Biomass & Bioenergy Article
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The economics of reburning with cattle manure-basedbiomass in existing coal-fired power plants for NOx
and CO2 emissions control
Nicholas T. Carlina, Kalyan Annamalaia,*, Wyatte L. Harmanb, John M. Sweetenc
aDepartment of Mechanical Engineering, Texas A&M University, College Station, TX, USAbBlackland Research and Extension Center, Texas A&M University System, Temple, TX, USAcTexas AgriLife Research and Extension Center, Texas A&M University System, Amarillo, TX, USA
a r t i c l e i n f o
Article history:
Received 30 January 2008
Received in revised form
20 April 2009
Accepted 29 April 2009
Published online 5 June 2009
Keywords:
Engineering Economics
Reburn
Coal
Cattle biomass
Manure
Sensitivity analysis
a b s t r a c t
Coal plants that reburn with catttle biomass (CB) can reduce CO2 emissions and save on
coal purchasing costs while reducing NOx emissions by 60–90% beyond levels achieved by
primary NOx controllers. Reductions from reburning coal with CB are comparable to those
obtained by other secondary NOx technologies such as selective catalytic reduction (SCR).
The objective of this study is to model potential emission and economic savings from
reburning coal with CB and compare those savings against competing technologies. A
spreadsheet computer program was developed to model capital, operation, and mainte-
nance costs for CB reburning, SCR, and selective non-catalytic reduction (SNCR). A base
case run of the economics model, showed that a CB reburn system retrofitted on an
existing 500 MWe coal plant would have a net present worth of �$80.8 million. Compara-
tively, an SCR system under the same base case input parameters would have a net present
worth of þ$3.87 million. The greatest increase in overall cost for CB reburning was found to
come from biomass drying and processing operations. The profitability of a CB reburning
system retrofit on an existing coal-fired plant improved with higher coal prices and higher
valued NOx emission credits. Future CO2 taxes of $25 tonne�1 could make CB reburning as
economically feasible as SCR. Biomass transport distances and the unavailability of suit-
able, low-ash CB may require future research to concentrate on smaller capacity coal-fired
units between 50 and 300 MWe.
ª 2009 Elsevier Ltd. All rights reserved.
1. Introduction
Cattle biomass (cattle manure) has been proposed for use as
a reburn fuel for nitrogen oxide (NOx) emission reduction in
coal-fired power plants and utility boilers. Cattle biomass (CB)
has shown promise in reducing NOx due to its high volatile
content, rapid release of volatile matter during combustion,
and rapid release of fuel bound nitrogen predominantly in the
form of ammonia (NH3). Experiments conducted by Sweeten
et al. [1], Annamalai et al. [2], Arumugam [3], and Lawrence
et al. [4] demonstrated that co-firing feedlot biomass (FB) and
coal (blending 10% FB and 90% coal) could reduce NOx emis-
sions from 290 ppm to 260 ppm. Numerical studies by Sami [5]
were also conducted for co-firing coal and biomass in low-NOx
swirl burners. Recent experiments and numerical models,
conducted at the Texas A&M Coal and Biomass Energy
* Corresponding author. Tel.: þ1 979 845 2562; fax: þ1 979 845 3081.E-mail address: [email protected] (K. Annamalai).
Avai lab le a t www.sc iencedi rec t .com
ht tp : / /www.e lsev i er . com/ loca te /b iombioe
0961-9534/$ – see front matter ª 2009 Elsevier Ltd. All rights reserved.doi:10.1016/j.biombioe.2009.04.007
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Laboratory, have shown that reburning with CB can reduce
NOx emissions up to 90% [6–10].
If these results can translate into similar NOx reductions
for larger burners and utility boilers, CB reburning can be
considered a competitive technology to other, more common
secondary NOx control retrofits such as selective catalytic
reduction (SCR) and perhaps superior to natural gas reburning
and selective non-catalytic reduction (SNCR) as far as NOx
reduction efficiency.
The purpose of this study was to predict and gage the
economic viability of reburning coal with CB at existing coal
plants against several major parameters such as dollar values
of avoided emissions, biomass processing costs, and trans-
portation costs. This study was conducted by generating
a mathematical model from engineering and economic anal-
yses of the drying, transportation, and combustion systems
involved in the overall process of utilizing CB as a reburn fuel
in existing coal plants. The methodology and justification of
the model will be covered later in this article, but first some
discussion of CB and reburning processes is necessary.
1.1. Cattle biomass from large feeding operations
American agriculture, particularly animal farming, has
become a highly industrialized business over the past 50
years. The larger and more productive of these animal farms
are commonly referred to as concentrated animal feeding
operations (CAFOs) or ‘‘super farms’’. Housing dairy cows,
beef cattle, and other traditional farm animals and also
disposing of the large amounts of manure produced from
them are significant undertakings [11]. These feeding opera-
tions show the potential for water and air pollution due to the
manure production, yet the concentration and constant
generation of the manure at discreet geographic areas, may
make this low-calorific value feedstock a viable source of fuel
for combustion and emission control systems for plants near
CAFOs. See Fig. 1. Yet simply finding power plants near animal
feeding operations that can also benefit from reburning
systems may be challenging. Thus, a study such as the one
described here is necessary before further implementation of
CB reburning is undertaken.
The three largest beef cattle states in the US are Texas,
Kansas and Nebraska, respectively [14]. Feedlot cattle can
produce 5–6% of their body weight in manure each day; a dry
mass roughly 5.5 kg per animal per day [15]. Thus, on a dry
basis, nearly 20 Tg of cattle manure per year comes from large
feedlot CAFOs. Texas alone produces over 27% of this annual
total. Similarly, areas such as the Bosque River Watershed
near Waco, Texas and many parts of California contain
dozens of large dairy operations, each with over 500 milking
cows. Full-grown milking cows can produce 7–8% of their body
weight in manure per day; roughly a dry mass of 7.3 kg per
animal per day [16]. A dry mass of about 24 Tg of dairy manure
is produced per year in the US. The term ‘‘cattle biomass (CB)’’
will refer to both feedlot and dairy manure in general. Manure
from feedlots will be termed feedlot biomass (FB) and manure
from dairies will be termed dairy biomass (DB).
The usefulness of CB as a fuel for combustion and emission
control systems can be determined from ultimate and heat
value analyses of each biomass fuel. These analyses are
summarized in Table 1 for DB (both low ash, LA, and high ash,
HA), FB (both LA and HA), and coal (Wyoming Powder River
Basin sub-bituminous, WYPRB, and Texas Lignite, TXL).
Low-ash biomass from cement-paved lots and feed yards
has a comparable amount of ash to TXL, which suggests that
boilers setup to burn lignite could probably handle burning LA
DB or LA FB. However, high ash fuels with contents up to 68%
(on a dry basis) are certainly not suitable for most combustion
systems. Please refer to contributions from Oh et al. [19] for
further discussion of ash fouling in CB boilers. Thus, the
present paper will concentrate on LA CB; however, it should be
noted that the vast majority of FB scraped from feed yards
contains high amounts of ash because nearly all lots are
currently unpaved. On the other hand, free stall dairies with
automated flushing systems are becoming quite prevalent,
especially for larger dairies. Many of these dairies use com-
posted solids as bedding to reduce sludge build-up in storage
structures and lagoons [20]. The mechanically (screen) sepa-
rated solids from flushing systems are typically of the low ash
variety if sand is not used as bedding. For a full discussion on
fuel properties of cattle biomass please refer to papers by
[1,17,21–24].
Fig. 1 – Matching coal-fired power plants and areas with high agricultural biomass densities, adapted from [12] and [13].
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1.2. Primary NOx control technologies
The primary NOx controls on coal-fired power plants typically
consist of either low-NOx burners (LNB), over fire air (OFA), or
a combination of both. These controls are widely used in coal-
fired plants throughout the United States. Low-NOx burners
delay the complete mixing of fuel and air as long as possible in
order to reduce oxygen in the primary flame zone, reduce
flame temperature, and reduce residence time at peak
temperatures. Basic principles of NOx reduction in coal-fired
burners were reviewed by Williams et al. [25]. Discussion of
the enhancements to these primary NOx controls such as
multilevel OFA and rotating opposed fire air can also be found
in papers by Srivastava et al. [26] and Li et al. [27].
1.3. Secondary NOx control technologies
1.3.1. ReburningA basic illustration of the reburning process is shown in Fig. 2.
Coal is injected into a lean (excessive amount of air) primary
burn zone (PZ) and releases gaseous emissions relatively high
in NOx. Next, the combustion gases enter a secondary stage of
combustion, or reburn zone (RZ), in which a fuel rich mixture
of reburn fuel and air react with the hot combustion gases to
produce emissions with a relatively low amount of NOx. The
mechanism of reduction is a reverse prompt NOx reaction in
which hydro-carbon (HC) fragments form nitrogen
compounds, such as hydrogen cyanide (HCN) and NH3, which
react with NOx to reduce it to harmless nitrogen (N2). Finally,
over fire air is injected into the boiler burner to complete the
combustion process and reduce carbon monoxide (CO)
emissions.
The most common reburn fuel is natural gas. Conventional
gas reburn systems can reduce NOx emissions by 50–60% [28].
Yang et al. [29] found that 65% reductions could be achieved by
reburning with coal. A CB reburn system can offer even
greater NOx reductions and also reduce CO2 emissions from
fossil fuel sources. However, unless ash is removed from the
CB before hand, ash emissions will increase when supplying
CB in the RZ because CB typically contains more ash than coal
and most lignite [8,19,30].
1.3.2. Selective catalytic and non-catalytic reductionThere are some more commercially available secondary NOx
controllers. One of the most common and effective of these
technologies is selective catalytic reduction (SCR). In these
reduction systems ammonia (NH3) or some other reagent is
injected, in the presence of a catalyst, to reduce NOx. Selective
Table 1 – Ultimate and heat value analyses of selected CB and coal fuels (all percentages are on a mass basis).
Dry basis
LADBa HADBa LAFBa HAFBa WYPRBb TXLb
%Moisture 0.00 0.00 0.00 0.00 0.00 0.00
%Ash 19.98 68.24 13.58 45.23 8.40 18.59
%Carbon 47.10 20.53 49.63 32.34 69.31 60.30
%Hydrogen 4.17 1.82 5.89 3.85 4.07 3.44
%Nitrogen 2.58 1.31 3.35 2.31 0.98 1.10
%Oxygen 25.62 7.89 27.01 15.83 16.83 15.59
%Sulfur 0.58 0.21 0.54 0.43 0.41 0.99
HHV (kJ kg� 1) 17,148 4,902 18,650 11,243 27,107 23,176
Dry ash free basis
%Moisture 0.00 0.00 0.00 0.00 0.00 0.00
%Ash 0.00 0.00 0.00 0.00 0.00 0.00
%Carbon 58.85 64.63 57.43 59.06 75.67 74.06
%Hydrogen 5.22 5.74 6.82 7.03 4.44 4.22
%Nitrogen 3.23 4.12 3.88 4.22 1.07 1.35
%Oxygen 32.02 24.86 31.26 28.91 18.37 19.14
%Sulfur 0.72 0.65 0.62 0.78 0.44 1.22
HHV (kJ kg� 1) 21,429 15,434 21,581 20,528 29,594 28,467
a Adopted from Sweeden et al. [17].
b Adopted from TAMU[18].
Primary Coal Injection• Along with primary
combustion air
Reburn Fuel Injection• Usually natural gas or coal, but
could be cattle biomass, • 10-20% of the plant heat rate• Rich mixture, ER = 1.05 –1.2 • Temperature: 1300-1500 K
High NOxemission
Lower NOx emission60 to 90% reduction
Over Fire Air• Completes the combustion
process
Exhaust Gases• With acceptable NOx
emission as low as 26 g/GJ• Lower CO2 emission
from nonrenewable sources
Fig. 2 – Reburning process in a coal-fired power plant.
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catalytic reduction systems can provide reductions greater
than 90%, depending on the catalyst, the flue gas temperature,
and the amount of NOx present in the combustion gases
exiting the PZ [26,31,32].
Selective non-catalytic reduction (SNCR) is a similar post
combustion technology to SCR, except that the NH3 or urea is
injected without the presence of a catalyst and at higher
temperatures [26]. However, reductions for SNCR are rarely
over 35% for large boilers with heat rates greater than
3.16 TJth h�1 (about 315 MWe) due to mixing problems [31,33].
2. Methods
A spreadsheet model for a single coal-fired unit utilizing CB
as a reburn fuel was developed to gage the economic
viability of retrofitting CB co-combustion systems in existing
coal-fired facilities. The methods, assumptions, and research
involved in generating this model are discussed in this
section. Once the model was completed, a reference or base
case run was completed. From this base case result, several
major parameters were varied over a certain range to
demonstrate the sensitivity of the overall cost (or benefit) of
reburning coal with CB.
2.1. Modeling plant operation
To demonstrate the spreadsheet program’s capabilities, and
for the sake of brevity, only one case of fueling setup for the
power plant was considered for the present article. For this
case, the primary fuel (PF) burned in the boiler’s primary burn
zone (PZ) was pure Wyoming sub-bituminous coal. Whereas
the reburn fuel (RF) injected into the reburn zone (RZ) was
cattle biomass. Blends of these fuels in either the PZ or RZ are
not discussed here; however, they too can be represented with
the present model.
Plant operating parameters such as the plant capacity, the
overall fueling rate, the capacity factor, the plant’s annual
operating hours, the higher heating values of the primary and
reburn fuels, and the percentage of the plant’s heat rate
supplied by the reburn fuel are usually known or design
variables. Other parameters such as the plant’s overall heat
rate, the mass fueling rates of the primary and reburn fuels,
and the plant’s overall efficiency, can generally be computed
from these inputs. Thermo-physical properties of CB, such as
bulk density and specific heat, and modeling equations of
these properties were discussed by Bohnhoff et al. [34] and
Chen [35]. These equations were also used throughout the
current model.
2.2. Modeling biomass processing and transportation
The cost of processing and importing coal was a simple dollar
per tonne (1.0 Mg) input value prescribed to the spreadsheet
program. However, this was not the case for CB. The cost of
preparing the biomass for the reburning process needed to be
determined from known values of fueling rate, biomass
moisture percentage, labor, distance between the plant and
feeding operation and other drying and transportation cost
parameters.
2.2.1. Drying cattle biomassCattle biomass reburn fuel must be supplied to a coal-fired
operation from neighboring animal feeding operations.
Therefore, a distribution system may be envisioned where
there are a number of small dryers (rated between dry matter
of 0.5–2.0 tonne h�1) installed on each feeding operation, or
perhaps a centralized composting and drying facility within 5–
30 km from the feeding operations. See Fig. 3. Brammer and
Bridgwater [36] reviewed numerous designs of dryers that
may be used for wood and crop-based biomass preparation for
combustion, while [37] conducted an economic modeling
study of how drying biomass affects the overall economics of
biomass gasifier-engine combined heat and power systems.
Kiranoudis et al. [38] presented a full mathematical model
simulating the operation and economics of similar conveyor
belt (band) dryers used for food processing, including an
algorithm for computing the conveyor belt area. Fig. 4 is
a representation of the biomass dryer setup with some typical
values for input parameters used during the present model. A
capital cost function for dryers in terms of the conveyor belt
area was also presented by [37]. The modeling equations for
biomass band dryers utilized in the spreadsheet program were
largely adopted from these papers. Labor costs, fueling costs
for heating dryer air, electricity cost for the dryer’s fans,
biomass loader costs, and the purchasing cost of land in which
the dryers would be built were also considered in the analysis.
2.2.2. Transporting cattle biomassThe cost of transporting the dried CB to the power plant was
also included in modeling studies. One of the most important
parameters was the average distance between the animal
feeding operation(s) and the power plant. This distance
determined the number of hauling vehicles (trucks) required
to move the biomass, as well as the number of round trips that
those trucks took per year to consistently supply the reburn
system at the power plant. Alternatively, Ghafoori et al. [39]
discussed piping liquid manure (12% solids) to anaerobic
digester sites. However, this method of biomass trans-
portation may not be applicable to CB reburning, because it is
doubtful that the power plant facility would handle huge
volumes of wastewater resulting from the solids extraction
from the liquid manure.
Therefore hauling transportation analysis was adopted
largely from a USEPA [40] report on the economics of running
CAFOs that transport solid manure to composting sites. Other
parameters that were required for the transportation analysis
included: the biomass loading and unloading times, the
average truck speed, the daily hauling schedule, the number
of hauling days per year, and the volumetric capacity of each
truck.
2.3. Modeling emissions from coal-fired powerplants and their NOx control technologies
Cattle biomass reburning systems may, at least, affect three
types of emissions from coal-fired units: nitrogen oxides
(NOx), carbon dioxide (CO2), and ash. Although the primary
function of a reburn system is to reduce NOx emissions, cattle
biomass reburning is expected to also decrease CO2 from
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nonrenewable sources and increase ash production. The
extent to which these emissions are affected depends on the
chemical composition of the biomass, the amount of RF
injected in the RZ relative to the coal firing rate, and the
expected NOx reduction due to reburning.
Some of the more important parameters in determining
the emissions from biomass combustion were the percent-
ages of moisture, ash and each combustible element in the
fuel. Hence, the ultimate and heat value analyses listed in
Table 1 were used as input parameters for the model.
An uncontrolled NOx level, that is the level that would
occur if there were no primary or secondary NOx controls
installed at the coal plant, was computed from expressions
taken from the USEPA [41]. These equations took into account
the coal’s rank and the boiler type (i.e. wall-fired, tangentially-
fired, etc.). Nitrogen oxide emission levels (g GJ�1) obtained by
primary NOx controls were determined based on the coal’s
rank, the boiler type, and the type of LNB and/or over fire air
system installed at the plant. NOx emissions obtained by CB
reburning, SCR, and SNCR were treated as input values. From
these levels, total annual reductions (tonne NOx year�1) as
well as reduction percentages were computed.
NOx emissions from hauling vehicles were also taken into
account during modeling. The NOx emission from hauling
Boiler
Ambient AirT = 25 °C
Cattle Biomass60% moisture
Cattle Biomass20% moistureT ≈ 107 °C
Exiting AirT = 107 °C
Entering AirT = 137 °C
Pressure = 345 kPa(gage)
saturated steamDrying
chamberBoiler
Fig. 4 – Dryer setup for spreadsheet model, adapted from [38].
Dairy
Dairy
Large feedlot or CAFO
Dryer
Power Plant
Centralized drying and
composting facility
5-30 km
(3-20 miles)
80-320 km
(50-200 miles)
Fig. 3 – Modeled cattle biomass processing and transportation system, picture of conveyor belt dryer adopted from [36].
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vehicles was computed, assuming typical load factors and
horse power ratings. Nonrenewable CO2 emissions from
hauling vehicles and biomass dryers were also included in the
model. Diesel fuel was modeled as C12H26. Natural gas and
electricity used to drive the boilers and fans, respectively, at
the drying facilities was also accounted for when determining
overall carbon emissions from the reburn system. The CO2
emitted from these two sources was computed and then
added to the CO2 emitted by the coal fired at the power plant.
Finally, the amount of inert ash produced by the plant was
expected to increase due to the generally higher ash content of
CB, even LA CB, compared to most coals. Moreover, since ash
must either be sold for exterior usage, or disposed in landfills,
the results from this analysis was used to compute overall
dollar savings or costs from ash production. Sulfur oxide (SOx)
emissions were also accounted for; however, these emissions
will either increase or decrease during reburning depending
on the sulfur content of the biomass relative that of the coal.
2.4. Modeling the economics of NOx control systems
The cost of installing an environmental retrofit on a coal-fired
power plant can be broken up into three different components:
capital cost, fixed operation and maintenance costs (FO&M), and
variable operation and maintenance costs (VO&M). The capital
cost is the initial investment of purchasing and installing all
necessary equipmentso that thesystem is fully functional.Fixed
operation and maintenance costs are generally incurred
whether the system is running or not. These costs typically
include labor and overhead items such as fuel feeders, grinders,
and air and fuel injectors, whereas, VO&M costs include
handling and delivery of raw materials and waste disposal [42].
2.4.1. Integrated planning model for common NOx controllersIn the economic spreadsheet model, both primary and
secondary NOx control technologies were modeled in much
the same way as was done for the USEPA Integrated Planning
Model (IPM). The results from the IPM are meant to compare
energy policy scenarios and governmental mandates con-
cerning electric capacity expansion, electricity dispatch and
emission control strategies. The latest update of the IPM, as of
the writing of this paper, may be found on the USEPA [41]
website. Since a section of the IPM is concerned with evalu-
ating the cost and emission impacts of environmental retro-
fits, it is possible to adopt these emission models to describe
the economics of common primary and secondary controls,
and then compare them to results for CB reburning.
The NOx control technology options modeled by the EPA
IPM are LNB (with and without over fire air), SCR, and SNCR.
Capital and FO&M costs are functions of power plant capacity,
while VO&M costs are functions of heat rate. Models pre-
sented by Mussatti et al. [32,33] offer more detailed and
comprehensive representations for SCR and SNCR cost
components, but require more inputs.
2.4.2. Cattle biomass reburn economicsReburn technologies were not included in the latest version of
the IPM. Thus, the main challenge of this study was to esti-
mate the cost performance of a CB reburning system even
when only experimental results and pilot scale tests have
been conducted for these systems, and few applications of gas
and coal reburning systems existed for comparison. Work by
Zamansky et al. [43] suggested that reburn systems utilizing
furniture wastes, willow wood, and walnut shell biomass have
similar capital costs to coal reburning systems. An earlier 1998
USEPA [44] report for the Clean Air Act Amendment, which
was also sited by Biewald et al. [45], modeled both gas and coal
reburn systems, although the coal reburn model was meant
only for cyclone boiler types. Gas reburning costs are generally
lower than coal reburning costs. Cyclone boilers burn coarsely
crushed coal, but coal reburn systems typically require
pulverized or micronized coal to avoid unburned carbon
emissions. Hence, purchasing pulverizing equipment is
generally required for cyclone boiler plants.
Some estimates of coal and biomass reburn capital costs
are presented in Table 2. Note that capital costs for reburning
in this table do not include the capital cost of dryers and
biomass hauling vehicles which will be needed for CB
reburning but not coal reburning. These costs, as was dis-
cussed earlier, were computed separately. As for the FO&M
cost equation, the model presented by the USEPA [44] was
used for the spreadsheet model, with the exception of an
additional scaling factor that accounted for the CB’s poorer
heat value and hence greater required fueling rate. To describe
the uniqueness of CB reburning to other reburning facilities,
VO&M costs such as biomass drying, transporting, and ash
disposal were individually calculated.
Annual monetary values pertaining to NOx, nonrenewable
CO2, and ash revenues were also computed during modeling.
Values for NOx emission credits were taken from the SCAQMD
[48]. During modeling it was assumed that that the plant
would earn monetary returns on all NOx emission reductions
beyond primary NOx emission levels. Although coal-fired
plants in the US are currently not required to reduce CO2
Table 2 – Coal and biomass reburn capital cost estimatesfrom various sources (all scaled to 2007 dollars).
Capital cost($ kWe
�1)Source Notes
42.3 Zamansky
et al. [43]
Same cost for both coal and
biomass reburning. 300 MWe plant.
Furniture, willow wood, and
walnut shell biomass.
54.3 Zamansky
et al. [43]
Same cost for both coal and
biomass reburning. 300 MWe plant.
Advanced reburn process.
91:2ð300P Þ
0:388 USEPA [44] Coal reburning in cyclone boilers
only. Where, P¼ plant capacity in
MWe
72.4 Smith [46] Coal reburning in cyclone boilers,
40% NOx reduction from an
370 g GJ�1 baseline emission
7.2–15.7 Smith [46] Pulverized coal configurations
using some existing equipment for
coal reburn fuel preparation
104.9 and 68.4 Mining
Engineering
[47]
For 110 MWe and 605 MWe plants,
respectively. 50% NOx reduction on
cyclone burners with pulverized
coal for reburn fuel
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emissions, the model was used to speculate how taxes, cap
and trade-based CO2 allowances, or avoided sequestering
costs may affect the profitability of a CB reburn system.
2.4.3. Overall operation economicsWith all annual costs computed, each cost component of the
NOx control technologies were added to compute a total
operating cost of the system. The spreadsheet generated for
the present study was used to compute emissions and annual
costs for four different cases:
1. coal fired in a unit with primary NOx controls only,
2. coal fired in a unit with primary controls retrofitted with
a CB reburn system,
3. coal fired in a unit with primary controls retrofitted with an
SCR system, and
4. coal fired in a unit with primary controls retrofitted with an
SNCR system.
An option to turn off primary NOx controls in order to
evaluate applications where secondary controls existed but
not primary was also written into the program.
One of the more common ways to indicate the economic
bottom line of a project is to compute a net present worth
(NPW) that is the equivalent combined value of all cash flows
throughout the life of the project in present dollars. The first
step in computing the NPW is to compute an operating income
(or cost, if negative) for each year, n. This summation is shown
in the following expression.
Operating Incomen ¼ �O&Mtotal-drying;n �O&Mtotal-truck;n
� FO&Mcofire;n þ Coal Savingsn
þ CO2 Savingsn � SO2 Costn
�Ash Disposaln þAsh Salen
þMBB Costn þNOx Savingsn (1)
Depending on the size of the benefits versus the costs, the
operating income can be positive (revenue) or negative (cost).
These cash flows are illustrated in Fig. 5. The total investment
of the reburn project will include the additional plant equip-
ment, the dryers, and the hauling vehicles. Note that for long
project life times (30 years in Fig. 5) drying equipment and
trucks will require replacements throughout the life of the
project.
Before computing the NPW, depreciation of capital and
taxes on income must also be addressed. The depreciation
method adopted for the present analysis was the modified
accelerated cost recovery system (MACRS).
The income after tax will be discounted by a factor:
Discount factorn ¼ ð1þDRÞn (2)
where DR is the discount rate. And the discounted income in
present dollars is simply:
Discounted Incomen
�$present
�¼ Income after taxn
Discount factorn(3)
Finally, theNPWcanbecomputedwiththefollowingexpression.
NPW�$present
�¼X30
n¼1
Discounted Incomen � Investmenttotal (4)
If the NPW is positive, then it is usually referred to as the net
present value (NPV), while negative NPWs are called net
present costs (NPC).
The NPW can be expressed as an annualized cost (or revenue)
leveled throughout the life of the project. For this case,
Annualized Cost or Revenue
�$
yr
�¼ NPW�
"DRð1þDRÞ30
ð1þDRÞ30�1
#
(5)
From here, the leveled annual cost can be expressed with
other parameters specific to the reburn model. For example,
the specific NOx reduction cost can be computed as:
Specifc NOx Reduction
�$
tonne NOx
�
¼ Annualized CostðRreburn � emissiontruck;NOx Þ
(6)
where Rreburn is the annual reduction of NOx from reburning
coal with biomass.
More information about computing depreciations, taxes,
and NPWs can be found in the textbook by Newnan et al. [42].
Project
time (yrs)
Cash
F
lo
ws (D
ollars)
3015 20 255 10
Diesel, natural gas, propane fueling costs
Labor & Maintenance
Coal savingsNew plant equipment and retrofit
Dryer facility and equipment
Transport vehicles
3015 20 255 10
Avoided CO2and NOxemission allowances
Annual Cash Flows Capital Costs
Fig. 5 – Capital and annual cash flows encountered for cattle biomass reburn operation and retrofit project.
b i o m a s s a n d b i o e n e r g y 3 3 ( 2 0 0 9 ) 1 1 3 9 – 1 1 5 7 1145
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All modeling equations for the present study are also pre-
sented in greater detail in a dissertation by Carlin [22]. The
flow diagram in Fig. 6 summarizes the computations con-
ducted with the spreadsheet model.
3. Base case parameters and data input
Base case input parameters for a theoretical 500-MWe coal-
fired power plant were chosen from research and literature
review. This set of inputs acted as a reference point for para-
metric study and sensitivity analysis. Tables 3–7 are lists of all
base case input parameters pertinent to modeling the opera-
tion of the NOx control technologies as well as the processing
and transportation of CB for reburning. All of the dollar inputs
were scaled to 2007 dollars and represented Year 1 of the
reburn retrofit project. Price escalation factors for some
parameters were also accounted for and discussed in the
‘‘Notes’’ column in the tables. However, these base case inputs
are not set. These numbers can and should be changed to
accommodate different situations and facilities. In fact, vari-
ations to some of the more significant base input parameters
were made in order to study the sensitivity of the overall NPW
and annualized cost.
4. Results and discussion
4.1. Base case results
From the base case inputs, a resulting reference run was
completed. The heat energy released by the CB in the reburn
zone of the boiler burner was found to be 2.38 PJ year�1 more
than the energy needed to dry and transport it to the plant.
Total CO2 emissions for reburning, including carbon emis-
sions from CB drying and transportation, were found to be
Fig. 6 – Overall flow diagram of economics spreadsheet computer model.
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263,000 tonne year�1 less than emissions for primary control
operation only. The electricity used to run the dryer’s fans was
assumed to come completely from coal combustion. Lastly,
since the hauling vehicles were assumed to meet 2007 NOx
standards with catalytic converter systems, the NOx emitted
by the vehicles only inhibited CB reburn NOx reductions by
about 6.0 tonne year�1, compared to a 2500 tonne year�1
reduction beyond primary control levels.
Table 3 – Base case input parameters for coal-fired plant operating conditions and emissions (all dollar amounts are in 2007dollars).
Input Value (unit) Source Notes
Plant capacity 500 MWe
Heat rate 10,290 kJth kWhe�1 About 35% plant efficiency, average for most coal-fired power plants
Capacity factor 80%
Operating hoursa 8760 h year�1 1 year¼ 8760 h. Non-stop utility operation.
Primary fuel WYPRB coal TAMU [18] See Table 1, Moisture percentage for coal when fired is 30%
Boiler type Tangentially-fired
Coal cost $38.58 tonne�1 EIA [49] As delivered cost for Powder River Basin Sub-bituminous coal. Coal prices
were assumed to escalate annually by 3.77% [50].
NOx credit/allowance $2,590 tonne�1 SCAQMD [48] Average annual price for Compliance Year 2005. Assume credits gained for
reductions beyond primary control levels. NOx values are assumed to
escalate annually by 4.5%.
CO2 price $0 tonne�1 No current mandatory markets for CO2 in most of the United States
SOx credit/allowance $970 tonne�1 SCAQMD [48] Average annual price for Compliance Year 2005. The value of SOx was
assumed to escalate by 4% annually.
Ash sale price $35.89 tonne�1 Robl [51] Range: $35.89–43.06 tonne�1. The sale price of ash and the disposal cost of ash
are both assumed to escalate by 1% annually.
Ash disposal cost $34.42 tonne�1 ACAA [52] Range: $22.05–44.09 tonne�1. Landfill tipping fees for non-hazardous waste.
Percentage of ash
soldb
20% Robl [51] For coal, 61% of solid byproduct is fly ash which can be sold for outside use.
On average, only 11% of solid byproduct is sold.
a For base case, reburn, SCR and SNCR systems are assumed to operate during all plant operating hours.
b For base case run, ash sold during reburning is the same, by mass, as that sold when only primary controls are used.
Table 4 – Base case input parameters for primary and secondary NOx control technologies (all dollar amounts are in 2007dollars).
Input Value (unit) Source Notes
Primary NOx control Low-NOx coal and air nozzles
with closed-coupled OFA
See primary control NOx level
(next item)
Primary NOx control
level
94.8 g GJ�1 Srivastava [26] About 45% average reduction
efficiency for these primary
controls when burning sub-
bituminous coals
Reburn fuel LADB Sweeten et al. [17] See Table 1
Heat contribution from
reburn fuel
10% Range: 5–20%
Reburn NOx control level 25.9 g GJ�1 Colmegna et al. [30], Oh et al.
[10], Annamalai et al. [7],
Annamalai et al. [53]
Reburn capital cost $42.25 kWe�1 Zamansky [43]
Reburn fixed O&M $1.39 kWe�1 year�1 Biewald et al. [45],USEPA [44] Scaled for different plant capacities
and firing cattle biomass.
SCR NOx control level 25.9 g GJ�1 USEPA [31] >90% reduction, but current
commercial systems are usually
limited to 25.9 g GJ�1
SNCR NOx control level 64.6 g GJ�1 Srivastava [26] w35% reduction from larger coal
plants
SOx control Flue gas desulphurization
system is installed
SOx reduction efficiency 95% USEPA [31] Typical for Limestone Forced
Oxidation (LSFO), which can reduce
SOx down to about 25.9 g GJ�1 and
is applicable to plants with greater
than 100 MW capacities
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Table 5 – Base case input parameters for cattle biomass drying (all dollar amounts are in 2007 dollars).
Input Value (unit) Source Notes
Biomass moisture
percentage before
drying
60% Carlin [23] Typical for partially composted separated dairy biomass
solids from flushing system
Biomass moisture
percentage after
drying
20% Annamalai et al.
[7], Annamalai
et al. [53]
Approximate moisture percentage of biomass during co-
firing and reburning experiments
The biomass is dried
before it is
transported to the
power plant
– The biomass can possibly be dried at the power plant by
using waste heat from the combustion processes at the
plant. However, this may increase the cost of transporting
the biomass and it may not be allowable to have as received
manure biomass at the power plant.
Capacity of single
biomass dryer
2 tonne dry basis Smaller scale dryer such as those discussed by Brammer
et al. [37]. The capital cost function of these dryers can be
found in [37]. The annual price escalation of dryers was
assumed to be 3.9% [50].
Height of drying
chamber
0.5 m Brammer et al. [37]
Width of drying
chamber
0.5 m Brammer et al. [37]
Number of drying days 300 d year�1 Approximately 6 days per week, minus holidays
Drying schedule 20 h d�1 2 1/2 eight hour shifts
Dryer operators 0.4 employees
dryer�1
Employees operate loaders and maintain the dryers
Number of loaders 0.2 loaders dryer�1 GSNet.com [54] 3.86–4.63 m3 capacity per loader. Loaders carry biomass
from dryer to transport vehicles. Capital cost of each loader
is about $200,000.
Characteristic particle
size of manure
2.18 mm Houkum et al. [55],
Carlin [22]
Characteristic size for Rosin-Rammler distribution of low
moisture beef cattle biomass particles
Biomass application
thickness at conveyor
belt entrance
30 mm Carlin [22]
Temperature of biomass
entering the dryer
25 �C Carlin [22] Same as ambient air temperature, see next item
Ambient air
temperature
25 �C Carlin [22] Annual average day time temperature for central Texas
Ambient relative
humidity
50% Carlin [22] Annual average day time relative humidity for central Texas
Temperature of air
exiting the dryer
107 �C Rodriguez et al.
[56], Carlin [22]
Can be, at most, 300 �C before rapid devolatilization occurs.
Moreover, at drying temperatures over 100 �C, drying times
should also be limited to less than five minutes to preserve
the biomass’s heating value.
Relative humidity of air
exiting the dryer
20% Carlin [22]
Air temperature
difference in dryer
30 �C Kiranoudis et al.
[38], Carlin [22]
Difference between temperature of air entering and exiting
the drying chamber. Generally determined by the air flow
through the dryer.
Boiler pressure 345 kPa (gage) Carlin [22] Capital cost of each boiler is approximately $28.6 (kg h�1)�1
of steam production
Boiler efficiency 85% Carlin [22]
Labor cost for dryer
operators
$15 h�1 The price of labor is assumed to escalate annually by
1.5% [50]
Cost of electricity $0.09 kWh�1 EIA [49] Average retail price for 2006 commercial consumers.
Electricity price is assumed to escalate at 3.71%
annually [50].
Natural gas price $7.36 GJ�1 EIA [49] Average 2006 price for electricity producers. Natural gas
prices are assumed to escalate by 5% annually.
Land requirement 4 hectares per
drying site
Note: 1 hectare¼ 10,000 m2. It was estimated that one
drying site of this size could house 5 dryers
Land cost $12,350 hectare�1 This cost may also include general overhead costs such as
small office buildings and parking lots at the drying sites.
Extra storage structures Four 30.6 m3
storage trailers
122.3 m3 of total extra biomass storage (about 2 days extra
capacity) in case of inclement weather.
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Table 6 – Base case input parameters for cattle biomass transportation from animal feeding operations to coal-fired powerplant (all dollars are in 2007 dollars).
Input Value (unit) Source Notes
Loading & unloading times 25 min each USEPA [40]
Average distance between
plant and animal feeding
operations
160 km This distance should be an average distance
weighted by the amount of biomass from each
animal feeding operation contributing to the power
plant’s fueling
Number of hauling days 300 d year�1 Approximately 6 days per week, minus holidays
Hauling schedule 16 h d�1 2 eight hour shifts
Truck capacity 30 m3 GSNet.com [54] 30 m3 trailers cost roughly $40,000 each, and the
truck tractors hauling the trailers cost approximately
$150,000 each.
Truck maintenance $0.40 km�1 USEPA [40]
Labor cost for biomass
haulers
$15 h�1 The price of labor is assumed to escalate annually by
1.5% [50]
Diesel fuel price $0.79 liter�1 The price of diesel fuel was assumed to escalate by
5% annually.
Average truck speed 80.5 km h�1 Krishnan [57] Fuel economy for the hauling vehicles was assumed
to be 3.4 km liter�1
Rated truck horse power 373 kW Krishnan [57]
Truck load factor 70% Krishnan [57]
Truck SCR cost $3,623 year�1 Krishnan [57] Includes O&M and annualized capital costs. SCR can
meet 74.5 g GJ�1 NOx levels; 2007 standards
Table 7 – Base case input parameters for overall economic analysis of reburn operation.
Input Value (unit) Source Notes
Book life 30 years USEPA [41] Balance sheet for corporate financing
structure for environmental retrofits
Real (non-inflated)
discount rate
5.30% USEPA [41] Balance sheet for corporate financing
structure for environmental retrofits
Inflation rate 4.00%
Capital charge rate 12.10% USEPA [41] Balance sheet for corporate financing
structure for environmental retrofits
Tax rate 34.00% Pratt [58] Omnibus Reconciliation Act of 1993:
Marginal tax rate for taxable incomes
between $335,000 and $10,000,000
Table 8 – Comparison of base case Year 1 costs of selected NOx control technology arrangements (500 MWe plant capacity,10% biomass by heat, all values are in Year 1 (2007) dollars).
Year 1 Costs Primarycontrol only
Primary controlþcattle biomass
reburn
Primarycontrolþ
SCR
Primarycontrolþ
SCR
Fixed O&M cost (74,920) (863,383) (412,239) (143,747)
Variable O&M costa (3,867) (9,835,158) (2,397,057) (3,439,747)
Biomass delivery cost 0 (5,958,876) 0 0
Coal delivery cost (73,130,746) (65,817,672) (73,130,746) (73,130,746)
NOx creditsb 0 6,457,235 6,472,716 2,861,506
CO2 penalty 0 0 0 0
SOx penalty (523,583) (588,155) (523,583) (523,583)
Ash revenue 614,507 614,250 614,507 614,507
Ash disposal cost (2,949,636) (3,966,794) (2,949,636) (2,949,636)
Annualized capital cost (582,491) (5,172,908) (6,912,518) (1,160,876)
Total cost (w/o capital) (76,068,245) (79,958,552) (72,326,038) (76,711,447)
a For CB reburning, VO&M includes the cost of drying the biomass.
b NOx credits are assumed to be earned for all reductions beyond those obtained from primary controls.
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Yet economically, the CB reburn system was found to have
a NPC (negative NPW) of $80.8 million. The base case Year 1
cost components of the four possible operating conditions are
juxtaposed in Table 8. The major increase in overall cost for CB
reburn systems came from the VO&M increase, largely due to
natural gas required for biomass drying operations. The CB
reburn option was the most expensive at Year 1 under base
case assumptions. Moreover, expected escalations of diesel
and natural gas prices under the base case assumptions were
found to overtake any escalation of avoided NOx and coal
prices, thus making the operating summation in equation (1)
negative throughout the life of the reburn project, allowing for
no net savings at any time.
Comparatively, SCR was found to have an NPV (positive
NPW) of $3.87 million. However, SCR was also found to have
the highest capital cost. SNCR was found to have the cheapest
capital investment cost, but the emission levels achieved by
SNCR were assumed to be poorer than levels achieved by
either CB reburning or SCR.
The final step in this economic analysis was to vary some
of the base case input parameters and study the sensitivity of
the NPW and the annualized cost. This analysis will be dis-
cussed presently.
4.2. Biomass and coal fueling
The higher O&M costs for CB reburning were partly attributed
to the relative expense of importing low-calorific value
biomass to meet a set percentage of the plant’s heat rate (for
the base case, 10%). Since the ammonia, urea, or other
0
5
10
15
20
25
30
35
5 10 15 20 25 30percentage of plant's heat rate supplied by reburn fuel
Dry
in
g a
nd
T
ra
ns
po
rt O
&M
C
os
t
(m
illio
n $
y
ea
r-1)
(45)
(40)
(35)
(30)
(25)
(20)
(15)
(10)
(5)
0
An
nu
alized
C
ost o
r R
even
ue o
f R
eb
urn
System
(m
illio
n $ year-1)
CB Drying O&M CB Transport O&M Annualized Cost
Fig. 7 – Overall annualized cost, CB drying O&M, and CB transport O&M vs. CB reburn fuel contribution to heat rate.
(20)
(15)
(10)
(5)
0
5
0 10 20 30 40 50 60 70 80 90 100year 1 coal price ($ tonne
-1)
An
nu
alize
d C
os
t o
r R
ev
en
ue
(m
illio
n $
y
ea
r-1)
(200)
(150)
(100)
(50)
0
50
30-Y
ear N
et P
resen
t W
orth
(m
illio
n $)
Coal price escalates 3.77% annually
Reburning coal withcattle biomass
SCR
Fig. 8 – Overall annualized cost and net present worth vs. the year 1 price of coal.
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reagents imported for competing technologies, such as SCR
and SNCR, typically does not add to the fueling of the plant,
O&M costs can stay relatively low for the same targeted NOx
level. If CB reburn systems are ever to be installed in coal
plants, operators must find the perfect balance between
lowering biomass contribution to the heat rate, saving on coal,
and still maintaining targeted NOx levels. In Fig. 7, the rise in
CB drying and transport O&M can be seen as more of the
plant’s heat rate is supplied by the CB reburn fuel. The
annualized cost, and hence the NPW, of CB reburning steadily
becomes more negative with CB reburn contribution.
Cattle biomass displaces some of the coal that must be
purchased by the plant. For this reason, the profitability of
a CB reburn system is extremely sensitive to the price of the
displaced coal (Fig. 8). If the coal is inexpensive, then there is
little economic return on its displacement.
4.3. NOx, ash, and CO2 emissions
The overall annualized cost of a CB reburn system was also
found to be sensitive to the dollar amount placed on emis-
sions. For example, in Fig. 9, the NPW increased steeply with
higher starting values of NOx credits. However SCR, the
competing technology, was found to be profitable at much
lower NOx values.
The major advantage of reburning with CB over SCR is the
possibility of saving on avoided CO2 emissions. Fig. 10 is a plot
of NPW and annualized cost against possible Year 1 dollar
values of CO2. A CO2 tax, cap and trade value, or avoided
sequestration cost of $25 tonne�1 of CO2 would make CB
reburning as economically feasible as SCR.
However, the amount of ash in CB may limit the fueling
rate of CB and thus the possible CO2 savings. The ash
(20)
(15)
(10)
(5)
0
5
10
15
0 1000 2000 3000 4000 5000 6000 7000 8000 9000
year 1 NOx value, beyond primary control reductions ($ tonne
-1)
An
nu
alize
d C
os
t o
r R
ev
en
ue
(m
illio
n $
y
ea
r-1)
NOx value escalates 4.5% annually
Reburning coalwith cattlebiomass
SCR
Fig. 9 – Overall annualized cost vs. the year 1 NOx value.
(10)
(8)
(6)
(4)
(2)
0
2
4
6
8
10
12
0 10 20 30 40 50 60CO
2 tax or avoided carbon sequestration cost ($ tonne
-1 CO
2)
An
nu
alized
C
ost o
r R
even
ue (m
illio
n $ year-1)
(100)
(80)
(60)
(40)
(20)
0
20
40
60
80
100
120
30
-Y
ea
r N
et P
re
se
nt W
orth
(m
illio
n $
)
SCR
Reburning withcattle biomass
CO2 value escalates 5.25% annually
Reburningprofitable
compared to SCR
Fig. 10 – Overall annualized cost and net present worth vs. year 1 dollar value of CO2.
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produced by CB, even low-ash CB, may be challenging from an
economic perspective and an O&M perspective. Fig. 11 is
a graph of the ash emissions from both coal and CB reburn
fuel. Supplying 10% of the heat rate through reburning was
found to increase ash production from 11.64 tonne h�1 (with
coal only) to 16.24 tonne h�1. This is troubling, given that
Megel et al. [59,60] reported that manure ash was not suitable
as a cement replacement on its own. However, manure ash
may be utilized in other ways, such as a suitable sub-grade
material for road construction, and if mixed with 10% Portland
cement, can be used as a light weight concrete material with
about one-third of the compressive strength of concrete. Also,
chemical analyses show that manure ash is a non-hazardous,
possibly reactive industrial waste which could be used for
feedlot surfacing, road base, and some structural building
projects. If ash is not sold, then it must be disposed, typically
in local landfills, which require tipping fees.
4.4. Biomass drying and transporting
An important logistical parameter was found to be the average
distance between the plant and the animal feeding opera-
tion(s) that supply the CB reburn fuel. The power plant should
be near a geographical area of high agricultural biomass
density. Goodrich et al. [61] studied manure production rates
and precise rural transportation routes between coal plants
and feeding operations in Texas. The importance of logistics
can be seen further in Figs. 12 and 13. These figures depict the
reburner O&M, the transportation O&M, the drying O&M, and
the respective capital costs vs. the distance to the feeding
operations. Once again, the cost of drying CB was found to be
the dominant O&M cost. However, if the average distance
between the plant and the feeding operations that supply it
were to be over 160 km, then transportation costs become
significant. Moreover, it was found that with longer transport
0
5
10
15
20
25
0 5 10 15 20 25 30percentage of plant's heat rate supplied by reburn fuel
As
h E
mis
sio
n (to
nn
e h
-1)
WYPRB coal Low-ash dairy biomass
Fig. 11 – Plant ash emissions from coal and CB vs. CB reburn fuel contribution to heat rate.
0
10
20
30
40
50
60
70
80
90
100
0 16 80 161 241 322average distance between plant and animal feeding operations (km)
Pe
rc
en
ta
ge
o
f C
attle
B
io
ma
ss
R
eb
urn
O&
M C
os
t (%
)
Reburner O&M Transportation Cost Drying O&M
Fig. 12 – CB reburn O&M cost components vs. distance between plant and animal feeding operations.
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distances, the number of possible round trips to and from the
feeding operations that hauling vehicles must make per day
decreases. Hence, more trucks would need to be purchased for
longer distances to adequately supply the reburner.
Fig. 14 is a plot of annualized cost against CB transport
distance. With such a plot, a maximum profitable distance for
the reburn retrofit can be determined. However, since CO2
allowances were assumed to be zero for the base case run, it
can be seen in the figure that, even for very short transport
distances, the annualized cost of reducing NOx by reburning
coal with CB was still more expensive than SCR. Yet even with
a dollar value on CO2, short transport distances would allow
some flexibility to some of the other base case input param-
eters such as coal prices and ash disposal costs. Moreover, it
may be possible to use the extra ash from CB burning to pave
more feed yards in nearby feedlots which would increase the
amount of low-ash feedlot biomass available for reburning
facilities and other combustion processes.
For the base case 500 MWe power plant, it was estimated
that 80,000 dairy cows would be required to supply the reburn
facility, if the reburn fuel supplied 10% of the overall heat rate,
and if each cow produced manure at a rate of 7.3 kg d�1 (dry
basis). The Bosque and Leon River Watersheds in Texas have
about 150,000 dairy cows in over 150 dairies. Therefore, one
500 MWe plant would require 53% of the cattle manure
produced by these farms. Hence, the availability of suitable,
low-ash CB, as well as the coordination between farmers,
centralized composting facilities, and plant operators easily
come into question when trying to apply this low heat value
biomass to large electric utility boilers.
To handle these issues, several methods such as storage
and reserve stockpiles of ready-to-fire CB can be kept near the
power plant. Reducing the reburn fuel’s heat rate contribution
would also have to be considered. Or, perhaps the initial base
case with a 500 MWe capacity plant should also be reconsid-
ered. A power plant with a 300 MWe capacity would require
0
10
20
30
40
50
60
70
80
90
100
0 16 80 161 241 322average distance between plant and animal feeding operations (km)
Pe
rc
en
ta
ge
o
f C
attle
B
io
ma
ss
R
eb
urn
Ca
pita
l C
os
t (%
)
Retrofitting the Reburner Purchasing Trucks Purchasing Dryers
Fig. 13 – CB reburn capital cost components vs. distance between plant and animal feeding operations.
(18)
(16)
(14)
(12)
(10)
(8)
(6)
(4)
(2)
0
2
0 50 100 150 200 250 300 350average distance between plant and animal feeding operations (km)
An
nu
alize
d C
os
t o
r R
ev
en
ue
(m
illio
n $
y
ea
r-1)
SCR
Reburning withcattle biomass
Fig. 14 – Overall annualized cost vs. distance between plant and animal feeding operations.
b i o m a s s a n d b i o e n e r g y 3 3 ( 2 0 0 9 ) 1 1 3 9 – 1 1 5 7 1153
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about 20 tonnes less per hour of CB. In Fig. 15 the number of
trucks and dryers are plotted against power plant capacity. A
500 MWe plant would require at least 22 two-tonne conveyor
belt dryers whereas a 300 MWe plant would only require 13
dryers. It may be more helpful to concentrate research and
development of animal biomass utilization on smaller, more
dispersed power facilities. From a feasibility stand point,
power plants with 50–100 MWe capacities would seem to be
the best candidates for CB reburning systems.
5. Conclusions and policy suggestions
� Assuming base case parameters, a cattle biomass (CB)
reburn system retrofitted on an existing 500 MWe coal plant
(10,290 kJth kWhe�1 and 80% capacity factor) was found to
have a net present worth of �$80.8 million. Comparatively,
a selective catalytic reduction (SCR) system under the same
base case input parameters was found to have a net present
worth ofþ$3.87 million. The greatest increase in overall cost
for the CB reburn system was found to come from the
variable operation and maintenance cost increase, largely
due to biomass drying operations.
� The profitability of a CB reburning system retrofit on an
existing coal-fired power plant can improve with higher coal
prices, higher dollar values on NOx emission credits, and
higher reduction efficiencies from reburning. Finding suit-
able markets for selling the higher rates of ash produced
from biomass combustion are also critical.
� A CO2 value of $25 tonne�1 would make CB reburning as
economically feasible as SCR.
� As of the publication of this paper, 27 coal-fired power
plants are under construction in the US. Forty-four others
are in the early stages of development [62]. Instead of con-
structing extremely large power plants dependant on
nonrenewable (although readily available) fossil fuels, steps
ought to be made to construct a greater number of smaller
plants. These new plants can be strategically placed near
areas with higher concentrations of agricultural biomass to
promote reburning and co-firing coal with carbon neutral
feedstock. Infrastructure such as this would curb NOx and
CO2 emissions, boost rural economies, minimize the envi-
ronmental load from large concentrated animal feeding
operations, and develop stronger business ties between the
agriculture and energy sectors of the US.
6. Further considerations and future work
� Mercury emissions may also affect the economics of CB
reburn facilities. For future development of co-combustion
systems, these emissions should be account for as well.
� Future work should also include extending the economic
models developed here to co-firing, thermal gasification,
and smaller on-the-farm combustion systems.
� Moreover, the discussion in this paper has concentrated on
the economic benefits to the power plant facility, yet there
are numerous benefits to farmers and others in the agri-
cultural sector. Removing large quantities of manure from
concentrated animal feeding operations decreases the
possibility of phosphorus overloading and subsequent soil
and water pollution by reducing the required capacity of
manure storage structures such as anaerobic lagoons.
� Future work should also include investigations into the
regional benefits such as job creation and rural economic
development related to cattle biomass combustion.
Acknowledgments
The present work was supported with grants from the DOE-
National Renewable Energy Laboratory, Grant #DE-FG36-
05GO85003 and the Texas Commission on Environmental
Quality (TCEQ), Grant #582-5-65591 0015.
0
5
10
15
20
25
5 25 50 75 100 200 300 400 500plant capacity (MW
e)
Nu
mb
ers o
f T
ru
cks an
d D
ryers
0
5
10
15
20
25
30
35
Cattle B
io
mass R
eb
urn
F
uelin
g, as
fired
(to
nn
e h
-1)
#trucks #dryers CB reburn fueling
Fig. 15 – Numbers of trucks and dryers vs. plant capacity and CB fueling rate (10% heat rate supplied by CB reburn fuel).
b i o m a s s a n d b i o e n e r g y 3 3 ( 2 0 0 9 ) 1 1 3 9 – 1 1 5 71154
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Nicholas T. Carlin is a PhD student at Texas A&M University at
College Station, Texas. He earned his BS degree in Mechanical
Engineering from The University of Texas at Austin in August
2003 and his MS degree in Mechanical Engineering from Texas
A&M University at College Station, Texas in December 2005.
He has authored or co-authored five journal articles and
conference papers on co-combustion and thermal gasification
of cattle biomass with coal, as well as cattle biomass
combustion in small, on-the-farm systems for heat genera-
tion and waste disposal.
Dr. Kalyan Annamalai is the Paul Pepper Professor of
Mechanical Engineering at Texas A&M University at College
Station. He earned his BS degree from The University of
Madras (Anna University), India in 1966. He then obtained his
MS from the Indian Institute of Science in 1968. He earned his
PhD from Georgia Tech in 1975. He has authored more than
200 articles, two books on ‘‘Advanced Thermodynamics’’ (CRC
Press, 2002) and ‘‘Combustion Science and Engineering’’
(Taylor and Francis, 2006), and a recent article for the Ency-
clopedia of Energy Engineering and Technology (2007 Taylor
and Francis). He serves on the editorial board of the Journal of
Green Energy and as Associate Editor for the ASME Journal of
Gas Turbines and Power.
Dr. Wyatte Harman is a Professor of Agricultural Economics at
the Blackland Research and Extension Center, Texas A&M
University, at Temple, Texas. He earned his BS from Texas
Technological University in 1961, his MS from Texas A&M
University in 1966 and his PhD from Oklahoma State Univer-
sity in 1974. His recent research has emphasized the economic
feasibility of new and innovative cropping systems involving
alternative tillage systems and best management practices.
b i o m a s s a n d b i o e n e r g y 3 3 ( 2 0 0 9 ) 1 1 3 9 – 1 1 5 71156
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He has recently published nine journal articles and technical
papers in the agricultural and environmental sciences areas.
Dr. John M. Sweeten has served as Resident Director of the
Texas AgriLife Research and Extension Center at Amarillo
since 1996. He earned his BS from Texas Tech University
in 1967. He then received his MS and PhD in Agricultural
Engineering from Oklahoma State University in 1969. Dr.
Sweeten has authored or co-authored more than 500
publications and papers and technical reports on livestock
and poultry manure management, including use as
biomass fuel, air and water quality management.
b i o m a s s a n d b i o e n e r g y 3 3 ( 2 0 0 9 ) 1 1 3 9 – 1 1 5 7 1157