SO3 Mitigation Strategy Process

Jeffrey P. White

American Electric Power, 1 Riverside Plaza, Columbus, OH 43215

E-mail: jpwhite@aep.com; Telephone: (614) 716-1248; Fax: (614) 716-1292

Summary

American Electric Power has developed and implemented a structured, analytical process to determine the most appropriate 

strategy to proactively mitigate SO3 emissions. This process is focused on units to be retrofitted with SCR and FGD 

technologies. This staged approach begins by examining multiple technology options with analytical assumptions based 

largely on test data. Reduction in creation of SO3 through optimizing SCR catalyst management is also considered and 

applicable technologies are screened using worst scenario assumptions. The life-cycle economics of screened technologies 

are evaluated using baseline assumptions. The result is a unit-specific, least-cost mitigation recommendation to achieve the 

desired strategy objective.

Currently, electric generating facilities are not subject to specific regulatory SO3 emission limits. However, SO3 emissions 

can impact flue gas plume appearance, increasing attention to plant operations by regulatory agencies and the public. Plume 

aesthetics are strongly influenced by SO3 concentrations, but ambient conditions, including temperature, relative humidity, 

sun position, cloud cover, and the relative position of an observer, can also subjectively impact appearance. Maintaining 

reduced SO3 concentrations is a key driver for minimizing plume visibility and associated risks. 

To evaluate the theoretical need for SO3 mitigation a spreadsheet mo del was developed to calculate the concentration of SO3

at discrete points of the flue gas stream from the furnace to the stack. For each generating unit, specific data such as design 

basis gas flow and SO2 fuel content were incorporated along with assumptions for creation and removal of SO3 along the flue 

gas path. Reduction of SO3 attributable to commercially-available mitigation technologies was optimized to yield a stack 

concentration of SO3. The following technologies were considered: wet electrostatic precipitator (WESP); low-conversion 

SCR catalyst; magnesium hydroxide injection in the boiler; ammonia, hydrated lime, or trona injection in the flue gas duct 

between the air heater and ESP; and combinations of magnesium hydroxide with ammonia, hydrated lime, or trona.

Baseline operating assumptions derived frombest engineering judgment, flue gas sampling, and operating experience were 

established for boiler SO2 to SO3 conversion rate, air heater H2SO4 capture, SCR SO2 to SO3 conversion rate, and scrubber 

H2SO4 removal. These assumptions, representing “average” unit operations, were used to perform economic evaluations.

Deviations from the baseline assumptions were proposed to evaluate a scenario enveloping the least favorable operating 

condition to screen viable mitigation technologies, consequently minimizing the volume of economic life-cycle analysis for 

each unit.

The base case catalyst management plan at each unit was defined as the replacement schedule associated with the original 

catalyst installation to maintain design basis NOX performance. Variations of this plan intended to expedite reduction of the 

SO2 to SO3 conversion rate through accelerated replacement of catalyst (and associated financial impacts from unscheduled 

outages and NOX performance) with low-conversion type were also developed. These alternative management plans were 

used to evaluate whether the reduced O&M costs associated with lower sorbent usage for SO3 mitigation would create 

superior net present value compared to the original catalyst replacement schedule.

Combinations of technologies/catalyst management plans for which the stack SO3 concentration theoretically achieved the 

upper limit of the SO3 target operating range were then subjected to economic analysis. Estimates of technology and catalyst 

replacement capital costs and O&M expenditures, primarily for mitigation consumables, were established and viable 

technologies for each unit were compared. Qualitative factors such as technical performance, secondary impacts, and risks

were also considered. In general, for the technologies evaluated, economic analysis revealed that additional capital to 

accelerate catalyst replacement was not sufficiently offset by reduced O&M costs to justify early replacement. Lowering the 

SO2 to SO3 conversion rate across the SCR catalyst through accelerated replacement provided an opportunity to specify 

multiple sorbent injection technologies – such as magnesium hydroxide with hydrated lime or trona – providing mitigation 

flexibility as a physical hedge to future volatility in sorbent pricing and supply.

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2006 Environmental Controls Conference

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In addition to evaluating the most appropriate mitigation strategy for each unit based on life-cycle economics, the following

technical/economic factors were also considered: utilization of existing ammonia injection systems at SCR-equipped units;

impact to fly ash sales and disposal (pond chemistry or groundwater impacts); mercury oxidation potential across lowconversion SCR catalyst; injection limits for sorbents considering ESP size and anticipated performance impacts; and flue 

gas temperature regulation in ducts for corrosion control and/or sorbent deposition.

The analytical process implemented by American Electric Power to determine the most appropriate SO3 mitigation strategy at 

its operating units retrofitted with FGD and SCR pollution control technologies provides a consistent, robust approach with 

meeting the target operating range. The flexibility of having multiple mitigation technologies available ensured that a leastcost life-cycle solution was provided at each unit.

Proceedings of the

2006 Environmental Controls Conference

59

U.S. Department of Energy

60

National Energy Technology Laboratory