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 ensure

compliance, 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). These

technologies 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 simultaneous

measurements 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 during

parametric 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 CaCl2 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 CaCl2 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 0.7

lb/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-phase

SCEM 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 observed

during 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% ACI

mercury 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 of

mercury 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.

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power, 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 CaCl2 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 added

costs for byproduct management and non-hazardous disposal. The severity of these byproduct impacts, however, is

dependent 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 CaCl2 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 impact

due 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 may

lead to additional costs for byproduct management and nonhazardous disposal. With this in mind, Table 3 presents the

20-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 & CaCl2 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 impact

of 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 & CaCl2 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 1369
often 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 during

parametric testing were held constant. The resulting hypothetical parametric datasets were then subjected to the ACI

data adjustment methodology to calculate the 20-year

levelized 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 specific

to 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 ProgramsPreliminary

Economic Analysis of Activated Carbon Injection,” that was

prepared 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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