Femp biomass co-firing (2007)

DOE/EE-0288

Leading by example,
saving energy and Biomass Cofiring in Coal-Fired Boilers
taxpayer dollars
in federal facilities
Using this time-tested fuel-switching technique in existing federal boilers
helps to reduce operating costs, increase the use of renewable energy,
and enhance our energy security

Executive Summary
To help the nation use more domestic fuels and renewable energy technologies—and increase
our energy security—the Federal Energy Management Program (FEMP) in the U.S. Department
of Energy, Office of Energy Efficiency and Renewable Energy, assists government agencies in
developing biomass energy projects. As part of that assistance, FEMP has
prepared this Federal Technology Alert on biomass cofiring technologies. This
publication was prepared to help federal energy and facility managers make
informed decisions about using biomass cofiring in existing coal-fired boilers
at their facilities.
The term “biomass” refers to materials derived from plant matter such as
trees, grasses, and agricultural crops. These materials, grown using energy
from sunlight, can be renewable energy sources for fueling many of today’s
energy needs. The most common types of biomass that are available at
potentially attractive prices for energy use at federal facilities are waste
wood and wastepaper.
The boiler plant at the
Department of Energy’s One of the most attractive and easily implemented biomass energy technologies is cofiring
Savannah River Site co-
fires coal and biomass.
with coal in existing coal-fired boilers. In biomass cofiring, biomass can substitute for up
to 20% of the coal used in the boiler. The biomass and coal are combusted simultaneously.
When it is used as a supplemental fuel in an existing coal boiler, biomass can provide the
following benefits: lower fuel costs, avoidance of landfills and their associated costs, and
reductions in sulfur oxide, nitrogen oxide, and greenhouse-gas emissions. Other benefits,
such as decreases in flue gas opacity, have also been documented.
Biomass cofiring is one of many energy- and cost-saving technologies to emerge as feasible for
federal facilities in the past 20 years. Cofiring is a proven technology; it is also proving to be
life-cycle cost-effective in terms of installation cost and net present value at several federal sites.

Energy-Saving Mechanism
Biomass cofiring projects do not reduce a boiler’s total energy input requirement. In fact, in
a properly implemented cofiring application, the efficiency of the boiler will be the same as
it was in the coal-only operation. However, cofiring projects do replace a portion of the non-
renewable fuel—coal—with a renewable fuel—biomass.

Cost-Saving Mechanisms
Overall production cost savings can be achieved by replacing coal with inexpensive biomass
fuel sources—e.g., clean wood waste and waste paper. Typically, biomass fuel supplies should
cost at least 20% less, on a thermal basis, than coal supplies before a cofiring project can be
economically attractive.

U.S. Department of Energy
Energy Efficiency Internet: 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 industry 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 fire the biomass/
biomass fuel sources, annual fuel and operating costs, and
coal mixture successfully. No fuel-
cost savings could be signifi- potential future needs to reduce
feeding problems were experi-
cantly higher. greenhouse gas emissions, an
enced, and no increases in main-
increasing number of industrial-
tenance are expected to be needed
Application and utility-scale boilers outside
at the steam plant. Steam plant
Biomass cofiring can be applied the pulp and paper industry are
personnel have been supportive
only at facilities with existing being evaluated for use in cofiring
of the project. Emissions measure-
coal-fired boilers. The best oppor- applications.
ments made during initial 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-
management are highly motivated For utility-scale power generation
able combustion, emissions, and
to implement the project success- projects, acquiring steady, year-
performance of the boiler and fuel
fully. As a rule, boilers producing round supplies of large quantities
processing and handling systems,
less than 35,000 pounds per hour of low-cost biomass can be diffi-
cofiring was expected to begin in
(lb/hr) of steam are too small to cult. But where supplies are avail-
2003 on a regular basis. The bio-
be used in an economically attrac- able, there are several advantages
mass cubes offset about 20% of
tive cofiring project. to using biomass for cofiring opera-
the coal used in the facility’s two
tions at federal facilities. For exam-
traveling-grate stoker boilers. The
ple, federal coal-fired boilers are
Field Experiences project should result in annual coal
typically much smaller than
Cofiring biomass and coal is a time- cost savings of about $112,000.
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 scrap 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
successfully demonstrated and In addition, federal boilers needed
per year. Net annual savings from
practiced in all types of coal for space heating typically operate
the project, after subtracting the
boilers, including pulverized- primarily during winter months.
$30,000 per year needed to oper-
coal boilers, cyclones, stokers, During summer months, waste
ate the AF cubing facility, will be
and fluidized beds. wood is often sent to the mulch
about $254,000. An initial capital


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 Iron City Brewery overall costs. Larger facilities “Super ESPC” for Biomass and
in Pittsburgh, Pennsylvania. with high capacity factors— Alternative Methane Fuels (BAMF),
those that operate at high loads which facilitates the use of bio-
These are some of the major policy year-round—can utilize more mass and alternative 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,
comparison to coal. This will FEMP enables federal facilities
• Permit modifications may be
also reduce payback periods. to obtain the energy- and cost-
required. Permit requirements
savings benefits of biomass and
vary from site to site, but
Conclusion alternative methane fuels at no
modifications to existing
up-front cost to the facility. More
emissions permits, even for DOE FEMP, with the support of
information about FEMP and
limited-term demonstration staff at the DOE National Labor-
atories and Regional Offices, offers BAMF Super ESPC contacts and
projects, may be required for
many services and resources to contract awardees is provided in
cofiring projects.
help federal agencies implement this Federal Technology Alert.

Disclaimer
This report was sponsored by the United States Department of Energy, Energy Efficiency and Renewable Energy, Federal Energy
Management Program. Neither the United States Government nor any agency or contractor thereof, nor any of their employees,
makes any warranty, express or implied, or assumes any legal liability or responsibility for the accuracy, completeness, or useful-
ness of any information, apparatus, product, or process disclosed, or represents that its use would not infringe privately owned
rights. Reference herein to any specific commercial product, process, or service by trade name, trademark, manufacturer, or other-
wise does not necessarily constitute or imply its endorsement, recommendation, or favoring by the United States Government or
any agency or contractor thereof. The views and opinions of authors expressed herein do not necessarily state or reflect those of
the United States Government or any agency or contractor thereof.


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


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 electricity. Next to hydro-
and enhancing national energy Federal Energy Management Pro-
power, more electricity is gener-
security. Specific requirements gram, which is part of the 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
energy mix. This publication describes biomass
fuel processing requirements.
cofiring, cost-saving mechanisms,
Biomass cofiring can be economi- and factors that influence its per-
cal at federal facilities where most formance. Worksheets allow the
or all of these criteria are met: reader to perform preliminary cal-
current use of a coal-fired boiler, culations to determine whether
access to a steady supply of com- a facility is suitable for biomass
petitively priced biomass, high cofiring, and how much it would
coal prices, and favorable regu- save annually. The worksheets
latory and market conditions for also allow required biomass sup-
renewable energy use and waste plies to be estimated, so managers
reduction. Boilers at several fed- can work with biomass fuel bro-
eral facilities were originally kers and evaluate their equipment
designed for cofiring biomass needs. Also included is a case
with coal. Others were modified study describing the design, oper-
after installation to allow cofiring. ation, and performance of a bio-
Some demonstrations—e.g., at the mass cofiring project at the 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 fossil fuels in exist-
tions are needed for cofiring.
ing boilers provides an opportu-

2 — FEDERAL ENERGY MANAGEMENT PROGRAM


About the Technology involves substituting biomass for cles, because biomass is a more
a portion of the fossil fuel 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 good energy managers to reduce their
ments for each boiler type men-
sources of renewable energy energy and waste disposal costs
tioned here are shown in Table 1.
and fuels for federal facilities. while making use of a renewable
fuel that is considered greenhouse-
Wood is the most commonly used Table 1. Biomass sizing requirements.
gas-neutral. Cofiring biomass
biomass fuel for heat and power.
counts toward a federal agency’s Existing Type Size Required
The most economical sources of of Boiler (inches)
goals for increasing the use of
wood fuels are wood residues from
renewable energy or “green power” Pulverized coal ≤1/4
manufacturers and mill residues,
(environmentally benign electric
such as sawdust and shavings; Stoker ≤3
power), and it results in a net cost
discarded wood products, such Cyclone ≤1/2
savings to the agency. Cofiring
as crates and pallets; woody yard Fluidized bed ≤3
biomass also increases our use of
trimmings; right-of-way trim-
domestic fuels, thus enhancing
mings diverted from landfills; More detailed information follows
the nation’s energy security.
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- fairly large fuel particles on travel-
fired boiler types and configura-
vert renewable biomass fuels to ing or vibrating grates, they are
tions, including stokers, fluidized
heat or electricity using equip- the most suitable federal boiler
beds, pulverized coal boilers, and
ment similar to that used for type for cofiring at significant
cyclones. The most likely opportu-
fossil fuels such as natural gas, biomass input levels. In these
nities at federal facilities will 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 turbines, 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 hydropower, more electricity spreader-fired traveling grate stoker
boilers have been installed at fed-
is generated from biomass than boiler, solid fuel is mechanically
eral facilities for standard, non-
from any other renewable energy or pneumatically spread from the
research uses.
resource in the United States. front of the boiler onto the rear
One of the most important keys of the traveling grate. Smaller par-
Cofiring is a fuel-diversification ticles burn in suspension above
to a successful cofiring operation
strategy that has been practiced the grate, while the larger particles
is to appropriately and consistently
for decades in the wood products burn on the grate as it moves the
size the biomass according to the
industries and more recently in fuel from the back to the front of
requirements of the type of boiler
utility-scale boilers. Several fed- the boiler. The ash is discharged
used. Biomass particles can usually
eral facilities have also cofired from the grate into a hopper at
be slightly larger than coal parti-
biomass and coal. Cofiring the front of the boiler.



03381101
The retrofit requirements for cofir-
ing in a stoker boiler will vary,
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 Magnetic
(coal and wood
a biomass cofiring project. If blend is passed separator Dump conveyor
through existing #1 Walking floor trailer
neither of these low-cost options Dump or dump truck
coal pulverizers)
is feasible, new handling and Wood conveyor #2
pile Scale
storage equipment will need
03381102
to be added. The cost of these
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 gan, Fort Stewart in Georgia, Puget
The best opportunities for cofiring
fired. With this blended feed Sound Naval Shipyard in Washing-
biomass with fossil fuels at federal
method, only about 3% or less ton, Wright- Patterson Air Force
facilities are at sites with regularly
of the boiler’s heat input can be Base in Ohio, Brunswick Naval
operating coal-fired boilers. Biomass
obtained from biomass at full Air Station in Maine, and the
cofiring has been successfully
boiler loads because of limitations Red River Army Depot in Texas.
demonstrated in nearly all coal-
in the capacity of the pulverizer.
fired boiler types and configura- More than 100 U.S. companies 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
to be used—up to 15% more on a cardboard or agricultural residues
biomass cofiring. Two facilities—



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

Air Intake Exhaust
Bin Dedicated biomass
vent injection Existing coal
Injection ports
Wood silo Boiler

Scale Pressure
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 manufacturing. 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 helpful conditions for econom-
are in stoker boilers in one of four
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, Great Lakes 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 Utility-scale cofiring projects are
ect. The primary factors consid-
New York shown on the map in Figure 5.
ered were average delivered state Pennsylvania
coal prices, estimated low-cost These sites are in or near states
Washington
biomass residue supply density identified by the screening model
Good Alabama as having good or high potential
(heat content in Btu of estimated Potential Georgia
available low-cost biomass resi- for cofiring. This increases confi-
Indiana
dues per year per square mile of dence that the states selected by
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 Tennessee 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.



pay off the initial investment—
by switching part of the fuel sup-
ply to biomass. Federal facilities
that operate coal-fired boilers but
are not in states on the list in
Table 2 could still be good candi-
dates for cofiring if specific condi-
tions at their sites are favorable.
“Wild card” factors, such as the
impact of a motivated project
manager or biomass resource
supplier, the local availability
of biomass, and the fact that a
large federal facility or campus
could act as its own source of
biomass fuel, capitalizing on
03381104
fuel cost reductions while avoid-
High potential for a Good potential for a
biomass cofiring project biomass cofiring project ing landfill fees. These factors
Locations of existing utility Locations of existing operational could easily tip the scales in
power plants cofiring biomass coal plants within the Federal System favor of a particular site. 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
MT VT (49) ME size, and very high coal prices.
ND (50) (46)
OR (19) (26) MN
(34) (56) MA The map in Figure 6 indicates
ID SD WI NY (48)
(26) WY MI (71) average landfill tipping fees for
(29) (33) (32) RI
(23) IA each state. It also shows cities
NV NE PA(51) NJ (41)
(15) (24) (31) CT in which fairly recent local bio-
UT IN OH (74)(61)
CO IL (26) (29) WA
(29) mass resource supply and cost
CA (16) KS MO (25) (39) VA MD DE
(29) (25) (27) KY(27) (38) (43) (47) studies have been performed,
AZ NC(30) as reported in Urban Wood Waste
NM OK TN(28)
(20) AR
(16) (21) Resource Assessment (Wiltsee 1998).
(18)
MS AL GA SC
Additional information on poten-
TX (19) (25) (25) (29)
AK (23) LA tial biomass resource supplies near
(22) federal facilities can be obtained
(42) FL
(41) from the DOE program manager
HI
(50) for the Technology-Specific Super
03381105 ESPC for Biomass and Alternative
High potential for a Good potential for a Methane Fuels, or BAMF; contact
biomass cofiring project biomass cofiring project
information can be found later in
(##) State average tipping Locations of recent local
fee ($/ton)* biomass supply studies this publication. To encourage
*Source: Chartwell Information Publishers, Inc., 1997. new projects under the BAMF
Super ESPC, the National 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.



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 price 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
in a fossil-fuel-only mode. When $49/ton x 0.61 = $30 in fuel cost
For example, if 15% of the coal
cofiring, the boiler operates to savings. The typical cost of pro-
used at a boiler were replaced by
meet the same steam loads for cessing biomass waste material
biomass delivered to the plant for
heating or power-generation into a form suitable for use in a
$1.25 per million Btu, annual fuel
operations as it would in fossil- boiler is $10 per ton, so the net
cost savings for the average DoD
fuel-only mode; usually, no costs savings per ton of biomass
boiler described above would be
changes in boiler efficiency residues could be about $56:
more than $120,000. Neither the
result from cofiring unless a $66/ton for the fuel and landfill
cofiring rate of 15% of the boiler's
very wet biomass is used. With cost savings minus $10/ton for
total heat input, nor the delivered
no change in boiler loads, and the biomass processing cost. This
price of $1.25 per million Btu, is
no change in efficiency, boiler assumes that the biomass is avail-
unrealistic, especially for stoker
energy usage will be the same. able at no additional transporta-
boilers. Higher cofiring rates and
The primary savings from cofiring tion costs, as is the case at the
lower biomass prices are common
are cost reductions resulting from Savannah River Site.
in current cofiring projects. Note
(1) replacing a fraction of high- that the cost of most biomass If the average DoD facility using 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
According to data obtained from of biomass residues per year, a
the United States is about $36 per
the Defense Energy Support quantity higher than most federal
ton of material dumped. Average
Center (DESC), the average facilities generate internally. The
tipping fees for each state are
delivered cost of coal for 18 coal- savings generated by a real cofir-
shown in Figure 6. If significant
fired boilers operated by the ing project would be expected to
quantities of clean biomass
Department of Defense (DoD) fall somewhere between the
residues—such as paper, card-
was about $49 per ton in 1999, two examples given here—
board, or wood—are generated
or about $2.10 per million Btu. between $120,000 and $560,000
at a federal site, and if some of
(The average coal heating value per year. They would probably
that material can be diverted from
for those boilers is about 11,500 depend on using some biomass
landfill disposal and used as fuel
Btu/lb) Coal costs for those facili- materials generated on site and
in a boiler, the savings generated
ties ranged from $1.60 to $3 per some supplied by a third party.
would be equivalent to about
million Btu, depending on the $66 per ton of biomass: $36/ton
location, coal type, and annual Other Benefits
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



• Reduced fuel costs. Savings in • Renewable energy when needed. modifications to existing opera-
overall production costs can Unlike other renewable energy tional procedures, such as increas-
be achieved if inexpensive technologies like those based ing over-fire air, may also be nec-
biomass fuel sources are avail- on solar and wind resources, essary. Increased fuel feeder rates
able (e.g., clean wood waste). biomass-based systems are are also needed to compensate for
Biomass fuel supplies at prices available whenever they are the lower density and heating
20% or more below current needed. This helps to accelerate value of biomass. This does not
coal prices will usually pro- the capital investment payoff usually present a problem at fed-
vide the cost savings needed. rate by producing more heat eral facilities, where boilers typi-
• Reduced sulfur oxide and nitrogen or power per unit of installed cally operate below their rated
oxide emissions. Because of dif- capacity. output. When full rated output
ferences in the chemical is needed, the boiler can be oper-
• Market-ready renewable energy
composition of biomass and ated in a coal-only mode to avoid
option. Cofiring offers a fast-
coal, emissions of acid rain derating.
track, low-cost opportunity
precursor gases—sulfur oxides to add renewable energy Expected fuel sources and boiler
(SOx) and nitrogen oxides capacity economically at type dictate fuel processing
(NOx)—can be reduced by
federal facilities. requirements. For suspension
replacing coal with biomass.
firing in pulverized coal boilers,
Because most biomass has • Fuel diversification. The ability
biomass should be reduced to a
nearly zero sulfur content, to operate using an additional
particle size of 0.25 in. or smaller,
SOx emissions reductions fuel source provides a hedge
with moisture levels less than
occur on a one-to-one basis against price increases and
25% when firing in the range
with the amount of coal supply shortages for existing
of 5% to 15% biomass on a heat
(heat input) offset by the fuels such as stoker coals. In
input basis. Equipment such as
biomass. Reducing the coal a cofiring operation, biomass
supply to the boiler by 10% hoggers, hammer mills, spike rolls,
can be viewed as an opportu-
will reduce SOx emissions and disc screens may be required
nity fuel, used only when the
by 10%. Mechanisms that to properly size the feedstock.
price is favorable. Note that
lead to NOx savings are Local wood processors are likely
administrative costs could
more complicated, and to own equipment that can ade-
increase because of the need
relative savings are typically quately perform this sizing in
to purchase multiple fuel
less dramatic than the SOx return for a processing fee. Other
supplies; this should be
reductions are, on a percent- boiler types (cyclones, stokers,
considered when evaluating
age basis. and fluidized beds) are better suited
this benefit.
to handle larger fuel particles.
• Landfill cost reductions. Using • Locally based fuel supply. The
waste wood as a fuel diverts Two common forms of processed
most cost-effective biomass
the material from landfills biomass are shown in Figure 7,
fuels are usually supplied
and avoids landfill disposal along with a typical stoker coal,
from surrounding areas, so
costs. shown in the center of the photo.
economic and environmental
Recent research and demonstra-
• Reduced greenhouse-gas emissions. benefits will accrue to local
tion on several industrial stoker
Sustainably grown biomass is communities.
boilers in the Pittsburgh area has
considered a greenhouse-gas-
shown that wood chips (on the
neutral fuel, since it results in Installation Requirements
right) are preferable to mulch-like
no net carbon dioxide (CO2)
Specific requirements depend on material (on the left) for cofiring
in the atmosphere. Using bio-
the site that uses biomass in cofir- with coal in stoker boilers that
mass to replace 10% of the coal
ing. In general, however, cofiring have not been designed or
in an existing boiler will reduce
biomass in an existing coal boiler previously reconfigured for
the net greenhouse-gas emis-
requires modifications or addi- multifuel firing. The chips are
sions by approximately 10% if
tions to fuel-handling, processing, similar to stoker coal in terms
the biomass resource is grown
storage, and feed systems. Slight of size and flow characteristics;
sustainably.

8— FEDERAL ENERGY MANAGEMENT PROGRAM


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
Federal-Sector Potential
29,000 tons of CO2 emissions
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
carbon dioxide would be about 6,700 tons/yr.
(CO2) emissions by If all biomass materials used in
more than 8,000 these boilers were diverted from
tons per year and landfills with no gas capture, the
Figure 7. Comparison of two biomass residues with coal. sulfur dioxide (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.
CO2 emissions would be avoided.
boilers. Wood chips can thus be used in existing boilers
Reductions in NOx
with minimal modifications to fuel-handling systems.
emissions could also (Continued on page 11)
Mulch-like processed wood (left) is more problematic.



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 Electric
Power Database, EPRI/DOE's Renewable Energy Technology Characterizations, 1997, coal cost of $2.10/MBtu, biomass cost of
$1.25/MBtu, and capacity factor of 70%.

Table 4. Example environmental impacts of cofiring in power generation applications (vs. 100 percent coal).

Example Annual Annual Annual
Plant Heat Reduced Biomass CO2 SO2 NOx
Size from Coal Use Used Savings Savings Period
Boiler Type (MW) Biomass (tons/yr) (tons/yr)1 (tons/yr)2 (tons/yr) (tons/yr)

Stoker
(low cost) 15 20% 10,125 16,453 27,843 466 N/A

Stoker
(high cost) 15 20% 10,125 16,453 27,843 466 N/A

Fluidized bed 15 15% 7,578 12,314 20,839 349 N/A

Pulverized coal 100 3% 7,429 12,072 20,430 342 N/A

Pulverized coal 100 15% 37,146 60,362 102,151 1,709 N/A

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

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


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.
4Carbon savings can easily be calculated from CO savings (i.e., carbon savings = 12 / 44 x CO savings).
2 2

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 briquettes 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
NREL, Sandia, and Oak Ridge could be manufactured and deliv-
DOE, NETL, and the Electric Power
National Laboratory (ORNL) on ered to a power plant for as little
Research Institute (EPRI) also col-
char burnout; ash deposition; as $0.30 per million Btu, or less
laborated on short-term demon-
NOx behavior; cofiring demon- than $5 per ton. This price
stration projects. Several of the
stration projects using various included all capital and operating
demonstrations took place at
boiler types, coal/biomass feed- costs for the manufacturing facility
federal facilities in the Pittsburgh
stock combinations, and fuel plus transportation costs within
area. They found no significant
handling systems; reburning for a 50-mile radius. The analysis
impact on boiler efficiency at low
enhanced NOx reduction; and the assumed the facility would
levels of cofiring. Fuel procure-
use of ash. These efforts have led collect a $15-per-ton tipping
ment, handling, and preparation
to improved and documented fee for biomass delivered to the
were found to require special
knowledge about the impacts site. See the bibliography for
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



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.
facilities. An exception could these devices. Instead, they
• Favorable regulatory climate for
be cofiring applications in use methods such as natural
renewable energy. As of Febru-
which the biomass fuel is gas overfiring to reduce par-
ary 2003, 28 states had either
gas piped to the boiler from ticulate emissions. In such
enacted electricity restructur-
a nearby landfill. Cofiring cases, a new baghouse may
ing legislation or issued orders
with landfill gas has been be required to permit cofiring
to open their electricity mar-
done in both coal-fired and biomass at significant input
kets to competition. Most of
natural-gas-fueled boilers, levels, and this would increase
these states have established
but is less common than project costs significantly.
some type of incentive pro-
solid-fuel cofiring because of • Storage space available on site. gram to encourage more
the need for a large boiler Unless the biomass is imme- installations of renewable
very close to the landfill. diately fed into a boiler’s energy technologies. Since
• Local expertise for collecting and fuel-handling system upon biomass is a renewable energy
processing biomass. Most boiler delivery, a temporary staging resource, some states may
operators at federal facilities area at the boiler plant will provide favorable conditions
are not likely to be interested be needed to store processed for implementing a cofiring
in purchasing and operating biomass supplies. An ideal project through incentive
equipment to process biomass storage facility would have programs, technical assis-
into a form that can be used at least a concrete pad and tance, or flexible permitting
as boiler fuel.Thus, it is advan- a roof to minimize the accu- procedures.
tageous for the facility to have mulation of moisture and



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.
implementing a biomass cofiring a biomass project at a federal
tipping fee is about $36 per
ing project. Prices above site are listed below. Each problem
ton, and the fee ranges from
$1.30 per million Btu are can be addressed with technical
about $15 per ton in Nevada
usually high enough to make assistance from experts with expe-
to about $74 per ton in
cofiring worth considering, rience in cofiring projects.
New Jersey.
especially if some of the other • Slagging, fouling, and corrosion.
factors mentioned in this sec- • Boiler size and usage patterns.
Some biomass fuels have high
tion are also favorable. Since Boiler size and capacity factor
alkali (principally potassium)
the average delivered coal price were considered in the initial
or chlorine content, or both.
for boilers operated by DoD screening process (see Figure
5). Larger, high-capacity-factor This can lead to unmanageable
was about $2.10 per million ash deposition problems on
Btu in 1999, and ranged from facilities (those that operate
at high loads year-round) heat exchange and ash-
$1.60 to $3.00 per million Btu, handling surfaces. Chlorine in
coal prices at nearly all federal can use more biomass and
will realize greater annual combustion gases, especially
facilities should be high at high temperatures, can
enough to make biomass cost savings. This in turn
reduces project payback cause accelerated corrosion
cofiring worth considering. of combustion system and
periods. Because the amount
• Biomass supply price. Abundant of environmental paperwork flue gas clean-up components.
local supplies of low-cost bio- needed is significantly less if These problems can be mini-
mass are necessary for cost- less than 5,000 tons of coal mized or avoided by screening
effective biomass cofiring proj- are burned annually, smaller fuel supplies for materials high
ects. This is most likely to occur facilities might also want to in chlorine and alkalis, by lim-
near cities, wood-based indus- consider cofiring. iting the biomass contribution
tries, or landfills and material to boiler heat input to 15% or
recycling facilities where wood • Boiler modifications and equipment less, by using fuel additives, or
waste is collected. NREL con- additions required. Start-up costs by increased sootblowing.
ducted a study that examined are a key consideration in eval- Additional site-specific adjus-
national waste wood availa- uating any cofiring project. The ments may be necessary.
bility and costs based on cost of modifying an existing Annual crops and agricultural
detailed local data gathered facility to use biomass or to residues, including grasses and
from 30 cities throughout purchase equipment to prepare straws, tend to have high
the United States. The study biomass for cofiring can range alkali and chlorine contents.
indicates that more than from nearly nothing to as In contrast, most woody mate-
60 million tons of wood much as $6/lb per hour of rials and waste papers are low
waste per year could be avail- boiler steaming capacity. in alkali and chlorine. As a pre-
able at a low enough cost to caution, a sample of each new
make cofiring economically type of fuel should be tested for



both chlorine and alkali before • Boiler efficiency losses. Some Equipment Integration
use. For further details on the design and operational A typical stoker boiler is shown in
alkali deposits associated with changes are needed to maxi- Figure 8. Recent demonstration
biomass fuels, including recom- mize boiler efficiency while projects of stoker boilers in Pitts-
mendations for fuel testing maintaining acceptable opac- burgh, Pennsylvania; Idaho Falls,
methods and specifications, ity, baghouse performance, Idaho; and Aiken, South Carolina,
see Miles et al. 1996. and so on. Without these have shown that properly sizing
adjustments, boiler efficiency the biomass fuel helps to avoid
• Fuel-handling and processing
and performance can decrease. the need for modifications to the
problems. Certain equipment
For example, boiler efficiency existing boiler. The Pittsburgh
and processing methods are
losses of 2% were measured project used premixed coal and
required to reduce biomass
during cofiring tests at a pul- wood chips. As indicated in Figure
to a form compatible with
verized coal boiler at a heat 8, no modifications were needed
coal-fired boilers and flue-
input level from biomass of to deliver the mixed fuel to the
gas-handling systems. Most
10% (Tillman 2000, p. 373). dump grate after the switch from
coal boiler operators are not
Numerous cofiring projects coal-only supplies. However, cofir-
familiar with biomass process-
have demonstrated that effi- ing biomass in an existing coal
ing, so technical assistance
ciency and performance boiler usually requires at least
may be needed to help make
losses can be minimized slight modifications or additions
the transition to biomass
with proper attention, how- to fuel-handling, processing, stor-
cofiring. Some cofiring facili-
ever. These losses should be age, and feed systems. Specific
ties have found it more con-
included in the final eco- requirements vary from site to site.
venient and cost-effective to
nomic evaluation for a project.
have biomass processed by a Fuel processing requirements are
third-party fuel supplier; in • Negative impacts on ash markets. dictated by the fuel source and
some cases, this is their coal Concrete admixtures represent boiler type. For suspension firing
supplier. When wood is used, an important market for some in pulverized coal (PC) boilers,
chips tend to work much coal combustion ash by-prod- biomass should be reduced to
better than mulch-like mate- ucts. Current ASTM standards a maximum particle size of
rial. Large quantities of fine, for concrete admixtures require 0.25 in. at moisture levels of
sawdust-like material should that the ash be 100% coal ash. less than 25%. When firing in
also be avoided because they Efforts are under way to demon- the range of 5% to 15% bio-
plug up the fuel supply and strate the suitability of com- mass (on a heat input basis),
storage system. mingled biomass and coal ash a separate injection system is
in concrete admixtures, but in normally required. For firing
• Underestimating fuel acquisition small amounts of biomass in
the near term, cofired ash will
efforts. Securing dependable, a PC boiler (less than 5% of
not meet ASTM specifications.
clean, economical sources of total heat), the biomass can be
This is a serious problem for
biomass fuels can be time- blended with the coal before
some utility-scale power plants
consuming, but this is one of injection into the furnace.
that obtain a significant amount
the most important tasks in
of revenue from selling ash. Additional processing and handling
establishing a biomass project.
Since most federal facilities equipment requirements make
Federal facilities that already
dispose of ash rather than separate injection systems more
have staff with experience in
sell it, this issue should not expensive than blended-feed sys-
aggregating and processing
be a problem; however, ash tems, but they offer the advantage
biomass are ideal sites for
disposal methods at each of higher biomass firing rates.
projects. In most cases, how-
potential project site should Cyclone, stoker, and fluidized-bed
ever, technical assistance
be considered early in the boilers are better suited to handle
will probably be required
evaluation process to avoid larger fuel particles, and they are
in this area.
future problems. thus usually less expensive to mod-
ify than PC boilers. In general,



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 Heating Plant 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-
to implement a cofiring project, it tration alternatives. Costs as low
Because of increases in regulations
is most likely to be commercially as $50 to $100/kW of biomass
for particulate emissions and
available. Therefore, it will carry power can be achieved for stokers,
increases in the availability of
the standard manufacturer’s war- fluidized beds, and low-percentage
natural gas, some federal boilers
ranty, which is usually a mini- (less than 2% biomass on a heat
are being converted from coal to
mum of one year for parts. Instal- basis) cofiring in cyclone and PC
natural gas despite the higher cost.
lation labor usually carries a one- boilers. For heating applications,
Fifteen projects in which natural
year warranty, as well. this is equivalent to about $3 to
gas (at about 10% of boiler heat
$6/lb per hour of steaming
capacity.
Retrofits for high-percentage
Chute cofiring (up to 15% of the total
heat input) at a pulverized coal
03381107

(PC) boiler are typically about
$200/kW of biomass power capac-
ity. Smaller applications such as
those at federal facilities have
Coal higher per-unit costs because they
Premixed coal bunker cannot take advantage of econo-
and biomass
mies of scale. For example, a
small-scale stoker application
Grating that requires a completely new
Gate
Chute receiving, storage, and handling
Hopper Boiler
system for biomass could cost as
Gate much as $350/kW of biomass
Stoker hopper
power capacity.

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



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
of $2.10/MBtu and a delivered For this Super ESPC, biomass fuels
streamlined Super ESPCs. These
biomass cost of $1.25/MBtu, pay- include any organic matter that is
“umbrella” contracts are awarded
back periods would be between available on a renewable or recur-
to ESCOs selected through a com-
one and three years for low-cost ring basis (excluding old-growth
petitive bidding process on 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
Through a standard ESPC, an ments, from energy-efficient light-
$110,000 for a typical federal
energy services company (ESCO) ing to heating and cooling systems.
boiler. Payback periods and annual
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



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-
Through the BAMF Super ESPC,
Performance tural residues. By using the waste
In general, facility managers who material as fuel, the companies
FEMP helps to make accessible to
have cofired biomass in coal- avoid a certain amount of fossil-
federal facilities the energy- and
fueled boilers have been pleased fuel purchases and disposal costs.
cost-savings benefits of biomass
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
transport 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
component of any project under
many boiler plant operators were Savings Calculations
seeking ways to reduce fuel costs.
this Super ESPC must feature the Appendix B contains worksheets
However, a steady number of
use of a biomass or alternative and supporting data for agencies
organizations have continued
methane fuel, all projects are to evaluate the feasibility of a
cofiring operations to reduce
also expected to employ a variety biomass cofiring operation in
their overall operating costs. Of
of traditional conservation meas- a preliminary manner. These
the 182 cofiring operations men-
ures, which include retrofits to worksheets were designed to
tioned above, 114 (or 63%) have
lighting, motors, and heating, permit useful calculations based
been at industrial facilities, 32 at



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
produce steam. The boilers were emissions, compelled SRS to
The first worksheet in Appendix B
manufactured by Combustion pursue the PEF project.
is for estimating the amount of
biomass fuel supply needed for a Engineering and have a capacity
of 60,000 lb/hr at full load. Fuel is New Technology Description
cofiring application. This can be
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 machine (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 particulates 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-
Appendix C provides examples of The PEF Facility has two major
age annual coal use at the facility
completed worksheets estimating handling sections: the tipping
was about 11,145 tons. At a deliv-
annual cost savings and biomass floor, where the PEF feedstock
ered price of $50 per ton, this coal
fuel supplies for DOE’s Savannah is delivered, and the processing
cost the site just over $550,000
River Site cofiring project. This line, which forms the feedstock
per year.
project is illustrated in the into cubes. Waste paper is col-
following case study. Like many other facilities its size, lected in plastic bags from facil-
SRS generates significant quanti- ity offices. The plastic bags con-
Case Study ties of scrap paper and cardboard taining the waste paper products
products—about 280 tons per are then loaded into 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 Utilities 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.



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 In other words,
right) are made of wood, cardboard, and office
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 elevator. 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



Table 7. Savings from the Savannah Performance Test Results review of emissions test results and
River Site Cofiring Project. procedures for material collection
As of February 2003, all equipment
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
ment installed at the SRS PEF operation at high levels of bio-
Disposal Savings (paper and
Facility was previously used in a mass input by the end of 2004.
cardboard)
PEF cube supply 3,880 tons/yr similar coal-and-biomass cofiring
Savings Source Savings
demonstration project at INEEL The Technology in
in Idaho. The equipment operated Perspective
Reduced coal costs $112,000/yr
Reduced landfill costs $89,000/yr well for more than a year at INEEL,
but its use was discontinued when Biomass cofiring has good poten-
Burn pit closure $83,000/yr
the steam plant was closed because tial for use at federal facilities
PEF processing costs ($30,000/yr)
of privatization of the utility. When with existing coal-fired boilers.
Total Cost Savings $254,000/yr Advantages to federal facilities
the equipment was used at INEEL,
PEF cubes provided about 25% (by that accrue from using biomass
Life-Cycle Cost volume) of the fuel at the steam cofiring technology can include
plant, and no major operational reductions in fuel, operating, and
Design, construction, and equip-
problems were encountered. landfill costs, as well as in emis-
ment purchases for the PEF
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- of the federal government.
tional costs. Operating the PEF
nance is expected to be necessary
Facility will cost about $30,000 By replacing coal with less expen-
at the steam plant.
per year. All expected costs and sive biomass fuels, a federal 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 technologies are readily available.
SRS steam plant personnel have
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.)



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
Detroit Stoker Company For more information about the
Bliss Industries
1510 East First Street BAMF Super ESPC, contact:
P.O. Box 910
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.
Foster Wheeler Corporation Philadelphia Regional Office
227 South Knox Drive
Perryville Corporate Park 100 Penn Square East, Suite 890
Burley, ID 83318
P.O. Box 4000 Philadelphia, PA 19107
Phone: 208-678-8015
Clinton, NJ 08809-4000 Phone: 215-656-6995
CPM Acquisitions Group E-mail:
Phone: (908) 730-4000
2975 Airline Circle christopher.abbuehl@ee.doe.gov
www.fwc.com
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
8259 Melrose Drive on biomass cofiring), prepared for
Constellation Energy Source
Lenexa, KS 66214 the U.S. Department of Energy
7133 Rutherford Rd.
Phone: 913-541-1703 Biomass Power Program.
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 Energy
Engineering 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



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Biomass Residue Supply Curves for Proceedings of the 4th Biomass Tillman, D.A. (2000), “Cofiring
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Sixteenth Annual Pittsburgh Coal Research Center, College of
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Conference Proceedings, University Engineering, University of
Hughes, E. (Sept. 1999), “Biomass
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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.



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
BDc = bulk density of coal _________ lb/ft3
HVb = average heating value of biomass fuel(s) _________ Btu/lb
BDb = bulk density of biomass _________ lb/ft3
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



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)



Average Daily Biomass Requirements:

DBFavg = daily biomass feed rate at average rated load (multiple units)

Annual Biomass Requirements:

ABU = annual biomass use (multiple units)



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)



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)



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)



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)



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 watts (W) and operates 2,000 hours annually requires 200,000
watt-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.



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.



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:
Energy consumption 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



About FEMP’s New Technology Demonstrations
The Energy Policy Act of 1992 and sector. Additional information on The information in the FTAs typical-
subsequent Executive Orders man- Federal Technology Alerts (FTAs) is ly includes a description of the can-
date that energy consumption in provided below. didate technology; the results of 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 FEMP sponsors publication of the
ogy demonstrations, is tasked to
use in the federal sector. FTAs to facilitate information-sharing
accelerate the introduction of energy-
efficient and renewable technol- between manufacturers and govern-
ogies into the federal sector and More on Federal Technology ment staff. While the 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-
have some experience but are not nology featured. Readers should
Technology Focuses—brief infor- note the publication date on the
mation on new, energy-efficient, in general use in the federal sector.
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-
within the federal sector and to pro- tions and the entrance of new man-
Federal Technology Alerts—
vide the right people in the field ufacturers or suppliers should be
longer summary reports that pro-
with accurate, up-to-date informa- anticipated since the date of publi-
vide details on energy-efficient,
tion on the new technologies so cation. FEMP encourages interested
water-conserving, and renewable-
that they can make educated judg- federal energy and facility managers
energy technologies that have been
ments on whether the technologies to contact the manufacturers and
selected for further study for possi-
are suitable for their federal sites. other federal sites directly, and to
ble implementation in the federal
use the worksheets in the FTAs to
aid in their purchasing decisions.

Federal Energy Management Program
The federal government is the largest energy consumer in the nation. Annually, in its 500,000 buildings and 8,000 locations
worldwide, it uses nearly two quadrillion Btu (quads) of energy, costing over $8 billion. This represents 2.5% of all primary
energy consumption in the United States. The Federal Energy Management Program was established in 1974 to provide direc-
tion, guidance, and assistance to federal agencies in planning and implementing energy management programs that will
improve the energy efficiency and fuel flexibility of the federal infrastructure.

Over the years, several federal laws and Executive Orders have shaped FEMP's mission. These include the Energy Policy
and Conservation Act of 1975; the National Energy Conservation and Policy Act of 1978; the Federal Energy Management
Improvement Act of 1988; the National Energy Policy Act of 1992; Executive Order 13123, signed in 1999; and most recently,
Executive Order 13221, signed in 2001, and the Presidential Directive of May 3, 2001.

FEMP is currently involved in a wide range of energy-assessment activities, including conducting new technology demonstra-
tions, to hasten the penetration of energy-efficient technologies into the federal marketplace.

A Strong Energy Portfolio for a Strong America For More Information
EERE Information Center
Energy efficiency and clean, renewable energy will mean a stronger economy, a cleaner 1-877-EERE-INF or
environment, and greater energy independence for America. Working with a wide array 1-877-337-3463
www.eere.energy.gov/femp
of state, community, industry, and university partners, the U.S. Department of Energy’s
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
1000 Independence Ave., S.W., EE-92
Washington, DC 20585
Phone: (202)-586-8017
Fax: (202)-586-3000
theodore.collins@ee.doe.gov
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 steven.parker@pnl.gov

• A New Technology Demonstration Overview Technical Contacts and Authors

• Information on technology demonstrations Sheila Hayter
National Renewable Energy Laboratory
• Downloadable versions of publications in Adobe Portable 1617 Cole Blvd.
Golden, CO 80401
Document Format (pdf)
Phone: (303) 384-7519
• A list of new technology projects under way E-mail: sheila_hayter@nrel.gov
Stephanie Tanner
• Electronic access to a regular mailing list for new products
National Renewable Energy Laboratory
when they become available 901 D Street, S.W., Suite 930
Washington, DC 20024
• How federal agencies may submit requests to us to assess Phone: (202) 646-5218
new and emerging technologies E-mail: stephanie_tanner@nrel.gov
Kevin Comer and Christian Demeter
Antares Group Inc.
4351 Garden City Drive, Suite 301
Landover, MD 20785
Phone: (301) 731-1900

Produced for the U.S. Department of
Energy, Energy Efficiency and Renewable
Energy, by the National Renewable Energy
Laboratory, a DOE national laboratory

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June 2004

Energy Efficiency
Printed with a renewable-source ink on paper containing at and Renewable Energy
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Bringing you a prosperous future
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