solar Lighting .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 2.13 Summary .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . .
79 79 80 81 83 83 85 87 102 102 104 104 107 110 112 120 129 131 131 134 136 136 137 140 141 141 142 144
3 Hydropower . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 3.1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 3.2 Hydropower Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 3.3 Hydropower System Construction Methods.. . . . .. . . . . . . . . . . . . . . . . . . . 3.3.1 Impoundment.. . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 3.4 Hydroturbine .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 3.4.1 Impulse Turbine .. . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 3.4.2 Reaction Turbine .. . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 3.5 Selection of Turbines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 3.6 Run-of-the-River Hydropower Systems . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 3.7 Small Hydroelectric Power System . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 3.7.1 Components of a Small Hydro Power System . . . . . . . . . . . . . . 3.8 Micro-Head Hydropower Systems . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 3.8.1 Selection of Turbine for Small or Micro Head Systems . . . 3.9 Pumped Storage Hydropower System . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . .
157 157 161 164 164 168 169 174 185 185 186 188 190 191 192
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3.10 Calculation of Power from Water Flow . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 3.10.1 Local Head Losses . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 3.10.2 Head Losses in Open Channels . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 3.11 Hydropower System Efficiency . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 3.12 Fish Ladder and Fish Passage in Hydropower Systems . . . . . . . . . . . . . 3.13 Summary .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . .
194 200 202 205 205 207 210
4 Geothermal Energy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 4.1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 4.2 Resource Identification . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 4.3 Geothermal Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 4.4 Applications.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 4.4.1 Electricity Generation.. . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 4.4.2 Direct Use of Geothermal Energy .. . . . . .. . . . . . . . . . . . . . . . . . . . 4.4.3 Ambient Ground Heat/Geothermal Heat Pump . . . . . . . . . . . . 4.5 Summary .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . .
217 217 219 223 224 227 238 243 256 258
5 Ocean Energy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 5.1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 5.2 Wave Power .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 5.3 Theory .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 5.3.1 Linear Wave Theory . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 5.3.2 Energy Transport and Power . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 5.3.3 Applicability of Linear Wave Theory . . .. . . . . . . . . . . . . . . . . . . . 5.3.4 Significant Wave Height . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 5.4 Wave Power .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 5.4.1 Tapered Channel (TAPCHAN) . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 5.4.2 Terminator Device/Oscillating Water Column.. . . . . . . . . . . . . 5.4.3 Point Absorber . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 5.4.4 Attenuator . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 5.4.5 Overtopping Devices. . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 5.5 Tidal Current Energy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 5.5.1 Tidal Barrage Method.. . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 5.5.2 Principles of Operation . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 5.5.3 Tidal Lagoons . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 5.5.4 Tidal Fence . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 5.5.5 Tidal Turbine Method .. . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 5.5.6 Linear Lift Mechanism or Oscillating Hydroplane Systems . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 5.5.7 Venture Based Systems . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 5.6 Tidal Farm . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . .
267 267 268 271 273 276 280 280 282 282 283 284 285 289 292 296 296 301 302 302 307 307 309
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5.7
Ocean Thermal Energy Conversion (OTEC) . . . . .. . . . . . . . . . . . . . . . . . . . 5.7.1 Closed-Cycle OTEC System . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 5.7.2 Open-Cycle OTEC System . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 5.7.3 Hybrid OTEC System. . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 5.7.4 Components of an OTEC System . . . . . . .. . . . . . . . . . . . . . . . . . . . 5.7.5 Byproducts of OTEC System . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 5.8 Summary .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . .
309 312 315 317 317 318 318 320
6 Bioenergy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 6.1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 6.2 Energy Source of Biomass . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 6.3 Composition of Biomass . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 6.3.1 Lignocellulosic Biomass. . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 6.3.2 Hemicellulose . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 6.3.3 Lignin .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 6.4 Types of Biomass .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 6.5 Biomass Resources, Land Requirement, and Production .. . . . . . . . . . . 6.5.1 Energy Crops Production Area . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 6.5.2 Lignocellulosic Based Biomass . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 6.5.3 Land for Biomass . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 6.6 Wood Fuel.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 6.6.1 Unit of Wood .. . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 6.6.2 Wood Burning .. . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 6.7 Use of Biomass . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 6.7.1 Process Heat and Steam Generation . . . .. . . . . . . . . . . . . . . . . . . . 6.7.2 Electric Power Generation .. . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 6.8 Biomethane . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 6.9 BioFuels .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 6.9.1 Biodiesel. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 6.9.2 Biofuel Production Method.. . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 6.10 Biofeedstock for Industrial Chemicals. . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 6.11 Summary .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . .
327 327 333 335 336 338 338 338 341 344 345 347 356 360 362 362 363 369 378 381 385 386 389 393 396
7 Ethanol .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 7.1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 7.2 Ethanol Production from Corn . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 7.2.1 Structure, Types, and Composition of Corn . . . . . . . . . . . . . . . . 7.2.2 Processing of Corn .. . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 7.2.3 Fermentation Process . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 7.2.4 Byproducts from Corn Processing . . . . . .. . . . . . . . . . . . . . . . . . . . 7.2.5 Comparison Between Dry Mill and Wet Mill Processes .. . 7.3 Sugar Crop Fermentation.. . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 7.4 Corn Versus Sugarcane .. . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . .
419 419 424 425 430 435 436 436 442 443
Contents
7.5
xi
Production of Ethanol from Cellulosic Biomass .. . . . . . . . . . . . . . . . . . . . 7.5.1 Pretreatment .. . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 7.5.2 Hydrolysis .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 7.5.3 Fermentation and Process Integration .. .. . . . . . . . . . . . . . . . . . . . 7.6 Energy Balance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 7.7 DDGS Market.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 7.8 Water Requirements for Corn Growing . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 7.9 Fuel Ethanol Quality Comparison . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 7.10 E-Diesel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 7.11 Summary .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . .
443 445 449 454 458 464 464 465 468 468 471
8 Hydrogen Energy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 8.1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 8.2 Hydrogen Economy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 8.3 Hydrogen Demand.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 8.4 Hydrogen Internal Combustion Engine .. . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 8.5 Hydrogen Production Methods . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 8.5.1 Reforming of Natural Gas . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 8.5.2 Biomass Gasification . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 8.5.3 Reforming of Biofuel . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 8.5.4 Hydrogen from Coal . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 8.5.5 High-Temperature Water Splitting . . . . . .. . . . . . . . . . . . . . . . . . . . 8.6 Nuclear Energy for Hydrogen Production .. . . . . . .. . . . . . . . . . . . . . . . . . . . 8.6.1 Water Electrolysis .. . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 8.6.2 High Temperature Electrolysis (HTE) of Steam.. . . . . . . . . . . 8.6.3 Thermochemical Water Splitting . . . . . . . .. . . . . . . . . . . . . . . . . . . . 8.7 Solar Energy for Hydrogen Production .. . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 8.7.1 High-Temperature Water Splitting-Solar Concentrators . . . 8.7.2 Solar Reforming of Natural Gas. . . . . . . . .. . . . . . . . . . . . . . . . . . . . 8.7.3 Thermochemical Solar Cycle. . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 8.8 Electrolytic Process .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 8.8.1 Alkaline Electrolysis .. . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 8.9 Thermochemical Hybrid Cycles . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 8.10 Hydrogen from Wind Energy . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 8.11 Hydrogen from Biomass . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 8.12 Photolytic Processes .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 8.12.1 Photobiological Water Splitting . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 8.12.2 Photocatalytical Processes . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 8.13 Cost of Hydrogen Production . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 8.14 Hydrogen Storage.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 8.14.1 High Pressure Cylinder . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 8.14.2 Liquid Hydrogen Storage System .. . . . . .. . . . . . . . . . . . . . . . . . . . 8.14.3 Carbon and Other High Surface Area Materials .. . . . . . . . . . .
495 495 497 497 500 501 503 508 508 509 509 510 510 512 515 543 544 545 548 555 555 555 557 560 560 560 563 566 566 568 573 575
xii
Contents
8.14.4 Clathrates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 8.14.5 Hydrides .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 8.15 Comparison of Hydrogen Storage Capacity . . . . . .. . . . . . . . . . . . . . . . . . . . 8.16 Hydrogen Delivery Methods . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 8.17 Summary .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . .
576 576 586 586 587 590
Appendices .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . Appendix 1: Wind Energy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . Appendix 2: Solar Energy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . Appendix 3: Hydropower .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . Appendix 4: Geothermal Energy . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . Appendix 5: Ocean Energy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . Appendix 6: Bioenergy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . Appendix 7: Ethanol . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . Appendix 8: Hydrogen .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . .
631 631 646 659 661 667 670 711 715
Index . . . . . . . .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . 719
Chapter 1
Wind Energy
Abstract The kinetic energy of wind is harvested using wind turbines to generate electricity. Among various renewable energy sources, wind energy is the second most technologically advanced renewable energy source; hydropower is the first. Although there is a significant potential for converting wind energy to electricity, a number of issues must be addressed before it can be used to its full potential. Wind blows in every corner of the earth; however, it does not blow constantly. In addition, it must maintain a certain speed to be effective for running a wind turbine and generating electricity. In this chapter, various aspects of wind energy including types of wind turbines, onshore and offshore wind farms, the cost of wind energy, and steps necessary for installing a wind turbine are discussed.
1.1 Introduction The utilization of wind energy can be dated back to as early as 5000 B.C., when wind energy propelled boats were sailing along the Nile River. By 200 B.C., the use of windmills in China for pumping water was documented. Vertical-axis windmills with woven reed sails were used for grinding grain in Persia and the Middle East. During that time period, the primary applications were for grain grinding and water pumping. Between 1850 and 1970, over six million, mostly small (one horsepower or less) wind mills were installed in the U.S. alone for conversion of the wind energy to the mechanical energy. The primary use was water-pumping for stock watering and meeting the water needs of farms and homes. Very large windmills, with rotors up to 18 m in diameter, were used to pump water for the steam railroad trains that provided the primary source of commercial transportation in areas where there were no navigable rivers. The historical perspective of wind energy development has been discussed by a number of researchers [1–12]. Wind energy got a big boost following the OPEC (Organization of Petroleum Exporting Countries) Oil Embargo of 1973, when several countries started investing T.K. Ghosh and M.A. Prelas, Energy Resources and Systems: Volume 2: Renewable Resources, DOI 10.1007/978-94-007-1402-1 1, © Springer Science+Business Media B.V. 2011
1
2
1 Wind Energy
Fig. 1.1 History of installed wind power capacity in the USA
in wind power related technologies. Federal and state tax incentives and aggressive government research programs triggered the development and use of many new wind turbine designs. A wide variety of small-scale models became available for home, farm, and remote areas. A new market for wind energy generated electricity, wind farms, began in the early 1980s. In the USA, the Public Utility Regulatory Policies Act of 1978 promoted wind farms. This legislation required utilities to buy electricity from private, non-utility individuals and developers that are using renewable energy resources for electricity generation. California, USA, led the use of wind energy, which was nick named as The Great California Wind Rush, when thousands of wind mills were delivered to the wind program in California in the early eighties. By 1997, nearly 2% of California’s electricity was generated by the wind. As the cost of the technology continued to decline, other areas in the USA, namely the Great Plains, Pacific Northwest and Northeast, began development of wind farms. As can be seen from Fig. 1.1, the installed capacity of wind energy in the USA has increased dramatically over the last several years. Modern wind turbines using advanced technologies are able to produce electricity at a affordable cost for homes, businesses, and even utilities. In the late nineteenth century, the multi-blade windmill design was introduced to generate electricity. A discussion on the current status of the wind energy can be found in various articles [13–24]. Wind power continues to prosper as new turbine designs are helping to reduce costs of wind power and make wind turbines economically viable in more places in the world. Worldwide capacity of wind energy for electricity production has increased from 58,982 MW in 2005 to about 93,864 MW in 2007; an increase
1.1
Introduction
3
Table 1.1 Installed wind power capacity of various countries (end of year data) Rank 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36
Nation Germany Spain United States India Denmark (incl. Faroe) China Italy United Kingdom Portugal France Netherlands Canada Japan Austria Australia Greece Ireland Sweden Norway Brazil Egypt Belgium Taiwan South Korea New Zealand Poland Morocco Mexico Finland Ukraine Costa Rica Hungary Lithuania Turkey Czech Republic Iran Rest of Europe Rest of America Rest of Asia Rest of Africa and Middle East Rest of Oceania World total
Source: Global Wind Energy Council [25]
2005 (MW) 18;000 10;028 9;149 4;430 3;132 1;260 1;718 1;332 1;022 757 1;219 683 1;061 819 708 573 496 510 267 29 145 167 104 98 169 83 64 3 82 77 71 18 6 20 28 23 129 109 38 31 12 59,091 MW
2006 (MW) 20;621 11;615 11;603 6;270 3;136 2;604 2;123 1;963 1;716 1;567 1;560 1;459 1;394 965 817 746 745 572 314 237 230 193 188 173 171 153 124 88 86 86 74 61 55 51 50 48 163 109 38 31 12 74,223 MW
132000 2009
2008
94122 2007
2006
2005
47686 2004
2003
31164 2002
24320 2001
18039 2000
1999
9663
0
1998
20000
7475
40000
13696
60000
39290
80000
59004
100000
74133
120000
109000
140000
1997
Cumulative Installed Capacity (MW)
Prediction
Actual
160000
160000
1 Wind Energy
2010
4
Year Fig. 1.2 Projected increase in world wind power installed capacity (Adapted from Global Wind Energy Council [25])
of about 35% in 3 years. This amount currently contributes less than 1% of worldwide electricity use. However, the wind generated electricity accounts for 23% of electricity use in Denmark, 6% in Germany and approximately 8% in Spain. The current wind-powered electricity generation capacity of various countries is shown in Table 1.1. Europe is leading the world in utilization of wind energy. The European Wind Energy Association (EWEA) is projecting Europe’s wind-generating capacity to be about 75,000 MW in 2010 and 180,000 MW in 2020. The increase in the installed capacity in the world is shown in Fig. 1.2. Also, several countries are evaluating their wind energy potential to further increase the generation capacity. The activities related to wind energy in various countries are discussed by a number of researchers [26–56]. The USA is also making a major push towards the use of more wind energy. The installed capacity in the USA has almost doubled to 40,180 MW in 2010 from that in 2008. This is becoming possible as legislators in several states are trying to increase the share of electricity generation by renewable energy sources. The current wind power capacity in various states of the USA is shown in Fig. 1.3. However, it is clear from Fig. 1.4 that wind energy is still contributing only a small fraction of total electricity generation in any state in the USA.
1.1
Introduction
5
Fig. 1.3 Installed wind power capacity in the USA as of 2010 (Courtesy of the National Renewable Energy Laboratory [57])
Washington 2.0% Oregon 3.5%
Montana 1.7% Idaho 1.6%
Wyoming 1.6%
North Dakota 1.8% South Dakota 2.6 Nebraska 0.7%
California 2.6%
Colorado 1.3%
New Mexico 3.9%
VT 0.2%
Minnesota 4.6% Wiscons 0.2%
New York 0.6% Pennsylvania 0.2%
lowa 5.5%
Kansas 2.3% Oklahoma 2.6%
ME 0.6%
Illinois 0.3
Tennessee 0.1% > 1,000 MW 100 MW-1,000 MW < 100 MW
Texas 2.0% Alaska 0.1% State generation as reported by the Energy Information Agency
Hawaii 1.3%
Wind generation estimated by AWEA, using capacity totals as of end 2007
Fig. 1.4 Percentage of electricity produced from wind energy by various states in the USA (Courtesy of American Wind Energy Association [58])
6
1 Wind Energy
1.2 Harvesting Energy from Wind The term wind energy or wind power is referred to the process by which the wind is captured to generate electricity. About 1–2% of 174,423,000,000,000kW h of energy that the sun radiates to the earth per hour are converted into wind energy. That is about 50–100 times more than the energy converted into biomass by all plants on the earth. Wind blows due to the uneven heating of the atmosphere by the sun, the irregularities of the earth’s surface, and rotation of the earth. Wind flow patterns depend on the earth’s terrain, oceans, and vegetative coverage. Locally, buildings, plants and mountains control the wind pattern and also the speed. The wind flow or the kinetic energy in the wind is harvested by wind turbines to generate either mechanical power or electricity. Wind turbines first convert the kinetic energy in the wind into the mechanical power, which then rotates a shaft to generate electricity. The mechanical power can also be used for other tasks, such as for grinding grain or pumping water. The wind rises from the equator and moves north and south to the higher layers of the atmosphere. In the equator, there will be a low pressure area close to ground level attracting winds from the north and south. At the poles, there will be high pressure due to the cooling of the air. Once air has been set in motion by these pressure gradients and the rotation of the earth, it undergoes an apparent deflection called the Coriolis force. Around 30ı latitude, in both hemispheres, the Coriolis force prevents the air from moving much farther. At this latitude there is a high pressure area, as the air begins sinking down again. As shown in Fig. 1.5, air is deflected to the right by the Coriolis force in the northern hemisphere as it moves
Fig. 1.5 A demonstration of the Coriolis force
1.2
Harvesting Energy from Wind
7
from high to low pressure. In the southern hemisphere, air moves from high to low pressure and is deflected to the left by the Coriolis force. The amount of deflection that air makes is directly related to both the speed at which the air is moving and its latitude; both are important factors in designing wind mills. In 1835, Gustave-Gaspard Coriolis, a French scientist, first described mathematically this phenomenon, giving his name to the Coriolis force. The Coriolis force is a fictitious force exerted on a body when it moves in a rotating reference frame. It is called a fictitious force because it does not appear when the motion is expressed in an inertial frame of reference. The acceleration corresponding to the Coriolis force is given by: aCoriolis D 2. v/ D 2.v /
(1.1)
where is the angular velocity of the rotating reference frame and v is the radial velocity of a particle relative to the center of the rotating reference frame. The Coriolis force can be expressed as: FCoriolis D 2m.v /
(1.2)
where m is the mass of the object causing the Coriolis force. Since the centripetal force is balanced by the Coriolis force on a body at a radial distance r from the center of a frame of reference, rotating with angular velocity , the relationship between and v is given by: v2 D 2v (1.3) r Substituting, v D !r ! D 2 (1.4) The Coriolis parameter .f / is defined as twice the vertical component of the earth’s angular velocity about the local vertical axis, and at latitude , and is given by: f D 2 sin
(1.5)
Due to the bending force of the Coriolis force, the following general direction for the prevailing wind results (Table 1.2). The prevailing wind sets the trend in speed and direction of wind over a particular point on the earth’s surface. The prevailing wind directions are important when determining sites for wind turbines; these should be placed in areas with least obstacles from the prevailing wind directions. Also, local geography should be taken into account since it will influence the performance of turbines.
Table 1.2 Prevailing wind directions Latitude Direction
90–60ı N NE
60–30ı N SW
30–0ı N NE
0–30ı S SE
30 60ı S NW
60 90ı S SE
8
1 Wind Energy
Table 1.3 Classes of wind power density at 10 m and 50 ma 10 m (33 ft) Wind power class 1 2
Wind power density (W=m2 ) 400
50 m (164 ft) Speedb m/s (mph) 7.0 (15.7)
Wind power density (W=m2 ) 800
Speedb m/s (mph) 8.8 (19.7)
a
Vertical extrapolation of wind speed based on the 1/7 power law. b Mean wind speed is based on the Rayleigh speed distribution of equivalent wind power density. Wind speed is for standard sea-level conditions. To maintain the same power density, speed increases 3%/1,000 m (5%/5,000 ft) of elevation [59].
Based on the wind speed, wind resources are categorized into seven classes. A wind-class refers to a range of wind power density and speed that describes the energy contained in the wind. The wind power classes are given in Table 1.3.
1.3 Wind Resource Map Areas designated as Class 4 or greater are suitable for the power generation using wind turbines that are currently available commercially. Areas with wind Class 3 areas may be suitable for future generation technology. Class 2 areas are marginal and Class 1 areas are unsuitable for wind energy development. The wind map for a country, a state, or a local area is generally available from the local government or designated authority. The wind resource map for the state of Missouri, USA is shown in Fig. 1.6. In the map, areas designate as 1, 2, or 3 are referred to as the wind class for that particular area. Class 3 wind that is essential for economical use of wind turbine is not available in most of the regions in Missouri, USA as shown in the wind map. This suggests that not necessarily all the areas within a country are suitable for wind power generation. The wind maps of the Europe and the USA are shown in Figs. 1.7 and 1.8, respectively. Similar maps for Denmark and England are shown in Figs. 1.9 and 1.10, respectively. Denmark is one of the leaders in utilization of wind power in Europe, and England is making rapid progress in utilization of wind power. It is considered that England may have the best wind resources among Europeans countries. Although several countries are considering wind energy for electricity generation,
1.3
Wind Resource Map
9
Fig. 1.6 Annual average wind power for Missouri, USA (Adapted from Wind Energy Resource Atlas of the United States [59])
according to Elliott [60], a major barrier to the deployment of the wind energy in many regions of the world is the lack of reliable and detailed wind resource data. Availability of this data is essential for the government and industry to identify wind power generation potential and to act on that knowledge. Wind resources assessment from the 1980s to early 1990s were used to produce wind atlases for the U.S. and the Europe [61, 62], and a worldwide wind resource map [63]. These maps have identified general areas of good wind resources and provided the basis for preliminary estimates of the wind-energy potential around the world. The US Department of Energy had also developed a worldwide wind resource map in 1985 using wind data compiled in 1980. It should be noted that much of the data underestimated the wind resources because of exposure problems and inadequate maintenance of the wind speed sensors (anemometers) that were use at that time. Many areas shown as Class 1 during the time of these studies actually have a better wind class than indicated. The availability of land in Class 4 and above is also critical, since this will determine the actual harvesting of wind energy of any country or region. As shown in Fig. 1.11, only a small percentage of land in the USA has above Class 3 wind on an annual basis. The land area for Class 3 wind is shown in Fig. 1.12.
10
1 Wind Energy
Fig. 1.7 Wind resource map of Europe (Printed with permission from Hau [3])
Even if a land mass has Class 3 or above wind, not necessarily all the land mass will be available for installation of wind turbines. Figure 1.13 shows the availability of land for installation of wind turbines if various restrictions are taken into account. In the US, when considering potential land area, 100% of federal and state environmentally sensitive lands were excluded from such consideration. These lands include parks, monuments, US Forest Service lands, wilderness areas and wildlife refuges. The available windy land area was further reduced when the primary lands
Wind Resource Map
Fig. 1.8 Wind resource map of the USA (Courtesy of National Renewable Energy Laboratory [57])
1.3 11
12
1 Wind Energy
Fig. 1.9 Wind resource map of Denmark (Printed with permission from Danish Energy Agency, Energy & Environmental Data [65])
used by a region was excluded. About 100 Quads of energy would be generated by this estimate with modest restriction. The percentage of type of land areas that would be excluded is given below: • • • • •
Forest – 50% excluded Agriculture – 30% excluded Range – 10% excluded Mixed Agriculture and Range – 20% excluded Barren – 10% excluded
1.3
Wind Resource Map
13
Annual mean wind speed at 25m above ground level [m/s] > 10.0 8.5 − 10.0 7.0 − 8.5 5.5 − 7.0 < 5.5
km 25 0
125 km
Fig. 1.10 Wind energy resource map for England (Adapted from The UK Wind resource Wind energy fact sheet 8) [64]
• Wetland – 100% excluded • Urban – 100% excluded • Water – 100% excluded Because of the change in exclusion methodologies, areas available for wind energy development are always changing.
Fig. 1.11 Percentage of land area with Class 3 or higher wind resources (Adapted from Elliot and Schwartz [66])
14 1 Wind Energy
Wind Resource Map
Fig. 1.12 Area with Class 3 wind in the USA (Courtesy of National Renewable Energy Laboratory) [57]
1.3 15
16
1 Wind Energy
Fig. 1.13 Wind energy potential in the contiguous US (Source: Schwartz and Elliot [67])
1.4 Land Area Requirement Once a site is found to be suitable for wind energy development, the availability of that particular land should be explored. The primary objective of a wind project design is to locate the wind turbines in the best wind sites to maximize energy production. A number of software packages are available to determine the placement of wind turbines at eligible sites (Wind Energy Finance, National Renewable Energy Laboratory, USA; RETScreen International Wind Energy, Canada; Job and Economic Development Model, EERL, US Department of Energy). Wind turbines are typically arranged in single or multiple rows, depending on the size and shape of the land. A single row is most often used on ridgelines and hilltops where the flat land is very limited. The distance between rows in complex terrain is typically dictated by the terrain characteristics. Multiple rows can be used in a broader and flatter land. In both cases, rows are laid out to be as perpendicular as possible to the prevailing wind direction(s). The main consideration in placing the wind turbines is the interference of one wind turbine from another turbine. The interference of a turbine by a downwind from another turbine is called the “wake effect” or “array effect”. If turbines are closely spaced, they will experience higher wake-effect-induced energy losses. Although wide spacing between wind turbines would maximize energy production, this would increase land requirement and other infrastructure requirements (i.e., cabling, roads). Therefore, the turbine spacing must be optimized to minimize the cost. The distance between wind turbines (between turbine rows and between turbines within a row) is commonly described in terms of rotor diameters. For example, if a
1.4
Land Area Requirement
17
Fig. 1.14 Spacing of wind turbines in a wind farm
project design is described as having 3 by 10 spacing, it means that the turbines are generally spaced 3 rotor diameters apart within rows, and the rows are spaced 10 rotor diameters apart (see Fig. 1.14). For a project using wind turbines with a 70 m (230 ft) rotor diameter, this would mean spacing the turbines 210 m (690 ft) apart within a row, and 700 m (2,300 ft) apart between rows. However, 3 by 10 spacing is not a fixed parameter. As can be seen from Table 1.4, the spacing can vary depending on the type of land and the location of the wind farm. For a wind farm, several wind turbines must be put together to generate the required power or electricity, increasing the total land requirements. Due to the low energy density of the wind energy, large land areas are required compared to conventional sources such as coal and nuclear. The land requirements for a 1;000 MWe system for various energy resources are given in Table 1.5. The land area was determined by local requirements and climate conditions (wind availability factors ranging from 20% to 40%). The energy density of fossil and nuclear fuel allows relatively small areas, 1–4 km2 . A number of assessments on land requirements for a wind farm are available in the literature from various agencies and are discussed below. According to the American Wind Energy Association (AWEA), in open flat terrain, the land area required is approximately 50 acres per MWe [58]. The land area also depends on the
18
1 Wind Energy
Table 1.4 Examples of turbine spacing in several wind farms in the USA Project location Madison, NY
Land use and type Farmed hilltop
Wethersfield, NY
Open farmland, north south ridgeline
Fenner, NY
Meyersdale, PA
Mixed farmland and woodlots on broad hill Ridgetop, farmland
Searsburg, VT
Forested ridgeline
Turbine layout Circular row of 7 turbines along hill rim Single north-south row of 10 turbines perpendicular to prevailing wind direction Variable layout of 20 turbines Single northeast-southwest row of 20 turbines Single northeast-southwest row of 11 turbines on ridge
Turbine spacing (rotor diameters) 4 Diameters between turbines 3 Diameters between turbines
Generally 5–7 diameters between turbines 3 Diameters between turbines Variable (1.5–3.5 diameters) between turbines
Source: Turbine verification program [68]
Table 1.5 A comparison of land requirement for a 1,000 MW(e) power plant Energy resource Land area Fossil and nuclear sites: 1–4 km2 Solar thermal or photovoltaic (PV) parks: 20–50 km2 (a small city) Wind fields: 50–150 km2 Biomass plantations: 4;000–6;000 km2 (a province) Source: Nuclear power advantages, Limited Environmental Impacts [69]
size of the wind turbine and the capacity factor. For example, a 1,000 MWe baseload plant would require over 3,400 MWe of widely dispersed wind generation capacity due to its low capacity factor of about 30%. Therefore, the land requirements should be calculated for installation of a 3,400 MWe system [70]. The USA National Renewable Energy Laboratory estimated that the “footprint” for a wind turbine would be typically between 0.25 and 0.50 acres (1,012 and 2;023 m2) per turbine. This estimate does not include the 5–10 turbine-diameter of spacing requirement between wind turbines. Also, “footprint” of land represents the land that has to be taken out of production to provide space for turbine towers, roads, and support structures. The area within the perimeter of the wind farm will be larger due to spacing of the turbines, but is still useable by the farm. According to the British Wind Energy Association (BWEA), a typical wind farm of 20 turbines would require an area of about 1 km2 , but only 1% of the land area would be used to house the turbines, electrical infrastructure and access roads; the remainder can be used for other purposes, such as farming or as a natural habitat.
Land Area Requirement
Fig. 1.15 A comparison of land area requirements for power plants based on the capacity and energy resources (Printed with permission from Gagnon et al. [72])
1.4 19
20
1 Wind Energy
To generate 10% of Britain’s electricity from the wind would require constructing around 12,000 MWe of wind energy capacity. The land requirement would be between 80,000 and 120,000 ha (0.3–0.5% of the UK land area). Less than 1% of this (800–1,200 ha) would be used for foundations and access roads, the other 99% could still be used for productive farming [71]. It should be noted that 1 ha is 10;000 m2. Gagnon et al. [72] assessed the land requirements for various types of electricity generation systems. Their finding is shown in Fig. 1.15.
1.5 Energy and Power from Wind The kinetic energy of wind is converted to mechanical or electrical energy using wind turbines. The amount of energy captured by the rotor depends on the density of the air, the rotor area, and the wind speed. This is schematically shown in Fig. 1.16. Power that is obtained from wind flowing at a certain speed may be calculated by assuming that a parcel of air is moving towards a wind turbine at a velocity of v as shown in Fig. 1.16. The kinetic energy (KE) of the air stream is given by: KE D
1 1 2 mv D a Va v2 2 2
(1.6)
Rotor Diameter (D)
where, m is the mass of the moving air, a is the density of the air, and Va is the volume of the air parcel. Since the air parcel will be swept away by the turbine, the
High velocity High kinetic energy
Fig. 1.16 Working principle of a wind turbine
Low velocity Low kinetic energy
1.5
Energy and Power from Wind
21
cross sectional area of the rotor (AT ) interacting with the air parcel and the velocity of air are critical in determining the power production, which can be expressed as: P D
1 a AT v3 2
(1.7)
This yields the theoretical power in a free flowing stream of wind. The actual power that is obtainable from a wind turbine is given by: 1 P D .CP "g "b / a AT v3 2
(1.8)
In Eq. 1.8: P D power in watts (746 W D 1 hp) (1;000 W D 1 kW) a D air density (about 1:225 kg=m3 at sea level, decreases with altitude) AT D rotor swept area, exposed to the wind .m2 / CP D coefficient of performance, also called power coefficient v D wind speed in meters/s .20 mph D 9 m=s/ "g D generator efficiency "b D gearbox/bearings efficiency The maximum theoretical value of CP possible is 0.593. This is also known as the Betz limit. The practical value of CP is in the range of 0.35–0.40. A value of greater than 0.80 is possible for "g if a permanent magnet generator or grid connected induction generator is used. The efficiency of gearbox and bearings can be greater than 95%.
1.5.1 Betz Limit Betz, a German physicist, in 1919, theoretically determined that a wind turbine can only convert 16/27 (59.3%) of the kinetic energy of the wind into mechanical energy by turning a rotor [73]. This is known as the Betz Limit or the Betz’s Law. Since the velocity at the rotor inlet (v1 ) is different from that at the outlet (v2 ), an average velocity was used to calculate the mass of the air streaming through the rotor per second (see Fig. 1.17) as follows: m D a AT
.v1 C v2 / 2
(1.9)
where Œ.v1 C v2 /=2 is the average wind speed through the rotor area. The power extracted from the wind by the rotor using the average wind speed is given by: P D
1 2 m v1 v22 2
(1.10)
22
1 Wind Energy
Fig. 1.17 Change in the velocity in a wind turbine 0.6 0.5
P/P0
0.4 0.3 0.2 0.1 0.0 0
0.2
0.4
V2 / V1
0.6
0.8
1
Fig. 1.18 Betz limit
Substitution of Eq. 1.9 into Eq. 1.10 provides: P D
a v21 v22 .v1 C v2 /AT 4
(1.11)
The total power in the wind .P0 / streaming through exactly the same area, AT , in the absence of the rotor can be written as: P0 D
a 3 v AT 2 1
(1.12)
The ratio of the two powers is given by: " 2 # P v2 1 v2 1 D 1C Po 2 v1 v1
(1.13)
1.6
Capacity Factor for a Wind Turbine
23
A plot of P =Po as a function of v2 =v1 is shown in Fig. 1.18. It shows that the curve passes through a maximum at 0.593 when v1 =v2 D 1=3. Therefore, according to Eq. 1.13, the maximum value for the power extracted from the wind is 0.593 or 16/27 of the total power in the wind.
1.6 Capacity Factor for a Wind Turbine The capacity factor of a wind turbine is the actual energy output for the year divided by the energy output if the turbine operated at its rated power output for the entire year. The output from a wind turbine depends on the wind speed through the rotor. The relationship between wind speed and rated power, called a power curve, is shown graphically in Fig. 1.19. The turbine starts to produce power only when a certain wind speed is reached (called cut-in wind speed). As the wind speed increases, the power output increases sharply. Similarly, at lower wind speeds, the power output drops off sharply. However, if the wind speed is above a certain value, the wind turbine is forced to remain idle. This is known as cut-out wind speed. The “rated wind speed” is the wind speed at which the “rated power (RF)” is achieved. There are two main options if the wind speed is above the rated wind speed. In one option, the power output above the rated wind speed is mechanically or electrically maintained at a constant level using an advanced control system. However, this is rather costly as the rotation of blades is hard to control. In the other option, the wind turbine is cut off from power production. Using the power curve, it is possible to determine roughly how much power will be produced at the average or mean wind speed prevalent at
Fig. 1.19 Dependence of power output of a turbine on wind speed
24
1 Wind Energy
a site. The power curve shown in Fig. 1.19 indicates that the turbine would produce about 20% of its rated power at an average wind speed of 15 mph (or 20 kW if the turbine was rated at 100 kW).
1.7 Energy Production While wind turbines are most commonly classified by their rated power at a certain wind speed, annual energy output is the most important measure for evaluating a wind turbine. The payout time for the wind turbine will depend on its energy production. The energy production can be calculated from the power production using: Energy D Power Time
(1.14)
In order to calculate expected energy output, the capacity factor of the turbine should be known. A reasonable capacity factor would be between 0.25 and 0.30. A very good capacity factor would be 0.40. Capacity factor is very sensitive to the average wind speed. When using the capacity factor to calculate estimated annual energy output, it is extremely important to know the capacity factor at the average wind speed of the intended site. The power curve can also be used to find the predicted power output at the average wind speed at the wind turbine site. By multiplying the rated power output by the capacity factor and the number of hours in a year, (8,760 h), an estimate of annual energy production can be obtained for a 100 kW turbine producing 20 kW at an average wind speed of 15 mph. The annual energy production would be: 100 kW.RP/ 0:20.RCF/ 8760.h/ D 175; 200 kWh where, RP is the rated power, RCF is the rated capacity factor, and h is hour. For accurate estimate of energy production, the wind distribution of the site should be known. If such data is not available, there are two common wind distributions functions that are used to make energy calculations for wind turbines: the Weibull distribution and a variant of the Weibull distribution, called the Rayleigh distribution that is thought to be more accurate at sites with high average wind speeds. Energy output is also influenced by the wind turbine design features, including cut-in and cut-out speeds. In most commercial operations, the turbine is shut down at the cut-out-speed to protect the rotor and drive train machinery from damage. Therefore, the wind turbine must be designed based on the characteristics of the site. Although the capacity factor of some wind turbines installed around 2006 approached 45% (Fig. 1.20), the average remained around 26%. The installed capacity of wind energy in the USA and its capacity factor is shown in Table 1.6. Only a small improvement in the averaged capacity factor is noticed from 2002 to 2006.
1.8
Turbine Types
25
Fig. 1.20 The improvement in capacity factor of wind turbines over the years (Courtesy of Wiser and Bolinger [74]) Table 1.6 The installed capacity of wind energy in the USA and the capacity factor
Year 2002 2003 2004 2005 2006
Installed capacity in MW 4,685 6,374 6,740 9,146 11,575
Net electricity generation in thousands kilowatt-hour 10,354,279 11,187,467 14,143,741 17,810,549 26,589,137
Capacity factor* 25.22936 20.03621 23.95523 22.23013 26.2228
Calculated based on 365 days, 24 h of continuous operation [74]
The increased capacity factor will lead to higher reliability and availability of the wind power and will reduce the need for stand-by excess capacity or energy storage systems.
1.8 Turbine Types Wind turbines can be divided into two categories based on the axis about which the turbine rotates: • Horizontal Axis Wind Turbines (HAWTs) • Vertical Axis Wind Turbines (VAWTs) The HAWTs generally can be designed for higher power. This is possible due to higher rotor diameters that can be used when designing HAWTs. The turbine capacity depends on the rotor diameter as shown in Fig. 1.21. As shown in Fig. 1.22, the rated power output from a single wind turbine has increased steadily over the past several decades. Currently, a single wind turbine
26
1 Wind Energy
Fig. 1.21 Relationship between power capacity and the rotor diameter (Printed with permission from Danish Wind Industry Association [75])
can theoretically generate 5 MW. This increase became possible due to development of wind turbines with a large rotor diameter. A rotor diameter of 124 m has been designed providing a power output of 5 MW.
1.8.1 Horizontal Axis Wind Turbines (HAWTs) The blades of horizontal-axis wind turbines spin in a vertical plane. During rotation, blades move more rapidly over one side, creating a low pressure area behind the blades and a high pressure area in front of it. The difference between these two pressures creates a force which causes blades to spin. The HAWTs have the main rotor shaft and electrical generator at the top of a tower, and are pointed into the wind. Small turbines are pointed by a simple wind vane, while large turbines generally use a wind sensor coupled with a servo motor. Most have a gearbox, which turns the slow rotation of the blades into a quicker rotation that is more suitable for generating electricity. The basic structure of a HAWT is shown in Fig. 1.23. There are several advantages of horizontal wind turbines. These are discussed below. • The design and location of blades provide a better stability of the structure. • The ability to pitch the rotor blades in a storm minimizes the damage.
1.8
Turbine Types
27
5000 kW f124 m
2000 kW f80 m
500 kW f 40 m 50 kW f15 m
1980
600 kW f50 m
100 kW f20 m
1985
1990
1995
2000
2003
Fig. 1.22 The increase in the wind turbine size over the years (Printed with permission from Leithead [23])
• The use of a tall tower allows access to stronger wind in sites with wind sheer and placement on uneven land. • The manufacturing cost can be less because of higher production volume, larger sizes and, in general, higher capacity factors and efficiencies. The disadvantages are: • tall towers and long blades (up to 180 ft long) are difficult to transport, • higher install costs, and • higher maintenance costs. Horizontal axis wind turbines are most widely used for commercial power generation. Currently three blade rotor systems are preferred; however, in the past both one blade and two blade wind turbines have been designed and tested (see Fig. 1.24). One-blade and two-blade wind turbines generate 15% and 5% less power than threeblade wind turbines, respectively. However, the main issue for using one-blade or two-blade systems is the stability of the turbine. More sophisticated and costly control mechanisms are necessary to make one-blade or two-blade turbines stable during rotation. Wind turbines with more than three blades (multi-blade) have also been explored, but no significant gain in costs or stability of multi-blade systems over three-blade turbines was achieved. Various multi-blade horizontal axis wind turbines and other proposed designs are shown in Fig. 1.25.
28
1 Wind Energy
Rotor Blade
Swept Area of Blades
Rotor Diameter
Nacelle with Gearbox and Generator
Hub Height Tower
Underground Electrical Connections (Front View)
Foundation (Side View)
Fig. 1.23 The basic schematic diagram of a horizontal axis wind turbine (Courtesy of European Security Network [76])
Fig. 1.24 One-blade and two-blade horizontal axis wind turbines (Printed with permission from Hau [3])
1.8
Turbine Types
29
Fig. 1.25 Various types of horizontal axis wind turbine
1.8.1.1 Wind Turbine Components The basic components of a wind turbine are as follows: • • • • • • • • • • • •
Nacelle Rotor blades Hub Low speed shaft Gearbox High speed shaft with its mechanical brake Electrical generator Yaw mechanism Electronic controller Tower Anemometer Wind vane
A diagram of a wind turbine with its components is shown in Fig. 1.26. A brief description of these components is given below.
Nacelle The nacelle contains the key components of a wind turbine, including the gearbox, and the electrical generator.
Rotor Blades The rotor blades capture the wind and transfer its power to the rotor hub. A 1,000 kWe wind turbine has rotor blades that are about 27 m (80 ft) in length. The blades or “rotors” catch the wind and cause the movement of the blades that turns
30
1 Wind Energy
Fig. 1.26 Various components of a wind turbine (Courtesy of National Renewable Energy Laboratory [57])
the shaft. The generator then turns this movement into electricity. Blades come in many sizes; as shown in Fig. 1.22, the longest blades in use today are about 62 m long (rotor diameter is 124 m). Hub The hub of the rotor is attached to the low speed shaft of a wind turbine. Low Speed Shaft The low speed shaft of a wind turbine connects the rotor hub to the gearbox. The rotor rotates at about 19–30 rotation per minute (rpm) in a 1,000 kWe wind turbine. The shaft contains pipes for the hydraulics system to enable the aerodynamic brakes to operate. Gearbox Gears connect the low-speed shaft to the high-speed shaft and increase the rotational speeds from about 19 to 30 rotations per minute (rpm) to about 1,000–1,800 rpm, which is required by most generators to produce electricity. The recent design uses “direct-drive” generators that operate at lower rotational speeds and do not need gear boxes.
1.8
Turbine Types
31
High Speed Shaft with Its Mechanical Brake This drives the generator and employs a disc brake, which can be applied mechanically, electrically, or hydraulically to stop the rotor in emergencies.
Electrical Generator The generator converts the mechanical energy of the rotating shaft into electrical energy.
Yaw Mechanism The turbines must face upwind for power production. The yaw drive is used to keep the rotor facing into the wind as the wind direction changes. Downwind turbines don’t require a yaw drive, since the wind blows the rotor downwind.
Electronic Controller The controller starts the machine at the specified wind speed which is generally between 8 and 16 miles per hour (mph) (3.58 and 7.15 m/s) and shuts off the machine at about 55 mph (24.6 m/s). Turbines do not operate at wind speeds above about 55 mph (24.6 m/s) because they might get damaged above this wind speed.
Tower The tower is a high stationary support structure for the wind turbine, so that consistent wind speed can be sustained for the operation of the turbine.
Anemometer It measures the wind speed and transmits wind speed data to the controller.
Wind Vane It measures wind direction and directs the yaw drive to appropriate orientation so that the turbine is properly aligned with respect to the wind direction.
32
1 Wind Energy
1.8.2 Vertical Axis Wind Turbines (VAWTs) The blades of vertical-axis wind turbines spin in a horizontal plane. VAWTs have the main rotor shaft running vertically. Various components of a VAWT are shown in Fig. 1.27. An advantage of this arrangement is that the generator and/or gearbox can be placed at the bottom, near the ground; therefore, a tower is not needed to support the turbine. Also, the turbine does not need to be pointed into the wind. The disadvantages are usually the pulsating torque that is produced during each revolution and the drag created when the blade rotates into the wind. The vertical axis turbines on towers need lower and more turbulent air flow near the ground. This type of condition is difficult to sustain resulting in a lower energy extraction efficiency. A variety of designs for VAWTs have been proposed and are described below.
THRUST BEARING GUY CABLE
ROTOR
BRAKES THRUST BEARING TORQUE SENSOR FLEXIBLE COUPLING SYNCHRONOUS GENERATOR SPEED INCREASER RIGHT ANGLE DRIVE
CLUTCH TORQUE SENSOR
INDUCTION GENERATOR
TIMING BELT
FLEXIBLE COUPLING
Fig. 1.27 Components of a vertical axis wind turbine (Adapted from Reuter and Worstell [77])
1.8
Turbine Types
33
Fig. 1.28 A Darrieus wind turbine (Printed with permission from Hau [3])
1.8.2.1 Darrieus Wind Turbine The most common type of VAWT is the Darrieus wind turbine. The design of these types of turbines looks like an eggbeater (Fig. 1.28). Generally, an external power source is required to start the rotation. The starting torque is very low. In the newer design, three or more blades are used which results in a higher solidity for the rotor. Solidity is measured by blade area over the rotor area. New Darrieus type turbines are not held up by guy wires, but have an external structure connected to the top bearing.
1.8.2.2 Savonius Wind Turbine The Savonius turbine consists of two half-cylinders mounted on a vertical shaft that has an S-shape appearance when viewed from the top. A schematic diagram of the
34
1 Wind Energy
Fig. 1.29 A savonius rotor for wind turbine (Printed with permission from Hau [3])
Savonius rotor is shown in Fig. 1.29. This drag-type VAWT turns relatively slowly, but yields a high torque. Because of the curvature, the scoops experience less drag when moving against the wind. The differential drag causes the Savonius turbine to spin. Most of the swept area of a Savonius turbine is near the ground, therefore, the overall energy extraction efficiency is lower. However, Savonius turbines are cheap and reliable.
1.8.2.3 Other Lift-Type Vertical Axis Configurations Darrieus also proposed another type of vertical axis wind turbine with straight vertical axis blades, called Giromills (Fig. 1.30). A variant of the Giromill, called the cycloturbine (Fig. 1.30b), uses a wind vane to mechanically orient a blade pitch change mechanism. The advantages of vertical axis wind turbines are: • The turbines are easy to maintain because most of their moving parts are located near the ground. • The rotor blades are vertical, therefore, a yaw device is not needed. • The vertical wind turbines have a higher airfoil pitch angle, giving improved aerodynamics while decreasing drag at low and high pressures. • The turbines are better suitable for Mesas, hilltops, ridgelines and passes as these locations can have higher wind speed near the ground. In these places, VAWTs placed close to the ground can produce more power than HAWTs placed higher up.
1.9
Comparison Between Turbines
35
Fig. 1.30 Lift type vertical wind turbine. (a) Giromill wind turbine (b) Cycloturbine (Courtesy of American Wind Energy Association [58])
• The turbine does not need a free standing tower. • The turbines have very high starting torque, therefore, these are better for water pumping. The disadvantages are: • The height and swept area may be limited. • Generally, a flat surface is necessary for their installation, otherwise the installation cost could be higher. • A strong structure is necessary to keep it straight, increasing the cost. • Most VAWTs produce energy at only 50% of the efficiency of HAWTs.
1.9 Comparison Between Turbines Wind turbines may be compared against each other by comparing their coefficient of performance (CP ) against tip speed ratio ( ). Various forces working on a turbine are shown in Fig. 1.31. The coefficient of performance, also known as the power coefficients, is defined by Eq. 1.15. CP D
P P0
(1.15)
36
1 Wind Energy
Fig. 1.31 The angular velocity of a wind turbine rotating in a horizontal axis
where, P and P0 are defined by Eqs. 1.11 and 1.12. Using the swept area and substituting the value of P0 ; P may be expressed as: P D
1 a r 2 v3 CP 2
(1.16)
The performance of the wind turbine depends on the wind speed and the rate of rotation of the rotor. The Tip Speed Ratio () refers to the ratio between the wind speed and the speed of the tip of the wind turbine blades and is expressed as: Tip Speed Ratio; D
Speed of rotor tip vr !r D D Wind speed v v
where, v D the wind speed (m/s) vr D velocity of rotor tip (m/s) r D rotor radius (m) ! D angular velocity (radian/s) and is given by ! D 2f f D frequency of rotation (Hz), Sec1 .
1.9
Comparison Between Turbines
37
Example 1.1. Consider a wind turbine of rotor diameter 20 m, rotating at a speed of one rotation per second. Calculate the tip speed ratio () for this turbine. Solution. Given, f D 1 rotation/s; rotor diameter D 20 m; therefore, radius r D 10 m; calculate !. ! D 2f D 2 1 radian=sec D 2 radian=sec v D !r D 2 10 D 20 m=sec D
20 !r D D 4:19 v 15
The tip speed ratio is an important factor in designing the wind turbine. The rotor must rotate at an optimum speed to maximize its efficiency. If the turbine rotates slowly, it will not catch any wind. The wind will simply pass unperturbed through the gap between the blades. If the turbine rotates at a very high speed, it will behave like a solid wall to the wind passage. Therefore, the turbine design must be optimized. Both the design of the blades (rotor airfoil profile) and number of blades play a critical role in optimization of a turbine’s performance. In general, a high tip speed ratio is desirable since it results in a high shaft rotational speed, which in turn can increase the efficiency of the electrical generator. The optimum value of tip speed ratio .opt / can be approximated by the following expression. opt
!opt r 2 v n
r AT
(1.17)
where n is the number of blades. The ratio (r=AT ) is generally 2, therefore, opt
4 n
(1.18)
The power coefficients (CP ) for various turbines are plotted against tip speed ratio () in Fig. 1.32. As can be seen from this figure, HAWTs with three-blade has the best power coefficient. Among VAWTs, Darrieus turbine has the highest power coefficient, and Savonius rotor has the lowest value. For most of the commercial applications, threeblade HAWTs are preferred. As mentioned earlier, a high tip speed ratio is desirable, but there are a number of disadvantages for operating a turbine at high . 1. A high rotating speed can cause erosion of the blades from impact with dust or sand particles in the air. 2. The level of noise increases, both in the audible and non-audible ranges. 3. The vibration also increases, and there is a chance of a catastrophic failure.
38
1 Wind Energy
Fig. 1.32 A plot of rotor power coefficient as a function of tip speed ratio for various turbines (Printed with permission from Hau [3])
1.10 Cost of Electricity from Wind Energy The cost of a wind energy system has two components: initial installation costs and operating expenses. The initial installation costs include the purchase price of the complete system, including turbine, tower, wiring, utility interconnection or battery storage equipment, and power conditioning unit. Installation costs also include foundations, normally made of reinforced concrete, road construction (necessary to move turbines and sections of the tower to the building site), a transformer (necessary to convert the low voltage (690 V) current from the turbine to 10–30 kV current for the local electrical grid), telephone connection for remote control and surveillance of the turbine, and cabling costs, i.e. the cable from the turbine to the local 10–30 kV power line. The delivery and installation charges, professional fees and sales tax are also part of these overall cost. The total installation costs of a wind energy system are generally expressed on the basis of electricity generation capacity. A grid-connected residential-scale system (1–10 kW) generally costs between $2,400 and $3,000 per installed kilowatt. A commercial system (10–100 kW) costs between $1,500 and $2,500/kW. However, these numbers are very dynamic and depend on a host of variables such as cost of fuels, energy price, metal price, labor costs, etc. Large-scale systems of greater than
1.10
Cost of Electricity from Wind Energy
39
Fig. 1.33 The total installation cost of a wind turbine based on its rated power (Courtesy of Wind Energy Manual, Iowa Energy Center [78])
Fig. 1.34 The history of installed project cost for wind turbines in the USA (Courtesy of Wiser and Bolinger [74])
l00 kW cost in the range of $1,000–$2,000/kW. The installed cost may be lower if multiple units are installed at one location. Figure 1.33 shows the installed cost range as a function of electrical generation capacity. A wind energy system in remote locations generally needs an operating battery storage, resulting in installed cost in the range of $4,000–$5,000/kW. A further analysis of the installed cost from 227 projects around the USA showed an upward trend in 2006–2007 compared to previous years. This analysis is shown in Fig. 1.34. The increase in the installation costs has been attributed to the increased cost of materials and metals.
40
1 Wind Energy
3.0 2003 2.5
2004 2005
2.0
2006 2007
1.5 1.0
S U
U
C an D ad en a m a Fi rk nl a G n er d m a G ny re e Ire ce la nd Ita ly N Ja et pa he n rla n N ds or w Po ay rtu ga Sp l S ai Sw we n itz de er n la nd
0
K
0.5
Fig. 1.35 Investment cost for wind energy systems in selected countries for 2006–2007 (Courtesy of International Energy Agency [79])
A similar trend was observed in other countries (see Fig. 1.35). A major component of the installation cost is the turbine cost. The costs of turbines have decreased by a factor of four since the early 1980s until 2004, but costs have increased by 20–80% by 2006. This is mainly due to the supply tightness of turbines, gear boxes, blades, bearings, and towers. Higher steel and copper prices contributed to this short supply of wind turbine components and their price increase. Total installed costs including turbine ranged from US$ 1,400/kW in the UK to US$ 2,700/kW in Ireland. The second component, operating costs, includes maintenance and service, insurance and other applicable taxes. Estimates for annual operating expenses are 2–3% of the initial system cost. Other estimates are based on the system’s energy production and are equivalent 1–2 cents/kWh of output. The U.S. wind energy industry, electric utilities, and the federal government are working together to develop low-cost, technologically advanced wind turbines. As can be noted from Fig. 1.36, the cost of electricity production from wind energy has decreased significantly in the last decade. The technology improvements have allowed the wind industry to achieve its goal for the cost of electricity generation at an average of 5 cents/kWh by the mid-1990s at sites with 5.8 m/s (13 mph) average annual wind speeds. This cost target was set by the US Department of Energy. New turbine design and development helped to lower the cost to 3.9 cents/kWh by 2006. The target is to achieve a cost of 3.6 cents/kWh by 2012. However, as shown in Fig. 1.37, the average production cost started to increase again in 2006–2007 due to the rising installation costs. Also, a significant variation in the production cost remained. The Energy Efficiency and Renewable Energy
1.10
Cost of Electricity from Wind Energy
41
Fig. 1.36 Cost of electricity produced from wind energy
Fig. 1.37 Average cumulative wind and wholesale power prices over time (Courtesy of Wiser and Bolinger [74])
Division of US Department of Energy conducted a detailed study of costs associated with the production of electricity from wind energy. The cost analysis was carried out under a number of scenarios, as discussed below. The cumulative capacity weighted average wind power price (plus or minus one standard deviation around that price) in each calendar year from 1999 to 2007 is shown in Fig. 1.38. The increase in weighted average wind price in 2006 and 2007 is attributed to higher installation and operating costs of new projects. The number of wind energy systems in the USA increased from 14 to 21, with the installed capacity increasing from 766 to 2,502 MW. Although the overall installation cost increased, as can be seen from Fig. 1.39, the wind power prices did not increase, rather decreased slightly. In Fig. 1.40 is shown the regional variation of wind power price of the projects constructed between 2006 and 2007. The lowest wind generated electricity price was from a Texas project, whereas it was the highest in the eastern region. This regional variation of the wind price is shown in Fig. 1.41.
42
1 Wind Energy
Fig. 1.38 Cumulative capacity-weighted average wind power price over time (Courtesy of Wiser and Bolinger [74])
Fig. 1.39 Wind power prices by commercial operation date (COD) (Courtesy of Wiser and Bolinger [74])
Fig. 1.40 Wind power prices by region in 2007 for projects installed in 2006–2007 (Courtesy of Wiser and Bolinger [74])
The annual operating cost for large onshore turbines worldwide in 2006, including insurance, regular maintenance, spare parts, repair and administration was in the range of US$ 0.014–0.026/kWh. The operating and maintenance costs are considerably higher for offshore wind turbines. For wind powers to be competitive with conventional electricity generators (i.e., coal and nuclear), sites must have
1.10
Cost of Electricity from Wind Energy
43
Fig. 1.41 Wind and wholesale power prices by region for projects installed over 1998–2007 (Courtesy of Wiser and Bolinger [74])
Fig. 1.42 Wind power production costs as a function of the wind resource and investment cost (Courtesy of International Energy Agency [79])
extremely good wind resource as well as nearby grid access. Typical production costs, levelized over turbine lifetime, with a discount rate of 7.5% are shown in Fig. 1.42 for two installation costs; US$ 1,640/kW and US$ 2,300/kW. The production cost was estimated to be from US$ 0.075/kWh to 0.097/kWh, at high to medium quality wind resource sites.
1.10.1 Payback Time for Wind Energy Systems The financial benefit of a wind system investment may be determined by estimating the payback period, which is calculated from the expression given below. Payback time .years/ D
Total annual cost Annual energy cost savings Annual operating costs
44
1 Wind Energy
Example 1.2. Calculate payback time for a 5 kW residential system and a 50 kW commercial system. Solution. It is assumed that the installation cost for residential system is $3,000/kW installed. It is $2,000/kW for the commercial system. The capacity factor is 30% and the cost of electricity is 6 cent/kWh. The installed cost is given by: Residential 5 kW system D $15;000 Commercial 50 kW system D $100;000 The annual electricity generation will be: Residential 5 kW system D 5 365 24 0:30 D 13; 140 kWh Commercial 50 kWsystem D 50 365 24 0:30 D 131; 400 kWh The annual energy-cost savings from both systems would be: Residential $0:06=kWh 13; 140 kWh D $788:50 Commercial $0:06=kWh 100; 000 kWh D $7885:00 Annual operating costs are assumed to be 1.5 cent/kWh. Therefore, annual operating costs are: Residential $0:015=kWh 13; 140 kWh D $197 Commercial $0:015=kWh 131; 400 kWh D $1; 970 The residential payback period will be: $15; 000=.$788:5 $197/ D 25years Commercial payback period: $100; 000=.$7885 $1; 970/ D 17years The above example reflects a simple calculation procedure for the payback period. A more detailed calculation could be performed which would include the following: • • • • •
interest paid on borrowed money insurance utility buy-back, if any state and federal tax benefits wind turbine salvage value, if any
1.10
Cost of Electricity from Wind Energy
Table 1.7 Comparative generating cost in European Union with 10% discount rate (US cent/kWh) (used 1 euro D 1.44 USD)
Gas CCGT Coal – pulverised Coal – fluidised bed Coal IGCC Nuclear Wind onshore Wind offshore
45
2005 4.9–6.5 4.3–5.8 5.0–6.5 5.8–7.2 5.8–7.9 5.0–15.8 8.6–21.6
Projected 2030 with USD 29 43=t CO2 cost 5.8–7.9 6.5–8.6 7.2–9.4 7.9–10.1 5.8–7.9 4.0–11.5 5.8–17.3
Source: World Nuclear Organization [80]
Table 1.8 A compilation of electricity cost (US cent/kWh) from various studies MIT 2003 France 2003 UK 2004 Chicago 2004 Canada 2004 Nuclear 4.2 3.7 4.6 4.2–4.6 5.0 Coal 4.2 5.2 3.5–4.1 4.5 Gas 5.8 5.8, 10.1 5.9, 9.8 5.5–7.0 7.2 Wind onshore 7.4 Wind offshore 11.0
EU 2007 5.4–7.4 4.7–6.1 4.6–6.1 4.7–14.8 8.2–20.2
First 5 gas row figures corrected for Jan 2007 US gas prices of $6.5/GJ (second figure for France & UK columns is using EU price of $12.15/GJ). Chicago nuclear figures corrected to $2,000/kW capital cost. Canada nuclear shows figures for Advanced CANDU Reactor (ACR). Currency conversion at June 2007 [80]
The calculation procedure for an economic analysis of a project of this type has been discussed in Chap. 2 of Volume 1 of this book series. Although the payback time for a commercial wind energy system is close to that of conventional electricity generating systems, still the production cost could be higher than coal and nuclear energy based power plants. Careful selections of sites for wind power systems may compete with coal or nuclear, but such sites are generally rare in most of the countries. A cost comparison among various electricity generating systems in Europe is given in Table 1.7. The World Nuclear Organization also compiled the data reported by various agencies at different countries on the costs of generating electricity from various energy sources. The electricity cost adjusted for 2007 from various studies is given in Table 1.8.
1.10.2 Cost Reduction Efforts As shown in Fig. 1.43, the major cost of a wind power system is the turbine cost. Researchers are working closely with turbine manufacturers to continually improve turbine performance. In addition to laboratories and field tests, researchers provide
46
1 Wind Energy
Insurance (1%)
Legal Cost (2%)
Interest During Construction (2%)
Bank Fees (1%)
Installation (1%)
Development Cost (1%)
Project Management (1%) Grid Connection (6%) Electrical Infrastructure (8%)
Civil works (13%)
Wind turbines (64%)
Fig. 1.43 Cost distribution of various components of a wind power system (The data are averaged from Ref. [81])
Fig. 1.44 Various types of airfoil designed by NREL for use in wind turbine (Courtesy of Advanced aerofoil for wind turbines [82])
independent technical design reviews, analysis and support to meet specific design challenges, and project management. Participating wind turbine manufacturers are also required to contribute a substantial share of research project costs, report regularly on progress, meet specific milestones, and complete project deliverables. There
1.11
Effect of Capacity Factor
47
are two major thrusts for cost reduction: the development of innovative components and subsystems for incorporation into wind turbines, and the development of nextgeneration, utility-grade turbines that use the latest advanced technology. In the USA, National Renewable Energy Laboratory (NREL) is leading the effort to design wind turbine blades to enhance the turbine performance. Since 1984, NREL researchers have developed nine families of thick and thin airfoils, crosssectional blade shapes, for wind turbine blades (Fig. 1.44). Using NREL-designed airfoils on stall-controlled turbine rotors, an increase in energy capture by 23–35% has been observed during field tests. NREL expects the new airfoil family will further improve annual energy capture by 8–10%.
1.11 Effect of Capacity Factor Capacity factor can be used to measure the productivity of a wind turbine and to compare it with other power production facilities. It compares the plant’s actual production over a given period of time with the amount of power the plant would have produced, if it had run at full capacity for the same amount of time and is expressed as: Capacity Factor D
Annual amount of power produced over time Power that would have been produced if turbine operated at maximum output 100% of the time
The capacity factor for several electricity generating power plants is given in Table 1.9. The capacity factor is a major contributor to the cost of electricity from the wind energy. Although the efforts are underway to increase the capacity factor, various studies try to identify the areas that need improvement for reduction of cost. Several researchers have reviewed the wind energy costs and its competitive edge with
Table 1.9 Capacity factor for various electricity generating systems
Fuel type Average capacity factors (%) Nuclear 91.8 Coal (steam turbine) 71.8 Gas (combined cycle) 43.3 Gas (steam turbine) 16.0 Oil (steam turbine) 19.6 Hydro 27.8 Wind 30.4 Solar 19.8 Source: Global Energy Decisions/Energy Information Administration [83]
48
1 Wind Energy
other energy sources [84–87]. However, the best way to assess the cost of the wind energy is to perform a life-cycle assessment of the complete system [88–93]. These studies noted that the payback time is very competitive to other conventional energy sources.
1.12 Industrial Wind Turbines Vestas Wind Systems, Denmark, and General Electric (GE), USA are currently dominating the market for industrial wind turbines, both in the USA and in the world. There are several other manufacturers in the USA and are listed in Table 1.10. As noted in Fig. 1.43, for a wind energy system, most of the cost is for a wind turbine. Accordingly, researchers are working in various areas to improve the turbine performance so that it becomes more efficient and cost effective. The areas of research include development of large turbines [94–97], new materials for turbine blades [98–109], modeling and analysis of wind turbine performance [110–116], airfoil design [117–120], and improvement of the power curve [121–135].
1.13 Basic Principles of Wind Resource Evaluation Wind resources evaluation is a critical element for turbine performance at a given site. Proper siting of the wind turbine is critical as the wind flow itself is seldom steady and consistent. It varies with the time of day, season, height above ground, and the type of terrain. Therefore, the siting of turbines should be in windy locations, away from large obstructions [136–146]. Both the aesthetic impact and wind turbulence, such as wake effects, must be taken into account when selecting a site for wind turbines. In general, an annual average wind speed of 5 m/s (11 mph) is required for gridconnected applications. An annual average wind speed of 3–4 m/s (7–9 mph) may be adequate for non-grid connected electrical and mechanical applications, such as battery charging and water pumping. Wind power density is a useful way to evaluate the wind resource available at a potential site. The wind power density, measured in watts per square meter, indicates how much energy is available at the site for conversion by a wind turbine. It may be noted that the energy available in a wind stream is proportional to the cube of its speed, which means that doubling the wind speed increases the available energy by a factor of eight. According to Jenkins [148], before selecting a site and layout of wind turbines, following attributes of a site should be considered: • A high mean annual wind speed. • A low turbulence (i.e., smooth undisturbed wind flow). • A remote location from habitation.
1.5 MW
2.3 MW
2.5 MW
2.7 MW
1.65 MW
GE 1.5sl
GE 2.3
GE 2.5
GE 2.7
Vestas V82 Vestas V90 Vestas V100 Vestas V90 Gamesa G87 Bonus (Siemens)
1.3 MW
2.0 MW
3.0 MW
2.75 MW
1.8 MW
1.5 MW
GE 1.5s
35.25 m (116 ft) 38.5 m (126 ft) 47 m (154 ft) 44 m (144 ft) 42 m (138 ft) 41 m (135 ft) 45 m (148 ft) 50 m (164 ft) 45 m (148 ft) 43.5 m (143 ft) 31 m (102 ft)
64.7 m (212 ft) 80 m (262 ft) 100 m (328 ft) 85 m (279 ft) 70 m (230 ft) 70 m (230 ft) 80 m (262 ft) 80 m (262 ft) 80 m (262 ft) 78 m (256 ft) 68 m (223 ft)
99.95 m (328 ft) 118.5 m (389 ft) 147 m (482 ft) 129 m (423 ft) 112 m (336 ft) 111 m (364 ft) 125 m (410 ft) 130 m (427 ft) 125 m (410 ft) 121.5 m (399 ft) 99 m (325 ft)
Table 1.10 Manufacturers of wind turbines and various related information Blade Model Capacity lengtha Hub htb Total ht 3,904 m2 (0.96 acre) 4,657 m2 (1.15 acre) 6,940 m2 (1.71 acres) 6,082 m2 (1.50 acres) 5,542 m2 (1.37 acres) 5,281 m2 (1.30 acres) 6,362 m2 (1.57 acres) 7,854 m2 (1.94 acres) 6,362 m2 (1.57 acres) 5,945 m2 (1.47 acres) 3,019 m2 (0.75 acres)
Area swept by blades
13/19
138 mph
194 mph
200 mph
9–19 9/19
179 mph
157 mph
138 mph
177 mph
170 mph
164 mph
184 mph
183 mph
Max blade tip speedc
7.2–15.3
8.8–14.9
8.0–14.4
6.0–18.0
5.5–16.5
5.0–14.9
10.1–20.4
11.1–22.2
Rpm range
12 m/s (27 mph) 11.8 m/s (26 mph) 14 m/s (31 mph) 14.5 m/s (32.5 mph) 15 m/s (34 mph) 13 m/s (29 mph) 11 m/s (25 mph) 15 m/s (34 mph) 15 m/s (34 mph) c. 13.5 m/s (30 mph) 14 m/s (31 mph) (continued)
Rated wind speedd
1.13 Basic Principles of Wind Resource Evaluation 49
2.0 MW
2.5 MW (4 650 KW)
1.25 MW
0.95 MW
38 m (125 ft) 41.2 m (135 ft) 32 m (105 ft) 32 m (105 ft) 44.5 m (146 ft) 46.5 m (153 ft) 46.25 m (152 ft)
Blade lengtha
100 m (328 ft)
60 m (197 ft) 80 m (262 ft) 65 m (213 ft) 73 m (240 ft) 80 m (262 ft)
Hub htb 98 m (322 ft) 121.2 m (398 ft) 97 m (318 ft) 105 m (344 ft) 124.5 m (409 ft) 126.5 m (415 ft) 146.25 m (480 ft)
Total ht 4,536 m2 (1.12 acres) 5,333 m2 (1.32 acres) 3,217 m2 (0.79 acres) 3,217 m2 (0.79 acres) 6,221 m2 (1.54 acres) 6,793 m2 (1.68 acres) 6,720 m2 (1.66 acres)
Area swept by blades
7.8–15.0
9.7–15.5
13.9/20.8
13.9/20.8
11/17
11/17
Rpm range
163 mph
168 mph
156 mph
156 mph
164 mph
151 mph
Max blade tip speedc
c. 15 m/s (c. 34 mph) c. 15 m/s (c. 34 mph) 11 m/s (25 mph) 12 m/s (27 mph) c. 11.5 m/s (c. 26 mph) c. 12.5 m/s (c. 28 mph) 11.2 m/s (25 mph)
Rated wind speedd
Source: Rosenbloom [147] a This figure is actually half the rotor diameter. The blade itself may be about a meter shorter, because it is attached to a large hub b Where different hub (tower) heights are available, the usually used size is presented c Rotor diameter (m) rpm 26:82 d The rated, or nominal, wind speed is the speed at which the turbine produces power at its full capacity. For example the GE 1.5s does not generate 1.5 MW of power until the wind is blowing steadily at 27 mph or more. As the wind falls below that, power production falls exponentially. Vestas models can be found at www.vestas.com, GE models at www.gepower.com/businesses/ge wind energy/en, Siemens Bonus models at www.powergeneration.siemens.com/en/ windpower/products, Suzlon models at www.suzlon.com./product overview.htm, Clipper models at www.clipperwind.com, REpower models at www.repower. de/index.php?id=12&L=1. Enercon, Fuhrl¨ander, Mitsubishi, Nordex, and Ecot`ecnia are also major manufacturers, but their turbines do not appear to be currently used in the U.S
REpower MM92
2.0 MW
Bonus (Siemens) Bonus (Siemens) Suzlon 950 Suzlon S.64/1250 Clipper Liberty
2.3 MW
Capacity
Model
Table 1.10 (continued)
50 1 Wind Energy
1.14
Wind Farm
51
• An area having good access for heavy transportation off a public road. • A high-voltage connection to the distribution network. • A site for enough turbines to spread the administrative and legal cost of the project. • An enthusiastic land owners and general land support. • A site with no impediments or restriction to construction.
1.14 Wind Farm A wind farm is a collection of wind turbines in the same location and is used for the generation of large amount of electricity. One such farm is shown in Fig. 1.45. Even if all the individual wind turbines are rated same, the power production generally varies from one turbine to another turbine. The operation and power management is rather complex and sophisticated electrical circuitry and load management is necessary before feeding to the grid [149]. Due to the variability of the power production and the quality of the power, the integration of the wind farm to the power grid is complicated. A number of studies have addressed this issue and different techniques and methods for the grid integration have been suggested [150– 160]. Although a number of large wind farms have been developed, by themselves, wind farms are not suitable for base-load electricity supply. This is because wind
Fig. 1.45 The wind farm near Palm Springs, California, USA [162]
52
1 Wind Energy
power output is variable and unpredictable with sufficient accuracy as it depends on the wind resources, which cannot be controlled. Therefore, the base load still has to be supplied by coal-fired or nuclear power plants. The design of wind farms is challenging. Steps involved in building a wind farm are given below [161]. 1. Understand Your Wind Resource A site must have a minimum annual average wind speed in the neighborhood of 11–13 mph to even be considered. Local weather data and wind maps for the area should be studied. In the USA, state wind maps are available at http://rredc.nrel.gov/ wind/pubs/atlas/. 2. Determine Proximity to Existing Transmission Lines The existing transmission lines and its availability should be determined. Installation of new high voltage lines can cost thousands of dollars per mile. Whenever possible, availability and access to existing lines should be considered in selecting a site. 3. Secure Access to Land The area should be accessible through roads. Also, the developer should be allowed to make it restricted area during construction period and thereafter if necessary. 4. Establish Access to Capital Building a wind farm is not cheap. On average, the development of the wind power costs around $1 million per megawatt (MW) of generating capacity installed. Therefore, the developer must secure sufficient cash flow for both installation and operation until the generation of revenue. 5. Identify Reliable Power Purchaser or Market Local power purchasers and distributors should be contacted and also a survey of the local market for power should be conducted. 6. Address Sitting and Project Feasibility Considerations Various other factors need to be addressed before finalizing the location and the technical feasibility. These include impact on endangered or protected species (if any), site’s geological suitability, effect of noise and aesthetics issues to the local community, local air traffic, and other issues related to site development, such as roads. 7. Understand Wind Energy’s Economics The economic feasibility and payback time should be determined. 8. Obtain Zoning and Permitting Expertise The county, city, and the state should be consulted for permitting purpose and any concern should be addressed before starting the construction. 9. Selection of Turbine The selection of turbines should take into account the required generation capacity, site specific design criteria, and costs.
1.14
Wind Farm
53
10. Secure Agreement to Meet Operating and Maintenance Needs An agreement should be in place for regular maintenance of the wind turbines and also for emergency response. In order to assure continuous power supply, a separate power generation facility that can be put on-line and ramped up in approximately the same time that wind power diminishes is necessary. Such power generation systems are generally more expensive per unit of electricity generated than base-load generators. Several solutions have been proposed to address this issue. These are: pumped-storage hydroelectricity, and the use of rechargeable flow batteries as a rapid-response storage medium [163]. Vanadium redox flow batteries are currently installed at Huxley Hill wind farm (Australia), Tomari Wind Hills at Hokkaido (Japan), as well as in other non-wind farm applications. A further 12 MWh flow battery is to be installed at the Hill wind farm (Ireland) to address the intermittent power generation.
1.14.1 Offshore Wind Farm Offshore wind farms are generally located about 10 km or more from the land. Offshore wind turbines are less obtrusive than turbines on land. The wind resources in the water are much more consistent compared to land. Also, the average wind speed is usually considerably higher over open water and capacity factors are considerably higher than for onshore locations. Among various countries, Denmark and England are making significant push towards the development of offshore wind energy systems; in addition, a number of other countries in Europe and the USA are also exploring and investing in its development. The offshore wind resource potential in the USA and in Europe are shown in Figs. 1.46 and 1.47, respectively. In the USA, the wind resource increases significantly if the depth is extended up to 900 m. In Europe, a depth of 200 m is sufficient for significant wind power generation. Just like onshore wind farms, a number of wind turbines are lined up in an array to build the offshore wind farm. Such an arrangement is shown in Fig. 1.48. One significant difference between an offshore and an onshore wind farm is that only HAWTs are used in offshore farms since they are easy to install and also they provide highest capacity. The installation of wind turbines offshore involves several steps. These steps are explained schematically in Fig. 1.49. Following identification of a location for an offshore wind farm, the turbines are anchored in the seabed. Various types of anchoring methods have been suggested and are discussed later. However, the current practice is to drive piles (1) into the seabed. Often, the top of the foundation is painted with a bright color to make it visible to ships and has an access platform to allow maintenance teams to dock. The fully assembled turbines are installed by a support structure and secured on the top of poles. The turbine blades (2) rotate around a horizontal hub, which is connected to a shaft inside the nacelle (3). The power generated by turbines is transmitted by
54
1 Wind Energy
Resource Not Yet Assessed Fig. 1.46 Potential offshore wind power in the USA (Courtesy of Robinson [164])
subsea cables (4) to an offshore transformer (5) which converts the electricity to high voltage (33 kV) before connecting to the grid at a substation on land (6). One of the main concerns of offshore wind turbines is the extreme weather conditions to which they will be exposed. In Fig. 1.50 are illustrated these adverse conditions. Turbines must be designed to withstand and survive under these conditions. Wind gusts up to 55 mph (88.5 km/h) are very common. Under these conditions, the blades of the turbine can fold down and remain idle. One of the main challenges of offshore wind turbines is its installation in the seabed. Among several methods for anchoring a wind turbine in the seabed, a monopole is most widely used. The details of a monopole structure used in Horns Rev wind farm, Denmark, are shown in Fig. 1.51. About 22–25 m of the tower is below the sea level and requires the use of corrosion resistant materials. Often stainless steel is used for the tower construction with various corrosion protection measures, such as painting, to ensure long life of various components of the structure. A tripod fixed bottom or a floating structure as shown in Fig. 1.52 has been proposed for installations at greater depths. Currently, the USA is pursuing the floating structure concept, whereas Denmark is developing trifloater concept as shown in Fig. 1.53. Recently, reduced transmission constraints, steadier and more energetic winds, and recent European success are making offshore wind turbines attractive worldwide. Some of the disadvantages include higher development and investment costs, and limited accessibility, resulting in higher capital and maintenance costs. Also, environmental conditions at sea are more severe: more corrosion from salt water
1.14
Wind Farm
55
500km
Wind resources over open sea (more than 10km offshore) for five standard heights 50m 100m 200m 10m 25m ms−1 W m−2 ms−1 W m−2 ms−1 W m−2 ms−1 W m−2 W m−2 ms−1 >1100 >1500 >8.0 >600 >8.5 >700 >9.0 >800 >10.0 >11.0 7.0−8.0 350−600 7.5−8.5 450−700 8.0−9.0 600−800 8.5−10.0 650−1100 9.5−11.0 900−1500 6.0−7.0 250−300 6.5−7.5 300−450 7.0−8.0 400−600 7.5 − 8.5 450−650 8.0 − 9.5 600−900 4.5−6.0 100−250 5.0−6.5 150−300 5.5−7.0 200−400 6.0 − 7.5 250−450 6.5 − 8.0 300−600 50 m)
Medium (10–50 m)
Low ( 4;000. The value of friction factor, f , is dependent on the Reynolds number. In a laminar flow, f , can be calculated by the equation: 64 64 D VD NRe
(3.10)
32 L V 64 L V 2 D VD D 2g g D2
(3.11)
f D Therefore, head loss, hf , is given by: hf D
For turbulent flow, the surface roughness of the pipe affects the friction factor significantly. The surface roughness is defined as e=D, where e represents the average roughness height of the pipe wall and D is the pipe diameter. The average value of e for different pipe materials is given in Table 3.7. An explicit form for the friction factor is not available. Von Karman [131] suggested the following empirical equation, if the pipe is considered hydraulically smooth but the flow is turbulent. p ! NRe f 1 p D 2 log10 (3.12) 2:51 f
3.10
Calculation of Power from Water Flow
Table 3.7 The value of roughness height, e, for several materials
199
Pipe materials Polyethylene Fiberglass with epoxy Seamless commercial steel (new) Seamless commercial steel (light rust) Seamless commercial steel (galvanized) Welded steel Cast iron (enamel coated) Concrete (steel forms with smooth joints) Riveted steel Concrete Wood stave Cast iron Galvanized iron Asphalted cast iron Commercial steel (wrought iron) Drawn tubing
e .mm/ 0.003 0.003 0.025 0.250 0.150 0.600 0.120 0.180 0.9–4.0 0.3–3.0 0.18–0.9 0.25 0.15 0.12 0.045 0.0015
Source: European Small Hydropower Association (ESHA) [134]
If the pipe is rough and the flow is turbulent, the friction factor may be estimated from the following equation: 1 D p D 2 log10 3:7 e f
(3.13)
Colebrook and White [132] also proposed an expression for calculation of friction factor for the entire range of pipe roughness, which is given below: 1 p D 2 log10 f
2:51 e=D C ıp 3:7 NRe f
! (3.14)
Although the friction factor can be calculated from Eqs. 3.12 and 3.14 by a trial and error method, Moody [133] provided a graphical approach for determining the friction factor. The Moody chart, better known as “Friction Factors For Pipe Flow” is included in Appendix XIII. The use of Moody chart for calculation of friction factor is demonstrated through the following example. Example 3.1. Calculate head loss for a power plant that has a gross head of 100 m, the water flow rate is 10 m3=s, the intake length is 1,000 m, and the pipe diameter is 2 m. Pipe material is welded steel, and assume average water temperature of 10ı C.
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Solution. To calculate the head loss, first the friction factor needs to be calculated. The Moody chart will be used. In order to use the chart, following information is needed: e=D and Reynolds number. From Table 3.7, e D 0:6 mm, therefore, e=D D 0:6=2;000 D 0:0003 To calculate Reynolds number, kinematic viscosity at 10ı C is obtained from Table 3.6 and is 1:307 106 m2 =s. The velocity is given by: V D
Q 4 10 4Q D D 3:18m=s D D 2 =4 D 2 3:14 22
Reynolds number, NRe D DV= D .2 3:18/=1:307 106 D 4:87 106 As can be seen from the Moody Chart (Fig. 3.47), the friction factor, f , is 0.015. The head loss is calculated from Eq. 3.8. 2 1000 3:182 L V D 0:015 D 3:86 m hf D f D 2g 2 2 9:81 Therefore, net head without taking into account other losses is given by: Net head D Gross head Head loss D 100 3:86 D 96:14 m
3.10.1 Local Head Losses Several local head losses also occur when water flowing through a pipe. These losses are due to geometric changes at entrances, bends, elbows, joints, racks, valves and at sudden contractions or enlargements of the pipe section. Losses are expressed as head loss and estimated from rather empirical formulas and are discussed below. These local losses are different for different channels. 3.10.1.1 Head Loss Equations for Closed Channels Entrance Loss hcc e D k1
v2 2g
(3.15)
where, k1 is the entrance loss coefficient for various types of entrances and v is the entrance velocity.
Contraction Loss hcc c D k2
v22 2g
where, k2 is called contraction coefficient, and v2 is the downstream velocity.
(3.16)
103
2
4
103
4
6 8104
2
2
2
4
6 8 105 2
4
2
4
6 8 106
Reynolds Number
6 8105
Smooth pipes
Complete turbulence, rough pipes
4
6 8 104
2
4
6 8 106
4
6 8107
2
2
6 8
4
0.000,01 6 8108
0.000,05
0.0001
0.0002
0.001 0.0008 0.0006 0.0004
0.002
0.004
0.01 0.008 0.006
0.02 0.015
0.03
0.05 0.04
Calculation of Power from Water Flow
Fig. 3.47 Determination of friction factor for Problem 3.1 from the Moody chart
0.010 0.009 0.008
0.015
0.020
0.025
f = 64 Re
flow
0.030
0.040
inar
0.050
0.060
0.070
0.080
0.090
0.100
Lam
Friction Factor
3.10 201
Relative Pipe Roughness (ε/D)
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3 Hydropower
Expansion Loss A1 2 v21 D 1 hcc ex A2 2g
(3.17)
where, A1 and A2 are the upstream and downstream flow areas and v1 is the upstream velocity.
Bends v2 2g
hcc B D kB
(3.18)
where, kB is bend loss coefficient and v is the velocity at the bend.
Gates and Valves hcc v D kv
v2 2g
(3.19)
where, kv is the gates and valves loss coefficient and v is the velocity at the gates and valves.
Gradual Expansion hcc ge D kge
v21 2g
(3.20)
where, kge is the expansion coefficient and v1 is the upstream velocity. The values of various loss coefficients are given in Appendix XIII.
3.10.2 Head Losses in Open Channels 3.10.2.1 Trash Rack Losses A screen is used at the entrance of both pressure pipes and intakes to capture the floating debris. This results in a head loss, which is generally small. Kirschmer [135] suggested the following formula. hTR D k a
a 4=3 V 2 0 sin b 2g
(3.21)
3.10
Calculation of Power from Water Flow
203
Fig. 3.48 General construction of a trashrack (Courtesy of European Small Hydropower Association (ESHA) [134])
where, hTR D head loss in trash rack k D constant that depends on the geometrical shape of the trash rack grid a D thickness of the grid b D spacing between the grid bar V0 D approach velocity D angle of inclination from horizontal These parameters are shown in Fig. 3.48 along with the value of k for different geometry of the trash rack grid.
Losses at Bends hB D SLB C 2 where, S D longitudinal slope of canal LB D centerline length of bend
bc V 2 rB 2g
(3.22)
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3 Hydropower
bc D bottom width of canal rB D radius of curvature of bend V D average velocity of flow The longitudinal slope of canal, S , is calculated from the following equation: QD
1 2=3 1=2 AR S n h
(3.23)
where, Q D volumetric flow rate (m3 =s) A D cross sectional area .m2 / Rh D hydraulic radius (m) n D Manning roughness constant. Values for various conditions of a channel are given in Appendix XIII. Values of n various from 0.01 for very smooth channel surface to 0.05 for natural rocky bed surface.
Losses at Entrances
he D 0:05
v22 v2 v21 C 2 2g 2g
(3.24)
where v2 is the velocity in canal and v1 is the velocity upstream from canal entrance.
Contraction
hc D 0:2
v22 2g
(3.25)
where, v2 is the downstream velocity.
Expansion A1 2 v22 hex D 1 A2 2g
(3.26)
where, A1 and A2 are the upstream and downstream flow areas, respectively and v2 is the downstream velocity.
3.12
Fish Ladder and Fish Passage in Hydropower Systems
205
3.11 Hydropower System Efficiency Various energy losses in a hydropower system affect the net power production. These losses are taken into account by multiplying the theoretical power by efficiencies. The hydraulic efficiency ( h ) addresses the head loss. The leakage around the runner is taken into account by the volumetric efficiency ( v ). The mechanical efficiency ( m ) takes into account various losses involving the hydroturbine and is often called the turbine efficiency. The overall efficiency is, therefore, given by: D h v m
(3.27)
The hydraulic efficiency is defined as: h D
Hu H
(3.28)
Where Hu is the head utilized by the runner and H is the net head on the turbine. Efficiencies of around 90–95% can be expected for h . The development of new sealing methods has increased the volumetric efficiency significantly, in the range of 95–98%. Similarly, the efficiency of modern hydroturbines is in the range of 90–95%. The overall efficiency, therefore, is in the range of 75–90%. The net power, therefore, is given by: P D Qhg (3.29)
3.12 Fish Ladder and Fish Passage in Hydropower Systems Although hydropower systems do not discharge pollutants into the environment, it is not free from other adverse environmental effects [136–142]. Efforts to reduce environmental problems associated with hydropower operations, such as providing a safe fish passage and improved water quality, have received considerable attention in the past decade, both at Federal facilities and non-Federal facilities licensed by the Federal Energy Regulatory Commission. Hydropower dams impede the flows of rivers, and, thereby, affect the habitation of various aquatic lives including fishes. Often, the river is the route of migratory fishes. Dams can affect the fish in several ways: they can restrict or delay the fish migration, increase predation, and subject fishes to direct damage and stress. These issues are addressed by designing better fish ladders and passage ways. Upstream fish passages are mainly through the fish ladders. Three main methods have been tried for upstream fish passages: (1) downstream capture followed by manual transportation to upstream. This method is generally costly and labor intensive, however, it can work if the transportation time is short, (2) fish ladders, the most common and rather successful method. These are generally long, since the uphill slope has to be gradual, (3) fish-lift or
206
3 Hydropower
fish-elevator, this method involves collection of fishes in a hopper downstream and holding them there for a certain period of time until the next lift, which can be manual or automatic. The hopper is raised from the tailrace level to the forebay level and fishes are released into the forebay on the upstream side of the dam. Fish lifts can be very effective and are used in many eastern U.S. dams where upstream passage for shads is an issue. The passage of fishes from upstream to downstream also occurs though several other systems: (1) juvenile bypass, (2) spillways, (3) sluiceways and other surface passage, (4) physical transportation, and (5) turbines. Generally, during construction of dams, special provisions are made for juvenile bypass, spillways, and sluiceways for safe passage of fishes. Since 1981, the U.S. Army Corps of Engineers (USACE) has been collecting juvenile salmonids from bypass systems at several dams (McNary Dam on the middle Columbia River and three of the four USACE dams on the lower Snake River) and barging or trucking them downstream. A major concern regarding the use of hydroelectric power is the mortality of turbine-passed fishes, especially among Pacific salmon, steelhead, Atlantic salmon, American shad, and catadromous eels. These fishes must travel from rivers back to the sea after the pawning season. The number of fishes killed, injured, or stressed by turbine passage can vary with species, age, time of year, water temperature, turbine type and operations. Mortality rates over 40% have been reported for juvenile American shad and blueback herring. Mathur et al. [143] reported mortality from zero to about 15% within 1 h of passage among juvenile American shad. A study by Bickford and Skalski [144] that used data from 25 years of Columbia-Snake River System survival studies, found mortality rates between about 7% and 13% for juvenile salmonid. Although the mortality of turbine-passage fish can be mitigated to some extent using the methods mentioned earlier, it can be further lessened by improving passage conditions within the turbine. In order to design a better passage within the turbine, the mechanisms for injuries and mortality among fishes that pass through hydroelectric turbines need to be understood first. The following mechanisms have been suggested: • Rapid and extreme pressure changes (water pressures within the turbine may increase to several times the atmospheric pressure, then drop to subatmospheric pressure, all in a matter of seconds), • Cavitations (extremely low water pressures cause the formation of vapor bubbles which subsequently collapse violently), • Shear stress (forces applied parallel to the fish’s surface resulting from the incidence of two bodies of water of different velocities), • Turbulence (irregular motions of the water, which can cause localized injuries or at larger scales, disorientation), • Strike (collision with structures including runner blades, stay vanes, wicket gates, and draft tube piers), and • Grinding (squeezing through narrow gaps between fixed and moving structures). The locations within the turbine where these events occur are shown in Fig. 3.49.
3.13
Summary
207 ORNL 2000-00571B/abh 3 Gradually 2 Increasing Pressures 1 0
Forebay
Tailrace Water Flow
Draft Tube
Wlcket Gate
Strike and Grinding
Shear Stress
Rapidly Decreasing Pressures and Cavitation
3 2 1 0
Turbulence
Fig. 3.49 Locations within a hydroelectric turbine at which particular injury mechanisms to turbine passed fish tend to be most severe (Cada [145])
The U.S. Department of Energy initiated the Advanced Hydropower Turbine System (AHTS) Program for developing low impact, fish-friendly turbines. The objective of the AHTS program was to design turbines that are environmental friendly, provide safe passage to fishes while maintaining a high efficiency for electricity generation. A turbine designed by the Alden Research Laboratory, Inc./Northern Research and Engineering Corporation (ARL/NREC) under this program is shown in Fig. 3.50. The runner of the new turbine was based on the shape of a pump impeller that minimized the leading edge of the blade and maximized the size of flow passages.
3.13 Summary Among renewable energy sources, hydropower is the leading generator of electricity providing more than 97% of all electricity generated by renewable sources. Other sources including solar, geothermal, wind, and biomass account for less than 3% of
208
3 Hydropower
Fig. 3.50 Schematic of a fish-friendly turbine (Designed by Alden Research Laboratory, and Northern Research and Engineering Corporation. Odeh [146])
renewable electricity production. Hydropower provides about 20% of the world’s electricity and is the main energy source for more than 30 countries. However, the further growth of hydropower systems in a number of developed countries is limited. Hydropower is very efficient because of the high efficiency of hydroturbines, which is 95% and more. Although hydropower systems have significant advantages over conventional coal and nuclear power plants, various environmental issues are restricting their growth. Hydropower can have negative ecological impacts, especially on fisheries and water ecosystems. Large scale hydropower installations can alter river ecosystems, killing fish and affecting the water quality. Various efforts are underway to design new types of hydroturbines that can allow safe passage of fishes during their use.
Problems
209
Problems 1. How does a hydroelectric plant work? 2. What are the advantages and disadvantages of hydroelectric power? 3. What are the obstacles of increasing hydropower systems in the world? 4. What is pumped storage hydropower? What is the difference between traditional pumped storage and closed loop pumped storage hydropower? 5. Is hydroelectric a renewable energy source? 6. What are some environmental benefits of hydroelectric dams? 7. What environmental problems does hydropower pose? 8. Can these environmental problems be solved? 9. What social/political problems are associated with hydropower? 10. Do any laws or regulations prevent the deployment of new hydropower? 11. What is the average cost of building a hydroelectric project? 12. What is the average cost of operating and maintaining a hydroelectric project? 13. What are the key components of a hydroelectric dam for generation of electricity? 14. Compare the efficiency of a hydroelectric power generation system with other conventional power plants. 15. Why is hydropower a renewable source of energy? 16. Explain the factors in determining the types of dam to be constructed in a particular location. 17. Where does hydroelectric power come from? 18. What are other uses of a hydropower system than electricity generation? 19. Is hydroelectric a useful source of energy? 20. What are the advantages and disadvantages of using micro hydro water wheels? 21. Explain key features of various hydroturbines and their selection. 22. Explain the importance of the net head of a hydropower system. 23. Explain the steps involve in designing a micro-head hydropower system. 24. Consider a hydropower system with gross head of 100 ft, pipeline length of 200 ft, head loss of 5 ft, and water flow rate of 200 gal per minute. Calculate the diameter of the pipe.
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25. How the flow rates and head loss are determined? 26. Discuss the economics of a small hydropower system. 27. Why is prevention of fish mortality important? 28. What are different approaches to prevent fish injuries in hydroturbines?
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Chapter 4
Geothermal Energy
Abstract Below the earth’s surface, at its center, there is a body of hot molten rock called Magma. Heat is continually produced at the center from the decay of radioactive materials trapped in Magma during formation of the earth. It is believed that this heat source is going to last for billions of years and the thermal energy can be harvested from this source on a regular basis. As a result, geothermal energy is considered a renewable energy source. The term geothermal comes from the Greek word geo, meaning earth, and thermal, meaning heat. Geothermal energy can be used for a variety of applications including electricity generation, heating buildings, and in heat pumps. In this chapter, we discussed various methods of harvesting and utilization of geothermal energy.
4.1 Introduction The interior of the earth or the earth’s core is extremely hot with a temperature of about 4;200ıC (7;600ıF). Although some of the heat is a relic of the formation of the earth some 4.5 billion years ago, the decay of radioactive materials in the core is the source of the heat. The interior consists of two layers. The inner layer is a solid iron core that is surrounded by the molten rock, called Magma. The heat from this hot inner core flows to the cooler outer crust of the earth. Although it is not possible to capture this vast amount of heat, which is estimated to be 42 1012 W, fortunately several natural geologic processes allow for some of this heat to be concentrated at temperatures and depths favorable for commercial exploitation. The energy from these heat sources is called the geothermal energy source, which is being captured and used in various applications. The temperature distribution at the interior of the earth is shown in Fig. 4.1. The outer core or the Magma is surrounded by a mantle, approximately 2,897 km (1,800 miles) thick. It is made of Magma and rocks. The outermost layer of the earth is called Crust. It is 3–5 miles (4.82–8.05 km) thick under the oceans and 15–35 miles (24.14–56.32 km) thick on the continents. The earth’s crust is made of pieces T.K. Ghosh and M.A. Prelas, Energy Resources and Systems: Volume 2: Renewable Resources, DOI 10.1007/978-94-007-1402-1 4, © Springer Science+Business Media B.V. 2011
217
218
4 Geothermal Energy
Ocean Crust
Mantle
Continental Crust (Note: Thickness of Crust is exaggerated)
930°C 1700°F
Lithosphere Asthenosphere Mesosphere
Outer Core
2760°C (5000°F) 4200°C (7600°F)
Inner Core
6371 km
5140 km 2883 km Mantle Mesosphere 350 km Asthenosphere Lithosphere
100 km
(Note: Figures represent distance from surface of Earth)
Fig. 4.1 Perspective view of earth cross section (Source: Braile [1])
of lands and oceans, called Plates. Magma is extended to the earth’s surface, near the edges of these Plates, where volcanic activities occur. The physical and chemical characteristics of the earth’s inner core are shown in Fig. 4.2. Large bodies of water are trapped in the fissures and pores of the underground rocks and are heated by the earth’s heat. The temperature of the rocks and water get hotter, progressing towards the inner core. The use of heat from this energy source can be used to heat buildings or generate electricity. Geothermal energy is considered a renewable energy source, because water is replenished by rainfall and the heat is continuously produced inside the earth. This is further explained in Sect. 4.3. Various aspects of geothermal energy are discussed in these references [2–16].
4.2
Resource Identification
219 Layering by Chemical Composition
Layering by Physical Properties Hydrosphere Liquid Asthenosphere Solid, but Ductile Lithosphere Solid & Brittle 100 km Thick
Atmosphere gas
Density 1.03 (Ocean) 2.7 (Crust) 3.3 3.6
m 0k 35
Crust 4.3
Mantle
Mesosphere Solid 0 20
Light Colored, Low Density Rock 8 - 70 km Thick
5.7 Dark Colored, High Density Rock 9.7
m 0k
Outer Core 51 5
Liquid
m 0k
14
Core Iron + Nickel
16
Inner Core
6371 km
Solid
Fig. 4.2 Structure of the earth and the origin of magmas (Source: Nelson [17])
4.2 Resource Identification The identification and quantification of geothermal resources require geological, hydrological, geophysical, and geochemical techniques that allow gathering of information regarding the potential use of specific sites. The information is necessary to determine if the site is suitable for development as a geothermal energy source. The preliminary indication of the presence of geothermal resources is given by volcanoes, hot springs, fumaroles, geysers and solfataras. Lumb [18] suggested that any geothermal exploration should address the following items: 1. Identification of geothermal phenomena. 2. Determining if a useful geothermal production field exists. 3. Determining if production wells can be drilled with the highest probability of tapping into the geothermal resource. 4. Estimating the shape, size, and depth of the resource. 5. Classifying of the geothermal field. 6. Locating of productive zones. 7. Determination of the heat content of fluids that will be discharged by the wells in the geothermal field. 8. Compilation of a body of data against which the results of future monitoring can be viewed. 9. Assessment of the exploitation values collected on environmentally sensitive parameters. 10. Determination of any characteristics that might cause problems during field development.
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4 Geothermal Energy
Fig. 4.3 The ring of fire. United Sates Geological Survey [19]
11. Assessing the geothermal system (i.e. water or vapor-dominated). 12. Determining the homogeneity of the water supply. 13. Determining the source of recharge water. Most of the geothermal activities in the world occur in the Pacific Ocean rim, known as the Ring-of-Fire (Fig. 4.3). A number of active volcanoes exist around the ring. It also contains many high-temperature hydrothermal-convection systems. Several countries around this Ring-of-Fire are utilizing the geothermal energy. The Philippines, Indonesia, and several countries in Central America (Costa Rica, El Salvador, Guatemala, Nicaragua, and Honduras) are using geothermal energy for generating electricity. The use of geothermal energy is already contributing to the economic development of industrialized nations along the circum-Pacific Ring of Fire, such as the United States, Japan, New Zealand, and Mexico. The geothermal activities have also been found in other areas and are shown in Fig. 4.4. For the practical use of geothermal energy, large geothermal reservoirs must be found. Drilling a well and testing the temperature deep underground is the only way to ensure that a geothermal reservoir exists. However, a number of other studies prior to drilling should be performed and these include [21]: • Satellite imagery and aerial photography • Volcanological studies
4.2
Resource Identification
221
Eurasian Plate
North American Plate
60º
Eurasian Plate 45º 30º Mi
d-
E a s t Pacific Ris
Indo-Australian Plate
A tlan tic R
0º
e idg
Pacific Plate
e
African Plate
Nazca Plate
South American Plate
30º
60º
Antarctic Plate 90º
120º
150º
180º
150º
120º
High.Temperature Geothermal Provines (Schematicalty Shown)
90º
60º
30º
0º
30º
60º
90º
Fig. 4.4 Geothermal province (Adapted from Hulen and Wright [20])
• • • •
Geologic and structural mapping Geochemical surveys Geophysical surveys Temperature gradient hole drilling
Satellite images and aerial survey provide the initial indications of existence of geothermal activities. Geologic landform and rock analysis can provide further information on the presence of geothermal energy. Once the existence of a geothermal source is identified, drilling and various temperature measurements are carried out to determine the size of the source and economic feasibility. The International Heat Flow Commission has analyzed the temperature profile data of the earth at various depths and noted that there are a number of areas around the world with high geothermal activities. This data is shown in Fig. 4.5. In the USA, most of the geothermal resources are located in the western region of the country. As a result, the geothermal power plants are located in four states: California, Nevada, Utah and Hawaii. At present, Idaho and New Mexico are considering construction of several plants. However, as shown in Fig. 4.6, geothermal energy can be used by other states too for other purposes such as district heating, heat and heat-pump. An additional 23 states in the USA are using the geothermal direct heat. Since the 1980s, Europe is very active in identifying and quantifying its geothermal resources. Various regional mapping projects, such as the Geothermal Atlas of Europe were published in 1992. Another study entitled, Atlas of Geothermal Resources in Europe, was released in 2002 based on the data obtained from drilling of boreholes. The locations of main geothermal basins in Europe are shown in
222
4 Geothermal Energy
Fig. 4.5 Worldwide geothermal temperature levels (Adapted from Czisch [22])
Fig. 4.6 Estimated subterranean temperatures at a depth of 6 km (Courtesy of US Department of Energy [23])
Fig. 4.7 and the temperature distribution at 5,000 m depth is shown in Fig. 4.8. Areas of high enthalpy are located in Iceland, Italy, Greece, parts of France, Germany and Austria. Countries such as Ireland, Norway, Sweden, UK, and Poland contain low enthalpy regions and may not be economical for geothermal development.
4.3
Geothermal Systems
223
Fig. 4.7 Major geothermal basins in Europe (Courtesy of Antics and Sanner [24])
4.3 Geothermal Systems A geothermal system is consists of three major elements: a heat source, a reservoir and a fluid, as schematically shown in Fig. 4.9. The heat source can be from the Magma having a temperature greater than 600ı C at depths of 5–10 km. Additionally, a heat source can also be low-temperature systems using the earth’s normal temperature, which increases with depth. The reservoir that is naturally formed by hot permeable rocks can heat a circulating fluid, which generally is the water. However, water loss occurs when it escapes from the reservoir through springs or extracted by boreholes. Therefore, the water must be replenished, if the meteoric water is not sufficient. The heat is transferred to the fluid mainly by convection. The hot water rises upward due to its lower density and is replaced by cold dense water. The mechanism is shown in Fig. 4.10. If the geothermal fluid is used for steam generation or direct heating, it must be replenished continuously to maintain the hydrostatic pressure
224
4 Geothermal Energy
Fig. 4.8 Temperature distribution at a depth of 5,000 m in Europe (Source: Shell International as reported by Antics and Sanner [24])
and the fluid mass. One practice is to inject it back into the reservoir through specific injection wells. This also reduces the impact on the environment from operation of geothermal plants.
4.4 Applications The use of the geothermal energy depends on the temperature of the resources. For electricity generation, the temperature of the resources must be above 150ıC. If the temperature of geothermal resources is below 150ı C, it can be still used for a number of other applications. The main applications of geothermal energy may be divided into following categories: • • • •
Electricity generation Direct district heating Heat pump Industrial applications
Lindal [26] suggested a number of uses of geothermal energy based on the temperature of the resources. Various uses of the geothermal energy corresponding to a particular temperature were illustrated in a diagram, which is currently known as the Lindal diagram. The original Lindal Diagram has been modified by a number
4.4
Applications
225
Recharge area
Hot spring or steam vent
Geothermal well Impermeable caprock (thermal conduction)
Cold Meteoric waters
Hot fluidsi
Reservoir (thermal convection)
Flow of heat (conduction)
ble rock Impermea nduction) co al m er (th
Magmatic intrusion
Fig. 4.9 Schematic representation of a geothermal system (Courtesy of Dickson and Fanelli [2])
Fig. 4.10 Model of a geothermal system. Curve 1 is the reference curve for the boiling point of pure water. Curve 2 shows the temperature profile along a typical circulation route from recharge at point A to discharge at point E (From White, 1973). White D E (1973). Characteristics of geothermal resources. In: Kruger P and Otte C (Eds.) Geothermal energy, Stanford University Press, Stanford, pp. 69–94 (Courtesy of Dickson and Fanelli [25])
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4 Geothermal Energy
Fig. 4.11 Various uses of geothermal energy based on temperature of the geo-resources (Printed with permission from Hunter and Schellschmidt [27])
of researchers as more applications of the geothermal energy were found. These applications are summarized in Fig. 4.11. From this figure, the minimum useful temperature for any application should be above 20ı C. The Lindal diagram is now widely used in the geothermal community to depict temperature as the yardstick of applications. In the USA, few areas have temperatures above 150ıC. As can be seen from Fig. 4.12, most of the areas have temperatures below 20ı C; however, these areas are good for geothermal heat pumps, which are discussed later in this chapter. Most of the western states have temperatures greater than 150ıC and are suitable for both district heating and electrical power generation. In Europe, Iceland is the leader in utilization of the geothermal energy. It is further discussed in the following section. The Paris area in France has the largest geothermal district heating systems. Other countries including Austria, Germany,
4.4
Applications
227
Fig. 4.12 US geothermal provinces used for various activities suggested in Fig. 4.11 (Adapted from Hulen and Wright [20])
Hungary, Italy, Poland, and Slovakia are developing a substantial number of geothermal district heating systems. Sweden, Switzerland, Germany and Austria are the leading countries in terms of market for geothermal heat pumps in Europe.
4.4.1 Electricity Generation Worldwide about 60,877 million kilowatt-hours of electricity were produced in 2007 from 9,968 MW of installed geothermal power plants. It is estimated that the average capacity factor of geothermal power plants is around 73%. At present 24 countries are utilizing the geothermal energy. The installed electricity generation capacity of top 20 countries is shown in Fig. 4.13. However, as can be noted from Table 4.1, the growth of geothermal energy in these top 20 countries is rather mixed. The installed capacity of these countries as of 2007, and their percent share of the world total electricity generation from the geothermal energy is given in Table 4.2. Potentially another 22 countries are expected to start using geothermal energy for electricity production by 2010. These new countries include Armenia, Canada, Chile, Djibouti, Dominica, Greece, Honduras, Hungary, India, Iran, Korea, Nevis, Rwanda, Slovakia, Solomon Islands, St. Lucia, Switzerland, Taiwan, Tanzania, Uganda, Vietnam, and Yemen.
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4 Geothermal Energy
3500
3.09 103
4000
2500
1.5
France
29
Portugal
24
52
Guatemala
6.6
56
Papua New Guine
Germany
82
China
82
166
Costa Rica
Russia
167
Kenya
Turkey
204
EI salvador
88
575
536
Japan
Italy
Mexico
Indonesia
Philippines
0
United states
500
Nicaragua
628
Iceland
1000
New Zealand
1500
958
1.18 103
2000
843
1.9 103
Megawatt (MW)
3000
Fig. 4.13 Installed geothermal electricity generation capacity of various countries around the world. In 2010 (Source of data: Holm [28])
In Europe, Italy is expected to nearly double its installed capacity by 2020. Germany is planning 150 new plants with most of the activities centered in Bavaria. In Asia, the Philippines is also planning to increase its installed geothermal capacity from about 2,000 MW to 3,130 MW. Indonesia is planning for 6,870 MW of new geothermal capacity to be developed over the next 10 years. The geothermal development potential of the Great Rift Valley in Africa is enormous. Kenya has announced a plan to install about 1,700 MW of new geothermal capacity within 10 years. The total projected growth of the installed capacity in the world is shown in Fig. 4.14. Electrical Power Generation in the USA As shown in Fig. 4.13, the USA has the highest installed capacity in the world. As of March 2008, geothermal electric power generation is occurring in eight U.S. states: Alaska, California, Hawaii, Idaho, Nevada, New Mexico, Utah and Wyoming. The installed capacities of these states are given in Fig. 4.15. The highest installed capacity is in California, providing about 4.5% of California’s electric energy generation in 2007, amounting to a net-total of 13,439 GWh. Hawaii has one power plant operating in the big island of Hawaii, called the Puna Geothermal Venture (PGV). PGV delivers an average of 25–35 MW on a continuous basis, supplying approximately 20% of the total electricity needs of the Big Island.
4.4
Applications
229
Table 4.1 A comparison of installed geothermal power production capacity between 2007 and 2010 Installed capacity Installed capacity Country in 2010, MW in 2007, MW % change United States 3;087 2923:5 5:59 Philippines 1;904 1969:7 3:33 Indonesia 1;179 992:0 18:85 Mexico 958 953:0 0:52 Italy 843 810:5 4:00 New Zealand 628 471:6 33:16 Iceland 575 421:2 36:51 Japan 536 535:2 0:15 El Salvador 204 204:2 0:09 Kenya 167 128:8 29:65 Costa Rica 166 162:5 2:15 Nicaragua 88 87:4 0:68 Russia 82 79:0 3:79 Turkey 82 38:0 115:79 Papua New Guinea 56 56:0 0:00 Guatemala 52 53:0 1:88 Portugal 29 23:0 26:08 China 24 27:8 13:66 Germany 6:6 8:4 21:42 France 1:5 14:7 89:79 Former USSR with total potential of 768–1,902 MW and Yugoslavia with a potential of 50–100 MW The GEA 2007 report considered France and Guadeloupe as one entity. Also development interest identified in six countries is not identified in 2010 – Korea, Solomon Islands, St Lucia, Tanzania, Uganda and Vietnam. Guadeloupe’s 15 MW installed capacity is included in the 2010 IGA report as part of France’s total installed capacity. Mainland France has 1.5 MW installed geothermal capacity in 2010 2007 source: Installed capacity from Ruggero Bertani, “World Geothermal Generation in 2007,” GHC Bulletin, September 2007, p. 9; United States from Geothermal Energy Association, Update on US Geothermal Power Production and Development (Washington, DC: 16 January 2008); capacity factor from Ingvar B. Fridleifsson et al., “The Possible Role and Contribution of Geothermal Energy to the Mitigation of Climate Change,” in Hohmeyer and Trittin [29]
According to the U.S. Bureau of Land Management, the Western states could generate 5,500 MW of geothermal energy from 110 plants by 2015, and projected to rise by another 6,600 MW by 2025. Geothermal resources that can be used to generate electricity may be divided into the following four categories: • • • •
Hydrothermal fluids Geopressurized brines Enhanced (Engineered) geothermal systems or Hot dry rock systems Magma
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4 Geothermal Energy
Table 4.2 Contribution to total electricity generating capacity by geothermal sources Electricity generated by geothermal energy in 2009, TWh/year 16:60 10:31 9:60 7:04 5:52 4:99 4:05 3:06 1:43 1:42 1:13 0:49 0:45 0:44 0:31
Country United States Philippines Indonesia Mexico Italy Iceland New Zealand Japan Kenya El salvador Costa Rica Turkey Papua New Guinea Russia Nicaragua
Total electricity generated from all sources in 2009 TWh/year 4149:6 60:6 151:7 258:0 289:2 16:8 43:5 1115:1 8:4 6:5 8:7 194:1 2:9 993:1 3:3
% of electricity from geothermal source 0:4 17:0 6:3 2:7 1:9 29:7 9:3 0:2 16:9 22:0 12:9 0:2 15:5 0:0 9:4
[Source: International Energy Agencyand BP Statistical Review of World Energy [30, 31]]
15000.0
Installed Capacity (MW)
Geothermal Energy Association Data
10000.0
5000.0
International Geothermal Association Data 0.0 1970
1980
1990
2000
2010
Year Fig. 4.14 Projected trend of the use of geothermal energy (Adapted from Gawell and Greenberg [33])
Of these four resources, only hydrothermal fluids have been developed commercially for power generation. Geopressurized reservoirs containing brine are generally saturated with natural gas and are under high pressure. The extraction of this fluid is technologically challenging. In the dry rock, the typical thermal
4.4
Applications
231
3500.0 3152.7 3000.0
2000.0 1500.0
New Mexico 0.24
Wyoming 0.25
Alaska 0.73
Idaho 15.8
Hawaii 35.0
California
0.0
Total Capacity
500.0
Utah 47.0
448.4
1000.0
Nevada
Installed Capacity (MW)
2605.3 2500.0
Fig. 4.15 Installed electricity generation capacity of various states in the USA as of August 2009 (Adapted from Geothermal Energy Association [32])
gradient is 30ı C=km. To attend a temperature of 190ı C, holes must be drilled to a depth of about 6,096 m (20,000 ft). The potential of this resource is enormous, but so far an economically feasible technology is not available to extract this energy in a commercially useable way. The temperature gradient in hot dry rock is little higher, 40ı C=km. Although the temperature of molten Magma is above 2;000ıC, there is no technology to take advantage of this energy. The ambient ground heat is generally too low for most of the applications. 4.4.1.1 Hydrothermal Fluid Three methods can be used for the generation of electricity from hot hydrothermal fluids [34–43]. Methods suitable for the electricity generation depend on the state of the fluid (whether it is steam or hot water) as determined by its temperature. These methods are called: dry steam, flash, and binary cycle hydrothermal systems. Dry Steam Power Plants If the geothermal energy is available in the form of steam, it can be used directly to run a conventional steam turbine. Therefore, fossil fuels and boilers that are essential for conventional power plants are not necessary. The dry steam geothermal system
232
4 Geothermal Energy
Fig. 4.16 Dry steam power plant (Courtesy of Idaho National Laboratory [44])
is the oldest type of geothermal power plant. It was first used at Lardarello in Italy in 1904, and is still in operation. The Geysers in northern California, the world’s largest single source of geothermal power, also uses the same technology to generate electricity. These plants emit excess steam and very small amounts of other gases to the atmosphere. A schematic diagram of a dry steam power plant is shown in Fig. 4.16. Flash Steam Hydrothermal Power Plants Flash steam power plants use the hydrothermal fluid, which is primarily water, for electricity generation. Water is available at temperatures above 200ıC and at a high pressure. The basic arrangement of this system is shown in Fig. 4.17. Water is sprayed into a flash-tank that operates at a lower pressure than the inlet water, causing some of the fluid to rapidly vaporize, or flash, to steam. The steam is used to drive a turbine and a generator. Depending on the temperature of the water collected in the first flash-tank, a second tank may be used to further generate steam. However, this depends on the temperature and pressure of the steam and economics of the process. Binary Cycle Hydrothermal Power Plant If the water temperature is less than 200ıC, a binary cycle method may be most suitable and cost effective for the generation of electricity. In this method
4.4
Applications
233
Fig. 4.17 Flash steam production (Courtesy of Idaho National Laboratory [44])
Fig. 4.18 Binary plant (Courtesy of Idaho National Laboratory [44])
(See Fig. 4.18), the geothermal energy is used to vaporize another working fluid, which then drives a turbine and a generator. Generally, hydrocarbons are preferred as the working fluid. A 1;000-kW binary cycle geothermal power plant with isobutane as the working medium was successfully run for the first time at Otake, Kyushu,
234
4 Geothermal Energy
Japan, in 1978. The working liquid mostly used in U.S. Geothermal power plants is isopentane, which vaporizes at a lower temperature and higher pressure than water. In a closed loop cycle, the vapor produced from the binary liquid drives the turbine-generator unit, and then it is condensed back to liquid before being reused in the heat exchanger. After a portion of the heat is used from the geothermal water, it exits the binary plant and is injected back into the reservoir. Exergy/AmeriCulture, USA, has designed and constructed a binary cycle geothermal plant near Cotton City, New Mexico, that has a gross electricity generation capacity of 1,420 kW (approximately 1,000 kW net). An ammonia-water working fluid is used in a Kalina cycle. The Kalina cycle boosted the geothermal plant efficiency by 20–40% and reduced plant construction costs by 20–30%, thereby lowering the cost of geothermal power generation. The Kalina cycle is discussed in Chap. 3 of Volume 1 of this book series. Maghiar and Antal [45] discussed a binary power plant at the University of Oradea, Romania that used low enthalpy geothermal source for power generation. The working fluid used at this binary power plant was carbon dioxide. There are some advantages of using CO2 , such as no explosion danger, it is non-flammable and non-toxic and is available at low cost. Moderate hot water plants, using high- or moderate-temperature geothermal fluids, have been developed recently. Hot water resources are much more common than steam. Hot water plants are now the major source of geothermal power in both the United States and the world. In the United States, hot water plants are operating in California, Hawaii, Nevada, and Utah. 4.4.1.2 Geopressurized Brines Geopressurized reservoirs exist at depths of 3,000–6,000 m (10,000–20,000ft) below the earth’s surface that contain brine and dissolved methane. These type of reservoirs is located throughout the world. In the USA, the best known geopressurized reservoirs are along the Texas and Louisiana Gulf Coast. The brine is typically saturated with methane, containing in the range of 30–80 cft of methane per barrel of fluid. These brines are hot with temperature in the range of 149–204ıC .300–400ıF/. The geopressurized brine can provide: (1) thermal energy from the temperature of the fluid; (2) mechanical energy from the fluid pressure; and (3) chemical energy from the methane that is dissolved within the fluid. The operation of geothermal power plants using geopressurized brine has been discussed by a number of researchers [46–53]. The US Department of Energy [54] has evaluated several reservoirs along the Texas and Louisiana Gulf Coast and noted that recoverable methane gas varied from 22 to 28 standard cubic feet per barrel and brine content was 70,000–131,000ppm. The analyses from test wells are provided in Table 4.3. Goldsberry [54] also provided a conceptual schematic diagram of a geopressurized geothermal system for both recovery of methane gas and electricity generation. This diagram is shown in Fig. 4.19.
4.4
Applications
235
Table 4.3 Test results geopressured geothermal well
Well location Pleasant Bayou No-2, TX Amoco Fee No-1, LA L. R. Sweezy No-1, LA Gladys McCall No-1, LA
Production depth (ft)
Interval thickness Temperature Pressure Permeability (ft) (ı F) (psia) (MD)
Recoverable Brine gas content TDS (Scf/bbl) (ppm)
14,700
60
309
11,050
157
22
131,000
15,400
254
310
12,000
296
22
128,000
13,400
49
235
12,500
1,250
23
103,000
14,412
1,072
288
13,000
170
28
70,000
[Source: Goldsberry [54]]
Fig. 4.19 A schematic diagram of a geopressurized system for methane recovery and power generation (Adapted from Goldsberry [54])
A commercial plant of 10 MW using geopressurized brine from the Salton Sea geothermal field in southern California, USA, was developed by Unocal Corporation in 1989. Two more units were added to boost the total power production to 47.5 MWe [55]. A schematic diagram of the Unocal system is shown in Fig. 4.20. The brine from these reservoirs is extremely corrosive, and scale formation in various parts of the plant must be avoided for commercial development. The brine can also contain traces of oxidizing metals enhancing the corrosion of the materials. Therefore, the brine chemistry should be properly understood and implemented for economical operation of power plants [57]. Corrosion-resistant alloys and cement linings have allowed reduction of corrosions of the system. Various measures are suggested by researchers to address the prevention of corrosion, scale formation, fouling, and minimization of environmental effects [58–76].
236
4 Geothermal Energy Production
Cyclone Separator Steam
Power Plant
Cyclone Scrubber
Steam Turbine
Electrical Generator
Transformer
Electrical Power to Grid
Cooling Tower
Condenser
Pump Pump Brine
Pump
Pump Condensate
Flashing to Steam-Brine in Borehole Reservoir
Brine Carry Over
Brine Injection Well
Condensate Injection Well
Fig. 4.20 Use of geopressurized brine for electricity production (Printed with permission from Gallup [56])
4.4.1.3 Enhanced (Engineered) Geothermal Systems A significant amount of heat is stored in hot rocks underneath the earth’s surface. This heat can be harvested through Enhanced or Engineered Geothermal systems (EGS). EGS are engineered reservoirs below the earth’s surface to extract energy from engineered geothermal resources (mainly from hot rocks) [77–91]. These resources are otherwise not economical due to the lack of a body of water and/or permeability through the rock formation. The USDOE estimates that the application of EGS technology is capable of providing at least 100,000 MW of electricity within the next 50 years. The technology to mine the heat from the hot rocks is available, but only up to a certain depth beneath the surface of the earth. Los Alamos National Laboratory, New Mexico, USA developed a conceptual design of the hot dry rock mining technology. As shown in the Fig. 4.21, water is pumped into hot, crystalline rock via injection wells, becomes superheated as it flows through open joints in the hot rock reservoir, and is returned through production wells. At the surface, the heat is extracted by conventional processes. Any unused water or the remaining water is recirculated back to the reservoir for reuse. The amount of thermal energy available at 10 km depth in the USA has been estimated by various agencies. The results from these studies are summarized in Table 4.4. Although the amount of heat that is projected to be extractable using EGS is enormous, the recoverable fraction from any underground resource is inherently speculative. Areas within national parks and monuments, and other recreational areas
4.4
Applications
237 injection pump
makeup water
Power Plant Sediments and/or Volcanics
Injection Well Production Well
Low Permeability Crystalline Basement Rocks
3-10km Depth
10,000-30,000ft Depth
Fig. 4.21 Schematic of a conceptual two-well enhanced geothermal system in hot rock in a low-permeability crystalline basement formation (Adapted from Renewable Energy and Power Department [89]) Table 4.4 Estimated U.S. geothermal resource base to 10 km depth by category
Category of resource Conduction-dominated EGS Sedimentary rock formations Crystalline basement rock formations Supercritical Volcanic EGSa Hydrothermal Coproduced fluids Geopressured systems
Thermal energy, in exajoules (1 EJ D 1; 018 J)
Reference
100,000
This study
13,300,000
This study
74,100
USGS Circular 790
2,400–9,600 0.0944–0.4510 71,000–170,000b
USGS Circulars 726 and 790 McKenna et al. (2005) USGS Circulars 726 and 790
[Source: Renewable Energy and Power Department [89]] a Excludes Yellowstone National Park and Hawaii b Includes methane content.
would permanently be excluded from development. When all these constrained are taken into account, the total thermal energy available from the EGS is shown in Fig. 4.22.
4 Geothermal Energy
Resource Base
238
Stored Thermal Energy in Place (3 to 10 km) 14 × 106 EJ
Estimated Recoverable EGS Resource
40% Upper Limit 5.6 × 106 EJ
20% Midrange 2.8 × 106 EJ
2% Conservative 2.8 × 105 EJ 0.0
5.0
10.0
15.0
Thermal Energy (106 EJ)
Fig. 4.22 Estimated total geothermal resource base in the USA and its recoverable amount in EJ .1018 J/ (Renewable Energy and Power Department [89])
4.4.1.4 Magma Magma is potentially a huge energy source [92–96]. According to Dunn et al. [94], in the USA an estimated 50,000–500,000 quads of energy is contained in magma at temperatures above 600ı C at depths shallower than 10 km. The greatest challenge with magma system is the extraction of energy. An open heat exchanger can be formed for the extraction of heat by solidifying magma around a cooled borehole and the resulting mass will be extensively fractured by thermally-induced stresses (See Fig. 4.23). However, the construction materials must be chosen carefully. Westrich [95] indicates that consideration of corrosion resistance, high-temperature strength, and cost suggest that Ni-base superalloys offer the most promise for use as construction material of a heat exchanger in rhyolite magma.
4.4.2 Direct Use of Geothermal Energy Direct uses of geothermal energy involve the use of hot waters from geothermal resources directly for bathing and cooking, heating of homes and buildings (better known as district heating), heating of greenhouses for growing vegetables and flowers, fish farming (aquaculture), drying of foods and lumber, and the use of heat pumps [97–104]. Spent fluids from geothermal electric plants still contain a significant amount of heat and can be subsequently used for direct use applications in a so-called “cascaded” operation. As shown in Fig. 4.24, in Europe, most of
4.4
Applications
239
Fig. 4.23 Conceptual representation of open heat exchanger with fluid flow through fractured, solidified magma (Courtesy of Dunn [94])
Casing
Overburden Transition Zone (Plastic)
Solidified Fracture Region
Convecting Magma
Plastic Region Tubing Injection Flow
Convecting Magma
Fluid Flow Through Fractures
Plastic Region Open Heat Exchanger Injection Tubing
the geothermal energy is used for direct heating. In the North, Central, and South America, the use of geothermal energy for electricity production is almost double of that used in direct use applications. In other continents, the geothermal energy is used evenly for direct use and electricity production. According to the US Department of Energy’s Energy Efficiency and Renewable Energy office, the direct use of geothermal energy in homes and commercial operations is significantly less expensive than using traditional fuels. Savings can be as much as 80% over fossil fuels. In the USA, there are approximately 120 facilities, each using hundreds of individual systems. In an individual facility, geothermal energy is used for district heating and space heating. There are also 38 greenhouse complexes, 28 aquaculture
240
4 Geothermal Energy
Fig. 4.24 Global distribution of geothermal production (Adapted from Oldmeadow [105])
Fig. 4.25 Direct use of geothermal energy in the US (Source of data: Geothermal Energy [20])
operations, 12 industrial plants, and more than 218 spas that use geothermal hot waters to provide heat. However, as shown in Fig. 4.25, percentage wise, aquaculture facilities utilizes the maximum amount of geothermal energy. The district heating systems are extremely reliable [106–123]. One such system in Boise, Idaho has been operating since the 1890s, and continues to provide
4.4
Applications
241 User Application Peaking/Backup Unit Heat Exchanger 5°C)
170°F (7
180°F (80°C)
130°F
(55°C)
TO Injection Well From Production Well
140°F (60°C)
Geothermal Water Working Fluid
Geothermal Reservoir
Fig. 4.26 Geothermal direct-use for direct heating (Adapted from US Department of Energy [124])
heating needs today. Another successful implementation of geothermal district heating is in Philips, South Dakota, USA. Direct-use systems typically include three components: • A production facility – usually a well to bring the hot water to the surface. • A mechanical system – piping, heat exchanger, and controls to deliver the heat to the space or processes. • A disposal system – injection well or storage pond to receive the cooled geothermal fluid. A schematic diagram of a direct-use system is shown in Fig. 4.26. The city Philips installed a district heating system to provide all of the energy necessary for heating purposes. A 1,300 m (4,266 ft) deep well, drilled in 1980, provides a maximum artesian flow of 0:0214 m3=s (340 gpm) at 69:4ı C .157ı F/. The geothermal fluid is first used by two schools located next to each other. The fluid, which is at around 60ı C (140ıF), is transported from the schools in a single pipe and is circulated through the downtown area providing heat to commercial and residential buildings. The schools and the fire station house the control points for the system. The geothermal fluid is discharged to the river after removing radium. Different types of heat exchange systems are used in different buildings. The buildings connected to the system used either Modine heaters, unit heaters, or piping in the floor. The bank building uses plate heat exchangers to isolate the geothermal fluid. This direct heating system in Philips, South Dakota, USA is shown in Fig. 4.27. According to Energy Efficiency and Renewable Energy, US Department of Energy, geothermal district heating systems in the USA can save consumers 30–50% of the cost of natural gas heating. The tremendous potential for district heating in the western U.S. was illustrated in a 1980s inventory which identified 1,277 geothermal sites within 5 miles of 373 cities in eight states.
Fig. 4.27 A schematic diagram of the Philip, South Dakota, district heating system using geothermal energy (Courtesy of Geo-Heat Center [126])
242 4 Geothermal Energy
4.4
Applications
243
Thorsteinsson [125] collected the data for US geothermal district heating systems that utilize a geothermal resource as a heat source and distributes heat through a distribution network to five or more buildings. His data are given in Table 4.5 along with their location, start up year, number of customers, capacity, annual energy use and temperature of the system. Although direct heat from a geothermal source can be used in a variety of applications, as shown in Fig. 4.28a,b, the main worldwide uses primarily involve heat pumps, balneology, and space heating. As shown in Fig. 4.29, a number of countries in Europe are using geothermal energy for district heating. Among these countries, Iceland is the leader, not only in Europe, but also in the world in utilization of the geothermal energy. In Iceland, most of the homes and buildings are connected to geothermal district-heating systems. Some district heating and cooling data for Iceland is given in Table 4.6. Direct heating was initiated in Iceland 1930s. At present, it serves about 99% of Reykjavik or about 190,000 people. Iceland utilizes about 62 geothermal wells and uses large storage tanks to meet the peak-load demands. As back-up, Iceland has several oil-fired stations. As shown in Fig. 4.30, several geothermal fields are interconnected with the city’s heating and cooling systems to provide a better reliable system year around. Iceland has both low and high enthalpy sites. Low-temperature fields that are located in the vicinity of Reykjavik, produce water at a temperature of below 150ıC. The hot water from these fields are used directly for space heating and washing. Iceland’s high-temperature fields are only found on the active volcanic rift zone that runs across the country, and yield water at temperatures in excess of 200ıC. However, these fields are rich in gases and minerals, and hot water can not be used directly in the distribution system. Its high pressure and high thermal energy, however, make it well suited to heating fresh cold water, which then can be used for space heating, and also for generation of electricity. The percent of the total geothermal energy used by various sectors in Iceland is shown in Fig. 4.31 and the layout of the district heating system is given in Fig. 4.32. Paris basin in France is utilized to heat many homes by bringing thermal water to the surface. Geothermal greenhouses are prominent in Italy and in the western U.S. As of early 2000s, the percentage of district heated houses in various countries in Europe is given in Table 4.7. Geothermal district heating represents about 35% of the European installed geothermal systems that are dedicated to direct uses, totaling about 5,000 MWt. Major geothermal district heating sites (over 35 exceeding 5 MWt capacity) are shown in Fig. 4.29.
4.4.3 Ambient Ground Heat/Geothermal Heat Pump Geothermal Heat Pumps (GHP) are extremely efficient for home heating and airconditioning. Heat pumps are electrical devices that transfer heat from a cool space
244
4 Geothermal Energy
Table 4.5 U.S. geothermal district heating systems 2007
System Susanville District Heating San Bernardino District Heating I’SOT District Heating System (Canby) Pagosa Springs District Heating Boise City Geothermal District Heating Fort Boise Veteran’s Hospital (Boise) Idaho Capital Mall (Boise) Warm Springs Water District (Boise) College of Southern Idaho (Twin Falls) Kanaka Rapids Ranch (north of Buhl) Gila Hot Springs New Mexico State University (Las Cruces) Warren Estates (Reno) Manzanita Estates (Reno) Elko County School District Elko District Heat City of Klamath Falls District Heating Oregon Institute of Technology (Klamath Falls) Lakeview Midland District Heating Philip District Heating Bluffdale
Number of customers 7
Capacity, MWt 5:60
Annual energy, GWh/year 3:4
System temp. (ı F) 168
22
128
State CA
Start up year 1982
CA
1984
77
12:80
CA
2003
1
0:50
1:2
185
CO
1982
22
5:10
4:8
146
ID
1983
58
31:20
19:4
170
ID
1988
1
1:80
3:5
161
ID
1982
1
3:30
18:7
150
ID
1892
275
3:60
8:8
175
ID
1980
1
6:34c
ID
1989
42
1:10c;d
NM NM
1987 1982
20 m
>25 m
>30 m
Source: Wave Dragon [88]
5.5 Tidal Current Energy The tides are cyclic variations in the level of the seas and oceans. The cyclic variation is predictable, since it is dependent on the position of the earth and the moon in their respective orbits. The kinetic energy of sea or ocean current can be harvested to generate power [90–97]. Various terminologies associated with tide and tidal currents are discussed below. Range: The difference in the height between consecutive high and low tides occurring at a given place. The range is reported in meter or feet. Syzygy: The locations of the moon when it is at new phase and full phase. During this time the gravitational attractions of the moon and sun act to reinforce each other, and, therefore, highest on the earth surface. The tidal range is greater at all locations which display a consecutive high and low water. Spring Tide: The tidal effect of the sun and the moon acting in concert twice a month, when the sun, earth and moon are all in a straight line (full moon or new moon). The range of tide is larger than average. Neap Tide: This is opposite of the spring tide, which occurs when the moon is at right angles to the earth-sun line (first or last quarter). The range of tide is smaller than average. Parallax Effects: The distance between the earth and moon vary throughout the month by about 49,879 km (31;000 miles). As a result the gravitational pull that
5.5
Tidal Current Energy
293
Fig. 5.23 The lunar parallax and solar parallax inequalities (Courtesy of National Oceanic and Atmospheric Administration [98])
causes the tide also vary. During perigee, when the moon is closest to the earth, above-average ranges in the tides occur. When the moon is at apogee, which is farthest from the earth, the tidal ranges will be less than average. The distance between the earth and the sun also varies causing different ranges in the tide. When the earth is closest to the sun, called perihelion, the tidal ranges increase, and when the earth is farthest from the sun (aphelion), the tidal ranges will be reduced. The parallax effects, both for the earth-moon, and the earth-sun systems are shown in Fig. 5.23. The monthly cycle (tropical month of 27.32 days) of lunar declination contributes to the overall tidal effects. The closer the moon comes to being overhead, the more powerful is its effect. Since, both the moon and the earth revolve in elliptical orbits, the distances from their centers of attraction vary. Increased gravitational influences and tide-raising forces are produced when the moon is at position of perigee, its closest approach to the earth (once each month) or the earth is at perihelion, its closest approach to the sun (once each year). Figure 5.24 also shows the possible coincidence of perigee with perihelion to produce tides of augmented range. The gravitational pull is enhanced when the plane of the moon’s orbit is inclined only about 5ı to the plane of the earth’s orbit (the ecliptic). The latitude of the moon reaches its maximum value at this inclination. Thus, the total declination of the moon can reach some 23:5ı above and below the ecliptic orbit. In Fig. 5.24, this condition is shown by the dashed position of the moon. The corresponding tidal force envelope due to the moon is depicted, in profile, by the dashed ellipse.
294
5 Ocean Energy
Fig. 5.24 Moon’s declination effect (Change in angle with respect to the equator) and the diurnal inequality; semidiurnal, mixed, and diurnal tides (Courtesy of National Oceanic and Atmospheric Administration [98])
Moon’s declination affects the types of tide in any particular location. There are three daily cycles of tide, called diurnal, semidiurnal, and mixed. These tides are shown in Fig. 5.25. • Semidiurnal tide – Having a period of approximately one-half of a tidal day. The predominant type of tide throughout the world is semidiurnal, with two high waters and two low waters each tidal day. • Mixed Diurnal – Type of tide characterized by a conspicuous diurnal inequality in the higher high and lower high waters and/or higher low and lower low waters. • Diurnal tide – Having a period of one tidal day. The tide is said to be diurnal when only one high water and one low water occur during a tidal day (tidal day=24 h and 50 min). There are two fundamentally different approaches for using tidal energy to generate electricity. The first approach exploits the cyclic rise and fall of the sea level and the second approach use the local tidal currents to run turbines. The World Offshore Renewable Energy Report 2002–2007, released by the DTI Renewable Energy Consulting, CO, USA [99], estimated that 3000 GW of tidal energy is available worldwide, however less than 3% is located in areas suitable for power generation. The total worldwide power in ocean currents has been estimated to be about 5,000 GW, with power densities of up to 15 kW=m2 . The tide can increase dramatically when it reaches continental shelves, bringing huge masses of water into narrow bays and river estuaries along a coastline. The tides in the Bay of Fundy, Canada are the greatest in the world, with amplitude between 16 and 17 m near shore. The other locations around the world where high tides are observed are listed in Table 5.3.
5.5
Tidal Current Energy
295 Tidal Day
Tidal Height (in feet above or below the standard datum)
Tidal Period 3 2 1 0 −1 −2 −3 −4
Tidal Period
Datum
SEMIDIURNAL TIDE
Tidal Period Higher Lower 3 High Water High Water 2 Tidal 1 Rise Datum 0 −1 Higher −2 Low Water −3 −4
Lower Low Water
Tidal Day
Tidal Range Tidal Range
MIXED TIDE
Tidal Amplitude = 1/2 Range
Tidal Day Tidal Period 2 1 0 −1 −2
Datum DIURNAL TIDE
Fig. 5.25 Different types of tides (Courtesy of National Oceanic and Atmospheric Administration [98]) Table 5.3 Locations for high tides
Country Canada England France France Argentina Russia Russia
Site Bay of Fundy Severn Estuary Port of Ganville La Rance Puerto Rio Gallegos Bay of Mezen (White Sea) Penzhinskaya Guba (Sea of Okhotsk)
Source: Wave Dragon APS [88]
Tide range (m) 16.2 14.5 14.7 13.5 13.3 10.0 13.4
296
5 Ocean Energy
As mentioned earlier, the tidal current energy resource of the world is rather large, particularly in countries such as the UK, Ireland, Italy, the Philippines, Japan and parts of the United States. In some parts of the world, water currents can be intense. The general surface current pattern around the world is shown in Fig. 5.26. Some of these locations are the Pentland Firth to the north of the Scottish mainland, around the British Islands and Ireland, between the Channel Islands and France, in the Straits of Messina between Italy and Sicily and in various channels between the Greek Islands in the Aegean. However, a good estimation of this resource has not been carried out by most of the countries. The potential for installation of marine current turbines in Europe is estimated to exceed 12,000 MW. The UK has the major component of the EU resource at approximately 4.3 GW. Ocean current in the vicinity of the USA coast line is shown in Fig. 5.27. Electric Power Research Institute (EPRI) has studied the North America tidal energy potential at selected sites and is shown in Fig. 5.28. EPRI estimates that the total tidal and river in stream potential is on the order of 140 TWh/year. Tidal power technologies may be categorized into two groups as follows: • Tidal Barrage or Dam Method • Tidal Turbine Method
5.5.1 Tidal Barrage Method A barrage or dam is typically used to force the water during high tide into a reservoir. When the tides produce an adequate difference in the level of the water on the opposite side of the dam, the gates are opened. The water is allowed to flow through a low head turbine, in a similar manner as a hydroelectric system. Gates and turbines are installed along the dam. The turbines turn an electric generator to produce electricity. There are currently two commercial barrages in operations. One is located in La Rance, France and the other one is in Annapolis Royal, Nova Scotia, Canada.
5.5.2 Principles of Operation Tidal barrage systems can be operated in two modes: • Single-Basin Tidal Barrage Mode • Multiple-Basin Mode
Fig. 5.26 Surface ocean current (Source: Windows to the universe [100])
5.5 Tidal Current Energy 297
298
5 Ocean Energy
Fig. 5.27 Tidal current in the vicinity of the USA coast line (Courtesy of the University of Texas [101])
Fig. 5.28 Electricity generation capacity from the tidal energy from selected sites in the USA (Source: Bedard [102])
5.5
Tidal Current Energy
299
Fig. 5.29 A hypothetical single-basin tidal barrage system (Printed with permission from Bryden et al. [103])
5.5.2.1 Single-Basin Tidal Barrage Mode The operating principle of a tidal barrage in a single basin mode is shown in Fig. 5.29. A single barrage across the estuary is used for power generation. Three different methods of operation of barrages may be employed with a single basin for electricity generation. All of the options allow water to flow relatively freely through the barrage, and gated turbines. Ebb Generation Mode During the flood tide, incoming water flows freely through sluices in the barrage. During low tide, when the water height outside the barrage has fallen sufficiently, the required water head is reached between the basin and the ocean water. At that point, the basin water is allowed to flow out though low-head turbines to generate electricity.
Flood Generation Mode The sluices and turbine gates are kept closed during the flood tide to allow the water level to build up outside the barrage. Once a sufficient head has been established the turbine gates are opened and water flows into the basin through turbines generating electricity. The water level during various stages is critical and must be maintained at the appropriate level as shown in Fig. 5.30. The energy produced by this method is generally lower than the ebb method, as the surface area of a basin would be larger at high tide than at low tide, which would result in rapid reductions in the head during the early stages in the generating cycle.
300
5 Ocean Energy
Fig. 5.30 Water levels in a flood generation scheme (Printed with permission from Bryden et al. [103])
Fig. 5.31 Hypothetical two-basin system (Printed with permission from Bryden et al. [103])
Two-Way Generation Mode With bi-directional turbines, it is possible to generate electricity in both ebb and flood methods. However, this would increase the operating and maintenance costs. The main advantage of this method is a reduced period with no generation and the peak power would be lower, allowing a reduction in the cost of the generators.
5.5.2.2 Double-Basin Systems Some of the problems associated with single basin systems may be overcome using double basin systems. Power could be generated almost on a continuous basis using double basin systems. A double-basin system, as shown schematically in Fig. 5.31, allows storage and provides control over power output levels.
5.5
Tidal Current Energy
Table 5.4 Country France Russia Canada China
301
Existing tidal power plants Site Installed power (MW) La Rance 240 Kislaya Guba 0.4 Annapolis 18 Jiangxia 3.9
Basin area (km2 ) 22 1.1 15 1.4
Mean tide (m) 8.55 2.3 6.4 5.08
Source: Gorlov [104] Table 5.5 Large scale tidal barrage plants under consideration
Site Seven Estuary (UK) Solway Firth (UK) Bay of Fundy (Canada) Gulf of Khambat (India) White Sea (Russia)
Mean tidal range (m) 7.0 5.5 11.7 6.1 –
Barrage length (m) 17,000 30,000 8,000 25,000 –
Estimated annual energy production (GWh) 8,600 10,050 11,700 7,000 15,000
The main basin used in the ebb generation mode is utilized the same way in the double basin as is used in a single-basin system. A proportion of the electricity generated during the ebb phase would be used to pump water to and from the second basin to ensure that there would always be a generation capability. The electricity generation efficiency of such a low-head storage system is in the range of 30%. The overall efficiency of these systems, when considered the use of the second basin for a pumped storage, can exceed 70%. Four large-scale tidal power plants currently exist. They are the La Rance Plant (France, 1967), the Kislaya Guba Plant (Russia, 1968), the Annapolis Plant (Canada, 1984), and the Jiangxia Plant (China 1985). Some of the features of these plants are given in Table 5.4. Worldwide there are several sites where tidal basins can be developed economically and are given in Table 5.5.
5.5.3 Tidal Lagoons Tidal lagoons are more environmental friendly. Both the Severn Estuary, which lies between England and Wales, and the mouth of the Yalu River, China have been suggested as potential locations for the lagoon-style development.
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Fig. 5.32 An artist’s impression of a tidal fence system (Source: Blue Energy Ltd [105])
5.5.4 Tidal Fence A tidal fence has vertical axis turbines mounted in a fence. They can be used in areas where there are channels between two landmasses. The tide water is forced through the turbines. As shown in Fig. 5.32, tidal fences sometimes look like giant turnstiles. They can reach across channels between small islands or across straits between the mainland and an island. This can be used as roadways too. The tidal currents can be at 5–8 knots (5.6–9 miles/h) and generate as much energy as winds of much higher velocity. Because seawater has a much higher density than air, ocean currents carry significantly more energy than air currents (wind).
5.5.5 Tidal Turbine Method Among various technological options, the use of tidal currents to run the turbines appears to be the best option. A number of countries are interested in pursuing the use of ocean current energy technologies. These countries include the European Union, Japan, and China. However, the technology is at an early stage of development, with only a small number of prototypes and demonstration units are tested to date. The main issue with the tidal current system is the design of the turbine. Most of the designs involve submerged systems. Although the tide turbines look the same as wind turbines, their working principle is different. Submerged tide turbines capture
5.5
Tidal Current Energy
303
Fig. 5.33 A submerged turbine working on tidal current (Courtesy of World Energy Council [106])
energy by the processes of hydrodynamic, rather than aerodynamic lift or drag. These turbines have rotor blades, a generator for converting the rotational energy into electricity, and a means for transporting the electrical current to shore for incorporation into the electrical grid. The basic operating concept of a submerged turbine working by the water current is shown in Fig. 5.33. Four types of turbine have been explored for generating electricity from the tidal current, and these include: • • • •
Horizontal Axis Turbines Vertical Axis Turbines Linear Lift Mechanism or Oscillating Hydroplane Systems Venturi Based Systems
5.5.5.1 Horizontal Axis Turbines (HAT) HATs are similar to wind turbines. The working principle is shown in Fig. 5.34. The power output depends on the stream flow rate and can be controlled using pitch controlled blades. The amount of power that can be harvested from the water current also depends on the rotor diameter (See Fig. 5.35). Similar to a wind turbine, the efficiency of water turbines depends on the water flow rate. Also, a minimum water velocity, called cut-in speed, is required before the turbine can start producing power. The power production increases exponentially with the increase in the velocity up to its rated power. The power output will not increase beyond this rated power even if the water velocity increases. These three regions of operations are shown in Fig. 5.36.
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Fig. 5.34 Basic orientation of horizontal axis turbines
Fig. 5.35 Power production as a function of rotor diameter (Adapted from Electric Power Research Institute [107])
Tidal current turbines can be either seabed-mounted or hanged from floating platforms. The sea-bed mounting is preferred for shallow water, whereas the floating platform is preferred for deep water installations. Various installation methods are shown in Fig. 5.37. Various designs of tidal horizontal axis turbines that are commercially available are shown in Fig. 5.38.
5.5.5.2 Vertical Axis Turbines In vertical axis turbines, water stream flow is perpendicular to the rotational axis of the turbine as shown in Fig. 5.39. Among vertical axis turbines, Gorlov turbines have the best performance, which are approximately 35% efficient in extracting energy from the water current. The Gorlov turbine always turns in the same direction, regardless of the stream direction, providing a higher energy conversion.
Power (kW)
5.5
Tidal Current Energy
305
2500
Region I: Velocity below cut-in speed
2000
Electric power = 0 (rotor cannot turn power train)
1500
Flow power Electric power
Region II: Velocity above cut-in speed Electric power = fluid power x power train efficiency
1000
500 I
Region III: Velocity above rated speed Electric power = rated power II
III
0 0.0
0.5
1.0
1.5
2.0 2.5 3.0 Flow speed (m/s)
3.5
4.0
4.5
Fig. 5.36 Dependence of turbine output power on the water speed (Adapted from Electric Power Research Institute [107])
Fig. 5.37 Various sea-bed mounting methods for turbines (Source: U.S. Department of the Interior [108])
Several vertical axis turbines have been designed and tested for their feasibility in commercial applications. Some of these turbines are shown in Fig. 5.40. Blue Energy Canada Inc. is involved in developing multiple vertical axis hydroturbines for generating electricity from ocean currents and tides. One such turbine is shown in Fig. 5.41. Current Power Sweden AB has also developed a vertical axis turbine (See Fig. 5.42) for extracting energy from streaming water, such as ocean current.
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Fig. 5.38 Horizontal axis turbines for power generation from the tidal current. (a) Lunar Energy RTT Turbine (Rotor dia. 21 m, Rated Power: 2 MW) (b) MCT Experimental Sea Flow (Rotor dia. 18 m, Rated Power: 1.5 MW) (c) Open Hydro Ream Drive Turbine (Rotor dia. 15 m, Rated Power: 1.5 MW) (d) UEK Shrouded Turbine (Rotor dia. 4 m, Rated Power: 0.4 MW) (e) Verdant Power RITE Turbines (Rotor dia. 5 m, Rated Power: 0.034 MW) (f) SMD Hydrovision (Rotor dia. 8 m, Rated Power: 1 MW)
5.5
Tidal Current Energy
307
Fig. 5.39 Working principle of vertical axis turbines
Fig. 5.40 Vertical axis turbines. (a) Gorlov Helical Turbine (GCK Technology) (Rotor dia. 1 m, Rated Power: 7 kW) (b) Seapower Vertical Axis Turbine (Rotor dia. 1 m, Rated Power: 44 kW)
5.5.6 Linear Lift Mechanism or Oscillating Hydroplane Systems In this method, a large wing-like hydroplane moves up and down in a linear motion and compresses the oil in a hydraulic ram to run an hydraulic power converter (See Fig. 5.43). These systems are generally mounted on the sea bed and prototypes are found in the range of 200–250 kW.
5.5.7 Venture Based Systems A venturi tube is used to accelerate the water flow. As the water is accelerated through the tube due to the reduction in cross-sectional area, a pressure drop is
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Machinery Enclosure Generator Gearbox Coupling Chamber
Turbine Power Duct
Water Flow
A
Rotor Shaft Support Arms Working Blades (Hydrofoil) A Bearings
Fig. 5.41 Blue energy vertical axis turbine (Nameplate capacity: 0.25 MW) (Source: Blue Energy Ltd [105]) Fig. 5.42 Current power AB vertical axis turbines (Nameplate capacity: 0.012-3 MW) (Source: Blue Energy Ltd [105])
5.7
Ocean Thermal Energy Conversion (OTEC)
309
Fig. 5.43 BioPower system oscillating hydroplane systems for power production (Nameplate capacity: 0.25-1 MW) (Source: Blue Energy Ltd [105])
generated in the tube as shown in Fig. 5.44. The pressure gradient is the driving force for the turbine which is connected to the constricted point in the tube.
5.6 Tidal Farm Coastal currents between 3.6 and 4.9 knots (4 and 5.5 mph) is ideal for the best performance of tidal turbines. In this range of water current, a 15-m (49.2-ft) diameter tidal turbine can generate as much energy as that of a 60-m (197-ft) diameter wind turbine. In large areas with powerful currents, it would be possible to develop tidal energy farm (See Fig. 5.45). These are arrayed underwater in rows, as in some wind farms. Turbine spacing would be determined based on wake interactions and maintenance needs. A 30-MW demonstration array of vertical turbines in a tidal fence is being investigated in the Philippines (WEC 2001). Ideal locations for tidal turbine farms are close to shore in water depths of 20–30 m (65.5–98.5 ft).
5.7 Ocean Thermal Energy Conversion (OTEC) Solar energy stored in the ocean water is converted to electric power by using the OTEC technology which utilizes the ocean’s natural thermal gradient [110–131]. The ocean’s layers of water have different temperatures. A thermodynamic cycle
Fig. 5.44 Venturi based system for power generation from tidal current (Courtesy of VerdErg) [109]
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5.7
Ocean Thermal Energy Conversion (OTEC)
311
Fig. 5.45 An artists impression of a tidal farm with two different types of turbines. As reported in U.S. Department of the Interior [108]
Fig. 5.46 Thermal gradient in different water bodies around the world (Courtesy of Ocean Thermal Energy Conversion, NREL [130])
could be operated between this temperature difference to drive a power-producing cycle. A temperature difference of about 20ı C .68ı F/ between the warm surface water and the cold deep water is desirable for an OTEC system to produce a significant amount of power. The temperature gradient at various parts of the world is shown in Fig. 5.46. As can be seen from the figure, a temperature gradient of 20ı C exists in tropical coastal areas, roughly between the Tropic of Capricorn and the Tropic of Cancer. Three basic OTEC system designs have been demonstrated to generate electricity. These are: • Closed cycle, • Open cycle, and • Hybrid cycle. The basic design and various components of an OTEC system are shown in Fig. 5.47.
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Fig. 5.47 Basic components and output from an ocean thermal energy conversion system (Courtesy of Ocean Thermal Energy Conversion, NREL [130])
5.7.1 Closed-Cycle OTEC System In a closed-cycle OTEC system, warm seawater vaporizes a working fluid, such as ammonia, flowing through a heat exchanger (evaporator). The vapor expands at a moderate pressure and turns a turbine coupled to a generator that produces electricity. The vapor is then condensed in an another heat exchanger (condenser) using cold seawater pumped from a certain depth of the ocean through a cold-water pipe. The condensed working fluid is pumped back to the evaporator to repeat the cycle. The working fluid remains in a closed system and circulates continuously. A schematic diagram of the cycle is shown in Fig. 5.48.
5.7.1.1 Work Done in the Closed/Anderson Cycle The Anderson closed cycle is mainly used in closed cycle OTEC systems. It is a Rankine-type cycle. In the Anderson cycle, the working fluid is superheated only a few degrees Fahrenheit above the saturation temperature of the working fluid. The P-V diagram of the cycle is shown in Fig. 5.49. In Fig. 5.49, the starting point of the cycle may be considered is at a where heat is added to the working fluid until it is pressurized to point b. The working fluid is allowed to vaporize at a constant temperature by continuous addition of heat. The volume increases and when it reaches point c, the fluid is expanded adiabatically to the point d to obtain the work. The low pressure vapor from the turbine is cooled
5.7
Ocean Thermal Energy Conversion (OTEC)
313
Fig. 5.48 A schematic diagram of a closed cycle OTEC process (Courtesy of Ocean Thermal Energy Conversion, NREL [130]) Fig. 5.49 The P–V diagram of the closed OTEC Rankine cycle (Printed with permission from Avery and Wu [131])
to its original state given by point a. In this cycle, QH is the heat transferred to the evaporator from the warm sea water that vaporizes the working fluid. The working fluid exits from the evaporator as a gas near its dew point. The high-pressure, hightemperature gas is expanded in the turbine to yield turbine work, WT . The working fluid is slightly superheated at the turbine exit and the turbine typically has an efficiency of 90% based on reversible, adiabatic expansion. Various parameters of the cycle are shown in Fig. 5.50. From the turbine exit, the working fluid enters the condenser where it rejects heat, QC , to the cold sea water. The condensate is then compressed to the highest pressure in the cycle, requiring condensate pump work, WC . The major additional
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Fig. 5.50 Work and heat flow in an closed cycle (Printed with permission from Iqbal and Starling [132])
energy requirements in the OTEC plant are the cold water pump work, WC T , and the warm water pump work, WH T . If other energy requirement is WA , the net work from the OTEC plant, WNP is WNP D WT C WC C WC T C WH T C WA
(5.47)
A simple energy balance for the working fluid of the system may be written as: WN D QH C QC
(5.48)
WN D WT C WC
(5.49)
where, WN is the net work for the thermodynamic cycle. The other works are rather small and can be neglected. The heat transferred to the evaporating fluid (QH ) and removed in the condenser .QC / can be expressed by following expressions if there is no pressure drop in the heat exchangers, Z TH ds (5.50) QH D H
5.7
Ocean Thermal Energy Conversion (OTEC)
and,
315
Z QC D
TC ds
(5.51)
C
where, TH is the temperature at the evaporator and TC is the temperature at the condenser and s is the entropy. The net thermodynamic cycle work becomes: Z
Z
WN D
TH ds C H
TC ds
(5.52)
C
The net thermal efficiency of the cycle is calculated as: D
WN QH
(5.53)
5.7.2 Open-Cycle OTEC System In an open-cycle OTEC system, warm seawater is the working fluid. The warm seawater is “flash” evaporated in a vacuum chamber to produce steam at an absolute pressure of about 2.4 kilopascals (kPa). The steam expands through a low-pressure turbine that is coupled to a generator to produce electricity. The steam exiting the turbine is condensed by cold seawater pumped from the ocean’s depths through a cold-water pipe. If a surface condenser is used in the system, the condensed steam remains separated from the cold seawater and provides a supply of desalinated water. A schematic diagram of the cycle is shown in Fig. 5.51. The T-s diagram of an open-cycle OTEC cycle is shown in Fig. 5.52. It may be assumed that the process starts at State 1, which defines the condition of the warm surface seawater. The sea water is then introduced into the deaerator at Warm seawater in
Non-condensable Desalinated gases water vapor Desalinated (saturated) water vapor (unsaturated) Vacuum Deaeration chamber Turbo(optional) flash generator evaporator
Non-condensable Warm seawater discharge to sea gases
Cold seawater discharge to sea
Condenser
Desalinated water (optional)
Cold seawater in
Fig. 5.51 A schematic diagram of an open-cycle OTEC process (Courtesy of Ocean Thermal Energy Conversion, NREL [130])
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Fig. 5.52 T s diagram of an open cycle OTEC system (Printed with permission from Avery and Wu) [131]
State 2, where the pressure is reduced suddenly allowing the water to flash evaporate. The majority of the dissolved gases are removed this way. The thermodynamic state of water in the flash evaporator is the same as that in the deaerator (State 2). The ambient pressure is dropped to the saturation pressure at this point. The steam produced at this point is referred to State 3. A two-phase system exists at this state. The vapor phase is designated as 3g , the mass flow rate of which can be written as x m, P where x is the vapor mass fraction and m P is the total warm water mass flow rate. The vapor expands through a turbine at this point converting thermal energy to mechanical energy. The liquid from State 3 having a flow rate of .1x/m P is pumped back to the sea at State 7. The turbine exhaust which is at State 4 is condensed using cold sea water to State 5. The condensate can be pumped back to sea water under the condition given by State 6. The condensate is considered fresh water and can be used for other purposes such as irrigation. However, it is released to the sea; its thermodynamic state will follow State 6 to State 7 to State 1.
5.7.2.1 Work Done by Open Cycle OTEC The efficiency of the open cycle system can be calculated as follows. QP D m P H CP .TH TW /
(5.54)
5.7
Ocean Thermal Energy Conversion (OTEC)
317
TC P Pg D T Qin 1 TH
(5.55)
QP out D QP in Pg
(5.56)
Pn D Pg PCSW PWSW Pmisc
(5.57)
D
Pn QP i n
(5.58)
Where, m P H is the warm water mass flow rate, TH is the warm water inlet temperature, TW is the outlet temperature of the warm water, Tc is the temperature of condensate, CP is the specific heat, QP in is the heat input to the system, QP out is the heat rejected from the system, is the overall system efficiency, T is the turbine efficiency, Pn is the net power, Pg is final power output after taking into account various losses given by PCWS (parasitic loss in cold water loop), PWSW (warm water loop loss), and Pmisc (other losses).
5.7.3 Hybrid OTEC System A hybrid cycle combines the features of both the closed-cycle and open-cycle systems. In a hybrid OTEC system, warm seawater enters a vacuum chamber where it is flash-evaporated into steam, which is similar to the open-cycle evaporation process. The steam vaporizes the working fluid of a closed-cycle loop on the other side of an ammonia vaporizer. The vaporized fluid then drives a turbine to generate electricity. The steam condenses within the heat exchanger and provides desalinated water. A schematic diagram of the hybrid system in shown in Fig. 5.53.
5.7.4 Components of an OTEC System The major components of OTEC systems are heat exchangers, evaporators, turbines, and condensers. The design of various components of OTEC systems depends on the working fluid. Various fluids have been proposed over the past decades for use in a closed OTEC cycle. However, the best working fluid appears to be ammonia, due to its superior transport properties, easy availability, and low cost. Ammonia, however, is toxic and flammable. The power plant size is dependent upon the vapor pressure of the working fluid. For fluids with high vapor pressure, the size of the turbine and heat exchangers decreases while the wall thickness of the pipe and heat exchangers should increase to endure high pressure especially on the evaporator side. The materials for construction of these components are a major issue and costly. The materials must be resistant to corrosion from sea water.
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Fig. 5.53 A schematic diagram of the hybrid OTEC system (Courtesy of Ocean Thermal Energy conversion, NREL [130])
5.7.5 Byproducts of OTEC System OTEC systems have many other applications other than electricity generation. OTEC can be used to produce desalinated water, support deep-water aquaculture (mariculture), and provide refrigeration and air-conditioning. These applications may make OTEC systems attractive to industry and island communities even if the price of oil remains low. Various uses are summarized in Fig. 5.54.
5.8 Summary The energy generation from the ocean is a developing technology. Although many energy devices have been invented, only a small number have been tested and evaluated, and very few of these have been tested in oceans – testing has usually been undertaken in a tank. In general terms ocean generation has the following advantages and disadvantages. Advantages: • the energy is free – no fuel is needed and no waste is produced • not expensive to operate and maintain • can produce a significant amount of energy. Disadvantages: • variable energy supply but more consistent than wind or solar energy • needs a suitable site, where waves or currents are consistently strong
Problems
319
Fig. 5.54 OTEC by products and their applications (Courtesy of Ocean Thermal Energy conversion, NREL [130])
• • • •
must be able to withstand very rough weather costly to develop visual impact if turbines are above water or on shore can disturb or disrupt marine life – including changes in the distribution and types of marine life near the shore • poses a possible threat to navigation from collisions • may interfere with mooring and anchorage lines with commercial and sportfishing • may degrade scenic ocean front views from wave energy devices located near or on the shore, and from onshore overhead electric transmission lines.
Problems 1. Why is ocean energy considered renewable? 2. What is the outer continental shelf (OCS)? 3. How does ocean thermal energy work? 4. What are various technologies for harvesting ocean energy? 5. What are the advantages and disadvantages of ocean energy? 6. What energy sources can be utilized from the ocean for electricity generation?
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7. What are the uses of ocean wave’s energy resource? 8. What are the advantages of ocean tidal energy? 9. Ocean waves of wavelength 100 m reach a maximum height of 20 m in 10 s with a velocity of 20 m/s. What is the power density of the wave? 10. How does ocean wave or tidal energy work? 11. What are the obstacles for mass scale utilization of ocean energy? 12. Is there a limitation on how much energy can be produced from ocean energy in a particular location? 13. Can ocean energy be used as a base load power? 14. How close to shore do some of the wave energy systems have to be for transmission of power to onshore or customers? 15. Is there a difference between marine current energy and tidal energy? 16. Can you propose any new concept designs for utilization of ocean power? 17. How would you design, build, and test a ocean energy device for power generation. 18. How would you advance wave energy conversion technologies – including point absorbers, oscillating water column devices, over-topping devices, and wave attenuators – along the commercial development path by demonstrating the economic and technical viability of their inventions? 19. How would you advance critical hydrokinetic turbine technologies – including horizontal and vertical axis water turbines, either tethered or fixed-mounted in a moving water stream – along the commercial development path by demonstrating the economic and technical viability of their systems? 20. Discuss a technical and integrated operational description of an ocean thermal energy conversion system including a detailed engineering analysis of the concept at full scale, a detailed engineering-economic analysis of the system at full scale based on the system and component capital costs, O&M costs (including refurbishment, levelized replacement, etc.), labor, fuel, and other costs such as decommissioning, and the expected energy and/or other (ammonia, hydrogen, water, etc.) production returns; and analysis of the critical design factors of the approach.
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Chapter 6
Bioenergy
Abstract Bioenergy is derived from various biological sources, called biomass, and is considered a renewable energy source, since biomass can be replenished on a regular basis. Biomass offers opportunity in every part of the world to develop sustainable resources including fuel, power, and chemicals. Biomass can be used to generate heat, electricity, and transportation fuel (called biofuel). In this chapter, the energy content of various types of biomass and their conversion to useful energy sources are discussed. Both the cellulosic and lignocellulosic based biomass can be used for energy generation or for biofuel synthesis. Various methods developed to process biomass are also discussed in this chapter.
6.1 Introduction Energy derived from the biomass is called bioenergy. Biomass can be vegetationtrees, grasses, plants parts such as leaves, stems and twigs, sea weeds, and waste products from various industries—including agriculture, forest products, transportation, and construction—that dispose of large quantities of wood and plant products. All of these materials can be used for generation of energy. Since some biomass, such as trees and plants, can be cultivated on a regular basis and replenished, bioenergy is considered a renewable energy source [1–19]. Biomass can be also used to produce biofuels, which is short for biomass fuel. It can be in the form of both liquid and gas. Another term, “biopower” refers to biomass power systems that produce electricity. The major use of “biofuels” is in the transportation sector. Bioenergy may be considered as a carbon neutral system. Carbon dioxide is released back into the atmosphere when burning biomass. However, it is hypothesized that there is little or no net addition of carbon to the atmosphere. If the growing of bioenergy crops is optimized to add humus to the soil, there may even be some net sequestration or long-term fixation of carbon dioxide into soil organic matter. Therefore, it is assumed that the bioenergy cycle, shown in Fig. 6.1, is not only renewable, but it can also provide a stable energy source without harming the environment. T.K. Ghosh and M.A. Prelas, Energy Resources and Systems: Volume 2: Renewable Resources, DOI 10.1007/978-94-007-1402-1 6, © Springer Science+Business Media B.V. 2011
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Fig. 6.1 The bioenergy cycle (Courtesy of Oakridge National Laboratory [20])
Carbon dioxide is a naturally occurring gas. Plants collect and store carbon dioxide to aid in the photosynthesis process. As plants or other matters decompose, or natural fires occur, CO2 is released. Before the anthropomorphic discovery of fossil fuels, the carbon dioxide cycle was stable; the same amount that was released was sequestered, but it has since been disrupted. In the past 150 years, the period since the industrial revolution, the carbon dioxide level in the atmosphere has risen from around 150 to 330 ppm, and is expected to double before the year 2050. The burning of any type of fossil fuel: coal, natural gas, or petroleum, releases CO2 into the atmosphere and is considered a major contributor to the current increased level. Carbon dioxide is released into the atmosphere in various ways and its estimated quantities is shown in Fig. 6.2. Worldwide, biomass is the fourth largest energy resource after coal, oil, and natural gas. It is used for heating (for example, wood stoves in homes and for
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Fig. 6.2 Amount of CO2 stored in the earth and its annual release from various sources (Courtesy of NASA [21]) Fig. 6.3 Fuel share of total primary energy supply of 11741 Mtoe in 2006 (Courtesy of International Energy Agency [22])
Hydro 2.2% Nuclear 6.2%
Combustible renewables & waste 10.1%
Other∗∗ 0.6% Coal/peat 26.0%
Gas 20.5% Oil 34.4%
process heat in bioprocessing industries), cooking (especially in many developing countries), as transportation fuels, such as ethanol, and increasingly, for electric power production. As shown in Fig. 6.3, combustible renewables and wastes contribute almost 10.1% of the world’s total energy supply. Out of this 10.1%, more than 90% is from biomass.
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Fig. 6.4 Share of electricity production by fuel types worldwide in 2006 (Courtesy of International Energy Agency [22])
Hydro 16.0%
Other∗∗ 2.3%
Coal/peat 41.0%
Nuclear 14.8% Gas 20.1%
Oil 5.8%
Fig. 6.5 Renewable energy consumption by regions and contribution of biomass (Adapted from FAO [23])
Although biomass contributes about 1,067 million tons oil equivalent (Mtoe) of energy worldwide, the electricity generation from biomass is less than 2% (Fig. 6.4). Developing countries are dominating on the use of bioenergy, although a number of developed countries such as the US, Canada, and several European countries have significant bioenergy resources. It is also expected that the biomass will continue to be a significant source of energy for these developing countries in the near future. In Fig. 6.5 is shown the current and projected use of bioenergy by different regions of the world.
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Fig. 6.6 Bioenergy consumption by G8 C 5 countries. Food and Agriculture Organization (Adapted from FAO [23])
Among G-8 countries, the USA is well ahead of other countries in utilizing biomass for energy production. Other countries are using only a small amount of biomass. In comparison, India and China together generate more than six times of bioenergy than that of combined G-8 countries. These data are shown in Fig. 6.6. In terms of percent contribution of bioenergy to the total energy consumption, most of the G-8 countries are still below 5%, whereas it is more than 20% for Brazil, China, and India (see Fig. 6.7). Among all the continents, Africa is the world’s largest consumer of biomass energy when calculated as a percentage of overall energy consumption. Biomass used in Africa includes firewood, agricultural residues, animal wastes, and charcoal. Biomass accounts for almost two-thirds of the total African energy consumption, which is equivalent to 205 Mtoe of biomass and 136 Mtoe of conventional energy in 1995, according to the International Energy Agency. Most of Africa’s biomass
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Fig. 6.7 Bioenergy consumption in G8 C 5 countries. Percent of biofuels considering all fuels (Adapted from FAO [23])
energy use is in sub-Saharan Africa. Biomass accounts for 5% of North African, 15% of South African, and 86% of sub-Saharan (minus South Africa) consumption. In the USA, about half of the biomass used today comes from burning wood and wood scraps such as saw dust. Another third is from biofuels, principally from ethanol that is used as a gasoline additive. The rest comes from crops, garbage, and landfill gas. Industries are the biggest user of biomass. Biomass use by various sectors in the USA is given in Fig. 6.8. Homes are the next biggest users of biomass; about one-fifth of homes in the USA burn wood for heating. Most of these homes
Energy Source of Biomass 60 52.3 50
40
30
12.6
20
10.9
21.4
Fig. 6.8 Biomass consumption by various sectors in the USA in 2008 (Courtesy of National Energy Education Development Project [24])
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Biomass Consumption (% of total)
6.2
Commercial
Electricity
Residential
Transportation
0
Industry
2.8
10
burn wood in fireplaces and wood stoves for additional heat. A detailed breakdown of the use of biomass by various sectors and fuel type is given in Table 6.1. A general overview of the potential contribution of renewable energy to the world’s energy resources is given in Table 6.2. The contribution of bioenergy to the world’s future energy demand under two scenarios (technical and theoretical) is given in Table 6.2. The United Nations conducted a study on the cost of electricity generation from biomass. The study showed that the biomass is competitive with other renewable energy sources, and just like other sources, the price is expected to go down in the near future (see Table 6.3).
6.2 Energy Source of Biomass Plants store energy as carbohydrates or sugar, lignin and cellulose. During photosynthesis, plants use sunlight to combine carbon dioxide from air and water from the soil to form carbohydrates, which are the building blocks of biomass. The structure of the biomass is shown in Fig. 6.9. While the actual ratio of components varies among species, the main components are carbohydrates or sugars and lignin.
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Table 6.1 Biomass consumption by various sectors in the USA (in Quadrillion BTU) Sector and energy source 2000 2001 2002 2003 2004 2005 2006 Total 6.264 5.316 5.893 6.150 6.261 6.444 6.922 Biomass 3.013 2.627 2.706 2.817 3.023 3.154 3.374 Biofuelsa 0.241 0.258 0.309 0.414 0.513 0.595 0.795 0.511 0.364 0.402 0.401 0.389 0.403 0.407 Wasteb Wood and derived fuels 2.262 2.006 1.995 2.002 2.121 2.156 2.172 Residential 0.490 0.439 0.449 0.471 0.483 0.527 0.495 Biomass 0.420 0.370 0.380 0.400 0.410 0.450 0.410 0.420 0.370 0.380 0.400 0.410 0.450 0.410 Wood and derived fuelsc 0.128 0.101 0.104 0.113 0.118 0.119 0.117 Commerciald Biomass 0.119 0.092 0.095 0.101 0.105 0.105 0.102 Biofuelse NA NA NA 0.001 0.001 0.001 0.001 0.047 0.025 0.026 0.029 0.034 0.034 0.036 Wasteb 0.071 0.067 0.069 0.071 0.070 0.070 0.065 Wood and derived fuelsf Industriald 1.930 1.721 1.723 1.731 1.861 1.884 1.999 Biomass 1.884 1.684 1.679 1.684 1.824 1.848 1.966 0.102 0.112 0.136 0.178 0.217 0.248 0.311 Biofuelsg 0.145 0.129 0.146 0.142 0.132 0.148 0.140 Wasteb Wood and derived fuelsf 1.636 1.443 1.396 1.363 1.476 1.452 1.515 Transportation 0.138 0.145 0.172 0.235 0.296 0.346 0.483 0.138 0.145 0.172 0.235 0.296 0.346 0.483 Biofuelsh 3.579 2.910 3.445 3.601 3.503 3.568 3.827 Electric power sectori Electric Utilitiesd 2.607 2.063 2.529 2.615 2.522 2.530 2.688 Biomass 0.021 0.014 0.033 0.029 0.031 0.040 0.042 0.014 0.008 0.022 0.012 0.011 0.013 0.015 Wasteb 0.007 0.006 0.011 0.017 0.020 0.027 0.027 Wood and derived fuelsf Independent power producer 0.972 0.847 0.916 0.986 0.981 1.038 1.139 Biomass 0.432 0.323 0.347 0.368 0.357 0.365 0.370 Wasteb 0.305 0.202 0.208 0.218 0.212 0.208 0.216 0.127 0.121 0.140 0.151 0.145 0.158 0.154 Wood and derived fuelsf Source: Energy Information Administration [25] Revised data are in italics. Totals may not equal sum of components due to independent rounding a Biofuels and biofuel losses and coproducts b Municipal solid waste biogenic, landfill gases, agriculture byproducts/crops, sludge waste, and other biomass solids, liquids and gases. Includes municipal solid waste nonbiogenic and tires for 1989–2000 c Wood and wood pellet fuel d Includes small amounts of distributed solar thermal and photovoltaic energy used in the commercial, industrial and electric power sectors e Ethanol primarily derived from corn f Black liquor, and wood/woodwaste solids and liquids g Ethanol primarily derived from corn and losses and coproducts from production of biodiesel and ethanol h Biodiesel primarily derived from soy bean oil and ethanol primarily derived from corn i The electric power sector comprises electricity-only and combined-heat-power (CHP) plants within North American Industry Classification System (NAICS) 22 category whose primary business is to sell electricity, or electricity and heat, to the public
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Composition of Biomass
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Table 6.2 Overview of current use, and the technical and theoretical potentials of different renewable energy options (EJ Exajoule, 1 EJ D1018 J) Source Current use (EJ) Biomass energy 50 Hydropower 9 Solar energy 0.1 Wind energy 0.12 Geothermal energy 0.6 Ocean energy NA Source: World Energy Assessment [26]
Technical potential (EJ) 200–400 .C/ 50 >1;500 640 5,000 NA
Theoretical potential (EJ) 2,900 147 3,900,000 6,000 140,000,000 >140,000,000
Table 6.3 Cost ranges (US-cents per unit) for production of electricity, heat, and fuel from various renewable energy options in 2004 and projection for 2050 Potential long-term future Technology Current energy cost energy cost (2050) Biomass energy (based on energy crops as feedstock) • Electricity USc= 7–21/kWh electricity USc= 5.6–14/kWh electricity • Heat USc= 1.4–7/kWh fuel USc= 1.4–7/kWh • Biofuels USc= 11.22–35/GJ fuel USc= 8.4–14/GJ Wind electricity USc= 7–18.2/kWh USc= 4.2–14/kWh Solar PV electricity USc= 35–175/kWh USc= 7–35/kWh Solar thermal electricity USc= 17–25/kWh USc= 5.6–14/kWh Low temperature solar heat USc= 4.2–28/kWh USc= 2.8–28/kWh Hydroelectricity USc= 2.4–14/kWh USc= 2.8–14/kWh Geothermal energy • Electricity USc= 2.8–14/kWh USc= 1.4–14/kWh • Heat USc= 0.7–7/kWh USc= 0.7–7/kWh Source: World Energy Assessment [26]
Most species also contain a smaller molecular fragments called extractives. When biomass is burned, oxygen in the air reacts with the carbon in plants to produce carbon dioxide and water.
6.3 Composition of Biomass The composition of biomass determines their use. Biomass that is rich in carbohydrates, which is essentially glucose, is suitable for generation of biofuels. The carbohydrate fraction consists of many sugar molecules linked together in long chains or polymers. In a number of plants, biomass is present in the form of starch. Starch is composed of glucose, but it is a mixture of ’-amylose and amylopectin (see Fig. 6.10). Starches found in nature are 10–30% ’-amylose and 70–90% amylopectin. Starch is soluble in water and relatively easy to break down into utilizable sugar units.
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Fig. 6.9 Plant cell structure. US Department of Energy (2008) An overview of science (Adapted from Bioenergy Research Center [27])
6.3.1 Lignocellulosic Biomass The non-grain portion of biomass (e.g., cobs, stalks), often referred to as agricultural stover or residues, and energy crops such as switchgrass, contains biomass in the form of lignin or cellulose. These lignocellulosic biomass resources are not as
6.3
Composition of Biomass
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CH2OH
a
CH2OH
CH2OH
O
O
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OH
OH
OH O
O
O OH
OH
OH
b
O
OH
O
O
CH2OH
OH
CH2OH O
OH
CH2OH
O
HO
OH
O
HO
CH2OH
O
O
O
O
OH
O
OH
OH O
O
CH2OH
CH2OH
CH2O
OH
OH
O
O
O OH
OH
OH
Fig. 6.10 Chemical structure of (a) alpha-amylose and (b) amylopectin (Courtesy of Garrett and Grisham [28]) OH
HO
HO
O
HO
H
OH O OH
H
H
O HO
O
O
H
O
H
O
O
OH
O
O OH
O
HO
HO
OH
O
O
O
H
H
OH
O O
OH O
O
O
H
O
O
HO HO
HO
HO O
O
H
H
OH
O
O
O
OH
HO
O
O
H
H
O
O
O
O
O
O
O
Fig. 6.11 Chemical structure of cellulose (Printed with permission from Sierra et al. [29])
readily accessible as starch. They are also called cellulosic and are comprised of cellulose, hemicellulose, and lignin. Generally, lignocellulosic material contains 30–50% cellulose, 20–30% hemicellulose, and 20–30% lignin. Some exceptions to this are cotton that contains 98% cellulose and flax that has 80% cellulose. Cellulose is also composed of glucose. However, in cellulose, glucose molecules are joined by “-1,4-glycosidic linkages (see Fig. 6.11) making them very stable chemically and insoluble. They serve as a structural component in plant walls.
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Fig. 6.12 Hemicellulose structure (Printed with permission from Sierra et al. [29])
6.3.2 Hemicellulose Hemicellulose is also a polymer containing primarily 5-carbon sugars such as xylose and arabinose (see Fig. 6.12). Glucose and mannose molecules are dispersed throughout within the structure. It forms a shortchain polymer that interacts with cellulose and lignin to form a matrix in the plant wall, strengthening it. Hemicellulose is more easily hydrolyzed than cellulose. Much of the hemicellulose in lignocellulosic materials is solubilized and hydrolyzed to pentose and hexose sugars.
6.3.3 Lignin Lignin helps bind the cellulose/hemicelluloses matrix while adding flexibility to the mix. The molecular structure of lignin polymers is very random and disorganized and consists primarily of carbon ring structures containing benzene rings with methoxyl, hydroxyl, and propyl groups. They are interconnected by polysaccharides (sugar polymers) (see Fig. 6.13). The ring structures of lignin have great potential as valuable chemical intermediates. However, the separation and recovery of lignin from plants is difficult. Lignin can be burned to produce the electricity required for the ethanol production process. Burning lignin directly can provide more energy than needed and selling extra electricity may help the process economics.
6.4 Types of Biomass Biomass resources may be divided into following categories: • Biomass Processing Residues – Pulp and Paper Industry Residues – Forest Residues – Agricultural or Crop Residues
Types of Biomass
339
O
C H 3
6.4
O
O
OCH3OCH3 OCH3 O HO
O O HO OH H3CO OCH3
OCH3
OCH3 OH
OCH3OCH3 O OH O O HO OH H3CO OCH3
OCH3 OH
Fig. 6.13 Lignin structure (Printed with permission from Sierra et al. [29])
• Municipal Solid Wastes – Landfill Gas • Urban Wastes • Animal Wastes • Energy Crops – – – – –
Herbaceous Energy Crops Woody Energy Crops Industrial Crops Agricultural Crops Aquatic Crops
These resources are discussed in the following section. Biomass Processing Residues: All industrial processes that use biomass produce byproducts and waste streams called residues, which have significant energy content. Some of these residues can be used to generate electricity. Others may be recycled back to the soil as a source of fertilizer. Pulp and Paper Industry Residues: Paper industry generates significant amount of biomass residues from the processing of plants where cellulose fiber is separated
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from the plants by making the pulp. Pulping process may be described as the separation and breaking down of the lignin fibers of a plant. The cellulose fibers is extracted to create paper. Leftover pulp, residues of logging and processing of wood create wastes that cannot be used in paper production. These wastes along with sawdust, barks, branches, leaves/needles, and chipped wood are used for power generation in paper mills. This power actually contributes a significant percent of the overall power consumption of paper mills. It may be noted that paper mills are an energy intensive industry. Forest Residues: These include wood from forest thinning operations, biomass from logging sites of commercial hardwood and softwood processing operations, and removal of dead and dying trees. Agricultural or Crop Residues: These are the biomass discarded during harvesting. They can be collected and prepared as pellets, chips, stacks or bales. Agriculture crop residues include corn stover (stalks and leaves), wheat straw, rice straw and nut hulls. Corn stover is expected to become a major biomass resource for bioenergy applications. Municipal Solid Wastes: These are waste paper, cardboard, wood waste and yard wastes. Landfill Gas: Biomass in various landfills is decomposed using bacteria to produce methane, which can be captured and used to create energy, most often through anaerobic digestion (AD). Urban Wastes: The construction industry generates significant amount of wood wastes. According to an estimate by the California Integrated Waste Management Board, CA, USA, about 4 million tons of wood wastes are available in California alone. Urban wood wastes generally consist of lawn and tree trimmings, tree trunks, wood pallets and other construction and demolition wastes made from lumber. Animal Wastes: These include cattle, chicken and pig manure. These can be converted to gas or burned directly for heat and power generation. The wastes may be processed to generate methane, which can be burned further to generate electricity. Generally, anaerobic digestion methods are used for conversion of animal manure to methane Energy Crops: These are fast-growing plants, trees, and other herbaceous biomass, which are harvested specifically for energy production. These crops can be grown, cut and replaced quickly. A list of potential plants which may be used as energy crops is given in the Handbook of Energy Crops [30]. Energy crops may be divided into several categories and are discussed below. Herbaceous energy crops are perennials, but takes 2–3 years before they can be harvested. These include grasses such as switchgrass, miscanthus (Elephant grass), bamboo, sweet sorghum, tall fescue, kochia, and wheatgrass.
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341
Woody Energy Crops include hybrid poplar, hybrid willow, silver maple, eastern cottonwood, green ash, black walnut, sweetgum, and sycamore. Generally, they are fast growing hardwood trees and have short-rotation time between harvesting; these trees may be used within 5–8 years after planting. Industrial Crops include plants such as kenaf and straws. They are more fibrous than others and are considered as industrial crops. These plants are grown specifically to produce industrial chemicals. For example, castor plants can be used for ricin or oleic acid. Agricultural Crops include cornstarch, corn oil, soybean oil and meal, wheat starch, and other vegetable oils. They generally yield sugars, oils, and extracts. Soybeans and sunflowers seeds are used to produce oil, which can be used to make fuels. These plants are also called oil-plants. Aquatic Crops are a wide variety of aquatic biomass such as algae, giant kelp, other seaweed, and marine microflora. They can be used for bioenergy generation. Giant kelp extracts are already used for thickeners and food additives. Global biomass resources vary widely from one country to another country. Also, it is extremely difficult to make an annual estimate of these resources. A number of variables such as rainfall, use of fertilizer and pesticides, and the availability of irrigation system can significantly affect the yield of the energy crops, and, thereby, the estimation. International Energy Agency (IEA) has compiled data from various researchers and projected the use of bioenergy by 2050 under various biomass resource categories. Their data are shown in Table 6.4. An intensive farming may be necessary to produce energy crops on a large-scale, which may result in loss of biodiversity. A balance between conventional crops, such as cereals and seeds, and energy crops may be necessary for optimal utilization of land. Also, it may be necessary to free up grassland currently used for grazing. These issues are discussed in more details in Volume 4 of this book series.
6.5 Biomass Resources, Land Requirement, and Production The energy contents of all of the biomass that are available today is estimated to be 2,740 Quads. At present, the world population uses only about 7% of the annual production of biomass. The large-scale use of existing forest resources for bioenergy generation is not feasible and should not be encouraged. The large scale supply of biomass should be from two sources: • Residues associated with current agricultural commodity production and processing • Energy crops grown on available land The USA uses three types of biomass: wood and wood wastes, solid wastes (garbage and landfill wastes), and biofuels. The percent contribution of these resources is shown in Fig. 6.14.
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Table 6.4 Overview of the global potential of biomass for energy (EJ (Exajoules) per year) generation to 2050 under various scenarios Energy potential in Biomass category Main assumptions and remarks biomass up to 2050 Potential land surplus: 0–4 Gha (average: Energy farming 0–700 EJ (more 1–2 Gha). A large surplus requires structural on current average deadaptation towards more efficient agricultural agricultural velopment: production systems. When this is not feasible, land 100–300 EJ) the bioenergy potential could be reduced to zero. On average higher yields are likely because of better soil quality: 8–12 dry ton/ha/yeara is assumed 100 MWe
Co-combustion of biomass with coal
Table 6.16 (continued) Conversion option Combustion for power generation
15–30% (electrical) 60–80% (overall)
Several hundred/ kWth, depending on capacity 1.000–3.000 (depends on configuration)
100–1,000 C costs of existing power station (depending on biomass fuelCco-firing configuration)
30–40% (electrical)
80–90% (overall)
Investment cost ranges (E/kW) 2.500 –1,600
Net efficiency (LHV basis) 20–40% (electrical)
Status and deployment Well established technology, especially deployed in Scandinavia and North America; various advanced concepts using fluid bed technology giving high efficiency, low costs and high flexibility. Commercially deployed waste to energy (incineration) has higher capital costs and lower (average) efficiency Widely deployed in various countries, now mainly using direct combustion in combination with biomass fuels that are relatively clean. Biomass that is more contaminated and/or difficult to grind can be indirectly co-fired, e.g., using gasification processes. Interest in larger biomass co-firing shares and utilisation of more advanced options is increasing Commercially available and deployed; but total contribution to energy production to date limited Various systems on the market. Deployment limited due to relatively high costs, critical operational demands, and fuel quality (continued)
6.7 Use of Biomass 367
10 tons/h in the shorter term, up to 100 tons/h in the longer term
Typical capacity 30–200 MWe
Source: International Energy Agency [31]
Pyrolysis for production of bio-oil
Table 6.16 (continued) Conversion option Gasification using combined cycles for electricity (BIG/CC) Investment cost ranges (E/kW) 5.000 – 3.500 (demos) 2.000 – 1.000 (longer term, larger scale) Scale and biomass supply dependent; Approx 700/kWth input for a 10 MWth input unit
Net efficiency (LHV basis) 40–50% (or higher; electrical)
60–70% biooil/feedstock and 85% for oil C char
Status and deployment Demonstration phase at 5–10 MWe range obtained. Rapid development in the nineties has stalled in recent years. First generation concepts prove capital intensive Commercial technology available. Bio-oil is used for power production in gas turbines, gas engines, for chemicals and precursors, direct production of transport fuels, as well as for transporting energy over longer distances
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Use of Biomass
369
Table 6.17 Electricity production from biomass in TWh Types 1995 2002 Solid biomass 85:3 110:0 Biogas 6:0 16:9 Liquid biomass Municipal solid waste (MSW) 13:4 21:3 Total 104:8 Source: World Energy Council [192]
148:2
2003 118:2 18:3 0:8 25:0
2004 131:4 20:7 0:6 24:0
2005 134:9 24:8 0:9 22:8
162:2
176:6
183:4
Table 6.18 Top biopower producing countries in 2005 Total electricity Percentage Country produced (TWh) of world USA 56:3 30.7 Germany 13:4 7.3 Brazil 13:4 7.3 Japan 9:4 5.1 Finland 8:9 4.9 UK 8:5 4.7 Canada 8:5 4.6 Spain 7:8 4.3 Rest of World 57:1 31.1 Source: World Energy Council [192]
the biomass-based electricity production are given in Table 6.18. Among these countries, Brazil is unique in that at present almost all of its biomass is bagasse from the expanding sugar cane-based alcohol fuel industry. Although the biopower generation is increasing, a key issue for the biopower sector is the efficiency of the system. In the United States about 9,733 MW of electricity was generated in 2002 using biomass. Of this 9,733 MW of capacity, about 5,886 MW was generated using forest product and agricultural residues, 3,308 MW from municipal solid waste, and 539 MW from other resources such as landfill gas. The majority of electricity production from biomass is used as the base load power for existing electrical distribution systems. Also, more than 200 companies outside the wood products and food industries generate biomass power in the United States.
6.7.2 Electric Power Generation There are four primary classes of biomass power systems: • • • •
Direct-fired System [193, 194] Co-fired Biopower Plants [46, 195–198] Gasification Process [199–214] Modular Systems [215]
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6.7.2.1 Direct-Fired System In direct-fired biomass power plants, the biomass fuel is burned in a boiler, similar to a coal power plant, to produce high-pressure steam. The steam is introduced into a steam turbine to generate electricity. Direct-fired biomass power boilers are typically in the range of 20–50 MW compared to a range of 100–1,500 MW for pure coalfired plants. Because of the small capacity, its efficiency is in the low 20% range. The small capacity plants tend to be lower in efficiency because of economic tradeoffs; efficiency-enhancing equipment cannot pay for itself in small plants. Although techniques exist to enhance biomass steam generation efficiency over 40%, it may not be economical. 6.7.2.2 Co-Fired Biopower Plants Co-firing involves substituting biomass for a portion of coal in an existing power plant furnace. Up to about 15% biomass can be mixed with coal for an existing fuel feed, thus, burning these together. In some plants, a separate boiler feed for the biomass is used. Most of the existing power plant equipment can be used without major modifications. The preparation of biomass for co-firing employs well known, commercially available technologies. Boiler technologies where co-firing have been successfully practiced, tested, or evaluated, include the following: pulverized coal (PC) boilers of both wall fired and tangentially fired designs, coal-fired cyclone boilers, fluidized-bed boilers, and spreader stokers. As a result, co-firing offers the most economic alternative to building a new biomass power plant. The replacement of biomass can also reduce sulfur dioxide (SO2 /, nitrogen oxides (NOx /, and other air emissions. After “tuning” the boiler for peak performance, there is little or no loss of efficiency from adding biomass. The efficiency can be in the range of 33– 37%. Currently, six power plants in the U.S. are co-firing coal and wood residue products on a commercial basis. A schematic diagram of a coal boiler retrofitted for biomass co-firing is shown in Fig. 6.30. Types of biomass that can be used in cofiring, include: (1) wood wastes from pallets, telephone poles, sawdust, and manufacturing scraps; (2) agricultural remnants from peach pits, rice hulls, wheat straw, alfalfa, barley, soybeans, sunflowers, bagasse, and other grains; (3) residues from logging, orchards, and forest management; (4) fast-growing energy crops such as hybrid poplar, willow, black locust, eucalyptus trees, and switchgrass; and (5) municipal wastes including plastic, paper, and cardboard. According to an estimate by the Electric Power Research Institute the payback time for retrofitting a coal power plant for co-firing of biomass can be 3.3 years. 6.7.2.3 Gasification Process The working principle of biomass gasifiers is the same as that of other gasifiers, such as coal gasifiers. The solid biomass particles break down when heated at a
Use of Biomass
Fig. 6.30 A schematic diagram of a pulverized coal boiler system retrofitted for biomass cofiring. (Source: Energy Efficiency and Renewable Energy [216])
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high temperature in the absence of oxygen to form a flammable gaseous product, called biogas. The biogas is next cleaned and filtered for use in more efficient power generation systems called combined-cycles, which combine a gas turbine and a steam turbine to produce electricity (See Fig. 6.31). The efficiency of these systems can reach 60%. Three types of gasifiers are under development by the USDOE. These are: fluidized-bed, fixed-bed, and entrained-flow gasifiers. The gasifiers can be used in a direct-fired mode in which air or oxygen is fed directly to the gasifier, or in an indirect mode in which externally supplied heat is used to gasify the biomass. The heating value of the biogas is generally considerably lower than natural gas and also depends on the gasification method. Gasification with air produces a low-Btu gas, with a heating value about one-fifth that of natural gas. Both indirectly heated gasification and oxygen-blown gasification produce a medium-Btu gas, with heating values as much as one-half that of natural gas. Gasification is a two-step process. The first step is called pyrolysis. During pyrolysis, the volatile components of the fuel are vaporized at temperatures below 600ıC (1;100ıF). The vapor produced in this step includes various hydrocarbons, hydrogen, carbon monoxide, carbon dioxide, tar, and water vapor. Because biomass fuels tend to have more volatile components (70–86% on a dry basis) than coal which is 30%, pyrolysis plays a larger role in biomass gasification than in coal gasification. Char (fixed carbon) and ash are the by-products, which are not vaporized. Depending on the desired heating value of the gaseous stream, either an air-blown or an oxygen blown gasifier is used. Currently, the preferred equipment for biomass integrated gasifier power systems is the air-blown gasifier, since the cost is much lower than oxygen blown system. Gasifiers are also designed for dry-ash or slag handling. The slagging gasifier requires substantially less blast steam injection for the gasification process, since it operates at higher temperatures. In the second step, char is further burned. In direct combustion gasifiers, the char is burned in another vessel. Indirect gasifier systems also use a separate reactor for char combustion from which heat is transferred to the gasifier reactor. A biomass gasification burner is shown in Fig. 6.32. The design of the gasifier is extremely crucial for high efficiency and the success of the process. Generally, all three stages of burning: pyrolysis, oxidation, and reduction are accommodated in a single burner to reduce the installation and operating costs and to increase the efficiency. The TK Energi (TKE) of Denmark has developed a 3-stage, down-draft gasifier, which includes pyrolysis and partial oxidation zones, and a reformer based char gasification zone with a rocking grate for ash discharge. The TKE gasifier is shown in Fig. 6.33. In a fluidized-bed reactor, the biomass is first pyrolyzed in the absence of oxygen using staged steam reformation. The vapors from the pyrolysis stage subsequently are reformed to synthesis gas with steam providing added hydrogen, as well as the proper amount of oxygen. The heat necessary for this stage comes from burning of the char.
Steam
PRESSURIZED FLUIDIZED-BED GASIFIER Oxygen/Air Char / Coke
Synthesis Gas
Process Use
Methanol, Petrochemicals, Fuels, Ammonia
Electricity Generation
Steam
Medium-BTU Gas, Substitute Natural Gas
Direct Combustion
Combined Cycle / Fuel Cell Power Generation
Use of Biomass
R Fig. 6.31 A schematic diagram of a typical biomass gasification system. The above system is called Renugas developed by IGT/GTI and Carbona. (Source: Babu [217])
FEED HOPPER
LOCKHOPPER
ASH CYCLONE
GAS PURIFICATION AND UPGRADING
Low-BTU Gas
GAS PURIFICATION
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Fig. 6.32 Schematic of a biomass gasification burner (Source: Babu [217])
Fig. 6.33 Three stage TKE gasifier (Source: Babu [217])
In an another fluidized-bed gasifier design, a continuous feed of biomass and an inert heat-distributing material (i.e., sand) are “fluidized” by an oxidant and/or steam. Fluidized bed gasifiers can be operated in two modes: direct heating and
6.7
Use of Biomass
375
Fig. 6.34 Biomass gasification via staged steam reformation with a fluidized bed gasifier (Source: U.S. Department of Energy [218])
Fig. 6.35 Biomass gasification via staged steam reformation with a screw Auger gasifier (Source: U.S. Department of Energy [218])
indirect heating. In a directly heated fluidized-bed gasifier, char is burned in the gasifier that supplies the required heat. In an indirectly heated fluidized bed gasifier, char is removed from the gasifier and is burned in a separate vessel. The advantage of the indirect heating of the gasifier is that the gasification product is not diluted with the char combustion by-products such as CO2 and N2 , if air is used. Product gas composition, efficiency, and hot gas utilization of the fluidized-bed process are comparable to those found in a fixed-bed gasifier design. Fluidized-bed gasifiers are capable of handling much smaller, less dense, and less uniform feedstocks. The process is shown in Fig. 6.34. Fixed bed gasifier utilizes a screw Auger reactor (See Fig. 6.35). Biomass is introduced at the pyrolysis stage that operates at about 700ıC. The process heat comes from burning some of the gas produced in the latter stage. The most commercial fixed-bed designs are an updraft gasifier type. The biomass is fed from the top of the gasifier and successively undergoes drying, pyrolysis, char
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Fig. 6.36 Biomass gasification via entrained flow steam reformation (Source: U.S. Department of Energy [218])
gasification, and char combustion as it settles to the bottom of the gasifier. The vapor from the gasifier is removed from the top and is introduced into a steam reforming unit. The ash is collected from the bottom. Blast air and steam are injected into the gasifier to keep the ash below its melting temperature (in a dry-ash gasifier) and to facilitate char conversion. Carbon conversion efficiency is typically 99%; the hot gas efficiency is in the range of 90–95%. The fixed-bed gasifier, however, requires large, dense, uniformly sized fuels. Thus, agricultural residues would generally require densification, thereby increasing fuel handling costs. A schematic diagram of the process is shown in Fig. 6.36. In entrained flow reformation, both external steam and air are introduced in a single-stage gasification reactor. Partial oxidation gasifiers use pure oxygen, with no steam, to provide the proper amount of oxygen. The use of air instead of oxygen, as in small modular system, yields producer gas (including nitrogen oxides) rather than synthesis gas. A partial oxidation gasification system is shown in Fig. 6.37.
Advantages of Gasification Biogasification offers several advantages including reduced emissions, increased efficiencies, and flexibility with respect to biomass feedstocks. Emissions from a biogasifier could be extremely low compared with conventional power plants. Furthermore, these systems can achieve high efficiencies. The use of advanced biomass gasifier and gas turbines can increase the electricity generation from the biomass by 50% or more. Various combinations of thermal cycles may further enhance the efficiency.
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Use of Biomass
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Fig. 6.37 Biomass gasification via partial oxidation (auto thermal) (Source: U.S. Department of Energy [218])
There are several types of biomass that cannot be used directly in a furnace. The inorganic portion of the biomass tends to stick to the furnace wall and reduce the heat transfer through the wall. Many fast-growing, desirable energy crops and residues have high proportions of these inorganic compounds. These inorganic compounds can be removed during gasification as a part of the cleanup process.
6.7.2.4 Small, Modular Systems Modular systems employ some of the same technologies mentioned above, but on a smaller scale that is more applicable for use in remote areas, villages, farms, and small industries. There are many opportunities to use these systems in developing countries. Large amounts of biomass are available in these areas for fuel that a small, modular system can utilize. Small systems, those with rated capacities of 5 MW and smaller, could potentially provide power to a small community. By adopting a standardized modular design, 5 kW-to-5 MW, systems can be designed at a lower cost. The hot gas from the gasification unit is cleaned and used for electricity generation. Waste heat from the turbine or engine can also be captured and directed to other applications. Small modular systems lend themselves to such combined heat and power operations much better than large central facilities. The basic operating principles of a small, modular system is shown in Fig. 6.38.
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Fig. 6.38 Biomass gasification via partial oxidation (auto thermal) for small modular applications (Source: U.S. Department of Energy [218])
Benefits of Small Modular Systems For a small community, small modular systems can have added economic benefit, since the biomass waste stream can be a source of energy. Otherwise, a landfill needs to be designed and operated. The flexibility to use more than one fuel is another advantage.
6.8 Biomethane Livestock manures contain fats, carbohydrates, and proteins along with other components that can be converted to methane and carbon dioxide using anaerobic bacteria [219–224]. The process mechanism is shown in Fig. 6.39. This is a two-stage process. In the first stage, most of the components in the manure break down in to a series of fatty acids by a particular group of bacteria, called acidogenic bacteria. In the second stage, methane producing bacteria (methanogenic bacteria) converts the acids to methane gas and carbon dioxide. Methanogenic bacteria is very sensitive to the oxygen content and pH of the solution and functions best at 95ı F (35ıC) and pH between 6.8 and 7.4. Methane concentration in the final product is between 60% and 70% and the rest is carbon dioxide and a trace quantity of hydrogen sulfide. The operation of a digester is challenging. A variety of materials
6.8
Biomethane
379
Fig. 6.39 Process for conversion of manure to methane (Source: Fulhage et al.[225])
can become toxic to anaerobic bacteria including salts, heavy metals, ammonia and antibiotics. Their concentrations must be monitored carefully; a minimum amount of these components is required for their growth, but in greater content they can be toxic to both acidogenic and methanogenic bacteria. Ammonia toxicity is a major concern in the anaerobic digestion of livestock manures. To avoid the problem, loading rates must be carefully controlled. Methane production rates from various types of animal manure are given in Table 6.19. There are several types of anaerobic digesters [226–234]. The main differences among these digesters are in the operating temperature and design of the unit. A digester can be designed to carry out acidogenesis and methanogenesis reactions separately or together in the same unit. The operating temperature ranges are identified as psychrophilic (68ı F or 20ı C), mesophilic (95–105ıF or 35–41ı C) and thermophilic (125–135ı F or 52–57ı C). There are a number of process designs currently used to digest livestock manures and are listed below. 1. Covered lagoons [235, 236] 2. Plug-flow digesters [237, 238] 3. Mixed plug-flow digesters [239, 240]
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Table 6.19 Potential gas production of swine, dairy, poultry and beef manure (20ı C or 68ı F, atmospheric pressure) Swine (150 lb) 12
Gas yield, cubic feet per pound volatile solids destroyed 0:7 Volatile solids voided, pounds per day Percent reduction 49 of volatile solids 4:1 Potential gas production cubic feet per animal unit per day 103 Energy production rate, Btu per hour per animal 70 Available energy Btu per hour (after heating digester) Source: Fulhage et al. [225]
4. 5. 6. 7. 8.
Dairy (1,200 lb) 7:7
9:5
31
22:7
Poultry (4 lb bird) 8:6
0:044
56
Beef (1,000 lb) 15
5
41
0:21
31
568
5:25
775
380
3:5
520
Complete-mixed digesters [241, 242] Fixed-film digesters [243–245] Temperature-phased anaerobic digesters [246–251] Anaerobic sequencing-batch reactor (ASBR) [252–266] Upflow anaerobic sludge bed (UASB) [267–271]
Among these technologies, covered lagoons, plug-flow digesters, complete mixed digesters and fixed-film digesters are most common. A comparison of these four technologies is provided by the US Environmental Protection Agency and is given in Table 6.20. Basic components of a manure digester are shown in Fig. 6.40. Various components required for operating a continuous-mix, heated anaerobic digester are expensive and require a substantial investment. Biomethane can be also produced from a number of other wastes. In the USA, California is the leader of utilization of biomethane. Krich et al. [273] analyzed the potential for biomethane production in California from diary and other wastes. Their findings are shown in Table 6.21.
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Table 6.20 Summary characteristics of digester technologies Covered lagoon Deep lagoon
Characteristics Digestion vessel
Level of technology Supplemental heat Total solids Solids Characteristics HRTa (days) Farm type Optimum location
Low No 0.5–3% Fine
Complete mix digester Round/Square in/ aboveground tank Medium Yes 3–10% Coarse
Plug flow digester Rectangular in-ground tank Low Yes 11–13% Coarse
Fixed film Above ground tank Medium No 3% Very fine
40–60 15C 15C 2–3 Dairy, hog Dairy, hog Dairy only Dairy, hog Temperate and All climates All climates Temperate warm and warm climates Source: US Environmental Protection agency [272] a Hydraulic Retention Time (HRT) is the average number of days a volume of manure remains in the digester Mixing device Other uses
Gas Collection pressure regulation
To heat exchanger
Gas Collector
Heated liquid
Air seal Liquid removal
Heat exchanger Digested liquid Pump
sludge removal
Pump
Digester Raw manure Holding dilution mixing
Sludge storage and disposal
Fig. 6.40 Basic components of a manure digester for methane production (Source: Fulhage et al.[225])
6.9 BioFuels Biomass can be converted directly into liquid fuels, called “biofuels,” which can be used as transportation fuel replacing petroleum [274–287]. The two most common types of biofuels are ethanol and biodiesel. Various process concepts for producing transportation fuels from biomass are shown in Table 6.22.
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Table 6.21 Potential methane generation from biomass sources, California Annual methane productiona (million ft3 /y) Biomass waste material Gross methane potential Technical methane potential Swine manureb Poultry layer manurec Poultry broiler manured Turkey manured Dairy manure Cattle feedlot manured Crop residues Vegetable residue Meat processing Rendering (wastewater)e Cheese whey (lactose permeate) Food processing waste Processed green wastef Landfilled manuref Landfilled composite organic waste Landfilled food wastef Landfilled green wastef Total
320 1;700 1;800 1;300 21;100 4;100 10;700 11;300 660 120 250 720 18;000 220 15;200 19;900 16;500
160 850 0 0 14,300 0 5,220 940 530 120 250 360 0 0 0 0 0
123;890
22,730
Krich et al. [273] Ft3 =y cubic feet per year a Unless otherwise indicated, these figures calculated based on Buswell AM., Hatfield WD (1936) Anaerobic fermentations. State of Illinois Dept. of Registration & Education, Div. of the State Water Survey, Urbana, IL, Bull No 32: 1–193 b American Society of Agricultural Engineers (ASAE). Standards 1990. 37th edition. American Society of Agricultural Engineers, St. Joseph, MI: 464 c RCM Digesters (1985) Study on poultry layer manure. February 1985 d California Biomass Collaborative (CBC) (2004) An assessment of biomass resources in California. http://faculty.engineering.ucdavis.edu/jenkins/CBC/Resource.html accessed 11/16/2010 e Metcalf A, Eddy E (1979) Wastewter engineering: treatment, disposal and reuse. 2 edition McGraw-Hill: 614 f Al Seadi T (11/20/2010) Good practice in quality management of AD residues in biogas production. IEA Bioenergy Task 24, Energy from Biological Conversion of Organic Waste. Available at . Accessed 20 Nov 2010
Ethanol, also known as ethyl alcohol or grain alcohol, can be used either as an alternative fuel or as an octane-boosting, pollution-reducing additive to gasoline. There are four basic steps for converting biomass to bioethanol: • Production of biomass such as corn or sugar cane. • Conversion of biomass to a useable fermentation feedstock (typically some form of sugar). • Fermentation of the biomass intermediates using suitable microorganisms including yeast and bacteria for production of ethanol. • Processing of the fermentation product into fuel-grade ethanol and byproducts that can be used to produce other fuels, chemicals, heat and/or electricity.
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BioFuels
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Table 6.22 Main conversion processes for biomass to transportation fuel Energy efficiency (HHV) Estimated production cost C energy inputs (euro cent/GJ fuel) Concept Hydrogen: via biomass gasification and subsequent syngas processing. Combined fuel and power production possible; for production of liquid hydrogen additional electricity use should be taken into account Methanol: via biomass gasification and subsequent syngas processing. Combined fuel and power production possible
Short term Long term Short term 60% (fuel only) 55% (fuel) 9–12 (C energy input 6% (power) of 0.19 GJe/GJ (C 0.19 GJe/GJ H2 for H2 for liquid liquid hydrogen) hydrogen)
Long term 5–8
55% (fuel only)
48% (fuel) 12% (power)
10–15
6–8
45% (fuel only) Fischer-Tropsch liquids: via biomass gasification and subsequent syngas processing. Combined fuel and power production possible
45% (fuel) 10% (power
12–17
7–9
46% (fuel) Ethanol from wood: production takes 4% (power) place via hydrolysis techniques and subsequent fermentation and includes integrated electricity production of unprocessed components
53% (fuel) 8% (power)
12–17
5–7
(continued)
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Table 6.22 (continued)
Concept Ethanol from sugar beet: production via fermentation; some additional energy inputs are needed for distillation
Energy efficiency (HHV) C energy inputs
Estimated production cost (euro cent/GJ fuel)
Short term 43% (fuel only) 0.065 GJeC 0.24 GJth/GJ EtOH
Short term Long term 20–30 20–30
Long term 25–35%
85 l EtOH per ton 95 l EtOH per ton of Ethanol from sugar wet cane. of wet cane, cane: production Electricity generally via cane crushing surpluses depend energy neutral and fermentation on plant lay-out and with respect to and power power generation power and heat generation from technology the bagasse. Mill size, advanced power generation and optimized energy efficiency and distillation can reduce costs further in the longer term Biodiesel RME: takes place via extraction (pressing) and subsequent esterification. Methanol is an energy input. For the total system it is assumed that surpluses of straw are used for power production
8–12
88%; 0.01 GJe C 0.04 GJ MeOH per GJ output 25–40 Efficiency of power generation in the shorter term, 45%; in the longer term, 55%
7–8
20–30
Source: International Energy Agency [22] •
•
•
Assumed biomass price of clean wood: E2/GJ. RME cost figures varied from E20/GJ (shortterm) to E12/GJ (longer term), for sugar beet a range of E8–E12/GJ is assumed. All figures exclude distribution of the fuels to fuelling stations For equipment costs, an interest rate of 10%, economic lifetime of 15 years is assumed. Capacities of conversion unit are normalised on 400 MWth input in the shorter term and >1,000 MWth input using advanced technologies and optimised systems in the longer term Diesel and gasoline production costs vary strongly depending on the oil prices, but for indication: recent cost ranges (1990s till 2006) are between E4 and E9/GJ. Longer term projections give estimates of roughly E6–E10/GJ. Note that the transportation fuel retail prices are usually dominated by taxation and can vary between Ect50 and Ect130 /l depending on the country in question
6.9
BioFuels
Table 6.23 Typical oil extraction from 100 kg of oil seeds
385
Crop Oil/100 kg Castor seed 50 kg Copra 62 kg Cotton seed 13 kg Groundnut kernel 42 kg Mustard 35 kg Palm kernel 36 kg Palm Fruit 20 kg Rapeseed 37 kg Sesame 50 kg Soybean 14 kg Sunflower 32 kg Source: Petroleum Club (with permission) [310]
The production of ethanol from biomass is discussed in details in Chap. 7. In the USA, the goal of ethanol production is about 28:4 hm3 by 2012. The drastic increase in the price of crude oil is encouraging worldwide increase of the ethanol production. The potential of biofuels for transportation may be limited since it may come at the expense of global food production. This is discussed in more details in Volume 4 of this book series. The expansion of biofuels has various other limitations. A major issue is the subsidies provided by various governments to their agricultural sectors. Although Brazil has foregone most agricultural subsidy to its sugar industry, the agricultural sectors in both the USA and EU countries are provided with subsidies particularly for ethanol and other biofuels production. The subsidy for ethanol production in the USA costs US$ 5 billion per year in 2009. Agricultural subsidies have been challenged during the Doha round of World Trade Organization negotiations as being bad for the environment (by encouraging intensive agriculture) and for their negative effects on the development of agriculture in third-world countries.
6.9.1 Biodiesel Biodiesel is a form of diesel fuel manufactured from vegetable oils, animal fats, or recycled restaurant greases by esterification [288–309]. It is considered safe, biodegradable, and produces less air pollutants than petroleum-based diesel. The energy content of biodiesel is about 90% that of petroleum diesel. There is a variety of vegetable oil that can be used for production of biodiesel [310–332]. Rapeseed and soybean oils are most commonly used; soybean oil alone accounts for about 90% of all feed stocks. Other oils such as mustard, flax, sunflower, palm oil have been also explored. Several researchers have also proposed the use of algae for biofuel production [333–336]. A list of vegetable oils that are promising feedstock for biodiesel is given in Table 6.23.
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Although biodiesel may be considered as renewable energy source, significant agricultural land must be dedicated for continuous and reliable supply of feedstock. Table 6.24 shows the land requirements for production of various types of vegetable oil yielding crops. Animal fats including tallow, lard, yellow grease, chicken fat and the by-products of the production of Omega-3 fatty acids from fish oil can also be used as the feedstock. For commercial production of vegetable oils, about 20 different species are used with soybean oil, palm/palm kernel oil, sunflower, rapeseed (Colza), and coconut oils. Although the worldwide annual production of oils and fats was about 142 mt in 2004–2005, the consumption was at around 138 mt. A 22% annual reserve stock to consumption ratio was maintained (According to the FAO Food Outlook series reports the 2004/2005 production [337]). Biodiesel production is increasing rapidly. Palm oil and soy oil comprise 50% of the annual vegetable oil production. The mandates by several governments are likely to increase the production of biodiesel. Brazil has a nationwide mandate for B2 in 2008 resulting in an estimated 1.1 hm3 demand for biodiesel (935 kt). The EU mandates the use of 5.75% biofuels in the transportation sector by 2010. The biodiesel production by several countries is given in Table 6.25. Europe, the largest producer and user of biodiesel, produces most of it from rapeseed (canola) oil. The USA, the second largest producer and user of biodiesel, makes it from soybean oil and recycled restaurant grease.
6.9.2 Biofuel Production Method Vegetable oils generally contains 16 and 22 carbon atoms that are generally in the form of triacyl glycerides (TAG), which on transesterification with methanol produce glycerol as a by-product and fatty acid methyl ester (FAME) as the precursor to biodiesel. After FAME purification and testing for compliance with either EN 14214 or ASTM D6751 standards, the product can be sold as biodiesel and as blends – typically B5 (5% biodiesel) to B20, depending on the engine warranties. There are three basic routes for synthesis of biodiesel or alkyl esters from oils and fats: • Base catalyzed transesterification of the oil with alcohol. • Acid catalyzed esterification of the oil with alcohol. • Lipase catalyzed transesterification. Among these methods, base catalyzed transesterification is mostly used for production of biodiesel [341–416]. This method has several advantages over the other two methods; it requires a low temperature 65ı C (150ıF) and pressure 1.4 bar (20 psi), a conversion in the range of 98% is achievable, by-products have various uses and values, and methyl ester is produced directly without any intermediate reactions.
6.9
BioFuels
387
Table 6.24 Yields of common crops in different measurement units Crop Kg oil/ha Liters oil/ha lbs oil/acre US gal/acre Corn (maize) 145 172 129 18 Cashew nut 148 176 132 19 Oats 183 217 163 23 Lupine 195 232 175 25 Kenaf 230 273 205 29 Calendula 256 305 229 33 Cotton 273 325 244 35 Hemp 305 363 272 39 Soybean 375 446 335 48 Coffee 386 459 345 49 Linseed (flax) 402 478 359 51 Hazelnuts 405 482 362 51 Euphorbia 440 524 393 56 Pumpkin seed 449 534 401 57 Coriander 450 536 402 57 Mustard seed 481 572 430 61 Camelina 490 583 438 62 Sesame 585 696 522 74 Safflower 655 779 585 83 Rice 696 828 622 88 Tung oil tree 790 940 705 100 Sunflowers 800 952 714 102 Cocoa (cacao) 863 1;026 771 110 Peanuts 890 1;059 795 113 Opium poppy 978 1;163 873 124 Rapeseed (Canola) 1;000 1;190 893 127 Olives 1;019 1;212 910 129 Castor beans 1;188 1;413 1;061 151 Pecan nuts 1;505 1;791 1;344 191 Jojoba 1;528 1;818 1;365 194 Jatropha 1;590 1;892 1;420 202 Macadamia nuts 1;887 2;246 1;685 240 Brazil nuts 2;010 2;392 1;795 255 Avocado 2;217 2;638 1;980 282 Coconut 2;260 2;689 2;018 287 Oil palm 5;000 5;950 4;465 635 Chinese tallow 5;500 6;545 4;912 699 6;894 7;660 6;151 819 Algae (actual yield)a 39;916 47;500 35;613 5;000 Algae (theoretical yield)b Source: Chinese tallow data, Mississippi State University. Used with permission from The Global Petroleum Club [310] Chinese tallow (Triadica sebifera, or Sapium sebiferum) is also known as the “Popcorn Tree” or Florida Aspen a Actual biomass algae yields from field trials conducted during the NREL’s aquatic species program, converted using the actual oil content of the algae species grown in the specific trials b Algae yields are projected based on the sustainable average biomass yields of the NREL’s aquatic species program, and an assumed oil content of 60%. Actual oil content was much less
388 Table 6.25 Biodiesel production by various countries in 1,000 tons
6 Bioenergy
Country Germany France Italy Malaysia USA Czech Republic Poland Austria Slovakia Spain Denmark UK Other EU Total
2004 1;035 348 320 83 60 57 15 13 70 9 6 2;016
2005 11;669 492 396 260 250 133 100 85 78 73 71 51 36 3;694
2006 2;681 775 857 600 826 203 150 134 89 224 81 445 430 7;495
Source: European Biodiesel Board [338], Malaysian Palm Oil Board [339], National Biodiesel Board, USA [340]
Fig. 6.41 Schematic diagram of a biodiesel production system (Source: National Biodiesel Board [340])
A schematic diagram of the process is shown in Fig. 6.41. A fat or oil is reacted with an alcohol, generally methanol, in the presence of a catalyst to produce glycerine and methyl esters or biodiesel. The unused methanol is recovered and recycled back to the system. The catalyst is usually sodium or potassium hydroxide, which is mixed with methanol before feeding to the reactor. The feed generally contains 12% alcohol, 1% catalyst, and rest oil. The product contains 86% methyl ester along with 9% glycerine, 4% unreacted alcohol, and 1% other components. An acid catalyzed esterification method is preferred if feedstock has a high free fatty acid (FFA) content (as is common with rendered fats and spent restaurant oils) [417–449]. Excess of alkali used in alkali catalyzed processes causes loss of the free fatty acids as their insoluble soaps. However, the acid-catalyzed reaction requires higher reaction temperatures (100ıC) and longer reaction times than alkali-catalyzed transesterification. The transesterification process is catalyzed by BrØnsted acids, preferably by sulfonic and sulfuric acids.
6.10
Biofeedstock for Industrial Chemicals
389
In the lipase catalyzed transesterification process, lipase is used as a biocatalyst for synthesis of biodiesel from oil and FFA [450–499]. Lipase-catalyzed transesterification reactions offer several advantages over chemically catalyzed reactions. Both alkaline and acid transesterification reactions have several backdraws: they are energy intensive, recovery of glycerol is difficult, the catalyst has to be removed from the product, wastewater requires treatment, and free fatty acids and water interfere with the reaction. In addition, they have low selectivity, as a result various undesirable side reactions take place. Lipase-catalyzed transesterification reactions can be carried out at much milder operating conditions and can overcome the problems of conventional chemical processes discussed above. The second-generation biodiesel is often called ‘renewable diesel’ and is produced by treating vegetable oil with hydrogen over catalysts in oil refineries. This is intended for use as a blend or co-processed with ‘fossil diesel’. The resultant product can be used in the range of B5 – B50 [500, 501]. As a fuel, the FAME biodiesel has about 90–95% of the volumetric energy content of regular diesel.
6.10 Biofeedstock for Industrial Chemicals Biofuels can be used as a feedstock to produce a number of industrial chemicals in a similar fashion as produced from the crude petroleum feed. The process of producing various industrial chemicals from biofuels is called biorefining [502–508]. There are several advantages for biorefining that include: • Lower feedstock costs: This may allow access to markets for bioproducts whose volume is too high and/or price is too low to be accessed when using corn as a raw material. • New markets: There is a potential to create new markets for products, such as polylactic acid and 1,3-propanediol. • Tax incentives: Biorefinery may qualify for various tax breaks. • Sustainable resource supply: Biomass refining has the potential to significantly reduce both greenhouse gas emissions and to slow down the non-renewable resource depletion. • Energy security: By reducing the dependence on foreign oil and the military investment associated with this dependence, large-scale biomass refining would enhance a nation’s energy security. • Rural economic development: By creating a large market for energy crops, various economic developments in rural areas are possible. Industrial and consumer products that can be manufactured wholly or in part from renewable biomass (plant-based resources) are listed in Table 6.26. Kamm and Kamm [509] provided an excellent review of various industrial products that can be derived from biomass through biorefining processes, which are shown in Figs. 6.42–6.47.
390 Table 6.26 Chemicals from renewable biomass
6 Bioenergy
Biomass resources Corn
Vegetable oils
Wood
Uses Solvents, pharmaceuticals, adhesives, starch, resins, binders, polymers, cleaners, ethanol Surfactants in soaps and detergents, pharmaceuticals (inactive ingredients), inks, paints, resins, cosmetics, fatty acids, lubricants, biodiesel Paper, building materials, cellulose for fibers and polymers, resins, binders, adhesives, coatings, paints, inks, fatty acids, road and roofing pitch
Fig. 6.42 Products from biological raw materials (Printed with permission from Kamm and Kamm [509])
6.10
Biofeedstock for Industrial Chemicals
391
Fig. 6.43 Possibility of various industrial chemicals from different types of biomass (Printed with permission from Kamm and Kamm [509]) Ligno-Cellulosic Feedstock Biorefinery [LCF-Biorefinery] LC-Feedstock (LCF) e.g. Cereals (Straw, Chaff); Ligno-Cellulosic Biomass (e.g. Reed, Reed Grass); Forest Biomass (Underwood, Wood); Paper-and Cellulosic Municipal Solid Waste
Lignocellulose (LC) Lignin
Hemicellulose
Cellulose
“Phenol-polymer”
Pentoses, Hexoses
“Glucose-polymer”
Hydrolysis
Natural Binder and Adhesives Sub-bituminous Coal Sulphur-free Solid Fuel
Xylose (Pentose)
Plant Gum Thickeners, Adhesives, Protective Colloids, Emulsifiers, Stabilizers
Celluloseapplicants
Xylite Sugar-Substitute
Hydrolysis (E/C)
Glucose HMF
(Hexose)
(5-Hydroxymethyl-furfural),
Furfural
Levulinic Acid
Furan Resins
Softener + Solvents
Chemical Products
Lubricants
Nylon 6; Nylon 6,6
Chemicals and Polymers
FermentationProducts ● Fuels e.g. Ethanol ● Organic Acids e.g. Lactic Acid ● Solvents Acetone, Butanol
Fig. 6.44 Various routes for producing consumer products from lignocelluloses (Printed with permission from Kamm and Kamm [509])
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6 Bioenergy
Combustion Electricity
Grain [ Cereals, Corn, Maize ]
Energy
Straw Decomposition
Elevatedpressure Gasification Biotechnological Conversion
Fields
Seed
Grinding
Meal
Strach
Extrusion
Directly Use Decomposition to paste/ pasting
Co-Extrusion
Chemical Conversion / Modification
Plasticization
Sorbitol
PHB
Methanol
Ether formation
Esterification
Ethanol
Syngas
Red. Amination
Fermentation
AcetateStarch
Glucosamine
Hydrogenation
Cellulose
Hemicellulose
Lignin
Glucose
Carboxymethyl Starch
Binder Bio-Plastic Adhesive
Co- and Mixpolymerisate
Cement
Fig. 6.45 Products from various grains (Printed with permission from Kamm and Kamm [509]) Precursors-contained Biomass Wood / Soft wood
BiomassPrecursors Straw Bagasse Leaf Lignin
Cereals / Maize
Carbohydrates
Lignin
Cellulose
Starch
Levulinic acid
Soya/Rape
Fats
Saccharose
Alfalfa / Grass/Clover
Proteins Aminoacids
Oil
enzymatic
chemical
Energy MaterialPrecursors
Sugar-beet /-cane
Feed
Enzymes
Glucose bacterial Acetic acid
Syngas
2,3-Pentanedion
Lactic acid Acrylic acid
Ethanol Dilactide Methanol Ethene Gasoline
Ethyllactate
Polymers
Fig. 6.46 Production routes for various industrial chemicals from a variety of biomass (Printed with permission from Kamm and Kamm [509])
6.11
Summary
393
Green Crop Drying Plant Wet Fractionation
Energy
Green (Wet) Raw Material
Press
Press Cake drying to Pellets + Bales
Power Station Heat, Electricity
Press Juice
Valuable Products
Biogas
Fermentation Fermenter
Carbohydrate Sources
Separation Decanter Lactic Acid + Derivatives
Green Pellets for Fodder Pellets or Bales for Solid Fuel
Enzymes Flavourings
Raw Material for Syngas
Dyes
Raw Material for Hydrocarbons
Amino Acids Carbohydrates
Proteins Pre-Treatment
Raw Material for Biogas
Proteins
Enzymes Whole Crops, Straw, Seeds, Starch, Hydrolyzate, Molasse, a.o.
Fields
Grass, Lucerne, Alfalfa, Herb a.o.
Organic Acids Ethanol
Raw Material for Fibres + Fleece Raw Material for Chemicals e.g. Levulinic Acid
Fig. 6.47 Production routes for various industrial chemicals from green crops (Printed with permission from Kamm and Kamm [509])
6.11 Summary Bioenergy is a renewable energy source as it is derived from biological sources, which can be replenished on a regular basis. Bioresources include dedicated energy crops and trees, agricultural crop wastes and residues, wood wastes and residues, and aquatic plants as well as animal, municipal, and other wastes. Bioenergy can be used for the generation of heat, electricity or biofuel for vehicles. Biofuel derived from plant materials is among the most rapidly growing renewable energy technologies. Recent legislations by various countries suggest further growth of both corn-based and advanced biofuels from other sources. In the United States, cornbased ethanol is currently the largest source of ethanol as a gasoline substitute or additive. Biomass resources can also be used to produce varieties of chemicals such as glues, cleaners, solvents, and plastics. The generation of heat or electricity using biomass requires continuous and reliable supply of biomass. To ensure the continuous supply, energy crops must be planted and harvested on a regular basis requiring additional lands. This may have significant implications for world agriculture. The impacts of bioenergy on food security have been highly debated. A set of criteria, indicators, good practices and policy options must be developed for sustainable bioenergy production that safeguards and, if possible, fosters food security.
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Problems 1. Define biomass. 2. Describe bioenergy. 3. What types of feedstock development are necessary to sustain the bioenergy? 4. What are energy crops? 5. Describe the mechanisms by which plants store energy. 6. What are the sources of biomass? 7. How much of biomass resources are being used as a fuel source? 8. Where are biomass resources located? 9. Is municipal solid waste (MSW) considered biomass? 10. How is biomass used for electric power generation? 11. Explain biomass gasifiers. 12. What are the best biomass fuels for electric power generation? 13. What are different techniques for producing electric power from biomass? 14. What are the advantages of biomass co-firing power generating systems? 15. Describe liquid fuel production processes from biomass. 16. What is the likely delivered cost of switchgrass in the U.S., per dry ton? 17. How many acres of land would be necessary in order to have a steady supply of bioenergy feedstock for a 1 MW power plant? 18. Compare the cost of electricity from biomass with conventional power plants. 19. What kind of biomass is grown for bioenergy systems? 20. Can energy crops be used for home use? 21. How does woody bioenergy crop used by wildlife compare to that of natural forests? 22. Will energy crops put pressure on forests in the United States, including National Forests? 23. Can roadside land and interstate medians be used for energy crops, and how tall are they? 24. Would use of animal wastes as energy sources encourage more large animalraising operations? 25. How can trees and forests act as a carbon sink?
6.11
Summary
395
26. Does tree harvesting cancel out the carbon sink? 27. How is the area for crop production calculated? 28. What area of land is needed to supply bioenergy to a 1 MW power station? 29. What area of forest is needed to offset the CO2 emissions from a 1 MW power station or from running a car for 100 km? 30. Can land be managed simultaneously as a carbon sink and for bioenergy and fiber production? 31. What are your thoughts on feedstock supply in the developing world? Does the food vs. fuel debate not hold up there as well? 32. What is green crude and its outlook for production? 33. What are the five top candidate biomass materials in the US? 34. In the wild, fires consume massive cellulosic mass. Can this be harvested and reduce fire hazards? 35. How do you produce microalgae in large scale for energy production? 36. How do you get the oil out of microalgae? 37. What is the current perspective of the necessary breakthroughs in algal biofuels development; genetic engineering, yield improvements, processing (harvesting, extraction, refining), or the biorefinery business model? 38. Will cap and trade and/or tax subsidies affect bioenergy? 39. Can biofuel operations also produce energy? 40. Do tropical areas have an advantage for feedstock production? 41. Is oil an attractive feedstock for biofuel? 42. What is a vertically integrated operation? 43. What does the dairy farmer need to do to turn the manure into profit? 44. How much manure is necessary on a continuous basis to operate a 1 MW electricity generating plant? 45. What is biodiesel? 46. How is biodiesel made? 47. Does special types of engine necessary to use biodiesel? 48. What is the mileage of biodiesel vehicles? 49. What types of chemicals can be derived from biofuel? 50. What are the issues surrounding lignocellulosic production of ethanol?
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Chapter 7
Ethanol
Abstract Ethanol is considered to be the best alternative to gasoline as a liquid fuel for use in automobiles. Although ethanol can be produced from a variety of biomass, currently the main focus is on the use of corn and sugarcane as the feedstock. Corn is the main feedstock in the USA, whereas it is sugarcane in Brazil for ethanol production. However, corn is not considered to be an ideal feedstock for ethanol. Not only it is one of the major food grains of the world, but also the energy balance for ethanol production is not very attractive. Alternative to corn are lignocelluloses based plants, such as switchgrass, that are rich in cellulose or lignin. Since, the biomass can be harvested on an annual basis, ethanol produced from these biomasses may be considered as a renewable energy source. Production methods of ethanol from corn, sugarcane, and lignocelluloses and its uses as energy sources are discussed in this chapter.
7.1 Introduction The best known use of ethanol is as an alcoholic beverage. It is also used extensively in various industrial applications that include the use as a solvent in the manufacture of varnishes and perfumes, as a preservative for biological specimens, in the preparation of essences and flavorings, in many medicines and drugs, and as a disinfectant. The use of ethanol in automobiles goes back to the days of Henry Ford, 1908, who envisioned ethanol as the primary fuel for his Model T car [1]. Although Henry Ford eventually used gasoline for Model T, currently the use of ethanol as fuel is increasing rapidly worldwide [2–10]. Various fuel properties of ethanol are compared with that of gasoline and No. 2 diesel in Table 7.1. As can be seen from Fig. 7.1, the use of ethanol as alcoholic beverage and industrial chemical remains rather flat, but its use as fuel increasing rapidly. In the USA, ethanol received a major boost in its use and production with the passage of the Clean Air Act Amendments (CAAA) of 1990. Various events that helped to boost the ethanol production are shown in Fig. 7.2. T.K. Ghosh and M.A. Prelas, Energy Resources and Systems: Volume 2: Renewable Resources, DOI 10.1007/978-94-007-1402-1 7, © Springer Science+Business Media B.V. 2011
419
420 Table 7.1 Fuel properties of common transportation fuels Property Ethanol Chemical formula C2 H5 OH Molecular weight 46.07 Carbon 52.2 Hydrogen 13.1 Oxygen 34.7 0.796 Specific gravity, 60ı F=60ı F Density, lb/gal @ 60ı F 6.61 172 Boiling temperature, ı F Reid vapor pressure, psi 2.3 Research octane no. 108 Motor octane no. 92 (R C M)/2 100 Cetane no.(1) – Fuel in water, volume % 100 Water in fuel, volume % 100 173.2 Freezing point, ı F Viscosity, centipoise @ 60ı F 1.19 Flash point, closed cup, ı F 55 793 Autoignition temperature, ı F Lower 4.3 Higher 19 Btu/gal @ 60ı F 2,378 396 Btu/lb @ 60ı F 44 Btu/lb air for stoichiometric mixture @ 60ı F Higher (liquid fuel-liquid water) Btu/lb 12,800 Lower (liquid fuel-water vapor) Btu/lb 11,500 Higher (liquid fuel-liquid water) 84,100 Btu/gal 76;000a Lower (liquid fuel-water vapor) ı Btu/gal @ 60 F Mixture in vapor state, Btu/cubic foot 92.9 @ 68ı F Fuel in liquid state, Btu/lb or air 1,280 Specific heat, Btu=lbı F 0.57 Stoichiometric air/fuel, weight 9 Volume % fuel in vaporized 6.5 stoichiometric mixture Source: U.S. Department of Energy [11] a Calculated value b Pour point ASTM D97 c Based on cetane
7 Ethanol
Gasoline C4–C12 100–105 85–88 12–15 0 0.72–0.78 6.0–6.5 80–437 8–15 90–100 81–90 86–94 5–20 Negligible Negligible 40 0.37–0.44a –45 495 1.4 7.6 900 150 10
No. 2 Diesel C3–C25 200 84–87 33–16 0 0.81–0.89 6.7–7.4 370–650 0.2 – – N/A 40–55 Negligible Negligible 40–30b 2.6–4.1 165 600 1 6 700 100 8
18,800–20,400 18,000–19,000 124,800
19,200–20,000 18,000–19,000 138,700
115,000
128,400
95.2
96:9c
1,290 0.48 14:7a 2
– 0.43 14.7 –
To meet the oxygen requirements in the fuel mandated by the CAAA, blending of ethanol with gasoline became a popular method. One of the objectives of the CAAA was to reduce carbon monoxide (CO) and ground-level ozone concentration in the
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Introduction
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Fig. 7.1 World ethanol use by various sectors (Source: Berg [12])
20000
60 RFS (?)
15000
50
30
10000 Clean Air Act
20
Cents/gallon
40 California
5000 10 0
0 1980 1984 1988 1992 1996 2000 2004 2008 2012 1978 1982 1986 1990 1994 1998 2002 2006 2010 Tax incentive (Y2)
Output (Y1)
Fig. 7.2 Ethanol production in the USA. RFS Renewable Fuel Standard (Source: Berg [12])
air. Oxygen level in gasoline of about 2.7% by weight for oxygenated fuel and 2.0% by weight for reformulated gasoline would be necessary to achieve the goal stated in the CAAA. As stated by the Energy Information Administration, “The Energy Policy Act of 1992 (EPACT) allowed two additional gasoline blends (7.7% and 5.7% ethanol). It also defined ethanol blends with at least 85% ethanol as “alternative transportation fuels.” It also required specified car fleets to begin purchasing alternative fuel vehicles, such as vehicles capable of operating on E-85 (a blend of 85% ethanol and 15% gasoline). EPACT also provided tax deductions for purchasing (or converting) a vehicle so that it could use an alternative fuel, such as E-85, and for installing equipment to dispense alternative fuels.
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The Clean Air Act Amendments mandated the winter-time use of oxygenated fuels in 39 major carbon monoxide non attainment areas (areas where the US Environmental Protection Agency (USEPA) emissions standards for carbon monoxide had not been met) and required year-round use of oxygenates in nine severe ozone non attainment areas in 1995. During 1999, some states began to pass legislation banning the use of Methyl Tertiary Butyl Ether (MTBE) in motor gasoline, because traces of it were showing up in drinking water sources, presumably from leaking gasoline storage tanks. MTBE was the primary oxygenate used in gasoline in the USA prior to 1999. Because ethanol and Ethyl Tertiary Butyl Ether (ETBE) are the main alternatives to MTBE as an oxygenate in gasoline, these bans increased the need for ethanol as the MTBE ban went into effect. In 2000, the USEPA recommended that MTBE should be phased out nationally. California began switching from MTBE to ethanol to make reformulated gasoline, resulting in a significant increase in ethanol demand by mid-year, even though the California MTBE ban did not officially go into effect until 2004. The Energy Policy Act of 2005 mandated that the gasoline sold in the USA must contain a minimum volume of renewable fuel, called the Renewable Fuels Standard. The regulations aimed to double the use of renewable fuel, mainly ethanol made from corn, by 2012. The Energy Independence and Security Act of 2007 expanded the Renewable Fuels Standard to require that 36 billion gallons (136,275 thousands cubic meter) of ethanol and other (27,254 thousands cubic meter) fuels be blended with gasoline, diesel, and jet fuel by 2022. The United States consumed 6.8 billion gallons (25,740 thousands cubic meter) of ethanol and 0.5 billions gallons (1,892 thousands cubic meter) of biodiesel in 2007. As of March 2008 (23,469 thousands cubic meter), United States ethanol production capacity was at 7.2 billion gallons (27,354 thousands cubic meter), with an additional 6.2 billion gallons (23,469 thousands cubic meter) of capacity under construction. Brazil is the second largest producer of ethanol and a leading exporter. As shown in Fig. 7.3, the ethanol production in Brazil is increasing slowly over the last decade. Brazil is consuming a significant percentage of their own ethanol for transportation. The fuel consumption in Brazil by fuel type is shown in Table 7.2. In 2008, Brazil used about 19,600 thousands cubic meter of ethanol fuel. The ethanol consumption in Brazil is increasing due to the introduction of flex-fuel cars. Table 7.3 shows the increase in the number of flex-fuel cars in Brazil, which increased from just over 48 thousands in 2003 to nearly 2 millions in 2007. Currently (as of May 2009) ethanol use in light vehicles in Brazil is more than 50% of the use of gasoline. When trucks and other diesel vehicles are included, ethanol represents about 20% of the road transportation usage. Ethanol represents 15% of the total supply of liquid fuels in Brazil. In 2003, the European Commission issued directives that will govern European Union (EU) biofuels policy through 2010. The commission adopted a target of 5.75% biofuels consumption in the transportation sector by 2010. However, the directive also had a target of 2% biofuel use by 2005, since there were little biofuel productions in Europe outside of the biodiesel production in Germany. The directive was designed to promote ethanol demand and supply and provided
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Introduction
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22.478
Anhydrous Hydrous
20
17.720 14.808
15 10.592
11.535
10 5.62
6.465
12.622
15.416 15.946 8.302 8.304
7.838
7.015 9.418 8.108
2006-07
2005-06
2002-03
2004-05
5.07
14.300
5.896
2003-04
4.972
2001-02
7.112 5.607
2007-08
5
0
8.178
8.912
2000-01
Ethanol Production (Billion Liters)
25
Crop Year
Fig. 7.3 Ethanol production in Brazil (Source: Global Agriculture Information Network (GAIN) [13])
Table 7.2 Various types of fuel consumption in Brazil Yearly fuel consumption (in thousands m3 ) Fuel type 2003 2004 2005 Diesel 36,853 39,219 39,052 21,791 23,165 23,542 Gasoline Ca Hybrid ethanol 3,245 4,355 4,654 Source: ANP[14] a Includes 20–25% anhydrous ethanol
2006 39,854 23,979 6,010
2007 41,559 24,326 9,367
Table 7.3 Brazil’s sales of light vehicles Year Gasoline Ethanol Flex-fuel 2000 1,310,479 10,292 2001 1,412,420 18,335 2002 1,283,963 55,961 2003 1,152,463 36,380 48,178 2004 1,077,945 50,950 328,379 2005 697,033 32,357 812,104 2006 316,561 1,863 1,430,334 2007 245,660 107 1,995,090 Source: National Association of Automotive Vehicle Manufacturers and Associac¸a˜ o Nacional dos Fabricantes de Ve´ıculos Automotores (ANFAVEA) [15]
2008 44,764 25,175 13,290
424 Table 7.4 Bioethanol production in Europe (million liters)
Table 7.5 World production of fuel ethanol in 2008
7 Ethanol
Country 2004 2005 2006 Germany 25 165 431 Spain 254 303 396 France 101 144 293 Poland 48 64 161 Sweden 71 153 140 Italy 0 8 78 Hungary 0 35 34 Lithuania 0 8 18 Netherlands 14 8 15 Czech Republic 0 0 15 Latvia 12 12 12 Finland 3 13 0 Total 528 913 1,592 Source: European Biomass Industry Association [16]
Country
Millions of gallons
USA 9000.0 Brazil 6472.2 European 733.6 Union China 501.9 Canada 237.7 Total 17,335.2 Data source: Licht [17]
Country
Millions of gallons
Other Thailand Colombia
128.4 89.8 79.29
India Australia
66.0 26.4
tax benefits and exemptions to facilitate growth. The target of 2% biofuel use by 2005 was non-binding. The biofuel use in the EU’s 25 member states in 2006, before Romania and Bulgaria joined the trade bloc in January, reached about 1.4%. However, in March 2006, the EU unveiled its Renewable Energy Roadmap that created a binding target of 10% biofuel use by 2020 for all of its 27 member states. Bioethanol productions by various European countries are given in Table 7.4. The leading ethanol producing countries in the world are given in Table 7.5. Ethanol is becoming an attractive fuel additive in many countries. The feedstock for ethanol can be home grown and produced locally since the technology is fairly well known. The use of ethanol can reduce the import of petroleum by most of the countries around the world. As a result, a number of countries are mandating the use of ethanol in the gasoline. The ethanol blending requirements mandated by various countries are given in Table 7.6.
7.2 Ethanol Production from Corn Ethanol can be produced from petroleum products, starches, sugar and lignocelluloses. Depending on the starting feedstock, production methods also differ. Various
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Ethanol Production from Corn
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Table 7.6 Ethanol blending requirements by various countries Country Current ethanol blending requirement Brazil All gasoline must contain between 20% and 25% anhydrous ethanol. Currently, the mandate is 23% Canada By 2010, 5% of all motor vehicle fuel must be ethanol or biodiesel France Set target rates for incorporation of biofuels into fossil fuels (by energy content). Calls for 5.75% in 2008, increasing to 10% in 2010 Germany 8% energy content in motor fuels by 2015, 3.6% coming from ethanol Lithuania Gasoline must contain 7–15% ETBE. The ETBE must be 47% ethanol Poland Mandatory “National Biofuel Goal Indicators” calling for biofuels to represent a set percentage of total transportation fuel use. 2008’s standard is 3.45%, on an energy content basis Argentina Requires the use of 5% ethanol blends by 2010 Thailand Gasoline in Bangkok must be blended with 10% ethanol India Requires 5% ethanol in all gasoline China Five Chinese provinces require 10% ethanol blends – Heilongjian, Jilin, Liaoning, Anhui, and Henan The Philippines Requires 5% ethanol blends in gasoline beginning in 2008. The requirement expands to 10% in 2010 Bolivia Expanding ethanol blends to 25% over the next 5 years. Current blend levels are at 10% Colombia Requires 10% ethanol blends in cities with populations over 500,000 Venezuela Phasing in 10% ethanol blending requirement Source: Renewable Fuels Associations [18] ETBE ethyl tertiary butyl ether
routes for ethanol productions are given below and the basic steps involved in the production of ethanol from these feedstocks are shown in Fig. 7.4. • Direct hydration of ethylene • Indirect hydration of ethylene • Ethanol from corn – Dry milling and fermentation – Wet milling and fermentation • Sugar crop fermentation • Ethanol from lignocellulose Among these methods, direct hydration of ethylene [19–24] and indirect hydration of ethylene [25–27] processes use a catalyst to convert ethylene, a petroleum product from the refinery, to ethanol. The rest of the methods are bio-based and are discussed in details later in this chapter.
7.2.1 Structure, Types, and Composition of Corn Corn and sugarcane are considered to be the two main feedstocks for production of ethanol. The use of other feedstocks, such as switchgrass, is still in the evaluation stage. Beside its use for the production of ethanol, corn has a number of other uses. These are summarized in Fig. 7.5.
Fig. 7.4 Processes for ethanol production from various feedstocks [28]
426 7 Ethanol
7.2
Ethanol Production from Corn
427
Fig. 7.5 Various components of a corn kernel and their potential use (Source: Food and Agriculture Industry [29])
Several varieties of corn are grown worldwide; some of them are for specific purposes and are discussed below. Dent corn (Zea mays indentata) is also called field corn. Its kernels contain both hard and soft starch and become indented at maturity. The major use of dent corn is for food production, animal feed, and industrial products, such as ethanol. This is the only variety used for cornstarch manufacturing. Flint corn (Zea mays indurate) has a hard, horny, rounded or short and flat kernel with the soft and starchy endosperm completely enclosed by a hard outer layer. This is grown mostly in South America and used for the same purposes as dent corns. Waxy corn has a waxy appearance when cut and contains only a branched-chain starch. Waxy corn is processed in a wet milling process to produce waxy cornstarch which slowly retrogrades back to the crystalline form of starch. It is grown to make special starches for thickening foods, particularly those that undergo large temperature changes in processing and preparation. Sweet or green corn is eaten fresh, canned, or frozen. It can be grown in many horticultural varieties. Its kernels contain a high percentage of sugar in the milk stage when they are eaten fresh. Popcorn (Zea mays everta) has small ears and small pointed or rounded kernels with very hard corneous endosperm. When exposed to high dry heat, they pops
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or everted by the expulsion of the contained moisture, and form a white starchy mass many times the size of the original kernel. It got its name from this popping characteristic. Indian (Zea mays) corn has white, red, purple, brown, or multicolored kernels. It was the original corn grown by the Indians. It is a attractive Halloween decorations in the USA. High-Amylose corn is a specialty corn, whose kernels have amylose content higher than 50%. This starch is used in textiles, candies, and adhesives. High-Oil corn contains 7–8% oil, 2–3% more than dent corn. High-oil corn also has enhanced protein quality and quantity. High-Lysine corn contains increased levels of two amino acids that are essential in the diet of non-ruminant animals, such as swine. The two amino acids are lysine and tryptophane. Flour corn (Zea mays amylacea) also called soft corn or squaw corn. Its kernels are shaped like those of flint corn and composed mostly of soft starch. The USA grows small amounts of blue flour corn to make tortillas, chips, and baked goods. In South America, this corn is grown in various colors to make food and beer. The appearance of different types of corn kernels is shown in Fig. 7.6. Not only the appearance of the corn kernels varies from one corn to another corn, but they are also different in their chemical compositions. The chemical analysis of three types of corn is given in Table 7.7. Among these corns, dent corn is most suitable for ethanol production. Most of the corn crops in the United States are yellow dent corn. Its vitamin A content,
Fig. 7.6 Kernels of most common corns (Source: Dickerson [30]) Table 7.7 Chemical composition of some common corns
Chemical compounds Flint in 100 g of grain corn Protein 10.7 Fat 4.7 Fiber 2.7 Starch 69.6 Sugars 1.9 Source: Domin and Kluza [31]
Popping corn 10.4–14.6 3.8–5.3 – 62.2–71.8 –
Sweet corn 2.1–4.5 1.1–2.7 0.9–1.9 3.0–20.0 2.5–8.5
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Ethanol Production from Corn
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Fig. 7.7 A mature dent corn kernel. (1 and 2 vertical sections in two planes of a mature kernel of dent corn, showing arrangement of organs and tissues). a silk scar, b pericap, c aleurone, d endosperm, e scutellum, f glandular layer of scutellum, g coleoptile, h plumule with stem and leaves, i first internode, j lateral seminal root, k scutellar node, l primary root, m coleorhiza, n basal conducting cells of endosperm, o brown abscission layer, p pedicel or flower stalk. 3 enlarged section through pericap and endosperm. a pericap, b nucellar membrane, c aleurone, d marginal cells of endosperm, e interior cells of endosperm. 4 enlarged section of scutellum. a glandular layer, b interiror cells. 5 vertical sction of the basal region of endosperm. a ordinary endosperm cells, b thick walled conducting cells of endosperm, c abscission layer (Source: Kiesselbach [32])
high feed value and availability in various hybrid forms account for its extensive use. Of the cereal grains, it contains the highest amount of carotene (vitamin A). Dent corn originated from crosses of flint and floury corns. Dent hybrids vary in the proportion of hard and soft endosperm. A careful analysis of dent corn is necessary before its processing and fermentation. A detailed structure of a dent corn kernel is shown in Fig. 7.7.
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Table 7.8 Composition of various components of yellow dent corn on percent of dry basis Kernel Component Percent (%) Starch (%) Protein (%) Oil (%) Ash (%) Sugars (%) Fiber (%) Endosperm 82:9 88:4 Germ 11:0 11:9 Bran coat 5:3 7:3 Tip cap 0:8 5:3 Whole kernel 100:0 75:0 Source: Bunge Milling [33]
8:0 18:4 3:7 9:1 8:9
0:8 29:6 1:0 3:8 4:0
0:3 10:5 0:8 1:6 1:5
Table 7.9 Proximate analysis of yellow dent corn grain Characteristic Moisture (% wet basis) Starch (% dry basis) Protein (% dry basis) Fat (% dry basis) Ash (oxide) (% dry basis) Pentosans (as xylose) (% dry basis) Fiber (neutral detergent residue) (% dry basis) Cellulose C Lignin (acid detergent residue) (% dry basis) Sugars, total (as glucose) (% dry basis) Total carotenoids (mg/kg) Source: White and Johnson [34]
0:6 10:8 0:3 1:6 1:7
Range 7–23 61–78 6–12 3.1–5.7 1.1–3.9 5.8–6.6 8.3–11.9 3.3–4.3 1.0–3.0 12–36
1:9 18:8 86:9 78:6 8:9
Average 16:0 71:7 9:5 4:3 1:4 6:2 9:5 3:3 2:6 26:0
The chemical composition of a dent corn kernel is given in Table 7.8. The composition can vary signficantly from one batch to another and even from one kernel to another kernel. The range of various contituents of corn kernels obtained from proximate analysis in given in Table 7.9.
7.2.2 Processing of Corn There are two approaches for converting corn to ethanol [35–41]: • Dry Milling Process • Wet Milling Process In the USA, the wet milling process was preferable in the 1990s. At present, dry milling processes are the most common type for ethanol production. In 2008, dry milling processes represented almost 90% of the ethanol production from corn (See Fig. 7.8). As discussed later in this chapter, the dry milling process requires fewer steps and equipment than the wet milling process providing better economy for ethanol production. 7.2.2.1 Dry Milling Process for Ethanol Production In dry milling, the entire corn kernel is first grounded into flour, and the starch in the flour is converted to ethanol via fermentation [42–55]. The other products are
7.2
Ethanol Production from Corn
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5000 Forecast
Wet Mill Process
4000
3000
2000
2015
2014
2013
2012
2011
2010
2009
2008
2007
2006
2005
2004
2003
2002
2001
2000
0
1999
1000
1998
Corn Used (Million Bushels)
Dry Mill Process
Year
Fig. 7.8 A comparison of corn use between dry mill and wet mill processes (Source: Food and Agricultural Policy Research Institute [41])
carbon dioxide (used in the carbonated beverage industry) and animal feeds called distillers dried grain with soluble. The dry milling process for production of ethanol may be divided into following five steps: 1. 2. 3. 4. 5.
Milling (Biomass Handling) Liquefaction Hydrolysis (Saccharification) Fermentation Distillation and Recovery
The ground corn flour, which is referred to as meal, is processed without separating out the various components of the grain kernel. Various processing steps are shown in Fig. 7.9. The liquefaction process involves making slurry of the meal with water to form a mash. Enzymes are added to the mash to convert the starch to sugar (dextrose). Ammonia is added for pH control and as a nutrient to the yeast. The mash is next cooked at a high-temperature to reduce bacteria levels prior to fermentation. The mash is cooled and transferred to fermenters where yeast is added for the conversion of sugars to ethanol. Carbon dioxide .CO2 / is also produced during the fermentation process. The fermentation process generally takes about 40–50 h. During fermentation, the mash is agitated continuously for uniform distribution of yeast and is kept cool to maintain high activity of the yeast. After fermentation, the resulting beer is transferred to distillation columns where ethanol is separated from the remaining stillage. The ethanol is concentrated to 190 proof using conventional distillation method and then is dehydrated to approximately 200 proof using a molecular sieve desiccant system. (The proof of an alcohol beverage is equal to twice the
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Fig. 7.9 Dry milling process for ethanol production (Courtesy of Singh et al. [43])
percentage of ethyl alcohol contained therein, Therefore, pure ethanol is 200 proof).The anhydrous ethanol is then blended with about 5% denaturant (such as natural gasoline) to make it a non-beverage, and thus allows its exemption from alcohol tax. The stillage is sent through a centrifuge that separates the coarse grain from the solubles, and several co-products are produced. The co-products are Corn Distillers Dried Grains (DDG), Corn Condensed Distillers Solubles (CDS), Corn Distillers Dried Grains/Solubles (DDGS), and Wet Distillers Grains with Solubles (WDGS). These products are described below. • Distillers Dried Grains (DDG) is obtained after the removal of ethanol by distillation from the yeast fermentation of grains or grain mixtures by separating the resultant coarse grain fraction of the whole stillage and drying it by methods employed in the grain distilling industry. • Distillers Dried Grains with Solubles (DDGS) is the product obtained after the removal of ethanol by distillation from the yeast fermentation of grains or grain mixtures by condensing and drying at least 3/4 of the solids by methods employed in the grain distilling industry. • Condensed Distillers Solubles (CDS) is the product obtained after the removal of ethanol by distillation from the yeast fermentation of grains or grain mixtures by condensing the thin stillage fraction to a semi-solid.
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• Wet Distillers Grains with Solubles (WDGS): Wet distillers grains (WDG) is the main co-product with the remaining volume after fermentation of corn starch to ethanol. Soluble nutrient-rich syrup is separated during the fermentation process which can be sold for feeding purposes as such or added back to the final product to obtain wet distillers grains plus solubles. The solubles from the dry milling processes are concentrated to about 30% solids by evaporation, resulting in CDS or “syrup”. The coarse grain and the syrup are then dried together to produce DDGS. This is a high quality feed for livestock. The CO2 released during fermentation is typically used for carbonating soft drinks and beverages.
7.2.2.2 Wet Milling In the wet milling process, the corn kernel is separated into three parts: (1) the hull, (2) the germ, and (3) the endosperm in an aqueous medium prior to fermentation [56–59]. The primary products of wet milling include starch and starch-derived products (e.g. high fructose corn syrup and ethanol), corn oil, and corn gluten. As shown schematically in Fig. 7.10, the process consists of several steps. A wet mill generally receives shelled corns, which pass through mechanical cleaners designed to remove unwanted material, such as pieces of cobs, sticks, husks, meal and stones. The cleaned corns are next fed into “steep” tanks, where these are soaked in dilute sulfuric acid from 24 to 48 h at a temperature of 125ı F .52ı C/. Steeping softens the kernel, helps to break down the protein holding the starch particles, and removes various soluble constituents. A number of tanks are used in series. Corn that has steeped for the desired length of time is discharged from the tank for further processing, and the tank is filled with fresh corn. Generally, water drained from the first steep tank is discharged to evaporators, called “light steepwater” that contains about 6% of the original dry weight of the grains. The solids from steepwater are rich in protein and are concentrated to 30–55% solids in multiple-effect evaporators. The resulting steeping liquor can be sold as animal feeds. The germ is removed from the steeped corn in the degerminating mills, which break the kernel apart to free both the germ and about half of the starch and gluten. The germ is separated in liquid cyclones from the mixture of fiber, starch, and gluten. It is subsequently washed, dewatered, and dried, and further processed to extract corn oil. The starch and gluten from the product slurry are removed from the rest of the fibrous material by further washing, grinding, and screening operations. The discarded hulls are dried for use in animal feeds. The starch is separated from gluten by centrifugation. A number of stages may be necessary. The separated starch is fed to the fermenter for production of ethanol.
434
Fig. 7.10 Corn wet milling process flow diagram (Source: Watson and Ramstad [60])
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Ethanol Production from Corn
435
7.2.3 Fermentation Process The fermentation step for the ethanol production is the controlling step of the process. It is a biological process in which complex organic materials are converted by microorganisms mainly to sugars. Sugars and similar compounds are further fermented by microorganisms to produce ethanol and CO2 . The selection of microorganisms for the fermentation is very critical. Several bacteria, yeasts, and fungi have been reportedly used for the production of ethanol. Among various microorganisms, yeasts are preferred for ethanol production, and among the yeasts, Saccharomyces cerevisiae also known as Bakers’ yeast, is most widely used. Saccharomyces cerevisiae can produce ethanol providing a concentration as high as 18% of the fermentation broth. Other types of bacteria explored by various researchers are given in Table 7.10. Another type of yeast that has been studied for ethanol production is Zymomonas mobilis. It can tolerate higher ethanol loading, up to 120 g/l ethanol and can yield 5–10% more ethanol per fermented glucose. However, Z. mobilis ferments only glucose, fructose, and sucrose and is not as hardy as Saccharomyces cerevisiae. A variety of microorganisms have been engineered to selectively produce ethanol. Several gram-negative bacteria have been engineered for this purpose that include: Escherichia coli, Klebsiella oxytoca, and Zymomonas mobilis. Engineered E. coli was able to ferment a wide spectrum of sugars. However, E. coli works in a
Table 7.10 Bacterial species used by various researchers for production of ethanol as main fermentation product Mesophilic organisms Clostridium sporogenes Clostridium Indoli (pathogenic) Clostridium sphenoides Clostridium sordelli (pathogenic) Zymomonas mobilis (syn. Anaerobica) Zymomonas mobilis subsp. Pomaceas Spirochaeta aurantia Spirochaeta stenostrepta Spirochaeta litoralis Erwinia amylovora Escherichia coli KO11 Escherichia coli LY01 Leuconostoc mesenteroides Streptococcus lactis Klebsiella oxytoca Klebsiella aerogenes Mucor sp. M105 Source: Lin and Tanaka [66]
mmol ethanol produced per mmol glucose metabolized up to 4.15a 1.96a 1.8a (1.8)b 1.7 1.9 1.7 1.5 (0.8) 0.84 (1.46) 1.1 (1.4) 1.2 0.7–0.1 40–50 g ethanol produced/l 1.1 1.0 0.94–0.98 24 g ethanol produced/l –
References [62] [62] [62] [62] [62] [62] [62] [62] [62] [62] [63, 64] [63] [62] [64] [65] [63]
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7 Ethanol
narrow and neutral pH range (6.0–8.0). It is a less hardy culture compared to yeast. Also, by-products may be tainted with E. coli reducing their value. Fermentation of starch is more challenging than fermentation of sugars because starch must first be converted into sugar and then into ethanol. Although, yeasts discussed above are capable of fermenting starch, the process is rather slow. According to Abouzied and Reddy [61], “Synergistic coculture of an amylolytic yeast (Saccharomycopsis fibuligera) and S. cerevisiae, a non-amylolytic yeast, fermented unhydrolyzed starch to ethanol with conversion efficiencies over 90% of the theoretical maximum. Fermentation was optimal between pH 5.0 and 6.0. Using a starch concentration of 10% (w/v) and a 5% (v/v) inoculum of S. fibuligera, increasing S. cerevisiae inoculum from 4% to 12% (w/v) resulted in 35–40% (w/v) increase in ethanol yields. Anaerobic or “limited aerobic” incubation almost doubled ethanol yields”. Conversion of cellulose to ethanol is some what complex. Saccharomyces cerevisiae and other engineered bacteria are not effective in fermenting cellulose. Various anaerobic thermophilic bacteria have been explored by a number of researchers and are given in Table 7.11. However, not only the fermentation process is found to be very slow (3–12 days), the yield was also poor (0.8–60 g/l of ethanol). Another disadvantage of using bacteria for fermentation is the production of various by-products, primarily acetic and lactic acids.
7.2.4 Byproducts from Corn Processing By-products from both dry and wet milling processes play an important role in determining economic viability of these two processes for ethanol production [81–87, 89, 90]. As discussed later in this chapter, byproducts are crucial in determining the energy balance of the fuel ethanol production from corns. Currently, nearly 3.8 million tons of distillers dry grains are produced during domestic dry grind ethanol production. For every bushel of corn made into ethanol, 18 pounds of DDGS are generated and must maintain the product value to contribute to plant profitability. The capacity for ethanol production is set to double in the near future and assuming that dry grind production will double as well, the potential supply of DDGS will be almost 7 million tons. The dry grind ethanol process uses most of the starch present in the corn kernel during ethanol fermentation, leaving protein, fat, minerals and vitamins behind in a concentrated form.
7.2.5 Comparison Between Dry Mill and Wet Mill Processes The amount of ethanol produced per bushel of corn in the USA by dry mill process is slightly higher than that by the wet mill process. A comparison of various byproducts produced by these two processes is shown in Fig. 7.11.
5.0
28
30
4.5
30
A3-S. cerevisiae
– 4.5
24 30
5.0
5.0
5.0
30
30
6.0
–
30–35
27
pH value 5.5
Temp .ı C/ 30
Fiso-S. cerevisiae
181-S. cerevisiae (aerobic) UO-1-S. cerevisiae (aerobic) V5-S. cerevisiae ATCC 24860-S. cerevisiae Bakers’ yeast-S. cerevisiae Bakers’ yeast-S. cerevisiae
Strain-species 27817Saccharomyces cerevisiae L-041-S. cerevisiae
Galactose (20–150)
Galactose (20–150)
Sucrose (220)
Glucose (250) Molasses (1.6–5.0) Sugar (150–300)
Sucrose (20)
Glucose (10)
Sucrose (100)
Carbon source and concentration (g/l) Glucose (50–200)
Peptone(5) and ammonium dihydrogen phosphate (1.5) Peptone, ammonium sulfate and casamino acid (10) Peptone, ammonium sulfate and casamino acid (10)
Ammonium sulfate (1) – Ammonium sulfate (0.72–2.0) –
Nitrogen source and concentration (g/l) Peptone (2) and ammonium sulfate (4) Urea (1) or ammonium sulfate (1–2) Peptone (5.0)
60
4.8–36.8
4.8–40
96.71
96
60
53 (max)
– 5–18.4
–
–
25–50
Concentration of ethanol produced (g/l) 5.1–91.8
192
36 24
60–96
40–160
24
Incubation time (h) 18–94
Table 7.11 Yeast species employed by various researchers for production of ethanol as the main fermentation product
(continued)
[75]
[75]
[74]
[73]
[71] [72]
[70]
[69]
[68]
References [67]
7.2 Ethanol Production from Corn 437
5.5
30
5.5
5.5
4.5
30
30
ATCC-32691-Pachysolen 30 tannophilus Source: Lin and Tanaka [66]
30016-Kluyveromyces marxianus 30091-Candida utilis
5.5
30
27774-Kluyveromyces fragilis 30017-K. fragilis
6.0 6.0 6.0 4.5 5.5 –
30 30 30 30 30 –
GCB-K5-S. cerevisiae GCA-II-S. cerevisiae KR18-S. cerevisiae CMI237-S. cerevisiae 2.399-S. cerevisiae 24860-S. cerevisiae
pH value 5.0
Temp .ı C/ 30
Strain-species L52-S. cerevisiae
Table 7.11 (continued)
Glucose (0–25) and xylose (0–25)
Glucose (100)
Glucose (100)
Glucose (20–120)
Glucose (20–120)
Sucrose (30) Sucrose (30) Sucrose (30) Sugar (160) Glucose (31.6) Glucose (150)
Carbon source and concentration (g/l) Galactose (20–150)
Nitrogen source and concentration (g/l) Peptone, ammonium sulfate and casamino acid (10) Peptone (5) Peptone (5) Peptone (5) Ammonium sulfate (0.5) Urea (6.4) Ammonium dihydrogen phosphate (2.25) Peptone (2) and ammonium sulfate (4) Peptone (2) and ammonium sulfate (4) Peptone (2) and ammonium sulfate (4) Peptone (2) and ammonium sulfate (4) Peptone (3.6) and ammonium sulfate (3) 100
18–94
18–94
18–94
18–94
72 72 72 30 30 27
7.8 (max)
44.4 (max)
44.4 (max)
48.96 (max)
48.96 (max)
27 42 22.5 70 (max) 13.7 (max) 48 (max)
Incubation Concentration of time (h) ethanol produced (g/l) 60 2.4–32.0
[80]
[67]
[67]
[67]
[67]
[76] [76] [76] [77] [78] [79]
References [75]
438 7 Ethanol
7.2
Ethanol Production from Corn
439
THE WET MILLING PROCESS 12.4 lbs of 21% protein feed 2.5 gallons of ethanol (or)
3.0 lbs of 60% gluten meal
33 lbs of sweetener 1.5 lbs of corn oil
(or) 31.5 lbs of starch
17 lbs of carbon dioxide THE DRY MILLING PROCESS
2.7 gallons of ethanol
10 one-lb boxes of cereal
22 lbs of hominy feed for livestock
15 lbs of brewer grits
0.7 lbs of corn oil
10 eight-oz packages of cheese curls
17 lbs of carbon dioxide
1 lb of pancake mix
Fig. 7.11 Various products from a bushel of corn by dry mill and wet mill processes (Source: Module 2 Ethanol Science and Technology [91]) Table 7.12 Potential byproducts from dry mill ethanol process Grits are used in Corn meal goes into Corn cones/flour is used in Brewing beer Corn flakes Other breakfast cereals Snack foods
Bakery mixes Cereals Corn bread Corn meal mixes Corn muffins Fritters Hush puppies Pancake mixes Snacks Spoon bread
Baby foods Bakery mixes Breadings, coatings and batters Cereals Dusting for pizzas English muffins Fermentation processes Meat products Pancakes, muffins, doughnuts
Source: Iowa Corn [92]
Although both the processes produce almost the same amount of ethanol, the main difference between these two processes is in the production of various byproducts that have very high product-value. By-products from a wet mill process are more versatile than from a dry mill process and are compared in Tables 7.12 and 7.13.
440
7 Ethanol
Table 7.13 Potential byproducts from wet mill ethanol process Industrial starch uses
Industrial sweetener uses
Industrial fermentation products
Paper, recycled paper Cardboard Textiles Glues and adhesives Batteries Bookbinding Cleaners, detergents
Acetic acid Charcoal briquettes Dyes and inks Enzymes Insecticides Laminated building materials Matches
Coatings on paper, wood and metal Color carrier for printing Crayons and chalk, dyes Fireworks Industrial filters and water recovery Lubricants Ore and oil refining Paints, Plastics Rubber tires Surgical dressings Wallboard and wallpaper
Metal plating Organic solvents Paper Plasticizing agents Rayon Shampoo Shoe polish Textiles Theatrical makeup
Acetic and amino acids Blankets and bedding Carpet tile Cosmetics Electroplating and galvanizing Food packaging Disposable cold drink cups, plates and cutlery Industrial chemicals Leather tanning Mannitol Organic solvents Paper Plastics Plasticizers Soaps and cleaners Sports and active wear Textiles
Food and drug starch uses Aspirin Baby food Baked goods Baking powder Cake, cookie, dessert mixes Candies Cereals Coffee whitener Dried soups Drugs Gravy mixes Instant breakfast foods Instant pudding mix Instant tea Salad dressings Spray cooking oil
Food and drug sweetener uses Alcoholic beverages and brewing Baby foods Bacon, sausage Cereals, baked goods Caramel color Carbonated and fruit beverages Canned fruits, fruit fillings Cheese spreads Chewing gum, condiments Confections, chocolate Drugs Food coloring Frosting and icing Frozen and dried eggs Hams, Hot dogs, bologna Ice cream, sherbets, and frozen puddings Jams, jellies, preserves Marshmallows, peanut butter Pet food Pickles and relishes Snack foods (pretzels, potato chips, corn chips) Soups, spices Tomato sauces, vegetables Vinegar, yeast
Powdered mixes Powdered sugar Precooked frozen foods Salt Seasoning mixes Yeast
Source: Iowa Corn [92]
Food and drug fermentation products Antibiotics Bakery products Citric acid Drugs Enzymes Food acids Pharmaceuticals Wine
7.2
Ethanol Production from Corn
441
Fig. 7.12 A comparison between dry mill and wet mill processes (Source: Module 2 Ethanol Science and Technology [91])
As discussed earlier, the dry mill processes are used more and more in the USA for the production of ethanol from corn. As shown in Fig. 7.12, one of the main reasons for using the dry mill process is the elimination of a number of steps that can reduce both the capital investment and the operating costs compared to the wet mill process.
442
7 Ethanol 0.6 Dry mill
$ 0.53 0.5
Wet mill
$ 0.46
$ 0.46
Cost ($ per gallon)
$ 0.41
$ 0.44 $ 0.39
0.4
0.3
0.2
0.1
0.0 15
30
40
(million gallons per year)
(million gallons per year)
(million gallons per year)
Plant Size Fig. 7.13 A comparison of ethanol production cost between dry mill and wet mill by plant size (Source: Kansas Energy Chart Book [93])
A comparison of ethanol production cost between these two processes is shown in Fig. 7.13. Although the cost decreased for both processes with the increase in the plant size, the production cost by the dry mill process always remained lower compared to the wet mill process.
7.3 Sugar Crop Fermentation Various sugar crops that include sweet sorghum, sugar cane, and sugar beats are also used for ethanol production [94–111]. Among these feedstocks, sugarcane is used most widely. During ethanol production from sugarcane, cane stocks are washed, crushed and milled to extract the juice and produce bagasse. The cane juice is sent to a clarification process for removal of impurities. The clear juice is sterilized and directed toward a fermentation tank. S. cerevisiae is used for the fermentation, which is continuously separated by centrifugation and recycled back to the fermenter. The stillage is further treated for generation of by-products that can be used as a fertilizer for cane plantations. A schematic of the process is shown in Fig. 7.14.
7.5
Production of Ethanol from Cellulosic Biomass
Sugarcane
Purge
443
Water
7
1 Yeast
2
9
8
10
Sulfuric acid
3
5
Sugarcane juice
Fermentation gases Yeast recycle
Bagasse
4 Cachaze
6 Culture broth
13 Flue gases
Regenerate
Condensed 11 water
Wastewater Stillage
Water
Ethanol
Steam
12
Very low Low pressure High pressure steam pressure steam steam
Concentrated stillage (Fertilizer)
Fig. 7.14 Simplified flowsheet of fuel ethanol production from sugarcane. 1 Washing tank, 2 Mill, 3 Clarifier, 4 Rotary drum, 5 Fermenter, 6 Centrifuge, 7 Ethanol absorber, 8 Concentration column, 9 Rectification column, 10 Molecular sieves, 11 Evaporator train, 12 Combustor, 13 Turbogenerator (Printed with permission from Quintero et al. [112])
7.4 Corn Versus Sugarcane Corn and sugarcane are the two main feedstocks for commercial production of ethanol. Several researchers compared between corn and sugarcane as the feedstock for ethanol production and noted that a variety of factors determine their use by a country [113–115]. The USA and Brazil are the two top producers of ethanol. As mentioned earlier, the USA uses corn as the feedstock, whereas sugarcane is used as the main feedstock in Brazil. An analysis of these two countries with respect to the ethanol production can provide some insight regarding the factors associated with the choice of a feedstock. This is provided in Table 7.14. The main factors in the choice of the feedstock are climate, growing season, and availability of land and water.
7.5 Production of Ethanol from Cellulosic Biomass Cellulosic ethanol is attractive because feedstocks that include the agricultural wastes such as wheat straw, corn stover, grass, paper, cardboard, wood chips, and other fibrous plant material, are cheap and abundant [117–139]. The feedstock is
444
7 Ethanol
Table 7.14 Comparison of Brazil and the US ethanol industries Brazil – sugarcane United States – corn The sugar (sucrose) in sugarcane can be The starch in corn is first converted into sugar. converted directly into ethanol Then the sugar is converted into ethanol Sugarcane is planted every 6 years using Corn is planted every year using seeds cuttings Sugarcane provides five cuttings over 6 Corn is harvested once each year years and then is replanted Sugarcane yields about 35 t per acre (entire Corn yields about 8.4 t per acre (entire plant) per plant) per harvested acre harvested acre Sugarcane yields about 4.2 t of sucrose per Corn yields 4.2 t of corn grain per acre (150 acre (10–15% of sugarcane yield) bushels) or 2.4 t of starch An acre of sugarcane produces about 560 An acre of corn produces about 420 gallons of gallons of ethanol (35 t yield) ethanol (150 bushels yield) Sugarcane feedstock is cheaper to grower Corn feedstock is more expensive to grow than than corn per gallon of ethanol sugarcane per gallon of ethanol Sugarcane-ethanol can be produced Corn-ethanol is more expensive to produce than cheaper than corn-ethanol sugarcane-ethanol The by-product of ethanol production is The byproduct of ethanol production is distillers bagasse grains with soluble that is used as livestock feed Currently about 9 million acres are used for The energy source for ethanol production is ethanol production natural gas, coal, and diesel Brazil has great potential for expanding Currently about 28 million acres are used for sugarcane acreage without limiting the ethanol production acreage of other crops No subsidies for ethanol US expansion of corn acreage will come at the expense of reduced soybean and other crop acres No import tariffs on ethanol Subsidy reduced from $0.51 per gallon to $0.45 A $0.54 per gallon import tariff Source: Hofstrand [116]
outside the human food chain; therefore, does not raise moral or ethical issues like the use of corn. Converting cellulosic feedstocks into ethanol requires less fossil fuel compared to corn, so it can have a bigger effect than corn ethanol on reducing greenhouse-gas emissions. Potentially, an acre of grasses or other energy crops could produce more than two times the number of gallons of ethanol as an acre of corn. When using cellulosic biomass, the whole plant can be used instead of just the grain. Cellulosic biomass contains three main groups; cellulose, lignin, and hemicelluloses. Their percentage distribution is shown in Fig. 7.15. Cellulosic biomass also contains sugars, but they are much harder to extract than those in corn, sugarcane, and other starchy biomass. Therefore, special pretreatments are necessary to release the sugars [141–156]. Three major steps are involved in production of cellulosic ethanol: Pretreatment, Hydrolysis and Fermentation and process integration. Several by-products formed during the pretreatment process can inhibit fermentation, and also some of the sugars from cellulosic biomass are difficult to ferment. A process flow diagram showing the basic steps of production of ethanol from cellulosic biomass is given in Fig. 7.16.
7.5
Production of Ethanol from Cellulosic Biomass
445
Fig. 7.15 Composition of lignocellulose portion of biomass (Source: US Department of Energy [140])
Fig. 7.16 Processing of cellulosic biomass for ethanol production
7.5.1 Pretreatment The main objective of the pretreatment of cellulosic biomass is to make cellulose more accessible to enzymatic hydrolysis and solubilize hemicllulosic sugars. As shown in Fig. 7.17, the plant cell starts to disintegrate during the pretreatment stage. The tight bonding among lignin, cellulose, and hemicelluloses are broken by the process. The benefits of pretreatment include: no need for size reduction of biomass particles and the preservation of the pentose (hemicelluloses) fractions (See Fig. 7.18). It also limits formation of degradation products that inhibit growth of fermentative microorganism, minimizes energy demands, and limits cost.
446
7 Ethanol
Fig. 7.17 The effect of pretreatment of biomass (Courtesy of US Department of Energy [140])
Fig. 7.18 Objectives of pretreatment process (Printed with permission from Mosier et al. [155])
A variety of processes for the pretreatment of cellulosic biomass have been explored. These processes may be divided into following four categories [158]. • Biological Pretreatments [159–161] • Physical Pretreatments – Mechanical treatments [162–164] – Extrusion [165, 166] • Chemical Pretreatments – Acid pretreatment [167–176] – Alkali (Lime) pretreatment [177–182]
7.5
Production of Ethanol from Cellulosic Biomass
447
– Ozone pretreatment [183–185] – Organosolv [186–189] – Ionic liquid pretreatment [190–194] • Physico-Chemical Pretreatments – – – – – – – –
Uncatalyzed steam explosion [195–203] Liquid hot water [204–209] Ammonia fiber/freeze explosion (AFEX) pretreatment [210–220] Ammonia recycled percolation (ARP) pretreatment [221–227] Wet oxidation [228–233] Microwave pretreatment [234–238] Ultrasound pretreatment [239–245] Carbon dioxide explosion [246–248]
Among these processes, following processes are most widely used. Other processes are still at the experimental stage and require further evaluation before commercialization.
7.5.1.1 Uncatalyzed Steam Explosion Process Uncatalyzed steam explosion is used commercially to hydrolyze hemicelluloses for manufacture of fiberboard and other products by the Masonite process. In this process, high-pressure steam is applied for a few minutes. No other additives or chemical is necessary for removal of hemicelluloses. Following pressure treatment, a portion of steam is rapidly released from the treatment vessel into another vessel allowing rapid (flash) cooling of the biomass.
7.5.1.2 Liquid Hot Water Process In this process, pressurized water at a temperature of 200–230ıC is used to disrupt the plant structure within 15 min. The high pressure maintains the liquid state of water. About 40–60% of the total biomass is dissolved in the method. All of the hemicelluloses could be removed by this method, followed by 35–60% of the lignin. Only a small amount of cellulose (4–22%) is recovered. Both co-current and counter-current arrangement have been used with similar results. Using a proper design, a continuous flow through system can be employed.
7.5.1.3 Acid Pretreatment Process Dilute sulfuric acid is used to convert hemicelluloses to xylose and other sugar. However, sulfuric acid can continue to breakdown xylose to form furfural. A mixture of acid and biomass is heated either indirectly or by direct steam injection, at
448
7 Ethanol
temperatures of 160–220ı C for few seconds to few minutes. The acid concentration is typically in the range of 0.7–3.0%. However, a concentration as low as 0.07%, has also been tried in a flow through reactor. Although, sulfuric acid appears to be the best acid for pretreatment of the biomass, other acids including nitric, hydrochloric, and phosphoric acid have also been employed with a limited success.
7.5.1.4 Lime Pretreatment A lower temperature and pressure can be used during the alkali pretreatment compared to the acid pretreatment method. Generally, lime (CaO or Ca.OH/2 / is used to remove lignin and improve cellulose digestion by enzymes through opening up the structure. Lime pretreatment conditions are: 100ı C for 1–2 h at a lime loading of 0.1 g Ca.OH/2 =g biomass with 5–15 g water /g biomass. This process has been used to pretreat wheat straw, poplar wood, switchgrass, and corn stover. However, for these resources, the temperature range was 85–150ıC and the treatment time varied between 2 and 13 h.
7.5.1.5 Ammonia Fiber Expansion (AFEX) Pretreatment The AFEX process is operated in the same manner as the steam explosion process. Lignocellulosic biomass is first soaked with liquid ammonia under pressure and then the pressure is released rapidly. This causes the fiber to expand resulting in decrystalization of cellulose, and hydrolysis of hemicelluloses. The fiber structure is greatly disrupted altering the lignin that is present in the plant. This allows hydrolysis of cellulose to glucose with high yields at low enzyme loadings. Herbaceous and agricultural residues are well suited for AFEX process. However, this method works only moderately on hardwoods, and not so well on softwoods. Although AFEX pretreatment is a batch process, it can be modified to a continuous process called FIBEX (fiber extrusion) that can significantly reduce both the time required for the treatment, and the amount of ammonia required for the same level of hydrolysis, as for the batch AFEX process.
7.5.1.6 Ammonia Recycle Percolation (ARP) Pretreatment An aqueous solution containing 5–10% ammonia is fed through a column packed with biomass at a temperature in the range of 80–180ıC. Ammonia is separated from the outlet stream and recycled back to the column. As noted by Yang and Wyman [249], when incorporated with a biomass saccharification process, ARP technology almost completely fractionates biomass into three major constituents (pentose/pentosans, cellulose, and lignin). The solid residue is a low-lignin, shortchained cellulosic material with a high glucan content. Ammonia reacts primarily with lignin, not cellulose, and causes depolymerization of lignin and does not
7.5
Production of Ethanol from Cellulosic Biomass
449
react at all with carbohydrate linkages. The removal of lignin increases cellulose accessibility to cellulase. ARP pretreatment process works rather well with hardwoods as it enhances the enzymatic digestibility of hardwoods. ARP technology was subsequently employed to herbaceous biomass, corn stover, and switchgrass with good success. ARP method generally provides a high degree of delignification while keeping most of the cellulosic components in biomass intact. However, a substantial amount of xylan is also removed along with lignin. A two-stage process, in which another pretreatment method such as dilute acid or hot water treatment is used followed by the ARP, can provide better results. Wu and Lee [226] suggested a two-stage diluteacid percolation (DA) process as a pretreatment method for switchgrass. Extremely low acid concentration (0.078 wt% sulfuric acid) under moderate temperature .145–170ıC/ completely solubilized hemicellulose in switchgrass showing no sugar decomposition. The treated switchgrass contained about 70% glucan and 30% lignin. The DA pretreatment, when combined with the ARP process, was found to be more effective in delignification. Kim and Lee [250] noted from their laboratory study that with optimized operating conditions, in a two-stage processhot water treatment followed by ARP- the xylan fraction was hydrolyzed with 92–95% conversion, and was recovered with 83–86% yields; and the lignin removal was 75–81%. The remaining solid after two-stage treatment contained 78–85% cellulose. The two-stage treatments enhanced the enzymatic digestibility to 90–96% with 60 Filter-Paper-Unit (FPU)/g of glucan, and 87–89% with 15 FPU/g of glucan. A comparison of these pretreatment processes is given in Tables 7.15 and 7.16. Among these processes, the lime and ARP treatment processes are found to be most effective in breaking down the cellulose structure. Both the processes removed hemicelluloses and lignin from the plant wall. The lime treatment process requires the lowest temperature, but the treatment time of 4 weeks is extremely high compared to other processes, which require 10–24 min of treatment time, but also need a higher temperature.
7.5.2 Hydrolysis After the pretreatment process, two processes may be used to hydrolyze the pretreated feedstocks for fermentation into ethanol. The hydrolysis methods most commonly used are: • Acid hydrolysis [251–268] – dilute acid hydrolysis – concentrated acid hydrolysis • Enzymatic hydrolysis [269–292]
450
7 Ethanol
Table 7.15 Composition of solids from pretreatment of corn stover (percent of dry weight) by CAFI leading technologies and their digestibilities after 72 h for an enzyme loading of 15 FPU/g cellulose in the original feedstock
Percent lignin 17.2
Percent conversion at 72 h (15 FPU/g cellulose) 23.3
9.5
22.5
91.1
76.1
4.8
7.1
95.5
52.7 36.1
16.2 21.4
25.2 17.2
85.2 96.0
61.9
17.9
8.7
90.1
52.70
16.20
25.20
93.0
Pretreatment system Untreated corn stover Dilute acid
Temp ı C –
Reaction time, minutes –
Percent chemical used –
160
20
59.3
Flow through Control pH AFEX
200
24
0.49 of sulfuric acid Water only
190 90
15 15
ARP
170
10
Lime
55
None 100 of anhydrous ammonia 15 of ammonia 0.08 g CaO/g biomass
4 weeks
Percent glucan 36.1
Percent xylan 21.4
Source: Yang and Wyman [249] Table 7.16 Effect of various pretreatment methods on the chemical composition and chemical/physical structure of lignocellulosic biomass Increases accessible Removes Alters surface Decrystalizes hemicelRemoves lignin area cellulose lulose lignin structure Uncatalyzed Major effect steam explosion Liquid hot Major effect water pH controlled Major effect hot water Flow-through Major effect liquid hot water Dilute acid Major effect Flow-through Major effect acid AFEX Major effect ARP Major effect Lime Major effect Source: Mosier et al. [155]
–
Major effect
–
Minor effect
ND
Major effect
–
Minor effect
ND
Major effect
–
ND
ND
Major effect
Minor effect
Minor effect
– –
Major effect Major effect
– Minor effect
Major effect Major effect
Major effect Major effect ND
Minor effect Minor effect Minor effect
Major effect Major effect Major effect
Major effect Major effect Major effect
7.5
Production of Ethanol from Cellulosic Biomass
451
7.5.2.1 Acid Hydrolysis Dilute Acid Hydrolysis In this process, aqueous solution containing 1% sulfuric acid is used in a continuous flow reactor at a high temperature of about 215ıC to hydrolyze lignocellulosic biomass. The sugar conversion efficiency of this method is about 50%. The operating parameters of the dilute acid hydrolysis process require proper controls. The cellulosic materials that are converted to sugar could be further converted to other chemicals if the reaction continues. The conditions under which the first reaction takes place are also the right conditions for the subsequent reactions to occur. The second reaction proceeds rapidly to convert sugars into other products, such as furfural (See Fig. 7.19). The sugar degradation not only reduces the sugar yield, but furfural and other by-products can inhibit the fermentation process. Since,
Spruce wood
Hemicellulose
Cellulose
Lignin
CH3COOH
Acetic acid (3) CHO H HO H
CHO
CHO
OH
HO
H
H
H
HO
H
HO
H
OH
HO
H
OH
H
OH CH2OH
O
H
HO
H
H
H
OH
OH
H
OH
Galactose (4)
HOH2C
HCOOH
Furfural (6)
OH
Formic acid (8)
O
Phenolic compounds
CH2OH
CH2OH
Mannose (2)
CHO
H
OH
CH2OH
Xylose (1)
CHO
Glucose (5)
CHO
O H3C
Hydroxymethylfurfural (7)
C
CH2
CH2
COOH
Levulinic acid (9)
Fig. 7.19 Reactions products during hydrolysis of lignocellulosic materials (Printed with permission from Palmqvist and Hahn-Hagerdal [293])
452
7 Ethanol
hemicelluloses (5-carbon) sugars degrade more rapidly than cellulose (6-carbon) sugars, one way to decrease sugar degradation is to implement a two-stage process. The two-stage dilute acid process was developed by the NREL for softwood. The process proceeds as follows: • Stage 1: 0.7% sulfuric acid, 190ıC, and a 3 min residence time • Stage 2: 0.4% sulfuric acid, 215ıC, and a 3 min residence time The first stage maximizes the yield from the more readily hydrolyzed hemicelluloses. The second stage is optimized for hydrolysis of the more resistant cellulose fraction. The liquid hydrolyzed products are recovered from each stage and fermented to alcohol. Bench scale tests confirmed the potential to achieve yields of 89% for mannose, 82% for galactose and 50% for glucose. Fermentation with Saccharomyces cerevisiae provided ethanol conversion of 90% of the theoretical yield. Lime is used to neutralize residual acids before the fermentation stage. Sugar degradation still occurs. In the two-stage method about 80 gallons of ethanol per ton of dry wood could be produced. The residual cellulose and lignin are used as boiler fuel for electricity or steam production.
Concentrated Acid Hydrolysis In this method, the decrystallization followed by dilute acid hydrolysis is the controlling step of the process. Lignocellulosic biomass that has been dried to 10% moisture content is contacted with a 70–77% sulfuric acid solution at about 50ı C for 2–6 h in a reactor. Acid is added at a ratio of 1.25:1 (acid: cellulose C hemicellulose). The low temperature and pressure minimize the degradation of sugars. The sugar formed at this stage is recovered through repeated water wash. Adding water to dilute the acid to 20–30% and heating at 100ı C for an hour results in further release of sugars from hemicelluloses. The residual solid that is mainly cellulose is hydrolyzed in the next step. The residue is dewatered and soaked in a 30–40% concentrated sulfuric acid for 1–4 h. The acid concentration in the solution is increased to 70% through dewatering and evaporation. After reacting for another 1–4 h at low temperature, the sugar and acid are recovered and the acid is concentrated and recycled to the first stage to provide the acid needed for the first stage of hydrolysis. A complete and rapid conversion of cellulose to glucose and hemicelluloses to 5-carbon sugars can be achieved with little degradation. Sugar recovery efficiency of about 90% of both hemicelluloses and cellulose sugars is possible. The acid and sugar are separated via an ion exchange column and acid is reconcentrated via multiple effect evaporators. The low temperature and pressure employed in this process allow the use of relatively low cost materials such as fiberglass tanks and piping.
7.5
Production of Ethanol from Cellulosic Biomass
453
7.5.2.2 Enzymatic Hydrolysis Enzymatic hydrolysis involves splitting the constituents of cellulose and hemicelluloses using enzymes. The cellulose produces glucose as the main hydrolysis product, whereas hemicelluloses breaks down into several pentoses and hexoses during hydrolysis from mannan, xylan, glucan, galactan, and arabinan. One of the main issues with enzymatic hydrolysis is the blocking of the enzyme accessibility by lignin. This has several detrimental effects: end-product inhibition, reduced reaction rate, and lower yield. Cellobiose and glucose also act as strong inhibitors of cellulases. Enzymatic hydrolysis requires mild conditions and long periods of time. Maximum cellulase and “-glucosidase activities occur at 40–60ı C and pH of 4.0–5.0. However, optimal conditions may change depending on the hydrolysis time. Combining a pretreatment process, such as high temperature with dilute acid or enzymatic hydrolysis, could increase the efficiency of hydrolysis of cellulosic materials. Enzymatic hydrolysis of lignocelluloses to glucose occurs by the synergistic actions of three distinct classes of enzymes: the endo-1, 4-“-glucanases, which act randomly on soluble and insoluble 1, 4-“-glucan substrates, but in the regions of low crystallinity of the cellulosic fiber; the exo-1, 4-“-D-glucanases, which release D-glucose from 1, 4-“-D-glucans and hydrolyze D-cellobiose slowly and liberate D-cellobiose from 1, 4-“-glucan, which comes from the non-reducing end of cellulose chains.; and the “-D-glucosidases, which release D-glucose units from cellobiose, soluble cellodextrins, and a group of glycosides. The hydrolysis process sequence is shown in Fig. 7.20. “-D-glucosidases not only generate glucose from cellobiose but also reduce cellobiose inhibition, allowing the cellulolytic enzymes to function more efficiently. The cellulases and “-glucosidase are inhibited by cellobiose and glucose, respectively. For a complete hydrolysis of cellulose to glucose, all these three enzymes must be present in the solution and in proper proportions. endo–glucanase Cellulose chain Shorter cellulose chains
exo–glucanase
Cellobiose fragments beta–glucosidase
Glucose Yeast Ethanol
Fig. 7.20 Mechanism for ethanol synthesis (Source: Process Description and Overview of Enzymatic Hydrolysis Technology, SERI, TP-3161 [294])
454
7 Ethanol
Ethanol production from cellulosic biomass is challenging. To produce it cheap and to make it competitive with gasoline and other ethanol producing methods, the enzymatic hydrolysis process needs to address the following issues. • The pretreatment processes should be further optimized and new processes may be needed that do not require expensive and hazardous chemicals and/or high pressure expensive equipment. • A high density of cells within the reactor should be maintained and sugars must be converted to ethanol quickly to avoid product inhibition. • A process should be developed to combine enzymatic conversion of cellulose and hemicelluloses with the fermentation process to keep sugar levels low that can enhance the enzymatic conversion rates. • For a better product yield, both the cellulose (glucose) and hemicelluloses (xylose) should be utilized fully. • A process to remove ethanol from the reactor vessel continuously should be designed to maintain a high fermentation reaction rate.
7.5.3 Fermentation and Process Integration After hydrolysis, the product sugar is fermented to ethanol. Although the fermentation process is the same as that described earlier, to increase the ethanol yield, the fermentation process is often integrated with the hydrolysis step. For process integration, generally, the enzymatic hydrolysis method is preferred. Different types of process integration at different level are possible when enzymatic hydrolysis is used for ethanol production. In all cases, pretreatment of the biomass is required to make the cellulose more accessible to the enzymes, and to hydrolyze the hemicellulose. Various process integration schemes have been explored to reduce the product inhibition associated with enzyme, eliminate a number of steps and associated reactors, reduce costs, and enhance the ethanol yield [295,296]. Successful integration of all the unit operations of biomass conversion is the key element to enabling commercialization. Various unit operations should be linked together in a mini-pilot and full scale pilot plants to demonstrate functionality of integrated parameters for industrial scale applications. The general integration scheme for a lignocelluloses based ethanol plant is shown in Fig. 7.21. For lignocelluloses based ethanol plants, integration of pretreatment, hydrolysis, and fermentation units are critical for the success of the process. Four integration schemes have been suggested: • • • •
Separate or Sequential Hydrolysis and Fermentation (SHF) Simultaneous Saccharification and Fermentation (SSF) Simultaneous Saccharification and Co-Fermentation (SSCF) Consolidated BioProcessing (CBP)
7.5
Production of Ethanol from Cellulosic Biomass
455
Fig. 7.21 A general scheme for a lignocelluloses based ethanol plant
7.5.3.1 Sequential Hydrolysis and Fermentation (SHF) Traditionally, hydrolysis and fermentation processes are carried out in separate steps. In the SHF configuration, the hydrolyzed stream from the reactor first enters the glucose fermentation reactor [297–312]. The mixture is distilled to remove ethanol. The unconverted xylose is then fed to a second reactor where xylose is further fermented to ethanol. The product from the second reactor is again distilled in another column to separate ethanol. As shown in Fig. 7.22 a,b, both glucose and xylose could be fermented simultaneously, and a single distillation column would be sufficient for separation of ethanol.
7.5.3.2 Simultaneous Saccharification and Fermentation (SSF) The SSF process, shown in Fig. 7.23, consolidates the hydrolyses of cellulose with the direct fermentation of the produced glucose, which reduces the number of reactors [313–377]. This approach also avoids the problem of product inhibition associated with enzymes. The presence of glucose inhibits the hydrolysis reaction. In SSF, there is a trade-off between the cost of cellulase production and the cost of hydrolysis/fermentation. The optimum conditions should be determined from process conditions. The SSF process was also shown to be better than the saccharification and subsequent fermentation due to the rapid assimilation of sugars by yeast during SSF. Other advantages of the SSF process are listed below. • SSF requires lower amounts of enzyme. • The contamination can be minimized.
456
7 Ethanol
Fig. 7.22 Schematic diagrams of sequential hydrolysis (SSF) and fermentation process for ethanol production. (a) most common type of configuration, (b) more compact version of SSF (Source: Hamelinck et al. [163])
• The inhibition effects of cellobiose and glucose to enzyme are lower. • SSF process requires lower capital cost. • SSF process has higher ethanol yield. The main disadvantage of SSF process is that different temperatures are required for saccharification .50ı C/ and fermentation .35ı C/. Besides, ethanol itself exerts some inhibition. Therefore, a thermotolerant yeast capable of fermenting glucose to ethanol at temperatures above 40ı C, which can also promote saccharification in the range of 40–45ı C is desirable. The conventional yeast, Saccharomyces cerevisiae, appears to be the best microbe for the SSF process. A number of researchers are exploring various yeast strains to improve the performance of the SSF process.
7.5
Production of Ethanol from Cellulosic Biomass
457
Fig. 7.23 Block diagram for conversion of biomass to ethanol by Simultaneous Saccharification and Fermentation process (SSF) (Printed with permission from Wyman [378])
Fig. 7.24 Process flow diagram for simultaneous Saccharification and co-fermentation of biomass for ethanol production (Source: Aden [392])
7.5.3.3 Simultaneous Saccharification and Co-Fermentation (SSCF) The co-fermentation of hexoses and pentoses sugars is the focus of SSCF system. A schematic flow diagram of the system is shown in Fig. 7.24. The objective is to ferment both these sugars in a single reactor using a single microorganism. The pretreated hemicelluloses and solid celluloses are not separated after pretreatment. Hemicelluloses sugars are converted to sugar along with SSF of the cellulose. The main challenge of the SSCF process is to engineer or identify a microorganism that can co-ferment glucose and xylose [315, 327, 348, 379–388].
458
7 Ethanol
Fig. 7.25 A consolidated bioprocessing system for conversion of biomass to ethanol (Printed with permission from Hamelinck et al. [163])
A metabolically engineered strain of Zymomonas mobilis was developed by NREL for the co-fermentation of glucose and xylose by the SSCF process from a synthetic pre-hydrolyzed hardwood and glucose. Later McMillan et al. [389] from NREL used a variant of Z. mobilis for ethanol production from dilute-acidpretreated yellow poplar by the SSCF. Kim et al. [390] used a recombinant E. coli for corn stover that was pretreated by ammonia. Teixeira et al. [391] used a recombinant strain of Z. mobilis to convert hybrid poplar wood and sugarcane bagasse. 7.5.3.4 Consolidated BioProcessing (CBP) In this process, ethanol and all required enzymes are produced by a single class of microorganisms, in a single reactor [393–414]. The capital and operating costs could be reduced significantly by this approach, since dedicated enzyme production (or purchase), reduced diversion of substrate for enzyme production, and compatible enzyme and fermentation systems are not necessary. However, currently such organisms or compatible combinations of microorganisms are not available that can produce both cellulase and other enzymes at the required high levels and also produce ethanol at the required high concentrations and yields. The conceptual process is shown in Fig. 7.25.
7.6 Energy Balance A discussion of fuel ethanol production from corn is not complete without addressing the energy balance of the system. There is a great deal of controversy regarding whether ethanol from corn provides a net energy gain [415–419]. The energy balance from various studies is shown in Fig. 7.26. For any energy resources to be economically viable, the amount of energy necessary to produce the fuel (energy input) must be lower than the useful energy that can be extracted (energy output) from the same fuel.
Fig. 7.26 Energy balance reported by various researchers for ethanol production from corn (Adapted from Aden 2007) [392]
7.6 Energy Balance 459
460
7 Ethanol
The research team led by Shapouri [420] at the US Department of Agriculture claims that ethanol production provides a net energy return. However, a number of other studies contradicted the findings by the Shapouri team. Other major concern of using corn for ethanol is that a large cropland will be necessary for growing corn that is currently used for food production and raises serious ethical issues. The difference in the net energy return among various studies is mainly due to the use of different values of input parameters and associated costs. Values of a set of input parameters used by Pimentel [421] are given in Table 7.17. These values are extremely variable and depend from one region to another region. The numbers cited in Table 7.17 are estimates and can change from one year to another year. For example, in 2002, Shapouri et al. [432] reported a net energy gain of 34%, however, in 2004 Shapouri group [439] claimed almost twice in the net positive energy (67%). During the same time period, Pimentel group [421] reported a negative 29% deficit. The Pimentel group [421] pointed out several issues that made the difference in the energy balance. According to the Pimentel group [421]: (1) Shapouri omitted several inputs, for instance, all the energy required to produce and repair farm machinery, as well as the fermentation-distillation equipment. All the corn production in the U.S. is carried out with an abundance of farm machinery, including tractors, planters, sprayers, harvesters, and other equipment. These are large energy inputs in corn ethanol production, even when allocated on a life cycle basis. (2) Shapouri used corn data from only nine states, whereas Pimentel group used corn data from 50 states. (3) Shapouri reported a net energy return of 67% for the co-products, primarily dried-distillers grain (DDG) that were used to feed cattle. (4) Although Pimentel group did not allocate any energy related to the impacts that the production of ethanol has on the environment, they are significant in the US for corn production. (5) Ferguson [457] made an astute observation about the USDA data. The proportion of the sun’s energy that is converted into useful ethanol, using the USDA’s positive data, only amounts to five parts per 10,000. If the figure of 50 million ha were to be devoted to growing corn for ethanol, then this acreage would supply only about 11% of U.S. liquid fuel needs. (6) Many other investigators supported Pimentel group’s assessment of ethanol production. As noted earlier, coproducts play an important role in the energy balance as demonstrated through Tables 7.18 and 7.19. Differences among these studies are related to various assumptions about corn yields, ethanol conversion technologies, fertilizer manufacturing efficiency, fertilizer application rates, co-product evaluation, and the number of energy inputs included in the calculations. For example, there is about a 64,000 Btu/gal difference between the results of Pimentel [421] and Lorenz and Morris [83]. With respect to growing the corn, Pimentel reports that it requires 56,720 Btu/gal (LHV) compared with Lorenz and Morris’s 27,134 Btu/gal (HHV). Both studies used the same basic inputs, such as fertilizer, pesticides, and fuel, but Pimentel also included the energy value embodied in farm machinery, though he did not present any details on how he derived embodied energy in farm machinery. Another factor that makes Pimentel’s estimates higher is the use of a national average corn yield of only 110 bu/ac, which is characteristic of corn yields seen in U.S. agriculture in the early 1980s. Lorenz and Morris [83] used 120 bu/ac, which is based on data from more recent years.
Table 7.17 Energy inputs and associated costs of corn production per hectare in the US Inputs
Quantity
kcal1,000
Costs $
Labor Machinery Diesel Gasoline Nitrogen Phosphorus Potassium Lime Seeds Irrigation Herbicides Insecticides Electricity Transport Total Corn yield 8;655 kg=ha ii
11:4 ha 55 kgd 188 Lg 40 Li 153 kgk 65 kgn 77 kgq 1;120 kgt 21 kgv 8:1 cmy 6:2 kgbb 2:8 kg cc 13:2 kWhdd 204 kggg
462b 1;018e 1;003h 405j 2;448l 270o 251r 315u 520w 320z 620ee 280ee 34ff 169hh 8,115 31,158 kcal
148:20c 103:21f 34:76 20:80 94:86m 40:30p 23:87s 11:00 74:81x 123:00aa 124:00 56:00 0:92 61:20 $916:93 Input:output 1:3.84
Source: Pimentel and Patzek [421] a NASS [443] b It is assumed that a person works 2,000 h per year and utilizes an average of 8,000 l of oil equivalents per year c It is assumed that labor is paid $13 an hour d Pimentel and Pimentel 1996 [444] e Prorated per ha and 10 year life of the machinery. Tractors weigh from 6 to 7 t and harvesters 8–10 t, plus plows, sprayers, and other equipment f Hoffman et al. [445] g Wilcke and Chaplin [446] h Input 11,400 kcal per l i Estimated j Input 10,125 kcal per l k USDA [447] l Patzek [438] m Cost 62 c/kg n USDA [447] o Input 4,154 kcal/kg p Cost $62/ kg q USDA [447] r Input 3,260 kcal/kg s Cost 31c/kg t Brees [448] u Input 281 kcal/kg v Pimentel and Pimentel [444] w Pimentel [449] x USDA [450] y USDA [451] z Batty and Keller [452] aa Irrigation for 100 cm of water per ha costs $1,000 (Larsen et al. [453]) bb Larson and Cardwell [454] cc USDA [447] dd USDA [455] ee Input 100,000 kcal/kg of herbicide and insecticide ff Input 860 kcal/kWh and requires 3 kWh thermal energy to produce 1 kWh electricity gg Goods transported include machinery, fuels, and seeds that were shipped an estimated 1,000 km hh Input 0.83 kcal/kg/km transported ii USDA [456]
462
7 Ethanol Table 7.18 Energy use and net energy value per gallon without co-products energy credits Production process Corn production Corn transport Ethanol conversion Ethanol distribution Total energy used Net energy value Energy ratio Source: Shapouri [458]
Milling process Dry
Wet
Weighted average
18,875 2,138 47,116 1,487 69,616 6,714 1.10
18,551 2,101 52,349 1,487 74,488 1,842 1.02
18,713 2,120 49,733 1,487 72,052 4,278 1.06
Table 7.19 Energy use and net energy value per gallon with co-products energy credits, 2001 Production process Corn production Corn transport Ethanol conversion Ethanol distribution Total energy used Net energy value Energy ratio Source: Shapouri [458]
Milling process Dry 12,457 1,411 27,799 1,467 43,134 33,196 1.77
Wet 12,244 1,387 33,503 1,467 48,601 27,729 1.57
Weighted average 12,350 1,399 30,586 1,467 45,802 30,528 1.67
Although Pimentel [431] increased corn yield in his 2001 report, the net energy value remained about the same as reported in the 1991 study. The co-products values play an important role in determining net energy value. When corn is converted into ethanol, the material that remains is a high-protein animal feed. One assumption is that the availability of that feed will enable traditional feed manufacturers to produce less, saving energy; ethanol producers should, therefore, get to subtract those energy savings from their energy consumption. When Groode and Heywood [459] put co-product credits into their calculations, ethanol’s life-cycle energy use became lower than gasoline’s. The choice of system boundary influences the outcome of the energy balance. To determine the importance of the system boundary, Groode and Heywood [459] compared their analysis with the study by Pimentel [421] and three other studies [458, 460, 461], considering the same energy-consuming inputs and no co-product credits in each case. Based on the results, Groode and Heywood [459] concluded that everybody is basically correct, and the energy balance is so close that the outcome depends on exactly how one defines the problem. The results also validated the methodology and results from the other studies and were within the range of probable results (See Fig. 7.27). However, among all feedstocks, the net energy balance for corn-ethanol system, even if it is positive, is considered to be lowest. According to Bourne [462],
1.7
9.0 2.8
6.8
lowa Corn Grain Ethanol
NEV (MJ/Ethanol Liter)
3.7
7.2
15.8
−7.6
−1.1
7.2
Fig. 7.27 A comparison of net energy balance for corn-ethanol production reported by several researchers with a Monte-Carlo model (Groode and Heywood 2008) [459]
−10
−3.2
1.7
Farrell
0
Pimentel
5.8
Shapourl
10
lowa Corn Grain Ethanol With 20% Co Product Credits
20
Wang,et.al.
Monte Carlo LCA Results
lowa Corn Grain Ethanol Plus DDGS
(Corn Grain Ethanol)
Georgia Corn Grain Ethanol
Previous Results
lowa Coal Powered Corn Grain Ethanol
30
2025 lowa Corn Grain Ethanol
7.6 Energy Balance 463
464
7 Ethanol
fossil-fuel energy used to make fuel (input) compared with the energy in the fuel (output) is 1:1.3 (input: output) for corn-ethanol, 1:8 for sugarcane ethanol, 1:2.5 for biodiesel, and 1:2–1:36 for cellulosic ethanol. For cellulosic ethanol, the output energy depends on production method.
7.7 DDGS Market The co-products from corm processing plants play a key role in determining the energy balance of the corn to ethanol production system [462–470]. Among various co-products, distiller’s dried grains with solubles (DDGS) has the best market value and also marketed internationally for use in dairy, beef, swine, poultry and aquaculture feeds. Nutrient values of high quality DDGS produced by modern ethanol plants in the US are generally higher than those required for various feeds, such as for the swine, poultry, dairy and beef. Wet mills produce corn gluten feed, corn gluten meal and corn germ meal that also have significant market value.
7.8 Water Requirements for Corn Growing Recent increases in oil prices in conjunction with the farm subsidy policies in the US have led to a dramatic expansion in corn based ethanol production. If the crude oil price remains high, which is most likely, further expansion is expected. A National Research Council committee was convened to look at how shifts in the nation’s agriculture to include more energy crops, and potentially more crops overall, could affect water management and long-term sustainability of biofuel production. The committee concluded: “In terms of water quantity, the committee found that agricultural shifts to growing corn and expanding biofuel crops into regions with little agriculture, especially dry areas, could change current irrigation practices and greatly increase pressure on water resources in many parts of the United States. The amount of rainfall and other hydroclimate conditions from region to region causes significant variations in the water requirement for the same crop, the report says. For example, in the Northern and Southern Plains, corn generally uses more water than soybeans and cotton, while the reverse is true in the Pacific and mountain regions of the country. Water demands for drinking, industry and such uses as hydropower, fish habitat, and recreation could compete with, and in some cases, constrain the use of water for biofuel crops in some regions. Consequently, growing biofuel crops requiring additional irrigation in areas with limited water supplies is a major concern, the report says.” [472] Several studies also addressed the use of water for corm growing and its impact [473–476]. There is a significant shortage of fresh water throughout the world, as well as in the USA. The effect of water usage for growing corn on the society is further discussed in Volume 4 of this book series.
7.9
Fuel Ethanol Quality Comparison
465
7.9 Fuel Ethanol Quality Comparison In the USA, fuel ethanol is blended in over 70% of the nation’s gasoline, and up to 10 vol% ethanol in gasoline (called E10) is allowed by federal gasoline regulations. All U.S. conventional vehicles are designed, certified and warranted for the use of blends up to E10 (10% by volume, approx 3.5% by mass). However, ethanol is also used in reformulated gasoline (RFG), and in much higher concentration in flexible fuel vehicles (FFVs). An ethanol concentration of up to 85% (called E85 fuel) can be used in FFVs. E85 is currently restricted to use in FFVs, but can be used at any level (E0–E85) of ethanol. E85 composition actually ranges form 70% ethanol/30% hydrocarbons to 79% ethanol/21% hydrocarbons. It is estimated that there are over 7 million FFVs on the roads today, and based on the U.S. automakers’ commitment, about 50% of their vehicles sold by 2012 could be FFVs. Fuel volatility (The vapor pressure of the blended fuel) is an important parameter for E85, since it determines the cold start and warm up performance. Therefore, there are three classes of E85 fuel. • Class 1 E85, which would typically contain 85% denatured ethanol, is required to meet a 79% minimum ethanol content. This is called summer grade E85 and requires a vapor pressure of 38–59 kPa (5.5–8.5 psi) at 37:8ı C. • Class 2 E85 may contain up to 74% by volume denatured ethanol. It requires a vapor pressure of 48–65 kPa (7.0–9.5 psi) at 37:8ı C, and is called inter-seasonal (spring/fall) blend. • Class 3 is formulated for winter that requires a vapor pressure of 66–83 kPa (9.5–12.0 psi) at 37:8ı C. Various aspects of E-85 blends that include handling, storing, dispensing are discussed in Handbook for Handling, Storing, and Dispensing E85 [476]. The vapor pressure of gasoline-ethanol blend for various compositions is given in Fig. 7.28. GASOLINE-ETHANOL MIXTURES VAPOR PRESSURE (kPa)
80 70 60 50 40 30 20 10 0 0
10
20
30
40
50
60
70
80
90
100
ETHANOL CONTENT (% V/V)
Fig. 7.28 Vapor pressure data for different gasoline-ethanol mixtures (Source: Renewable Fuels Association [478])
466
7 Ethanol
Table 7.20 ASTM D 5798–99 standard specification for fuel ethanol for automotive sparkignition engines Property ASTM volatility class Ethanol, plus higher alcohols (minimum volume %) Hydrocarbons (including denaturant) (volume %) Vapor pressure at 37:8ı C kPa psi Lead (maximum, mg/L) Phosphorus (maximum, mg/L) Sulfur (maximum, mg/kg)
Methanol (maximum, volume %) Higher aliphatic alcohols, C3–C8 (maximum volume %) Water (maximum, mass %) Acidity as acetic acid (maximum, mg/kg) Inorganic chloride (maximum, mg/kg) Total chlorine as chlorides (maximum, mg/kg) Gum, unwashed (maximum, mg/100 mL) Gum, solvent-washed (maximum, mg/100 mL) Copper (maximum, mg/100 mL) Appearance
Value of class 1 2 79 74
3 70
Test method N/A ASTM D 5501
17–21
17–26
17–30
ASTM D 4815
38–59 5.5–8.5
48–65 7.0–9.5
66–83 9.5–12.0
2.6 0.3
2.6 0.3
3.9 0.4
ASTM D 4953 D 5190 D 5191 ASTM D 5059 ASTM D 3231
210
260
300
0.5
N/A
ASTM D 3120 D 1266 D 2622
2
N/A
1.0 50
ASTM E 203 ASTM D 1613
1
ASTM D 512 D 7988
2
ASTM D 4929
20
ASTM D 381
5.0
ASTM D 381
0.07
ASTM D 1688
Product shall be visibly free of suspended or precipitated contaminants (shall be clear and bright) Source: US Department of Energy [477] N=A not applicable
Appearance determined at ambient temperature or 21 ı C .70ı F/, whichever is higher
Various properties and their standard test methods as recommended by the ASTM is given in Table 7.20 for fuel ethanol (Ed75–Ed85) for automotive spark-ignition engines, and in Table 7.21 for denatured fuel ethanol for blending with gasoline for use in automotive spark-ignition engine fuel. The lower case “d” in “Ed” stands for “denatured” ethanol.
7.9
Fuel Ethanol Quality Comparison
467
Table 7.21 Specifications contained in ASTM D 4806 standard specification for denatured fuel ethanol for blending with gasoline Property Ethanol volume %, min Methanol, volume %. max Solvent-washed gum, mg/100 mL max Water content, volume %, max Denaturant content, volume %, min volume %, max Inorganic Chloride content, mass ppm (mg/L) max Copper content, mg/kg, max Acidity (as acetic acid CH3COOH), mass percent (mg/L), max pHe Appearance
Specification 92.1
ASTM test method D 5501
0.5
5
D 381
1
E 203
1.96
4.76 40
D 512
0.1
D 1688
0.007
D 1613
6.5–9.0 Visibly free of suspended or precipitated contaminants (clear and bright) Source: Renewable Fuels Association [478]
D 6423
The Energy Efficiency and Renewable Energy, Alternative Fuels Data Center of the USDOE compared various properties of three fuels that are used for transportation: ethanol, gasoline, and No.2 Diesel. These data provide a basis for comparison among these fuels and are earlier given in Table 7.21. The Table 7.22 shows how an 2007 Chevrolet Tahoe performed while running on E85 and gasoline in three fuel-economy tests, in four acceleration tests, and in three emissions tests [479].
468 Table 7.22 Testing of a 2007 Chevrolet Tahoe with E85 fuel and its comparison with gasoline
7 Ethanol
Fuel economy, mpg City Highway 150-mile trip Overall Acceleration 0–30 mph, s 0–60 mph, s 45–65 mph, s Quarter-mile, s/mph Emissions, parts per million Nitrogen oxide Hydrocarbons Carbon monoxide Source: Consumer report [479] a Blended with 10% ethanol
E85 7 15 13 10
Gasolinea 9 21 18 14
3.4 8.9 5.7 16.8/84.6
3.5 9.1 5.8 16.9/84.5
1 1 0
9 1 0
7.10 E-Diesel E-Diesel is a diesel fuel that uses conventional diesel blend stock(s) with 7.7–15 vol% anhydrous ethanol (ASTM D 4806) and from 0:6 to 5:0 vol% of special proprietary additive(s) to prevent ethanol and diesel from separating at very low temperatures and water contamination [480–497]. In some cases, a cetane enhancement, if required, is added. E-Diesel is currently an experimental fuel and is being developed by many companies, who can receive federal ethanol tax credit when blending ethanol with diesel. E-diesel is targeted for use in heavy-duty trucks, busses, and farm machinery. Although there are many environmental benefits of using e-diesel, 7–10% decreased in mileage is expected. The use of e-diesel may reduce emissions of particulate matter from 27% to 41%, carbon monoxide by 20–27%, and nitrogen oxides by 4–5%.
7.11 Summary Ethanol is currently blended with gasoline into more than 50% of the USA’s fuel supply. Ethanol is also increasingly available in E85, an alternative fuel that can be used in flexible fuel vehicles. Studies have estimated that ethanol and other biofuels could replace 30% or more of U.S. gasoline demand by 2030. Corn is the primary feedstock for ethanol production in the USA, whereas Brazil, the second largest producer of ethanol, uses sugarcane. About 20% of the corn supply in the USA is used for ethanol production. Although ethanol can also be made from other grains such as sorghum as well as from cellulosic biomass such as corn cobs, cornstalks, wheat straw, rice straw, and switchgrass, further technological advancements are needed to make it competitive with corn or sugar based ethanol.
Problems
469
Ethanol production methods depend mainly on the feedstock. In the USA, ethanol is primarily produced from corn crops by dry-mill or wet-mill processing. Although cellulosic ethanol has not yet been produced commercially, several commercial cellulosic ethanol production plants are under construction. Mainly two processes, biochemical and thermochemical processes, are currently explored for cellulosic ethanol production. The use of corn-ethanol raises several concerns including worldwide food shortages, increase in food price, and the consumptive use of water, which is defined as any use of water that reduces the supply from which it is withdrawn or diverted. These concerns must be addressed before expanding corn based ethanol production.
Problems 1. What is the difference between ethanol and E85? 2. What are distillers dried grains (DDG) or even distillers dried grains with solubles (DDGS)? Do they have any market value? 3. Describe ethanol production processes and their advantages and disadvantages. 4. Calculate the amount of Carbon Dioxide .CO2 / emitted during production of a gallon of ethanol? 5. What feedstock types can I use for ethanol production? Discuss various advantages and disadvantages associated with these feedstock. 6. What are the advantages to using ethanol blended fuels? 7. Discuss environmental benefits of using ethanol or ethanol blended fuel. 8. Does ethanol blended fuel burn cleaner than premium gasoline? If so, why? 9. What are ETBE and MTBE? 10. Can 100% ethanol be used in automobile? 11. Does ethanol blended with gasoline require special handling? 12. How much ethanol can I get from one ton of wheat? 13. What is the difference between a wet and a dry mill ethanol plant? 14. What is cellulosic ethanol? 15. How is cellulosic ethanol made? 16. What is switchgrass and why is it a good potential source for ethanol? 17. How close is cellulosic ethanol to being commercialized? 18. Can ethanol blends be used in small engines, such as boats, lawnmowers, or chainsaws?
470
7 Ethanol
19. What is E85? 20. Can my vehicle run on E85 even if it’s not an FFV? 21. What is the ethanol “subsidy”? 22. How many bushels of corn are needed for a typical ethanol plant? 23. How many gallons are in a barrel of oil / ethanol? 24. What is ethanol’s “net energy balance”? 25. Discuss the issues surrounding the use of E15. 26. Why corn is favored for ethanol production in the US? 27. Is the subsidy for corn ethanol in the US necessary for its competition with other Fuel? 28. What is the energy balance of Brazil sugarcane-produced ethanol? 29. What are the byproducts when making cellulosic ethanol? 30. How much water does it take to produce a gallon of cellulosic ethanol? 31. What kinds of ethanol-blended fuels are available? Discuss their merits and demerits. 32. What type of storage and dispensing conversion procedures are required for offering E85 at a gas station? 33. How many bushels of corn are needed for a typical ethanol plant? How many acres of corn would be needed to satisfy that demand? 34. What is switchgrass? Why is it considered to be a good potential source for ethanol in the USA? 35. Discusses issues for commercialization of cellulosic ethanol? 36. What is the Renewable Fuels Standard? 37. What is the ethanol incentive? 38. How does the production and use of ethanol impact the USA, Europe, and world economy? 39. How much oil can ethanol displace? 40. Can corn- ethanol drive up prices at the grocery store? 41. What does “net energy balance” mean? What is ethanol’s energy balance? Compare corn-ethanol energy balance with other feedstocks? 42. What about ethanol’s impact on fuel economy?
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451. USDA (1997) Farm and ranch irrigation survey (1998). 1997: Census of Agriculture, vol 3, Spec. Studies, Part 1 452. Batty JC, Keller J (1980) Energy requirements for irrigation. In: Pimentel D (ed) Handbook of Energy Utilization in Agriculture. CRC Press, Boca Raton, pp 35–44 453. Larsen K, Thompson D, Harn A (2002) Limited and full irrigation comparison for corn and grain sorghum. http://www.colostate.edu/Depts/SoilCrop/extension/Newsletters/2003/ Drought/sorghum.html 454. Larson WE, Cardwell VB (1999) History of U.S. corn production. http://citv.unl.edu/cornpro/ html/history/history.html. Accessed 20 Nov 2010 455. USDA (1991) Corn-state costs of production: U.S. Dept. Agriculture, Economic Research Service, Economics and Statistics System, Washington, D.C. Stock #94018 456. USDA (2003) Agricultural statistics: USDA, Washington, DC, I-1-XV-34 457. Ferguson ARB (2003) Implications of the USDA 2002 update on ethanol from corn. The Optimum Population Trust, Manchester, pp 11–15 458. Shapouri H (2003) The 2001 net energy balance of corn-ethanol. U.S. Department of Agriculture (USDA), Office of the Chief Economist (OCE). http://www.usda.gov/oce/reports/ energy/net energy balance.pdf 459. Groode TA, Heywood JB (2008) Biomass to ethanol: potential production and environmental impacts. Laboratory for Energy and Environment, MIT, USA, Report No. LFEE 2008–02 RP 460. Farrell AE, Plevin RJ, Turner BT, Jones AD, O’Hare M, Kammen DA (2006) Ethanol can contribute to energy and environmental goals. Science 311(5760):506–508 461. Wang M, We M, Huo H (2007) Life-cycle energy and greenhouse gas emission impacts of different corn ethanol plant types. Environ Res Lett 2(2):2 024001 462. Bourne JK (2007) Biofuel: green dream. National Geographic Magazine: 41–50 463. Baker A, Zahniser S (2006) Ethanol reshapes the corn market. Amber Waves (US Dept Agric) 4(2):30–35 464. Bothast RJ (2005) New technologies in biofuel production. Agricultural Outlook Foram 2005. http://gisceu.net/PDF/U361.pdf. Accessed 20 Nov 2010 465. Fabiosa JF, Hansen J, Matthey H, Pan S, and Tuan F (2009) Assessing China’s potential import demand for distillers dried grain: implications for grain trade. Center for Agricultural and Rural Development, Iowa State University Report 09-SR 104 466. Jonker JS, Cryan R (2010) Biofuel production in the United Stats: Brief discussion of implications for the diary industry. www.nas.edu. Accessed 18 Nov 2010 467. Kingsly ARP, Ileleji KE, Clementson CL, Garcia A, Maier DE, Stroshine RL, Radcliff S (2010) The effect of process variables during drying on the physical and chemical characteristics of corn dried distillers grains with solubles (DDGS) – plant scale experiments. Bioresour Technol 101(1):193–199 468. Liu K (2009) Effects of particle size distribution, compositional and color properties of ground corn on quality of distillers dried grains with solubles (DDGS). Bioresour Technol 100(19):4433–4440 469. Nuez O, N WG, Yu P (2009) Nutrient variation and availability of wheat ddgs, corn ddgs and blend ddgs from bioethanol plants. J Sci Food Agric 89:1754–1761 470. Rodrıguez LF, Li C, Khanna M, Spaulding AD, Lin T, Eckhoff SR (2010) An engineering and economic evaluation of quick germ-quick fiber process for dry-grind ethanol facilities: analysis. Bioresour Technol 101(14):5282–5289 471. The National Academics (2007) Increase in ethanol production from corn could significantly impact water quality and availability if new practices and techniques are not employed. http:// www8.nationalacademies.org/onpinews/newsitem.aspx?RecordID=12039. Accessed 20 Nov 2010 472. Simpson TW, Sharpley AN, Howarth RW, Paerl HW, Mankin KR (2008) The new gold rush: fueling ethanol production while protecting water quality. J Environ Qual 37(2):318–324 473. Anon (2007) Ethanol production from corn: impact on water. Biotechnol J 2(12):1458 474. Chiu YW, Walseth B, Suh S (2009) Water embodied in bioethanol in the United States. Environ Sci Technol 43(8):2688–2692
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Chapter 8
Hydrogen Energy
Abstract Hydrogen may be considered as a secondary energy source, since it is not available as a pure hydrogen gas. Pure hydrogen must be produced from its compound using another energy source prior to its use. For example, the electricity that is produced from a primary energy source can be used to produce hydrogen from water by electrolysis. The supply of hydrogen on demand also requires a storage system. Hydrogen production, storage, and distribution methods are discussed in this chapter.
8.1 Introduction Hydrogen is abundant on the earth’s surface, however, it is mainly bound with other chemical compounds, such as water (H2 O) and organic compounds. Hydrogen is an energy carrier; it can store and deliver usable energy. Hydrogen must be first dissociated from bound chemical compounds using a primary energy source. Hydrogen is an environmentally attractive fuel as it produces only water during its combustion and use as a fuel. Various physical and chemical properties of hydrogen are given in Table 8.1. Before using hydrogen as a fuel, its combustion properties should be known and compared with other common fuels such as methane and gasoline to determine its effectiveness. Combustion related properties of hydrogen are compared with that of methane and gasoline in Table 8.2. Hydrogen can be used in any application in which fossil fuels are being used today, except where carbon is specifically needed [1–4]. Hydrogen can be used as a fuel in furnaces, internal combustion engines, turbines and jet engines, more efficiently than fossil fuels, i.e., coal, petroleum and natural gas. Automobiles, buses, trains, ships, submarines, airplanes and rockets can run on hydrogen. Hydrogen can also be converted directly to electricity by using fuel cells, which can be fed directly to the grid or to operate automobiles. Combustion of hydrogen with oxygen results in pure steam, which has applications in industrial processes and space heating. T.K. Ghosh and M.A. Prelas, Energy Resources and Systems: Volume 2: Renewable Resources, DOI 10.1007/978-94-007-1402-1 8, © Springer Science+Business Media B.V. 2011
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8 Hydrogen Energy Table 8.1 Various physical and chemical properties of hydrogen Properties Values Atomic hydrogen Atomic number 1 Atomic weight 1.0080 Ionization potential 13.595 eV Electron affinity 0.7542 eV Nuclear spin 1/2 Nuclear magnetic moment 2.7927 (nuclear magnetons) Nuclear quadrupole moment 0 Electronegativity (Pauling) 2.1 Molecular hydrogen Bond distance Dissociation energy (25ı C) Ionization potential Density of solid Melting point Heat of fusion Density of liquid Boiling point Heat of vaporization Critical temperature Critical pressure Critical density Heat of combustion to water (g)
0.7416 104.19 kcal/mol 15.427 eV 0:08671 g=cm 3 259:20ı C 28 cal/mol 0.07099 at 252:78ı C 252:77ı C 216 cal/mol 240:0ı C 13.0 atm 0:0310 g=cm 3 57:796 kcal=mol
Table 8.2 A comparison of fuel properties of hydrogen with that of methane and gasoline Properties Lower heating value, kW h/kg Self ignition temperature, ı C Flame temperature, ı C Ignition limits in air, vol% Minimum ignition energy, mWs Flame propagation in air, m/s Detonation limits, vol% Detonation velocity, km/s Explosion energy, kg TNT=m3 Diffusion coefficient in air, cm2 =s
Hydrogen 33.33 585 2,045 4–75 0.02 2.65 13–65 1.48–2.15 2.02 0.61
Methane 13.9 540 1,875 5.3–15 0.29 0.4 6.3–13.5 1.39–1.64 7.03 0.16
Gasoline 12.4 228–501 2,200 1.0–7.6 0.24 0.4 1.1–3.3 1.4–1.7 44.22 0.05
Moreover, hydrogen is an important industrial gas and raw material for numerous industries, such as the computer, metallurgical, chemical, pharmaceutical, fertilizer and food industries. The major use of hydrogen is listed below. • Ammonia (NH3 ) production for use in fertilizer • Oil industry • Semi conductor production
8.3
• • • • • • •
Hydrogen Demand
497
Glass industry (shielding gas) Hydrogenation of fats and oils Methanol production Production of HCl Plastics recycling Rocket fuel Welding and cutting
8.2 Hydrogen Economy A hydrogen economy is envisioned as an economy in which hydrogen will be the main energy source [5–13]. The current global economy is called the carbon economy since most of the primary energy resources are derived from carbon or fossil fuels: Coal, Petroleum, and Natural gas. Hydrogen energy based economy is attractive as hydrogen can be produced from water; a resource that every country on the earth has. The regional dominance of an energy source can be eliminated leading to a better political environment. Various components of the hydrogen economy are discussed in Volume 4 of this book series.
8.3 Hydrogen Demand Total hydrogen production worldwide is about 550 billion Nm3 =year. Approximately 50% of it is used for ammonia based fertilizer production. The consumption of hydrogen in refineries per year is around 200 billion Nm3 . Other major uses of hydrogen include methanol production (8%) and the use as fuel in space programs (1%). Ninety-five percent of hydrogen production is captive, i.e., produced at the site where it is used. Other 5% is called merchant produced, which is sold for industrial and chemical uses. Hydrogen demand in the United States in 2006 was 11 million tons/year and accounted for 5% of the natural gas consumed in the US for its production. Centrally produced merchant hydrogen, which is sold for industrial and chemical uses, amounts to 1.5 million tons. Hydrogen use in the USA in 2006 is shown in Fig. 8.1. The usage is expected to double by 2010. However, this represents only a small increase in the production capacity in the USA from 2003 and 2008 (see Table 8.3). The production capacity must be increased to meet the future demand. The supply of hydrogen could be a significant issue, if hydrogen fuel cell cars are introduced in the market in large numbers. The main objective of a hydrogen economy is to use hydrogen as a fuel source. Its major use as fuel will be in fuel-cell cars. The working principle of fuel cells is discussed in Volume 3 of this book series. It is assumed that fuel cell cars will go
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100
8 Hydrogen Energy Percent of Regional Total
80 Ammonia Producers Refineries Methanol Producers Other Captive Use Pipeline or On Site Cylinder and Bulk
60
40
20
0 North America
Central/South America
Europe
CIS
Africa/ Middle East
Japan
Other Asia
Fig. 8.1 Hydrogen use by end users in 2006 (Courtesy of Suresh et al. [14])
Table 8.3 Hydrogen production capacity in the US in 2003 and 2008 Production capacity (thousands metric tons per year) Capacity type 2003 2008 On-purpose capacitya Oil refinery 2,870 2,723 Ammonia 2,592 2,271 Methanol 393 189 Other 18 19 On-purpose merchanta Off-site refinery Non-refinery compressed gas (cylinders and bulk) Compressed gas (pipeline) Liquid hydrogen Small reformers and electrolyzers Total on-purpose Byproduct Catalytic reforming at oil refineries Other off-gas recoveryb Chloro-alkali production
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