Exhibit 8
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G.T. Bielawski

J.B. Rogan

D.K. McDonald

The Babcock & Wilcox Company

Barberton, Ohio, U.S.A.

Presented to:

The U.S. EPA/DOE/EPRI Combined Power Plant Air

Pollutant Control Symposium: “The Mega Symposium”

August 20-23, 2001

Chicago, Illinois, U.S.A.

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There is currently a demand for new coal-fired generation in

the USA. The few coal-fired plants that have been permitted

within the last ten years have been required to meet emission

levels considerably less than NSPS. The realities of permitting

a new coal-fired plant today will require low emissions.

The need for ultra-high removal efficiency technologies for

NOx, SO2, sulfuric acid mist, PM2.5, mercury, and particulate is

here. There is also the potential need to lower CO2 emissions by

utilizing more efficient steam cycles than have been used in this

country to date.

This paper will examine in detail cost-effective advancements

in known, proven emissions control technologies that achieve

synergistic multi-pollutant capture and will briefly discuss steam

cycle options to reduce CO2. Emission control technologies for

eastern bituminous high sulfur fuels that can achieve 0.016 lb/

MBtu NOx, 0.04 lb/MBtu SO2, and 0.006 lb/MBtu particulate

(including acid mist) are examined. For PRB coal, emission levels down to 0.008 lb/MBtu NOx, 0.04 lb/MBtu SO2, and 0.006

lb/MBtu particulate with a high level of mercury capture can be

achieved. This level of NOx is less than the permit levels of many

of today’s new gas turbine combined-cycle units.

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When it comes to coal-fired technologies for power generation, only three technologies promising high efficiency are sufficiently developed to have any impact on the industry over the

next two or three decades: pulverized coal-fired boilers (PC),

pressurized fluidized bed combustion (PFBC) and integrated

gasification combined cycle (IGCC). When net plant efficiencies are compared based on the same site and ambient conditions and using the same units, first generation PFBC, IGCC

and PC with state-of-the-art steam conditions can currently

achieve comparable net plant heat rates approaching 8200 Btu/

kWh (41-42% HHV efficiency).

Similarly, with the advances in emissions control devices, a

modern pulverized coal plant can achieve comparable emissions

to PFBC and IGCC plants. However, on a capital cost basis, the

pulverized coal technology has a clear advantage and will be

the technology of choice for the near and intermediate term.

This paper discusses the emissions and efficiency performance

of a modern pulverized coal-fired plant.

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Over the last ten years, higher efficiency pulverized coal

plants have gone into commercial operation outside the U.S.

The higher efficiencies are due to not only advanced steam

cycles, but also improvements in turbines and reductions in

power requirements for plant auxiliary equipment. Materials are

currently available for some coals to allow steam conditions as

high as 4500 psi and 1100F/1100F which, depending on site

conditions and coal characteristics, can achieve heat rates as

low as 8050 Btu/kWh (42.5% HHV efficiency). Materials are

currently being developed to permit steam temperatures of 1200F

and higher, depending on the corrosiveness of the coal ash.

Pulverized coal power plant heat rate improvements versus

steam cycle conditions are shown in Figure 1. (The actual operating plants have steam cycles close to the examples under which

they are listed.)
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The point is that higher efficiency cycles are now being demonstrated with commercially required availability and reliability. Higher efficiency cycles will reduce electric production cost

through lower fuel consumption, reduce CO2 emissions per kWh

of energy generated, and result in lower capital and operating

costs for all the environmental equipment (on a $/kW basis).

The ambient air emissions (NOx, SOx, particulate, and mercury)

are a function of the emissions control device (SCR, scrubber,

fabric filter, etc.). However, more efficient, lower heat rate plants

will provide additional marginal emissions reductions as well.

For the U.S. market, the economically optimum cycle efficiency

is very project specific. However, today, even though advanced

cycles are now available and have been demonstrated commercially, they will only be applied where project economics dictate.

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The key drivers to increasing efficiency are reduced fuel cost

and reduced CO2 emissions. Because of the abundance and low

cost of coal in the U.S., fuel cost savings do not provide as

significant a motivation as in many other countries. Though not

yet widely regulated in the U.S., greenhouse gas emissions and

concern for global warming have recently sparked considerable

interest in higher efficiency cycles. Figure 2 shows that CO2 emissions can be significantly reduced by increasing plant efficiency.

However, as Figures 3, 4 and 5 show, improving efficiency

has only a minimal impact on the other key emissions.

Figure 3 shows the NOx emissions in lb/MWh for selective

catalytic reduction (SCR) removal rates of 25% to 95% and net

plant heat rates varying from 9300 Btu/kWh (36.7% net plant effi-

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Figure 5 shows the outlet particulate emission in lb/MWh as

a function of the particulate in the flue gas in lb/MBtu. Again

the conclusion is that as fabric filters and other particulate removal devices become more efficient, the impact of improved

heat rates on emissions is nearly negligible.

Figures 3 through 5 show that projects requiring low ambient air emissions will primarily achieve those low levels through

the performance of the emissions control devices (SCR, scrubber, ESP/fabric filter); cycle heat rate has minimal impact.

More efficient heat rate cycles will primarily be justified by

lower fuel consumption and the potential future benefit of lower

CO2 emissions.

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ciency) to 8050 Btu/kWh (42.4%). The graph shows that as a

higher removal rate SCR is selected, the impact of the cycle heat

rate declines. Although current removal rates are typically 90%, as

high as 93% has been demonstrated, and even higher removal is

possible with improved mixing and additional catalyst. At these

high removal rates, improving heat rate (or cycle efficiency) has

little impact on the further reduction of NOx emissions.

Figure 4 shows the same comparison for SO2. A typical removal in a wet scrubber is 90% with some today as high as 95% to

98%. Again, as the SO2 removal rate in the scrubber increases, the

effect of cycle heat rate improvement on further SO2 removal decreases.
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In 1971, the New Source Performance Standards for new

coal-fired power plants in the U.S. were 0.7 lb NOx/MBtu, 1.2

lb SO2/MBtu, and 0.1 lb particulate /MBtu. These regulations

were tightened in 1979. For NOx, the regulation was 0.5 or 0.6

lb NOx/MBtu depending on the type of coal. The regulation for

SO2 was a sliding scale from 1.2 down to 0.3 lb SO2/MBtu depending on the coal sulfur. The particulate limit was lowered to

0.03 lb/MBtu. The few new coal-fired power plants that received

permits in the 1990s typically had permit levels less than the

New Source Performance Standards as shown on Table 1.

The technology of emission control equipment has advanced

such that even lower emissions goals can be sought today. This

should make coal more environmentally acceptable and more

frequently the choice for future power generation needs.

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Possible configurations of environmental control equipment for

new coal plants will now be examined. One such configuration is

for high sulfur bituminous coal and another configuration is for

low sulfur western coal from the Powder River Basin.

The plant configuration for high sulfur bituminous coal consists of low NOx burners, an advanced high removal efficiency

selective catalytic NOx removal system, fabric filter, and limestone wet flue gas desulfurization (FGD) with integral wet electrostatic precipitator (ESP) and additive for mercury control.

The plant configuration is shown in Figure 6.

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The plant configuration for low sulfur western coal consists

of low NOx burners, limestone injection into the furnace, partial particulate collection upstream of the SCR, an advanced

high removal efficiency SCR, spray dry absorber FGD system

and fabric filter. The plant configuration is shown in Figure 7.

The emissions goals for these advanced PC plants are as

shown in Table 2.

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Each of the unit operations or systems that is utilized in a

flue gas cleaning train has normally been associated with the

treatment of one particular pollutant. An example would be that

a selective catalytic reduction system is used to reduce NOx.

However, the synergistic effects of each unit operation or system in the train on all the pollutants must now be recognized.

Some of these effects are positive and some may be negative. For

example, it is known that an SCR oxidizes elemental mercury into

ionic mercury. Oxidized mercury is much easier to remove in an

FGD system. Thus, making the SCR larger will increase mercury

removal in the FGD downstream. However, an SCR also oxidizes

SO2 to SO3, which becomes sulfuric acid, H2SO4. Sulfuric acid

forms a very fine mist, which is very difficult for a wet FGD to

remove.

The two plant configurations are summarized in Table 3.

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NOx is controlled by advanced low NOx burners and an advanced selective catalytic NOx reduction system. Figure 8 shows

the NOx performance goal in comparison with existing coalfired technology and how it compares with emissions from existing natural gas combined cycle power generation.

Table 4 shows the NOx emissions performance in several different equivalent measurements and how it compares to a state-ofthe-art natural gas combined cycle plant using dry low NOx combustion and with a nominal emissions rate of 9 ppm @ 15% O2.

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As can be seen, the NOx levels from this plant will be significantly lower than the current state-of-the-art for natural gas

combined cycle technology using dry low NOx combustion.

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The NOx level leaving the boiler and entering the SCR is a

function of the coal being burned, the burner design, the degree

of air staging, and mixing of the air and fuel. For high sulfur

coal applications, little or no air staging is used to avoid corrosion of the furnace tubes due to local sub-stoichiometric conditions. Although variations in the coal can have substantial impact on the NOx level leaving the boiler, a typical eastern bituminous coal with the best low NOx burner and minimal staging

can achieve approximately 0.31 lb/MBtu leaving the boiler.

The B&W DRB-4ZTM burner is designed to produce lower

NOx emissions without significant impact on unburned carbon

by featuring a patented transition zone. This zone acts as a buffer

between the fuel-rich flame core and secondary combustion air

streams. This design improves mixing and flame stability by

limiting recirculation between air streams. The DRB-4ZTM

burner, developed as part of the U.S. Department of Energy’s

Combustion 2000 program, is the product of extensive numerical modeling using B&W’s proprietary combustion modeling

technology. The prototype burner was refined through a program of large-scale combustion tests performed in B&W’s Clean

Environment Development Facility (CEDF) and is the newest

and most advanced coal burner B&W has commercially available. These burners are already in successful operation.

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The basic principle of conventional selective catalytic NOx

reduction is the reduction of NOx to N2 and H2O by the reaction

of NOx and ammonia (NH3). In the presence of the catalyst, the

following NOx reduction reactions occur:

NO Reduction:

4 NO + 4 NH3 + 02 → 4 N2 + 6 H20

NO2 Reduction:

6 NO2 + 8 NH3 → 7 N2 + 12 H20

2 NO2 + 4 NH3 + 02 → 3 N2 + 6 H20

Secondary reactions that can occur in the presence of the

catalyst are the oxidation of SO2 to SO3 according to:

SO2 + 1⁄2 O2 → SO3

and the oxidation of elemental mercury according to:

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catalyst

The synergistic impacts of these secondary reactions will be

described.

Commercial SCR installations on gas, oil, and coal-fired

power plants have demonstrated that NOx reductions of 90%

can routinely be achieved with low ammonia slip. The critical

parameters to consider in the design of an SCR are the level of

flyash, SO2 and SO3 in the flue gas, the trace metals present in

the flyash, and the injection, distribution and mixing of the

ammonia. Over the course of designing nearly 12,000 MW of

installed SCR systems, B&W has determined that achieving very

high NOx removal efficiencies requires increasingly uniform

NH3/NOx molar ratio profiles entering the reactor.

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Today, it is possible to design an SCR to provide 95% NOx

control if the mixing issues are adequately addressed. The degree of maldistribution in a NH3/NOx molar ratio profile is referred to as the coefficient of variation (Cv). The Cv is the standard deviation of the distribution of measured values, expressed

as a percentage of the average. The greater the Cv, the broader

the distribution, with maximum and minimum values located

farther out from the mean. Values less than the mean result in

insufficient NH3 to achieve the design reduction. Values higher

than the mean will meet the reduction required but will exceed

the design NH3 slip. A coefficient of variation of 5% is the current industry standard for NH3/NOx molar ratio uniformity on

high efficiency SCR systems. The objective for the advanced

plant is to achieve 95% NOx removal with 2 ppm average outlet

ammonia slip. If this goal is approached by the conventional

means, catalyst volume needed to compensate for the

maldistribution becomes excessive.

To minimize the catalyst volume requirement while maintaining low outlet ammonia slip, a blend uniformity of < 3% Cv

is targeted for the 95% removal SCR design. The methods to

achieve high blend uniformity are based on a combination of

advanced ammonia injection and mixing techniques developed

by B&W. The development of the advanced mixing system not

only considers the injection technique but also the equipment

arrangement. Numerical 3D modeling is used to evaluate the

impacts of plant arrangement and the injection and mixing techniques on the NH3/NOx molar ratio profile.

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The high level of sulfur in typical bituminous coals presents

a challenge to minimizing the formation of sulfuric acid (H2SO4).

A small portion of SO2 is oxidized to SO3 in the boiler. Additional SO2 oxidation occurs across the SCR due to the presence

of vanadium in the catalyst. The amount of oxidation is dependent upon the catalyst formulation, catalyst volume, and operating conditions. The SO3 combines with H2O vapor to form

H2SO4, which can cause corrosion of air heaters, fabric filter

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components, flue work, and stack. One method of preventing

this corrosion is to raise the air heater outlet temperature. This

approach is detrimental to the thermal efficiencies of the boiler

and power plant. To counteract the amount of SO3 formed both

by the catalyst and within the boiler and permit low air heater

outlet temperatures, an alkali reagent is injected upstream of

the SCR to selectively react with the SO3. The reagent injection

will reduce the SO3 loading to the air heater. As discussed in

the next section, considerable H2SO4 removal is also expected

in the pulse-jet fabric filter. Final polishing of the H2SO4 takes

place in the downstream wet ESP component of the wet FGD

absorber tower to meet the combined particulate and sulfuric

acid emission target of 0.006 lb/MBtu.

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In addition, the SCR favorably impacts mercury control in

the wet FGD absorber tower. The SCR increases the relative

amount of oxidized mercury, thus improving mercury control

in the wet FGD. Measurements from several European boilers

indicate that SCR catalysts oxidize elemental mercury. Essentially all coal-fired power boilers in Germany are equipped with

both SCR systems and limestone-based wet scrubbers. Total

mercury capture in these systems exceeds 80% system-wide.1

The International Energy Agency (IEA) has summarized the

experience of several power plants equipped with SCRs and has

noted an elemental mercury range from 40 to 60% of the total

vapor phase mercury upstream of the SCRs and only 2 to 12%

downstream of the SCR.2 Although the conversion of the form

of vaporous mercury across an SCR had been reported as early

as 1994, the recent EPA sponsored Information Collection Request (ICR) did not examine the impact of SCR on mercury

speciation. Of the approximately 75 power plants characterized

for mercury behavior in the EPA ICR study, very few included

an SCR. In those studies, speciation measurements across the

SCR were not conducted.

McIlvaine has recently identified 179 planned SCR systems

in 22 states.3

 B&W views SCR as an important element in the

development of an overall mercury control strategy for the utility industry and B&W has sponsored internal studies on the

conversion of mercury across SCRs.

B&W has performed tests at flue gas temperatures of 750F

and 350F using an SCR catalyst designed for coal applications

at B&W’s Research Center and observed substantial mercury

oxidation. Figure 9 illustrates the mercury oxidation that was

observed at 750F based on the Ontario Hydro analysis method

at the SCR inlet and outlet. On average, the percentage of oxidized mercury in the flue gas increased from 51% at the SCR

inlet to 93% at the SCR outlet, facilitating removal by downstream scrubbing.

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Fabric filters operate by passing flue gas through a woven or

felted fabric. The particulate in the flue gas is collected on the

fabric surface. The cake which forms on the fabric from the

collected particulate contributes significantly to collection efficiency. There are two types of fabric filters for utility applications: reverse air and pulse-jet. Today, the pulse-jet type is usually chosen over the reverse air type due to a pulse-jet’s smaller

size and lower cost. In a pulse-jet fabric filter, cake forms on

the outside of the bags. Particulate collected on the outside of

the bags is removed by a reverse pulse of high-pressure air.

Pulse-jet fabric filters are often capable of 99.9% removal efficiencies and can commonly reduce utility boiler particulate

emissions to 0.015 lb/MBtu.

A pulse-jet fabric filter is located downstream of the SCR

for primary particulate control. The SO3 removal process initiated with reagent injection upstream of the SCR continues in

the pulse-jet fabric filter. The flyash and residual unreacted reagent absorb SO3 as the reagent accumulates on the bag surface

while protecting the bags from deterioration by acid attack.

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The integrated advanced absorber tower illustrated in Figure 10 combines wet scrubbing and wet electrostatic precipita-

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tor (WESP) technologies for simultaneous SO2, sulfuric acid

mist, fine particulate and mercury control.

An advanced plant can be designed to achieve 99.5% SO2

removal with high sulfur coals. An SO2 emissions performance

comparison is shown on Figure 11.

The wet ESP incorporated in the top of the wet scrubber

serves to collect the scrubber gypsum carryover, residual flyash,

and sulfuric acid, enabling extremely low particulate emission

goals. The advanced plant makes provision for the removal of

sulfuric acid mist, which at this time is not reported or widely

regulated. As the traditional solid particulate pollutants of flyash

and scrubber carryover (gypsum) are controlled to very low levels, the sulfuric acid emissions, which are a product of SO2 to

SO3 conversion in both the combustion process and in the SCR

catalyst, become the dominant part of the total particulate. In

such plants, solid particulate is controlled to levels below 0.03

lb/MBtu and SO2 removal is 90%+. The conventional wet FGD

absorber tower on such a plant typically removes 50%+ of the

remaining particulate. Sulfuric acid can cause visible white

plumes trailing from the stacks of these plants after the dissipation of the water vapor. This problem has been noted at numerous high sulfur coal-fired units with conventional wet FGD systems with and without SCR systems. As little as 3-5 ppmv of

sulfuric acid can cause such a plume. In today’s environmentally conscious world, any visible plumes from existing plants

do not promote the acceptability of new coal-fired generation.

The particulate emission target level of 0.006 lb/MBtu, which

includes sulfuric acid mist, is approximately 50% below the most

stringent level permitted today, which does not include sulfuric

acid mist. As Figure 12 shows, when additionally considering the

sulfuric acid, the particulate emissions of an advanced plant could

be 90% below a limit for solid particulate only of 0.015 lb/MBtu.

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Conventional wet scrubbers utilize a wet limestone process

with in-situ forced oxidation to remove flue gas SO2 and produce a gypsum by-product according to the following overall

reaction:

CaCO3 + SO2 + 1/2 O2 + 2H2O → CaSO4 • 2H2O + CO2

The SO2 removal process begins as hot flue gas enters the absorber tower and is cooled and saturated by the scrubber slurry.

The flue gas then flows upward through the scrubber tray, which

uniformly distributes flue gas across the scrubber cross-sectional

area. As the gas passes through the layer of slurry on the scrubber

tray, the increased gas velocity, caused by the tray perforations,

generates a frothing action, promoting intimate gas-liquid contact.

The flue gas then passes through the scrubber spray zone, where

scrubber slurry is sprayed countercurrent to the flue gas flow, completing the SO2 removal process. The SO2 removal process includes

an in-situ forced oxidation system which converts calcium sulfite

(CaSO3 • 1⁄2H20) formed by the SO2 removal process to calcium

sulfate (CaSO4 • 2H20) or gypsum.

Limestone forced oxidation systems have achieved SO2 removal

efficiencies as high as 96 to 98% in a variety of power plants firing

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tained through the use of costly additives. It is possible, however, to meet low SO2 emission targets without additives while

minimizing additional capital and operating costs.

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The wet scrubber portion of the integrated advanced absorber

tower is a logical extension of existing technologies. In order

to achieve 99.5% removal efficiency, uniform gas distribution

is necessary to maximize gas-slurry contact in the absorber. One

cause of poor SO2 control is the bypass of the flue gas in areas

of low slurry concentration. Even very low levels of flue gas

bypass can adversely impact overall SO2 control. Inherent physical limitations in the arrangement of the spray headers in the

tower result in non-uniform distribution of the slurry in the spray

zone, with low slurry concentrations at the circumference. The

B&W-patented variable open tray is used to direct flue gas away

from the walls towards the center of the tower where a higher

concentration of slurry is present.

A wet scrubber contains multiple spray levels. The driving

force for mass transfer in the scrubber is the difference in the

partial pressure between the gas and the slurry. Due to the reduction of SO2 by the initial spray zones, the driving force for

mass transfer in the last spray zone is retarded. In order to meet

the high SO2 control target, fresh limestone feed is added to the

last spray zone header to provide additional driving force for

the SO2 reactions to occur.

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Integration of a wet ESP within the wet scrubber is in itself

a technology development. Very fine sulfuric acid mist is formed

in the scrubber as the flue gas containing H2SO4 is quenched at

the inlet of the absorber tower.

The wet scrubber does not effectively remove the resulting

droplets due to their very small size. Particulate emissions from

a wet scrubber operated on coal-fired flue gas are typically 40%

H2SO4 by weight. Another significant portion of the particulate

emissions from a wet scrubber can be gypsum carryover due to

entrainment of scrubber slurry in the outlet flue gas.

The wet ESP functions in a manner that is very similar to the

more familiar dry-type electrostatic precipitator, where charging of the particulate in a flue gas stream causes the charged

particles to be collected at the wetted wall surface by the strong

field strength near the wall. As in a dry system, there are independent charging and collection systems contained within the

collecting device and there are subsystems for power supplies

with controls, electrical isolation, purging, and water spray

cleaning. Although the collecting mechanisms for the wet and

dry type precipitators are similar, the advantages of the wet ESP

technology include the following:

1. Acid mist and solid particulate collection are not dependent on particulate resistivity.

2. The technology can be highly effective on the sub-micron particles and acid mist.

3. The collection surface cleaning by water washing prevents the re-entrainment of particulate back into the gas

stream.

4. The compact design of the wet ESP allows the integration of design with the wet scrubber.

5. Integration with the wet scrubber provides handling of

the wash water and solids from the wet ESP with the

scrubber slurry rather than in a separate tank and

blowdown system. The acidic water from cleaning the wet

ESP falls into the alkaline scrubber slurry and is neutralized.

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At least 90% mercury removal can be achieved through the

combined contributions of particulate removal in the fabric filter and oxidation of mercury in the SCR for subsequent capture

in the integrated advanced absorber tower by using additives

specifically selected for mercury removal. Because the additives are inexpensive, used in very small quantities, and there is

no separate mercury control device, the cost of mercury removal

will be an order of magnitude lower than with activated carbon

technologies. In addition, the mercury in the flyash and gypsum is in an insoluble form at concentrations sufficiently low

to be typically considered non-hazardous and suitable for utilization as a by-product.

The proprietary process of adding low-cost reagents to the

wet scrubber has been developed by B&W as a method to increase mercury capture in a wet scrubber to 90%. Mercury collection in a wet scrubber cannot be considered successful if the

collected mercury can be re-emitted into the environment. The

potential for re-emission of mercury from the by-products has

been investigated. Tests performed by B&W to date indicate

the form of mercury is normally stable and re-release to the

environment is not expected given the types of disposal practices or by-product uses for spent material from wet scrubber

systems. The extremely low concentration of mercury contained

in the gypsum is insoluble, thermally stable and not expected to

adversely impact its use for wallboard or for disposal in a landfill. In general, the mercury concentration in the scrubber gypsum will be lower than the mercury levels in naturally occurring gypsum mined for commercial use.

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The configuration of the low sulfur western coal-fired plant

was depicted in Figure 7.

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Today’s low NOx burners, as discussed above, can achieve

0.16 lb/MBtu burning PRB fuel with moderate staging. A typical SCR removal efficiency on a PRB unit today is 60% with 2

ppm of ammonia slip. As discussed above, the issue with achieving high NOx removal efficiency is mixing of the flue gas with

the ammonia. With a 95% removal SCR, an outlet NOx level of

0.008 lb/MBtu can be achieved on PRB fuel.

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For the PRB coal-fired advanced plant, SO2 will be controlled

by the E-LIDS process or Enhanced Limestone Injection Dry

Scrubbing as shown in Figure 13.4

 SO2 removal of 98% can be

achieved with a nominal 0.8% sulfur, 8,000 Btu/lb coal.

Limestone (CaCO3) is injected in the upper part of the furnace where it is calcined into lime (CaO) and SO2 removal begins. Low sulfur PRB coal contains naturally occurring calcium

oxide in the ash that supplies much of the reagent needed for

SO2 removal. The amount of limestone that must be injected

into the furnace as a supplemental reagent is therefore low. This

mitigates the concern of increasing the ash solids loading going through the boiler’s convection pass and the concern for

increased erosion and slagging/fouling.

The first evolution of this process was the so-called LIDS

process. In this process, limestone is injected into the furnace,

is calcined into lime, passes through the spray dry absorber

where some of the lime reacts with SO2, and the dry powder is

then collected in the fabric filter downstream of the spray dryer.

It is known from earlier work performed at B&W’s Research

Center that limestone that is calcined in the furnace and then

subsequently collected in a fabric filter downstream of a spray

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dry absorber tends to be of low reactivity. This is because the

CaO that is produced in the furnace receives a layer of CaSO4

on its surface by the reactions which take place in the spray dry

absorber. B&W’s earlier work demonstrated that CaO produced

in the furnace is best separated from the flue gas, slaked, and

then injected into the spray dry absorber.

In the E-LIDS process, a nominal 80% removal efficiency

particulate collector is installed upstream of the SCR. This has

the additional benefit of reducing the ash solids loading going

through the SCR catalyst. The material collected is sent to the

lime slaking system to produce the fresh slurry feed for the spray

dry absorber. The spray dry absorber is illustrated in Figure 14.

The dry powder carried with the flue gas from the spray dry

absorber is collected in the fabric filter. A portion of the material collected is recycled to the slaking system, and the remainder is sent to disposal.

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The speciation of mercury from low sulfur coal-fired units

tends to favor the elemental form, which is the most difficult

form of mercury to remove from the flue gas stream. The benefits of the SCR in converting elemental mercury into oxidized

mercury have been previously discussed. The larger amount of SCR

catalyst that is utilized in this advanced plant further enhances the

conversion of elemental mercury into oxidized mercury.

Another technology that can be utilized to boost mercury

removal is to inject small amounts of chloride with the coal

fuel.5 This process of “salting the coal” has been demonstrated

in Europe on spray dry absorber FGD systems.

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A distinct advantage of spray dryer FGD technology versus

conventional wet FGD technology (without a wet ESP) is that

the spray dry FGD system puts the very efficient dust collector

(the fabric filter) as the last unit operation in the flue gas cleaning train before the stack. The spray dryer has also cooled the