MEGA S YMPOSIUM 2008



## P ERFORMANCE 

## U PGRADES FOR 

## L OW 

## -S ULFUR 

## W ET


## S CRUBBERS

P APER # 134

Andrew J. Carstens, William E. Siegfriedt, and Rajendra Gaikwad Steven Escobedo

Sargent & Lundy LLC Chicago Illino is CPS Energy, San Antonio, TX



### A BSTRACT

The class of wet FGD systems installed in the late 1970s through early 19 90s 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% SO 2 reduction from their already-low emissions. Based on this requirement, these units typically included partial FGD bypass and only modest SO 2 removal in the wet absorber. Regulatory consider ations such as the Clea n 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 op timization 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 project ed impact of each and the estimated cost of

each.



### I NTRODUCTION

Upgrading wet scrubbers requir es not only a thorough understanding of the key process variables involved, but also requires a thoroug h review of site-specific design considerations as well as the capabilities of the existing equi pment to identify cost-effective opportunities to improve scrubber performance. The main objective of this pape r is to present the de sign options that were considered in Sargent & Lundy’s recent study to upgrade the wet FGD sy stem 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 di sadvantages, both from a pro cess standpoint and an economic standpoint, of design options availa ble for this class of units.

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2 of 14 The topics discussed are as follows:

• Upgrading to treat 100% of the flue gas

• Operation with or without spare absorbers

• Scrubber modifications to improve SO 2 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



### U PGRADING TO 

### T REAT 

### 100% OF THE 

### F LUE 

### G AS

There are two basic types of bypasse s on this class of units. The first is a partial bypass, which was conceived to reduce the amount of flue ga s 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 be nefits 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 unders tanding 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 beca use FGD reliability has improved substantially enough to render them unnece ssary. For existing units with bypasses, the

1990 Clean Air Act Amendments’ advent of the SO 2 -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 SO 2 allowances will change from one per

ton of SO 2 to two per ton of SO 2 in 2010, effectively doubling the va lue of allowances, there is a strong economic driver for utilities with F GD 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 th e 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 clos e off the bypass without re viewing three important

issues:

• Chimney liner material suitability for wet stack operation

• Assurance of flue gas path

• Protection of absorber materialsMEGA S YMPOSIUM 2008

3 of 14 As mentioned previously, the hot bypass gas reheats the satu rated 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 he nce materials that are le ss 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 que stion of whether the existing chimney liner material is adequate for the we t stack operation. If it is not, the cost of demolishing the existing liner and replacing it with FRP or alloy would ha ve to be included as part of the FGD upgrade project. Even worse, the typical design velo cities of 90 to 100 fps for dry stack operation are no longer valid for wet stack operation. The si gnificantly lower EPRI-recommended maximum velocities of 50 to 60 fps, depending on the line r material used, may determine whether the existing chimney liner is too small for wet serv ice and needs to be completely replaced.

In addition to liner material and velocity cons iderations, the logic for the FGD absorber module isolation dampers must be review ed 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 viol ation of fire code and insurer’s rules. The logic must be modified su ch that the last module cannot close off until the

boiler has cooled.

The third issue of absorber material protection th en 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 ab sorber is open to flue gas, there is quenching of the flue gas. If all the slurry pumps fa il (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 dies el fire pump or other reliable source.

To upgrade an FGD system to treat 100% of th e 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 ty pically opposed blade and are thro ttled to control stack inlet temperature above the acid dew point . Therefore, they are not desi gned to operate in the closed position. Even when such dampers are fully clos ed, upwards of 10% leakage can occur. The opposed-blade dampers can be replaced with paralle l-blade dampers, but it is important to realize that the tight shutoff bypass applic ation is a severe application. On one side of the damper, there is dry, acid-laden flue gas at 300°F. On the othe r side, there is flue gas at ~135°F saturated with

water and acidic mist. These differences are a c oncern from the standpoint of materials as well as thermal design of the damper.MEGA S YMPOSIUM 2008

4 of 14 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 outle t duct would be built enti rely of alloy or alloyclad steel to match the outlet duct. To ensure pr oper isolation, there must be a continuous supply

of seal air. Loss of seal air ca n result in serious damage to ma terials of construction as well as

consume SO 2 emission allowances. Sargent & Lundy r ecommended against trying to satisfy this application with a double-louver damper because of insufficient space where the existing opposed-blade damper was installed. Furtherm ore, installing one double-louver damper per bypass duct would have had the disa dvantage of leaving dead space that could lead to corrosion problems if seal air flow failed. It should be noted that inadequate mainte nance of seal air fans and duct systems is the primary reason for damper trouble.

The second option for upgrading the system to tr eat 100% of the flue ga s is to seal the bypass ducts with blank-off plates. Blanking off th e 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 pl ate at the outlet duct woul d be built entirely of fiberglass, alloy or alloy-clad steel. The bypa ss 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 estim ated 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.



### O PERATION WITH OR WITHOUT SPARE ABSORBERS

The fact that incorporating a bypa ss into early FGD systems allowe d 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 in clusion 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 SO 2 with bypass reheat systems, have 3 to 5 absorber modules instead of the single abso rber design that is now common in new FGD systems. In CPS Energy’s case, a 3 by 50% absorb er design was supplied for J.K. Spruce Unit 1.

Most utilities with FGD systems now achieve a high degree of abso rber 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 SO 2 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 take n in the system mass tr ansfer characteristics because of the lower absorber gas velocities. Th ere is a point below which the lower velocityMEGA S YMPOSIUM 2008

results in lower SO 2 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 SO 2 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 SO 2 removal, K is the average overall mass transfer coefficient for the gas phase (lb/hr-ft 2 ), A is the liquid surface area available for mass transfer (ft 2 ), and G is the overall gas flow rate (lb/hr). Clearly, higher system mass transfer coefficients, higher surface areas, and lower gas flow ra tes will all result in higher absorber SO 2 scrubbing efficiencies. But how do we change th ese process variables operationally?

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

2 absorbers on-line and one off-lin e to include all three absorbers in operation. For this first case, let’s assume that the number of spray leve ls 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 availabl e, has not changed either because th e total amount of liquid, relative to the gas has not changed as there are st ill 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 hi gher pH levels. However, higher pH levels also

increase the amount of undissolv ed limestone in the reaction ta nk, and, therefore, increases the reagent consumption (2), which translates to higher limestone consumption for the same SO 2 removed. For a limestone FGD system, the pH is t ypically 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 whic h depend on droplet size and relative velocities between gas and liquid. The dropl et sizes are unchanged since no changes to the nozzles were made, but the velocity of the gas relative to th e liquid decreases when the number of operating absorbers was changed from two to three. Th e decrease in velocity, lowers the system

turbulence and mass transfer coeffi cient, which results in lower SO 2 diffusion, and consequently,

lower SO 2 absorption.

What about changing the operating s cenario 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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6 of 14 SO 2 removal. However, in this case, the liquid- to-gas ratio (L/G) increases, which corresponds to an increase in the liquid surface area availabl e for mass transfer. Since there are competing effects in this scenario, it is more complicat ed to predict performance changes. For CPS Energy’s Spruce Unit 1, Sargent & Lundy determined th at operating all three absorbers with nine spray levels would increase the SO 2 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 individua l system characteristics be analyzed to determine the most costeffective solution for each situa tion. In certain cases, accep ting 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 SO 2 removal. Of course, there are other challenging questions with an FGD upgrade project. Should each absorber be upgrad ed, or should the spare be decommissioned to save capital cost? If al l absorbers are upgraded, will the improvements make it more economically attractive to put a ll the absorbers in operation? The following sections discuss in more detail some of the challenges involved with improving the absorber performance.



### S CRUBBER MODIFICATIONS TO IMPROVE 

### SO 2 ABSORPTION

In order for SO 2 removal to occur, molecules of SO 2 need to come into contact with molecules of

H 2 O and CaCO 3 in slurry. It’s just that simple. The complexity comes into play when deciding how best to get the molecules to find each othe r. Obviously removing the bypass, as discussed above, is going to increase the probability that the SO 2 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, eith er with the gas flow into the absorber or the liquid coverage by the spray levels, the success of other syst em modifications may be severely limited.

Improving Gas Flow Distribution

On the gas side, improving flow distribution can have several a dvantages. For one, it can reduce the amount of energy wasted as the gas navigate s the turns in the ducting, which may reduce the ID fan power consumption and thereby reduce oper ating 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 cont act between the gas and slurry leads to a higher amount of SO 2 absorbed without any other system modifications.MEGA S YMPOSIUM 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 progr ams for the prediction of laminar and turbulent flow, as well as heat transfer. To keep com putations manageable, the CFD simulations were

divided into two sections: inle t ductwork and absorber modules. Each section of the FGD system was simulated according to the curren t design as well as with potential remedial modifications (i.e. guide vane s, 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 Sp ruce 1 is symmetric only with respect to two

absorbers. Two of the absorbers are in-line with the tw o ID fans, but the third absorber is located in between the other two and receives gas from on e or both of the ID fans. Figure 1 shows twoabsorber operation with the middle absorber in se rvice both before and after incorporating flow improvement devices. On the left of Figure 1, there are areas of reci rculation, the flue gas collides with the plenum wall, and the inlet duct to the absorber is under-uti lized (blue area). On the right of Figure 1, straightening vanes help gr ab the gas and guide it around the corner of the plenum. With the help of turning vanes and a pe rforated gas distribution plate, the flow profile going to the middle absorber is significantly improved with minimal impact on the system Δ P. Currently CPS avoids operating the middle absorb er because of instab ility, 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 reco mmended as part of the Spruce 1 study can be seen in Figure 2. The existing sy stem does not contain any turning va nes 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 spra y 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 abso rber 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 distribu tion should boost the effi ciency of the bottom spray level and improve overall SO 2 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 th e flue gas, the liquid slurry distribution from the spray levels is equally im portant. Adequate liquid c overage from the spray levels is critical to ensure full advantage is ta ken as the gas passes throug h a spray level. Spray nozzles that leave significant gaps in spray covera ge result in regions of low resistance to flow. These low resistance regions provi de 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 to wer 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 dr oop in the 90° spray angl e 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 regi ons 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 supplie rs, are annular baffles located below spray

levels that create curtains of liquid through which gas flowing n ear 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 Covera g e Anti-sneakage Wall Rings

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

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

installed at all central locations of each spray level. The sp ray pattern from th e 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 th e 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 woul d result in higher slurry velocities contacting the vessel shell, which would lead to increased erosion at the vessel wa ll in those locations.

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In addition to changing nozzle sp ray 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 header s 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 estim ated 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 cont act 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. Th e trays are installed above the top of the inlet flue gas duct, but 5 to 6 feet below the bottom sp ray level; so adequate room in this zone is necessary for this option to be f easible. The tray covers the entire cross-sectional area of the tower and contains perforations to allow liquid to flow down to the reacti on 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 migr ation of the froth, avoidi ng areas where flue gas could blow through untreated.

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11 of 14 A frothing tray can provide even more benefit th an an additional spray level and can result in significant improvements in SO 2 removal. The froth effectively provides a high surface area of liquid to contact the gas, and th erefore provides excellent mass tr ansfer. The disadvantages of this option are the capital invest ment required and the increased operating costs due to higher ID fan power consumption associated with the additional Δ P across the tray. The tray would add a

nominal 2 to 3 in. w.c. Δ P 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 previous ly, a higher L/G would increase the liquid surface area available and would increase SO 2 absorption. This option is a question of the capability of the existing recycle sl urry pump system. If the recycle slurry lines are already close to the maximum allowable velocity of this se rvice (10 fps), increasing pump flow is not a viable option without changing th e piping to a larger di ameter. Installing new piping could be cost-prohibitive. A thorough analysis of the limita tions of the existing pumps is also required. If the pumps are already running out on thei r 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 requ iring new motors, this may be a cost-effective upgrade option. If new motors are required, modi fying 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 SO 2 absorption.

SO 2 + H 2 O → H 2 SO 3 (Equation 2)

H 2 SO 3 → H + + HSO 3 ⎯ (Equation 3)

CaCO 3 + H + + HSO 3 ⎯ → Ca +2 + SO 3 = + H 2 O + CO 2 (Equation 4)

Equation 2 shows how SO 2 is absorbed into the water pha se to form sulfurous acid, which dissociates according to Equati on 3. Without DBA injection, ne utralization occu rs when the

CaCO 3 from the limestone is dissolved, as shown in Equation 4. If the acidity was not neutralized by the limestone, the pH in the reac tion tank would continue to drop until no more

SO 2 could be absorbed. The rate of neut ralization, or the rate at which the CaCO 3 is dissolved, is usually the slowest reaction and, therefore, limits the overall rem oval efficiency (2). AddingMEGA S YMPOSIUM 2008

12 of 14 DBA enhances the neutralization achieved by the limestone. This increases the alkalinity of the system and drives reactions 2 a nd 3 to the right, raising the SO 2 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.



### A SSURING 

### C ONTINUED 

### B YPRODUCT 

### Q UALITY

As mentioned previously, dur ing 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 oxida tion results in solid products that are easily dewatered. Current designs typi cally employ forced oxidati on, or the injection of air into the reaction tank, becau se the resulting gypsum product is ideal for either of two purposes: 1) For sale to wallboard or cement pr oducers or 2) For dispos al 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. Landfilli ng 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 sulf ate 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 o ccurs at nearly the same rate

as the SO 2 absorption. In fact, CPS Energy’s Spru ce 1 has always yielded cement quality gypsum without forced oxidation. With 100% flue gas treating and higher SO 2 absorption, the demands on the reaction tank are high er. It is important to confir m that the greater quantity of

SO 2 absorbed will not jeopardize th e quality of byproduct. Not only does that mean the possible addition of forced oxidation to a system that doe s not have it, but existi ng limestone preparation and gypsum dewatering systems need to be evaluated for suitability for the higher SO 2 load.

Air injection into the reaction tank is not the on ly reactivity consideration either. The system must provide adequate residence time for the li mestone reagent to dissolve (liquid residence time), as well as provide sufficient time for crys tal formation (solids retention time). When upgrading a scrubber, it should be confirmed that the residence tim es are adequate to prevent disastrous consequences such as having to landf ill product that was previously all sold. With higher reactivity, the reagent pr eparation 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 shou ld serious maintenance problems arise.MEGA S YMPOSIUM 2008



### C ONCLUSION

Various ways to change absorber performance have been discussed. First, the implications of changing the absorber system to treat 100% of th e flue gas were examined. Column A in Figure 5 shows Sargent & Lundy’s estimated SO 2 removal and cost per additional ton of SO 2 removed to eliminate the bypass duct at CPS Energy’ s Spruce Unit 1. Secondly, several different operating scenarios were studied to determine th e 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

SO 2 removal. There is no difference in the ca pital or O&M cost between columns A and B, but when considering the value of additional SO 2 removal, as in Figure 5, scrubbing less SO 2
comes at a cost.



## Case Study: Cost to Remove Additional SO 2

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 SO2Removed

80 82 84 86 88 90 92 94 96 98 100% SO2Removal 

### ABCD E F G

Figure 5: Summary of Cost (Capital and O&M) per Additional Ton SO 2 Removed

Column C represents the results for operating three absorbers with 9 spray levels. The gain in L/G for this case out-weighs th e negative impact of the lowe r velocity and has a higher SO 2 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 sma ll increase in the head requirements of the ID

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14 of 14 fan. Column F shows the estimated incremental cost and SO 2 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 pu mp 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 effici encies and incremental cost per allowance for the addition of anti-sneakage rings and frothing trays to the absorb ers at Spruce 1. The frothing tray was estimated to result in the highest scr ubbing efficiency, but the cap ital cost was slightly higher than the anti-sneakage rings. The anti-sne akage rings were more attractive economically,

but were estimated to increase SO 2 absorption less than the frot hing 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-eff ective option that meets the project goal can be

selected.



### R EFERENCES

1. Shattuck, Donald, et al. “A History of Fl ue 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.