# Exhibit 8!"#$%$&'(')*+$%, - 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
NO

x , SO 2 , sulfuric acid mist, PM 2.5 , mercury, and particulate is here. There is also the potential need to lower CO 2 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 CO 2 . Emission control technologies for eastern bituminous high sulfur fuels that can achieve 0.016 lb/
MBtu NO

x , 0.04 lb/MBtu SO 2 , and 0.006 lb/MBtu particulate(including acid mist) are examined. For PRB coal, emission levels down to 0.008 lb/MBtu NO

x , 0.04 lb/MBtu SO 2 , and 0.006 lb/MBtu particulate with a high level of mercury capture can be achieved. This level of NO

x is less than the permit levels of many of today’s new gas turbine combined-cycle units.



## ()$%*+,'$-*)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 integratedgasification 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.



## ./0.1&)$023&$04&$3 Over the last ten years, higher efficiency pulverized coal plants have gone into commercial operation outside the U.S. The higher efficiencies are due to not only advanced steam cycles, but also improvements in turbines and reductions in power requirements for plant auxiliary equipment. Materials are currently available for some coals to allow steam conditions as high as 4500 psi and 1100F/1100F which, depending on site conditions and coal characteristics, can achieve heat rates as low as 8050 Btu/kWh (42.5% HHV efficiency). Materials are currently being developed to permit steam temperatures of 1200F and higher, depending on the corrosiveness of the coal ash. Pulverized coal power plant heat rate improvements versussteam cycle conditions are shown in Figure 1. (The actual operating plants have steam cycles close to the examples under which they are listed.). !"#$%$&'(')*+$%,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 CO 2emissions 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 (NO

x , SO

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

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### $'()$*'+,-./0',1$23-44-5(4$647 81',$9',1 The key drivers to increasing efficiency are reduced fuel cost and reduced CO 2emissions. 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 CO 2 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 NO

x 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. Againthe 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 throughthe 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
CO 2 emissions. !"#$%&', /01"$2'%3'45"2'6"25'%7'F9 ! '50*::*%7:;

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 NO

xemissions. Figure 4 shows the same comparison for SO 2 . A typical removal in a wet scrubber is 90% with some today as high as 95% to 98%. Again, as the SO 2removal rate in the scrubber increases, the effect of cycle heat rate improvement on further SO 2removal decreases.@ !"#$%$&'(')*+$%, 

## 56-##-*)#07-6-$#80!09%-3:02-#$*%;
In 1971, the New Source Performance Standards for new coal-fired power plants in the U.S. were 0.7 lb NO

x/MBtu, 1.2 lb SO 2 /MBtu, and 0.1 lb particulate /MBtu. These regulations were tightened in 1979. For NOx, the regulation was 0.5 or 0.6
lb NO

x /MBtu depending on the type of coal. The regulation for
SO 2 was a sliding scale from 1.2 down to 0.3 lb SO 2 /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.



### :)6'(.1)$*0'(,$!5(;-</+',-5(4 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 NO

x burners, an advanced high removal efficiency selective catalytic NO

x 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. -./0&')
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! 32 " 45 #$ G+"72'<'O-PPDQ A;-R A;.. A;A-A G+"72'!'O-PP@Q A;-R A;-S A;A-T G+"72'8'O-PPUQ A;-R A;-R A;A-T G+"72'V'O-PPSQ A;-A A;-A A;A-T G+"72'W'O.AA-Q A;AP A;-U A;A-- G+"72'C'O.AA-Q A;AT A;-. A;A-T The plant configuration for low sulfur western coal consists
of low NO

x 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.



### =/0,->?500/,'(,$:??+5'.@ 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 NO

x .However, the synergistic effects of each unit operation or system in the train on all the pollutants must now be recognized. Some of t hese 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
SO 2to SO 3 , which becomes sulfuric acid, H 2 SO 4 . 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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NO

x is controlled by advanced low NO

x burners and an advanced selective catalytic NO

xreduction system. Figure 8 shows
the NO

xperformance 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 NO

xemissions performance in several different equivalent measurements and how it compares to a state-ofthe-art natural gas combined cycle plant using dry low NO

xcombustion and with a nominal emissions rate of 9 ppm @ 15% O 2 .

!"#$%&'6 G8'1+"72'3%6'4*X4':?+3?6'#*2?0*7%?:'$%"+;!"#$%$&'(')*+$%, U As can be seen, the NO

x levels from this plant will be significantly lower than the current state-of-the-art for natural gas combined cycle technology using dry low NO

x combustion.



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The NO

x 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 sulfurcoal 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 NO

xlevel leaving the boiler, a typical eastern bituminous coal with the best low NO

x 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
NO

x 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’sCombustion 2000 program, is the product of extensive numerical modeling using B&W’s proprietary combustion modelingtechnology. 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 newestand most advanced coal burner B&W has commercially available. These burners are already in successful operation. !"#$%&'7 G8'1+"72'3%6'+%J':?+3?6'GI!'$%"+;

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### 234$'5-60)"(*7 The basic principle of conventional selective catalytic NO

x reduction is the reduction of NO

xto N 2 and H 2 O by the reaction
of NO

xand ammonia (NH 3 ). In the presence of the catalyst, the following NO

x reduction reactions occur: NO Reduction:
4 NO + 4 NH 3 + 0 2 → 4 N 2 + 6 H 2 0
NO 2 Reduction: 6 NO 2 + 8 NH 3 → 7 N 2 + 12 H 2 0
2 NO 2 + 4 NH 3 + 0 2 → 3 N 2 + 6 H 2 0 Secondary reactions that can occur in the presence of the catalyst are the oxidation of SO 2 to SO 3 according to:
SO 2 + 1⁄2 O 2 → SO 3 and the oxidation of elemental mercury according to: Hg 0 Hg 2+ 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 NO

x 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, SO 2and SO 3 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 NO

x removal efficiencies requires increasingly uniform
NH 3 /NO

x molar ratio profiles entering the reactor.



### 234$,+-.*"/"01$8795*-+:+*;< Today, it is possible to design an SCR to provide 95% NO

xcontrol if the mixing issues are adequately addressed. The degree of maldistribution in a NH 3 /NO

x 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 NH 3 to achieve the design reduction. Values higher than the mean will meet the reduction required but will exceed the design NH 3 slip. A coefficient of variation of 5% is the current industry standard for NH 3 /NO

x molar ratio uniformity on high efficiency SCR systems. The objective for the advanced plant is to achieve 95% NO

x 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 theimpacts of plant arrangement and the injection and mixing techniques on the NH 3 /NO

x molar ratio profile.



### 234$=:>5-;$"*$2& "

### $&?@75;@"* The high level of sulfur in typical bituminous coals presents a challenge to minimizing the formation of sulfuric acid (H 2 SO 4 ). A small portion of SO 2is oxidized to SO 3 in the boiler. Additional SO 2oxidation occurs across the SCR due to the presenceof vanadium in the catalyst. The amount of oxidation is dependent upon the catalyst formulation, catalyst volume, and operating conditions. The SO 3 combines with H 2 O vapor to form
H 2 SO 4 , which can cause corrosion of air heaters, fabric filter

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"'50*::*%7:'1563%60"7$5;!"#$%$&'(')*+$%, R 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 SO 3 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 SO 3 . The reagent injection
will reduce the SO 3 loading to the air heater. As discussed in the next section, considerable H 2 SO 4 removal is also expected in the pulse-jet fabric filter. Final polishing of the H 2 SO 4 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.



### 234$=:>5-;$"*$A+)-()1$2>+-@5;@"* 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 boilersindicate 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 earlyas 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 methodat the SCR inlet and outlet. On average, the percentage of oxidized mercury in the flue gas increased from 51% at the SCRinlet to 93% at the SCR outlet, facilitating removal by downstream scrubbing.



### A'B+-.$A-0,1+ 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 thecollected 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 SO 3 removal process initiated with reagent injection upstream of the SCR continues inthe pulse-jet fabric filter. The flyash and residual unreacted reagent absorb SO 3 as the reagent accumulates on the bag surface while protecting the bags from deterioration by acid attack.



### C(,1<+',1)$:)6'(.1)$:B45+B1+$D5E1+The integrated advanced absorber tower illustrated in Figure 10 combines wet scrubbing and wet electrostatic precipita-

!"#$%&'I 9,*="2*%7'%3'056$?6\'"$6%::'F8I'$"2"+\:2'"2'RUAC;T !"#$%$&'(')*+$%, tor (WESP) technologies for simultaneous SO 2 , sulfuric acid mist, fine particulate and mercury control. An advanced plant can be designed to achieve 99.5% SO 2 removal with high sulfur coals. An SO 2 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 flyashand scrubber carryover (gypsum) are controlled to very low levels, the sulfuric acid emissions, which are a product of SO 2 to SO 3 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 SO 2 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 whiteplumes 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 ofsulfuric 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.



### B+;$2-)(CC+)$'5-60)"(*7 Conventional wet scrubbers utilize a wet limestone process with in-situ forced oxidation to remove flue gas SO 2and produce a gypsum by-product according to the following overall reaction:

CaCO 3 + SO 2 + 1/2 O 2+ 2H 2 O → CaSO 4 • 2H 2 O + CO 2

The SO 2 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, wherescrubber slurry is sprayed countercurrent to the flue gas flow, completing the SO 2 removal process. The SO 2removal process includes an in-situ forced oxidation system which converts calcium sulfite (CaSO 3 • 1⁄2 H 2 0) formed by the SO 2removal process to calcium sulfate (CaSO 4 • 2H 2 0) or gypsum. Limestone forced oxidation systems have achieved SO 2 removal efficiencies as high as 96 to 98% in a variety of power plants firing a variety of fuels. The high removal efficiencies are typically ob- !"#$%&')J /725X6"25='"=>"7$5='"#:%6#56'2%J56; !"#$%&')) F9 ! '50*::*%7:'1563%60"7$5'$%01"6*:%7;!"#$%$&'(')*+$%, Ptained through the use of costly additives. It is possible, however, to meet low SO 2 emission targets without additives while minimizing additional capital and operating costs.



### B+;$DEF$,+-.*"/"01$8795*-+:+*;< 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 SO 2 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 SO 2control. 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 thepartial pressure between the gas and the slurry. Due to the reduction of SO 2 by the initial spray zones, the driving force for mass transfer in the last spray zone is retarded. In order to meet the high SO 2 control target, fresh limestone feed is added to the last spray zone header to provide additional driving force for
the SO 2 reactions to occur.



### B+;$G2H$=*;+0)5;@"* 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 H 2 SO 4 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%
H 2 SO 4 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 themore 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 strongfield 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 wetESP falls into the alkaline scrubber slurry and is neutralized.



### =1+./+F$!5(,+50 At least 90% mercury removal can be achieved through thecombined contributions of particulate removal in the fabric filter and oxidation of mercury in the SCR for subsequent capture in the integrated advanced absorber tower by using additivesspecifically selected for mercury removal. Because the additives are inexpensive, used in very small quantities, and there is no separate mercury control device, the cost of mercury removal will be an order of magnitude lower than with activated carbontechnologies. In addition, the mercury in the flyash and gypsum is in an insoluble form at concentrations sufficiently lowto be typically considered non-hazardous and suitable for utilization as a by-product. The proprietary process of adding low-cost reagents to thewet scrubber has been developed by B&W as a method to increase mercury capture in a wet scrubber to 90%. Mercury collection in a wet scrubber cannot be considered successful if the collected mercury can be re-emitted into the environment. The potential for re-emission of mercury from the by-products has been investigated. Tests performed by B&W to date indicate the form of mercury is normally stable and re-release to theenvironment is not expected given the types of disposal practices or by-product uses for spent material from wet scrubber systems. The extremely low concentration of mercury contained in the gypsum is insoluble, thermally stable and not expected toadversely impact its use for wallboard or for disposal in a landfill. In general, the mercury concentration in the scrubber gypsum will be lower than the mercury levels in naturally occurring gypsum mined for commercial use. !"#$%&')( 8%01"6"2*>5'1"62*$?+"25'650%>"+'*7$+?=*7X'"$*='0*:2;-A !"#$%$&'(')*+$%, 

## 7*?0>,1:,%0@3#$3%)0A.49B0/*&10.1&)$ /*):-<,%&$-*) The configuration of the low sulfur western coal-fired plant was depicted in Figure 7.



### %"
"

### $!5(,+50 Today’s low NO

x burners, as discussed above, can achieve0.16 lb/MBtu burning PRB fuel with moderate staging. A typical SCR removal efficiency on a PRB unit today is 60% with 2ppm of ammonia slip. As discussed above, the issue with achieving high NO

x removal efficiency is mixing of the flue gas with the ammonia. With a 95% removal SCR, an outlet NO

x level of 0.008 lb/MBtu can be achieved on PRB fuel.



### &" ! 

### $!5(,+50 For the PRB coal-fired advanced plant, SO 2will be controlled by the E-LIDS process or Enhanced Limestone Injection Dry Scrubbing as shown in Figure 13. 4 SO 2 removal of 98% can be achieved with a nominal 0.8% sulfur, 8,000 Btu/lb coal. Limestone (CaCO 3 ) is injected in the upper part of the furnace where it is calcined into lime (CaO) and SO 2removal begins. Low sulfur PRB coal contains naturally occurring calcium oxide in the ash that supplies much of the reagent needed for
SO 2 removal. The amount of limestone that must be injected into the furnace as a supplemental reagent is therefore low. Thismitigates 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 SO 2 , 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

!"#$%&')* W74"7$5='H*05:2%75'/7_5$2*%7'V6\'F$6?##*7X'G6%$5::'OWLH/VFQ; dry absorber tends to be of low reactivity. This is because the CaO that is produced in the furnace receives a layer of CaSO 4 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 dryabsorber 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.



### =1+./+F$!5(,+50 The speciation of mercury from low sulfur coal-fired units tends to favor the elemental form, which is the most difficultform of mercury to remove from the flue gas stream. The benefits of the SCR in converting e lemental 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.



### A'B+-.$A-0,1+ 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