Successful SO3 Mitigation While Enhancing the ESP Performance at AEP s Gavin Plant by Dry Injection of Trona Upstream of the ESP Douglas P. Ritzenthaler American Electric Power 155 W. Nationwide Blvd. Columbus, Ohio 43215 ABSTRACT The effort to reduce NOx emissions from coal-fired power plants via selective catalytic reactors (SCRs) has resulted in the unintended consequence of oxidizing SO 2 to SO 3 and thereby increasing total SO 3 emissions. Although the higher stack SO 3 concentrations are still very low (measured in ppm) the emissions can sometimes produce a highly visible secondary plume, which, although unregulated, is nonetheless perceived by many to be problematic. Efforts to reduce the SO 3 levels can impede particulate matter (PM) collection for stations that employ cold side electrostatic precipitators (ESPs). SO 3 in the flue gas adsorbs onto fly ash particles and lowers fly ash resistivity thereby enhancing cold side ESP to capture the particle by electrostatic means. Low SO 3 levels can lead to excessively high fly ash resistivity levels resulting in opacity excursions due to PM that is difficult to capture or is easily re-entrained. AEP has successfully implemented a system that significantly lowers SO 3 emissions while simultaneously enhancing ESP operation at the General James M. Gavin Plant in Cheshire, OH. The system employs dry trona injection upstream of the ESP. This system replaced two other systems that were operated in tandem: one injecting a magnesium hydroxide slurry into the furnace, and the other injecting dry hydrated lime upstream of the ESP. Test results using the controlled condensation method verified visual indicators that stack SO 3 levels equal to or below pre-scr operation were routinely attainable without opacity excursions. Challenges to this new technology included material handling problems peculiar to trona and deposition of precipitates in the duct downstream of the injection point. INTRODUCTION Title I of the Clean Air Act Amendments of 1990 included requirements for reducing NOx emissions from electric generating facilities. The power industry responded with facility modifications such as the installation of low-nox emitting burners, introduction of over-fired air, installation of selective non-catalytic reduction (SNCR) technology, and the installation of selective catalytic reactors (SCRs).
The effort to reduce NOx emissions from coal-fired power plants via SCRs was pursued for the General James M. Gavin Plant (Gavin Plant). Gavin Plant Units 1 and 2 are believed to be the first two 1300 MW units burning high-sulfur coal to be equipped with SCRs. SCR s employ a catalyst (typically vanadium pentoxide) to convert NOx to N 2 and H 2 O with the addition of NH 3. There is also an unintended oxidation of the SO 2 to SO 3. Because of the direct relationship between duct SO 3 levels and H 2 SO 4 acid vapor formation, the terms SO 3 and H 2 SO 4 are often used interchangeably; this report employs the former phraseology. Stack SO 3 emissions are currently unregulated, except for OSHA standards for personnel exposure (at ground level) and for stack opacity. Therefore, for units burning low-sulfur coal the additional SO 3 generated by the SCR may not be problematic. However, for units burning moderate to high sulfur fuels the increase in emitted SO 3 from SCR operation can result in a dramatically more visible secondary plume. Although the higher stack SO 3 concentrations are still very low (measured in ppm) the emissions can sometimes produce a highly visible secondary plume, which, though unregulated, is nonetheless perceived by many to be problematic. SO 3 reacts with water vapor in the duct and forms vaporous H 2 SO 4. A portion of this condenses out in the air heater baskets. Another portion of the sulfuric acid vapor can condense in the duct if the duct temperature is too low, thereby corroding the duct. The remaining acid vapor condenses either when the plume is quenched when it contacts the relatively cold atmosphere or when wet scrubbers are employed for flue gas desulfurization (FGD), in the scrubber s quench zone. The rapid quenching of the acid vapor in the FGD tower results in a fine acid mist. The droplets are often too fine to be absorbed in the FGD tower or to be captured in the mist eliminator. Thus, there is only limited SO 3 removal by the FGD towers. If the sulfuric acid levels emitted from the stack are high enough, a secondary plume appears. Levels as low as 7-10 ppmvd (corrected to 3% O 2 ) can be visible, depending upon meteorological conditions. The conversion rate of SO 2 to SO 3 in the SCR varies primarily with SCR temperature and catalyst type. Although the SO 2 to SO 3 conversion rate from the furnace normally resulted in a visible SO 3 plume at Gavin, the additional SO 3 formed in the SCR resulted in a condition that was perceived to be problematic. The SO 3 plume separated from the main water vapor plume and several touchdowns were reported. The lack of buoyancy combined with the local topography at Gavin Plant was such that the secondary plume did not always disperse readily. Various SO 3 mitigation efforts have been tested. Some of these are documented by EPRI 1. These include fuel blending, Mg(OH) 2 slurry injection into the furnace, Ca(OH) 2 injected dry into the flue gas duct upstream of the ESP (with and without humidification), sodium bi-carbonate, and other sorbents. More recently some utilities have tested sodium bi-sulfate, OmniClear (a fuel additive) and other proprietary materials. All of these approaches have their limitations: reactivity limitations, capital costs, operating costs, degradation of existing air pollution control devices (i.e., ESPs) and fouling of equipment downstream of the injection point to name a few.
In light of these problems, American Electric Power endeavored to select a sorbent for SO 3 mitigation that was highly reactive, low cost, required a simply designed system (i.e., low capital investment), minimized the risk for downstream fouling and at the same time enhanced ESP performance. Trona is a sodium based sorbent that is relatively low in cost, is highly reactive, and requires minimal capital for injection into the duct. Although it was believed that the risk for fouling downstream equipment was low, it is now known that at higher temperatures (above ~340-350 F) fouling is a concern. Work to eliminate the fouling problem is underway. One option would be to change the injection location closer to the ESP. Another challenge, which has already been resolved, was material handling problems related to bridging and moisture in the aeration air. Despite these problems, the Trona injection system was successful in maintaining stack SO 3 levels to pre-scr levels while at the same time enhancing ESP performance. American Electric Power has a patent pending for this process 3. TRONA FORMATION AND USE Trona Formation, Processing, and Effective Size Solvay Chemicals, the Trona provider, describes the formation of Trona, its processing and effective size in their sales literature from which the following is gleaned. Trona s formation at Green River, Wyoming is the result of rapidly repeated evaporation cycles of Lake Gosiute approximately 50-60 million years ago. The result was a precipitated sodium carbonate-bicarbonate compound known as the mineral trona (chemical formula: Na 2 CO 3 NaHCO 2H 2 O). Numerous beds of trona have been formed containing billions of tons of trona and related minerals. Trona ore is crushed and screened before being sent through a fluid bed dryer. The dryer serves to remove free moisture from the product and to separate the coarse from fine product. Solvay mechanically refines and dries sodium sesquicarbonate (natural trona) into Solvay T 50 (250-300µms) and T- 200 (23µms) for use in acid gas and acid neutralization applications. Trona rapidly calcines to sodium carbonate when heated above 275 F. Solvay claims that particle decomposition increases surface area on the order or 5 to 20 times the original surface. Figure 1 is taken from Solvay sales literature and illustrates their experience with respect to particle size versus removal efficiency of SO 2. Figure 1. Effect of Sorbent Size @ NSR 1 Source: Solvay Chemicals 100 %SO2 Removal 80 60 40 20 0 11 14 32 65 93 microns
Gavin Plant SO 3 Mitigation Efforts During the 2003 ozone season Gavin Plant employed two temporary sorbent injection systems for mitigating SO 3. Magnesium Hydroxide slurry was injected into the upper furnace and dry hydrated lime injection upstream of the cold-side ESP. The systems were shared by both units and were successful in maintaining SO 3 levels at pre-scr emission levels. As with any new system, numerous operational problems were reported. However, degraded ESP performance due to hydrated lime injection was a key challenge. This limited the amount of hydrated lime injection to about 2 to 2.5 TPH per unit. The limitation in lime injection resulted in the need for a higher magnesium hydroxide injection rate to achieve a given stack SO 3 level. While most of the other problems could have been overcome with design changes, the high capital cost associated with the employment of two sorbent injection systems as well as the relatively high sorbent cost of magnesium hydroxide was an incentive to explore more cost effective options. An EPRI report 2 states that sodium bicarbonate injection upstream of the ESP was tested and did not cause ESP operating problems. However, the material had much lower SO 3 removal compared to other sorbents EPRI tested. The EPRI report explained this as being due to the relatively large particle size tested, i.e., 38µ. At least one bi-carbonate supplier contacted by American Electric Power stated that a typical particle size for sodium bicarbonate is 48µ. Therefore, it is not clear from the EPRI data whether the sodium was conditioning the precipitator to maintain ESP performance or if there was still sufficient SO 3 present in the gas stream to maintain low fly ash resistivity. Because of the high cost of the sorbent, EPRI did not recommend employing sodium bi-carbonate alone. Rather EPRI suggested mixing the bicarbonate with a less expensive sorbent such as hydrated lime. American Electric Power sought out sorbents for testing that contained elements such as potassium and sodium that were not expected to degrade ESP performance. KOH, KHCO 3, K 2 CO 3, NaOH, SBS, sodium bicarbonate/ nahcolite, trona and other chemicals were investigated. Some of these were judged to be unacceptable as sorbents. Others were expected to perform well, but were not tested due to safety concerns associated with handling the material. Others were excluded due to cost. Trona was selected as a candidate for testing based on its acid neutralizing abilities coupled with its sodium content that would be utilized for conditioning the precipitators. Trona was expected to be useful for maintaining low fly ash resistivity even as SO 3 was removed from the gas stream. Trona is the least expensive sodium-based sorbent available. This made it more attractive to test compared to sodium bicarbonate. The dry form was the preferred method of injection over slurry or solution. This was based on the relative ease of handling, simplicity, safety (e.g. lower conveying pressure), and lower probability of fouling downstream of the injection point. Another reason to favor Trona was the advantage over calcium-based sorbents. The optimum temperature range of sodium sorbent/gas reactions is in the temperature range of 257-894 F based on both Solvay s laboratory and commercial scale systems. Lime
usually works best in a slurry or when DSI is employed when it is injected into a gas stream that is at or near saturated conditions. Most of the trona suppliers that were contacted process trona into soda ash. Particle size is not critical for that application and thus it was difficult to find a source of trona with a small average particle size. One supplier (Solvay) was found that had experience using trona for acid gas (SO 2 ) mitigation and understood AEP s needs with respect to reaction efficiencies. The material supplied for tests had an average particle size of 23-28µ. This coupled with the decrepitation effect during calcination was judged to provide sufficient surface area for to be an effective sorbent. Surface area was judged to be acceptable based on the product s performance. Trona, like most alkali reagents, will tend to react more rapidly with the stronger acids in the gas stream first, and then after some residence time it will react with the weaker acids. Such gas constituents as HCl and SO 3 are strong acids and trona will react much more rapidly with these acids than it will with a weak acid such as SO 2. Trona is injected into the hot flue gas where it calcines to soda ash. A simplified equation of the calcining and neutralization process is shown below. The flue gas path and trona injection location are shown in Figure 2. The reaction of soda ash with SO 3 is believed to form sodium sulfate, Na 2 SO 4, according to equation 2 below. However, recently analyzed duct deposition suggests that sodium bisulfate may also be unintentionally forming. 1. 2 [Na 2 CO 3 NaHCO 3 2H 2 O] + heat 3 Na 2 CO 3 + CO 2 + 5 H 2 O 2. Na 2 CO 3 + SO 3 Na 2 SO 4 + CO 2
Figure 2: Gavin Plant Trona Injection Location and Flue Gas Path Trona Injection SCR Furnace ESP FGD Absorbers Air Heater Test Results of Trona Injection at Gavin Unit 2 Trona injection was tested for SO3 control at Gavin Unit 2 via an existing hydrated lime injection system. Two sets of tests were conducted: the first set lasted 11 days, the second 4 days. The use of Trona injection to obtain the simultaneous mitigation of SO3 and cold ESP conditioning is believed to be a unique application. A patent is pending for this technology2. The injection system consisted of a skirted bulk storage silo of bolted construction, a rotary valve feeder, de-aeration bin, air lock and conveying lines to three flue gas ducts. Each duct had four injection lances consisting of four nozzles each. Injection was perpendicular to the gas flow. A positive displacement blower provided the motive force to convey the material to the ducts. SO3 was measured at the AH outlet (i.e., ESP inlet upstream of the trona injection location) and the ESP outlet.
Testing was conducted first with the SCR s out of service (O/S). After these test proved to be successful, the #2 SCR reactor was placed in service (I/S). Finally all three reactors were placed I/S. The Ammonia on Demand (AOD) system was O/S since testing was conducted outside the ozone season. Hence, no ammonia was injected during the tests. In Figures 3 to 5, the reduction of SO 3 is depicted various ways. Figure 3 shows the percent SO 3 reduction as a function of dry sorbent injection (DSI) in tons per hour. Removal rates ranged from a low of 63% at about 1 ton per hour to a high of 86% at a rate of about 5.8 tons per hour DSI. Figure 4 presents the same data in the units of moles of trona injected per mole SO 3. Figure 5 depicts test data taken with the SCR O/S and compares trona data to hydrated lime. Both sorbents were injected with the same conveying equipment and nozzle arrangements at the same duct location. Referring to Figure 3, at a DSI rate of 2.9 TPH with the SCR O/S there is an indication that ESP conditioning may improve SO 3 removal efficiencies. The first data point was taken directly after trona injection began. There was no attempt to condition the ESP prior to this first test point. This resulted in a removal efficiency of about 63%. The removal was measured again at 2.9 TPH later in the test schedule. However, for the second data point at 2.9 TPH the ESP was well conditioned and a 78% removal was seen. Looking at these two data points in Figure 4 one can see that the unconditioned point is slightly above a 2.0 molar ratio (removing 63% SO 3 ) while the conditioned point is actually removing a higher percentage of SO 3 (78%) while being at a molar ratio slightly lower than 2.0. Refer now to Figure 5: a comparison of trona versus hydrated lime. The trona data was re-organized into No ESP Conditioning and ESP Conditioning. The comparison of trona to lime indicates that trona possesses a superior reactivity at the given duct conditions. Data from this figure also supports the position that there is a secondary scrubbing effect from the trona in the ESP. This is evident by the comparison of conditioned versus non-conditioned points. Data was collected immediately after injection of trona commenced for the data labeled No ESP Conditioning, while data labeled ESP Conditioned was taken after injecting trona for at least one or two days. It is suspected that both the SO 3 and trona are attracted to the ESP plates where SO 3 is neutralized. In addition, the relatively long residence time in the ESP allows for acid neutralizing reactions to be completed.
Figure 3: Gavin U-2: SO 3 Reduction With Trona Injection Upstream Of ESP % SO3 Reduction Measured at ESP Outlet. 100% 90% 80% 70% 60% 50% 40% 30% 20% 10% 0% # 2 SCR I/S Only 2.9 TPH, ESP Conditioned 2.9 TPH, No ESP Conditioning SCR O/S SCR I/S 0 1 2 3 4 5 6 7 DSI Rate (T/ hr) Figure 4: Gavin U-2, SO 3 Reduction with Dry Trona Injection Testing % SO3 Reduction Measured at ESP Outlet. 100% 90% 80% 70% 60% 50% 40% 30% 20% SCR O/S SCR I/S 10% 0% 0.0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0 Moles Sorbent : Moles SO 3
3 % SO Reduction Measured at ESP Outlet 100% 90% 80% 70% 60% 50% 40% 30% 20% 10% Figure 5: Gavin Unit 2: SO 3 Reduction Lime and Trona Data: SCR Out of Service 0% 0.0 1.0 2.0 3.0 4.0 5.0 6.0 7.0 8.0 9.0 Moles Sorbent : Moles SO3 Trona - No ESP Conditioning Trona ESP Conditioned Lime Figure 6 presents predicted removal levels of SO 3 as a function of trona injection rates. This illustrates the removal of SO 3 due to trona injection alone, and does not consider additional SO 3 removal due to AH baskets, or the FGD towers. This figure is based on both the preceding data as well as subsequent data. Figure 6: Expected SO 3 Removal with Trona Injection at ESP Inlet Trona Injection Rate %SO 3 Removal Lb/hr/kacfm Measured at Exit of Precipitator 0 15 0.5 63 1.0 71 1.5 76 2.0 78 Recall that hydrated lime injection rates were limited to 2 to 2.5 TPH due to ESP performance degradation. No such degradation was noted with trona injection, see Figure 7. Data suggests that opacity was unchanged or improved slightly with trona injection. Refer to Figure 8. It did not appear that ESP performance was negatively impacted by trona injection. VI curves were also generated during trona injection with
no indication of back corona. After a permanent system was installed, it was noticed that plant operators actually injected trona for the sole purpose of enhancing ESP performance. This was done when several T/R sets were O/S due to internal grounds. Hence, the trona system actually benefited ESP performance while SCRs were O/S. 35 Figure 7: Gavin U-2, 2003 ESP Total Current Density vs. Trona Injection Levels Sq. Ft Current Density, ma/ 1000 30 25 20 15 10 5 Lower Boxes Upper Boxes All Boxes 0 0 0.5 1 1.5 2 2.5 3 DSI, TPH Figure 8: Aeration of Trona at Room Temperature Water Vapor Absorption March/ April 2004 - By American Analytical Lab for American Electric Power %wt. of Sample that is Water 0.50% 0.45% 0.40% 0.35% 0.30% 0.25% 0.20% 0.15% 0.10% 0.05% 0.00% 3 Hours 12 Hours 48 Hours Baseline, Not Aerated 7 Days (168 hours) Mat'l Flow Degradation Noted Mat'l changes within 25 min. 0 10 20 30 40 50 60 70 80 90 100 Relative Humidity
Typically, when the trona injection is initially started up, there is a brief negative impact on ESP performance. Directly after trona start up, a 1-3% increase in opacity was seen. This is explained by the rapid drop in SO 3 concentrations while the sodium has yet to condition the precipitator plates. The opacity levels recover after about 15-20 minutes. The recovery rate may be longer depending upon the initial opacity upset and the overall condition of the ESP (e.g. number of fields O/S, etc.). FGD performance during trona injection was monitored. No discernable impact was noticed. Since the ESP s are collecting the trona as it is being injected, no chemistry upset was predicted nor were any observed. It was noticed that SO 3 levels at the air heater outlet were about 10 ppmdv lower when air heater outlet set points were reduced from 325 to 305 F. This is consistent with testing conducted at Gavin Plant in 2002. The lower SO 3 level will carry over to the stack and ultimately reduce the amount of sorbent required for mitigation. Precipitator performance may also improve somewhat with the lower flue gas temperature. The lower air heater operating temperature may not be achievable on hot summer days due to run out of the air heaters when the bypass dampers are fully closed. The green-field estimate for capital costs for a complete trona system that could serve two 1300 MW units burning high sulfur coal with SCR operation is approximately $ 7.0 MM. This includes all engineering, design, equipment, construction, commissioning, operator training, and overheads but does not include additional bulk storage capacity or rail unloading facilities. These costs were significantly lower than the Mg(OH) 2 slurry injection system estimates. O&M costs are proprietary but they are substantially lower than a duel Mg(OH) 2 + Ca(OH) 2 injection system. In fact, the O&M costs are lower than the Mg(OH) 2 system alone. Ammonia injection would be a cheaper option than trona injection, and would be especially desirable for plants already employing ammonia injection for ESP conditioning or employing an AOD system. However, impacts on the flyash pond (e.g. ph control) and ammonia off-gassing continue to be obstacles to injecting at rates needed with SO 3 levels typically seen with SCR operation. Unexpected Challenges Based on the success of initial testing, the decision was made to transform the temporary lime injection system into a permanent trona injection system. Trona was injected into both Gavin Plant units beginning in 2003. Trona was injected year-round regardless of SCR status because of the enhanced sensitivity of plume appearance. Material handling was identified as a challenge during the initial testing program. The small particle size and the cohesive nature of trona made bridging and rat holing the most obvious problems. Design changes were made to the permanent system to address these and after the permanent system was installed material handling issues seemed to be resolved. However, after a few weeks of operation bridging and clumping was detected inside the storage silo. These problems threatened to interrupt the trona supply and put SO 3 mitigation at risk. This in turn threatened the operation of the plant since Gavin
Plant has agreed to maintain SO 3 emission concentrations to pre-scr operation levels. Without SO 3 mitigation, unit load would have to be curtailed. Initial testing of product from the silo indicated high moisture content. Material specifications required a maximum free moisture content of 0.01%, while lab analysis showed moisture levels as high as 10% or more by weight. After an intense investigation, aeration air was found to be adding moisture to the resident trona in the silo. Figure 8 depicts results of a laboratory test program whereby a column of trona was aerated at room temperature with compressed air at various humidity levels. It was concluded that although trona is not hygroscopic on a molecular level (i.e., the trona is not chemically bonding with the water vapor), the very dry material does nonetheless absorb moisture (water vapor) from the air. The intimate contact of the material with aeration air accelerates the moisture absorption. Testing indicates that at high humidity levels, time plays a factor in the rate at which the moisture is absorbed. Testing also showed that at low enough humidity levels exposure time is not critical. However, the laboratory noted that with as little moisture as 0.05%wt. material flow characteristics were altered. This problem was resolved by adding air driers to the aeration air. No material flow problems were encountered after this modification. In the spring of 2004, just before entering the ozone season, duct deposition was found during a unit outage. The deposition was severe and totally unexpected. It was discovered that deposition varied across the duct. Turning vanes were becoming plugged with the debris. The duct temperature is stratified downstream of the AH s. The hot side of the duct experienced much more deposition than the cold side of the duct. At some locations, the cold side of the duct was clear. The temperature gradient across the duct varies with outside temperature, load, and other factors. But a typical temperature range at full load is approximately 300 F at the cold side of the duct, with a maximum temperature of just under 400 F at the hottest point of the duct. Deposits are mostly flyash with very low ph (~2.0 to 2.9). Testing is currently underway to determine the cause of the deposition and a resolution to the problem. One possible resolution would be to inject the trona closer to the ESP inlet thereby avoiding several turning vanes. Augmenting the ESP inlet screen with rapper mechanism would keep the inlet screens clean. Other actions being considered are coating the turning vanes to avoid the deposition, mechanically rapping the turning vanes, and reducing flue gas temperature by judicial injection of tempering air on the hot side of the duct. Currently the deposition problem is being monitored by trending differential pressures across the turning vanes. The overall differential pressure is also monitored. Manual cleaning of the turning vanes and ESP inlet screen is conducted via duct ports when high differential pressures are observed. A 1986 report 4 identifies a fouling problem in a Kraft boiler that was caused by the formation of sodium bisulfate. The same report provides a phase diagram for the sulfates of sodium. The phase diagram suggests that above 374 º F and above 10 ppmdv SO 3 liquid sodium bisulfate should form. This is the suspected cause of the deposits.
Conclusions Trona injection does an excellent job of neutralizing SO 3 while at the same time enhancing ESP performance. Testing successfully demonstrated efficient SO 3 removal with simultaneous ESP enhancement. The latter effect was so apparent, that trona was sometimes injected for ESP conditioning even when little or no SO 3 removal was necessary. A permanent system is now installed that serves both units at Gavin Plant. There are some characteristics of trona that are peculiar. Someone familiar with the unique characteristics of trona should design the material handling system. While trona is not chemically hygroscopic, it does behave as if it were hygroscopic when dried to 0.01% free moisture. There is much knowledge already gained about the current deposition problem. It is a phenomenon that is temperature related. It is believed that deposition formation begins at duct temperatures above about 350 to 375 F. Below these temperatures, deposition is minimal to nil. Laboratory testing to better understand the chemical process that causes the deposition is underway. Once the process is understood, it is hoped that means may be developed to avoid the depositions altogether. If the deposition is unavoidable, then changing the injection location closer to the ESP inlet and augmenting the ESP inlet distribution perforated plate with rapping mechanisms could minimize its impact. An alternate approach is to coat the turning vanes to avoid deposition. References 1. SO 3 Mitigation Guide; Rhudy, R. G. Radian Corp.; EPRI TR-104424s October 1994 2. Ibid, p. 3-13 3. Ritzenthaler, D. P. U.S. Patent Application Number 60/552908 4. Nelson, W.; A Study of the Fouling Mechanism on Kraft Chemical Recovery Boiler Economizer and Convection Steam Generating Tubes, 1986 Pulping Conference Key Words SO 3, Plume, ESP, Resistivity, Pollution
AEP Successful SO 3 Mitigation While Enhancing ESP Operation at AEP s Gavin Plant by Dry Injection of Trona into the ESP Douglas P. Ritzenthaler, American Electric Power Presented at Power-Gen International December 9-11, 2004 1
Figure A: Gavin Plant Flue Gas Path AEP SCR Furnace ESP FGD Absorbers Air Heater 2
Figure B: 2002 System Overview: Injection Locations AEP Mg(OH) 2 Slurry Secondary SCR Reaction: 2SO 2 + O 2 2SO 3 SCR Furnace H 2 O Air Heater ESP FGD S T A C K Dry Ca(OH) 2 3
Figure C: Trona Mine, Green River, WY AEP 4
Impact of Size on Performance AEP Figure 1. Effect of Sorbent Size @ NSR 1 Source: Solvay Chemicals %SO2 Removal 100 80 60 40 20 0 11 14 32 65 93 microns 5
Acid Neutralization AEP 2 [Na 2 CO 3 NaHCO 3 2H 2 O] + heat 3 Na 2 CO 3 + CO 2 + 5 H 2 O Na 2 CO 3 + SO 3 Na 2 SO 4 + CO 2 6
AEP Test Data Figure 3: Gavin U-2: SO 3 Reduction With Trona Injection Upstream Of ESP % SO3 Reduction Measured at ESP Outlet. 100% 90% 80% 70% 60% 50% 40% 30% 20% 10% 0% # 2 SCR I/S Only 2.9 TPH, ESP Conditioned 2.9 TPH, No ESP Conditioning SCR O/S SCR I/S 0 1 2 3 4 5 6 7 DSI Rate (T/ hr) 7
AEP Test Data, continued Figure 4: Gavin U-2, SO 3 Reduction with Dry Trona Injection Testing % SO3 Reduction Measured at ESP Outlet. 100% 90% 80% 70% 60% 50% 40% 30% 20% SCR O/S SCR I/S 10% 0% 0.0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0 Moles Sorbent : Moles SO 3 8
AEP Test Data, continued % SO3 Reduction Measured at ESP Outlet Figure 5: Gavin Unit 2: SO 3 Reduction Lime and Trona Data: SCR Out of Service 100% 90% 80% 70% 60% 50% 40% 30% 20% 10% 0% Trona - No ESP Conditioning Trona ESP Conditioned Lime 0.0 1.0 2.0 3.0 4.0 5.0 6.0 7.0 8.0 9.0 Moles Sorbent : Moles SO3 9
Typical Performance AEP Figure 6: Expected SO 3 Removal with Trona Injection at ESP Inlet Trona Injection Rate Lb/hr/kacfm %SO 3 Removal Measured at Exit of Precipitator 0 15 0.5 63 1.0 71 1.5 76 2.0 78 10
AEP ESP Performance Data 35 Figure 7: Gavin U-2, 2003 ESP Total Current Density vs. Trona Injection Levels Current Density, ma/ 1000 Sq. Ft 30 25 20 15 10 5 Lower Boxes Upper Boxes All Boxes 0 0 0.5 1 1.5 2 2.5 3 DSI, TPH 11
Hygroscopicity AEP Figure 8: Aeration of Trona at Room Temperature Water Vapor Absorption March/ April 2004 - By American Analytical Lab for American Electric Power 0.50% 0.45% 3 Hours %wt. of Sample that is Water 0.40% 0.35% 0.30% 0.25% 0.20% 0.15% 0.10% 0.05% 12 Hours 48 Hours Baseline, Not Aerated 7 Days (168 hours) Mat'l Flow Degradation Noted Mat'l changes within 25 min. 0.00% 0 10 20 30 40 50 60 70 80 90 100 Relative Humidity 12