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biomass and bioenergy 33 (2009) 1139–1157

Available at www.sciencedirect.com

http://www.elsevier.com/locate/biombioe

The economics of reburning with cattle manure-based
biomass in existing coal-fired power plants for NOx
and CO2 emissions control

Nicholas T. Carlina, Kalyan Annamalaia,*, Wyatte L. Harmanb, John M. Sweetenc
a
Department of Mechanical Engineering, Texas A&M University, College Station, TX, USA
b
Blackland Research and Extension Center, Texas A&M University System, Temple, TX, USA
c
Texas AgriLife Research and Extension Center, Texas A&M University System, Amarillo, TX, USA

article info abstract

Article history: Coal plants that reburn with catttle biomass (CB) can reduce CO2 emissions and save on
Received 30 January 2008 coal purchasing costs while reducing NOx emissions by 60–90% beyond levels achieved by
Received in revised form primary NOx controllers. Reductions from reburning coal with CB are comparable to those
20 April 2009 obtained by other secondary NOx technologies such as selective catalytic reduction (SCR).
Accepted 29 April 2009 The objective of this study is to model potential emission and economic savings from
Published online 5 June 2009 reburning coal with CB and compare those savings against competing technologies. A
spreadsheet computer program was developed to model capital, operation, and mainte-
Keywords: nance costs for CB reburning, SCR, and selective non-catalytic reduction (SNCR). A base
Engineering Economics case run of the economics model, showed that a CB reburn system retrofitted on an
Reburn existing 500 MWe coal plant would have a net present worth of À$80.8 million. Compara-
Coal tively, an SCR system under the same base case input parameters would have a net present
Cattle biomass worth of þ$3.87 million. The greatest increase in overall cost for CB reburning was found to
Manure come from biomass drying and processing operations. The profitability of a CB reburning
Sensitivity analysis system retrofit on an existing coal-fired plant improved with higher coal prices and higher
valued NOx emission credits. Future CO2 taxes of $25 tonneÀ1 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 form of ammonia (NH3). Experiments conducted by Sweeten
et al. [1], Annamalai et al. [2], Arumugam [3], and Lawrence
Cattle biomass (cattle manure) has been proposed for use as et al. [4] demonstrated that co-firing feedlot biomass (FB) and
a reburn fuel for nitrogen oxide (NOx) emission reduction in coal (blending 10% FB and 90% coal) could reduce NOx emis-
coal-fired power plants and utility boilers. Cattle biomass (CB) sions from 290 ppm to 260 ppm. Numerical studies by Sami [5]
has shown promise in reducing NOx due to its high volatile were also conducted for co-firing coal and biomass in low-NOx
content, rapid release of volatile matter during combustion, swirl burners. Recent experiments and numerical models,
and rapid release of fuel bound nitrogen predominantly in the 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: kannamalai@tamu.edu (K. Annamalai).
0961-9534/$ – see front matter ª 2009 Elsevier Ltd. All rights reserved.
doi:10.1016/j.biombioe.2009.04.007


1140 biomass and bioenergy 33 (2009) 1139–1157

Laboratory, have shown that reburning with CB can reduce The three largest beef cattle states in the US are Texas,
NOx emissions up to 90% [6–10]. Kansas and Nebraska, respectively [14]. Feedlot cattle can
If these results can translate into similar NOx reductions produce 5–6% of their body weight in manure each day; a dry
for larger burners and utility boilers, CB reburning can be mass roughly 5.5 kg per animal per day [15]. Thus, on a dry
considered a competitive technology to other, more common basis, nearly 20 Tg of cattle manure per year comes from large
secondary NOx control retrofits such as selective catalytic feedlot CAFOs. Texas alone produces over 27% of this annual
reduction (SCR) and perhaps superior to natural gas reburning total. Similarly, areas such as the Bosque River Watershed
and selective non-catalytic reduction (SNCR) as far as NOx near Waco, Texas and many parts of California contain
reduction efficiency. dozens of large dairy operations, each with over 500 milking
The purpose of this study was to predict and gage the cows. Full-grown milking cows can produce 7–8% of their body
economic viability of reburning coal with CB at existing coal weight in manure per day; roughly a dry mass of 7.3 kg per
plants against several major parameters such as dollar values animal per day [16]. A dry mass of about 24 Tg of dairy manure
of avoided emissions, biomass processing costs, and trans- is produced per year in the US. The term ‘‘cattle biomass (CB)’’
portation costs. This study was conducted by generating will refer to both feedlot and dairy manure in general. Manure
a mathematical model from engineering and economic anal- from feedlots will be termed feedlot biomass (FB) and manure
yses of the drying, transportation, and combustion systems from dairies will be termed dairy biomass (DB).
involved in the overall process of utilizing CB as a reburn fuel The usefulness of CB as a fuel for combustion and emission
in existing coal plants. The methodology and justification of control systems can be determined from ultimate and heat
the model will be covered later in this article, but first some value analyses of each biomass fuel. These analyses are
discussion of CB and reburning processes is necessary. summarized in Table 1 for DB (both low ash, LA, and high ash,
HA), FB (both LA and HA), and coal (Wyoming Powder River
1.1. Cattle biomass from large feeding operations Basin sub-bituminous, WYPRB, and Texas Lignite, TXL).
Low-ash biomass from cement-paved lots and feed yards
American agriculture, particularly animal farming, has has a comparable amount of ash to TXL, which suggests that
become a highly industrialized business over the past 50 boilers setup to burn lignite could probably handle burning LA
years. The larger and more productive of these animal farms DB or LA FB. However, high ash fuels with contents up to 68%
are commonly referred to as concentrated animal feeding (on a dry basis) are certainly not suitable for most combustion
operations (CAFOs) or ‘‘super farms’’. Housing dairy cows, systems. Please refer to contributions from Oh et al. [19] for
beef cattle, and other traditional farm animals and also further discussion of ash fouling in CB boilers. Thus, the
disposing of the large amounts of manure produced from present paper will concentrate on LA CB; however, it should be
them are significant undertakings [11]. These feeding opera- noted that the vast majority of FB scraped from feed yards
tions show the potential for water and air pollution due to the contains high amounts of ash because nearly all lots are
manure production, yet the concentration and constant currently unpaved. On the other hand, free stall dairies with
generation of the manure at discreet geographic areas, may automated flushing systems are becoming quite prevalent,
make this low-calorific value feedstock a viable source of fuel especially for larger dairies. Many of these dairies use com-
for combustion and emission control systems for plants near posted solids as bedding to reduce sludge build-up in storage
CAFOs. See Fig. 1. Yet simply finding power plants near animal structures and lagoons [20]. The mechanically (screen) sepa-
feeding operations that can also benefit from reburning rated solids from flushing systems are typically of the low ash
systems may be challenging. Thus, a study such as the one variety if sand is not used as bedding. For a full discussion on
described here is necessary before further implementation of fuel properties of cattle biomass please refer to papers by
CB reburning is undertaken. [1,17,21–24].

Fig. 1 – Matching coal-fired power plants and areas with high agricultural biomass densities, adapted from [12] and [13].


biomass and bioenergy 33 (2009) 1139–1157 1141

Table 1 – Ultimate and heat value analyses of selected CB and coal fuels (all percentages are on a mass basis).
Dry basis
a a a
LADB HADB LAFB 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 À 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 À 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].

1.2. Primary NOx control technologies reburning with coal. A CB reburn system can offer even
greater NOx reductions and also reduce CO2 emissions from
The primary NOx controls on coal-fired power plants typically fossil fuel sources. However, unless ash is removed from the
consist of either low-NOx burners (LNB), over fire air (OFA), or CB before hand, ash emissions will increase when supplying
a combination of both. These controls are widely used in coal- CB in the RZ because CB typically contains more ash than coal
fired plants throughout the United States. Low-NOx burners and most lignite [8,19,30].
delay the complete mixing of fuel and air as long as possible in
order to reduce oxygen in the primary flame zone, reduce 1.3.2. Selective catalytic and non-catalytic reduction
flame temperature, and reduce residence time at peak There are some more commercially available secondary NOx
temperatures. Basic principles of NOx reduction in coal-fired controllers. One of the most common and effective of these
burners were reviewed by Williams et al. [25]. Discussion of technologies is selective catalytic reduction (SCR). In these
the enhancements to these primary NOx controls such as reduction systems ammonia (NH3) or some other reagent is
multilevel OFA and rotating opposed fire air can also be found injected, in the presence of a catalyst, to reduce NOx. Selective
in papers by Srivastava et al. [26] and Li et al. [27].

Exhaust Gases
1.3. Secondary NOx control technologies • With acceptable NOx
emission as low as 26 g/GJ
1.3.1. Reburning • Lower CO2 emission
from nonrenewable sources
A 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 Over Fire Air
• Completes the combustion
combustion, or reburn zone (RZ), in which a fuel rich mixture Lower NOx emission
process
of reburn fuel and air react with the hot combustion gases to 60 to 90% reduction
Reburn Fuel Injection
produce emissions with a relatively low amount of NOx. The • Usually natural gas or coal, but
mechanism of reduction is a reverse prompt NOx reaction in could be cattle biomass,
• 10-20% of the plant heat rate
which hydro-carbon (HC) fragments form nitrogen
• Rich mixture, ER = 1.05 –1.2 High NOx
compounds, such as hydrogen cyanide (HCN) and NH3, which • Temperature: 1300-1500 K
emission
react with NOx to reduce it to harmless nitrogen (N2). Finally,
Primary Coal Injection
over fire air is injected into the boiler burner to complete the
• Along with primary
combustion process and reduce carbon monoxide (CO) combustion air
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 Fig. 2 – Reburning process in a coal-fired power plant.



catalytic reduction systems can provide reductions greater 2.2.1. Drying cattle biomass
than 90%, depending on the catalyst, the flue gas temperature, Cattle biomass reburn fuel must be supplied to a coal-fired
and the amount of NOx present in the combustion gases operation from neighboring animal feeding operations.
exiting the PZ [26,31,32]. Therefore, a distribution system may be envisioned where
Selective non-catalytic reduction (SNCR) is a similar post there are a number of small dryers (rated between dry matter
combustion technology to SCR, except that the NH3 or urea is of 0.5–2.0 tonne hÀ1) installed on each feeding operation, or
injected without the presence of a catalyst and at higher perhaps a centralized composting and drying facility within 5–
temperatures [26]. However, reductions for SNCR are rarely 30 km from the feeding operations. See Fig. 3. Brammer and
over 35% for large boilers with heat rates greater than Bridgwater [36] reviewed numerous designs of dryers that
3.16 TJth hÀ1 (about 315 MWe) due to mixing problems [31,33]. 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
2. Methods biomass gasifier-engine combined heat and power systems.
Kiranoudis et al. [38] presented a full mathematical model
A spreadsheet model for a single coal-fired unit utilizing CB simulating the operation and economics of similar conveyor
as a reburn fuel was developed to gage the economic belt (band) dryers used for food processing, including an
viability of retrofitting CB co-combustion systems in existing algorithm for computing the conveyor belt area. Fig. 4 is
coal-fired facilities. The methods, assumptions, and research a representation of the biomass dryer setup with some typical
involved in generating this model are discussed in this values for input parameters used during the present model. A
section. Once the model was completed, a reference or base capital cost function for dryers in terms of the conveyor belt
case run was completed. From this base case result, several area was also presented by [37]. The modeling equations for
major parameters were varied over a certain range to biomass band dryers utilized in the spreadsheet program were
demonstrate the sensitivity of the overall cost (or benefit) of largely adopted from these papers. Labor costs, fueling costs
reburning coal with CB. for heating dryer air, electricity cost for the dryer’s fans,
biomass loader costs, and the purchasing cost of land in which
2.1. Modeling plant operation the dryers would be built were also considered in the analysis.

To demonstrate the spreadsheet program’s capabilities, and 2.2.2. Transporting cattle biomass
for the sake of brevity, only one case of fueling setup for the The cost of transporting the dried CB to the power plant was
power plant was considered for the present article. For this also included in modeling studies. One of the most important
case, the primary fuel (PF) burned in the boiler’s primary burn parameters was the average distance between the animal
zone (PZ) was pure Wyoming sub-bituminous coal. Whereas feeding operation(s) and the power plant. This distance
the reburn fuel (RF) injected into the reburn zone (RZ) was determined the number of hauling vehicles (trucks) required
cattle biomass. Blends of these fuels in either the PZ or RZ are to move the biomass, as well as the number of round trips that
not discussed here; however, they too can be represented with those trucks took per year to consistently supply the reburn
the present model. system at the power plant. Alternatively, Ghafoori et al. [39]
Plant operating parameters such as the plant capacity, the discussed piping liquid manure (12% solids) to anaerobic
overall fueling rate, the capacity factor, the plant’s annual digester sites. However, this method of biomass trans-
operating hours, the higher heating values of the primary and portation may not be applicable to CB reburning, because it is
reburn fuels, and the percentage of the plant’s heat rate doubtful that the power plant facility would handle huge
supplied by the reburn fuel are usually known or design volumes of wastewater resulting from the solids extraction
variables. Other parameters such as the plant’s overall heat from the liquid manure.
rate, the mass fueling rates of the primary and reburn fuels, Therefore hauling transportation analysis was adopted
and the plant’s overall efficiency, can generally be computed largely from a USEPA [40] report on the economics of running
from these inputs. Thermo-physical properties of CB, such as CAFOs that transport solid manure to composting sites. Other
bulk density and specific heat, and modeling equations of parameters that were required for the transportation analysis
these properties were discussed by Bohnhoff et al. [34] and included: the biomass loading and unloading times, the
Chen [35]. These equations were also used throughout the average truck speed, the daily hauling schedule, the number
current model. of hauling days per year, and the volumetric capacity of each
truck.
2.2. Modeling biomass processing and transportation

The cost of processing and importing coal was a simple dollar 2.3. Modeling emissions from coal-fired power
per tonne (1.0 Mg) input value prescribed to the spreadsheet plants and their NOx control technologies
program. However, this was not the case for CB. The cost of
preparing the biomass for the reburning process needed to be Cattle biomass reburning systems may, at least, affect three
determined from known values of fueling rate, biomass types of emissions from coal-fired units: nitrogen oxides
moisture percentage, labor, distance between the plant and (NOx), carbon dioxide (CO2), and ash. Although the primary
feeding operation and other drying and transportation cost function of a reburn system is to reduce NOx emissions, cattle
parameters. biomass reburning is expected to also decrease CO2 from



Large feedlot or CAFO

Dairy

Dairy Dryer

5-30 km
(3-20 miles)

Centralized drying and
composting facility

80-320 km
Power Plant
(50-200 miles)

Fig. 3 – Modeled cattle biomass processing and transportation system, picture of conveyor belt dryer adopted from [36].

nonrenewable sources and increase ash production. The installed at the coal plant, was computed from expressions
extent to which these emissions are affected depends on the taken from the USEPA [41]. These equations took into account
chemical composition of the biomass, the amount of RF the coal’s rank and the boiler type (i.e. wall-fired, tangentially-
injected in the RZ relative to the coal firing rate, and the fired, etc.). Nitrogen oxide emission levels (g GJÀ1) obtained by
expected NOx reduction due to reburning. primary NOx controls were determined based on the coal’s
Some of the more important parameters in determining rank, the boiler type, and the type of LNB and/or over fire air
the emissions from biomass combustion were the percent- system installed at the plant. NOx emissions obtained by CB
ages of moisture, ash and each combustible element in the reburning, SCR, and SNCR were treated as input values. From
fuel. Hence, the ultimate and heat value analyses listed in these levels, total annual reductions (tonne NOx yearÀ1) as
Table 1 were used as input parameters for the model. well as reduction percentages were computed.
An uncontrolled NOx level, that is the level that would NOx emissions from hauling vehicles were also taken into
occur if there were no primary or secondary NOx controls account during modeling. The NOx emission from hauling

Entering Air
T = 137 °C

Cattle Biomass
saturated steam Cattle Biomass 20% moisture
60% moisture Drying T ≈ 107 °C
Boiler
Boiler chamber

Pressure = 345 kPa
(gage) Exiting Air
T = 107 °C
Ambient Air
T = 25 °C

Fig. 4 – Dryer setup for spreadsheet model, adapted from [38].



vehicles was computed, assuming typical load factors and been conducted for these systems, and few applications of gas
horse power ratings. Nonrenewable CO2 emissions from and coal reburning systems existed for comparison. Work by
hauling vehicles and biomass dryers were also included in the Zamansky et al. [43] suggested that reburn systems utilizing
model. Diesel fuel was modeled as C12H26. Natural gas and furniture wastes, willow wood, and walnut shell biomass have
electricity used to drive the boilers and fans, respectively, at similar capital costs to coal reburning systems. An earlier 1998
the drying facilities was also accounted for when determining USEPA [44] report for the Clean Air Act Amendment, which
overall carbon emissions from the reburn system. The CO2 was also sited by Biewald et al. [45], modeled both gas and coal
emitted from these two sources was computed and then reburn systems, although the coal reburn model was meant
added to the CO2 emitted by the coal fired at the power plant. only for cyclone boiler types. Gas reburning costs are generally
Finally, the amount of inert ash produced by the plant was lower than coal reburning costs. Cyclone boilers burn coarsely
expected to increase due to the generally higher ash content of crushed coal, but coal reburn systems typically require
CB, even LA CB, compared to most coals. Moreover, since ash pulverized or micronized coal to avoid unburned carbon
must either be sold for exterior usage, or disposed in landfills, emissions. Hence, purchasing pulverizing equipment is
the results from this analysis was used to compute overall generally required for cyclone boiler plants.
dollar savings or costs from ash production. Sulfur oxide (SOx) Some estimates of coal and biomass reburn capital costs
emissions were also accounted for; however, these emissions are presented in Table 2. Note that capital costs for reburning
will either increase or decrease during reburning depending in this table do not include the capital cost of dryers and
on the sulfur content of the biomass relative that of the coal. biomass hauling vehicles which will be needed for CB
reburning but not coal reburning. These costs, as was dis-
2.4. Modeling the economics of NOx control systems cussed earlier, were computed separately. As for the FO&M
cost equation, the model presented by the USEPA [44] was
The cost of installing an environmental retrofit on a coal-fired used for the spreadsheet model, with the exception of an
power plant can be broken up into three different components: additional scaling factor that accounted for the CB’s poorer
capital cost, fixed operation and maintenance costs (FO&M), and heat value and hence greater required fueling rate. To describe
variable operation and maintenance costs (VO&M). The capital the uniqueness of CB reburning to other reburning facilities,
cost is the initial investment of purchasing and installing all VO&M costs such as biomass drying, transporting, and ash
necessary equipment so that the system is fully functional. Fixed disposal were individually calculated.
operation and maintenance costs are generally incurred Annual monetary values pertaining to NOx, nonrenewable
whether the system is running or not. These costs typically CO2, and ash revenues were also computed during modeling.
include labor and overhead items such as fuel feeders, grinders, Values for NOx emission credits were taken from the SCAQMD
and air and fuel injectors, whereas, VO&M costs include [48]. During modeling it was assumed that that the plant
handling and delivery of raw materials and waste disposal [42]. would earn monetary returns on all NOx emission reductions
beyond primary NOx emission levels. Although coal-fired
2.4.1. Integrated planning model for common NOx controllers plants in the US are currently not required to reduce CO2
In 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
Table 2 – Coal and biomass reburn capital cost estimates
energy policy scenarios and governmental mandates con-
from various sources (all scaled to 2007 dollars).
cerning electric capacity expansion, electricity dispatch and
emission control strategies. The latest update of the IPM, as of Capital cost Source Notes
($ kWÀ1)
e
the writing of this paper, may be found on the USEPA [41]
website. Since a section of the IPM is concerned with evalu- 42.3 Zamansky Same cost for both coal and
ating the cost and emission impacts of environmental retro- et al. [43] biomass reburning. 300 MWe plant.
Furniture, willow wood, and
fits, it is possible to adopt these emission models to describe
walnut shell biomass.
the economics of common primary and secondary controls,
54.3 Zamansky Same cost for both coal and
and then compare them to results for CB reburning. et al. [43] biomass reburning. 300 MWe plant.
The NOx control technology options modeled by the EPA Advanced reburn process.
IPM are LNB (with and without over fire air), SCR, and SNCR. 91:2ð300Þ0:388
P USEPA [44] Coal reburning in cyclone boilers
Capital and FO&M costs are functions of power plant capacity, only. Where, P ¼ plant capacity in
while VO&M costs are functions of heat rate. Models pre- MWe
72.4 Smith [46] Coal reburning in cyclone boilers,
sented by Mussatti et al. [32,33] offer more detailed and
40% NOx reduction from an
comprehensive representations for SCR and SNCR cost
370 g GJÀ1 baseline emission
components, but require more inputs. 7.2–15.7 Smith [46] Pulverized coal configurations
using some existing equipment for
2.4.2. Cattle biomass reburn economics coal reburn fuel preparation
Reburn technologies were not included in the latest version of 104.9 and 68.4 Mining For 110 MWe and 605 MWe plants,
the IPM. Thus, the main challenge of this study was to esti- Engineering respectively. 50% NOx reduction on
[47] cyclone burners with pulverized
mate the cost performance of a CB reburning system even
coal for reburn fuel
when only experimental results and pilot scale tests have



emissions, the model was used to speculate how taxes, cap project life times (30 years in Fig. 5) drying equipment and
and trade-based CO2 allowances, or avoided sequestering trucks will require replacements throughout the life of the
costs may affect the profitability of a CB reburn system. project.
Before computing the NPW, depreciation of capital and
2.4.3. Overall operation economics taxes on income must also be addressed. The depreciation
With all annual costs computed, each cost component of the method adopted for the present analysis was the modified
NOx control technologies were added to compute a total accelerated cost recovery system (MACRS).
operating cost of the system. The spreadsheet generated for The income after tax will be discounted by a factor:
the present study was used to compute emissions and annual
Discount factorn ¼ ð1 þ DRÞn (2)
costs for four different cases:
where DR is the discount rate. And the discounted income in
1. coal fired in a unit with primary NOx controls only, present dollars is simply:
2. coal fired in a unit with primary controls retrofitted with
Â Ã Income after taxn
a CB reburn system, Discounted Incomen $present ¼ (3)
Discount factorn
3. coal fired in a unit with primary controls retrofitted with an
SCR system, and Finally, the NPW can be computed with the following expression.
4. coal fired in a unit with primary controls retrofitted with an
SNCR system. Â Ã X30
NPW $present ¼ Discounted Incomen À Investmenttotal (4)
n¼1

An option to turn off primary NOx controls in order to
If the NPW is positive, then it is usually referred to as the net
evaluate applications where secondary controls existed but
present value (NPV), while negative NPWs are called net
not primary was also written into the program.
present costs (NPC).
One of the more common ways to indicate the economic
The NPW can be expressed as an annualized cost (or revenue)
bottom line of a project is to compute a net present worth
leveled throughout the life of the project. For this case,
(NPW) that is the equivalent combined value of all cash flows
! " #
throughout the life of the project in present dollars. The first $ DRð1 þ DRÞ30
step in computing the NPW is to compute an operating income Annualized Cost or Revenue ¼ NPW Â
yr ð1 þ DRÞ30 À1
(or cost, if negative) for each year, n. This summation is shown
(5)
in the following expression.
From here, the leveled annual cost can be expressed with
Operating Incomen ¼ ÀO&Mtotal-drying;n À O&Mtotal-truck;n other parameters specific to the reburn model. For example,
À FO&Mcofire;n þ Coal Savingsn the specific NOx reduction cost can be computed as:
þ CO2 Savingsn Æ SO2 Costn !
$
À Ash Disposaln þ Ash Salen Specifc NOx Reduction
tonne NOx
þ MBB Costn þ NOx Savingsn (1) Annualized Cost
¼ (6)
ðRreburn À emissiontruck;NOx Þ
Depending on the size of the benefits versus the costs, the
operating income can be positive (revenue) or negative (cost). where Rreburn is the annual reduction of NOx from reburning
These cash flows are illustrated in Fig. 5. The total investment coal with biomass.
of the reburn project will include the additional plant equip- More information about computing depreciations, taxes,
ment, the dryers, and the hauling vehicles. Note that for long and NPWs can be found in the textbook by Newnan et al. [42].

Annual Cash Flows Capital Costs
Avoided CO2and NOxemission allowances New plant equipment and retrofit
Coal savings Dryer facility and equipment
Diesel, natural gas, propane fueling costs Transport vehicles
Labor & Maintenance
Cash Flows (Dollars)

5 10
10 15
15 20
20 25
25 30
30
Project
time (yrs)

Fig. 5 – Capital and annual cash flows encountered for cattle biomass reburn operation and retrofit project.



Fig. 6 – Overall flow diagram of economics spreadsheet computer model.

All modeling equations for the present study are also pre- ‘‘Notes’’ column in the tables. However, these base case inputs
sented in greater detail in a dissertation by Carlin [22]. The are not set. These numbers can and should be changed to
flow diagram in Fig. 6 summarizes the computations con- accommodate different situations and facilities. In fact, vari-
ducted with the spreadsheet model. 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.
3. Base case parameters and data input

Base case input parameters for a theoretical 500-MWe coal- 4. Results and discussion
fired power plant were chosen from research and literature
review. This set of inputs acted as a reference point for para- 4.1. Base case results
metric study and sensitivity analysis. Tables 3–7 are lists of all
base case input parameters pertinent to modeling the opera- From the base case inputs, a resulting reference run was
tion of the NOx control technologies as well as the processing completed. The heat energy released by the CB in the reburn
and transportation of CB for reburning. All of the dollar inputs zone of the boiler burner was found to be 2.38 PJ yearÀ1 more
were scaled to 2007 dollars and represented Year 1 of the than the energy needed to dry and transport it to the plant.
reburn retrofit project. Price escalation factors for some Total CO2 emissions for reburning, including carbon emis-
parameters were also accounted for and discussed in the sions from CB drying and transportation, were found to be



Table 3 – Base case input parameters for coal-fired plant operating conditions and emissions (all dollar amounts are in 2007
dollars).
Input Value (unit) Source Notes

Plant capacity 500 MWe
Heat rate 10,290 kJth kWhÀ1
e About 35% plant efficiency, average for most coal-fired power plants
Capacity factor 80%
Operating hoursa 8760 h yearÀ1 1 year ¼ 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 tonneÀ1 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 tonneÀ1 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 tonneÀ1 No current mandatory markets for CO2 in most of the United States
SOx credit/allowance $970 tonneÀ1 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 tonneÀ1 Robl [51] Range: $35.89–43.06 tonneÀ1. The sale price of ash and the disposal cost of ash
are both assumed to escalate by 1% annually.
Ash disposal cost $34.42 tonneÀ1 ACAA [52] Range: $22.05–44.09 tonneÀ1. Landfill tipping fees for non-hazardous waste.
Percentage of ash 20% Robl [51] For coal, 61% of solid byproduct is fly ash which can be sold for outside use.
soldb 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.

263,000 tonne yearÀ1 less than emissions for primary control standards with catalytic converter systems, the NOx emitted
operation only. The electricity used to run the dryer’s fans was by the vehicles only inhibited CB reburn NOx reductions by
assumed to come completely from coal combustion. Lastly, about 6.0 tonne yearÀ1, compared to a 2500 tonne yearÀ1
since the hauling vehicles were assumed to meet 2007 NOx reduction beyond primary control levels.

Table 4 – Base case input parameters for primary and secondary NOx control technologies (all dollar amounts are in 2007
dollars).

Primary NOx control Low-NOx coal and air nozzles See primary control NOx level
with closed-coupled OFA (next item)
Primary NOx control 94.8 g GJÀ1 Srivastava [26] About 45% average reduction
level efficiency for these primary
controls when burning sub-
bituminous coals
Reburn fuel LADB Sweeten et al. [17] See Table 1
Heat contribution from 10% Range: 5–20%
reburn fuel
Reburn NOx control level 25.9 g GJÀ1 Colmegna et al. [30], Oh et al.
[10], Annamalai et al. [7],
Annamalai et al. [53]
Reburn capital cost $42.25 kWÀ1
e Zamansky [43]
Reburn fixed O&M $1.39 kWÀ1 yearÀ1
e Biewald et al. [45],USEPA [44] Scaled for different plant capacities
and firing cattle biomass.
SCR NOx control level 25.9 g GJÀ1 USEPA [31] >90% reduction, but current
commercial systems are usually
limited to 25.9 g GJÀ1
SNCR NOx control level 64.6 g GJÀ1 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 GJÀ1 and
is applicable to plants with greater
than 100 MW capacities



Table 5 – Base case input parameters for cattle biomass drying (all dollar amounts are in 2007 dollars).

Biomass moisture 60% Carlin [23] Typical for partially composted separated dairy biomass
percentage before solids from flushing system
drying
Biomass moisture 20% Annamalai et al. Approximate moisture percentage of biomass during co-
percentage after [7], Annamalai firing and reburning experiments
drying et al. [53]
The biomass is dried – The biomass can possibly be dried at the power plant by
before it is using waste heat from the combustion processes at the
transported to the plant. However, this may increase the cost of transporting
power plant the biomass and it may not be allowable to have as received
manure biomass at the power plant.
Capacity of single 2 tonne dry basis Smaller scale dryer such as those discussed by Brammer
biomass dryer 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 0.5 m Brammer et al. [37]
chamber
Width of drying 0.5 m Brammer et al. [37]
chamber
Number of drying days 300 d yearÀ1 Approximately 6 days per week, minus holidays
Drying schedule 20 h dÀ1 2 1/2 eight hour shifts
Dryer operators 0.4 employees Employees operate loaders and maintain the dryers
dryerÀ1
Number of loaders 0.2 loaders dryerÀ1 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 2.18 mm Houkum et al. [55], Characteristic size for Rosin-Rammler distribution of low
size of manure Carlin [22] moisture beef cattle biomass particles
Biomass application 30 mm Carlin [22]
thickness at conveyor
belt entrance
Temperature of biomass 25 C Carlin [22] Same as ambient air temperature, see next item
entering the dryer
Ambient air 25 C Carlin [22] Annual average day time temperature for central Texas
temperature
Ambient relative 50% Carlin [22] Annual average day time relative humidity for central Texas
humidity
Temperature of air 107 C Rodriguez et al. Can be, at most, 300 C before rapid devolatilization occurs.
exiting the dryer [56], Carlin [22] 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 20% Carlin [22]
exiting the dryer
Air temperature 30 C Kiranoudis et al. Difference between temperature of air entering and exiting
difference in dryer [38], Carlin [22] 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 hÀ1)À1
of steam production
Boiler efficiency 85% Carlin [22]
Labor cost for dryer $15 hÀ1 The price of labor is assumed to escalate annually by
operators 1.5% [50]
Cost of electricity $0.09 kWhÀ1 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 GJÀ1 EIA [49] Average 2006 price for electricity producers. Natural gas
prices are assumed to escalate by 5% annually.
Land requirement 4 hectares per Note: 1 hectare ¼ 10,000 m2. It was estimated that one
drying site drying site of this size could house 5 dryers
Land cost $12,350 hectareÀ1 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 122.3 m3 of total extra biomass storage (about 2 days extra
storage trailers capacity) in case of inclement weather.



Table 6 – Base case input parameters for cattle biomass transportation from animal feeding operations to coal-fired power
plant (all dollars are in 2007 dollars).

Loading unloading times 25 min each USEPA [40]
Average distance between 160 km This distance should be an average distance
plant and animal feeding weighted by the amount of biomass from each
operations animal feeding operation contributing to the power
plant’s fueling
Number of hauling days 300 d yearÀ1 Approximately 6 days per week, minus holidays
Hauling schedule 16 h dÀ1 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 kmÀ1 USEPA [40]
Labor cost for biomass $15 hÀ1 The price of labor is assumed to escalate annually by
haulers 1.5% [50]
Diesel fuel price $0.79 literÀ1 The price of diesel fuel was assumed to escalate by
5% annually.
Average truck speed 80.5 km hÀ1 Krishnan [57] Fuel economy for the hauling vehicles was assumed
to be 3.4 km literÀ1
Rated truck horse power 373 kW Krishnan [57]
Truck load factor 70% Krishnan [57]
Truck SCR cost $3,623 yearÀ1 Krishnan [57] Includes OM and annualized capital costs. SCR can
meet 74.5 g GJÀ1 NOx levels; 2007 standards

Table 7 – Base case input parameters for overall economic analysis of reburn operation.

Book life 30 years USEPA [41] Balance sheet for corporate financing
structure for environmental retrofits
Real (non-inflated) 5.30% USEPA [41] Balance sheet for corporate financing
discount rate 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 Primary Primary control þ Primary Primary
control only cattle biomass control þ control þ
reburn SCR SCR

Fixed OM cost (74,920) (863,383) (412,239) (143,747)
Variable OM 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, VOM includes the cost of drying the biomass.
b NOx credits are assumed to be earned for all reductions beyond those obtained from primary controls.



CB Drying OM CB Transport OM Annualized Cost

35 0

Annualized Cost or Revenue of Reburn
Drying and Transport OM Cost
(5)
30

System (million $ year-1)
(10)
(million $ year-1)
25
(15)

20 (20)

15 (25)

(30)
10
(35)
5
(40)

0 (45)
5 10 15 20 25 30
percentage of plant's heat rate supplied by reburn fuel

Fig. 7 – Overall annualized cost, CB drying OM, and CB transport OM vs. CB reburn fuel contribution to heat rate.

Yet economically, the CB reburn system was found to have the highest capital cost. SNCR was found to have the cheapest
a NPC (negative NPW) of $80.8 million. The base case Year 1 capital investment cost, but the emission levels achieved by
cost components of the four possible operating conditions are SNCR were assumed to be poorer than levels achieved by
juxtaposed in Table 8. The major increase in overall cost for CB either CB reburning or SCR.
reburn systems came from the VOM increase, largely due to The ﬁnal step in this economic analysis was to vary some
natural gas required for biomass drying operations. The CB of the base case input parameters and study the sensitivity of
reburn option was the most expensive at Year 1 under base the NPW and the annualized cost. This analysis will be dis-
case assumptions. Moreover, expected escalations of diesel cussed presently.
and natural gas prices under the base case assumptions were
found to overtake any escalation of avoided NOx and coal 4.2. Biomass and coal fueling
prices, thus making the operating summation in equation (1)
negative throughout the life of the reburn project, allowing for The higher OM costs for CB reburning were partly attributed
no net savings at any time. to the relative expense of importing low-caloriﬁc value
Comparatively, SCR was found to have an NPV (positive biomass to meet a set percentage of the plant’s heat rate (for
NPW) of $3.87 million. However, SCR was also found to have the base case, 10%). Since the ammonia, urea, or other

5 50
Annualized Cost or Revenue (million $ year-1)

30-Year Net Present Worth (million $)

SCR
0 0

(5) (50)

(10) (100)

Reburning coal with
cattle biomass
(15) (150)

Coal price escalates 3.77% annually
(20) (200)
0 10 20 30 40 50 60 70 80 90 100
year 1 coal price ($ tonne-1)

Fig. 8 – Overall annualized cost and net present worth vs. the year 1 price of coal.



15

10 SCR

5

0

(5)

(10)
Reburning coal
with cattle
(15) biomass

NOx value escalates 4.5% annually
(20)
0 1000 2000 3000 4000 5000 6000 7000 8000 9000
year 1 NOx value, beyond primary control reductions ($ tonne-1)

Fig. 9 – Overall annualized cost vs. the year 1 NOx value.

reagents imported for competing technologies, such as SCR 4.3. NOx, ash, and CO2 emissions
and SNCR, typically does not add to the fueling of the plant,
OM costs can stay relatively low for the same targeted NOx The overall annualized cost of a CB reburn system was also
level. If CB reburn systems are ever to be installed in coal found to be sensitive to the dollar amount placed on emis-
plants, operators must find the perfect balance between sions. For example, in Fig. 9, the NPW increased steeply with
lowering biomass contribution to the heat rate, saving on coal, higher starting values of NOx credits. However SCR, the
and still maintaining targeted NOx levels. In Fig. 7, the rise in competing technology, was found to be profitable at much
CB drying and transport OM can be seen as more of the lower NOx values.
plant’s heat rate is supplied by the CB reburn fuel. The The major advantage of reburning with CB over SCR is the
annualized cost, and hence the NPW, of CB reburning steadily possibility of saving on avoided CO2 emissions. Fig. 10 is a plot
becomes more negative with CB reburn contribution. of NPW and annualized cost against possible Year 1 dollar
Cattle biomass displaces some of the coal that must be values of CO2. A CO2 tax, cap and trade value, or avoided
purchased by the plant. For this reason, the profitability of sequestration cost of $25 tonneÀ1 of CO2 would make CB
a CB reburn system is extremely sensitive to the price of the reburning as economically feasible as SCR.
displaced coal (Fig. 8). If the coal is inexpensive, then there is However, the amount of ash in CB may limit the fueling
little economic return on its displacement. rate of CB and thus the possible CO2 savings. The ash

12 120

10 100
30-Year Net Present Worth (million $)

Reburning with
8 80
cattle biomass
6 60

4 40

2 20
SCR
0 0

(2) Reburning (20)
profitable
(4) compared to SCR (40)

(6) (60)

(8) (80)
CO2 value escalates 5.25% annually
(10) (100)
0 10 20 30 40 50 60
CO2 tax or avoided carbon sequestration cost ($ tonne-1 CO2)

Fig. 10 – Overall annualized cost and net present worth vs. year 1 dollar value of CO2.



25
WYPRB coal Low-ash dairy biomass

20

Ash Emission (tonne h-1)
15

10

5

0
0 5 10 15 20 25 30
percentage of plant's heat rate supplied by reburn fuel

Fig. 11 – Plant ash emissions from coal and CB vs. CB reburn fuel contribution to heat rate.

produced by CB, even low-ash CB, may be challenging from an 4.4. Biomass drying and transporting
economic perspective and an OM perspective. Fig. 11 is
a graph of the ash emissions from both coal and CB reburn An important logistical parameter was found to be the average
fuel. Supplying 10% of the heat rate through reburning was distance between the plant and the animal feeding opera-
found to increase ash production from 11.64 tonne hÀ1 (with tion(s) that supply the CB reburn fuel. The power plant should
coal only) to 16.24 tonne hÀ1. This is troubling, given that be near a geographical area of high agricultural biomass
Megel et al. [59,60] reported that manure ash was not suitable density. Goodrich et al. [61] studied manure production rates
as a cement replacement on its own. However, manure ash and precise rural transportation routes between coal plants
may be utilized in other ways, such as a suitable sub-grade and feeding operations in Texas. The importance of logistics
material for road construction, and if mixed with 10% Portland can be seen further in Figs. 12 and 13. These figures depict the
cement, can be used as a light weight concrete material with reburner OM, the transportation OM, the drying OM, and
about one-third of the compressive strength of concrete. Also, the respective capital costs vs. the distance to the feeding
chemical analyses show that manure ash is a non-hazardous, operations. Once again, the cost of drying CB was found to be
possibly reactive industrial waste which could be used for the dominant OM cost. However, if the average distance
feedlot surfacing, road base, and some structural building between the plant and the feeding operations that supply it
projects. If ash is not sold, then it must be disposed, typically were to be over 160 km, then transportation costs become
in local landfills, which require tipping fees. significant. Moreover, it was found that with longer transport

Reburner OM Transportation Cost Drying OM
100
Percentage of Cattle Biomass Reburn

90

80

70
OM Cost (%)

60

50

40

30

20

10

0
0 16 80 161 241 322
average distance between plant and animal feeding operations (km)

Fig. 12 – CB reburn OM cost components vs. distance between plant and animal feeding operations.



Retrofitting the Reburner Purchasing Trucks Purchasing Dryers
100

Percentage of Cattle Biomass Reburn
90

80

Capital Cost (%) 70

60

50

40

30

20

10

0
0 16 80 161 241 322

Fig. 13 – CB reburn capital cost components vs. distance between plant and animal feeding operations.

distances, the number of possible round trips to and from the For the base case 500 MWe power plant, it was estimated
feeding operations that hauling vehicles must make per day that 80,000 dairy cows would be required to supply the reburn
decreases. Hence, more trucks would need to be purchased for facility, if the reburn fuel supplied 10% of the overall heat rate,
longer distances to adequately supply the reburner. and if each cow produced manure at a rate of 7.3 kg dÀ1 (dry
Fig. 14 is a plot of annualized cost against CB transport basis). The Bosque and Leon River Watersheds in Texas have
distance. With such a plot, a maximum profitable distance for about 150,000 dairy cows in over 150 dairies. Therefore, one
the reburn retrofit can be determined. However, since CO2 500 MWe plant would require 53% of the cattle manure
allowances were assumed to be zero for the base case run, it produced by these farms. Hence, the availability of suitable,
can be seen in the figure that, even for very short transport low-ash CB, as well as the coordination between farmers,
distances, the annualized cost of reducing NOx by reburning centralized composting facilities, and plant operators easily
coal with CB was still more expensive than SCR. Yet even with come into question when trying to apply this low heat value
a dollar value on CO2, short transport distances would allow biomass to large electric utility boilers.
some flexibility to some of the other base case input param- To handle these issues, several methods such as storage
eters such as coal prices and ash disposal costs. Moreover, it and reserve stockpiles of ready-to-fire CB can be kept near the
may be possible to use the extra ash from CB burning to pave power plant. Reducing the reburn fuel’s heat rate contribution
more feed yards in nearby feedlots which would increase the would also have to be considered. Or, perhaps the initial base
amount of low-ash feedlot biomass available for reburning case with a 500 MWe capacity plant should also be reconsid-
facilities and other combustion processes. ered. A power plant with a 300 MWe capacity would require

2

0
SCR
Annualized Cost or Revenue

(2)

(4)
(million $ year-1)

(6)
Reburning with
(8) cattle biomass

(10)

(12)

(14)

(16)

(18)
0 50 100 150 200 250 300 350

Fig. 14 – Overall annualized cost vs. distance between plant and animal feeding operations.

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