MEMORANDUM 

From: The Office of Air Quality Planning and Standards 

 U.S. Environmental Protection Agency 

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 predominately oxidizes to sulfer dioxide 

(SO2) gas. A small portion of the SO2 further oxidizes to sulfur trioxide (SO3), which forms sulfuric 

acid mist (H2SO4) when combined with water. SO2 emissions from EGUs are typically controlled by 

pre-combustion, add-on controls, or a combination of the two. The two types of add-on controls 

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 pulverized coal (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 by-product. 

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% 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% reduction in potential emissions. The standard for 

owners/operators of modified affected facilities is 0.15 lb/MMBtu or 90% 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 subpart Da SO2 emissions standard for owner/operators of new and reconstructed 

affected facilities is 1.0 lb/MWh gross output or 97% 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 

The following is a brief summary of some of the SO2 control technologies, including propriety 

technologies. This summary is not intended to be a comprehensive list of available technologies. The 

performance values given here are those that have been provided by the technology provider in 

publically available sources. Inclusion of a technology in this summary is not intended to be an 

endorsement of that technology by the US EPA the US Government 

Coal gasification 
The gasification process breaks coal apart into its chemical constituents (typically a mixture of carbon 

monoxide, hydrogen, and other gaseous compounds) prior to combustion. Sulfur in the product syngas 

is present as H2S and technologies such as Selexol, Rectisol and desulfurization sorbents can 

effectively reduce the concentration of H2S in the syngas stream prior to combustion in the 

downstream combustion turbine. Any residual H2S the syngas stream will be converted to SO2 in the 

combustion turbine. Gasification allows for the reduction of SO2 emissions by over 99% and is the 

only pre-combustion technique that is a feasible standalone NSPS control technologies. The other precombustion approaches are incapable of meeting the NSPS as a standalone approach. 

In-situ SO2 Control Technologies 

Furnace Sorbent Injection (FSI). Furnace Sorbent Injection is another once-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. A potential 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. 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). Once-through ammonia- based FGD 

systems typically produce a liquid or solid fertilizer byproduct. In regenerable technologies, the SO2 is 

released from the sorbent during regeneration and processed to yield a potentially valuable by-product 

(e.g., sulfuric acid or elemental sulfur). 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 semi-
dry 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% when using lime or 

limestone, and up to 90% 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 SO2

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

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 byproducts 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% water by weight. A wet scrubber system consumes between 25 to 33% more water 

than a comparable SDA scrubber. The SO2 removal efficiencies of new alkali wet scrubbing systems 

are generally greater than 95%. 

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. A common wet scrubber application utilizes limestone as the reagent and forced 

oxidation of the reaction by-products to form calcium sulfate (synthetic gypsum). 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. 

Enhanced Wet Flue Gas Desulfurization. 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 liquid-to-gas contact 

while increasing pressure drop instead of increasing pumping requirements. Modern wet FGD designs 

can achieve 98 to 99% SO2 removal for medium to high sulfur coals on an annual basis. 

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 multi-pollutant control technologies in various stages of commercial development are available 

to reduce SO2 emissions. These include, but are not limited to, the Airborne ProcessTM, the APTECH 

CST process, the CEFCO process, Eco Power’s COMPLY 2000, the copper-oxide (CuO) process, 

Powerspan’s Electro Catalytic Oxidation (ECO®) process, the electron beam (E-Beam) process, the 

Indigo Multi Air Pollutant System (MAPSystemTM) process, the Nalco Mobotec technology, The 

NOXSO process, the Pahlman process technology developed by Enviroscrub, ReACTTM, Skyonic’s 

SkyMine®, TOPSØE SNOXTM, and the SOx-NOx-Rox Box (SNRBTM) process. These technologies 

offer the potential for improved environmental performance at lower costs than traditional 

technologies. This list is intended to merely illustrate that the multiple technologies exist and may not 

include all available technologies. EPA and the U.S. government do not endorse any of the listed 

multi-pollutant technologies. 

SO2 Control Performance 
30-day SO2 emission rates were calculated by dividing the sum of the unadjusted emissions for all non 

out-of-control operating hours by the sum of the gross electrical energy output over the same period as 

reported to the Clean Air Markets Division (CAMD) of EPA. Out-of-control hours were defined as 

when either the unadjusted applicable emissions or gross output could not be determined for that 

operating hour. The reduction in potential SO2 emissions was calculated by comparing the reported 

SO2 emissions during a 30-day period to the potential emissions for that same 30-day period. Potential 

uncontrolled SO2 emissions were calculated using monthly delivered fuel receipts and fuel quality data 

from the Energy Information Administration (EIA) forms EIA-923 (utility and nonutility coal data post 

2007), EIA-423 (nonutility coal data prior to 2008), and FERC-423 (utility coal data prior to 2008), as 

applicable. For each operating day, the total potential uncontrolled SO2 emissions were calculated by 

multiplying the uncontrolled SO2 emissions rate for the applicable month as determined using the EIA 

data by the heat input for that day. For locations with multiple affected facilities burning different fuel 

combinations, we used the information submitted to the Toxics’ rule information collection request 

(ICR) on individual boiler fuel use data to apportion the fuels to the separate affected facilities. In 

addition, for locations with combustion turbines we used the fuel use data reported using EIA-906 and 

920 to subtract out the natural gas and/or distillate oil burned in the combustion turbines. Figures 1 

shows the performance of the best performing facilities in terms of percent reduction in potential SO2

emissions. 

Figure 1: SO2 Emissions Performance Data 

Facility Time Period Maximum 30-Day 

SO2 Emissions Rate 

(lb/MWh) 

Minimum 30-Day % 

SO2 Reduction 

Cayuga 1 12/08 – 12/09 1.03 97.4 

Harrison 1 01/06 – 01/09 1.45 96.7 

Harrison 2 01/06 – 01/09 1.01 97.7 

Harrison 3 01/06 – 01/09 0.97 98.2 

HL Spurlock 1 06/09 – 12/09 1.83 96.9 

HL Spurlock 2 11/08 – 12/09 1.26 98.0 

HL Spurlock 3 01/09 – 12/09 1.45 96.5 

HL Spurlock 4 01/09 – 12/09 1.08 97.7 

Wansley 1 02/09 – 12/09 0.31 97.7 

Wansley 2 05/09 – 12/09 0.37 97.4 

Iatan 1 04/09 – 12/09 0.16 98.2 

Jeffrey 2 05/09 – 12/09 0.09 99.0 

Jeffrey 3 04/09 - 12/09 0.13 98.5 

Trimble County 1 01/05 – 12/09 1.14 97.6 

Mountaineer 1 05/07 – 12/09 1.15 97.6 

With the exception of the HL Spurlock 3 and 4 facilities, all of the listed facilities use wet limestone 

based scrubbers. HL Spurlock 3 and 4 are fluidized bed boilers that remove the majority of SO2 using 

limestone injection into the boiler and then remove additional SO2 by lime injection into the ductwork 

prior to the fabric filter. Of the identified best performing facilities, we only have multiple years of 

performance data for the Harrison, Trimble County, and Mountaineer facilities. Based on the 

performance of these facilities, we have concluded that 97% reduction in potential SO2 emissions has 

been demonstrated and is achievable on a long term basis. Therefore, the proposed upper limit on a 

percent reduction basis is 97%. Even though the Iatan and Jeffery facilities are achieving a 98% 

reduction in potential SO2 emissions we are not proposing this standard because it is based on 
relatively short term data. Based on the variability in SO2 reductions from the Harrison, Trimble 

County, and Mountaineer facilities, we have concluded that short term data does not necessarily take 

into account the range of operating conditions that a facility would be expected to operate or control 

equipment variability and degradation. 

The sulfur concentrations in the flue gas of EGUs burning medium and low sulfur coals is more diffuse 

than for EGUs burning high sulfur coals, and it has not been demonstrated that facilities burning these 

coals would be able to achieve 97% reduction of potential emissions on a continuous basis. Therefore, 

we are proposing an alternate numerical standard in conjunction with the percent reduction standard. 

To determine an appropriate alternate numerical standard, we evaluated the performance of several 

recently constructed facilities in addition to the numerical standards for the facilities in Figure 1. 

Figure 2 shows the maximum 30-day average SO2 emissions rate of facilities that commenced 

operation between 2005 and 2008, that are emitting at levels below the current NSPS, that are reducing 

potential SO2 emissions by less than 97%, and that reported both SO2 emissions and gross electric 

output data to CAMD. 

Figure 2: SO2 EMISSIONS PERFORMANCE DATA FOR NEW FACILITIES 

Facility Time Period In Service 

Date 

Maximum 30-Day SO2

Emissions Rate (lb/MWh) 

Minimum 30-Day % 

SO2 Reduction 

Weston 4 01/08 – 12/09 2008 0.61 90.0 

Cross 4 05/08 – 12/09 2008 1.02 96.5 

TS Power Plant 1 06/08 – 12/09 2008 0.56 91.8 

Wygen II 01/08 – 12/09 2008 0.95 92.5 

Walter Scott Jr. 

Energy Center 4 

07/07 – 12/09 2007 0.73 87.7 

Cross 3 01/07 – 12/09 2007 1.06 95.9 

Springerville TS3 04/07 – 12/09 2006 1.04 93.0 

With the exception of the Cross 3 and 4 facilities, which burn medium sulfur bituminous coals and use 

wet limestone-based scrubbers, the remaining facilities burn lower sulfur subbituminous coals and use 

lime-based spray dyers. To provide the maximum emissions reduction, we concluded that the alternate 

numerical standard should be as stringent as the numerical rates achieved by the facilities used to 

determine the percent reduction standard. If the alternate numerical standard were less stringent than 

the emissions rate achieved by the facilities used to determine the maximum percent reduction, those 

facilities would not be required to achieve the maximum percent reduction that has been demonstrated. 

In addition, the numerical standard should account for variability in today’s SO2 control technologies 

and provide sufficient compliance margin for owners/operators of new facilities burning medium 

sulfur coals to comply with the numerical standard and thereby provide an incentive to burn cleaner 

fuels. We are proposing 1.0 lb/MWh as the alternate numerical standard because it provides a 

comparable level of performance to the 97% reduction requirement and satisfies the criteria mentioned 

above. The numerical standard would require at least 80% reduction even from the lowest sulfur coals 

and would accommodate the use of spray dryer scrubbers for owner/operators of new facilities burning 

coal with uncontrolled SO2 emissions of up to approximately 1.6 lb/MMBtu. 

Based on the performance of the spray dryer at the Springerville TS3 power plant, the numerical 

standard would provide sufficient flexibility such that an owner/operator of an EGU could burn over 

90% of the subbituminous coals presently being used in combination with a spray dryer. This 

technology choice provides owners/operators the flexibility to minimize water use and associated 
waste water discharge, as well as reducing additional CO2 that is chemically created as part of the SO2

control device. Even though there is not necessarily an overall GHG reduction from using a lime 

based instead of a limestone based scrubber, lime production facilities have relatively concentrated 

CO2 streams. Capture and storage of CO2 at the lime manufacturing facility could potentially be easier 

since separation of the CO2 would not be necessary, as is the case with an EGU exhaust gas. 

Owners/operators of new and reconstructed facilities burning coals with higher uncontrolled SO2

emissions could either use IGCC with a downstream process to control sulfur prior to combustion, 

fluidized bed combustion, or a wet SO2 scrubbing system to comply with the standard. The proposed 

limit would allow the higher sulfur coals (uncontrolled emissions of greater than approximately 3 lb 

SO2/MMBtu) to demonstrate compliance with the 97% reduction requirement as an alternative to the 

numerical limit.