MEMORANDUM

From: The Office of Air Qu ality Planning and Standards

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

Date: March, 2011

Subject: Control of SO 2 Emissions

Introduction

During combustion, the organic and pyretic sulfur in coal are pr edominately oxidized s to SO 2 gas. A small portion of the SO 2 oxidizes further to sulfur trioxide (SO 3 ), which forms sulfuric acid mist (H 2 SO 4 ) when combined with water. SO 2 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 combus tion control (sorbent injection) and post-combustion flue gas desulfurization (FGD). In-situ cont rol is used effectively in fluidi zed bed (FB) boilers, and may be used in a PC boiler by dry injection of sorbents. Post-combustion cont rols applicable to EGUs include wet scrubbing or spray dryer abso rber (SDA) technology. Pre-combus tion control limits the sulfur

content of the fuel. Add-on contro l technologies rely on either absorp tion or adsorption processes that

react SO 2 with lime, limestone, or another alkaline mate rial to form an aqueous or solid sulfur byproduct.

The present subpart Da SO 2 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 pot ential 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 emissi ons. The standard for owners/operators of modified affected facilities is 0.15 lb/MMBtu or 90 per cent reduction in potential emissions. The dual standard reflects that higher rem oval efficiencies tend to be more practical when there is a high concentration of SO 2 in the flue gas, and vice versa.

The proposed SO 2 emissions standard for owner/operators of new and reconstructe d 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 SO 2 standard for owners/operators of modified affected facilities or owners/operators of affected coal refuse-fired facilities.

Add-on SO 2 Control Technologies

In-situ SO 2 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 SO 2 . In the FSI technology, the reagent (e.g., finely crushed limestone) is inject ed directly into the furnace and th e 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 installe d between the air heater and particulate collection device. The reagent used in the spray dryer is a hydrated reaction byproduct recycl ed from the particulate collection device.

Fluidized-bed (FB) boilers . FB boilers generally c ontrol the majority of SO 2 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 lim e by subjecting to heat) occurs si multaneously with the oxidation of

sulfur in the coal to form SO 2 . The SO 2 , in the presence of excess oxyge n, reacts with the lime particles to form calcium sulfate. The sulfated lime particles ar e removed with the bottom ash or collected with the fly ash by a downstream PM contro l 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 th e reacted limestone.

Post-Combustion SO 2 Control Technologies

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

SO 2 in the flue gas are often referred to as F GD systems. The potentially applicable add-on technologies for control of SO 2 emissions can be classified as eith er once-through or re generable. In once-through technologies, the SO 2 is permanently bound with the sorbent, which must then be disposed of as a waste or utilized as a by-produc t (e.g., gypsum). In regenerable technologies, the SO 2 is released from the sorbent dur ing regenerating and processed to yield a potentially valuable byproduct, such as sulfuric acid or elemental su lfur. (Once-through ammonia- based FGD systems typically produce a liquid or solid fertilizer byproduct.) Th e 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 in clude low flue gas outlet te mperatures of 50oC to 60oC (120oF to 140oF), saturated flue gas conditio ns, and a wet reaction product. The particulate control system is typica lly 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 ope rate at temperatures well above saturation, 120oC to 180oC (250oF to 350oF). True dry processes use dry sorbent injection without water ad dition. Locating the dry or semidry FGD system upstream of the particulate contro l 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 SO 2 and sulfuric acid (H 2 SO 4 ) mist emissions from EGUs. The system works by injec ting a powdered sorbent (s uch 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. SO 2 is adsorbed and reacts with the powdered sorbent. The dry solids ar e entrained in the combustion gas stream, along with fly ash, and then collected by the downstream PM control device. The

effectiveness of this cont rol technology for removing SO 2 emissions depends on the sorbent used and the injection rate. However, the SO 2 removal efficiencies for existi ng dry injection systems are lower than for the other FGD technologies, ranging from a pproximately 40 to 60 percent when using lime or limestone, and up to 90 percent using ot her sorbants (e.g., so dium 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 SO 2 . The SO 2 reacts with the hydrated lime reagent to form solid calcium sulfite and calcium sulfate. The moisture in the droplets evaporates and reacts with the SO 2 in the flue gas to form insoluble calcium salts. When a fabric filter is used as the particulate cont rol 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 la ndfill, sold as by-product, or recycled into the slurry mixture. The SO 2 removal efficiencies of new lime spra y 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 SO 2 . The fluidization of the particles is accomplished by the vertical upward flow of flue gas through the reactor. The r eagent is typically dry hydrated lime. Water is injected into the CDS reactor independent of the reagent. The CDS reactor promotes absorption of SO 2 into the water and the reaction of SO 2 with the hydrated lime by intense gas-solid mixing. The reaction products include calc ium sulfite and calcium sulfate. The reaction products, unreacted lime, and fly ash are then co llected downstream in th e particulate collection device. Several advanced semi-dry FGD technologi es 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 slurri ed with water and spra yed into an absorber

vessel located downstream of the particulate control device. Fl ue gas enters at the bottom of the absorber tower, continues vertic ally through the water spray- resu lting in intimate liquid-to-gas contact- passes through a mist eliminator to contro l the re-entrained slurry drops, and then exits the

tower. The intimate contact results in the SO 2 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 SO 2 removal efficiencies of new alkali wet scrubbing systems are ge nerally greater than 95 percent.

Wet FGD systems can utilize a variety of alkaline mediums to remove SO 2 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 mo re often. This is especi ally the case for medium to high sulfur coals. The most common wet scrubber application utilizes lime stone 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 SO 2 from the flue gas. An inhibited oxidation system will produce calcium sulfite that is more diffi cult to dewater and has very little potential for commercial use, and is typically di sposed of in a landfill. A forced oxidation system produces calcium sulfate (synthetic gypsu m), which may be marketable depend ing 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 ga s sparging systems to achieve 98 to 99 percent SO 2 removal for medium to high sulfur coals on an annua l 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 thr ough the scrubber (i.e., flue gas that has received little or no treatment). Buffering agents may re duce 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 contro l 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 slu rry. This is done by utilizing a gas sparger design rather than sp raying the flue gas with slurry. Another wet FGD liquid-to-gas contact design application is the perforated plate scrubber. Yet another de veloped design includes bidirectional sprays and wall rings to be used within the wet FGD ab sorber tower in order to reduce

SO 2 sneakage over the conven tional FGD. All these wet FGD de sign technologies improve the liquidto-gas contact while increasing pressure dr op 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 SO 2 from the flue gas. The spent sorbent is regenerated to produce concentrated streams of SO 2 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 SO 2 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 va rious stages of commercial development are

available to reduce SO 2 emissions. These include the Airborne Process TM , the CEFCO process, Eco Power’s COMPLY 2000, Powerspan’s Electro Ca talytic Oxidation (ECO®) process, ReACT TM

, Skyonic’s SkyMine®, TOPSØE SNOX TM , and the Pahlman process technology developed by Enviroscrub. These technologies offer the potentia l for improved environmental performance at lower costs than traditional technologies.

SO 2 Control Costs

Cost estimates were prepared for the regulatory ba seline and the proposed re gulatory amendment. We defined two separate baselines for the comparisons. The first baseline considers the existing NSPS requirements in the absence of othe r regulatory requirements. The alte rnate baseline take s into account the requirements of New Source Review and the pr oposed 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 amendmen ts, we estimated the incremental costs for two 500 MW model plants. One of the model plants bur ns Illinois bituminous coal and the other burns

subbituminous coal from Montana. Under the exis ting NSPS, owners/operato rs of a new EGU would already be required to install some type of FGD. The proposed am endments would require that the owner/operator of the subbitu minous plant increase the SO 2 removal efficiency from 75 to 82 percent. The owner/operator of the bituminous f acility would have to increase the SO 2 removal efficiency from95 to 97 percent. The overall annual SO 2 reductions would be 2,100 tons and the annualized costs would be $870,000. The incremental cost of $420 is cons idered cost effective. However, since the toxics rule acid gas standard is more stringent than the proposed standard the actu al costs and benefits of the proposed amendments would be negligible.