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Home My WebLink AboutUse of Mixed Fuels in Direct Combustion Systems, June 1989ENE 124 Alaska Energy Authority LIBRARY COPY Alaska Energy Authority Use of Mixed Fuels in Direct Combustion Systems % by David C. Junge University of Alaska Anchorage and Alaska Energy Authority State of Alaska June 30, 1989 DISCLAIMER This monograph entitled "Use of Mixed Fuels in Direct Combustion Systems" was prepared with the support of the Bonneville Power Administration, Assistance No. DE- FG79-84-BP14984, A006. However, any opinions, findings, conclusions or recommendations expressed herein are those of the author and do not necessarily reflect the views of BPA. Neither the United States Government nor the State of Alaska’s agencies or employees makes any warranty, expressed or implied, or assumes any legal liability or responsibility for the accuracy or completeness of information in this monograph. ENE iz ACKNOWLEDGEMENTS Many individuals have contributed to the publication of "Use of Mixed Fuels in Direct Combustion Systems". First, | would like to thank members of the peer review committee who provided many useful comments and suggestions on the preliminary draft. Members include: oO Craig Chase, Consultant on Biomass Systems; Bellevue, Washington oO Dr. P. J. Hill, Associate Professor of Economics, School of Public Affairs, University of Alaska Anchorage; Anchorage, Alaska oO Mark Hooper, Chemical Engineer, Environmental . Protection Agency; Seattle, Washington ° Dr. David Tillman, Combustion Consultant, Envirosphere; Bellevue, Washington Special thanks are due to Craig Chase for making a trip to Anchorage to discuss the project outline and for his many helpful comments. | would also like to thank the Alaska Power Authority for its support of the project. The Power Authority provided funds and staff assistance in completing this project. Pat Woodell was particularly helpful in gathering important reference materials, in formulating the initial outline, in keeping the project moving smoothly, and in providing pertinent ideas and information included in the text. Cal Kerr provided information on state regulations and other reference materials; he also helped edit and format the final publication. Special thanks are also due to C.R. (Chuck) McGowin, Project Manager, Electric Power Research Institute (EPRI), in Palo Alto, California. He provided many helpful review comments on preliminary draft material. EPRI, Power Magazine, and the Journal of the Air Pollution Control Association, very generously allowed us to reprint copyrighted materials from their publications. This assistance allows us to reprint a variety of tables and other data that illustrate themes in this research. The University of Alaska, School of Engineering, allowed release time from teaching duties and provided office support necessary for this project. Frances M. (Franny) Junge deserves special recognition and thanks for providing the home-base support system so necessary for the successful completion of this monograph. David C. Junge May, 1989 THE AUTHOR David C. (Dave) Junge is a Professor of Mechanical Engineering and a faculty member of the School of Engineering at the University of Alaska Anchorage. Prior to this faculty appointment, he served as Director of the Institute for Energy Research and Development at Oregon State University in Corvallis, Oregon. Dr. Junge received a B.S. degree from Stanford University and a Ph.D. from Oregon State University. He is the author of diverse publications dealing with combustion of biomass fuels and environmental concerns related thereto. However, he is best known nationally for mediocre banjo playing at conventions. His local reputation centers around design achievements with spinning wheels. iv EXECUTIVE SUMMARY The State of Alaska participates in the Pacific Northwest and Alaska Bioenergy Program, a regional organization funded by the U. S. Department of Energy and administered by the Bonneville Power Administration. With funds provided by this program, the Alaska Power Authority and the University of Alaska Anchorage conducted a technology assessment of co- firing, the use of mixed fuels in direct combustion systems. This report summarizes the findings of the technology assessment. The purpose of this technology assessment is to promote co-firing of biomass and fossil fuels where it is reasonable and economic to do so. The monograph makes no attempt to sell co-firing technology. Rather, it offers the reader relevant information for reaching soundly based decisions about co-firing. The focus of the work includes the operational, environmental, economic, and other considerations associated with co-firing fuels. Specific examples in the report emphasize the co-firing of fossil fuels (coal, oil and/or natural gas) with wood based fuels and with municipal solid waste based fuels. However, the overall presentation will guide readers in evaluating co-firing of other fuels as well. The monograph is intended to serve a wide audience including boiler owners and operators in utility, agricultural, industrial, institutional, military, and commercial sectors. In addition, it is intended for equipment manufacturers, engineers, planners and regulatory agencies dealing with environmental and siting issues. The material is presented in 12 chapters. The first two are introductory, offering a brief history of co-firing and summary of alternative benefits deriving from co-firing. Chapters 3 and 4 illustrate the extent to which co-firing is used in various sectors of the economy including the electric utility industry, food and agriculture, manufacturing, chemicals and textiles, military and institutional settings, municipalities, the wood products industry and others. These two chapters provide information on the range of fuels which are co-fired and some of the typical combinations of fuels used, the size of boilers used for co-firing, and combustion equipment used. Almost every aspect of co-firing (equipment, environment, economic, etc.) is influenced by the physical and chemical characteristics of the fuels which are burned. Chapter 5 provides detailed comparative information on fuel characteristics for 11 kinds of fuels which are most typically used in co-firing applications. Chapter 6 is devoted to equipment design and operational experience specific to co-firing and provides guidance and useful information with respect to each of the equipment areas which are influenced by co-firing. The topics include: 1) fuel receiving, storage, and reclaim; 2) fuel preparation; 3) fuel feed systems; 4) grates; 5) combustion air; 6) gaseous products of combustion; and 7) ash. Whenever co-firing is considered, the question invariably arises; "What will it do to the overall efficiency of the combustion system?" This is the topic of Chapter 7. It delves into methods of calculating combustion efficiency, the significance of efficiency, provides comparative data on estimated efficiency for 11 fuels which are commonly co-fired, and presents information gathered by the electric utility industry on efficiency changes experienced due to co-firing. Chapter 8 summarizes the principal environmental concerns associated with co-firing. It includes detailed discussions on particulate air pollutant emissions, gaseous air pollutant emissions, liquid wastes, solid wastes associated with co-firing and toxic and hazardous emissions. The chapter discusses the type and quantities of emissions expected and presents information on control strategies and systems which have been used successfully to control emissions. Chapter 9 is a guide to environmental regulations which pertain to co-fired boilers. The principal federal regulations are outlined along with most of the state and other regulatory concerns. The chapter directs interested readers to recently published reference materials devoted exclusively to helping the reader through the regulatory maze. The economics of co-firing are the focus of Chapter 10. The approach taken is one of guiding the reader through the steps necessary to reach a conclusion about whether or not co-firing will have positive economic benefits for a particular facility. It takes into account the overall operation of a plant site, changes in power plant operating expenses due to co-firing, fuel replacement values, debt service (which includes a checklist of the equipment that you may have to buy or modify in order to make co-firing work....It doesn’t tell you how much the equipment will cost. That has to be determined on a site by site basis), and consideration of economic risks associated with co-firing. Chapter 11 summarizes the decision making criteria that might be used in evaluating co-firing options. The format is a series of questions that should be addressed in the areas of fuel, equipment, environmental concerns, economic considerations, finance, and "other" in the process of reaching a GO or NO-GO decision. The “other area takes into account political considerations, timing, institutional barriers, and questions about whether or vi not there is an adequate infra-structure to support the operation of a co- fired facility. The final chapter is a brief look at the market areas into which co-firing of fuels is most likely to expand. Each chapter is written as an independent, "stand alone" essay. The references used are noted in the text as they occur and footnotes are included as necessary. The text is supplemented with 24 tables and 12 figures. vii ABSTRACT The State of Alaska participates in the Pacific Northwest and Alaska Bioenergy Program, an effort funded by the U. S. Department of Energy and administered by the Bonneville Power Administration. With funds provided through this program, the Alaska Power Authority and the University of Alaska Anchorage conducted a technology assessment of co- firing, the use of mixed fuels in direct combustion systems. This report contains the findings of the technology assessment. The purpose of this monograph is to promote co-firing of biomass and fossil fuels where it is reasonable and economic to do so, although, the text makes no attempt to sell co-firing technology. Rather, it offers the reader relevant information that can be used to reach soundly based decisions about co-firing. The focus of the work includes the operational, environmental, economic, and other considerations associated with co-firing fuels. Each chapter is written as an independent, "stand alone" essay. The text is supplemented with 23 tables and 12 figures. viii TABLE OF CONTENTS SPEIER SoS ca Sh yO A oh iake seks ee a Pe eee ee Sew es i Pe 8S SSG Sh nied s Se Pe Ee ii UN se erg aa oe 8 Mie 6 A Dd ee ee iv I citi SC os a oes peat ee aes v ra os Sees ee ee ew eR eee viii We ae eg a Ries Sp eee ois pa ix A ee onc oe eee eet aay bs ee aera CS xiii lutte CEG HESS 5 os... ee eee eo tet ee eS ia see eS xv CHAPTER 1: ss os ae eh Sine esi ote a 3 0 ae 1 SOME TERMS OF Gita TeOmnmOrOGy 26552 ee ee a eee 1 A BRIER Hiisi@pe Oe CO WinING 65 eco LS es ea oe eS ok 1 CHAPTER 2: ALTERNATIVE REASONS FOR CO-FIRING ............. 5 CHAPTER 3: ELECTRIC UTILITY EXPERIENCE IN CO-FIRING......... 9 (SO) TTS OAS see IS Go 6 ose i 84 eae oe 15 COPING GORE ER he cs a gs i Raila Se a 16 CHAPTER 4: NON-UTILITY EXPERIENCE WITH CO-FIRING ........... 21 SHAE OR CO rer SPU so 5a porta cect lars ever chan epee ts 28 7AYEES OF-FUEBES USED IN: CO-FIRING =. 5360 re ee es 28 COMBUSTION EQUIPMENT USED IN CO-FIRING .-. 2. ee 32 PIS. Sy sig op Ges ee a oe tes 33 a os Saco wc g 8 Re ws es et eee tes 8 ore 35 ae en ee Fa ee i aS ec Glas S See 37 Rats ee oa OS es OS a hee oe 38 NN IIR pon Reel a ey Sg SS a ed ees Go ale es 40 I Go i eh eek che ees 4 Pe te Pea NN as EP ae ee ae ere ERIE sso oe og ye oe oe bee te eee 46 CR EER IS con a he aces Se eh ee 49 SUM ISO ORION os es a ak St CHAPTER 5: PHYSICAL AND CHEMICAL CHARACTERISTICS OF FUELS TYPICALLY USED IN CO-FIRING APPLICATIONS. ....... 53 PGA 8556 gece See tie See gi ss Sis se eee wd a eee bas eS 53 Reatnien RMON 2 Sg sary ar a Goh esac ies ie S andct ce we ane aw 55 Re ee ara a arene in ene ocr a OR rg Poros ce 56 Soe 6 ina a os nee oe ot Ra ee 4 S7 nO 5s oa, oo. HS. ya cota ae a eae She copies Oe 60 ee st ih 6 oss 6, Sag aw Shee gibi eee bo ry se lt 61 No sca o's Fa uy ee dn ee me eee eae 63 et So on gaia se eipvervaal > hs soalaaernohpie need aaa oS 64 eI I 5 ik sas ds aden sw a ate aie @ Obs panes niet Seb 68 CHAPTER 6: EQUIPMENT DESIGN AND OPERATIONAL EXPERIENCE WI 6 eth Se ach ak 0G cute a's 69 FUEL RECEIVING; STORAGE, AND RECEAIN |. ocak ho i eas. 69 See rte nc as i ee ee ta ee I ate Ss Ses 70 Ne ie a a er soe ca ee ee oe wa Municipal Solid Waste and Refuse Derived Fuels ............... 73 FUR Piet 5 os Sigil oes eee 75 I ei See gh k ahs cial 4 hase wisnsraae, a WE RHOLATS Baoan 75 NURI. Sr oa. Te see g source eadidae mbes 79 ag wl gy Sl DS S| SR OS eR 81 Meatoring: Ca-BingdiUipis. 5 5. Se oe re ce 8 sei ean Distributing Fuels in the Combustion Chamber ................. 83 Ride rc id 5k wg Skea Bahay MIC WL EEG ar oud Ri rey a a 86 COMBUSTION eis 5 oo eect hg oe OV eae tis Ge noes 88 Gomplstion Air Gan Game. oS ie a ete ck bbe ee es 89 Measurement and Control of Combustion Air Flow.............. 93 GASEOUS PRODUGIS GF COMBUSTION oe i oe es 95 fe aiae ae Ces I oo be ws wee a oe ee bd ee oes 96 IPI root y sass coos Se oes 2 wk SS ee 97 IN 2S Fe Sons kas as 3 ese 687s oe Heh osha wee awe we 98 pe Tt IG 5 NE hte as See 100 Pea eM 8 gay aos Gg F the oo sas vo. gineln a dinin oases 101 SENN TOE e's 5 soos ah Cate Cis Tao soe wes 8c OEE 105 CHAPTER 7: THE IMPACT OF CO-FIRING ON EFFICIENCY.......... 109 GOMBUSTION AND THERMAL EFFICIENCY. . ooh. 5 ee i ee cee 109 THE SIGNIFICANCE OF THERMAL EFFICIENCY .................... 110 KEEPING THERMAL EFFICIENCY IN PERSPECTIVE ................. ae STi i ook erg iss we aeie ous t+ oie wee ed ecw ae 112 ELECTRIC UTILITY THERMAL EFFICIENCY EXPERIENCE ............ 114 I sock ose. gM oon wie eS MC MGR ab ve 115 CHAPTER 8: ENVIRONMENTAL CONSIDERATIONS ASSOCIATED WITH RN 5 5. o S30 so se LGU At Weer WIE ee gS 117 Re IN: ooo ose gk Ss wine Senay eee ate aes Ce ee Ae Particulate Emissions From Non-Combustible Ash .............. 118 Particulate Emissions Due To Incomplete Combustion ........... 120 Parueticn® CONSCHON DEVICES 6.5 ee ee eee Hee es 122 GASEOUS irs lemtanr ose ces he heer te cette wear he eic ee ebare Hoey gals 125 Gana aaa PCE gS Se PR ak ee Soo Soe Sage ew 125 UIGppea aA NOR MOONS 62S Sine viv 5 a sae wlan wie ce ee es we 127 nN aS D1 Soa is oi hcg Oe as Bos a a NiGeg ee ew 127 ICMP og ah gc ace Pee OECD ee ee NG Fe Sree oS a plies 129 ENUM Se ese i Gacy Site Gerace nics ev wih e HM ewe 132 Fuel Receiving, Storage and Reclaim Facilities ................. 132 PSI eaCM ea INC EIEN cS a Se OSG 53" 8 wes oF 15d a oo 133 Ar: POMMON: COMNGHIDOVIGES: goo cio eins os ee avs Soe wise ols owe 134 Additional: Comment on- Liquid Wastes:...-.7. 6. 6 os ees 134 TOXIG:AND: HAZARDOUS EMISSIONS. «1.5 0! ssssci5. 6 ences. sais Gitar coe ose rwiie) 0! aki) ’ SUMMARY OF ENVIRONMENTAL CONSIDERATIONS ASSOCIATED WITH Use Sac ates Seem eg me PM Lee oe LOS 139 CHAPTER 9: ENVIRONMENTAL REGULATIONS PERTAINING TO CO- a ee a ie oe re ee Te ee wee 143 SOUROES OF eo ty =o ee i he eka ee ee ees 143 FEDERAL LAWS AND REGULATIONS PERTINENT TO CO-FIRING ...... 144 STATE ENVIRONMENTAL REGULATIONS 200 eee eee 146 SURREY MUNI Ce oe Cr ene hes Ga 8 Ba eee ois 8 149 xi CHAPTER 10: ECONOMIC CONSIDERATIONS IN CO-FIRING ......... 151 OVERALL OPERATIONSOE THE GAGIUIEY 05 so oe cee ths ce wi a as 152 POWER PLANT CO-FIRING OPERATION EXPENSE ................. 153 Gromaes i Plant PUBPEMERNSE . 6... ee ee ee ees 153 Gilera A IY i ete cee ects 154 Changes in’ Plant Power Requirements ...............-...... 155 Changes in System Maintenance Expense.................... 155 Changes |i Onerung Gabor Expense ..........5......-.46., 155 Changes in Operating Expense Associated with Changes in Peak Steam Ra a ok wee Khe oss Ce eee es ee 156 Bee erry VR ek a i gh eee eee ee os wees 157 I he Se be OE ig tS aes hig ade wie ag hale aves et 158 PSI OO NAO AG RE goa ec ucee og Eos natecb Suse ole ku 8 ese a's 160 ADDITIONAL ECONOMIC CONSIDERATIONS IN CO-FIRING ........... 161 SUPAMAGY GOIN oscil. re Sees Poe ob ee pb eres 162 CHAPTER 11: DECISION MAKING CRITERIA FOR CO-FIRING ........ 165 Fete ee che neta ris oye Ga toe ar ae eae eae re eae SEs aoe tee is esas 165 Eee EE PF Parse es a aR CON OE EET A are ew A ec 166 I a as Pace aya rg ekg an Marg s RE eet 168 PRR a a eae St aa oe edu ole Sa stk ha eRe aes Ras 170 Buh ecko ek Scie hah N ss: a os duke “pia ese eee nasties oe 170 OTHER QUESTIONS TO CONSIDER IN REACHING A DECISION ABOUT (GOSRIRINGE crate ee ed si ee eae a 170 eis sc. cistern ee a ee RS ea ee Gees Tel SMUT: sto geht his ats ars er me ver a i ee eos tae acre a aes teets 172 [ASHEN NEINSOIEMS ES. Faso cpt Sy as ig Gelemeea os puke aay peer ee EAGK OF IireeSUIGtUNG: 65a hae ee ee 173 MAKING The rie MEClOlON 2 fo eee et ee Se oie ce 173 SUMRW any GOnnreIN ES cues cs coats ce ee ee 175 CHAPTER 12: POTENTIAL MARKETS FOR CO-FIRING .............. 177 NGAP Ort Ney go eile Sk eee wie ee a eee 177 Cr MR r,s oe reg ae Ss es as oa Ra peemes 179 xii TABLE 3-1 TABLE 3-2 TABLE 3-3 TABLE 3-4 TABLE 3-5 TABLE 3-6 TABLE 3-7 TABLE 4-1 TABLE 4-2 TABLE 4-3 TABLE 4-4 TABLE 4-5 TABLE 4-6 TABLE 4-7 TABLE 5-1 LIST OF TABLES Electric Utilities Involved in Co-Firing Coal and Waste Wood Riese RES ocr Sc ee pone aha, pis ne Se eee wanes one ote 9 Electric Utilities Involved in Co-Firing Coaland RDF ........ 10 Electric Utilities Involved in Co-Firing Coal and Miscellaneous Wastes Including Agricultural Wastes, Tires, Sewage Sludge, SUE PI Gs 5-3. es aio ea ee wo a eed anes a Electric Utilities Involved in Co-Firing Non-Coal Fossil Fuels With ROAR UH so. sss s25 sacs Sede Sra aes eum ne eemiem eetee 12 Notes in Reference to TABLE Nos. 3-1, 3-2, 3-3, and3-4 .... 12 Co-Firing Installations Operated by Utilities .............. 14 Summary of Nine Utility Sites Which Co-Fired Coal With eee ecient cs Ea ae en oR eae ae ace cutee Ss 19 Co-firing Installations in the Food and Agricultural Sectors ... 22 Co-Firing Installations in the Manufacturing, Chemicals & RR I sO CG eo) fei feo tg ae ee ee 23 Co-Firing Installations at Military Sites and Institutional Sites .. 24 Co-Firing Installations at Municipal Sites ................ 25 Co-Firing Installations Operated by the Wood Products SOON eat al opal so Saa ae wes cae Moe arene ee maa eset OAs 26 Co-Firing Installations Operated by Miscellaneous OpgameeNO NS ee ee ge ee ee se os 27 Combinations Used In Co-Firing Fossil and Non-Fossil Pere tere Meh et ee eae epee aig Soy 31 Fuel Characteristics Determined from Ultimate Analyses and Proximate Analyses of Fuels Which Are Commonly Used in CINE Sorin cers cet e bis os ols ies, Curae se emer eee 54 xiii TABLE 5-2 TABLE 5-3 TABLE 5-4 TABLE 6-1 TABLE 6-2 TABLE 6-3 TABLE 7-1 TABLE 8-1 TABLE 9-1 Fuel Parameters of Higher Heating Value, Moisture Content, Co-Fired Heating Value, Bulk Density, As-Fired Energy Density, Fuel Feed Rates and Ash Flow Rates For Fuels Which Are Commonly Used in Co-Firing Applications. ...... 59 ASTM Classifications of Refuse Derived Fuels ............ 66 Recommended Specifications for Refuse Derived Fuels ..... 67 Comparison of Combustion Air Requirements For 11 Different Fuels Which Are Commonly Used In Co-Firing Applications. The Table Also Includes Assumed Values For Fuel Moisture Level, Higher Heating Values (Wet and Dry Basis), Assumed Levels of Excess Air, Assumed Exhaust Gas Temperatures, and Calculated Thermal Efficiency Comparison of Exhaust Gas Volumes For 11 Different Fuels Which Are Commonly Used In Co-Firing Applications. The Table Also Includes Assumed Values For Fuel Moisture Level, Higher Heating Values (Wet and Dry Basis), Assumed Levels of Excess Air, Assumed Exhaust Gas Temperatures, Calculated Thermal Efficiency Values and Calculated Ediewet Gas Moisture Content: <i. Pe cree 92 Comparison Of Ash Input Rates For 11 Different Fuels. The Right Hand Column Is Presented In Units Of Pounds Of Ash Per Million BTU’s Of Effective Heat Input From The Fuel. .... 102 Calculated Values Of Thermal Efficiency For 11 Fuels....... 113 Comparison of the Ash Input Rates for 11 Different Fuels. ... 119 Summary List of Federal Laws and Regulations Which May Apply to Construction and Operation of Combustion PME sco cot gree rae Pee EC tte Gee hots 145 xiv LIST OF FIGURES FIGURE 4-1: Schematic Illustration of a Spreader Stoker Furnace... 35 FIGURE 4-2: Schematic Illustration of a Dutch Oven Furnace ...... 37 FIGURE 4-3: Schematic Illustration of a Fuel Cell Furnace ........ 39 FIGURE 4-4: Schematic Illustration of a Ward Furnace ........... 40 FIGURE 4-5: Schematic Illustration of a Small Suspension Burner EN 5c ear POS Oe aes Ga aN ae seem aia 8 42 FIGURE 4-6: Schematic Illustration of a Vortex Suspension Burner .. 43 FIGURE 4-7: Schematic Illustration of a Rotary Burner System ..... 45 FIGURE 4-8: Schematic Illustration of a Rotary Burner With Fixed Exterior Shell and Internal Helical Scraper .......... 46 FIGURE 4-9: Schematic Illustration of a Bubbling Fluidized Bed Be Gas apc h sho at sche hale em ean aa ate agen s Gui = 47 FIGURE 4-10: Schematic Illustration of a Circulating Fluidized Bed ... 50 FIGURE 5-1: Variations In Fuel Use Rates and Boiler Thermal Efficiencies as a Function of Fuel Moisture Content ... 60 FIGURE 6-1: Curves Showing the Relationship of Levels of Excess Air to Oxygen Content in the Exhaust Gas Stream for- SOVENGRRUGIS: . Ose Cees ey Sore Betws 93 CHAPTER 1: INTRODUCTION This is a monograph about co-firing. It is a text designed to provide useful information about the subject of burning more than one fuel at a time in combustion systems. The subject is moderately complicated but not difficult to understand. The text has been organized to assist you in locating needed information. SOME TERMS OF THIS TECHNOLOGY The terminology of this subject is very much the same as that used in combustion and energy generation related discussions. There are a few specific terms that are particularly helpful to understand as you read this text: Co-firing: This term is used to indicate that at least two different fuels are being burned at the same time under controlled combustion conditions. Examples include burning pulverized coal and municipal solid waste (MSW) simultaneously, burning natural gas and wood sanderdust at the same time, or burning coal and ground up tires simultaneously. "Co- combustion" and co-firing are equivalent terms. Co-generation: Steam is usually generated for some primary purpose such as space heating, supplying process heat or generating electricity. In many installations, the steam can also be used for some secondary purpose. For example, it might be used to both generate electricity and for space heating. Or it might be used to supply process heat and to generate electricity. Whenever steam is used to both generate electricity and for some other process the system is typically described as a co- generation system. Co-firing and co-generation are unrelated terms and should not be confused. A BRIEF HISTORY OF CO-FIRING Many combustion systems are capable of burning a variety of fuels. The earliest fire pits, fire places and stoves could burn wood, coal, peat, dung or whatever else might be available as a fuel. Steam locomotives and the early steam driven ships could burn either wood or coal and made the choice based on availability and cost. As industrial combustion systems were developed and marketed, particularly after World War Il, it was quite usual to equip them with burners designed for multiple fuels including natural gas, oil and/or a variety of solid fuels. That permitted the customer the option of broadening the fuel base and minimizing energy costs. While many systems have been designed and constructed to burn a variety of fuels, most industrial, commercial and utility combustion systems typically operate using only one kind of fuel at a time. There are several reasons for this: Availability. Many plant sites have only one fuel available in sufficient quantity to meet the energy needs of the plant. Economy. Even when operators have the luxury of choosing among several alternative fuels, it is usual for one fuel to be the least expensive to burn. The least costly fuel becomes the fuel of choice. Environmental regulations. With the advent of the 1967 Clean Air Act, regulations restricting the allowable emission of pollutants have been imposed on most combustion systems. Meeting emission standards requires both careful control of the combustion process as well as correct operation of emission control systems. Burning two or more fuels simultaneously may complicate control of the combustion process making it more difficult to maintain compliance with emission regulations. Of equal importance, the collection efficiency of emission control systems may be influenced by the type of fuel burned. For example, an emission control system designed specifically for operation with bituminous coal may not be adequate to meet emission limitations wnen wood or MSW is burned in the system. There are some combustion facilities which historically have burned two or more fuels simultaneously. Plants in the pulp and paper industry typically have co-fired coal and waste wood, or oil and waste wood in order to dispose of plant site wastes while meeting plant energy needs. Similar situations arise in the sugar industry where bagasse is often co-fired with fossil fuels for waste disposal and energy production. Municipalities have a recent, though significant, record of co-firing municipal solid waste with fossil fuels. Interest in co-firing was spurred in the early 1970’s during the oil crisis. That episode emphasized the fuel dependency of utilities, municipalities and industry, prompting eager searches for alternative fuels that might be co-fired with oil or used as replacement fuels for oil. During the 1980’s there has been a resurgence of interest in co-firing. The main reason is that municipalities (and other waste producers) are experiencing increased difficulty in disposing of solid wastes in landfills. Burning solid wastes offers some energy recovery and significant volume reduction of the waste, thus extending the life of landfills. Co-firing offers the opportunity at some sites to burn solid wastes in existing combustion facilities which are normally fired with other fuels, thus limiting the capital costs associated with the construction of new combustion facilities. Other justifications for co-firing are discussed in Chapter 2. CHAPTER 2: ALTERNATIVE REASONS FOR CO-FIRING The justifications offered for co-firing of fuels are quite diverse. The more commonly found reasons include: Reduction of Waste Volume Energy Recovery from Wastes Broadening the Fuel Base Economic Incentives Environmental Incentives Civic Incentives Improved Performance om 6.2.0 6 © Reduction of the volume solid wastes that would otherwise have to be placed in landfills. Typically one can expect that the volume of municipal solid waste can be reduced to about 1/4 of its initial volume through combustion. The potential for volume reduction of industry wastes varies considerably from industry to industry. The expected range is from fifty to ninety five percent volume reduction. Energy recovery from liquid/solid wastes. The amount of energy that can be recovered from waste materials depends, of course, on the characteristics of the waste. In the case of wood wastes from a wood products manufacturing plant there is a very significant amount of recoverable energy potentially available. At the other extreme of the energy spectrum, clarifier sludge from a municipal waste treatment plant can be burned but generally requires the use of auxiliary fuel to maintain combustion due to the high moisture level of the sludge and its relatively low energy content. Broadening the fuel base of a plant site and thereby limiting dependency on particular fuel supplies. Historically it has been common for plant sites operating natural gas fired boilers to maintain a reserve supply of fuel oil which could be used when natural gas supplies are curtailed. The same logic is now being applied at plant sites which normally burn coal. Several such sites have made modifications necessary to burn wood fuels and/or refuse derived fuels in combination with coal in order to reduce dependence on coal as the primary fuel. An Oregon utility, the Eugene Water and Electric Board, burned waste wood as the primary fuel but maintained a backup supply of coal to supplement the wood fuel in times of fuel shortages. Economic incentives associated with the ability to burn more than one kind of fuel. As municipalities and counties find it increasingly difficult and expensive to dispose of solid waste in land fills, they tend to look at alternatives such as paying utilities and/or industries to burn the waste materials. Thus economic incentives may arise which would make it profitable for utilities and/or industries to co-fire MSW or refuse derived fuels (RDF) with their primary fuels. For those industries which operate combustion facilities and which also generate liquid and or solid wastes which are combustible, it may be found that the cost to dispose of the wastes on a co-firing basis is less than the cost to dispose of the waste through landfilling or other alternative disposal means. Environmental incentives associated with reduced pollutant emission rates for sulfur dioxide. The argument has been presented that for those facilities burning sulfur bearing coals and which are required to reduce sulfur emissions to the atmosphere, co-firing of non-sulfur bearing fuels is a legitimate approach. Non-sulfur bearing fuels might include such options as natural gas, wood, MSW (or RDF), etc. Environmental incentives based on more lenient allowable emission rates for particulate matter. Federal New Source Performance Standards (NSPS) for particulate emissions from boilers are more lenient if the boilers are co-fired. The particulate matter limit is 0.05 Ibs/million BTUs of heat input for coal fired boilers and for coal/wood and coal/refuse-fired boilers where the non-coal fuel is used to produce under 10% of the steam generating capacity. However, the regulations are eased to 0.10 Ibs/million BTUs for co-fired boilers where the non- coal fuel’s contribution is greater than 10%. (Ref: "Final Industrial NSPS for PM, NOx Reflect Industry Comments" by Lee Catalano, Power Magazine, January 1987, P. 7) Civic incentives. \t appears from review of the literature that some industrial plants and electric utilities have agreed to co-fire refuse derived fuels in part due to a sense of civic concern. As noted above, there is an opportunity to significantly reduce the volume of MSW though combustion prior to landfilling. For those plant sites in which MSW or RDF can be co-fired in an environmentally acceptable manner, such an undertaking on a long term basis can provide significant waste removal benefits. Improved performance of combustion facilities. There are recorded several instances in the wood products and pulp/paper industries in which oil and wood or natural gas and wood are co-fired in order to improve the steam generation capacity of boilers. The common situation is that the boilers are designed principally to fire waste wood but are unable to meet the plant steam demand due to the high moisture level of the wood fuel. Co-firing wood and fossil fuels can improve not only the steam generation rate of waste wood fired boilers but can improve the load following capability of the boilers in terms of response time. An interesting variation of this concept was demonstrated at a prison facility in the State of Washington. There, coal fired boilers were being operated at steam generation rates well below their design capacity. Thus the gas flow rates through the boiler and the emission control devices were well below the design flow rates. This resulted in significantly reduced collection efficiencies of the control devices. By co- firing with wood fuels, the gas flow rates through the boiler were increased, thus improving the efficiency of particulate collection and reducing emission rates. Not all of these justifications apply to all sites at which co-firing is used. Many of the reasons noted apply only at a few sites. However, the list may trigger some constructive thinking about incentives for co-firing. CHAPTER 3: ELECTRIC UTILITY EXPERIENCE IN CO-FIRING The July 1987 edition of Power Magazine in a special report on co-combustion provided a list of 31 electric utilities in the U.S. which have experimented with co-firing. Some of the utilities discontinued co-firing on a permanent basis. Others were still co- firing at the time of publication. The utilities listed in the magazine are shown below in Table Nos. 3-1 through 3-3 are arranged on the basis of the primary and secondary fuels fired. Explanatory notes accompanying the tables are found in Table 3-5. Table 3-6 provides the original data from the Power Magazine special report and includes some information on boiler sizes. TABLE 3-1 Electric Utilities Involved in Co-Firing Coal and Waste Wood Related Fuels Operation | Combustion Utility and Location Since Equipment Eugene Water and Electric Board (#1) 1941 Spreader stoker Eugene, Oregon with traveling grates Traverse City Light and Power Dept. 1983 Traveling grate Traverse City, Mich Northern States Power Co. (#2) 1982 Bubbling fluidized bed Lacrosse, Wisc Public Utility District No. 1 Chehalis, Wash Portland General Electric Co. 1980 Boardman, Oregon New York State Electric 1982 and Gas Corp (#3) Lake Superior District Power Co. 1979 Spreader stoker Eau Claire, Wisc Tacoma Public Utilities (#4) 1987 Fluidized bed Tacoma, Wash boiler Note: See Table 3-5, page 12 for notes 1, 2, 3, and 4. TABLE 3-2 Electric Utilities Involved in Co-Firing Coal and RDF Utility and Location Wisconsin Electric Co. Milwaukee, Wisc Northern States Power Co. Burnsville, Minn City of Ames Ames, lowa City of Columbus (#5) Columbus, Ohio Union Electric Co. St. Louis, Missouri Rochester Gas & Electric Co. Rochester, New York Public Service Electric & Gas Co.(#6) Newark, New Jersey Potomac Electric Co. (#7) Dickerson, Maryland Potomac Electric Co. (#8) Washington, D.C. Madison Gas & Electric Co. Madison, Wisc Commonwealth Edison Co. Chicago, Illinois City of Lakeland Lakeland, Florida Baltimore Gas & Electric Baltimore, Maryland Operation Combustion Since Equipment 1970's Tangentially fired boiler 1986 Fluidized bed 1975 Tangentially fired boiler Spreader stoker 1972 1981 Suspension firing 1978 Wet bottom boilers 1985 1979 1978 Cyclone fired boiler 1982 1984 Cyclone fired boiler Note: See Table 3-5, page 12 for notes 5, 6, 7, and 8. 10 TABLE 3-3 Electric Utilities Involved in Co-Firing Coal and Miscellaneous Wastes Including Agricultural Wastes, Tires, Sewage Sludge, and/or Peat Operation | Combustion Utility and Location Since Equipment Cedar Falls Utilities (#9) Spreader stoker Cedar Falls, lowa Molokai Electric Co. (#10) 1983 Kaunakaki, Hawaii United Power Assn. (#11) 1982 Stoker Elk River, Minnesota Southwestern Public Service Co. (#12) Amarillo, Texas Minnesota Power Co. (#13) 1983 Tangentially fired Duluth, Minnesota boiler Carolina Power & Light Co. (#14) 1982 Basin Electric Power Co-op (#15) 1982 Velva, North Dakota Note: See Table 3-5, page 12 for notes 9 through 15. 1 TABLE 3-4 Electric Utilities Involved in Co-Firing Non-Coal Fossil Fuels With Other Fuels Operation Combustion Utility and Location Since Equipment United Illuminating Co. 1970's Cyclone furnace New Haven, Connecticut Firing oil and RDF Delmarva Power & Light Co. (#16) Firing oil and RDF Wilmington, Delaware Washington Water Power Co. Firing natural gas Kettle Falls, Wash and wood Note: See Table 3-5, page 12 for note 16. TABLE 3-5 Notes in Reference to TABLE Nos. 3-1, 3-2, 3-3, and 3-4 Table 3-1 Notes: 1) 2) 3) 4) Wastewood is the primary fuel. Coal is the secondary fuel. Various combinations of fuels have been co-fired experimentally including sewage sludge, shredded tires, shredded railroad ties, wastewood, RDF and peat. Project determined feasibility of burning wood as a supplemental fuel in existing stoker fired boilers. Secondary fuels included wood-waste and RDF. 12 Table 3-2 Notes: 5) 6) 7) 8) City has modified the plant to burn only RDF. Utility investigated co-combustion in 1978 primarily to characterize emissions. Conducted a 10 week trial with RDF and coal. Utility investigated co-combustion in the mid- 1970’s using RDF, sewage sludge and coal. Co-firing was found to be feasible but no data were developed or published. Table 3-3 Notes: 9) 10) 11) 12) 13) 14) 15) Experiments were carried out burning contaminated seedcorn and coal. Co-firing was done using diverse fuels including straw, woodchips, pineapple waste and waste paper. Experiments were conducted using shredded tires co-fired with coal. Utility analyzed wastes from feedlots to determine handling, processing and combustion characteristics for use in existing boilers. Conducted tests using peat (30% - 40%) and coal. Experimental project burning peat premixed with coal. Carried out tests with sunflower seed hulls mixed with lignite coal. Table 3-4 Notes: 16) Utility once had plans to burn RDF from nearby facility in an oil fired boiler converted to coal firing. 13 vL TABLE 3-6 Co-Firing Installations Operated by Utilities DATE OF STEAM FOSSIL FUEL(S) INITIAL NO. OF CAPACITY BIOMASS FUEL(S) % OF OWNER/OPERATOR PLANT LOCATION OPERATION BOILER OR FIRING SYSTEM UNITS LBS/HR % OF HEAT INPUT HEAT INPUT WISCONSIN ELECTRIC CO MILWAUKEE, WISC 1970'S TANGENTIALLY FIRED BOILER 2 2,000,000 RDF, 10% COAL, 90% NORTHERN STATES POWER CO BURNSVILLE, MN 1986 FLUIDIZED BED 1 1,000,000 RDF COAL CITY OF AMES AMES, IA 1975-81 TANGENTIALLY FIRED BOILER 2 620,000 RDF,(UP TO 20%) PULV. COAL WASHINGTON WATER POWER KETTLE FALLS, WA .... sees S 415,000 WOOD GAS EUGENE WATER & ELECTRIC BD EUGENE, OR 1941 SPREADER STOKER 2 310,000 WOOD, WOODWASTE COAL, OIL TACOMA PUBLIC UTILITIES TACOMA, WA eeee FLUIDIZED BED BOILER 2 264,000 WOODWASTE, RDF, TIRES .... TRAVERSE CITY LIGHT & POWER TRAVERSE CITY, MI 1983 TRAVELING GRATE 1 175,000 WOODCHIPS, 40% COAL, 60% CEDAR FALLS UTILITIES CEDAR FALLS, IA .... SPREADER STOKER W/ TRAVELING GRATE 1 165,000 SEED CORN (CONTAMINATED )COAL NORTHERN STATES POWER CO LACROSSE, WI 1982 BUBBLING FLUIDIZED BED o 150,000 WOODWASTE, ;RDF, PEAT .... CITY OF COLUMBUS COLUMBUS, OH ceae SPREADER STOKER cess 150,000 SHREDDED REFUSE, 60% COAL, 40% MOLOKAI ELECTRIC CO KAUNAKAKI, HI 1983 cove ese 40,000 STRAW, WOODCHIPS COAL UNITED POWER ASSN ELK RIVER, MN 1982-83 STOKER eece eee SHREDDED TIRES COAL UNITED ILLUMINATING CO NEW HAVEN, CT 1970'S CYCLONE FURNACE aes RDF, 40% OIL, 60% UNION ELECTRIC CO ST. LOUIS, MO 1972 ase ees RDF COAL SOUTHWESTERN PUBLIC SERVICE AMARILLO, TX aisles cose cece see FEEDLOT WASTES COAL ROCHESTER GAS & ELECTRIC CO ROCHESTER, NY 1981 SUSPENSION FIRING eee RDF COAL PUBLIC UTIL. DIST. NO. 1 CHEHALIS, WA esos eee see WOOD, REFUSE asee PUBLIC SERVICE ELECT. & GAS NEWARK, NJ 1978 WET BOTTOM BOILERS sees SLUDGE, RDF COAL, OIL POTOMAC ELECTRIC POWER CO DICKERSON, MD 1985 oses sees RDF COAL POTOMAC ELECTRIC POWER CO WASHINGTON, DC cece cove sees eee RDF, SLUDGE COAL PORTLAND GENERAL ELECTRIC BOARDMAN, OR eeee coe sees WOODWASTE, REFUSE COAL NY STATE ELECT. & GAS CORP .... 1982-83 oo WOOD COAL MINNESOTA POWER CO DULUTH, MN 1983-86 TANGENTIALLY FIRED BOILER PEAT (30% - 40%) COAL DELMARVA POWER & LIGHT CO WILMINGTON, DE sees eeee RDF COAL MADISON GAS & ELECTRIC CO MADISON, WISC 1979 FRONT FIRED BOILERS RDF COAL LAKE SUPERIOR DIST. POWER EAU CLAIRE, MI 1979 SPREADER STOKER 2 . WOOD, WOODWASTE, COAL COMMONWEALTH EDISON CO CHICAGO, ILL 1978 CYCLONE FIRED BOILER sees . RDF (UP TO 10%) COAL TACOMA PUBLIC UTILITIES TACOMA, WA 1987 sees . WOODWASTE, REFUSE eee CITY OF LAKELAND LAKELAND, FL 1982 WALL FIRED BOILER . RDF, 10% COAL CAROLINA POWER & LIGHT CO .... 1982-83 we 50 sess . PEAT COAL BASIN ELECTRIC POWER CO VELVA, ND 1982 oe. 2 . SUNFLOWER SEED HULLS COAL, 80% BALTIMORE GAS & ELECT. BALTIMORE, MD 1984 CYCLONE FIRED BOILERS 2 . RDF (UP TO 20%) COAL (Reference: "Special Report on Co-Combustion," Power Magazine, July, 1987, reprinted with permission) The information contained in the preceding tables clearly indicates the interest of utilities in co-firing. Most of the utilities attempted co-firing using coal as the primary fuel. Waste wood fuels and refuse derived fuels (RDF) have been the most popular choices for secondary fuels. Because of the interest in these two secondary fuels, each is discussed further. CO-FIRING COAL/WOOD Co-firing of coal and wood has been popular among utilities for a variety of reasons: oO The systems and equipment required for fuel receiving, handling, storage, reclaim, metering and feeding are very similar for coal and for wood fuels. oO Many of the utility boiler designs can be modified at relatively low cost to accommodate co-firing of coal and waste wood. oO Co-firing with coal and wood fuels requires relatively minor alterations in the operation of combustion control equipment. oO Air pollution control equipment for particulate emissions (i.e., multiple cyclones, wet scrubbers, electrostatic precipitators, fabric filters (baghouses), etc.) has proven effective for both wood and coal fuels. This permits co-firing without major detrimental impacts on plant pollutant emission rates. oO For the past 2 decades, wood fuels have been a highly touted alternative to fossil fuels. Commercial fuel suppliers have been effective in promoting wood fuels in a wide variety of forms including hogged fuel (coarsely ground wood and bark), pelletized wood/bark and compressed wood/bark in larger sizes. The marketing success appears to be based on four independent factors: 1) Wood fuels are available in large quantities in many geographic areas of the U.S. 2) The cost of wood fuels may be very competitive with the cost of fossil fuels. 3) Wood fuels are renewable and are, therefore, attractive as an energy resource compared to non-renewable fossil fuels. 15 4) Wood fuels have low sulfur content and thus do not generate sulfur dioxide in significant quantities as products of combustion. This increases the attractiveness of wood fuels compared to sulfur bearing fossil fuels (i.e., coal and oil). There are, of course, limitations facing utilities in co-firing coal and wood. One of these is the availability of wood fuels in quantities sufficiently large to have an impact on utility power production. It is generally recognized that to be economically competitive, wood fuels cannot be transported more than 100 miles’. Typical biomass growth rates in the contiguous United States are sufficient to sustain wood fuel harvesting at a rate required to generate up to 50 megawatts electric (MWe) within an economic radius of fuel transport. Thus, utilities considering co-firing coal and wood can expect wood fuels to provide not more than 50 MWe of the total plant output. A second limitation on co-firing of coal and wood by utilities is related to the utility’s combustion equipment. There are many designs of utility boilers. Some of these designs including spreader stokers with traveling grates, bubbling fluidized beds and circulating fluidized beds are easily modified for co-firing of waste wood fuels. Other designs such as cyclone furnaces and pulverized coal furnaces are less easily adapted to co-firing of coal and wood. (See Chapter 4 for descriptions of alternative designs of combustion systems. Chapter 6 contains additional detailed discussion concerning equipment concerns and limitations in co-firing). : CO-FIRING COAL/RDF Co-firing of coal and RDF has been attempted by several electric utilities during the past 2 decades. Table 3-2 (page 10) lists thirteen utilities which have conducted tests on co-firing these fuels as reported by Power Magazine. ' Economic transport distance may be less than 100 miles in areas with limited road access. 16 In June 1988 the Electric Power Research Institute published a 3 volume study entitled, "Guidelines for Co-Firing Refuse Derived Fuel in Electric Utility Boilers"*. The research for the publication began with a review of utility experience with RDF co-firing sponsored by the U.S. Dept. of Energy’s Argonne National Laboratory (ANL) and published by ANL in 1983. On the basis of this information a project team developed design criteria for equipment to receive, handle and co-fire RDF and evaluated the impact of RDF co-firing technologies. Volume 2, Engineering Evaluation Guidelines, summarizes key factors to consider when evaluating a proposed RDF co-firing project and addresses the impact of co-firing on power plant performance, operations and economics. Volume 2 also contains an RDF co-firing boiler performance model, RDFCOAL, a personal computer spreadsheet model. Volume 3 contains appendices which provide supplemental design, operating and cost data. The EPRI study indicates that between 1972 and 1984, nine utilities co-fired more than 600,000 tons of RDF with coal and oil. (Very little of the fuel was co-fired with oil. Most utilities co-fired with coal.) RDF typically contributed 10% - 15% of the total heat input. The utilities encountered several operating problems, most of which have been resolved through improvements in RDF quality and through modifications to combustion chambers (in particular through the addition of dump grates on pulverized coal boilers). As of 1988, four of the nine utilities continued to co-fire RDF with coal on a regular basis. The other utilities dropped the co-firing due to problems associated with co-firing fuels in boilers which were not well suited to the task and/or due to economic limitations wherein revenues could not support continued operations. Table 3-7 (page 19) lists the nine utilities involved in the co-firing study, the status of co-firing at each of the sites, the type of furnace used and information concerning the ash content of the RDF used at the site. Municipal utility interest in co-firing with RDF is quite natural. Many utility electrical plants are located near population centers which generate significant quantities of : Copyright 1988, Electric Power Research Institute. EPRI CS-5754, “Guidelines for Cofiring Refuse- Derived Fuel in Electric Utility Boilers, Volumes 1-3." Reprinted with permission. 17 municipal solid waste (MSW) from which RDF may be produced on a continuous, year around basis. Similar to the case of co-firing of coal and wood fuels, some utilities have found that: oO Boilers can (sometimes) be modified at relatively low cost to accommodate co-firing of coal and RDF. oO Co-firing of coal and RDF requires relatively minor alterations in the operation of combustion equipment. oO Air pollution control equipment which works for coal will generally function with acceptable efficiencies for co-firing of coal and RDF. (See discussion of particulate collection devices beginning on page 122.) oO The delivered cost of the processed RDF may be competitive with costs for fossil fuels. 18 TABLE 3-7 Summary of Nine Utility Sites Which Co-Fired Coal With RDF Average RDF Status Success in Success in Ash Content Suspension Cyclone Level of (Dry Basis) Fired Fired RDFAsh Location % by wt Boilers Boilers Content Ames (with 11.0 to 11.0 Ongoing commercial operation Yes Low disc screens) Bridgeport 12.4to 12.8 | Shut down. Process for pro- Yes Low ducing finely powdered and dry (2.6 to 3% moisture) RDF not economical. Baltimore 12.9 to 16.6 | Ongoing commercial operation. Yes Low to (See note A) Medium Madison 16.2 to 17.1 Ongoing commercial operation Yes Medium Lakeland 20.0 Ongoing commercial operation Yes High (See note B) Ames (without 24.8 Successful in stoker boilers No High disc screens) but excessive boiler fouling and slagging in suspension fired boiler. Milwaukee 22.6 to 27.2 Shut down. Excessive boiler No High slagging. Chicago 23.8 to 27.7. Shut down. Bottom ashre- No High moval problems. St. Louis 26.3 to 31.2 Successful test. No ongoing Yes High commercial operation after completion of test program. Rochester 28.1 to 32.1 Shut down No High Note A: The Baltimore RDF plant has produced RDF with an average dry basis ash content ranging from 8.5% to 16.6%. The initial boiler tests were conducted using RDF with an average ash content of 16.6%. During the first six months of commercial operation the RDF ash content averaged 12.9%. Note B: Analysis of only one RDF sample. This may not be typical of average RDF. Reference: Copyright 1988 Electric Power Research Institute. EPRI CS-5754, “Guidelines for Cofiring Refuse- Derived Fuel in Electric Utility Boilers, Volumes 1-3." Reprinted with permission. 19 Municipalities have actively pursued the option of having utilities burn RDF principally because of difficulties associated with the continued use of landfills. ° Increasingly landfills are being pinpointed as the source of ground and subsurface water contamination. Many landfill sites currently in use are at or near their maximum landfill capacity. Citizen groups are becoming very vocal in rejecting proposed new landfill sites. Burning RDF significantly reduces the volume of waste materials that must be landfilled. The EPRI/ANL study has shown that not all electric utility sites are candidates for co- firing of RDF with fossil fuels. The industry experience suggests that co-firing will be most successful when plant sites are selected with the following constraints: Unit selection should focus on baseloaded units that have at least 15 years of remaining life; The boilers should operate with high capacity factors and high load factors; The units selected should be those that do not exhibit boiler slagging and fouling or have ash handling problems; The units selected should be those which do not have electrostatic precipitator or unit derating problems while burning coal. Obviously these limitations significantly narrow the field of candidate utility sites. Co-firing with RDF presents a variety of engineering and operational concerns which are discussed in more detail in Chapters 6 & 7. Nevertheless, it is highly likely that utilities will continue to co-fire fossil fuels (particularly coal) with RDF and that the number of sites at which co-firing takes place will increase. 20 CHAPTER 4: NON-UTILITY EXPERIENCE WITH CO-FIRING Several sectors of the economy (in addition to the electric utilities) have experience with co-firing of fuels. The July 1987 edition of Power Magazine identifies six groups of non-utility organizations with co-firing experience. The tabled data provided in the reference document are not complete but they indicate the broad range of co-firing experience obtained in the U.S. during the past 2 decades. The data have been reproduced below in Tables 4-1 through 4-6. Table No. Sector Described 4-1: Food and Agriculture 4-2: Manufacturing, Chemicals and Textiles 4-3: Military and Institutional 4-4: Municipal 4-5: Wood Products 4-6: Miscellaneous Review of the information contained in the tables as well as information published in other references leads to interesting and perhaps useful conclusions about co-firing in the non-utility sectors. 21 2 TABLE 4-1 Co-Firing Installations in the Food and Agricultural Sectors DATE OF STEAM FOSSIL FUEL(S) INITIAL NO. OF CAPACITY BIOMASS FUEL(S) % OF OWNER/OPERATOR PLANT LOCATION OPERATION BOILER OR FIRING SYSTEM UNITS LBS/HR % OF HEAT INPUT HEAT INPUT SUGAR CANE GROWERS CO-OP BELLEGLADE, FL wees sees 5 880,000 BAGASSE coos CONTINENTAL CAN CO HODGE, LA sees eee 1 600,000 WOOD OIL, GAS HAWAIIAN COMM. & SUGAR CO MAUI, HI eves see 3 385,000 BAGASSE wees THE LIHUE PLANTATION LIHUE, KAUAI, HI 1978 cece if 320,000 BAGASSE OIL HANOKAA SUGAR CO HAINA, HI 1975 FLAT WATER COOLED GRATE 1 288 , 000 BAGASSE OIL HAWAIIAN AGRICULTURAL CO PAHALA, HI coos ees 1 240,000 BAGASSE sees ST. JAMES SUGAR CO-OP ST. JAMES, LA eee slese q 200,000 BAGASSE pee OSCAR MAYER & CO MADISON, WISC 1980 SPREADER STOKER . 125,000 RDF COAL STERLING SUGARS INC FRANKLIN, LA 1977 sees 1 100,000 BAGASSE OIL, GAS NESTLE CO FULTON, NY 1985 3-DRUM/SUSPENSION 1 85,000 COCOA BEANS GAS, OIL NESTLE CO SUNBURY, OH 1984 HYDROGRATE 1 80,000 COFFEE GROUNDS OIL, GAS JACK DANIELS DISTILLERS LYNCHBURG, TN 1981 SPREADER STOKER 2 80,000 SAWDUST COAL, GAS FOLGERS COFFEE CO SHERMAN, TX 1978 FLAT WATER COOLED GRATE 1 70,000 COFFEE GROUNDS OIL, GAS TRI-VALLEY GROWERS MODESTO, CA 1977 cece 1 60,000 AGRICULTURAL WASTES GAS, OIL GOLDKIST INC VALDOSTA, GA 1982 REFRACTORY LINED FUEL CELL 1 60,000 WOODWASTE, NUT HULLS sees DIAMOND SUNSWEET INC STOCKTON, CA 1980 SPREADER STOKER, STATIONARY GRATE 1 60,000 WALNUT SHELLS eaee WESTERN KRAFT ALBANY, OR 1980 SUSPENSION BURNER 1 50,000 DRIED HOGGED FUEL OIL FOLGERS COFFEE CO SHERMAN, TX 1982 cows 1 50,000 wood, 95% GAS CAMPBELL SOUP CO MAXTON, NC 1982 FLUIDIZED BED 1 50,000 PROCESS WASTE COAL MCCAIN FOODS LTD EASTON, ME 1981 D-TYPE BOILER 1 40,000 PELLETIZED WOOD GAS FOLGERS COFFEE CO SHERMAN, TX 1982 GRATE-TYPE WITH BURNER 1 40,000 COFFEE GROUNDS, WOOD GAS CARGILL INC RIVERSIDE, ND 1979 FLAT WATER COOLED GRATE 1 37,000 SUNFLOWER SEED HULLS OIL HEAVEN HILL DISTILLERS BARDSTOWN, KY 1986 3-DRUM/SUSPENSION 1 28,000 WOOD, 95% GAS, OIL KNOUSE FOODS INC ORTANNA, PA 1979 SCROLL FEED BURNER . 22,000 APPLE POMACE FINES, 90% OIL, GAS MID-AMERICAN DAIRIES LEBANON, MO 1986 A-TYPE BOILER 1 20,000 WOOD, 95% OIL SARA LEE CORP NEW LONDON, WISC 1986 ROTARY COMBUSTOR . 10,000 WASTEWATER SLUDGE GAS WALNUT PRODUCTS INC ST. JOSEPH, MO 1975 BUBBLING FLUIDIZED BED 1 10,000 WOODWASTE GAS, OIL TRI-VALLEY GROWERS MODESTO, CA 1981 oeee eeee 10,000 PEACH PITS, WOODWASTE OIL, GAS HONOKUA SUGAR CO PAAUHAU, HI 1977 SPREADER STOKER cece BAGASSE OIL UNITED ETHANOL CORP DELANO, CA 1985 see wees WOODY COTTON STALKS eee IMOTEK INC (Reference: SAN FRANCISCO, CA .... Special Report on Co-Combustion, Power Magazine, July, 1987. ALMOND SHELLS, FRUITPITS.... Reprinted by permission.) €% TABLE 4-2 Co-Firing Installations in the Manufacturing, Chemicals & Textiles Sectors DATE OF STEAM FOSSIM FUEL(S) INITIAL NO. OF CAPACITY BIOMASS FUEL(S) % OF OWNER/OPERATOR PLANT LOCATION OPERATION BOILER OR FIRING SYSTEM UNITS LBS/HR % OF HEAT INPUT HEAT INPUT EASTMAN KODAK CORP ROCHESTER, NY 1983 eas 1 550,000 BARK OIL GENERAL MOTORS CORP PONTIAC, MI . CIRCULATING FLUIDIZED BED 1 300,000 INDUSTRIAL SLUDGE BIT. COAL DOW CORNING CO MIDLAND, MI aeee sees 1 275,000 WOOD OIL PROCTOR & GAMBLE CO STATEN ISLAND, NY 1981 eee 4 240,000 WOOD OIL HERCULES, INC BRUNSWICK, GA 1979 SPREADER STOKER W/ TRAVELING GRATE 1 200,000 WOOD OIL GENERAL MOTORS CORP PONTIAC, MI 1976 SPREADER STOKER W/ TRAVELING GRATE . 200,000 INDUSTRIAL SOLID WASTE COAL, 50% PROCTOR & GAMBLE CO LONG BEACH, CA 1982 FLAT WATER-COOLED GRATE 1 150,000 WOOD GAS GENERAL MOTORS CORP FORT WAYNE, IND 1986 FLUIDIZED BED BOILER 2 150,000 INDUSTRIAL WASTE COAL SHAWMUT ENGINEERING INC ERIE, PA 1987 BUBBLING FLUIDIZED BED 2 140,000 REFUSE, SHREDDED TIRES .... PROCTOR & GAMBLE CO ALBANY, GA 1979 eoee 1 140,000 WOODWASTE, PEANUT HULLS OIL PROCTOR & GAMBLE GREENBORO, NC 1981 PILE BURNER 1 30,000 BARK, SAWDUST, WOOD wees FIRESTONE TIRE & RUBBER CO DECATUR, ILL 1984 PULSED HEARTH INCINERATOR cone 23,000 TIRES, INDUSTRIAL WASTES.... FIRESTONE TIRE & RUBBER CO DES MOINES, IA 1982 PULSED HEARTH INCINERATOR ooee 20,000 TIRES, INDUSTR. WASTES OIL, GAS CERTAINTEED CORP OXFORD, NC 1984 BUBBLING FLUIDIZED BED 1 7,000 WOOD ASPHALT WASTE OCCIDENTAL CHEMICAL CORP 1980 SPREADER STOKER eee oeee RDF COAL GULF & WESTERN CORP OKEELANTA, FL eeee eeee q BAGASSE OIL BURLINGTON INDUSTRIES LEXINGTON, VA oeoe cee WOOD OIL RUSSELL MILLS ALEXANDER CITY, eee 1 WOOD OIL REINOLD CHEMICALS CO PENSACOLA, FL eves hoes oes eee WOOD OIL (Reference: Special Report on Co-Combustion, Power Magazine, July, 1987. Reprinted by permission.) ve TABLE 4-3 Co-Firing Installations at Military Sites and Institutional Sites DATE OF STEAM FOSSIL FUEL(S) INITIAL NO. OF CAPACITY BIOMASS FUEL(S) % OF OWNER/OPERATOR PLANT LOCATION OPERATION BOILER OR FIRING SYSTEM UNITS LBS/HR % OF HEAT INPUT HEAT INPUT MILITARY SITES PUGET SOUND NAVAL SHIPYARD BREMERTON, WA 1987 SPREADER STOKER 2 420,000 HOGGED FUEL, RDF COAL, OIL U.A. AIR FORCE PATTERSON AFB, OH 1989 SPREADER STOKER 2 175,000 WOODWASTE COAL FORT STEWART FORT STEWART, GA .... TRAVELING GRATE STOKER 1 80,000 WOOD OIL, GAS BRUNSWICK NAVAL AIR STATION BRUNSWICK, ME 1985 STOKER 2 80,000 BARK OIL, GAS K.1. SAWYER AFB MARQUETTE, MI 1985 STOKER 2 60,000 BARK BIT. COAL RED RIVER ARMY DEPOT TEXARKANA, TX 1985 STOKER 3 50,000 BARK BIT. COAL RED RIVER ARMY DEPOT TEXARKANA, TX. 1982 cece 3 35,000 WOODCHIPS COAL UNIVERSITIES/COLLEGES UNIVERSITY OF MISSOURI ROLLA, MO 1980 eeee sees 50,000 WOODCHIPS COAL CENTRAL MICHIGAN UNIV. MT. PLEASANT, MI 1984 STOKER 1 50,000 BARK OIL, GAS BATES COLLEGE BREWER, ME sees eee 1 40,000 WOOD OIL MIDDLEBURY COLLEGE MIDDLEBURY, VT sees eeee 1 25,000 WOOD COAL, OIL GONVICK TRAIL SCHOOL GONVICK, MN 1983 UNDERFEED STOKER 1 800 PELLETIZED WOOD COAL UNIVERSITY OF MINNESOTA sees sees sees sees see WOOD COAL LASSEN COMMUNITY COLLEGE SUSANVILLE, CA 1 eeee REFUSE, WOODCHIPS oeee INSTITUTIONS DOROTHEA DIX HOSPITAL RALEIGH, NC 1981 STATIONARY GRATE 1 30,000 SAWDUST OIL, GAS EASTERN SHORE PRISON SOMERSET CO., MD 1986 D-TYPE, HYDROGRATE 2 25,000 HOGGED FUEL OIL NY STATE DEPT MENTAL HEALTH BINGHAMTON, NY 1981 BUBBLING FLUIDIZED BED 1 11,000 WOODWASTE OIL (Reference: Special Report on Co-Combustion, Power Magazine, July, 1987. Reprinted by permission.) s@ TABLE 4-4 Co-Firing Installations at Municipal Sites DATE OF STEAM FOSSIL FUEL(S) INITIAL NO. OF CAPACITY BIOMASS FUEL(S) % OF OWNER/OPERATOR PLANT LOCATION OPERATION BOILER OR FIRING SYSTEM UNITS LBS/HR % OF HEAT INPUT HEAT INPUT CITY OF ERIE ERIE, PA 1988 CIRCULATING FLUIDIZED BED 2 220,000 RDF, WOODCHIPS, TIRES .... CITY OF ROCHESTER ROCHESTER, NY 1970 eee sees 135,000 SLUDGE, REFUSE OIL, 25% CITY OF HARRISBURG HARRISBURG, PA 1983 WATERWALL INCINERATOR 2 120,000 REFUSE/SEWAGE SLUDGE eee CITY OF ALBANY ALBANY, NY 1981 SPREADER STOKER W/TRAVELING GRATE 1 100,000 RDF OIL, GAS NASHVILLE THERMAL TRANSFER NASHVILLE, TN 1986 STOKER 4 90,000 REFUSE GAS CITY OF DULUTH DULUTH, MN 1979 FLUIDIZED BED BOILER 2 90,000 SLUDGE, RDF, WOOD eee CITY OF BRISTOL BRISTON, CT cece eeee 1 73,000 REFUSE GAS CITY OF PITTSFIELD PITTSFIELD, MA 1982 eee 2 70,000 SEWAGE SLUDGE, REFUSE .... LA COUNTY SANITATION DIST CARSON, CA 1988 CIRCULATING FLUIDIZED BED z 50,000 MUNICIPAL SLUDGE OIL STATE OF CALIFORNIA SACRAMENTO, CA wee BUBBLING FLUIDIZED BED 1 45,000 WOODWASTE GAS, OIL CITY OF GLEN COVE GLEN COVE, NY 1984 STOKER cose 34,000 SEWAGE SLUDGE, REFUSE COAL JASPER HEATING CO JASPER, IN 1981 SUSPENSION/GRATE 1 10,000 WOODCHIPS, HOGGED FUEL COAL CITY OF STAMFORD STAMFORD, CT 1974 eee wees cece RDF 96%, SLUDGE 4% sees CITY OF INDIANAPOLIS INDIANAPOLIS, IN 1988 TRAVELING GRATE 1 ° REFUSE, 96%, SLUDGE 4% .... CITY OF HARTFORD HARTFORD, CT sees eee ooee coos RDF COAL CITY OF FLINT RIVER CLAYTON CO., GA .... PULSED HEARTH FURNACE sees oes DRY SLUDGE, WOOD CHIPS CITY OF BLOOMINGTON BLOOMINGTON, IN 1987 ROTARY COMBUSTOR sees SEWAGE SLUDGE & REFUSE BAY COUNTY PANAMA CITY, FL 1987 ROTARY COMBUSTOR eee WOODWASTE, REFUSE (Reference: Special Report on Co-Combustion, Power Magazine, July, 1987. Reprinted by permission.) 9% TABLE 4-5 Co-Firing Installations Operated by the Wood Products Sector DATE OF STEAM FOSSIL FUEL(S) INITIAL NO. OF CAPACITY BIOMASS FUEL(S) % OF OWNER/OPERATOR PLANT LOCATION OPERATION BOILER OR FIRING SYSTEM UNITS LBS/HR % OF HEAT INPUT HEAT INPUT MASONITE CORP UKIAH, CA 1979 INCLINED WATER COOLED GRATE 1 220,000 REDWOOD BARK, SAWDUST OIL HOLLY HILL LUMBER CO HOLLY HILL, SC aces eee 1 185,000 WOOD GAS KIRBY FOREST PRODUCTS CLEVELAND, TX eee GRATE WITH BURNER 1 180,000 WOOD NO. 2 OIL SUPERWOOD CORP DULUTH, MN 1970 GRATE WITH BURNER ‘ 140,000 WOOD OIL, GAS COLLINS PINE CO CHESTER, PA eee STOKER WITH BURNER A 140,000 WOOD, SANDERDUST cose BUCKEYE CELLULOSE CORP FOLEY FL 1981 SUSPENSION BURNER 1 125,000 DRIED WOOD FINES GAS, OIL MONTANA DE FIBRA LAS VEGAS, NV 1984 PINHOLE GRATE WITH BURNER 1 120,000 WOOD, SANDERDUST PROPANE COASTAL LUMBER CO HAVANA, FL 1980 SPREADER STOKER, STATIONARY GRATE 1 70,000 BARK, SAWDUST ses BASSETT FURNITURE INDUST. MONT AIRY, NC sees eee 1 70,000 WOOD COAL VAAGAN BROS LUMBER CO COLVILLE, WA 1979 CELL-TYPE BURNER 1 60,000 BARK, SAWDUST, WOOD secs J. M. HUBER CORP EASTON, ME 1983 CELL-TYPE BURNER 1 60,000 BARK ROY O MARTIN INDUSTRIES ALEXANDRIA, VA oees eee : 60,000 WOOD, WOODWASTE BIG VALLEY LUMBER CO BIEBER, CA 1983 CELL-TYPE BURNER 1 60,000 BARK, SAWDUST BATSON LUMBER CO NATALBANY, LA 1980 SPREADER STOKER, STATIONARY GRATE 1 60,000 BARK, SAWDUST seise US PLYWOOD CORP GAYLORD, MI sees sees 1 55,000 WOOD GAS ETHAN ALLEN FURNITURE CO OLD FORD, NC 1974 ae 1 55,000 WOOD GAS AMERICAN FOREST PROD. CO MARTEL, CA 1974 aces 1 55,000 WOOD GAS SAN POIL LUMBER CO. REPUBLIC, WA 1979 VERTICAL CELL-TYPE BURNERS 1 50,000 BARK, WOOD, SAWDUST eoee LINNTON PLYWOOD CORP PORTLAND, OR 1977 aces 1 44,000 SAWDUST, WOODWASTE GAS, OIL PACIFIC WOOD TREATING CO RIDGEFIELD, WA 1977 PILE BURNERS 1 40,000 BARK, WOOD, SAWDUST COAL LAND PLYWOOD INC EUGENE, OR 1977 aoe 1 40,000 WOOD GAS ALASKA TIMBER CORP KLAWOCK, AK 1983 STOKER 1 40,000 BARK, SAWDUST eee ARMSTRONG WORLD INDUSTRIES THOMASVILLE, NC 1967 HRT BOILER 1 27,600 WOODWASTE, 70% COAL, 30% COMMERCIAL CARVING CO THOMASVILLE, NC 1970 eee ees 26,000 WOODWASTE COAL WOOD-METAL INDUSTRIES KREAMER, PA 1980 1 1 25,000 WOOD OIL SUPERWOOD CORP LITTLE ROCK, ARK 1974 A-TYPE BLR 1 25,000 WOOD GAS HARDEI MUTUAL PLYWOOD OLYMPIA, WA 1972 3 DRUM BLR 1 25,000 WOOD GAS AMERICAN FURNITURE CO BATESVILLE, IN 1973 cece 1 24,000 WOOD GAS, OIL WYOMING SAW MILLS INC SHERIDAN, WY 1980 PILE BURNER 1 20,000 BARK, SAWDUST, WOOD sees VAUGHAN FURNITURE CO GALAX, VA 1973 SPREADER STOKER W/TRAVELING GRATE 2 20,000 wood, 90% COAL, 10% S$ PLYWOOD CORP HOLDEN, LA 1975 sees 1 20,000 GROUND WOOD GAS BAKER FURNITURE CO ANDREWS, NC sees FIRETUBE eee 20,000 WOOD OIL DOVER MILLS CHERRYVILLE, NC 1982 FIRETUBE sees 17,000 WOOD COAL THIESING VENEER CO MOORESVILLE, IN 1973 SUSPENSION BURNER 1 15,000 WOODWASTE COAL FORMICA CORP CINCINNATI, OH 1983 STOKER 5 15,000 wood, 90% COAL, 10% (Reference: Special Report on Co-Combustion, Power Magazine, July, 1987. Reprinted by permission.) Ze TABLE 4-6 Co-Firing Installations Operated by Miscellaneous Organizations DATE OF STEAM FOSSIL FUEL(S) INITIAL NO. OF CAPACITY BIOMASS FUEL(S) % OF OWNER/OPERATOR PLANT LOCATION OPERATION BOILER OR FIRING SYSTEM UNITS LBS/HR % OF HEAT INPUT HEAT INPUT SCOTT PAPER CO CHESTER, PA 1986 CIRCULATING FLUIDIZED BED 1 650,000 WOODWASTE, RDF OIL, GAS P.H. GLATFELTER CO SPRING GROVE, PA .... CIRCULATING FLUIDIZED BED 1 400,000 WOODWASTE, SLUDGE COAL, OIL ULTRA SYSTEMS, INC FRESNO, CA 1988 CIRCULATING FLUIDIZED BED 4 220,000 ALMOND PRUNINGS sees MASONITE CORP UKIAH, CA 1978 FIELD ERECTED STOKER 1 220,000 WOOD OIL SIGNAL SHERMAN ENERGY CO SHERMAN STATION, ME sees 1 180,000 WOOD OIL ERG BIOMASS 1 MEDFORD, OR 1986 HYDROGRATE 2 175,000 HOGGED FUEL OIL SWIFT RIVER GROUP GREENVILLE, ME 1986 eeee 1 155,000 HOGGED FUEL OIL PINETREE POWER BETHLEHEM, NH eeee 1 150,000 WOOD OIL FEGLES POWER SERVICE CO MINNEAPOLIS, MN .... eee 3 125,000 BARK, SLUDGE, REFUSE COAL TREMONT CORP JOYCE, LA coos eee 1 100,000 WOOD OIL H. E. HUNT & ASSOC OGDEN, UT sees oeee 1 100,000 REFUSE GAS EVANS PRODUCTS MONCURE, NC sees eeee 1 80,000 WOOD OIL BIOMASS POWER CORP MONTICELLO, FL 1983 STOKER 1 80,000 BARK, SAWDUST, SANDERDUST ATCHISON, TOPEKA & SANTA FE SOMERVILLE, TX sees STOKER WITH BURNER 1 70,000 WOOD GAS, OIL CELOTEX CORP MARION CO, SC 1973 sees 1 66,000 WOOD GAS, OIL (Reference: Special Report on Co-Combustion, Power Magazine, July, 1987. Reprinted by permission.) SIZE OF CO-FIRING FACILITIES In the non-utility sectors, co-firing is accomplished in combustion facilities ranging in size (steam generation rates) from 650,000 Ibs per hour to less than 1,000 Ibs per hour. The maximum size is roughly one half of the maximum size of co-fired units in the electric utility sector. The important thing to note is that the size of the facility does not appear to influence the ability to successfully co-fire various fuels. The concept works equally well for large and for small sized combustion facilities. TYPES OF FUELS USED IN CO-FIRING The choice of fuels which are co-fired varies according to the user, as might be expected. In the food and agricultural sectors, waste products from the foods grown and processed are used as supplemental fuels. For example, in processing cane sugar, bagasse is a waste product which is burned to remove it from the plant site and to recover energy. In the coffee roasting and processing industry, coffee grounds are an energy bearing waste product which is co-fired. In the nut industry, shells and hulls are burned for waste removal and heat recovery. In each of these industries the energy contained in the plant generated wastes is not sufficient to meet the needs of the plant site. So the wastes are co-fired with other fuels. The same concept applies to other sectors of the economy. In manufacturing, chemicals and textiles it is not surprising to see plant generated industrial wastes burned for energy recovery (i.e. tires, broken wood pallets, paper, cardboard, etc.). In the wood products and pulp/paper industries there are large quantities of bark, sawdust, non-merchantable scrap, sanderdust, product edge and end trim and other forms of wood fiber available whose most economic end use is as an energy resource. Co-fired with other fuels, these plant generated wastes can often provide a major portion of the total energy needs of the facility. 28 The predominant non-fossil fuels which are co-fired at military sites, and institutional facilities such as colleges, universities, prisons, and hospitals are waste wood fuels. These are generally supplied by contractors who obtain the fuels from nearby wood products manufacturing plants, pulp/paper mills, and/or other sources of wood fiber. A small portion of the fuel may be from wastes generated on site, however, the energy content from wastes generated on site is usually quite small compared to the overall energy use at military facilities and institutional sites. The fuel choice decisions for municipalities reflect their needs for waste disposal perhaps more than their needs for energy recovery. RDF, sewage sludge and general refuse are the most common of the non-fossil fuels used by municipalities in co-firing installations. The fossil fuels used in co-firing are, of course, either coal, oil, and/or natural gas. Other fossil fuels such as propane and butane are used to a limited extent in a variety of industrial and commercial settings but are seldom co-fired with non-fossil fuels. It is suspected although not verified that the reason is principally economic. Propane and butane are just too expensive. In the electric utility sector (See Chapter 3) coal is the predominant fossil fuel used in co-firing situations. In the non-utility sectors oil and natural gas are the most commonly used fossil fuels for co-firing. For example, in the food and agricultural sectors only 3 out of 31 facilities listed use coal. The remainder co-fire with oil and/or natural gas. Similar statistics are found in the manufacturing, chemicals and textiles sectors (see Table 4-2, page 23) and in the "miscellaneous organizations" sector (see Table 4-6, page 27) where the majority of installations use oil and or natural gas rather than coal. 29 The decision about which (if any) fossil fuel to co-fire may be based on any one of several factors or on a combination of factors including: ° ° The availability of coal, oil, and/or natural gas The cost of each alternative fuel The design of existing combustion facilities with respect to the ability to burn fuels in the gaseous, liquid and/or solid states Environmental restrictions affecting the plant site Other factors But note that the choice of which fossil fuel to co-fire is not limited by the ability to co- fire particular combinations of fuels. Coal can be co-fired with just about any other fossil or non-fossil fuel as long as the overall combustion facility is properly designed and maintained. The.same can be said of oil and of natural gas. There is no inherent physical or chemical limitation which prevents co-firing of particular combinations of fossil and non-fossil fuels. Table 4-7 provides a summary of the co-fired fuel combinations listed in Tables 3-3 (page 11) and Tables 4-1 (page 22) through 4-6 (page 27). 30 TABLE 4-7 Combinations Used In Co-Firing Fossil and Non-Fossil Fuels Fossil Non-Fossil Fossil Non-Fossil Fuel Co-Fired Fuels Fuel Co-Fired Fuels Coal Wood Coal Peat . Woodwastes : Straw . Woodchips : Feed lot wastes z Sawdust % Contaminated seed corn ' Bark ~ Sunflower seed hulls c Hogged fuel : Industrial solid waste z Pelletized wood : Industrial sludge . RDF : Sewage sludge . Tires ' Food process waste Oil Wood Oil Cocoa beans 8 Woodwastes Coffee grounds ei Hogged fuel 2 Agricultural waste , Bark Sunflower seed hulls : Sawdust E Apple pomace fines . Dry wood fines . Peach pits RDF : Peanut hulls Sludge : Industrial wastes : Bagasse : Tires Nat’lGas | Wood Nat’lGas Cocoa beans co Pelletized wood Be Coffee grounds ~ Woodwaste esas Agricultural wastes Mi we Bark eae Apple pomace fines Rep Sawdust ree Peach Pits Pets Dry wood fines rae Tires eke Ground wood Pade Industrial wastes ort RDF Rosie Refuse Bagasse The combinations of fossil and non-fossil fuels shown in Table 4-7 do not represent all of the combinations which have been co-fired. However, the list does illustrate the wide variety of possible combinations of fuels which can be successfully co-fired. 31 The discussion of fuels used in co-firing has been organized and presented based on the distinction between the fossil and the non-fossil fuels. It is convenient basis for organizing the materials and developing reasonable discussion. But note that there is nothing in the definition of co-firing which requires that fossil and non-fossil fuels be fired simultaneously. Co-firing takes place when any two fuels are fired at the same time. The possible combinations include two or more fossil fuels burned simultaneously, two or more non-fossil fuels burned simultaneously, and a mix of fossil and non-fossil fuels as illustrated in Table 4-7. COMBUSTION EQUIPMENT USED IN CO-FIRING Review of the information concerning the boiler and firing systems used in the non- utility sector for co-firing shows that there is a great variety of combustion facility designs in use (See Tables 4-1 through 4-6, pages 22 through 27). This variety reflects, of course, the physical differences in the fuels which are used and the varying requirements for steam generation or other end uses for the recovered energy. It also reflects (in some cases) the kind of equipment which happened to be on hand at the time the plant management decided to undertake co-firing. A very important part of the combustion equipment involved in co-firing is the grate system. Therefore, variables in grate design are discussed below. In addition, the most commonly used types of combustors are described including: o Spreader stokers o Suspension burners o Dutch ovens o Rotary burners o Fuel cells o Bubbling fluidized beds o Ward Furnaces o Circulating fluidized beds 32 Alternative Grate Designs The purpose of grates in a combustor or furnace is to provide a place for large particles of fuel to rest as they burn to completion. Combustion air is feed through the grates, usually through small holes which are drilled or cast into the grates. Grates also provide a place for the non-combustible ash component of the fuel to be collected for removal from the furnace. The grate design in furnaces is subject to many alternate variations including: © Traveling grates © Vibrating/Reciprocating grates o Dumping grates o Water cooled grates o Fixed grates o Pin hole grates Traveling grates: Grates supported on a chain conveyor system and which move at a very slow rate to carry the ash out of the furnace. Dumping grates: Grates which can rotate from a horizontal to a vertical position to drop the collected ash into a hopper(s) located under the grates. The grates are usually rotated on a regular basis and then returned to a horizontal position to support the fuel pile. Dumping grates may be equipped with manually operated or motor operated linkage for dumping. Fixed grates: Fixed grates are grates which do not move. Ash which collects on fixed grates may be removed manually using long handled scrapers or may be removed pneumatically by blowing air (or steam) across the surface of the grates. Vibrating/reciprocating grates: Some grates are equipped with mechanical vibrators whose purpose is to vibrate the collected ash so that it moves to one edge of the grates where it can be collected. An alternative to this design is the reciprocating grate system in which grates move back and forth in a horizontal 33 plane. The motion of the grates moves the ash to a collection point in the furnace. Water cooled grates: The grates are in very close proximity to the combustion process and get very hot. Some grates are designed to have cooling water flow through them in interior passages. Other grates are supported on pipes through which cooling water flows. Fixed grates and dumping grates are most commonly equipped with water cooling because it is relatively easy to accomplish mechanically and it extends the life of the grates by reducing high temperature oxidation/reduction. Pin hole grates: Combustion air fed upwards through the grates should be distributed as uniformly as possible through the entire furnace floor. One means of improving the uniformity of the air distribution is to use grates with small holes either drilled or cast for the air to pass through. The small holes (pin holes) have a moderate pressure drop across them. The pressure differential helps to insure uniform air flow from one section of the furnace floor to the next. The alternatives noted above for grate designs are not mutually exclusive. One furnace may be equipped with traveling, pin hole grates. Another furnace may have fixed, water cooled, pin hole grates. A third option might be just described as dumping grates. Each alternative design has its own benefits and shortcomings in terms of the operation and economics of the system. Traveling grates are the easiest and probably the safest to operate but are also the most costly in terms of capital equipment requirements and maintenance expense. Fixed, pin hole grates (without water cooling) are the least expensive to design and install but present problems in terms of safe operation of the furnace during the ash removal portion of the operating cycle, in terms of air pollution emissions during grate cleaning, and in terms of maintenance costs for replacement grate sections due to burnout. 34 Spreader Stoker Furnaces Probably the most common combustor design in the non-utility sectors is the spreader-stoker furnace. Illustrated in Figure 4-1, this design is effective in burning solid fuels which contain fuel particles of sufficient size that they must rest on a grate to burn (as opposed to burning in suspension). Solid fuel is introduced into the furnace using either a pneumatic or mechanical spreader which "stokes" (feeds) the furnace. If the stoker feeds fuel into the furnace by flinging it mechanically (or pneumatically) over the top of the grate, the stoker is referred to as a spreader stoker. If the stoker augers fuel up into the furnace from underneath the grate, the design is referred to as an underfeed stoker. Fuel Overfire Air Chute tai \ Preheater Collector Multiple | Cyclone Fuel Induced Draft Fon Spreader NS Under Grate Air SS ae —— FIGURE 4-1: Schematic Illustration of a Spreader Stoker Furnace 35 Spreader stokers are popular for co-firing because many of the designed systems have the ability to burn a wide variety of solid fuels simultaneously. Commercially available stokers can distribute diverse fuels such as RDF, coal, wood chips, bark, hogged wood, and/or shredded tires either separately or mixed into the combustion area of the furnace. Finely sized fuel particles will burn in suspension above the grate. Larger solid fuel particles fall to the grate where they burn to completion. The non- combustible ash collects on the grate and can be removed on a regular basis from the furnace. Combustion air for spreader stoker furnaces is usually distributed in part as underfire air (passing through the grate) and in part as overfire air (distributed through headers located above the grate. The ratio of underfire to overfire air is controlled by the proximate analyses of the fuel(s) being burned. For most biomass and cellulose based fuels a 1:1 ratio of underfire to overfire air is appropriate. The interior walls of spreader stoker furnaces are generally lined with heat transfer tubes for steam generation. (See Figure 4-1, page 35.) These are called "water walls" and they are commercially manufactured in several alternative designs. Additional heat transfer surface for steam generation is usually provided by water filled tubes connected at the top to a "steam drum" and at the bottom to a "mud drum". The combined heat transfer surface (water walls, water filled tubes and drums) are referred to as a "water tube boiler". Additional heat transfer surface may also be found in the boiler to superheat the steam (superheater tubes). Spreader stoker boilers have been built to generate as much as 800,000 Ibs per hour of superheated steam at high pressure. Not only can spreader stokers handle a wide variety of solid fuels, the design lends itself to the successful firing of both oil and natural gas as auxiliary fuels. Side mounted or front mounted commercially manufactured burners meter both the combustion air and the fuel (oil and/or natural gas) in proper proportions to maintain good combustion for each auxiliary fuel used in the furnace. 36 Dutch Ovens Dutch ovens are refractory lined combustion chambers which burn fuel in a pile. (See Figure 4-2). Fuel is fed to the pile from a fuel chute which drops the fuel onto the top, center of the pile. Combustion air is supplied around the sides of the pile. Undergrate air may or may not be supplied. TO CINDER COLLECTORS, AIR HEATER, AND STACK OVERFIRE AIR_IN ne DROP OVERFIRE NOSE aIR_IN-~} ARCH / BRIDGE_WALL FUEL PILE AUXILIARY I] FUEL BURNER | ASH PIT FIGURE 4-2: Schematic Illustration of a Dutch Oven Furnace The Dutch oven design is a very old design, in common use before 1900. It is also a very expensive design (compared to alternatives) due to the use of refractory materials 37 (fire brick) in the furnace. Very few Dutch ovens have been constructed during the past 40 years. However, there are many old systems still in operation, particularly in the wood products industry. Dutch ovens function adequately for co-firing of solid fuels. That is, they are quite capable of burning a mix of fuels -- essentially whatever is dropped onto the pile. But the response time and load following capability of the design, coupled with the high capital cost and high maintenance costs for the systems do not make them attractive as new installations. Operation of the system usually must be interrupted for grate cleaning (ash removal). Auxiliary fuels such as oil and natural gas have been co-fired in Dutch ovens. There are also industrial systems in which the auxiliary fuels are fired in wall mounted burners downstream from the Dutch ovens. Steam generation is usually accomplished downstream from the Dutch oven and may be done in either fire tube or water tube boilers. Fire tube boilers are those in which the hot combustion gases pass through the inside of the tubes. Water on the outside of the tubes picks up the heat energy from the hot gases and forms steam. Water tube boilers have water inside the tube and hot gas on the outside. Steam generation is usually limited to less than 50,000 Ibs per hour in Dutch oven systems. Fuel Cells Fuel cells, like the Dutch ovens are refractory lined combustion chambers. They are usually limited to low steam generation rates, typically less than 20,000 Ibs per hour. Unlike the Dutch ovens which are usually rectangular in plan view and only 4 to 6 feet tall, fuel cells tend to be circular in plan view and may have combustion chambers which are 20 to 30 feet tall. (See Figure 4-3) 38 Fuel cells are popular because they provide a good combustion atmosphere for solid fuels with a wide range of moisture levels. They have been used successfully to burn waste wood fuels (bark, sawdust, slabs, etc.) with moisture levels of 60% (wet basis). Combustion air is carefully distributed in the furnace to complete the combustion reaction and limit emissions of particulate matter to the atmosphere. Fuel may be fed to the fuel cell either through a top loading chute or through an underfeed auger. As with the Dutch ovens, steam may be generated using either a fire tube or a water tube boiler located downstream from the fuel cell. Auxiliary fuels (oil and/or natural gas) may be co-fired with commercially manufactured burners attached to the fuel cell. EXHAUST GASES STEAM OUT HORIZONTAL, RETURN TUBE STEAM GENERATOR OPTIONAL FUEL FEED BIN L PROMEATER SECONDARY COMBUSTION CHAMBER 4 REFRACTORY LINED FURNACE SS—= OVERFIRE AIR 2 GRATES i= UNDERFIRE AIR UZZZZZZZZZIL FIGURE 4-3: Schematic Illustration of a Fuel Cell Furnace 39 Ward Furnaces A variation of the fuel cell called the Ward furnace is used in the sugar cane processing industry to burn bagasse, the fibrous residue left from grinding sugar cane. Illustrated in Figure 4-4, Ward furnaces are typically fed by a fuel chute that dumps the bagasse onto a pile in the furnace. Combustion air is distributed around the fuel pile and as overfire air. Steam is generated downstream from the combustion zone, usually with water tube boilers. Steam generation rates may exceed 50,000 Ibs per hour for the larger furnaces. FIGURE 4-4: Schematic Illustration of a Ward Furnace Source: "Steam, Its Generation and Use", 38th Edition, Babcock and Wilcox, 1975. 40 As is the case with Dutch ovens and fuel cells, Ward furnaces are expensive to construct due to the refractory requirements and the supporting structure to hold the refractory in place. The design is a relatively old one which has been successfully used in the sugar industry for many decades. However, it is unlikely to be a popular alternative for general co-firing applications principally due to the high costs for construction and maintenance. Suspension Burners Both oil and gas burn in suspension, that is, the flame is supported in a gas stream. These fuels burn fast enough that they do not require a grate system to hold them while they complete the combustion process. Solid fuels can also burn in suspension if they are of small enough size and have sufficiently low moisture content so that the combustion reaction can take place rapidly. The most common solid fuel that is burned in suspension is pulverized coal which is burned in utility boilers without the aid of any grate system. In the wood products industry, sanderdust is typically burned in suspension since it is usually dry and has a small particle size. Where solid fuels are burned in suspension, it is common practice to provide an auxiliary fossil fuel burner. There are two reasons for doing this: 1) Startup of suspension combustion systems using solid fuels is much easier and safer if the system can be pre-warmed using natural gas or oil. Once the system is up to temperature, solid fuels can be introduced without fear of flameout; : 2) Solid fuels with small sizes are often difficult to feed to burners on a uniform, continuous rate basis. They tend to plug in conveyors, bridge in hoppers and in other ways frustrate attempts to keep the fuel flowing on a continuous metered basis. Without the presence of at least a pilot flame provided by oil or gas, solid fuel suspension burners may suffer from flameouts, pulsing, and potential fireside explosions. 41 To the extent that solid fuel fired suspension burners use an auxiliary fossil fuel for startup mode and as a pilot flame, it can be argued that many such installations are co-fired. An illustration of a small suspension burner is shown in Figure 4-5. Note that the primary combustion chamber is lined with refractory material in order to provide a high temperature zone to speed the combustion reaction. EXHAUST STACK MULTIPLE, CYCLONE COLLECTOR br STEAM OUT FIRE TUBE BOILER { z FUEL METERING SYSTEM fo\ COMBUSTION 2 FORCED peer ion DRAFT AUXILIARY TARGET FUEL WALL Fo BURNER UL — PREPARED FUEL on STORAGE SILO EED AUGER SILO LOADING CONVEYOR Grate — FIGURE 4-5: Schematic Illustration of a Small Suspension Burner System 42 Another design of suspension burner employs a cylindrical design in which the combustion air and solid fuels are introduced into the burner tangentially. Gas flows within the burner may be described as a vortex, swirling in a circular path around the inside of the burner and finally exiting at the far end of the burner. (See Figure 4-6). It is usual for these burners to be lined with refractory and to operate at high temperatures. Fuel particles are permitted a reasonably long residence time for burnout in this design, especially when compared to the short residence time found the burners similar to that illustrated in Figure 4-5 (page 42). Longer residence time allows larger fuel particle sizes to complete the combustion process before leaving the burner. Further, the swirling action tends to break apart larger solid fuel particles as they rub against the interior wall of the burner. FUEL METERING AUGER REFRACTORY LINED VORTEX BURNER NN INSULATED COVERING HIGH TEMPERATURE GASEOUS COMBUSTION PRODUCTS TO STEAM GENERATOR OR Te OTHER END USE MALTIPLE, CYCLONE COLLECTOR / N\ COLLECTED ASH FIGURE 4-6: Schematic Illustration of a Vortex Suspension Burner 43 For purposes of warmup and flame stability, vortex design suspension burners are usually equipped to co-fire fossil fuels through an auxiliary burner system. Heat exchangers used downstream from suspension burners may be either fire tube or water tube. Both are commonly used in a wide variety of applications with steam generation rates from approximately 1,000 to 50,000 Ibs per hour. Rotary Burners Another design of burner that uses a cylindrical combustion section for solid fuels is the rotary burner. In this design, a cylinder with a slightly sloping horizontal axis is mounted on bearings that permit it to rotate about its axis. Solid fuels are introduced at the top end of the burner and are ignited. As the burner rotates the fuels are mechanically stirred and mixed with combustion air. The design has worked particularly well for mixed solids such as municipal solid waste and RDF. The systems are generally co-fired with auxiliary fossil fuels in order to maintain flame stability and for warmup purposes. Heat exchange systems downstream from the burner may be either fire tube or water tube design. A rotary burner design is illustrated in Figure 4-7. 44 se FUEL FEED CHUTE COMBUSTION AIR ENTERS WITH FUEL THROUGH CHUTE FUEL CHUTE MUST BE KEPT UNDER POSITIVE PRESSURE DURING OPERATION ROTATING HIGH TEMPERATURE SEAL HIGH TEMPERATURE COMBUSTION PRODUCTS LEAVE THE ROTATING COMBUSTOR AND ENTER A BOILER — COMBUSTION PRODUCTS ARE PULLED THROUGH THE SYSTEM BY AN INDUCED DRAFT FAN AT THE EXIT OF THE BOILER, CHAIR DRIVE ITH ELECTRIC MOTOR ROTATING AUGER FOR CONTINUOUS ASH REMOVAL STEEL SUPPORT STRUCTURE FIGURE 4-7: Schematic Illustration of a Rotary Burner System An interesting variation of the rotary burner designs is shown in Figure 4-8. In this design the exterior cylinder is fixed, that is, it does not rotate. On the interior of the burner, a rotating helical scraper acts to stir the solid fuel during the combustion process and to move the fuel forward toward the exit end of the burner. The system may be operated either with excess combustion air or in a starved air mode. For those installations in which the air supply to the burner is limited to sub-stoichiometric (starved air) levels, a secondary combustion chamber is provided downstream to complete the combustion reactions. These units are designed to burn a mix of waste fuel and have been used with success on MSW and RDF. They are usually co-fired with auxiliary fossil fuels to assist during the warmup and to maintain flame stability. 45 ae SECONDARY COMBUSTION CHAMBER FUEL FEED AND PRIMARY COMBUSTION AIR INLET i A\_f\_f\_, ye Ne COMBUSTION CHAMBER VITH HELICAL AUGER AUGER DRIVE MOTOR AND GEAR REDUCER FIGURE 4-8: Schematic Illustration of a Rotary Burner With Fixed Exterior Shell and Internal Helical Scraper Bubbling Fluidized Beds Fluidized bed combustion technology has been quite popular for co-firing of solid fuels. Bubbling fluidized bed systems have been in commercial operation in the U.S. for more than a decade burning coal, a wide range of wood waste fuels, MSW, and RDF. They have also been used for combustion of industrial wastes (both liquid and solid) and for disposal of municipal sewage sludge. One of the reasons for the popularity of these systems is their inherent ability to successfully burn fuels with widely divergent physical and chemical characteristics. 46 Bubbling fluidized beds are usually designed as refractory lined chambers filled to some nominal depth (2 to 4 feet) with bed media. (See Figure 4-9). The media may be sand, small gravel, limestone, dolomite or some other product which can withstand combustion temperatures and a great deal of turbulent mixing and still maintain the initial size and strength characteristics. FUEL INLET HIGH TEMP. EXHAUST GAS DUCT TD END EXHAUST GAS DUCT a \ OPTIONAL MULTIPLE CYCLONE COLLECTOR Vj—sereacrony LINED COMBUSTION CHAMBER Z NOMINAL FLUIDIZED (A (A) es DEPTH = 3 FT. FORCED DRAFT FAN iY) BUBBLE CAP MEDIA AND DISTRIBUTOR SOLIDS REMOVAL f Y LINE =— ILLIA COMBUSTION AIR FIGURE 4-9: Schematic Illustration of a Bubbling Fluidized Bed Design The bed media is fluidized by being suspended in an rising gas stream (usually air) which is distributed uniformly throughout the bottom of the bed. Superficial gas velocities for bubbling fluidized beds typically range from 6 to 14 feet per second. 47 In the operating cycle, the bed media is usually fluidized by an air stream which has been preheated using an auxiliary fossil fuel burner. When the bed temperature reaches a level sufficient to ignite incoming solid fuel and to maintain combustion stability, the auxiliary fossil fuels are generally shut off. Solid fuels are then introduced to the bed either from pipes inserted into the bed or from fuel chutes located above the top or to the sides of the bed. The high temperature bubbling bed media mixes with the fuel, ignites it, and mechanically stirs it so that combustion can take place rapidly and completely. Non-combustible materials sift downward through the bed media to the bottom of the system where they can be removed either on a batch or on a continuous basis. Steam generators placed downstream from the fluidized bed combustor may be either fire tube or water tube designs. Most commercial systems use water tube designs to accommodate the steam generation rates and pressures required. Some bubbling fluid bed systems have heat exchange tubes inserted into the bed media so that heat can be removed directly from the bed during operation. This is done as much for temperature control of the combustion process as for economy in the design of the heat transfer system. Temperature control is critical to the operation of fluidized beds. If the bed temperature exceeds the fusion temperature for the bed media, the media will melt and stop the action of the bed. When this occurs, the bed must be allowed to cool, the fused bed media must be removed with pneumatic "jack" hammers, the damaged refractory must be replaced and then the system can be restarted. This replacement process is requires several weeks of down time for the combustion system and is, of course, very costly. For those fluidized beds in which coal is burned, limestone or dolomite are used as bed media. These materials have the ability to absorb sulfur dioxide, an air pollutant generated in the combustion of sulfur bearing coal. The absorption efficiency of the bed media is very temperature dependent, which requires that the bed be operated 48 within a relatively narrow temperature range (1625 - 1675 deg. F.) Heat transfer surface placed in the bed (for steam generation) serves as a means of limiting and controlling bed temperatures within the desired range. Circulating Fluidized Beds Circulating fluidized beds are similar to bubbling fluidized beds except that the gas velocities within the bed are increased to a range from approximately 16 to 30 feet per second. These higher gas velocities are sufficient to physically transport the bed media and the fuel load within the bed. During operation, the bed media and the fuel are carried from the media return point through the primary combustion zone, into the heat exchange zones, and finally into the cyclone collectors where the solids are dis- entrained from the gas stream and are returned to the primary combustion zone. (See Figure 4-10). The circulating fluidized bed design solves several of the problems inherent in the bubbling fluidized bed designs, particularly problems related to temperature control. To illustrate, if the temperature in the bed rises above a preset level, increasing the velocity of the carrier gas stream will increase the heat transfer rates to the heat exchange surface and thereby reduce the bed temperature. Circulating fluidized beds are capable of successfully firing a wide variety of both liquid and solid fuels either individually or on a co-firing basis. As in the case of the bubbling fluidized beds. the combustion zone provides excellent turbulence for mixing of the fuel and the combustion air, good heat transfer rates to initiate the combustion process for the fuel, uniform temperature profiles at elevated levels and adequate time for the combustion reaction to be completed. 49 HIGH TEMPERATURE EXHAUST GASES CYCLONE BURNING SOLIDS AND Z SEPARATOR BED MEDIA CIRCULATE UPWARD THROUGH THE COMBUSTION ZONE AND ARE CARRIED TO THE PARTICLE SEPARATOR. REFRACTORY LINED, CYLINDRICAL COMBUSTION CHAMBER SOLIDS RETURN LINE FORCED DRAFT FAN MEDIA AND SOLIDS REMOVAL LINE FIGURE 4-10: Schematic Illustration of a Circulating Fluidized Bed In the commercially available designs of circulating fluidized beds, steam is generated in water tubes rather than in fire tubes. Ash and other non-combustible materials can be removed from the bed either on a continuous basis or on an as-needed basis. 50 SUMMARY DISCUSSION From the foregoing discussion, it should be apparent that co-firing of fuels is widely practiced in non-utility sectors. Combinations of fuels which are co-fired include fossil/fossil fuels, fossil/non-fossil fuels, and non-fossil/non-fossil fuels. The non-fossil fuels which are co-fired cover very wide ranges of physical and chemical characteristics®. Similarly the size of facilities used for co-firing covers a wide range: from less than 1,000 Ibs of steam per hour to almost 1,000,000 Ibs per hour. The combustion equipment used to co-fire fuels includes diverse designs from spreader stokers, to fuel cells, to circulating fluidized beds, and others. From all of this, one can surmise that co-firing works well in many circumstances, with many fuel combinations, in many sectors of the economy. There are, of course, limitations to co-firing of fuels. In Chapter 6 equipment design and operational problems associated with co-firing are discussed in detail to familiarize the reader with practical applications of co-firing. 3 See Chapter 5 for a detailed discussion of the physical and chemical characteristics of fuels which are typically used in co-firing applications. 51 CHAPTER 5: PHYSICAL AND CHEMICAL CHARACTERISTICS OF FUELS TYPICALLY USED IN CO-FIRING APPLICATIONS Experience in co-firing various combinations of fuels in utility and non-utility settings has shown that both design of the equipment and operation of the equipment are strongly influenced by the physical and chemical characteristics of fuels which are used. It may be helpful to review some important fuel related parameters for those fuels typically used in co-firing applications. The parameters of concern include: Ultimate analyses Proximate analyses Heating value Moisture level Fuel density Energy density Fuel combustion rate 0. 8 OO: 0:.0: 0 Ultimate Analyses Ultimate analyses are used to determine the chemical composition of fuels. The components of particular interest are the levels of carbon, oxygen, hydrogen, nitrogen, sulfur and non-combustible ash. These components determine the amount i combustion air which is required to burn the fuel. Also, they are important in determining the composition of the exhaust gas from the combustion process. For any particular fuel some variations in the ultimate analyses are expected from sample to sample. However, the variations are generally confined to a small range for large, composite samples. For comparative purposes typical ultimate fuel analyses are shown in Table 5-1 for fuels which are commonly used in co-firing applications. 53 vs Proximate Analyses of Fuels Which Are Commonly Used in Co-Firing TABLE 5-1 Fuel Characteristics Determined from Ultimate Analyses and Ory Typical Municipal Refuse No. 2 No. 6 Wood Ory Hogged Solid Derived Penn. Utah Wyo. Fuel Fuel Nat'l Fuel Parameters Pellets Wood Fuel Waste Fuels Coal Coal Coal Oil oil Gas Moisture (% wet basis) 10 10 40 30 24 a ase 25.0 0 0 0 Carbon content 48.06 48.06 32.04 22.8 33.0 79.17 70.68 54.11 87.2 85.6 13-55 wet basis (%) Oxygen content 34.11 34.11 22.74 18.0 25.0 2.12 10.45 12.12 0 2.00 0.71 wet basis (%) Ultimate Hydrogen content 5.04 5.04 3.36 3.0 aco 4.25 4.96 3.63 12.50 9.70 23.10 Analyses wet basis (%) Nitrogen content 0.09 0.09 0.06 0.4 0.5 1.33 1.50 1.14 0.02 0 2.64 wet basis (%) Sulfur content 0.09 0.09 0.06 0.1 0.2 1.50 0.80 0.30 0.30 2.30 0 wet basis (%) Ash content 2.61 2.61 1.74 2 12.0 10.32 6.40 3.70 0 0.12 0 wet basis (%) Volatile matter 82.54 82.54 82.54 64.0°" 71.0 17.83 40.30 40.67 100.00 99.88 100.00 dry basis (%) Proximate Fixed carbon 14.56 14.56 14.56 13.2 71.83 52.95 54.40 0 0 0 Analyses dry basis (%) Ash content 2.90 2.90 2.90 36.0 15.8 10.44 6.75 4.93 0 0.12 0 dry basis (%) * * Combined volatile matter and fixed carbon Sources: 1) Design and Operation of Industrial Boilers Fired With Wood and Bark Residue Fuels, Pub. by the Solar Energy Research Institute, SERI/TR 09380-1, August 1982 Steam, 2) , Its Generation and Use, 38th Edition, Pub. by Babcock and Wilcox, 1975 3) "Guidelines for Co-Firing Refuse Derived Fuel in Electric Utility Boilers," EPRI CS-5754, Vol. 2, Copyright 1988 Reprinted with permission. Electric Power Research Institute. Note that the carbon content of the fossil fuels (natural gas, oil, and coal) is higher than the carbon content of the wood derived fuels, MSW and RDF. Conversely, the oxygen content of the fossil fuels is lower than that of the wood based fuels, MSW and RDF. These variations in carbon and oxygen content of fuels influence the amount of combustion air that is required for stoichiometric combustion. (Further discussion of combustion air is found in Chapter 6). Proximate Analyses Proximate analyses provide information on percentages of volatile material, fixed carbon, and ash in a fuel sample. Volatile fuel components are those which will evaporate when subjected to elevated temperatures (1100 deg. F [600 deg. C] or above), and which will burn very rapidly when they are in the gaseous state. Fixed carbon components will not evaporate and must burn in the solid state as carbon char. Carbon char burns relatively slowly and must either be burned while supported on a grate or else must be very finely ground in order to burn in suspension (i.e., pulverized coal). Information from proximate analyses is used in the design considerations for sizing combustion chambers, and to determine the optimum distribution of combustion air in burner systems. The data shown in Table 5-1 (page 54) demonstrates significant differences in the volatile portions of wood based and refuse based fuels compared to coal. It is typical to find that more than 75% of the wood based fuels evaporate and burn in the gaseous state during the combustion process. For refuse based fuels (MSW and RDF) the percentage of fuel which burns in the gaseous state is somewhat lower (60% to 75%). The percentage of coal that burns in the gaseous state (the volatile portion) may range from 15% to 40%. Liquid fossil fuels evaporate completely when they burn. Natural gas is always in a gaseous state when it is used as a fuel. The significance of these variations will be discussed in depth later in the chapter. However, the reader should be aware at this point that there are variations in the volatile and fixed carbon 55 content of fuels and that these variations may influence the design and operation of combustion facilities. The ash content of fuel samples is determined also from proximate analyses. As shown on the bottom of Table 5-1 (page 54), the ash content of wood based fuels is approximately 3%. It may range from 1% to 8%. MSW has a very high ash content (36% with an expected range from 25% to 45%). However, when MSW is processed to remove non-combustible components, the resultant RDF has a far lower ash level (16% with an expected range from 10% to 25%). Coal ash levels vary widely depending on the kind of coal that is used. Typical coal ash levels range from 3% to 12% except for some of the lignite coals which have elevated ash content levels. The liquid fossil fuels have very low ash levels compared to the solid fuel alternatives. No. 2 fuel oil (diesel) and similar light oils have essentially no ash component. However, the heavier liquid fuels such as No. 6 fuel oil do have a small percentage of non-combustible material. Ash levels are important in the design and operation of combustion systems because any ash that is carried into the combustion process must either be removed as bottom ash or be collected in air pollution control devices downstream from the combustor. Further, the ash components of fuels may tend to foul the heat exchange surfaces of the system and may also plug gas passages in the system. Ash fuses at high temperatures to form slag which can damage boiler interiors and cause extensive down time for removal. Heating Value The heating value of fuel is a measure of the amount of energy per pound of dry fuel. It is typically measured in a device called a "bomb calorimeter". There are two measures of heating value: higher heating value; and lower heating value. The difference between higher and lower heating values can be explained as follows: 56 When the hydrogen content of fuel undergoes the combustion process, it forms water according to the reaction: H, + 1/20, = H,O The water in the exhaust gases is in the form of vapor. When the vapor condenses, it releases heat energy (approximately 1000 BTU/Ib of water vapor condensed). In the bomb calorimeter the water vapor condenses so that the heat of condensation is included in the measured heating value of the fuel. But in the "real world" of boilers, the flue gas containing the water vapor leaves the boiler at a temperature which is above the condensation temperature. Therefore, the heat of condensation is not available in boilers. Higher heating values include the heat of condensation of the water formed from the combustion of fuel-bound hydrogen. Lower heating values do not include the heat of condensation. Table 5-2 contains higher heating values from wood based fuels, MSW, RDF, 3 types of coal, 2 fuel oils and natural gas. Note that on a weight basis, natural gas and fuel oils have the largest energy content, in the range of 18,000 to 20,000 BTU’s per Ib. Coal has the next highest energy content, typically ranging from 12,000 to 14,000 BTU’s per Ib. Wood based fuels generally contain 8,500 to 9,500 BTU’s per Ib followed by MSW and RDF. The heating values for MSW and RDF vary over wide ranges, particularly for MSW. The values shown in Table 5-2 are typical average energy levels. Moisture Level There are two ways to describe the moisture content of fuel: the wet or "as-is" basis; and the dry basis. For wet basis determinations, the weight of moisture in a fuel sample is divided by the total weight of the wet fuel sample. The answer is expressed as a percentage. 57 Wet basis moisture (%) = weight of water in fuel x 100 weight of wet fuel For dry basis moisture determination, the weight of moisture in the fuel sample is divided by the dry weight of the fuel sample. Again the answer is expressed as a percentage. Dry basis moisture (%) = weight of water in fuel x 100 weight of dry fuel Moisture content is significant for two reasons. First, it may vary over a wide range of values for some fuels including the wood based fuels, MSW and some RDF. Second, the heating value of fuels is strongly influenced by moisture levels. Moisture in fuel has a negative heating value, that is, heat is needed to evaporate the moisture in the fuel and that heat requirement reduces the heat energy available for steam production. Thus, as moisture levels increase, more fuel must be burned in order to maintain steam production rates. This can be seen by comparing the data in the 1st and 3rd rows of Table 5-2 (page 59). The 1st row contains higher heating values for fuels which are commonly co-fired. The 3rd row contains the as-fired heating values for the fuels, taking the moisture levels into account. Note in particular the reduction in heating values for typical hogged fuel, for MSW and for Wyoming coal due to the moisture content of these fuels. Because of the influence of moisture on the heating values of fuels, moisture levels are an important parameter in the design and operation of combustion systems. This is illustrated in Figure 5-1 which shows plots of fuel use rates and boiler thermal efficiencies as a function of fuel moisture level for typical wood fuels. Note that as fuel moisture levels increase, fuel use rates increase and thermal efficiency goes down. 58 6S TABLE 5-2 Fuel Parameters of Higher Heating Value, Moisture Content, As-Fired Heating Value Bulk Density, As-Fired Energy Density, Fuel Feed Rates and Ash Flow Rates for Fuels Which Are Commonly Used in Co-Firing Applications Ory Typical Municipal Refuse No. 2 No. 6 Wood Dry Hogged Solid Derived Penn. Utah Wyo. Fuel Fuel Nat'l Fuel Parameters Pellets Wood Fuel Waste Fuels Coal Coal Coal oil oil Gas Higher heating value 9,030 9,030 9,030 6,400 7,700 13,982 13,291 12,460 19,430 18,300 19,800 (BTU/dry lb) Moisture content 10 10 40 30 24 1.3 5.2 25.0 0 0 0 (% wet basis) As-fired heating value 8,18?) 8427 5,418 4,500 5,800 13,800 12,600 9,345 19,430 18,300 19,800 (BTU/wet lb) Fuel bulk density 35.00 16.00 22.00 12.00 4.00 50.00 47.00 45.00 53.90 58.70 0.0503 (Lbs/cu. ft.) As-fired energy density 284,400 130,000 119,200 54,000 23,200 690,000 592,200 420,500 1,047,000 1,074,000 1,000 (BTU/cu. ft.) Fuel feed rates 5.5 fe7 8.4 18.5 43.1 1.4 Ald 2.4 1.0 0.9 1,000 (Cu. Ft./MMBTU) Ash input rate 3.2 3s2 5.2 56.3 20.5 75 5.4 4.0 0 0.07 0 (Lbs /MMBTU) Sources: 1) Design and Operation of Industrial Boilers Fired With Wood and Bark Residue Fuels, Pub. by the Solar Energy Research Institute, SERI/TR 09380-1, August 1982 2) Steam, Its Generation and Use, 38th Edition, Pub. by Babcock and Wilcox, 1975 3) “Guidelines for Co-Firing Refuse Derived Fuet in Electric Utility Boilers," EPRI CS-5754, Vol. 2, Copyright 1988 Electric Power Research Institute. Reprinted with permission. 6.0 — 80 5.0 EFFICIENCY 70 4.0 60 30 3.0 40 2.0 30 FUEL USE MULTIPLIER 20 LO FUEL USE =] 10 i he 2 t 0 10 20 30 40 50 60 FUEL MOISTURE CONTENT (% - WET BASIS) CALCULATED BOILER THERMAL EFFICIENCY (¢%) FIGURE 5-1: Variations In Fuel Use Rates and Boiler Thermal Efficiencies as a Function of Fuel Moisture Content Fuel Density Fuel bulk density has a major impact on the volume of fuel that must be stored at a facility and on the volumetric feed rates required for a boiler or burner system. Values of fuel bulk density are found in Table 5-2 (page 59) and are helpful for comparison purposes. 60 For the wood based fuels, bulk density values may cover a wide range. Planer shavings, for example, have a typical bulk density of 8 Ibs per cu. ft. Typical hogged fuel samples indicate bulk density of approximately 22 Ibs per cu. ft. At the extreme end of the scale, densified wood pellets have bulk density of approximately 35 Ibs per cu. ft. Bulk density levels for MSW and for RDF also have wide ranges and can be expected to deviate from mean values on a random basis. Note from Table 5-2 (page 59) that the bulk density for RDF is 4.0 Ibs per cu. ft. This value assumes that the process for converting MSW to RDF includes an air separator and produces "fluff RDF which has limited heavy solids. The reader should be aware that the bulk density of RDF is dependent upon the processing steps used to make the RDF from MSW. Bulk densities for fossil fuels are not expected to vary over wide ranges, particularly for liquid and for gaseous fuels. Coal density typically extends from 45 to 50 Ibs per cu. ft. Note that the density of coal is significantly larger than the densities of wood based fuels and the refuse based fuels. Energy Density If the as-fired heating values are multiplied by the fuel bulk density values for each fuel, the product may be thought of as the energy density of the fuel, that is, how much energy is contained in a given volume of fuel. These products are shown in Table 5-2 (page 59) in the 5th row of data and are expressed in units of BTU’s per cu. ft. of fuel. The inverse of energy density provides a measure of fuel feed rates in units of cu. ft. of fuel which must be burned to provide an input energy of one million BTU’s (cu.ft./MMBTU). These values are also shown in Table 5-2 in the 6th row of data. The data concerning fuel feed rates are particularly important with respect to co-firing of fuels. For example, assume that a boiler is designed to burn Wyoming coal and that it is desired to co-fire hogged fuel at a rate which will provide 25% of the energy 61 input to the boiler. To accomplish this it is necessary to proportion the fuel so that 750,000 BTU’s come from coal and 250,000 BTU’s come from hogged fuel for every million BTU’s of heat input. Using the data in Table 5-2, it can be shown that the volume of fuel required per million BTU’s of heat input should be: Wyoming coal 1.8 cu. ft. Hogged fuel 2.1 cu. ft. Even though the hogged fuel is to provide only 25% of the energy input the volumetric flow rate of the hogged fuel is more than 50% of the total volumetric flow rate. Obviously the energy density of fuels significantly influences their feed rates. To further illustrate this point, consider a boiler which is designed to burn Utah coal and which is being considered for a retrofit to co-fire RDF such that 10% of the heat energy is to come from RDF. Thus, for every million BTU’s of heat input, 900,000 would come from coal and 100,000 would come from RDF. Using the data in Table 5- 2, it can be shown that the volume of fuel required per million BTU’s would be: Utah coal 1.53 cu. ft. RDF (fluff) 4.31 cu. ft. In this example, the volumetric feed rate for the RDF must be 74% of the totat feed rate in order to provide only 10% of the total heat input. The example further illustrates the importance of fuel energy density on fuel feed rates and, therefore, on the design and operation of co-fired combustion systems. There is one more bit of useful information to be found in Table 5-2 (page 59) and that concerns the rate of ash input to combustion systems for fuels which are typically used in co-firing applications. The last row at the bottom of the table contains these values expressed in units of lbs of ash input per million BTU’s of heat input. 62 Consider a boiler designed to burn wood fuels and assume that a plan is underway to convert the boilers to co-firing with 20% of the heat input from RDF. Thus wood fuels would provide 800,000 BTU’s and RDF would provide 200,000 BTU’s per million BTU’s of heat input. From the data in Table 5-2, it can be shown that the ash input rates per million BTU’s are: Hogged fuel 2.56 Ibs RDF 2.05 Ibs Total ash 4.61 lbs Since the hogged fuel used alone input only 3.2 lbs of ash per million BTU’s, one result of providing 20% energy input from RDF is to increase the ash input rate to the boiler by 1.4 lbs/MMBTU which is a 44% increase. This increased rate of ash flow into the combustion system may have some detrimental effects on its operation. The topic will be discussed in greater depth in Chapter 6. Fuel Combustion Rate The rate at which solid fuels burn is not well understood. It is known that large pieces of fuel take longer to burn than small pieces. And it is known that wet fuel burns more slowly than dry fuel. But there are no useful prediction equations that can accurately estimate how long it will take a specific kind of fuel to burn, given its species, size, moisture level, etc. The concern of fuel combustion rates (with respect to co-firing of fuels) is this: If the rate of combustion of fuel particles is sufficiently high so that particles can complete the combustion process in a matter of one to two seconds, then the fuel can be burned in suspension. If, on the other hand, the rate of combustion of the fuel particles is slow enough so that the combustion process cannot be completed within a very few seconds from the time of entering the combustion zone, then it is necessary to have a grate system on which to burn the fuel. The grates provide physical support 63 for the fuel while it proceeds through the various steps of the combustion process. (See Chapter 4 for a discussion of alternative grate designs). There are not many solid fuels that are small enough and dry enough to burn completely in one or two seconds. Wood sanderdust, rice hulls and pulverized coal qualify but there aren’t many others. Most solid fuels burn slowly enough that some sort of grate system is necessary. The rate of burning has been a problem at several electric utility sites where RDF was injected into furnaces designed to burn pulverized coal in suspension. The pulverized coal burned sufficiently fast to complete the combustion reaction. However, the slower burning fractions of RDF fell to the bottom of the furnace where they were unable to burn rapidly due to lack of proper support and poorly distributed combustion air. The solution to the problem was to install an appropriate grate system. Whenever liquid fuels or gaseous fuels are burned there is no reason for concern about the rate of the combustion process. These fuels all burn sufficiently fast in suspension that no grates are required. FUEL STANDARDS Fuel standards specifying such variables as chemical composition, ash content, heating value, viscosity and other parameters have existed for many decades for the fossil fuels. Most of the standards have been established by the American Society for Testing and Materials (ASTM) and can be found in the ASTM publications. In the case of the wood based fuels (i.e., pelletized wood, hogged fuel, sawdust, sanderdust, etc.) there are some standards which have been developed principally for commerce in the wood products and pulp/paper industry. Typically these are standards regarding species, particle size, moisture levels and non-combustible material content (i.e., ash, tramp metal, dirt, etc.). 64 Standards for the refuse derived fuels (RDF) have been developed only recently in response to the increased use of refuse as an energy resource. The ASTM classifications for RDF are listed in Table 5-3. The classifications noted in Table 5-3 are quite general and do not include much in the way of detailed specifications for RDF. However, the Electric Power Research Institute (EPRI) has developed four additional recommended specifications for RDF. The specifications are based on particle size and ash content and are labeled RDF-A, RDF-B, RDF-C and RDF-D: Ash Content Particle Size Low (10%) Medium (12%) Fine (<1 inch) RDF-A RDF-B Coarse (<2.5 inches) RDF-C RDF-D The details of these RDF specifications are shown in Table 5-4. EPRI recommends RDF-D for general use. RDF-A, RDF-B and RDF-C are recommended for problem retrofit situations depending upon the site specific problems encountered. 65 Class RDF-1 RDF-2 RDF-3 RDF-4 RDF-5 RDF-6 RDF-7 Source: Note A: TABLE 5-3 ASTM Classifications of Refuse Derived Fuels Form Raw Coarse Fluff Powder Densified Liquid Gas Thermal Description Municipal solid waste (MSW) with minimal processing to remove oversize bulky waste. MSW processed to coarse particle size with or without ferrous metal separation such that 95% by weight passes through a 6 inch screen. Shredded fuel derived from MSW processed for the removal of metal, glass, and other entrained inorganics; particle size of this material is such that 95% by weight passes through a 2 inch square mesh screen. (See note A). Combustible MSW fraction processed into powdered form such that 95% by weight passes through a 10 mesh screen (0.035 inches square). Combustible MSW fraction densified (compressed) into pellets, slugs, cubettes, briquettes, or similar forms. Combustible MSW fraction processed into a liquid fuel. Combustible MSW fraction processed into a gaseous fuel. tems for Conversion of Municipal Solid Waste: Over- view. Chicago, Illinois Argonne National Laboratory, May 1983. CN5V-TM-120, Volume 1. Measured RDF particle size distributions indicate that 95% by weight of the RDF is smaller than 2 inches and that over 99% by weight of the RDF is smaller than 2.5 inches. 66 TABLE 5-4 Recommended Specifications for Refuse Derived Fuels RDF Properties For RDF Properties Category Problem Retrofit Boilers For General Use Type A Type B Type C Type D Ash Low Low Medium Medium Size Fine Coarse Fine Coarse As-Received Analysis Maximum particle size, inches 1 2.5 1 2.5 Bulk density, lbs/cu. ft. = $ 4 4 Organics, % by weight 4 4 5 5 Heating value, BTU/|b 6,500 6,500 5,900 5,900 Lbs of ash/MMBTU 15.38 15.38 20.34 20.34 Proximate Analysis, % by weight Moisture 20 20 24 24 Ash 10 10 12 12 Volatile matter 60 60 54 54 Fixed carbon 10 10 10 10 100 100 100 100 Ultimate Analysis, % by weight Moisture 20 20 24 24 Ash 10 10 12 12 Carbon 36 36 33 33 Hydrogen 5 5 5 5 Nitrogen 0.6 0.6 0.5 0.5 Oxygen 27.8 27.8 25 235 Sulfur 0.3 0.3 0.2 0.2 Chlorine 0.3 0.3 0.3 0.3 100.0 100.0 100.0 100.0 Dry Basis Analysis Heating value, BTU/Ib 8,100 8,100 7,700 7,700 Proximate Analysis, % by weight Ash Ws 12 16 16 Volatile matter 75 75 71 71 Fixed carbon 13 13 13 Ultimate Analysis, % by weight Ash 12 12 16 16 Carbon 46 46 44 44 Hydrogen 6 6 6 6 Nitrogen 0.7 0.7 0.7 0.7 Oxygen 34.5 34.5 32.6 32.6 Sulfur 0.4 0.4 0.3 0.3 Chlorine 0.4 0.4 0.4 0.4 100.0 100.0 100.0 100.0 Reference: "Guidelines for Co-Firing Refuse Derived Fuel in Electric Utility Boilers," EPRI CS- 5754, Vol. 2, Copyright 1988 Electric Power Research Institute. Reprinted with permission. 67 SUMMARY COMMENTS The physical and chemical characteristics of fuels have a major impact on the design and operation of equipment used for combustion. When fuels are co-fired, these characteristics must be taken into account so that the co-firing systems can be properly designed for successful, long term operation. Most of the characteristics of fuels may be determined through analyses of moisture levels, heating values, size distribution, bulk densities and through the ultimate and proximate analyses. However, data gathered from such analyses will not provide information on how fast the fuels burn, and that information is important to the design of solid fuel burning systems. Fuel specifications for the fossil fuels have been developed and published by ASTM. Industry specifications have also been developed for the wood based fuels. Recently ASTM and EPRI have developed classifications and recommended specifications for refuse derived fuels. 68 CHAPTER 6: EQUIPMENT DESIGN AND OPERATIONAL EXPERIENCE CO-FIRING FUELS In Chapters 3 and 4 the discussion centered around the experience of the electric utilities and the non-utility sectors in co-firing fuels. The emphasis was on the types of fuels fired with some discussion devoted to a general description of the combustion equipment used. Attention will now focus on the more specific problems encountered in co-firing and the experiences gained in equipment and operational practices to correct the problems. The discussion is organized into the following areas: Fuel receiving, storage and reclaim Fuel preparation Fuel feed systems Grates Combustion air Gaseous products of combustion Ash considerations OO. Ge ©: O © Problems associated with emission control equipment due to co-firing are discussed in Chapter 8. FUEL RECEIVING, STORAGE, AND RECLAIM In Chapter 5, Table 5-2 (page 59) there are comparisons of the energy densities for fossil fuels, wood based fuels and refuse based fuels. The table also includes data for the reciprocal of energy density referred to as fuel feed rates (in units of cu. ft. of fuel per million BTU’s of heat input). For facilities which co-fire fuels, these tabled values may be helpful for purposes of sizing equipment for fuel receiving, storage and reclaim. 69 As an example, assume that a plant produces 100,000 Ibs of steam an hour (600 PSIA, 700 deg. F) with a boiler burning bituminous coal at 88% thermal efficiency. At full load the boiler will consume approximately 7,200 Ibs of coal per hour. Operating with an 80% load factor, a 30 day supply of coal will require a storage facility with a capacity of 3,000 cubic yards. For the sake of illustration, assume that the same plant decides to co-fire coal and hogged fuel such that 65% of the energy input comes from coal and 35% from hogged fuel. Because of its higher moisture content and the requirement for higher levels of excess air to complete the combustion process, hogged fuel will burn at 68% efficiency. The feed rate of the hogged fuel will be 8,400 Ibs per hr. (380 cu. ft./hr.) and a 30 day supply of hogged fuel will occupy 8,120 cu. yds. The coal feed rate will be reduced to 4,550 Ibs per hr. (91 cu. ft./hr.) and a 30 day supply of coal will occupy 1,940 cu. yds. The effect on the plant fuel storage requirements in changing from burning only coal to co-firing 65% coal and 35% hogged fuel is to increase the required storage volume from 3,000 cu. yds. to 10,060 cu. yds., over 200% increase in storage volume requirements. Of course, there is no specific requirement that plant sites store a 30 day supply of fuel. But the example does illustrate some of the fuel storage volume considerations that go along with co-firing. The specific equipment design for fuel receiving, storage, and reclaim in co-firing applications obviously should take into consideration the volumetric storage and flow rate requirements for each fuel used. There may be additional design considerations as noted below for fossil fuels, wood fuels, and MSW/RDF. The Fossil Fuels For the liquid fossil fuels there exist well documented standards which can be used to design and specify receiving docks, storage tanks, pipes, pumps, heaters, vents, 70 safety equipment, environmental protection required, etc. The same can be said with respect to facilities for handling coal. There is a large body of information available regarding the design and specification of coal receiving, storage and reclaim equipment so that installations can be built and operated in a safe and environmentally acceptable fashion. At those installations where natural gas is co-fired, facilities for receiving, storage and reclaim of the fuel are generally not required except where liquified gas is used. At such locations, the design and specification of proper facilities may be based on a significant body of well tested standards, regulations, and specifications. Wood Fuels Where wood based fuels are fired, the technology for receiving, storage and reclaim is well developed. However, there are specific problems associated with wood fuels of which the reader may not be aware and which are worth noting: oO Spontaneous combustion oO Dust oO Bridging Spontaneous combustion: Hogged fuel (coarsely ground wood and bark) has a well deserved reputation for spontaneous combustion. This seems to occur in fuel piles in which the moisture level is above 25% (wet basis) and where tramp metal is present to act as a catalyst. The tramp metal may be as small as a nail. Compaction of the fuel pile appears to influence spontaneous combustion. Experience has shown that the more tightly the fuel pile is compacted, the lower the chance for fires to start because of the reduced flow of oxygen to "hot spots" in the pile. The "hot spots" are thought to be started by heat from bacterial growth, escalated by a catalytic oxidation reaction. Since hogged fuel is subject to spontaneous combustion, it is important to design hogged fuel storage facilities with fire fighting in mind. Provisions should be made to ue have access to all sides (the complete perimeter) of the fuel pile by front end loaders and other equipment that can be used to separate burning fuel from the remainder of the pile and to extinguish fires as they occur. Compacting the fuel pile does help to limit fuel pile fires. Compacting can be done by running over the top of the pile with heavy equipment on a regular basis. One mill in Oregon found a unique method of controlling fuel pile fires. The pile is compacted regularly and the fires occur near the edge of the pile. When a fire is located, a back hoe is used to remove the fuel near the fire. Several pounds of dry ice are placed in the hole and the fuel is replaced and compacted with the back hoe. As the dry ice sublimates (evaporates), it floods the burning fuel with carbon dioxide gas. The carbon dioxide prevents oxygen from reaching the fire and thus extinguished the fire. The procedure is fast, fairly effective, and does not leave a water mess behind (from trying to fight the fire with water). Dust: Most wood based fuels do not present a dust problem. However, wood fuels which have been dried may present a very significant dust problem which can result in explosive conditions in and around the fuel handling system. Pelletized wood and bark fuels are notably difficult from a dust standpoint as is hogged fuel which has been dried. Any process which moves, stirs, tumbles or transports dried wood fuels results in small particles of dry wood fines becoming airborne. The concentrations of airborne dust are in many cases considered to be just a nuisance. However, in several industrial facilities, the airborne dust has resulted in explosions and fires. Control of airborne wood fines must be designed into the system for fuel receiving, storage, reclaim and feeding. Typically the dust is collected with pneumatic pickup and transport systems and is filtered from the air using a baghouse or other filtration device. Collected fines can be injected into furnaces for heat recovery and disposal. Doing all this is not technically difficult, but it is an area which is sometimes overlooked 72 at facilities where dry wood fuels are to be burned. The resulting high levels of airborne wood dust have been a major concern at such facilities and in at least two instances have resulted in curtailment of the use of dry wood fuels. Bridging: Wood residue fuels have a tendency to “bridge” in fuel hoppers, in fuel chutes, in fuel storage bins, and in other places where they have any opportunity to hang-up and disrupt the flow. Hogged fuel is particularly good at bridging and has caused problems at most places where it is used at one time or another. This is especially true at installations which were designed to feed lump coal as a fuel. Systems which are designed and used successfully for lump coal do not necessarily work well for hogged fuel, due to the differences in the fuel handling characteristics of the two fuels. Most companies that burn hogged fuel and many of the architectural and engineering firms that design fuel systems have learned to design hoppers and conveyors and fuel silos with negatively sloping sides and ends. They have also learned to construct systems that have limited places where the fuel can hang-up or bridge. The design variations are not always straight forward or easy and in many cases result from trial and error approaches. This is particularly true if the hogged fuel contains long, stringy pieces such as cedar bark which can wrap around conveyor shafts and other objects. The message here is to be aware of the potential for bridging and plugging by hogged fuel and to take steps to avoid the problems before they occur. Do not make the assumption (as many unfortunate plant owners and operators have) that fuel systems designed for coal will necessarily work well for hogged fuel. Municipal Solid Waste and Refuse Derived Fuels Receiving, storage and reclaim facilities for MSW and for RDF at co-firing installations warrant some special considerations based on the experience of others who have co- fired these fuels. The perspective offered here is that of plant sites at which fuels other 73 than MSW and/or RDF are considered to be the primary fuels, that is, from plants at which MSW/RDF provided less than 50% of the total heat input. The various users of MSW/RDF found that these fuels have characteristics which are not common to other fuels and which must be accounted for in order to successfully operate the plant facilities. The fuel characteristics which appear to have the greatest impact on facilities for receiving, storage and reclaim include: oO Bad odor oO Some fractions of the waste can be easily wind blown oO The wastes may have packing problems Odors associated with municipal wastes are well known and recognized. They are sufficiently obnoxious that they must be dealt with. One successful approach to the design and operation of receiving, storage and reclaim facilities has three components: 1) Keep all such wastes in an enclosed building; 2) Store minimum amounts of waste, typically not more than a two day supply at the plant site; 3) Maintain a negative pressure in the building and then use the building interior air as a supply for the combustion chamber. That way odors from the MSW/RDF are destroyed in the combustion process and do not leave the building to become a neighborhood nuisance. The problems associated with waste components becoming windblown and scattering about the plant site (or further) can be readily solved by keeping all receiving and unloading facilities (for truck and/or rail shipments) indoors. Indoor receiving and unloading facilities are an added expense compared to outdoor facilities but are considered necessary for a project to be environmentally acceptable to the surrounding neighborhood. 74 Both electric utilities and other entities have found that MSW and RDF tend to pack down when stored for more than a few days. If the material does pack down in storage it makes reclaim difficult and may also present feeding problems. The solution is to avoid extended storage of these fuels at the plant site by using a first in, first out fuel storage system and by minimizing the fuel supply at the plant site. A one to two days’ supply is sufficiently small to limit fuel packing problems. FUEL PREPARATION SYSTEMS Co-firing fuels does not necessarily require that special steps be taken to prepare the individual fuels. The liquid and gaseous fossil fuels arrive at the plant site in a fully prepared state and no further preparation is necessary prior to burning. Similarly, coal delivered at a plant site generally does not require any additional treatment or preparation other than pulverizing for use in pulverized coal (PC) boilers. For the other most commonly co-fired fuels (i.e., the waste wood based fuels, MSW, and RDF) some additional fuel preparation may be warranted. Wood Fuels Waste wood fuels, especially hogged fuel, often require preparation prior to burning: To control size distribution of the fuel To remove tramp metal To lower moisture level O7O..28)... Oo To remove dirt. Fuel Size: The maximum size of wood fuel pieces must be limited to avoid plugging or jamming any part of the fuel system. At those plant sites which require fuel sizing equipment the usual practice is to screen the fuel and to convey any oversize pieces to either a knife hog or a hammer hog where they are reduced in size to an acceptable 75 level. Equipment to carry out these procedures is well developed and commercially available. Tramp Metal: Most places that burn wood based fuels, particularly hogged fuel, have experienced tramp metal in the fuel. It comes in all forms including axe heads, bolts, nuts, car parts, scrap steel, etc. No one has ever found the source of tramp metal in fuel piles. It seems to appear from nowhere. Unfortunately, it often causes problems with the fuel handling and feeding equipment and may damage combustion facilities. Tramp metal can be particularly injurious to fuel grinders (hogs) and fuel feeders. There are several techniques for dealing with tramp metal. Metal detectors work well in locating ferrous metals and can be connected to alarms or conveyor stop buttons (or both). Magnetic separators of several designs are commercially available and these can be effective in separating ferrous materials from the fuel. For those plants which purchase wood fuels from outside sources, contract clauses which exact a penalty for tramp metal in the fuel can also be influential in reducing the problem. Fuel Moisture Level: Figure 5-1 (page 60) shows the variations in fuel use rates and boiler thermal efficiencies with fuel moisture level for wood fuels. As fuel moisture levels increase, fuel use rates go up and efficiencies go down. It is, therefore, generally desireable to keep fuel moisture at relatively low levels. Unfortunately, this is not always a straight forward task since there are many factors working to increase rather than decrease moisture levels in wood fuels. For example: 1) Bark is often peeled from trees with a high pressure water spray; 2) Saws (generating waste sawdust) are often cooled with a water spray; 3) Logs may be stored in log ponds to prevent drying and checking of the wood. That increases the moisture level of the wood and bark and, therefore, of the waste wood; 76 4) Hogged fuel piles are large in volume and are seldom covered to protect them from rain; 5) Green logs (fresh cut) are high in natural moisture. The combined factors noted above result in moisture levels which may be as low as 20% or as high as 70% (wet basis) and which may vary seasonally or over short time periods. There are productive steps that can be taken to limit and/or to control fuel moisture levels. For facilities which purchase wood based fuels under contract, certainly the purchase price should take into account the as-received moisture level of the fuel. That will, at minimum, serve to discourage the practice of watering down the fuel truck so that the buyer pays a high price based on the weight of the fuel received. It may also provide economic incentive to the fuel supplier to keep the fuel as dry as possible prior to delivery. Fuel piles can be covered to keep off rainwater. In very wet locales putting fuel piles under roofs has proven to be worth while. There are tradeoffs with roofs, however. They are expensive to install and expensive to maintain. The maintenance costs arise because the fuel is typically moved about by heavy equipment (blades, front end loaders, etc.) which bump into and damage support structures for roofs. Several companies have installed fuel drying facilities using boiler exhaust gases as the energy source and/or burning a portion of the wood to provide the drying energy. The economics of drying wood waste fuels are not always favorable (since fuel dryers must be equipped with air pollution control systems), but for specific installations the capital cost and operating expense may be justified. Dirt Content: The normal ash content of waste wood fuels ranges from 1% to 5%, occasionally higher for particular species. The ash comes from dust that settles into the bark of the trees and from inorganic components of cellulose and lignin which Le make up the structure of the tree. Ash from these sources is generally not a problem in the operation of boilers because its presence is expected and can be taken into account in the design of the combustion systems. Dirt is something in addition to the ash content of waste wood fuels and can be traced to several sources. For example, when trees are harvested they may be dragged through streams, through mud, through clay or in other ways collect non-combustible dirt which becomes part of the waste fuel. Fuel piles which are stored in unpaved areas are prone to increased dirt added to the fuel by loaders scraping too deep as they pick up loads of fuel. Dirt from such sources adds to the burden of non- combustible material entering the combustion system and is always a negative factor in the plant operation. Keeping the dirt content to reasonable levels can be accomplished by a variety of steps. One approach is to store all harvested logs in a log pond. That tends to loosen mud, clay and small rocks permitting them to fall to the bottom of the pond. Another approach is to store fuel only in paved fuel storage areas. A third approach is to implement stiff penalties for dirt content in purchased fuel supplies. Other approaches may be successful for specific plant sites. None of the problems associated with wood fuels (size, tramp metal, moisture level and/or dirt) arise specifically from co-firing wood waste fuels. Rather, they are typical problems which can occur at any installation at which wood waste fuels are burned. They are presented here because they are problems which have been faced at facilities which have attempted co-firing and because their summary may benefit those considering the use of wood fuels for co-firing. 78 MSW and RDF Fuel preparation for the refuse based fuels is particularly important and necessary for co-firing applications. This is so because of the variations expected in the physical and chemical characteristics of MSW over time. The makeup of MSW is constantly changing depending on how it is generated, what season it is, and a variety of other factors. To start with a highly variable waste material and process it so that its physical and chemical parameters are somewhat uniform and fall within acceptable ranges requires a significant investment in equipment and personnel. As might be expected, much has been written on the topic of refuse derived fuels and how best to prepare them. Excellent references can be found in Chapter 4 of “Guidelines for Co-Firing Refuse Derived Fuel in Electric Utility Boilers," EPRI CS-5754, Volume 2. (Copyright Electric Power Research Institute, 1988). The amount of preparation that is required at any plant site depends to a very large extent upon the kind of combustion equipment and fuel feeding equipment that is available. Bubbling and circulating fluidized beds (see Chapter 4 for descriptions of these systems) are very forgiving and can burn MSW and/or RDF with large variations in fuel size, in fuel moisture levels, in fuel ash content, etc. Some of the rotary burner designs are also relatively forgiving. At the other end of the spectrum of combustion systems, suspension burners require very careful control over size distribution, moisture content, and fuel ash content and thus require a great deal of fuel preparation. Utility boilers designed to burn pulverized coal (PC) in suspension have been used successfully to co-fire highly prepared RDF under test conditions without the use of bottom grates. However, the history of PC boilers co-fired with RDF strongly suggests that the best practice is to install grates in order to provide an appropriate combustion environment for large, dense fractions of the RDF and for ash removal from the system. An alternative to the boiler modifications was to further prepare the RDF to reduce its fuel particle size, reduce its 79 ash content and reduce its moisture level so that the remaining fuel would burn in suspension along with the pulverized coal. The experience gained at those plant sites which have co-fired RDF indicates that the RDF is most often supplied to the plant site in a prepared state and requires no further preparation. Most plant sites have received RDF-3 (see Table No. 5-3, page 65), for ASTM classifications of RDF) although there have been some test burns with RDF-5. To summarize, the amount and kind of fuel preparation required to co-fire RDF depends primarily on the design of the fuel feed system and the kind of combustion system used at a plant site. An engineering evaluation of the combustion facilities can establish acceptable ranges of the RDF properties (i.e., size, moisture level, ash content, heating value) required for successful co-firing. Once these parameters are established, then the steps required for fuel preparation of the RDF can be determined. As a final comment concerning fuel preparation for co-firing, Table 4-7 (page 31) lists a variety of fuels which have been co-fired but which do not fall into the categories of either waste wood fuels or refuse based fuels. The list includes such fuels as peat, straw, feed lot wastes, industrial solid waste, cocoa beans, agricultural wastes, etc. It should be apparent that each of these fuels may require some specific pre-treatment prior to co-firing. As with the wood based fuels and the refuse based fuels, the pre- treatment requirements will be strongly influenced by the kind of combustion equipment and fuel feeding equipment used at the plant site. 80 FUEL FEED SYSTEMS There are two general areas of concern that arise when fuels are co-fired which are related to fuel feed systems. The first concern has to do with properly metering the co-fired fuels. The second has to do with the physical distribution inside the combustion chamber of solid fuels which are co-fired. Metering Co-Fired Fuels In practically all steam generating combustion facilities, the flow rate of fuel is controlled based on the steam pressure in the boiler. As the steam pressure falls, indicating increased steam use rates, the flow rate of the fuel is increased in order to generate steam faster. Conversely, when steam drum pressures increase, control signals are sent to the fuel feed system to decrease the rate of fuel flow, thereby reducing the rate of steam production. It is an elegantly simple and well proven control system. Part of what makes it nice is that the control system does not require that the fuel flow rate be metered. It only requires that the flow rate can be increased or decreased through some reasonable range in keeping with the design criteria for the boiler. The lack of requirement for metering the rate of fuel use is very important because, while it is comparatively easy to obtain reasonably accurate flow rates for fuels like natural gas and the liquid fossil fuels (i.e., No. 2 oil and No. 6 oil), it is correspondingly difficult to accurately meter the flow rate of solid fuels such as coal, wood, MSW, RDF, etc. In fact, for all useful purposes, the technology does not exist today to accurately, instantaneously and continuously meter the flow rates of solid fuels. Herein, lies the basis of one of the principal problems of co-firing fuels. If one or more of the co-fired fuels is a solid fuel, there is no accurate method available to meter the flow rate of the fuel(s) on an instantaneous and continuous basis. And, therefore, there is no proven method by which to accurately control the rate of heat input to the 81 combustion system from the solid fuel(s) used. It’s all well and good to plan the operation of a system so that 15% of the energy comes from RDF-3, but the technology does not exist to feed exactly 15% of the energy from RDF ona continuous, instantaneous basis throughout the range of steam generation rates for which the plant is designed. Plant sites have been able to reach some reasonable approximations to the desired percentage of heat input from solid fuels. There are several means of accomplishing this. For example, variable speed screw feeders can be calibrated for specific fuels (i.e., hogged fuel or RDF-5) by carrying out calibration tests on the feeders. But inaccuracies are introduced during operation of the feeders due to variations in fuel moisture levels, in fuel higher heating values, in fuel ash and dirt content, and in fuel density. A second method commonly used to reach the desired percentage of heat input from solid, co-fired fuels is to premix the solid fuels before they are sent to the fuel feed system. Several plant sites have followed a procedure of weighing batches of solid fuels and then mixing the pre-weighed batches using a front end loader operating on a tipping floor. A variation of this approach is to pre-mix the fuels on a batch basis where the volume of each fuel is used to determine the amount rather than the weight of each fuel. Pre-mixing has the same limitations to accuracy that calibrated feeders have: the fuels (particularly the waste wood and refuse base fuels) have variations in moisture level, heating value, in bulk density and in ash content. You can achieve a reasonably close approximation to the target levels in a fuel mix, but you cannot count on an accurate blend of heat input from solid fuels on a continuous basis. For many plant sites, the inability to accurately meter fuel flow rates for solid fuels is not considered to be a problem. For example, a boiler can be base loaded using coal fed at a constant rate. Then wood fuels, or oil, or gas or some other co-fired fuel can 82 be fed at a variable rate to accommodate swings in steam flow rates. That way, when the steam demand increases, the coal flow rate stays constant and the flow rate of the other co-fired fuel(s) increases to meet the steam demand. This approach works at many plant sites and is a practical solution. It does not maintain a consistent ratio of heat inputs from the co-fired fuels, but at many plant sites, that is not important. Note that it is not necessary to base load with coal. The burner might just as easily be base loaded with some other fuel (e.g., No. 6 fuel oil, hogged fuel, etc.). The accurate blending of co-fired fuels may be important at plant sites for a variety of reasons. One is that the ash content of fuels and the ash characteristics of fuels may be critical to the operation of the boiler and/or to the operation of the emission control equipment. This has been the experience of electric utilities co-firing coal and RDF-3. A particular plant site may work OK at 15% heat input from RDF but not at 20%. And it may be that if the RDF heat input rate falls below 10%, that problems arise because the economic success of the project is based on a 15% heat input; or it may be that at 10% heat input rates, not enough RDF is being used to solve the solid waste disposal problems of the community. Distributing Fuels in the Combustion Chamber When gaseous and/or liquid fossil fuels are used, they are burned in commercially manufactured burners designed specifically for the type of fuel used. The combustion process is controlled entirely by the burner configuration which meters both fuel and combustion air in proper proportion throughout the full operating range of the boiler. The burners are designed to achieve both high combustion efficiency and high thermal efficiency. Flame zones are controlled to avoid flame impingement on either refractory or heat transfer surfaces. There is no concern over the distribution of the fuel throughout the combustion chamber of a boiler because the fuels are burned completely within the operating zone of the burner. 83 On the other hand, when solid fuels are burned the distribution of the solid fuels within the burner system can become a major problem area. It depends on the kind of combustion equipment used and on the physical characteristics of the solid fuel. If the burner is a circulating fluidized bed, a Dutch oven, a fuel cell, a vortex suspension burner or a rotary burner, then the distribution of the solid fuel in the burner is relatively unimportant. But if the combustion system is a spreader stoker, a non-vortex suspension burner (like a PC furnace) or a bubbling fluidized bed then the distribution of fuel may be very important to the successful operation of the system. In spreader stoker systems, it is desired to uniformly distribute the fuel across the entire grate system so that the fuel bed on the grates has a uniform thickness (no thick spots, no thin spots). The fuel can be spread across the grates either by blowing it pneumatically with a medium pressure air stream or by throwing the fuel using a paddle wheel flinger. In either case, the size of the fuel and the density of the fuel . particles dictate how fuel will be distributed. If the spreader stoker is properly adjusted to fling coal pieces uniformly across a grate, it is unlikely that the same settings will work to uniformly distribute RDF-3 or hogged fuel across the grate. The fuel will either go too far and impinge on the opposite wall of the furnace leaving a bare spot on the near side of the furnace, or it will not be carried far enough and will build up in the center of the grate leaving a bare spot on the far side of the furnace. So trying to use the same flinger or pneumatic spreader to co-fire coal and other solid fuels may well lead to operating problems. One possible solution to this difficulty is to use separate spreaders for individual solid fuels and to adjust each of the spreaders for optimum distribution of the fuel it feeds. Similar problems have shown up in the operation of suspension fired systems. In electric utility applications burning RDF-3 in PC boilers, the RDF is pneumatically conveyed to the furnace and distributed inside the furnace by the same air stream. The heavier (more dense) fractions of the fuel often impinge on the far walls while the light fractions (i.e., paper and plastic) are not carried far enough into the furnace. The result is that the fuel is not uniformly distributed in the combustion zone. Some 84 fractions of the fuel may be carried out of the furnace in the exhaust gas stream before they have had an opportunity to complete the combustion reaction. Other fractions may fall to the furnace floor, pile up and smolder, unable to complete the combustion reaction due to insufficient air. A possible solution to this kind of fuel distribution problem is to revamp the furnace to provide a traveling grate (if it doesn’t already have one) and to further process the RDF so that the size distribution of the fuel particles is reduced and more uniform. It may also be helpful to relocate the point of introduction of the fuel into the furnace so that it is relatively low in the furnace. The traveling grate will support any dense fractions of fuel and distribute combustion air to those dense fractions while they complete the combustion reaction. Reducing the fuel particle size and making it more uniforms speeds the combustion process and improves the opportunity for the solid particles to complete the combustion reaction before being swept out of the furnace by the rising exhaust gases. Introduction of the fuel low in the combustion chamber serves to increase residence time in the flame zone for suspended particles and, thereby, contributes to completing the combustion reaction. Some of the bubbling fluidized bed combustion systems which were designed specifically for high sulfur coal combustion in a utility setting require very careful attention to the distribution of fuel within the bed. In fact, EPRI and the U. S. Department of Energy have carried out extensive research and development programs related to the distribution of coal in these systems and have come to appreciate the importance of uniform distribution of the solid fuel in regard to sulfur capture efficiency and in regard to controlled heat transfer from heat exchange surfaces immersed in the bed. In such specialized utility boilers, it may be unwise to attempt to co-fire other fuels if only because of the potential difficulties of uniformly distributing the co-fired fuels within the bed. 85 There are, however, many other less specialized applications of bubbling fluidized beds in which the introduction of solid fuels does not have to be done uniformly across the bed. Single fuel chutes have been used successfully in several installations for a variety of solid fuels including hogged fuel, MSW, RDF, municipal waste treatment sludge and others. GRATES Grates have several functions in combustion systems. They support solid fuels for whatever time period is necessary for the fuels to go through the various stages of the combustion process. They distribute combustion air to the solid fuels. They act as a collection surface for the non-combustible ash in the fuel and, in the case of reciprocating and traveling grates, they move the collected ash to a central pickup point. Not all combustion systems are equipped with grates. Natural gas fired and liquid fossil fuel fired boilers don’t need them. Some of the pulverized coal boilers are not designed with grates and use other mechanisms to collect and remove ash from the furnace. Pulverized coal particles burn in suspension and do not need the physical support of grates. Rotary combustors generally do not have grates built in. The solid fuel particles are supported by the interior shell of the rotary furnace and the ash is carried through the combustor either by gravity or by an interior helical screw. Neither bubbling nor circulating fluidized bed systems use grates. In these systems, the fuel is supported by the uprising gas stream and burns in suspension. Ash is removed by a variety of ways which do not require a grate system. Vortex suspension burners do not use grate. Like the rotary burners they support the solid fuel particles on the interior shell of the burner and carry ash from the burner in the exit gases. In some designs the vortex burners are operated at sufficiently high temperatures that the ash melts in the burner and is removed as molten slag. 86 So, a logical question is: What’s the concern with grates in co-firing applications? Experience in the electric utility and in the non-utility sectors indicates that in co-firing applications grates are only of concern when co-firing solid fuels. As noted above, they are not necessary for use with liquid or gaseous fuels. Further, they are only of concern under a few limited circumstances: oO When PC furnaces (or other non-vortex, non- fluidized bed suspension fired systems) are to be used for co-firing solid fuels whose combustion rate is sufficiently slow that the particles cannot burn completely in suspension. Then the furnace needs to be equipped with a grate system that can support the large fuel particles, distribute combustion air to them while they complete the combustion process and remove the collected ash. oO When the furnaces are equipped with grates but the co-fired fuels significantly increase the ash input rate to the furnace. Under these circumstances, it may be necessary to revise the design and/or operation of the grates to increase their ability to collect and remove ash from the system. An engineering analysis of most combustion systems (by qualified professional engineers) can be used to determine if a particular furnace needs any modification of its grates in order to successfully co-fire solid fuels. If there is reasonable doubt about the need for grate installation and/or modification, then such an engineering analysis should be carried out. 87 COMBUSTION AIR Combustion air must be provided for each fuel that is used in a burner system. The volume of combustion air is determined from several design variables including: ° The chemical composition of the dry fuel oO The moisture content of the fuel oO The heating value of the fuel oO The level of excess air required to complete the combustion reaction oO The inlet air temperature ° The temperature of the exhaust gases oO The steam generation rate required With all of these variables influencing the volume of combustion air, the volumes differ substantially for different fuels. The data in Table 6-1 (page 91) provide comparisons of the combustion air volume requirements for 11 different fuels which are commonly used. Also, data are provided for each of the fuels regarding: oO The assumed fuel moisture content oO The higher heating value for each fuel (dry basis) oO The higher heating value for each fuel (wet basis) ° The assumed level of excess air required to complete the combustion reaction (expressed as a percent) oO The assumed exhaust gas temperature oO The calculated thermal efficiency of the combustion process oO The volume of combustion air expressed in actual cubic feet of air required at 80° F per million BTU’s of energy input oO The volume of combustion air expressed in actual cubic feet of air required at 80° F per million BTU’s of energy output. Combustion Air Fan Capacity The bottom line of Table 6-1 (page 91) is important to this discussion for it provides a direct comparison of the combustion air volume requirements for each of the 11 fuels considered. Note that the combustion air requirements for the fossil fuels are substantially lower than the requirements for waste wood and refuse based fuels. Utah coal, for example, requires 41% less combustion air than hogged fuel on the basis of useful heat output from a combustion system. The combustion air volume requirements are an essential part of the design criteria for combustion systems. A boiler designed to burn Utah coal should have its fans, ducts, dampers, air pre-heaters, and other components of the combustion air system sized to provide 14,300 cubic feet of air (at 80° F) per million BTU’s of useful heat output. The combustion air systems may present some problems for boilers in which co-firing of fuels is attempted. For example, assume that a boiler has been designed and built to burn Utah coal. If it is later decided to co-fire RDF-3 so that 20% of the heat input is provided by the RDF then the combustion air requirement will be as follows: Air Req’d for Coal + Air Req’d for RDF (0.80 x 14,300) + (0.20 x 20,700) Total Air Req’d 15,580 ACF/MMBTU,,, If the combustion air fan system was designed to deliver 14,300 ACF (Actual Cubic Feet) per million BTU’s of heat output from the system, then the fan system will be undersized by 9% in the co-firing mode, and the overall system will be derated by 9%. Thus, one of the possible outcomes from co-firing fuels is that the combustion system (boiler) may be derated due to limited combustion air fan capacity. 89 Lack of adequate combustion air capacity and subsequent derating of boilers does not necessarily occur due to co-firing. However, it is of sufficient concern that any serious consideration of co-firing should include an engineering analysis of the combustion air system design and its potential limitations on the operation of the overall system. 90 16 TABLE 6-1 Comparison of Combustion Air Requirements For 11 Different Fuels Which Are Commonly Used in Co-Firing Applications. The Table Also Includes Assumed Values for Fuel Moisture Level, Higher Heating Values (Wet and Dry Basis), Assumed Levels of Excess Air, Assumed Exhaust Gas Temperatures, and Calculated Thermal Efficiency Values. Dry Typical Municipal Refuse No. 2 No. 6 Wood Ory Hogged Solid Derived Penn Utah Wyo. Fuel Fuel Nat'l Pellets Wood Fuel Waste Fuels Coal Coal Coal oil oil Gas Moisture (% wet basis) 10 10 40 30 24 AS 5.2 25.0 0 0 0 Higher heating value 9,030 9,030 9,030 6,400 7,700 13,982 13,291 12,460 19,430 18,300 19,800 (BTU's/\b -- dry basis) Higher heating value (BTU's/lb -- wet basis) 8,127 8,127 5,418 4,500 5,800 13,800 12,600 9,345 19,430 18,300 19,800 Assumed excess air level (%) 40 40 50 50 50 20 20 20 15 15 4 Assumed exhaust gas temp (°F) 450 450 450 450 450 420 420 420 420 420 420 Calc. thermal efficiency (%) 79.4 79.4 70.6 60.1 73.0 86.5 85.4 82.2 85.2 86.5 83.3 Combustion air flow rate 13,400 13,400 14,300 12,700 15,100 12,500 12,200 12,100 11,700 11,500 10,900 (ACF @ 80°F per MMBTU;_) Combustion air flow rate 16,900 16,900 20,200 21,100 20,700 14,400 14,300 14,700 13,800 13,200 13,000 (ACF @ 80°F per MMBTU. **) ‘out = ACF/MMBTU. = ACF/MMBTUiNn It should be interpreted to mean the combustion air requirement per million BTU's of energy output from Thermal Eff. the fuel taking into account the losses from the combustion system. 26 TABLE 6-2 Comparison of Exhaust Gas Volumes For 11 Different Fuels Which Are Commonly Used in Co-Firing Applications. The Table Also Includes Assumed Values for Fuel Moisture Level, Higher Heating Values (Wet and Dry Basis), Assumed Levels of Excess Air, Assumed Exhaust Gas Temperatures, Calculated Thermal Efficiency Values and Calculated Exhaust Gas Moisture Content. Ory Typical Municipal Refuse No. 2 No. 6 Wood Dry Hogged Solid Derived Penn Utah Wyo. Fuel Fuel Nat'l Pellets Wood Fuel Waste Fuels Coal Coal Coal oil oil Gas Moisture (% wet basis) 10 10 40 30 24 ia5: 52 25.0 0 0 0 Higher heating value 9,030 9,030 9,030 6,400 7,700 13,982 13,291 12,460 19,430 18,300 19,800 (BTU's/lb -- dry basis) Higher heating value (BTU's/lb -- wet basis) 812%... | 85427. 5,418 4,500 5,800 13,800 12,600 9,345 19,430 18,300 19,800 Assumed excess air level (%) 40 40 50 50 50 20 20 20 15 15 14 Assumed exhaust gas temp (oF) 450 450 450 450 450 420 420 420 420 420 420 Calc. thermal efficiency (%) 79.4 79.4 70.6 60.1 73.0 86.5 85.4 82.2 85.2 86.5 83.3 Calc. exhaust gas moisture (%) 12.0 12.0 18.4 19.8 16.0 6.9 8.7 12.1 deze, 10.7 18.0 Exhaust gas flow rates 25,000 25,000 28,700 25,800 29,200 21,000 20,900 21,600 20,200 19,500 19,300 (ACF @ stack temp. per MMBTU;) Exhaust gas flow rates 31,500 31,500 40,700 43,000 40,000 24,200 24,500 26,300 23,700 22,600 23,200 (ACF @ stack temp. per MMBTU.**) ae ACF/MMBTU = ACF/MMBTUin It should be interpreted to mean the exhaust gas per million BTU's of energy output from the fuel taking Thermal Eff. into account the losses from the combustion system. Measurement and Control of Combustion Air Flow A second area of concern related to combustion air that arises in co-firing centers around the excess air requirements for fuels. Excess air levels are determined by measuring the residual oxygen in the exhaust gases from the system. As the measured level of residual oxygen increases, it indicates that the excess air level is increasing. The relationship between levels of excess air and residual oxygen are shown in Figure 6-1 for several types of fuels. Og Curves Wood/bark Coal Natural Gas 150 100 90 80 70 60 50 Excess 40 Air Level (%) 30 20 15 10 0 5 10 15 20 25 Coo or Op in Flue Gas (%) FIGURE 6-1: Curves Showing the Relationship of Levels of Excess Air to Oxygen Content in the Exhaust Gas Stream for Several Fuels 93 The oxygen level in the exhaust gas stream can be used as an input to control the air to fuel ratio (and, therefore, the level of excess air). The control strategy works well as long as there is only one fuel being burned at a time. If more than one fuel is burned in the same combustion system, then control of the excess air levels for each fuel becomes slightly more complicated since the exhaust gases mix. From a single point reading of the residual oxygen levels in the combined exhaust gases, it may be difficult to ensure that each fuel is burning with an appropriate level of excess air. Unfortunately, with current technology the most accurate way to measure excess air is by sampling the oxygen content of the exhaust gases. Still, the problems of measuring and controlling excess air levels in co-firing applications are not all that troublesome if the excess air requirements for the fuels are about the same. Note in Table 6-1 (page 91) that the excess air levels assumed for the fossil fuels (coal, oil, and gas) are all in the range of 14% to 20%. So if these fuels are co-fired it is possible to achieve excess air levels for each fuel in approximately the desired range. That situation does not exist when dissimilar fuels such as fossil fuels and wood based or refuse based fuels are co-fired. The excess air requirements for the wood and refuse based fuels are typically much higher than those of the fossil fuels (40% to 50% excess air for wood and refuse based fuels compared to 14% to 20% for fossil fuels). Co-firing these fuels so that each of the fuels is provided with the optimum level of excess air at the point of combustion requires that two specific tasks be accomplished: 1) The level of excess air should be accurately measured at the location of combustion for each fuel fired on a continuous basis. Note that this is very difficult to accomplish technically and may prove to be impractical for many co-fired facilities. 94 2) The flow rate of combustion air should be accurately metered and delivered to the point of combustion for each fuel fired such that the level of excess air at the point of combustion stays within an acceptable range. This should be accomplished throughout the full operating range of fuel flow rates for each fuel being burned. The situation is further complicated at many co-firing sites because the fuel feed rates for each of the co-fired fuels are not kept in constant proportion. (Refer to the discussion on Fuel Feed Rates earlier in this chapter). With these many complications pertaining to the measurement and control of combustion air, it is important that sites considering co-firing should include in their engineering analyses specific consideration of the control and distribution of combustion air for each fuel to be fired. GASEOUS PRODUCTS OF COMBUSTION In the preceding discussion of combustion air it was pointed out that combustion air flow rates differ according to the type of fuel used, the level of excess air required for that fuel, and several other variables. Calculated values of combustion air requirements per million BTU’s of useful heat output are provided in Table 6-1 (page 91) for 11 commonly used fuels. The gaseous products of combustion‘ also vary according to similar parameters. As levels of excess air increase, the flow rate of combustion products increases. As steam generation rates for boilers go up, the flow rate of combustion gases goes up, and so on. * The gaseous products typically include nitrogen, carbon dioxide, water vapor, oxygen, carbon monoxide, sulfur dioxide and small concentrations of other constituents. 95 Exhaust Gas Temperatures There are, however, some differences between the controlling parameters for combustion air volumes and for exhaust gas volumes. One of these is the exhaust gas temperature. As the temperature increases, the volume of the exhaust gases increases in accordance with the ideal gas laws, and there is a corresponding increase in the exhaust gas flow rate. Exhaust gas (e.g "flue" gas) temperatures are influenced by many design and operational parameters which are inter-related in a complex fashion. For purposes of discussion about co-firing of fuels, it is useful to be aware that flue gas exit temperatures can increase due to: © Increased levels of excess air o Air heater combustion air bypassing o Slag buildup on furnace heat transfer surfaces Operational experience in single firing and in co-firing fuels suggests that for any given boiler facility, the flue gas temperature is apt to be 30° F higher using waste wood and/or refuse based fuels compared to using fossil fuels. These factors are accounted for in the 5th row of data for Table 6-1 (page 91) and Table 6-2 (page 92). 96 Exhaust Gas Volumes All of this flue gas discussion is leading to a comparison of the volumes of exhaust gases which are typical for fuels used in co-firing. The bottom row of data in Table 6-2 (page 92) provides a comparison of the exhaust gas volumes for 11 different fuels”. The table includes: Assumed values for fuel moisture level Higher heating values (dry basis) Higher heating values (wet basis) Assumed levels of excess air Assumed exhaust gas temperature Calculated thermal efficiency O66. Oo <6. Calculated exhaust gas moisture level The calculated values for exhaust gas volumes clearly show a significant difference in the volume generated from burning fossil fuels compared to the volume for the non- fossil fuels. The exhaust gas volume for fossil fuels ranges from 22,600 to 26,300 actual cubic feet (at the noted stack temperature) per million BTU’s of effective heat output from the fuel. By comparison, the range of exhaust gas volumes for the waste wood and refuse based fuels is from 31,500 to 43,000 actual cubic feet (at the noted stack temperature) per million BTU’s of effective heat output from the fuel. 5 The combustion calculations used to develop the exhaust gas flow rate numbers follow the ASME Heat Loss Method in which the major heat losses are summed and then subtracted from 100%. For further information on this method, see Chapter 6 of Steam, Its Generation and Use, 38th edition, published by Babcock and Wilcox, 1975. 97 Boiler Derating The volume of exhaust gases is important in that it influences the design and operation of: oO Air pre-heaters oO Induced draft fans oO Air pollution control devices including baghouses, electro-static precipitators, scrubbers, etc. oO Related flue gas ducts, dampers, etc. To illustrate, assume that a boiler has been designed and built to burn Utah coal. The design criteria include exhaust gas volumes of 24,500 cubic feet of gas at 420° F per million BTU’s of effective heat output from the fuel. If it is later decided to co-fire hogged fuel and Utah coal such that 40% of the energy comes from hogged fuel and 60% comes from coal, then the resulting exhaust gas volumes will be approximately: Total Exhaust Gas 31,000 ACF/MMBTU,,, Exh. Gas for Hogged Fuel + Exh. Gas for Coal (0.40 x 40,700) + (0.60 x 24,500) That is approximately 26% more exhaust gas flow than the system was originally designed to handle. This, in turn, may result in derating the boiler by 26% due to limitations in the capacity of the air pre-heaters, induced draft fans, emission control devices, and or the miscellaneous ducts, dampers and other equipment designed to contain and control flue gases. Even in those cases where relatively small amounts of fuels are co-fired, boiler derating is potentially of concern. For example, assume that a PC boiler is designed and built to burn Pennsylvania coal. Later it is deemed desireable to co-fire the unit with 15% of the heat input coming from RDF-3. The exhaust gas volume will be approximately: 98 Exh. Gas for RDF + Exh. Gas for Coal (0.15 x 40,000) + (.85 x 24,200) Total Exhaust Gas 26,600 ACF/MMBTU,,, or 9.9% more than the design volume. Thus, providing 15% heat input to this system from RDF-3 may result in almost a 10% reduction in the maximum steam generation rate of the boiler if the system is limited by exhaust gas flow rates®. Of course, not all co-firing results in boiler derating due to exhaust gas limitations. Where only fossil fuels are co-fired the resulting changes in flue gas volumes are apt to be small enough that no significant effects are likely to be noted in the operation of the system. In the case of boilers which were initially designed and constructed to burn waste wood and/or refuse base fuels, the decision to co-fire fossil fuels will only serve to reduce flue gas volumes. Again, no derating would be anticipated. Certainly, as a cautionary measure, it is desireable to thoroughly investigate the potential for boiler derating due to flue gas volume limitations for any installation at which co-firing is proposed. © Volume 2, chapter 3 of “Guidelines for Co-firing Refuse Derived Fuel in Electric Utility Boilers", EPRI CS-5754 (Copyright Electric Power Research Institute, 1988) contains an extensive discussion on derating of boilers due to co-firing and includes several useful graphs of boiler operating variables as a function of varying levels of heat input from RDF. $9 Flue Gas Moisture Content The 7th row of data in Table 6-2 (page 92) lists the calculated percentage concentrations of exhaust gas moisture (based on volume) for 11 different fuels. The moisture levels range from a low of 6.9% to a high of 19.8%. The flue gas moisture levels come from two principal sources. The hydrogen content of the fuel forms water in the combustion process and, of course, any water which is brought into the combustion process with wet fuel remains as water in the exhaust gases. There is also a minor input of water to the system which comes from the moisture in the air supplied to the combustion process. The principal effect of moisture in the flue gas is that it increases heat loss from the system and thereby reduces thermal efficiency. But it also has the limitation that the more water there is in the flue gas, the greater the volume of the flue gas. To illustrate, consider the example calculation in which hogged fuel and Utah coal were co-fired on a 40:60 ratio of heat input (see page 98). In that instance, it was determined that the resulting flue gas volume would be 26% larger than the flue gas volume due to burning only Utah coal. To see influence of moisture, assume now that dried wood fuel (at 10% moisture content rather than hogged fuel at 40% moisture content) is to be co-fired with Utah coal at the same 40:60 ratio of heat input. The resulting flue gas volume will be: Exh. Gas for Wood + Exh. Gas for Coal (0.40 x 31,500) + (0.60 x 24,500) Total Exhaust Gas 27,300 ACF/MMBTU,,, which is approximately 11.4% larger than the volume resulting from burning only Utah coal. By lowering the fuel moisture content of one of the co-fired fuels, the volume of the flue gas can be effectively reduced and this may, in some instances, have a significant influence on potential derating of the system. It’s something to keep in mind when analyzing combustion systems with a view toward co-firing. 100 ASH CONSIDERATIONS In Chapter 5, the last row of Table 5-2 (page 59) provides comparative values of ash input in units of pounds of ash per million BTU’s of heat input with the fuel. Taking into account the thermal efficiencies associated with each of the 11 fuels listed in Table 6-1 (page 91) it is possible to arrive at the ash input rates in units of lbs of ash per million BTU’s of effective heat output from the fuel using the relationship: Ash Input (Ibs ) x 4 (MMBTUin) = Effective Ash (_Ibs_) MMBTUin Thermal Eff.(MMBTUout) Input Rate (MMBTUout) These values are shown for comparative purposes in Table 6-3. The input of ash to combustion systems can have and, indeed, has had a major impact on operations. But the impact depends on what kind of fuels the system was designed to burn initially and on what fuels are to be co-fired. For example, systems initially designed to burn liquid fossil fuels can easily burn natural gas without any ash problems. Generally the reverse is also true although some of the residual fuel oils do have high enough ash content to cause problems in boilers designed for natural gas. Similarly, systems designed to burn coal, which has a higher ash content than waste wood fuels, can usually co-fire waste wood fuels without ash related problems. This has been shown in many installations on a test basis and in a lesser number of installations on a continuing basis. However, systems which were designed for relatively low ash waste wood fuels may have difficulty in handling higher ash content coals even on a co-firing basis. Part of the problem here is related to the differing physical characteristics of coal ash and wood ash. The differences come from variations in ash fusion temperatures, clinker formation and slag behavior. 101 TABLE 6-3 Comparison Of Ash Input Rates For 11 Different Fuels. The Right Hand Column Is Presented In Units Of Pounds Of Ash Per Million BTU’s Of Effective Heat Input From The Fuel. Type of Fuel Ash Input Rate Thermal Effective From Table 5-2 Efficiency | Ash Input Rate (Lbs/MMBTU,,) (Percent) (Lbs/MMBTU,,,) Dry Wood Pellets 3.2 79.4 4.0 Dry Wood 3.2 79.4 4.0 Typical Hogged Fuel 3.2 70.6 4.5 Municipal Solid Waste 56.3 60.1 93.7 Refuse Derived Fuels 20.5 73.0 28.1 Pennsylvania Coal 13 86.5 8.7 Utah Coal a 85.4 6.0 Wyoming Coal 4.0 82.2 4.9 No. 2 Fuel Oil 0 85.2 0 No. 6 Fuel Oil 0.07 86.5 0.08 Natural Gas 0 83.3 0 102 Based on the data in Table 6-3, it should be apparent that the greatest ash related problems stem from co-firing MSW and/or RDF with other fuels. The ash content of the refuse based fuels is obviously so much higher than the other commonly used alternative fuels that special facilities must be provided in the combustion systems for ash removal even where small percentages of refuse based fuels are co-fired. Consider, for example, a boiler designed to burn Pennsylvania coal with an ash content of 8.7 Ibs per million BTU’s of effective heat input. If that facility should attempt to co-fire RDF-3 on the basis of 15% of the effective heat energy to be supplied by the RDF, then the ash input rate to the system would be approximately: Ash From Coal + Ash From RDF (0.85 x 8.7) + (0.15 x 28.1) Total Ash Input Rate 11.6 lbs/MMBTU,,, This is equivalent to a 33% increase in the ash flow rate to the boiler. The experience reported by EPRI indicates that with respect to ash problems, co-firing coal and RDF may result in furnace slagging, fouling and bottom ash handling problems, particularly if the unit already has a slagging problem with coal. In Section 5 of Volume 1, "Guidelines for Co-Firing Refuse Derived Fuel in Electric Utility Boilers," EPRI CS-5754 (Copyright Electric Power Research Institute 1988. Reprinted with permission.): FURNACE SLAGGING AND FOULING RDF ash exhibits poor slagging and fouling characteristics and lower ash fusion temperatures than coal. Units using a high slagging coal and having high rates of furnace volumetric heat release are not considered good candidates for retrofit to RDF co-firing. RDF contains some glass and aluminum particles which will soften at the combustion temperatures encountered and worsen any existing slagging or fouling problem. Furnace slagging and ash buildup appear to be a result of insufficient or excessive RDF furnace injection velocities. In tangentially fired units, RDF injected at too low a velocity does not penetrate the fireball, but rather is 103 carried around the periphery of the fireball to impact on the furnace water wall. In front wall-fired units, RDF is injected from the side walls, and excessive injection velocity appears to cause material to impact on the opposite wall or build up on the bottom dump grate near the opposite walls. BOTTOM ASH HANDLING The major effects of co-firing RDF and coal on bottom ash handling are: ° Increased bottom ash flow rates due to higher ash [content] and lower heating value. The result is higher boiler ash loading at all unit loads. Clinkering and bridging of dump grates due to lowered ash softening temperature and insufficient excess combustion air. Plugging of sluice lines due to the presence of oversized material and of large amounts of wire and steel bands. Plugging of clinker grinder due to oversized material. Plugging of ash dewatering bin screen Septic sluice pond water at one installation that did not have a dump grate. For the interested reader, the subject of ash difficulties experienced with co-firing of RDF and coal is treated in depth in Chapter 6, Vol. 2, "Guidelines for Co-Firing Refuse Derived Fuel in Electric Utility Boilers," EPRI CS- 5754 (Copyright Electric Power Research Institute 1988). In addition, in Chapter 8 of this monograph the subject of ash is considered with respect to its impact on particulate emission control devices, and the collection and disposal as a solid waste from combustion facilities. 104 SUMMARY COMMENTS Chapter 3 and Chapter 4 summarize the experience of electric utilities and non-utility sectors with co-firing of fuels and clearly demonstrate that co-firing is possible and has been used on a wide scale. However, it often requires special consideration in the design and operation of facilities. Fuel receiving, storage and reclaim facilities must be provided for each fuel used in co- firing. The storage volume and the material handling capacity of these facilities is important and should be carefully considered for each project. The example used in the text indicates that a coal burning plant which is to be modified for co-firing with 65% input from coal and 35% input from hogged fuel may find that its fuel yard storage capacity must increase by over 200%. Similarly, the volume flow rate of the hogged fuel will be significantly larger than the volume flow rate of the coal and this must be accounted for in the design of the material handling equipment. The design and operation of systems to receive, store and reclaim most fuels is based on an extensive body of literature, specifications and regulations. The wood based fuels do have some special problems including spontaneous combustion, dust and bridging. Similarly, the refuse based fuels have special problems associated with odor, ease in becoming windblown and fuel packing. In cold regions, exposed fuel piles may freeze. These are all problems that can be dealt with through proper design considerations and operation of the facilities. Concerning fuel preparation facilities, the fossil fuels generally require little in the way of preparation after they are delivered at the plant site. On the other hand, waste wood fuels often require additional preparation to control size, remove tramp metal, control fuel moisture levels and to remove dirt. The amount of and type of fuel preparation required depends to a large extent on the kind of combustion equipment available to burn the fuel. The same reasoning applies to the refuse based fuels. Some require extensive preparation in order to be burned, whereas, others require little preparation 105 for co-firing and it depends mostly on the kind of burner system being used. EPRI publications are an excellent reference source on alternative designs for refuse based fuel preparation systems. Fuel feeding systems used for co-firing have two problem areas. The first is that it is very difficult to accurately meter fuel flow rates on an instantaneous and continuous basis so that the desired heat input rates can be maintained for co-fired fuels. There are several techniques used to achieve proper blending. Some are more successful than others. The second problem area in fuel feeding is to achieve the desired distribution of solid fuels in the combustion chamber, that is, to get the fuel physically into the right place. For some combustion systems, it is fairly critical to successful operation. For other types of burners, it is not so critical. Extensive modifications have been required on some boilers to eliminate problems associated with improper fuel distribution. Not all combustion systems have grates. For those that do use grates, their design and operation may be crucial to the operation of the boiler. For the liquid and gaseous fossil fuels they are not necessary. Grates become a point of concern when firing solid fuels because they support pieces of fuel during combustion, they distribute combustion air to the fuel, they act as a collection surface for ash and they can serve the function of removing the ash from the combustion chamber. For those systems that require grates in co-firing fuels, it is recommended that a careful analysis of the system be conducted by a qualified professional engineer to determine design and operational requirements. Combustion air must be provided to burner systems, whether co-firing or not. The air is typically supplied by forced draft fans but may be handled through induced draft fans in some boilers (or by a combination of forced and induced draft fans). The combustion air flow rate requirements can be determined through combustion calculations taking into account the chemistry of the fuels to be burned. One of the difficulties encountered in co-firing fuels is that some fuels require more combustion air 106 than others. The air flow needs of co-fired fuels may exceed the design limitation of boilers and result in boiler derating. Different fuels require different levels of excess air for optimal combustion. A technical difficulty arises in measuring levels of excess air for each fuel burned in co-firing applications and in controlling the flow rate of air for each fuel to maintain proper levels of excess air throughout the full range of operation of the system. These technical difficulties usually result in compromised operation of the boiler with some reduction in thermal efficiency. The amounts and concentrations of the gaseous products of combustion can be determined from combustion analyses. They differ for each fuel and for each level of excess air. Further, their volumetric flow rates change with exhaust gas temperatures. These factors are important in co-firing. Examples used in the text illustrate the possible derating of combustion systems under co-firing scenarios due to high flow rates of exhaust gases (above the design specifications for the system). The amount of moisture in the fuel may have a major impact on the volumetric flow rate of exhaust gases. Example calculations in the chapter are used to illustrate this and to make the point that flue gas flow rates can be reduced by reducing fuel moisture levels. Some fuels have little or no ash content. Others, particularly the refuse based fuels, may have very high levels of ash. And, as might be expected, some boilers are designed to handle large flow rates of ash while others are not equipped for ash collection and recovery. Ash inputs rates should be carefully considered in planning co-firing facilities since ash can effectively reduce the steam generation rate of boilers, can plug gas passes, can jam grates, and in other ways cause problems. The ash related problems are not insurmountable, but they must be addressed carefully in the design and operation of combustion systems which attempt to co-fire fuels. 107 These many design and operational concerns that surface regarding equipment used in co-firing are not intended in any way to discourage consideration of co-firing. Rather, they are practical problems that are important to be aware of and to address forthrightly in undertaking co-firing. The many utility and non-utility sector facilities that have successfully implemented co-firing should demonstrate that the problems noted in this chapter can be overcome with a reasonable degree of planning, design and careful operation. 108 CHAPTER 7: THE IMPACT OF CO-FIRING ON EFFICIENCY COMBUSTION AND THERMAL EFFICIENCY In combustion related discussions, the term "efficiency" can be defined in several ways. For purposes of this monograph it is helpful to distinguish between "combustion efficiency" and "thermal efficiency" as follows: Combustion efficiency: The heat energy released in the combustion process expressed as a percentage of the higher heating value (HHV) of the fuel may be thought of as "combustion efficiency". For example, typical wood fuels have a higher heating value of 9030 BTU’s per pound of dry material. If the wood burns completely so that all of the carbon originally in the wood forms carbon dioxide and all of the hydrogen in the wood forms water, then all of the heat energy initially in the wood fuel (9,030 BTU’s/dry Ib) will be released during the combustion process and the combustion efficiency is said to be 100%. On the other hand, if part of the carbon is left over as solid carbon char and/or if some of the carbon forms carbon monoxide rather that completing the reaction to form carbon dioxide, then not all of the initial HHV of the fuel will be released. Therefore, the combustion reaction will be less than 100% efficient. Efficient combustion requires an adequate supply of oxygen, high temperatures, turbulence to mix the fuel with the oxygen, and time for the various physical and chemical processes that take place during combustion to be completed. Thermal efficiency: The net useful heat energy available from a combustion process expressed as a percentage of the HHV of the fuel can be thought of as thermal efficiency. Thermal efficiency is generally calculated using the heat loss method adopted by the American Society of Mechanical Engineers (ASME). The method is carefully reviewed and well illustrated with examples in Steam, Its Generation and Use, 38th edition, published by Babcock and Wilcox, 1975, Chapter 6. 109 In the ASME method, the heat energy losses are summed and expressed as a percentage of the HHV. The resulting percentage is subtracted from 100% to reach the calculated value for thermal efficiency. Heat losses include: oO Losses due to dry gases (nitrogen, oxygen, carbon dioxide, carbon monoxide, and sulfur dioxide) exiting the exhaust stack at the exhaust stack temperature. oO Losses due to water in the combustion air supply exiting the exhaust stack at the exhaust stack temperature. oO Losses due to water in the fuel (as initial moisture content of the fuel) plus water formed from the combustion of hydrogen the fuel exiting the exhaust stack at the exhaust stack temperature. oO Losses due to the latent heat of vaporization of the water in the fuel (as initial moisture content of the fuel). oO Losses due to unburned carbon in the ash after the combustion process has stopped. The unburned carbon still has energy which was initially part of the HHV of the fuel. oO Losses due to unburned carbon monoxide in the exhaust stack. The unburned carbon monoxide still has energy which was initially part of the HHV of the fuel. THE SIGNIFICANCE OF THERMAL EFFICIENCY In practical application, thermal efficiency is a particularly useful concept. For example, consider the case of a boiler fired with Utah coal and operating with 85.4% thermal efficiency. If the HHV of the fuel is 12,600 BTU’s per pound (wet basis), then the net heat available to make steam in the boiler will be 85.4% of 12,600 or 10,760 BTU’s per pound of wet fuel burned. The fuel use rate will be 92.93 pounds of wet fuel per million BTU’s of energy added to the steam in the boiler. Suppose that this same boiler is to be co-fired using RDF-3 and that 20% of the energy added to the steam is to come from the RDF. Efficiency calculations indicate that the RDF-3 has a thermal efficiency of 73.0% based on a higher heating value for the fuel of 110 5,800 BTU’s per wet pound. Therefore, the net effective energy value of the fuel is 5,800 x 0.730 or 4,324 BTU’s per wet pound of fuel. To add one million BTU’s to the steam by burning the RDF-3 requires the combustion of 236.2 Ibs of wet RDF-3. And to co-fire the boiler so that 20% of the energy in the steam comes from RDF-3, one must feed approximately: 0.20 x 236.2 47.2 lbs of RDF-3 per MMBTU,,, plus 0.80 x 92.9 74.3 lbs of Utah Coal per MMBTU,,, for a total of 121.5 Ibs of fuel per MMBTU,,, Note that to obtain 20% of the energy from RDF-3, 38.8% of the total weight of the fuel must be RDF-3. The resultant thermal efficiency from co-firing these two fuels can be roughly approximated as: Approx. Overall Eff. (RDF) + Eff. (Coal) Thermal Efficiency (0.20 x 73.0) + (0.80 x 85.4) 82.9%. Considering that the initial thermal efficiency of the system fired on coal was calculated to be 85.4%, it might be concluded that co-firing resulted in a loss of efficiency of 2.5%. This conclusion may not be entirely accurate because it does not take into account a possible increase in the overall exhaust gas temperature for the system, or any other alterations that may occur due to co-firing. 111 KEEPING THERMAL EFFICIENCY IN PERSPECTIVE At any plant site where fuel is purchased, the overall thermal efficiency is usually considered to be an important operating parameter because it has a direct relationship to the cost of operating the plant. High efficiencies are generally equated with low fuel expenses. But note that changes in thermal efficiency which may result from co-firing fuels are not necessarily either good or bad. For example, co-firing RDF-3 in boilers initially designed for use with coal will very probably result in reduced overall thermal efficiency of the system. But if the cost of RDF-3 is low compared to the cost of coal, then it may be possible to reduce the net plant operating expenses by co-firing RDF and coal. Seen from this perspective, the resulting lower thermal efficiency of the plant may not be particularly important. What may be more important is the possibility of derating the boiler as a result of co- firing. As noted in Chapter 6, when some fuel combinations are co-fired the resulting combustion air requirements at full load conditions may exceed the capacity of the forced draft fan system. The same situation can also apply to the induced draft fans, air preheaters, emission control devices, ducts, dampers, etc. with the overall result that the boiler may not be able to generate steam at its design capacity when co-firing specific fuel combinations. If co-firing results in derating a boiler by 20% that may be much more significant economically than a loss of 2.5% thermal efficiency due to co- firing. THERMAL EFFICIENCY VALUES Table 6-1 (page 91) and Table 6-2 (page 92) list calculated values of thermal efficiency for 11 different fuels. These values were determined using the ASME Heat Loss Method and are repeated in Table 7-1 for reference. The residue fuels (waste wood and municipal refuse based) burn with lower thermal efficiencies than the fossil fuels as noted in Table 7-1. This occurs for several reasons: 112 oO Residue fuels have higher fuel moisture levels than most of the fossil fuels. ° Residue fuels require higher levels of excess air to complete the combustion reaction and, therefore, sustain higher dry gas losses in the exhaust stack. oO The higher heating values for residue fuels are substantially lower than the HHV’s for fossil fuels. TABLE 7-1 Calculated Values Of Thermal Efficiency For 11 Fuels Residue Based Fuels Eff. (%) Fossil Fuels Eff. (%) Dry Wood Pellets 79.4 Pennsylvania Coal 86.5 Dry Wood 79.4 Utah Coal 85.4 Typical Hogged Fuel 70.6 Wyoming Coal 82.2 Municipal Solid Waste 60.1 No. 2 Fuel Oil 85.2 Refuse Derived Fuel (RDF-3) 73.0 No. 6 Fuel Oil 86.5 Natural Gas 83.3 Since the thermal efficiencies for the residue fuels are lower than for the fossil fuels, the thermal efficiency resulting from co-firing residue and fossil fuels will be lower than for fossil fuels fired alone. (But, as noted above, that’s not necessarily bad.) 113 ELECTRIC UTILITY THERMAL EFFICIENCY EXPERIENCE EPRI’s report, “Guidelines for Co-Firing Refuse Derived Fuel in Electric Utility Boilers," EPRI CS-5754, Vol. 2, Chapter 5, (Copyright Electric Power Research Institute 1988. Reprinted with permission) recounts utility experience with thermal efficiency as quoted below: At full boiler load and co-firing RDF at 20% heat input [and coal at 80% heat input], RDF co-firing reduces boiler efficiency by 1.9 to 4.2% due to the following factors: © Increased flue gas exit temperature due to: Increased excess air Air heater combustion air bypass (retrofit units) Furnace slagging © Increased flue gas flow rate due to: Higher excess air Lower RDF BTU/Ib heating values Higher RDF moisture o Increased heat losses due to: Dry gas loss Unburned combustibles Fuel moisture loss Flue gas exit temperature increases during RDF co-firing, since the higher excess air required for RDF combustion normally increases gas velocities and furnace and boiler exit temperatures. Likewise, furnace slagging may reduce heat transfer and raise the exit temperature. In addition, the air heater gas exit temperature will increase due to the RDF combustion air bypassing the air heater. 114 SUMMARY COMMENTS When considering efficiencies, it is helpful to clearly distinguish between combustion efficiency and thermal efficiency. They are related concepts but have quite different interpretations. For purposes of this monograph, thermal efficiency is a more useful term. It may be calculated using a well recognized heat loss method adopted by ASME. The method accounts for six different types of energy losses in a typical combustion system. Thermal efficiency is a particularly useful concept in calculating fuel use rates and other fuel requirements. In the case of co-firing applications, thermal efficiencies for each fuel can be taken into account in calculating the required amounts of each type of fuel used. These calculations can then be used in the overall design of the system for co- firing. A comparison of the thermal efficiencies for waste wood based and municipal refuse based fuels indicates that their thermal efficiencies are lower than those of the fossil fuels. When waste fuels are co-fired with fossil fuels, the overall thermal efficiency for the co-fired system will be less than that the thermal efficiency for the same system fired only with fossil fuel. That is not necessarily bad since it is possible to have reduced thermal efficiency and reduced fuel expenses at the same time if co-firing permits the use of inexpensive fuels. It is important to keep the significance of thermal efficiency in perspective and not to overemphasize its importance. Boiler derating resulting from co-firing may have a larger economic impact on a plant site than any impact due to thermal efficiency variations. Electric utility experience in co-firing coal and RDF has shown thermal efficiency losses of 1.9 to 4.2% based on 20% heat input from RDF. 115 CHAPTER 8: ENVIRONMENTAL CONSIDERATIONS ASSOCIATED WITH CO-FIRING Since fuels have differing chemical composition, the combustion products released into the atmosphere will differ for each kind of fuel used in co-fired systems. Thus, co-firing raises environmental questions and concerns which must be addressed in order to comply with federal, state, and local regulations. In this chapter the environmental aspects of co-firing are addressed specifically with respect to: Particulate emissions Gaseous emissions Liquid wastes Toxic and hazardous emissions oe 2 oo The focus of discussion is on the anticipated influence of co-firing in each of the four areas noted above. The subject of specific environmental regulations which are applicable to co-firing is covered in Chapter 9. PARTICULATE EMISSIONS Particulate matter is defined (in the regulatory sense) as any airborne substance other than condensed water which can exist in either a liquid or solid state at 68° F (20° C) and 1 atmosphere of pressure. Particulate emissions from boilers are products of the combustion process and include components of many chemical species with widely differing physical characteristics of size, shape, density, etc. A common term for particulate emissions is "total suspended particulate" (TSP) referring to the fact that the small particles are suspended in the exhaust gases leaving the combustion system and will eventually become particles suspended in the air. It is generally assumed (although not necessarily correctly) that most particulate found in exhaust gas streams comes from the initial ash content of the fuel. Ash is defined Arne as that part of the fuel which is not combustible and, therefore, cannot burn. But it is also true that particulate can be formed by incomplete combustion of the fuel. A common type of particulate stemming from incomplete combustion is unburned carbon char which burns relatively slowly and easily can be entrained in exhaust gases. Particulate Emissions From Non-Combustible Ash Consider now just the non-combustible ash in fuel. Any ash which enters a combustion system must either stay in the system as slag, leave the system as bottom ash or leave the system as fly ash. The bottom ash is usually collected with some kind of grate system and mechanically removed from the boiler or combustor. (Note: See discussion on this topic in Chapter 6.) The fly ash is suspended in the exhaust gas stream and is carried to the emission control devices which remove most of it. Any fly ash which is not captured by the control devices is transported out of the system as particulate pollution. The division of incoming ash into bottom ash and fly ash depends to a very large extent on the kind of combustion system used. In suspension burners, the majority of the ash is fly ash. At the other end of the spectrum, pile burners such as fuel cells and Dutch ovens tend to capture the majority of the ash as bottom ash. Other types of combustion equipment usually have a mix of bottom ash and fly ash, the proportions of which are difficult to predict. It is to be expected that increased ash entering the combustion system with the fuel will result in increased levels of entrained particulate exiting the system downstream from the emission control devices. In Chapter 6, Table 6-3 (page 102) provides a comparison of the ash input rates for 11 different fuels expressed as pounds of ash per million BTU’s of effective heat input (taking into account the combustion efficiency for each fuel). The data from Table 6-3 have been reproduced in Table 8-1. 118 TABLE 8-1 Comparison of the Ash Input Rates for 11 Different Fuels. Fuel Ash Content Fuel Ash Content Type (lbs/Effective MMBTU) Type (lbs/EffectiveMMBTU) Dry Wood Pellets 4.0 Pennsylvania Coal 8.7 Dry Wood 4.0 Utah Coal 6.0 Typical Hogged Fuel 4.5 Wyoming Coal 4.9 MSW 93.7 No. 2 Fuel Oil 0.0 Refuse Derived Fuel 28.1 No. 6 Fuel Oil 0.08 Natural Gas 0.0 Based on the data in Table 8-1, one might speculate about the potential for particulate emission problems in co-firing and perhaps reach the following conclusions: oO Boilers designed to burn coal can probably co-fire waste wood fuels without significantly increasing particulate emission levels. oO Boilers designed to burn wood fuels can co-fire coal fuels but in the process may expect some increase in particulate emission rates. oO Boilers designed to burn either waste wood or any of the fossil fuels can expect significant increases in emission rates when co-firing refuse based fuels. oO Boilers designed to burn waste wood, coal or refuse based fuels can expect to co-fire liquid fossil fuels or natural gas with a resulting decrease in particulate emission rates. The conclusions noted above are based solely on the ash content of the fuel. The data in Table 8-1 are limited to 11 typically used fuels and do not encompass all of the 119 The conclusions noted above are based solely on the ash content of the fuel. The data in Table 8-1 are limited to 11 typically used fuels and do not encompass all of the fuels which have been co-fired. However, it is not difficult to obtain ash analyses for fuels and considering the potential impact of fuel ash content on particulate emission rates, any plant site which proposes co-firing of fuels would be well advised to obtain fuel ash data and to evaluate the anticipated ash input rates based on the data. Particulate Emissions Due To Incomplete Combustion Incomplete combustion can result from many conditions and/or combinations of conditions including: Wet fuel Insufficient combustion air Improper mixing of the fuel and combustion air Low temperatures in the combustion zone O70)", OO. 20) Insufficient time for the combustion process to be completed Whenever any of these conditions occurs in the combustion zone, even on a transient basis, the combustion reaction will not be completed and products of incomplete combustion will be carried out of the furnace with the exhaust gas stream. The products of incomplete combustion may include both pollutant gases and particulate matter. The design of the combustion system certainly influences the degree to which the combustion process is completed. Some furnace designs when operated properly and well within the design envelope are recognized for their ability to burn fuels completely and to emit low concentrations of entrained particulate. Fuel cells, for example, fall into this category. Other furnace designs such as the water wall lined spreader stokers are not as effective in completing the combustion reaction in the furnace. Their design counts heavily on collecting any entrained unburned particulate 120 matter in pollution control devices downstream from the furnace. Some, but not all furnace systems include facilities to recycle the collected, combustible ash back to the burner through re-injection ports. Fuel moisture levels may be particularly important in their affect on completion of the combustion reaction in co-firing application. Probably the most infamous fuel to co-fire is sludge generated from either industrial or municipal waste treatment plants. Sludge is very high in moisture and low in heating value. When it is co-fired for disposal purposes, the high moisture level lowers the temperature of the combustion reaction thereby promoting incomplete combustion. The design envelope of a combustion system refers to the operating parameters of the system used in the initial design. The parameters include: oO The maximum steam generation rate specified at a given temperature and pressure oO The turn down ratio which is the ratio of the maximum steam generation rate to the minimum steam generation rate ° The temperature of the feedwater oO The maximum boiler drum blow down rate ° The acceptable range of levels of excess air ° The anticipated temperature of the combustion air. Once these parameters are specified, then coincidentally all of the design parameters for fuel flow rates, combustion air flow rates, and exhaust gas flow rates become specified. If any of the design parameters are exceeded in the operation of the boiler (furnace), then the system is said to be operating outside of its design envelope. The consequences of operating outside of the design envelope include possible combustion upset conditions, loss of efficiency, and in extreme circumstances, possible safety hazards including fire side and/or water side explesions. 121 Electric utility experience in co-firing RDF with coal has shown repeated problems of poor fuel distribution on grate and resultant smoking. This problem is essentially one of improper mixing of the air and fuel coupled with low temperatures in the immediate combustion zone. The overall result in terms of air pollution is an increase in particulate formation and emission rates. Certainly not all co-firing combinations are negative with respect to pollutant formation. Many firms in the wood products industry have co-fired fossil fuels (principally oil and gas) in systems designed primarily for hogged fuel use with the intent (and outcome) of increasing temperatures in the combustion zone and, thereby, improving the combustion conditions. It has proven to be effective in reducing pollutant emissions from unburned fuel. Time, temperature, turbulence (for mixing) and a proper ratio of fuel and air are critical to the completion of the combustion reaction and are, therefore, important to limiting the formation of products of incomplete combustion. Co-firing may be used to improve these operational parameters. Alternately, there are some co-firing applications which have been detrimental to the completion of the combustion process. But it is not just a case of which fuels are used or what their relative proportions are. Pollutant formation in co-firing is also dependent on the design of the furnace and on the operation of the system. Each fuel must be considered carefully to ensure that as it burns it has proper conditions of time, temperature, turbulence and fuel to air ratios. Particulate Collection Devices Thus far the discussion on particulate emissions has focused on emissions resulting from the non-combustible ash content of fuel and on emissions resulting from products of incomplete combustion of the fuel. But most combustion systems are equipped with particulate emission control devices. It is assumed (and the assumption is 122 probably valid) that as the pollutant concentration level entering the control device(s) goes up, the pollutant concentration level leaving the device also goes up. The discussion now turns to the question, “what is the influence of co-firing on the collection efficiency of particulate control devices?" First, consider the flow rate of exhaust gases through the control device. Collection efficiency for some of the particulate control devices depends on the flow rate of flue gas through them. This is the case with electrostatic precipitators, with inertial separators such as multiple cyclones, with some of the wet scrubber designs, and possibly with the gravel bed scrubber designs. But gas flow rate does not have much impact on the collection efficiency of fabric filter systems. So, if co-firing results in a significant increase in flue gas flow rates (or in a significant decrease in flow rates) and if the emission control system uses a baghouse, then there is likely to be no significant change in collection efficiency or in emission rates of particulate matter. If the collection system is based on other control devices and a major change in flue gas flow rates is predicted due to co-firing, then it would be well warranted to investigate the expected collection efficiency of the control device(s) under the new operating parameters to determine if allowable emission rates will be exceeded. Manufacturers of control devices generally can be helpful in conducting such evaluations. Second, consider the impact of co-firing on control device collection efficiency due to changes in the physical and or chemical characteristics of particulate matter. The collection efficiency of particulate emission control devices may be influenced by the physical and chemical properties of the particles suspended in the flue gas. For example, control devices which use inertial separation (e.g., multiple cyclones) are effective for large particle sizes and high particle densities but have low collection efficiency for small particles and low density particles. The collection efficiency of electrostatic precipitators (ESP) is strongly influenced by the electrical resistivity of particles. On the other hand, some emission control devices are not highly influenced 123 by particle characteristics. Baghouses (fabric filters) seem to work reasonably well for a very wide range of particle types, sizes, and densities, as do high efficiency wet scrubbers, gravel bed filters and sand bed filters. The message here is that if co-firing results in a significant alteration of either the physical or chemical characteristics of the particles carried in the flue gas, then a change in the collection efficiency of inertial collectors and of electrostatic precipitators should be expected. The collection efficiency of other control devices probably won’t be seriously affected. All of this is a bit complicated and may be difficult to keep in perspective. When attempting to determine how co-firing affects particulate emissions, there are so many variables that a simple answer is precluded. But in general the following conclusions are valid: oO Co-firing may increase or decrease the rate at which non- combustible ash enters the combustion system. When changes occur in ash input rates, it is reasonable to expect corresponding changes in emission rates of particulate. Accurate predictions of ash input rates can be made with relative ease based on fuel analyses and an understanding of the operating envelope for the system. oO Co-firing may improve combustion conditions in the furnace, or alternately may be detrimental to complete combustion. It depends on the fuels to be used, their proportions, the design of the furnace, and several other parameters. Where combustion is poor, additional particulate will be generated by incomplete combustion and emission rates from the system will increase. oO Co-firing may result in changes to the collection efficiency of particulate emission control devices. The efficiency may improve or decrease depending on such parameters as flue gas flow rates, physical/chemical character of the particles entrained in the flue gas and the design of the collection system. Collection efficiencies resulting from co-firing specific fuel combinations may be difficult to predict. oO In order to operate combustion facilities, plants must meet the allowable emission limitations for particulate. Since many plants 124 co-fire fuels in a wide variety of combinations, it is apparent that particulate emission limitations can be met with existing control technology and do not seriously hamper co-firing opportunities. GASEOUS EMISSIONS The gaseous products of the combustion process include non- pollutant compounds (nitrogen, carbon dioxide, oxygen, and water vapor) and compounds which are considered to be air pollutants. The air pollutant gases typically include: Carbon monoxide (CO) Unburned hydrocarbons (HC) Sulfur dioxide (SO,) Oxides of nitrogen (NO,) C8. OO The pollutant gases typically make up less than 1% of the total volume of the gaseous products of combustion for reasonably well operated systems. They are considered to be "primary pollutants" because they are generated at the plant site and emitted to the atmosphere. That distinguishes them from "secondary pollutants" which are those formed as a result of atmospheric chemical reactions involving the primary pollutants. Carbon Monoxide Of the gaseous primary pollutants from combustion processes, carbon monoxide and unburned hydrocarbons result from incomplete combustion. They are generated under conditions which do not provide one or more of the following: oO Adequate time for the combustion process to be completed oO High enough temperatures to initiate and maintain the combustion reactions 125 oO Sufficient turbulence to bring about complete mixing of the fuel and the oxygen in the combustion air stream oO A reasonable ratio of fuel to air to ensure that sufficient oxygen is available to burn the fuel. Note that the conditions which lead to incomplete combustion and the formation of pollutant gases are the same as those that lead to increased levels of particulate matter discussed earlier in the chapter. These conditions can occur in either single fueled combustion systems or in co-fired systems. And they are influenced by the same kinds of variables including: oO The design of the combustion system oO The operation of the combustion system inside (or outside) of its design envelope oO The characteristics of the fuels being burned Carbon monoxide (CO) is a parameter that is particularly important. In a well controlled combustion process, CO will be emitted in concentrations that range from 0.02 to 0.10 percent (200 PPM to 1000 PPM). The concentration can be measured accurately on a continuous and instantaneous basis and can be used as a control input variable to make minor adjustments in the fuel to air ratio to optimize the thermal efficiency of the system. Control of CO emissions is invariably accomplished through control of the combustion process. Down stream emissions control devices have not been used for industrial, utility, or commercial settings. However, CO emissions have not been identified as a source of major concern in the operation of co-fired facilities. Which is to say that the literature does not recount instances in which facilities (having once received their operating permits) have had to curtail or limit the operation of co-fired boilers (furnaces) due to exceeding allowable emission limitations for CO. 126 Unburned Hydrocarbons The same situation applies to emissions of unburned hydrocarbons (HC). The concentration of HC’s in the exhaust gas stream is controlled by regulating the combustion process rather than by down steam emission control devices. However, hydrocarbon concentrations in the flue gas are rarely measured. Generally they are not considered to be a problem area for either single fuel furnaces or for co-fired systems. The literature does not report cases in which co-fired facilities which have received their operating permits have had to curtail or to limit their production due to exceeding allowable HC emission rates. It is not usual for emission regulations to include specification of allowable concentrations of either CO or unburned HC’s in the flue gas. However, concern about the emission rates of these pollutant gases is revealed in the process of obtaining operating permits for plant sites. See Chapter 9 for information regarding Prevention of Significant Deterioration of Air Quality regulations in which it is noted that the annual total emission rates of each of the criteria pollutants (including CO and HC’s) must be considered in the application process. Sulfur Dioxide Sulfur dioxide is an oxidation product that arises from the sulfur content of fuel. Thus, the combustion products from any fuel which contains sulfur (even in very small quantities) will include some SO,. Most of the sulfur in fuel burns to form SO,. A small percentage of the sulfur content of the fuel may end up as sulfates or some other compound other than SO,,. Sulfur dioxide is one of the criteria pollutants recognized and controlled through the regulations promulgated and enforced by federal, state and local air pollution control agencies. There are several approaches that have been used to control it: 127 Limit the amount of sulfur in the fuel by burning principally low sulfur fuels Limit the total amount of sulfur burned in a boiler (furnace) by co- firing sulfur bearing fuels with non-sulfur or low sulfur bearing fuels Limit the total amount of sulfur burned in a boiler by limiting (derating) the steam generation rate of the system Pretreat the fuel to remove or reduce the sulfur content prior to burning Equip the boiler (furnace) with a flue gas de-sulfurization (FGD) system Burn the sulfur bearing fuel(s) in a fluidized bed combustion system in which the bed media (limestone or dolomite) adsorbs the SO, and thereby removes it from the flue gas. Essentially all combustion facilities used in the utility, industrial, municipal and commercial sectors are subject to federal and state (and in some cases local) regulations pertaining to sulfur dioxide emissions. Most of the regulations specify that once a permit has been issued to operate a combustion system, any significant modification to the system, including a change of fuel(s) which might result in alterations to the pollutant emissions from the system, requires a reconsideration of the operating permit. This is important with respect to co-firing and emissions of SO, and leads to the following options: % ° If co-firing will result in a reduced (or unchanged) sulfur input rate to a permitted facility, then it is likely that no changes will be made in the operating permit and no additional flue gas treatment will be required. If co-firing will result in an increased sulfur input rate to a permitted facility, then it is likely that steps will be required to control the emission rate of sulfur dioxide from the system. The options available for controlling the emission rate include those shown at the top of this page. For new, un-permitted combustion facilities, the permitting application requires a list of all of the fuels to be burned, an analysis of the total sulfur input rate from the fuels, an analysis of 128 the annual emission rate of sulfur dioxide, an analysis of the environmental impact of the sulfur dioxide as determined through the use of dispersion modelling techniques, and information on the design for control systems to limit the emission of sulfur dioxide to meet federal, state, and local standards. Thus, if a new facility is to co-fire fuels, and if any of the fuels to be co-fired contains sulfur, a thorough analysis of the system is necessary prior to permitting and the analysis may show that emission controls will be required. There have been some interesting situations regarding sulfur dioxide emissions in co- firing applications. In the early I970’s, a pulp mill near Portland, Oregon conducted experiments in which chopped up automobile tires were co-fired with hogged fuel in boilers designed initially to burn hogged fuel. The purpose of the tests was to see if the tires could be used as a competitive fuel source and to determine the impact of co- firing this fuel upon the furnace operation and upon the pollutant emission rate from the boilers. From an operational and economic standpoint, the test results all looked positive. However, the state regulatory authority would not issue a permit to co-fire the tires due to the sulfur content in the rubber. Calculations indicated that co-firing the tires would result in a significant and unacceptable discharge of sulfur dioxide to the atmosphere. Oxides of Nitrogen Oxides of nitrogen are comprised of two compounds, nitrous oxide (NO) and nitrogen dioxide (NO,). Both are formed in the combustion process, however, most flue gas streams contain higher concentrations of NO than of NO,. Once these compounds are emitted to the atmosphere, they undergo atmospheric chemical reactions which change their relative proportions. As a handy means of keeping track of the total, NO and NO, are usually combined and considered under the general category of NO,. The nitrogen to form NO, can come from the fuel. Some fuels have nitrogen as part of the elemental composition of the fuel. It is generally assumed (and supported by experimental test data) that most of the nitrogen in fuel oxidizes during the combustion 129 process to form NO,. The higher the fuel nitrogen level, the higher the expected NO, level on pretty much a linear scale. Nitrogen can also come from the combustion air supply. Air contains approximately 79% nitrogen by volume and a portion of that nitrogen can oxidize to form NO, if the combustion temperature reaches levels of 2600° F or higher. Some fuels burn with high temperatures, sufficiently high to result in the oxidation of atmospheric nitrogen to form NO,. Fuels which have high heat content are more likely to burn with high combustion temperatures than fuels with lower heat content. Oxides of nitrogen have been and continue to be of major concern from an environmental standpoint. Since combustion systems are the principal source of this gaseous pollutant, they come under particular scrutiny by regulatory agencies. The control techniques which have been satisfactorily used for stationary combustion systems (excluding internal combustion engines) include: oO Staging the combustion reaction by limiting the flow of oxygen to the fuel. This is accomplished by separating the combustion air stream into two or more air inlet points and controlling the flow rate of air at each point so that the desired combustion temperatures are maintained. oO Cooling the combustion reaction by using high levels of excess air. oO Recirculation of a portion the flue gas back to the combustion chamber to limit the oxygen supply the combustion chamber and thereby limit peak flame temperatures. oO Treating the flue gas by passing it through a selective catalyst which reduces the NO, and lowers its concentration in the exhaust gas stream. Selective catalytic reduction is a relatively new technology which has not been widely used in the United States. It has been used in some commercial applications in Europe and in Japan. oO Injecting ammonia into the flue gas. Ammonia reacts with NO, and reduces the concentration emitted to the atmosphere. Ammonia injection is being used in commercial operations in California and is proposed for used in Washington and Oregon. 130 The implications of NOx with respect to co-firing of fuels are similar to those regarding emissions of sulfur dioxide. The options appear to include the following: Oo If co-firing will result in a reduced (or unchanged) nitrogen input rate to a permitted facility, and further will not result in significant increases in peak combustion temperatures in the boiler (furnace), then it is likely that no changes will be made in the operating permit and no additional control technology will be required. If co-firing will result in either increased nitrogen input rates to a permitted facility or in increased combustion temperatures in the boiler (furnace), then an engineering evaluation to determine the environmental impact due to co-firing may be required. If the impact study indicates the potential for significantly increased emission rates of NO, and detrimental impact to the air shed, then emission controls may be required before the operating permit will be re-issued. The options available for controlling NO, include those listed at the top of the previous page. For new, un-permitted combustion facilities, the permitting process will have to be followed in full, including a list of all fuels to be burned, an analysis of the fuel nitrogen content and subsequent estimates of the fuel related NO, emission rates on an annual and peak basis, estimates of the emission rates of temperature related NO,, evaluation of environmental impact of NO, emissions as determined through the use of dispersion modeling techniques, and information on the control technology to be used to limit the emissions of NO, to meet federal, state, and local standards. These requirements apply to most new, un-permitted combustion facilities regardless of whether or not they intend to co-fire fuels. A final comment regarding oxides of nitrogen: commercial manufacturers of oil and gas burner systems and of coal burning boilers are very cognizant of EPA regulations on NO, emissions and of the combustion technology and pollutant emission control technology available to meet the federal requirements. 131 LIQUID WASTES Co-firing of fuels may have some impact on the type and quantity of liquid wastes generated at specific plant sites. Almost all plants with combustion facilities will generate some liquid waste streams regardless of whether or not co-firing in practiced. However, where co-firing is practiced it may alter the quantity and/or the quality of liquid waste streams generated from three parts of the operation: oO Fuel receiving, storage and reclaim facilities oO Ash handling facilities ° Air pollution control devices Fuel Receiving, Storage and Reclaim Facilities With the exception of natural gas, fuels which are co-fired must be received and stored in appropriately designed facilities for each plant site. The majority of the fuels which are co-fired are stored in enclosed facilities and are not subject to rain and subsequent liquid runoff. The notable exception is waste wood based fuel (particularly hogged fuel) which is often stored outside in uncovered fuel yards. Coal is stored in a similar fashion at some plant sites. (See footnote’.) The position of most state regulatory agencies is that liquid runoff (leachate) from fuel storage piles must be treated prior to discharge into sewers or receiving waters. This applies also to liquids resulting from washdown operations on any of the facilities for receiving, storing and/or reclaiming the fuels. Treatment is typically limited to control fs Liquid wastes found in the refuse based fuels (MSW and RDF) are usually absorbed by the paper and cardboard portions of the fuel during processing and, therefore, do not seem to pose a problem in terms of liquid runoff. Since refuse based fuels are typically stored in covered facilities to avoid problems with wind blown material and odors, rain does not have any impact on leachate runoff from these fuels. 132 of biochemical oxygen demand (BOD,), total suspended solids, pH, and color. The control technology is well developed and commercially available. Ash Handling Facilities Bottom ash collected in boilers (furnaces) may be mixed with water and conveyed as a slurry to clarifiers or to receiving ponds. It is one of the options used in ash handling systems. Fly ash collected in air pollution control devices may also be slurried with water and pumped to clarifiers as part of the water recirculation system for the pollution control device. Where either of these options is employed, some cleanup of the water is required before it may be discharged to sewers or receiving waters. Treatment, as in the case of fuel facility runoff, typically centers around BOD reduction, PH control, removal of suspended solids and color. Where co-firing of fuels is used, it may result in changes to either the quantity of ash or to the characteristics of the ash entering the combustion system and, thereby, may have some impact on the level of treatment required for liquids involved in ash collection and disposal. As an example, regarding the co-firing of coal and RDF, the EPRI publication, "Guidelines for Co-Firing Refuse Derived Fuel in Electric Utility Boilers," reports in Volume 2, Chapter 7 (Copyright Electric Power Research Institute 1988 - Reprinted with permission): Changes in liquid wastes resulting from RDF co-firing should be anticipated for the ash handling system, air heater washing, and ash pond operation. The amount and nature of these changes are site- and unit-specific. At Rochester, where bottom ashes are hydraulically conveyed, it was observed that water quantity increased and alkalinity increased by about |.8 pH units. The change in alkalinity of water used for bottom ash slurries and for fly ash collection and transport has been noted at several plants which were designed and operated for coal and which subsequently co-fired coal and wood based fuels. The raised pH level is considered as a side benefit to co-firing wood with coal. 133 Air Pollution Control! Devices Earlier in this chapter the potential impacts of co-firing fuels on particulate and gaseous pollutant emissions are summarized. It should be clear from the discussion that co- firing may result in changes in the emissions rates for both particulate and gaseous pollutants and, therefore, may necessitate changes in the design and/or the operation of air pollution control devices. Some of the pollution control devices, for example, wet contact scrubbers, venturi scrubbers, wet electrostatic precipitators, and slurried limestone injection systems for flue gas de-sulfurization necessarily involve liquid streams which contain wastes. Thus, co-firing of fuels may bring about some change in the liquid waste streams from air pollution control devices. Cleanup requirements for these liquid wastes are generally the same as those required for liquid runoff from fuel piles and for water used for ash collection and slurry. The technology is well developed and commercially available. Additional Comment on Liquid Wastes The liquid wastes generated at typical boiler sites also include boiler blowdown, boiler condensate, plant washdown water, liquid chemical spills, human sanitary wastes, and others. These liquid wastes, of course, are subject to treatment as required by various federal, state and local regulations. However, the flow rate and content of these waste streams usually are not influenced by the practice of co-firing fuels. The majority of plant sites attempt to treat liquid waste streams through integrated system design which attempts to maximize the amount of recirculation and to minimize fresh makeup water requirements. An obvious advantage is that this also minimizes the total effluent from the plant and, therefore, the total treatment costs for liquid effluent. 134 TOXIC AND HAZARDOUS EMISSIONS The combustion process may lead to the formation of toxic and hazardous substances. Incomplete combustion of fuels, for example, can generate compounds such as benzo-a-pyrene which is known to be carcinogenic (cancer causing). Fuels which contain the element chlorine, such as polyvinyl chloride plastics, may form polychlorinated biphenyls (PCB’s), polychlorinated dibenzo-dioxins (PCDD) and/or polychlorinated dibenzo-furans (PCDF) as products of incomplete combustion. PCB’s, dioxins and furans are considered to be toxic, carcinogenic substances. Many fuels contain trace elements of heavy metals and other toxic materials which are released to the atmosphere during combustion but not necessarily as products of incomplete combustion. Lead, arsenic, antimony and mercury are frequently pointed out as air contaminants that may be released during the combustion of coal, municipal solid waste (including RDF) and some of the industrial wastes. Asbestos is also commonly found in MSW and RDF as well as other waste streams and may become air borne through the combustion process. Nickel and cadmium, components of dry cell batteries, fall into the same category. Thus, toxic and potentially hazardous compounds may be found in measurable quantities as components of the exhaust gas stream. Their presence may be attributed to incomplete combustion. On the other hand, their presence may be due to the existence of toxic substances as constituents of the fuel which are then released to the atmosphere during combustion. An obvious question arises: "Does co-firing contribute to the release of toxic and or hazardous substances?" A logical response to the question is that co-firing may contribute to the release of toxic and or hazardous substances if any of the fuels co- fired are subjected to poor combustion conditions which lead to incomplete combustion or if any of the fuels co-fired contain toxic and or hazardous components which can be released during combustion. In one sense, this answer should be 135 reassuring and in another sense it may be cause for concern. In either case, additional comment is warranted. Concerning products of incomplete combustion which might be categorized as toxic or hazardous materials: Information presented in Chapters 3, 4 and 6 should convince the reader that there are many existing combustion facilities which are satisfactorily co- firing a wide variety of fuels. Adequate technology exists to bring about sufficiently complete combustion of these co-fired fuels to limit the emission of products of incomplete combustion to acceptable levels. Further, gaseous and particulate pollution control devices are used on many combustion systems and these devices further limit emissions of products of incomplete combustion. So the emission of toxic materials due to incomplete combustion in co-firing fuels should not be a problem. There is adequate combustion control and emissions control technology available to avoid the problem. If any of the fuels co-fired contain toxic and or hazardous components which can be released during combustion, it is safe to assume that they will be released but not necessarily to the atmosphere as airborne pollutants. Recall that materials entering the combustion chamber may follow a variety of alternative routes. They may: oO Undergo chemical oxidation to form non-toxic substances ° Remain in their initial chemical state and be removed as bottom ash collected from the system oO Remain in their initial chemical state and be removed as particulate matter collected in dry pollution control, devices oO Remain in their initial chemical state and be removed as particles or as liquids collected in wet scrubbers oO Remain in their initial chemical state and be emitted to the atmosphere as toxic particulate matter or gas. 136 Exactly how much of a particular toxic material takes which of these alternative routes cannot be predicted. What exactly are the toxic materials to be concerned about? A few have already been mentioned: lead, arsenic, antimony, mercury, asbestos, nickel and cadmium. According to a November 1988 article published in the International Journal of Air Pollution and Waste Management, Vol. 38, No. 11, entitled "State and Federal Air Toxicity Developments: Disclosure Strategies Overtake Regulations" by Michael Levin (reprinted with permission): In 1987, EPA estimated that there were over 60,000 chemicals in significant commercial or consumer use in this country, and at least 15,000 of these should be assessed for toxicity. Fewer than 1,000 have been so assessed, and EPA has taken regulatory action on less than three dozen.... This strongly suggests that the list of toxic materials is apt to grow significantly in the future and that owners and operators of combustion facilities will be faced with increasing requirements to monitor and control emissions of toxic substances. The trend is established as noted in an October 1987 article published in Power Magazine entitled "Traditional Control Processes Handle New Pollutants" by Jason Makansi. The byline of the article says (reprinted with permission): Permitting of refuse-fired steam generators now includes control of emissions of heavy metals and products of incomplete combustion in addition to particulates and acid gas. The industry responds with process innovations, many from overseas, for conventional pollution control systems. An important side issue relative to toxic and hazardous wastes relates to the disposition of bottom ash and collected fly ash from combustion systems. EPA has struggled in recent years with the question of whether or not to designate collected ash as hazardous material. At the time of this writing, it appears that the federal 137 agency is heading toward a decision not to designate collected ash as hazardous. However, the matter has not been settled completely. No mention has been made concerning amounts or quantities of toxic materials which are considered to be acceptable or not acceptable. This is a particularly difficult question area. Michael Levin’s article on "State and Federal Air Toxicity Developments:..." comments: .... fundamental questions are raised by the nature of the air toxics universe. Because of that universe’s size, flux and variability, neither toxic emissions nor their effects are very amenable to uniform chemical- by-chemical regulations based on feasible control technology. ... EPA’s experience demonstrates different approaches appear to be required. The article explores this question in depth, and interested readers are urged to review it. Be forewarned, however, that it includes no definitive emission limits on toxic substances because for the most part, they have not been established. The toxic and hazardous substances issue is potentially of great concern for plants which co-fire fuels. However, it should be noted that for many commonly co-fired fuels, there is presently little concern over the toxics issues. Toxics are not considered to be a problem with the most of the waste wood fuels, nor the liquid fossil fuels and certainly not with natural gas, propane, or butane. While there is growing concern over toxic emissions due to firing coal, to date there has been relatively little pressure exerted on plants which fire coal either to monitor emissions for various toxic components or to control such toxic emissions as might be present. The refuse based fuels and industrial wastes, on the other hand, have been subject to close scrutiny over the issue of toxic substances and it is likely that regulatory pressure will increase in this regard. 138 SUMMARY OF ENVIRONMENTAL CONSIDERATIONS ASSOCIATED WITH CO-FIRING For purposes of discussion, the environmental concerns associated with co-firing fuels have been divided into four categories: 1) Particulate emissions 2) Gaseous emissions 3) Liquid wastes 4) Toxic and hazardous emissions. Particulate emissions may emanate from the non-combustible ash content of the fuel or may be formed due to incomplete combustion. The input rate of the non- combustible ash due to co-firing can be estimated based on the ash characteristics of the fuels to be fired and their relative quantities. Particulate emissions generated by incomplete combustion are difficult if not impossible to estimate. They depend on too many variables. Fortunately, the parameters which control the completeness of the combustion reaction are fairly well understood and, thus, formation of these particulate pollutants can be minimized. Co-firing may improve combustion conditions, or, alternately may detract from combustion and result in increased pollutant formation. Time, temperature, turbulence and proper fuel to air ratios are all important aspects of completing the combustion reaction. The collection efficiency of particulate emission control devices may be influenced by co-firing due to changes in gas flow rates through devices and/or changes in the physical/chemical characteristics of the particles themselves. The collection efficiency of some devices is more strongly influenced by these factors than the collection efficiency of other devices. An engineering evaluation of any possible efficiency effects due to co-firing is recommended if there is any question about the ability of the system to comply with allowable emission rates. The gaseous pollutants of concern in co-firing include carbon monoxide, unburned hydrocarbons, sulfur dioxide, and oxides of nitrogen. The first two (CO and HC) are 139 products of incomplete combustion and are most easily controlled through proper regulation of the combustion parameters (time, temperature, turbulence, and proper fuel to air ratios). They are potentially influenced by co-firing only to the extent that co- firing improves or detracts from the completion of the combustion process. Sulfur dioxide is formed from the oxidation of any sulfur which enters the combustion system with the fuel. Thus, if sulfur bearing fuels are co-fired, SO, will be emitted as an air pollutant. There are several strategies for control of SO, which are well proven. Oxides of nitrogen are also oxidation products of the combustion process. Nitrogen may be provided by the nitrogen component of the fuel(s) burned. Nitrogen may also come from atmospheric nitrogen if the combustion zone temperatures exceed 2600° F. Control strategies are available to limit emissions of NO,. With respect to co-firing, NO, may be of concern if the fuel(s) co-fired have a high fuel nitrogen content and/or if the combustion process is carried out at high temperatures which permit the oxidation of atmospheric nitrogen. Commercial manufacturers of oil and gas burners and of coal burning boilers are very cognizant of federal regulations on NO, emissions and of the technology available to meet the standards. Liquid wastes are generated at most combustion facilities. Some of the liquid waste streams may be influenced as a result of co-firing fuels. The text explores liquid wastes tied to: |) Fuel receiving, storage, and reclaim facilities 2) Ash handling facilities 3) Air pollution control devices. Rainwater runoff, leachate from outside fuel storage piles, and cleanup water from fuel handling facilities are regulated and subject to treatment. Some bottom ash handling systems use water slurries to transport collected ash to receiving points. Similarly, wet scrubber systems use water to collect fly ash and transport it to receiving points. In each case the liquid streams must be treated prior to entering receiving waters. Wet scrubbers and some other designs of gaseous emissions control devices also have 140 liquid waste streams which require treatment. Since co-firing can very well influence the existence and nature of fuel piles, fuel receiving and handling equipment, the composition and quantity of bottom and fly ash, and the gaseous emissions from a combustion system, co-firing, therefore, may well influence the liquid waste streams of a plant site. Typical requirements for liquid waste treatment are noted. Toxic and hazardous materials may come from two routes in co-firing: 1) They may be formed through incomplete combustion; or 2) They may result from toxic or hazardous materials which are inherent in the fuel prior to combustion. Examples of toxic compounds formed through incomplete combustion are PCB’s, dioxins, furans, and benzo-a-pyrene. Examples of toxic materials in fuels include lead, arsenic, antimony, mercury, asbestos, nickel and cadmium. Where toxic materials result from poor combustion, they can be reduced or eliminated by improving the combustion conditions through better control of the parameters of time, temperature, turbulence, and proper fuel to air ratios. Toxics which enter through the fuel stream are more difficult to control and, in fact, their fate once they enter the combustion system is very difficult to predict. Fortunately, in the case of most of the fuels which are co-fired, toxic emissions are not considered to be a major source of concern. The notable exceptions to this include industrial wastes and the refuse based fuels (MSW and RDF). 141 CHAPTER 9: ENVIRONMENTAL REGULATIONS PERTAINING TO CO- FIRING Combustion facilities may be subject to a long list of regulations enforced at the federal, state, and local levels. In this chapter emphasis is placed on those regulations specific to co-firing. In addition a brief summary of pertinent federal and state regulations affecting combustion facilities is provided along with recommended additional references. First, the references. SOURCES OF INFORMATION One of the best overall references concerning environmental regulations which affect combustion facilities is the Biomass Energy Project Development Guidebook. Published in July, 1987, this book was authored by Vranizan, J. et al and is available through the Bonneville Power Administration. While it’s emphasis is on biomass fuels, Chapter 5, Environmental Considerations, offers an excellent overview of federal and state regulations pertinent to a broad range of combustion facilities including those which are co-fired. The Pacific Northwest states (Oregon, Washington, Idaho, Montana, and Alaska) have each prepared and published guidebooks which outline the permitting requirements for construction and operation of biomass based energy facilities. These monographs identify pertinent regulations at the federal, state, and local levels which may have an impact on not only biomass fired facilities but on other combustion facilities as well. The monographs may be identified as: ° Guide to Oregon’s Environmental Permits for Biomass Energy Projects, prepared by Miles, T. R. et al, October, 1984, available through the Oregon Department of Energy, Portland, Oregon ° Guide to Washington’s Permits for Biomass Energy Projects, prepared by Simpson, S. J., June, 1988, available through the Washington State Energy Office, Olympia, Washington 143 ° Permitting Guidebook for Bioenergy Projects in the State of Idaho, prepared by CH,M-Hill, November, 1986, available through the Idaho Department of Water Resources, Boise, Idaho oO Montana’s Bioenergy Project Permitting Guidebook, July, 1986, available through the Montana Department of Natural Resources and Conservation, Helena, Montana oO Biomass Permit Handbook, prepared by the Alaska Power Authority, May, 1986, available through the Alaska Power Authority, Anchorage, Alaska The regional offices of the Environmental Protection Agency throughout the country and the various state offices with enforcement authority over environmental regulations are always good sources of information. They are equipped to provide copies of pertinent regulations and to answer questions that may arise about the interpretation and the enforcement of regulations. Further, they can assist in providing necessary official forms and guidance for filling out the various forms. FEDERAL LAWS AND REGULATIONS PERTINENT TO CO-FIRING Federal laws and regulations which pertain to co-firing extend over a rather wide range of topics including air pollution, water pollution, solid waste, toxic and hazardous substances and others. The principal acts and regulations are summarized in _ Table 9-1. The interplay of the various federal regulations and specifically how they might impact a plant site that proposes to co-fire fuels is quite site specific and can only be determined after a thorough and careful review of each of the regulations. 144 TABLE 9-1 Summary List of Federal Laws and Regulations Which May Apply to Construction and Operation of Combustion Facilities. Federal Clean Air Act Prevention of Significant Deterioration of Air Quality (40 CFR 52) New Source Performance Standards NSPS (40 CFR 60) Federal Clean Water Act National Pollutant Discharge Elimination system (NPDES) Section 404 and the River and Harbors Act Section 10 National Environmental Policy Act (NEPA) Federal Resource Conservation and Recovery Act (RCRA) This law governs federal and state air pollution programs. The U.S. EPA administers the act and establishes regulations pertinent to air quality. One of the many areas in which EPA is involved is the establishment of National Emission Standards for Hazardous Air Pollutants (NESHAPs). Regulations promulgated by EPA which govern the issuance of operating permits for new and/or modified combustion facilities (as well as other facilities). Restricts allowable emissions of particulate, and gaseous pollutants from specific categories of sources including industrial steam generating plants, municipal waste to energy facilities, and others. Regulations dealing with NSPS are promulgated by EPA. Governs discharges of all point sources liquid effluents. EPA administers the Act and promulgates regulations under the Act. Requires a permit for any point source discharge into surface waters. Requires permits for any dredging, filling and other construction activities on navigable waterways. May trigger federal environmental review pursuant to the National Environmental Policy Act. Can require substantial efforts such as determination of projected socio-economic impacts and endangered species review for sizeable projects prior to the issuance of a permit to construct. Requires substantial reporting and control of toxic and hazardous substances including liquid and solid wastes. Can trigger an environmental review pursuant to NEPA. It is interesting to note that rarely do any of the regulations mention co-firing. The only recent instance of federal recognition of co-firing in regulations was EPA’s modification 145 to the New Source Performance Standards (NSPS) for fossil fuel fired steam generating plants. Early in 1987, EPA increased the allowable emission rate for coal fired boilers which are used to co-fire refuse based fuels or wood based fuels. The particulate matter emissions limit is 0.05 Ibs of particulate per million BTU’s of heat input for coal fired boilers and for coal/wood- and coal/refuse-fired boilers where the non-coal fuel is used to produce under 10% of the steam generating capacity. The emission limit is raised to 0.10 Ibs per million BTU’s for co-fired boilers where the non- coal fuel’s contribution is greater than 10%. While co-firing is not specifically mentioned in the federal regulations, it is hinted at. One of the phrases that is oft repeated in environmental regulations is ".....construction of or major modification to...."._ In regard to combustion systems, the implication is that a change or alteration in the kind of fuel used to fire a facility which would result in significant change in the quantity or quality of pollutants emitted to the environment, would constitute a major modification to a plant site. Major modifications, from a regulatory standpoint, usually require a thorough re-evaluation of the plant operating permit(s), an involved and often costly exercise both in time and financially. This is not to suggest that all plants which might undertake co-firing necessarily would be required to have their operating permits re-evaluated. Bult it is certainly a possibility for some specific fuel types, notably for plants which are considering co-firing MSW or RDF. These fuels are subject to more rigorous evaluation because of their potential to emit heavy metals and other toxic compounds. STATE ENVIRONMENTAL REGULATIONS Most states work very closely with the federal enforcement agencies in environmental matters and have developed state environmental regulations which dovetail with federal regulations in the areas of air pollution control, water pollution control and solid waste management. The regulations which have been adopted at the state level (and at the regional/local levels) typically complement the federal regulations and extend them to 146 deal with the more local and/or regional environmental concerns. Volume 1 of the EPRI report, "Guidelines for Co-Firing Refuse Derived Fuel in Electric Utility Boilers", (Copyright Electric Power Research Institute, June, 1988. Reprinted with permission.) offers a summary list of environmental issues that typically must be addressed at the state and local levels when considering a co-fired utility plantsite: State: oO Wastewater discharge to state waters must satisfy the requirements of the National Pollution Discharge Elimination System (NPDES) oO New sewer lines oO Increased use of surface or groundwater oO Air permits for boiler stack emissions oO Air permits for solid waste process and handling facilities oO Impact on resource value of land oO Impact on state wetlands oO Impact on archaeological and historical land resources oO Oil storage tanks oO Plumbing connections and well connections oO Power plant ash pond leachate (may also require a local permit) Local: oO RDF plant zoning permit oO Wastewater discharge to local treatment plant oO Construction permits oO Impact on waste management disposal plan 147 oO Impact on local terrain drainage ° Roadway access ° Vermin and insect control State environmental regulations do not make specific mention of co-firing or attempt to establish regulations specific to co-fired facilities. There is one exception. The State of Idaho regulations pertaining to Prevention of Significant Deterioration of Air Quality (PSD) identify "...Combined fossil and biomass boilers totaling more than 250 million BTU’s per hour heat input...." as being subject to PSD provisions. This is not to suggest that co-fired facilities are unregulated at the state level. With respect to the air quality regulations, most states have opted to regulate combustion facilities according to their size based on heat input rates, or according to the kind of fuel used (for example, coal fired plants, municipal waste incinerators, liquid fossil fuel fired boilers, etc.) Thus, most co-fired plants will fall somewhere within the purview of state regulations on air quality. 148 SUMMARY COMMENTS The environmental regulations that may be applied to specific plant sites which intend to co-fire fuels are highly complex and involve many agencies at the federal, state, and often at the local level. They cover the general areas of air pollution control, water pollution control, solid waste management, and toxic and hazardous substances. But they may extend into other areas such as preservation of wetlands, archeological resources, coastal zone management, etc. There are very few regulations which specify "co-firing". Most of the applicable regulations encompass co-firing applications by virtue of being combustion/fuel burning facilities or through some alternative mechanism. For some plant sites, the myriad of regulations is an onerous burden which may consume extensive time and financial resources. However, that situation certainly does not apply to all plant sites. It should be apparent, based on the data presented in Chapters 3 and 4, that many plant sites have successfully integrated co-firing operations. For additional information on which regulations may affect co-fired plants, readers are encouraged to review the references noted at the outset of this chapter. 149 CHAPTER 10: ECONOMIC CONSIDERATIONS IN CO-FIRING The decision to co-fire fuels is often based principally on economic incentives. There are, of course, other incentives as noted in Chapter 2. The strength of the economic incentives can be determined by analyzing alternative scenarios for co-firing. This may involve some considerations which are not normally included for single fueled plant sites. The usual categories considered in an economic analysis of a plant site include: oO Return on equity invested in capital ° Service of debt invested in capital ° Depreciation oO Income taxes oO Property taxes oO Insurance oO Fuel costs oO O & Mcosts oO Income received When co-firing is considered there are additional subcategories that may influence the economic picture. Volume | of "Guidelines for Co-Firing Refuse Derived Fuel in Electric Utility Boilers" (EPRI CS-5754, copyright Electric Power Research Institute, June, 1988. Reprinted with permission.), provides a summary of important issues which should be inctuded in an economic analysis of utilities which co-fire coal and RDF. It’s an appropriate summary list which, with minor additions, can be generally applied for economic analyses of co-fired facilities outside of the electric utility industry. EPRI’s summary is divided into the following four general areas: 151 oO Power plant co-firing operating expense oO Fuel replacement value oO Debt service oO Risk compensation One additional area is worth considering and that is the overall operation of the facility. Each of these 5 areas should be carefully reviewed before reaching conclusions about the economics of co-firing. OVERALL OPERATION OF THE FACILITY Economic analyses of power plant options tend to focus on the economics of making steam and/or generating electricity and may, through oversight, ignore important economics concerns in "the big picture". Some examples may help to illustrate this and provide useful guidance: ° Many manufacturing operations incur significant expense in landfilling combustible wastes which might be co-fired for energy recovery. Manufacturing waste disposal expense is not normally part of the budget for power plant operations. However, the economic analysis of co-firing options for such plant sites should extend beyond the accounting limits of the boiler room and include the avoided cost of landfilling the waste. This is true generally. Wherever co-firing applications result either in avoided cost or increased cost for the overall operation of a municipality, a manufacturing plant site, an institution, a military installation, or an electric utility, the costs should be included in the economic analysis. oO Projects in which co-firing is proposed for an existing facility may involve significant disruptions to the overall operation of a site during the construction period and the startup period. It may even require significant change in the long term operation of a facility in order to accommodate fuel storage, fuel deliveries, etc. Wherever 152 these disruptions may influence financial aspects of the overall operation of the plant site, either positively or negatively, they should be taken into account in the economic analysis of co-firing options. POWER PLANT CO-FIRING OPERATION EXPENSE Within the boundaries of steam plants and/or power generating plants, economic analyses of co-firing options should include the following specific considerations: oO Changes in plant fuel expense oO Changes in boiler efficiency oO Changes in plant power requirements ° Changes in system maintenance expense oO Changes in operating labor expense oO Changes in operating expense associated with changes in peak steam generating capacity Changes in Plant Fuel Expense This is often the focal point of proposals to co-fire fuels since the cost of fuel burned is a major factor in the overall expense of operating any boiler. The basis for determining the cost of fuel burned needs to be clearly established in carrying out an economic analysis. To illustrate this, consider three differing scenarios: oO A manufacturing plant generates industrial wastes which can be co-fired for energy recovery but which are currently being landfilled. Under this circumstance, it might be well to consider the cost of the waste fuel as $0.00. The avoided landfill cost will be taken into account under the category of "Overall Operation of the Facility" noted above. Costs associated with receiving, storage and reclaim of the fuel and with fuel preparation will be taken into account under cost items noted below in the following discussion. 153 It is important not to confuse the "value of the fuel" with the "cost of the fuel". The waste fuel may indeed have value by virtue of replacing some or all of the purchased fossil fuels used at a plant site. But the actual purchased cost of the waste fuel at the plant site is $0.00. oO An electric utility buys coal as its primary fuel. The utility is asked to consider burning RDF as a service to the local municipality. The municipality agrees to pay the utility to burn the fuel recognizing that the utility will have increased costs associated with burning the RDF. Most utilities involved in this or similar scenarios place a value on the fuel equivalent to the cost of BTU’s in coal which are replaced by the RDF. The subsequent economic analyses take into account the myriad of other expenses associated with co-firing RDF and coal to come to an agreed price that will be paid to the utility to burn the RDF. (See additional comment below under the topic of Fuel Replacement Value). oO A university burns coal in a central heating plant to make steam for space heating. Local dealers of densified wood fuel offer their product as a supplementary fuel to be co-fired with coal in the existing boilers. In this scenario, the cost of fuels is established by what the university pays for them delivered at the plant site. Any other costs will be accounted for in other parts of the overall economic analysis. Changes in Boiler Efficiency Boiler thermal efficiency is an important parameter needed to determine fuel use rates. As efficiency improves, fuel use decreases and vice versa. Efficiency changes with the fuel used and the operating conditions under which each fuel is burned. 154 Efficiency calculations are outlined in Chapter 7 using the heat loss method adopted by ASME. These calculations should be carried out for each co-fired fuel as an important step in the overall economic analysis. Changes in Plant Power Requirements In-plant power requirements may be influenced by co-firing. The specific areas which are most apt to be influenced are: oO Fuel receiving, storage, and reclaim oO Fuel preparation oO Bottom ash collection and handling oO Air pollution control devices Power requirements do not necessarily increase with co-firing. There are scenarios in which power requirements may decrease as a result of co-firing. Whether they are expected to increase or decrease, they should be considered as part of the economic evaluation of co-firing. Changes in System Maintenance Expense The components of co-fired systems must be adequately maintained. This requires expense for labor and for materials which should be included the economic analyses. For most plant sites, maintenance expenses for co-firing will be larger than for single fueled operations because co-firing necessarily involves more plant equipment. Changes in Operating Labor Expense Co-firing may bring about increased labor expense for supervision, plant engineering, unit operators, and startup crews depending upon the complexity of the overall 155 system. Any anticipated additional labor related expense should be incorporated into the economic analysis. Changes in Operating Expense Associated with Changes in Peak Steam Generating Capacity Derating of boilers may result when some fuels are co-fired. This is discussed in Chapters 6, 7 & 8. Derating or forced reduction in the steam generation rate can result if the flow rate of combustion gases exceeds the design capacity of the forced draft fans, induced draft fans, air preheater, pollution control devices, or other components of the system. Derating may also result from reduced heat transfer brought about by slag buildup on heat transfer surfaces in either the steam generator or superheater tubes. Limitations in the ash handling capability of the system can also bring about boiler derating. The cost/expense associated with derating should include complete consideration of the consequences of reduced steam generation capacity. For utility applications, reduced capacity may require power replacement at or above market rates in order to meet peak load requirements of customers. For manufacturing and other operations, the consequences of reduced steam generation capacity may range from negligible to significant disruption of plant operations. On the other hand, co-firing may bring about increased steam generation capacity. This is one of the justifications noted in Chapter 2. Where this situation occurs, it may have very positive economic benefits. For example, increased steaming capacity resulting from co-firing the right combination of fuels could offset or perhaps delay a need for constructing additional boiler capacity. The important point here is that at most plant sites, the peak steam generation capacity of boilers has significant potential impact on the economic operation of the plant. Whether co-firing may improve peak steaming capacity or result in boiler 156 derating, the economic consequence should be considered in the overall economic analysis. FUEL REPLACEMENT VALUE Calculations of the replacement value of fuel are critically important in the analysis of co-fired electric utility plants. Typically the goal is to set a justifiable and reasonable price on refuse based fuels which the utility burns. The price which a utility is paid to co-fire RDF is set so that the busbar electricity cost remains the same as for firing the plant with coal only. The February, 1987 edition of Power Magazine carried an article by Dave Ege entitled “When It’s Economic to Co-fire Refuse Derived Fuel with Coal". At the conclusion of the article, the author presents an important argument (reprinted with permission) concerning fuel pricing and utility incentives to co-fire RDF. The argument hinges on the price set for replacement value of fuels. ",...consider the incentives for the utility to be in the municipal waste business. The solid waste disposal area is not the.same as the utility’s service area. If the utility profits from the RDF fuel, then those electric customers that are in the solid-waste area are being penalized by the utility. On the other hand, if the utility performs the waste disposal as a public service and loses money at it, then the electric customers outside the solid waste area are similarly penalized. This means that, from a regulatory commissioner’s point of view, any transaction between a municipal solid waste district and a utility should be a break even proposition in both directions to be completely fair to all of the customers concerned. This appears to remove all incentives to the utility to be in the waste business. This factor should be considered completely separately from other portions of the problem. " Readers interested in additional information on utility pricing of RDF will find Volume 3 of "Guidelines for Co-Firing Refuse Derived Fuel in Electric Utility Boilers" (EPRI CS- 5754, copyright Electric Power Research Institute, June, 1988) to be a valuable resource. 157 In sectors other than the electric utility area, calculations of the replacement value of fuels are not apt to be beneficial in economic evaluations of co-firing alternatives. For most facilities, the fuel value will be established by the market price of the purchased fuel. (See discussion above under the topic of Changes in Plant Fuel Expense.) DEBT SERVICE The capital cost of modifying a combustion facility to accommodate co-firing can be borne either through equity capital or debt. That’s an accounting matter, of course. And any reasonably thorough economic analysis of co-firing options will automatically include costs associated with servicing the debt. The important point here is to include in the economic analysis all of the capital costs associated with the project. Particular things to look for are: oO Additional real estate required (for fuel storage or other) ° Cost for all engineering associated with the design, construction, startup, licensing and permitting of the co-fired facilities. (Note: For some plant sites, the costs associated with licensing and permitting may be very significant. See Chapter 9 for discussion and references dealing with licensing and permitting of co-fired facilities). oO Cost for mechanical components of the facility associated with co- firing including: ° Fuel receiving, storage, and reclaim oO Fuel preparation (including screens, dryers, hogs, metal detection and removal, and all air and water pollution control facilities required for the operation of the fuel preparation equipment) O Fuel flow metering oO Fuel feed (injection) system oO Furnace grate modifications 158 Bottom ash collection, handling, storage, and disposal facilities Furnace combustion air system modifications including both primary (under grate) and secondary (over fire) air supplies, all related ducts, dampers, flow meters, etc. Particulate pollutant emission control devices Gaseous pollutant emission control devices Pollution monitoring equipment for the criteria pollutants as well as toxic and hazardous pollutants Fly ash collection, handling, storage, and disposal facilities Forced draft fan increased capacity Induced draft fan increased capacity Liquid waste collection and treatment facilities Solid waste collection, handling, storage and disposal facilities Modifications to power plant operating controls required for co-firing Any additional items needed to accommodate changes in plant personnel required for the operation, supervision, plant engineering, maintenance, accounting, or other aspects of the co- fired plant including: oo 0 0 office space and office equipment laboratory space and laboratory equipment maintenance shop space and maintenance tools trucks, trailers, and/or other transportation equipment Financing costs during the construction period Project financing costs 159 This is a rather long check list but not all items will apply to every scenario for co-firing. The list illustrates the potential complexity of co-firing projects both in terms of the economic analysis of the project and in terms of the potential capital costs for equipment to carry out a project. RISK COMPENSATION EXPENSE A thorough economic analysis of a co-firing project should include some consideration of the potential financial risks involved in the project in the event of late startup, unscheduled shutdowns, plant performance below anticipated levels and similar circumstances which effect the economics of the site. Murphy’s law requires that things will go wrong and it is often said that Murphy was an optimist. Table 3-6 (page 14) in Chapter 3 confirms the existence of Murphy’s law with respect to co-firing in electric utilities. Out of 9 plants that attempted to co-fire coal and RDF (each plant making a very considerable investment in their project) only 4 are listed as on-going commercial operations. The remainder shut down for various reasons such as "..process not economical..", "... excessive boiler fouling and slagging...", "...ash removal problems...", etc. Obviously there was and still is risk associated with undertaking co-firing projects. This is not to suggest that co-firing projects are all too risky to attempt. The information in Chapters 3 & 4 clearly demonstrates that co-firing projects are economically effective in many sectors of the economy. But the potential risks should be evaluated and included in the economic assessment of project in order to avoid taking unnecessary financial risks. 160 ADDITIONAL ECONOMIC CONSIDERATIONS IN CO-FIRING The Biom Energy Project Development Gui k by Vranizan, J.M. et al, published in July 1987 (available through the Bonneville Power Administration) discusses the economics of biomass projects in its Chapter 6. The presentation is broadly applicable to many co-firing projects and is recommended as a reference source. One of the important points of the Guidebook is that economics of a project are strongly influenced by the type of ownership involved. The big influence is taxes. Private, for-profit organizations subject to federal and state income taxes have tax credit and tax deduction opportunities which are not available to not-for-profit businesses and institutions. Thus, the profitability of a planned co-fired project will be influenced by who owns it. The Guidebook also provides a particularly well organized outline for carrying out a thorough economic analysis for a proposed project. It is recommended as a reference. A final comment concerning the many economic considerations in planning and evaluating co-firing projects: The overall task typically involves several levels of detail starting with rough, ball-park calculations and leading eventually to an in-depth, detailed review of the options. It is often work carried out by professional planners, engineers, and economists using large and diverse data bases. 161 SUMMARY COMMENT The economics of co-firing can be evaluated through a complete economic analysis of a project and can include a variety of options, fuel types, fuel mixes, etc. The approach to the analysis is very much the same as would be used to evaluate any engineering/construction project. However, based on the experiences of the electric utility industry and other sites which have undertaken co-firing applications, there are some details in addition to those normally considered which should be looked at for co-firing. The economic impact of co-firing should be considered from the perspective of the overall operation and economics of the facility as opposed to limiting the analysis to the economics of the power plant or boiler room. The analysis should investigate changes in the plant fuel expenses, changes in plant boiler efficiency, changes in plant power requirements, changes in plant maintenance expense, changes in plant labor expense, and changes due to increasing (or decreasing) the peak steam generating capacity of the boilers due to co-firing. Within the electric utility industry, determination of the replacement fuel value is very critical to the economic success of co-firing. It is less critical in other sectors of the economy. Debt service analysis for proposed co-firing operations requires that the anticipated capital costs for the new or modified facilities be determined. The capital costs may include a very wide array of items dealing with fuel facilities, furnace modification, pollution control equipment, waste handling and disposal, and other items. It’s a long check list but needs to be carefully evaluated in order to avoid reaching erroneous conclusions about the economic feasibility of a proposed project. The economics of co-firing may be influenced by ownership of the plant site. This is due to tax considerations which should be investigated as part of the overall economic analysis of the project. There is an element of risk associated with any project. The history of co-firing in the electric utility industry attests to the risks 162 involved in attempting to co-fire RDF in boilers designed and built for firing coal. At the same time, the lists of successful co-firing operations in other sectors of the economy indicate that co-firing is technically and economically feasible under a wide variety of conditions. The message is to consider the risks and the economic impact of late startups, unscheduled shutdowns and other events associated with co-firing and to include these risks in the overall economic evaluation of the project. 163 CHAPTER 11: DECISION MAKING CRITERIA FOR CO-FIRING There are many questions to consider in reaching a decision to undertake co-firing. The more obvious questions that arise may be organized into the following categories: oO Fuel oO Equipment oO Environment oO Economics oO Finance oO Other FUEL Fuel related questions that may arise can cover a broad range of topics. It is likely that not all of the questions can be answered in the process of planning a co-firing project. But just raising the questions may help to focus attention on potential problem areas and can help in deciding whether or not to pursue a project. oO What quantities of fuel are currently required at the plant site? oO What are the projected fuel requirements at the plant site for both the short term and long term? oO What alternative fuels are available for use at the plant site? oO What quantities of each alternative fuel are available? ° For each alternative fuel considered, is it available on a continuous basis, seasonal basis, or other basis? ° For each alternative fuel considered, is it likely to be available on a long term basis (i.e., 5 years, 10 years) in adequate quantities to meet projected plant fuel demand? Note: This question introduces a series of questions concerning the ability of fuel suppliers to 165 meet long term commitments for delivery. These are questions for which it may be difficult to find good answers. oO What are the chemical and physical characteristics of each fuel including its higher heating value, moisture content, ash content, size range, etc. oO What is the anticipated thermal efficiency of the fuel under the combustion conditions expected at the plant site? ° Does the fuel contain sulfur, chlorine, heavy metals, toxic or hazardous components? oO Is the fuel explosive, corrosive, or in other ways potentially dangerous requiring special precautions? oO What is the cost for each fuel in units of dollars per million BTU’s taking into account the combustion efficiency expected as the fuel burns? oO What are the requirements for receiving, storing, reclaiming and preparing the fuel for use in terms of volume flow rates? oO If the fuel is a waste product generated at the plant site, what alternatives exist for disposal of the waste? EQUIPMENT The equipment required for co-firing fuels may extend beyond the boiler room to include fuel receiving, storage, reclaim, and preparation, pollution control and waste disposal. Each alternative that is considered for co-firing will have its own attendant equipment requirements and associated costs. The following list of questions may be helpful in identifying equipment requirements for specific co-firing projects. What equipment is needed: oO To receive, store and reclaim each of the fuels to be co-fired? oO To prepare each fuel? 166 To convey each fuel to the boiler? To feed each fuel into the boiler at the right place and to properly distribute each fuel in the boiler for good combustion? To control the fuel flow rate for each fuel throughout the full operating range of steam generation rates in the boiler’s operating envelope? To provide primary combustion air for each fuel burned To provide secondary combustion air for each fuel burned To control the flow rates of primary and secondary combustion air to maintain proper fuel to air ratios throughout the full operating envelope of the boiler? To preheat the combustion air? To modify the boiler for proper combustion of the fuels? For example, is it necessary to add or to modify grates in the furnace, or to add or modify refractory used in the furnace? To remove bottom ash from the furnace? To blow soot in the heat transfer sections of the boiler? To meet the particulate air pollution emission limitations required under the terms of the operating permit? To meet the gaseous air pollution emission limitations required under the terms of the operating permit To meet special pollution control requirements for emissions of toxic and/or hazardous substances To meet the water pollution control requirements for the plant site? To collect and dispose of solid wastes for the plant site? To control the operation of the boiler(s) when co-firing fuels in a manner which optimizes thermal efficiency throughout the full operating envelope of the boiler? To ensure safe operation of the complete facility? 167 ENVIRONMENT It is necessary to meet environmental restrictions in order to make any co-firing project a success. Discussions in Chapters 8 & 9 outline the principal environmental concerns and requirements as set forth in federal, state and local regulations. From these discussions a brief list can be made of the broad environmental questions that arise in regard to co-firing projects. Within the confines of federal, state, regional and local regulations: oO Will co-firing an existing facility be interpreted as making a major modification to the facility? Note: This may be a particularly crucial question due to the potential consequences of answering it yes". oO What particulate emission limits must be met? ° What gaseous emission limits must be met? oO What limits are placed on toxic and/or hazardous substances associated with the plant site? oO What are the requirements for treatment of liquid wastes generated on the plant site before they can be released to receiving waters? oO What are the requirements for collection and disposal of solid waste? oO Are there any special requirements for control of odors or dust associated with the operation of the facility? oO Are there any requirements regarding noise from the operation which would necessitate noise control measures? With the exception of the first question, these very broad questions can only be answered with a thorough analysis of the environmental aspects of the overall project and that, of course, involves answering many very detailed questions. It is not profitable to list them all here. 168 Assume, however, that all of the minute questions have been raised and satisfactorily answered and that the broad ranging questions noted above are also answered. There still exist other areas of environmental questions which may be very important to the economics and overall success of a co-firing project: oO Will an Environmental Impact Statement (EIS) or an Environmental Assessment be required? oO Does the project involve wetlands? oO Are any archeological studies required? oO Does the project involve coastal zone management? ° Which agencies have jurisdiction in the project? oO What steps are required to obtain the necessary permits for construction and operation of the co-fired facility? oO How long will it take to obtain permits for construction and operation of the project? ° Will the permitting process delay the project to the point where it is no longer feasible? ° What requirements have to be met with respect to monitoring and reporting air pollutant emissions, liquid wastes, solid wastes, toxic/hazardous wastes, noise levels, or other parameters? oO What are the reporting requirements of each of the involved environmental control agencies? These many environmental questions pose significant burden to some plant owners who may wish to co-fire fuels. However, many plant owners have sought answers to the questions and have concluded that co-firing was still appropriate and could be done within existing environmental constraints. 169 ECONOMIC In many, but not all instances, the decision to co-fire fuels boils down to an economic decision. The text of Chapter 10 summarizes many of the key economic considerations in co-firing which interested readers may wish to review. An important consideration in economic analyses which is not discussed in Chapter 10 is cash flow. The Biomass Energy Project Development Guidebook by Vranizan, J.M., et al, published in July 1987, available through the Bonneville Power Administration, includes a very good approach to the economic evaluation process for biomass projects in its Section 6. The method takes cash flow carefully into account and appears to be broadly applicable, quite suitable for evaluation of co-fired projects. Also, well-organized presentations on investment evaluation criteria and economic modeling are included Section 6. FINANCE There are many projects proposed which have been shown to be technically feasible, environmentally sound and economically attractive and yet were not undertaken due to limitations in financing. It is not within the scope of this monograph to delve into all of the possible ways to finance projects. Interested readers are directed to Section 7 of the Biomass Energy Project Development Guidebook for information about financial options available to utilities, businesses, institutions, and governmental agencies. OTHER QUESTIONS TO CONSIDER IN REACHING A DECISION ABOUT CO-FIRING The discussion to this point of the chapter on decision making criteria for co-firing has reviewed the more important questions that may arise in the areas of fuel, equipment, environment, and economics. Finance has been mentioned but not discussed. 170 Assume now that each of these topical areas has been fully investigated for a co-firing project and that it has been determined that the project is feasible and should be pursued. Are there other avenues of investigation which should be inquired into to ensure that the project can proceed smoothly? How about politics, timing, institutional barriers, and lack of infra-structure? Politics There are co-firing projects which are technically feasible and easily justifiable in terms of economics and financial and environmental restraints, but which were delayed and/or completely stopped for political reasons. The "Not In My Back Yard" (NIMBY) syndrome is a common community response to proposals to co-fire MSW, and this response has prevented several proposed projects from being built. It is a social and political concern which can arise unexpectedly and is often difficult to deal with. "Guidelines for Co-Firing Refuse Derived Fuel in Electric Utility Boilers", Vol. 1, (EPRI CS-5754, Copyright Electric Power Research Institute, June, 1988. Reprinted with permission.) emphasizes this aspect of projects in a discussion on institutional issues: "Institutional issues affecting implementation of a ...... facility include siting, permitting, financing, ownership, control of the waste stream, tipping fees for waste disposal, contracts between participants, and public acceptance. Because of public opposition and the NIMBY factor, the last issue, public acceptance, is often the most difficult to achieve..... Community opposition is based on attitudes formed from anticipated real or imaginary environmental impacts. These impacts include noise, air pollution, strong odors, truck traffic, unattractive visual appearance of the plant, property value depreciation and vermin...... Early involvement of the community in the planning and decision-making process is a key factor in gaining support. The public hearing process allows the community the opportunity to obtain responses to its concerns. Projects that have been successful had effective public information and publicity programs. 171 As an illustration of the importance of politics in co-firing projects, the Alaska Railroad constructed new boiler facilities designed to co-fire natural gas and used lubricating oil from large diesel locomotives. Co-firing of these fuels is commonly practiced throughout the U.S. and the technology is well developed and commercially available. Issuance of an operating permit to co-fire the boilers was delayed by the Mayor of Anchorage for over a year due to the Mayor’s sensitivity to public concern over methods of waste disposal. The Mayor had taken some political heat over a proposal to destroy PCB’s in a municipal incinerator and didn’t want to face a similar public reaction over co-firing of waste oil by the Alaska Railroad. It wasn’t all one sided, of course. The railroad had erred in the initial process of applying for operating permits by inadvertently overlooking the municipal air pollution authority. That didn’t sit well with the local licensing body whose political response was decidedly negative. Timing Timing of a proposed project is also an important consideration for an existing plant, particularly if the project requires an interruption to steam production or in other ways may interfere with plant operations. In those industries which operate on a continuous 24 hour, 7 day a week basis, loss of steam production even for a brief period can be extremely costly. If down time is required for boiler modifications to accommodate co- firing, the down time must be carefully planned and scheduled to mesh with other plant maintenance and to minimize production losses. This may significantly delay the startup of co-fired projects. Institutional Barriers A curious trait common to many federal, state, and municipal institutions such as agencies, bureaus, universities, hospitals, and prisons is that they have little incentive to save money (for example by reducing their heating bills by co-firing inexpensive fuels). Typically the funding support for institutions is set up so that any money saved must be returned to a general fund (federal government, state legislature, etc.) and 172 may not be used as discretionary funds by the institution that did the saving. This is an institutional barrier to co-firing. It exists widely. How much it limits interest in co- firing applications is unknown and not easily determined. Lack of Infra-Structure Co-firing of fuels to generate electricity, for space heating or for other end uses requires a modest degree of technical sophistication, ready access to skilled services for maintenance and repairs, and fast access to replacement equipment components. It also requires the presence of well- trained operators who can work effectively to keep the facility functioning and performing safely within its design limits. Finally, co- firing of fuels requires that the fuels can be received as needed at the plant site. In urban areas, all of these requirements can be met. Even in most of the rural areas of the contiguous U.S. there is sufficient infra-structure of transportation, supply centers, communication and skilled employees to establish successful co-fired facilities and keep them operational. There are, however, remote regions of the country where there is not sufficient infra-structure to support co-fired installations. The rural ("bush") communities of Alaska are prime examples of places where co-firing of fuels may have a very limited application if for no other reason than the infra-structure of society and commerce is inadequate to support such facilities. MAKING THE FINAL DECISION The decision making process to go or not to go ahead with proposed co-firing projects is usually carried out in stages. The first stage can be limited to rough estimates and calculations about the availability and cost of alternative fuels and the anticipated annual fuel use. If these estimates indicate that substantial fuel cost savings are possible through co-firing, the next step is to make some rough estimates of the cost to implement the project and to roughly determine the scale of the project involvement. If the project still appears to be feasible and will provide overall benefits, then it is time 173 to begin more thorough evaluations of each of the different aspects of the project. When apparent roadblocks to the success of the project arise, seek alternative solutions where it is reasonable to do so. For larger projects, detailed engineering feasibility studies are usually required to reach of point of deciding to pursue financial support. The engineering feasibility studies are critically important in making sound decisions. They should be approached with an open outlook, willing to accept the results of the study without bias. 174 SUMMARY COMMENT Making the decision to proceed with a co-firing project involves finding answers to questions which may be organized into categories of fuel, equipment, environmental concerns, economics, finance, and a category of "other". The fuel related questions should attempt to determine how much fuel is needed, what kinds of fuels are available to meet the need, how long can you count on being able to obtain each fuel considered, what are the characteristics of each fuel, what special provisions must be made for each fuel and finally, how much do the alternative fuels cost in dollars per million BTU’s. The equipment oriented questions are directed at learning about the items of equipment and/or modifications to equipment which are necessary to do the complete project. The equipment related questions range from items needed for the fuel supply, to fuel metering, to fuel feeding, to boiler modifications, air pollution control systems, water pollution control, solid waste handling and disposal and related miscellaneous items. Once a checklist of equipment items needed has been prepared, then the projected cost for capital equipment and equipment modifications can be determined. The equipment check list can also be used to estimate the time required for design, manufacture, delivery, installation and startup of the proposed or modified facility. Environmental concerns may be very important in the decision making process for co- firing applications. A project may be so extensive that it has potential impacts in the areas of air pollution, water pollution, solid waste, toxic and hazardous substances, noise, and others. Before construction may proceed permits must be issued for the project by all of the concerned agencies at the federal, state, regional and local levels. Obtaining the required permits may involve a significant effort and expense as well as time delays in pursuing the project, and these factors may be important in deciding to whether carry out the project. 175 The economic feasibility of proposed co-firing projects can be determined through careful consideration of all of the anticipated costs and benefits as well as the risks associated with the undertaking. Before the economic analysis can be completed, most of the questions associated with the fuel, the equipment and the environmental concerns need to be answered. The financing of a project can be pursued after it has been determined that the proposed effort is economically attractive. Financing options are strongly dependent upon the type of ownership involved. The decision to pursue a project depends, of course, on the ability to obtain financing and, therefore, that part of the decision making process may be delayed considerably. The "other" factors to be considered as part of the decision making process can be just as important as those dealing with fuel, equipment, environmental concerns, economic feasibility and possible financing. Political problems must be anticipated and dealt with, timing of the project must be carefully planned so that it can mesh with production schedules and planned down time, institutional barriers must be considered and recognized at the outset of the project, and finally, it must be determined that sufficient infrastructure is available to support the proposed effort. If all of these considerations still point to "GO", then the proposed undertaking will have good prospects for success. However, if the decision making process uncovers a major problem area that cannot be resolved or bypassed for whatever reason, then it is important to be able to decide on "NO GO" and to stop further activity. 176 CHAPTER 12: POTENTIAL MARKETS FOR CO-FIRING The opportunities for co-firing of fuels exist in every segment of the economy. Chapters 3 & 4 include lists of co-fired facilities among the electric utility industry, food and agriculture, manufacturing, chemicals and textiles, military sites, institutional settings, the wood products industry and miscellaneous other areas. There appear to be no insurmountable barriers to the implementation of co-firing in any sector of the economy. MARKETS FOR CO-FIRING Where are the most likely markets for expansion of co-firing? Certainly the electric utility industry will continue to explore opportunities for co-firing of RDF with coal, taking advantage of the EPRI CS-5754, "Guidelines for Co-Firing Refuse Derived Fuel in Electric Utility Boilers". However, that market does have some specific limits as noted in Dave Ege’s article, "When It’s Economic To Co-Fire Refuse Derived Fuel With Coal" published in the February, 1987 issue of Power Magazine (reprinted with permission): "Most power generating units that operate at good load factors most of the year are now located outside of metropolitan areas. Those units that are most suitable for waste disposal are generally older, smaller power stations located in town, but these units don’t have good load factors which are essential for municipal waste disposal. This means that the likelihood of finding a unit that is ideal for burning municipal waste is relatively small. But this doesn’t mean that there aren’t quite a few good candidates available in the U.S. RDF could be a substantial factor in considering life extension for some of these older units." It is also expected that the utility industry will see expanded use of fossil fuels co-fired with biomass fuels, particularly in the wooded areas of the country. Food processing and agricultural industries have been quite active during the past 20 years in developing systems to co-fire their waste products for energy recovery and to reduce the expense of waste disposal. The same positive incentives exist in the ae manufacturing, chemicals and textiles sectors of the economy. It is very likely that the trend toward increased co-firing of fuels will continue in all of these economic sectors. There is no indication that strong negative influences are developing which would deter increased use of waste products for energy recovery. Military facilities are under pressure to reduce expenses and to develop and implement systems for waste energy recovery. Many military installations have boiler facilities which can be adapted for co-firing of wastes generated on site as well as for co-firing of purchased fuels including a wide range of biomass based and refuse based fuels. It is, therefore, likely that incidence of co-fired fuels will expand at military installations throughout the country during the next decade. Private institutional settings such as hospitals, universities and college campuses can expect to see some increase in the use of co-firing during the next decade but only in those locations where the economic return is quite good and the capital investment requirements are small. This hypothesis is based on the knowledge that many private institutions have limited capital resources available and typically will place co-firing projects low on the priority list unless the economic return is quite high. State and federally owned institutional settings will also see some scattered increase in co-fired facilities but the expanded use of co-firing will continue to be limited by economic institutional barriers. State and federal sites for the most part have no economic incentive to adopt co-firing. (See discussion on Institutional Barriers in Chapter 11.) Municipalities across the country are faced with increasing concerns about solid waste disposal. Many municipalities either have built or are currently in the process of building mass burn systems designed for solid waste reduction and energy recovery. Typically mass burn plants are co-fired with fossil fuel but only for startup operations, not for continuous, long term co-firing. The emphasis in the design and operation of most municipally owned mass burn plants is in waste disposal and volume reduction 178 rather than on efficient and economical energy generation. Co-firing will be used for specialty wastes such as shredded tires and agricultural waste products but the degree of processing of the fuels will be very minimal if it exists at all. For the most part, specialty wastes will just be mass burned along with the MSW. This is not to suggest that co-firing options will be ignored by municipalities. Central heating plants owned and operated by municipalities can often benefit from co-firing of fuels (for example burning shredded waste paper, used lubricating oils, and other fuels with fossil fuels). In addition, municipalities are currently giving careful consideration to erecting specialized combustion facilities to dispose of toxic and hazardous wastes such as PCB’s. Many of these combustion units will be capable of co-firing a range of fuels for waste disposal and (occasionally) energy recovery. In the wood products industry and the pulp and paper industry, co-firing of fuels will continue as it has for many decades. Wood based fuels in a variety of forms including hogged fuel, planer shavings, sanderdust, sawdust, edge and end trim, will be burned for energy recovery and waste reduction along with an array of fossil fuels including natural gas, No. 2 fuel oil, Bunker "C", and several grades of coal. Multi-fueled boilers have served this economic sector well and should continue to do so. NEW TECHNOLOGIES The expanded use of co-firing is certain to be influenced by technological developments in the areas of combustion facilities and environmental controls. Particularly important advancements have been made during the past 20 years in the design and operation of bubbling fluidized bed combustors. More recently, development efforts have been concentrated in the area of circulating fluidized bed combustors. Both of these designs have demonstrated capability for multi-fuel firing. Control of particulate air pollutants and gaseous pollutants has become an increasing concern in the face of ever tightening federal, state, regional and local environmental 179 regulations. It is of particular importance in co-firing fuels since the pollutant emissions are fuel specific. Fortunately, emission control technology has been advancing steadily since the implementation of the 1967 Clean Air Act. Current emission control technology is adequate to meet the requirements for multi-fueled combustion facilities in the areas of particulate and gaseous emission. It is true that the cost of meeting environmental restrictions attendant to co-firing fuels may act as a limitation on the expanded use of co-firing. But for most facilities, the technology required to meet environmental restrictions is commercially available. 180