DOE/EE-0288

Leading by example, saving and in -Fired taxpayer dollars Using this time-tested -switching technique in existing federal boilers in federal facilities helps to reduce operating costs, increase the use of , and enhance our Executive Summary To help the nation use more domestic 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 matter such as , 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 for energy use at federal facilities are waste and wastepaper. The plant at the Department of Energy’s One of the most attractive and easily implemented biomass energy technologies is cofiring Savannah River Site co- 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 oxide, oxide, and greenhouse-gas emissions. Other benefits, such as decreases in 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: www.eere.energy.gov/femp/ 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. Federal Technology Alert

Payback periods are typically To make economical use of captive investment of $850,000 was between one and eight years, wood waste materials—primarily required, resulting in a simple and annual cost savings could bark and wood chips that are payback period for the project range from $60,000 to $110,000 unsuitable for making paper—the of less than four years. The net for an average-size federal boiler. U.S. pulp and paper has present value of the project, These savings depend on the cofired wood with coal for evaluated over a 10-year analysis availability 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 that than-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 no costs by using self-generated input. Spurred by a need to reduce modification to 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. emissions, an enced, and no increases in main- increasing number of industrial- tenance are expected to be needed Application and -scale boilers outside at the plant. Steam plant the are Biomass cofiring can be applied personnel have been supportive being evaluated for use in cofiring only at facilities with existing of the project. Emissions measure- applications. coal-fired boilers. The best oppor- ments made during initial testing tunities for economically attrac- showed level or reduced emissions tive 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 expected lowing conditions apply: (1) coal (DOE) Savannah River Site (SRS) to be reduced by 20%. Opacity prices 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 year mass 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 series means it is costly to dispose of of successful test burns have been Implementation Barriers biomass; and (5) plant staff and completed to demonstrate accept- For utility-scale generation management are highly motivated able , emissions, and projects, acquiring steady, year- to implement the project success- performance of the boiler and fuel round supplies of large quantities fully. As a rule, boilers producing processing and handling systems, of low-cost biomass can be diffi- less than 35,000 pounds per hour cofiring was expected to begin in cult. But where supplies are avail- (lb/hr) of steam are too small to 2003 on a regular basis. The bio- able, there are several advantages be used in an economically attrac- mass cubes offset about 20% of to using biomass for cofiring opera- tive cofiring project. the coal used in the facility’s two tions at federal facilities. For exam- traveling-grate stoker boilers. The ple, federal coal-fired boilers are Field Experiences project should result in annual coal typically much smaller than cost savings of about $112,000. Cofiring biomass and coal is a time- utility-scale boilers, and they tested fuel-switching strategy that Cost savings associated with avoid- are most often used for space is 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 cations. Thus, they do not have found at coal-fired federal facili- wood from on-site construction utility-scale fuel requirements. ties. However, cofiring has been activities will total about $172,000 In addition, federal boilers needed successfully demonstrated and per year. Net annual savings from for space heating typically operate practiced in all types of coal the project, after subtracting the primarily during winter months. boilers, including pulverized- $30,000 per year needed to oper- During summer months, waste coal boilers, cyclones, stokers, ate the AF cubing facility, will be wood is often sent to the mulch and fluidized beds. about $254,000. An initial capital Federal Technology Alert

market, which makes the wood • Economics is the driving factor. energy efficiency and renewable unavailable for use as fuel. Thus, Project economics largely deter- energy projects. Projects can be federal coal-fired boilers could mine whether a cofiring proj- funded through Energy Savings become 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 these tors behind a cofiring demonstra- been identified will reduce resources is a Technology-Specific tion at the City Brewery overall costs. Larger facilities “Super ESPC” for Biomass and in Pittsburgh, Pennsylvania. with high capacity factors— Alternative 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 methane and 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 supplies federal sites: are obtained at a discount in Through the BAMF Super ESPC, FEMP enables federal facilities • Permit modifications may be comparison to coal. This will to obtain the energy- and cost- required. Permit requirements also reduce payback periods. savings benefits of biomass and vary from site to site, but alternative methane fuels at no modifications to existing Conclusion 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- BAMF Super ESPC contacts and projects, may be required for atories and Regional Offices, offers contract awardees is provided in cofiring projects. many services and resources to 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. Federal Technology Alert Federal Technology Alert

Contents 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 Federal Technology Alert

Abstract 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 activities vert renewable biomass fuels to energy and waste disposal costs in the Department of Energy’s heat or . 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 DOE ated from biomass than from any will depend on the site. But in Office of Energy Efficiency and other renewable energy resource general, cofiring biomass in an Renewable Energy, to provide in the United States. Biomass existing coal-fired boiler involves facility and energy managers cofiring is attracting interest modifying or adding to the fuel with the information they need because 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 facilities. new biomass resources into today’s of boiler at the site will dictate . 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 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 DOE Figure 1. The NIOSH boiler plant was modified 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 also Cofiring 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 fuels in exist- tions are needed for cofiring. ing boilers provides an opportu-

2 — FEDERAL ENERGY MANAGEMENT PROGRAM Federal Technology Alert

About the Technology involves substituting biomass for cles, because biomass is a more a portion of the used volatile fuel. Biomass that does Biomass is organic material from in a boiler. not meet these specifications is living things, including plant likely to cause flow problems in matter such as trees, grasses, Cofiring inexpensive biomass with the fuel-handling equipment or and 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 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 biomass biomass fuel for heat and power. counts toward a federal agency’s Existing Type Size Required The most economical sources of goals for increasing the use of of Boiler (inches) wood fuels are wood residues from renewable energy or “green power” manufacturers and mill residues, Pulverized coal ≤1/4 (environmentally benign electric such as sawdust and shavings; Stoker ≤3 power), and it results in a net cost discarded wood products, such savings to the agency. Cofiring Cyclone ≤1/2 as crates and pallets; woody yard biomass also increases our use of Fluidized bed ≤3 trimmings; right-of-way trim- domestic fuels, thus enhancing mings diverted from landfills; the nation’s energy security. More detailed information follows and clean, nonhazardous wood about the cofiring options for debris resulting from construction This publication focuses on the stoker and pulverized-coal federal and demolition work. Using these most promising, near-term, boilers. materials as sources of energy proven option for cofiring—using recovers their energy value and solid biomass to replace a portion Stoker boilers. Most coal-fired boilers avoids 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 the other disposal methods. cofiring has been successfully schematic in Figure 2. Because demonstrated in nearly all coal- these boilers are designed to fire Biomass energy technologies con- fired boiler types and configura- fairly large fuel particles on travel- vert renewable biomass fuels to tions, including stokers, fluidized ing or vibrating grates, they are heat or electricity using equip- beds, pulverized coal boilers, and the most suitable federal boiler ment similar to that used for cyclones. The most likely opportu- type for cofiring at significant fossil fuels such as , biomass input levels. In these nities at federal facilities will be oil, or coal. This includes fuel- boilers, fuel is either fed onto found at those that have stokers handling equipment, boilers, the grate from below, as in under- and pulverized coal boilers. This steam , and engine gener- feed stokers, or it is spread evenly is because the optimum operating ator sets. Biomass can be used in across the grate from fuel spread- range of cyclone boilers is much solid 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 bed to , more electricity spreader-fired traveling grate stoker boilers have been installed at fed- is generated from biomass than boiler, 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 to a successful cofiring operation ticles burn in suspension above strategy that has been practiced is to appropriately and consistently the grate, while the larger particles for decades in the wood products size the biomass according to the burn on the grate as it moves the industries and more recently in requirements of the type of boiler fuel from the back to the front of utility-scale boilers. Several fed- used. Biomass particles can usually the boiler. The is discharged eral facilities have also cofired be slightly larger than coal parti- from the grate into a hopper at biomass and coal. Cofiring the front of the boiler.

FEDERAL ENERGY MANAGEMENT PROGRAM — 3 Federal Technology Alert

The retrofit requirements for cofir-

ing in a stoker boiler will vary, 03381101 depending on site-specific issues. If properly sized biomass fuel can be delivered to the facility pre- mixed with coal supplies, on-site Gas burners capital expenses could be negligi- ble. Some facilities have multiple Hopper coal hoppers that discharge onto Receiving a common conveyor to feed fuel bin Traveling into the boiler. Using one of the grate Overfire existing coal hoppers and the Boiler air associated conveying equipment injection for biomass could minimize new Figure 2. Schematic of a typical traveling-grate spreader-stoker. capital expenses for a cofiring project. Both methods have been Front end loader successfully employed at federal to blend wood Metal stoker boilers for implementing and coal supplies detector (coal and wood Magnetic a biomass cofiring project. If blend is passed separator Dump conveyor neither of these low-cost options through existing #1 Walking floor trailer coal pulverizers) Dump or dump truck is feasible, new handling and Wood conveyor #2 pile storage equipment will need Scale to be added. The cost of these 03381102 additions is discussed later. Figure 3. Schematic of a blended-feed cofiring arrangement for a pulverized coal boiler. Pulverized coal boilers. There are two primary methods for cofiring bio- heat input basis. If the biomass is the NIOSH Bruceton boiler plant mass 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 with verizers. This is the least expensive cofiring experience include KI method, but it is limited in the Application Domain Sawyer Air Force Base in Michi- amount of biomass that can be The best opportunities for cofiring gan, Fort Stewart in Georgia, Puget fired. With this blended feed biomass with fossil fuels at federal Sound Naval Shipyard in Washing- method, only about 3% or less facilities are at sites with regularly ton, Wright- Patterson Air Force of the boiler’s heat input can be operating coal-fired boilers. Biomass Base in Ohio, Brunswick Naval obtained from biomass at full cofiring has been successfully Air Station in Maine, and the boiler loads because of limitations demonstrated in nearly all coal- Red River Army Depot in Texas. in the capacity of the pulverizer. fired boiler types and configura- More than 100 U.S. companies or The second method, illustrated in tions, including stokers, fluidized organizations have experience in Figure 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 in handling, and storage system opportunities are most likely to operation today. Most are found for biomass, and injecting the be for stoker boilers, but cofiring in industrial applications, in biomass into the boiler through in pulverized coal boilers may which the owner generates a dedicated biomass ports. Although also be economically attractive. significant amount of biomass this 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, or cardboard or agricultural residues to be used—up to 15% more on a biomass cofiring. Two facilities—

4 — FEDERAL ENERGY MANAGEMENT PROGRAM Federal Technology Alert

Metal detector Magnetic separator Conveyor #1 Wood Disc screener pile Grinder Front end Walking floor trailer 03381103 Scale loader or dump truck Rotary airlock feeder

Air Intake Exhaust Separator Bin Dedicated biomass vent injection Existing coal Injection ports

Wood silo Boiler

Scale blower Figure 4. Schematic of a separate-feed cofiring arrangement for a pulverized coal boiler. like orchard trimmings and coffee project, and the next 10 states were Within each group in Table 2, grounds) during . classified as having good potential. states are shown in alphabetical Using these residues as fuel allows See Table 2 and Figures 5 and 6. order, because slight variations organizations to avoid landfill in rankings result from selecting and 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 are in stoker boilers in one of four helpful conditions for econom- Potential State industries: wood products, agricul- ically successful cofiring projects. ture, textiles, and chemicals. High Connecticut It found that the Northeast, South- Potential Delaware east, states, and A screening analysis was done to Florida Washington State are the most determine which states have the Maryland attractive locations for cofiring most favorable conditions for a Massachusetts projects. financially successful cofiring proj- New Hampshire New Jersey ect. The primary factors consid- Utility-scale cofiring projects are New York shown on the map in Figure 5. ered were average delivered state Pennsylvania These sites are in or near states coal prices, estimated low-cost Washington biomass residue supply density identified by the screening model Good Alabama (heat content in Btu of estimated as having good or high potential Potential Georgia for cofiring. This increases confi- available low-cost biomass resi- Indiana dence that the states selected by dues per year per square mile of Michigan state land area), and average state Minnesota the screening process were reason- landfill tipping fees. See Appendix North Carolina able choices. Figure 6 shows the A 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 spondence between the locations were classified as having high Virginia of these facilities and the states potential for a biomass cofiring identified as promising for cofiring.

FEDERAL ENERGY MANAGEMENT PROGRAM — 5 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 cofiring biomass coal plants within the Federal System favor of a particular site. The Figure 5. States with most favorable conditions for biomass cofiring, based on coal-fired boilers in Alaska high 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 ME MT VT (49) ND (50) (46) size, and very high coal prices. OR (19) (26) MN (34) (56) MA The map in Figure 6 indicates ID SD WI NY (48) (26) MI (71) WY (29) (33) RI average landfill tipping fees for (23) (32) NV NE IA PA(51) (41) each state. It also shows cities (31) NJ CT (15) (24) IN OH (74) in which fairly recent local bio- UT IL WA (61) (29) CO (26) (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, NC(30) AZ OK TN(28) as reported in Urban Wood Waste (20) NM AR (16) (21) (18) Resource Assessment (Wiltsee 1998). MS AL SC (25) GA Additional information on poten- TX (19) (25) (29) (23) LA tial biomass resource supplies near AK (22) (42) FL federal facilities can be obtained (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 Energy Figure 6. Average tipping fee and locations of local biomass supply studies Technology Laboratory (NETL) (Chartwell 1997, Wiltsee 1998). has compiled a database that Coal-fired federal boilers in the biomass if annual coal use is high identifies federal facilities within 20 states indicated in the study enough to obtain significant 50 miles of 10 or more potential would be promising for cofiring annual cost savings—enough to sources of wood waste.

6 — FEDERAL ENERGY MANAGEMENT PROGRAM Federal Technology Alert

Cost-Saving Mechanisms mated the quantities and costs of dry biomass would have a heating Cofiring 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 11,500 implemented to reduce energy quantities of biomass are available Btu/lb for the coal used at DoD costs as well as the cost of other at delivered costs well below the facilities. Each ton of biomass facility operations. In a typical $2.10 per million Btu average will thus offset 7,000/11,500 = cofiring operation, the boiler of coal at the DoD facilities. 0.61 ton of coal. If the biomass requires 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 worth $49/ton x 0.61 = $30 in fuel cost in a fossil-fuel-only mode. When For example, if 15% of the coal savings. The typical cost of pro- cofiring, the boiler operates to used at a boiler were replaced by cessing biomass waste material meet the same steam loads for biomass delivered to the plant for into a form suitable for use in a heating or power-generation $1.25 per million Btu, annual fuel boiler is $10 per ton, so the net operations as it would in fossil- cost savings for the average DoD costs savings per ton of biomass fuel-only mode; usually, no boiler described above would be residues could be about $56: changes in boiler efficiency more than $120,000. Neither the $66/ton for the fuel and landfill result from cofiring unless a cofiring rate of 15% of the boiler's cost savings minus $10/ton for very wet biomass is used. With total heat input, nor the delivered the biomass processing cost. This no change in boiler loads, and price of $1.25 per million Btu, is assumes that the biomass is avail- no change in efficiency, boiler unrealistic, especially for stoker able at no additional transporta- energy usage will be the same. boilers. Higher cofiring rates and tion costs, as is the case at the The primary savings from cofiring lower biomass prices are common Savannah River Site. are cost reductions resulting from in current cofiring projects. Note (1) replacing a fraction of high- that the cost of most biomass If the average DoD facility using a cost 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 own avoiding 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 would be required to dispose of the at a low price. be about $560,000 per year. This biomass. would require about 10,000 tons The average landfill tipping fee in of biomass residues per year, a According to data obtained from the United States is about $36 per quantity higher than most federal the Defense Energy Support ton of material dumped. Average facilities generate internally. The Center (DESC), the average tipping fees for each state are savings generated by a real cofir- delivered cost of coal for 18 coal- shown in Figure 6. If significant ing project would be expected to fired boilers operated by the quantities of clean biomass fall somewhere between the Department of Defense (DoD) residues—such as paper, card- two examples given here— was about $49 per ton in 1999, board, or wood—are generated between $120,000 and $560,000 or about $2.10 per million Btu. at a federal site, and if some of per year. They would probably (The average coal heating value that material can be diverted from depend on using some biomass for those boilers is about 11,500 landfill disposal and used as fuel materials generated on site and Btu/lb) Coal costs for those facili- in a boiler, the savings generated some supplied by a third party. ties ranged from $1.60 to $3 per would be equivalent to about million Btu, depending on the $66 per ton of biomass: $36/ton Other Benefits location, coal type, and annual by avoiding the tipping fee, and quantity consumed. The average $30/ton by replacing the coal When used as a supplemental fuel annual coal cost for these boilers with biomass. Since biomass has in an existing coal boiler, biomass was 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 outlays year. 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 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 is needed, the boiler can be oper- ferences in the chemical • Market-ready renewable energy ated in a coal-only mode to avoid composition of biomass and option. Cofiring offers a fast- derating. coal, emissions of 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 (NO )—can be reduced by x 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, SO emissions reductions fuel source provides a hedge x 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 . In input basis. Equipment such as biomass. Reducing the coal a cofiring operation, biomass hoggers, hammer mills, spike rolls, supply to the boiler by 10% can be viewed as an opportu- and disc screens may be required will reduce SOx emissions nity fuel, used only when the to properly size the feedstock. by 10%. Mechanisms that price is favorable. Note that Local wood processors are likely lead to NOx savings are administrative costs could to own equipment that can ade- more complicated, and increase because of the need quately perform this sizing in relative savings are typically to purchase multiple fuel return for a processing fee. Other less dramatic than the SOx supplies; this should be boiler types (cyclones, stokers, reductions are, on a percent- considered when evaluating and fluidized beds) are better suited age basis. this benefit. to handle larger fuel particles. • Landfill cost reductions. Using • Locally based fuel supply. The Two common forms of processed waste wood as a fuel diverts 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 dioxide (CO ) 2 Specific requirements depend on material (on the left) for cofiring in the atmosphere. Using bio- the site that uses biomass in cofir- mass to replace 10% of the coal with coal in stoker boilers that ing. In general, however, cofiring in an existing boiler will reduce have not been designed or biomass in an existing coal boiler the net greenhouse-gas emis- previously reconfigured for requires modifications or addi- sions by approximately 10% if multifuel firing. The chips are tions to fuel-handling, processing, the biomass resource is grown similar to stoker coal in terms storage, and feed systems. Slight sustainably. of size and flow characteristics;

8— FEDERAL ENERGY MANAGEMENT PROGRAM Federal Technology Alert

therefore, 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-sized like 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 could cles (sawdust size or smaller) can ogy-screening process of FEMP’s also occur. If the biomass fuel cause 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 released feed systems. These blockages years, and annual fuel cost sav- to the atmosphere as a by-product can 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-capturing lems, so fuel should be processed boiler. Savings depend on the system is installed. Since CH4 is to avoid those difficulties. With availability of low-cost biomass 21 times more powerful than CO2 properly sized and processed feedstocks. The savings would in terms of its ability to trap heat biomass fuel, cofiring operations be greater if the federal site can in the atmosphere and increase have been implemented success- avoid landfill costs by using its the greenhouse effect, cofiring fully without extensive modifica- own clean biomass waste mate- at one typical coal-fired federal tions to equipment or operating rials as part of the biomass fuel facility could avoid decomposition procedures at the boiler plant. supply. processes that would be equiva- lent to reducing an additional Estimated Savings and Market 29,000 tons of CO emissions Federal-Sector Potential 2 Potential per year. The National Renewable Energy A large percentage of federal facili- Laboratory (NREL) conducted a Payback periods using cofiring ties with coal-fired boilers have study for FEMP of the economic at suitable federal facilities are the potential to benefit from this and environmental impacts of between one and eight years. technology. However, as noted, biomass cofiring in existing fed- Annual cost savings range from the potential is highest in areas eral boilers, as well as associated about $60,000 to $110,000 for with 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 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, the Figure 7. Comparison of two biomass residues with coal. (SO2) greenhouse-gas equivalent of an Because they are similar in size and flow characteristics, emissions by about additional 1.45 million tons of wood chips (right) flow more like coal (center) in stoker 136 tons per year. CO emissions would be avoided. boilers. Wood chips can thus be used in existing boilers 2 with minimal modifications to fuel-handling systems. Reductions in NOx (Continued on page 11) Mulch-like processed wood (left) is more problematic. emissions could also

FEDERAL ENERGY MANAGEMENT PROGRAM — 9 Federal Technology Alert

Table 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 3.15

Notes: 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 EPRI's Technical Assessment Guide, 1993, EIA's Costs of Producing Electricity, 1992, UDI's Database, EPRI/DOE's Renewable Characterizations, 1997, coal cost of $2.10/MBtu, biomass cost of $1.25/MBtu, and 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/A

Notes: 1Depending on the source of biomass, “biomass used” could be avoided landfilled material. 2 Carbon savings can easily be calculated from CO2 savings (i.e., carbon savings = 12/44 x CO2 savings). Table 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 2.4

Notes: 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 Federal Technology Alert

Table 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/A

Notes: 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. 4 Carbon savings can easily be calculated from CO2 savings (i.e., carbon savings = 12 / 44 x CO2 savings).

Laboratory Perspective that, in general, NOx emissions be used more easily as fuel at Since the 1970s, DOE and NETL decrease with cofiring as a result existing coal-fired facilities. In have worked with alternative fuels of the lower nitrogen content of a separate project with funding such as solid waste and refuse- most woody biomass in relation from NETL, the University of derived fuel. In 1995, NETL, to coal, and the greater volatility Missouri-Columbia’s Capsule Sandia 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 compacting led to several projects evaluating results in a natural staging of the various forms of biomass into technical and commercial issues combustion process that can small or cubes for use associated with biomass cofiring. reduce NOx emissions to levels as supplemental fuels at existing These 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 cubes could be manufactured and deliv- NREL, Sandia, and Oak Ridge DOE, NETL, and the Electric Power ered to a power plant for as little National Laboratory (ORNL) on Research Institute (EPRI) also col- as $0.30 per million Btu, or less burnout; ash ; laborated on short-term demon- than $5 per ton. This price NO behavior; cofiring demon- stration projects. Several of the x included all capital and operating stration projects using various demonstrations took place at costs for the manufacturing facility boiler types, coal/biomass feed- federal facilities in the Pittsburgh plus transportation costs within stock combinations, and fuel area. They found no significant a 50-mile radius. The analysis handling systems; reburning for impact on boiler efficiency at low assumed the facility would enhanced NO reduction; and the levels of cofiring. Fuel procure- x collect a $15-per-ton tipping use of ash. These efforts have led ment, handling, and preparation fee for biomass delivered to the to improved and documented were found to require special site. See the bibliography for knowledge about the impacts attention. of cofiring biomass with coal more detailed information on in a wide range of circumstances. In addition, DOE’s Idaho National biomass cofiring research activities Energy and Environmental Labor- and published results of research Results 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 Application more benign than herbaceous convert paper and wood waste This section addresses technical crops. It has also been shown materials into a form that can aspects of biomass cofiring in

FEDERAL ENERGY MANAGEMENT PROGRAM — 11 Federal Technology Alert

coal-fired boilers, including the access to local expertise in dirt. It may also be possible range of situations in which cofir- collecting and processing to arrange storage through ing 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 the biomass cofiring application are among companies specializ- federal facility. At the very discussed, as well as the factors ing in materials recycling, least, increases will be that influence the cost-effective- mulch, and wood products. necessary in administrative ness of projects. Design and inte- • Boiler plant equipped with a bag- activities associated with gration considerations are also house. Cofiring biomass with adding a new fuel to a boiler discussed 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. As Application Prerequisites already equipped with a bag- opposed to a capital improve- The best opportunities for cofiring house or cyclone separation ment project, which requires occur at sites in which many of devices, this should not be a one-time installation and the 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. these devices. Instead, they facilities. An exception could • Favorable regulatory climate for use methods such as natural be cofiring applications in renewable energy. As of Febru- gas overfiring to reduce par- which the biomass fuel is ary 2003, 28 states had either ticulate emissions. In such gas piped to the boiler from enacted electricity restructur- cases, a new baghouse may a nearby landfill. Cofiring ing legislation or issued orders be required to permit cofiring with has been to open their electricity mar- biomass at significant input done in both coal-fired and kets to competition. Most of levels, and this would increase natural-gas-fueled boilers, these states have established project costs significantly. but is less common than 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 and

12 — FEDERAL ENERGY MANAGEMENT PROGRAM Federal Technology Alert

Cost-Effectiveness Factors viable at nearly any federal Where to Apply The list below presents the major facility. This amount of wood The most common applications contains 40 times the amount factors influencing the cost-effec- for biomass cofiring are at coal- of energy supplied by coal to tiveness 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 states mating total project cost savings • Landfill tipping fees. High local in which these conditions are based on easy-to-obtain informa- landfill tipping fees increase most likely to occur, see Table 2 tion 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. ing a biomass project at a federal implementing a biomass cofir- tipping fee is about $36 per site are listed below. Each problem ing project. Prices above ton, and the fee ranges from can be addressed with technical $1.30 per million Btu are about $15 per ton in Nevada assistance from experts with expe- usually high enough to make to about $74 per ton in rience in cofiring projects. cofiring worth considering, New Jersey. especially if some of the other • Slagging, fouling, and corrosion. • Boiler size and usage patterns. factors mentioned in this sec- Some biomass fuels have high Boiler size and capacity factor tion are also favorable. Since alkali (principally potassium) were considered in the initial the average delivered coal price or chlorine content, or both. screening process (see Figure for boilers operated by DoD This can lead to unmanageable was about $2.10 per million 5). Larger, high-capacity-factor facilities (those that operate ash deposition problems on Btu in 1999, and ranged from heat exchange and ash- $1.60 to $3.00 per million Btu, at high loads year-round) can use more biomass and handling surfaces. Chlorine in coal prices at nearly all federal combustion gases, especially facilities should be high will realize greater annual cost savings. This in turn at high temperatures, can enough to make biomass cause accelerated corrosion cofiring worth considering. reduces project payback periods. Because the amount of combustion system and • 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 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 • Fuel-handling and processing the biomass fuel helps to avoid and performance can decrease. problems. Certain equipment the need for modifications to the For example, boiler efficiency and processing methods are existing boiler. The Pittsburgh losses of 2% were measured required to reduce biomass project used premixed coal and during cofiring tests at a pul- to a form compatible with wood chips. As indicated in Figure verized coal boiler at a heat coal-fired boilers and flue- 8, no modifications were needed input level from biomass of gas-handling systems. Most to deliver the mixed fuel to the 10% (Tillman 2000, p. 373). coal boiler operators are not dump grate after the from Numerous cofiring projects familiar with biomass process- coal-only supplies. However, cofir- 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 the near term, cofired ash will small amounts of biomass in efforts. Securing dependable, not meet ASTM specifications. a PC boiler (less than 5% of clean, economical sources of This is a serious problem for total heat), the biomass can be biomass fuels can be time- some utility-scale power plants blended with the coal before consuming, but this is one of that obtain a significant amount injection into the . the most important tasks in of revenue from selling ash. establishing a biomass project. Additional processing and handling Since most federal facilities Federal facilities that already equipment requirements make dispose of ash rather than have staff with experience in separate injection systems more sell it, this issue should not aggregating and processing expensive than blended-feed sys- be a problem; however, ash biomass are ideal sites for tems, but they offer the advantage disposal methods at each projects. In most cases, how- of higher biomass firing rates. potential project site should ever, technical assistance Cyclone, stoker, and fluidized-bed be considered early in the will probably be required boilers are better suited to handle evaluation process to avoid in this area. larger fuel particles, and they are future problems. thus usually less expensive to mod- ify than PC boilers. In general,

14 — FEDERAL ENERGY MANAGEMENT PROGRAM Federal Technology Alert

each boiler and fuel combination Codes and Standards input) is cofired with coal or wood must be carefully evaluated to Permit requirements vary from have been implemented or are in maximize boiler efficiency, mini- site to site, but a facility’s emis- progress. Eleven of these projects mize costs, and avoid combustion- sions permits—even for limited- involve coal-fired boilers and four related problems in the furnace. term demonstration projects— involve wood-fired units. They usually have to be modified for include the coal-fired Capital Maintenance cofiring projects. Results from in Washington, D.C. Maintenance requirements for earlier cofiring projects in which Such projects do not eliminate boilers cofiring biomass and coal emissions were not negatively the possibility of cofiring biomass are 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 obtained to 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 offset fire 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 evaluate be successful, the biomass fuel the permit requirements for a Costs must be processed before cofiring cofiring project. NETL and the Cofiring system retrofits require to 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 required Equipment Warranties results can be found in several for most other renewable energy If additional equipment is required papers listed in the bibliography. technologies and carbon seques- tration alternatives. Costs as low to implement a cofiring project, it Because of increases in regulations as $50 to $100/kW of biomass is most likely to be commercially for particulate emissions and power can be achieved for stokers, available. Therefore, it will carry increases in the availability of fluidized beds, and low-percentage the standard manufacturer’s war- natural gas, some federal boilers (less than 2% biomass on a heat ranty, which is usually a mini- are being converted from coal to basis) cofiring in cyclone and PC mum of one year for parts. Instal- natural gas despite the higher cost. boilers. For heating applications, lation labor usually carries a one- Fifteen projects in which natural this is equivalent to about $3 to year warranty, as well. 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 (PC) boiler are typically about

03381107 $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 Stoker hopper much as $350/kW of biomass power capacity.

Figure 8. A typical stoker boiler conveyor system receiving premixed coal and When inexpensive biomass fuels biomass (Adapted from J. Cobb et al., June 1999). are used, cofiring retrofits have

FEDERAL ENERGY MANAGEMENT PROGRAM — 15 Federal Technology Alert

payback periods ranging from one Utility Incentives a comprehensive energy audit and to eight years. A typical existing At present, there are no known identifies improvements that will coal-fired power plant can pro- utility incentives for biomass save energy and reduce utility bills duce power for about 2.3¢/kWh. cofiring at federal facilities. at the facility. The ESCO guaran- However, cofiring inexpensive tees that energy improvements biomass fuels can reduce this cost Project Financing and Technical will result in a specified level of to 2.1¢/kWh. For comparison, a Assistance annual cost savings to the federal new combined-cycle power plant customer and that these savings DOE FEMP, with support from staff using natural gas can generate will be sufficient to repay the at national laboratories and DOE electricity for about 4¢ to 5¢/kWh. ESCO for initial and ongoing Regional Offices, can provide These generation costs are based work over the term of the con- many services and resources to on large-scale power plants and tract. In other words, agencies help federal agencies implement would be higher for smaller federal use a portion of their guaranteed energy efficiency and renewable power 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 life of 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 savings and heating, respectively. Federal or appropriations. Among these accrue to the agency. Contract boilers 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 the 3 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 performance are similar in terms of rated steam tion and energy-related costs. contract (ESPC) can be complex generating capacity. At coal costs and time-consuming, FEMP created For this Super ESPC, biomass fuels of $2.10/MBtu and a delivered streamlined Super ESPCs. These include any that is biomass cost of $1.25/MBtu, pay- “umbrella” contracts are awarded available on a renewable or recur- back periods would be between to ESCOs selected through a com- ring basis (excluding old-growth one and three years for low-cost petitive bidding process on a stoker installations. The payback timber). Examples include dedi- regional or technology-specific period for a higher cost stoker cated energy crops and trees, basis. Super ESPCs thus allow installation, like the one shown agricultural food and feed crop agencies to bypass the initial in Table 4, row 2, would be about residues, aquatic plants, wood competitive bidding process and 5.3 years. and wood residues, animal wastes, to undertake multiple energy and other waste materials. Alter- projects under one contract. Each All these examples of stoker boilers native methane fuels include Super ESPC project is designed to assume 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 of mass. Annual fuel cost savings bed methane. energy- and cost-saving improve- thus range from about $60,000 to ments, from energy-efficient light- $110,000 for a typical federal Through a standard ESPC, an ing to heating and cooling systems. boiler. Payback periods and annual energy services company (ESCO) savings for power-generating boil- arranges financing to develop and Technology-Specific Super ESPCs ers 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. The because they are usually used ects. This allows federal energy technologies are well suited for fairly 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 well more fuel. ment at no up-front cost. As part enough established in the mar- of the project, the ESCO conducts ketplace to be readily available

16 — FEDERAL ENERGY MANAGEMENT PROGRAM Federal Technology Alert

through routine acquisition ventilation, and cooling systems utility-owned power plants, 18 at processes. The ESCOs that have in order to reduce energy costs. municipal boilers, 10 at educational been awarded technology- institutions, and 8 at federal facili- For further information, see the specific Super ESPC contracts ties. The majority of cofiring proj- FEMP and BAMF Super ESPC have demonstrated their exper- ects have occurred in industrial contacts listed on page 24. See tise in the application of these applications. These are primarily also the list of manufacturers technologies through past per- in the wood products, agricultural, for BAMF Super ESPC contract formance, such as proposing chemical, and textile industries, awardees. and carrying out specific proj- in which companies generate a ects defined in DOE's requests biomass waste by-product such for proposals. Technology as sawdust, scrap wood, or agricul- Performance tural residues. By using the waste Through the BAMF Super ESPC, material as fuel, the companies FEMP helps to make accessible to In general, facility managers who avoid a certain amount of fossil- federal facilities the energy- and have cofired biomass in coal- fuel purchases and disposal costs. cost-savings benefits of biomass fueled boilers have been pleased and alternative methane fuels. with the technology’s operation, Several U.S. power generators are Projects carried out under the once initial testing and perform- either considering or actually BAMF 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 in biomass 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 Valley such as steam boilers, hot-water and the various cost savings and Authority (TVA), New York State heaters, engines, and vehicles. emissions benefits as factors that Electric and Gas, Northern States The federal facility, the ESCO, have made their projects Power, Tacoma City Light, and or a third party could own the worthwhile. Southern Company. The TVA biomass or alternative methane expects annual fuel cost savings fuel resource. If the fuel requires Field Experience of about $1.5 million as a result 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 182 equipment so that the facility reducing energy costs and envi- separate boilers and organizations can supplant or supplement its ronmental emissions at federal in the United States have cofired conventional fuel supply with a facilities, the program is working biomass with fossil fuels; although biomass 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 most could 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 experience thing altogether new at a federal has been gained as a result of the facility, such as on-site power energy crisis of the 1970s, when Fuel Supply and Cost generation. Although the primary many boiler plant operators were Savings Calculations component of any project under seeking ways to reduce fuel costs. Appendix B contains worksheets this Super ESPC must feature the However, a steady number of and supporting data for agencies use of a biomass or alternative organizations have continued to evaluate the feasibility of a methane fuel, all projects are cofiring operations to reduce biomass cofiring operation in also expected to employ a variety their overall operating costs. Of a preliminary manner. These of traditional conservation meas- the 182 cofiring operations men- worksheets were designed to ures, which include retrofits to tioned above, 114 (or 63%) have permit useful calculations based lighting, motors, and heating, been at industrial facilities, 32 at

FEDERAL ENERGY MANAGEMENT PROGRAM — 17 Federal Technology Alert

on information that is readily Existing Technology Description directives in Executive Order available at any coal-fueled Savannah River Site uses two mov- 13123 to increase the use of boiler plant. ing-grate spreader stoker boilers to renewable energy and reduce emissions, compelled SRS to The first worksheet in Appendix B produce steam. The boilers were pursue the PEF project. is for estimating the amount of manufactured by Combustion biomass fuel supply needed for a and have a capacity New Technology Description cofiring application. This can be of 60,000 lb/hr at full load. Fuel is used to determine the size of bio- fed to the facility from two track The PEF Facility uses a shredder mass processing equipment hoppers of equal size, located next and a cubing (see Figure required and to evaluate local to the boiler plant. Steam from 9) to convert waste paper into biomass supplies in relation to the boilers is required year-round cubes that can be used as fuel in the biomass fuel requirements for process heating applications. the SRS stoker boilers. The cuber of the cofiring project. The second Steam demands peak during win- greatly increases the bulk density worksheet in Appendix B is for ter as a result of extra comfort- of the waste materials and makes determining the annual cost sav- heating loads. Multiclones remove them compatible with fuel con- ings resulting from cofiring with from the stack gases. veyors and handling equipment biomass at a coal-fired facility. Before the PEF project, the boilers at the steam plant. used only coal for fuel, and aver- The PEF Facility has two major Appendix C provides examples of age annual coal use at the facility handling sections: the tipping completed worksheets estimating was about 11,145 tons. At a deliv- floor, where the PEF feedstock annual cost savings and biomass ered price of $50 per ton, this coal is delivered, and the processing fuel supplies for DOE’s Savannah cost the site just over $550,000 line, which forms the feedstock River Site cofiring project. This 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 dumpsters Savannah River Cofiring Project month. In the years before imple- marked “PAPER PRODUCTS Facility Description menting the PEF cofiring project, ONLY.” These dumpsters are The primary function of the SRS had been paying Department of Energy's Savan- about $23 per ton nah River Site (SRS)—constructed to landfill these during the early 1950s in Aiken, materials. Landfill South Carolina—is to handle, costs for the paper recycle, and process basic nuclear waste amounted to materials such as tritium and about $77,280 per plutonium. The Site year. In addition, Department at SRS is implement- the site burned ing an innovative, cost-effective about 70 tons per system for cofiring biomass with month of recently coal in the site's existing coal- unclassified paper fired stoker boilers. The system in an on-site burn converts paper and wood waste pit. The annual generated from the day-to-day cost of operating operations of the site into “process the burn pit was engineered 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 Federal Technology Alert

collected by trucks that bring Energy Savings this material directly to the PEF This project will facility tipping floor. Because not decrease the previous landfill disposal activi- amount of energy ties for paper required the same input to the boilers amount of collection and trans- at the steam plant; portation, no new costs were however, it will incurred by diverting the waste replace a signifi- material from the landfill to the cant amount of PEF Facility. coal with a renew- After they are delivered to the tip- able fuel made ping floor, the plastic bags con- from waste paper taining waste paper are pushed that previously into a hopper. The hopper drops had to be disposed the paper onto a conveyor that of at great expense. delivers it to a shredder. The waste The worksheets in paper is shredded in a 300-hp Appendix C show high-speed shredder that yields the calculations pieces no larger than 2 in. in needed to deter- length, width, or depth. Water mine that, if the sprays and/or dry granular mate- PEF cubes are 50% rial can easily be added to the of the volume of shredded paper to incorporate fuel input to the emission-reducing agents into boilers, the heat the cubes. A dust collection sys- Figure 10. The combined feedstock material is input obtained tem filters air from the shredder, processed through a machine that extrudes it into from PEF is about feedstock 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 to cuber. Dust is removed from the right) are made of wood, cardboard, and office In other words, airflow in a cyclone separator paper. 20% less coal will and 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 PEF is processed through a machine 13,000 Btu/lb for the coal. The project was about 11,145 tons per that extrudes it into cubes approx- cost of operating the PEF facility year, the annual coal savings will imately 1 in. square and 3 to 4 in. is about $7.61 per ton of cubes be about 2,240 tons (11,145 x long. The cubing machine can be produced. 20% = 2,240). Since the heating modified to produce cubes from The PEF cubes are delivered to one value of the coal used at SRS is 1/4 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 boilers 10. From left to right, the cubes one hopper and PEF cubes are fed will be reduced by about 58,240 shown in the inset are made of from the other. The two fuels are million Btu per year (2,240 tons x wood, 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 . The bucket elevator lb/ft3. The bulk density of the places the coal/PEF mix into the PEF cubes at SRS is from 35 to fuel bunkers, which supply fuel 40 lb/ft2. The bulk density of to the boilers. the coal used in the SRS boilers is 80 lb/ft2. The PEF cubes have

FEDERAL ENERGY MANAGEMENT PROGRAM — 19 Federal Technology Alert

Table 7. Savings from the Savannah Performance Test Results review of emissions test results and River Site Cofiring Project. As of February 2003, all equipment procedures for material collection Energy Savings had been installed and tested at and handling. The project manager Coal 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 operation at high levels of bio- Disposal Savings (paper and ment installed at the SRS PEF mass input by the end of 2004. cardboard) Facility was previously used in a PEF cube supply 3,880 tons/yr similar coal-and-biomass cofiring demonstration project at INEEL Savings Source Savings The Technology in in Idaho. The equipment operated Reduced coal costs $112,000/yr Perspective well for more than a year at INEEL, Reduced landfill costs $89,000/yr Biomass cofiring has good poten- Burn pit closure $83,000/yr but its use was discontinued when tial for use at federal facilities PEF processing costs ($30,000/yr) the steam plant was closed because of privatization of the utility. When with existing coal-fired boilers. Total Cost Savings $254,000/yr the equipment was used at INEEL, Advantages to federal facilities PEF cubes provided about 25% (by that accrue from using biomass Life-Cycle Cost volume) of the fuel at the steam cofiring technology can include reductions in fuel, operating, and Design, construction, and equip- plant, and no major operational landfill costs, as well as in emis- ment purchases for the PEF problems were encountered. sions, and increases in their use Facility totaled about $850,000. Test burns at the SRS have shown of domestic renewable energy The net annual cost savings gener- that no modifications were needed resources. Cofiring biomass with ated by the project are expected to current stoker boiler fuel-han- coal is expected to become more to be about $254,000. These sav- dling equipment to successfully widespread as concerns for energy ings are the result of reduced coal fire the PEF/coal mixture. No fuel- security and the environment purchases, reduced landfill costs, feeding problems were experi- become greater within agencies and elimination of burn-pit opera- enced, and no increase in mainte- tional costs. Operating the PEF of the federal government. nance is expected to be necessary Facility will cost about $30,000 at the steam plant. By replacing coal with less expen- per year. All expected costs and sive biomass fuels, a federal facility savings are summarized in Table 7, Emissions measurements made can reduce air emissions such as and 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 a Based on a National Institute of the low (nearly zero) sulfur con- near-term renewable energy Standards and Technology (NIST) tent of wood and paper, sulfur option, and it reduces their fuel Building Life-Cycle Costing (BLCC) emissions are expected to price risk by diversifying the fuel comparative 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 minimum 10-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 operational a 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 boiler according 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, proven back period for the project will SRS steam plant personnel have technologies are readily available. be 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 of the NIST BLCC comparative operation and evaluation, after a analysis in Appendix E.)

20 — FEDERAL ENERGY MANAGEMENT PROGRAM Federal Technology Alert

Manufacturers The Babcock & Wilcox Systems Engineering and Company Management Corp. The following list includes compa- 20 South Van Buren Avenue 1820 Midpark Road, Suite C nies identified as manufacturers of Barberton, OH 44203-0351 Knoxville, TN 37921-5955 biomass cofiring equipment. We Phone: 800-BABCOCK Phone: 865-558-9459 made every effort to identify cur- www.babcock.com rent manufacturers; however, this Trigen Development listing is not purported to be com- Babcock Borsig Power Corporation plete or to reflect future market (Formerly DB Riley, Inc.) One North Charles Street conditions. Please see the Thomas 5 Neponset Street Baltimore, MD 21201 Register (www.thomasregister.com) Worcester, MA 01606 Phone: 937-256-7378 for more information. Phone: 508-852-7100 www.dbriley.com For Further Information Biomass Pelletizing Equipment For more information about the Bliss Industries Detroit Stoker Company BAMF Super ESPC, contact: P.O. Box 910 1510 East First Street Ponca City, OK 74602 P.O. Box 732 Christopher Abbuehl Phone: 580-765-7787 Monroe, MI 48161 National BAMF Program www.bliss-industries.com Phone: 800-STOKER4 Representative www.detroitstoker.com U.S. Department of Energy Cooper Equipment Inc. Philadelphia Regional Office 227 South Knox Drive Foster Wheeler Corporation 100 Penn Square East, Suite 890 Burley, ID 83318 Perryville Corporate Park Philadelphia, PA 19107 Phone: 208-678-8015 P.O. Box 4000 Clinton, NJ 08809-4000 Phone: 215-656-6995 CPM Acquisitions Group Phone: (908) 730-4000 E-mail: 2975 Airline Circle www.fwc.com [email protected] Waterloo, IA 50703 Phone: 319-232-8444 SNC-Lavalin Constructors Inc. See also the following U.S. www.cpmroskamp.com (Formerly Zurn/NEPCO) Government Web sites: Sprout Matador, Div. of P.O. Box 97008 www.eere.energy.gov/biopower/ Andritz Redmond, WA 98073-9708 main.html 35 Sherman Street Phone: 425-896-4000 www.eere.energy.gov/states Muncy, PA 17756-1202 www.nepco.com Phone: 570-546-5811 Biomass and Alternative Bibliography www.sprout-matador.com Methane Fuels (BAMF) Super Antares Group Inc. (2000), The UMT (Universal Milling ESPC Competitively Awarded Cofiring Connection (CD-ROM Technology) Inc. Contractors compendium of technical papers on biomass cofiring), prepared for 8259 Melrose Drive Constellation Energy Source the U.S. Department of Energy Lenexa, KS 66214 7133 Rutherford Rd. Biomass Power Program. Phone: 913-541-1703 Suite 401 www.umt-group.com Baltimore, MD 21244 Antares Group Inc. (May 1999), Boiler Equipment/Cofiring Phone: 410-907-2002 Strategic Plan and Analysis for Systems DTE Biomass Energy, Inc. Biomass Cofiring at Federal ALSTOM Power Inc. 54 Willow Field Drive Facilities, prepared for the (Formerly, ABB-Combustion North Falmouth, MA 02556 National Renewable Inc.) Phone: 508-564-4197 Laboratory, Task Order No. 2000 Day Hill Road KAW-5-15061-01. Energy Systems Group P.O. Box 500 101 Plaza East Boulevard Windsor, CT 06095 Suite 320 Phone: 860-285-3654 Evansville, IN 47715 www.power.alstom.com Phone: 812-475-2550 x2541

FEDERAL ENERGY MANAGEMENT PROGRAM — 21 Federal Technology Alert

Antares Group Inc. (June 1999), Vibrating Grate Technology,” Mitchell, C.P., Overend, R.P., and Biomass Residue Supply Curves for Proceedings of the 4th Biomass Tillman, D.A. (2000), “Cofiring the United States, prepared for Conference of the , Benefits for Coal and Biomass,” the U.S. Department of Energy’s Elsevier Science Ltd., Oxford, UK. Biomass & (special issue), Biomass Power Program and Vol. 19, No. 6, Elsevier Science Idaho National Engineering and the 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 River Directory 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 and Cobb, 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., and Conference Proceedings, University Engineering, University of Hughes, E. (Sept. 1999), “Biomass of 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 Biomass Boilers,” Proceedings of the of the bustion: Burning biomass, fossil Conference of the Americas, Elsevier Air and Waste Management fuels together simplifies waste Science Ltd., Oxford, UK. Association's 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 in Comer, K. (Dec. 1997), “Biomass Miles, T. R.; Miles, T. R. Jr.; Baxter, the United States: 1999 State Level Cofiring,” Renewable Energy L. L.; Bryers, R. W.; Jenkins, B. M.; Analysis, Oak Ridge National Technology 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), Urban Palo Alto, CA. in Biomass Power Plants. A Prelim- Wood Waste Resource Assessment, inary Investigation of Their Extent Electric Power Research Institute, prepared for the National and (Vol. I); The Behavior of et al. (1999), Biomass Cofiring: Field Renewable Energy Laboratory, Inorganic Material in Biomass-Fired Test Results, EPRI Topical Report NREL/SR-570-25918, Golden, CO. Power Boilers—Field and Laboratory No. 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 Energy 1999), “Cofiring Biomass with Laboratory, NREL Report No. Coal Utilizing Water-Cooled TP-433-8142; Golden, CO.

22 — FEDERAL ENERGY MANAGEMENT PROGRAM Federal Technology Alert

Appendix A Assumptions and Explanation for Screening Analysis

Average 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 Supply Curves for the United States (Antares Group Inc., June 1999). Average state landfill tipping fees were obtained from Chartwell Information Publishers. Data for coal costs, biomass supplies, and tipping fees were normalized on a 100-point scale for each of the 50 states to capture the relative variation in each item from one state to the next. Weighting factors (ranging from one to three) were then applied to the normalized coal cost, biomass supply, and tipping fee data to account 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 weighted values for the normalized coal cost, biomass supply, and tipping fees were then summed together for each state, and the state rankings were based on these totals. A wide range of weighting-factor combinations were attempted 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 of weighting factors to the next, the relative ranking of each state was very stable from trial to trial over a wide combination of weighting factors. In general, states with high coal costs, high biomass supplies, and high tipping fees ranked very high, while those with low coal costs, low biomass supplies, and low tipping fees ranked very low.

FEDERAL ENERGY MANAGEMENT PROGRAM — 23 Federal Technology Alert

Appendix B Blank Worksheets for Preliminary Evaluation of a Cofiring Project Biomass Fuel Supply Estimation Worksheet

The amount of biomass needed for a cofiring application depends on the size of the boiler, its loading, the cofiring rate (biomass/coal blend), and the type of biomass used. Biomass fuel supplies required for a cofiring operation can be estimated as follows, if the rate of coal use in the boiler, the heating value and density of the coal, the biomass/coal blend (or cofiring rate), and the heating value and density 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 3 BDc = bulk density of coal ______lb/ft

HVb = average heating value of biomass fuel(s) ______Btu/lb 3 BDb = bulk density of biomass ______lb/ft

If 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 80

Fill 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 Hb

24 — FEDERAL ENERGY MANAGEMENT PROGRAM Federal Technology Alert

To 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 two of 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 Federal Technology Alert

Average 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 Federal Technology Alert

Annual Cost Savings Estimation Worksheet

ACU = annual coal use (based on operating history) ______tons/yr

Hb = % biomass, heat basis (% of total heat provided by biomass) ______%

UCcoal = unit cost of coal delivered to the boiler facility ______$/ton ABU = annual biomass use proposed/estimated for boiler facility ______tons/yr

UCbiomass = unit cost of biomass delivered to the boiler facility ______$/ton TF = average tipping fee avoided by diverting biomass from landfill ______$/ton

Cother = 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 processing equipment, 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 of handling biomass, etc.) Annual Cost Savings

CScoal = 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 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)

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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 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 Federal Technology Alert

Appendix D Federal Life-Cycle Costing Procedures and the BLCC Software

Federal 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 potential actions, 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 investment is 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 of labor needed to install it. Energy cost includes annual expenditures on energy to operate equipment. For example, a lighting fixture that draws 100 (W) and operates 2,000 hours annually requires 200,000 -hours (2 kWh) annually. At an electricity price of $0.10/kWh, this fixture has an annuals energy cost of $20. Non-fuel O&M costs include annual expenditures on parts and activities required to operate the equipment, for example, checking light bulbs in the fixture to see if they are all operating. Replacement costs include expenditures for replacing equipment upon failure, for example, replacing a fixture when it can no longer be used or repaired. Because LCC includes the cost of money, periodic and other O&M, and equipment replacement costs, energy escalation 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 the LCC of an energy-saving or energy-cost-reducing alternative and the LCC of the baseline equipment. If the alternative’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 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 Federal Technology Alert

Appendix E NIST BLCC 5.0 Comparative Economic Analysis

10-Year Case Study Base Case: Coal Only Alternative: Biomass and Coal Cofiring General Information Project name: Westinghouse Savannah River Company Fuel Facility Economic Study Project location: South Carolina Analysis type: Federal analysis, agency-funded project Base date of study: January 1, 2001 Service date: January 1, 2002 Study 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) Discounting convention: End-of-year Comparison of Present-Value (PV) Costs: PV Life-Cycle Cost Base Case Alternative Savings Initial investment costs: Capital requirements as of base date $0 $850,000 -$850,000 Future costs: costs $4,220,115 $3,369,685 $850,430 Recurring and non-recurring OM&R costs: $1,333,451 $219,134 $1,114,316 Capital replacements $0 $0 $0 Total PV life-cycle cost $5,553,566 $4,438,819 $1,114,747 Net Savings from Alternative Compared with Base Case PV of non-investment savings $1,864,747 – Increased total investment $850,000 Net savings $1,114,747 Savings-to-investment ratio (SIR): 2.31 Adjusted internal rate of return: 11.59% Payback Period Estimated years to payback (from beginning of service period): Simple payback occurs in year 4. Discounted payback occurs in year 4. Energy Savings Summary Note: Total energy use would remain approximately the same. Figures below indicate reduced coal consumption. 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 Federal Technology Alert

34 — FEDERAL ENERGY MANAGEMENT PROGRAM Federal Technology Alert

About FEMP’s New Technology Demonstrations

The 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 its federal buildings be reduced by screening tests; a description of its 35% from 1985 levels by the year Technology Installation performance, applications, and field 2010. 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 contact Energy Management Program study results, typically from another information. Attached appendixes (FEMP) sponsors a series of acti- demonstration or pilot project. provide supplemental information vities to reduce energy consumption and example worksheets on the Other Publications—we also at federal installations nationwide. technology. issue other publications on energy- One of these activities, new technol- saving technologies with potential ogy demonstrations, is tasked to FEMP sponsors publication of the use in the federal sector. accelerate the introduction of energy- FTAs to facilitate information-sharing efficient and renewable technol- between manufacturers and govern- ogies into the federal sector and More on Federal Technology ment staff. While the technology to 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 a As part of this effort, FEMP sponsors tion on candidate energy-saving particular product, as FEMP has not the following series of publications technologies developed and manu- independently verified performance that 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 chart technologies: have already entered the market and market activity vis-a-vis the tech- nology featured. Readers should Technology Focuses—brief infor- have some experience but are not in general use in the federal sector. note the publication date on the mation on new, energy-efficient, back cover, and consider the FTAs environmentally 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 the federal sector. new energy-saving technologies time of publication. Product innova- tions and the entrance of new man- Federal Technology Alerts— within the federal sector and to pro- ufacturers or suppliers should be longer summary reports that pro- vide the right people in the field anticipated since the date of publi- vide details on energy-efficient, with accurate, up-to-date informa- cation. FEMP encourages interested water-conserving, and renewable- tion on the new technologies so federal energy and facility managers energy technologies that have been that they can make educated judg- to contact the manufacturers and selected for further study for possi- ments on whether the technologies other federal sites directly, and to ble implementation in the federal are suitable for their federal sites. 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 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 FEMP's mission. These include the Energy Policy and Conservation Act of 1975; the National 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. A Strong Energy Portfolio for a Strong America For More Information EERE Information Center Energy efficiency and clean, renewable energy will mean a stronger , a cleaner 1-877-EERE-INF or environment, and greater for America. Working with a wide array 1-877-337-3463 of state, community, industry, and university partners, the U.S. Department of Energy’s www.eere.energy.gov/femp Office of Energy Efficiency and Renewable Energy invests in a diverse portfolio of General Program Contacts energy 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 [email protected] 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 www.eere.energy.gov/femp/ Phone: (509)-375-6366 Fax: (509)-375-3614 You will find links to [email protected] • 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. Document Format (pdf) Golden, CO 80401 Phone: (303) 384-7519 • A list of new technology projects under way E-mail: [email protected] • Electronic access to a regular mailing list for new products Stephanie Tanner 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: [email protected] Kevin Comer and Christian Demeter Antares Group Inc. 4351 Garden City Drive, Suite 301 Landover, MD 20785 Phone: (301) 731-1900

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June 2004

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