The visible consequences of sulfuric acid aerosol emissions—opaque stack emissions called "blue plumes"—are merely the tip of an iceberg. In sufficient concentration, SO3 also can increase corrosion and fouling of equipment and components downstream of the furnace while decreasing their efficiency and penalizing overall plant heat rate.
Emissions of SO3 (or its hydrated form, H2SO4) have received increasing attention due to the proliferation of selective catalytic reduction (SCR) and wet flue gas desulfurization (FGD) systems. Although much of this attention has focused on plume opacity and buoyancy, SO3 also has significant negative impacts on plant performance, operations, and maintenance. Among them are:
- Reduction of unit heat rate and increased corrosion of downstream equipment due to the raising of dew point by SO3.
- Fouling of air heaters and SCR catalysts due to the reaction of SO3 with ammonia.
- Competition of SO3 with mercury for adsorption sites on carbon particles, reducing the effectiveness of mercury emissions control.
The point at which SO3 is removed from flue gas, and to what extent, largely determine both the level of its negative impacts on plant O&M and the potential benefits achievable by its removal. Table 1 lists those benefits under four different removal scenarios. Though plume opacity and buoyancy are addressed by three of the four scenarios, the most benefits accrue to a coal-fired unit only if SO3 is reduced to a very low level (<3 ppm) upstream of the air heater (the scenario in the left column).
If SO3 is removed downstream of the air heater but before the stack (the scenarios in the other three columns), the benefits are fewer and smaller:
- If efficient removal (to 5 ppm at the stack) is achieved between the air heater and the electrostatic precipitator (ESP), plume issues are resolved and reasonable corrosion protection is provided for equipment downstream of the injection point.
- Moderate removal of SO3 between the air heater and the ESP (to a level between 10 and 20 ppm, similar to that present during "pre-SCR" operations) reduces the risk of plume touchdown. But the plume will still be discolored, and equipment downstream of the injection point will enjoy only limited corrosion protection.
- For units configured with a wet ESP downstream of a wet FGD system, plume issues are resolved, but none of the other benefits listed will be realized.
Note that the table lists several benefits of SO3 reduction on mercury removal. SO3 and mercury compete for adsorption sites on native flyash. If SO3 is not removed prior to cooling of the gases in the air heater, the sites will be occupied by condensing SO3 (sulfuric acid), thus inhibiting the adsorption of mercury.
Part 2 of this series explained that reducing SO3 to very low levels (below 3 ppm) can enhance mercury retention by native flyash by as much as an order of magnitude. A number of researchers have reported a similar negative impact of SO3 on the ability of activated carbon to capture mercury. Accordingly, removing SO3 prior to the air heater will not only increase the capture of mercury on flyash but by injected carbon as well.
Finally, if a plant's mercury control strategy includes the use of a high-oxidation catalyst in its SCR system for enhanced oxidation of mercury (and its subsequent removal in a wet FGD system), removal of the additional SO3 generated across the catalyst will be essential to avoid the negative operational impacts previously discussed.
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