NOx Emission Control

NOx and SO2 Emissions Control Technologies and Regulatory Options Professor Yehia Khalil Chemical & Environmental Engineering Department

Invited Lecture at Yale School of Forestry and Environmental Studies January 19, 2001

Lecture Outline 1. NOx emission control • At-the-source control technologies • Down-the-pipe control technologies 2. SO2 emission control • Options: scrub, switch, trade allowances or retire plant • Other options • Down-the-pipe technologies: wet FGD, semi-dry FGD (SDA) and dry (DSI) FGD 3. Summary Professor Yehia Khalil

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Stack

Down-the-Pipe NOx and SO2 Control Technologies

Boiler followed by three air pollution control technologies: SCR, FF and FGD units. Professor Yehia Khalil

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NOX Control Technologies 1) At-the-Source Control Technologies • Air staging • Fuel staging • Flue gas recirculation (FGR) • Low NOX burners (LNB) • Combinations of the above technologies 2) Down-the-Pipe Control Technologies • Selective catalytic reduction (SCR) • Selective non-catalytic reduction (SNCR) Professor Yehia Khalil

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NOx Formation in Boilers Two oxidation mechanisms: 1) Thermal NOx - Oxidation of N2 in air (79 vol%) with excess O2 2) Fuel NOx - Reaction of N2 that is ‘chemically bound’ in the fossil fuel (coal or oil)

Quantity of NOX formed depends on the “three T’s” of combustion: Temperature, Time (residence time), and Turbulence (mixing of fuel and air) Example: less mixing of fuel and air, reduces the flame temperature and hence reduces NOx formation Professor Yehia Khalil

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Air-Lean (Fuel Rich) vs. Fuel Lean (Air-Rich) Combustion Fuel + Air  Combustion Gases (CO, CO2, O2, NOx, SO2, H2O, UBHC, etc) + PM

Two Competing Conditions: Air Rich vs. Fuel Rich Optimize the fuel/air ratio for best burner performance Air rich (fuel lean)  more excess O2 in combustion gases, more NOx, less unburned hydrocarbons (UBHC), and less CO  Higher flame temperature and, hence, more thermal NOx

Air lean (fuel rich)  less excess O2 in combustion gases, less NOx, more unburned hydrocarbons (UBHC), and more CO  Lower flame temperature and, hence, less thermal NOx

Professor Yehia Khalil

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At-the-Source NOx Control Strategies: Furnace Modification • Air staging Staged Combustion: fuel-rich & air-rich zones aka, Off-Stoichiometric Combustion (OSC) • Fuel staging • Flue-gas recirculation (FGR) • Boiler hardware modifications: use Low-NOx Burners (LNB) Two Key objectives: 1) Reduce combustion flame temperature to reduce thermal NOX 2) Minimize use of excess air and, hence, excess N2 from air Professor Yehia Khalil

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At-the-Source NOx Control Technologies Control Technology

NOX Reduction (%)

Cost $/kW

Combustion modifications (air staging, fuel staging, FGR, fuel/air biasing, etc)

10 – 40

1-5

Low NOX burners (LNB)

35 – 50 (Wall) 30 – 40 (T)

10 – 25 (Wall) 10 – 15 (T)

Hybrid: LNB + OFA

45 – 65 (Wall) 35 – 55 (T)

10 - 40

OFA = Overfire Air Wall = Wall-fired Boilers T = Tangentially fired Boilers NSPS = New Source Performance Standards – national emission standards Wall-Fired Wet bottom means that the ash is removed from the furnace in a molten state.


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2NOX  N2 + xO2

Combustion Gases

Overfire Air (OFA) Combustion Modification

Windbox

Fuel

Bottom Ash Professor Yehia Khalil

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Combination of LNB + Overfire Air (OFA)

OFA Port

Air

Wall-Fired Boiler Professor Yehia Khalil

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Overfire Air (OFA) Furnace Side Wall OFA

LNB

Notice the vertical tubes on the walls where water is converted to steam

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Wind Box

Wind Box Professor Yehia Khalil

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Biased Firing, Burners-out-of-Service (EPRI Design Based on Empirical Studies)


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Air-Staging Scheme Flue Gas Boiler

Secondary air

Air-rich zone (fuel-lean)

Primary air

Fuel-rich (air-lean) zone

• Divide combustion air into primary and secondary ports. • Introduce a small part of the air with the fuel (i.e., fuel-rich zone). Subsequently introduce the remaining air (i.e., air-rich zone) • Air staging reduces O2 levels (fuel-rich zones) where thermal NOx is likely to form • Air staging increases the likelihood of formation of N2 rather than NOx from the fuel chemicallybound N atoms. Professor Yehia Khalil

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Fuel Staging (Reburning) Scheme • Fuel is initially burned with excess air (air/fuel ~1.15, i.e., 15% excess air). • More fuel is subsequently injected above the primary combustion zone, creating a fuel-rich zone. – The fuel-rich reburning zone creates hydrocarbon radicals (HCN) which reduce NOx formation: NO + HC  HCN + O – HCN, under fuel-rich conditions tends to form N2 instead of NOx • Further air is added to burn out added fuel in an air-rich zone. • Fuel staging scheme works best for natural gas (NG), but the scheme is also possible with other fuels Flue Gas Boiler Burn-out air (air rich) Reburning fuel (fuel rich)

NOx Reduction of ~50% is possible

Fuel and air (air reach)


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Flue-Gas Recirculation (FGR) • Part of the flue gas is mixed with the combustion air. This can be done internally within the boiler or externally:

Flue Gas

External FGR

Flue Gas

Boiler

Combustion Air

Internal FGR

Flue Gas

Boiler

Combustion Air

• Mixing combustion products with combustion air dilutes the O2 and reduces combustion flame temperature. • Additionally, some of the NOx formed is recycled where it undergoes decomposition reaction (i.e., NOX decomposes to N2 and O2). Professor Yehia Khalil

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Low NOx Burner (LNB) Schematic

• LNB is designed to accomplish the staging techniques (air-staging and fuel-stages). • Important LNB design features: – Placement of the air and fuel jets/ports – Degree of swirl (i.e., mixing) imparted to air and fuel

Professor Yehia Khalil Smart, J.P. & Weber, R., J. Inst. Energy, 237-245, 1989.

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Down-the-Pipe (Post Combustion) NOx Control Technologies

1) Selective catalytic reduction (SCR) 2) Selective Non-catalytic Reduction (SNCR)


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Selective Catalytic Reduction (SCR) Description • Ammonia (NH3) is injected into the flue gas (or exhaust gas in gas turbine combustor), which then passes through a catalytic reactor • The catalytized NOx– NH3 reaction generates N2 and water vapor • NOx Reduction Potential: ~ 80% to 95%

Examples of Industrial Applications • Utility boilers • Industrial boilers • Combined-cycle (gas and steam turbines) or cogeneration turbines • Simple-cycle gas turbines (GT) Professor Yehia Khalil

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Selective Catalytic Reduction (SCR) • Ammonia gas (NH3) injected into the flue gas is the reducing agent • NOx is reduced to N2 in the SCR unit containing the catalyst Reactions: NOx

4NO

+ 4NH3 + O2  4N2 + 6H2O O2 comes from air

2NO2 + 4NH3 + O2  3N2 + 6H2O Professor Yehia Khalil

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Types of Catalysts in SCR Catalyst Type

Operating Range

• Titanium oxide based (TiO2)

270 - 400 oC

• Zeolite (Al2O3, SiO2, Fe2O3)

300 – 430 oC

• Iron-oxide based catalyst

380 – 430 oC

• Activated coal/coke

100 – 150 oC

Vanadium oxide (V2O5) can be added TiO2 to increase the activity, but this also tends to increase the rate of SO2 oxidation to SO3. Professor Yehia Khalil

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NOx Selective Catalytic Reduction (SCR)

Economizer if needed

Flue Gas Heated Air

SCR Reactor

Fuel

Bottom Ash

The economizer could be used to heat the secondary air in staged combustion


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NOx Selective Catalytic Reduction (SCR) Flue Gas


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NOx Selective Catalytic Reduction (SCR) Technical Issues/Concerns – Achieving the optimum temperature range for conventional catalysts (650°F to 850°F) – Thermal stress/fatigue of the catalyst bed during start-ups and shutdowns – Sulfur compounds (SO2, H2S) may poison catalyst’s active cites – Ammonia storage & handling  industrial safety hazard (NH3 is flammable & toxic) – Unreacted ammonia (NH3 slip) - - NH3 is toxic and also odor is an health concern – Fly ash contaminated with unreacted NH3 cannot be sold as a useful byproduct. Professor Yehia Khalil

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SCR Catalyst Location Low Dust Location • SCR catalyst in located after the ESP and before the air preheater. • The flue gas reaching the catalyst is almost dust free but contains SO2 Tail End Location The SCR catalyst located in the end of the chain of flue gas cleaning equipment. Sloss, Leslie, L., et al., 1992. Nitrogen Oxides Control Technology Fact Book, Noyes Data Corporation.


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Selective Non-catalytic Reduction (SNCR) Inject ammonia (NH3) or urea (NH2CONH2) near top of boiler: 6NO + 4NH3  5N2 + 6H2O

2NO + (NH2)2CO + 1/2O2  2N2 + 2H2O + CO2


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Selective Non-catalytic Reduction (SNCR)

Benefits: • Lower capital and O&M costs compared to SCR. • Can be easily retrofitted with other air pollution control technologies.


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Selective Non-catalytic Reduction (SNCR) • Ammonia (NH3) injection at 950oC - 1050oC (~ 1740 – 1920oF) • Urea (NH2CONH2) injection at 1000oC - 1150oC (~ 1830 – 2100oF) • Generally, SNCR technology is capable of achieving ≈ 30 - 50% NOx reduction efficiency Professor Yehia Khalil

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SCR and SNCR Control Technologies Unreacted NH3 (Ammonia Slip) in the Flue Gas 1)Unreacted ammonia (slip) can adsorb on fly ash particles 2)Adsorbed NH3 adversely impacts selling the byproduct ash as an ingredient for concrete 3)Disposal problems Pond: NH3 can promote algae growth Landfill: NH3 odor Professor Yehia Khalil

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Impact of Key Parameters on NOX Reduction • Efficiency of NOx reduction depends upon: NOx concentration, flue gas temperature and catalyst type.

Each catalyst type has an optimum operating temperature

• Unreacted NH3 can react with SO2 to form ammonium bisulfate NH4HSO4 (corrosive). Heck, R.M. & Farrauto, R.J., Catalytic Air Pollution Control: Commercial Technology, Van Nostrand Reinhold, 1995.


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SO2 Emission Control SO2 Dilemma: Scrub, Switch, Trade Allowances or Retire Plant Options: 1) Install flue gas desulfurization (FGD) scrubbers (down-the-pipe or postcombustion treatment method). 2) Switch fossil fuel type (at-the-source control) • From high (3 – 4 wt% S) to low sulfur coals (< 1 wt% S) • Burn natural gas or oil 3) Exercise emission allowance trading; meaning buy SO2 allowances as needed from other utilities that have surplus allowance (regulatory-based approach) 4) Retire the plant for being uneconomical to run (in particular when the remaining life of the plant is short). 5) Can you suggest other options? Professor Yehia Khalil

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SO2 Emission Control SO2 Dilemma: Scrub, Switch, Trade Allowances or Retire Plant

Can you suggest other options? • Enhance thermal efficiency of the plant: • Combined cycle (gas turbine and steam turbine) • Waste heat to energy conversion: a joule in hand is worth ten in the ground • Add renewable sources to the utility’s energy production portfolio • Wind turbines • Solar PV • Geothermal • Nuclear Professor Yehia Khalil

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SO2 Emission Control Down-the-Pipe Control Technologies: • Wet scrubbers: Limestone (CaCO3) sorbent, Lime (CaO) sorbent or magnesium-enhanced {MgSO4 + Ca(OH)2} wet scrubber (aka Mg-Lime FGD). • Lime spray drying absorber (SDA): Semi-Dry FGD system • Dry sorbent injection (DSI): Dry FGD system Typical scrubber (spray towers) Designs:

Packed bed or tray columns with counter current flows (sorbent vs. flue gas) Professor Yehia Khalil

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Flue Gas Desulfurization ( Wet FGD)

Boiler flow gas

ECONOMIZER

Heat Exchanger

Slurry

Notice that the ESP is placed upstream of the FGD because sulfur removal in the FGD will degrade the efficiency of ESP if it placed downstream of the FGD.

Forced Oxidation CaSO3 & CaSO4


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Wet FGD System

Ca(OH)2 + SO2  CaSO3 (s) + H2O CaSO3 + ½ O2  CaSO4 (s) Slurried sorbent

513 MWe Coal-fired Plant Typical Values for FGD System: Limestone/Lime consumption: 63,000 lb/hr

Flue Gas

Ca/S molar ratio: 1.14 Flue gas flow at FGD inlet: 5,766,000 lb/hr

Wet Sludge

SO2 removal: 34,000 lb/hr

Source: EPRI IE-7365, Volume 1, Topical Report June 1991

Bubble-Cap Column

Title: Engineering and economic evaluation of CO2 removal from fossil-fuel-fired power plants.


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Magnesium-Enhanced {MgSO4 + Ca(OH)2} Wet Scrubber Magnesium-Enhanced FGD Process with Byproduct Mg(OH)2 MgSO4 + Ca(OH)2 + 2H2O → CaSO4•2H2O (gypsum) + Mg(OH)2

Cleaned Gas Magnesium Enhanced Absorber Lime Water

Flue Gas

Slaker Lime Slurry Tank

Stack

FGD

Oxidizer Belt Filter Inerts

Compressed Air

Gypsum Byproduct

Pre-Treated FGD Effluent Byproduct Magnesium Hydroxide Precipitation Tank System pH 9.5 - 10 Professor Yehia Khalil

Gypsum to Oxidizer

Magnesium Hydroxide 36

Dry Sorbent Injection (DSI) Mg(OH)2 Injection Locations

Furnace

Selective Catalytic Reduction

DSI Mg(OH)2 Injection Locations

Flue Gas

ESP

Wet FGD

Boiler


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Dry Sorbent Injection (DSI) Notice the need to add particulate collection device (ESP) after the dry sorbent injection (DSI) because the particulate loading increases due to the injection of dry sorbent powder.

Coal cleaning by washing

Flue gas

CaO Sorbent (dry powder) Injection

Wash Water Pulverized Coal

Flue gas to stack

Burners

Polluted waste water

Ash

Minerals such as FeS2 (Pyrite) are removed from the coal by washing with water.


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Dry Sorbent Injection (DSI)

• Inject dry sorbent, sodium bicarbonate (NaHCO3), downstream from the boiler’s burners. • Reaction temperature 130 - 180oC: 2NaHCO3  Na2CO3 + CO2 + H2O Na2CO3 + SO2 + 1/2O2  Na2SO4 + CO2 Professor Yehia Khalil

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Dry Sorbent Injection (DSI) • Disadvantage: high cost of sodium bicarbonate. • Alternative sorbent: inject lime (CaO) instead of sodium bicarbonate • SO2 capture efficiency range: ~ 40 - 80%


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Semi-Dry Sorbent Injection aka, Spray Drying Absorber (SDA) Point of injection of flue gas + lime slurry {Ca(OH)2}

Absorption chamber designed with specific L/D ratio

SDA

Ca(OH)2 slurry Slurried lime, Ca(OH)2, is injected into the flue gas where it dries as it reacts. Products are dry particles which exit with flue gas.

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Semi-Dry Sorbent Injection aka, Spray Drying Absorber (SDA) • SDA is appropriate for coals with low S content < 1 wt% • Amount of water that can be injected is limited by cooling of the flue gas while remaining above the SO3 dew point to avoid corrosion problems due to H2SO4 acid formation.

SO3 vapor condensation is highly corrosive and should be avoided by keeping the flue gas temperature above SO3 dew point. Professor Yehia Khalil

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Semi-Dry Sorbent Injection aka, Spray Drying Absorber (SDA)

• Slurried lime, Ca(OH)2, is injected into the flue gas where it dries as it reacts. Products are dry particles which exit with flue gas. • Often end with a mixture of calcium sulfate (CaSO4) and sulfite (CaSO3). • 60 - 80% SO2 removal efficiency is possible with Ca:S molar ratio ~2:1. • Typically, Ca/S ratio is greater than 1.0 (the stoicheometric ratio)


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Chemistry of the Wet FGD System

CaO MgO Ca++, Mg++, Na+, CO3- -, SO4- -, etc Acidic

CaSO4

Flue Gas

Gas Phase Diffusion

Liquid Phase Ionic Reactions Professor Yehia Khalil

Solid Phase Precipitation 44

Flue Gas Desulfurization (FGD) Overall reactions: Limestone: CaCO3 (s)  CaO (s) + CO2 (g) (calcination – energy intensive)

FGD technologies remove SO2 but adds CO2 to the environment!

Sulfur Removal: SO2 (g) + CaO (s)  CaSO3 (s) (Dry sorbent injection also called dry scrubber FGD) Lime: CaO + H2O  Ca(OH)2 SO2 + Ca(OH)2  CaSO3 + H2O

(Lime slaking) (Wet Scrubber FGD system)

Forced Air Oxidation: CaSO3 + 1/2O2  CaSO4 (s) Professor Yehia Khalil

(Gypsum) 45

Common Problems with Limestone FGD Systems  Insufficient or low utilization of limestone (CaCO3)  Low sulfur dioxide (SO2) removal efficiency  Production of large amounts of waste water and wet sludge  Scaling (solids formation in the wrong places inside the absorber) such as ‘mist eliminators’ and ‘packing material’ in packed bed absorbers. Professor Yehia Khalil

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Wet FGD Systems • Here, the product from FGD is wet sludge. • Wet systems are usually located downstream of the fly ash collector (cyclone, ESP, baghouse, etc). • Can achieve very high sorbent utilization (90% capture with Ca:S ratio ~ 1:1) • Wet FGD can be divided into 2 categories: – Non recoverable (throwaway) sorbent – Recoverable sorbent Professor Yehia Khalil

See Table 15.2, page 461

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Wet FGD systems: Non-Recoverable Sorbent • Wet sodium carbonate Na2CO3 scrubbing: Flue gas is scrubbed with sodium carbonate solution to produce soluble sodium salts. The latter are oxidized to sodium sulfate. • Sodium carbonate is relatively expensive. • 90% capture efficiency with Ca:S ~1.8:1


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Wet FGD systems: Non-Recoverable Sorbent • The Walther wet scrubber: NH3 solution is injected into flue gas where it reacts with SO2 to form ammonium sulfates (NH4)2SO4 and sulfites (NH4)2SO3, which can be sold as fertilizer. • 90% SO2 capture efficiency is possible.


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Wet FGD systems: Recoverable Sorbent • Dual-alkali (NaOH and CaO) scrubbing: Sodium carbonate or sodium hydroxide scrubs flue gas. • Sodium products are recovered by mixing with lime (CaO) in a separate reaction vessel (producing NaOH sorbent and solid calcium sulfate). • This technology is rather complex, and is not widely used. Professor Yehia Khalil

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Wet FGD systems: Recoverable Sorbent • Wellman-Lord (WL) Process (see page 468) • Much more complex and costly • Reactions: – Absorb SO2 in aqueous NaOH to form sodium sulfite solution (Na2SO3). – Some of sulfite will oxidize to sulfate (Na2SO4), which is undesirable. – NaOH is regenerated by liberating a concentrated stream of SO2, which can be used to produce sulfuric acid (H2SO4) or elemental sulfur. Professor Yehia Khalil

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Wet FGD systems: Recoverable Sorbent • Magnesium Oxide (MgO) Process: – Flue gases are scrubbed with MgO slurry. – MgSO3 and MgSO4 are produced. These can be dried and calcined to regenerated MgO and to produce a high-concentration stream of SO2. MgSO4  MgO + SO2 – 98% of SO2 removal efficiency is achievable. Professor Yehia Khalil

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Summary 1. NOx emission control • At-the-source technologies: Air staging, fuel staging, FGR, LNB, hybrid • Down-the-pipe technologies: SCR and SNCR


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Summary 2. SO2 emission control • Available Options: Scrub, switch, trade allowances or retire plant • Other options Waste heat to energy conversion, enhance plant efficiency, add renewable sources to the energy portfolio • Down-the-pipe technologies: Wet FGD, semi-dry FGD (SDA) and dry (DSI) FGD Professor Yehia Khalil

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