July 2008 1 

An Update on DOE/NETL’s Mercury Control Technology 

Field Testing Program 

Thomas J. Feeley, III1 and Andrew P. Jones2

1

U.S. Department of Energy, National Energy Technology Laboratory 

2

Science Applications International Corporation 

The U.S. Department of Energy’s National Energy Technology Laboratory (NETL), 

under the Office of Fossil Energy’s Innovations for Existing Plants (IEP) Program, 

manages the premier mercury (Hg) research and development (R&D) program for coalfired power generation facilities in the world. Working collaboratively with the U.S. 

Environmental Protection Agency (EPA), the Electric Power Research Institute (EPRI), 

power plant operators, state and local agencies, and a host of research organizations 

and academic institutions, the IEP Program has identified the major factors that affect 

Hg speciation and capture in coal combustion flue gas and funneled this knowledge into 

the development of a suite of Hg-specific control technologies for the diverse fleet of U.S. 

coal-fired power plants. The high performance observed during many of these field tests 

has given coal-fired power plant operators the confidence to begin deploying technology. 

As of April 2008, over 44 gigawatts (GW) of coal-based electric generating capacity have 

placed orders for full-scale activated carbon injection (ACI) systems. 

BACKGROUND 

Since first being identified for potential regulation in the 1990 Clean Air Act 

Amendments, there has been concern within the industry whether it would be possible to 

develop cost-effective emission control technologies for Hg because of its low 

concentration and reactivity during coal combustion. However, while technical issues 

remain, the U.S. Department of Energy’s NETL has been successful, through publicprivate partnerships, in significantly improving both the cost and performance of Hg 

control technology. 

NETL initiated comprehensive Hg research under the Office of Fossil Energy’s IEP 

Program in the early 1990s to ensure that cost-effective and reliable pollution control 

technologies are available for the existing fleet of coal-fired utility boilers.1 To 

comprehensively address the life-cycle of Hg released during coal combustion, NETL has 

directed over $80 million in Federal funding over the last decade toward external 

(extramural) and in-house research projects focusing on six inter-related research areas 

(see Figure 1): 

• Emissions characterization; 

• Development and testing of total and speciated measurement devices; 

• Speciation research; 

• Development and testing of control technologies; 
July 2008 2 

• Coal utilization by-products (CUB) characterization; and 

• Fate and transport of emissions. 

Figure 1 – Overview of Hg R&D Conducted under NETL’s IEP Program 

Emissions characterization performed by NETL and others in the early 1990s showed 

that Hg was not effectively captured across existing air pollution control device (APCD) 

configurations. Further conclusions were limited by the lack of a reliable method to 

measure the different chemical forms of Hg in coal combustion flue gas. To overcome 

this hurdle, NETL co-funded the development and validation of the Ontario Hydro (OH) 

method through a Jointly Sponsored Research Program with the University of North 

Dakota’s Energy and Environmental Research Center (UNDEERC). 

Analysis of OH method sampling campaigns revealed that the trace amount of Hg present 

in coal is volatilized during combustion and converted to gaseous elemental mercury 

(Hg0

). Subsequent cooling of the coal combustion flue gas and interaction of the gaseous 

Hg0

 with other flue gas constituents, such as chlorine (Cl) and unburned carbon (UBC), 

result in a portion of the Hg0 being converted to gaseous oxidized forms of mercury 

(Hg2+) and particulate-bound mercury (HgP). As a result, coal combustion flue gas 

contains varying percentages of HgP

, Hg2+, and Hg0 and the exact speciation has a 

profound effect on the Hg capture efficiency of existing APCD configurations, which has 

been found to range from 0 to over 90%.2

 The HgP fraction is typically removed by a 

particulate control device such as an electrostatic precipitator (ESP) or fabric filter (FF). 

The Hg2+ portion is water-soluble and therefore a relatively high percent can be captured 

in wet flue gas desulfurization (FGD) systems, while the Hg0

 fraction is generally not 

captured by existing APCD. 

DOE/NETL’s Hg R&D

* ORD (In-house R&D) 

 - CUB characterization 

 - Control technology R&D 

* Technology transfer 

* Economic analyses 

* Regulatory analysis 

Emissions Research 

* HAP characterization 

 stack testing 

CUB Research 

* Fate characterization 

* Impact of controls 

Speciation Research 

* OH sampling campaigns 

* Co-benefit enhancements 

Fate & Transport 

* Wet deposition monitoring

* Stack plume measurements 

Control Technology R&D

* Bench- & pilot-scale tests 

* Full-scale field tests 

Measurement R&D 

* OH method 

* SCEMs 
July 2008 3 

Insight into the factors that influence Hg speciation and capture in coal combustion flue 

gas allowed NETL to focus its R&D efforts on the most promising technologies for 

controlling Hg emissions from coal-based power systems. One obvious cost-effective 

strategy for power plants that have or plan to install FGD would be to take advantage of 

the “co-benefit” capture of Hg. However, wet scrubbers do not achieve 100% capture of 

Hg2+, nor as noted above is all the Hg in an oxidized form, even for bituminous coal. 

Moreover, this approach is not a viable Hg control option for power generation facilities 

not equipped with FGD systems. As such, NETL initiated an R&D program in the mid1990s directed at two general approaches for controlling Hg -- (1) Hg-specific control 

technology such as sorbent injection and (2) Hg0 oxidation concepts. 

In 2000, following laboratory through pilot-scale development of these technology 

approaches, NETL launched a three-phase field testing program. This program called for 

the installation and full-scale and slip-stream testing of the most promising Hg control 

technologies at operating coal-fired power plants. The initial field testing (Phase I) 

focused on untreated ACI and improving the capture of Hg across wet FGD systems, 

while Phase II, which began in 2003, was expanded to include testing of chemicallytreated ACI, sorbent (i.e., activated carbon) enhancement additives, and Hg0

 oxidation 

catalysts. The goal of Phases I and II was to develop Hg control technologies (available 

for commercial demonstration by year-end 2007 for all coal ranks) that could achieve 50 

to 70% Hg capture at costs 25 to 50% less than the baseline (1999) estimate of about 

$60,000 per pound of Hg removed ($/lb Hg removed). Phase III of the field testing 

program was initiated in 2006 and directed at continued field testing of advanced Hg 

control technologies that could achieve 90% or greater capture at a 50 to 75% cost 

reduction and that would be available for commercial demonstration by 2010. In addition, 

the Phase III field testing emphasized the assessment of potential balance-of-plant 

impacts associated with continuously operating a Hg-specific control technology. 

This paper focuses on results from the Phase II Hg control technology field testing 

program with the data segregated by technology. In addition, the results of NETL’s 

economic analysis of Hg control via ACI are presented, along with a discussion of 

potential coal utilization by-product (CUB) impacts. Preliminary results from NETL’s 

Phase III Hg field testing program are also presented. 

Field Testing of Advanced Mercury Control Technologies

Building on promising advances from the Phase I field testing program, NETL selected 

eight new full-scale projects in September 2003 to test and evaluate Hg control 

technologies under a Phase II, Round 1 (Phase II-1) field testing solicitation. The Phase 

II-1 projects shown in Table 1 were initiated in 2004 and completed in 2007. An 

additional six projects – representing seven technologiesa

 - were subsequently awarded in 

October 2004 under a Phase II, Round 2 (Phase II-2) solicitation that were also 

 

a

 The seven Phase II-2 Hg control technologies are: TOXECONTM, TOXECONTM II, high-temperature Hg 

sorbents, brominated PAC injection, chemically-treated PAC injection via the Mer-CureTM process, wet 

FGD chemical additives, and an integrated approach to Hg control that includes combustion modifications. 
July 2008 4 

completed in 2007 (Table 2). Total funding for the Phase II program was about $45 

million with the various research teams providing nearly $13 million in cost sharing. 

 

The Phase II projects focus on longer-term (~ 1 month at optimized conditions), largescale field testing on plants burning primarily low-rank coals or blends (with some units 

burning bituminous coal) and equipped with a variety of APCD configurations. Most of 

the 14 projects fall under two general categories of Hg control – sorbent injection or 

oxidation enhancements. Sorbent injection generically describes conventional (untreated) 

ACI, chemically-treated ACI, or the injection of non-carbon sorbents into the flue gas for 

Hg control. Mercury oxidation enhancements are intended to improve the Hg capture 

efficiency of conventional ACI or downstream APCD by converting Hg0

 to a more 

reactive oxidized state. For instance, coal or flue gas additives are being investigated both 

alone, and in conjunction with conventional ACI. Additional Hg control technologies are 

being tested to enhance Hg capture at coal-fired units equipped with wet FGD systems. 

These FGD-related technologies include coal and flue gas chemical additives and fixedbed catalysts to increase levels of Hg2+ in the combustion flue gas, and wet FGD 

chemical additives to promote Hg capture and prevent re-emission of Hg0 from the FGD 

absorber vessel. 
July 2008 5 

Table 1 -- NETL’s Phase II-1 Field Testing Projects 

Project Title Lead 

Company Test Location Coal Rank APCD Configuration 

Sunflower Electric’s 

Holcomb Unit 1 PRB SDA/FF 

AmerenUE’s Meramec Unit 2 PRB CS-ESP (320 SCA) 

Missouri Basin Power 

Project’s Laramie River Unit 3 PRB SDA & 

CS-ESP (599 SCA) 

DTE Energy’s 

Monroe Unit 4 

PRB/Bit. 

Blend 

SCR & 

CS-ESP (258 SCA) 

American Electric Power’s 

Conesville Unit 6 

High-Sulfur 

Bituminous 

CS-ESP (301 SCA) 

& Wet FGD 

Evaluation of 

Sorbent Injection 

for Mercury 

Control 

ADA-ES 

AmerenUE’s Labadie Unit 2 PRB CS-ESP (279 SCA) 

Southern Company’s 

Plant Yates Unit 1 

Low-Sulfur 

Bituminous 

CS-ESP (173 SCA) 

& Wet FGD 

Southern Company’s 

Plant Yates Unit 2 

Low-Sulfur 

Bituminous CS-ESP (144 SCA) 

Sorbent Injection 

for Small ESP 

Mercury Control 

URS Group 

Reliant Energy’s 

Shawville Unit 3 

Mid-Sulfur 

Bituminous 

Two CS-ESPs 

(82 & 230 SCA) 

Basin Electric’s 

Leland Olds Unit 1 ND Lignite CS-ESP (320 SCA) 

Great River Energy’s 

Stanton Unit 10 ND Lignite SDA/FF 

Basin Electric’s 

Antelope Valley Unit 1 ND Lignite SDA/FF 

Great River Energy’s 

Stanton Unit 1 PRB CS-ESP (470 SCA) 

Enhancing 

Carbon 

Reactivity in 

Mercury Control 

in Lignite-Fired 

Systems 

UNDEERC 

Montana-Dakota Utilities Co. 

Lewis & Clark Station ND Lignite 

Mechanical 

Collector & Wet 

Venturi Scrubber 

DTE Energy’s 

St. Clair Unit 1 

PRB/Bit. 

Blend CS-ESP (SCA 467) Advanced Utility 

Mercury Sorbent 

Field-Testing 

Program 

Sorbent 

Technologies Duke Energy’s 

Buck Unit 6 

Low-Sulfur 

Bituminous HS-ESP (240 SCA) 

Demonstration 

of Amended 

Silicates for 

Mercury Control 

Amended 

Silicates 

Duke Energy’s 

Miami Fort Unit 6 

Mid-Sulfur 

Bituminous CS-ESP (353 SCA) 

Luminant Power’s 

Monticello Unit 3 

TX 

Lignite/PRB 

blend 

CS-ESP (452 SCA) 

& Wet FGD 

Pilot Testing of 

Mercury 

Oxidation 

Catalysts for 

Upstream of Wet 

FGD Systems 

URS Group 

Southern Company’s 

Plant Yates Unit 1 

Low-Sulfur 

Bituminous 

CS-ESP (173 SCA) 

& Wet FGD 

Great River Energy’s 

Stanton Unit 10 ND Lignite SDA/FF Evaluation of MerCAPTM for 

Power Plant 

Mercury Control 

URS Group Southern Company’s 

Plant Yates Unit 1 

Low-Sulfur 

Bituminous 

CS-ESP (173 SCA) 

& Wet FGD 

Minnkota Power’s 

Milton R. Young Unit 2 ND Lignite CS-ESP (375 SCA) & Wet FGD 

Mercury 

Oxidation 

Upstream of an 

ESP and Wet 

FGD 

UNDEERC 

Luminant Power’s 

Monticello Unit 3 

TX 

Lignite/PRB 

blend 

CS-ESP (452 SCA) 

& Wet FGD 
July 2008 6 

Table 2 -- NETL’s Phase II-2 Field Testing Projects 

Project Title Lead 

Company Test Location Coal Rank APCD Configuration 

Field Testing of 

Activated Carbon 

Injection Options for 

Mercury Control 

UNDEERC Luminant Power’s 

Big Brown Unit 2 

TX Lignite/PRB 

Blend 

CS-ESP (162 SCA) 

& COHPAC® FF 

PacifiCorp’s 

Dave Johnston Unit 3 PRB CS-ESP (600 SCA) 

Basin Electric’s 

Leland Olds Unit 1 ND Lignite CS-ESP (320 SCA) 

Field Demonstration 

of Enhanced Sorbent 

Injection for Mercury 

Control 

ALSTOMPPL 

Reliant Energy’s 

Portland Unit 1 

Mid-Sulfur 

Bituminous CS-ESP (284 SCA) 

Entergy’s 

Independence Unit 1 PRB CS-ESP (542 SCA) 

MidAmerican’s 

Louisa Unit 1 PRB HS-ESP (459 SCA) 

Low Cost Options for 

Moderate Levels of 

Mercury Control 

ADA-ES 

MidAmerican’s 

Council Bluffs Unit 2 PRB HS-ESP (224 SCA) 

Progress Energy’s 

Lee Unit 1 

Low-Sulfur 

Bituminous CS-ESP (300 SCA) 

Midwestern 

Generation’s 

Crawford Unit 7 

PRB CS-ESP (112 SCA) 

Brominated Sorbents 

for Small Cold-Side 

ESPs, Hot-Side ESPs, 

and Fly Ash use in 

Concrete 

Sorbent 

Technologies 

Midwestern 

Generation’s 

Will County Unit 3 

PRB HS-ESP (233 SCA) 

Luminant Power’s 

Monticello Unit 3 

TX Lignite/PRB 

blend 

CS-ESP (452 SCA) 

& Wet FGD 

Southern Company’s 

Plant Yates Unit 1 

Low-Sulfur 

Bituminous 

CS-ESP (173 SCA) 

& Wet FGD 

Field Testing of a Wet 

FGD Additive for 

Enhanced Mercury 

Control 

URS Group 

Indianapolis Power 

& Light’s 

Petersburg Unit 2 

High-Sulfur 

Bituminous 

CS-ESP (430 SCA) 

& Wet FGD 

Demonstration of 

Integrated Approach to 

Mercury Control 

GE-EER Progress Energy’s 

Lee Unit 3 

Low-Sulfur 

Bituminous CS-ESP (300 SCA) 

The intent of NETL's Phase I and II Hg control technology field testing programs was to 

work with industry to evaluate the most promising Hg control technologies at full-scale 

in a variety of configurations. Although 30-day long-term tests were conducted in Phase 

II, the test period was not sufficient to answer many fundamental questions about longterm consistency of Hg removal and reliability of the system when integrated with plant 

processes. As the technologies move towards commercial implementation, it is critical to 

accurately define the Hg removal performance and costs so that power companies and 

policy makers can make informed decisions. NETL awarded nine new projects in 2006 to 

conduct Hg control tests at full-scale coal-fired units and in the laboratory, under a Phase 

III Hg control solicitation. Table 3 presents general information about each of the Phase 

III projects selected by NETL. Total funding for the Phase III program was just over $27 

million with the various research teams providing nearly $9 million in cost sharing. 

Building on advances from the Phase I and II mercury projects, Phase III has four topic 

areas. 
July 2008 7 

3⁄4 Topic Area I – Phase III Field Testing of Mercury Control Technology Capable 

of Achieving 90% or Greater Removal of Mercury 

3⁄4 Topic Area II – Additional (Round 3) Phase II Field Testing of Mercury Control 

Technology Capable of Achieving 50-70% Mercury Removal 

3⁄4 Topic Area III – Novel Combustion and Post-Combustion Control Technologies 

3⁄4 Topic Area IV – Novel Pre-combustion Control Technology 

Table 3 -- NETL’s Phase III Mercury Control Technology Projects 

Project Title Lead 

Company Test Location Coal Rank APCD Configuration 

TTTooopppiiicccAAArrreeeaaa IIIPPPrrrooojjjeeeccctttsss

Demonstration of MerCureTM Technology ALSTOMPPL Lower Colorado River 

Authority’s Fayette Unit 3 PRB Blends CS-ESP (640 SCA) 

& Wet FGD 

Kansas City Power & 

Light’s Hawthorne Unit 5 PRB SCR & SDA/FF Long-Term Demonstration of SEA 

Technology for 

Mercury Control 

UNDEERC E.ON America’s 

Mill Creek Unit 4 

High-Sulfur 

Bituminous 

SCR, CS-ESP (232 

SCA) & Wet FGD 

Full-Scale Field Trial 

of the Low 

Temperature Mercury 

Capture Process 

CONSOL 

Energy TBD TBD TBD 

Long-Term ACI Field 

Test for >90% 

Mercury Removal 

ADA-ES Rocky Mountain Power’s 

Hardin Station PRB SDA/FF 

TTTooopppiiicccAAArrreeeaaa IIIIIIPPPrrrooojjjeeeccctttsss

Full-Scale Testing of 

Mercury Oxidation 

Catalyst 

URS 

Group 

LCRA’s 

Fayette Unit 3 PRB Blends CS-ESP (640 SCA) & Wet FGD 

Mercury Control for 

Plants Firing Texas 

Lignite and Equipped 

with ESP-Wet FGD 

URS 

Group 

NRG Texas Power LLC’s 

Limestone Station Unit 1 

TX 

Lignite/PRB 

blend 

CS-ESP (452 SCA) 

& Wet FGD 

Evaluation of Mercury 

Control Strategies on a 

Cyclone Boiler with 

SCR 

ADA-ES 

Public Service of New 

Hampshire Company’s 

Merrimack Unit 2 

Mid-Sulfur 

Bituminous 

SCR & (2) CS-ESPs 

in series (120 & 230 

SCAs) 

TTTooopppiiicccAAArrreeeaaa IIIIIIIIIPPPrrrooojjjeeecccttt

Utilization of Partially 

Gasified Coal for 

Mercury Removal 

GE-EER Boiler Simulator Facility Multiple Multiple 

TTTooopppiiicccAAArrreeeaaa IIIVVVPPPrrrooojjjeeecccttt

Pilot Testing of WRI’s 

Novel Mercury 

Control Technology 

WRI WRI & UNDEERC’s PTC Multiple Multiple 

The following is a discussion of results obtained during NETL’s Phase II Hg control 

technology field testing program. While multiple Hg control technologies were explored 

at many of the Phase II field testing sites, the results are grouped by the technology 
July 2008 8 

selected for evaluation during the 30-day extended tests. In addition, preliminary results 

from the Phase III field testing sites are presented. 

 

Elemental Hg Oxidation Enhancements 

Oxidation of flue gas Hg0

 followed by absorption of Hg2+ across a wet FGD system has 

the potential to be a reliable and cost-effective Hg control strategy for coal-fired power 

plants. To optimize Hg capture across FGD systems, NETL is funding the development 

of technologies that promote Hg0 oxidation in coal combustion flue gas: retrofit Hg0

oxidation catalysts and chemical additives. The impact of combustion modifications, such 

as coal reburn, on flue gas Hg0 oxidation has also been examined under the IEP 

Program.3 In addition, NETL field tested FGD additives designed to suppress Hg0 reemissions across the scrubber. 

Combustion Modifications

General Electric Energy and Environmental Research Corporation (GE EER) evaluated a 

novel multi-pollutant control technology to reduce Hg, NOx, and carbon monoxide 

emissions, while simultaneously improving plant efficiency and reliability, at Progress 

Energy’s bituminous coal-fired Lee Station Unit 3 that is equipped with a CS-ESP and 

SO3 flue gas conditioning (FGC) system.4

 The primary objective of this Phase II project 

was to achieve at least 70% incremental Hg capture via: (1) combustion modifications 

designed to enhance “co-benefit” Hg capture by fly ash; (2) duct humidification to reduce 

ESP temperature; and (3) ACI upstream of the ESP for polishing control. Preliminary 

results indicate a 38% improvement in “co-benefit” Hg capture following combustion 

optimization activities. Meanwhile, untreated ACI at about 18 lb/MMacf achieved 80% 

total Hg removal with SO3 conditioning idled, but the removal efficiency was limited to 

approximately 55% with the operation of SO3 FGC. 

Elemental Hg Oxidation Catalysts

URS Corporation (URS), in collaboration with EPRI, Great River Energy (GRE), City 

Public Service (CPS) of San Antonio, and the North Dakota Industrial Commission, 

conducted pilot-scale testing of Hg0

 oxidation catalysts at GRE’s North Dakota (ND) 

lignite-fired Coal Creek Station (CCS) and CPS of San Antonio’s J.K. Spruce Plant, 

which burns PRB coal. CCS is equipped with a wet FGD system downstream of a CSESP, while Spruce is equipped with a wet FGD downstream of a reverse-gas FF. Pilot 

catalyst skids installed at both plants were loaded with a palladium (Pd#1) catalyst, a 

selective catalytic reduction (SCR) catalyst, and an experimental activated carbon (C#6) 

catalyst. In addition, a subbituminous ash-based (SBA#5) catalyst was installed at CCS, 

while a gold (Au) catalyst was evaluated at Spruce. In a full-scale application, the fixedbed catalysts would be installed downstream of an ESP or FF, to: (1) minimize fly ash 

deposition on the catalysts; (2) prevent or minimize catalyst erosion; and (3) ensure a low 

flue gas temperature and flow rate, which reduces the catalyst space velocity and 

minimizes the length of catalyst required. 

High levels of baseline Hg2+ downstream of the FF at Spruce made it difficult to evaluate 

the Hg0

 oxidation catalysts. Final catalyst activity measurements, conducted at CCS in 

June 2004, showed 79% Hg0 oxidation across the C#6 catalyst, with nearly 13 months of 
July 2008 9 

operation, and about 67% oxidation across the Pd#1 catalyst after more than 20 months 

of operation.5 Significantly lower activity was measured for the SCR and SBA#5 

catalysts. In an attempt to extend the effective life of the catalysts, in-situ thermal catalyst 

regeneration tests were performed. Following thermal regeneration, Hg0

 oxidation across 

the Pd#1 catalyst increased from 67 to 88% (near the 95% activity of the fresh catalyst), 

while the C#6 catalyst showed no improvement. It is important to note that these “proof 

of concept” tests were conducted simply to determine if the catalysts could be thermally 

regenerated, and conditions were not adjusted to optimize thermal regeneration. 

Meanwhile, 79% total Hg capture was observed across the pilot-scale wet limestone 

forced oxidation (LSFO) FGD, with 84% Hg2+ at the FGD inlet. 

URS has completed pilot-scale testing of Hg0

 oxidation catalysts at Luminant Power’s 

Monticello Steam Electric Station (MoSES) Unit 3, which fires a blend of Texas (TX) 

lignite and PRB coals.6

 In January 2005, four Hg0 oxidation catalysts were installed 

downstream of the CS-ESP: (1) Au; (2) SCR; (3) regenerated Pd#1 from CCS; and (4) 

fresh Pd#1. During catalyst inspection, URS observed severe fly ash buildup on the 

catalyst surfaces, likely caused by frequent pilot unit outages during the test campaign. 

Following in-situ catalyst cleaning in August 2006, Hg0

 oxidation was approximately 

72% across the regenerated Pd#1 catalyst and 66% across the Au catalyst, after 17 

months of pilot-scale operation. Tests completed in April 2005 indicated total Hg capture 

across a pilot-scale wet FGD ranged from 76 to 87%, compared to only 36% removal 

under baseline conditions. This equates to about 70% incremental Hg capture due to the 

catalysts. 

URS has also completed pilot-scale testing of the catalytic Hg oxidation technology at 

Southern Company’s Plant Yates Unit 1, which fires a low-sulfur Eastern bituminous 

coal. The pilot catalyst skid, installed downstream of a CS-ESP, was loaded with fresh 

Pd#1 and Au catalysts in December 2005, along with regenerated SCR and Au catalysts 

from J.K. Spruce. After nearly 11 months of operation, Hg0 oxidation measured 58% 

across the fresh Au catalyst, 38% across the fresh Pd#1 catalyst, 32% across the 

regenerated SCR catalyst, and 26% across the regenerated Au catalyst. The pilot catalyst 

skid was taken off-line in January 2007 to accommodate an SO3 injection test plan. 

Under a Phase III award, URS began a full-scale field test of a gold-based Hg0

 oxidation 

catalyst at Lower Colorado River Authority’s Fayette Power Project Unit 3 in May 2008. 

The test is intended to confirm the required catalyst quantities and catalyst life for 

achieving an average of 70% or greater Hg0

 oxidation in PRB flue gases over a two-year 

period. The project represents the next logical advancement of the catalytic oxidation 

technology from its current pilot-scale. It will answer technical questions such as the 

catalyst quantity required to achieve high Hg oxidation percentages, catalyst life, the 

efficiency of catalytically-oxidized Hg capture in full-scale wet FGD systems, and the 

ability to keep the catalysts clean of fly ash buildup at full-scale with sonic horns. 

 

Chemical Additives

NETL is funding Phase II field tests of chemical additives designed to promote flue gas 

Hg0 oxidation and enhance FGD Hg capture.7 The additives, collectively referred to as 
July 2008 10 

sorbent enhancement additives (SEA) by UNDEERC and as oxidation additives (OA) by 

URS, are sprayed onto the coal as an aqueous salt solution. This approach maximizes the 

residence time available for interactions with Hg0. Full-scale field testing of this 

technology has been completed at Minnkota Power Cooperative’s Milton R. Young 

(MRY) Unit 2 and Luminant Power’s MoSES Unit 3. 

MRY Unit 2 fires ND lignite coal in a cyclone boiler and is equipped with a CS-ESP and 

wet FGD. UNDEERC evaluated three additives during short-term parametric tests: 

SEA1, calcium chloride (CaCl2); SEA2, a proprietary chemical formulation; and 

magnesium chloride (MgCl2). SEA2 yielded the best results, achieving approximately 

44% total Hg capture across the ESP/FGD combination with injection at 75 ppm (on a 

dry coal basis), as compared to less than 20% Hg capture with SEA1 and MgCl2 injection 

at 500 ppm. About 60% total Hg capture was observed with SEA2 injection at 50 ppm 

(on a dry coal basis), coupled with DARCO® Hg (an untreated PAC developed by 

NORIT Americas, Inc.) injection at 1 lb/MMacf. During the 30-day long-term test, total 

Hg capture across the ESP/FGD configuration ranged from 50 to 65% with SEA2 

injection at 60-100 ppm (on a dry coal basis) and DARCO® Hg injection at 0.15 

lb/MMacf. 

During parametric testing at MoSES Unit 3, URS evaluated the performance of OA1 

(CaCl2) and OA2 (calcium bromide - CaBr2). These trials clearly displayed the superior 

performance of CaBr2 as 72% Hg2+ was observed at the ESP outlet with an injection rate 

of 100 ppm Br in the coal (on a dry basis). As a result, long-term testing was conducted 

with CaBr2. The two-week test, at a CaBr2 injection rate equivalent to 55 ppm Br in the 

coal, oxidized 67% of the Hg entering the FGD, resulting in an average total Hg capture 

of 65%. At a CaBr2 injection rate equivalent to 113 ppm Br in the coal, Hg0 oxidation 

reached 85%, resulting in an average total Hg capture of 86% over the subsequent twoweek test. In addition, a short-term test conducted with a CaBr2 injection rate equivalent 

to 330 ppm Br in the coal resulted in 92% total Hg capture across the ESP/FGD 

configuration. 

Addressing Hg Re-emissions across FGD Systems 

Originally thought to be a sampling artifact, Hg0 re-emissions have been observed at 

several coal-fired units and occur when Hg2+ captured by a wet FGD is chemicallyreduced within the vessel and re-emitted as Hg0

. Through funding provided by NETL, 

URS is conducting bench-scale testing to determine the mechanisms and kinetics of the 

aqueous reactions of Hg absorbed by wet FGD systems, and to develop a kinetics model 

that predicts Hg reduction and re-emission reactions in wet FGD systems over a wide 

range of chemical conditions.8 The underlying hypothesis of this project is that Hg reemission reactions (apparently driven by SO2-derived "sulfite" species in the liquid 

phase) are limited by kinetics rather than equilibrium. Results indicate that low FGD 

chloride concentrations can slow Hg2+ reduction, while high chloride concentrations may 

completely inhibit the sulfur reactions, preventing Hg2+ reduction within the FGD vessel. 

Moreover, results show that the rate of Hg2+ reduction increases by a factor of about 10 

as the pH decreases from 5 to 6 down to about pH 3, in the presence of chloride. These 
July 2008 11 

results suggest that Hg0

 re-emissions in full-scale wet FGD systems could be greatly 

influenced by factors such as chloride concentration and slurry droplet pH. 

A chemical kinetics model has been developed to describe the aqueous Hg reactions in 

FGD systems. The model predicts the basic trends seen experimentally for pH, sulfite, 

thiosulfate, and chloride effects, and provides fairly good numerical agreement with 

experimental data. The model is currently being verified through a series of bench-scale 

wet FGD tests using simulated flue gas to determine if it accurately predicts the tendency 

for Hg0

 re-emissions, and the phase in which Hg is found in the FGD by-products. 

Preliminary results indicate that mercuric mono-chlorosulfite (ClHgSO3

-

) is a key species 

since the rate constant for decomposition of ClHgSO3

- to Hg0

 is much smaller than that 

for the mercuric sulfite complex, thus contributing to the inhibiting effect of chloride on 

Hg0

 re-emissions. In addition, thiosulfate appears to inhibit Hg0 re-emissions at low pH, 

but accelerate this phenomenon at high pH. The validated model will be run over a wide 

range of potential wet FGD operating conditions with and without the use of FGD 

additives to determine conditions that: (1) optimize FGD Hg capture; and (2) influence 

the phase in which Hg leaves in the FGD by-products. 

Wet FGD Additives

URS also conducted pilot- and full-scale field tests of a wet FGD additive, Degussa 

Corporation’s TMT-15, to determine whether the additive can precipitate absorbed Hg as 

a stable salt, thereby minimizing Hg0 re-emissions and lowering FGD liquor Hg 

concentrations.9

 This project is also assessing whether this same additive can be used to 

minimize Hg in reused FGD solid by-products, through separation of the fine Hgcontaining salts from the remainder of the byproduct. The project included pilot-scale 

testing at MoSES Unit 3 and Plant Yates Unit 1. Full-scale field tests have been 

completed at Indianapolis Power & Light’s Petersburg Station Unit 2, which fires highsulfur bituminous coal, and Plant Yates. 

The effectiveness of Degussa Corporation’s TMT-15 additive in suppressing Hg0 reemissions was inconclusive at pilot-scale due to: (1) the absence of re-emissions, even 

without chemical addition, at Monticello Station; and (2) Hg measurement issues at 

Southern Company’s bituminous-fired Plant Yates. However, TMT-15 had the 

anticipated impact on FGD by-products as the FGD liquor Hg concentrations were 

significantly reduced during both tests. During a full-scale field test at Indianapolis 

Power & Light’s Petersburg Station, which burns high-sulfur bituminous coal, a modest 

decline in Hg0

 emissions was observed during an eight-day TMT-15 injection test, but the 

additive did not impact the partitioning of Hg in FGD by-products at this site. 

Meanwhile, full-scale results obtained during a 30-day evaluation of Nalco Company’s 

8034 additive at Plant Yates were confounded by low baseline Hg0

 re-emission levels. 

A third wet FGD additive, Babcock & Wilcox’s Absorption Plus(Hg)TM, was evaluated at 

E.ON America’s high-sulfur bituminous-fired Mill Creek Station after parametric trials 

revealed that untreated ACI had little, if any, impact on Hg removal.10 During long-term 

testing, total Hg removal averaged about 92% with the addition of Absorption 
July 2008 12 

Plus(Hg)TM. Note that over 80% total Hg removal was observed under baseline 

conditions. 

Sorbent Injection 

NETL’s Phase II portfolio of full-scale field testing projects encompass several variations 

of sorbent injection technology: untreated ACI, untreated ACI with chemical additives, 

chemically-treated ACI, EPRI’s TOXECONTM configuration, TOXECON IITM, as well 

as non-carbon and “concrete-friendly” PAC sorbents. The development, and subsequent 

field testing, of chemically-treated ACI and chemical additives, in conjunction with 

untreated ACI, represents a concerted effort to enhance Hg capture at units firing lowrank coal after Phase I results at the PRB-fired Pleasant Prairie Unit 2 showed total Hg 

removal via untreated ACI was limited to about 65%.11 These advanced Hg-specific 

control technologies are designed to introduce excess halogens into the Cl-deficient flue 

gas emitted from low-rank coals to promote Hg0

 oxidation and adsorption. Meanwhile, 

minimizing the impact of ACI on fly ash utilization is the driving force behind Phase II 

field testing of the TOXECONTM configurations and non-carbon/“concrete-friendly” 

sorbent injection. 

Untreated PAC

In addition to serving as a benchmark during nearly all of NETL’s Phase II full-scale 

field tests, untreated ACI has also been evaluated during two 30-day long-term tests. At 

Plant Yates Unit 1, URS selected RWE Rhinebraun’s Super HOK sorbent and total Hg 

capture varied from 50 to 86% with injection rates ranging from 4.5 to 9.5 lb/MMacf.12

Plant Yates was selected for long-term testing, in part, to gain a better understanding of 

the effect of ACI on small-SCA ESP (173 SCA) and wet FGD operation. URS observed 

an increase in the ESP arcing rate during continuous ACI, particularly at high load. While 

the 30-day long-term injection test caused no visible physical damage to the ESP, it 

remains unclear what effect the increased arcing rate will have on ESP performance over 

longer time periods. 

ADA-ES chose DARCO® Hg for the 30-day long-term test conducted at DTE Energy’s 

Monroe Station Unit 4, which burns a 60% PRB and 40% bituminous coal blend and is 

equipped with an SCR and CS-ESP.13 Total Hg removal averaged 78% with DARCO®

Hg injection at 4.9 lb/MMacf. The performance of untreated DARCO® Hg during select 

Phase I and II full-scale field tests is presented in Figure 2. 
July 2008 13 

Figure 2 – Phase I and II Performance Curves for Untreated ACI 

Chemically-Treated PAC

The limited Hg removal achieved by untreated ACI at Pleasant Prairie spurred the 

development and full-scale field testing of alternatives, such as PAC chemically-treated 

with bromine. Two brominated PACs – NORIT Americas’ DARCO® Hg-LH and 

Sorbent Technologies’ B-PACTM - have consistently been top performers at Phase II field 

testing units burning lower-rank coals. In fact, the outstanding performance (see Figure 3) 

of these brominated sorbents has accelerated the commercialization of Hg-specific 

controls technologies and drastically reduced the estimated cost of Hg control due to a 

reduction in the ACI rate required to achieve a given level of control, which offsets the 

higher cost of these sorbents. 

ADA-ES selected brominated DARCO® Hg-LH for 30-day long-term field tests at two 

PRB-fired units: Sunflower Electric’s Holcomb Station Unit 1 and AmerenUE’s 

Meramec Station Unit 2. At Meramec, 93% average total Hg removal was achieved 

across the CS-ESP with DARCO® Hg-LH injection at 3.3 lb/MMacf.14 Total Hg capture 

averaged 93% across the spray dryer absorber and fabric filter (SDA/FF) configuration at 

Holcomb with DARCO® Hg-LH injection at 1.2 lb/MMacf.15 UNDEERC also conducted 

a 30-day evaluation of DARCO® Hg-LH at GRE’s ND lignite-fired Stanton Station Unit 

10. With DARCO® Hg-LH injection at 0.7 lb/MMacf, total Hg capture across the 

SDA/FF configuration averaged 59%.16 However, greater than 90% Hg capture was 

achieved at this unit during parametric trials with both DARCO® Hg-LH and B-PACTM 

injection at 1.5 lb/MMacf. 

ACI Concentration (lb/MMacf)

Mercury Removal (%)

0

20

40

60

80

100

0 5 10 15 20

Brayton Point (Bit/ESP)

Pleasant Prairie (PRB/ESP)

Leland Olds (ND Lignite/ESP)

Monroe (60:40 PRB-Bit blend/ESP)

E.C. Gaston (Bit/FF)

Holcomb (PRB/FF)

Antelope Valley (ND Lignite/FF)

Big Brown (70:30 TX Lignite-PRB blend/FF)

* All data generated using NORIT Americas’ DARCO® Hg 

ACI Concentration (lb/MMacf)

Mercury Removal (%)

0

20

40

60

80

100

0 5 10 15 20

Brayton Point (Bit/ESP)

Pleasant Prairie (PRB/ESP)

Leland Olds (ND Lignite/ESP)

Monroe (60:40 PRB-Bit blend/ESP)

E.C. Gaston (Bit/FF)

Holcomb (PRB/FF)

Antelope Valley (ND Lignite/FF)

Big Brown (70:30 TX Lignite-PRB blend/FF)

* All data generated using NORIT Americas’ DARCO® Hg 
July 2008 14 

The brominated B-PACTM sorbent has also been selected for 30-day long-term trials at 

three of NETL’s Phase II field testing sites. At GRE’s PRB-fired Stanton Station Unit 1, 

URS observed 85% average total Hg removal across the CS-ESP with B-PACTM injection 

at 1.7 lb/MMacf.17 Sorbent Technologies conducted long-term field tests with B-PACTM 

at DTE Energy’s St. Clair Station Unit 1, which burns an 85% PRB and 15% bituminous 

coal blend, and Progress Energy’s bituminous-fired Lee Station Unit 1. At St. Clair, 94% 

average total Hg removal was achieved across the CS-ESP with B-PACTM injection at 3 

lb/MMacf.18 Total Hg capture averaged 85% across the CS-ESP at Lee with B-PACTM 

injection at 8 lb/MMacf.17 Note that the 30-day long-term test at Lee was conducted with 

the SO3 FGC system idled and opacity levels remained acceptable. 

ADA-ES is conducting Phase III testing at Rocky Mountain Power’s PRB-fired Hardin 

Generating Station to evaluate the Hg removal performance, long-term emissions 

variability, and associated operating and maintenance costs of PAC injection for greater 

than 90% Hg control during a ten- to twelve-month full-scale demonstration. Baseline Hg 

capture at Hardin ranged from 20 to 30% across the SCR and SDA/FF configuration.19

During parametric testing, an injection rate of about 1 lb/MMacf was required to attain 

slightly more than 90% total Hg removal with DARCO® Hg-LH and Calgon Carbon’s 

brominated FLUEPACTM-MC Plus. In addition, injection of a DARCO® Hg and 

FLUEPACTM-MC Plus mixture achieved 90% total Hg at 0.14 lb/MMacf, with a low 

KNXTM additive rate. The long-term test began in September 2007 and will continue 

through August 2008 using DARCO® Hg-LH. At low load (80 to 90 MW), a DARCO®

Hg-LH injection rate of 1.5 lb/MMacf is required to maintain 90% removal compared to 

3.0 lb/MMacf at 120 MW. This is likely due the high fraction of Hg2+ produced at low 

load (up to 50%) that is captured in the SDA. 

URS conducted Phase III field testing at NRG Texas Power LLC’s Limestone Electric 

Generating Station Unit 1, which fires a 70:30 blend of TX lignite and PRB coals and is 

equipped with a CS-ESP and wet FGD. Baseline Hg removal was highly variable ranging 

from about 5 to 50%. Since this unit markets its fly ash for reuse, two Hg control 

technologies designed to preserve ash quality were evaluated during parametric tests: 

low-ash impact sorbent injection and TOXECON IITM.20 During injection upstream of the 

ESP, the brominated B-PACTM and DARCO® Hg-LH sorbents performed similarly with 

about 90% ACI Hg removal at 2 to 3 lb/MMacf. Untreated DARCO® Hg also achieved 

90% ACI Hg removal with injection at slightly less than 6 lb/MMacf. Injection of the 

“concrete-friendly” C-PACTM sorbent at about 1.5 lb/MMacf resulted in approximately 

73% ACI Hg removal. During parametric trials with the TOXECON IITM configuration, 

ACI Hg removal was limited to about 60% with DARCO® Hg and DARCO® Hg-LH 

injection at about 5 to 6 lb/MMacf. Note that DARCO® Hg-LH injection into the 

TOXECON IITM configuration took place with the unit firing 100% PRB coal. A twomonth continuous injection test was completed with DARCO® Hg-LH injection at 2 

lb/MMacf and preliminary results indicate that the project goal of 50 to 70% ACI Hg 

removal across the ESP was achieved. In addition, URS is confident that the low 

DARCO® Hg-LH injection rate will not prohibit fly ash reuse, but analysis is ongoing. 
July 2008 15 

Another chemically-treated ACI technology, ALSTOM Power, Inc. – U.S. Power Plant 

Laboratories’ (ALSTOM-PPL) Mer-CureTM process, is unique in that injection takes 

place in the high-temperature region upstream of the air preheater (APH) and the process 

employs a proprietary “processor” to prevent chemically-treated Mer-CleanTM sorbent 

agglomeration and ensure uniform sorbent dispersion.21 Three 30-day long-term field 

tests of Mer-CureTM have been completed at Phase II sites equipped with a CS-ESP: (1) 

PacifiCorp’s PRB-fired Dave Johnston Unit 3; (2) Leland Olds Unit 1; and (3) Reliant 

Energy’s medium-sulfur (2%) bituminous-fired Portland Station Unit 1. Chemicallytreated Mer-CleanTM 8 injection rates of 0.63 and 1.4 lb/MMacf achieved average total 

Hg removals of 92 and 90% at Dave Johnston and Leland Olds, respectively. At Portland, 

about 95% average total Hg capture was observed with chemically-treated Mer-CleanTM 

8-21 injection at 8.5 lb/MMacf. The reduced efficiency of the Mer-CleanTM sorbents at 

Portland may have been caused by elevated levels of flue gas SO3, resulting from the 

combustion of medium-sulfur bituminous coal. 

A Phase III evaluation of Mer-CureTM was completed at LCRA’s Fayette Unit 3 in April 

2007.22 Baseline Hg capture was approximately 50% across the CS-ESP and wet FGD. 

Note that all results are based on the incremental (or ACI) level of Hg control. ALSTOMPPL evaluated three sorbents (eSorbTM 11, eSorbTM 13, and eSorbTM 18) designed to 

preserve fly ash quality, along with Mer-CleanTM 8, during parametric testing. Excluding 

eSorbTM 18, 80% ACI Hg capture was achieved with injection at 0.4 to 0.5 lb/MMacf. At 

an injection at about 0.8 lb/MMacf, eSorbTM 11 and Mer-CleanTM 8 attained 90% ACI Hg 

capture. Preliminary results indicate that fly ash remains marketable with eSorbTM 13 at 

about 0.5 lb/MMacf (85% ACI Hg capture). The testing program was halted prematurely 

due to an unscheduled plant outage. 

Figure 3 – Phase II Performance Curves for Chemically-treated ACI 

ACI Concentration (lb/MMacf)

Mercury Removal (%)

0

20

40

60

80

100

0369

Dave Johnston - PRB/ESP (Mer-Clean 8)

Meramec - PRB/ESP (DARCO Hg-LH)

Stanton 1 - PRB/ESP (B-PAC)

Holcomb - PRB/FF (DARCO Hg-LH)

Leland Olds - ND Lignite/ESP (Mer-Clean 8)

Stanton 10 - ND Lignite/FF (DARCO Hg-LH)

St Clair - 85:15 PRB-Bit blend/ESP (B-PAC)

Portland - Bit/ESP (Mer-Clean 8-21)

Lee - Bit/ESP (B-PAC)

ACI Concentration (lb/MMacf)

Mercury Removal (%)

0

20

40

60

80

100

0369

Dave Johnston - PRB/ESP (Mer-Clean 8)

Meramec - PRB/ESP (DARCO Hg-LH)

Stanton 1 - PRB/ESP (B-PAC)

Holcomb - PRB/FF (DARCO Hg-LH)

Leland Olds - ND Lignite/ESP (Mer-Clean 8)

Stanton 10 - ND Lignite/FF (DARCO Hg-LH)

St Clair - 85:15 PRB-Bit blend/ESP (B-PAC)

Portland - Bit/ESP (Mer-Clean 8-21)

Lee - Bit/ESP (B-PAC)
July 2008 16 

SO3 Impacts 

NETL Hg control R&D has shown that flue gas SO3, even at low concentrations, can 

interfere with the performance of ACI. SO3 is generated in coal combustion flue gas via 

three mechanisms: (1) oxidation of SO2 within the furnace; (2) further oxidation of SO2

across SCR catalysts; and (3) SO3 FGC systems. It appears that SO3 competes with Hg 

for adsorption sites on the PAC surface thereby limiting its performance and/or requiring 

much higher ACI rates to achieve a given level of Hg control (see Figure 4).23 

Figure 4 - Impact of SO3 on ACI Performance

During Phase II field testing at AEP’s high-sulfur (3-4%) bituminous-fired Conesville 

Station Unit 6, ADA-ES evaluated over 50 candidate sorbents and total Hg removal was 

limited to approximately 30% with chemically-treated PAC injection at 12 lb/MMacf.24

Consequently, a 30-day long-term field test was not conducted at this unit; instead, NETL 

funding was used to evaluate the impact of SO3 FGC on brominated DARCO® Hg-LH at 

AmerenUE’s PRB-fired Labadie Station.25 As shown in Figure 4, turning the SO3 FGC 

system off at Labadie increased total Hg removal from about 50 to 80% with DARCO®

Hg-LH injection at 8 lb/MMacf. In addition, greater than 90% Hg removal was observed 

with no SO3 injection and DARCO® Hg-LH injection upstream of the APH at about 5 

lb/MMacf. The performance of brominated B-PACTM was also impacted by SO3 FGC at 

Lee Station. With B-PACTM injection at 8 lb/MMacf, Hg capture increased from 32 to 

82% when SO3 FGC was idled at Lee. One possible solution to this problem is the dual 

injection of PAC and alkaline materials. Preliminary results from a few Phase II and III 

field testing sites are encouraging. Mercury Removal (%)

ACI Concentration (lb/MMacf)

0

20

40

60

80

100

0 5 10 15 20

Lee (B-PAC/15 ppm SO3)

Labadie (DARCO Hg-LH/10.3 ppm SO3)

Conesville Unit 6 (DARCO Hg)

Lee (H-PAC/Hot-side/15 ppm SO3)

Labadie (DARCO Hg-LH/Hot-side/10.3 ppm SO3)

Lee (B-PAC/No SO3)

Labadie (DARCO Hg-LH/No SO3)

Labadie (DARCO Hg-LH/Hot-side/No SO3)

Mercury Removal (%)

ACI Concentration (lb/MMacf)

0

20

40

60

80

100

0 5 10 15 20

Lee (B-PAC/15 ppm SO3)

Labadie (DARCO Hg-LH/10.3 ppm SO3)

Conesville Unit 6 (DARCO Hg)

Lee (H-PAC/Hot-side/15 ppm SO3)

Labadie (DARCO Hg-LH/Hot-side/10.3 ppm SO3)

Lee (B-PAC/No SO3)

Labadie (DARCO Hg-LH/No SO3)

Labadie (DARCO Hg-LH/Hot-side/No SO3)
July 2008 17 

ADA-ES is conducting a Phase III field test at Public Service of New Hampshire 

Company’s Merrimack Station Unit 2, which utilizes a cyclone-fired boiler to burn a 

blend of bituminous coals (1.0 - 1.3% sulfur content) and is equipped with an SCR 

system followed by two CS-ESPs in series.26 This is a challenging environment for ACI 

due to elevated SO3 levels and high flue gas temperature. During parametric testing, 

several Hg sorbents were evaluated both with and without the injection of magnesium 

oxide (MgO) or sodium sesquicarbonate (trona) – two potential SO3 mitigation additives 

that also permit a reduction in flue gas temperature. Results indicate that trona injection 

enhanced ACI performance to a greater degree than MgO; however, the sodium content 

of trona may limit fly ash recycling opportunities. 

Without SO3 mitigation, Hg removal was limited to about 22% with brominated 

DARCO® Hg-LH injection between the two ESPs at 8 lb/MMacf. Untreated DARCO®

Hg injection at 8 lb/MMacf, coupled with trona injection, resulted in about 65% Hg 

removal. During a continuous injection test completed in March 2008, 50% Hg removal 

was achieved with trona injection upstream of the APH at 500 lb/hr and DARCO® HgLH injection between the two ESPs at about 4 lb/MMacf. 

Conventional PAC with Chemical Additives

As an alternative to using chemically-treated PAC, NETL also has sponsored field tests 

using conventional PAC supplemented with chemical additives applied to the coal and/or 

flue gas to overcome the poor performance of conventional PAC in low-rank coal 

applications. Through funding provided by NETL, UNDEERC conducted two 30-day 

long-term field tests at full-scale units firing ND lignite coal to determine whether SEA 

coal treatment enhances the performance of untreated ACI at units burning lower-rank 

coals.16 Indeed, SEA coal treatment improved the Hg capture efficiency of untreated ACI 

at both of these Phase II field testing sites. During the 30-day trial at Basin Electric’s 

Leland Olds Station Unit 1, 58% average total Hg capture was observed across the CSESP with DARCO® Hg injection at 2.7 lb/MMacf, coupled with the addition of an 

aqueous CaCl2 solution to the ND lignite coal at a rate of 2.9 lb/MMacf. UNDEERC also 

evaluated this advanced Hg-specific control technology at Basin Electric’s Antelope 

Valley Station Unit 1. Total Hg removal averaged 92% across the SDA/FF configuration 

with the addition of SEA2 to the ND lignite coal at a rate of 0.033 lb/MMacf and 

DARCO® Hg injection at 0.81 lb/MMacf. 

UNDEERC conducted additional Phase II Hg control field testing at Montana-Dakota 

Utilities Company’s Montana lignite-fired Lewis & Clark Station that is equipped with a 

mechanical collector and wet venturi scrubber. Parametric tests evaluated the Hg capture 

efficiency of SEA1 and SEA2 addition to the coal with and without ACI upstream of the 

wet venturi scrubber.27 With SEA1 injection at 600 ppm coal equivalent, about 90% Hg 

removal is achieved with untreated DARCO® Hg injection at 3 lb/MMacf. Slight 

improvements in performance were observed with higher SEA1 and DARCO® Hg 

injection rates. Ninety percent Hg removal was also observed with SEA2 injection at 100 

ppm coal equivalent and DARCO® Hg injection at 1 lb/MMacf. Note that in the absence 

of PAC injection, Hg removal was limited to about 55% with SEA2 injection at 100 ppm 
July 2008 18 

coal equivalent. A one-week, optimized field test was also conducted, but results are 

currently unavailable. 

Under a Phase III award, UNDEERC is evaluating PAC and SEA injection, as well as, 

the SEA2 technique 2 (SEA2 T2) technology, which involves co-injection of the 

proprietary SEA2 additive and PAC upstream of the particulate control device. Full-scale 

field testing is currently on-going at Kansas City Power & Light's Hawthorn Unit 5 that 

burns PRB coal and is equipped with an SCR and SDA/FF configuration. During 

parametric testing at Hawthorne, greater than 90% total Hg capture was achieved with 

SEA1 added to the coal at 1200 ppm and DARCO® Hg-LH injection at 3 lb/MMacf.28

With the SEA2 T2 technology, the co-injection of DARCO® Hg at 2.8 lb/MMacf and 

SEA2 at 0.14 lb/lb of PAC, resulted in about 85% total Hg removal. In addition, >90% 

Hg removal was achieved with SEA1 added to the coal at ~500 ppm and DARCO® Hg 

injection at 2 lb/MMacf. A 45-day long-term is scheduled for Hawthorne where 

UNDEERC will further evaluate SEA1 addition to the coal, coupled with untreated 

DARCO® Hg injection upstream of the ESP. 

 

ACI Upstream of a Hot-Side ESP

NETL is also evaluating Hg control technologies designed specifically for hot-side ESP 

(HS-ESP) applications, where the elevated flue gas temperature limits the Hg capture 

efficiency of ACI. A four-day trial conducted at Duke Energy’s low-sulfur bituminous 

coal-fired Buck Plant achieved approximately 70% total Hg removal with the injection of 

Sorbent Technologies’ chemically-treated H-PACTM at 10 lb/MMacf.18 Sorbent 

Technologies conducted additional field testing at Midwestern Generation’s PRB-fired 

Will County Unit 3. A high temperature version of the brominated, “concrete-friendly” 

C-PACTM sorbent was evaluated since fly ash from this unit is marketed for reuse. Using 

a newly developed X-a-Lance distributing lance design, 73% Hg removal was achieved 

during a parametric trial with C-PACTM injection at 5 lb/MMacf.29 During a six-day 

continuous test, Hg removal ranged from about 60 to 73% with C-PACTM injection at 5 

lb/MMacf. 

Under a separate Phase II project, ADA-ES evaluated the impact of adding hightemperature liquid sorbents to the pre-combusted coal and/or upstream of the HS-ESP on 

Hg control at MidAmerican’s PRB-fired Louisa Station Unit 1.30 While Alstom’s 

brominated KNXTM coal additive promoted Hg0 oxidation, the lack of a downstream 

FGD at this unit led to no increase in Hg removal. 

Alternative Sorbent Injection Technologies

The typical ACI system is located upstream of a particulate control device to enable 

simultaneous capture of the spent PAC and fly ash. This Hg control strategy leads to 

commingling of the PAC and fly ash that can prohibit certain fly ash recycling efforts. In 

particular, fly ash collected at coal-fired units that employ sorbent injection for Hg 

control is banned from serving as a feedstock at cement kilns following a December 2006 

final rule issued by EPA.31 Note that this ruling is based on the potential for increased Hg 

emissions at cement kilns rather than carbon contamination concerns. In 2006, over 4 
July 2008 19 

million tons of fly ash served as alternative feedstock to shale or clay at about 34 U.S. 

cement kilns.32 

Meanwhile, one of the highest-value reuse applications for fly ash is use as a substitute 

for Portland cement in concrete production. The utilization of fly ash in concrete 

production is particularly sensitive to carbon content as well as the surface area of the 

carbon present in the fly ash. PAC injection will increase the carbon content of the fly ash 

with the degree of carbon contamination dependent upon the ACI concentration required 

to achieve a given level of Hg control. In addition, PAC has a high surface area that is 

ideal for Hg capture, but also promotes the adsorption of surfactants known as air 

entraining admixtures (AEA) that are added to the concrete slurries to stabilize an 

optimum amount of air in the concrete product, thus improving its workability and 

durability to freeze-thaw cycles.33,34 The adsorption of AEA by the injected PAC will 

lead to an increased Foam Index value, which refers to the quantity of AEA required to 

saturate the fly ash and cement mixture, resulting in an inferior concrete product. 

Furthermore, the association of fly ash with Hg capture may influence marketability 

simply due to a perceived connection with the hazards of Hg. As a result, NETL’s Phase 

II Hg control technology field testing program includes evaluations of alternative sorbent 

injection technologies designed to minimize, or completely eliminate, fly ash carbon 

contamination caused by ACI upstream of a particulate control device. 

 

TOXECONTM Configuration

Based on the promising Phase I results at E.C. Gaston (see Figure 5), TOXECONTM was 

selected for a first-of-a-kind commercial Hg control technology demonstration at 

WeEnergies’ Presque Isle Power Plant in Marquette, Michigan, under DOE’s Clean Coal 

Power Initiative. Currently operational, the TOXECONTM configuration has achieved 

about 90% total Hg removal with untreated DARCO® Hg and brominated DARCO® HgLH injection at about 1.7 and 1.2 lb/MMacf, respectively.35 During an extended testing 

period, greater than 90% total Hg removal was maintained for 48 consecutive days with 

both DARCO® Hg and DARCO® Hg-LH injection. 

Under the Phase II program, NETL has also funded a full-scale field test of the 

TOXECONTM configuration at Luminant Energy’s Big Brown Unit 2, which fires a 70% 

TX lignite and 30% PRB coal blend.36 UNDEERC evaluated the performance of 

untreated ACI, co-injection of SEA and untreated PAC, and UNDEERC’s proprietary 

enhanced PAC during parametric tests. Due to concerns about the cumulative impact of 

SEA and PAC injection on differential pressure across the relatively small FF (air-tocloth ratio of 12:1), UNDEERC’s enhanced PAC was selected for the 30-day long-term 

demonstration and total Hg capture average about 74% with an injection rate of 1.5 

lb/MMacf. 

According to an in-depth BOP analysis performed by UNDEERC, enhanced PAC 

injection at 1.5 lb/MMacf increased the pressure drop across the FF at Big Brown by 

about 1” H2O at high load (~600 MW). Handling and storage issues with the PAC/ash 

mixture have also been observed at both Presque Isle and Big Brown. In particular, a 

portion of the PAC/ash mixture was found to be very hot and smoldering at each unit and 
July 2008 20 

preliminary results indicate that plant personnel will need to monitor and empty the FF 

hoppers on a regular basis to avoid self-heating and ignition of the PAC/ash mixture. 

TOXECON IITM Configuration

EPRI’s TOXECON IITM technology injects sorbents directly into the downstream 

collecting field(s) of an ESP. Since the majority of fly ash (~90%) is collected in the 

upstream ESP fields, only a small portion of the total collected ash contains spent 

sorbent. The technology requires minimal capital investment compared to the 

TOXECONTM configuration, because a retrofit FF is not required. A full-scale 

TOXECON IITM field test was conducted by ADA-ES at Entergy’s PRB-fired 

Independence Station Unit 1.37 The CS-ESP at Independence contains four electric fields 

(542 SCA) and ACI took place between the second and third fields. During a long-term 

field test in November 2005, about 60% average total Hg removal was observed with 

DARCO® Hg-LH injection at 4 to 5 lb/MMacf. While the project goal of 50 to 70% Hg 

capture was attained, ADA-ES felt that performance was limited by the injection lance 

design. During subsequent full-scale field testing at Independence in February 2007, 

DARCO® Hg-LH injection at 5.5 lb/MMacf achieved 90% total Hg removal with ADAES’ new TOXECON IITM lance design. A remaining concern with any Hg control 

strategy involving sorbent injection, particularly the TOXECON IITM technology that 

limits the ESP residence time, is the potential for increased particulate emissions that 

could trigger New Source Review requirements. 

Figure 5 – Phase I and II TOXECONTM Performance Curves 

 

Mercury Removal (%)

ACI Concentration (lb/MMacf)

0

20

40

60

80

100

01234567

Big Brown - 70:30 TX Lignite/PRB blend 

(DARCO Hg)

Big Brown - 70:30 TX Lignite/PRB blend 

(DARCO Hg & SEA4)

Big Brown - 70:30 TX Lignite/PRB blend 

(EERC Enhanced PAC)

Big Brown - PRB (EERC Enhanced PAC)

Presque Isle - PRB (DARCO Hg)

E.C. Gaston - Bituminous (DARCO Hg)

Mercury Removal (%)

ACI Concentration (lb/MMacf)

0

20

40

60

80

100

01234567

Big Brown - 70:30 TX Lignite/PRB blend 

(DARCO Hg)

Big Brown - 70:30 TX Lignite/PRB blend 

(DARCO Hg & SEA4)

Big Brown - 70:30 TX Lignite/PRB blend 

(EERC Enhanced PAC)

Big Brown - PRB (EERC Enhanced PAC)

Presque Isle - PRB (DARCO Hg)

E.C. Gaston - Bituminous (DARCO Hg)
July 2008 21 

Non-carbon & “Concrete-friendly” PAC Sorbents

NETL is funding full-scale field tests of alternative Hg sorbents that would allow coalfired power generators to continue marketing fly ash commingled with the spent sorbent 

as a suitable replacement for Portland cement in concrete. Two approaches are discussed 

below: non-carbon based sorbent injection and injection of PAC that is passivated during 

production to limit AEA adsorption. 

The performance of Amended Silicates’ non-carbon Amended SilicatesTM sorbent 

(comprised of a chemically-amended silicate substrate) was evaluated during a 30-day 

long-term field test at Duke Energy’s medium-sulfur (~2.3%) bituminous-fired Miami 

Fort Unit 6.38 Total Hg capture across the CS-ESP averaged 40% with Amended 

SilicatesTM injection at 5 to 6 lb/MMacf. Once again, flue gas SO3 may have had a 

detrimental effect on sorbent performance at Miami Fort. 

Under a separate Phase II project, Sorbent Technologies conducted a 30-day long-term 

evaluation of their brominated, “concrete-friendly” C-PACTM at Midwestern Generation’s 

PRB-fired Crawford Station Unit 7.39 With C-PACTM injection at about 4.6 lb/MMacf, 

total Hg removal across the small CS-ESP averaged 81%. Most importantly, preliminary 

results indicate that fly ash samples collected during sorbent injection at these units 

would satisfy the criteria used to determine the suitability for reuse in concrete 

production. 

Novel Hg Control Concepts 

Innovative techniques for Hg control that could eventually replace and/or augment the 

more mature technologies discussed above are also being explored under the IEP 

Program. The following is a brief discussion of these NETL-funded efforts. 

MerCAPTM 

The Hg control via adsorption process (MerCAPTM), developed by EPRI, relies on fixed 

structure sorbents positioned in the flue gas stream to adsorb Hg and then, as the sorbent 

becomes saturated, regenerate the sorbent and recover the Hg. An initial retrofit 

application of the MerCAPTM technology is for “polishing” control of Hg0

 downstream of 

FGD systems. During two six-month extended pilot-scale tests, the performance of goldcoated MerCAPTM plates was evaluated downstream of a: (1) spray dryer adsorber and 

fabric filter (SDA/FF) configuration at Great River Energy’s Stanton Station Unit 10; and 

(2) wet FGD system at Plant Yates Unit 1.40

After more than 6,000 hours of continuous operation at Stanton Station, Hg removal 

averaged 30 to 35% across the acid-treated MerCAPTM plates and 10 to 30% across the 

untreated plates. Testing also revealed that regeneration via acid treatment and tighter 

plate spacing (1⁄2-inch vs. 1-inch) improved the Hg capture efficiency of the MerCAPTM 

technology. At Plant Yates, Hg removal decreased from 15 to 3% during the first three 

days of pilot-scale MerCAPTM operation. It was believed that limestone slurry carryover 

from the FGD system was inhibiting Hg reactions. Subsequent use of a water wash 

system for the plates was able to restore Hg removal to 15%. 
July 2008 22 

Utilization of Partially Gasified Coal for Mercury Removal 

GE EER will evaluate the Hg capture efficiency of sorbents produced from coal in an insitu gasification process at coal burning plants. Proposed Phase III work will optimize the 

gasification process to maximize sorbent reactivity while minimizing sorbent production 

costs.41 Optimization will be conducted with respect to coal type, gasification process 

parameters, and the sorbent injection rate required to achieve at least 70% Hg removal. 

Among the gasification process parameters to be optimized are: (1) composition of solid 

fuel/air mixture, (2) temperature, and (3) mixture residence time. GE EER will also 

evaluate the stability of captured Hg and the potential impact on fly ash marketability. 

Low Temperature Mercury Capture Process 

CONSOL Energy, Inc. (CONSOL) will conduct a Phase III field test of the Low 

Temperature Mercury Capture (LTMC) process at a bituminous-fired power plant that is 

equipped with a CS-ESP. LTMC has the ability to reduce Hg emissions by over 90%, as 

was recently shown by CONSOL on a slip-stream pilot plant at Allegheny Power’s 

Mitchell Station. The LTMC process controls Hg by cooling the flue gas temperature to 

about 220°F, which promotes Hg adsorption on the UBC inherent in fly ash. To avoid 

corrosion at the low-temperature conditions, the SO3 concentration will be controlled 

through magnesium hydroxide slurry injection. The project will also demonstrate that 

water spray humidification can maintain ESP performance under low-SO3 conditions. A 

two-month test will be conducted to evaluate long-term performance and any potential 

balance-of-plant impacts. 

Pilot Testing of WRI’s Novel Mercury Control Technology 

Western Research Institute (WRI) will develop and evaluate pre-combustion Hg removal 

of raw coal by thermal treatment.42 Key process steps in the WRI technology include 

treating the fuel at two selected temperature windows. In the first stage, the moisture in 

the fuel is driven-off; in the second stage, coal is heated by nearly inert gas resulting in 

significant removal of coal-bound Hg. Bench-scale testing has revealed that residence 

time is an important parameter for Hg release in some coals - an increase of 8 minutes of 

residence time results in almost 80% of Hg released from coal. The percentage of Hg 

released from the coals varied from 50 to 87% depending on residence time. In addition, 

initial results from a fixed-bed test unit indicate that high temperature sorbents will be 

available to remove Hg from the process recycle sweep gas in the temperature range of 

550 to 600°F. Pilot-scale testing (100 lb/hr) is currently being conducted to assess and 

scale-up results from the bench-scale tests. The pilot unit will examine two different Hg 

removal configurations: a vibratory fluid bed, and a proprietary vertical reactor. 

NETL in-house development of novel control technologies 

After studying numerous sorbents for Hg capture in simulated coal-derived gases, 

scientists at NETL discovered and patented three trace metal capture technologies that are 

now licensed and in commercial demonstration. The Thief process, licensed to NalcoMobotec USA, is a cost-effective alternative to ACI for Hg removal from flue gas as 

Thief carbon sorbents range from $90 to $200 per ton. The Photochemical Oxidation 

(PCO) process, licensed to Powerspan Corporation, introduces a 254-nm ultraviolet light 

into the flue gas, leading to enhanced Hg oxidation and capture. NETL researchers 
July 2008 23 

received the 2005 Award for Excellence in Technology Transfer from the Federal 

Laboratory Consortium (FLC) for the PCO method. 

Recognizing the need for a low-cost technique to remove Hg from coal-based Integrated 

Gasification Combined Cycle power plants, NETL researchers have invented a new

sorbent that works on fuel gas at elevated temperatures. The new sorbent is palladium 

(Pd) on an inert support. Unlike conventional sorbents such as activated carbon, which 

operate at ambient temperature, high temperature Pd sorbents remove Hg and arsenic at 

temperatures above 500°F, and have more than twice the capacity of previously existing 

sorbents, resulting in a major improvement in overall energy efficiency of the power 

combustion process. NETL researchers received the 2008 Award for Excellence in 

Technology Transfer from the FLC for developing the Pd-based Hg sorbents licensed to 

Johnson Matthey. 

 

Economic Analysis of ACI 

NETL published an updated economic analysis of Hg control via ACI at 12 of the Phase 

II ACI field testing sites.43 The May 2007 report provides “study-level”, plant-specific 

cost estimates and was carried out to provide NETL a gauge in measuring its success in 

achieving the target of reducing the baseline (1999) Hg control cost estimate of 

$60,000/lb Hg removed by 25 to 50%. As shown in Figure 6, 20-year levelized cost 

estimates for the incremental cost of Hg control ($/lb Hg removed) were calculated for 

90% ACI Hg removal at seven Phase II field testing sites. Note that chemically-treated 

ACI was the Hg control technology evaluated at each of these units. 

The Phase II field testing results are very encouraging both in terms of the level of Hg 

removal achieved and the estimated cost of control on a 20-year levelized basis. 

Specifically, the economics of Hg control via chemically-treated ACI at units burning 

lower-rank PRB and lignite coals is noteworthy. The 20-year levelized incremental 

increase in cost of electricity (COE) for 90% ACI Hg removal remains below 1.30 mills 

per kilowatt-hour (mills/kWh) for the four PRB units (Holcomb, Meramec, Stanton Unit 

1, and Dave Johnston), as well as the units firing a PRB/bituminous blend (St. Clair), and 

ND lignite (Leland Olds), when CUB impacts are excluded.b

 For comparison, the 

increase in COE calculated for 90% ACI Hg removal at the medium-sulfur bituminousfired Portland Station is over 1.90 mills/kWh, when CUB impacts are excluded. 

Meanwhile, the incremental cost of 90% ACI Hg removal ranges from less than $10,000 

to about $30,000/lb Hg removed, when CUB impacts are excluded. 

The increase in COE resulting from Hg control via ACI is primarily determined by 

annual PAC consumption costs that are dependent on the required ACI rate, delivered 

PAC price, and the volume of flue gas being treated. Chemical composition also affects 

PAC price since manufacturers charge a higher price for chemically-treated PAC to offset 

the additional production costs required to alter the sorbent’s molecular structure. The 

 

b

 As shown in Figure 6, the economic analysis also included an assessment of the potential for ACI to 

negatively impact the sale and disposal of CUB (fly ash) and therefore impact the overall cost of Hg 

control. 
July 2008 24 

ACI rate required to achieve a given level of Hg control can be impacted by a host of 

plant-specific dynamics, including, but not limited to: chlorine and sulfur contents of the 

coal being burned, APCD configuration, flue gas temperature, boiler efficiency, UBC 

content of the fly ash, and ductwork geometry in proximity to the ACI location. The 

impact of PAC manufacturing location on delivered sorbent price has taken on added 

significance following the U.S. Department of Commerce’s decision to impose tariffs, 

ranging from 62 to 228%, on Chinese activated carbon manufacturers.44 The February 26, 

2007 determination responds to concerns that Chinese manufacturers were dumping 

activated carbon at less than the fair U.S. market value. 

Figure 6 – 20-Year Levelized Incremental Cost of 90% ACI Hg Control 

The cost on a $/lb Hg removed basis is impacted largely by the level of “co-benefit” Hg 

capture exhibited by the existing APCD configuration and coal Hg content. For example, 

the incremental cost of Hg control will increase when: (1) “co-benefit” Hg capture is 

high; and/or (2) coal Hg content is low, because a smaller quantity of Hg is removed 

from the flue gas for a given level of control. 

Additional factors can influence the cost of Hg control, including: economic factors 

(labor rate, taxes and contingencies, economic life of capital equipment, etc.), process 

disruptions (unexpected or excessive outages, etc.), proximity to a reliable PAC 

manufacturer, and modifications to existing equipment. The estimates developed here 

assume an uncomplicated retrofit and minimal economic impact due to the installation of 

the ACI system, assuming that the installation occurs during a regularly scheduled plant 

outage. The estimates are also based on the assumption that Hg control via ACI will not 

cause any BOP impacts. In addition, the potential demand for a significant quantity of 

ACI systems within a relatively short timeframe, to ensure nationwide compliance with 

CAMR and the patchwork of state-level regulations, could place a strain on qualified 

$0

$10,000

$20,000

$30,000

$40,000

$50,000

$60,000 with By-product Impactsa

Meramec 

PRB / ESP

DARCO® Hg-LH

Dave Johnston

PRB / ESP

Mer-CleanTM 8

Holcomb

PRB / FF

DARCO® Hg-LH

St. Clair

PRB-Bit blend / ESP

B-PACTM

Incremental Cost of Control, $/lb Hg Removed

a For units equipped with an ESP, by-product impacts include the fly ash disposal cost ($17/ton) and lost revenue from fly ash sales 

($18/ton), assuming 100% utilization. For the SDA/FF configuration, only the cost of SDA by-product disposal ($17/ton) is included.

without By-product Impacts

Leland Olds #1 

Lignite / ESP

Mer-CleanTM 8

Stanton #1

PRB / ESP

B-PACTM

Portland

Bit / ESP

Mer-CleanTM 8-21

DOE Cost target: 

≤ $45,000/lb Hg removed

$0

$10,000

$20,000

$30,000

$40,000

$50,000

$60,000 with By-product Impactsa

Meramec 

PRB / ESP

DARCO® Hg-LH

Dave Johnston

PRB / ESP

Mer-CleanTM 8

Holcomb

PRB / FF

DARCO® Hg-LH

St. Clair

PRB-Bit blend / ESP

B-PACTM

Incremental Cost of Control, $/lb Hg Removed

a For units equipped with an ESP, by-product impacts include the fly ash disposal cost ($17/ton) and lost revenue from fly ash sales 

($18/ton), assuming 100% utilization. For the SDA/FF configuration, only the cost of SDA by-product disposal ($17/ton) is included.

without By-product Impacts

Leland Olds #1 

Lignite / ESP

Mer-CleanTM 8

Stanton #1

PRB / ESP

B-PACTM

Portland

Bit / ESP

Mer-CleanTM 8-21

DOE Cost target: 

≤ $45,000/lb Hg removed
July 2008 25 

engineers, skilled laborers, and the raw materials required to erect both retrofit and new 

PAC storage and injection systems. 

Technology Commercialization 

Although the Federal regulatory structure for Hg emissions from coal-fired power plants 

is once again uncertain following the vacatur of EPA’s Clean Air Mercury Rule on 

February 8, 2008,45 NETL’s field testing program has successfully brought Hg control 

technologies to the point of commercial-deployment readiness. As of April 2008, nearly 

90 full-scale ACI systems, a signature technology of the IEP Program, have been ordered 

by U.S. coal-fired power generators.46 These contracts represent over 44 gigawatts (GW) 

of coal-fired electric generating capacity. This includes approximately 33 GW of existing 

capacity (~10% of total U.S. coal-fired capacity) that will be retrofit with ACI systems to 

control Hg emissions. The ACI systems have the potential to remove more than 90% of 

the Hg in most applications, at a cost that can dip below $10,000/lb Hg removed. 

Although the results achieved during NETL’s field tests met or exceeded program goals, 

site-specific Hg characterization and testing may be required to evaluate alternative 

methods and their Hg capture efficiency on individual power plant generating units.

COAL UTILIZATION BY-PRODUCTS R&D PROGRAM 

In addition to developing cost-effective control technologies for coal-fired power 

generation facilities, NETL’s Hg research also focuses on CUB characterization.47 CUB 

research is in response to the transfer of Hg and other trace metals from flue gas to the 

solid and liquid effluent streams as a result of implementing pollution controls on coalbased power systems, and driven by the goal of increasing the overall beneficial use of 

CUB. At least partly attributable to NETL’s research efforts, CUB beneficial utilization 

has increased from 25% in 1990 to over 43% in 2006, while annual CUB production in 

the United States has risen from about 80 to nearly 125 million tons over this time 

period.32 NETL’s overall goal is to increase CUB reuse to 50% by 2010, and nearly 

100% by 2020. 

CUB are currently regulated as non-hazardous under the Resource Conservation and 

Recovery Act, and it is expected that they will continue to be regulated as such. 

However, EPA has left the door open for future review of the regulatory status of CUB 

because of continuing concern over the fate of Hg and other trace metals in by-products. 

This concern is heightened in light of the deployment of Hg capture technology under 

CAMR. In response, NETL has sponsored a number of projects that focus on an 

evaluation of the potential leaching and volatilization of Hg and other trace metals from 

CUB, particularly FGD by-products, such as synthetic gypsum, and fly ash. 

 

Determining the Fate of Hg in FGD By-products

The use of FGD as a Hg capture technology highlights the importance of better 

understanding the chemistry of Hg and FGD solids and synthetic gypsum products in 

order to predict the environmental fate of the CUB-bound Hg. The following NETL-
July 2008 26 

sponsored research is examining the mobility and ultimate fate of Hg in FGD byproducts. 

NETL’s Office of Research and Development (NETL/ORD) is conducting an in-house 

research effort directed at determining the fate of Hg in FGD materials.48 This activity 

focuses on Hg stability during FGD gypsum drying, Hg stability during wallboard 

production using FGD gypsum, Hg leachability from FGD gypsum, and the Hg-binding 

phase in FGD gypsum. The stability of Hg during FGD gypsum drying was studied by 

collecting samples before and after a natural gas-fired heating unit, which reduces the 

moisture content of the FGD solids for ease of handling during the wallboard 

manufacturing process. Results indicated that within analytical precision, no Hg desorbed 

during drying of free moisture. 

The stability of Hg in FGD gypsum during wallboard production was analyzed by 

NETL/ORD by collecting samples of FGD gypsum feedstock and the corresponding 

wallboard products from five wallboard manufacturing plants. The Hg present in the 

unprocessed FGD gypsum and the finished wallboard product ranged from 0.04 to 1.5 

ppm on a dry basis. The quantity of Hg retained in the finished wallboard product varied, 

with three samples showing nearly complete Hg retention during the wallboard 

manufacturing process. For the other two samples, Hg losses were 12 and 58%, 

suggesting that the quantity and thermal stability of Hg in FGD gypsum and wallboard 

depends on the origin of the gypsum and/or the nature of processing. 

NETL/ORD also conducted settling and leaching experiments using FGD slurry samples 

in an attempt to isolate the Hg-binding phase from bulk gypsum. During settling, Hg 

partitioned almost exclusively to the top, slower-settling layer of the FGD slurry. 

Analysis of this residue revealed that both Hg and iron (Fe) were enriched in the top layer 

by factors of about 20 and 10, respectively. Meanwhile, Hg was not mobilized during 

FGD slurry leaching experiments using a continuous, stirred-tank extractor. This is 

indicative of a strong chemisorption rather than physical adsorption of Hg. As a result, it 

is believed that Hg sequestered in FGD gypsum is primarily bound to an iron-rich phase, 

such as iron-coated clay materials or iron oxide/hydroxide particles, probably introduced 

with the limestone used as the FGD reagent. Additional research49 has also shown that 

some Hg retained in FGD gypsum requires hydrogen peroxide oxidation for release, such 

as a phase containing sulfides or carboneous materials. Mercury not bound in either of 

these two fractions is likely a precursor to Hg0

 that could form via mechanisms being 

investigated through URS’ bench-scale kinetics model. 

Leach testing is also being used to evaluate the impacts of pH and oxidation-reduction 

potential (ORP) on Hg mobility in FGD byproducts. Leaching of six FGD materials to 

pH > 2 under aerobic conditions failed to mobilize appreciable amounts of Hg. While no 

Hg was released to the leachate during experiments with pH > 4 and ORP > 100 

millivolts (mV), dissolution of the major immobilized form of Hg was complete with pH 

< 1 and an ORP of approximately 350 mV. Consequently, NETL/ORD researchers 

concluded that the Hg-retaining phase will immobilize Hg in many reuse applications, 
July 2008 27 

with one possible exception being placement in mine-land reclamation areas where the 

FGD by-products could be exposed to acidic, anaerobic conditions. 

The extramural thrust of NETL’s CUB research is focused on the fate of Hg in FGD 

gypsum during wallboard production and ultimate disposal. For instance, the Tennessee 

Valley Authority (TVA) evaluated Hg retention in FGD gypsum from three sources: a 

Hg-amended commercial calcium sulfate, a laboratory-scale wet FGD system, and a fullscale wet FGD system.50 TVA researchers concluded that no Hg would evolve from 

disposed FGD byproducts up to a maximum temperature of 140°F, although thermal 

desorption of Hg from FGD gypsum did occur at approximately 400°F. 

USG Corporation is providing data on the extent and location of Hg loss during the 

wallboard production process, and also providing information on the potential for Hg 

leaching at the end of the wallboard life-cycle, when it is disposed in municipal 

landfills.51 FGD gypsum evaluation tests from six different power plant/FGD feedstock 

variations have been completed to investigate the impact of different configurations on 

the stability of Hg during wallboard production. Testing included the use of FGD gypsum 

produced during TMT-15 injection into a power plant scrubber. 

Results to date indicate that use of fines blowdown in wet FGD systems significantly 

reduced Hg content in the FGD gypsum. For FGD gypsum generated without fines 

blowdown, Hg loss amounted to less than 8%, while tests using FGD gypsum from 

power plants employing fines blowdown indicated Hg loss of 46 to 55% during 

wallboard production. 

Determining the Fate of Hg in Fly Ash

Beginning with the Phase I full-scale field testing program, NETL has required that field 

contractors evaluating Hg control via sorbent injection collect and analyze fly ash 

samples. Fly ash analyses are focused on determining the stability and ultimate fate of Hg 

during potential utilization applications and disposal. More recently, NETL awarded a 

contract to Frontier Geosciences, Inc. (Frontier) to conduct independent laboratory 

analysis of CUB generated during NETL’s Phase II full-scale Hg control technology field 

testing program.52 The purpose of the independent laboratory analysis is to ensure 

accurate and consistent laboratory procedures are used to determine the environmental 

fate of Hg in CUB. NETL/ORD has also been conducting in-house leaching experiments 

with fly ash collected from ACI field testing sites. 

The Frontier work includes leaching studies using the Synthetic Precipitation Leaching 

Procedure (SPLP, EPA Method 1312), low- (40°C for 30 days), medium- (190°C for 1 

hour), and high-temperature (900-1200°C for 5 minutes) Hg volatility tests, microbial 

methylation experiments, and halide analysis. Preliminary SPLP results indicate that little 

to no Hg would be released under normal disposal conditions. In addition, Hg bound to 

PAC sorbents, particularly those that have been chemically-treated, appears to be more 

stable than the UBC-bound Hg. During the low-temperature volatility tests, essentially no 

Hg was emitted from the fly ash samples. Thermal desorption of Hg has been observed 
July 2008 28 

during the medium- and high-temperature volatility tests conducted by Frontier; however, 

the extent of release is still under investigation. 

Using a pure culture of sulfate reducing bacteria known to methylate Hg, the production 

of methyl-mercury, over a 30 day period, is being monitored to assess the methylation 

potential of Hg present in CUB. Preliminary results from this “worst-case-scenario” 

microbial mobilization study indicate an increase in methyl-mercury production. 

However, microbial activity has also stabilized a number of target metals. 

NETL/ORD researchers have also conducted leaching experiments on the Phase II byproducts using the modified SPLP, the NETL Serial Batch Leaching Procedure (SBLP), 

and NETL Column Leaching on a select number of sample pairs. During a five-month 

continuous column experiment using four leachants: water (pH=5.7), dilute sulfuric acid 

(pH=1.2), dilute acetic acid (pH=2.9), and sodium carbonate (pH=11.1),53 the PAC/ash 

mixtures were generally found to effectively immobilize the captured Hg over a range of 

laboratory conditions. Overall, very little of the Hg (always below 0.5% and often under 

0.1%) contained in the ash samples was solubilized during leaching. Neither the pH nor 

the nature of the anion had a noticeable effect on the leachate mercury. 

Not only have the Hg control technologies demonstrated capture of Hg that would 

otherwise be released into the environment, but the Hg has generally been shown to be 

retained in the control technology by-products under conditions of laboratory leaching 

tests. For some of these materials, the tests performed in this study show these control 

technology ashes, in spite of their higher Hg content, to be environmentally more stable 

with respect to Hg release than the corresponding baseline ashes of lower Hg content.54

SUMMARY 

Over the past seven years, NETL has managed full-scale field tests of Hg control 

technologies at nearly 50 U.S. coal-fired power generation facilities. The flexible nature 

of this program allowed NETL to quickly incorporate insights and lessons learned from 

its network of partners into the development of advanced Hg control technologies tailored 

to specific areas of need. For instance, a determination that chlorine released during coal 

combustion promotes Hg0

 oxidation in flue gas led to the development of technologies 

designed to provide a halogen “boost” for coals, such as subbituminous and lignite, that 

tend to contain low levels of chlorine and thus lower concentrations of the more reactive 

oxidized form(s) of Hg. 

NETL has observed a step-change improvement in both the cost and performance of Hg 

control during full-scale field tests with chemically-treated (or brominated) ACI. The 

improved Hg capture efficiency of these advanced sorbent injection systems has given 

coal-fired power plant operators the confidence to begin deploying technology. As of 

April 2008, nearly 90 full-scale ACI systems have been ordered by U.S. coal-fired power 

generators. These contracts include both new and retrofit installations and represent over 

44 GW of coal-based electric generating capacity. The ACI systems have the potential to 

remove more than 90% of the Hg in many applications based on results from NETL’s 
July 2008 29 

field testing program, at a cost estimated to dip below $10,000/lb Hg removed. However, 

while the results achieved during NETL’s field tests met or exceeded program goals, only 

through experience gained during long-term continuous operation of these advanced 

technologies in a range of full-scale commercial applications will their actual costs and 

performance be determined.

ACKNOWLEDGEMENT 

This report would not have been possible without the efforts of the NETL project 

managers and researchers who provided valuable technical input. The authors would like 

to acknowledge the contributions of Lynn Brickett, Andrew O’Palko, Bruce Lani, 

Charles Miller, Sara Pletcher, Pierina Noceti, Barbara Carney, William Aljoe, Evan 

Granite, Henry Pennline, and James Murphy. The authors would also like to 

acknowledge the efforts of EPA, EPRI, coal-fired power generators who participated in 

the program, and the research organizations and academic institutions who were active 

participants.

DISCLAIMER 

References in this article to any specific commercial product or service are to facilitate 

understanding and do not imply endorsement by the U.S. Department of Energy. 

REFERENCES 

 

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17 Landreth, R.; Nelson, S.; Liu, X.; Tang, Z.; Miller, J.; Hoeflich, P.; Moore, G.; Brickett, L. New FullScale Results from B-PAC Control Trials. In Proceedings of the A&WMA/EPA/DOE/EPRI Combined 

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19 Amrhein, J. Long-Term Carbon Injection Field Test for 90% Mercury Removal for a PRB Unit with a 

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20 Dombrowski, K. Evaluation of Low-Ash Impact Sorbent Injection Technologies at a Texas Lignite/PRB 

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21 Kang, S. G.; Brickett, L. A. Field Demonstration of Enhanced Sorbent Injection for Mercury Control. 

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23 Presto, A.; Granite, E. Impact of Sulfur Oxides on Mercury Capture by Activated Carbons. In 

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25 Sjostrom, S.; Dillon, M.; Donnelly, B.; Bustard, J.; Filippelli, G.; Glesmann, R.; Orscheln, T.; Wahlert, 

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27 Brickett, L. An Update of DOE’s Phase II & III Mercury Control Technology Program. Presented at the 

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28 Laumb, J.; Pavlish, B. Long-Term Demonstration of Sorbent Enhancement Additive Technology for 

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29 Landreth, R.; Nelson, S.; Liu, X.; Tang, Z.; Donochod, D.; Kulpinski, K.; Wanninger, K.; Brickett, L. 

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38 Butz, J.; Broderick, T.; Turchi, C.; Geers, J. Trial of Amended SilicatesTM for Mercury Control at Miami 

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39 Nelson, S.; Landreth, R.; Liu, X.; Tang, Z.; Miller, J.; Brickett, L. Brominated Sorbents for Small ColdSide ESPs, Hot-Side ESPs, and Fly Ash Use in Concrete. Presented at the DOE/NETL Mercury Control 

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40 Machalek, T. Mercury Control by EPRI MerCAPTM Process. Presented at the DOE/NETL Mercury 

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41 Samuelson, C.; Lissianski, V.; McNemar, A. Utilization of Partially Gasified Coal for Mercury Removal. 

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52 Hensman, C.; Dahl, A.; McIntosh, B.; Hawkins, L.; Kilner, P.; Hien, J.; Prestbo, E.; Gilmour, C.; 

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