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Cost of Controlling Mercury Emissions from Utility Boilers

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Cost of Controlling Mercury Emissions from Utility Boilers Powered By Docstoc
					APPENDIX C PRELIMINARY ESTIMATES OF COSTS OF MERCURY EMISSION CONTROL TECHNOLOGIES FOR ELECTRIC UTILITY BOILERS
Ravi K. Srivastava, Charles B. Sedman, and James D. Kilgroe U.S. Environmental Protection Agency National Risk Management Research Laboratory Research Triangle Park, NC 27711

As noted in Chapter 1 of this report, the U.S. Environmental Protection Agency (EPA) has conducted an examination of the “co-benefits” of potential pollution control options for the electric power industry to lower the emissions of its most significant air pollutants. One of these pollutants is mercury. The examination of the co-benefits was conducted using the Integrated Planning Model (IPM) [1]. For the co-benefits study, this model had to be supplemented with information on performance and cost of mercury emission control technologies. Described in this appendix is the development of a preliminary assessment of performance and cost of mercury emission control technologies for utility boilers. Behavior of Mercury in Combustion Systems In combustion systems, mercury is volatilized and converted to elemental mercury (Hgo) in the high temperature regions of furnaces. As the flue gas is cooled, Hgo is oxidized to ionic forms of mercury (Hg++). The rate of oxidization is dependent on the temperature, flue gas composition, and the properties and amount of fly ash and any entrained sorbents. The time/temperature profile within a combustion system determines the instantaneous equilibrium conditions, the kinetics of chemical reactions, and the time available for reactions. In incinerators the flue gas concentration of chlorine, in the form of hydrogen chloride (HCl), is substantially higher than the concentration of Hgo. When the concentration of HCl is greater than the concentration of Hg, thermochemical calculations indicate that Hgo is preferentially converted to mercuric chloride (HgCl2). In coal-fired combustors, where the concentrations of HCl are much lower and where equilibrium conditions are not achieved, Hgo may be oxidized to mercury oxide (HgO), mercury sulfate (HgSO4), HgCl2, or some other form of mercury. The oxidization of Hgo to HgCl2 and other ionic forms of mercury is abetted by catalytic reactions on the surface of fly ash or sorbents that may be present in the flue gas. Hg°, HgCl2, and HgO are primarily in a vapor phase at flue gas cleaning temperatures, and special methods must be used for their capture. Each of these forms of mercury can be adsorbed onto porous solids such as fly ash, powdered activated carbon (AC), and calcium-based

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acid gas sorbents for subsequent collection in a particulate matter (PM) control device. These mercury compounds can also be captured in carbon bed filters or other reactors containing appropriate sorbents. In the U.S., the control of mercury in municipal waste combustors (MWCs) is based on the injection of powdered AC upstream of an electrostatic precipitator (ESP) or a fabric filter (FF). HgCl2 is water soluble and readily reacts with alkali metal oxides in an acid-base reaction; therefore, conventional acid gas scrubbers used for sulfur dioxide (SO2) control can effectively capture HgCl2. Hgo is insoluble in water and must be adsorbed onto a sorbent or converted to a soluble form of mercury that can be collected by wet scrubbing. HgO has low solubility and probably has to be collected by methods similar to those used for Hgo. Where scrubbers are already employed, mercury control is a function of the ratio of HgCl2 to total mercury concentrations in the flue gas -- a ratio that is inherent to the properties of coal or other material being burned. The total mercury removal efficiency of scrubbers has been reported by the Electric Power Research Institute (EPRI) and the Department of Energy (DOE), to range from 30 to 90% [2]. Where scrubbers are not employed, activated carbon can be added upstream of the PM control device (ESP or FF). While full-scale tests have not yet been attempted, EPRI reports poor carbon utilization in tests with a pilot-scale ESP installed on a flue gas slip stream from a coal-fired utility boiler. Status of Technologies for Control of Mercury Emissions A variety of air pollution control technologies are now commercially used to control mercury emissions from MWCs. In Europe these technologies include activated carbon injection (ACI) followed by collection in a PM control device, the use of wet scrubbers, the use of carbon bed filters, and the use of reagents (sodium sulfide or sodium tetrasulfide) to convert mercury into more easily captured forms. In the U.S., mercury emissions from MWCs are typically controlled by the use of ACI in conjunction with dry scrubbing systems. Few, if any, MWCs use wet scrubbers. The control of mercury emissions from coal-fired boilers is not commercially practiced in the U.S. The direct application of MWC mercury control technologies to coal-fired boilers is difficult because of factors that make mercury more difficult and costly to capture:  There is typically a higher fraction of Hg° in the flue gas from coal-fired boilers than in MWCs. This means that more effective sorbents must be developed for Hg° capture or that Hg° must be converted to more a easily captured form such as HgCl2. The concentration of mercury in coal-fired utility flue gas is typically less that 10 g/dscm while the concentration of mercury in MWCs may range from less the 200 to more than 1500 g/dscm. As a consequence, the stack mercury concentrations of well-controlled MWCs will typically be higher than the inlet mercury flue gas concentrations in coal-fired utility
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

boilers. The low mercury concentrations at the inlet to coal-fired boiler air pollution control devices and the large volumes of flue gases that must be cleaned increase the difficulty and cost of control. EPA, DOE, and EPRI are all engaged in research to develop more cost-effective mercury control technologies for coal-fired boilers. This includes research on mercury speciation, studies of mercury capture, and the development of improved control technologies. Major objectives of these research efforts are to:  Develop improved manual methods to measure mercury speciation in coal-fired boilers and other combustion systems. Evaluate continuous emission monitors (CEMs) that are being developed for measuring total and speciated mercury in flue gases. Effective CEMs can be used to monitor and adjust mercury control technology performance as well as serve as a compliance monitoring tool. Determine the factors that affect mercury speciation in flue gases and develop methods that can be used to control speciation in order to improve mercury capture. Develop more effective sorbents and reagents for mercury capture. More effective sorbents or reagents can be expected to accomplish one or more of the following goals: lower sorbent or reagent unit costs ($/lb), increase sorbent collection efficiency or reagent reactivity, increase sorbent or reagent utilization rates, and provide more effective multi-pollutant control. Evaluate and develop improved control technologies as embodied in more effective equipment or process conditions. For example: the use of additional ducting upstream of the PM control device to improve sorbent utilization through increased residence time, recycling of collected fly ash and sorbent into the flue gas upstream of the PM control device to increase sorbent utilization, and equipment modifications needed to inject a reagent into the flue gas to increase conversion of Hg° to HgCl2 for collection in wet scrubbers.

 



It is believed that this research will develop improved technologies for controlling mercury emissions from coal- fired boilers. While substantial progress is expected over the next several years, it is not now possible to quantify the improvements in performance and costs that will accrue from these efforts. Control Technology Options Approximately 67% (capacity basis) of the existing coal-fired utility boilers in the U.S. are equipped only with ESPs for the control of PM. Another 7% employ ESPs followed by wet scrubbers. The remaining boilers employ dry scrubbers (spray dryers and ESPs or FFs) or employ FFs for control of PM.
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In this study, model plants with eight different flue gas cleaning equipment configurations, called existing configurations, were used. In addition, it was assumed that each of the existing flue gas cleaning system configurations could be associated with a coal-fired utility boiler that burns either bituminous or subbituminous coal -- depending on the plant location. These 16 model plants, reflecting differences in flue gas cleaning equipment and type of coal burned, are shown in Exhibit C1. Each retrofit option shown in Exhibit C1 was based on the use of ACI. This is the only technology for which there is pilot-scale performance data for both eastern and western coals. Two major performance parameters were selected for each retrofit option:   The mercury collection efficiency across the air pollution control system, and The ratio of the required carbon injection rate to mercury flow rate in the flue gas at the inlet to the first air pollution control device.

Mercury collection efficiencies in combustion systems, equipped only with ESPs or FFs, are affected by the concentration of mercury in the flue gas at the inlet to the PM control device, and the amount of mercury that is adsorbed onto the fly ash and subsequently removed in the PM control device. No attempt was made in this study to quantify the capture of adsorbed mercury on PM since there is only fragmentary information on this subject. Two assumptions were made on the effects of low mercury inlet concentrations in order to obtain reasonable mercury control retrofit costs. In the EPA Mercury Study Report to Congress, the required mercury control efficiency for each retrofit option was assumed to be 90% [3]. In this study 90% control was assumed to be required for only those units whose existing equipment configuration includes wet scrubbers. Lower collection efficiencies were assumed for units that now employ ESPs, FFs, or dry scrubbers (see Exhibit C1). An 85% collection efficiency was assumed for non-FGD units that select some combination of ACI and FFs as the mercury control method. For the two cold-side ESP cases that use SC + ACI as the retrofit option, collection efficiencies of 80 and 65 percent are assumed respectively for the plants that burn bituminous coal (Case 1A) and subbituminous coal (Case 1B). Dropping the collection efficiency from 90 to 85, from 90 to 80, or from 90 to 65% will have a disproportionate effect on the amount of carbon needed. At high collection efficiencies, increasingly larger amounts of carbon are required for each percentage point in collection efficiency gain. For Case 1B, a plant with a cold-side ESP that burns subbituminous coal, a combination of lower performance requirements (65% collection efficiency) and lower carbon/mercury ratio (7,500) was selected because of the potentially lower mercury flue gas inlet concentrations associated with the combustion of subbituminous coals.
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Units equipped only with ESPs will be the most difficult to retrofit in a cost-effective manner. Cost trade-off studies indicated that the most cost effective retrofit option, for which pilot-scale test data exist, is spray cooling (SC) followed by carbon injection upstream of a new (relatively small) FF installed downstream of the existing ESP. It will be less difficult to effectively retrofit plants with existing configurations that consist of FFs, either with or without dry scrubbers. Activated carbon in the FF cake provides better gas-particle contact than an ESP, and the longer effective carbon residence times greatly improve sorbent utilization. This has been validated in full-scale tests on MWCs and pilot scale tests on coal-fired combustors. Field tests have shown that it takes two to three times more ACI to achieve the same performance on MWCs equipped with dry scrubbers and ESPs than with dry scrubbers and FFs [4]. It is anticipated that current research on wet scrubbers will result in improved performance through the use of reagents or catalysts to convert mercury to chemical forms that are soluble in aqueous based scrubbers. However, since there are no published pilot-scale test data that confirm this hypothesis, it was assumed for this study that ACI is needed for facilities with existing wet scrubbers. For utilities with cold-side ESPs, this will entail SC followed by ACI. In facilities with existing hot-side ESPs, the installation of FF downstream of the existing ESP will also be required. Described in the following sections is the development of the information shown in Exhibit C-1. This is followed by a description of the cost methodology that EPA adopted in this work. Finally, costs associated with each of the model plants of Exhibit C1 are provided. Model Performance Parameters Based on the information in EPA’s Mercury Study Report to Congress [3] and other published literature [2, 5-10], control technologies based on injection of AC into the flue gas appear to hold promise for reducing mercury emissions from utility boilers. EPA arrived at this determination by considering that: (1) ACI technologies have been applied successfully on MWCs; (2) information on results achieved in pilot-scale ACI tests, conducted on coal-fired utility boilers, is available in published literature; and (3) limited cost data are available for applications of ACI - based technologies on utility boilers. As discussed below and summarized in Exhibit C1, the estimates of mercury emission reduction performance and associated carbon injection rates are based on reported pilot-scale applications [6-10]. In arriving at the contents of Exhibit C1, six assumptions were made with respect to mercury control system hardware and performance. These assumptions are described below.

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1.

The performance estimates presented in Exhibit C1 reflect the mercury emission reduction percent calculated using Reduction (%) = 100*(Emissionin - Emissionstack) / Emissionin where: Emissionin = flue gas mercury concentration at the inlet to the first air pollution control device; and Emissionstack = mercury emission level at stack exhaust. (1)

2.

It is known that the type of coal fired in the boiler can influence the performance of mercury emission reduction technologies. Therefore, as shown in Exhibit C1, separate estimates of mercury emission reduction performance and carbon injection rate were determined for bituminous and subbituminous coals. As described in assumptions 4, 5, and 6, below, these estimates are based on published data [6-10]. In each of the technologies shown in Exhibit C1, the boiler flue gas is spray cooled before injection of AC. In general, the operating costs associated with use of AC comprise a significant portion of total costs for ACI-based technologies. Since spray cooling of flue gas results in significantly reduced requirements of AC, this cooling was included in each of the technologies shown in Exhibit C1. Note that the capital costs associated with spray cooling equipment are independent of the degree of cooling needed, within the range of referenced applications. Note also that spray cooling is assumed to exist at boiler sites with dry scrubbers. Consequently, no additional SCs are needed in Cases 7A, 7B, 8A, and 8B. The performance estimates for cases 1A, 1B, 5A, 5B, 7A, 7B, 8A, and 8B were interpolated from field pilot data in references [6-10], as described below. Reference [6] describes AC injection application on a low-sulfur, high chlorine, Eastern bituminous coal-fired boiler served by parallel pilot ESP and pilot FF units. In this application: (1) with an ESP and gas cooling (Case 1A), 80% mercury control was achieved at 55,000:1 C/Hg and (2) with a FF and gas cooling (Case 5A), 90% mercury control was achieved at 40,000:1 C/Hg. The high chlorine content of coal was thought to be responsible for the poor carbon utilization. Reference [10] describes subsequent attempts to add lime with ACI upstream of the FF, which resulted in improved performance of ACI. In this application, using an FF (Case 5A), 90% mercury control was achieved at 12,000:1 C/Hg. Interpolation of these results suggests that 85% mercury reduction may be achieved using C/Hg of 10,000:1 as shown in Exhibit C1.

3.

4.

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For the analyses, C/Hg at 10,000:1 was selected for Case 5A. Since no comparable data are available for Case 1A, the proportional improvement in ACI performance due to the removal of HCl by lime is assumed to hold for ESPs. Therefore, 75% improvement in AC utilization suggests that ESPs (Case 1A) can achieve 80% Hg control at 15,000:1 C/Hg with hydrated lime assistance, or with no HCl present in the flue gas. It is observed that the supplemental use of hydrated lime with ACI to enhance mercury capture will not negatively impact the estimated costs of control. Capital costs are already covered by the sorbent storage and injection system costs, and lime is relatively cheap compared to the AC that it may displace (the cost of hydrated lime is about $85/ton compared with $909/ton for the AC used in this study). In addition, the use of hydrated lime will generate additional credits for the control of SO2 , SO3 and fine PM. Reference [7] describes similar pilot ACI testing on low sulfur subbituminous coal. Using the results of this testing, mercury emission reduction performance and carbon requirements for Cases 1B and 5B were determined. In the tests with an ESP (Case 1B), up to 74% mercury removal was achieved at a C/Hg of <10,000:1. This suggests that an average of 65% mercury removal can be achieved at a C/Hg of 7500:1 with gas cooling (Case 1B). Again in the tests with a FF (Case 5B), 90% mercury removal was achieved at a C/Hg of 10,000:1. This suggests that an average of 85% mercury removal can be achieved at a C/Hg of 6,000:1 with gas cooling (Case 5B). The improved carbon utilization achieved in subbituminous coal tests over the bituminous coal results provided above is thought to be directly related to high fly ash alkalinity and low chlorine content of subbituminous coal. Reference [8] describes mercury removal using a pilot dry scrubber and ACI on a simulated flue gas with no chlorine and elemental mercury vapor present. AC removed essentially all of the mercury at a C/Hg of 770 (using iodine-impregnated AC). Reference [9] describes mercury removal using wet and dry scrubbers on a midwestern coal in which the dominant form of mercury is known to be HgCl2. Mercury removals of 7585% were observed using no ACI, where the HgCl2 behaved as an acid gas and was sequestered by the alkaline FGD sorbent. Assuming that 50% of the mercury in the typical coal flue gas is oxidized and that remaining is elemental mercury, it is judged that dry scrubbing will control 50% of the mercury in Eastern coals and 65% of the mercury in high alkalinity Western subbituminous coals. With ACI, 85% removal can be achieved on both types of coal, but the AC needed will vary from 3000:1 C/Hg on the alkaline ash coals with FF control (Case 7B) up to 10,000:1 C/Hg on Eastern bituminous coal with ESP control (Case 8A). Intermediate levels of AC addition – around 6,000:1 – were judged necessary for Cases 7A and 8B to achieve 85% control. 5. The performance and carbon requirements associated with Cases 2A and 2B are assumed to be identical to Cases 5A and 5B, respectively. This assumption is made because a FF is the PM control device in each of these cases. However, whereas in Cases 5A and 5B

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FFs exist at boiler sites, in Cases 2A and 2B small FFs are considered to be needed to collect AC. 6. If wet FGD is available at a boiler site in addition to an ACI-based technology, then 90% mercury reduction is assumed to be available without any change in cost over the corresponding case without wet FGD. Thus, for example, costs for Cases 1A and 3A of Exhibit C1 would be identical but 90% reduction is available in Case 3A in contrast to 80% in Case 1A. Thus costs for Cases 3A, 3B, 4A, 4B, 6A, and 6B are identical to Cases 1A, 1B, 2A, 2B, 5A, and 5B, respectively, but 90% mercury removal is available in cases with wet FGD.

Based on the carbon injection rates shown in Exhibit C1, costs associated with the use of each of the ACI technologies were developed. Described in the ensuing paragraphs is the methodology used in arriving at these costs.

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Exhibit C1 Viable Mercury Emission Control Technologies for Utility Boilers
Case Existing Equipment 1A 1B 2A 2B 3A 3B 4A 4B 5A 5B 6A 6B 7A 7B 8A 8B Cold ESP Cold ESP Hot ESP Hot ESP Cold ESP + FGD Cold ESP + FGD Hot ESP + FGD Hot ESP + FGD FF FF FF + wet FGD FF + wet FGD DS + FF DS + FF DS + ESP DS + ESP bituminous subbituminous bituminous subbituminous bituminous subbituminous bituminous subbituminous bituminous subbituminous bituminous subbituminous bituminous subbituminous bituminous subbituminous Coal Type Mercury Emission Equipment SC + ACI SC + ACI SC + ACI + FF SC + ACI + FF SC + ACI SC + ACI SC + ACI + FF SC + ACI + FF SC + ACI SC + ACI SC + ACI SC + ACI ACI ACI ACI ACI Reduction (%) 80 65 85 85 90 90 90 90 85 85 90 90 85 85 85 85

C/Hg
(g carbon / g Hg) 15,000 7,500 10,000 6,000 15,000 7500 10,000 6,000 10,000 6,000 10,000 6,000 6,000 3,000 10,000 6,000

Abbreviations: activated carbon injection dry scrubber (either a spray dryer absorber/particulate matter removal system or a dry alkali sorbent injection/particulate matter removal system) ESP: electrostatic precipitator FGD: flue gas desulfurization system FF: fabric filter (or baghouse) Hg: mercury SC: spray cooler ACI: DS:

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Determination of Capital Costs ACI systems, FFs, and SCs are utilized in the ACI-based technologies shown in Exhibit C-1. Some cost information on these hardware elements, in the context of ACI-based technologies, is available in the EPA’s Mercury Study Report to Congress [3] and a recent Department of Energy (DOE) publication [11]. This cost information, pertinent to specific applications on boiler sizes of 100 and 975 MW, is shown in Exhibit C2.

Exhibit C2 Cost in $s of Major Equipment Used in ACI-based Technologies1
FF 100 MW EPA2 DOE3 1,813,479 Same as EPA 975 MW 12,978,750 Same as EPA 100 MW 258,627 Same as EPA SC 975 MW 2,993,796 Same as EPA ACI System 100 MW 109,448 257,000 975 MW 109,448 2,231,000

DOE has reported that it examined EPA’s cost estimates for FF and SC provided in refrence [3] and found them to be reasonable [11]. However, as described in reference [11], DOE appears to have conducted more detailed cost estimates for ACI systems. Accordingly, EPA’s costs for FFs and SCs and DOE’s costs for ACI systems were used to develop the capital cost functions for each of the ACI-based technologies shown in Exhibit C-1. Note, however, that DOE used a carbon injection rate of 30,000 g of carbon/g of mercury [11]. Therefore, the DOE ACI system costs were adjusted to correspond to the injection rates shown in Exhibit C-1. The steps taken in calculating capital cost ($/kW) of applying a specific ACI-based technology on a specific boiler are shown in Exhibit C3.

1

The EPA and DOE costs presented in this table were based on the same model boilers. A description of these model boilers of sizes 100 MW and 975 MW can be found in references [3] and [11]. Per Appendix B of Volume VIII of the Mercury Study Report to Congress [3], purchased equipment costs for SC and ACI systems were based on vendor contacts reported in 1993 and FF costs were based on 1992 data. Accordingly, in this study, EPA’s costs for SC and FF are considered to be in 1993 dollars. Per the reference [11], DOE’s costs are on 1989 basis. These costs were escalated to 1993 dollars using the inflator factor of 1.144003567. This inflator factor has been derived from the Economic Report of the President, Council of Economic Advisers, Feb 1998 [13].

2

3

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Exhibit C3 Capital Cost Calculation
Description Boiler size (MW) Purchased equipment cost ($) Installation cost ($)4 Indirect cost ($)5 Total capital cost ($) Retrofit factor6 Total capital cost w/ retrofit ($) Capital cost ($/kW) Cost or Data Symbol MW1 PE Inst = x*PE Ind = y*PE TCC = PE + Inst + Ind 1.15 TC = 1.15*TCC CC = TC/(MW1*1000)

For each of the ACI-based technologies, capital costs ($/kW) were calculated for model boiler sizes of 100 and 975 MW. These model boilers are described in the references [3] and [11]. The capital costs ($/kW) obtained were used to develop the capital cost function relating ($/kW) to boiler size (MW). This function has the form C1 = C2 (MW2/MW1)a (2)

where: C1 = capital cost ($/kW) of ACI-based technology installation at the first model boiler; C2 = capital cost ($/kW) of ACI-based technology installation at the second model boiler; MW1 = first model boiler size in MW; MW2 = second model boiler size in MW; and a = a scaling factor reflecting economy-of-scale. Capital cost functions, expressed by Equation (2), were obtained for each of the ACI-based technologies.

4

The values of the installation cost factor, x, used are identical to those used in the Mercury Study Report to Congress [3]. These values are: 0.34 for SC, 0.15 for ACI, and 0.72 for FF. The values of the indirect cost factor, y, used are identical to those used in the Mercury Study Report to Congress [3]. These values are: 0.45 for SC, 0.30 for ACI, and 0.45 for FF. A retrofit factor of 1.15 was included in the cost estimation procedure to account for more difficult retrofits.

5

6

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Determination of Annual Fixed Operation and Maintenance (O&M) Costs Fixed O&M costs include costs related to maintenance requirements (labor and materials); taxes, insurance, and administration; and capital recovery. Following the guidelines in the Electric Power Research Institute’s Technical Assessment Guide [12], the annual cost of maintenance labor and materials, expressed in ($/kW), is assumed to be 1.5% of the capital cost ($/kW). The annual carrying charge used in the IPM model includes the effects of capital recovery as well as taxes and insurance. Note that, as mentioned in Chapter 2 of this report, administration costs were not modeled in this effort. Determination of Annual Variable O&M Costs7 Variable O&M costs include labor charges, costs related to consumption of activated carbon and power, any incremental waste disposal cost, cost of operating materials (water for SC), and overhead. Calculation of each of these is described below. Labor cost: Both operating labor and supervisory labor are accounted for in the cost estimates. Following the information provided in reference [3], the labor rate is taken to be $12/hr and supervisory labor costs total 15% of operating labor costs. Then for a capacity factor (CF), labor cost is computed using Labor (mills/kWh) = 1.15*$12/hr*CF*8760 hr/yr*1000 mills/$ / (MW*1000 kW/MW*8760 hr/yr*CF)

(3)

Activated carbon cost: Based on recent information,8 the cost of activated carbon is taken to be $ 1.00 per kg of activated carbon. Using this cost along with the flue gas flow, concentration of mercury in the flue gas, CF, and carbon injection rate, the cost of activated carbon consumption (mills/kWh) is determined for each model boiler application. An average of the costs for the model boiler applications is considered to be the carbon consumption cost (mills/kWh) for each of the ACI-based technologies. Power consumption cost: Power costs provided in reference [3] for model boiler applications were based on a unit power cost of 46 mills/kWh and on a carbon injection rate of 460 g of carbon per g of mercury. For this work, the annual power consumption costs ($/yr) provided in reference [3] were adjusted to reflect any change in carbon injection rate and a power cost of 19.4 mills/kWh in 1993. The adjusted power consumption costs ($/yr) were used to arrive at the
7

Note that although the Mercury Study Report to Congress [3] was released in December 1997, the cost data in this study, at least for equipment, appear to be pertinent to 1993 (see footnote 2). As a conservative measure, for this study all of the cost data presented in [3] were assumed to be for the year 1993. Personal communication between Charles Sedman and Jim Kilgroe of EPA and Anthony Licata of Licata Energy & Environmental Consultants, Inc., Yonkers, NY, December 14, 1998.

8

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power consumption cost (mills/kWh) for model boiler applications. The average of the costs for the model boiler applications is considered to be the carbon consumption cost (mills/kWh) for each of the ACI-based technologies. Disposal cost: Annual disposal costs ($/yr) for the model boiler applications provided in reference [3] were adjusted to reflect any change in carbon injection rate and then were used to arrive at disposal costs expressed in mills/kWh. The average of the costs for the model boiler applications is considered to be the carbon consumption cost (mills/kWh) for each of the ACIbased technologies. Operating materials cost: These costs for the various applications were taken from the Mercury Study Report to Congress [3]. Overhead: Following the information in reference [3], the overhead cost for each of the ACIbased technologies was taken to be 60% of the labor and maintenance costs. Results The costs of the ACI-based technologies, developed using the above methodology, are shown in Exhibits C-4 through C-13 at the end of this appendix. Caveats The performance and cost estimates of the ACI-based technologies presented in this appendix are considered to be preliminary for several reasons. First, the performance estimates and associated carbon requirements are based on relatively few data points that have been established in pilot-scale tests. Factors that are known to affect adsorption of mercury on activated carbon are: speciation of mercury in flue gas, available residence time (duct length), effect of flue gas and ash characteristics, and adequacy of mixing between flue gas and activated carbon. The effect of these factors may not be accounted for in the relatively few, pilot-scale, data points that comprised the basis for this work. The research being conducted by EPA, DOE, and EPRI is expected to address these issues in the next few years. In addition to the technical issues surrounding the use of AC for mercury control, more accurate estimation of equipment costs is needed to better capture the economy-of-scale that would be expected.

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References

1.

Analyzing Electric Power Generation Under CAAA, Office of Air and Radiation, U.S. Environmental Protection Agency, Washington, D.C., March 1998. Available at the web site www.epa.gov/capi. EPA Study of Hazardous Air Pollutant Emissions from Electric Utility Steam Generating Plants – Final Report to Congress, Volume 1, EPA 453R-98-004a (NTIS PB98-131773), Office of Air Quality Planning and Standards, U.S. Environmental Protection Agency, Research Triangle Park, NC, February 1998. Keating, M.H., et. al., Mercury Study Report to Congress, EPA-452/R-97-003 (NTIS PB98-124738), Office of Air Quality Planning and Standards and Office of Research and Development, U.S. Environmental Protection Agency, Research Triangle Park, NC, December 1997. Kilgroe, J.D., Control of Dioxin, Furan, and Mercury Emissions from Municipal Waste Combustors, Journal of Hazardous Materials, 47 (1966) 163-194. R. Chang and G. Offen, "Mercury Emission Control Technologies: An EPRI Synopsis," Power Engineering, November 1995. Waugh, E., et al., "Mercury Control in Utility ESPs and Baghouses through Dry CarbonBased Sorbent Injection Pilot-Scale Demonstration," in EPRI-DOE-EPA Combined Air Pollutant Control Symposium, Particulates and Air Toxics, Volume 3, EPRI TR-108683V3, Electric Power Research Institute, Palo Alto, CA, August 1997. Haythornthwaite, S., et al., "Demonstration of Dry Carbon-Based Sorbent Injection for Mercury Control in Utility ESPs and Baghouses," in EPRI-DOE-EPA Combined Air Pollutant Control Symposium, Particulates and Air Toxics, Volume 3, EPRI TR-108683V3, Electric Power Research Institute, Palo Alto, CA, August 1997. Helfritch, D., P. Feldman, and S. Pass, "A Circulating Fluid Bed Fine Particulate and Mercury Control Concept," in EPRI-DOE-EPA Combined Air Pollutant Control Symposium, Particulates and Air Toxics, Volume 3, EPRI TR-108683-V3, Electric Power Research Institute, Palo Alto, CA, August 1997. Redinger, K., et al., "Mercury Emissions Control in FGD Systems," in EPRI-DOE-EPA Combined Air Pollutant Control Symposium, Particulates and Air Toxics, Volume 3, EPRI TR-108683-V3, Electric Power Research Institute, Palo Alto, CA, August 1997.

2.

3.

4.

5.

6.

7.

8.

9.

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10.

Waugh, E.G., et al., "Mercury Control on Coal-Fired Flue Gas Using Dry Carbon-Based Sorbent Injection: Pilot-Scale Demonstration,” presented at the 1998 Air & Waste Management Association Annual Meeting and Exhibition, San Diego, CA, June 1998. Brown T., W. O’Dowd, R. Reuther, and D. Smith, “Control of Mercury Emissions from Coal-Fired Power Plants: A Preliminary Cost Assessment,” in Proceedings of the Conference on Air Quality, Mercury, Trace Elements, and Particulate Matter, Energy & Environmental Research Center, McLean, VA, December 1998. Technical Assessment Guide, Volume 1: Electricity Supply – 1993 (Revision 7), EPRI TR-102276s Vol. 1 Rev. 7, Electric Power Research Institute, Palo Alto, CA, 1993. Economic Report of the President, Council of Economic Advisers, February 1998. Available at the web site www.access.gpo.gov/eop/.

11.

12.

13.

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Exhibit C4 SC+ ACI + cold ESP with Bituminous Coal
Case 1A: SC+ ACI + cold ESP with bituminous coal Data for 975 MW from Table B-12 in EPA's Report to Congress (RTC) [3] Data for SC+ ACI for 100 MW from Table B-11 in EPA's RTC[3] Source Size (MW) Capacity factor g carbon / g Hg Hg concentration (g/dscm) Flue gas flowrate (dscm/hr) Carbon ($/kg)9 $ 975 0.65 15000 10 4050000 0.89 $ 100 RTC 0.65 RTC 15000 Based on published data 10 RTC 411000 RTC 0.89

Capital Costs: Spray cooling system ($) Carbon injection system ($)10 Purchased equipment, PE, ($) Installation ($) Indirect ($) Total capital cost ($) Retrofit factor Total capital cost w/ retrofit ($) Total capital cost ($/kW) Capital cost ($/kW) = Annual O&M: Maintenance ($/kW-Yr) Maintenance ($/kW-Yr) =

1993$ $ $ $ $ $ $ $ $ 2,993,796 1,276,136 4,269,932 1,209,311 1,730,049 7,209,292 1.15 8,290,686 8.50 $ $ $ $ $ $ $ $ 258,627 RTC, 1993 $s 147,004 405,631 109,984 160,483 676,099 1.15 777,514 7.78 Exponent = -0.04

8.50*(975/MW)^-0.04

0.13

0.12 0.13*(975/MW)^-0.04 975 100 0.55 0.07 0.166 0.03 Formula 0.55 0.07 0.096 0.04

Labor ($/yr) Carbon cost ($/yr) Power ($/yr) Disposal ($/yr) Operating materials ($/yr) Overhead (mills/kWh)

$ $ $ $ $

59,616 3,077,496 964,396 139,826 219,572

$ $ $ $ $

49,680 312,309 88,921 94,630 18,968

RTC RTC RTC RTC RTC

Labor (mills/kWh) = Carbon (mills/kWh) = Power (mills/kWh) = Disposal (mills/kWh) = Operating matls (mills/kWh) =

0.01 0.55 0.07 0.025 0.04 0.02

0.09 Given below

0.06 Given below

Labor varies with usage (not with boiler size); overhead at 60% of labor & maintenance. Hence use: Labor (mills/kWh) = 1.15*12*CF*8760*1000 / MW*1000*8760*CF Overhead (mills/kWh) = 0.6 [1000/8760*fixed O&M($/kW-Yr) + labor(mills/kWh)]
9

(1993$)

The carbon cost of $1.00/kg, see footnote 8, has been deflated using a deflator of 0.8896797. The deflator was obtained using a 1997 to 1992 relationship from CEA, Economic Report of the President (ERP), using February 1998 as a proxy for 1998 to 1993 relationship. Carbon injection system costs were determined by adjusting the DOE costs, expressed in 1989 $s, for carbon injection rate and escalating 1989 dollars to 1993 dollars using the inflation factor of 1.144003567. This inflation factor has been derived from CEA, ERP, 1993.

10

C-16

Exhibit C5 SC+ ACI + Cold ESP with Subbituminous Coal
Case 1B: SC+ ACI + cold ESP with subbituminous coal Data for 975 MW from Table B-12 in EPA's RTC [3] Data for SC+ ACI for 100 MW from Table B-11 in EPA's RTC [3] Source Size (MW) Capacity factor g carbon / g Hg Hg concentration (g/dscm) Flue gas flowrate (dscm/hr) Carbon ($/kg) $ 975 0.65 7500 10 4050000 0.89 $ 100 RTC 0.65 RTC 7500 Based on published data 10 RTC 411000 RTC 0.89 See footnote 9

Capital Costs: Spray cooling system ($) Carbon injection system ($) Purchased equipment, PE, ($) Installation ($) Indirect ($) Total capital cost ($) Retrofit factor Total capital cost w/ retrofit ($) Total capital cost ($/kW) Capital cost ($/kW) = Annual O&M: Maintenance ($/kW-Yr) Maintenance ($/kW-Yr) =

1993$ $ $ $ $ $ $ $ $ 2,993,796 638,068 3,631,864 1,113,601 1,538,629 6,284,093 1.15 7,226,707 7.41 $ $ $ $ $ $ $ $ 258,627 RTC, 1993 $s 73,502 See footnote 10 332,129 98,959 138,433 569,521 1.15 654,949 6.55 Exponent = -0.05

7.41*(975/MW)^-0.05

0.11

0.10 0.11*(975/MW)^-0.05 975 100 Formula

Labor ($/yr) Carbon cost ($/yr) Power ($/yr) Disposal ($/yr) Operating materials ($/yr) Overhead (mills/kWh)

$ $ $ $ $

59,616 1,538,748 961,379 69,913 219,572

$ $ $ $ $

49,680 156,154 85,856 47,315 18,968

RTC RTC RTC RTC RTC

Labor (mills/kWh) = Carbon (mills/kWh) = Power (mills/kWh) = Disposal (mills/kWh) = Operating matls (mills/kWh) =

0.01 0.28 0.07 0.013 0.04 0.01

0.09 Given below 0.27 0.06 0.083 0.03 0.28 0.07 0.048 0.04

0.06 Given below

Labor varies with usage (not with boiler size); overhead at 60% of labor & maintenance. Hence use: Labor (mills/kWh) = 1.15*12*CF*8760*1000 / MW*1000*8760*CF Overhead (mills/kWh) = 0.6 [1000/8760*fixed O&M($/kW-Yr) + labor(mills/kWh)]

C-17

Exhibit C6 Hot ESP + SC+ ACI with Bituminous Coal
Case 2A: Hot ESP + SC+ ACI + FF with bituminous coal Data from Tables B-10 and B-11, in EPA's RTC [3] Source Size (MW) Capacity factor g carbon / g Hg Hg concentration (g/dscm) Flue gas flowrate (dscm/hr) Carbon ($/kg) 975 0.65 10000 10 4050000 0.89 100 RTC 0.65 RTC 10000 Based on published data 10 RTC 411000 RTC 0.89 See footnote 9

Capital Costs: Spray cooling system ($) Carbon injection system ($) Fabric Filter ($) Purchased equipment ($) Installation ($) Indirect ($) Total capital cost ($) Retrofit factor Total capital cost w/ retrofit ($) Capital cost ($/kW) Capital cost ($/kW) = Annual O&M: Maintenance ($/kW-Yr) Maintenance ($/kW-Yr)

1993$ $ $ $ $ $ $ $ $ $ 2,993,796 850,757 12,978,750 16,823,303 10,490,204 7,442,873 34,756,380 1.15 39,969,838 40.99 $ $ $ $ $ $ $ $ $ 258,627 RTC, 1993 $s 98,003 See footnote 10 1,813,479 RTC, 1993 $s 2,170,109 1,408,339 961,849 4,540,296 1.15 5,221,340 52.21 Exponent = 0.11

40.99*(975/MW)^0.11

0.61

0.78 0.61*(975/MW)^0.11 975 100 0.37 0.15 0.111 Formula 0.37 0.15 0.111

Labor ($/yr) Carbon cost ($/yr) Power ($/yr) Disposal ($/yr) Operating materials ($/yr) Overhead (mills/kWh)

$ $ $ $ $

238,464 2,051,664 2,050,797 621,152 521,674

$ $ $ $ $

109,296 208,206 203,834 63,087 79,785

RTC RTC RTC RTC RTC

Labor (mills/kWh) = Carbon (mills/kWh) = Power (mills/kWh) = Disposal (mills/kWh) = Operating matls (mills/kWh) =

0.04 0.37 0.16 0.112 0.09 0.07

0.19 Given below

0.14 Given below 0.17 Given below

Labor and operating materials costs (mills/kWh) vary with boiler size;overhead at 60% of labor & maintenance. Hence use: Labor (mills/kWh) = 1.15*12*CF*8760*1000/MW*1000*8760*CF Operating materials (mills/kWh) = (0.09-0.14)/875*(MW-100) + 0.14 Overhead (mills/kWh) = 0.6 [1000/8760*fixed O&M($/kW-Yr) + labor(mills/kWh)]

C-18

Exhibit C7 Hot ESP + SC+ ACI with Subbituminous Coal
Case 2B: Hot ESP + SC+ ACI + FF with subbituminous coal Data from Tables B-10 and B-11, in EPA's RTC [3] Source Size (MW) Capacity factor g carbon / g Hg Hg concentration (g/dscm) Flue gas flowrate (dscm/hr) Carbon ($/kg) $ 975 0.65 6000 10 4050000 0.89 $ 100 RTC 0.65 RTC 6000 Based on published data 10 RTC 411000 RTC 0.89 See footnote 9

Capital Costs: Spray cooling system ($) Carbon injection system ($) Fabric Filter ($) Purchased equipment ($) Installation ($) Indirect ($) Total capital cost ($) Retrofit factor Total capital cost w/ retrofit ($) Capital cost ($/kW) Capital cost ($/kW) = Annual O&M: Maintenance ($/kW-Yr) Maintenance ($/kW-Yr) =

1993$ $ 2,993,796 $ 510,454 $ 12,978,750 $ 16,483,000 $ 10,439,159 $ 7,340,782 $ 34,262,941 1.15 $ 39,402,382 $ 40.41 $ $ $ 258,627 RTC, 1993 $s 58,802 See footnote 10

$ 1,813,479 RTC, 1993 $s $ 2,130,908 $ 1,402,458 $ 950,088 1.15 $ 5,155,972 51.56 Exponent = 0.11 $ 4,483,454

40.41*(975/MW)^0.11

0.61

0.77 0.61*(975/MW)^0.11 975 100 0.22 0.15 0.066 Formula 0.22 0.15 0.067

Labor ($/yr) Carbon cost ($/yr) Power ($/yr) Disposal ($/yr) Operating materials ($/yr) Overhead (mills/kWh)

$

238,464

$ $ $ $ $

109,296 124,924 202,199 37,852 79,785

RTC RTC RTC RTC RTC

Labor (mills/kWh) = Carbon (mills/kWh) = Power (mills/kWh) = Disposal (mills/kWh) = Operating matls (mills/kWh) =

0.04 0.22 0.16 0.067 0.09 0.07

0.19 Given below

$ 1,230,998 $ 2,049,188 $ $ 372,691 521,674

0.14 Given below 0.17 Given below

Labor and operating. materials. costs (mills/kWh) vary with boiler size;overhead at 60% of labor & maintenance. Hence use: Labor (mills/kWh) = 1.15*12*CF*8760*1000/MW*1000*8760*CF Operating materials (mills/kWh) = (0.09-0.14)/875*(MW-100) + 0.14 Overhead (mills/kWh) = 0.6 [1000/8760*fixed O&M($/kW-Yr) + labor(mills/kWh)]

C-19

Exhibit C8 SC+ ACI + FF with Bituminous Coal
Case 5A: SC+ ACI + FF with bituminous coal Using SC + ACI costs from Tables B-10 & B-11 in EPA's RTC [3] Source Size (MW) Capacity factor g carbon / g Hg Hg concentration (g/dscm) Flue gas flowrate (dscm/hr) Carbon ($/kg) $ 975 0.65 10000 10 4050000 0.89 $ 100 RTC 0.65 RTC 10000 Based on published data 10 RTC 411000 RTC 0.89 See footnote 9

Capital Costs: Spray cooling system ($) Carbon injection system ($) Purchased equipment, PE, ($) Installation ($) Indirect ($) Total capital cost ($) Retrofit factor Total capital cost w/ retrofit ($) Total capital cost ($/kW) Capital cost ($/kW) = Annual O&M: Maintenance ($/kW-Yr) Maintenance ($/kW-Yr) =

1993$ $ 2,993,796 $ 850,757 $ 3,844,553 $ 1,145,504 $ 1,602,435 $ 6,592,493 1.15 $ 7,581,367 $ 7.78 $ $ $ $ $ $ $ $ 258,627 RTC, 1993 $s 98,003 See footnote 10 356,630 102,634 145,783 605,047 1.15 695,804 6.96 Exponent = -0.05

7.78*(975/MW)^-0.05

0.12

0.10 0.12*(975/MW)^-0.05 975 100 0.37 0.06 0.111 0.03 Formula 0.37 0.07 0.111 0.04

Labor ($/yr) Carbon cost ($/yr) Power ($/yr) Disposal ($/yr) Operating materials ($/yr) Overhead (mills/kWh)

$ $ $ $

59,616 962,385 621,152 219,572

$ $ $ $ $

49,680 208,206 86,878 63,087 18,968

RTC RTC RTC RTC RTC

Labor (mills/kWh) = Carbon (mills/kWh) = Power (mills/kWh) = Disposal (mills/kWh) = Operating matls (mills/kWh) =

0.01 0.37 0.07 0.112 0.04 0.014

0.09 Given below

$ 2,051,664

0.059 Given below

Labor varies with usage and not with boiler size; overhead at 60% of labor amd maintenance. Hence use: Labor (mills/kWh) = 1.15*12*CF*8760*1000 / MW*1000*8760*CF Overhead (mills/kWh) = 0.6 [1000/8760*fixed O&M($/kW-yr) + labor(mills/kWh)]

C-20

Exhibit C9 SC+ ACI + FF with Subbituminous Coal
Case 5B: SC+ ACI + FF with subbituminous coal Using SC + ACI costs from Tables B-10 & B-11 in EPA's RTC [3] Source Size (MW) Capacity factor g carbon / g Hg Hg concentration (g/dscm) Flue gas flowrate (dscm/hr) Carbon ($/kg) 975 0.65 6000 10 4050000 0.89 100 RTC 0.65 RTC 6000 Based on Published data 10 RTC 411000 RTC 0.89 See footnote 9

Capital Costs: Spray cooling system ($) Carbon injection system ($) Purchased equipment, PE, ($) Installation ($) Indirect ($) Total capital cost ($) Retrofit factor Total capital cost w/ retrofit ($) Total capital cost ($/kW) Capital cost ($/kW) = Annual O&M: Maintenance ($/kW-Yr) Maintenance ($/kW-Yr) = Labor ($/yr) Carbon cost ($/yr) Power ($/yr) Disposal ($/yr) Operating materials ($/yr) Overhead (mills/kWh)

1993$ $ 2,993,796 $ 510,454 $ 258,627 RTC, 1993 $s $ 58,802 See footnote 10 $ 317,429 $ 96,753 $ 134,023 $ 548,205 1.15 $ 630,436 $ 6.30 Exponent = -0.06

$ 3,504,250 $ 1,094,459 $ 1,500,345 $ 6,099,054 1.15 $ 7,013,912 $ 7.19

7.19*(975/MW)^-0.06

0.11

0.09 0.11*(975/MW)^-0.06 975 100 0.22 0.06 0.066 0.03 Formula 0.22 0.07 0.067 0.04

$ $ $ $

59,616 960,776 372,691 219,572

$ $ $ $

49,680 85,243 37,852 18,969

RTC RTC RTC RTC RTC

Labor (mills/kWh) = Carbon (mills/kWh) = Power (mills/kWh) = Disposal (mills/kWh) = Operating matls (mills/kWh) =

0.01 0.22 0.07 0.067 0.04 0.014

0.09 Given below

$ 1,230,998

$ 124,924

0.059 Given below

Labor varies with usage and not with boiler size; overhead at 60% of labor amd maintenance. Hence use: Labor (mills/kWh) = 1.15*12*CF*8760*1000 / MW*1000*8760*CF Overhead (mills/kWh) = 0.6 [1000/8760*fixed O&M($/kW-yr) + labor(mills/kWh)]

C-21

Exhibit C10 DS + ACI + FF with Bituminous Coal
Case 7A: DS + ACI + FF with bituminous coal Taking only ACI costs from Tables B-10 & B-11 in EPA's RTC [3] Source Size (MW) Capacity factor g carbon / g Hg Hg concentration (g/dscm) Flue gas flowrate (dscm/hr) Carbon ($/kg) $ 975 0.65 6000 10 4050000 0.89 $ 100 RTC 0.65 RTC 6000 Based on published data 10 RTC 411000 RTC 0.89 See footnote 9

Capital Costs: Carbon injection system ($) Purchased equipment ($) Installation ($) Indirect ($) Total capital cost ($) Retrofit factor Total capital cost w/ retrofit ($) Capital cost ($/kW) Capital cost ($/kW) = Annual O&M: Maintenance ($/kW-Yr) Maintenance ($/kW-Yr) =

1993$ $ $ $ $ $ $ $ 510,454 510,454 76,568 153,136 740,159 1.15 851,183 0.87 $ $ $ $ $ $ $ 58,802 See footnote 10 58,802 8,820 17,641 85,263 1.15 98,052 0.98 Exponent = 0.05

0.87*(975/MW)^0.05

0.013

0.015 0.013*(975/MW)^0.05 975 100 0.22 0.066 0.00 Formula 0.22 0.00100 0.067 0.00

Labor ($/yr) Carbon cost ($/yr) Power ($/yr) Disposal ($/yr) Operating materials ($/yr) Overhead (mills/kWh)

$ $ $ $

29,808 2,413 372,691 0

$ $ $ $ $

29,808 124,924 2,452 37,852 0

RTC RTC RTC RTC RTC

Labor (mills/kWh) = Carbon (mills/kWh) = Power (mills/kWh) = Disposal (mills/kWh) = Operating matls (mills/kWh) =

0.005 0.22 0.067 0.00 0.004

0.05 Given below

$ 1,230,998

0.00018 0.00182

0.032 Given below

Labor varies with usage and not with boiler size; overhead at 60% of labor and maintenance. Hence use: Labor (mills/kWh) = 1.15*12*CF*8760*1000 / MW*1000*8760*CF Overhead (mills/kWh) = 0.6 [1000/8760*fixed O&M($/kW-yr) + labor(mills/kWh)]

C-22

Exhibit C11 DS + ACI + FF with Subbituminous Coal
Case 7B: DS + ACI + FF with subbituminous coal Taking only ACI costs from Tables B-10 & B-11 in EPA's RTC [3] Source Size (MW) Capacity factor g carbon / g Hg Hg concentration (g/dscm) Flue gas flowrate (dscm/hr) Carbon ($/kg) $ 975 0.65 3000 10 4050000 0.89 $ 100 RTC 0.65 RTC 3000 Based on published data 10 RTC 411000 RTC 0.89 See footnote 9

Capital Costs: Carbon injection system ($) Purchased equipment ($) Installation ($) Indirect ($) Total capital cost ($) Retrofit factor Total capital cost w/ retrofit ($) Capital cost ($/kW) Capital cost ($/kW) = Annual O&M: Maintenance ($/kW-Yr) Maintenance ($/kW-Yr) =

1993$ $ 255,227 $ 255,227 $ $ 38,284 76,568 1.15 $ 425,591 $ 0.44 $ $ $ $ $ $ $ 29,401 See footnote 10 29,401 4,410 8,820 42,631 1.15 49,026 0.49 Exponent = 0.05

$ 370,079

0.44*(975/MW)^0.05

0.007

0.007 0.007*(975/MW)^0.05 975 100 0.11 0.033 0.00 Formula 0.11 0.00050 0.033 0.00

Labor ($/yr) Carbon cost ($/yr) Power ($/yr) Disposal ($/yr) Operating materials ($/yr) Overhead (mills/kWh)

$ $ $

29,808 1,207 0

$ $ $ $ $

29,808 62,462 1,226 18,926 0

RTC RTC RTC RTC RTC

Labor (mills/kWh) = Carbon (mills/kWh) = Power (mills/kWh) = Disposal (mills/kWh) = Operating matls (mills/kWh) =

0.005 0.11 0.034 0.00 0.004

0.05 Given below

$ 615,499 $ 186,346

0.00009 0.00091

0.032 Given below

Labor varies with usage and not with boiler size; overhead at 60% of labor and maintenance. Hence use: Labor (mills/kWh) = 1.15*12*CF*8760*1000 / MW*1000*8760*CF Overhead (mills/kWh) = 0.6 [1000/8760*fixed O&M($/kW-yr) + labor(mills/kWh)]

C-23

Exhibit C12 DS+ ACI + Cold ESP with Bituminous Coal
Case 8A: DS+ ACI + cold ESP with bituminous coal Data for 975 MW from Table B-12 in EPA's Report to Congress [3] Data for 100 MW from Table B-11 in EPA's Report to Congress [3] Source Size (MW) Capacity factor g carbon / g Hg Hg concentration (g/dscm) Flue gas flowrate (dscm/hr) Carbon ($/kg) $ 975 0.65 10000 10 4050000 0.89 $ 100 RTC 0.65 RTC 10000 Based on published data 10 RTC 411000 RTC 0.89 See footnote 9

Capital Costs: Carbon injection system ($) Purchased equipment, PE, ($) Installation ($) Indirect ($) Total capital cost ($) Retrofit factor Total capital cost w/ retrofit ($) Total capital cost ($/kW) Capital cost ($/kW) = Annual O&M: Maintenance ($/kW-Yr) Maintenance ($/kW-Yr) = Labor ($/yr) Carbon cost ($/yr) Power ($/yr) Disposal ($/yr) Operating materials ($/yr) Overhead (mills/kWh)

1993$ $ $ $ $ $ $ $ 850,757 850,757 127,614 255,227 1,233,598 1.15 1,418,638 1.46 $ $ $ $ $ $ $ 98,003 See footnote 10 98,003 14,700 29,401 142,104 1.15 163,420 1.63

.

Exponent = 0.05

1.46*(975/MW)^0.05

0.02

0.02 0.02*(975/MW)^0.05 975 100 0.37 0.111 0.00 Formula 0.37 1.7E-03 0.111 0.00

$ $ $ $ $

29,808 2,051,664 4,022 621,152 0

$ $ $ $ $

29,808 208,206 4,087 63,087 0

RTC RTC RTC RTC RTC

Labor (mills/kWh) = Carbon (mills/kWh) = Power (mills/kWh) = Disposal (mills/kWh) = Operating matls (mills/kWh) =

0.01 0.37 0.112 0.00 0.005

0.05 Given below

3.1E-04 3.0E-03

0.033 Given below

Labor varies with usage (not with boiler size); overhead at 60% of labor & maintenance. Hence use: Labor (mills/kWh) = 1.15*12*CF*8760*1000 / MW*1000*8760*CF Overhead (mills/kWh) = 0.6 [1000/8760*fixed O&M($/kW-Yr) + labor(mills/kWh)] (1993$)

C-24

Exhibit C13 DS+ ACI + Cold ESP with Subbituminous Coal
Case 8B: DS+ ACI + cold ESP with subbituminous coal Data for 975 MW from Table B-12 in EPA's Report to Congress [3] Data for SC+ ACI for 100 MW from Table B-11 in EPA's Report to Congress [3] Source Size (MW) Capacity factor g carbon / g Hg Hg concentration (g/dscm) Flue gas flowrate (dscm/hr) Carbon ($/kg) $ 975 0.65 6000 10 4050000 0.89 $ 100 RTC 0.65 RTC 6000 Based on published data 10 RTC 411000 RTC 0.89 See footnote 9

Capital Costs: Carbon injection system ($) Purchased equipment, PE, ($) Installation ($) Indirect ($) Total capital cost ($) Retrofit factor Total capital cost w/ retrofit ($) Total capital cost ($/kW) Capital cost ($/kW) = Annual O&M: Maintenance ($/kW-Yr) Maintenance ($/kW-Yr) = Labor ($/yr) Carbon cost ($/yr) Power ($/yr) Disposal ($/yr) Operating materials ($/yr) Overhead (mills/kWh)

1993$ $ $ $ $ $ $ $ 510,454 510,454 76,568 153,136 740,159 1.15 851,183 0.87 $ $ $ $ $ $ $ 58,802 See footnote 10 58,802 8,820 17,641 85,263 1.15 98,052 0.98

.

Exponent = 0.05

0.87*(975/MW)^0.05

0.01

0.01 0.01*(975/MW)^0.05 975 100 0.22 0.066 0.00 Formula 0.22 1.0E-03 0.067 0.00

$ $ $ $ $

29,808 1,230,998 2,413 372,691 0

$ $ $ $ $

29,808 124,924 2,452 37,852 0

RTC RTC RTC RTC RTC

Labor (mills/kWh) = Carbon (mills/kWh) = Power (mills/kWh) = Disposal (mills/kWh) = Operating matls (mills/kWh) =

0.01 0.22 0.067 0.00 0.004

0.05 Given below

1.8E-04 1.8E-03

0.032 Given below

Labor varies with usage (not with boiler size); overhead at 60% of labor & maintenance. Hence use: Labor (mills/kWh) = 1.15*12*CF*8760*1000 / MW*1000*8760*CF Overhead (mills/kWh) = 0.6 [1000/8760*fixed O&M($/kW-Yr) + labor(mills/kWh)]

C-25


				
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