# 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 yearsand 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 SO 2 removal performance. For others, the goals wereto 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 developapproaches 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 84145Power Industry Services

1 

### 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 decisionon 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 SO 2 has declined steadily over the years as shown in Figure 1. However, overall emission of SO 2 are currently exceeding provided allowances requiring to consumebanked 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 SO 2 allowance cap proposed by theClear 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 SO 2 emissions exceed allocated SO 2 allowances andare reviewing how to best minimize the cost of environmental compliance.

The price of SO 2 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 perton but it is widely believed that the price will increase considerably as then banked allowance pool is depleted.


 



       
  
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Figure 1. SO 2 Emission and SO 2 Allowance Overview Figure 2. Historical Price of SO 2 Allowances

Emissions of SO 2 from existing FGD systems can typicallybe 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. SO 2 emissions from the existing scrubber fleet was 1.4 million tons in 1999. Ithas 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 SO 2 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 goalsImproving the Performance of Older FGD Systems

2 ❚ 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 SO 2 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 includesoptions 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 oflimestone 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 regionof 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 fluegas 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 SO 2 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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3 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 SO 2 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 becomesubstantial 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 andround 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

SO 2 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 SO 2 removal by creating additional surface area obtained from liquid holdup on the tray.

The degree of improvement in SO 2 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 scrubberchemistry 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 SO 2 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 recyclespray 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 inImproving the Performance of Older FGD Systems

4 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 SO 2 . 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 belowthe 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 wasoriginally 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 SO 2 removal, plugging and scaling of the mist eliminator and scrubber internals leading to poor reliabilityand 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 horizontalscrubber 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 SO 2 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 maymake poor gas distribution problems, gas sneakage problems, and slurry recirculation problems significantly worse. In some cases, it may be necessary to replace or re-designthe 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 withacid 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 thegas bypass is eliminated. The design process for system considering eliminating bypass reheat, and the technical issuesthat must be dealt with, are very site specific. No one technology or set of technical guidelines can be applied for these projects.Power Industry Services

5 CFD Modeling Computational fluid dynamics or CFD modeling is a method of obtaining solutions to complex equations describing fluidflow, 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 whenevaluating 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 varioustechnologies described in this paper to help a number of utilities improve the performance and reliability of their FGDsystems. 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 brieflydescribed 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 towertowards 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 SO 2 removal efficiency overa 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 SO 2 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 SO 2 Removal

removal values obtained during the testing and used for the comparisons are summarized in Table 2.

The data show that the improvement in SO 2 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 theImproving the Performance of Older FGD Systems

6 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 eachof 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 withsodium formate, it was discovered that the unit could not achieve a SO 2 removalefficiency above 95 percent due to wall sneakage. The plant has been retrofitting Liquid Distribution Rings with a dramatic improvement in SO 2 removal efficiency. Figure 6 shows the SO 2 concentration profile before and after installation of LDR.

The installation of LDRs has greatly improved the SO 2 concentration profile and eliminated the high concentrations of SO 2 along the walls and in the corners. In side by side testing, SO 2 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. SO 2 Concentration (ppm) Profile Before and After Installation of LDRsPower Industry Services

7 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 distributionrings 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 gasvelocity 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 thegas 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, suggestedthat 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 EliminatorImproving the Performance of Older FGD Systems

8The 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 earlygeneration, 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,Power Industry Services

9 Figure 11. CFD Modeling Results for Quencher Section

unquenched flue gas was exiting the quencher section of theabsorber. 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 theuneven 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 resultedin 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 shownin 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 evaluatingchanges to improve the gas handling capacity of the scrubber and the SO 2 removal performance to allow them greater flexibility in fuel selection. The approach that was taken toaccomplish these goals was to eliminate the quencher headers, bowl section, and piping internal support memberswhere 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 includeda 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 OutletImproving the Performance of Older FGD Systems

10There 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 lowerportion 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 underminethe 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 velocityfor 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, shouldimprove 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 ChangesPower Industry Services

11 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 beexpected 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 ofthe 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 SO 2 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 SO 2 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 FGDsystem 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 dropwhile 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 CreekImproving the Performance of Older FGD Systems

12 increase the SO 2 removal efficiency from 88 percent to 95 percent. Initially, organic acid was under consideration to increase scrubber efficiency; however, upgrading Unit 8 to atwin 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 gaspasses through an electrostatic precipitator it enters a common inlet plenum where the flow is distributed through fourparallel 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 SO 2 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 SO 2 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 SO 2 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 SO 2 removal efficiency to the desired 95 percent. In addition, installation of the liquid distribution rings on Unit 7 increases the SO 2 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 DesignPower Industry Services

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### Summary Utilities are facing increasing pressure to reduce emissions of SO 2 and other pollutants. At the same time, these utilitiesmust 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 meetthese 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 systemperformance 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 developmentof 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 SO 2 Removal Efficiencies. U.S EPA-DOE-EPRI Mega Symposium, August 2001URS is a full-service organization providing engineering, procurement, project management, and construction services worldwide with annual revenues exceeding $10 billion. URS has approximately 45,000 employees in a network of offices in major cities in the Americas, Asia-Pacific, the Middle East and Europe. Our broad-based expertise is a valued resource for federal, state, and local governmental agencies, as well as Fortune 500 and other private industry clients worldwide. The Engineering-News Recordhas ranked URS as one of the top three design firms for the past decade.

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