Fayette Power Project Unit 3 FGD Upgrade: Design and Performance for More Cost- Effective SO2 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. Fayette Power Project Unit 3 FGD Upgrade: Design and Performance for More Cost-Effective SO2 Reduction

Y. J. Lee A. Jayaprakash C. Frazer B. R. Tielsch S. M. Katzberger Lower Colorado River Authority Babcock & Wilcox Sargent & Lundy, L.L.C. Austin, Texas, U.S.A. Power Generation Group, Inc. Chicago, Illinois, U.S.A. Barberton, Ohio, U.S.A.

Presented to: BR-1845 EPRI Mega Symposium 2010 August 30 - Sept. 2, 2010 Baltimore, Maryland, U.S.A.

Introduction through a pair of regenerative Ljungstrom air preheaters, before passing through a cold-side electrostatic precipitator Lower Colorado River Authority’s (LCRA) Fayette (ESP) and then approximately 95 to 99% of the flue gas is Power Project – Unit 3 (FPP3), located near La Grange, treated in a WFGD system. The treated flue gas is mixed Texas, was completed in 1988. The original wet flue gas with bypassed flue gas and then emitted from the station desulfurization (WFGD) system design was to reduce sulfur through a dry chimney. dioxide (SO2) 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 Original air quality control system (AQCS) 95.5% SO2 capture without flue gas bypass, while firing 1% technology sulfur Powder River Basin (PRB) coal. Sargent & Lundy, The FGD system was originally designed as a wet lime- L.L.C. (S&L) performed an FGD upgrade study that identi- stone, forced oxidation system by Combustion Engineer- fied a concept for achieving these goals. S&L subsequently ing, and consists of a 3x50% absorber arrangement. Each prepared a specification to obtain bids for performing the absorber is 38 ft x 36.5 ft in the spray zone with expansion of upgrade work on a supply and erect basis. BE&K, and their the absorber to 40 ft x 41.5 ft as the flue gas passes through subcontractor Babcock & Wilcox Power Generation Group, the ME zone. Each absorber was fabricated of 317 LMN Inc. (B&W PGG) were selected as the supplier for these stainless steel, including the ladder vanes located at the inlet modifications, which included new spray headers, the addi- of each absorber. The reaction tank for each absorber is not tion of trays, turning vanes, and a new mist eliminator (ME) integrated to the spray zone and slurry is funneled through system. Non-proprietary details of the design modifications the base of the absorber into the separate reaction tank. as well as actual performance data comparing the original In the spray section of each absorber, the original design installation and the modified installation are presented in included five spray levels, each with 42 spray nozzles spaced this paper. 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 Overview of Fayette Power Project – Unit 3 lowest spray header in Absorber A was removed during this LCRA Fayette Station is located near La Grange, Texas, project. The headers were supported from beams across the and consists of three pulverized coal-fired units that burn absorber using simple rod hangers, which have frequently PRB sub-bituminous coal. Unit 3 is a nominal 470 MW failed in the past. This led to a number of instances where tangentially fired unit, which was designed to burn high- one of the spray headers inside the absorber collapsed due to sulfur Texas lignite, but is currently firing 1.0 lb SO2/ a broken hanger rod, resulting in a lack of support along the MBtu sub-bituminous coal. The boiler was manufactured span of the header. Additionally, some of the spray nozzles by Combustion Engineering (Alstom). The flue gas passes have broken off in the past, leading to a maldistribution of

Babcock & Wilcox Power Generation Group 1 slurry across the absorber as well as a loss of atomization to meet current emission limits. However, there was reason of the slurry across the affected spray header, due to the to improve the performance of the scrubber in anticipation significant decrease in pressure drop across that section of of future emission limits set by the plant-wide flexible air the header. permit that will go into effect in 2012. Coupled with the The original ME system consisted of three ME levels upgrade driven by the flexible air permit requirements, there and a retractable, lance-style ME wash system. The MEs was also an opportunity to improve the cost effectiveness consisted of a flat level of chevron blades, known as the of the upgrade by purchasing lower-cost higher-sulfur coal bulk entrainment separator, and two “tepee” style levels. and by selling excess SO2 credits that would result from the The MEs were washed by the lance-style wash system that upgrade. Additionally, the spray headers and ME systems was mechanically inserted in and out of the absorbers. The were approaching end-of-life and were either obsolete, or MEs were washed with 100% reclaim water. Even though not supported by the OEM. this system kept them clean, the MEs were no longer supported by the original equipment manufacturer (OEM) and the lance-style wash system had come to require increasingly Bypass to maintain dry stack higher maintenance. Originally, to maintain a dry stack, a portion of the flue Flue gas flow through the spray zone, with two absorb- gas was bypassed around the WFGD to keep the temperature ers in service, at full load was originally designed for 12.1 of the bulk flue gas above the gas saturation temperature. ft/s, based on firing lignite. Subsequent to the PRB coal Current operation bypasses approximately 1 to 5% of the conversion, the velocity of the flue gas through the spray flue gas around the WFGD system. Dampers are present in zone dropped to 9.71 ft/s. 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 Original design conditions option to operate with a closed flue gas bypass. Fuels The WFGD system was originally designed to treat flue gas generated from the firing of 10 lb SO2/MBtu lignite. Goals of the upgrade project After the design of the absorbers was completed, it was de- Based on regulatory requirements and on the experiences cided to burn a sub-bituminous fuel instead of Texas lignite. of the station with operating the WFGD system on FPP3, As a result, the absorbers and all ancillary equipment are as detailed above, the goals of this project were to improve: significantly oversized for current operating conditions. For • SO2 removal efficiency across each absorber to meet a example, while typical recycle tank solids residence time minimum of 95.5%, with zero bypass. for a new WFGD system is approximately 16-24 hours, the • FGD system reliability to reduce maintenance costs. solids residence time at FPP3 is approximately seven days. SO2 removal efficiency Prior to the upgrade, the FPP3 AQCS was capturing 85 Preliminary engineering to 88% of the SO2 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 Upgrade study result, the overall efficiency of the WFGD system, from In 2006, S&L was tasked with assisting LCRA to ac- WFGD inlet to stack outlet, was operating at 81 to 84%, as complish the goals set forth above to improve FPP3 FGD shown in Table 1. overall performance. In doing so, S&L prepared a study to address the two goals. The results from that study are summarized below. Performance prior to upgrade Considering the current firing of low-sulfur, sub-bituminous coal, the SO2 removal capability has been adequate Upgrade performance A number of options were investigated to determine Table 1 the best potential performance upgrade choice for FPP3. Progression of SO2 Removal Efficiency Quotes were solicited from FGD OEMs to provide accu- Original Post-Upgrade rate assessments of the expected costs associated with wall Design Original Design Operation Operation baffles, trays, DBA injection systems, replacement spray Texas Lignite PRB Coal nozzles to improve coverage in the absorber, and conversion PRB Coal Fuel (10 lb SO2/ (2 lb SO2/ to scrubbing 100% of the flue gas. A cost-benefit analysis (1 lb SO2/MBtu) MBtu) MBtu) Tested was performed for each option and several combinations Bypass 20% 1-5% 0% thereof to determine which solution was the most cost ef- Overall fective for FPP3. Using capital and O&M cost estimates for 72% 81-84% 95.5% SO2 removal each upgrade option as well as an LCRA-prescribed index

2 Babcock & Wilcox Power Generation Group for the expected sale price for SO2 credits and the cost of FPP3 was modeled from the inlet manifold of the absorbers higher-sulfur coal, the overall SO2 removal efficiency and through the outlet manifold into the chimney. This included cost effectiveness of each of the upgrade technologies were CFD modeling of the bypass duct and the absorbers, as well evaluated over the life of the project. as the spray zones. The results of the study indicated that the most cost- The inlet manifold modeling was conducted to determine effective solution for FPP3 was the installation of one tray if pressure drop to the system could be reduced, while also in each absorber, increasing the number of spray nozzles per maintaining a 50:50 ratio of flows to the two active absorb- spray level, replacing the original turning vanes (which had ers in all three potential operating configurations. The base corroded and been removed), and converting the chimney model with no modifications to the inlet manifold showed for wet operation. 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 Upgrade reliability was adequate from a flow distribution standpoint. While A number of options were investigated to determine the vanes added in the inlet manifold could reduce pressure drop best potential reliability upgrade choice for FPP3. Quotes through the system, they could also alter the flow split to were solicited from FGD OEMs to provide accurate assess- each FGD absorber. It was determined that no vanes were ments of the expected costs associated with self-supporting needed in the inlet manifold duct. spray headers, new MEs and ME wash systems, and lining Each absorber was also modeled to determine any poten- the floors and walls of the reaction tanks with Stebbins tile. tial vaning that could be applied to the unit to reduce pres- A cost-benefit analysis was performed for each option and sure drop and improve performance by improving gas flow several combinations thereof to determine which solution distribution. Based on the results from the inlet manifold was the most cost effective for FPP3. modeling, it was assumed that the gas flow to each absorber The results of the reliability upgrade study indicated that was the same for modeling purposes. Each absorber was the most cost-effective upgrades for FPP3 were self-sup- designed to have certain flow improvement devices. For porting spray headers and new MEs and ME wash systems. 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, Two versus three absorbers/no FGD bypass was modeled. Additionally, new and modified ladder vanes The FGD system was originally designed for two ab- were modeled to prevent the flue gas from having an impact sorbers in operation, with the remaining absorber serving on the far wall of the absorber. The modeling results sug- as a spare. Periodically, one absorber would be taken out of gested vanes could be added to the absorber to improve the service and the spare absorber would be returned to service. gas flow inside the absorber. These would include an angled The absorber off line would be maintained and then cycled vane in the inlet duct to each absorber to force a portion of back into service. Additionally, as stated above, the chimney the flue gas entering from the bottom of the duct to the top, was designed to operate dry. To achieve this, the FGD design and an extension to the existing ladder vanes to further direct incorporated a bypass, which is approximately 5% of the flow to the center of the absorber, where the concentration flue gas for typical operation. When considering the options of slurry spray is the highest. However, since a tray (which to upgrade both the performance and the reliability of the inherently provides good gas/liquid distribution) was part of WFGD absorbers, operation of the absorbers in a 2x50% ar- the recommended option for improving overall SO2 removal rangement and elimination of the FGD bypass were consid- efficiency, it was determined that the benefit associated with ered. Ultimately, the options selected, and discussed above, these vanes was not required. offer the station the flexibility to permanently remove one of The outlet of each absorber was also modeled to deter- the absorbers from regular service and provide the option to mine any potential vaning that could be applied to the unit stop the FGD bypass. Outside of the addition of a tray and to reduce pressure drop and improve performance by im- turning vanes to each absorber, only two of the absorbers proving gas flow distribution. OEM drawings of the outlet needed to be fully upgraded, thereby saving capital cost for elbow show that the absorbers were designed to have turning the project. The addition of a tray and turning vanes to the vanes in this location. Discussion with LCRA personnel third absorber is to maintain equal pressure drop and flow indicated that these turning vanes had corroded over time balance if the third absorber is used as an emergency backup. 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 Computational fluid dynamic (CFD) modeling material suitable for the wet environment. results Lastly, the outlet manifold duct connecting the bypass S&L was also tasked during the study phase to determine duct and the outlet ducts from all three absorbers with the if there was potential for improvement in the flue gas flow chimney was modeled. OEM drawings of the outlet ducts path to reduce pressure drop throughout the system. Using show that the ducts were designed to have turning vanes in the ANSYS CFX suite of software, the FGD system for this location. Discussion with LCRA personnel indicated

Babcock & Wilcox Power Generation Group 3 Table 2 Required Performance Guarantees Guarantee Guarantee Value

SO2 removal efficiency 95.5 Increase in absorber pressure drop ≤2.0 in. W.C. ME carryover 0.0004 gpm/ft2 Limestone consumption rate 16,000 lb/hr ME wash water consumption 342 gpm Particulate emission 0.030 lb/MBtu 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 maldistributions due to improper mixing. Cases were modeled based both on continued operation of the dry stack due to bypass Fig. 2 Access door to tray level. 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, Based on the review of the competitive bids received the pressure drop could be significantly reduced. 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. Implementation phase To support the FGD upgrades determined during the study phase, a specification was written to solicit competitive bids Tray design and implementation for the work. The specification encompassed the scope of Each of the three absorber modules was retrofitted with work for the engineering, procurement and construction a single tray (Figure 1). As flue gas passes through the ab- of all the specified upgrades. These included installation sorber, it is quenched by absorber slurry falling from sprays of a tray in each of the three absorbers, replacement of the as it passes through the perforated absorber tray. The tray 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 SO2 removal and absorber pressure drop increase. The required performance guarantees for burning 2 lb/MBtu SO2 coal at full load with three spray headers operating and no bypass are summarized in Table 2.

Fig. 1 Tray sections with hold-down plates. Fig. 3 Spray headers, supports and spray nozzles.

4 Babcock & Wilcox Power Generation Group The six new headers per spray level were constructed of alloy 2205. The spray nozzles are hollow cone, nitride- bonded, 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 Absorber Spray Pattern – Original Absorber Spray Pattern – Upgrade of the perimeter section. The overlapped upgraded spray coverage greatly reduces flue gas escape and effectively Fig. 4 Spray coverage of slurry nozzles – before and after upgrades. increases liquid-gas contact. supports and tray were constructed of alloy 2205 and the tray was sectioned into compartments by baffles. The baffles ME design and implementation in the tray assist in the even distribution of limestone slurry on top of the tray, which provides an area of close contact Absorber modules A and C were retrofitted with new ME between the flue gas and the active reagent. The tray sup- wash systems (Figure 5). Each module was equipped with ports also serve as an excellent platform for inspection and two stages of MEs, which remove carryover mist by iner- maintenance (provided proper planking is used on top of the tial contact. The primary stage captures large particles and baffles) of the slurry spray headers and nozzles, which will the secondary stage captures wash water droplets and finer aid in future O&M of the absorber. particles. The two-stage ME is kept free of slurry deposits At each tray level, an access door and platform were by a new stationary water wash system. ME wash water is provided (Figure 2). The new platforms are accessible from directed to the upstream face for washing the primary stage existing platforms for each of the three absorbers. 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. Spray headers/spray nozzles design and A 50/50 mixture of fresh water and reclaim water is used implementation for ME wash due to tight water balance and zero discharge Absorber modules A and C were retrofitted with new requirements at the facility. spray headers and spray nozzles (Figure 3). The existing The MEs were designed to be washed sequentially by sec- absorber recirculation pumps (three operating and one spare) tion to optimize the wash flow rate. The primary underspray and piping were reused to supply the absorber spray headers and the primary overspray/secondary underspray levels are with slurry from the absorber reaction tank. each divided into four sections. The primary overspray and

Fig. 5 Mist eliminator design – original and upgraded.

Babcock & Wilcox Power Generation Group 5 Table 3 SO2 and O2 Emission Measurements Inlet Duct Absorber A Outlet Duct Absorber C Outlet Duct O SO SO O SO SO O SO SO Run 2 2 2 2 2 2 2 2 2 % dry ppm dry ppmc * % dry ppm dry ppmc % dry ppm dry 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%. secondary underspray levels are washed simultaneously boiler burned 2 lb SO2/MBtu sub-bituminous coal. The FGD using the existing ME wash pumps. modules received 100% of the flue gas flow and three spray The ME blades are constructed of FRP. The ME wash headers were operating. Measurements of SO2 concentra- spray headers and wash nozzles are constructed of alloy tions were taken at specified sampling locations in the inlet 2205. 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% O2 in the flue gas. A Turning vanes design and implementation summary of the results from the testing is shown in Table 3. Three turning vanes were installed in each tower outlet These raw results were then used to compute the overall duct in the 90-degree turn toward the plenum (Figure 6). removal efficiency of the upgraded FGD absorbers as sum- Each tower also received a turning vane at the connection marized in Table 4. to the common outlet plenum. The turning vanes are con- When compared against the guaranteed SO2 removal structed of AL6XN® steel alloy. efficiency of 95.5%, the performance testing showed com- The purpose of the turning vanes is to evenly distribute pliance with the guaranteed value with significant margin. flow into the common outlet plenum and reduce pressure drop. Pressure drop To determine the increase in pressure drop across the Performance testing results system due to the installation of the upgrades, a baseline Upon completion of the implementation phase of the test was run in April 2009, prior to the installation of the upgrades, the FGD system was tested between January tray and the turning vanes. These data were then compared 26-28, 2010, to determine the performance of the system with the measured data taken during performance testing. and compare the results with B&W PGG’s guarantees. The data collected in the baseline test are shown in Table 5. In particular, two criteria of paramount importance were During the performance testing performed in January tested: SO2 removal efficiency and absorber pressure drop. 2010, the static pressure at both the inlet and the outlet of Additionally, the reliability of the system was monitored to each absorber was measured. The resulting pressure drop determine if one of the absorbers could be removed from determined by the difference of these two values was then future operation. The results from that performance testing compared against flow-adjusted baseline data to determine are discussed below. 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. SO2 removal efficiency Compliance with the guaranteed value was determined Three tests by a third-party independent testing company by comparing the measured pressure drop across each tested were taken over the course of three days. For the tests, the absorber with the expected pressure drop determined in

Table 4 Table 5 SO2 Removal Efficiency Baseline Absorber Pressure Drop Results Run Absorber A Absorber C Load Volumetric Flow Pressure Drop Run 1 99.6% 99.2% (MW) (scfm, wet) (in. W.C.) 1 469 679,451 4.06 2 99.3% 98.9% 2 399 803,717 3.47 3 99.3% 98.8% 3 352 598,942 3.15 Average 99.4% 99.0%

Site Average 99.2% * Due to abnormally high volumetric flow, Run 2 was omitted from calculations.

6 Babcock & Wilcox Power Generation Group Fig. 6 Outlet turning vanes.

the baseline testing. The baseline pressure drop was also absorber out of service for maintenance would be returned adjusted to match the flow from the performance testing. to service and another would be taken off line for service in The measured data and the expected pressure drop data accordance with the station’s maintenance schedule. Reasons were then compared by difference to establish compliance for continuous maintenance, as detailed above, included with the performance guarantee. These data are summarized broken spray nozzles and fallen spray headers. The intent in Table 7. of the upgrade was to improve the reliability of the absorb- When compared against the maximum guaranteed ers to the point where LCRA could reliably expect the two absorber pressure drop increase of 2.0 in. W.C., the perfor- upgraded absorbers to operate on a two-year cycle without mance testing showed compliance with the guarantee and going off line for forced maintenance issues. a marked improvement from the guaranteed value. Further- To date, the unit has not experienced the maintenance more, the addition of the turning vanes in the outlet elbow problems that occurred in the past. LCRA is monitoring and outlet manifold, the addition of the high-efficiency ME the availability of the absorbers with the goal of reduc- system, as well as the dampening effect of the tray pressure ing the overall maintenance for the FPP3 FGD system by drop, seems to have improved any flow maldistributions to permanently removing one of the absorbers from service. the point that the FGD upgrade work has reduced the overall However, this goal will require time to achieve, as the ab- pressure drop across each absorber when compared with the sorbers must show consistent availability in the next couple baseline testing. of maintenance cycles, as a minimum, before one can be permanently removed from service. Also, the modifications to the chimney liner to convert to wet operation must Reliability be completed before operating with the FGD bypass in the The performance testing for the modules was completed closed position. in late January, 2010. Prior to the FGD upgrade, one module was always in maintenance mode. Every six months, the

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 2.68

Babcock & Wilcox Power Generation Group 7 Table 7 Conclusions Comparison of Measured Pressure Drop with The FPP3 FGD upgrade project was a tremendous suc- Expected Pressure Drop cess for LCRA, BE&K, B&W PGG, and S&L. The upgrades Performance Test 1 Module A Module C Total should enable this system to operate efficiently for many Measured pressure drop 2.70 2.51 2.61 years. The improved SO2 removal efficiency will allow the Expected pressure drop 4.19 2.94 3.62 unit to effectively meet the permit emission limits and offer Pressure increase -1.01 the option for selling credits should that market return. The unit also has the option to burn lower-cost, high-sulfur coal, Performance Test 2 Module A Module C Total while still maintaining emissions limits. Additionally, with Measured pressure drop 2.75 2.51 2.64 the upgrades aimed at improving the reliability of the FGD Expected pressure drop 4.30 2.41 3.48 system, it is anticipated that overall maintenance associated Pressure increase -0.84 with the FPP3 FGD system will be significantly reduced. Performance Test 3 Module A Module C Total In the future, LCRA will convert the existing FPP3 dry Measured pressure drop 3.09 3.01 3.05 stack to a wet stack, which will provide the option for the Expected pressure drop 4.22 2.64 3.52 unit to operate without an FGD bypass. Pressure increase -0.46

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