MEGA SYMPOSIUM 2008

PERFORMANCE UPGRADES FOR LOW-SULFUR WET 

SCRUBBERS

PAPER # 134 

Andrew J. Carstens, William E. Siegfriedt, and 

Rajendra Gaikwad 

Steven Escobedo 

Sargent & Lundy LLC Chicago Illinois CPS Energy, San Antonio, TX 

ABSTRACT

The class of wet FGD systems installed in the late 1970s through early 1990s included a large 

number of units burning low-sulfur coal. The Clean Air Act Amendments of 1977 required that 

these units achieve a minimum of 70% SO2 reduction from their already-low emissions. Based 

on this requirement, these units typically included partial FGD bypass and only modest SO2

removal in the wet absorber. Regulatory considerations such as the Clean Air Visibility Rule 

(CAVR) and, until recently, the Clean Air Interstate Rule (CAIR), have resulted in owners of 

these units to consider improving their performance. This paper explores various methods that 

have been used to achieve these performance improvements and the pros and cons of each. 

Sargent & Lundy has recently performed an optimization study for CPS Energy (San Antonio, 

Texas) to find the most cost-effective way to upgrade their J.K. Spruce Unit 1 FGD system. The 

paper reviews the available technologies, the projected impact of each and the estimated cost of 

each. 

INTRODUCTION

Upgrading wet scrubbers requires not only a thorough understanding of the key process variables 

involved, but also requires a thorough review of site-specific design considerations as well as the 

capabilities of the existing equipment to identify cost-effective opportunities to improve scrubber 

performance. The main objective of this paper is to present the design options that were 

considered in Sargent & Lundy’s recent study to upgrade the wet FGD system at CPS Energy’s 

J.K. Spruce Unit 1. However, an additional goal is to discuss design options that are relevant to 

other units firing low-sulfur coals designed from the 1970s to the early 1990s. This paper 

reviews the advantages and disadvantages, both from a process standpoint and an economic 

standpoint, of design options available for this class of units. 

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The topics discussed are as follows: 

• Upgrading to treat 100% of the flue gas 

• Operation with or without spare absorbers 

• Scrubber modifications to improve SO2 absorption 

o Improving gas flow distribution 

o Improving spray level coverage 

o Adding Frothing Trays 

o Increasing Liquid-to-Gas Ratio (Increasing Recycle Flow) 

o Injecting Dibasic Acid (DBA) 

• Assuring continued byproduct quality 

UPGRADING TO TREAT 100% OF THE FLUE GAS

There are two basic types of bypasses on this class of units. The first is a partial bypass, which 

was conceived to reduce the amount of flue gas that is treated to minimize capital and O&M 

costs as well as provide reheat to the absorber outlet gas. The second type of bypass is a full 

bypass that, in addition to offering the same benefits as the partial bypass, allows the FGD 

system to be bypassed entirely to ensure boiler operation is not dependent on the FGD system. 

The reliability of early absorbers was low due largely to a poor understanding of the complex 

chemistry associated with flue gas desulfurization systems, and the full bypass provided a means 

to protect boiler availability. New unit designs do not use bypasses because FGD reliability has 

improved substantially enough to render them unnecessary. For existing units with bypasses, the 

1990 Clean Air Act Amendments’ advent of the SO2-allowance trading program created an 

opportunity to either buy fewer allowances or bank/sell more allowances by upgrading scrubber 

performance. Furthermore, since the consumption of SO2 allowances will change from one per 

ton of SO2 to two per ton of SO2 in 2010, effectively doubling the value of allowances, there is a 

strong economic driver for utilities with FGD bypass ducts to stop bypassing flue gas. 

So why don’t utilities with bypasses simply close their dampers and be done with it? 

Unfortunately, it is not as easy as simply closing the dampers. The reality is that eliminating the 

controlled bypass in a partial-scrubbing FGD system is an intricate topic that must be carefully 

examined. It is not feasible to simply close off the bypass without reviewing three important 

issues: 

• Chimney liner material suitability for wet stack operation 

• Assurance of flue gas path 

• Protection of absorber materials 
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As mentioned previously, the hot bypass gas reheats the saturated absorber outlet gas to 

temperatures well above the moisture dew point. Depending on the extent of reheat, materials 

that are less resistant to acid corrosion (and hence materials that are less expensive), can be 

selected for chimney liners. Because of this, many of the units with bypasses avoided significant 

capital cost from acid-resistant liners such as alloy and fiberglass. 

However, eliminating the bypass raises the question of whether the existing chimney liner 

material is adequate for the wet stack operation. If it is not, the cost of demolishing the existing 

liner and replacing it with FRP or alloy would have to be included as part of the FGD upgrade 

project. Even worse, the typical design velocities of 90 to 100 fps for dry stack operation are no 

longer valid for wet stack operation. The significantly lower EPRI-recommended maximum 

velocities of 50 to 60 fps, depending on the liner material used, may determine whether the 

existing chimney liner is too small for wet service and needs to be completely replaced. 

In addition to liner material and velocity considerations, the logic for the FGD absorber module 

isolation dampers must be reviewed to be sure that when the bypass is eliminated, there is no 

possibility that the flue gas path from the boiler can be shut off in violation of fire code and 

insurer’s rules. The logic must be modified such that the last module cannot close off until the 

boiler has cooled. 

The third issue of absorber material protection then becomes a corollary of assuring an open flue 

gas path. Plastic and rubber materials in the absorber must be protected from raw, 300°F flue 

gas. There must be assurance that whenever an absorber is open to flue gas, there is quenching 

of the flue gas. If all the slurry pumps fail (such as in a station blackout), an emergency 

quenching system must be operational. This is typically a small spray system in the absorber 

inlet nozzle using water provided from the diesel fire pump or other reliable source. 

To upgrade an FGD system to treat 100% of the flue gas, there are two possible solutions: 

• Add tight-shutoff dampers with a seal air system 

• Use blankoff plates to eliminate the bypass altogether 

Controlled bypass dampers are typically opposed blade and are throttled to control stack inlet 

temperature above the acid dew point. Therefore, they are not designed to operate in the closed 

position. Even when such dampers are fully closed, upwards of 10% leakage can occur. The 

opposed-blade dampers can be replaced with parallel-blade dampers, but it is important to realize 

that the tight shutoff bypass application is a severe application. On one side of the damper, there 

is dry, acid-laden flue gas at 300°F. On the other side, there is flue gas at ~135°F saturated with 

water and acidic mist. These differences are a concern from the standpoint of materials as well 

as thermal design of the damper. 
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For the Spruce 1 upgrade project, two independent parallel-blade dampers were considered for 

each bypass duct, one near the bypass connection to the inlet duct and one near the bypass 

connection to the outlet duct. The damper at the inlet duct would be built entirely of carbon steel 

to match the inlet duct. The damper at the outlet duct would be built entirely of alloy or alloyclad steel to match the outlet duct. To ensure proper isolation, there must be a continuous supply 

of seal air. Loss of seal air can result in serious damage to materials of construction as well as 

consume SO2 emission allowances. Sargent & Lundy recommended against trying to satisfy this 

application with a double-louver damper because of insufficient space where the existing 

opposed-blade damper was installed. Furthermore, installing one double-louver damper per 

bypass duct would have had the disadvantage of leaving dead space that could lead to corrosion 

problems if seal air flow failed. It should be noted that inadequate maintenance of seal air fans 

and duct systems is the primary reason for damper trouble. 

The second option for upgrading the system to treat 100% of the flue gas is to seal the bypass 

ducts with blank-off plates. Blanking off the bypass involves breaking the connections of the 

bypass at both ends. As with the dampers, the material would be consistent with the 

environment to which it is exposed. Therefore, the blank-off plate at the inlet duct would be 

built entirely of carbon steel, and the blank-off plate at the outlet duct would be built entirely of 

fiberglass, alloy or alloy-clad steel. The bypass duct may be abandoned in place, although it may 

be advantageous to remove it and sell it for scrap. This option has no O&M costs associated 

with it, in contrast to the seal air system that would be required for the tight shutoff damper 

system. In addition, Sargent & Lundy estimated that, for CPS Energy’s Spruce 1 upgrade 

project, it would cost almost $200,000 less to seal the bypass duct compared to a damper system 

with seal air. 

OPERATION WITH OR WITHOUT SPARE ABSORBERS

The fact that incorporating a bypass into early FGD systems allowed concerns of FGD reliability 

to remain independent of boiler reliability has already been discussed. What wasn’t mentioned 

previously was that the EPA only allowed the inclusion of bypasses in FGD designs when spare 

absorbers were available (1). Therefore, most of the low sulfur absorbers discussed in this paper, 

designed to remove approximately 70% of the SO2 with bypass reheat systems, have 3 to 5 

absorber modules instead of the single absorber design that is now common in new FGD 

systems. In CPS Energy’s case, a 3 by 50% absorber design was supplied for J.K. Spruce Unit 1. 

Most utilities with FGD systems now achieve a high degree of absorber availability. Does that 

mean that all the absorber modules should be put into operation, leaving no spare? Certainly it 

costs more to operate three absorbers compared to two. So the question becomes: Is the 

additional cost of operating three absorbers offset by higher SO2 absorption? The answer is a 

resounding maybe. With the same flue gas flow, increasing the number of spray levels in 

operation assures a higher L/G, but a hit is taken in the system mass transfer characteristics 

because of the lower absorber gas velocities. There is a point below which the lower velocity 
MEGA SYMPOSIUM 2008

results in lower SO2 absorption despite the higher L/G. In short, there’s a balance. The key to 

determining the value of multiple absorber operation is to find out in which direction the scales 

are leaning. 

To better understand the impact of multiple absorber operation on the system’s SO2 removal the 

equation approximating the “two film” theory of FGD absorber performance is shown below: 

G

AK

outSO

inSO *

)1ln( ),ln(

),ln(

2

2 η ≅−−= (Equation 1)

In Equation 1, η is defined as fractional SO2 removal, K is the average overall mass transfer 

coefficient for the gas phase (lb/hr-ft2), A is the liquid surface area available for mass transfer 

(ft2

), and G is the overall gas flow rate (lb/hr). Clearly, higher system mass transfer coefficients, 

higher surface areas, and lower gas flow rates will all result in higher absorber SO2 scrubbing 

efficiencies. But how do we change these process variables operationally? 

In the case of Spruce 1, we could change the mode of operation from its typical configuration of 

2 absorbers on-line and one off-line to include all three absorbers in operation. For this first 

case, let’s assume that the number of spray levels is the same; so now instead of three spray 

levels in two absorbers, there are two spray levels in three absorbers. What effect does this have 

on the K, A, and G parameters from Equation 1? Starting with the easiest to understand, the 

same coal is being fired with the same heat input, so the flue gas flow (G) has not changed at all. 

The gas flow has merely been redistributed to the three absorbers instead of two. The A, or 

liquid surface area available, has not changed either because the total amount of liquid, relative 

to the gas has not changed as there are still only 6 spray levels in service. 

The impact on the mass transfer coefficient (K) is not as obvious. The K term is partly 

influenced by alkalinity and increases with higher pH levels. However, higher pH levels also 

increase the amount of undissolved limestone in the reaction tank, and, therefore, increases the 

reagent consumption (2), which translates to higher limestone consumption for the same SO2

removed. For a limestone FGD system, the pH is typically controlled between 5 to 6, and for the 

purposes of this paper is assumed relatively constant. The K term is also a function of individual 

gas and liquid mass transfer coefficients which depend on droplet size and relative velocities 

between gas and liquid. The droplet sizes are unchanged since no changes to the nozzles were 

made, but the velocity of the gas relative to the liquid decreases when the number of operating 

absorbers was changed from two to three. The decrease in velocity, lowers the system 

turbulence and mass transfer coefficient, which results in lower SO2 diffusion, and consequently, 

lower SO2 absorption. 

What about changing the operating scenario from two absorbers with a total of 6 spray levels to 

three absorbers with a total of 9 spray levels in operation? As in the previous case, there is no 

change in the gas flow and there is a reduction in absorber velocity that works against increased 

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SO2 removal. However, in this case, the liquid-to-gas ratio (L/G) increases, which corresponds 

to an increase in the liquid surface area available for mass transfer. Since there are competing 

effects in this scenario, it is more complicated to predict performance changes. For CPS 

Energy’s Spruce Unit 1, Sargent & Lundy determined that operating all three absorbers with nine 

spray levels would increase the SO2 absorption compared to two absorbers with six spray levels. 

However, there are increased O&M costs including a significant impact due to operating all nine 

pumps and a small additional load on the ID fans for this case. While it may seem as though it’s 

always favorable to raise the system L/G, the greater O&M costs might make multiple absorber 

operation less economically attractive compared to other equipment modifications discussed in 

the next section. 

It is important that the individual system characteristics be analyzed to determine the most costeffective solution for each situation. In certain cases, accepting higher O&M costs to save 

capital expenditures may make sense. In other cases, investing in scrubber upgrades may costeffectively meet the utitility’s target SO2 removal. Of course, there are other challenging 

questions with an FGD upgrade project. Should each absorber be upgraded, or should the spare 

be decommissioned to save capital cost? If all absorbers are upgraded, will the improvements 

make it more economically attractive to put all the absorbers in operation? The following 

sections discuss in more detail some of the challenges involved with improving the absorber 

performance. 

SCRUBBER MODIFICATIONS TO IMPROVE SO2 ABSORPTION 

In order for SO2 removal to occur, molecules of SO2 need to come into contact with molecules of 

H2O and CaCO3 in slurry. It’s just that simple. The complexity comes into play when deciding 

how best to get the molecules to find each other. Obviously removing the bypass, as discussed 

above, is going to increase the probability that the SO2 molecules that would have exited through 

the bypass duct will contact the slurry and therefore be absorbed. However, if there are already 

problems with flow distribution, either with the gas flow into the absorber or the liquid coverage 

by the spray levels, the success of other system modifications may be severely limited. 

Improving Gas Flow Distribution 

On the gas side, improving flow distribution can have several advantages. For one, it can reduce 

the amount of energy wasted as the gas navigates the turns in the ducting, which may reduce the 

ID fan power consumption and thereby reduce operating costs. In addition, and perhaps more 

importantly, more controlled flow profiles going into an absorber can result in more even flow 

distribution across each absorber and put more flue gas in contact with slurry from the spray 

levels. This increase in contact between the gas and slurry leads to a higher amount of SO2

absorbed without any other system modifications. 
MEGA SYMPOSIUM 2008

To better understand the flow distribution at Spruce 1, computational fluid dynamics (CFD) 

modeling was employed to analyze the gas flow characteristics. To do this, Sargent & Lundy 

utilized ANSYS CFX, which is a suite of programs for the prediction of laminar and turbulent 

flow, as well as heat transfer. To keep computations manageable, the CFD simulations were 

divided into two sections: inlet ductwork and absorber modules. Each section of the FGD 

system was simulated according to the current design as well as with potential remedial 

modifications (i.e. guide vanes, turning vanes, etc.). 

 

Absorber Inlets 

ID Fan Outlets 

Figure 1: Absorbers A and B Operating: Plan View of Absorber Inlet Duct Before 

Modification (Left) and After (Right) 

The duct configuration for the FGD system at Spruce 1 is symmetric only with respect to two 

absorbers. Two of the absorbers are in-line with the two ID fans, but the third absorber is located 

in between the other two and receives gas from one or both of the ID fans. Figure 1 shows twoabsorber operation with the middle absorber in service both before and after incorporating flow 

improvement devices. On the left of Figure 1, there are areas of recirculation, the flue gas 

collides with the plenum wall, and the inlet duct to the absorber is under-utilized (blue area). On 

the right of Figure 1, straightening vanes help grab the gas and guide it around the corner of the 

plenum. With the help of turning vanes and a perforated gas distribution plate, the flow profile 

going to the middle absorber is significantly improved with minimal impact on the system ΔP. 

Currently CPS avoids operating the middle absorber because of instability, but S&L believes 

these improvements will enable it to become part of the regular absorber rotation. 

Improving Spray Level Coverage 

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The importance of another flow modification recommended as part of the Spruce 1 study can be 

seen in Figure 2. The existing system does not contain any turning vanes at the ID fan discharge. 

As a result, the CFD model showed that the flue gas hugs the top of the inlet duct (not pictured) 

and creates cyclonic patterns that cause portions of the bottom spray level to be under-utilized, as 

shown in Figure 2. The bulk of the gas is directed to the center of the bottom spray level while 

some gas is circulated to the back of the absorber before turning and entering the bottom spray 

level. The CFD model predicts that adding turning vanes to the ID fan outlet results in much 

better utilization of the inlet duct, which causes the gas to be spread much more evenly across the 

bottom spray level. The improved gas distribution should boost the efficiency of the bottom 

spray level and improve overall SO2 removal. 

Figure 2: Plan View 5 Feet Below Bottom Spray Level Before (Left) and After (Right) 

Although the previous two examples discuss flow distribution of the flue gas, the liquid slurry 

distribution from the spray levels is equally important. Adequate liquid coverage from the spray 

levels is critical to ensure full advantage is taken as the gas passes through a spray level. Spray 

nozzles that leave significant gaps in spray coverage result in regions of low resistance to flow. 

These low resistance regions provide potential paths for the acid flue gas to pass through a spray 

level untreated. Gas passing through coverage gaps near the absorber tower walls is referred to 

as “sneakage,” while gas passing through gaps in the center of the tower is referred to as 

“laning.” 

Figure 3 shows the predicted spray pattern below one of the spray levels at CPS Energy’s Spruce 

1 unit with the existing 90° spray angle nozzles. The patterns shown are slices taken at 5 feet 

below the spray levels and assume there is no droop in the 90° spray angle as the liquid falls. 

The solid portions are areas where there is no coverage or areas where only one nozzle provides 

coverage. These are highlighted to illustrate regions that may be subject to sneakage or laning. 

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It can be seen on the left of Figure 3 that there are significant areas where slurry coverage is suboptimal. 

Anti-sneakage rings, offered by some FGD suppliers, are annular baffles located below spray 

levels that create curtains of liquid through which gas flowing near the perimeter of the tower 

must pass. The anti-sneakage rings eliminate the low resistance regions created by coverage 

gaps along the circumference of the absorber wall. 

Existing Spray Coverage 120° Nozzles and Anti-sneakage Rings 

Existing Nozzle 

Locations 

Poor Coverage Anti-sneakage Wall 

Rings 

Figure 3: Existing Coverage (Left) and Predicted Coverage with 120° Nozzles and AntiSneakage Wall-Rings (Right). 

The right side of Figure 3 shows the projected spray pattern if 120° spray angle nozzles were 

installed at all central locations of each spray level. The spray pattern from the 120° nozzles will 

droop or sag compared to the 90° nozzles, which is taken into account in the projected coverage 

shown in Figure 3. The red circle is meant to approximate the coverage provided by antisneakage rings. Since the anti-sneakage rings help rectify coverage gaps along the walls, 

replacing the nozzles along the outside edge of the spray level with 120° nozzles is not necessary 

and would increase slurry impingement on the absorber walls. In other words, using higher 

spray angle nozzles along the absorber wall would result in higher slurry velocities contacting 

the vessel shell, which would lead to increased erosion at the vessel wall in those locations. 

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In addition to changing nozzle spray angle and incorporating anti-sneakage rings, spray coverage 

can be improved by skewing the spray header alignment. Typically new FGD systems are 

designed with spray levels that are not vertically aligned. The inlet headers enter the absorber at 

staggered radial angles to minimize coverage gaps. Although this skewed arrangement is 

typical, the main headers on many older designs, including Spruce 1, are aligned. Therefore, 

another potential modification to upgrade performance at Spruce 1 includes reconfiguring the 

main headers. For this specific case, it was estimated by S&L that altering the header design was 

not a cost-effective modification and was not considered in the economic analysis. 

Adding Frothing Trays 

Figure 4: Example Absorber Frothing Tray 

Some FGD suppliers incorporate frothing trays to increase contact between the flue gas and 

slurry. The addition of a frothing tray helps both gas-side and liquid-side flow distribution. 

Figure 4 shows an example of a frothing tray. The trays are installed above the top of the inlet 

flue gas duct, but 5 to 6 feet below the bottom spray level; so adequate room in this zone is 

necessary for this option to be feasible. The tray covers the entire cross-sectional area of the 

tower and contains perforations to allow liquid to flow down to the reaction tank and gas to flow 

upward and through the spray levels above. Flue gas passing up through the holes in the tray 

blows bubbles in the slurry on top of the tray. The froth may be 4 to 8 inches high. Vertical 

baffles are installed on the tray to minimize migration of the froth, avoiding areas where flue gas 

could blow through untreated. 

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A frothing tray can provide even more benefit than an additional spray level and can result in 

significant improvements in SO2 removal. The froth effectively provides a high surface area of 

liquid to contact the gas, and therefore provides excellent mass transfer. The disadvantages of 

this option are the capital investment required and the increased operating costs due to higher ID 

fan power consumption associated with the additional ΔP across the tray. The tray would add a 

nominal 2 to 3 in. w.c. ΔP to the system, depending on the exact design and open area of the tray. 

Increasing Liquid-to-Gas Ratio (Increasing Recycle Flow) 

Another design option to increase contact between the flue gas and slurry is to modify the 

recycle pumps to provide a higher liquid flow. As mentioned previously, a higher L/G would 

increase the liquid surface area available and would increase SO2 absorption. This option is a 

question of the capability of the existing recycle slurry pump system. If the recycle slurry lines 

are already close to the maximum allowable velocity of this service (10 fps), increasing pump 

flow is not a viable option without changing the piping to a larger diameter. Installing new 

piping could be cost-prohibitive. A thorough analysis of the limitations of the existing pumps is 

also required. If the pumps are already running out on their performance curves, pump 

modification may not be feasible or cost-effective. If the pumps are belt or gear driven and can 

be changed to increase pump speed without requiring new motors, this may be a cost-effective 

upgrade option. If new motors are required, modifying the pumps becomes a significantly less 

appealing option economically. 

Injecting Dibasic Acid (DBA) 

One final way to increase the system reactivity is to inject dibasic acid (DBA) to speed the 

neutralization of protons formed with the SO2 absorption. 

SO2 + H2O → H2SO3 (Equation 2)

H2SO3 → H+ + HSO3⎯ (Equation 3)

CaCO3 + H+ + HSO3⎯ → Ca+2 + SO3

=

 + H2O + CO2 (Equation 4)

Equation 2 shows how SO2 is absorbed into the water phase to form sulfurous acid, which 

dissociates according to Equation 3. Without DBA injection, neutralization occurs when the 

CaCO3 from the limestone is dissolved, as shown in Equation 4. If the acidity was not 

neutralized by the limestone, the pH in the reaction tank would continue to drop until no more 

SO2 could be absorbed. The rate of neutralization, or the rate at which the CaCO3 is dissolved, is 

usually the slowest reaction and, therefore, limits the overall removal efficiency (2). Adding 
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DBA enhances the neutralization achieved by the limestone. This increases the alkalinity of the 

system and drives reactions 2 and 3 to the right, raising the SO2 removal efficiency significantly. 

The removal efficiency with DBA can reach 98% but other problems are created in the process. 

In addition to the added cost to purchase DBA, the quality of the byproduct is endangered. The 

DBA that doesn’t degrade exits the system with the gypsum, which may impact its marketability, 

and with the purge water, which may require wastewater treatment. DBA injection was not 

considered for the Spruce 1 upgrade project because of the risk to the gypsum quality. 

ASSURING CONTINUED BYPRODUCT QUALITY

As mentioned previously, during the epoch of early FGD designs, scaling was a common 

problem due to a poor understanding of the reaction chemistry involved. Now it is readily 

understood that keeping high levels of oxidation with forced oxidation results in solid products 

that are easily dewatered. Current designs typically employ forced oxidation, or the injection of 

air into the reaction tank, because the resulting gypsum product is ideal for either of two 

purposes: 1) For sale to wallboard or cement producers or 2) For disposal as a stable, firm 

landfill. The gypsum product is most prevalently sold for use as cement or wallboard, depending 

on the gypsum purity and moisture level of the final product. Landfilling is common where the 

gypsum market is satisfied and/or landfill costs are low. 

Most wet FGD applications are on units burning high-sulfur coal, where natural oxidation may 

produce a split of calcium sulfite to calcium sulfate of about 70% / 30%. However when burning 

Powder River Basin (PRB) coal, as at Spruce 1, it is possible to obtain a high degree of natural 

oxidation without air sparging if the rate of oxidation of the sulfite occurs at nearly the same rate 

as the SO2 absorption. In fact, CPS Energy’s Spruce 1 has always yielded cement quality 

gypsum without forced oxidation. With 100% flue gas treating and higher SO2 absorption, the 

demands on the reaction tank are higher. It is important to confirm that the greater quantity of 

SO2 absorbed will not jeopardize the quality of byproduct. Not only does that mean the possible 

addition of forced oxidation to a system that does not have it, but existing limestone preparation 

and gypsum dewatering systems need to be evaluated for suitability for the higher SO2 load. 

Air injection into the reaction tank is not the only reactivity consideration either. The system 

must provide adequate residence time for the limestone reagent to dissolve (liquid residence 

time), as well as provide sufficient time for crystal formation (solids retention time). When 

upgrading a scrubber, it should be confirmed that the residence times are adequate to prevent 

disastrous consequences such as having to landfill product that was previously all sold. With 

higher reactivity, the reagent preparation and gypsum dewatering equipment also need to be 

evaluated. Storage times and equipment cycle times for both subsystems need to include 

adequate margin to avoid derating the unit should serious maintenance problems arise. 
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CONCLUSION

Various ways to change absorber performance have been discussed. First, the implications of 

changing the absorber system to treat 100% of the flue gas were examined. Column A in Figure 

5 shows Sargent & Lundy’s estimated SO2 removal and cost per additional ton of SO2 removed 

to eliminate the bypass duct at CPS Energy’s Spruce Unit 1. Secondly, several different 

operating scenarios were studied to determine the benefit of running without a spare absorber. 

Column B in Figure 5 shows the first case where the number of absorbers was increased but the 

number of spray levels was kept constant. S&L estimated that the lower gas velocity for three 

absorbers relative to having two absorbers with 6 spray levels in operation would decrease the 

SO2 removal. There is no difference in the capital or O&M cost between columns A and B, 

but when considering the value of additional SO2 removal, as in Figure 5, scrubbing less SO2

comes at a cost. 

Case Study: Cost to Remove Additional SO2 

0

200

400

600

800

1000

1200

1400

1600

1800

2000

100% Treating

- 6 Spray

Levels in 2

Absorbers

100% Treating6 Spray Levels

in 3 Absorbers

100% Treating

- 9 Spray

Levels in 3

Absorbers

100% Treating

- 6 Spray

Levels in 2

Absorbers -

Tray

100% Treating

- 6 Spray

Levels in 2

Absorbers -

Anti-Sneakage

Rings

100% Treating

- Recycle

Pump

Modifications 

(new motors)

100% Treating

- Pump

Modifications -

9 Spray Levels

in 3 Absorbers

$/Additional Ton SO2 Removed

80

82

84

86

88

90

92

94

96

98

100

% SO2 Removal

ABCD E F G

Figure 5: Summary of Cost (Capital and O&M) per Additional Ton SO2 Removed 

Column C represents the results for operating three absorbers with 9 spray levels. The gain in 

L/G for this case out-weighs the negative impact of the lower velocity and has a higher SO2

removal than shown in Column A or B. However, there is a higher operating cost for this 

scenario due to running all nine pumps and a small increase in the head requirements of the ID 

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fan. Column F shows the estimated incremental cost and SO2 removal for pump modifications 

that would be required to maximize the recycle slurry velocity while G shows the impact of 

running all nine spray levels with the same pump modifications. For Spruce 1, F and G are 

significantly less attractive than all other options because the existing motors on the nine recycle 

slurry pumps would have required replacement. It is entirely likely that another plant would find 

pump modifications or the addition of a frothing tray more economical. 

Column D and E show the estimated removal efficiencies and incremental cost per allowance for 

the addition of anti-sneakage rings and frothing trays to the absorbers at Spruce 1. The frothing 

tray was estimated to result in the highest scrubbing efficiency, but the capital cost was slightly 

higher than the anti-sneakage rings. The anti-sneakage rings were more attractive economically, 

but were estimated to increase SO2 absorption less than the frothing tray. While some vendors 

favor one technology over another it is important for the utility to have well-defined goals for 

their upgrade project so that the most cost-effective option that meets the project goal can be 

selected. 

REFERENCES

1. Shattuck, Donald, et al. “A History of Flue Gas Desulfurization (FGD) – The Early 

Years.” (PDF File Downloaded from Utility Engineering’s Web site : http://www.uecorp.com/news/wp_fluegas.pdf) 

2. U.S. Department of Energy, Electric Utility Engineer’s FGD Manual Volume 1 –

FGD Process Design, 1996.