# Fayette Power Project Unit 3 FGD Upgrade:Design and Performance for More CostEffective SO 2 

# Reduction Technical Paper

BR-1845

Authors: C. Frazer

Lower Colorado River Authority Austin, Texas, U.S.A.

A. Jayaprakash S. M. Katzberger

Sargent & Lundy, L.L.C. Chicago, Illinois, U.S.A.

Y. J. Lee B. R. Tielsch

Babcock & Wilcox Power Generation Group, Inc. Barberton, Ohio, U.S.A.

Presented to: EPRI Power Plant Air Pollutant Control Mega Symposium

Date: August 30 - Sept. 2, 2010

Location: Baltimore, Maryland, U.S.A.Babcock & Wilcox Power Generation Group 1 

# Fayette Power Project Unit 3 FGD Upgrade: Design and Performance for More Cost-Effective SO 2 

# Reduction

A. Jayaprakash S. M. Katzberger Sargent & Lundy, L.L.C. Chicago, Illinois, U.S.A.

BR-1845



## Introduction Lower Colorado River Authority’s (LCRA) Fayette Power Project – Unit 3 (FPP3), located near La Grange, Texas, was completed in 1988. The original wet flue gas desulfurization (WFGD) system design was to reduce sulfur dioxide (SO 2 ) by approximately 90% across the absorbers, while burning high-sulfur Texas lignite and bypassing up to 20% of the flue gas. In the future, the station will require 95.5% SO 2 capture without flue gas bypass, while firing 1% sulfur Powder River Basin (PRB) coal. Sargent & Lundy, L.L.C. (S&L) performed an FGD upgrade study that identi

fied a concept for achieving these goals. S&L subsequently prepared a specification to obtain bids for performing the upgrade work on a supply and erect basis. BE&K, and their subcontractor Babcock & Wilcox Power Generation Group, Inc. (B&W PGG) were selected as the supplier for these modifications, which included new spray headers, the addi

tion of trays, turning vanes, and a new mist eliminator (ME) system. Non-proprietary details of the design modifications as well as actual performance data comparing the original installation and the modified installation are presented in this paper.



### Overview of Fayette Power Project – Unit 3 LCRA Fayette Station is located near La Grange, Texas, and consists of three pulverized coal-fired units that burn PRB sub-bituminous coal. Unit 3 is a nominal 470 MWtangentially fired unit, which was designed to burn highsulfur Texas lignite, but is currently firing 1.0 lb SO 2 / MBtu sub-bituminous coal. The boiler was manufactured by Combustion Engineering (Alstom). The flue gas passes through a pair of regenerative Ljungstrom air preheaters, before passing through a cold-side electrostatic precipitator (ESP) and then approximately 95 to 99% of the flue gas is treated in a WFGD system. The treated flue gas is mixed with bypassed flue gas and then emitted from the station through a dry chimney.



### Original air quality control system (AQCS) technology The FGD system was originally designed as a wet lime

stone, forced oxidation system by Combustion Engineer

ing, and consists of a 3x50% absorber arrangement. Each absorber is 38 ft x 36.5 ft in the spray zone with expansion of the absorber to 40 ft x 41.5 ft as the flue gas passes through the ME zone. Each absorber was fabricated of 317 LMN stainless steel, including the ladder vanes located at the inlet of each absorber. The reaction tank for each absorber is not integrated to the spray zone and slurry is funneled through the base of the absorber into the separate reaction tank. In the spray section of each absorber, the original design included five spray levels, each with 42 spray nozzles spaced evenly across the absorber. At the time the project began, only Absorber A still had all five spray levels. Absorbers B and C had the lowest spray header previously removed. The lowest spray header in Absorber A was removed during this project. The headers were supported from beams across the absorber using simple rod hangers, which have frequently failed in the past. This led to a number of instances where one of the spray headers inside the absorber collapsed due to a broken hanger rod, resulting in a lack of support along the span of the header. Additionally, some of the spray nozzles have broken off in the past, leading to a maldistribution of Presented to: EPRI Mega Symposium 2010 August 30 - Sept. 2, 2010 Baltimore, Maryland, U.S.A. Y. J. Lee B. R. Tielsch Babcock & Wilcox Power Generation Group, Inc. Barberton, Ohio, U.S.A. C. Frazer Lower Colorado River Authority Austin, Texas, U.S.A.2 Babcock & Wilcox Power Generation Group slurry across the absorber as well as a loss of atomization of the slurry across the affected spray header, due to the significant decrease in pressure drop across that section of the header. The original ME system consisted of three ME levels and a retractable, lance-style ME wash system. The MEs consisted of a flat level of chevron blades, known as the bulk entrainment separator, and two “tepee” style levels. The MEs were washed by the lance-style wash system that was mechanically inserted in and out of the absorbers. The MEs were washed with 100% reclaim water. Even though this system kept them clean, the MEs were no longer sup

ported by the original equipment manufacturer (OEM) and the lance-style wash system had come to require increasingly higher maintenance. Flue gas flow through the spray zone, with two absorb

ers in service, at full load was originally designed for 12.1 ft/s, based on firing lignite. Subsequent to the PRB coal conversion, the velocity of the flue gas through the spray zone dropped to 9.71 ft/s.

Original design conditions
Fuels The WFGD system was originally designed to treat flue gas generated from the firing of 10 lb SO 2 /MBtu lignite. After the design of the absorbers was completed, it was de

cided to burn a sub-bituminous fuel instead of Texas lignite. As a result, the absorbers and all ancillary equipment are significantly oversized for current operating conditions. For example, while typical recycle tank solids residence time for a new WFGD system is approximately 16-24 hours, the solids residence time at FPP3 is approximately seven days. SO2removal efficiency Prior to the upgrade, the FPP3 AQCS was capturing 85 to 88% of the SO 2 present in the flue gas that passed through the absorber. This treated flue gas was then blended with the WFGD (1 to 5%) bypass gas to maintain a dry stack. As a result, the overall efficiency of the WFGD system, from WFGD inlet to stack outlet, was operating at 81 to 84%, as shown in Table 1.

Performance prior to upgrade Considering the current firing of low-sulfur, sub-bitu

minous coal, the SO 2 removal capability has been adequate to meet current emission limits. However, there was reason to improve the performance of the scrubber in anticipation of future emission limits set by the plant-wide flexible air permit that will go into effect in 2012. Coupled with the upgrade driven by the flexible air permit requirements, there was also an opportunity to improve the cost effectiveness of the upgrade by purchasing lower-cost higher-sulfur coal and by selling excess SO 2 credits that would result from the upgrade. Additionally, the spray headers and ME systems were approaching end-of-life and were either obsolete, or not supported by the OEM.

Bypass to maintain dry stack Originally, to maintain a dry stack, a portion of the flue gas was bypassed around the WFGD to keep the temperature of the bulk flue gas above the gas saturation temperature. Current operation bypasses approximately 1 to 5% of the flue gas around the WFGD system. Dampers are present in the bypass duct to control the amount of flue gas bypassed based upon temperature measurements in the stack. Once the stack is upgraded for wet operation, LCRA will have the option to operate with a closed flue gas bypass.



### Goals of the upgrade project Based on regulatory requirements and on the experiences of the station with operating the WFGD system on FPP3, as detailed above, the goals of this project were to improve:

• SO 2 removal efficiency across each absorber to meet a

minimum of 95.5%, with zero bypass.

• FGD system reliability to reduce maintenance costs.


## Preliminary engineering

Upgrade study In 2006, S&L was tasked with assisting LCRA to ac

complish the goals set forth above to improve FPP3 FGD overall performance. In doing so, S&L prepared a study to address the two goals. The results from that study are sum

marized below.

Upgrade performance A number of options were investigated to determine the best potential performance upgrade choice for FPP3. Quotes were solicited from FGD OEMs to provide accu

rate assessments of the expected costs associated with wall baffles, trays, DBA injection systems, replacement spray nozzles to improve coverage in the absorber, and conversion to scrubbing 100% of the flue gas. A cost-benefit analysis was performed for each option and several combinations thereof to determine which solution was the most cost ef

fective for FPP3. Using capital and O&M cost estimates for each upgrade option as well as an LCRA-prescribed index Table 1 Progression of SO 2 Removal Efficiency

Design Original Design Original Operation Post-Upgrade Operation

Fuel Texas Lignite (10 lb SO 2 /

MBtu) PRB Coal (1 lb SO 2 /MBtu) PRB Coal (2 lb SO 2 / MBtu) Tested Bypass 20% 1-5% 0%
Overall SO 2 removal 72% 81

- 84% 95.5%Babcock & Wilcox Power Generation Group 3 for the expected sale price for SO 2 credits and the cost of higher-sulfur coal, the overall SO 2 removal efficiency and cost effectiveness of each of the upgrade technologies were evaluated over the life of the project.The results of the study indicated that the most costeffective solution for FPP3 was the installation of one tray in each absorber, increasing the number of spray nozzles per spray level, replacing the original turning vanes (which had corroded and been removed), and converting the chimney for wet operation.

Upgrade reliability A number of options were investigated to determine the best potential reliability upgrade choice for FPP3. Quotes were solicited from FGD OEMs to provide accurate assess

ments of the expected costs associated with self-supporting spray headers, new MEs and ME wash systems, and lining the floors and walls of the reaction tanks with Stebbins tile. A cost-benefit analysis was performed for each option and several combinations thereof to determine which solution was the most cost effective for FPP3. The results of the reliability upgrade study indicated that the most cost-effective upgrades for FPP3 were self-sup

porting spray headers and new MEs and ME wash systems.

Two versus three absorbers/no FGD bypass The FGD system was originally designed for two ab

sorbers in operation, with the remaining absorber serving as a spare. Periodically, one absorber would be taken out of service and the spare absorber would be returned to service. The absorber off line would be maintained and then cycled back into service. Additionally, as stated above, the chimney was designed to operate dry. To achieve this, the FGD design incorporated a bypass, which is approximately 5% of the flue gas for typical operation. When considering the options to upgrade both the performance and the reliability of the WFGD absorbers, operation of the absorbers in a 2x50% ar

rangement and elimination of the FGD bypass were consid

ered. Ultimately, the options selected, and discussed above, offer the station the flexibility to permanently remove one of the absorbers from regular service and provide the option to stop the FGD bypass. Outside of the addition of a tray and turning vanes to each absorber, only two of the absorbers needed to be fully upgraded, thereby saving capital cost for the project. The addition of a tray and turning vanes to the third absorber is to maintain equal pressure drop and flow balance if the third absorber is used as an emergency backup.



### Computational fluid dynamic (CFD) modeling results S&L was also tasked during the study phase to determine if there was potential for improvement in the flue gas flow path to reduce pressure drop throughout the system. Using the ANSYS CFX suite of software, the FGD system for FPP3 was modeled from the inlet manifold of the absorbers through the outlet manifold into the chimney. This included CFD modeling of the bypass duct and the absorbers, as well as the spray zones. The inlet manifold modeling was conducted to determine if pressure drop to the system could be reduced, while also maintaining a 50:50 ratio of flows to the two active absorb

ers in all three potential operating configurations. The base model with no modifications to the inlet manifold showed the flow splits between the two active absorber inlets, for all operating scenarios, to be within ±5% of each other. The model indicated that the existing design of the inlet ducts was adequate from a flow distribution standpoint. While vanes added in the inlet manifold could reduce pressure drop through the system, they could also alter the flow split to each FGD absorber. It was determined that no vanes were needed in the inlet manifold duct. Each absorber was also modeled to determine any poten

tial vaning that could be applied to the unit to reduce pres

sure drop and improve performance by improving gas flow distribution. Based on the results from the inlet manifold modeling, it was assumed that the gas flow to each absorber was the same for modeling purposes. Each absorber was designed to have certain flow improvement devices. For instance, at the end of the inlet duct, the rain hood, which prevents “short-circuiting” of gas along the near wall and forces the gas into the bulk of the limestone slurry spray, was modeled. Additionally, new and modified ladder vanes were modeled to prevent the flue gas from having an impact on the far wall of the absorber. The modeling results sug

gested vanes could be added to the absorber to improve the gas flow inside the absorber. These would include an angled vane in the inlet duct to each absorber to force a portion of the flue gas entering from the bottom of the duct to the top, and an extension to the existing ladder vanes to further direct flow to the center of the absorber, where the concentration of slurry spray is the highest. However, since a tray (which inherently provides good gas/liquid distribution) was part of the recommended option for improving overall SO 2 removal efficiency, it was determined that the benefit associated with these vanes was not required. The outlet of each absorber was also modeled to deter

mine any potential vaning that could be applied to the unit to reduce pressure drop and improve performance by im

proving gas flow distribution. OEM drawings of the outlet elbow show that the absorbers were designed to have turning vanes in this location. Discussion with LCRA personnel indicated that these turning vanes had corroded over time and had previously been removed from service. These vanes were modeled to determine any benefit provided and it was determined that these vanes should be reinstalled using a material suitable for the wet environment. Lastly, the outlet manifold duct connecting the bypass duct and the outlet ducts from all three absorbers with the chimney was modeled. OEM drawings of the outlet ducts show that the ducts were designed to have turning vanes in this location. Discussion with LCRA personnel indicated4 Babcock & Wilcox Power Generation Group that these turning vanes had also corroded over time and been removed from service. Flow was modeled to reduce pressure drop and to allow for no temperature maldistribu

tions due to improper mixing. Cases were modeled based both on continued operation of the dry stack due to bypass of flue gas and on scrubbing of 100% of the flue gas. The results of this modeling showed that by installing turning vanes near the chimney-side wall of each absorber outlet, the pressure drop could be significantly reduced.


## Implementation phase To support the FGD upgrades determined during the study phase, a specification was written to solicit competitive bids for the work. The specification encompassed the scope of work for the engineering, procurement and construction of all the specified upgrades. These included installation of a tray in each of the three absorbers, replacement of the existing spray header/spray nozzle system, replacement of the MEs and ME wash system in two of the absorbers, and installation of the turning vanes based on the results of the CFD modeling performed by S&L. A tray and turning vanes were installed in the third absorber so that the pressure drop across any two of the operating absorbers in service would be equal. The other upgrades were installed only in two absorbers to reduce capital cost. Performance guarantees were required for a number of parameters, but in particular, focused on SO 2 removal and absorber pressure drop increase. The required performance guarantees for burning 2 lb/MBtu SO 2 coal at full load with three spray headers operating and no bypass are summarized in Table 2. Based on the review of the competitive bids received in response to the specification, BE&K (with B&W PGG as its engineer subcontractor) was selected to perform the upgrades to the FPP3 FGD system.



### Tray design and implementation
Each of the three absorber modules was retrofitted with a single tray (Figure 1). As flue gas passes through the ab

sorber, it is quenched by absorber slurry falling from sprays as it passes through the perforated absorber tray. The tray Table 2 Required Performance Guarantees

Guarantee Guarantee Value
SO 2 removal efficiency 95.5 Increase in absorber pressure drop ≤ 2.0 in. W.C. ME carryover 0.0004 gpm/ft 2 Limestone consumption rate 16,000 lb/hr ME wash water consumption 342 gpm
Particulate emission 0.030 lb/MBtu

Fig. 1 Tray sections with hold-down plates. Fig. 2 Access door to tray level.

Fig. 3 Spray headers, supports and spray nozzles.Babcock & Wilcox Power Generation Group 5 supports and tray were constructed of alloy 2205 and the tray was sectioned into compartments by baffles. The baffles in the tray assist in the even distribution of limestone slurry on top of the tray, which provides an area of close contact between the flue gas and the active reagent. The tray sup

ports also serve as an excellent platform for inspection and maintenance (provided proper planking is used on top of the baffles) of the slurry spray headers and nozzles, which will aid in future O&M of the absorber. At each tray level, an access door and platform were provided (Figure 2). The new platforms are accessible from existing platforms for each of the three absorbers.



### Spray headers/spray nozzles design and implementation
Absorber modules A and C were retrofitted with new spray headers and spray nozzles (Figure 3). The existing absorber recirculation pumps (three operating and one spare) and piping were reused to supply the absorber spray headers with slurry from the absorber reaction tank. The six new headers per spray level were constructedof alloy 2205. The spray nozzles are hollow cone, nitridebonded, silicon carbide and are designed to provide uniform spray coverage over the entire cross-sectional area of the tower. For comparison, the spray coverage before and after the FGD upgrades is shown in Figure 4. Before the upgrade, it is clear that a significant portion of the cross-section, either inside the absorber or along the wall, was not covered by the spray circles. After the upgrade, the spray pattern shows a minimum of 200% coverage, except for a small portion of the perimeter section. The overlapped upgraded spray coverage greatly reduces flue gas escape and effectively increases liquid-gas contact.



### ME design and implementation
Absorber modules A and C were retrofitted with new ME wash systems (Figure 5). Each module was equipped with two stages of MEs, which remove carryover mist by iner

tial contact. The primary stage captures large particles and the secondary stage captures wash water droplets and finer particles. The two-stage ME is kept free of slurry deposits by a new stationary water wash system. ME wash water is directed to the upstream face for washing the primary stage ME using an array of spray headers and spray nozzles. The top surface of the primary stage and the bottom surface of the secondary stage MEs are also washed with ME wash water. A 50/50 mixture of fresh water and reclaim water is used for ME wash due to tight water balance and zero discharge requirements at the facility. The MEs were designed to be washed sequentially by sec

tion to optimize the wash flow rate. The primary underspray and the primary overspray/secondary underspray levels are each divided into four sections. The primary overspray and Fig. 4 Spray coverage of slurry nozzles – before and after upgrades.

Fig. 5 Mist eliminator design – original and upgraded. Absorber Spray Pattern – Upgrade Absorber Spray Pattern – Original6 Babcock & Wilcox Power Generation Group secondary underspray levels are washed simultaneously using the existing ME wash pumps. The ME blades are constructed of FRP. The ME wash spray headers and wash nozzles are constructed of alloy 2205.



### Turning vanes design and implementation Three turning vanes were installed in each tower outlet duct in the 90-degree turn toward the plenum (Figure 6). Each tower also received a turning vane at the connection to the common outlet plenum. The turning vanes are con

structed of AL6XN ® steel alloy. The purpose of the turning vanes is to evenly distribute flow into the common outlet plenum and reduce pressure drop.


## Performance testing results Upon completion of the implementation phase of the upgrades, the FGD system was tested between January 26-28, 2010, to determine the performance of the system and compare the results with B&W PGG’s guarantees. In particular, two criteria of paramount importance were tested: SO 2 removal efficiency and absorber pressure drop. Additionally, the reliability of the system was monitored to determine if one of the absorbers could be removed from future operation. The results from that performance testing are discussed below.



### SO 2 

### removal efficiency Three tests by a third-party independent testing company were taken over the course of three days. For the tests, the boiler burned 2 lb SO 2 /MBtu sub-bituminous coal. The FGD modules received 100% of the flue gas flow and three spray headers were operating. Measurements of SO 2 concentra

tions were taken at specified sampling locations in the inlet and outlet ducts of Absorbers A and C. These measurements were then adjusted in accordance with 40CFR60, Appendix A, Method 7E to a common basis of 7% O 2 in the flue gas. A summary of the results from the testing is shown in Table 3. These raw results were then used to compute the overall removal efficiency of the upgraded FGD absorbers as sum

marized in Table 4. When compared against the guaranteed SO 2 removal efficiency of 95.5%, the performance testing showed com

pliance with the guaranteed value with significant margin.



### Pressure drop To determine the increase in pressure drop across the system due to the installation of the upgrades, a baseline test was run in April 2009, prior to the installation of the tray and the turning vanes. These data were then compared with the measured data taken during performance testing. The data collected in the baseline test are shown in Table 5. During the performance testing performed in January 2010, the static pressure at both the inlet and the outlet of each absorber was measured. The resulting pressure drop determined by the difference of these two values was then compared against flow-adjusted baseline data to determine the change in pressure drop across the absorber as a result of the FGD upgrade. A summary of the data collected is shown in Table 6. Compliance with the guaranteed value was determined by comparing the measured pressure drop across each tested absorber with the expected pressure drop determined in
Table 4 SO 2 Removal Efficiency

Run Absorber A Absorber C

1 99.6% 99.2%

2 99.3% 98.9%

3 99.3% 98.8%
Average 99.4% 99.0%
Site Average 99.2% Table 5 Baseline Absorber Pressure Drop Results

Run Load (MW) Volumetric Flow (scfm, wet) Pressure Drop (in. W.C.)

1 469 679,451 4.06

2 399 803,717 3.47

3 352 598,942 3.15 * Due to abnormally high volumetric flow, Run 2 was omitted from calculations. Table 3 SO 2 and O 2 Emission Measurements
Inlet Duct Absorber A Outlet Duct Absorber C Outlet Duct

Run O2 % dry SO2 ppm dry SO2 ppmc* O2 % dry SO2 ppm dry SO2 ppmc O2 % dry SO2 ppm dry SO2 ppmc

1 6.28 709.8 674.8 6.49 2.7 2.6 6.72 5.6 5.5

2 6.33 769.7 734.3 6.48 5.3 5.1 6.69 8.4 8.2

3 6.44 765.5 735.9 6.59 5.3 5.1 6.76 8.7 8.6 * ppmc refers to parts per million corrected to a fixed O2 concentration of 7%.Babcock & Wilcox Power Generation Group 7 the baseline testing. The baseline pressure drop was also adjusted to match the flow from the performance testing. The measured data and the expected pressure drop data were then compared by difference to establish compliance with the performance guarantee. These data are summarized in Table 7. When compared against the maximum guaranteed absorber pressure drop increase of 2.0 in. W.C., the perfor

mance testing showed compliance with the guarantee and a marked improvement from the guaranteed value. Further

more, the addition of the turning vanes in the outlet elbow and outlet manifold, the addition of the high-efficiency ME system, as well as the dampening effect of the tray pressure drop, seems to have improved any flow maldistributions to the point that the FGD upgrade work has reduced the overall pressure drop across each absorber when compared with the baseline testing.



### Reliability The performance testing for the modules was completed in late January, 2010. Prior to the FGD upgrade, one module was always in maintenance mode. Every six months, the absorber out of service for maintenance would be returned to service and another would be taken off line for service in accordance with the station’s maintenance schedule. Reasons for continuous maintenance, as detailed above, included broken spray nozzles and fallen spray headers. The intent of the upgrade was to improve the reliability of the absorb

ers to the point where LCRA could reliably expect the two upgraded absorbers to operate on a two-year cycle without going off line for forced maintenance issues. To date, the unit has not experienced the maintenance problems that occurred in the past. LCRA is monitoring the availability of the absorbers with the goal of reduc

ing the overall maintenance for the FPP3 FGD system by permanently removing one of the absorbers from service. However, this goal will require time to achieve, as the ab

sorbers must show consistent availability in the next couple of maintenance cycles, as a minimum, before one can be permanently removed from service. Also, the modifica

tions to the chimney liner to convert to wet operation must be completed before operating with the FGD bypass in the closed position. Fig. 6 Outlet turning vanes.

Table 6 Performance Measurement of Absorber Pressure Drop

Run A Inlet A Outlet Pressure Drop C Inlet C Outlet Pressure Drop

1 3.00 0.30 2.70 3.00 0.49 2.51

2 3.10 0.35 2.75 3.00 0.49 2.51

3 3.45 0.36 3.09 3.50 0.49 2.64
Average 3.18 0.34 2.74 3.17 0.49 2.688 Babcock & Wilcox Power Generation Group 

## Conclusions The FPP3 FGD upgrade project was a tremendous suc

cess for LCRA, BE&K, B&W PGG, and S&L. The upgrades should enable this system to operate efficiently for many years. The improved SO 2 removal efficiency will allow the unit to effectively meet the permit emission limits and offer the option for selling credits should that market return. The unit also has the option to burn lower-cost, high-sulfur coal, while still maintaining emissions limits. Additionally, with the upgrades aimed at improving the reliability of the FGD system, it is anticipated that overall maintenance associated with the FPP3 FGD system will be significantly reduced. In the future, LCRA will convert the existing FPP3 dry stack to a wet stack, which will provide the option for the unit to operate without an FGD bypass. Table 7 Comparison of Measured Pressure Drop with Expected Pressure Drop
Performance Test 1 Module A Module C Total Measured pressure drop 2.70 2.51 2.61 Expected pressure drop 4.19 2.94 3.62

Pressure increase -1.01
Performance Test 2 Module A Module C Total Measured pressure drop 2.75 2.51 2.64 Expected pressure drop 4.30 2.41 3.48

Pressure increase -0.84
Performance Test 3 Module A Module C Total Measured pressure drop 3.09 3.01 3.05 Expected pressure drop 4.22 2.64 3.52

Pressure increase -0.46

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