MEMORANDUM 

From: The Office of Air Quality Planning and Standards 

To: EGU NSPS Docket (EPA-HQ-OAR-2011-0044) 

Date: March, 2011 

Subject: Control of SO2 Emissions 

Introduction 

During combustion, the organic and pyretic sulfur in coal are predominately oxidized s to SO2 gas. A 

small portion of the SO2 oxidizes further to sulfur trioxide (SO3), which forms sulfuric acid mist 

(H2SO4) when combined with water. SO2 emissions from EGUs are typically controlled by precombustion, add-on controls, or a combination of the two. The two types of add-on control applicable 

to EGUs include: in-situ combustion control (sorbent injection) and post-combustion flue gas 

desulfurization (FGD). In-situ control is used effectively in fluidized bed (FB) boilers, and may be 

used in a PC boiler by dry injection of sorbents. Post-combustion controls applicable to EGUs include 

wet scrubbing or spray dryer absorber (SDA) technology. Pre-combustion control limits the sulfur 

content of the fuel. Add-on control technologies rely on either absorption or adsorption processes that 

react SO2 with lime, limestone, or another alkaline material to form an aqueous or solid sulfur byproduct. 

The present subpart Da SO2 emissions standard for owners/operators of new facilities is 1.4 pounds per 

megawatt hour gross output (lb/MWh gross) or 95 percent reduction of the potential emissions on a 30-

day rolling average basis. The standard for owners/operators of reconstructed affected facilities is 1.4 

lb/MWh, 0.15 lb/MMBtu heat input, or 95 percent reduction in potential emissions. The standard for 

owners/operators of modified affected facilities is 0.15 lb/MMBtu or 90 percent reduction in potential 

emissions. The dual standard reflects that higher removal efficiencies tend to be more practical when 

there is a high concentration of SO2 in the flue gas, and vice versa. 

The proposed SO2 emissions standard for owner/operators of new and reconstructed affected facilities 

is 1.0 lb/MWh gross output or 97 percent reduction of potential emissions on a 30-day rolling average 

basis. We are not proposing to amend the SO2 standard for owners/operators of modified affected 

facilities or owners/operators of affected coal refuse-fired facilities. 

Add-on SO2 Control Technologies 

In-situ SO2 Control Technologies 

Furnace Sorbent Injection (FSI). Furnace Sorbent Injection is another one-through dry technology that 

utilizes dry lime or limestone as the reagent to absorb SO2. In the FSI technology, the reagent (e.g., 

finely crushed limestone) is injected directly into the furnace and the reaction product is collected in 

the downstream particulate control device. 
Limestone Injection Dry Scrubbing (LIDS). Limestone Injection Dry Scrubbing (LIDS) combines FSI 

and dry scrubber technologies. In the LIDS system, limestone is injected into the furnace and a spray 

dryer absorber is installed between the air heater and particulate collection device. The reagent used in 

the spray dryer is a hydrated reaction byproduct recycled from the particulate collection device. 

Fluidized-bed (FB) boilers. FB boilers generally control the majority of SO2 by adding finely crushed 

limestone along with the coal (or other solid fuel) to the fluidized bed. During combustion, calcination 

of the limestone (reduction to lime by subjecting to heat) occurs simultaneously with the oxidation of 

sulfur in the coal to form SO2. The SO2, in the presence of excess oxygen, reacts with the lime 

particles to form calcium sulfate. The sulfated lime particles are removed with the bottom ash or 

collected with the fly ash by a downstream PM control device (for most existing FBC steam generating 

unit applications, a fabric filter is used as the PM control device). Fresh limestone is continuously fed 

to the bed to replace the reacted limestone. 

Post-Combustion SO2 Control Technologies 

Post combustion control technologies that rely upon chemical reactions to reduce the concentration of 

SO2 in the flue gas are often referred to as FGD systems. The potentially applicable add-on 

technologies for control of SO2 emissions can be classified as either once-through or regenerable. In 

once-through technologies, the SO2 is permanently bound with the sorbent, which must then be 

disposed of as a waste or utilized as a by-product (e.g., gypsum). In regenerable technologies, the SO2

is released from the sorbent during regenerating and processed to yield a potentially valuable byproduct, such as sulfuric acid or elemental sulfur. (Once-through ammonia- based FGD systems 

typically produce a liquid or solid fertilizer byproduct.) The regenerated sorbent is then recycled for 

re-use. 

Both once-through and regenerable technologies can be further classified as either wet or dry 

technologies. Characteristics of a wet FGD system include low flue gas outlet temperatures of 50oC to 

60oC (120oF to 140oF), saturated flue gas conditions, and a wet reaction product. The particulate 

control system is typically located upstream of a wet FGD. This allows for particulate and FGD 

reaction products to be collected separately. Semi-dry FGD systems are located upstream of the 

particulate control system and operate at temperatures well above saturation, 120oC to 180oC (250oF to 

350oF). True dry processes use dry sorbent injection without water addition. Locating the dry or semidry FGD system upstream of the particulate control system allows for a common collection location 

for both the fly ash and the FGD reaction product. 

Dry Sorbent Injection. Dry sorbent injection can be used to reduce SO2 and sulfuric acid (H2SO4) mist 

emissions from EGUs. The system works by injecting a powdered sorbent (such as hydrated lime, 

soda ash, limestone, or sodium bicarbonate) into the ductwork between the air pre-heater and the 

particulate collection device. Some systems use spray humidification followed by dry injection. SO2

is adsorbed and reacts with the powdered sorbent. The dry solids are entrained in the combustion gas 

stream, along with fly ash, and then collected by the downstream PM control device. The 

effectiveness of this control technology for removing SO2 emissions depends on the sorbent used and 

the injection rate. However, the SO2 removal efficiencies for existing dry injection systems are lower 

than for the other FGD technologies, ranging from approximately 40 to 60 percent when using lime or 

limestone, and up to 90 percent using other sorbants (e.g., sodium bicarbonate). 
Spray Dryer Absorber (SDA). The SDA is located upstream of the particulate collection system. The 

flue gas passes through a spray dryer vessel, where it encounters a fine mist of lime slurry. The slurry 

is atomized into fine droplets in the dryer and the lime particles react with the absorbed SO2. The SO2

reacts with the hydrated lime reagent to form solid calcium sulfite and calcium sulfate. The moisture 

in the droplets evaporates and reacts with the SO2 in the flue gas to form insoluble calcium salts. 

When a fabric filter is used as the particulate control device, it allows for further reaction of the lime 

with the sulfur (and other acid gases) in the flue gas. This is because all flue gas must pass through the 

layer of porous filter cake containing the reagent on the surface of the filter. The collected waste 

product from an SDA system can be disposed in a landfill, sold as by-product, or recycled into the 

slurry mixture. The SO2 removal efficiencies of new lime spray dryer systems are generally greater 

than 90 percent. 

Advanced Semi-dry FGD Circulating Dry Scrubber (CDS). Circulating dry scrubber (CDS) systems 

utilize a fluidized bed of moistened reagent for absorbing SO2. The fluidization of the particles is 

accomplished by the vertical upward flow of flue gas through the reactor. The reagent is typically dry 

hydrated lime. Water is injected into the CDS reactor independent of the reagent. The CDS reactor 

promotes absorption of SO2 into the water and the reaction of SO2 with the hydrated lime by intense 

gas-solid mixing. The reaction products include calcium sulfite and calcium sulfate. The reaction 

products, unreacted lime, and fly ash are then collected downstream in the particulate collection 

device. Several advanced semi-dry FGD technologies are similar to the CDS system, including 

Turbosorp®, flash dryer absorber (FDA) (also known as NIDS), and other circulating fluidized bed 

(CFB) dry scrubbers. 

Wet Scrubber. In a wet scrubber system, a reagent is slurried with water and sprayed into an absorber 

vessel located downstream of the particulate control device. Flue gas enters at the bottom of the 

absorber tower, continues vertically through the water spray- resulting in intimate liquid-to-gas 

contact- passes through a mist eliminator to control the re-entrained slurry drops, and then exits the 

tower. The intimate contact results in the SO2 absorption into the liquid and the reaction with the 

reagent. The by-products of the sorption and reaction are in a wet form upon leaving the system and 

must be dewatered using thickeners, centrifuges, or vacuum filters prior to transport/disposal. The 

final slurry may contain 10 to 40 percent water by weight. A wet scrubber system consumes between 

25 to 33 percent more water than a comparable SDA scrubber. The SO2 removal efficiencies of new 

alkali wet scrubbing systems are generally greater than 95 percent. 

Wet FGD systems can utilize a variety of alkaline mediums to remove SO2 from the flue gas. These 

mediums include lime, limestone, sodium carbonate, magnesium oxide, dual alkali, high alkalinity fly 

ash, and amine-based liquors such as ammonia. Seawater has also been used as a reagent, since it has 

a high concentration of dissolved limestone. All of these systems produce a byproduct that may either 

be disposed of or sold. Most installed wet FGD systems use lime or limestone scrubbing reagents. 

Since limestone is much less expensive, it is used more often. This is especially the case for medium 

to high sulfur coals. The most common wet scrubber application utilizes limestone as the reagent and 

forced oxidation of the reaction by-products to form calcium sulfate (gypsum). Wet scrubbers all rely 

on the reaction of calcium in the reagent to remove SO2 from the flue gas. An inhibited oxidation 

system will produce calcium sulfite that is more difficult to dewater and has very little potential for 

commercial use, and is typically disposed of in a landfill. A forced oxidation system produces calcium 

sulfate (synthetic gypsum), which may be marketable depending on its quality and local market 

requirements. 
Enhanced Wet Flue Gas Desulfurization. Modern wet FGD designs may include wall rings, buffering 

agents, advanced gas distribution, or advanced gas sparging systems to achieve 98 to 99 percent SO2

removal for medium to high sulfur coals on an annual basis. Enhanced wet scrubbers include (1) the 

use of buffering agents for the scrubber slurry, (2) novel methods of contacting the flue gas and slurry, 

and (3) methods for preventing flue gas sneakage through the scrubber (i.e., flue gas that has received 

little or no treatment). Buffering agents may reduce the operating costs by reducing the amount of 

liquid that needs to be recycled in the absorber tower. The buffering agents typically used are organic 

acids or salts of these acids. Other developments in wet FGD pollution control include design features 

within the absorber tower that minimize operating costs. The Jet Bubbling Reactor, developed by 

Chiyoda, and Alstom’s Flowpac systems are examples of designs that were developed to improve 

liquid-to-gas contact by forcing the flue gas to bubble through the slurry. This is done by utilizing a 

gas sparger design rather than spraying the flue gas with slurry. Another wet FGD liquid-to-gas 

contact design application is the perforated plate scrubber. Yet another developed design includes 

bidirectional sprays and wall rings to be used within the wet FGD absorber tower in order to reduce 

SO2 sneakage over the conventional FGD. All these wet FGD design technologies improve the liquidto-gas contact while increasing pressure drop instead of increasing pumping requirements. 

Regenerable Wet Scrubber. This technology uses sodium sulfite, magnesium oxide, sodium 

carbonate, amine, or ammonia as the sorbent for removal of SO2 from the flue gas. The spent sorbent 

is regenerated to produce concentrated streams of SO2 or other sulfur compounds, which may be 

further processed to produce other products. These FGD technologies may require additional flue gas 

treatment prior to the SO2 absorption process to remove other flue gas constituents, such as hydrogen 

chloride and hydrogen fluoride, that may affect the sorbent and/or final by-product. 

Multi-Pollutant Technologies 

Several emerging multi-pollutant technologies in various stages of commercial development are 

available to reduce SO2 emissions. These include the Airborne ProcessTM, the CEFCO process, Eco 

Power’s COMPLY 2000, Powerspan’s Electro Catalytic Oxidation (ECO®) process, ReACTTM, 

Skyonic’s SkyMine®, TOPSØE SNOXTM, and the Pahlman process technology developed by 

Enviroscrub. These technologies offer the potential for improved environmental performance at lower 

costs than traditional technologies. 

SO2 Control Costs 

Cost estimates were prepared for the regulatory baseline and the proposed regulatory amendment. We 

defined two separate baselines for the comparisons. The first baseline considers the existing NSPS 

requirements in the absence of other regulatory requirements. The alternate baseline takes into account 

the requirements of New Source Review and the proposed Toxics Rule. The alternate baseline is 

lower than the NSPS, since these regulations require additional reductions beyond what the NSPS 

requires. 

To estimate impacts of the proposed NSPS amendments, we estimated the incremental costs for two 

500 MW model plants. One of the model plants burns Illinois bituminous coal and the other burns 

subbituminous coal from Montana. Under the existing NSPS, owners/operators of a new EGU would 

already be required to install some type of FGD. The proposed amendments would require that the 

owner/operator of the subbituminous plant increase the SO2 removal efficiency from 75 to 82 percent. 

The owner/operator of the bituminous facility would have to increase the SO2 removal efficiency from 
95 to 97 percent. The overall annual SO2 reductions would be 2,100 tons and the annualized costs 

would be $870,000. The incremental cost of $420 is considered cost effective. However, since the 

toxics rule acid gas standard is more stringent than the proposed standard the actual costs and benefits 

of the proposed amendments would be negligible.