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Biomass & Bioenergy Article


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Biomass & Bioenergy 33 (2009) 1139-1157

Biomass & Bioenergy 33 (2009) 1139-1157

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  • 1. This article appeared in a journal published by Elsevier. The attached copy is furnished to the author for internal non-commercial research and education use, including for instruction at the authors institution and sharing with colleagues. Other uses, including reproduction and distribution, or selling or licensing copies, or posting to personal, institutional or third party websites are prohibited. In most cases authors are permitted to post their version of the article (e.g. in Word or Tex form) to their personal website or institutional repository. Authors requiring further information regarding Elsevier’s archiving and manuscript policies are encouraged to visit:
  • 2. Author's personal copy biomass and bioenergy 33 (2009) 1139–1157 Available at 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 $25 tonneÀ1 could make CB reburning as economically feasible as SCR. Biomass transport distances and the unavailability of suit- able, low-ash CB may require future research to concentrate on smaller capacity coal-fired units between 50 and 300 MWe. ª 2009 Elsevier Ltd. All rights reserved. 1. Introduction form of ammonia (NH3). Experiments conducted by Sweeten et al. [1], Annamalai et al. [2], Arumugam [3], and Lawrence Cattle biomass (cattle manure) has been proposed for use as et al. [4] demonstrated that co-firing feedlot biomass (FB) and a reburn fuel for nitrogen oxide (NOx) emission reduction in coal (blending 10% FB and 90% coal) could reduce NOx emis- coal-fired power plants and utility boilers. Cattle biomass (CB) sions from 290 ppm to 260 ppm. Numerical studies by Sami [5] has shown promise in reducing NOx due to its high volatile were also conducted for co-firing coal and biomass in low-NOx content, rapid release of volatile matter during combustion, swirl burners. Recent experiments and numerical models, and rapid release of fuel bound nitrogen predominantly in the conducted at the Texas A&M Coal and Biomass Energy * Corresponding author. Tel.: þ1 979 845 2562; fax: þ1 979 845 3081. E-mail address: (K. Annamalai). 0961-9534/$ – see front matter ª 2009 Elsevier Ltd. All rights reserved. doi:10.1016/j.biombioe.2009.04.007
  • 3. Author's personal copy 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].
  • 4. Author's personal copy 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.
  • 5. Author's personal copy 1142 biomass and bioenergy 33 (2009) 1139–1157 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
  • 6. Author's personal copy biomass and bioenergy 33 (2009) 1139–1157 1143 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].
  • 7. Author's personal copy 1144 biomass and bioenergy 33 (2009) 1139–1157 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
  • 8. Author's personal copy biomass and bioenergy 33 (2009) 1139–1157 1145 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  à 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.  à 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  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.
  • 9. Author's personal copy 1146 biomass and bioenergy 33 (2009) 1139–1157 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
  • 10. Author's personal copy biomass and bioenergy 33 (2009) 1139–1157 1147 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). Input Value (unit) Source Notes 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
  • 11. Author's personal copy 1148 biomass and bioenergy 33 (2009) 1139–1157 Table 5 – Base case input parameters for cattle biomass drying (all dollar amounts are in 2007 dollars). Input Value (unit) Source Notes 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 [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.
  • 12. Author's personal copy biomass and bioenergy 33 (2009) 1139–1157 1149 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). Input Value (unit) Source Notes 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 [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. Input Value (unit) Source Notes 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.
  • 13. Author's personal copy 1150 biomass and bioenergy 33 (2009) 1139–1157 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.
  • 14. Author's personal copy biomass and bioenergy 33 (2009) 1139–1157 1151 15 Annualized Cost or Revenue (million $ year-1) 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 Annualized Cost or Revenue (million $ year-1) 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.
  • 15. Author's personal copy 1152 biomass and bioenergy 33 (2009) 1139–1157 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.
  • 16. Author's personal copy biomass and bioenergy 33 (2009) 1139–1157 1153 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 average distance between plant and animal feeding operations (km) 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 average distance between plant and animal feeding operations (km) Fig. 14 – Overall annualized cost vs. distance between plant and animal feeding operations.
  • 17. Author's personal copy 1154 biomass and bioenergy 33 (2009) 1139–1157 #trucks #dryers CB reburn fueling 25 35 Cattle Biomass Reburn Fueling, as 30 Numbers of Trucks and Dryers 20 25 fired (tonne h-1) 15 20 15 10 10 5 5 0 0 5 25 50 75 100 200 300 400 500 plant capacity (MWe) Fig. 15 – Numbers of trucks and dryers vs. plant capacity and CB fueling rate (10% heat rate supplied by CB reburn fuel). about 20 tonnes less per hour of CB. In Fig. 15 the number of plants. These new plants can be strategically placed near trucks and dryers are plotted against power plant capacity. A areas with higher concentrations of agricultural biomass to 500 MWe plant would require at least 22 two-tonne conveyor promote reburning and co-firing coal with carbon neutral belt dryers whereas a 300 MWe plant would only require 13 feedstock. Infrastructure such as this would curb NOx and dryers. It may be more helpful to concentrate research and CO2 emissions, boost rural economies, minimize the envi- development of animal biomass utilization on smaller, more ronmental load from large concentrated animal feeding dispersed power facilities. From a feasibility stand point, operations, and develop stronger business ties between the power plants with 50–100 MWe capacities would seem to be agriculture and energy sectors of the US. the best candidates for CB reburning systems. 6. Further considerations and future work 5. Conclusions and policy suggestions Mercury emissions may also affect the economics of CB reburn facilities. For future development of co-combustion Assuming base case parameters, a cattle biomass (CB) systems, these emissions should be account for as well. reburn system retrofitted on an existing 500 MWe coal plant Future work should also include extending the economic (10,290 kJth kWhÀ1 and 80% capacity factor) was found to e models developed here to co-firing, thermal gasification, have a net present worth of À$80.8 million. Comparatively, and smaller on-the-farm combustion systems. a selective catalytic reduction (SCR) system under the same Moreover, the discussion in this paper has concentrated on base case input parameters was found to have a net present the economic benefits to the power plant facility, yet there worth of þ$3.87 million. The greatest increase in overall cost are numerous benefits to farmers and others in the agri- for the CB reburn system was found to come from the cultural sector. Removing large quantities of manure from variable operation and maintenance cost increase, largely concentrated animal feeding operations decreases the due to biomass drying operations. possibility of phosphorus overloading and subsequent soil The profitability of a CB reburning system retrofit on an and water pollution by reducing the required capacity of existing coal-fired power plant can improve with higher coal manure storage structures such as anaerobic lagoons. prices, higher dollar values on NOx emission credits, and Future work should also include investigations into the higher reduction efficiencies from reburning. Finding suit- regional benefits such as job creation and rural economic able markets for selling the higher rates of ash produced development related to cattle biomass combustion. from biomass combustion are also critical. A CO2 value of $25 tonneÀ1 would make CB reburning as economically feasible as SCR. As of the publication of this paper, 27 coal-fired power Acknowledgments plants are under construction in the US. Forty-four others are in the early stages of development [62]. Instead of con- The present work was supported with grants from the DOE- structing extremely large power plants dependant on National Renewable Energy Laboratory, Grant #DE-FG36- nonrenewable (although readily available) fossil fuels, steps 05GO85003 and the Texas Commission on Environmental ought to be made to construct a greater number of smaller Quality (TCEQ), Grant #582-5-65591 0015.
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He has authored more than 2008 [accessed December 2008]. 200 articles, two books on ‘‘Advanced Thermodynamics’’ (CRC [51] Robl TL. We are running out of fly ash: the nature of regional Press, 2002) and ‘‘Combustion Science and Engineering’’ supply problems. In: Prepared for NETL of the DOE. Third (Taylor and Francis, 2006), and a recent article for the Ency- Annual conference on unburned carbon on utility fly ash; clopedia of Energy Engineering and Technology (2007 Taylor 1997 and Francis). He serves on the editorial board of the Journal of 97/97ub/robl.pdf [accessed March 2005]. Green Energy and as Associate Editor for the ASME Journal of [52] ACAA. American Coal Ash Association; 2006. http://www. [accessed July 2006]. Gas Turbines and Power. [53] Annamalai K, Thien B, Sweeten JM, Heflin K, Greene LW. Feedlot manure as reburn fuel for NOx reduction in coal fired Dr. Wyatte Harman is a Professor of Agricultural Economics at power plants. In: Air pollution for agricultural operations III the Blackland Research and Extension Center, Texas AM proceedings, Research Triangle Park, North Carolina; October University, at Temple, Texas. He earned his BS from Texas 12, 2003. Technological University in 1961, his MS from Texas AM [54] The largest source of machinery listings online,; 2007 [accessed October 2007]. University in 1966 and his PhD from Oklahoma State Univer- [55] Houkom RL, Butchbaker AF, Brusewitz GH. Effect of moisture sity in 1974. His recent research has emphasized the economic content on thermal diffusivity of beef manure. Transactions feasibility of new and innovative cropping systems involving of the ASABE 1974;17:973–7. alternative tillage systems and best management practices.
  • 20. Author's personal copy biomass and bioenergy 33 (2009) 1139–1157 1157 He has recently published nine journal articles and technical in 1967. He then received his MS and PhD in Agricultural papers in the agricultural and environmental sciences areas. Engineering from Oklahoma State University in 1969. Dr. Sweeten has authored or co-authored more than 500 Dr. John M. Sweeten has served as Resident Director of the publications and papers and technical reports on livestock Texas AgriLife Research and Extension Center at Amarillo and poultry manure management, including use as since 1996. He earned his BS from Texas Tech University biomass fuel, air and water quality management.