P O W E R

Technical Paper

FGD 

Upgrades

Improving the Performance of Older FGD Systems
Abstract

Economic pressures to reduce the operating costs of FGD 

systems have continued to increase over the last few years

and will likely increase further in the future along with pressure for significant improvements in reliability. There are also

pressures to increase the removal performance of older FGD

systems to meet present or future regulatory requirements, or

to allow flexibility to fuel switch to lower operating costs. URS

Corporation offers a number of technologies, and have worked

with a number of utilities to improve the performance of older

FGD systems. The goals for some of these projects were to

improve SO2 removal performance. For others, the goals were

to solve process problems, improve reliability and reduce operating costs.

Several case studies are presented providing details for some

recent projects URS has conducted. Included are descriptions

of the objectives for the project, the approach taken to achieve

those objectives, and operating data demonstrating the

improvements that were achieved. For many of the projects,

Computational Fluid Dynamics (CFD) modeling was one of the

tools employed to evaluate performance and help develop

approaches for improvement. All of the projects were successful in either increasing removal performance to levels typically

well above 95%, or in solving process problems allowing the

systems to reduce operating costs, improve reliability and

extend operating run times between outages.

Improving the Performance of Older FGD Systems

Gordon Maller

Dr. Jonas S. Klingspor

URS Corporation

9400 Amberglen Blvd

Austin, TX 78729

Mellissa S. Cook

TVA

101 Market St

Chattanooga, TN 37402

Gregory W. Betenson

PacifiCorp Power Supply

201 South Main Street

Salt Lake City, Utah 84145
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Introduction 

Utilities are experiencing increasing economic competitive

pressures to reduce operating costs, improve reliability and

reduce emissions of criteria pollutants such as sulfur dioxide

and particulate. New FGD systems will be installed over

coming years at substantial costs to comply with existing

and future regulations. Utilities with existing FGD systems

are in possession of a significant investment that can be

optimized, improved, and/or upgraded to minimize the cost

of environmental compliance.

A number of financial and regulatory drivers are currently

facing electric utilities which will greatly impact the decision

on how to best meet environmental current and future compliance demands including:

❚ Current allowance vs. emission situation

❚ NSR

❚ Clear Skies Initiative

❚ Proposed mercury regulations

❚ Proposed PM2.5 regulations

❚ State initiatives

Emissions of SO2 has declined steadily over the years as

shown in Figure 1. However, overall emission of SO2 are currently exceeding provided allowances requiring to consume

banked allowances to make up for the annual deficit of emission credits. At the current consumption rate, the banked

allowances will be consumed by 2010 which coincides with

reduction in the national SO2 allowance cap proposed by the

Clear Skies initiative. The graph indicates that electric utilities will focus on installing new scrubbers maybe as early as

2004 but certainly in the 2005 to 2006 time frame and

beyond. Meanwhile, numerous utilities face a situation

where SO2 emissions exceed allocated SO2 allowances and

are reviewing how to best minimize the cost of environmental compliance.

The price of SO2 credits has varied considerably since the

introduction in August of 1994 as shown in Figure 2. During

recent years, the price has stayed between $150 to $200 per

ton but it is widely believed that the price will increase considerably as then banked allowance pool is depleted. 



























	



	





















   

   







 
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Figure 1. SO2 Emission and SO2 Allowance Overview

Figure 2. Historical Price of SO2 Allowances

Emissions of SO2 from existing FGD systems can typically

be reduced significantly by using one or several of the available upgrade options discussed below. An upgrade of an

existing FGD system is typically much more cost effective

than installing a complete new system. SO2 emissions from

the existing scrubber fleet was 1.4 million tons in 1999. It

has been estimated that on an average, the removal efficiency of the installed scrubber fleet can be increased from

an average of 80 to 90 percent by applying various upgrade

technologies, potentially cutting SO2 emissions in half from

scrubbed units or by about 700 thousand TPY. At cost of

$200/ton, 700 thousand tons of emission credits would be

worth $140 million per year.

However, a reduction in SO2 emissions is not the only driver

to upgrade an existing FGD system; other drivers include:

❚ Improving the reliability of the FGD system to reduced

the number and lengths of non-scheduled outages

❚ Ability to extend operating periods between outages to

meet corporate goals
Improving the Performance of Older FGD Systems

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❚ Solving process related problems leading to high

maintenance costs or excessive costs of reagents and/or

byproduct disposal

❚ Ability to treat a higher flue gas volume

❚ Reducing maintenance and cleaning requirements

Technologies to Reduce Emissions and

Improve System Reliability 

Numerous options are available to reduce SO2 emissions

and improve the reliability of existing FGD systems.

Available options typically fall into two categories: (1)

gas/liquid contact improvements and (2) improvement of the

FGD chemistry. The gas/liquid contact category includes

options such as elimination of wall sneakage, improved liquid distribution by installing new spray headers and/or spray

nozzles, increased recycle slurry pump flow, improved gas

distribution etc. The chemistry category includes a wide

array of options including limestone grind size, elimination of

limestone blinding, introduction of forced oxidation, optimization of operating pH, use of performance additives etc.

Some of the more effective upgrade options are discussed

below.

Liquid Distribution Rings

Open spray towers provide a balanced approach to efficient

gas/liquid contact, reliability, and draft loss expenditure.

However, inherent in any design using spray nozzles for

introduction and distribution of the recycle slurry, is a region

of lower spray density close to the absorber walls. A reduction in spray density is a result of recycle slurry being captured

by the absorber walls and a limitation in nozzle placement in

the wall region leading to a zone of low spray density.

Liquid distribution rings were developed to reintroduce

slurry running down the absorber walls to reduce the flue

gas sneakage. The liquid distribution rings are sloped downwards to re-inject wall slurry into the spray zone to increase

the spray density close to the wall. The liquid distribution

devices are placed between spray levels as shown in Figure 3.

Tests on full-scale scrubbers revealed a steep concentration gradient from the wall penetrating 3 to 5 feet into the

scrubber, as shown in Figure 4. The SO2 concentration profile

basically mimics the spray density gradient in the same

region. Hence, the flue gas is exposed to a region with lower

Figure 3. Liquid Distribution Rings

Figure 4. Wall Sneakage in Open Spray Towers







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spray density providing a path of lower resistance. The result

is a region close to absorber wall which is characterized by a

higher than average gas velocity, lower than average spray

density (resulting in a lower than average liquid-to-gas ratio)

and reduced SO2 removal capacity. A five foot section in an

open spray tower 40 ft inch diameter, represents 35 percent

of the total cross sectional area. In a 60-foot diameter tower,

the sneakage area is 25 percent, still a significant percentage of the overall cross section.

The experience with liquid distribution rings has become

substantial over the last few years. A summary of FGD systems retrofitted with Liquid Distribution rings is shown in

Table 1. The experience includes large to small towers and

round or rectangular shapes. Small round towers and rectangular towers tend to benefit the most from liquid distribution

rings as the wall sneakage tends to be more pronounced in

smaller towers and the corners in rectangular towers is an

area of considerable sneakage.

Trays

Perforated trays have been applied successfully in lime and

limestone-based scrubbers and is a proven contact device

Table 1. LDR Experience List

SO2

Utility Station Year Generating Absorber Rings per Emissions

in Serv. Capacity Size Abs. Reduction

PacifiCorp Hunter 2 2005 1 x 445 Ø 27 ft 2 

TVA Paradise 2 2004 1 x 650 Ø 8 ft 3 >60%1

TVA Paradise1 2004 1 x 650 Ø 8 ft 3 >60%1

PacifiCorp Hunter Unit 1 2004 1 x 445 Ø 27 ft 2

TVA Widows Creek 7 2003 1 x 550 21.5 x 25.5 ft 3 >60%1

LG&E Cane Run 5 2003 1 x 400 28 ft x 32 ft 2 >60%1

PacfiCorp Hunter 3 2003 1 x 445 Ø 27 ft 2

AES Petersburg 2 2003 1 x 471 Ø 60 ft 2 >50%

Santee Cooper Cross Unit 2 2003 1 x 550 Ø 32 ft 2 >55%

AES Petersburg 1 2002 1 x 270 Ø 46 ft 2 55%

LADWP Intermountain Power 2 2001 1 x 875 37 ft x 35.5 ft 2 69%

LADWP Intermountain Power 1 2001 1 x 875 37 ft x 35.5 ft 2

Minnkota Power Coop., Inc. M.R. Young 2 2001 1 x 440 Ø 40 ft 4 60%

Dakota Gasification Company Dakota Gasification Company 1997 1 x 350 Ø 43 ft 2 60%

1 Projected

for calcium based systems. A tray provides additional SO2

removal by creating additional surface area obtained from

liquid holdup on the tray. 

The degree of improvement in SO2 removal by adding a

tray is very similar to adding liquid distribution rings.

However, the addition of a tray will significantly increase the

gas-side pressure drop and the applicability of a tray is

dependent on sufficient fan capacity being available. Also,

trays are subject to plugging and scaling if the scrubber

chemistry is not controlled carefully and trays are less attractive if the absorber gas velocity is increased. Finally, trays

are particularly useful if space is limited, when efficient

spray header designs are not present, and to correct a

skewed gas distribution profile. The degree of improvement

in SO2 removal can be controlled by pressure drop that can

be accepted by the system.

Re-design of Recycle Spray Header

A problem that has often been encountered in the recycle

spray header design of many older FGD systems is incomplete spray coverage, especially near the walls of the

absorber where gas flows tend to be higher. This results in
Improving the Performance of Older FGD Systems

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poor gas-liquid contact in areas of the absorber which places

a limitation on the maximum removal efficiency that can be

achieved for the system. Another problem that utilities with

older systems often face is erosion of the header piping. This

erosion can occur either on the outside of the pipe due to

impingement, or can occur inside the pipe at elbows or stub

connections. Erosion problems are more common in piping

made from FRP, however, erosion has also occurred in steel

pipe. The result can be holes in the pipe, broken branches,

and missing spray nozzles all of which can have a significant

impact on the ability of the system to remove SO2. URS has

conducted a number of projects, over the years, to replace

the spray headers of older scrubbers. The approach that has

been taken, for these projects, is to carefully map out the

spray coverage, for the particular nozzle layout, to ensure

that high level of spray density with a high degree of overlap

is present in the cross-sectional area of the absorber below

the spray level. This ensures a high degree of gas-liquid contact with little possibility for gas sneakage. Several of the

projects involved the replacement of FRP pipe which was

originally used because of its cost and good corrosion resistance. The material used for the replacement pipe was either

an alloy, or a stainless steel material, such as Duplex 2205,

which offers good corrosion resistance, high tensile strength

and is priced in a range which is competitive with the FRP

pipe. Use of the stronger steel pipe has also allowed the

headers to be designed to be self-supporting meaning that

internal support members in the absorber can be eliminated.

This is a significant advantage in eliminating flow disturbances and locations where scale and solids can accumulate. 

Innovative Re-design for Older Absorber Towers

Some of the older FGD systems includes a design aspects

which by today standards would be considered unusual such

as cross flow horizontal scrubber designs, top entry—side

exit scrubber designs with an annulus spray section, high

pressure—high flow full cone spray nozzles and FGD system

designed to induce cyclonic flow. The symptoms of FGD

designs of this type is typically flue gas mal-distribution

leading to poor SO2 removal, plugging and scaling of the mist

eliminator and scrubber internals leading to poor reliability

and frequent forced outages. However, most of design deficiencies can be corrected with relatively simple correction

devices. The liquid distribution rings mentioned above is one

example. However, by applying advanced computational fluid

dynamics modeling and subsequent introduction of gas flow

correction devices, dramatic improvements can be obtained.

Some examples of upgrades of older systems are discussed below. They include upgrade of a venturi/absorber

scrubber to a twin tower DFCS scrubber, and simple but

effective correction to cyclonic flow in a dual-loop scrubber.

Another example of a substantial rebuild of a older type

scrubber system is a upgrade of a cross-flow horizontal

scrubber to a horizontal scrubber using high efficiency cocurrent spray headers.

Elimination of Bypass Reheat

Many older FGD systems are designed to bypass a portion of

the flue gas, typically between 5% and 15%. This bypassed

gas is mixed with the treated gas upstream of the stack to

achieve some degree of stack gas reheat to improve gas

buoyancy and reduce moisture condensation. A clear and

obvious way for these plants to significantly reduce overall

SO2 emissions is to eliminate the bypass and treat all of the

gas. There are a number of technical issues that need to be

addressed before a utility should consider doing this. The

first issue concerns the performance of the scrubber.

Eliminating the bypass gas means that the scrubber will

have to treat additional gas volume. This will put added

strain on the performance of the mist eliminators and may

make poor gas distribution problems, gas sneakage problems, and slurry recirculation problems significantly worse.

In some cases, it may be necessary to replace or re-design

the mist eliminator to be able to handle the higher gas volume and velocity. The second area that must be addressed is

the stack. Eliminating bypass will mean that the stack will

now have to operate in a wet environment. For stacks with

acid brick liners, this may mean improving the drainage systems. For stacks with carbon steel liners, operation in a wet

mode will certainly mean that some type of lining, such as

alloy wallpaper, will need to be added. With regards to brick

stack liners, however, the good news is that the tendency for

leaning, if it is present, should be greatly reduced when the

gas bypass is eliminated. The design process for system considering eliminating bypass reheat, and the technical issues

that must be dealt with, are very site specific. No one technology or set of technical guidelines can be applied for these

projects.
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CFD Modeling

Computational fluid dynamics or CFD modeling is a method

of obtaining solutions to complex equations describing fluid

flow, heat transfer, and mass transfer processes. For scrubber improvement work, CFD modeling is an extremely powerful tool that URS has used on most of the projects that have

been performed. With CFD modeling, a clear picture of gas

velocity, pressure, and temperature distribution within the

tower can be obtained along with a picture of fluid flow and

fluid concentration distribution. This is invaluable when

evaluating gas liquid interactions and when trying to evaluate solid deposition problems or problems of poor liquid-gas

contacting. 

Case Studies 

Over the last several years, URS has employed the various

technologies described in this paper to help a number of utilities improve the performance and reliability of their FGD

systems. These projects, some of which have been completed while others are currently in the design or construction phases, have involved such things as the installation of

liquid distribution rings or trays to improve performance, the

redesign and installation of spray headers and ME wash

headers to improve performance and reliability, and the

redesign and reconstruction of the absorber tower to solve a

number of operation problems and improve performance and

reliability. Several case studies for projects are briefly

described in the paragraphs below. These case studies suggest the wide range of objectives and project complexity that

is possible for this technology.

Case 1: Midwestern Utility - Installation of LDRs

The project objective for this utility was to achieve a 2 to 3%

improvement in removal efficiency for their Phase 1 era FGD

system. The utility also wanted to improve the operating

flexibility of the system to be able to handle a wider range of

coal sulfur levels, or to be able to turn off recycle pumps to

reduce operating costs. Currently the plant fires a medium

(2.5% to 3.5%) sulfur, bituminous fuel. The flue gas is

scrubbed in a limestone, forced oxidation FGD system with

an open spray tower design absorber. The design liquid to

gas (L/G) ratio for the scrubber, which has four operating and

one spare spray level, is 140 gal/103 acf. 

The approach that was taken to achieve the project objectives was to install 2 sets of liquid distribution rings (LDR),

one set between the lowest and the second lowest spray

levels, and the second set between the second lowest and

third lowest spray levels. Recall that liquid distribution rings

act to redirect slurry near the walls of an open spray tower

towards the middle of the tower to improve gas-liquid contact and minimize gas wall sneakage.

Following the installation of the liquid distribution rings,

the unit was tested to determine SO2 removal efficiency over

a range of pH set points, and with 3 or 4 spray levels in service. These data were then compared to removal levels prior

to the installation of the LDR. Data used for the base cases

were at similar conditions with respect to load, inlet SO2 levels and pH. The variation in removal efficiency as a function

of increasing pH is shown graphically in Figure 5 for 3 and 4

spray level operation, and with and without the LDR. The

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Figure 5. Impact of LDR on SO2 Removal

removal values obtained during the testing and used for the

comparisons are summarized in Table 2.

The data show that the improvement in SO2 removal efficiency, following the installation of the LDR, ranged from

2.4% at a pH of 5.9, to 3.0% at a pH of 5.6 with 4 spray levels

in service, and 2.0% at a pH of 5.9, to 2.4% at a pH of 5.6

with 3 spray levels in service. The fact that the improvement

in removal efficiency was less at the higher pH, for both four

spray level and three spray level service is a result of the fact

that at the higher pH the mass transfer limit of the absorber

is being approached. This fact can also explain why the
Improving the Performance of Older FGD Systems

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improvement achieved with the LDR is less for three spray

level operation where the available alkalinity is less due to

the lower liquid recycle rate. What is significant to note is

the overall increase in the maximum removal efficiency,

greater than 99%, that can now be achieved for this system.

This affords the plant a great deal of flexibility in the fuel

they fire. In addition, the data showed that, following the

installation of the LDR, the system achieves better removal

performance with three spray levels in service than it had

previously with four spray levels. It also achieves this better

removal at a lower pH set-point meaning that the plant can

turn off recycle pumps to reduce operating costs, and can

lower the pH set-point to improve limestone utilization and

gypsum quality.

Table 2. Improvement in Removal Achieved With LDR

No. of Spray Removal Efficiency %

Levels pH Without LDR With LDR Improvement

4 5.6 95.7 98.7 3.0

5.7 96.0 98.8 2.8

5.8 96.4 99.0 2.6

5.9 96.8 99.1 2.4

Average Improvement: 2.7

3 5.6 93.8 96.1 2.4

5.7 94.2 96.4 2.2

5.8 94.7 96.8 2.1

5.9 95.1 97.1 2.0

Average Improvement: 2.2

Case 2: Western Utility -

Installation of LDRs

The FGD systems at each

of the two coal-fired boilers at this western utility

consists of 6 rectangular

open spray tower absorber

modules. Each modules

has three spray levels and

two of the modules are

typically on standby.

Through testing with

sodium formate, it was discovered that the unit could

not achieve a SO2 removal

efficiency above 95 percent due to wall sneakage. The plant has been retrofitting

Liquid Distribution Rings with a dramatic improvement in

SO2 removal efficiency. Figure 6 shows the SO2 concentration profile before and after installation of LDR. 

The installation of LDRs has greatly improved the SO2 concentration profile and eliminated the high concentrations of

SO2 along the walls and in the corners. In side by side testing, SO2 emissions from a module retrofitted with LDR was

reduced by 69 percent while the impact on pressure drop

was undetectable. The module retrofitted with LDRs was

later operated with only two spray headers in service and

showed lower emissions than the original module design

operating with 3 spray levels in service.

Figure 6. SO2 Concentration (ppm) Profile Before and After Installation of LDRs
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Case 3: Western Utility - LDR Installation and Spray

Header Replacement

This project involved the replacement of three levels of spray

headers and the installation of two sets of liquid distribution

rings in a four module, approximately 20 year old FGD system located in the Western US. The spray headers being

replaced were manufactured out of FRP and had shown signs

of severe erosion. In addition, the carbon steel box beam

support members for each spray levels, which were wrapped

with FRP, had corroded very badly as a result of damage to

the FRP coating and were at risk of collapsing. The plant also

reported that they were experiencing significant problems

with solids pluggage of their mist eliminators which required

that they take a module offline every few months for cleaning.

CFD modeling of the tower, shown in Figure 7, revealed

several things about the gas flow and liquid droplet patterns

which provided important insights into these problems.

The colors in the figures indicate the magnitude of the gas

velocity or, for the figure on the right, the relative concentration of slurry particles. The colors range from blue, which is

the low end of the range, to red which is the high end of the

range. The modeling results showed that a good deal of the

gas flow is along or near the walls of the tower with very little in the middle. The uneven gas distribution and area of

high gas flow at the mist eliminator is also very evident. The

figure on the right indicated that the liquid loading rate for

part of the mist eliminator is significantly higher than the

other areas. Not too surprisingly, it was this area of the ME

where the plant saw the most severe solids pluggage.

An analysis of the spray pattern for the recycle headers,

shown in Figure 8, indicated that the spray density along the

wall was either very low or, in some areas, there was no

spray coverage at all as indicated by the black areas. This

fact, coupled with the CFD modeling results which showed

that the highest gas flow was along the walls, suggested

that the apparent liquid to gas ratio for the system was significantly lower than design. 

Figure 7. CFD Modeling Showing Poor Gas and Slurry Particle Distribution

Figure 8. Absorber Recycle Spray Coverage at Three Feet

Gas Velocity at Spray Levels and

Mist Eliminator

Upward Gas Velocity

at Mid-Plane

Slurry Particle Distribution

at Mist Eliminator
Improving the Performance of Older FGD Systems

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The approach that URS developed for this project incorporated a number of features to correct the problems and

improve the operation of the scrubber. The design for the

new spray headers doubled the number of spray nozzles and

greatly improved the spray density as shown in Figure 9. The

re-designed headers were manufactured out of 2205 Duplex

stainless steel pipe which provides extremely high tensile

strength and good corrosion resistance at a price similar to

FRP pipe. As a result of the higher strength, the headers

could be supported by the support brackets along the wall,

some of which were reinforced. This eliminated the need for

Figure 9. Absorber Recycle Spray Coverage for 

Re-designed Spray Header

Figure 10. CFD Modeling Following Re-design of Headers and Addition of LDRs

Gas Velocity at Spray Levels 

and Mist Eliminator

Upward Gas Velocity

at Mid-Plane

Slurry Particle Distribution

at Mist Eliminator

the box beam support members resulting in a tower with

fewer flow obstructions and areas where solids deposits

could accumulate. The improved gas and slurry distribution

profiles are shown in Figure 10.

Case 4: Western Utility Re-design of Dual Loop

Absorber

The motivation for this project, which was performed for a

Western utility, was to develop a new design for an early

generation, dual loop FGD system to solve problems of scaling and solids pluggage in the quencher area of the absorber.

The plant also wanted to evaluate improving the capacity

and performance of the scrubber to make it more robust, and

allow for greater flexibility in fuel selection. CFD modeling

performed at the beginning of the project indicated that the

design of the quencher inlet and headers, intended to

encourage cyclonic gas flow in the quencher portion of the

tower, and the high (about 90 fps) inlet gas velocity resulted

in a large portion of the inlet flue gas short-circuiting the

quencher spray and running up the wall opposite the inlet.

This fact, coupled with the poor spray coverage of the quencher headers, meant that a significant portion of the flue gas

was not cooled and quenched when it reached the level of the

bowl separating the upper and lower loops. Some of the

worst solids deposition was occurring in this area of the

tower. Results of CFD modeling performed to characterize the

quencher section of the absorber clearly indicated that hot,
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Figure 11. CFD Modeling Results for Quencher Section

unquenched flue gas was exiting the quencher section of the

absorber. The CFD results indicated that the average gas temperature at the bowl level was about 190oF. The modeling

results also indicated that a high concentration of slurry

droplets was also being carried up to the edge of the bowl

along two sides of the tower. This was due to both the

uneven gas distribution through the quencher and the orientation of the spray nozzles.The combination of the hot

unquenched flue gas and high concentration of slurry resulted

in a significant and rapid build-up of solid deposits in the vicinity of and along the edge of the bowl. Some of the CFD modeling results for the quencher section are shown in Figure 11.

The first approach the was evaluated to improve the ability of the quencher spray to cool the gas and reduce the

amount of solids that were deposited at the bowl level was

to re-orient the spray nozzles so that the spray would be

directly counter-current to the upward flow of the gas in the

tower. In addition, the flow rate for half of the spray nozzles,

on the gas inlet side of the tower, was increased and the

flow rate for the spray nozzles on the opposite side of the

tower decreased in an attempt to force more gas into the

middle of the tower. Based on CFD modeling, this approach

was successful in improving the ability of the quench spray

to cool the gas resulting in a decrease in average flue gas

temperature at the bowl level from 190oF to 140oF as shown

in Figure 12. However, it was unclear if this fix would be successful in completely eliminating the solids deposits which

was the plants long-term goal for the project.

The next phase of the project was to evaluate a more

extensive re-design of the absorber to address the utilities

goal of significantly improving the scrubber's reliability and

availability. The utility also was interested in evaluating

changes to improve the gas handling capacity of the scrubber and the SO2 removal performance to allow them greater

flexibility in fuel selection. The approach that was taken to

accomplish these goals was to eliminate the quencher headers, bowl section, and piping internal support members

where the majority of the chronic scaling and solids deposition was occurring. Essentially, the plan was to convert the

dual-loop design to a more conventional single-loop design.

It was felt that this change alone would significantly

enhance the reliability of the system allowing it to greatly

extend the operating time periods between cleanings. Other

features of the proposed design were to abandon the

quencher recycle pumps, and tie the quencher and absorber

reaction tanks together with a pipe. The design also included

a single sieve tray to improve the mass transfer characteristics of the absorber to enhance removal, and lowering the

elevation of the spray levels to increase the liquid droplet

disengagement distance above the spray headers to improve

mist eliminator performance. These changes are illustrated

in the conceptual sketches shown in Figure 13.

Slurry Droplet Flow

Through Quencher

Gas Flow Streamlines

Colored by Temperature

Gas Temperature at

Quencher Outlet
Improving the Performance of Older FGD Systems

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There were several technical questions that were evaluated in the development of the single loop conversion

design. The first considered the gas distribution within the

absorber. In the original design for the scrubber, the gas inlet

is located off center on one side of the tower. This was done

to encourage cyclonic circulation of the gas within the lower

portion of the absorber. The CFD modeling done at the beginning of the project, however, showed that rather than

cyclonic flow, a good deal of the gas entering the tower was

short circuiting the quencher spray and running along the

wall opposite the

inlet. The technical

concern, therefore,

was whether the

location of the inlet

would undermine

the ability of the system to get good gasliquid contact and

thereby negatively

impact the removal

performance of the

system. 

To evaluate this,

additional CFD modeling was performed

evaluating the gas

flow distribution for a tray tower, versus an open spray

tower. The results of the modeling are shown in the Figure 14

below which show the magnitude of the upward gas velocity

for a tray tower and open spray tower at three different elevations, just below the tray level, just above the tray level,

and just below the upper spray level. The CFD results clearly

show that the presence of the sieve tray greatly improves

the gas distribution within the tower which, in turn, should

improve the removal performance of the system. This conclusion was verified by process simulation model testing that

Figure 12. Flue Gas Temperature at Quencher Outlet Following Changes to Nozzle Orientation and Flow Rate

Figure 13. Conceptual Sketch of Proposed Conversion To Single Loop Design

Before Proposed Changes

Average Temperature 190°F Average Temperature 140°F Plan View

After Proposed Changes
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Figure 14. Gas Velocity Magnitude for Tray and Open Spray Tower

was performed using EPRI's FGDPRISM. That testing indicated that when operated at conditions similar to the plant's

design conditions, about a 98% removal efficiency could be

expected for a tray tower compared to an 88% removal efficiency for an open spray tower operated at similar conditions. 

Widows Creek Unit 7 & 8 - Upgrade to DCFS and LDR

The Tennessee Valley Authority's Widows Creek Fossil Plant

is located on the west bank of the Tennessee River in

Jackson County, Alabama. The plant has generating units

with a combined net capacity of 1,750 megawatts. Two of

the units, units 7 and 8, are retrofitted with flue gas desulfurization systems to scrub sulfur dioxide from the flue gas.

Both units 7 and 8 burn high sulfur coal and have a nominal

rating of approximately 550 megawatts each.

TVA is taking further NOx and SO2 emission reductions at

its Widows Creek plant as part of its efforts to comply with

various environmental regulations. A Selective Catalytic

Reduction (SCR) system is currently under construction on

Unit 8, and a SCR is also planned for installation on Unit 7. In

addition, projects are planned to increase Units 7 and 8 

SO2 removal efficiency from 88 percent to 95 percent.

In 1977, Widows Creek unit 8 was retrofitted with a wet

limestone scrubber system. This scrubber was originally

intended as a demonstration model and was the first full

scale scrubber in the Tennessee Valley. The scrubber was

designed by TVA and consists of four parallel modules. As

shown in Figure 15, each module consists of a variable

throat venturi for particulate removal, followed by a counter

current flow absorber with one level of sprays and five levels

of gratings, an entrainment separator and flue gas reheat.

The venturi and absorber section each have a dedicated

recycle tank. The absorber tank level is controlled by gravity

overflow to the venturi recycle tank. Forced oxidation air is

injected into both recycle tanks to control scaling. The FGD

system does not have a dewatering system; the venturi recycle tank blowdown is pumped to a dedicated FGD pond.

Since the addition of the SCR on Unit 8 will cause additional pressure drop through the flue gas path, in May 2003

TVA contracted with ADVATECH (jointly owned by URS and

MHI) to perform a feasibility study to recover pressure drop

while maintaining a particulate removal level above 99 percent. After reviewing several options, AVATECH recommended converting the existing scrubber system to a dual

contact flow scrubber (DCFS) as shown in Figure 16. The

existing venturi section will be replaced with a new tower

and inlet duct. The first tower will be equipped with MHI

DCFS fountain type spray header which will provide the

required particulate removal. The existing spray header and

grating in the second tower will be removed and replaced

with MHI DCFS fountain type spray header. Larger recycle

pumps will be provided on the first and second towers to

Figure 15. Current FGD System Design at Widows Creek
Improving the Performance of Older FGD Systems

12

increase the SO2 removal efficiency from 88 percent to 95

percent. Initially, organic acid was under consideration to

increase scrubber efficiency; however, upgrading Unit 8 to a

twin tower design eliminates the need for organic acid injection and allows TVA to reduce both capital and O&M costs.

Construction of the twin tower design will began in

September and is expected to be operational by January, 2004

In 1981 a Combustion Engineering FGD system became

operational on Widows Creek Unit 7. After the flue gas

passes through an electrostatic precipitator it enters a common inlet plenum where the flow is distributed through four

parallel modules. Once distributed between the four modules, the gas passes through a variable throat rod scrubber

(for additional particulate removal), a counter current

absorber consisting of three levels of sprays, two levels of

mist eliminators and a flue gas reheat. Current SO2 removal

efficiency is 88 percent.

Similarly efforts were being made to increase Unit 7 FGD

efficiency from 88 percent to 95 percent without the addition

of an organic acid. In March 2003, TVA contracted with

ADVATECH to design liquid distribution rings between each

spray level as shown in Figure 17. Most of the SO2 emissions

occur from flue gas flowing up the sides of the absorber

walls. Installing the rings will force the gas to the center of

the module where the SO2 can be effectively scrubbed.

Installing liquid distribution rings on Unit 7 alleviates the

need for injecting an organic acid into the system. The addition of the rings on the Widows Creek Unit 7 is expected to

be complete by January 2004.

By upgrading the unit 8 FGD system to a twin tower design

and increasing the L/G ratio, ADVATECH will be able to

reduce pressure drop to the required level for SCR operation

and increase SO2 removal efficiency to the desired 95 percent. In addition, installation of the liquid distribution rings

on Unit 7 increases the SO2 removal efficiency to 95 percent.

Conversion of the Unit 8 scrubber to a twin tower design and

installation of the rings on Unit 7 allows TVA to successfully

combine capital projects, reducing both capital and O&M

expenses while meeting its environmental commitments.

Figure 17. Widows Creek Unit 7 Absorber Design with Liquid

Distribution Rings.

Figure 16. Widows Creek Unit 8 FGD Configuration after Upgrade

to DCFS Design
Power Industry Services

13

Summary 

Utilities are facing increasing pressure to reduce emissions

of SO2 and other pollutants. At the same time, these utilities

must reduce operating costs and increase plant capacity factors to remain competitive. They are under pressure to

improve unit reliability, eliminate unplanned outages and

significantly extend time periods between planned outages.

Many new FGD systems being offered today can easily meet

these performance and reliability objectives, however, utilities who have already made a significant investment in an

older FGD system cannot afford to make an additional, very

large investment in a replacement FGD system. Rather, these

utilities must find a cost effective way to improve and

upgrade their existing systems to meet the performance and

reliability levels of a new system.

This paper has described a number of technologies and

presented a number of case studies to demonstrate that it is

possible to upgrade and improve older FGD systems so that

they can operate at performance and reliability levels similar

to new systems. This can be done at a cost which is significantly lower than the cost for a new system. In many cases,

achieving the goal of improving an old system to new system

performance levels required that significant process problems be corrected first. The experience of performing the

improvement work described in the paper has shown that no

one technology can be applied universally to solve problems

and upgrade performance. Each new project offers unique

problems and unique design challenges. It is the innovative

application of a number of technologies, and the development

of new technologies when required, that have made it possible to successfully upgrade and improve older FGD systems.

References

J. S. Klingspor and G.N Brown, Improving FGD System

Performance to Achieve Ultra-high SO2 Removal Efficiencies. U.S EPA-DOE-EPRI Mega Symposium, August 2001 
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