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  • 1. DOE/EE-0288Leading by example,saving energy and Biomass Cofiring in Coal-Fired Boilerstaxpayer dollarsin federal facilities Using this time-tested fuel-switching technique in existing federal boilers helps to reduce operating costs, increase the use of renewable energy, and enhance our energy security Executive Summary To help the nation use more domestic fuels and renewable energy technologies—and increase our energy security—the Federal Energy Management Program (FEMP) in the U.S. Department of Energy, Office of Energy Efficiency and Renewable Energy, assists government agencies in developing biomass energy projects. As part of that assistance, FEMP has prepared this Federal Technology Alert on biomass cofiring technologies. This publication was prepared to help federal energy and facility managers make informed decisions about using biomass cofiring in existing coal-fired boilers at their facilities. The term “biomass” refers to materials derived from plant matter such as trees, grasses, and agricultural crops. These materials, grown using energy from sunlight, can be renewable energy sources for fueling many of today’s energy needs. The most common types of biomass that are available at potentially attractive prices for energy use at federal facilities are waste wood and wastepaper.The boiler plant at theDepartment of Energy’s One of the most attractive and easily implemented biomass energy technologies is cofiringSavannah River Site co-fires coal and biomass. with coal in existing coal-fired boilers. In biomass cofiring, biomass can substitute for up to 20% of the coal used in the boiler. The biomass and coal are combusted simultaneously. When it is used as a supplemental fuel in an existing coal boiler, biomass can provide the following benefits: lower fuel costs, avoidance of landfills and their associated costs, and reductions in sulfur oxide, nitrogen oxide, and greenhouse-gas emissions. Other benefits, such as decreases in flue gas opacity, have also been documented. Biomass cofiring is one of many energy- and cost-saving technologies to emerge as feasible for federal facilities in the past 20 years. Cofiring is a proven technology; it is also proving to be life-cycle cost-effective in terms of installation cost and net present value at several federal sites. Energy-Saving Mechanism Biomass cofiring projects do not reduce a boiler’s total energy input requirement. In fact, in a properly implemented cofiring application, the efficiency of the boiler will be the same as it was in the coal-only operation. However, cofiring projects do replace a portion of the non- renewable fuel—coal—with a renewable fuel—biomass. Cost-Saving Mechanisms Overall production cost savings can be achieved by replacing coal with inexpensive biomass fuel sources—e.g., clean wood waste and waste paper. Typically, biomass fuel supplies should cost at least 20% less, on a thermal basis, than coal supplies before a cofiring project can be economically attractive. U.S. Department of Energy Energy Efficiency Internet: and Renewable Energy No portion of this publication may be altered in any form without Bringing you a prosperous future where energy prior written consent from the U.S. Department of Energy, Energy is clean, abundant, reliable, and affordable Efficiency and Renewable Energy, and the authoring national laboratory.
  • 2. Federal Technology AlertPayback periods are typically To make economical use of captive investment of $850,000 wasbetween one and eight years, wood waste materials—primarily required, resulting in a simpleand annual cost savings could bark and wood chips that are payback period for the projectrange from $60,000 to $110,000 unsuitable for making paper—the of less than four years. The netfor an average-size federal boiler. U.S. pulp and paper industry has present value of the project,These savings depend on the cofired wood with coal for evaluated over a 10-year analysisavailability of low-cost biomass decades. Cofiring is a standard period, is about $1.1 million.feedstocks. However, at larger- mode of operation in that indus- Test burns at SRS have shown thatthan-average facilities, and at try, where biomass fuels provide the present stoker boiler fuel han-facilities that can avoid disposal more than 50% of the total fuel dling equipment required nocosts by using self-generated input. Spurred by a need to reduce modification to fire the biomass/biomass fuel sources, annual fuel and operating costs, and coal mixture successfully. No fuel-cost savings could be signifi- potential future needs to reduce feeding problems were experi-cantly higher. greenhouse gas emissions, an enced, and no increases in main- increasing number of industrial- tenance are expected to be neededApplication and utility-scale boilers outside at the steam plant. Steam plantBiomass cofiring can be applied the pulp and paper industry are personnel have been supportiveonly at facilities with existing being evaluated for use in cofiring of the project. Emissions measure-coal-fired boilers. The best oppor- applications. ments made during initial testingtunities for economically attrac- showed level or reduced emissionstive cofiring are at coal-fired facili- Case Study Summary for all eight measured pollutants,ties where all or most of the fol- The U.S. Department of Energy’s and sulfur emissions are expectedlowing conditions apply: (1) coal (DOE) Savannah River Site (SRS) to be reduced by 20%. Opacityprices are high; (2) annual coal in Aiken, South Carolina, has levels also decreased significantly.usage is significant; (3) local or installed equipment to produce The project will result in a reduc-facility-generated supplies of bio- “alternate fuel,” or AF, cubes from tion of about 2,240 tons per yearmass are abundant; (4) local land- shredded office paper and finely in coal usage at the facility.fill tipping fees are high, which chipped wood waste. After a seriesmeans it is costly to dispose of of successful test burns have been Implementation Barriersbiomass; and (5) plant staff and completed to demonstrate accept-management are highly motivated For utility-scale power generation able combustion, emissions, andto implement the project success- projects, acquiring steady, year- performance of the boiler and fuelfully. As a rule, boilers producing round supplies of large quantities processing and handling systems,less than 35,000 pounds per hour of low-cost biomass can be diffi- cofiring was expected to begin in(lb/hr) of steam are too small to cult. But where supplies are avail- 2003 on a regular basis. The bio-be used in an economically attrac- able, there are several advantages mass cubes offset about 20% oftive cofiring project. to using biomass for cofiring opera- the coal used in the facility’s two tions at federal facilities. For exam- traveling-grate stoker boilers. The ple, federal coal-fired boilers areField Experiences project should result in annual coal typically much smaller thanCofiring biomass and coal is a time- cost savings of about $112,000. utility-scale boilers, and theytested fuel-switching strategy that Cost savings associated with avoid- are most often used for spaceis particularly well suited to a ing incineration or landfill disposal heating and process heat appli-stoker boiler, the type most often of office waste paper and scrap cations. Thus, they do not havefound at coal-fired federal facili- wood from on-site construction utility-scale fuel requirements.ties. However, cofiring has been activities will total about $172,000successfully demonstrated and In addition, federal boilers needed per year. Net annual savings frompracticed in all types of coal for space heating typically operate the project, after subtracting theboilers, including pulverized- primarily during winter months. $30,000 per year needed to oper-coal boilers, cyclones, stokers, During summer months, waste ate the AF cubing facility, will beand fluidized beds. wood is often sent to the mulch about $254,000. An initial capital
  • 3. Federal Technology Alertmarket, which makes the wood • Economics is the driving factor. energy efficiency and renewableunavailable for use as fuel. Thus, Project economics largely deter- energy projects. Projects can befederal coal-fired boilers could mine whether a cofiring proj- funded through Energy Savingsbecome an attractive winter mar- ect will be implemented. Performance Contracts (ESPCs),ket for local wood processors. This Selecting sites where waste Utility Energy Services Contracts,has been one of the driving fac- wood supplies have already or appropriations. Among thesetors behind a cofiring demonstra- been identified will reduce resources is a Technology-Specifiction at the Iron City Brewery overall costs. Larger facilities “Super ESPC” for Biomass andin Pittsburgh, Pennsylvania. with high capacity factors— Alternative Methane Fuels (BAMF), those that operate at high loads which facilitates the use of bio-These are some of the major policy year-round—can utilize more mass and alternative methaneand economic issues and barriers biomass and will realize fuels to reduce federal energy con-associated with implementing greater annual cost savings, sumption, energy costs, or both.biomass cofiring projects at assuming that wood suppliesfederal sites: are obtained at a discount in Through the BAMF Super ESPC, comparison to coal. This will FEMP enables federal facilities• Permit modifications may be also reduce payback periods. to obtain the energy- and cost- required. Permit requirements savings benefits of biomass and vary from site to site, but Conclusion alternative methane fuels at no modifications to existing up-front cost to the facility. More emissions permits, even for DOE FEMP, with the support of information about FEMP and limited-term demonstration staff at the DOE National Labor- atories and Regional Offices, offers BAMF Super ESPC contacts and projects, may be required for many services and resources to contract awardees is provided in cofiring projects. help federal agencies implement this Federal Technology Alert. Disclaimer This report was sponsored by the United States Department of Energy, Energy Efficiency and Renewable Energy, Federal Energy Management Program. Neither the United States Government nor any agency or contractor thereof, nor any of their employees, makes any warranty, express or implied, or assumes any legal liability or responsibility for the accuracy, completeness, or useful- ness of any information, apparatus, product, or process disclosed, or represents that its use would not infringe privately owned rights. Reference herein to any specific commercial product, process, or service by trade name, trademark, manufacturer, or other- wise does not necessarily constitute or imply its endorsement, recommendation, or favoring by the United States Government or any agency or contractor thereof. The views and opinions of authors expressed herein do not necessarily state or reflect those of the United States Government or any agency or contractor thereof.
  • 4. Federal Technology Alert
  • 5. Federal Technology AlertContents Abstract .....................................................................................................2 About the Technology ..............................................................................3 Application Domain Cost-Saving Mechanisms Other Benefits Installation Requirements Federal-Sector Potential ............................................................................9 Estimated Savings and Market Potential Laboratory Perspective Application .............................................................................................11 Application Prerequisites Cost-Effectiveness Factors Where to Apply What to Avoid Equipment Integration Maintenance Equipment Warranties Codes and Standards Costs Utility Incentives Project Financing and Technical Assistance Technology Performance........................................................................17 Field Experience Fuel Supply and Cost Savings Calculations ...........................................17 Case Study — Savannah River Cofiring Project ....................................18 Facility Description Existing Technology Description New Technology Description Energy Savings Life-Cycle Cost Performance Test Results The Technology in Perspective ..............................................................20 Manufacturers.........................................................................................21 Biomass Pelletizing Equipment Boiler Equipment/Cofiring Systems Biomass and Alternative Methane Fuels (BAMF) Super ESPC Competitively Awarded Contractors For Further Information .........................................................................21 Bibliography ...........................................................................................21 Appendix A: Assumptions and Explanations for Screening Analysis .......23 Appendix B: Blank Worksheets for Preliminary Evaluation of a Cofiring Project ......................................................................................24 Appendix C: Completed Worksheets for Cofiring Operation at Savannah River Site ................................................................................28 Appendix D: Federal Life-Cycle Costing Procedures and BLCC Software Information .............................................................................31 Appendix E: Savannah River Site Biomass Cofiring Case Study: NIST BLCC Comparative Economic Analysis ........................................33 FEDERAL ENERGY MANAGEMENT PROGRAM — 1
  • 6. Federal Technology AlertAbstract nity for federal energy managers This Federal Technology Alert was to use a greenhouse-gas-neutral produced as part of the New Tech-Biomass energy technologies con- renewable fuel while reducing nology Demonstration activitiesvert renewable biomass fuels to energy and waste disposal costs in the Department of Energy’sheat or electricity. Next to hydro- and enhancing national energy Federal Energy Management Pro-power, more electricity is gener- security. Specific requirements gram, which is part of the DOEated from biomass than from any will depend on the site. But in Office of Energy Efficiency andother renewable energy resource general, cofiring biomass in an Renewable Energy, to providein the United States. Biomass existing coal-fired boiler involves facility and energy managerscofiring is attracting interest modifying or adding to the fuel with the information they needbecause it is the most economical handling, storage, and feed sys- to decide whether to pursue bio-near-term option for introducing tems. Fuel sources and the type mass cofiring at their biomass resources into today’s of boiler at the site will dictateenergy mix. This publication describes biomass fuel processing requirements. cofiring, cost-saving mechanisms, Biomass cofiring can be economi- and factors that influence its per- cal at federal facilities where most formance. Worksheets allow the or all of these criteria are met: reader to perform preliminary cal- current use of a coal-fired boiler, culations to determine whether access to a steady supply of com- a facility is suitable for biomass petitively priced biomass, high cofiring, and how much it would coal prices, and favorable regu- save annually. The worksheets latory and market conditions for also allow required biomass sup- renewable energy use and waste plies to be estimated, so managers reduction. Boilers at several fed- can work with biomass fuel bro- eral facilities were originally kers and evaluate their equipment designed for cofiring biomass needs. Also included is a case with coal. Others were modified study describing the design, oper- after installation to allow cofiring. ation, and performance of a bio- Some demonstrations—e.g., at the mass cofiring project at the DOEFigure 1. The NIOSH boiler plant wasmodified to cofire biomass with coal. National Institute of Occupational Savannah River Site in Aiken, Safety and Health (NIOSH) Bruce- South Carolina. A list of contacts ton Boiler plant in Pittsburgh, and a bibliography are alsoCofiring is the simultaneous com- Pennsylvania (Figure 1)—show included.bustion of different fuels in the that, under certain circumstances,same boiler. Cofiring inexpensive only a few boiler plant modifica-biomass with fossil fuels in exist- tions are needed for boilers provides an opportu-2 — FEDERAL ENERGY MANAGEMENT PROGRAM
  • 7. Federal Technology AlertAbout the Technology involves substituting biomass for cles, because biomass is a more a portion of the fossil fuel used volatile fuel. Biomass that doesBiomass is organic material from in a boiler. not meet these specifications isliving things, including plant likely to cause flow problems inmatter such as trees, grasses, Cofiring inexpensive biomass with the fuel-handling equipment orand agricultural crops. These fossil fuels in existing federal boilers incomplete burnout in the boiler.materials, grown using energy provides an opportunity for federal General biomass sizing require-from sunlight, can be good energy managers to reduce their ments for each boiler type men-sources of renewable energy energy and waste disposal costs tioned here are shown in Table 1.and fuels for federal facilities. while making use of a renewable fuel that is considered greenhouse-Wood is the most commonly used Table 1. Biomass sizing requirements. gas-neutral. Cofiring biomassbiomass fuel for heat and power. counts toward a federal agency’s Existing Type Size RequiredThe most economical sources of of Boiler (inches) goals for increasing the use ofwood fuels are wood residues from renewable energy or “green power” Pulverized coal ≤1/4manufacturers and mill residues, (environmentally benign electricsuch as sawdust and shavings; Stoker ≤3 power), and it results in a net costdiscarded wood products, such Cyclone ≤1/2 savings to the agency. Cofiringas crates and pallets; woody yard Fluidized bed ≤3 biomass also increases our use oftrimmings; right-of-way trim- domestic fuels, thus enhancingmings diverted from landfills; More detailed information follows the nation’s energy security.and clean, nonhazardous wood about the cofiring options fordebris resulting from construction This publication focuses on the stoker and pulverized-coal federaland demolition work. Using these most promising, near-term, boilers.materials as sources of energy proven option for cofiring—usingrecovers their energy value and solid biomass to replace a portion Stoker boilers. Most coal-fired boilersavoids the need to dispose of of the coal combusted in existing at federal facilities are stokers,them in landfills, as well as coal-fired boilers. This type of similar to the one shown in theother disposal methods. cofiring has been successfully schematic in Figure 2. Because demonstrated in nearly all coal- these boilers are designed to fireBiomass energy technologies con- fairly large fuel particles on travel- fired boiler types and configura-vert renewable biomass fuels to ing or vibrating grates, they are tions, including stokers, fluidizedheat or electricity using equip- the most suitable federal boiler beds, pulverized coal boilers, andment similar to that used for type for cofiring at significant cyclones. The most likely opportu-fossil fuels such as natural gas, biomass input levels. In these nities at federal facilities will beoil, or coal. This includes fuel- boilers, fuel is either fed onto found at those that have stokershandling equipment, boilers, the grate from below, as in under- and pulverized coal boilers. Thissteam turbines, and engine gener- feed stokers, or it is spread evenly is because the optimum operatingator sets. Biomass can be used in across the grate from fuel spread- range of cyclone boilers is muchsolid form, or it can be converted ers above the grate, as in spreader larger than that required at a fed-into liquid or gaseous fuels. Next stokers. In the more common eral facility, and few fluidized bedto hydropower, more electricity spreader-fired traveling grate stoker boilers have been installed at fed-is generated from biomass than boiler, solid fuel is mechanically eral facilities for standard, non-from any other renewable energy or pneumatically spread from the research uses.resource in the United States. front of the boiler onto the rear One of the most important keys of the traveling grate. Smaller par-Cofiring is a fuel-diversification ticles burn in suspension above to a successful cofiring operationstrategy that has been practiced the grate, while the larger particles is to appropriately and consistentlyfor decades in the wood products burn on the grate as it moves the size the biomass according to theindustries and more recently in fuel from the back to the front of requirements of the type of boilerutility-scale boilers. Several fed- the boiler. The ash is discharged used. Biomass particles can usuallyeral facilities have also cofired from the grate into a hopper at be slightly larger than coal parti-biomass and coal. Cofiring the front of the boiler. FEDERAL ENERGY MANAGEMENT PROGRAM — 3
  • 8. Federal Technology Alert 03381101The retrofit requirements for cofir-ing in a stoker boiler will vary,depending on site-specific issues.If properly sized biomass fuel canbe delivered to the facility pre-mixed with coal supplies, on-site Gas burnerscapital expenses could be negligi-ble. Some facilities have multiple Hoppercoal hoppers that discharge onto Receivinga common conveyor to feed fuel bin Travelinginto the boiler. Using one of the grate Overfireexisting coal hoppers and the Boiler airassociated conveying equipment injectionfor biomass could minimize new Figure 2. Schematic of a typical traveling-grate expenses for a cofiringproject. Both methods have been Front end loadersuccessfully employed at federal to blend wood Metalstoker boilers for implementing and coal supplies detector Magnetic (coal and wooda biomass cofiring project. If blend is passed separator Dump conveyor through existing #1 Walking floor trailerneither of these low-cost options Dump or dump truck coal pulverizers)is feasible, new handling and Wood conveyor #2 pile Scalestorage equipment will need 03381102to be added. The cost of theseadditions is discussed later. Figure 3. Schematic of a blended-feed cofiring arrangement for a pulverized coal boiler.Pulverized coal boilers. There are twoprimary methods for cofiring bio- heat input basis. If the biomass is the NIOSH Bruceton boiler plantmass in a pulverized coal boiler. obtained at a significant discount in Pennsylvania and DOE’s Savan-The first method, illustrated in to current coal supplies, the addi- nah River Site in South Carolina—Figure 3, involves blending the tional expense may be warranted have been considering implement-biomass with the coal before the to offset coal purchases to a ing commercial cofiring applica-fuel mix enters the existing pul- greater degree. tions. Other federal sites withverizers. This is the least expensive cofiring experience include KImethod, but it is limited in the Application Domain Sawyer Air Force Base in Michi-amount of biomass that can be gan, Fort Stewart in Georgia, Puget The best opportunities for cofiringfired. With this blended feed Sound Naval Shipyard in Washing- biomass with fossil fuels at federalmethod, only about 3% or less ton, Wright- Patterson Air Force facilities are at sites with regularlyof the boiler’s heat input can be Base in Ohio, Brunswick Naval operating coal-fired boilers. Biomassobtained from biomass at full Air Station in Maine, and the cofiring has been successfullyboiler loads because of limitations Red River Army Depot in Texas. demonstrated in nearly all coal-in the capacity of the pulverizer. fired boiler types and configura- More than 100 U.S. companies orThe second method, illustrated in tions, including stokers, fluidized organizations have experience inFigure 4 on page 5, requires beds, pulverized coal boilers, and cofiring biomass with fossil fuels,installing a separate processing, cyclones. The least expensive and many cofiring boilers are inhandling, and storage system opportunities are most likely to operation today. Most are foundfor biomass, and injecting the be for stoker boilers, but cofiring in industrial applications, inbiomass into the boiler through in pulverized coal boilers may which the owner generates adedicated biomass ports. Although also be economically attractive. significant amount of biomassthis method is more expensive, it At least 10 facilities in the federal residue material (such as sawdust,allows greater amounts of biomass sector have had experience with scrap wood, bark, waste paper, orto be used—up to 15% more on a cardboard or agricultural residues biomass cofiring. Two facilities—4 — FEDERAL ENERGY MANAGEMENT PROGRAM
  • 9. Federal Technology Alert Metal detector Magnetic separator Conveyor #1 Wood Disc screener pile Grinder Scale Front end Walking floor trailer 03381103 loader or dump truck Rotary airlock feeder Separator Air Intake Exhaust Bin Dedicated biomass vent injection Existing coal Injection ports Wood silo Boiler Scale Pressure blowerFigure 4. Schematic of a separate-feed cofiring arrangement for a pulverized coal orchard trimmings and coffee project, and the next 10 states were Within each group in Table 2,grounds) during manufacturing. classified as having good potential. states are shown in alphabeticalUsing these residues as fuel allows See Table 2 and Figures 5 and 6. order, because slight variationsorganizations to avoid landfill in rankings result from selectingand other disposal costs and off- Table 2. States with most attractive weighting-factor values. The anal-sets some purchases of fossil fuel. conditions for biomass cofiring. ysis was intended simply to indi-Most ongoing cofiring operations cate which states have the most Cofiring helpful conditions for econom-are in stoker boilers in one of four Potential Stateindustries: wood products, agricul- ically successful cofiring projects.ture, textiles, and chemicals. High Connecticut It found that the Northeast, South- Potential Delaware east, Great Lakes states, andA screening analysis was done to Florida Washington State are the mostdetermine which states have the Maryland attractive locations for cofiringmost favorable conditions for a Massachusetts projects.financially successful cofiring proj- New Hampshire New Jersey Utility-scale cofiring projects areect. The primary factors consid- New York shown on the map in Figure 5.ered were average delivered state Pennsylvaniacoal prices, estimated low-cost These sites are in or near states Washingtonbiomass residue supply density identified by the screening model Good Alabama as having good or high potential(heat content in Btu of estimated Potential Georgiaavailable low-cost biomass resi- for cofiring. This increases confi- Indianadues per year per square mile of dence that the states selected by Michiganstate land area), and average state Minnesota the screening process were reason-landfill tipping fees. See Appendix North Carolina able choices. Figure 6 shows theA for a more detailed discussion. Ohio locations of existing federal coal- South Carolina fired boilers. There is good corre-The top 10 states in the analysis Tennessee spondence between the locationswere classified as having high Virginia of these facilities and the statespotential for a biomass cofiring identified as promising for cofiring. FEDERAL ENERGY MANAGEMENT PROGRAM — 5
  • 10. Federal Technology Alert pay off the initial investment— by switching part of the fuel sup- ply to biomass. Federal facilities that operate coal-fired boilers but are not in states on the list in Table 2 could still be good candi- dates for cofiring if specific condi- tions at their sites are favorable. “Wild card” factors, such as the impact of a motivated project manager or biomass resource supplier, the local availability of biomass, and the fact that a large federal facility or campus could act as its own source of biomass fuel, capitalizing on 03381104 fuel cost reductions while avoid- High potential for a Good potential for a biomass cofiring project biomass cofiring project ing landfill fees. These factors Locations of existing utility Locations of existing operational could easily tip the scales in power plants cofiring biomass coal plants within the Federal System favor of a particular site. TheFigure 5. States with most favorable conditions for biomass cofiring, based on coal-fired boilers in Alaskahigh coal prices, availability of biomass residues, and high landfill tipping fees. could be examples of good candidates not located in highly rated states because of WA a long heating season, large (57) NH MT VT (49) ME size, and very high coal prices. ND (50) (46) OR (19) (26) MN (34) (56) MA The map in Figure 6 indicates ID SD WI NY (48) (26) WY MI (71) average landfill tipping fees for (29) (33) (32) RI (23) IA each state. It also shows cities NV NE PA(51) NJ (41) (15) (24) (31) CT in which fairly recent local bio- UT IN OH (74)(61) CO IL (26) (29) WA (29) mass resource supply and cost CA (16) KS MO (25) (39) VA MD DE (29) (25) (27) KY(27) (38) (43) (47) studies have been performed, AZ NC(30) as reported in Urban Wood Waste NM OK TN(28) (20) AR (16) (21) Resource Assessment (Wiltsee 1998). (18) MS AL GA SC Additional information on poten- TX (19) (25) (25) (29) AK (23) LA tial biomass resource supplies near (22) federal facilities can be obtained (42) FL (41) from the DOE program manager HI (50) for the Technology-Specific Super 03381105 ESPC for Biomass and Alternative High potential for a Good potential for a Methane Fuels, or BAMF; contact biomass cofiring project biomass cofiring project information can be found later in (##) State average tipping Locations of recent local fee ($/ton)* biomass supply studies this publication. To encourage *Source: Chartwell Information Publishers, Inc., 1997. new projects under the BAMF Super ESPC, the National EnergyFigure 6. Average tipping fee and locations of local biomass supply studies Technology Laboratory (NETL)(Chartwell 1997, Wiltsee 1998). has compiled a database thatCoal-fired federal boilers in the biomass if annual coal use is high identifies federal facilities within20 states indicated in the study enough to obtain significant 50 miles of 10 or more potentialwould be promising for cofiring annual cost savings—enough to sources of wood waste.6 — FEDERAL ENERGY MANAGEMENT PROGRAM
  • 11. Federal Technology AlertCost-Saving Mechanisms mated the quantities and costs of dry biomass would have a heatingCofiring operations are not imple- unused and discarded wood resi- value of about 7,000 Btu/lb, com-mented to save energy—they are dues in the United States, large pared with an average of 11,500implemented to reduce energy quantities of biomass are available Btu/lb for the coal used at DoDcosts as well as the cost of other at delivered costs well below the facilities. Each ton of biomassfacility operations. In a typical $2.10 per million Btu average will thus offset 7,000/11,500 =cofiring operation, the boiler price of coal at the DoD facilities. 0.61 ton of coal. If the biomassrequires about the same heat Coal prices at other federal facili- is used to replace coal at $49/ton,input as it does when operating ties are likely to be similar. each ton of biomass is worthin a fossil-fuel-only mode. When $49/ton x 0.61 = $30 in fuel cost For example, if 15% of the coalcofiring, the boiler operates to savings. The typical cost of pro- used at a boiler were replaced bymeet the same steam loads for cessing biomass waste material biomass delivered to the plant forheating or power-generation into a form suitable for use in a $1.25 per million Btu, annual fueloperations as it would in fossil- boiler is $10 per ton, so the net cost savings for the average DoDfuel-only mode; usually, no costs savings per ton of biomass boiler described above would bechanges in boiler efficiency residues could be about $56: more than $120,000. Neither theresult from cofiring unless a $66/ton for the fuel and landfill cofiring rate of 15% of the boilersvery wet biomass is used. With cost savings minus $10/ton for total heat input, nor the deliveredno change in boiler loads, and the biomass processing cost. This price of $1.25 per million Btu, isno change in efficiency, boiler assumes that the biomass is avail- unrealistic, especially for stokerenergy usage will be the same. able at no additional transporta- boilers. Higher cofiring rates andThe primary savings from cofiring tion costs, as is the case at the lower biomass prices are commonare cost reductions resulting from Savannah River Site. in current cofiring projects. Note(1) replacing a fraction of high- that the cost of most biomass If the average DoD facility using acost fossil fuel purchases with residues will range from $2 to coal-fired boiler could obtain bio-lower cost biomass fuel, and (2) $3 per million Btu, so successful mass fuel by diverting its ownavoiding landfill tipping fees or cofiring project operators must residues from landfill disposal,other costs that would otherwise try to obtain the biomass fuel the net annual cost savings wouldbe required to dispose of the at a low price. be about $560,000 per year. Thisbiomass. would require about 10,000 tons The average landfill tipping fee inAccording to data obtained from of biomass residues per year, a the United States is about $36 perthe Defense Energy Support quantity higher than most federal ton of material dumped. AverageCenter (DESC), the average facilities generate internally. The tipping fees for each state aredelivered cost of coal for 18 coal- savings generated by a real cofir- shown in Figure 6. If significantfired boilers operated by the ing project would be expected to quantities of clean biomassDepartment of Defense (DoD) fall somewhere between the residues—such as paper, card-was about $49 per ton in 1999, two examples given here— board, or wood—are generatedor about $2.10 per million Btu. between $120,000 and $560,000 at a federal site, and if some of(The average coal heating value per year. They would probably that material can be diverted fromfor those boilers is about 11,500 depend on using some biomass landfill disposal and used as fuelBtu/lb) Coal costs for those facili- materials generated on site and in a boiler, the savings generatedties ranged from $1.60 to $3 per some supplied by a third party. would be equivalent to aboutmillion Btu, depending on the $66 per ton of biomass: $36/tonlocation, coal type, and annual Other Benefits by avoiding the tipping fee, andquantity consumed. The average $30/ton by replacing the coal When used as a supplemental fuelannual coal cost for these boilers with biomass. Since biomass has in an existing coal boiler, biomasswas about $2 million and ranged a lower heating value than coal, can provide the following bene-from $28,000 to $8.9 million per it takes more than one ton of bio- fits, with modest capital outlaysyear. According to three independ- mass to offset the heat provided for plant modifications:ently conducted studies that esti- by one ton of coal. A ton of fairly FEDERAL ENERGY MANAGEMENT PROGRAM — 7
  • 12. Federal Technology Alert• Reduced fuel costs. Savings in • Renewable energy when needed. modifications to existing opera- overall production costs can Unlike other renewable energy tional procedures, such as increas- be achieved if inexpensive technologies like those based ing over-fire air, may also be nec- biomass fuel sources are avail- on solar and wind resources, essary. Increased fuel feeder rates able (e.g., clean wood waste). biomass-based systems are are also needed to compensate for Biomass fuel supplies at prices available whenever they are the lower density and heating 20% or more below current needed. This helps to accelerate value of biomass. This does not coal prices will usually pro- the capital investment payoff usually present a problem at fed- vide the cost savings needed. rate by producing more heat eral facilities, where boilers typi-• Reduced sulfur oxide and nitrogen or power per unit of installed cally operate below their rated oxide emissions. Because of dif- capacity. output. When full rated output ferences in the chemical is needed, the boiler can be oper- • Market-ready renewable energy composition of biomass and ated in a coal-only mode to avoid option. Cofiring offers a fast- coal, emissions of acid rain derating. track, low-cost opportunity precursor gases—sulfur oxides to add renewable energy Expected fuel sources and boiler (SOx) and nitrogen oxides capacity economically at type dictate fuel processing (NOx)—can be reduced by federal facilities. requirements. For suspension replacing coal with biomass. firing in pulverized coal boilers, Because most biomass has • Fuel diversification. The ability biomass should be reduced to a nearly zero sulfur content, to operate using an additional particle size of 0.25 in. or smaller, SOx emissions reductions fuel source provides a hedge with moisture levels less than occur on a one-to-one basis against price increases and 25% when firing in the range with the amount of coal supply shortages for existing of 5% to 15% biomass on a heat (heat input) offset by the fuels such as stoker coals. In input basis. Equipment such as biomass. Reducing the coal a cofiring operation, biomass supply to the boiler by 10% hoggers, hammer mills, spike rolls, can be viewed as an opportu- will reduce SOx emissions and disc screens may be required nity fuel, used only when the by 10%. Mechanisms that to properly size the feedstock. price is favorable. Note that lead to NOx savings are Local wood processors are likely administrative costs could more complicated, and to own equipment that can ade- increase because of the need relative savings are typically quately perform this sizing in to purchase multiple fuel less dramatic than the SOx return for a processing fee. Other supplies; this should be reductions are, on a percent- boiler types (cyclones, stokers, considered when evaluating age basis. and fluidized beds) are better suited this benefit. to handle larger fuel particles.• Landfill cost reductions. Using • Locally based fuel supply. The waste wood as a fuel diverts Two common forms of processed most cost-effective biomass the material from landfills biomass are shown in Figure 7, fuels are usually supplied and avoids landfill disposal along with a typical stoker coal, from surrounding areas, so costs. shown in the center of the photo. economic and environmental Recent research and demonstra-• Reduced greenhouse-gas emissions. benefits will accrue to local tion on several industrial stoker Sustainably grown biomass is communities. boilers in the Pittsburgh area has considered a greenhouse-gas- shown that wood chips (on the neutral fuel, since it results in Installation Requirements right) are preferable to mulch-like no net carbon dioxide (CO2) Specific requirements depend on material (on the left) for cofiring in the atmosphere. Using bio- the site that uses biomass in cofir- with coal in stoker boilers that mass to replace 10% of the coal ing. In general, however, cofiring have not been designed or in an existing boiler will reduce biomass in an existing coal boiler previously reconfigured for the net greenhouse-gas emis- requires modifications or addi- multifuel firing. The chips are sions by approximately 10% if tions to fuel-handling, processing, similar to stoker coal in terms the biomass resource is grown storage, and feed systems. Slight of size and flow characteristics; sustainably.8— FEDERAL ENERGY MANAGEMENT PROGRAM
  • 13. Federal Technology Alerttherefore, they cause minimal The potential savings resulting occur. In terms of CO2 reductions,problems with existing coal- from using the technology at this would be equivalent to remov-handling systems. Using a mulch- typical federal facilities with ing about 1,000 average-sizedlike material, or a biomass supply existing coal-fired boilers were automobiles from U.S. highways.with a high fraction of fine parti- estimated as part of the technol- Additional indirect benefits couldcles (sawdust size or smaller) can ogy-screening process of FEMP’s also occur. If the biomass fuelcause periodic blockage of fuel New Technology Demonstration would otherwise be sent to a land-flow openings in various areas activities. Payback periods are fill to decay over a period of time,of the conveying, storage, and usually between one and eight methane (CH4) would be releasedfeed systems. These blockages years, and annual fuel cost sav- to the atmosphere as a by-productcan cause significant maintenance ings range from $60,000 to of the decomposition process,increases and operational prob- $110,000 for a typical federal assuming no landfill-gas-capturinglems, so fuel should be processed boiler. Savings depend on the system is installed. Since CH4 isto avoid those difficulties. With availability of low-cost biomass 21 times more powerful than CO2properly sized and processed feedstocks. The savings would in terms of its ability to trap heatbiomass fuel, cofiring operations be greater if the federal site can in the atmosphere and increasehave been implemented success- avoid landfill costs by using its the greenhouse effect, cofiringfully without extensive modifica- own clean biomass waste mate- at one typical coal-fired federaltions to equipment or operating rials as part of the biomass fuel facility could avoid decompositionprocedures at the boiler plant. supply. processes that would be equiva- lent to reducing an additional Estimated Savings and MarketFederal-Sector Potential 29,000 tons of CO2 emissionsPotential per year. The National Renewable EnergyA large percentage of federal facili- Laboratory (NREL) conducted a Payback periods using cofiringties with coal-fired boilers have study for FEMP of the economic at suitable federal facilities arethe potential to benefit from this and environmental impacts of between one and eight However, as noted, biomass cofiring in existing fed- Annual cost savings range fromthe potential is highest in areas eral boilers, as well as associated about $60,000 to $110,000 forwith high coal prices, easy-to- savings. Results of the study are a typical federal boiler, if low-obtain biomass resources, and presented in Tables 3 through 6 cost biomass feedstocks are avail-high landfill tipping fees. on pages 10 and 11. As shown in able. There are more than 1500 Table 6, cofiring bio- industrial-scale stoker boilers in mass with coal at operation in the United States. one typical coal- If federal technology transfer fired federal facility efforts result in cofiring projects will replace almost at 50 boilers (this is about 7% 3,000 tons of coal of existing U.S. stokers), the per year, could resulting CO2 reductions would divert up to about be about 405,000 tons/yr (the 5,000 tons of bio- equivalent of removing about mass from landfills, 50,000 average-size cars from U.S. and will reduce net highways), and SO2 reductions carbon dioxide would be about 6,700 tons/yr. (CO2) emissions by If all biomass materials used in more than 8,000 these boilers were diverted from tons per year and landfills with no gas capture, theFigure 7. Comparison of two biomass residues with coal. sulfur dioxide (SO2) greenhouse-gas equivalent of anBecause they are similar in size and flow characteristics, emissions by about additional 1.45 million tons ofwood chips (right) flow more like coal (center) in stoker 136 tons per year. CO2 emissions would be avoided.boilers. Wood chips can thus be used in existing boilers Reductions in NOxwith minimal modifications to fuel-handling systems. emissions could also (Continued on page 11)Mulch-like processed wood (left) is more problematic. FEDERAL ENERGY MANAGEMENT PROGRAM — 9
  • 14. Federal Technology AlertTable 3. Example economics of biomass cofiring in power generation applications (vs. 100 percent coal). Net Example Heat Total Annual Production Production Plant from Biomass Unit Cost for Cost Payback Cost, no Cost, with Size Biomass Power Cost Cofiring Savings Period Cofiring Cofiring Boiler Type (MW) (%) (MW) ($/kW)1 Retrofit ($) ($/yr)2 (years) (¢/kWh)3 (¢/kWh)3 Stoker (low cost) 15 20 3.0 50 150,000 199,760 0.8 5.25 5.03 Stoker (high cost) 15 20 3.0 350 1,050,000 199,760 5.3 5.25 5.03 Fluidized bed 15 15 2.3 50 112,500 149,468 0.8 5.41 5.24 Pulverized coal 100 3 3.0 100 300,000 140,184 2.1 3.26 3.24 Pulverized coal 100 15 15.0 230 3,450,000 700,922 4.9 3.26 3.15Notes:1Unit costs are on a per kW of biomass power basis (not per kW of total power).2Net annual cost savings = fuel cost savings – increased O&M costs.3Based on data obtained from EPRIs Technical Assessment Guide, 1993, EIAs Costs of Producing Electricity, 1992, UDIs Electric Power Database, EPRI/DOEs Renewable Energy Technology Characterizations, 1997, coal cost of $2.10/MBtu, biomass cost of$1.25/MBtu, and capacity factor of 70%.Table 4. Example environmental impacts of cofiring in power generation applications (vs. 100 percent coal). Example Annual Annual Annual Plant Heat Reduced Biomass CO2 SO2 NOx Size from Coal Use Used Savings Savings Period Boiler Type (MW) Biomass (tons/yr) (tons/yr)1 (tons/yr)2 (tons/yr) (tons/yr) Stoker (low cost) 15 20% 10,125 16,453 27,843 466 N/A Stoker (high cost) 15 20% 10,125 16,453 27,843 466 N/A Fluidized bed 15 15% 7,578 12,314 20,839 349 N/A Pulverized coal 100 3% 7,429 12,072 20,430 342 N/A Pulverized coal 100 15% 37,146 60,362 102,151 1,709 N/ANotes:1Depending on the source of biomass, “biomass used” could be avoided landfilled material.2Carbon savings can easily be calculated from CO savings (i.e., carbon savings = 12/44 x CO savings). 2 2Table 5. Example economic of biomass cofiring in heating applications (vs. 100 percent coal). Example No. of Heat from Biomass Total Cost Net Annual Payback Boiler Size Boilers Biomass Capacity Unit Cost for Cofiring Cost Savings Period (steam lb/hr) at Site (steam lb/hr) (steam lb/hr) ($/lb/hr)1 Retrofit ($) ($/yr)2 (years) 120,000 2 15% 36,000 2.8 100,075 41,628 2.4Notes:1Unit costs are on a per unit of biomass capacity basis (not per unit of total capacity).2Assumptions: coal cost of $2.10/MBtu and capacity factor of 25% (based on data from coal-fired federal boilers), biomass cost of$1.25/MBtu.10— FEDERAL ENERGY MANAGEMENT PROGRAM
  • 15. Federal Technology AlertTable 6. Potential environmental impact of cofiring in heating applications (vs. 100 percent coal). Annual Annual Annual No. of Reduced Biomass CO2 SO2 NOx Cofiring Coal Use Used Savings Savings Period Projects1,2 (tons/yr) (tons/yr)3 (tons/yr)4 (tons/yr) (tons/yr) 1 2,947 5,057 8,103 136 N/A 2 5,893 10,114 16,206 271 N/A 10 29,466 50,570 81,030 1,355 N/A 50 147,328 252,851 405,151 6,777 N/ANotes:1There are approximately 1500 industrial stoker boilers operating today.2Assumptions for the average project were: 120,000 lb/hr steam capacity per boiler, 2 boilers at site, 15% heat from biomass, and a 25% capacity factor.3Depending on the source of biomass, “biomass used” could be avoided landfilled material.4Carbon savings can easily be calculated from CO savings (i.e., carbon savings = 12 / 44 x CO savings). 2 2Laboratory Perspective that, in general, NOx emissions be used more easily as fuel atSince the 1970s, DOE and NETL decrease with cofiring as a result existing coal-fired facilities. Inhave worked with alternative fuels of the lower nitrogen content of a separate project with fundingsuch as solid waste and refuse- most woody biomass in relation from NETL, the University ofderived fuel. In 1995, NETL, to coal, and the greater volatility Missouri-Columbia’s CapsuleSandia National Laboratories, and of biomass in relation to coal. Pipeline Research Center exam-NREL sponsored a workshop that The greater volatility of biomass ined the potential for compactingled to several projects evaluating results in a natural staging of the various forms of biomass intotechnical and commercial issues combustion process that can small briquettes or cubes for useassociated with biomass cofiring. reduce NOx emissions to levels as supplemental fuels at existingThese projects included research below those expected on the coal-fired boilers. The results indi-conducted or sponsored by NETL, basis of fuel nitrogen contents. cated that biomass fuel cubesNREL, Sandia, and Oak Ridge could be manufactured and deliv- DOE, NETL, and the Electric PowerNational Laboratory (ORNL) on ered to a power plant for as little Research Institute (EPRI) also col-char burnout; ash deposition; as $0.30 per million Btu, or less laborated on short-term demon-NOx behavior; cofiring demon- than $5 per ton. This price stration projects. Several of thestration projects using various included all capital and operating demonstrations took place atboiler types, coal/biomass feed- costs for the manufacturing facility federal facilities in the Pittsburghstock combinations, and fuel plus transportation costs within area. They found no significanthandling systems; reburning for a 50-mile radius. The analysis impact on boiler efficiency at lowenhanced NOx reduction; and the assumed the facility would levels of cofiring. Fuel procure-use of ash. These efforts have led collect a $15-per-ton tipping ment, handling, and preparationto improved and documented fee for biomass delivered to the were found to require specialknowledge about the impacts site. See the bibliography for attention.of cofiring biomass with coal more detailed information onin a wide range of circumstances. In addition, DOE’s Idaho National biomass cofiring research activities Energy and Environmental Labor- and published results of researchResults from a joint Sandia/NETL/ atory (INEEL) and DOE’s Savan- led by DOE and its laboratories.NREL project found that in terms nah River Site have biomass-of slagging and fouling, wood was cubing equipment that can Applicationmore benign than herbaceous convert paper and wood waste This section addresses technicalcrops. It has also been shown materials into a form that can aspects of biomass cofiring in FEDERAL ENERGY MANAGEMENT PROGRAM — 11
  • 16. Federal Technology Alertcoal-fired boilers, including the access to local expertise in dirt. It may also be possiblerange of situations in which cofir- collecting and processing to arrange storage throughing technology can be used best. waste wood. This expertise the biomass fuel provider.First, prerequisites for a successful can be found primarily • Receptive plant operators at thebiomass cofiring application are among companies specializ- federal facility. At the verydiscussed, as well as the factors ing in materials recycling, least, increases will bethat influence the cost-effective- mulch, and wood products. necessary in administrativeness of projects. Design and inte- • Boiler plant equipped with a bag- activities associated withgration considerations are also house. Cofiring biomass with adding a new fuel to a boilerdiscussed and include equipment coal has been shown to plant’s fuel mix. In addition,and installation costs, installation increase particulate emissions new or additional boiler con-details, maintenance, and permit- in some applications in com- trol and maintenance proce-ting issues. parison to coal-only opera- dures will be required to use tion. If the existing facility is biomass effectively. AsApplication Prerequisites already equipped with a bag- opposed to a capital improve-The best opportunities for cofiring house or cyclone separation ment project, which requiresoccur at sites in which many of devices, this should not be a one-time installation andthe following criteria apply: significant problem; in other minimal attention afterwards• Existing, operational coal-fired words, it should not cause (such as equipment upgrades), boiler. It is possible to cofire noncompliance with particu- a cofiring operation requires biomass with fossil fuels late emissions standards. The ongoing changes in fuel pro- other than coal; however, existing baghouse or cyclone curement, fuel-handling, and the similarities in the fuel- typically provides sufficient boiler control operations. handling systems required particulate filtration to allow Receptive boiler plant opera- for both coal and biomass stack gases to remain in com- tors and management are (because they are both solid pliance with air permits. How- therefore instrumental in fuels) usually make cofiring ever, some small coal-fired implementing and sustaining less expensive at coal-fired boilers are not equipped with a successful cofiring project. facilities. An exception could these devices. Instead, they • Favorable regulatory climate for be cofiring applications in use methods such as natural renewable energy. As of Febru- which the biomass fuel is gas overfiring to reduce par- ary 2003, 28 states had either gas piped to the boiler from ticulate emissions. In such enacted electricity restructur- a nearby landfill. Cofiring cases, a new baghouse may ing legislation or issued orders with landfill gas has been be required to permit cofiring to open their electricity mar- done in both coal-fired and biomass at significant input kets to competition. Most of natural-gas-fueled boilers, levels, and this would increase these states have established but is less common than project costs significantly. some type of incentive pro- solid-fuel cofiring because of • Storage space available on site. gram to encourage more the need for a large boiler Unless the biomass is imme- installations of renewable very close to the landfill. diately fed into a boiler’s energy technologies. Since• Local expertise for collecting and fuel-handling system upon biomass is a renewable energy processing biomass. Most boiler delivery, a temporary staging resource, some states may operators at federal facilities area at the boiler plant will provide favorable conditions are not likely to be interested be needed to store processed for implementing a cofiring in purchasing and operating biomass supplies. An ideal project through incentive equipment to process biomass storage facility would have programs, technical assis- into a form that can be used at least a concrete pad and tance, or flexible permitting as boiler fuel.Thus, it is advan- a roof to minimize the accu- procedures. tageous for the facility to have mulation of moisture and12 — FEDERAL ENERGY MANAGEMENT PROGRAM
  • 17. Federal Technology AlertCost-Effectiveness Factors viable at nearly any federal Where to ApplyThe list below presents the major facility. This amount of wood The most common applications contains 40 times the amountfactors influencing the cost-effec- for biomass cofiring are at coal- of energy supplied by coal totiveness of biomass cofiring appli- fired boilers located in areas with all DoD-operated federal facili-cations. The worksheets in Appen- an adequate, reliable supply of ties in 1999.dix B provide procedures for esti- biomass fuel. For a list of statesmating total project cost savings • Landfill tipping fees. High local in which these conditions arebased on easy-to-obtain informa- landfill tipping fees increase most likely to occur, see Table 2tion for any federal facility with the probability that low-cost and Figures 5 and 6.a coal-fired boiler. biomass supplies could be available for a cofiring proj- What to Avoid• Coal supply price. The higher the ect. Average state landfill coal supply price, the greater Major technical issues and prob- tipping fees are indicated in the potential cost savings from lems associated with implement- Figure 6. The average U.S. implementing a biomass cofir- ing a biomass project at a federal tipping fee is about $36 per ing project. Prices above site are listed below. Each problem ton, and the fee ranges from $1.30 per million Btu are can be addressed with technical about $15 per ton in Nevada usually high enough to make assistance from experts with expe- to about $74 per ton in cofiring worth considering, rience in cofiring projects. New Jersey. especially if some of the other • Slagging, fouling, and corrosion. factors mentioned in this sec- • Boiler size and usage patterns. Some biomass fuels have high tion are also favorable. Since Boiler size and capacity factor alkali (principally potassium) the average delivered coal price were considered in the initial or chlorine content, or both. for boilers operated by DoD screening process (see Figure 5). Larger, high-capacity-factor This can lead to unmanageable was about $2.10 per million ash deposition problems on Btu in 1999, and ranged from facilities (those that operate at high loads year-round) heat exchange and ash- $1.60 to $3.00 per million Btu, handling surfaces. Chlorine in coal prices at nearly all federal can use more biomass and will realize greater annual combustion gases, especially facilities should be high at high temperatures, can enough to make biomass cost savings. This in turn reduces project payback cause accelerated corrosion cofiring worth considering. of combustion system and periods. Because the amount• Biomass supply price. Abundant of environmental paperwork flue gas clean-up components. local supplies of low-cost bio- needed is significantly less if These problems can be mini- mass are necessary for cost- less than 5,000 tons of coal mized or avoided by screening effective biomass cofiring proj- are burned annually, smaller fuel supplies for materials high ects. This is most likely to occur facilities might also want to in chlorine and alkalis, by lim- near cities, wood-based indus- consider cofiring. iting the biomass contribution tries, or landfills and material to boiler heat input to 15% or recycling facilities where wood • Boiler modifications and equipment less, by using fuel additives, or waste is collected. NREL con- additions required. Start-up costs by increased sootblowing. ducted a study that examined are a key consideration in eval- Additional site-specific adjus- national waste wood availa- uating any cofiring project. The ments may be necessary. bility and costs based on cost of modifying an existing Annual crops and agricultural detailed local data gathered facility to use biomass or to residues, including grasses and from 30 cities throughout purchase equipment to prepare straws, tend to have high the United States. The study biomass for cofiring can range alkali and chlorine contents. indicates that more than from nearly nothing to as In contrast, most woody mate- 60 million tons of wood much as $6/lb per hour of rials and waste papers are low waste per year could be avail- boiler steaming capacity. in alkali and chlorine. As a pre- able at a low enough cost to caution, a sample of each new make cofiring economically type of fuel should be tested for FEDERAL ENERGY MANAGEMENT PROGRAM — 13
  • 18. Federal Technology Alert both chlorine and alkali before • Boiler efficiency losses. Some Equipment Integration use. For further details on the design and operational A typical stoker boiler is shown in alkali deposits associated with changes are needed to maxi- Figure 8. Recent demonstration biomass fuels, including recom- mize boiler efficiency while projects of stoker boilers in Pitts- mendations for fuel testing maintaining acceptable opac- burgh, Pennsylvania; Idaho Falls, methods and specifications, ity, baghouse performance, Idaho; and Aiken, South Carolina, see Miles et al. 1996. and so on. Without these have shown that properly sizing adjustments, boiler efficiency the biomass fuel helps to avoid• Fuel-handling and processing and performance can decrease. the need for modifications to the problems. Certain equipment For example, boiler efficiency existing boiler. The Pittsburgh and processing methods are losses of 2% were measured project used premixed coal and required to reduce biomass during cofiring tests at a pul- wood chips. As indicated in Figure to a form compatible with verized coal boiler at a heat 8, no modifications were needed coal-fired boilers and flue- input level from biomass of to deliver the mixed fuel to the gas-handling systems. Most 10% (Tillman 2000, p. 373). dump grate after the switch from coal boiler operators are not Numerous cofiring projects coal-only supplies. However, cofir- familiar with biomass process- have demonstrated that effi- ing biomass in an existing coal ing, so technical assistance ciency and performance boiler usually requires at least may be needed to help make losses can be minimized slight modifications or additions the transition to biomass with proper attention, how- to fuel-handling, processing, stor- cofiring. Some cofiring facili- ever. These losses should be age, and feed systems. Specific ties have found it more con- included in the final eco- requirements vary from site to site. venient and cost-effective to nomic evaluation for a project. have biomass processed by a Fuel processing requirements are third-party fuel supplier; in • Negative impacts on ash markets. dictated by the fuel source and some cases, this is their coal Concrete admixtures represent boiler type. For suspension firing supplier. When wood is used, an important market for some in pulverized coal (PC) boilers, chips tend to work much coal combustion ash by-prod- biomass should be reduced to better than mulch-like mate- ucts. Current ASTM standards a maximum particle size of rial. Large quantities of fine, for concrete admixtures require 0.25 in. at moisture levels of sawdust-like material should that the ash be 100% coal ash. less than 25%. When firing in also be avoided because they Efforts are under way to demon- the range of 5% to 15% bio- plug up the fuel supply and strate the suitability of com- mass (on a heat input basis), storage system. mingled biomass and coal ash a separate injection system is in concrete admixtures, but in normally required. For firing• Underestimating fuel acquisition small amounts of biomass in the near term, cofired ash will efforts. Securing dependable, a PC boiler (less than 5% of not meet ASTM specifications. clean, economical sources of total heat), the biomass can be This is a serious problem for biomass fuels can be time- blended with the coal before some utility-scale power plants consuming, but this is one of injection into the furnace. that obtain a significant amount the most important tasks in of revenue from selling ash. Additional processing and handling establishing a biomass project. Since most federal facilities equipment requirements make Federal facilities that already dispose of ash rather than separate injection systems more have staff with experience in sell it, this issue should not expensive than blended-feed sys- aggregating and processing be a problem; however, ash tems, but they offer the advantage biomass are ideal sites for disposal methods at each of higher biomass firing rates. projects. In most cases, how- potential project site should Cyclone, stoker, and fluidized-bed ever, technical assistance be considered early in the boilers are better suited to handle will probably be required evaluation process to avoid larger fuel particles, and they are in this area. future problems. thus usually less expensive to mod- ify than PC boilers. In general,14 — FEDERAL ENERGY MANAGEMENT PROGRAM
  • 19. Federal Technology Alerteach boiler and fuel combination Codes and Standards input) is cofired with coal or woodmust be carefully evaluated to Permit requirements vary from have been implemented or are inmaximize boiler efficiency, mini- site to site, but a facility’s emis- progress. Eleven of these projectsmize costs, and avoid combustion- sions permits—even for limited- involve coal-fired boilers and fourrelated problems in the furnace. term demonstration projects— involve wood-fired units. They usually have to be modified for include the coal-fired CapitalMaintenance cofiring projects. Results from Heating Plant in Washington, D.C.Maintenance requirements for earlier cofiring projects in which Such projects do not eliminateboilers cofiring biomass and coal emissions were not negatively the possibility of cofiring biomassare similar to those for coal-only affected can be helpful during with natural gas and coal, how-boilers. However, slight changes the permit modification process. ever. If biomass can be obtainedto previous operational proce- Air permitting officials also may more cheaply than coal and gas,dures, such as increasing over- need detailed chemical analyses using biomass could help offsetfire air and fuel feeder speeds, of biomass fuel supplies and the cost of the gas.may be needed. For a project to a fuel supply plan to evaluatebe successful, the biomass fuel the permit requirements for a Costsmust be processed before cofiring cofiring project. NETL and the Cofiring system retrofits requireto avoid large increases in current University of Pittsburgh are relatively small capital invest-maintenance levels. already developing this type ments per unit of capacity, in of information. Preliminary comparison to those requiredEquipment Warranties results can be found in several for most other renewable energyIf additional equipment is required papers listed in the bibliography. technologies and carbon seques-to implement a cofiring project, it tration alternatives. Costs as low Because of increases in regulationsis most likely to be commercially as $50 to $100/kW of biomass for particulate emissions andavailable. Therefore, it will carry power can be achieved for stokers, increases in the availability ofthe standard manufacturer’s war- fluidized beds, and low-percentage natural gas, some federal boilersranty, which is usually a mini- (less than 2% biomass on a heat are being converted from coal tomum of one year for parts. Instal- basis) cofiring in cyclone and PC natural gas despite the higher cost.lation labor usually carries a one- boilers. For heating applications, Fifteen projects in which naturalyear warranty, as well. this is equivalent to about $3 to gas (at about 10% of boiler heat $6/lb per hour of steaming capacity. Retrofits for high-percentage Chute cofiring (up to 15% of the total heat input) at a pulverized coal 03381107 (PC) boiler are typically about $200/kW of biomass power capac- ity. Smaller applications such as those at federal facilities have Coal higher per-unit costs because they Premixed coal bunker cannot take advantage of econo- and biomass mies of scale. For example, a small-scale stoker application Grating that requires a completely new Gate Chute receiving, storage, and handling Hopper Boiler system for biomass could cost as Gate much as $350/kW of biomass Stoker hopper power capacity.Figure 8. A typical stoker boiler conveyor system receiving premixed coal and When inexpensive biomass fuelsbiomass (Adapted from J. Cobb et al., June 1999). are used, cofiring retrofits have FEDERAL ENERGY MANAGEMENT PROGRAM — 15
  • 20. Federal Technology Alertpayback periods ranging from one Utility Incentives a comprehensive energy audit andto eight years. A typical existing At present, there are no known identifies improvements that willcoal-fired power plant can pro- utility incentives for biomass save energy and reduce utility billsduce power for about 2.3¢/kWh. cofiring at federal facilities. at the facility. The ESCO guaran-However, cofiring inexpensive tees that energy improvementsbiomass fuels can reduce this cost Project Financing and Technical will result in a specified level ofto 2.1¢/kWh. For comparison, a Assistance annual cost savings to the federalnew combined-cycle power plant customer and that these savings DOE FEMP, with support from staffusing natural gas can generate will be sufficient to repay the at national laboratories and DOEelectricity for about 4¢ to 5¢/kWh. ESCO for initial and ongoing Regional Offices, can provideThese generation costs are based work over the term of the con- many services and resources toon large-scale power plants and tract. In other words, agencies help federal agencies implementwould be higher for smaller federal use a portion of their guaranteed energy efficiency and renewablepower plants. energy cost savings to pay for energy projects. Projects can be facility improvements and speci-Tables 3 and 5 provide examples funded through energy savings fied maintenance over the lifeof the economic impacts of bio- performance contracts (ESPCs), of the contract. After the con-mass cofiring projects for power utility energy service contracts, tract ends, additional cost savingsand heating, respectively. Federal or appropriations. Among these accrue to the agency. Contractboilers are most likely to be simi- resources is a technology-specific terms can be up to 25 years,lar to the 15 MW stoker in Table “Super ESPC” for Biomass and depending on the scope of the3 for power generation, and Alternative Methane Fuels (BAMF), project.results shown in Table 5 for heat- which facilitates the use of bio-ing. The stoker unit and the two mass and alternative methane fuels Recognizing that awarding a stand-120,000 lb/hr boilers in Table 5 to reduce federal energy consump- alone energy savings performanceare similar in terms of rated steam tion and energy-related costs. contract (ESPC) can be complexgenerating capacity. At coal costs and time-consuming, FEMP createdof $2.10/MBtu and a delivered For this Super ESPC, biomass fuels streamlined Super ESPCs. Thesebiomass cost of $1.25/MBtu, pay- include any organic matter that is “umbrella” contracts are awardedback periods would be between available on a renewable or recur- to ESCOs selected through a com-one and three years for low-cost ring basis (excluding old-growth petitive bidding process on astoker installations. The payback timber). Examples include dedi- regional or technology-specificperiod for a higher cost stoker cated energy crops and trees, basis. Super ESPCs thus allowinstallation, like the one shown agricultural food and feed crop agencies to bypass the initialin Table 4, row 2, would be about residues, aquatic plants, wood competitive bidding process and5.3 years. and wood residues, animal wastes, to undertake multiple energy and other waste materials. Alter- projects under one contract. EachAll these examples of stoker boilers native methane fuels include Super ESPC project is designed toassume that 20% of the heat input landfill methane, wastewater meet the specific needs of a facility;to the boiler is obtained from bio- treatment digester gas, and coal- it can include a wide range ofmass. Annual fuel cost savings bed methane. energy- and cost-saving improve-thus range from about $60,000 to Through a standard ESPC, an ments, from energy-efficient light-$110,000 for a typical federal energy services company (ESCO) ing to heating and cooling systems.boiler. Payback periods and annualsavings for power-generating boil- arranges financing to develop and Technology-Specific Super ESPCsers tend to be more favorable than carry out energy and water effi- focus on technologies that prom-similarly sized heating boilers, ciency and renewable energy proj- ise substantial energy savings. Thebecause they are usually used ects. This allows federal energy technologies are well suited forfairly consistently throughout and facility managers to improve application in federal facilities,the year, and thus they consume buildings and install new equip- but they are usually not wellmore fuel. ment at no up-front cost. As part enough established in the mar- of the project, the ESCO conducts ketplace to be readily available16 — FEDERAL ENERGY MANAGEMENT PROGRAM
  • 21. Federal Technology Alertthrough routine acquisition ventilation, and cooling systems utility-owned power plants, 18 atprocesses. The ESCOs that have in order to reduce energy costs. municipal boilers, 10 at educationalbeen awarded technology- institutions, and 8 at federal facili- For further information, see thespecific Super ESPC contracts ties. The majority of cofiring proj- FEMP and BAMF Super ESPChave demonstrated their exper- ects have occurred in industrial contacts listed on page 24. Seetise in the application of these applications. These are primarily also the list of manufacturerstechnologies through past per- in the wood products, agricultural, for BAMF Super ESPC contractformance, such as proposing chemical, and textile industries, awardees.and carrying out specific proj- in which companies generate aects defined in DOEs requests biomass waste by-product suchfor proposals. Technology as sawdust, scrap wood, or agricul-Through the BAMF Super ESPC, Performance tural residues. By using the waste In general, facility managers who material as fuel, the companiesFEMP helps to make accessible to have cofired biomass in coal- avoid a certain amount of fossil-federal facilities the energy- and fueled boilers have been pleased fuel purchases and disposal costs.cost-savings benefits of biomassand alternative methane fuels. with the technology’s operation, Several U.S. power generators areProjects carried out under the once initial testing and perform- either considering or actuallyBAMF Super ESPC can reduce ance verification activities have using economical forms of bio-federal energy costs by utilizing been completed. They cite the mass as supplemental fuels inbiomass and alternative methane ease of retrofitting their opera- coal-fired boilers. These gener-fuels in a variety of applications, tions to accommodate biomass ators include the Tennessee Valleysuch as steam boilers, hot-water and the various cost savings and Authority (TVA), New York Stateheaters, engines, and vehicles. emissions benefits as factors that Electric and Gas, Northern StatesThe federal facility, the ESCO, have made their projects Power, Tacoma City Light, andor a third party could own the worthwhile. Southern Company. The TVAbiomass or alternative methane expects annual fuel cost savingsfuel resource. If the fuel requires Field Experience of about $1.5 million as a resulttransport to end-use equipment, Biomass cofiring has been success- of cofiring at the Colbert pulver-that equipment must be located fully demonstrated and practiced ized-coal power plant in Alabama.on federal property. in a full range of coal boiler types Currently, federal facilities use very and sizes, including pulverized-As discussed earlier, some projects little biomass energy. Because of coal boilers, cyclones, stokers,may modify or replace existing DOE FEMP’s commitment to and fluidized beds. At least 182equipment so that the facility reducing energy costs and envi- separate boilers and organizationscan supplant or supplement its ronmental emissions at federal in the United States have cofiredconventional fuel supply with a facilities, the program is working biomass with fossil fuels; althoughbiomass or alternative methane to add biomass cofiring to the this number is not comprehen-fuel. In other projects, ESCOs portfolio of options for improving sive, it is based on the mostcould install equipment that uses the economic and environmental thorough and current list avail-these fuels to accomplish some- performance of these facilities. able. Much of this experiencething altogether new at a federal has been gained as a result of thefacility, such as on-site power energy crisis of the 1970s, when Fuel Supply and Costgeneration. Although the primarycomponent of any project under many boiler plant operators were Savings Calculations seeking ways to reduce fuel costs.this Super ESPC must feature the Appendix B contains worksheets However, a steady number ofuse of a biomass or alternative and supporting data for agencies organizations have continuedmethane fuel, all projects are to evaluate the feasibility of a cofiring operations to reducealso expected to employ a variety biomass cofiring operation in their overall operating costs. Ofof traditional conservation meas- a preliminary manner. These the 182 cofiring operations men-ures, which include retrofits to worksheets were designed to tioned above, 114 (or 63%) havelighting, motors, and heating, permit useful calculations based been at industrial facilities, 32 at FEDERAL ENERGY MANAGEMENT PROGRAM — 17
  • 22. Federal Technology Alerton information that is readily Existing Technology Description directives in Executive Orderavailable at any coal-fueled Savannah River Site uses two mov- 13123 to increase the use ofboiler plant. ing-grate spreader stoker boilers to renewable energy and reduce produce steam. The boilers were emissions, compelled SRS toThe first worksheet in Appendix B manufactured by Combustion pursue the PEF for estimating the amount ofbiomass fuel supply needed for a Engineering and have a capacity of 60,000 lb/hr at full load. Fuel is New Technology Descriptioncofiring application. This can beused to determine the size of bio- fed to the facility from two track The PEF Facility uses a shreddermass processing equipment hoppers of equal size, located next and a cubing machine (see Figurerequired and to evaluate local to the boiler plant. Steam from 9) to convert waste paper intobiomass supplies in relation to the boilers is required year-round cubes that can be used as fuel inthe biomass fuel requirements for process heating applications. the SRS stoker boilers. The cuberof the cofiring project. The second Steam demands peak during win- greatly increases the bulk densityworksheet in Appendix B is for ter as a result of extra comfort- of the waste materials and makesdetermining the annual cost sav- heating loads. Multiclones remove them compatible with fuel con-ings resulting from cofiring with particulates from the stack gases. veyors and handling equipmentbiomass at a coal-fired facility. Before the PEF project, the boilers at the steam plant. used only coal for fuel, and aver-Appendix C provides examples of The PEF Facility has two major age annual coal use at the facilitycompleted worksheets estimating handling sections: the tipping was about 11,145 tons. At a deliv-annual cost savings and biomass floor, where the PEF feedstock ered price of $50 per ton, this coalfuel supplies for DOE’s Savannah is delivered, and the processing cost the site just over $550,000River Site cofiring project. This line, which forms the feedstock per year.project is illustrated in the into cubes. Waste paper is col-following case study. Like many other facilities its size, lected in plastic bags from facil- SRS generates significant quanti- ity offices. The plastic bags con-Case Study ties of scrap paper and cardboard taining the waste paper products products—about 280 tons per are then loaded into dumpstersSavannah River Cofiring Project month. In the years before imple- marked “PAPER PRODUCTSFacility Description menting the PEF cofiring project, ONLY.” These dumpsters areThe primary function of the SRS had been payingDepartment of Energys Savan- about $23 per tonnah River Site (SRS)—constructed to landfill theseduring the early 1950s in Aiken, materials. LandfillSouth Carolina—is to handle, costs for the paperrecycle, and process basic nuclear waste amounted tomaterials such as tritium and about $77,280 perplutonium. The Site Utilities year. In addition,Department at SRS is implement- the site burneding an innovative, cost-effective about 70 tons persystem for cofiring biomass with month of recentlycoal in the sites existing coal- unclassified paperfired stoker boilers. The system in an on-site burnconverts paper and wood waste pit. The annualgenerated from the day-to-day cost of operatingoperations of the site into “process the burn pit wasengineered fuel” (PEF) cubes, about $83,050.which will replace about 20% of These high waste-the coal used at the steam plant. disposal costs, Figure 9. The PEF Facility has a shredder and a cubing combined with machine to convert waste paper into cubes used for fuel in SRS stoker boilers.18 — FEDERAL ENERGY MANAGEMENT PROGRAM
  • 23. Federal Technology Alertcollected by trucks that bring Energy Savingsthis material directly to the PEF This project willfacility tipping floor. Because not decrease theprevious landfill disposal activi- amount of energyties for paper required the same input to the boilersamount of collection and trans- at the steam plant;portation, no new costs were however, it willincurred by diverting the waste replace a signifi-material from the landfill to the cant amount ofPEF Facility. coal with a renew-After they are delivered to the tip- able fuel madeping floor, the plastic bags con- from waste papertaining waste paper are pushed that previouslyinto a hopper. The hopper drops had to be disposedthe paper onto a conveyor that of at great expense.delivers it to a shredder. The waste The worksheets inpaper is shredded in a 300-hp Appendix C showhigh-speed shredder that yields the calculationspieces no larger than 2 in. in needed to deter-length, width, or depth. Water mine that, if thesprays and/or dry granular mate- PEF cubes are 50%rial can easily be added to the of the volume ofshredded paper to incorporate fuel input to theemission-reducing agents into boilers, the heatthe cubes. A dust collection sys- Figure 10. The combined feedstock material is input obtainedtem filters air from the shredder, processed through a machine that extrudes it into from PEF is aboutfeedstock metering box, and cubes approximately 1 in. square and 3 to 4 in. 20% of the total. long. Sample cubes shown in the inset (left tocuber. Dust is removed from the In other words, right) are made of wood, cardboard, and officeairflow in a cyclone separator paper. 20% less coal willand a baghouse filter before be required to pro-being vented to the atmosphere. duce the same an average heating value of about amount of steam. Since the aver-The combined feedstock material 7,500 Btu/lb, compared with age annual coal use before the PEFis processed through a machine 13,000 Btu/lb for the coal. The project was about 11,145 tons perthat extrudes it into cubes approx- cost of operating the PEF facility year, the annual coal savings willimately 1 in. square and 3 to 4 in. is about $7.61 per ton of cubes be about 2,240 tons (11,145 xlong. The cubing machine can be produced. 20% = 2,240). Since the heatingmodified to produce cubes from The PEF cubes are delivered to one value of the coal used at SRS is1/4 to 1 in. square. Sample cubes of the two track hoppers at the about 13,000 Btu/lb, the coal-are shown in the inset of Figure SRS steam plant. Coal is fed from based energy input to the boilers10. From left to right, the cubes one hopper and PEF cubes are fed will be reduced by about 58,240shown in the inset are made of from the other. The two fuels are million Btu per year (2,240 tons xwood, cardboard, and office paper. placed in equal volumes onto the 2,000 lb/ton x 13,000 Btu/lb =The initial bulk density of shred- conveyor that feeds the bucket 58,240 MBtu).ded paper is only about 2 to 4 elevator. The bucket elevatorlb/ft3. The bulk density of the places the coal/PEF mix into thePEF cubes at SRS is from 35 to fuel bunkers, which supply fuel40 lb/ft2. The bulk density of to the boilers.the coal used in the SRS boilersis 80 lb/ft2. The PEF cubes have FEDERAL ENERGY MANAGEMENT PROGRAM — 19
  • 24. Federal Technology AlertTable 7. Savings from the Savannah Performance Test Results review of emissions test results andRiver Site Cofiring Project. procedures for material collection As of February 2003, all equipmentEnergy Savings had been installed and tested at and handling. The project managerCoal supply reduced 2,240 tons/yr the SRS, and the facility is in pre- hopes the facility will be licensed 58,240 MBtu/yr liminary startup mode. The equip- by South Carolina for long-term ment installed at the SRS PEF operation at high levels of bio-Disposal Savings (paper and Facility was previously used in a mass input by the end of 2004.cardboard)PEF cube supply 3,880 tons/yr similar coal-and-biomass cofiringSavings Source Savings demonstration project at INEEL The Technology in in Idaho. The equipment operated PerspectiveReduced coal costs $112,000/yrReduced landfill costs $89,000/yr well for more than a year at INEEL, but its use was discontinued when Biomass cofiring has good poten-Burn pit closure $83,000/yr the steam plant was closed because tial for use at federal facilitiesPEF processing costs ($30,000/yr) of privatization of the utility. When with existing coal-fired boilers.Total Cost Savings $254,000/yr Advantages to federal facilities the equipment was used at INEEL, PEF cubes provided about 25% (by that accrue from using biomassLife-Cycle Cost volume) of the fuel at the steam cofiring technology can include plant, and no major operational reductions in fuel, operating, andDesign, construction, and equip- problems were encountered. landfill costs, as well as in emis-ment purchases for the PEF sions, and increases in their useFacility totaled about $850,000. Test burns at the SRS have shown of domestic renewable energyThe net annual cost savings gener- that no modifications were needed resources. Cofiring biomass withated by the project are expected to current stoker boiler fuel-han- coal is expected to become moreto be about $254,000. These sav- dling equipment to successfully widespread as concerns for energyings are the result of reduced coal fire the PEF/coal mixture. No fuel- security and the environmentpurchases, reduced landfill costs, feeding problems were experi- become greater within agenciesand elimination of burn-pit opera- enced, and no increase in mainte- of the federal government.tional costs. Operating the PEF nance is expected to be necessaryFacility will cost about $30,000 By replacing coal with less expen- at the steam plant.per year. All expected costs and sive biomass fuels, a federal facilitysavings are summarized in Table 7, Emissions measurements made can reduce air emissions such asand associated calculations are during initial tests showed level NOx, SO2, and greenhouse gases.shown in the annual cost savings or reduced emissions for all eight Cofiring with biomass also pro-worksheet in Appendix C. measured pollutants. Because of vides facility managers with aBased on a National Institute of the low (nearly zero) sulfur con- near-term renewable energyStandards and Technology (NIST) tent of wood and paper, sulfur option, and it reduces their fuelBuilding Life-Cycle Costing (BLCC) emissions are expected to price risk by diversifying the fuelcomparative economic analysis decrease. Sulfur emissions are supply. Cofiring also allows facili-(see Appendix E), the net present reduced on a one-to-one basis ties to make use of local fuel sup-value of the project, based on a with the fraction of heat input plies. Finally, only a minimum10-year analysis period, will be obtained from biomass; i.e., number of modifications to exist-more than $1.1 million. With obtaining 20% of the plant’s total ing equipment and operationala savings-to-investment ratio of heat input from PEF cubes will procedures (if any) are required,2.3, the project is cost-effective reduce sulfur emissions by 20%. for the most part, to adapt a boileraccording to federal criteria Opacity levels were also noticed to cofiring with biomass. When(W CFR 43G). The simple pay- to decrease significantly. new equipment is needed, provenback period for the project will technologies are readily available. SRS steam plant personnel havebe less than 4 years. (For details, supported the project. In 2003,see the federal life-cycle costing permitting officials in South Caro-procedures in Appendix D and lina licensed SRS for one year ofthe NIST BLCC comparative operation and evaluation, after aanalysis in Appendix E.)20 — FEDERAL ENERGY MANAGEMENT PROGRAM
  • 25. Federal Technology AlertManufacturers The Babcock & Wilcox Systems Engineering and Company Management Corp.The following list includes compa- 20 South Van Buren Avenue 1820 Midpark Road, Suite Cnies identified as manufacturers of Barberton, OH 44203-0351 Knoxville, TN 37921-5955biomass cofiring equipment. We Phone: 800-BABCOCK Phone: 865-558-9459made every effort to identify cur- www.babcock.comrent manufacturers; however, this Trigen Developmentlisting is not purported to be com- Babcock Borsig Power Corporationplete or to reflect future market (Formerly DB Riley, Inc.) One North Charles Streetconditions. Please see the Thomas 5 Neponset Street Baltimore, MD 21201Register ( Worcester, MA 01606 Phone: 937-256-7378for more information. Phone: 508-852-7100 For Further InformationBiomass Pelletizing Equipment Detroit Stoker Company For more information about theBliss Industries 1510 East First Street BAMF Super ESPC, contact:P.O. Box 910Ponca City, OK 74602 P.O. Box 732 Christopher AbbuehlPhone: 580-765-7787 Monroe, MI 48161 National BAMF Phone: 800-STOKER4 Representative U.S. Department of EnergyCooper Equipment Inc. Foster Wheeler Corporation Philadelphia Regional Office227 South Knox Drive Perryville Corporate Park 100 Penn Square East, Suite 890Burley, ID 83318 P.O. Box 4000 Philadelphia, PA 19107Phone: 208-678-8015 Clinton, NJ 08809-4000 Phone: 215-656-6995CPM Acquisitions Group E-mail: Phone: (908) 730-40002975 Airline Circle www.fwc.comWaterloo, IA 50703Phone: 319-232-8444 SNC-Lavalin Constructors Inc. See also the following (Formerly Zurn/NEPCO) Government Web sites:Sprout Matador, Div. of P.O. Box 97008 Redmond, WA 98073-9708 main.html35 Sherman Street Phone: 425-896-4000, PA 17756-1202 www.nepco.comPhone: 570-546-5811 Biomass and Alternative Methane Fuels (BAMF) Super Antares Group Inc. (2000), TheUMT (Universal Milling ESPC Competitively Awarded Cofiring Connection (CD-ROMTechnology) Inc. Contractors compendium of technical papers8259 Melrose Drive on biomass cofiring), prepared for Constellation Energy SourceLenexa, KS 66214 the U.S. Department of Energy 7133 Rutherford Rd.Phone: 913-541-1703 Biomass Power Program. Suite Baltimore, MD 21244 Antares Group Inc. (May 1999),Boiler Equipment/Cofiring Phone: 410-907-2002 Strategic Plan and Analysis forSystems DTE Biomass Energy, Inc. Biomass Cofiring at FederalALSTOM Power Inc. 54 Willow Field Drive Facilities, prepared for the(Formerly, ABB-Combustion North Falmouth, MA 02556 National Renewable EnergyEngineering Inc.) Phone: 508-564-4197 Laboratory, Task Order No.2000 Day Hill Road KAW-5-15061-01. Energy Systems GroupP.O. Box 500 101 Plaza East BoulevardWindsor, CT 06095 Suite 320Phone: 860-285-3654 Evansville, IN Phone: 812-475-2550 x2541 FEDERAL ENERGY MANAGEMENT PROGRAM — 21
  • 26. Federal Technology AlertAntares Group Inc. (June 1999), Vibrating Grate Technology,” Mitchell, C.P., Overend, R.P., andBiomass Residue Supply Curves for Proceedings of the 4th Biomass Tillman, D.A. (2000), “Cofiringthe United States, prepared for Conference of the Americas, Benefits for Coal and Biomass,”the U.S. Department of Energy’s Elsevier Science Ltd., Oxford, UK. Biomass & Bioenergy (special issue),Biomass Power Program and Vol. 19, No. 6, Elsevier Science Idaho National Engineering andthe National Renewable Energy Ltd., Oxford, UK. Environmental Laboratory (1999),Laboratory, Task Order No. Waste-to-Energy Paper Cuber Project, Muschick, R. (Oct. 1999), Alter-ACG-7-17078-07. Award Application to the Ameri- nate Fuel Facility Economic Study,Thompson, J. (updated annually), can Academy of Environmental Westinghouse Savannah RiverDirectory and Atlas of Solid Waste Engineers, U.S. Department of Company Site Utilities Depart-Disposal Facilities, Chartwell Energy, Idaho Operations Office, ment, Aiken, SC.Information Publishers, Idaho Falls, ID. Tillman, D.A. (ed.) (2000), “Co-Alexandria, VA. Liu, H. (Feb. 2000), Economic Anal- firing Benefits for Coal andCobb, J., et al. (Oct. 1999), ysis of Compacting and Transporting Biomass,” Biomass & Bioenergy“Demonstration of Wood/Coal Biomass Logs for Cofiring with Coal (special issue), Vol. 19, No. 6,Cofiring in a Spreader Stoker,” in Power Plants, Capsule Pipeline Elsevier Science Ltd., Oxford, UK.Sixteenth Annual Pittsburgh Coal Research Center, College of Tillman, D., Plasynski, S., andConference Proceedings, University Engineering, University of Hughes, E. (Sept. 1999), “Biomassof Pittsburgh, Pittsburgh, PA. Missouri-Columbia, CPRC Report Cofiring In Coal-Fired Boilers: No. 2000-1.Cobb, J., et al. (June 1999), “Wood/ Summary of Test Experiences,”Coal Cofiring in Industrial Stoker Makansi, J. (July 1987), “Co-com- Proceedings of the 4th BiomassBoilers,” Proceedings of the of the bustion: Burning biomass, fossil Conference of the Americas, ElsevierAir and Waste Management fuels together simplifies waste Science Ltd., Oxford, UK.Associations 1999 Annual Meeting disposal, cuts fuel cost,” Power, Walsh, M., et al. (January 2000),and Exhibition, St. Louis, MO. McGraw-Hill, New York, NY. Biomass Feedstock Availability inComer, K. (Dec. 1997), “Biomass Miles, T. R.; Miles, T. R. Jr.; Baxter, the United States: 1999 State LevelCofiring,” Renewable Energy L. L.; Bryers, R. W.; Jenkins, B. M.; Analysis, Oak Ridge NationalTechnology Characteristics, EPRI Oden, L. L.; Dayton, D. C.; Milne, Laboratory, Oak Ridge, TN.Topical Report No. TR-109496, T. A. (1996), Alkali Deposits Found Wiltsee, G. (Nov. 1998), UrbanPalo Alto, CA. in Biomass Power Plants. A Prelim- Wood Waste Resource Assessment, inary Investigation of Their ExtentElectric Power Research Institute, prepared for the National and Nature (Vol. I); The Behavior ofet al. (1999), Biomass Cofiring: Field Renewable Energy Laboratory, Inorganic Material in Biomass-FiredTest Results, EPRI Topical Report NREL/SR-570-25918, Golden, CO. Power Boilers—Field and LaboratoryNo. TR-113903, Palo Alto, CA. Experiences (Vol. II), Vol. I: 133 pp.;Giaier, T., and Eleniewski, M. Vol II: 496 pp.; prepared for the[Detroit Stoker Company] (Sept. National Renewable Energy1999), “Cofiring Biomass with Laboratory, NREL Report No.Coal Utilizing Water-Cooled TP-433-8142; Golden, CO.22 — FEDERAL ENERGY MANAGEMENT PROGRAM
  • 27. Federal Technology Alert Appendix A Assumptions and Explanation for Screening AnalysisAverage delivered state coal prices were obtained from the Department of Energy’s Energy Information Admin-istration. Estimated state-level low-cost biomass residue supplies were obtained from Biomass Residue SupplyCurves for the United States (Antares Group Inc., June 1999). Average state landfill tipping fees were obtainedfrom Chartwell Information Publishers.Data for coal costs, biomass supplies, and tipping fees were normalized on a 100-point scale for each of the50 states to capture the relative variation in each item from one state to the next. Weighting factors (rangingfrom one to three) were then applied to the normalized coal cost, biomass supply, and tipping fee data toaccount for the varying importance of these items in terms of the economics of a potential cofiring project.Typically, coal cost was weighted the highest, followed by biomass supply and then tipping fees. The weightedvalues for the normalized coal cost, biomass supply, and tipping fees were then summed together for eachstate, and the state rankings were based on these totals. A wide range of weighting-factor combinations wereattempted to test the sensitivity of the screening tool, including a case in which coal costs, biomass supplies,and tipping fees were weighted equally.This process showed that, although there were slight changes in the ordering of the states from one set ofweighting factors to the next, the relative ranking of each state was very stable from trial to trial over a widecombination of weighting factors. In general, states with high coal costs, high biomass supplies, and hightipping fees ranked very high, while those with low coal costs, low biomass supplies, and low tipping feesranked very low. FEDERAL ENERGY MANAGEMENT PROGRAM — 23
  • 28. Federal Technology Alert Appendix B Blank Worksheets for Preliminary Evaluation of a Cofiring ProjectBiomass Fuel Supply Estimation WorksheetThe amount of biomass needed for a cofiring application depends on the size of the boiler, its loading, thecofiring rate (biomass/coal blend), and the type of biomass used. Biomass fuel supplies required for a cofiringoperation can be estimated as follows, if the rate of coal use in the boiler, the heating value and density ofthe coal, the biomass/coal blend (or cofiring rate), and the heating value anddensity of the biomass are known. DCFmax = daily coal feed rate at maximum rated load _________ tons/day DCFave = daily coal feed rate at average operating load _________ tons/day (based on operating history) ACU = annual coal use (based on operating history) _________ tons/year HVc = average heating value of coal _________ Btu/lb BDc = bulk density of coal _________ lb/ft3 HVb = average heating value of biomass fuel(s) _________ Btu/lb BDb = bulk density of biomass _________ lb/ft3If actual data are not available for HVc, BDc, HVb, and BDb, use the table below to estimate them. As-received Bulk Heating Value Density Fuel Type Example Fuel (Btu/lb) (lb/ft3) Dry biomass (10% moisture) Chipped pallets 7,500 12.5 Moist biomass (30% moisture) Slightly air-dried wood chips or sawdust 6,000 15.0 Wet biomass (50% moisture) Fresh (“green”) wood chips or sawdust 4,500 17.5 Pelletized or cubed biomass Paper or sawdust cubes 7,500 to 8,500 40 Coal Stoker coal 13,000 80Fill in one of the following three blanks and use the indicated equations to compute the other two values: Hb = % biomass, heat basis (% of total heat provided by biomass)_____%, use Eq. 1 and 2 to obtain Mb and Vb Mb = % biomass, mass basis (% of total fuel mass that is biomass)_____%, use Eq. 2 and 3 to obtain Vb and Hb Vb = % biomass, volume basis (% of total fuel volume that is biomass)_____%, use Eq. 4 and 3 to obtain Mb and Hb24 — FEDERAL ENERGY MANAGEMENT PROGRAM
  • 29. Federal Technology AlertTo determine the cofiring rate (percent biomass) on a mass, heat, and volume basis:After selecting a desired/target cofiring rate on either a mass (Mb), heat (Hb), or volume (Vb) basis, use twoof the following equations to estimate the cofiring rate in the other units of measure:The following equations allow you to estimate key biomass fuel supply rates in three units of measure:tons, cubic feet (ft3), and cubic yards (yd3). These numbers may be useful when sizing equipment,scheduling fuel deliveries, and obtaining biomass supply prices.Maximum Daily Biomass Requirements: DBFmax = daily biomass feed rate at maximum rated load (multiple units) FEDERAL ENERGY MANAGEMENT PROGRAM — 25
  • 30. Federal Technology AlertAverage Daily Biomass Requirements: DBFavg = daily biomass feed rate at average rated load (multiple units)Annual Biomass Requirements: ABU = annual biomass use (multiple units)26 — FEDERAL ENERGY MANAGEMENT PROGRAM
  • 31. Federal Technology AlertAnnual Cost Savings Estimation WorksheetACU = annual coal use (based on operating history) ___________ tons/yrHb = % biomass, heat basis (% of total heat provided by biomass) ___________ %UCcoal = unit cost of coal delivered to the boiler facility ___________ $/tonABU = annual biomass use proposed/estimated for boiler facility ___________ tons/yrUCbiomass = unit cost of biomass delivered to the boiler facility ___________ $/tonTF = average tipping fee avoided by diverting biomass from landfill ___________ $/tonCother = other annual costs associated with using biomass ($/yr) ___________ $/yr(not including the cost of delivered biomass; could include increased power consumption by material handling and processingequipment, additional labor costs associated with using biomass, etc.)CSother = other annual cost savings associated with using biomass ($/yr) ___________ $/yr(could include reduced biomass waste handling and transportation costs, recycling savings associated with the new method ofhandling biomass, etc.)Annual Cost SavingsCScoal = annual cost savings from reduced coal consumption ($/yr)Cbiomass = annual cost of biomass delivered to the boiler facility ($/yr)CSlandfill = annual cost savings from avoided landfill fees ($/yr)CStotal = total annual cost savings ($/yr) FEDERAL ENERGY MANAGEMENT PROGRAM — 27
  • 32. Federal Technology Alert Appendix C Completed Worksheets for Cofiring Operation at Savannah River Site Biomass Fuel Supply Estimation Example (from Appendix B) daily coal feed rate at maximum rated load daily coal feed rate at average operating load (based on operating history) annual coal use (based on operating history)28 — FEDERAL ENERGY MANAGEMENT PROGRAM
  • 33. Federal Technology Alert daily biomass feed rate at maximum rated load (multiple units) daily biomass feed rate at average rated load (multiple units)annual biomass use (multiple units) FEDERAL ENERGY MANAGEMENT PROGRAM — 29
  • 34. Federal Technology Alert annual coal use (based on operating history) unit cost of coal delivered to the boiler facility annual biomass use proposed/estimated for boiler facility unit cost of biomass delivered to the boiler facility average tipping fee avoided by diverting biomass from landfill other annual cost savings associated with using biomass ($/yr)30 — FEDERAL ENERGY MANAGEMENT PROGRAM
  • 35. Federal Technology Alert Appendix D Federal Life-Cycle Costing Procedures and the BLCC SoftwareFederal agencies are required to evaluate energy-related investments on the basis of minimum life-cycle costs(LCC) (10 CFR part 436). An LCC evaluation computes the total long-term costs of a number of potentialactions, and selects the action that minimizes long-term costs. In considering retrofits, using existing equip-ment is one potential action; this is often called the baseline condition. The LCC of a potential investmentis the present value of all of the costs associated with the investment over time.The first step in calculating the LCC is to identify various costs: installed cost, energy cost, non-fuels opera-tion and maintenance (O&M) costs, and replacement cost. Installed cost includes the cost of materials pur-chased and the cost of labor, for example, the price of an energy-efficient lighting fixture plus the cost oflabor needed to install it. Energy cost includes annual expenditures on energy to operate equipment. Forexample, a lighting fixture that draws 100 watts (W) and operates 2,000 hours annually requires 200,000watt-hours (2 kWh) annually. At an electricity price of $0.10/kWh, this fixture has an annuals energy costof $20. Non-fuel O&M costs include annual expenditures on parts and activities required to operate theequipment, for example, checking light bulbs in the fixture to see if they are all operating. Replacementcosts include expenditures for replacing equipment upon failure, for example, replacing a fixture when itcan no longer be used or repaired.Because LCC includes the cost of money, periodic and other O&M, and equipment replacement costs, energyescalation rates, and salvage value, it is usually expressed as a present value, which is evaluated by LCC = PV (IC) + PV(EC) + PV (OM) + PV (REP) where PV (x) denotes “present value of cost stream x,” IC is the installed cost, EC is the annual energy cost, OM is the annual non-energy cost, and REP is the future replacement cost.Net present value (NPV) is the difference between the LCCs of two investment alternatives, e.g., between theLCC of an energy-saving or energy-cost-reducing alternative and the LCC of the baseline equipment. If thealternative’s LCC is less than the baseline’s LCC, the alternative is said to have NPV, i.e., it is cost-effective.NPV is thus given by NPV = PV(EC0) - PV(EC1) + PV(OM0) – PV(OM1) + PV(REP0) – PV(REP1) – PV (IC) or NPV = PV(ECS) + PV (OMS) + PV(REPS) – PV (IC) where subscript 0 denotes the baseline condition, subscript 1 denotes the energy cost-saving measure, IC is the installation cost of the alternative (the IC of the baseline is assumed to be zero), ECS is the annual energy cost savings, OMS is the annual non-energy O&M savings, and REPS is the future replacement savings. FEDERAL ENERGY MANAGEMENT PROGRAM — 31
  • 36. Federal Technology Alert Levelized energy cost (LEC) is the break-even price (blended) at which a conservation, efficiency, renewable, or fuel-switching measure becomes cost effective (NPV ≥ 0). Thus, a project’s LEC is given by PV(LEC*EUS) = PV(OMS) + PV(REPS) - PV(IC) where EUS is the annual energy use savings (energy units/yr). Savings-to-investment ratio (SIR) is the total (PV) saving of a measure divided by its installation cost: SIR = (PV(ECS) + PV(OMS) + PV(REPS))/PV(IC)Some of the tedious effort of LCC calculations can be avoided by using the Building Life-Cycle Cost (BLCC)software developed by NIST. For copies of BLCC, call the FEMP Help Desk at 800-363-3732.32 — FEDERAL ENERGY MANAGEMENT PROGRAM
  • 37. Federal Technology Alert Appendix E NIST BLCC 5.0 Comparative Economic Analysis10-Year Case Study Base Case: Coal OnlyAlternative: Biomass and Coal Cofiring General InformationProject name: Westinghouse Savannah River Company Fuel Facility Economic StudyProject location: South CarolinaAnalysis type: Federal analysis, agency-funded projectBase date of study: January 1, 2001Service date: January 1, 2002Study period: 11 years 0 months (January 1, 2001, through December 31, 2011)Discount rate: 3.4% (assumes initial system service date occurs one year after project evaluation begins)Discountingconvention: End-of-year Comparison of Present-Value (PV) Costs: PV Life-Cycle Cost Base Case Alternative SavingsInitial investment costs:Capital requirements as of base date $0 $850,000 -$850,000Future costs:Energy consumption costs $4,220,115 $3,369,685 $850,430Recurring and non-recurring OM&R costs: $1,333,451 $219,134 $1,114,316Capital replacements $0 $0 $0Total PV life-cycle cost $5,553,566 $4,438,819 $1,114,747 Net Savings from Alternative Compared with Base CasePV of non-investment savings $1,864,747– Increased total investment $850,000 Net savings $1,114,747Savings-to-investment ratio (SIR): 2.31Adjusted internal rate of return: 11.59% Payback PeriodEstimated years to payback (from beginning of service period):Simple payback occurs in year 4.Discounted payback occurs in year 4. Energy Savings SummaryNote: Total energy use would remain approximately the same. Figures below indicate reduced coalconsumption. Displaced energy from coal will be replaced with energy from renewable biomass. Energy Average Annual Consumption Life-Cycle Type Base Case (MBtu) Alternative (MBtu) Savings (MBtu) Savings (MBtu) Coal 289,800.0 231,400.0 58,400.0 583,760.2 Emissions Reduction Summary Emission Average Annual Emission Life-Cycle Type Base Case (kg) Alternative (kg) Reduction (kg) Reduction (kg) CO2 27,478,053.40 21,940,723.11 5,537,330.29 55,350,562.35 SO2 235,570.14 188,098.45 47,484.70 474,521.95 FEDERAL ENERGY MANAGEMENT PROGRAM — 33
  • 38. Federal Technology Alert34 — FEDERAL ENERGY MANAGEMENT PROGRAM
  • 39. Federal Technology AlertAbout FEMP’s New Technology DemonstrationsThe Energy Policy Act of 1992 and sector. Additional information on The information in the FTAs typical-subsequent Executive Orders man- Federal Technology Alerts (FTAs) is ly includes a description of the can-date that energy consumption in provided below. didate technology; the results of itsfederal buildings be reduced by screening tests; a description of its35% from 1985 levels by the year Technology Installation performance, applications, and field2010. To achieve this goal, the U.S. Reviews—concise reports describing experience to date; a list of manu-Department of Energy’s Federal a new technology and providing case facturers; and important contactEnergy Management Program study results, typically from another information. Attached appendixes(FEMP) sponsors a series of acti- demonstration or pilot project. provide supplemental informationvities to reduce energy consumption and example worksheets on the Other Publications—we alsoat federal installations nationwide. technology. issue other publications on energy-One of these activities, new technol- saving technologies with potential FEMP sponsors publication of theogy demonstrations, is tasked to use in the federal sector. FTAs to facilitate information-sharingaccelerate the introduction of energy-efficient and renewable technol- between manufacturers and govern-ogies into the federal sector and More on Federal Technology ment staff. While the technologyto improve the rate of technology Alerts featured promises significant fed-transfer. Federal Technology Alerts, our signature eral-sector savings, the FTAs do not reports, provide summary informa- constitute FEMP’s endorsement of aAs part of this effort, FEMP sponsors tion on candidate energy-saving particular product, as FEMP has notthe following series of publications technologies developed and manu- independently verified performancethat are designed to disseminate factured in the United States. The data provided by manufacturers.information on new and emerging technologies featured in the FTAs Nor do the FTAs attempt to charttechnologies: have already entered the market and market activity vis-a-vis the tech- have some experience but are not nology featured. Readers shouldTechnology Focuses—brief infor- note the publication date on themation on new, energy-efficient, in general use in the federal sector. back cover, and consider the FTAsenvironmentally friendly technol- The goal of the FTAs is to improve as an accurate picture of the tech-ogies of potential interest to the the rate of technology transfer of nology and its performance at thefederal sector. new energy-saving technologies time of publication. Product innova- within the federal sector and to pro- tions and the entrance of new man-Federal Technology Alerts— vide the right people in the field ufacturers or suppliers should belonger summary reports that pro- with accurate, up-to-date informa- anticipated since the date of publi-vide details on energy-efficient, tion on the new technologies so cation. FEMP encourages interestedwater-conserving, and renewable- that they can make educated judg- federal energy and facility managersenergy technologies that have been ments on whether the technologies to contact the manufacturers andselected for further study for possi- are suitable for their federal sites. other federal sites directly, and toble implementation in the federal use the worksheets in the FTAs to aid in their purchasing decisions. Federal Energy Management Program The federal government is the largest energy consumer in the nation. Annually, in its 500,000 buildings and 8,000 locations worldwide, it uses nearly two quadrillion Btu (quads) of energy, costing over $8 billion. This represents 2.5% of all primary energy consumption in the United States. The Federal Energy Management Program was established in 1974 to provide direc- tion, guidance, and assistance to federal agencies in planning and implementing energy management programs that will improve the energy efficiency and fuel flexibility of the federal infrastructure. Over the years, several federal laws and Executive Orders have shaped FEMPs mission. These include the Energy Policy and Conservation Act of 1975; the National Energy Conservation and Policy Act of 1978; the Federal Energy Management Improvement Act of 1988; the National Energy Policy Act of 1992; Executive Order 13123, signed in 1999; and most recently, Executive Order 13221, signed in 2001, and the Presidential Directive of May 3, 2001. FEMP is currently involved in a wide range of energy-assessment activities, including conducting new technology demonstra- tions, to hasten the penetration of energy-efficient technologies into the federal marketplace.
  • 40. A Strong Energy Portfolio for a Strong America For More Information EERE Information CenterEnergy efficiency and clean, renewable energy will mean a stronger economy, a cleaner 1-877-EERE-INF orenvironment, and greater energy independence for America. Working with a wide array 1-877-337-3463 state, community, industry, and university partners, the U.S. Department of Energy’sOffice of Energy Efficiency and Renewable Energy invests in a diverse portfolio of General Program Contactsenergy technologies. Ted Collins New Technology Demonstration Program Manager Federal Energy Management Program U.S. Department of Energy 1000 Independence Ave., S.W., EE-92 Washington, DC 20585 Phone: (202)-586-8017 Fax: (202)-586-3000 Steven A. Parker Log on to FEMP’s Web site for information about Pacific Northwest National Laboratory New Technology Demonstrations P.O. Box 999, MSIN: K5-08 Richland, WA 99352 Phone: (509)-375-6366 Fax: (509)-375-3614 You will find links to • A New Technology Demonstration Overview Technical Contacts and Authors • Information on technology demonstrations Sheila Hayter National Renewable Energy Laboratory • Downloadable versions of publications in Adobe Portable 1617 Cole Blvd. Golden, CO 80401 Document Format (pdf) Phone: (303) 384-7519 • A list of new technology projects under way E-mail: Stephanie Tanner • Electronic access to a regular mailing list for new products National Renewable Energy Laboratory when they become available 901 D Street, S.W., Suite 930 Washington, DC 20024 • How federal agencies may submit requests to us to assess Phone: (202) 646-5218 new and emerging technologies E-mail: Kevin Comer and Christian Demeter Antares Group Inc. 4351 Garden City Drive, Suite 301 Landover, MD 20785 Phone: (301) 731-1900 Produced for the U.S. Department of Energy, Energy Efficiency and Renewable Energy, by the National Renewable Energy Laboratory, a DOE national laboratory DOE/EE-0288 June 2004 U.S. Department of Energy Energy EfficiencyPrinted with a renewable-source ink on paper containing at and Renewable Energyleast 50% wastepaper, including 20% postconsumer waste. Bringing you a prosperous future where energy is clean, abundant, reliable, and affordable