Combustion Engineering Issues for Solid Fuels
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Combustion Engineering Issues for Solid Fuels Editors
Bruce G. Miller
Associate Director, Energy Institute, The Pennsylvania State University and
David A. Tillman
Chief Engineer – Fuels and Combustion, Foster Wheeler NA
Academic Press is an imprint of Elsevier 30 Corporate Drive, Suite 400, Burlington, MA 01803, USA 525 B Street, Suite 1900, San Diego, California 92101–4495, USA 84 Theobald’s Road, London WC1X 8RR, UK Copyright # 2008, Elsevier Inc. All rights reserved. No part of this publication may be reproduced or transmitted in any form or by any means, electronic or mechanical, including photocopy, recording, or any information storage and retrieval system, without permission in writing from the publisher. Permissions may be sought directly from Elsevier’s Science & Technology Rights Department in Oxford, UK: phone: (þ44) 1865 843830, fax: (þ44) 1865 853333, E-mail:
[email protected]. You may also complete your request online via the Elsevier homepage (http://elsevier.com), by selecting “Support & Contact” then “Copyright and Permission” and then “Obtaining Permissions.” Library of Congress Cataloging-in-Publication Data Application submitted British Library Cataloguing-in-Publication Data A catalogue record for this book is available from the British Library. ISBN: 978-0-12-373611-6 For information on all Academic Press publications visit our Web site at www.books.elsevier.com Printed in United States of America 08 09 10 9 8 7 6 5 4 3 2 1
Dedication For Anna Konrad Taylar Trevar
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Contents Preface List of Authors
1.
2.
xix xxiii
Introduction 1.1 Overview 1.1.1 A Perspective on Solid Fuel Utilization 1.1.2 Fuels and Combustion Technology Development 1.2 Solid Fuels Used in Electricity Generation and Process Industry Applications 1.2.1 Characteristics of Solid Fuels 1.2.2 Some Economic Considerations of Solid Fuels 1.3 The Combustion Process for Solid Fuels 1.3.1 Combustion Mechanism Overview 1.3.2 Heating and Drying 1.3.3 Pyrolysis or Devolatilization 1.3.4 Volatile Oxidation Reactions 1.3.5 Char Oxidation Reactions 1.3.6 Formation of Airborne Emissions 1.3.7 Reactions of Inorganic Matter 1.3.8 Combustion and Heat Release 1.4 The Combustion System 1.4.1 Fuel Quality and Fuel Management 1.4.2 Fuel Preparation 1.4.3 Burners and the Combustion Systems 1.4.4 Post-Combustion Controls 1.5 Organization of This Book 1.6 References
1 1 2 4 5 5 8 11 12 12 15 18 19 21 22 24 26 26 27 28 29 30 30
Coal Characteristics 2.1 Introduction to Coal 2.1.1 Coal Formation and Coalification
33 33 34 vii
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Contents
2.2
2.3 2.4 2.5
2.6
2.7
3.
Coal Classification 2.2.1 Coal Rank 2.2.2 Coal Type 2.2.3 Coal Grade 2.2.4 Coal Classification 2.2.4.1 ASTM Classification System 2.2.4.2 International Classification System Coal Reserves/Resources 2.3.1 World Coal Reserves 2.3.2 United States Coal Resources and Reserves Coal Production 2.4.1 World Coal Production 2.4.2 United States Coal Production Traditional Coal Characterization Methods and Their Industrial Application 2.5.1 Proximate Analysis 2.5.2 Ultimate Analysis 2.5.3 Heating Value 2.5.4 Sulfur Forms 2.5.5 Chlorine 2.5.6 Grindability 2.5.7 Ash Composition 2.5.8 Trace Element Characterization 2.5.9 Ash Fusion 2.5.10 Free-Swelling Index (FSI) 2.5.11 Petrography/Coal Reflectance Nontraditional Characterization Methods and Their Industrial Application 2.6.1 Coal Structure 2.6.2 Coal Reactivity 2.6.3 Volatile Matter Evolution Patterns References
Characteristics of Alternative Fuels 3.1 Introduction 3.1.1 Typical Alternative Fuel Applications 3.1.1.1 The Use of Alternative Fuels in Electric Utility Boilers 3.1.1.2 Cofiring Alternative Fuels in Process Industries and Independent Power Producers 3.2 Petroleum Coke 3.2.1 Petroleum Coke Production Processes
37 37 38 41 41 41 41 44 44 47 48 51 52 61 69 70 70 71 71 71 71 72 72 72 73 73 74 74 77 80 83 83 84 84 86 87 88
Contents
3.2.2
3.3
3.4
3.5
3.6
ix
Fuel Characteristics of Petroleum Coke 88 3.2.2.1 Proximate and Ultimate Analysis of Petroleum Coke 89 3.2.2.2 Ash Characteristics of Petroleum Coke 90 3.2.3 Petroleum Coke Utilization in Cyclone Boilers 92 3.2.4 Cofiring Petroleum Coke in Pulverized Coal Boilers 93 3.2.5 Petroleum Coke Utilization in Fluidized-Bed Boilers 94 Woody Biomass 96 3.3.1 Types of Woody Biomass Fuels 98 3.3.2 Physical and Chemical Characteristics of Woody Biomass Fuels 99 3.3.2.1 Proximate and Ultimate Analysis of Woody Biomass 100 3.3.2.2 Inorganic Matter in Woody Biomass 100 3.3.2.3 Trace Metal Concentrations 101 3.3.3 Using Woody Biomass in Dedicated Boilers 102 3.3.4 Woody Biomass in Pulverized Coal Firing Applications 106 3.3.5 Cofiring Woody Biomass in Cyclone Boilers 107 3.3.6 Conclusions Regarding Using Woody Biomass as an Alternative Fuel 108 Tire-Derived Fuel (TDF) 110 3.4.1 General Description of Tire-Derived Fuel 111 3.4.2 Fuel Characteristics of Tire-Derived Fuel 112 3.4.2.1 Proximate and Ultimate Analysis of Tire-Derived Fuel 112 3.4.2.2 Ash Constituents of TDF 113 3.4.2.3 Trace Element Emissions from TDF 114 3.4.3 Cofiring Applications with Tire-Derived Fuel 114 3.4.4 Summary Regarding TDF as an Alternative Fuel 115 Herbaceous Crops 116 3.5.1 Types of Herbaceous Biomass Fuels 116 3.5.2 Sources and Uses of Herbaceous Materials 117 3.5.3 Fuel Characteristics of Switchgrass and Related Agricultural Biomass Materials 118 3.5.3.1 Density of Switchgrass and Related Materials 118 3.5.3.2 Proximate and Ultimate Analysis of Switchgrass and Related Agricultural Materials 119 3.5.3.3 Ash Chemistry for Herbaceous Biomass Fuels 121 3.5.4 Herbaceous Crop Summary 123 References 124
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4.
5.
Characteristics and Behavior of Inorganic Constituents 4.1 Introduction 4.2 Inorganic Composition of Coal 4.2.1 Distribution of Inorganic Constituents in Coal 4.2.2 Methods of Determining Inorganic Composition 4.2.3 General Coal Characteristics 4.2.3.1 Lignites 4.2.3.2 Subbituminous Coals 4.2.3.3 Bituminous Coals 4.2.3.4 World-Traded Coals 4.3 Ash Formation: Transformation of Coal Inorganic Constituents 4.4 Ash Deposition Formation 4.4.1 Deposition Phenomena in Utility Boilers 4.4.2 Slagging Deposits 4.4.3 Fouling Deposits 4.4.4 High-Temperature Fouling 4.4.5 Low-Temperature Fouling 4.4.6 Ash Impacts on SCR Catalyst 4.4.7 Deposit Thermal Properties 4.5 Deposit Strength Development 4.6 Deposit Characterization 4.7 Predicting Ash Behavior 4.7.1 Advanced Indices 4.7.2 Mechanistic Models 4.8 References Fuel Blending for Combustion Management 5.1 Introduction 5.1.1 Types of Fuel Blending 5.1.2 The Reasons for Fuel Blending 5.1.3 Issues for Fuel Blending 5.2 Equipment and Controls Issues Associated with Fuel Blending 5.2.1 The Blending System at Monroe Power Plant 5.2.2 Alternative Blending Systems 5.3 Fuel and Combustion Effects of Blending 5.3.1 Blending Overview 5.3.2 The Monroe Power Plant Case Study 5.3.2.1 Development of Combustion Models as an Analytical Tool 5.3.2.2 Fuel Effects of Blending at Monroe 5.3.2.3 Volatility and Volatile Release Patterns 5.3.2.4 Char Oxidation 5.3.2.5 Ash Chemistry
133 133 136 136 137 148 148 148 149 150 151 153 153 155 156 157 158 159 160 161 162 167 167 167 167 171 171 172 173 174 175 176 177 181 182 182 182 185 185 187 187
Contents
5.4
5.5 5.6
5.3.3 Fuel Effects for Other Locations Operational Issues with Fuel Blending 5.4.1 Managing Inorganic Constituents 5.4.2 Managing the Fire 5.4.3 Managing Blend Changes Conclusions References
xi
193 193 194 194 194 196 196
6.
Fuel Preparation 6.1 Know Your Fuel 6.1.1 Fuel Types 6.1.2 Fuel Issues 6.1.3 Coal 6.1.4 Petroleum-Based Products 6.1.5 Biomass 6.2 Fuel Storage Silo 6.2.1 Storage Capacity 6.2.2 Silo/Bunker Design Considerations 6.2.3 Safety Considerations 6.3 Solid Fuel Flow Control 6.4 Fuel Sizing Equipment 6.5 Pulverized Coal System Analysis Guidelines 6.5.1 Mill Sizing and Standard Ratings 6.5.2 Coal Mill Capacity and Capability Analysis 6.5.2.1 Coal Throughput Capability 6.5.2.2 Primary Air Capability 6.5.2.3 Air Heater Leakage 6.5.2.4 Thermal Requirements 6.5.2.5 Analysis Summary 6.5.3 Coal Mill Capability Test Plan 6.6 References
199 200 200 201 202 204 205 206 206 208 211 211 214 225 226 229 230 232 232 234 237 237 239
7.
Conventional Firing Systems 7.1 Overview 7.2 Types of Traditional Combustion Systems 7.2.1 Stoker Firing Systems 7.2.2 Pulverized Firing Systems 7.2.3 Cyclone Firing Systems 7.2.4 Fluidized-Bed Systems 7.3 Applications and Uses of Conventional Firing Systems 7.3.1 Electricity Generation 7.3.2 Industrial Boilers, Kilns, and Process Heaters 7.4 Basic Issues 7.4.1 Fuel Selection
241 241 242 242 242 243 243 243 243 246 247 247
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Contents
7.4.2 7.4.3
7.5
7.6 7.7
8.
Operational Considerations Airborne Emissions 7.4.3.1 Particulates 7.4.3.2 SO2 7.4.3.3 NOx 7.4.3.4 CO2 7.4.3.5 Other Emissions (Hazardous Air Pollutants) Firing Systems and Combustion Issues 7.5.1 Stoker Firing 7.5.1.1 Basic Description and Identification of Types 7.5.1.2 Fuel Selection for Stokers 7.5.1.3 Fuel Preparation 7.5.1.4 Design Parameters 7.5.1.5 Functioning of Grates 7.5.2 Pulverized Firing 7.5.2.1 Applications 7.5.2.2 Basic Description and Identification of Types 7.5.2.3 Wall-Fired Pulverized Coal Boilers and Firing Systems 7.5.2.4 Tangentially Fired Pulverized Coal Boilers 7.5.2.5 Vertically Fired (Arch-Fired) Boilers 7.5.2.6 Pulverized Coal Burner Systems 7.5.2.7 Typical and Maximum Conditions 7.5.2.8 Fuel Preparation 7.5.2.9 Effect of Moisture 7.5.2.10 Swirling Flow 7.5.2.11 Overfire Air Systems as Burner-Based Emissions Control 7.5.3 Cyclone Firing 7.5.3.1 Basic Description and Identification of Types 7.5.3.2 Typical and Maximum Conditions 7.5.3.3 NOx Formation and Cyclones 7.5.3.4 Design and Operating Parameters Concluding Statements References
Fluidized-Bed Firing Systems 8.1 Introduction 8.2 Fluidized-Bed Combustion Systems 8.2.1 Bubbling Fluidized-Bed Combustion (BFBC)
249 250 250 250 250 251 251 252 252 252 253 254 254 255 256 256 257 257 262 264 264 265 265 267 267 267 268 268 269 269 269 271 272 275 275 276 278
Contents
8.3 8.4 8.5 8.6
8.7
8.8
8.2.2 Circulating Fluidized-Bed Combustion (CFBC) 8.2.3 Pressurized Fluidized-Bed Combustion (PFBC) Heat Transfer Combustion Efficiency Fuel Flexibility Pollutant Formation and Control 8.6.1 Sulfur Dioxide 8.6.1.1 Transformation of Sorbents in the FBC Process 8.6.1.2 Bed Temperature 8.6.1.3 Particle Residence Time 8.6.1.4 Bed Quality 8.6.1.5 Gaseous Environment 8.6.1.6 Combustor Pressure 8.6.1.7 Chemical Composition 8.6.1.8 Porosity 8.6.1.9 Surface Area 8.6.1.10 Particle Size 8.6.2 Nitrogen Oxides 8.6.2.1 NOx Formation 8.6.2.2 Fuel Nitrogen and Volatile Matter Content: Fuel Rank 8.6.2.3 Combustion Temperature 8.6.2.4 Excess Air 8.6.2.5 Gas Velocity/Residence Time 8.6.2.6 Limestone Effects 8.6.2.7 NOx Reduction Techniques 8.6.3 Particulate Matter 8.6.4 Carbon Monoxide/Hydrocarbons 8.6.5 Trace Elements Ash Chemistry and Agglomeration Issues 8.7.1 Chemical Fractionation of Biomass 8.7.1.1 Results of the Chemical Fractionation Study 8.7.2 Thermodynamic Modeling to Predict Inorganic Phases 8.7.3 Viscosity of Inorganic Melt Phases 8.7.3.1 Viscosity Results 8.7.4 Conclusions FBC Boilers and Their Role in Clean Coal Technology Development 8.8.1 United States 8.8.1.1 Clean Coal Technology Development Program (CCTDP) 8.8.1.2 Clean Coal Power Initiative
xiii
280 282 283 284 284 288 289 289 291 292 292 292 292 293 293 294 294 295 295 296 296 297 297 297 297 298 298 299 301 303 304 311 316 319 320 321 322 322 324
xiv Contents
8.8.2 8.8.3
9.
Worldwide Further Developments Needed for Conventional Clean Coal Technologies 8.9 Unique Opportunities for FBCs 8.9.1 Background of Opportunity/Food Industry Issue 8.9.2 Disposal Options 8.9.3 Cofiring ATB in Coal-Fired Boilers for Carcass Disposal 8.9.4 Summary of ATB/Coal Cofiring in a Pilot-Scale Fluidized Bed Combustor 8.9.4.1 NCBA/Cargill Food Solutions Tests 8.9.4.2 PEDA/Cargill Food Solutions Tests 8.9.4.3 DOE Oxygen-Enhanced Combustion Testing 8.9.5 Closing Statements 8.10 References
324
Post-Combustion Emissions Control 9.1 Introduction 9.2 Particulate Capture 9.2.1 Introduction 9.2.2 Electrostatic Precipitation 9.2.2.1 Introduction 9.2.2.2 Theory 9.2.2.3 Equipment Arrangement 9.2.2.4 Resistivity 9.2.2.5 Process Control 9.2.2.6 Operating an Electrostatic Precipitator 9.2.2.7 Diagnostics 9.2.2.8 Resistivity Conditioning 9.2.3 Baghouse/Fabric Filters 9.2.3.1 Overview 9.2.3.2 Basic Principles 9.2.3.3 Specific Designs 9.2.3.4 Collection Efficiency 9.2.3.5 Conclusions 9.3 Acid Gas Control 9.3.1 Acid Gases of Importance: SO2, HCl 9.3.2 Array of Technologies Depending on Application 9.3.3 Wet Scrubber Technology 9.3.3.1 Basic Principles 9.3.3.2 Typical Designs/Scale of Operations 9.3.3.3 Efficiencies
341 341 341 341 342 342 343 345 346 347 351 356 360 361 361 362 363 365 366 366 366
325 325 326 328 329 329 330 332 332 333 333
367 367 367 367 369
Contents
9.3.4
9.4
9.5
9.6
9.7
10.
Spray Dryer Absorbers 9.3.4.1 Basic Principles 9.3.4.2 Typical Designs/Scale of Operation 9.3.4.3 Efficiencies 9.3.4.4 Waste Streams 9.3.5 Dry Injection Systems 9.3.5.1 Basic Principles 9.3.5.2 Typical Designs/Scale of Operations 9.3.5.3 Efficiencies 9.3.6 Reactions 9.3.6.1 Kinetics and Thermodynamics NOx Control 9.4.1 Introduction 9.4.2 Post-Combustion Technologies of Significance 9.4.2.1 Selective Noncatalytic Reduction (SNCR) 9.4.2.2 Selective Catalytic Reduction (SCR) Mercury Control 9.5.1 Mercury Emissions from Existing Control Technologies from Coal-Fired Power Plants 9.5.2 Mercury Legislation 9.5.3 Technologies for Mercury Control 9.5.3.1 Sorbent Injection 9.5.3.2 Wet Flue Gas Desulfurization Carbon Dioxide Capture 9.6.1 Introduction 9.6.2 Approaches for Capturing Carbon Dioxide from Coal-Fired Power Plants 9.6.3 Post-Combustion Carbon Dioxide Scrubbing References
Some Computer Applications for Combustion Engineering with Solid Fuels 10.1 Introduction 10.1.1 Computer Applications in Combustion Engineering 10.1.1.1 Analytical Modeling 10.1.1.2 Computer Applications for Process Control 10.1.1.3 Computer Applications for Fuel Control 10.2 Background 10.3 Process for Fuels Opportunity Realization 10.3.1 Identify Current Fuels Opportunities
xv
369 369 369 370 371 371 371 372 372 372 374 376 376 377 377 378 380 380 383 383 384 388 389 389 389 389 390
393 393 394 394 396 396 396 397 397
xvi Contents
10.3.2
10.4 10.5 10.6
10.7 10.8
11.
Validate Objectives and Develop Effective Design Successfully Applying Computer Technology to Fuels Control AccuTrack Situation Challenges and Response Modeling the Flow of Coal in Bunkers and Silos 10.6.1 Plug Flow Models 10.6.2 Discrete Element Modeling (DEM) 10.6.3 Void Model 10.6.4 Stochastic Model 10.6.5 Bunker Geometry 10.6.6 Validation of Bunker Modeling Conclusions Regarding the AccuTrack Approach to Computer Management of Fuel Properties Summary
Gasification 11.1 Introduction to Gasification 11.2 Gasification Theory 11.3 Features of Gasification Systems 11.3.1 Bed Type 11.3.2 Flow Direction 11.3.3 Feed Preparation 11.3.4 Operating Temperature 11.3.5 Oxidant 11.3.6 Reactor Containment 11.3.7 Primary Syngas Cooling 11.3.8 Primary Gas Cleaning 11.3.9 Fuel Issues 11.4 Commercial Gasification Systems 11.4.1 GE Energy (formerly Texaco) 11.4.2 Shell 11.4.3 E-Gas (ConocoPhillips) 11.4.4 Siemens (formerly Future Energy GSP) 11.4.5 KBR Transport Gasifier 11.4.6 Lurgi 11.4.7 Raw Gas Analysis 11.5 Trace Components in Gasifier Syngas 11.5.1 Sulfur Compounds 11.5.2 Nitrogen Compounds 11.5.3 Chlorine Compounds 11.5.4 Unsaturated Hydrocarbons 11.5.5 Oxygen
399 403 408 410 410 410 411 411 412 415 420 421 423 423 424 427 427 430 430 431 432 433 433 435 435 436 436 436 439 439 441 442 443 443 443 444 444 444 444
11.6
11.7
11.8
11.9
12.
Contents
xvii
11.5.6 Formic Acid 11.5.7 Carbon 11.5.8 Metal Carbonyls 11.5.9 Mercury 11.5.10 Arsenic Gas Treating 11.6.1 Introduction 11.6.2 Desulfurization 11.6.3 Chemical Solvent Processes 11.6.3.1 Amine Processes 11.6.4 Physical Solvent Processes 11.6.4.1 Physical Washes 11.6.4.2 Selexol 11.6.4.3 Rectisol 11.6.4.4 Liquid Redox Processes 11.6.5 Membranes 11.6.6 COS Hydrolysis 11.6.7 CO Shift 11.6.7.1 Clean Gas Shift 11.6.7.2 Raw Gas Shift 11.6.8 Mercury Removal Complete Systems 11.7.1 Integrated Gasification-Combined Cycle (IGCC) 11.7.1.2 Gasification Block 11.7.1.3 Gas Treatment and Sulfur Recovery 11.7.1.4 Combined Cycle Power Plant 11.7.2 IGCC with Carbon Capture 11.7.3 Methanol Benefits and Limits of Gasification 11.8.1 Efficiency 11.8.2 Environmental Impact 11.8.2.1 Sulfur Emissions 11.8.2.2 NOx Emissions 11.8.2.3 Mercury 11.8.2.4 Other Emissions 11.8.2.5 Start-Up Emissions 11.8.3 Availability 11.8.4 Capital Requirements References
445 445 445 445 446 446 446 447 448 448 448 448 449 450 453 453 453 454 455 456 457 457 457 459 460 461 462 462 464 464 464 465 465 465 465 465 466 466 467
Policy Considerations for Combustion Engineering 12.1 Introduction 12.1.1 Combustion Engineers Do Not Make Policy 12.1.2 Combustion Engineers Respond to Policy
469 469 471 472
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Contents
12.2
12.3
12.4 12.5 12.6 Index
Environmental Policy and the Engineering Response 12.2.1 A Historical Perspective 12.2.2 Environmental Policy and Legislation Since 1990 12.2.3 Mechanisms of Engineering Response to Environmental Policy Energy Policy and Combustion Engineering 12.3.1 Energy Policy and Fuel Selection 12.3.2 Deregulation and Its Precursors 12.3.3 Energy Efficiency and Energy Policy Other Federal, State, Local, and Private Policies Impacting Combustion Engineers Conclusions References
473 474 474 477 480 481 481 482 482 484 484 485
Preface Over the course of our careers, the practice of combustion engineering applied to solid fuels has changed dramatically. Agents of change have included significant advances in knowledge concerning fuel characteristics and characterization methods, advances in knowledge concerning the processes and mechanisms of combustion, commercial deployment of new combustion processes including bubbling and circulating fluidized bed systems, new methods for pollution control (e.g., selective catalytic reduction or SCR for reducing oxides of nitrogen emissions), and a host of new methods for using computers to enhance the combustion engineering process. Our knowledge of fuels includes increased focus on statistics—inherent variability among fuel deposits or sources. It includes more scientific knowledge on petrography, and the relationship of fuel origins to fuel characteristics. In addition to traditional analyses—proximate and ultimate analysis, ash elemental analysis, etc.—there is increasing emphasis and information on structure and reactivity both of the organic fuel matrix and the inorganic constituents of the various ranks of coal and on other solid fuels ranging from biomass and peat to waste coal and petroleum coke. Methods for analysis now include measurements of pyrolysis and char oxidation kinetics, inorganic reactivity, and more. Techniques for analysis now include use of drop tube reactors and laser-based instrumentation, scanning electron microscopy (SEM) frequently governed by computer controls (CCSEM), Carbon 13 Nuclear Magnetic Resonance (13C NMR), Thermo Mechanical Analysis (TMA) for ash fusion characteristics, and a host of other analytical technologies. These technologies assist in both fuel characterization and combustion mechanism analysis. All of these are additions to—not substitutes for—traditional analyses of coal. New combustion processes include the family of fluidized bed systems: bubbling bed combustors, circulating fluidized bed combustors, and spouted bed combustors. These may be operated at atmospheric pressure or at elevated pressures. New combustion processes also include xix
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Preface
oxygen-enhanced combustion for NOx control and pure oxygen-based combustion to facilitate capture and sequestration of carbon dioxide, a greenhouse gas. Many new combustion techniques are driven by regulatory requirements—particularly for NOx control or greenhouse gas capture and sequestration. The computer has made dramatic impacts on combustion engineering in a host of different ways. Computer controls in the form of DCS systems have virtually replaced the older bench boards and hard stations. PI systems and their counterparts now accomplish data archiving, replacing the old circular charts, strip charts, and extensive manual data logging. PI systems and their counterparts also permit data manipulation, making test programs more feasible, and more sophisticated. Computers have been used extensively for modeling. Such modeling efforts include computational fluid dynamics (CFD) modeling of furnaces, boilers, windboxes, ducts, precipitators, etc. Modeling of solids flow in conveying systems and through both bunkers and silos also provides a means for understanding—in real time—the characteristics of the solid fuels being burned. More simplified zoning models and thermodynamic models also are employed. The modeling can be employed successfully because of better characterization of the fuel or fuels being burned. Computer applications have other significant contributions to combustion engineering. These permit more detailed understanding of fuel blending processes and the fuel behavior of blends. Such processes facilitate fueling boilers and kilns that can no longer access their “design fuel.” Computer analyses also provide the basis for technology selection. The driving forces behind many of these improvements include changing economics and increasing environmental regulations. From an economic perspective, solid fuels—particularly the various coals—have become increasingly attractive relative to petroleum and natural gas. Within the various coals, eastern bituminous coal prices have risen faster than subbituminous coals typically found in the Powder River Basin (PRB) and other western coal fields. Consequently PRB coal mines now supply over 400 million tons to the U.S. economy—generating over 20 percent of the electricity used in the United States. Other countries are experiencing similar phenomena. Because petroleum and natural gas are increasingly expensive for power generation and industrial applications, and because of rising coal prices, opportunity fuels such as petroleum coke, tire-derived fuel, wood waste, and other such products have become increasingly attractive to electricity-generating stations and industrial organizations. This, too, has impacted combustion engineering. Economically, a major shift in design approach has also occurred. Twenty-five years ago plants were designed to a “design fuel,” and a long-term
Preface
xxi
contract was signed with a mine. As a consequence, the design was specific to that coal. Today designs consider a range of coals, and potentially opportunity fuels from waste coals to petroleum coke to biomass. This causes significant changes in the combustion engineering approach. Existing units also are modified to handle a range of coals as the availability of the “design coals” recedes. The environmental drivers, not totally divorced from the economic drivers, include more stringent regulations of criteria pollutants: particulates, sulfur dioxide, and oxides of nitrogen. More attention is being given to other pollutants as well: mercury, arsenic and other trace metals, sulfur trioxide and sulfuric acid mist (SO3 and H2SO4), halogen-based emissions (HCl, HF), and more. Greenhouse gases—principally CO2 but also methane (CH4)—are also driving many environmental decisions. The above inventory does not include increasingly stringent water and solid waste concerns, along with the management of hazardous wastes. Because these concerns impact environmental permitting, they impact the selection of fuels and the design and operation of solid fueled installations—hence solid fuel combustion engineering. Combustion engineering is also impacted, increasingly, by policy and political decisions that may or may not have a technical foundation. These decisions—made at the federal, state, and local level as well as at the private industry level—determine to a significant extent how combustion engineering is practiced. Despite all of the dramatic advances in the past 25 years, firing of solid fuels fundamentally involves the following steps: acquiring (and understanding) the fuel or fuels to be burned; preparing the fuels, largely through pulverization; burning the fuels; and capturing the benefits (heat transfer) and managing the consequences (airborne emissions, solid wastes) of the combustion process. The advances and changes that have occurred can be considered within that context. This text attempts to capture many of the major forces and trends within solid fuel combustion engineering. It brings together authors from the academic community, from the consulting world, from manufacturing and system supply industry, and from the solid fuel utilization community. These authors provide a level of expertise essential in their given areas of specialty. This diversity of backgrounds among authors, along with the expertise represented, attempts to reflect the varying perspectives on combustion engineering, as well as the major topics. This book could not have been assembled without the diligent efforts of its many authors, along with the patience and perseverance of many colleagues throughout the combustion community. These colleagues, from all aspects of the combustion community, provided ideas and concepts for
xxii Preface
inclusion; they also provided extensive dialogue concerning topics to include in the book. Family members and friends provided constant encouragement and support for the entire project. With that, we have prepared the book: Combustion Engineering Issues for Solid Fuels. Bruce G. Miller Associate Director Energy Institute The Pennsylvania State University University Park, PA David A. Tillman Chief Engineer – Fuels and Combustion Foster Wheeler North America Clinton, NJ
List of Authors Dao N.B. Duong Performance Engineer, Foster Wheeler, NA Sharon Falcone Miller Research Associate, Energy Institute, The Pennsylvania State University Bruce C. Folkedahl Senior Research Manager, University of North Dakota Energy and Environmental Research Center N. Stanley Harding President, N.S. Harding & Associates Christopher Higman Chief Consultant, Syngas Consultants Ltd. Joe Hoffman Staff Engineer, ECG Consultants Donald Kawecki Vice President – Engineering, Foster Wheeler, NA Jason D. Laumb Research Manager, University of North Dakota Energy and Environmental Research Center Peter Marx President, ACT, Inc. Melanie McCoy General Manager, Wyandotte Municipal Utilities xxiii
xxiv
List of Authors
Bruce G. Miller Associate Director, Energy Institute, The Pennsylvania State University Jeffrey Morin Staff Engineer, ACT, Inc. David Nordstrand Subject Matter Expert – Emissions Control, DTE Energy Michael Santucci President, ECG Consultants James Scavuzzo Vice President, ECG Consultants David A. Tillman Chief Engineer – Fuels and Combustion, Foster Wheeler NA Anthony Widenman Director – Fuels Laboratory, DTE Energy Christopher J. Zygarlicke Deputy Associate Director, University of North Dakota Energy and Environmental Research Center
CHAPTER
1
Introduction David A. Tillman
Chief Engineer – Fuels and Combustion Foster Wheeler NA
1.1 Overview What is combustion engineering? An operational definition would be the application of engineering disciplines—principally mechanical and chemical engineering—to the conversion of fuels into useful forms of energy through the use of combustion processes. It involves the design, construction, and operation of utility and industrial power plants, process industry kilns and furnaces, and a host of similar facilities designed to supply and use fuels. Combustion is the dominant means for converting the potential energy, typically measured in Btu or kilocalories, contained in solid, liquid, and gaseous fuels into useful energy forms. The heat released from combustion can be used directly in thermal applications. More commonly, it is used to raise steam which, when driving turbines or steam engines, can be converted into shaft power or electricity. Combustion engineering applied to solid fuels has a long and illustrious history with practitioners including Thomas Newcomen, Sadi Carnot, James Watt, Lord Kelvin, George Stephenson, Allen Stirling, and many more. These individuals developed the origins of the theory and applications associated with combustion engineering. Combustion engineering for solid fuels involves a diverse collection of disciplines and activities, and it requires understanding of a variety of issues. These issues include an historical perspective concerning combustion of solid fuels, a basic understanding of the chemistry and physics 1
2 Combustion Engineering Issues for Solid Fuels
involved in combustion, and a consideration of the elements of the combustion system from fuel receiving and management from fuel preparation through burning fuel in the boiler system to post-combustion pollution controls. All these considerations come under the umbrella of combustion engineering for solid fuels.
1.1.1 A Perspective on Solid Fuel Utilization Coal, lignite, petroleum coke, wood waste, trees and crops grown as fuel, tire-derived fuel, municipal solid waste, animal wastes, and a host of industrial byproducts and wastes; these are the solid fuels and, collectively, these are the dominant energy sources for electricity generation and much of process industry. Combustion of solid fuels, historically, has been the primary source of energy for industrialization throughout the world. Further, economic development in the 20th and 21st centuries has virtually paralleled the electrification of industrial, commercial, and residential activity (see Figure 1-1) [1]. While all other stationary uses of energy have exhibited virtually no growth, electricity generation continues to increase in its use of all fossil and nuclear fuels, hydroelectric resources, and such renewable resources as wind power. In the United States, this growth in electricity has dramatically increased the use of solid fuels—principally coals of all ranks—as coal, wood waste, urban refuse, and other solid fuels provide the driving force for over 55% of the electricity generated and consumed. Solid fuels also dominate energy supply for such process industries as steel, cement, pulp and paper (including internally generated solid fuels such as
Energy Consumption (1012 Btu)
45000
Electricity
40000 Industrial - Primary Energy 35000 30000 25000 20000 15000
Transportation Residential - Primary Energy
10000 5000 Commercial - Primary Energy 0 1970 1975 1980 1985
1990 Year
1995
2000
2005
2010
FIGURE 1-1 Consumption of fuel in the United States for electricity generation and all other uses (Source: [1]).
Introduction
3
hogged wood waste and spent pulping liquor), and some aspects of mineral ore processing and refining. Intensification of the use of electricity in the economy is but one of several reasons why projections of future energy consumption show increased consumption of coal and other solid fuels on both a relative and an absolute basis, as shown in Figure 1-2 [1]. Increased use of coal—and of all solid fuels (e.g., peat, petroleum coke, biomass, waste-based fuels)— is based on their relative abundance along with the ability to convert these fuels into all useful forms of energy: electricity, liquid and gaseous fuels, and process and space heat. Coal, petroleum coke, wood waste, and other biomass fuels are used in a wide variety of applications. The relative worldwide resources and reserves of coal, peat, wood and other biofuels, and other solid fuels dwarf the worldwide resources and reserves of liquid and gaseous fuels; the long-term future of energy supply remains with the solid fuels. Major deposits of various ranks of coal, peat, and other solid fuels are found throughout the United States, Canada, Russia, China, South Africa, Australia, Germany, Poland, Colombia, and other countries. Estonia operates its economy largely on the use of oil shale as a solid fuel and has reserves for the long-term future. Scandinavia and other regions of the world rely heavily on peat, wood, and other renewable biomass fuels. Peat bogs also supply significant energy resources to Ireland
Annual Energy Consumption (1015 Btu)
60 Petroleum (Liquid Fuels) 50
40
Coal
30 Natural Gas
20 Nuclear 10
0 2005
Renewables 2010
2015
2020
2025
2030
Year
FIGURE 1-2 Projected consumption of coal, petroleum, natural gas, nuclear, and renewable energy sources in the United States in the year 2030. Note that current consumption of coal is about 231015 (quads)/yr. Coal consumption is projected to increase more rapidly and significantly than any other primary energy source (Source: [1]).
4 Combustion Engineering Issues for Solid Fuels
and other nations as well. The vast forests of Siberia, Brazil and the Amazon Basin, and other regions of the globe also must be considered as solid fuel energy resources. Countries such as Brazil are capable of growing agricultural crops for energy supplies on an economically advantageous basis. Some industrial and post-consumer wastes also must be included in the available solid fuels; these include petroleum coke, mixed municipal solid wastes, tire-derived fuel, and a host of other products. Petroleum coke has long been used as a priority solid fuel for some select industries. The pulp and paper industry derives a significant share of its energy from the combustion of spent pulping liquors in chemical recovery boilers. Other specific industrial, pre-consumer, and post-consumer wastes have found niche markets or have found use in generating electricity as a byproduct of incineration.
1.1.2 Fuels and Combustion Technology Development The discovery of fire is often considered to be the most important discovery of mankind [2]; this discovery is commonly considered on a par with the invention of the wheel [2–4]. Taming of fire meant productively using combustion—particularly of solid fuels. Consequently, combustion has been with societies—both the most primitive and most sophisticated—virtually forever. Despite the long traditions in the productive application of combustion and solid fuels, knowledge of this arena has virtually exploded in the past 30 years. During this time, a plethora of new technologies have been developed and commercially deployed. These technologies include (not exhaustive): (1) circulating fluidized-bed combustion, (2) supercritical boilers (boilers with typical main steam conditions of 3500 psig/1000 F) and ultra supercritical boilers (boilers with steam conditions approximating 5000 psig/1200 F main steam), (3) low-NOx firing technologies, (4) integrated gasification–combined cycle (IGCC) technology, (5) advanced post-combustion treatments for pollution control, (6) oxygen-enhanced combustion, and more. New technologies including combustion supported by pure oxygen and oxygen/flue gas mixtures are also under development and will emerge in the coming years. Analytical technologies also have advanced significantly including online, real-time analysis of coal; computer modeling of combustion including computational fluid dynamics (CFD) modeling, carbon 13 and nitrogen 15 nuclear magnetic resonance (13C NMR and 15N NMR) analysis of coal, the application of lasers to coal and combustion analysis, and many more analytical tools and approaches. Software and control technologies have also advanced, including the development of data acquisition systems and computer control technologies. Combustion, as a scientific and engineering arena, has received renewed vigor in recent years. Given the recent advances in combustion science and engineering, several questions merit attention: (1) what are the solid fuels? (2) what is
Introduction
5
the process of solid fuel combustion? and (3) what is involved in the combustion system, applicable to combustion engineering? These questions will be surveyed here and addressed in significantly greater detail in subsequent chapters.
1.2 Solid Fuels Used in Electricity Generation and Process Industry Applications Solid fuels used in electricity generation and process industrial applications include a wide array of materials: anthracite; various ranks and types of bituminous coals; various ranks and types of subbituminous coals, lignites, and brown coals; numerous types of petroleum cokes, oil shale, wood wastes (including spent pulping liquors); and the array of biomass fuels, tire-derived fuel, municipal wastes, and their derivatives; and a host of industrial residues and byproducts. Of these, the coals are the dominant solid fuels. Chapter 2 details the characteristics of coal, and Chapter 3 provides similar information concerning biomass and other opportunity fuels from petroleum coke to tire-derived fuels and agriculturally based biomass. Chapter 4 provides critical information concerning the behavior of inorganic constituents of solid fuels. For purposes of introduction, some salient characteristics of these fuels are summarized next.
1.2.1 Characteristics of Solid Fuels Fuel characteristics typically center on physical and chemical properties. These properties form the basis of subsequent chapters describing various lignites and coals, and various opportunity fuels. Of the analytical values, the standard chemical analyses—proximate and ultimate analyses—are most commonly used to characterize the composition of specific fuels. For the solid fuels, characterizations also include ash elemental analyses to define the basic properties of the inorganic constituents in such fuels. Table 1-1 provides representative proximate and ultimate analyses for various fuels including selected biomass fuels, lignites and various coals, a representative petroleum coke, tire-derived fuel, and mixed municipal waste. Table 1-2 provides representative ash elemental analyses for selected biomass fuels, representative coals, and other solid fuels. Note that the increase in rank from biomass fuel to bituminous coal or petroleum coke involves deoxygenation of the solid fuel and an increase in carbon content. The consequence is a decrease in the atomic hydrogen/carbon ratio and a decrease in the atomic oxygen/carbon ratio as shown in Figure 1-3 [9]. The data in Table 1-1 and Figure 1-3 show that, on balance, as solid fuels increase in rank, reactivity as measured by hydrogen/carbon atomic ratios and oxygen/carbon atomic ratios decreases. These phenomena are
6 Combustion Engineering Issues for Solid Fuels TABLE 1-1 Proximate and Ultimate Analysis of Representative Solid Fuels
Fuel
Weathered Switchgrass Fresh sawdust Beulah Lignite Black Thunder Caballo Rojo Shoshone Crown II (Illinois Basin) Pittsburgh Seam (washed) Pittsburgh Seam Shot Petroleum Coke
Proximate Analysis (wt %, oven dry)
Moisture (% A.R.)
Ultimate Analysis (wt %, oven dry)
HHV (Btu/lb)
VM
FC
Ash
C
H
O
N
S
13.7
81.8
14.8
3.4
49.4
5.9
40.6
0.4
0.3
8,150
42.1 37.0 27.9 31.1 14.7 14.0
80.0 47.8 45.2 45.3 42.6 38.1
19.0 44.9 49.1 48.2 51.3 50.3
1.0 7.5 5.5 6.5 6.1 11.5
49.2 65.1 69.1 70.0 73.1 68.5
6.0 4.1 4.8 4.9 5.4 4.7
43.7 21.6 19.1 23.6 19.1 7.3
0.1 0.6 0.8 1.0 1.4 1.5
— 1.0 0.6 0.6 0.9 1.7
8,400 10,800 12,200 11,900 12,500 12,450
7.1
34.0
55.5
10.5
76.6
5.0
5.0
1.4
1.6
13,600
11.0 6.5
30.6 16.0
55.7 81.5
13.7 2.5
73.6 87.8
4.7 3.7
4.9 0.9
1.3 1.3
1.6 3.9
13,000 14,800
Source: [5]
TABLE 1-2 Ash Elemental Analysis of Representative Solid Fuels Ash Elemental Analysis (wt %) Fuel
SiO2
Al2O3
TiO2
Fe2O3
CaO
MgO
Na2O
K2O
P2O5
Switchgrass Sawdust Utah Bituminous Illinois Basin coal East Ky coal Montana PRB coal Wyoming PRB coal N. Dakota Lignite Petroleum Coke*
71.98 20.38 47.53 44.32 54.69 33.82 32.24 29.8 21.22
1.43 4.05 10.89 19.33 29.92 17.93 16.37 10.0 11.31
0.14 0.06 0.48 0.93 1.37 1.17 1.25 9.0 6.66
0.60 4.57 6.60 22.17 6.23 6.08 5.11 0.4 4.51
9.65 32.6 19.30 3.19 1.80 14.22 21.77 19.0 7.54
3.12 3.51 2.68 0.66 0.99 4.01 5.14 5.0 2.13
0.14 0.85 0.34 0.41 0.48 6.84 1.55 5.8 1.13
3.57 19.9 0.67 2.09 2.31 0.99 1.01 0.49 1.58
2.55 2.49 0.13 0.13 0.29 0.38 1.18 — 1.54
*Vanadium content was 17.8% of ash Source: [5, 6, 7]
explored more completely in Chapter 2. The data in Table 1-2 show that the lower rank fuels—biomass, lignites, and subbituminous coals—have more alkali metal and alkaline earth inorganic constituents. These constituents are more likely to create slagging and fouling issues in their use.
Introduction
7
3.00
Oxygen/Carbon Atomic Ratio
Increasing Rank of Coal 2.50
2.00
1.50
1.00
0.50
0.00 0.00
1.00
4.00 2.00 3.00 Hydrogen/Carbon Atomic Ratio
5.00
6.00
FIGURE 1-3 Coal rank as a function of hydrogen/carbon and oxygen/carbon atomic ratios (Source [9]).
Further, the data available show that the lower-rank coals and biomass fuels have more readily available and reactive inorganic constituents; this further contributes to the slagging and fouling potential of such fuels [10, 11]. In addition to the basic chemical characteristics discussed previously, the solid fuels exhibit physical properties, which must be understood in terms of the use of these fuels. Such properties include porosity, specific gravity and bulk density, and grindability or the ability to reduce the fuel particles to their most usable particle sizes. Thermal properties of significance include heat capacity and thermal conductivity (the ability to conduct heat from the surface of the particle to its center). Additional chemical properties include chemical structure plus pyrolysis and char oxidation kinetic parameters. All these are considered in more detail in Chapters 2 and 3. Virtually all solid fuels are porous structures. Further, most solid fuels consist of aromatic clusters with 1–10 fused aromatic rings linked together by aliphatic bridges (see Figure 1-4) [12]. The aromatic structures provide the backbone of the fuel. These structures include functional groups and heteroatoms linked either to the aromatic structures or to the bridges. The number of fused aromatic rings provides critical insights into the rank of the fuel. Biomass fuels and lignites typically contain single aromatic rings linked by open aromatic structures. Subbituminous coals and bituminous
8 Combustion Engineering Issues for Solid Fuels
H O
H S
H
H
H
H H2 H2 H
H C H HH
O NH2 H2 HH HH H C H H
H H2H H2 H H C H H C H H S H H C H H C H
H
C
H
H
O H
H H H2
C
H C
H
HH
H2
OH H
S C O O H H
S
O
N
O
H C
H
H H O
H
H O
N
H
H
O
H
H C H
H C
C
C
CH3 C
O
H
S H
O
H H
H2 H
H
O H2
H
H H
HH
H O H C H H H H 2 C H H H2 H2
H2
H
O
H
H2
C H H
H H
H
H O
H
H
H
H H
H
H H
H H C H H H O
O H H
H H2
H
C
H
H
H
H2
FIGURE 1-4 Representative structure of subbituminous coal (Source [12]).
coals contain 2–4 fused aromatic rings on average. Anthracites and petroleum cokes contain many fused aromatic rings and far fewer bridges, functional groups, and heteroatoms.
1.2.2 Some Economic Considerations of Solid Fuels The properties of various types of solid fuels determine many of the economic considerations in their usage. For example, the woody biomass fuels with 40–50% moisture, bulk densities of 15–20 lb/ft3, and higher heating values of 4,000–5,000 Btu/lb have a limited transportation radius [7]. Typically this is considered to be 35–50 miles [7]. The biomass fuels such as switchgrass, with 5–10% moisture and 6–10 lb/ft3 have even a more limited effective transportation radius despite higher heating values of 5,500– 7,000 Btu/lb [7]. Lignites are also limited in transportation distance, while subbituminous coals can be moved over 1000 miles by rail or ship, and bituminous coals can be moved even longer distances. Because of the economics of transportation, typical biomass fuel installations are restricted to 500 106 – 700 106 Btu/hr heat input (nominally 50–70 MWe). Lignite and coal-fired plants—including those that burn petroleum coke in the fuel blend—can range in size from the smaller industrial installations to >3,000 MWe (see Figure 1-5). Size begets efficiency to a
Introduction
9
FIGURE 1-5 The Monroe Power Plant of DTE Energy, in Monroe, MI. This 3100 MWe (net) station is fueled by a blend of Powder River Basin and Central Appalachian Coals, blended in the coal yard shown in the upper left area of the picture.
significant extent—and as capacities increase the attention to efficiency also increases. This includes both the combustion system and heat recovery system. It is only the larger units (e.g., >500 MWe) that employ supercritical steam cycles, single and double reheat cycles, extensive use of feedwater heaters, and similar devices. The confluence of size and efficiency can be seen through historical data, as presented in Figures 1-6 and 1-7 [13]. Figure 1-6 shows the increase in boiler size as a function of time, starting in the post World War II era. Figure 1-7 shows the increase in main steam pressure over this period of time. By 1960, virtually all boilers were installed with 1000 F main steam temperatures—the limit of metallurgy at that time. Note that there was one experiment with an ultra supercritical unit (5,000 psig/1,200 F/1,000 F) in the mid 1950s [13]. Since metallurgy could not support this development, the unit was returned to a 3,500 psig/1,000 F/1,000 F configuration. It should also be noted that reheat cycles, invented in the 1920s, became popular after World War II. By 1950–1955, 75% of the boilers installed by the electric utility industry were reheat boilers. By 1960, virtually all boilers
10
Combustion Engineering Issues for Solid Fuels Average MW per Boiler 750.00 700.00 650.00
Megawatts (Name plate)
600.00 550.00 500.00 450.00 400.00 350.00 300.00 250.00 200.00 150.00 100.00 50.00 0.00 1940-1945 1946-1950 1951-1955 1956-1960 1961-1965 1966-1970 1971-1975 1976-1980 1981-1985 1986-1990 1991-1996
Time period
FIGURE 1-6 The growth in the size of utility boilers installed since World War II (Source: [13]).
Increase in Main Steam Pressure over Time 5500
Main Steam Pressure (psig)
5000
Maximum Main Steam Pressure
4500 4000 3500 3000 2500 2000 1500 1000 Average Main Steam Pressure
500 0 1940-1945 1946-1950 1950-1951 1955-1960 1961-1965 1966-1970 1971-1975 1976-1980 1981-1985 1986-1990 1991-1995
Time Period (5-year Increments)
FIGURE 1-7 The increase in main steam pressure in utility boilers since World War II (Source: [13]).
Introduction
11
installed by electric utilities were reheat boilers. However, supercritical boilers received some—but less—acceptance relative to the reheat trends. Consequently, many boilers designed in the late 1970s and early 1980s were installed using subcritical (drum) designs with steam conditions of 2,400 psig/1,000 F/1,000 F. Currently there is resurgence in coal-fired boiler orders. This resurgence, however, focuses on supercritical issues due to advances in metallurgy and techniques to overcome the problems associated with the early supercritical units. The trends in utility boilers contrast with industrial boilers and kilns. These installations are significantly smaller. Reheat is not commonly employed in industrial installations (e.g., pulp and paper industry boilers). Further, this resurgence includes more significant interest in and application of circulating fluidized-bed (CFB) technology. Despite the fact that industrial boilers were not of sufficient size to justify reheat units, they did justify increased attention to system efficiency. Industrial installations joined the parade of units employing extensive preheating of combustion air, attention to the temperatures of gaseous combustion products exiting the combustion system, minimizing the use of excess air, and other approaches to system efficiency. In the cement industry, for example, attention was given to the design of precalcination towers and preheating of combustion air to improve fuel efficiency; use of oxygen-enhanced combustion also came to the cement industry to improve fuel effectiveness and increase system capacities.
1.3 The Combustion Process for Solid Fuels Combustion of solid fuels, which involves both physical and chemical processes, is generally summarized by the following chemical equation: Ca Hb Oc Sd þ (a þ d þ b=4 c=2)O2 ! aCO2 þ 1=2bH2 O þ dSO2 þ heat [1-1] Because solid fuels typically contain some nitrogen and, potentially, chlorine, the equation can be modified to reflect their reactions; specifically, the oxidation of some but far less than all the fuel nitrogen to NOx and the behavior of chlorine as an oxidant, competing with oxygen for available hydrogen. Additionally, most solid fuels contain inorganic matter that may pass through the combustion system largely unreacted, may oxidize, and may undergo phase changes to form liquid matter that becomes slag or fouling deposits. Additionally, the oxygen normally comes from air, which contains 3.76 moles of nitrogen/mole of oxygen, and contains varying amounts of moisture depending on the humidity of the air. All these contribute to the products of combustion, including the amount of heat released that can be captured in useful form.
12
Combustion Engineering Issues for Solid Fuels
Given the general characteristics of solid fuel utilization systems and general properties of these fuels, it is useful to posit an overall combustion mechanism or framework. This framework can then be used to provide an overall method for evaluating the fuels, their uses, and the combustion systems—equipment and processes—used to harness solid fuels as positive economic forces.
1.3.1 Combustion Mechanism Overview The process of combustion involves multiple activities, which are best viewed in terms of reactions of a single particle. The combustion process, as frequently described, is complex [14, 15]. The generally accepted mechanism involves, initially, particle heating and drying. Dried particles then pyrolyze or devolatilize, yielding an array of volatile species and chars. Volatile species further react, as pyrolysis is typically a two-stage mechanism. Subsequently, volatiles are oxidized in a series of free radical reactions. Chars are also oxidized in a series of complex reactions. Subsets of these reactions include behaviors of inorganic constituents including both major inorganics (e.g., silica, alumina, iron, calcium) and trace metals. These overall reaction sequences, shown in Figures 1-8 through 1-10 [15], lead to the operator’s requirements for combustion: time, temperature, and turbulence.
1.3.2 Heating and Drying The solid fuel particle enters the boiler, furnace, or kiln containing moisture. Further, it enters at a relatively low temperature (e.g., room temperature to 150 F). If the particle is being fired in a stoker or cyclone boiler, it is crushed Noncondensible Volatiles
O2, N2
CO2 H2O N2
H2O
Solid Coal Particle
Condensible volatiles
Dry Coal Particle Heat
Heat
Heat
Char (with ash)
FIGURE 1-8 Overall combustion mechanism schematic.
O2, N2
CO2 SO2 Ash
Introduction
S
H
H2
H2
H
H2 H
CH3
H H2 HH H 2H C H H C H H S H H C H H C H
H
H C HH
H H H2
H
H2 HH
H O
H H H2
H
H
H2 H H2
2
CH3
H O
N
H O
H
O C
H H2 H2
H
H H
H
H H
H
H
H
H
O
CH3 H H H 2
CH3 H2
H S
H2 C
H
H O
CH3 N
OH
H
H2 H2
H CH3 O
OH
H H
H H
H O
H
H2 H2 H
H
H O H C
H
H H
H H2
OH H
H
H O
N
H
CH3
H O
O
H
H
H H
H
H
O
CH3
CH3 CH3
CH3
O
H H C H H H
H
H C H H O O H C H HH H C H H H
H
N
H
O
H
H2
OH H
H H2 H
H H C H CH3
H C H H H H2
SH
H2 H
H2
H C H
H2 C H
H H
H
13
H C H
H H
H H
H
H
H H
H
O H H
H
C
H
H
H2 H2
FIGURE 1-9 Representation of the mechanisms involved in the first stage of coal pyrolysis (Source: [15]).
but not pulverized. For stoker firing, the particle can be 3/4" 0"; for the cyclone boiler, the particle is typically 3/8" 0". If the particle is fired in a pulverized boiler, it is typically 90% in anthracite [8, 12, 13, 14]. TABLE 2-1 Oxygen Content by Functional Group (%) Oxygen Content by Functional Group (wt %) Carbon Content (%) 65.5 70.5 75.5 81.5 85.5 87.0 88.6 90.3 Source: [9]
OCOOH
OOCH3
OOH
OC¼O
ONR
8.0 5.1 0.6 0.3 0.05 0.0 0.0 0.0
1.1 0.4 0.3 0.0 0.0 0.0 0.0 0.0
7.2 7.8 7.5 6.1 5.6 3.2 1.9 0.5
1.9 1.1 1.4 0.5 0.5 0.6 0.25 0.2
9.6 8.2 6.4 4.2 1.75 1.3 0.85 2.2
Coal Characteristics
37
During coalification, the presence and structure of heteroatoms also become significant. Nitrogen in the biomass typically exists in amine form; under coalification processes it becomes incorporated into ring structures and commonly exists as pyridine (6-membered ring accounting for 50–60% of the total nitrogen) or pyrrole (5-membered ring contributing 20–40% of the nitrogen). The remaining 0–20% nitrogen is in amine or quaternary forms, whose contribution increases with decreasing rank [15]. Only lignite exhibits some nitrogen in amine form. Sulfur, resulting largely from the environment, becomes incorporated into the coal matrix; often it is found in bridges between fused aromatic clusters. Chlorine, coming from the environment, may also become incorporated into the coal structure. The coalification process that governed the formation of eastern and midwestern United States coals is distinct and well understood. Coals coming from other countries and regions, however, have been produced with coalification processes that differ significantly from the processes governing North American bituminous coals. Particularly coals formed in the Pacific regions known as the “Ring of Fire” are influenced by the fact that volcanic activity supplied both heat and inorganic matter to the coalification process.
2.2 Coal Classification Coals differ throughout the world in the degree of metamorphism or coalification (rank of coal), in the kinds of plant materials deposited (type of coal), and in the range of impurities included (grade of coal). In this section, coal rank, type, and grade are discussed along with the U.S. classification system by rank.
2.2.1 Coal Rank The degree of coal maturation is known as rank of coal and is an indication of the extent of metamorphism the coal has undergone. Heat and pressure converted the organic material (accumulated plant debris) progressively to a substance that more resembles graphite. Coals are ranked according to how severely they were metamorphosed. Because vitrinite precursors (see Section 2.2.2 for a discussion on maceral types), such as humates and humic acids, were the major constituents in peat, the extent of metamorphism is often determined by noting the changes in the properties of vitrinite [11]. Some of the more important properties of vitrinite that did change with metamorphism are listed in Table 2-2 [11]. Metamorphism did affect the other macerals, but the relationship between the severity of metamorphism and magnitude of change are different from those of vitrinite. Several useful rank-defining properties are elemental carbon content, volatile matter content, moisture-holding capacity, heating value, and microscopic reflectance of vitrinite [11]. Figure 2-2 illustrates the relationship between rank and fixed carbon content [16], the one chemical property
38
Combustion Engineering Issues for Solid Fuels
TABLE 2-2 Properties of Vitrinite Affected Progressively by Metamorphism Increase with Increasing Rank Reflectance (microscopic) and optical anisotropy Carbon content Aromaticity, fa ¼ Caromatic/Ctotal Condensed-ring fusion Parallelization of molecular moieties Heating value (a slight decrease at very high rank) Decrease with Increasing Rank Volatile matter (especially oxygenated compounds) Oxygen content (especially as functional groups) Oxidizability Solubility (especially in aqueous alkalis and polar hydrocarbons) Increase Initially to a Maximum, then Decrease Hardness (minor increase at very high rank) Plastic properties Hydrogen content Decrease Initially to a Minimum, then Increase Surface area Porosity (and moisture-holding capacity) Density (in helium) Source: [11]
most used to express coal rank. Figure 2-2 also shows the comparison between heating value, another property widely used as a measure of rank. Note that the heating value increases with rank but begins to decrease with semianthracite and higher rank coals due to the significant decrease in volatile matter. Porosity decreases with increasing level of metamorphism, thereby reducing the moisture-holding capacity of the coal. Moisture-holding capacity is also affected by the functional group characteristics, and in coals where cationic elements replace protons on acid functional groups, moisture-holding capacity is reduced [11]. Vitrinite reflectance is another import rank-measuring parameter. The advantage of this technique, discussed in Section 2.4, is that it measures a rank-sensitive property on only one petrographic constituent; therefore, it is applicable even where the coal type is atypical [11].
2.2.2 Coal Type As mentioned previously, coal is composed of macerals, discrete minerals, inorganic elements held molecularly by the organic matter, and water and gases contained in submicroscopic pores. Macerals are organic substances derived from plant tissues that have been incorporated into the sedimentary strata, subjected to decay, compacted, and chemically altered by
Coal Characteristics
39
16,000
2000
A
E
D
C
A
Meta-anthracite
E
R
B
Meta-anthracite
Anthracite
Semianthracite
E
T
R R
Low-volatie bituminous
M
A T
U
Medium-volatie bituminous
E
T
High-volatile A bituminous
Lignite B
X
L
High-volatile C bituminous
I
A T
L
Subbituminous A
Subbituminous C
F
40
20
O
Lignite A
V
Subbituminous B
60
I
S
High-volatile B bituminous
M
80
Percent
Anthracite
0 100
B
Semianthracite
I
Low-volatile bituminous
Lignite B Lignite A
6000 4000
Subbituminous B
Subbituminous C
Btu/Ib
8000
High-volatile A bituminous
High-volatile C bituminous
O
10,000
High-volatile B bituminous
Subbituminous A
12,000
Medium-volatile bituminous
14,000
O
N
FIGURE 2-2 (A) Comparison of heating values (on a moist, mineral matter-free basis) and (B) proximate analyses of coals of different ranks (Source: [16]).
geological processes. This organic matter is extremely heterogeneous, and a classification system has been developed to characterize it [11, 17, 18]. Classifying the coal, known as petrography, was primarily used to characterize and correlate coal seams and resolve questions about coal diagenesis and metamorphism, but it also has a role in coal utilization (see Section 2.4). All macerals are classified into three maceral groups—vitrinite, liptinite (sometimes also referred to as exinite), and inertinite—and they are characterized by their appearance, chemical composition, and optical properties. Each maceral group includes a number of macerals and other subcategories; however, only the three maceral groups are introduced here because extensive discussions of petrography can be found elsewhere [11, 12, 17, 18]. In most cases, the constituents in the coal can be traced back to specific components of the plant debris from which the coal formed [11, 12, 17, 18]. This is illustrated in Figure 2-3, which is a simplified overview of
40
Combustion Engineering Issues for Solid Fuels Source Material
Peat Swamp
Coal Components
Humified “Decomposed”
Vitrinite
“Charred”
Fusinite
Waxy Exines
Incorporated
Exinite
Resins
Incorporated
Resinite
“Wood”
Micrinite
“Chelated” Inorganic Ions Mineral Grains
Precipitated
Minerals
Incorporated
Minerals
FIGURE 2-3 Plant materials that accumulated along with inorganic materials in the peat swamp retain their identity as distinctive macerals in the coal (modified from [11]).
the various substances that accumulated as peat deposited and the components they represent in coal [11]. Adding to the complexity of the source materials were inorganic substances (also shown in Figure 2-3) that entered the environment as mineral grains and dissolved ions. Many of the dissolved ions either combined with the organic fraction or were precipitated in place to form discrete mineral grains [11]. Vitrinite group macerals are coalification products of humic substances originating from woody tissues and can either possess remnant cell structures or be structureless [9, 17]. Vitrinites contain more oxygen than the other macerals at any given rank level, and are characterized by a higher aromatic fraction. Liptinite group macerals are not derived from humifiable materials but rather from relatively hydrogen-rich plant remains such as resins, spores, cuticles, waxes, fats, and algal remains, which are fairly resistant to bacterial and fungal decay [9, 17]. Liptinites are distinguishable by a higher aliphatic (i.e., paraffin) fraction and a correspondingly higher hydrogen content, especially at lower rank [17]. The inertinite group macerals were derived mostly from woody tissues, plant degradation products, or fungal remains. While they were derived from the same original plant substances as vitrinite and liptinite, they have experienced a different primary transformation [17]. Inertinite group macerals are characterized by a high carbon content that resulted from thermal or biological oxidation, as well as low hydrogen content and an increased level of aromatization [9, 17].
Coal Characteristics
41
2.2.3 Coal Grade The grade of a coal establishes its economic value for a specific end use. Grade of coal refers to the amount of mineral matter that is present in the coal and is a measure of coal quality. Sulfur content; ash fusion temperatures, i.e., measurement of the behavior of ash at high temperatures; and quantity of trace elements in coal are also used to grade coal. Although formal classification systems have not been developed around grade of coal, grade is important to the coal user.
2.2.4 Coal Classification Since the rank of the coal is most important for the coal industry, almost every coal-producing country has its own economic coal classification, which is based mainly on rank parameters [17]. An excellent discussion of the many classification systems, scientific as well as commercial, is provided by van Krevelen [7]. There are two primary commercial classification systems in use—the American Society for Testing and Materials (ASTM) system used in the United States/North America and an international Economic Commission for Europe (ECE) Codification system developed in Europe. The classification systems used commercially are primarily based on the content of volatile matter [7]. In some countries, a second parameter is also used, and in the United States, for example, this is the heating value (see Figure 2-2). For many European countries, this parameter is either the caking or coking properties. 2.2.4.1 ASTM Classification System The ASTM classification system (ASTM D388) distinguishes between four coal classes, each of which is subdivided into several groups and is shown in Table 2-3. High-rank coals, i.e., medium volatile bituminous coals or those of higher rank, are classified based on their fixed carbon and volatile matter contents, expressed on a dry, mineral matter-free (dmmf) basis, whereas low-rank coals are classified in terms of their heating value (expressed on a moist, mineral matter-free [mmmf] basis). 2.2.4.2 International Classification System In 1998, the ECE Coal Committee developed a new classification system for higher rank coals [7]. This classification system, which in reality is a system of codes, is better known as a Codification System. The Codification System for hard coals, combined with the International Organization for Standardization (ISO) Codification of Brown Coals and Lignites, provides a complete codification for coals in the international trade. The ISO Codification of Brown Coals and Lignites is given in Table 2-4 [7]. Total moisture content of run-of-mine coal and tar yield are the two parameters coded.
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Combustion Engineering Issues for Solid Fuels
TABLE 2-3 ASTM Coal Classification by Rank Class/Group
Fixed Carbona (%)
Volatile Matterb (%)
>98 92–98 86–92
14,000 13,000–14,000 10,500–13,000c 10,500–11,500c 9,500–10,500 8,300–9,500 6,300–8,300 20–30 >30–40 >40–50 >50–60 >60
Code
Weight %
0 1
10 >10–15
2 3 4
>15–20 >20–25 >25
Source: [7]
The ECE International Codification of Higher Rank Coals is much more complicated and is listed in Table 2-5. Eight basic parameters define the main properties of the coal, which are represented by a 14-digit code number. The codification is commercial; includes petrographic, rank, grade, and environmental information; is for medium- and high-rank coals
TABLE 2-5 International Codification of Higher Rank Coalsa Parameter:
Maceral Group Composition (mmf) Vitrinite Reflectance (mean random)
Characteristics of Reflectogramb
Inertinitec
Liptinite
1, 2
3
4
5
Digit: Coding:
Parameter:
Code
Rrandom%
Code
02 03 04 — 48 49 50
0.2—0.29 0.3—0.39 0.4—0.49 — 4.8—4.89 4.9—4.99 5.0
0 1 2 3 4 5 —
1 >0.10.2 >0.2
—
no gap no gap no gap 1 gap 2 gaps >2 gaps —
Type
Code
Vol. %
Code
Vol. %
Seam coal Simple blend Complex blend Blend with 1 gap Blend with 2 gaps Blend with >2 gaps —
0 1 2 — 7 8 9
0—70% passing 200 mesh [or 74 mm]). Chapter 6 provided a detailed discussion of pulverizers for fuel preparation. The pulverized fuel is pneumatically transported into the furnace, where it is combusted. A description of the combustion process is provided in Chapter 1. Pulverized firing systems are also used in process industry settings such as rotary kilns.
7.2.3 Cyclone Firing Systems Cyclone firing systems are based on using centrifugal forces to facilitate burning of crushed (e.g., 3/8"0") fuel particles [3]. Since spiraling air drags the particles outwardly, they build up against the outer wall of the chamber, resulting in very high temperatures at the walls. Cyclone-fired systems operate at extremely high temperatures (typically >3,300 F), thus they often create high NOx emissions (e.g., 1.2–1.9 lb/106 Btu). Cyclone firing systems were originally designed to capitalize on the slagging properties of certain coals—Illinois Basin and Western Kentucky coals, Northern Appalachian coals—and to remove 70% of the inorganic matter in these coals as tapped slag or bottom ash.
7.2.4 Fluidized-Bed Systems Fluidized-bed combustion technology is a relatively new technology, with most of its coal-fired development starting in the 1950s and 1960s, with major commercialization occurring in the 1980s. It is a leading technology for the combustion of a range of fuels because of its inherent advantages over conventional combustion systems, including fuel flexibility, low NOx emissions, in situ control of SO2 emissions, excellent heat transfer, high combustion efficiency, and good system availability. A detailed discussion of fluidized-bed systems and their applications is provided in Chapter 8.
7.3 Applications and Uses of Conventional Firing Systems 7.3.1 Electricity Generation Coal-fired systems are the dominant sources of energy in the power industry; pulverized coal systems dominate, followed by cyclone-fired systems. (Circulating fluidized-bed systems, used increasingly for power generations, are discussed separately in Chapter 8.) A few installations employ stoker-firing, and many of the smaller independent power plants also use stoker technology. In the United States, coal generates roughly 50% of our electricity [4]. The next closest source of electricity is nuclear power (19.3%) followed by natural gas (18.7%). Data describing this distribution of electricity generation are presented in Table 7-1.
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Combustion Engineering Issues for Solid Fuels
TABLE 7-1 Distribution of Electricity Generation by Fuel, 2005 Fuel/Energy Source Coal Petroleum Natural Gas Other Gases Nuclear Hydroelectric Other Renewables Hydro-Pumped Storage Other Total
Net Thousand Megawatt-hours Generated
Percentage of Total
2,013,179 122,522 757,974 16,317 781,986 269,587 94,932 6558 4,749 4,054,688
49.7 3.0 18.7 0.4 19.3 6.6 2.3 0.2 0.1 100.0
Source: [4]
The overall process for electricity generation starts with the combustion of the fuel. The heat that is generated during the combustion process raises the temperature of a series of tubes that are contained within a boiler. The tubes contain water, which eventually changes to highpressure/high-temperature steam due to the high temperatures present within the boiler. The high-pressure steam from the boiler passes through the blades of a turbine, thus spinning the turbine shaft. The rotation of the turbine shaft is then used within a generator that creates the final product of electrical current. The history of power generation in coal-fired boilers is one of increasing the pressure and temperature of the steam, and of adding reheat steam cycles, for improved boiler thermal efficiency and reduced fuel consumption per unit of energy generated. This phenomenon is the reduction in net unit heat rate, expressed typically as Btu/kWh. Figure 7-2 illustrates the increase in pressure of utility boilers during the period 1945–1996. Steam temperatures rose from an average design temperature of 900 F in 1945 to 1,000 F in the period from 1960–1996. There were two units built with design temperatures of 1,100 F and 1,200 F during the periods of 1960–1965 and 1956–1960, respectively. The metallurgy available at that time could not sustain such temperatures, and values in the 1,000–1,025 F range were commonly accepted as state of the art [5]. Today, cycles designed for 1,050 F are common, and there is constant pressure to raise the main steam temperature to 1,100 F and beyond. Reheat cycles also became common—and virtually always employed—by 1960 in coal-fired utility boilers (see Figure 7-3). As shown in Figure 7-3, a few units were designed with double reheat cycles; however, single reheat became the standard. The combination of more severe steam conditions and reheat cycles permitted utility boilers to continuously increase in capacity, as is shown in Figure 7-4. While the very large
Conventional Firing Systems
245
Increase in Main Steam Pressure over Time Main Steam Pressure (psig)
5500 Maximum Main Steam Pressure
5000 4500 4000 3500 3000 2500 2000 1500 1000
Average Main Steam Pressure
500
6 99
0 –1
19
91
99
5 19
86
–1
98
0 19
81
–1
98
5 19
76
–1
97
0 19
71
–1
97
5 19
66
–1
96
0 19
61
–1
96
5 19
56
–1
95
0 –1
95 51 19
–1 46 19
19
40
–1
94
5
0
Time Period (5-year Increments)
FIGURE 7-2 Increase in main steam pressure among coal-fired utility boilers (data from [5]).
Implementation of Reheat Cycles in Boilers 200
Total Number of Boilers
180 Number of Boilers
160 140 120 100 80 60
Boilers with Reheat Boilers with Double Reheat
40 20
19 40 –1 94 19 5 46 –1 95 19 0 51 –1 95 19 5 56 –1 96 19 0 61 –1 96 19 5 66 –1 97 19 0 71 –1 97 19 5 76 –1 98 19 0 81 –1 98 19 5 86 –1 99 19 0 91 –1 99 6
0
Time Period (5-year Increments)
FIGURE 7-3 Implementation of reheat cycles to increase coal-fired boiler efficiency (data from [5]).
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Combustion Engineering Issues for Solid Fuels
6 99
0 –1
19
91
99
5 –1 86 19
–1
98
0 19
81
98
5 –1 76 19
–1
97
0 19
71
97
5 –1 66 19
–1
96
0 19
61
96
5 –1
95 56 19
–1
95 51 19
–1
94 46
–1 19
40 19
0
750 700 650 600 550 500 450 400 350 300 250 200 150 100 50 0
5
Megawatts (Nameplate)
Average MW per Boiler
Time Period (5-year Increments)
FIGURE 7-4 Average capacity of coal-fired utility boilers over time (data from [5]).
units such as Cumberland Fossil Plant of the Tennessee Valley Authority (TVA)—10 106 lb/hr or 1,300 MWe per boiler—are rarely on the drawing boards, 600–800 MWe supercritical boilers are still proposed and built using pulverized coal technology. Within the United States, some 50% of the electricity is generated by use of coal—largely by pulverized firing systems. Cyclone boilers account for only about 15% of the coal-fired capacity among utilities, and stoker firing accounts for much less. Because of the vast resources and reserves of coal in the United States (see Chapter 2), coal is the natural choice of fuel due to the fact that it is so readily available within the country. Coal and the other solid fuels—petroleum coke, various forms of biomass, wastes— remain the backbone of the U.S. energy supply. Further, utility boilers are at the heart of the solid fuels combustion community as they consume over 90% of the coal produced in the United States.
7.3.2 Industrial Boilers, Kilns, and Process Heaters Solid fuel combustion systems are used across the world to provide high amounts of intense heat for various practices. Many of the combustion systems are used to simply provide heat for boilers to create steam. The steam can then be used in various processes such as heating, pulp and paper processing, textile formation, refineries, food processing, and
Conventional Firing Systems
247
pharmaceutical purposes. Such systems include, but are not limited to, the following: Process steam boilers for industry (e.g., steam boilers supplying
energy to the dry kilns of sawmills); Power boilers for the pulp and paper industry (commonly cogenera-
tion boilers producing steam at 950 psig/1,250 F for backpressure or automatic expansion cogeneration turbines, and exhausting steam at 150 or 50 psig for process applications); Process rotary kilns such as cement kilns, lime kilns for pulp and paper manufacture, and ore processing kilns for the mining industry; and Process heaters of other designs for a myriad of manufacturing industries. These do not include the use of coal, coke, and other solid fuels in the smelting and refining of metals (e.g., coal and coke for blast furnaces, wood chips for nickel refining, which has been practiced periodically). Of these, industrial boilers are most prominent. There are three main types of industrial-sized boilers that are used which include watertube, firetube, and cast iron. Watertube boilers are the conventional style used in the utility industry and in the process industry; and they are designed in such a way that water passes through tubes that are in direct contact with the heat created by the fuel combustion. Watertube boilers are mainly used for steam generation. Further, for the large cogeneration boilers, the watertube design is the only appropriate technology. Firetube boilers are designed so that the hot combustion gases flow through the tubes, which are then surrounded by the intended heating water contained in a large open vessel. Firetube boilers are limited in both capacity and steam pressure. Typically, these are small (e.g., 50,000 lb/h or less), low pressure (e.g.,
