Previous MACT Sub Categories

1. Previous MACT Sub Categories • EPA has recognized differences in other industry rules by using sub-categorization: • Differences in processes • Differences in emissions characteristics • Differences in control technology applicability and/or effectiveness • To determine whether utilities should be sub-categorized, there needs to be an analysis of the distinctions between different size/type/class of units.

2. Class, Type and Size Relative To Utility Units • ICR data includes 1,086 coal fired generating units • Units range from 25 MW to 1,400 MW with each unit designed for site specific needs and conditions • Wide variety in equipment, process techniques, and raw materials (fuel and other) • EPA made 36 bins for Part III of the ICR • Reading EPA’s notice, appears that EPA means to sub categorize oil and coal, consistent with other rules (e.g., boiler MACT) • Will not discuss coal gasification because manufacturing of fuel gas should not be covered by this rule

3. Are There Potential Utility Subcategories? • Different types and classes of generating units result in a wide variation in Hg emissions and speciation. • There are many factors that influence the magnitude and speciation of Hg emissions. Many are interrelated. • Must look for relevant differences in processes, emissions characteristics, or control technology applicability and/or effectiveness.

4. Are There Potential Utility Subcategories? • Looked at large number of potential factors grouped in four areas. • Different types/methods of fuel combustion • Coal considerations • Overall operating characteristics • Process design configurations & equipment applicability • Not realistic to have a sub category for each factor • Attempted to group related factors together to define a smaller number of potential sub categories.

5. Combustion Processes: Conventional Boiler Types • Conventional Coal Boilers • Pulverized Coal (Wall fired, T-Fired, etc.) • Cyclone Fired • Stoker Fired • Units differ greatly in coal prep and firing technique • With all other variables equal, there are no significant differences in emissions or speciation between these types. • Sub categorization on this basis not appropriate.

6. Combustion Processes:Fluid Bed Combustors (FBC) • Combusts fuel in a fluidized bed of solids at ~1,500 F vs. 2,500 F for conventional boilers • Coal prep equipment, fans, ash collection, and steam water/steam tubing are very different than conventional boilers • Sulfur in fuel converted to a solid in the furnace • FBCs have wider fuel flexibility than other boilers • Radically different combustion process • A FBC sub category for all fuel types is appropriate

7. Coal Considerations: Rank • ASTM ranks coals by different properties • Western Bituminous (AZ, CO, NV, NM, UT and WY) • Eastern Bituminous • Sub-Bituminous • Texas Lignite • North Dakota Lignite • Boilers are constructed to burn specific coals • Different coals have different volatilities • Lower rank coals require a larger size boiler • Coal prep equipment, furnace configuration, and plant aux. equipment designed for specific fuels

8. Fuel Considerations: Coal Rank • Flue gas Hg from bituminous coals tends to oxidize more than sub-bituminous or lignite • Eastern bituminous coal tends to have higher levels of chlorine, sulfur and Hg than western bituminous, and different ash characteristics. These differences result in different speciation. • Lignite units are mostly mine mouth, limiting fuel flexibility. • North Dakota and Texas lignite have different Hg concentrations, and due to ash characteristics, different speciation.

9. Fuel Considerations: Coal Rank • Differences in coal properties affect control technology performance and applicability (different ranks with the same controls have different performance) • Appropriate to sub categorize by coal rank • Western Bituminous • Eastern Bituminous • Sub-Bituminous • North Dakota Lignite • Texas Lignite

10. Fuel Considerations: Chlorine Content • EPRI’s work shows that coal chlorine (Cl) is a critical factor that dictates speciation and mercury removal. • Much of the difference is captured by coal rank. Lignite and sub bit. have less Cl than bituminous, and western is lower than eastern bituminous. • Sub categorizing by chlorine has merit even within eastern bituminous, but would be complicated to administer both for industry and regulators.

11. Fuel Considerations: Other Chemical Properties • Ash with high alkali content tends to inhibit the oxidation effect of chlorine • Iron content tends to increase oxidation • Sulfur content, ash type and amount of ash affect the choice of downstream processes for SO2 and particulate removal • These are important factors, but would be largely captured by fuel rank and other process types

12. Operating Considerations • Unit size (MWs, steam flow, fuel flow, etc.) • Unit load, capacity factor, dispatching (i.e. baseload, load following, peaking) • Online cleaning of air heaters, boiler, etc. • Longer residence time which allows more oxidation • Unburnt carbon (LOI) shown to remove mercury • These are important factors and may be a basis for sub categories.

13. Operating Considerations:Temperature • Temperatures can effect speciation and removal efficiency. • Mercury removal is more effective at lower temperatures • Process configuration affects temperature • Hot stack (above acid dew point) • Near saturated stack (above saturation temp) • Wet stack ( saturated with water vapor)

14. Operating Considerations:Temperature • Acid dew point – temperature must be kept high enough to prevent SO3/H2SO4 from condensing and corroding all components downstream of the air heater (e.g. cold ESP, FF) • Saturation temperature - must keep temperature high enough to prevent water from condensing and solids plugging downstream (e.g. spray dryer) • Wet stack – designed for wet and corrosive conditions (e.g. wet FGD)

15. Process Design Considerations:NOx Controls • SNCR not conclusively shown to affect Hg speciation or capture • Low NOx Burners do not directly affect speciation, but increased unburnt carbon may increase mercury removal downstream • SCR in some instances promotes oxidation of mercury making it more readily captured downstream

16. Process Design Considerations:Particulate Controls • Overall units have displayed good control of particulate mercury • Hot ESPs operate at temperatures not favorable to Hg capture. • Particulate controls are selected based on fuel, ash loading and ash characteristics

17. Process Design Considerations:Wet FGD for SO2 Control • Wet FGD efficient at removing oxidized Hg • Wet FGD can convert oxidized Hg to elemental • Potential co-benefits from SCR • Hg removal efficiency different for different coal ranks • Results in a water saturated flue gas • Placed after particulate controls

18. Process Design Considerations:Dry FGD for SO2 Control • Dry scrubbers (spray dryers) used on lower sulfur coal as shown by ICR data. Most are on western units • Not capable of high SO2 removal on higher sulfur fuels • Located prior to particulate control devices • Dry scrubbers limited by approach temperature (saturation temperature) to prevent wet solid deposition. • Some spray dryers perform better than others for Hg removal, depending on coal rank & variations in rank

19. Process Configuration

20. Recommended Modeling Sub- Categories: Scenario #1 Six total Sub Categories • Fluidized Bed Combustors (all coal ranks) • Conventional boilers using • Eastern Bituminous • Western Bituminous • Sub-Bituminous • North Dakota Lignite • Texas Lignite

21. Recommended Modeling Sub- Categories: Scenario #2 Sixteen total sub categories • Fluidized Bed Combustors (all coal ranks) • Previous 5 fuel subcategories each sub divided by process outlet temperature • Hot (above acid dew point) • Near saturated (above saturation temp) • Wet (saturated with water vapor) • Some sub categories may be a “null set”