MEMORANDUM

From: The Office of Air Qu ality Planning and Standards U.S. Environmental Protection Agency

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

Date: March, 2011

Subject: Control of SO 2 Emissions

Introduction

During combustion, the organic and pyr etic sulfur in coal predominat ely oxidizes to sulfer dioxide (SO 2 ) gas. A small portion of the SO 2 further oxidizes 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 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 cont rol (sorbent inje ction) and post-combustion flue gas desulfurization (FGD). In-situ control is used effectively in flui dized bed (FB) boilers, and may be used in a pulverized coal (PC) bo iler by dry injection of sorbents. Post-combustion controls applicable to EGUs include wet scrubbing or spray dryer absorber (SDA) tec hnology. Pre-combustion control

limits the sulfur content of the fuel. Add-on control technol ogies rely on either absorption or adsorption processes that react SO 2 with lime, limestone, or another alkaline material to form an aqueous or solid sulfur by-product.

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% reduction of the potential emissions on a 30-day rolling average basis. The standard for owners/ope rators of reconstructed affected facilities is 1.4 lb/MWh, 0.15 lb/MMBtu heat input, or 95% redu ction in potential emissi ons. The standard for owners/operators of modified affected facilitie s is 0.15 lb/MMBtu or 90% 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 subpart Da SO 2 emissions standard for owner/ope rators 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 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

The following is a brief summary of some of the SO 2 control technologies, including propriety technologies. This summary is not intended to be a comprehensive list of av ailable technologies. The performance values given here are those that have been provided by the technology provider in publically available sources. Incl usion of a technology in this summa ry is not intended to be an endorsement of that technology by the US EPA the US Government

Coal gasificationThe gasification process breaks coal apart into its chemical constituents (typi cally a mixture of carbon monoxide, hydrogen, and other gaseous compounds) prio r to combustion. Sulfur in the product syngas is present as H 2 S and technologies such as Selexol, Rect isol and desulfurization sorbents can effectively reduce the concentration of H 2 S in the syngas stream prior to combustion in the downstream combustion turbine. Any residual H 2 S the syngas stream will be converted to SO 2 in the

combustion turbine. Gasificati on allows for the reduction of SO 2 emissions by over 99% and is the only pre-combustion technique that is a feasible st andalone NSPS control tec hnologies. The other precombustion approaches are incapable of mee ting the NSPS as a standalone approach.

In-situ SO 2 Control Technologies

Furnace Sorbent Injection (FSI) . Furnace Sorbent Injection is another once-through dry technology that utilizes dry lime or limest one as the reagent to absorb SO 2 . In the FSI technology, the reagent (e.g., finely crushed limestone) is in jected directly into the furnace a nd the reaction product is collected in the downstream particul ate 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. A potential reagent used in the spray dryer is a hydrat ed reaction byproduct recycled from th e 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. Fresh limestone is continuously fed to the bed to replace the 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-pr oduct (e.g., gypsum). Once-through ammonia- based FGD systems typically produce a liquid or solid fertiliz er byproduct. In regenerable technologies, the SO 2 is released from the sorbent during regeneration and processed to yiel d a potentially valuable by-product (e.g., sulfuric acid or elemental sulfur). The rege nerated 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 semi-dry 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 collectedby 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 fromapproximately 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 SO 2 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 al lows 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 containi ng the reagent on the surface of the filte r. 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 SO 2 removal efficiencies of new lime spray dr yer 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 SO 2 . The fluidization of the particles is accomplished by the vertical upward flow of flue gas through the reactor. The re agent 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 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 SO 2 absorption into the li quid and the reaction with the reagent. The byproducts of the sorption and reactio n are in a wet form upon leaving th e 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 SO 2 removal efficiencies of ne w alkali wet scrubbing systems are generally greater than 95%.

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 hasa 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. A common we t scrubber application utilizes limes tone 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 typi cally disposed of in a landfill.

Enhanced Wet Flue Gas Desulfurization. Enhanced wet scrubbers incl ude (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 ha s received little or no treatment). Buffering agents may reduce the opera ting costs by reducing the amount of liquid that needs to be recycled in the absorber tower. The buffering agents typically us ed are organic acids or

salts of these acids. Other devel opments in wet FGD pollu tion 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 desi gns that were developed to improve liquid-to-gas contact by forcing the flue gas to bubble through the slurr y. This is done by utilizing a gas sparger design rather than spraying the flue gas with slur ry. Another wet FGD liqui d-to-gas contact design application is the perforated pl ate scrubber. Yet another devel oped design includes bidirectional sprays and wall rings to be used within the wet FGD absorber tower in order to reduce SO 2 sneakage

over the conventional FGD. All these wet FGD desi gn technologies improve the liquid-to-gas contact while increasing pressure drop instead of increasi ng pumping requirements. Modern wet FGD designs

can achieve 98 to 99% SO 2 removal for medium to high sulf ur 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 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 multi-pollutant control technologies in vari ous stages of commercial development are available

to reduce SO 2 emissions. These include, but are not limited to, the Airborne Process TM , the APTECH CST process, the CEFCO process, Eco Power’s COMPLY 2000, the copper-oxide (CuO) process, Powerspan’s Electro Catalytic Oxidation (ECO®) pr ocess, the electron beam (E-Beam) process, the Indigo Multi Air Pollutant System (MAPSystem TM) process, the Nalco Mobotec technology, The NOXSO process, the Pahlman process tec hnology developed by Enviroscrub, ReACT TM , Skyonic’s SkyMine®, TOPSØE SNOX TM , and the SOx-NOx-Rox Box (SNRBTM) process. These technologies offer the potential for improved environmental pe rformance at lower costs than traditional technologies. This list is intended to merely illust rate 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.

SO 2 Control Performance30-day SO 2 emission rates were calculated by dividing th e 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 orgross output could not be determined for that operating hour. The reduction in potential SO 2 emissions was calculated by comparing the reported

SO 2 emissions during a 30-day period to the potential emissions for that same 30-day period. Potential

uncontrolled SO 2 emissions were calculated using monthly deliv ered fuel receipts and fuel quality data from the Energy Information Administration (EIA) fo rms EIA-923 (utility and nonutility coal data post 2007), EIA-423 (nonutility coal data prior to 2008), a nd FERC-423 (utility coal data prior to 2008), as applicable. For each operating day, the total potential uncontrolled SO 2 emissions were calculated by multiplying the uncontrolled SO 2 emissions rate for the applicable month as determined using the EIA data by the heat input for that day. For locations w ith 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 th e 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 combusti on turbines. Figures 1 shows the performance of the best performing facil ities in terms of percent reduction in potential SO 2 emissions.

Figure 1: SO 2 Emissions Performance Data

Facility Time Period Maximum 30-Day

SO 2 Emissions Rate (lb/MWh) Minimum 30-Day %

SO 2 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 facil ities, all of the listed facilities use wet limestone based scrubbers. HL Spurlock 3 and 4 are fluidi zed bed boilers that remove the majority of SO 2 using limestone injection into the boile r and then remove additional SO 2 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 Count y, and Mountaineer facilities. Based on the performance of these facilitie s, we have concluded that 97% reduction in potential SO 2 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 faciliti es are achieving a 98% reduction in potential SO 2 emissions we are not proposing this standard because it is based onrelatively short term data. Based on the variability in SO 2 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 facili ty 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 numer ical standard in conjunction with the percent reduction standard. To determine an appropriate alternate numerical st andard, we evaluated the performance of several recently constructed facilit ies in addition to the numerical standa rds for the facilities in Figure 1. Figure 2 shows the maximum 30-day average SO 2 emissions rate of facilities that commenced operation between 2005 and 2008, that are emitting at leve ls below the current NSPS, that are reducing potential SO 2 emissions by less than 97%, and that reported both SO 2 emissions and gross electric output data to CAMD.

Figure 2: SO 2 EMISSIONS PERFORMANCE DATA FOR NEW FACILITIES

Facility Time Period In Service

Date Maximum 30-Day SO 2 Emissions Rate (lb/MWh) Minimum 30-Day %

SO 2 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 facil ities burn lower sulfur subbituminous coals and use lime-based spray dyers. To provide the maximum em issions reduction, we concl uded that the alternate

numerical standard should be as stringent as the numerical rates ach ieved by the facilities used to determine the percent reducti on standard. If the alte rnate numerical standard were less stringent than the emissions rate achieved by the facilities used to determine th e maximum percent reduction, those facilities would not be requi red to achieve the maximum percent redu ction that has been demonstrated. In addition, the numerical standard shoul d account for variability in today’s SO 2 control technologies and provide sufficient compliance margin for owne rs/operators of new fa cilities 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 alte rnate numerical standard because it provides a comparable level of performance to the 97% reducti on requirement and satisfies the criteria mentioned

above. The numerical standard woul d require at least 80% reduction even from the lowest sulfur coals and would accommodate the use of spray dryer scrubbe rs for owner/operators of new facilities burning

coal with uncontrolled SO 2 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 su fficient flexibility such that an owne r/operator of an E GU could burn over 90% of the subbituminous coals presently being used in combination with a spray dryer. This technology choice provides owners/operators the flex ibility to minimize water use and associatedwaste water discharge, as well as reducing additional CO 2 that is chemically created as part of the SO 2 control device. Even though there is not necessa rily an overall GHG reduction from using a lime based instead of a limestone based scrubber, lime production facilities have relatively concentrated

CO 2 streams. Capture and storage of CO 2 at the lime manufacturing facil ity could potentially be easier since separation of the CO 2 would not be necessary, as is the case with an EGU exhaust gas. Owners/operators of new and reconstructed faci lities burning coals with higher uncontrolled SO 2 emissions could either use IGCC with a downstream process to control sulfur prior to combustion, fluidized bed combustion, or a wet SO 2 scrubbing system to comply with the standard. The proposed limit would allow the higher sulfur coals (uncontrolle d emissions of greater than approximately 3 lb

SO 2 /MMBtu) to demonstrate compliance with the 97% reduction requirement as an alternative to the

numerical limit.