Combustion Additives for Control of 

Phosphorus Effects and Achieving 

Mercury Reduction

Technical Paper

BR-1910

Authors:

M. Gadgil, G. Bielawski, and 

M. Schmeida

Babcock & Wilcox 

Power Generation Group, Inc.

Barberton, Ohio, U.S.A.

Presented to:

Power-Gen Europe

Date:

June 3-5, 2014

Location:

Cologne, Germany
1

Combustion Additives for Control of Phosphorus Effects and Achieving Mercury 

Reduction

BR-1910

Presented to Power-Gen Europe 2014

Mandar Gadgil, Greg Bielawski, Melanie Schmeida

Babcock & Wilcox Power Generation Group, Inc.

20 S. Van Buren Ave,

Barberton, Ohio 44203 USA

Abstract

Biomass is generally considered CO2 neutral, so the utilization of biomass fuels for energy production 

continues to grow. Many European power companies are transitioning to greater biomass use through 

biomass and coal co-combustion and conversion of coal-fired boilers to biomass firing. The increased 

use of biomass presents some unique challenges to the operation of both boilers and flue gas treatment 

equipment. One such challenge involves phosphorus deactivation of the selective catalytic reduction 

(SCR) catalyst.

In addition to these phosphorus issues associated with biomass firing or coal-biomass co-combustion, 

there is a need to reduce mercury emissions from the combustion process. Halogen addition to the fuel 

is a widely accepted technology for enhancing mercury oxidation, since oxidized mercury is more readily 

removed by flue gas cleaning systems. However, under certain operating conditions, halogens are also 

known to increase fouling and corrosion.

Field data will be presented demonstrating the use of a patent-pending combustion additive developed 

by Babcock & Wilcox Power Generation Group, Inc. (B&W PGG). This additive has been shown to 

maintain SCR catalyst performance and reduce the halogen concentration required to achieve mercury 

oxidation. 

Introduction

Reducing carbon dioxide CO2 emissions from the power-generating industry, has led to considerable

interest in the utilization of biomass and municipal and industrial waste in power plant boilers. The use 

of renewable energy sources, such as biomass co-firing with coal or 100% biomass firing in existing coalfired power plants, represents one option for combined renewable and fossil energy utilization to 

reduce CO2 emissions. Biomass is considered CO2 neutral with respect to the greenhouse gas balance if 

the use of fossil fuel in harvesting and transporting the biomass is not considered. Direct co-firing, i.e.,

firing coal and biomass in the same boiler, is the simplest and most widely applied technology for cofiring biomass. 

Biomass and coal have fundamentally different fuel properties. Biomass (and some low-rank coals) 

contains larger relative quantities of alkali and alkaline-earth elements (potassium, sodium, calcium, and 
2

magnesium), phosphorus and chlorine than coal. Since all the constituents of the biomass enter the 

boiler during combustion, several technical concerns arise. Higher fuel chlorine content can lead to 

increased high temperature corrosion in boilers. Accelerated fouling and slagging can occur when fuels 

containing high potassium levels are utilized. For the operation of SCR systems, there are technical 

challenges associated with co-combustion of biomass and coal in boilers designed for coal as the 

constituents of biomass have the potential to impair the SCR. SCR catalysts are susceptible to 

deactivation from several mechanisms resulting in shorter catalyst life. The deactivation mechanisms 

include condensation of volatile inorganic species on the catalyst surface and the reaction of gas-phase

poisons with the vanadium sites. Formation of the sulfate-based deposits on the catalyst surface or 

reaction with the catalyst’s active species can also significantly reduce catalyst life. Biomass in the form 

of wastes may also contribute elements such as arsenic, potassium and phosphorus, which are well 

known catalyst poisons. [1]

SCR Catalyst Deactivation by Phosphorus

As noted in the introduction, the SCR catalyst can be deactivated due to the actions of different types of 

poisons. Some of these poisons include alkali and alkaline earth metals, arsenic and phosphorus. Each 

one of the poisons attacks the SCR catalyst in different ways, resulting in the deactivation. The 

deactivation mechanism for phosphorus is discussed in more detail. 

The release mechanism of phosphorus in the gas-phase during combustion is very different between 

coal and biomass. In the case of coal, most of the phosphorus is inorganically associated within the coal 

matrix. During the coal combustion process, especially under air-staged combustion conditions, the 

phosphorus compounds undergo a carbothermic reduction reaction that releases gas-phase 

phosphorus. For biomass, almost all of the phosphorus is organically associated in the fuel. The 

organically bound phosphorus is readily released as gas-phase phosphorus during the combustion 

process. This release of organically bound phosphorus in the gas phase is similar to the release of the 

volatile components of the fuel, which are also organically bound in the fuel, and are released in the gas 

phase during combustion, albeit irrespective of staged or un-staged combustion. The gas-phase 

phosphorus can react with the active sites on the surface of the catalyst resulting in chemical 

deactivation of the catalyst due to formation of vanadium-phosphorus bonds. One interesting 

observation noted with phosphorus deactivation of multilayer SCR catalyst installations is that the 

second catalyst layer is often more deactivated than the first layer. The possible explanation of this 

could be due to the suppression of phosphorus adsorption on the catalyst surface in the presence of 

ammonia. For the first layer, there is much more ammonia present in the gas whereas for the second 

layer, there is comparatively less ammonia present in the flue gas due to the consumption of ammonia 

for the nitrogen oxides (NOx) reduction reaction. It may be possible that ammonia gets adsorbed more 

easily on the active sites than phosphorus and hence, the second layer deactivates more than the first 

layer. [2] 
3

Mitagent TM Combustion Additive Development

B&W PGG initiated the MitagentTM combustion additive development program to develop a way to 

reduce the rapid deactivation of SCR catalyst by phosphorous observed on air-staged Powder River Basin 

(PRB) coal-fired units in the United States. There are two primary sources by which phosphorus can 

enter the SCR catalyst. One is in the form of gas-phase phosphorus; the other is associated with the ash. 

The ash-bound source of phosphorus was investigated first because there was no reliable technique at 

that time to measure gas-phase phosphorus concentration in the high dust gas entering the SCR. Sizeseparated ash samples were collected from plants that were experiencing rapid catalyst deactivation. 

These samples were analyzed to determine the possibility of ash-bound phosphorus leaching into the 

SCR catalyst and causing a chemical deactivation. Due to high calcium and low sulfur nature of the PRB 

coal, two pH levels were chosen for this leaching study, with one pH being slightly acidic (pH = 5) and the 

other pH being slightly alkaline (pH = 9). These are the two pH conditions most likely present during 

short (two to three days) or long (two to four weeks) term unit outages. Due to the high calcium and 

low sulfur nature of the PRB coal, the pH values of 5 and 9 were chosen for the leaching study. It was 

observed that under these two pH conditions, negligible amounts of phosphorus can leach out; leading 

to the conclusion that ash-bound phosphorus was an unlikely source of SCR catalyst deactivation. As a 

result of this analysis, particulate-bound phosphorus was thus ruled out as the source for SCR 

deactivation.

Following this analysis, B&W PGG began to investigate whether gas-phase phosphorus or gas-phase 

phosphorus compounds were the primary deactivation agent. B&W PGG developed a modified

procedure to reliably measure gas-phase phosphorus at high dust locations such as the SCR inlet. The 

primary problem with measurement of gas-phase phosphorus at high dust locations is an interference of 

the particulate-bound phosphorus with the impinger solution. This interference caused the prior gasphase phosphorus measurements determined by standard EPA Method 29 to produce highly variable 

results. B&W PGG believes that this variability was due to particulate-bound phosphorus breaking 

through into the impingers and being reported as gas-phase phosphorus. Following numerous 

investigations, B&W PGG modified the standard EPA Method 29 procedure for gas-phase phosphorus

measurement. The modifications included installing an in-stack thimble and a backup filter to collect 

the ash inside the duct. The impinger solutions used to collect the gas were also modified. The first 

impinger solution was filled with de-ionized (DI) water because it was observed that ash-bound 

phosphorus was insoluble in DI water and slightly acidic solutions. The other two impingers were filled 

with a mixture of hydrogen peroxide and nitric acid. The first impinger, filled with DI water, served as an 

additional filter to catch any particulate breakthrough. This technique was tested at different power 

plants burning PRB coal with staged combustion and was found to be a reliable method to measure gasphase phosphorus.

Since the deactivation phenomenon was observed only on units with air-staged combustion or those 

with known poor combustion issues, a mechanism was proposed to explain the release of gas-phase 

phosphorus as a result of such staging or poor combustion of the PRB fuel. This mechanism is based on 

carbothermic reduction of phosphorus-bearing minerals, resulting in release of gas-phase phosphorus. 

Mineral analysis of the PRB coal revealed that the phosphorus was primarily associated with calcium 
4

(Ca) in the form of calcium phosphate, which is a very stable compound (high melting and boiling point) 

under un-staged combustion conditions. A coal sequential extraction technique also revealed that a 

negligible amount of phosphorus was organically associated within the coal matrix. Organic phosphorus

is readily released into the gas phase. This is the reason why SCRs on biomass-fired units can experience 

rapid catalyst deactivation from phosphorus. Formation of vapor phase silicon mono-oxide (SiO) under 

reducing conditions due to carbothermic reduction of SiO2 was explained by Quann. [3] Based on that 

knowledge, B&W PGG proposed a similar theory involving carbothermic reduction of phosphorusbearing inorganic compound resulting in the release of gas-phase phosphorus. The reaction involved is 

between a phosphorus-bearing inorganic mineral compound and carbon monoxide and is represented 

as follows: 

P (compound S) + CO (g)  P (g) + CO2 (g) Equation (1)

This mechanism could potentially explain increased deactivation of the catalyst by phosphorus under 

staged combustion conditions. The release of gas-phase phosphorus from Equation 1 is dependent on 

both carbon monoxide (CO) concentration and residence time in a high CO atmosphere. In boilers with 

staged combustion, the concentration of CO is typically higher in the lower furnace (below the over fire

air (OFA) ports) compared to an un-staged furnace. In addition, due to air staging the phosphorusbearing coal particles, on an average, spend more time in a high CO atmosphere compared to an unstaged furnace. Combined, these two conditions result in a significantly higher release of gas-phase 

phosphorus compared to an un-staged combustion process.

Based on this theory, B&W PGG proposed that, for a unit using staged combustion to reduce the boiler 

outlet NOx, there should be more gas-phase phosphorus produced compared to a unit without staged 

combustion. This theory was tested at a power plant located in the midwestern United States. The 

plant has two units that burn the same coal. Unit 1 does not have air staging, whereas unit 2 does have

air staging. Unit 1 is 200 MW generating capacity with SCR and ESP installed, and Unit 2 is 320 MW 

generating capacity with SCR, circulating dry scrubber (CDS) and fabric filter installed.

Table1: Gas-Phase Phosphorus Comparison 

Parameter Unit 1 (Un-staged Combustion) Unit 2 (Staged Combustion) 

Boiler Outlet NOx, ppm 300 220

Gas-phase phosphorus, ppb 14 (9 runs average) 27 (9 runs average) 

P2O5% in ash day 1 1.07 0.92

P2O5 % in ash day 2 1.2 0.86

 

As seen in Table 1, for Unit 1 without air staging, the gas-phase phosphorus was significantly lower than 

Unit 2. It is also important to note that for Unit 1, the P2O5 content in the ash was significantly higher 

than Unit 2. This supports the theory that gas-phase phosphorus is released as a result of carbothermic 

reduction reaction. Due to air staging, Unit 2 is expected to have higher CO concentration than Unit 1. 

As a result of higher CO concentration, it was expected that Unit 2 will have more gas-phase phosphorus 
5

as compared to Unit 1. The test results from B&W PGG’s testing support the hypothesis that 

significantly more gas-phase phosphorus is produced as a result of air staging.

Based on the theory of a carbothermic reduction reaction causing release of gas-phase phosphorus, it 

was proposed that for two units with two different boiler outlet NOx levels due to the extent or the 

degree of staging, not just staged or un-staged, there should be different gas-phase phosphorus levels. 

This theory and the modified Method 29 technique were tested by performing gas-phase phosphorus 

sampling at SCR inlet locations of two plants with different degrees of air staging. Figure 1 shows the 

results supporting this hypothesis. Plant A in Figure 1, is the same plant as Unit 2 inTable1. The other 

plant in Figure 1 is Black Hill Power & Light’s Wygen II unit. The unit has 100 MW generation capacity 

from a B&W PGG subcritical PRB coal-fired boiler and is equipped with air-staged combustion, SCR, 

spray dryer absorber (SDA) and fabric filter. Wygen II is a deep-staged combustion unit with boiler 

outlet NOx of 150 ppm (0.15 lb/MBtu NOx), whereas Plant A has less staging as indicated by boiler outlet 

NOx of 220 ppm (0.22 lb/MBtu NOx). Wygen II previously experienced rapid SCR catalyst deactivation by 

what has been confirmed to be gas-phase phosphorus poisoning.

Figure1: Gas-Phase Phosphorus Comparison

In Figure 1, the red columns represent Wygen II measurements and the blue columns represent Plant A 

measurements. As predicted, there was more gas-phase phosphorus at Wygen II than Plant A. This 

sampling validated the theory of carbothermic reduction and B&W PGG’s modified Method 29 

procedure for sampling of gas-phase phosphorus in a high particulate loading location.

Gas Phase P at Plant A

Inlet NOx 0.22 lb/MBtu

Gas Phase P at Wygen II

Inlet NOx 0.15 lb/MBtu
6

Mitagent Additive Performance Demonstration for Phosphorus Mitigation 

Catalyst samples were obtained and analyzed from Unit 1 mentioned in Table 1. The analysis showed 

that there was no appreciable catalyst deactivation due to phosphorus poisoning and the performance 

was as predicted. This was not surprising as the gas-phase sampling at Unit 1 showed that the 

phosphorus levels in the gas phase were low (14 ppb ). Catalyst samples were also obtained from the 

Wygen II plant. The catalyst samples analyzed from Wygen II showed the deactivation was caused due 

to phosphorus poisoning. This also was not surprising as the gas-phase phosphorus sampling at Wygen 

II showed the phosphorus concentration to be much higher (36 ppb) as compared to Unit 1. Based on 

the research performed, it was concluded that the rapid deactivation of the SCR catalyst was caused by

gas-phase phosphorus poisoning of the catalyst. Therefore, B&W PGG embarked on a developmental 

program to identify additives and methods that are capable of mitigating and/or reducing gas-phase 

phosphorus compounds. A novel material was identified that sequestered gas-phase phosphorus under 

typical combustion conditions as particulate-bound phosphorus. This additive and application method 

lowers the concentration of gas-phase phosphorus and its aerosols entering the SCR. Detailed studies 

were performed to investigate the effects of this material on boiler operation and to confirm that there 

were no adverse affects, particularly in the areas of boiler slagging and convection pass fouling and

corrosion. The required addition rate of this material was also analyzed as well as leaching studies to 

observe stability of this new particulate-bound phosphorus under standard SCR operating conditions.

B&W PGG’s Mitagent additive technology was first tested at Wygen II in two short-term (4 to 5 days) 

injection tests. The additive was injected at rates less than 0.5% of the total plant coal flow rate using 

pneumatic conveying. Gas-phase phosphorus was measured at baseline conditions, and during and 

after the injection test. It was observed that the gas-phase concentration decreased by about 50%

during additive injection compared to the baseline conditions. This injection testing demonstrated the 

ability of the B&W PGG additive to achieve lower gas-phase phosphorus concentrations entering the 

SCR. The result of this test is shown in Figure 2. 
7

Figure 2: Demonstration of reduction in gas-phase phosphorus at SCR inlet as a result of additive 

injection at Wygen II. 

As seen from Figure 2, the average gas-phase phosphorus before the additive injection was 36 ppb. The 

average gas-phase phosphorus was 21 ppb with the addition of the Mitagent combustion additive. 

Memory effect was observed after the injection of additive was stopped. The memory effect highlights 

two points: one is that more material was injected than needed and it will be possible to optimize the 

injection rate in the future, and second, the injected material may have scavenged the gas-phase 

phosphorus after it was deposited on walls or economizer tubes, etc., in the upper furnace.

Another short-term Mitagent additive test was performed at Plant A which was mentioned in Figure 1. 

B&W PGG’s additive injection at Plant A reduced the gas-phase phosphorus concentration at the SCR 

inlet. The baseline gas-phase phosphorus was 27 ppb and after injection of the Mitagent additive it was 

reduced to 17 ppb. This testing again demonstrated that by adding Mitagent to the coal, the gas-phase 

phosphorus concentration at the SCR inlet can be reduced.

In a third short-term test, the Mitagent additive was used along with halogen addition to the coal. Gasphase sampling was performed at the stack by EPA Method 29 instead of the SCR inlet. This is also a 

B&W PGG subcritical boiler with 250 MW generation capacity, equipped with SCR, ESP, CDS and fabric 

filter. Gas-phase emissions comparisons are shown in Table 2.
8

Table2: Gas-Phase Emissions Comparison 

Metal Average baseline stack 

gas-phase emission

(kg/hr)

Two-day average 

Average stack gasphase emission with 

B&W PGG’s Mitagent 

additive (kg/hr) 

Two-day Average 

% Emissions Reduction

Phosphorus 0.0081 0.005 40

Selenium 0.00033 0.00022 25

 

The results again showed that the combustion additive injection was able to reduce phosphorus 

emissions, along with selenium. The gas-phase phosphorus emissions at the stack were reduced by 40% 

on average. This was very similar to the reduction in phosphorous observed at Wygen II and Plant A 

with the Mitagent additive. It was also observed that the gas-phase emissions of selenium and arsenic 

were also reduced.

To demonstrate actual improvement in catalyst life performance as a result of gas-phase phosphorus 

mitigation using the Mitagent additive, a long-term injection test was performed at Wygen II. The 

deactivation trend at Wygen II as a result of the additive injection for 13,500 hours is shown in Figure 3.

 Figure 3: Actual catalyst deactivation trend for Wygen II with continuous additive injection.

Figure 3 shows three different catalyst deactivation trends. The green curve represents the expected

deactivation trend of the original catalyst. The blue curve represents the actual deactivation curve after 

the catalyst was installed at Wygen II. This very rapid deactivation was later confirmed to be due to gasphase phosphorus poisoning of the catalyst. The deactivated catalyst was regenerated and was 

reinstalled at Wygen II in March 2010. The red curve represents the deactivation curve of this 

Operating Hours 
9

regenerated catalyst with the same formulation as the original catalyst along with Mitagent additive 

injection. The objective of the testing was to determine whether the deactivation of the catalyst could 

be reduced as a result of the additive injection. As illustrated in Figure 3, as a result of the B&W PGG 

additive injection, the actual deactivation of the catalyst (as shown by the red curve) was very gradual 

and closely followed the expected deactivation trend (as shown by the green curve). This improvement 

in the catalyst deactivation performance was a result of the additive injection process that converted

the gas-phase phosphorus into particulate-bound phosphorus. The reduced phosphorus deactivation 

component for the catalyst resulted in slower deactivation. The B&W PGG Mitagent additive can be 

used to reduce phosphorus deactivation for coal, biomass and/or coal-biomass co-combustion units 

because the phosphorus is sequestered in the combustion process. As a result, this additive can be 

applied to both new as well as regenerated catalyst and also for any type (plate, honeycomb, 

corrugated) of catalyst. During the long-term testing for phosphorus mitigation, some additional 

interesting effects of Mitagent on halogen chemistry and therefore on mercury removal were also 

observed [2], which is further expanded upon below.

Mitagent Additive Application for the Enhancement of Mercury Emission Control

Mercury enters the environment in various ways, such as through volcanic activity, coal combustion, and 

chemical manufacturing. As a toxic element, mercury poses ecological threats when it enters water 

bodies, where small aquatic organisms convert it into its highly toxic form, methyl mercury. This form of 

mercury may then migrate up the food chain as predator species consume the smaller organisms. Fish 

contaminated with methyl mercury may pose health threats to people who rely on fish as part of their 

diet. Mercury can harm fetuses and cause neurological disorders in children, resulting in, among other 

things, impaired cognitive abilities. As a result, there is a need to control mercury emissions from coaland biomass-fired power plants. [4] There are multiple proven technologies available for mercury 

emissions control. The control technologies include injecting sorbents such as brominated or nonbrominated activated carbon or amended silicates, or by adding halogens to the coal to increase 

oxidation removal of oxidized mercury in a flue gas desulfurization (FGD) system which is then 

sequestered in liquid or solid byproducts. Each control technology has its advantages and 

disadvantages. The advantage of adding halogen to the coal for mercury oxidation and removal is that it 

is a very simple yet effective technology to implement and maintain. Halogen addition to the coal has 

been used for different types of coal with different emissions control equipment downstream of the 

boiler. Chlorine, bromine and even iodine have been used as halogen additions to the coal for mercury 

oxidation. From a cost and effectiveness point of view, the addition of bromine to the coal has been the 

most successful. The most common method of application of bromine is through the addition of 

calcium bromide solution to the coal.

The application rate of bromine or any halogen for mercury oxidation depends upon the presence or

absence of an SCR system. When an SCR system is installed, the SCR catalyst reduces the application 

rate of bromine by 50 to 80% compared to the application rate of bromine when there is no SCR. On 

units with higher application rates of bromine, there have been some cases of negative balance-of-plant 

impacts due to bromine application. The addition of bromine to the coal has the potential to increase 

corrosion at any point along the fuel handling and flue gas path, including the point at which the 
10

bromine is introduced to the coal, the furnace where the bromine is volatilized, and through the flue gas 

path to the FGD system and stack. The most commonly observed impact has been on the air heater

where cases of corrosion have been observed in the last several inches of the cold end basket where the 

coldest temperatures occur within the air heater. In many cases, air heater corrosion occurred very 

quickly, sometimes within months of the start of the calcium bromide injection process. The rate of 

corrosion depends upon the operation of the unit (in particular with respect to load swings), whether a 

steam coil air heater is used to preheat the cold air, materials of construction, and on the application 

rate of calcium bromide.

There are different possible mechanisms that can explain the corrosion, but the most likely mechanism 

is the direct condensation of hydrogen bromide (HBr) gas on the metal. Although the dew point of HBr 

is lower than that of SO3, when adding a halogen for mercury oxidation on low halogen, low sulfur coals, 

the air heater corrosion is mainly from HBr and not from SO3. This is because the concentration of SO3

in the flue gas is much less than the concentration of HBr. Depending upon the moisture content of the 

flue gas and the HBr concentration in the gas phase, the dew point of HBr can be as low as 125 F. The 

metal temperature of the cold end of the air heater as it rotates back into the flue gas stream can be 

below the acid dew point temperature of HBr. This can therefore provide the sites for the HBr from the 

gas phase to condense on the metal. As a result, the possibility of cold end corrosion for air heater 

baskets increases. 

As discussed above, the rate of corrosion depends on flue gas concentration of HBr. Therefore, by 

reducing the HBr concentration in the gas, it is possible to reduce the rate of corrosion. In systems with 

an SCR, the application rate of bromine for low halogen, low sulfur coals is very low, usually in the range 

of 10 to 40 ppm of bromine added to the coal on a dry basis. On units in which no SCR is installed, the 

application rate is significantly higher, ranging from 100 to 200 ppm of bromine added to the coal on a 

dry basis. This significant difference in the application rate is a result of HBr gas initially forming when 

bromine is added to the coal. The HBr gas has to undergo the “Deacon reaction” to be converted into 

diatomic form be it molecular or other halogen compound. This reaction is shown by equation 2. 

4 HBr+ O2 2H2O+ Br2 Equation (2)

The reaction of molecular bromine with mercury results in the formation of oxidized mercury. This 

reaction is as shown by equation 3. 

 Hg+ Br2 HgBr2 Equation (3)

B&W PGG’s Mitagent additive allows for the reduction in the application rate of bromine or a brominecontaining compound regardless of whether or not an SCR is installed. The addition of B&W PGG’s 

Mitagent catalyzes the bromine Deacon Reaction, resulting in a reduction in the application rate of 

bromine for mercury oxidation.

The data presented below from both lab and full-scale units demonstrates the reduction in bromine 

usage for units without an SCR. The lab-scale testing was performed at the Energy and Environmental

Research Center (EERC) pilot-scale test facility. The facility has 560,000 Btu/hr firing capacity and can 

fire all coal types. The test facility fires pulverized coal with the capability for air staging. Different air 

quality control system (AQCS) equipment combinations such as SCR, ESP and dry or wet FGD, and fabric 

filter can be used to mimic the actual plant configuration. 
11

The objective of the pilot testing was to demonstrate the reduction in the bromine application rate as a 

result of the Mitagent additive. Both bituminous and sub bituminous coals were tested. The results 

demonstrated that the same amount of mercury oxidation could be achieved at 50% of the bromine

addition rate when using the Mitagent additive.

Based on the pilot-scale testing, a full-scale test was performed at a midwestern United States power 

plant with an 82 MW gross electric generating unit burning PRB coal. This unit has only an ESP as the 

AQCS equipment. The objective of the field testing was to demonstrate similar or better mercury 

oxidation using B&W PGG’s Mitagent combustion additive with lower bromine application rate 

compared to the oxidation obtained with higher bromine application rates.

For the testing, the oxidized mercury at the stack was measured by the EPA Method 30B (modified for 

speciation) or the modified sorbent trap method. The injection testing started on December 9, 2013,

and continued until December 12, 2013. Table 3 shows the mercury oxidation measured at the stack as 

a result of the Mitagent additive to the coal.

Table 3: Effect of Mitagent Additive on Halogen Addition and Mercury Oxidation 

Br Addition Rate (ppm dry ) % Oxidized Hg with 

Mitagent 

% Oxidized Hg without Mitagent 

0 38 37

60 75 46.5 

100 83.8 62.5

35 56 Not tested 

The data in Table 3 shows that the average mercury oxidation was 38% without addition of halogen and 

Mitagent to the coal. With the addition of 60 ppm of bromine to the coal, the average mercury 

oxidation was 46.5%. With addition of 60 ppm of bromine to the coal and Mitagent, the mercury 

oxidation was improved to 75%. With the addition of 100 ppm of bromine to the coal, the mercury 

oxidation without Mitagent was 62.5%, which increased to 83.8% with the addition of the Mitagent 

additive. This showed that, with addition of Mitagent to the coal, there was an improvement to the 

overall mercury oxidation. An interesting observation was that even with a much lower bromine 

addition rate to the coal (35 ppm) with Mitagent, the average mercury oxidation was 56%. This average 

oxidation was higher than the 46.5% oxidation observed with 60 ppm of bromine added to the coal 

without Mitagent. This testing demonstrated that with the addition of B&W PGG’s Mitagent to the coal, 

the bromine addition rate can be reduced significantly while achieving the same mercury oxidation. The 

benefits of reducing the bromine addition rate to the coal are both reduction in cost and the reduction 

in the rate of corrosion.

Pilot-Scale Testing for Mercury Emission Reduction

Testing was also performed at the EERC pilot-scale combustion test facility to evaluate the effectiveness 

of the combined addition of bromine as CaBr2, Mitagent, and S SORB III for mercury emission reduction. 

S SORB III is a proprietary additive offered by Chem Mod LLC, and has the capability to remove oxidized 

mercury as particulate-bound mercury. S SORB III also has the capability to reduce the tendency of 

particulate-bound mercury to leach from the ash compared to particulate-bound mercury removed by 

powdered activated carbon (PAC) injection. Table 4 shows the data from this testing on PRB coal.
12

Table 4: Pilot-Scale Mercury Emission Results for PRB Coal 

Bromine Rate

% added to the coal 

S SORB III

% added to the coal 

Mitagent 

% added to the coal 

Hg @ ESP Outlet 

ug/sm3

0.0 0.0 0.0 3.41

0.02 0.3 0.0 1.35

0.01 0.175 0.075 1.43

As seen in Table 4, the baseline mercury emission was 3.41 ug/sm3 (2.73 lb/TBtu). The mercury 

emission with application of a 0.02% CaBr2 solution to the coal and 0.3% S SORB III to the coal was 1.35 

ug/sm3 (1.08 lb/TBtu). This was a reduction of 60% in mercury emissions. With the addition of 0.075% 

by weight Mitagent additive to the coal, the CaBr2 application rate was reduced by 50% from 0.02% to 

0.01% while still achieving similar mercury removal. This result showed that the Mitagent additive can 

reduce the bromine addition rate and the S SORB III can remove the oxidized mercury in a particulatebound form.

Field Test for Mercury Emission Compliance

The second objective of the field testing described above was to achieve stack mercury emissions below 

1.5 ug/sm3

(1.2 lb/TBtu) as a result of addition of bromine as CaBr2 ,Mitagent additive and S SORB III to 

the coal. The value of 1.5 ug/sm3 (1.2 lb/TBtu) is the current gas-phase mercury emission limit in the 

United States per the Environmental Protection Agency (EPA)’s Mercury and Air Toxic Standards (MATS) 

emissions limit for bituminous and sub bituminous coal-fired utility electric generating units. S Sorb III 

was added to the coal along with CaBr2 and Mitagent on November 12, 2013 and December 12, 2013. 

On November 12, the average total Hg at the stack was about 0.38 ug/sm3 (0.3 lb/TBtu). On December 

12, only 20 ppm of bromine, Mitagent additive and S Sorb III was tested and the average total Hg in the 

stack was 0.75 ug/m3 (0.6 lbs/TBtu). Figure 4 shows the stack mercury emission for December 12, 2013. 
13

 

Figure 4: Stack Mercury Emission with Additive Injection 

As seen from Figure 4, the stack mercury emissions before the start of the injection was approximately 

2.25 ug/sm3

(1.8 lb/TBtu). With the injection of the additive to the coal, the stack mercury emission was 

reduced to an average value of 0.75 ug/sm3

(0.6 lb/TBtu) during the injection period from 8:00 AM to 

3:30 PM. The stack mercury increased back to the baseline mercury values once the injection was 

stopped. One of the most important advantages of the blended additive (S Sorb III plus Mitagent

additive) injection for mercury control is that it can remove the mercury in a particulate-bound form [5]. 

This advantage could be very beneficial for units with wet FGD systems, as the removal of the majority 

of the mercury before the wet FGD will reduce the concerns associated with mercury in the gypsum or

wet FGD waste water.

Conclusion

Based on the long-term testing data from Wygen II, B&W PGG demonstrated that the use of the 

Mitagent additive can significantly reduce the rate of SCR catalyst deactivation by reducing catalyst 

poisoning by phosphorus. This combustion additive can be applied to any type of SCR catalyst. The 

Mitagent additive can also reduce the application rate of halogen for mercury oxidation for units 

without an SCR and, along with Chem Mod’s S SORB III additive, can be an inexpensive yet effective

mercury control alternative to activated carbon injection.

 
14

 References 

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