Wet FGD spray nozzles distribute limestone or lime slurry throughout the absorber vessel in a counter-current contact pattern with the rising flue gas. SO₂ dissolves into the slurry droplets and reacts with calcium carbonate to form calcium sulfite, which is then oxidized to gypsum. Achieving 95–99% SO₂ removal requires three spray parameters working together: droplet size 300–600 µm for the correct surface area-to-settling balance, liquid-to-gas ratio of 50–150 gallons per 1,000 ACFM, and uniform coverage across the full absorber cross-section to prevent gas channeling where SO₂ bypasses treatment.

The abrasion challenge is what makes FGD nozzle selection the most material-critical application in the power plant. Limestone slurry at 15–25 wt% solids, pH 4–6, with calcium carbonate and silica particles, wears standard stainless steel orifices measurably within 3–12 months of continuous operation. As orifices enlarge, flow rate increases above design, droplet size increases reducing SO₂ absorption surface area, and spray angle changes degrading coverage uniformity. The cumulative effect is declining removal efficiency — from 97% when new toward the EPA exceedance threshold.

Cooling tower distribution nozzles connect directly to turbine output through a thermodynamic chain: distribution uniformity → approach temperature → condenser backpressure → LP turbine exhaust pressure → available enthalpy drop → megawatt output. Each 1°F improvement in cooling tower approach temperature reduces condenser backpressure by 0.10–0.15 inches HgA, enabling approximately 0.2–0.3% additional turbine output per 0.1 inch HgA. For a 500 MW unit, 2°F approach improvement from distribution nozzle optimization translates to 2–3 MW of additional generation.

The performance impact of plugged cooling tower nozzles is disproportionate to the number of plugged positions. When one nozzle plugs, cooling airflow preferentially redistributes toward the dry fill zone — the lower air-side resistance of the dry section draws more airflow through it, reducing air-water contact in the wetted zones by 2–5× more than the proportional flow reduction from the single plugged nozzle. The approach temperature impact of one plugged nozzle in 100 is much larger than 1% of total degradation.

SCR injection systems with non-uniform ammonia distribution across the flue gas duct produce two compliance failures simultaneously from the same grid: zones with NH₃:NOx ratio above 1.05 produce ammonia slip — unreacted NH₃ that forms ammonium bisulfate deposits on downstream air heater baskets, progressively increasing pressure drop and forcing 2–5 day water washing outages; zones with NH₃:NOx ratio below 0.95 produce inadequate NOx reduction at those locations, producing permit exceedances even when the duct-averaged NOx appears compliant.

Achieving ±5% NH₃ concentration uniformity across the full duct cross-section requires injection grid design based on the actual flue gas velocity profile in the specific duct geometry — not a generic grid layout. Velocity profiles in ducts downstream of bends, dampers, and flow obstructions are non-uniform and cannot be assumed from duct dimensions alone. CFD modeling or physical duct traverse measurements are required before injection grid design to identify the velocity distribution that the nozzle spacing must compensate for.

Ash and slag deposits on boiler heat transfer surfaces — superheater, reheater, economizer, and air heater — progressively reduce heat transfer coefficients, forcing increased fuel firing to maintain target steam temperatures and eventually causing tube overheating failures. Soot blowing with high-velocity steam or compressed air lances removes these deposits before they reach the thickness where heat transfer degradation causes fuel efficiency penalties or tube failures.

The failure modes from incorrect soot blowing are opposite: too infrequent allows cumulative deposit buildup causing heat rate degradation and tube damage; too frequent causes tube wall erosion from high-velocity steam impingement. Both under-blowing and over-blowing produce forced outages — the mechanism differs but the consequence is the same. Optimal blowing frequency and sequence is determined by monitoring furnace exit gas temperature rise and steam temperature deviation as real-time fouling indicators.

Bottom ash quench is the most consequential spray application in coal plant ash handling — inadequate quench of 1,800–2,200°F incandescent ash causes clinker formation that blocks hopper discharge and requires 3–14 day forced outages for manual removal. Quench nozzle capacity must be sized for the peak instantaneous ash discharge rate — not the hourly average — with a minimum 1.5× safety factor. Peak instantaneous rates during high-load operation can be 2–4× the hourly average, exactly the condition when underpowered quench systems fail.

Condenser tube fouling from biological growth, silt, scale, and corrosion products progressively reduces heat transfer and increases condenser backpressure — the same backpressure-to-turbine-output relationship that governs cooling tower performance. High-pressure rotating nozzles at 3,000–10,000 PSI clean condenser tube bundles, removing fouling deposits that restore heat transfer to design values. The business case is direct: severe fouling forces 2–5 day offline cleaning outages; online ball cleaning systems provide continuous fouling control eliminating most offline cleaning requirements.

Gas turbine inlet fogging provides power augmentation — injecting 5–20 µm water droplets into the inlet air stream reduces compressor inlet temperature, increasing air density and mass flow, boosting output 5–15% for combined-cycle and 10–25% for simple-cycle peaking turbines during high-demand periods. Droplet size is the critical safety parameter: droplets above the evaporation size limit for the specific turbine geometry and ambient conditions cause compressor blade erosion from high-velocity droplet impingement.