# DOE/NETL’s Phase II Mercury Control Technology Field Testing Program: Preliminary Economic Analysis of Activated Carbon Injection

ANDREW P. JONES,* JEFFREY W.
HOFFMANN, DENNIS N. SMITH, THOMAS
J. FEELEY, III, AND JAMES T. MURPHY
National Energy Technology Laboratory, 626 Cochrans Mill Road, P.O. Box 10940, Pittsburgh, Pennsylvania 15236



### Based on results of field testing conducted by the U.S. Department of Energy’s National Energy Technology Laboratory (DOE/NETL), this article provides preliminary costs for mercury control via conventional activated carbon injection (ACI), brominated ACI, and conventional ACI coupled with the application of a sorbent enhancement additive (SEA) to coal prior to combustion. The economic analyses are reported on a plant-specific basis in terms of the cost required to achieve low (50%), mid (70%), and high (90%) levels of mercury removal “above and beyond” the baseline mercury removal achieved by existing emission control equipment. In other words, the levels of mercury control are directly attributable to ACI. Mercury control costs

via ACI have been amortized on a current dollar basis. Using a 20-year book life, levelized costs for the incremental increase in cost of electricity (COE), expressed in mills per kilowatt-hour (mills/kWh), and the incremental cost of mercury control, expressed in dollars per pound of mercury removed ($/lb Hg removed), have been calculated for each level of ACI mercury control. For this analysis, the increase in COE varied from 0.14 mills/kWh to 3.92 mills/kWh. Meanwhile, the incremental cost of mercury control ranged from $3810/lb Hg removed to $166 000/lb Hg removed.



## Introduction

The clock is ticking for U.S. coal-fired power plants. On May 18, 2005, the U.S. Environmental Protection Agency (EPA) issued a final regulation for control of mercury emissions from coal-fired power plants ( 1 ). Based on 1999 power plant
emission estimates (2), the cap-and-trade provision of the Clean Air Mercury Rule (CAMR) would reduce mercury emissions by almost 70%, from 48 tons per year (tons/year) to 38 tons/year by 2010 and to 15 tons/year in 2018. To ensurecompliance, coal-fired power plant owners must (1) understand applicable mercury regulations; (2) accurately characterize a given unit’s baseline mercury emissions, in terms of both quantity and chemical composition; and (3) develop an effective mercury control strategy. However, one size does not fit all in regards to controlling mercury from the broad range of coals burned by, and various air pollution control devices (APCD) installed on, today’s coal-fired power plants due to the chemical speciation of mercury exiting the boiler ( 3). Consequently, development of the most cost-effective mercury control plan will require coal-fired power plant owners to closely evaluate results of ongoing pilot- and/or full-scale tests of several promising mercury-specific control technologies. Moreover, for many plant operators, installation of selective catalytic reduction and flue gas desulfurization (FGD) systems under EPA’s Clean Air Interstate Rule may be sufficient to meet the requirements

of CAMR. Recognizing the potential for mercury regulation, the U.S.Department of Energy’s National Energy Technology Laboratory (DOE/NETL) initiated comprehensive mercury research under the DOE Office of Fossil Energy’s Innovations for Existing Plants (IEP) program in the early 1990s to ensure that effective pollution control strategies would be available as needed for the existing fleet of coal-fired utility boilers ( 4 ). The near-term goal is to develop mercury control technologies

that can achieve 50

- 70% mercury capture at costs 25

- 50% less than baseline (1999) estimates of $50 000

- $70 000 per pound of mercury removed ($/lb Hg removed). Thesetechnologies would be available for commercial demonstration by 2007 for all coal ranks. The longer-term goal is to develop advanced mercury control technologies to achieve 90% or greater capture that would be available for commercial demonstration by 2010. In September 2003, DOE/NETL selected eight projects to test and evaluate mercury control technologies under a Phase II, Round 1 (Phase II-1) field testing solicitation. An additional six projects were subsequently awarded in October 2004 under a Phase II, Round 2 solicitation. The Phase II projects focus on longer-term, large-scale field testing on plants burning primarily low-rank coals and equipped with a variety of APCD configurations. To date, activated carbon injection (ACI) has shown the most promise as a near-term mercury control technology. In a typical configuration, powdered activated carbon (PAC) is injected upstream of a particulate control device, either an electrostatic precipitator (ESP) or fabric filter (FF). The PAC adsorbs the mercury from the combustion flue gas and is subsequently captured along with the fly ash in the ESP

or FF. While Phase II field testing is still ongoing, DOE/NETL completed a preliminary economic analysis of mercury

control via ACI based on results obtained at the six coal-fired units listed in Table 1. The control costs, with an estimated accuracy of ( 30%, were derived for conventional ACI, brominated ACI, and conventional ACI coupled with the application of a sorbent enhancement additive (SEA) to coal prior to combustion. The cost estimates are intended to provide DOE/NETL a gauge in measuring its success in achieving the target of reducing baseline mercury control costs by 25

- 50%. Prior to field testing, mercury semi-continuous emission monitors (SCEM) were installed to allow simultaneousmeasurements upstream and downstream of the ACI location. Following baseline testing, parametric tests were

conducted with several candidate PACs to establish the optimal operating conditions for the 30-day long-term continuous ACI trial. Results obtained during each of these ACI field testing demonstrations are summarized below.

Holcomb Station Unit 1. ADA Environmental Solutions (ADA-ES) selected a brominated PAC (DARCO Hg-LH) for the long-term, continuous ACI trial at this 360 megawatt (MW) unit. Prior to parametric tests with DARCO Hg-LH, baseline mercury capture was approximately 37% ( 5). As shown in Figure 1, 75 % total mercury removal was obtained * Corresponding author phone: (412) 386-5531; fax: (412) 386- 4516; e-mail: Andrew.Jones@netl.doe.gov. **Environ. Sci. Technol.** 2007

**, 41,**  **1365**

- **1371**

**10.1021/es0617340 CCC: $37.00**  **2007 American Chemical Society VOL. 41, NO. 4, 2007 / ENVIRONMENTAL SCIENCE & TECHNOLOGY** 9 1365 **Published on Web 01/17/2007**during parametric testing with a DARCO Hg-LH injection concentration of 0.7 pounds per million actual cubic feet (lb/MMacf) of flue gas. An average DARCO Hg-LH injection concentration of 1.2 lb/MMacf yielded 93% total mercury capture during long-term testing.

Meramec Station Unit 2. ADA-ES also selected brominated DARCO Hg-LH for long-term testing at this 140 MW unit. Prior to parametric tests with DARCO Hg-LH, baseline mercury capture was approximately 32% ( 6). As shown in Figure 1, 75% total mercury removal was obtained duringparametric testing with a DARCO Hg-LH injection concentration of 1.5 lb/MMacf. During the 30-day long-term trial, an average DARCO Hg-LH injection concentration of 3.3 lb/ MMacf was required to achieve 93% total mercury removal.

Plant Yates Unit 1. URS Group, Inc. (URS) chose an untreated sorbent (Super HOK) for long-term testing at this 100 MW unit. In contrast to other long-term tests, the Super HOK injection concentration was varied from 0 to 16 lb/ MMacf to assess the impact on ESP outlet particulate emissions. Consequently, Figure 1 displays the baseline mercury capture of approximately 50% observed prior to Super HOK injection ( 7

, 8), and results from the 30-day longterm test where Super HOK injection concentrations of 4.5 lb/MMacf, 6.5 lb/MMacf, and 9.5 lb/MMacf were required to achieve average total mercury removals of approximately 68%, 75%, and 76%, respectively.

Leland Olds Station Unit 1. The University of North Dakota Energy and Environmental Research Center (UNDEERC) evaluated an untreated PAC (DARCO Hg), coupled with SEA (aqueous calcium chloride [CaCl2 ] solution) coal treatment, during long-term testing at this 220 MW unit. Prior to parametric testing, baseline mercury capture was approximately 18% ( 9

, 10). During parametric tests with a DARCO Hg injection concentration of 10 lb/MMacf, total mercury removal increased from 64 to 85% with the addition

of CaCl 2 at a feed rate that is equivalent to adding approximately 500 parts per million (ppm) chlorine to the coal.Based on parametric results shown in Figure 1, the longterm test was conducted with a constant CaCl 2 feed rate (equivalent to
∼ 500 ppm in the coal) and a DARCO Hg injection concentration of 3 lb/MMacf, resulting in 63% total mercury removal.

Stanton Station Unit 10. URS selected the brominated DARCO Hg-LH for long-term testing. Prior to parametric testing, no baseline mercury capture was observed across this 60 MW unit ( 10

, 11 ). As shown in Figure 1, a DARCO Hg-LH injection concentration of 1.5 lb/MMacf achieved 94% total mercury removal during the parametric testing campaign. An average injection concentration of 0.7lb/MMacf yielded 60% total mercury capture during longterm testing.
St. Clair Station Unit 1. Sorbent Technologies Corporation chose their brominated PAC (B-PAC) for long-term testing at this 145 MW unit. Prior to parametric testing, baseline mercury capture was approximately 25% ( 12). As shown in Figure 1, a B-PAC injection concentration of 1 lb/MMacf achieved 78% total mercury removal during parametric testing. During long-term testing, total mercury removal 

### TABLE 1. Description of Phase II Field Test Sites

plant plant owner coal rank APCD configuration date test completed

**Holcomb Station Unit 1 Sunflower Electric subbituminous spray dryer absorber and fabric filter (SDA/FF)**  **August 2004**

**Meramec Station Unit 2 AmerenUE subbituminous cold-side electrostatic precipitator (CS-ESP)**  **November 2004**

**Plant Yates Unit 1 Southern Company bituminous CS-ESP and wet FGD December 2004 Leland Olds Unit 1 Basin Electric Lignite CS-ESP May 2004**  **Stanton Station Unit 10 Great River Energy Lignite SDA/FF July 2004 St. Clair Station Unit 1 Detroit Edison 85% Subbit. / 15% Bit. Blend CS-ESP October 2004** 

FIGURE 1. ACI performance data from phase II field tests.

1366 9 **ENVIRONMENTAL SCIENCE & TECHNOLOGY / VOL. 41, NO. 4, 2007**averaged 94% with an average B-PAC injection concentration

of 3 lb/MMacf.



## Analysis Section

Economic Framework. For this analysis, the quantity of PAC required to achieve a particular level of mercury capture is expressed in terms of pounds of PAC per volume of flue gas (lb/MMacf), rather than per pound of mercury captured (lb/lb). This approach assumes that the percent mercury capture is dependent on flue gas volume and independent of the flue gas mercury concentration. The parametric performance curves displayed in Figure 1, which are based on a few SCEM measurements at discrete ACI concentrations, serve as the foundation for this economic analysis of mercury control via ACI. Since the economics are based on the PAC chosen for extended testing, the selection of these particular curves was dictated by the long-term testing conditions at each of these coal-fired units. Meanwhile, the shape of these curves can be influenced by a number of factors, including (1) coal rank; (2) type of particulate collection device (ESP or FF); and (3) PAC composition (conventional or brominated). In addition, the curvature is dependent on a limited number of vapor-phaseSCEM mercury measurements that have a degree of uncertainty due to the presence of extremely low mercury concentrations in the flue gas, which makes the quality assurance and quality control practices of field contractors extremely important. The ACI performance curves shown in Figure 1 display total mercury removal, which includes the level of baseline mercury capture observed prior to parametric testing and the subsequent reduction in mercury emissions that is attributable to ACI, as a function of ACI concentration. To evaluate the progress of DOE/NETL’s mercury control field testing program and discern the performance of ACI, an ACI data adjustment methodology (see Appendix C, Supporting Information) was developed to account for baseline mercury capture. As a result, economic analyses were completed in a manner that yields the cost required to achieve low (50%), mid (70%), and high (90%) levels of mercury control “above and beyond” the plant-specific baseline mercury removal. In other words, the economics are based on levels of mercury control that are directly attributable to ACI. To determine the percentage of total mercury capture that is attributable to ACI, the parametric performance curves displayed in Figure 1 were adjusted to account for baseline mercury removal observed prior to parametric testing. The baseline-adjusted parametric performance curves were then scaled to conform to the average mercury removal observedduring the 30-day test, because results obtained from longterm testing are thought to be more representative of ACI performance than the short-term parametric results. The resultant ACI datasets were used to develop the final adjusted algorithms that express the percent ACI mercury removal as a function of ACI concentration. These algorithms are represented by the nonlinear regression curves displayed in Figure 2. The adjusted regression curves display the entire range of ACI concentrations evaluated during the parametric testing campaign conducted at each of the Phase II field testing units. The nonlinear algorithms were not used to extrapolate the regression curves beyond the maximum tested ACI concentration. As a result, cost estimates for 90% ACImercury removal were only developed for Holcomb, Meramec, and St. Clair. Annual Operating and Maintenance Costs. The importance of developing accurate nonlinear algorithms cannot be overstated because the adjusted regression curves shown in Figure 2 are used to calculate the quantity of PAC required to achieve a given level of ACI mercury control. Once the required ACI concentration was determined, the annual cost of PAC consumption was calculated using an assumed capacity factor of 80% and the following delivered PAC prices: (1) $0.39 per pound ($/lb) for RWE Rhinebraun’s conventional Super HOK; (2) $0.54/lb for NORIT Americas’conventional DARCO Hg; (3) $0.85/lb for Sorbent Technologies’ brominated B-PAC; and (4) $0.95/lb for NORIT Americas’ brominated DARCO Hg-LH. These prices are considered valid as of August 2005 and include $0.10/lb for transportation

expenses. The annual operating and maintenance (O&M) cost ofmercury control via ACI also includes (1) cost of nonhazardous PAC disposal; (2) ancillary costs including electric FIGURE 2. Adjusted phase II non-linear regression curves.

**VOL. 41, NO. 4, 2007 / ENVIRONMENTAL SCIENCE & TECHNOLOGY** 9 1367power, O&M labor, and spare parts and (3) an annual SEA consumption cost was also calculated using a delivered cost of $0.15/lb for the aqueous CaCl 2 solution used at Leland

Olds. The ACI systems included in this analysis are designed to inject PAC upstream of a particulate control device to enable simultaneous capture of the spent PAC and fly ash. This ACI configuration will result in commingling of the PAC and fly ash that could potentially affect the marketability of the fly ash. Consequently, a parallel economic analysis of mercury

control via ACI was conducted with the inclusion of addedcosts for byproduct management and non-hazardous disposal. The severity of these byproduct impacts, however, isdependent on the APCD configuration employed at the coalfired unit as discussed below. For units equipped with a CS-ESP, it is assumed that the utility is able to sell all fly ash collected in the ESP hoppers for $18 per ton ($/ton) prior to ACI. The byproduct impacts incurred once the utility installs an ACI system for mercury control assume that the fly ash can no longer be sold; instead, the utility must pay $17/ton for non-hazardous fly ash disposal. As a result, total byproduct impacts are based on an estimated value of $35/ton, which includes $18/ton for lost revenue from fly ash sales and $17/ton for non-hazardous fly ash disposal. Prior to the installation of an ACI system, it is assumed that units equipped with an SDA/FF configuration give their byproducts away since the majority of SDA byproducts (i.e., ash and calcium sulfite) are used for low-value applications such as mining reclaim and flowable fill ( 13). After installing an ACI system, it is assumed that the SDA byproduct material can no longer be given away; instead, the utility must pay $17/ton for non-hazardous SDA byproduct disposal. Capital Costs. In addition to annual O&M costs, the total cost of ACI mercury control also includes capital cost required to install a PAC storage and injection system. As part of the DOE/NETL Phase II field testing program, ADA-ES recently completed economic evaluations of ACI mercury control based on results obtained during full-scale field testing at the Holcomb and Meramec Stations ( 5

, 6). These estimates were used to approximate the capital costs required to retrofit similar ACI systems at the other Phase II field testing sites included in this economic analysis. The capital cost estimates include both direct and indirect cost components. The total direct cost (TDC) for the ACI system is calculated as the sum of the following: (1) uninstalled equipment cost; (2) materials and labor associated with site integration; (3) applicable taxes; and (4) installation costs that can vary significantly depending on plant-specific retrofit issues. In addition, an estimated cost of $100 000 is included for installation of an SEA storage and injection system used to add an aqueous CaCl 2 solution to coal during field testing

at Leland Olds. The indirect costs were estimated as percentages of the TDC using the Electric Power Research Institute’s Technical Assessment Guide (TAG) methodology. The total capital requirement (TCR) for the ACI system was calculated with the inclusion of indirect costs and contingencies. However, the cost required to install and calibrate a mercury monitoring system was excluded from this economic analysis since utilities will incur these costs regardless of their mercury control strategy. In addition, capital cost estimates assume an uncomplicated retrofit and minimal economic impactdue to installation of the ACI system, assuming that installation occurs during a regularly scheduled plant outage. Also note that no adjustments were made for interest during construction since it is assumed that the ACI system can be

installed in a few months. For this analysis, the TCR ranges from about $1 270 000 to $1 390 000 showing that ACI equipment cost is relatively insensitive to unit capacity. Capital costs are also commonly expressed as a function of unit capacity. The TCR values expressed as a function of unit capacity range from $3.63 per kilowatt ($/kW) for the 360 MW Holcomb Station Unit 1 to $21.10/kW for the 60 MW Stanton Station Unit 10. However, on a unit capacity basis, the installed capital cost for an ACI system would be less for larger coal-fired units.



## Results

The variable O&M and fixed capital costs were used to calculate ACI mercury control costs on an amortized, current dollar basis. Using a 3% escalation rate and a 20-year book life, levelized costs for the incremental increase in cost of electricity (COE), expressed in mills per kilowatt-hour (mills/ kWh), and the incremental cost of mercury control ($/lb Hg removed) were calculated for each level of ACI mercury control. These levelized cost estimates, which represent the constant level of annual revenue necessary to recover all expenses over the 20-year plant life, are presented in Table 2 without the added costs associated with byproduct management and non-hazardous disposal. As mentioned previously, mercury control via ACI maylead to additional costs for byproduct management and nonhazardous disposal. With this in mind, Table 3 presents the20-year levelized costs of mercury control including byproduct impacts. While the severity of these byproduct impacts cannot be disputed, economic impacts related to byproduct management and disposal resulting from mercury control via ACI are hypothetical and represent a worst-case scenario. The cost of byproduct management and disposal is dependent on the quantity of byproducts (i.e., fly ash, SDA ash, calcium sulfite, etc.) produced by the coal-fired unit. Factors that affect byproduct generation include (1) unit capacity; (2) coal ash content; (3) coal sulfur content; (4) net plant heat rate; and (5) the higher heating value of coal. The annual byproduct impacts range from approximately $579 000
for the 60 MW Stanton Station Unit 10 to $3 240 000 for the

220 MW Leland Olds Unit 1. While both of these units burn lignite coal, the disparity in unit capacity and the assumption of no lost revenue from reuse of SDA byproducts leads to a wide range in byproduct impacts. The following discussion offers insight into factors that influence levelized costs of mercury control via ACI. In 

### TABLE 2. Twenty-Year Levelized Cost of Mercury Control without Byproduct Impacts

ACI Hg removal, % 50% 70% 90%

20-Year levelized costs (current$) COE, mills/kWh $/lb Hg

removed COE, mills/kWh $/lb Hg

removed COE, mills/kWh $/lb Hg

removed

**Holcomb Unit 1 DARCO Hg-LH 0.14 $4220 0.18 $3810 0.37 $6060 St. Clair Unit 1 B-PAC 0.36 $16200 0.48 $15 200 1.06 $26 200**  **Meramec Unit 2 DARCO Hg-LH 0.37 $11800 0.47 $10 800 0.99 $17 700 Stanton Unit 10 DARCO Hg-LH 0.82 $19500 1.02 $17 400**  **Leland Olds Unit 1 DARCO Hg & CaCl 2**  **0.83 $20600 1.25 $22 200 Plant Yates Unit 1 Super HOK 0.97 $54,600 1.72 $69 500** 

1368 9 **ENVIRONMENTAL SCIENCE & TECHNOLOGY / VOL. 41, NO. 4, 2007**particular, economic impacts of PAC cost, baseline mercury capture, and coal mercury content expressed in units of pounds per trillion British thermal unit (lb/TBtu) are explored. Twenty-Year Levelized Incremental Increase in COE. The increase in COE is directly related to the required ACI concentration, and inherently the desired level of mercury control. As shown in Tables 2 and 3, the incremental increase in COE for a particular unit is lowest for 50% ACI mercury removal and highest for 90% ACI mercury removal. Therefore, the increase in COE for each unit will be impacted primarily by the ACI concentration required to achieve a given level of mercury control and PAC composition (conventional or brominated) due to price variability. A sensitivity analysis was conducted to establish a relationship between delivered PAC cost and the 20-year levelized incremental increase in COE. Figure 3 displays the effect of varying brominated PAC cost on the 20-year levelized increase in COE. The brominated PAC cost ranges from $0.40/lb to $2.00/lb, and the oval symbols indicate the delivered costs for B-PAC and DARCO Hg-LH used for this economic analysis. Figure 3 illustrates the linear relationship

that exists between the increase in COE and brominated PAC cost at 70% ACI mercury removal excluding byproduct impacts. The increase in COE for Stanton Station Unit 10 displays the highest degree of sensitivity to changes in brominated PAC cost due to a required DARCO Hg-LH injection concentration of 1.15 lb/MMacf. Conversely, a DARCO Hg-LH injection concentration of 0.27 lb/MMacf is required to achieve 70% ACI mercury removal at Holcomb Station, resulting in the lowest degree of sensitivity to variations in brominated PAC cost. At St. Clair Station, a B-PAC injection concentration of 0.60 lb/MMacf is required to achieve 70% ACI mercury removal, while a DARCO Hg-LH injection concentration of 0.62 lb/MMacf is required to achieve the same level of mercury control at Meramec Station. However, the increase in COE remains slightly higher for St. Clair Station due to a higher full-load flue gas flow rate of approximately 751 000 actual cubic feet per minute (acfm), resulting in a higher annual B-PAC consumption cost. In some instances, PAC consumption costs account for approximately 75% of the total cost of mercury control. As a result, the delivered PAC cost as well as the required ACI concentration are principal factors in determining economics of mercury control via ACI. A similar analysis of the impactof conventional PAC cost (see Figure 5, Supporting Information) revealed that despite the higher cost of brominated PAC, the 20-year levelized incremental increase in COE is more sensitive to changes in conventional PAC cost due to the higher injection concentrations required to achieve a given level of mercury control. 20-Year Levelized Incremental Cost of Mercury Control. The economic analyses were conducted on a plant-specific basis meaning that the economics are dependent on actual power plant operating conditions and coal properties observed during full-scale field testing. In particular, the incremental cost of mercury control is responsive to several, 

### TABLE 3. Twenty-Year Levelized Cost of Mercury Control with Byproduct Impacts

ACI Hg removal, % 50% 70% 90%

20-year levelized costs (current$) COE, mills/kWh $/lb Hg

removed COE, mills/kWh $/lb Hg

removed COE, mills/kWh $/lb Hg

removed

**Holcomb Unit 1 DARCO Hg-LH 0.86 $25 700 0.90 $19 200 1.09 $18 000 St. Clair Unit 1 B-PAC 1.36 $60 100 1.47 $46 600 2.05 $50 600**  **Meramec Unit 2 DARCO Hg-LH 1.75 $56 400 1.85 $42 700 2.37 $42 500 Stanton Unit 10 DARCO Hg-LH 2.57 $61 300 2.77 $47 300**  **Leland Olds Unit 1 DARCO Hg & CaCl 2**  **3.50 $86 900 3.92 $69 600 Plant Yates Unit 1 Super HOK 2.94 $166 000 3.69 $149 000** 

FIGURE 3. Effect on the 20-year levelized COE increase for 70% ACI mercury control without byproduct impacts by varying brominated
PAC cost.

**VOL. 41, NO. 4, 2007 / ENVIRONMENTAL SCIENCE & TECHNOLOGY** 9 1369often competing factors that include the required ACI concentration, plant-specific baseline mercury capture, and coal mercury content (lb/TBtu). For example, the incremental cost on a $/lb Hg removed basis will increase when baseline mercury capture is high or coal mercury content is low, because a smaller quantity of mercury is removed from the flue gas for a given level of control. For this analysis, the incremental cost of mercury control was calculated using the quantity of mercury removed by ACI. This was accomplished by (1) converting coal mercury content to a flue gas mercury flow rate; (2) reducing the flue gas mercury flow rate by a percentage consistent with that unit’s baseline mercury removal; and (3) taking a percentage of the mercury remaining in the system to determine the quantity of mercury removed by ACI for a given level of

control. A sensitivity analysis was conducted to investigate the impact of baseline mercury capture variability on the 20- year levelized incremental cost of 70% ACI mercury removal when byproduct impacts are excluded. To complete this analysis, the level of baseline mercury capture was altered, while the levels of total mercury capture observed duringparametric testing were held constant. The resulting hypothetical parametric datasets were then subjected to the ACI data adjustment methodology to calculate the 20-yearlevelized incremental mercury control cost estimates presented in Figure 4. In addition, the flue gas mercury flow rate, derived from the coal mercury content, was reduced by a percentage consistent with the level of baseline mercury control. This final adjustment ensures that the injected PAC is given credit for removing the appropriate quantity of mercury from the flue gas. The economic estimates presented in Figure 4 correspond to 70% brominated ACI mercury removal. The oval symbols highlight the baseline mercury capture values of 0, 25, 32, and 37% that were used to complete economic analyses for Stanton Station Unit 10, St. Clair Station, Meramec Station, and Holcomb Station, respectively. For each level of baseline mercury capture investigated in this analysis, the incremental cost of mercury control at Stanton Station Unit 10 is highest due to a required DARCO Hg-LH injection concentration of 1.15 lb/MMacf. The shape of the sensitivity curves displayed for St. Clair Station and Meramec Station are very similar; however, the incremental cost of mercury control is higher for St. Clair Station due to lower coal mercury content of 5.66 lb/TBtu. The incremental cost of mercury control for Holcomb Station is lowest and exhibits the smallest degree of sensitivity to changes in the level of baseline mercury capture due to high coal mercury content of 10.36 lb/TBtu and a required DARCO Hg-LH injection concentration of

0.27 lb/MMacf. In general, the sensitivity curves displayed in Figure 4 show the 20-year levelized incremental cost of mercury control rising with increasing levels of baseline mercury capture. A similar trend was observed for 70% conventional ACI mercury control at Plant Yates and Leland Olds (see Figure 9, Supporting Information). This relationship is expected, because the injected PAC is required to remove a smaller quantity of mercury to achieve a given level of mercury control as the baseline mercury capture increases.

Current Status. The preliminary Phase II field testing results are very encouraging, both in terms of the level of mercury removal achieved and the estimated cost of control on a mills/kWh and $/lb Hg removed basis. However, it must be kept in mind that the field tests still represent relatively short-term testing at optimum conditions. While such testing provides a sound basis for evaluating performance and cost,the limited duration of testing does not allow for a comprehensive assessment of several key operational and balance-of-plant issues associated with ACI in general and the use of chemically treated PAC and SEA specifically. These include (1) changes in coal characteristics; (2) changes in load; (3) long-term impact on particulate collection device (ESP or FF); (4) potential for PAC carryover downstream of particulate collection device to trigger New Source Review requirements; (5) corrosion issues; (6) potential off-gassing of bromine compounds; (7) formation of flue gas halides; and (8) leaching from brominated PAC byproducts. It should also be noted that the economic analyses represent “snapshots” in time based on the methodology used, assumptions made, and conditions that were specificto the time when DOE/NETL field testing occurred. Consequently, economics presented in this article are plant- and condition-specific and attempts to use this document as a FIGURE 4. Effect on the 20-year levelized incremental cost of 70% brominated ACI mercury control without byproduct impacts by varying the level of baseline mercury capture

1370 9 **ENVIRONMENTAL SCIENCE & TECHNOLOGY / VOL. 41, NO. 4, 2007**tool to predict the performance of these mercury control technologies at other power plants should be conducted cautiously regardless of similarities in coal rank and APCD configuration. In addition, the economics originate from relatively small datasets in many cases. As a result, the cost of mercury control could vary significantly with the inclusion of additional ACI performance data from current and future DOE/NETL field testing.



## Acknowledgments

We acknowledge ADA-ES, URS Group, UNDEERC, and Sorbent Technologies for their contributions to this analysis. We also thank Sunflower Electric, AmerenUE, Southern Company, Basin Electric, Great River Energy, and Detroit Edison for supplying host sites for the full-scale ACI field

tests.



## Supporting Information Available

The complete report, entitled “DOE/NETL’s Phase II Mercury Control Technology Field Testing Program

s Preliminary Economic Analysis of Activated Carbon Injection,” that wasprepared for DOE/NETL is provided as Supporting Information. This document provides more detail on O&M and capital costs, in addition to various economic and power plant operating assumptions.



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Received for review July 20, 2006. Revised manuscript received November 13, 2006. Accepted December 5, 2006.

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