biomass & bioenergy article

This article appeared in a journal published by Elsevier. The attachedcopy is furnished to the author for internal non-commercial researchand education use, including for instruction at the authors institution

and sharing with colleagues.

Other uses, including reproduction and distribution, or selling orlicensing copies, or posting to personal, institutional or third party

websites are prohibited.

In most cases authors are permitted to post their version of thearticle (e.g. in Word or Tex form) to their personal website orinstitutional repository. Authors requiring further information

regarding Elsevier’s archiving and manuscript policies areencouraged to visit:

http://www.elsevier.com/copyright

http://www.elsevier.com/copyright

Author's personal copy

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

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


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].



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.

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 1141


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



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].



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



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.



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.



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).


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



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


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.



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


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.


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


Inflation rate 4.00%

Capital charge rate 12.10% USEPA [41] Balance sheet for corporate financing


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.



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.



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.



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.



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.



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).



r e f e r e n c e s

[1] Sweeten JM, Annamalai K, Thien B, McDonald LA. Co-firingof coal and cattle feedlot biomass (FB) fuels. Part I. Fuel 2003;82:1167–82.

[2] Annamalai KA, Thien B, Sweeten JM. Co-firing of coal andcattle feedlot biomass (FB) fuels. Part II. Fuel 2003;82:1183–93.

[3] Arumugam S, Annamalai K, Thien B, Sweeten JM. Feedlotbiomass co-firing: a renewable energy alternative for coal-fired utilities. International Journal of Green Energy 2005;2:409–19.

[4] Lawrence B, Annamalai K, Sweeten JM. Performance of smallscale boiler burner fired with blends of coal and dairybiomass. In: Paper #H02 topic: technology, 5th UScombustion meeting; March 25–28, 2007.

[5] Sami M. Numerical modeling of coal-feedlot biomass blendcombustion and NOx emissions in swirl burner. PhD thesis.College Station, Texas: Texas A&M University; 2000.

[6] Annamalai K, Thien B. Feedlot manure as reburn fuel for NOx

reduction in coal fired plants. In: National CombustionConference, Oakland, California; March 25–27, 2001.

[7] Annamalai K, Sweeten JM. Reburn system with feedlotbiomass. US Patent #6,973,883B1; 2005.

[8] Arumugam S. Nitrogen oxides emission control throughreburning with biomass in coal-fired power plants. MSthesis. College Station, Texas: Texas A&M University; 2004.

[9] Colmegna G. Modeling of the reburn process with the use ofbiomass as a reburn fuel. MS thesis. College Station, Texas:Texas A&M University; 2007.

[10] Oh H. Reburning renewable biomass for emissions controland ash deposition effects in power generation. Doctoraldissertation. College Station, Texas: Texas A&M University;2008.

[11] Centner TJ. Empty pastures: confined animals and thetransformation of the rural landscape. Urbana and Chicago,Illinois: University of Illinois Press; 2004.

[12] Virtus Energy Research Associates. Texas renewable energyresource assessment: survey, overview, andrecommendations. Report for the Texas Sustainable EnergyDevelopment Council; July 1995. <http://www.infinitepower.org/pdf/re_study1995.pdf> [accessed July 2006].

[13] Western Region Ash Group. Coal fired plants in the westernUSA, <http://www.wrashg.org/coalplant.htm>; 2006[accessed July 2006].

[14] NASS. Livestock slaughter 2006 summary. National AgriculturalStatistics Service of the US Department of Agriculture,<http://usda.mannlib.cornell.edu/usda/current/LiveSlauSu/LiveSlauSu-03-02-2007.pdf>; 2007 [accessed July 2007].

[15] DPI&F. Feedlot waste management series: manureproduction data. Australia: Department of PrimaryIndustries and Fisheries. Government of Queensland,<http://www.dpi.qld.gov.au/environment/5166.html>; 2003[accessed October 2005].

[16] Schmidt GH, Van Vleck LD, Hutjens MF. Dairy cattle housing.In: Principles of dairy science. 2nd ed. Englewood Cliffs, NewJersey: Prentice Hall; 1988. p. 428–44.

[17] Sweeten JM, Heflin K. Preliminary interpretation of data fromproximate, ultimate and ash analysis, results of June 7, 2006,samples taken from feedlot and dairy biomass biofuelfeedstocks at TAES/USDA-ARS, Bushland, TX. Amarillo/Bushland/Etter, TX: Texas A&M Agricultural Research &Extension Center; 2006.

[18] TAMU. TAMU fuel data bank. Texas A&M University Coaland Biomass Energy Laboratory, <http://www1.mengr.tamu.edu/REL/TAMU%20FDB.htm>; 2006 [accessed July 2007].

[19] Oh H, Annamalai K, Sweeten JM. Investigations of ashfouling with cattle wastes as reburn fuel in a small-scale

boiler burner under transient conditions. Journal of Air andWaste Management Association 2008;58:517–29.

[20] Mukhtar S, Ullman JL, Auvermann BW, Feagley SE,Carpenter TA. Impact of anaerobic lagoon management onsludge accumulation and nutrient content for dairies.Transactions of the ASAE 2004;47(1):251–7.

[21] Annamalai K, Priyadarsan S, Arumugam S, Sweeten JM.Energy conversion: principles of coal, animal waste, andbiomass fuels. Encyclopedia of Energy Engineering andTechnology 2007;1(1):476–97.

[22] Carlin NT. Optimum usage and economic feasibility ofanimal manure-based biomass in combustion systems.Doctoral dissertation. College Station, Texas: Texas A&MUniversity; 2009.

[23] Carlin NT. Thermo-chemical conversion of dairy wastebased biomass through direct firing. MS thesis. CollegeStation, Texas: Texas A&M University; 2005.

[24] Carlin NT, Annamalai K, Sweeten JM, Mukhtar S. Thermo-chemical conversion analysis on dairy manure-basedbiomass through direct combustion. International Journal ofGreen Energy 2007;4(2):133–59.

[25] Williams A, Pourkashanian M, Jones JM, Rowlands L. Areview of NOx formation and reduction mechanisms incombustion systems, with particular reference to coal.Journal of the Institute of Energy 1997;70:102–13.

[26] Srivastava RK, Hall RE, Khan S, Culligan K, Lani BW. Nitrogenoxides emissions control options for coal-fired electric utilityboilers. Journal of Air & Waste Management Association2005;55:1367–88.

[27] Li ZQ, Chen ZC, Sun R, Wu SH. New low NOx, low grade coalfired swirl stabilized technology. Journal of the EnergyInstitute 2007;80(3):123–30.

[28] Staudt JE. Technologies and cost effectiveness of post-combustion NOx controls. Andover Technology Partners. In:Prepared for NETL of the DOE, 1999 conference on SCR/SNCRfor NOx Control, <http://www.netl.doe.gov/publications/proceedings/99/99scr-sncr/staudt.pdf>; March 2005.

[29] Yang YB, Naja TA, Gibbs BM, Hampartsoumian E.Optimisation of operating parameters for NO reduction bycoal reburning in a 0.2 MWt furnace. Journal of the Instituteof Energy 1997;70:9–16.

[30] Colmegna G, Annamalai K, Udayasarathy AV. Modeling of Hgreduction during reburn process with the use of cattle biomassas a reburn fuel. In: Third International Green EnergyConference (IGEC-III), Vasteras, Sweden; June 17–21, 2007.

[31] USEPA. Standalone documentation for EPA base case 2004 (V.2.1.9) using the integrated planning model, chapter 5,emissions control technologies. Clean Air Markets Division.EPA Contract No. 430-R-05-011; September 2005. <http://www.epa.gov/airmarkets/progsregs/epa-ipm/past-modeling.html> [accessed April 2006].

[32] Mussatti DC, Srivastava R, Hemmer PM, Strait R. EPA airpollution control cost manual. 6th ed. Section 4, Chapter 2,Selective catalytic reduction; 2000. <http://www.epa.gov/ttn/catc/products.html> [accessed March 2005].

[33] Mussatti DC, Srivastava R, Hemmer PM, Strait R. EPA airpollution control cost manual. 6th ed. Section 4, Chapter 1,Selective non catalytic reduction; 2000. <http://www.epa.gov/ttn/catc/products.html> [accessed March 2005].

[34] Bohnhoff DR, Converse JC. Engineering properties ofseparated manure solids. Biological Wastes 1987;19:91–106.

[35] Chen YR. Thermal properties of beef cattle manure.Agricultural Wastes 1983;6:13–29.

[36] Brammer JG, Bridgwater AV. Drying technologies for anintegrated gasification bio-energy plant. Renewable andSustainable Energy Reviews 1999;3:243–89.

[37] Brammer JG, Bridgwater AV. The influence of feedstockdrying on the performance and economics of a biomass



gasifier-engine CHP system. Biomass & Bioenergy 2002;22:271–81.

[38] Kiranoudis CT, Maroulis ZB, Marinos-Kouris D. Modeling anddesign of conveyor belt dryers. Journal of Food Engineering1994;23:375–96.

[39] Ghafoori E, Flynn PC, Feebes JJ. Pipeline vs. truck transport ofbeef cattle manure. Biomass & Bioenergy 2007;31:168–75.

[40] USEPA. Cost methodology report for beef and dairy animalfeeding operations. EPA contract no. 821-R-01-019.Engineering and Analysis Division, <http://www.epa.gov/waterscience/guide/cafo/pdf/BDCostReport.pdf>; 2001[accessed April 2006].

[41] USEPA. Documentation for EPA base case 2006 (V.3.0) usingthe integrated planning model. EPA contract no. 430-R-05-011. Clean Air Markets Division, <http://www.epa.gov/airmarkets/progsregs/epa-ipm/>; November 2006 [accessedFebruary 2007].

[42] Newnan DG, Lavelle JP, Eschenbach TG. Engineeringeconomic analysis. 8th ed. Austin, Texas: Engineering Press;2000.

[43] Zamansky VM, Sheldon MS, Lissianski VV, Maly PM, MoyedaDK, Marquez A, et al. Advanced biomass reburning for highefficiency NOx control and biomass reburning – modeling/engineering studies. USDA Phase II SBIR, Contract #97-33610-4470 and DOE NETL, Contract # DE-FC26-97FT-97270;September 29, 2000. <http://www.osti.gov/bridge/servlets/purl/786516-Dddr9I/native/786516.pdf> [accessed January2005].

[44] USEPA. Analyzing electric power generation under theCAAA. Report from the Environmental Protection Agency ofthe US, Appendix No. 5; March 1998.

[45] Biewald B, Cavicchi J, Woolf T, Allen D. Use of selectivecatalytic reduction for control of NOx emissions from powerplants in the US. Prepared for the Ontario Campaign; 2000.

[46] Smith DJ. Coal reburning reduces NOx emissions. PowerEngineering August 2000:66–7.

[47] Mining Engineering. Clean coal technology project cuts NOx

emissions. Mining Engineering 2001;53(2):24–5.[48] SCAQMD. Annual RECLAIM audit report for 2005 compliance

year. South Coast Air Quality Management District; March 2,2007 board meeting. <http://www.aqmd.gov/hb/2007/March/070334a.html> [accessed July 2007].

[49] EIA. Annual energy outlook 2007 with projections to 2030.DOE/EIA-0383. Energy Information Administration of the USDepartment of Energy, http://www.eia.doe.gov/oiaf/aeo/;2007 [accessed November 2007].

[50] US Bureau of Labor Statistics. Producer price indexes:archived producer price index detailed report information.United States Bureau of Labor Statistics of the USDepartment of Labor, <http://www.bls.gov/ppi/ppi_dr.htm>;2008 [accessed December 2008].

[51] Robl TL. We are running out of fly ash: the nature of regionalsupply problems. In: Prepared for NETL of the DOE. ThirdAnnual conference on unburned carbon on utility fly ash;1997 <http://www.netl.doe.gov/publications/proceedings/97/97ub/robl.pdf> [accessed March 2005].

[52] ACAA. American Coal Ash Association; 2006. http://www.acaa-usa.org/FAQ.htm [accessed July 2006].

[53] Annamalai K, Thien B, Sweeten JM, Heflin K, Greene LW.Feedlot manure as reburn fuel for NOx reduction in coal firedpower plants. In: Air pollution for agricultural operations IIIproceedings, Research Triangle Park, North Carolina; October12, 2003.

[54] GSNet.com. The largest source of machinery listings online,http://www.gsnet.com; 2007 [accessed October 2007].

[55] Houkom RL, Butchbaker AF, Brusewitz GH. Effect of moisturecontent on thermal diffusivity of beef manure. Transactionsof the ASABE 1974;17:973–7.

[56] Rodriguez PG, Annamalai K, Sweeten JM. The effect of dryingon the heating value of biomass fuels. Transactions of theASAE 1998;41(4):1083–7.

[57] Krishnan R, Tarabulski TJ. Economics of emission reductionfor heavy duty trucks. DieselNet technical report, http://www.dieselnet.com/papers/0501krishnan/; 2005 [accessedMay 2007].

[58] Pratt D. Economic analysis. In: Turner WC, editor. Energymanagement handbook. 4th ed. Liburn, Georga: TheFairmont Press; 2001. p. 37–83.

[59] Megel AJ, Parker DB, Mitra R, Sweeten JM. Assessment ofchemical and physical characteristics of bottom, cyclone,and baghouse ashes from combustion of manure. In:Presented at the ASABE annual meeting, Portland, Oregon;June 2006.

[60] Megel AJ, DeOtte RE Jr, Robinson C. Investigation ofeconomically viable co-products developed from ash fromthe combustion of manure. Paper Number: 074066. In:Presented at the ASABE annual meeting, Minneapolis,Minnesota; June 2007.

[61] Goodrich LB, Mukhtar S, Capareda S, Harman W.Characterization and transportation analysis of dairybiomass for co-firing in coal-fired power plants. Texas A&MUniversity; 2007.

[62] NETL. Tracking new coal-fired power plants. Presentationmade by Erik Shuster, Office of Systems Analyses andPlanning, National Energy Technology Laboratory of theDepartment of Energy; April 6, 2009 <http://www.netl.doe.gov/coal/refshelf/ncp.pdf> [accessed April 2009].

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.



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.


biomass & bioenergy article

Documents