# SO 3 

# 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 strateg y to proactively mitigate SO 3 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. Reductio n in creation of SO 3 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 re sult is a unit

- specific, least

- cost mitigation recommendation to achieve the desired strategy objective.

Currently, electric generating facilities are not subject to specific regulatory SO 3 emission limits. However, SO 3 emissions can impact flue gas plume appearance , increasing attention to plant operations by regulatory agencies and the public. Plume aesthetics are strongly influenced by SO 3 concentrations, but ambient conditions, including temperature, relative humidity, sun position, cloud cover, and th e relative position of an observer, can also s ubjectively impact appearance. Maintaining reduced SO 3 concentrations is a key driver for minimizing plume visibility and associated risks.

To evaluate the theoretical need for SO 3 mitigation a spreadsheet mo del was developed to calculate the concentration of SO 3 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 SO 2 fuel content were incorporated along with assumpt ions for creation and removal of SO 3 along the flue gas path. Reduction of SO 3 attributable to c ommercially

- available mitigation technologies was optimized to yield a stack concentration of SO 3 . 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 am monia, hydrated lime, or trona.

Baseline operating assumptions derived from best engineering judgment, flue gas sampling, and operating experience were established for boiler SO 2 to SO 3 conversion rate, air heater H 2 SO 4 capture, SCR SO 2 to SO 3 conversion rate, and scrubber H 2 SO 4 removal. These assumptions
, represent ing “average” unit operation s , 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 t he original catalyst installation to maintain design basis NO X performance

. Variations of this plan intended to expedite reduction of the SO 2 to SO 3 conversion rate through accelerated replacement of catalyst (and associated financial impacts from unschedu led outages and NO X 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 SO 3 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 SO 3 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 fa ctors 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. L owering the SO 2 to SO 3 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

.In addition to evaluating the most appropriate mitigation strategy for each unit based on life

- cycle economics, the following

t echnica l/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 low

conversion SCR catalyst ; injection limit s 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 Amer ican Electric Power to determi ne the most appropriate SO 3 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 least

cost life

- cycle solution was provided at each unit.