1 

## FGD Performance Capability

Paper # 62

Chuck Dene

Electric Power Research Institute
, 3420 Hillview Avenue
, Palo Alto, CA 94304

Lesley A. Baker Washington Division of URS Corporation
, P.O. Box 5888
, Denver, CO 80217

Robert J. Keeth Washington Division of URS Corporation
, P.O. Box 5888
, Denver, CO 80217



### ABSTRACT

Utilities continue to specify FGD sy stem performance at increasing SO 2 removal efficiencies in response to permit requirements, local cons ent decrees and the potential need to install

CO 2 controls in the future. Environmental groups are also pressuring public utility commissions to push pulverized coal power plants to achieve emission levels similar to IGCC and NGCC. This paper summarizes FGD system design and operation upgrades that may be necessary to achieve 99+% SO 2 removal on a continuous basis, resulting in single digit SO 2 ppm emission rates. This paper will al so address several multi-pollutant emission control technologies that can ach ieve or show promise of ach ieving very high levels of SO 2 removal in addition to removal of NO

x and/or mercury.



### INTRODUCTION

The FGD market in the U.S. has been working at near capacity for the last few years. The regulatory environment for coal fired units has been more and more restrictive due to the perception of coal fired generati ng facilities as being dirty in comparison to gas fired plants and other renewable energy options. But coal s till plays an integral part in the generating mix in the U.S. due to ever increasing de mand for electricity. In response to public perception, the state and federal regulatory agencies continue to promulgate more restrictive legislation for coal fired plants, in so me cases requiring 98-99% reduction of SO 2 from new coal fired generating plants. The control of CO 2 generated by new and existing coal plants will further push the SO 2 reduction technologies to reduce their SO 2 emission levels to the single digits to help reduce the operating costs associated with some of the CO 2 removal systems. This paper provides a summary of the gains in FGD system performance that are now being offered in the U.S. utility market today, and describes some of the new technologies that may meet thes e requirements in the future.2 

### EXPERIMENTAL METHODS

Some of the major FGD systems suppliers serving the U.S. utility industry are listed below:

• Siemens-Wheelabrator

• Chiyoda

• Babcock & Wilcox

• Babcock Power

• Alstom

• Advatech/Mitsubishi

• Hitachi America

• Marsulex

In 2006, it was estimated that these companies ha d combined sales for more than 90% of the

wet FGD market in the United States.

URS Washington Division contac ted many of these major vendors of FGD equipment to discuss how they would plan to address the need for increased SO 2 reduction efficiency for continuous, long-term operation of their FGD syst ems. Specific installations were identified that have already achieved 98% to 99% removal on a continuous basis. System upgrades that allowed these high levels of pe rformance were also identifie d, including modifications that have been incorporated into recent installations , or could be used in existing FGD systems to

achieve outlet emissions that approach single digit ppm levels. The information from the conference calls and supplier visits was combined with material from previous EPRI reports, conference proceedings, and public domain literat ure to complete the documentation for this paper. All of the information and data from these sources were compiled and are presented in multiple EPRI reports that were published in 2007-2008.

Much of the discussion surrounding FGD system s focuses on wet systems as they have a distinct advantage over dry F GD systems in achieving 99+% SO 2 removal. In addition to FGD processes, the report contains process descriptions and development information on multi-pollutant processes that have the capability or show promise to achieve 99+% SO 2 removal. The discussion of these processes also includes their capabilities to remove NOx and mercury simultaneously.



### THE NEED FOR HIGHER SO 2 

### REMOVAL EFFICIENCIES

Power generation companies in the U.S. are f acing an increasingly stringent regulatory landscape, not only from the EPA, which ha s implemented CAIR and visibility (and attempted mercury) regulations in the last few years, but also from states, some of which

have established SO 2 emission limits lower than the federal emissions standards. Most power producers have conclude d that continuing public conc erns regarding the overall impacts of coal-fired power generation will result in even more stringent limits of NO

x , SO 2 ,3 mercury, and primary particulates in the future. In addition, public pressure on regulators to mandate consideration of alternatives to pulve rized coal (PC) fired generation because of their carbon footprint is on the ri se. In response to public con cern and pressure, future state and/or federal regulatory limits on SO 2 emissions could require FGD process to reduce SO 2 emission rates to single digit ppm levels.

One of the alternatives to PC fired generati on identified as the preferred method to achieve low emission rates by some environmental groups and regulatory agenci es is Integrated Gasification Combined Cycle (IGCC). Although ve ry few of these plants have been built, and many have recently been cancelled due to costs or regulatory uncertainty, they were becoming the emissions benchmark for coal-fir ed power generation technologies. As a result, utilities that have decide d that PC-fired plants are more viable to meet increasing load demand because they are more cost-effec tive than IGCC designs may face regulatory requirements for new and retrofit FGD systems that can reduce sulfur emission to levels achieved by IGCC. Advocates of Natural Gas Combined Cycle (NGCC) are going one step further and lobbying to have these systems re place coal-generated power outright because NGCC emits virtually no SO 2 and reduces green house gas (GHG) emissions.

Green house gas emissions, especially CO 2 , play a role in the globa l warming theory. Public

attention has driven federal a nd state regulators toward enactme nt of regulations to reduce

CO 2 emissions from new and existing power plan ts. New technologies are currently under development for pre- and post-combustion CO 2 reduction, as well as modifications to the combustion process itself. Some of the post-combustion CO 2 removal processes operate more efficiently and are more cost-effective when inlet SO 2 concentrations are maintained at very low levels.

All of these factors are lead ing utilities toward FGD processes that can achieve SO 2 emission levels that approach the single di git ppm level when firing all types of coal in PC plants. To meet the challenges for near-zero SO 2 emissions from PC plants, it is likely that FGD systems will have to incorporate design modifications to enhance SO 2 reduction, and operating practices will have to be modified to achieve the lower SO 2 outlet concentrations.



### ACHIEVING HIGHER SO 2 

### REMOVAL EFFICIENCIES

Utilities are already installing FGD system s with performance guarantees of 98+% SO 2 removal. These systems incorporate some of the latest absorb er design upgrades and modified operating conditions specified by th e FGD original equipment manufacturers (OEMs). However, it should be noted that these newest installations are designed to meet the contract performance test requirements while th e supplier staff are on the site, and typically the FGD system guarantees do not apply to the actual long-term operatin g performance. The operating procedures of plant staff will tend to be different from those used by the OEM staff, and changes in equipment performance as the system ages will tend to result in some reductions in the reduction efficiency capabilitie s of the FDG systems. Therefore, additional4 design upgrades may still be necessary to achieve continuous single digit SO 2 emission rates during long term operation.

Utilities will also need to c onsider adopting a different operating philosophy in order to

achieve 99+% SO 2 removal on a multi-day rolling average basis. To achieve these single digit SO 2 levels, the utilities will need to place greater emphasis on monitoring FGD performance including augmenting operati ng staff with engineering staff who can appropriately respond to changes in process chemistry due to system upsets, and paying greater attention to the accur acy and performance of process instrumentation and equipment maintenance. In essence, U.S. utilities w ould need to adopt the Japanese FGD operating philosophy, which includes hands-on involvement of operating engineers on a day to day basis, regular preventative maintenance to instruments and opera ting components, and consistent vigilance by operating staff to en sure that the desired process chemistry is maintained within specified ranges so that th e FGD performance can be maintained at it maximum capability.



### FGD System Design Modifications

The following sections focus on the latest st ate-of-the-art FGD system design innovations that are allowing these systems to achieve SO 2 reductions above 99% removal for high sulfur coals, and above 98.5% for low sulfur coals, resulting in SO 2 emission rates that approach the single digit ppm level. It is assumed that the reader has a basic understanding of the FGD systems, including design and reaction chemistry, offered by the major FGD vendors that were mentioned earlier. Only brief descriptio ns of each process are given here, focusing on those elements in the design and operation of th ese systems that will contribute to increased

SO 2 removal.

Chiyoda CT-121 Jet Bubbling Reactor (JBR)

The CT-121 FGD process was developed more than 20 years ago by the Chiyoda Corporation in Japan. They have since licensed the technology to engineering and

construction contractors thr oughout the world. The CT-121 process utilizes the same reaction chemistry as the wet Limestone with Forced Oxidation (LSFO) process.

The major difference between the CT-121 process and other LSFO FGD systems is the Jet Bubbling Reactor that serves as the SO 2 absorber, oxidizer, and r eaction crystallizer in one vessel. Flue gas from the boiler is cooled using a water quench and then is forced down through a series of sparger tubes positioned in a tube sheet above the reaction tank and immersed in the limestone/gypsum slurry (s ee Figure 1). The gas flows down through the tubes and then bubbles upward through the absorber slurry to form a froth layer. The froth provides a gas-liquid cont act zone to promote SO 2 dissolution into the reaction tank slurry.

Chiyoda has stated that the CT-121 process can achieve SO 2 removal of more than 99%. They have some limited experience on very high SO 2 inlet concentrations (4000 ppm), and5 have demonstrated that achieving 99+% rem oval on these units is re latively easy. Chiyoda has also provided guarantees for 99+% remova l on medium sulfur units, in particular the Shinko-Kobe Unit #2 with a design sulfur cont ent of 0.93% S on these two coal fired units (700 MW). At this facility, Chi yoda guarantees greater than 99% SO 2 reduction from an inlet flue gas stream containing 840 ppm SO 2 . The actual condition fo r the performance test was 320 ppm, and the Chiyoda system attained 99.8% SO 2 reduction under those conditions.

Figure 1: Chiyoda CT-121 Schema tic Flow Diagram (Round Vessel)

These high reduction efficiencies are achieved with an increas e in pressure drop across the absorber (added power consumption) and ope ration at a higher slurry pH. The CT-121 system operates at a higher pressure drop than an open spray tower design because the flue gas is bubbled through the slurry. This higher pr essure drop, and resultant increase in ID fan power consumption is offset by the fact that the CT-121 process does not use large recycle pumps to feed slurry to the absorber vessel. In order to achieve higher reduction efficiencies, the CT-121 absorber can be run with a higher pressure drop by increa sing the depth of the slurry through which the flue gas must flow to r each the top of the froth layer. This increases

the contact time of the SO 2 and the slurry, promoting greater removal, but it also increases the power consumption of the system.

The latest CT-121 installations have been ab le to reduce their pow er consumption 15% by increasing the pH of the slurry by 1.0, ther eby reducing the depth of the sparging tube immersion in the slurry. Chiyoda noted that high dissolved chloride concentrations can significantly suppress the pH in the absorber slurry, potentially reducing the SO 2 removal. This effect is due to the high ionic strengt h caused by the chloride concentration, which6 negatively impacts the transport of hydrogen ions to the surface of the limestone particles.

This H + ion transport is necessary for the limestone dissolution process. The CT-121 process is relatively unaffected by the chloride concen tration. In a typical spray tower design it would be necessary to increase the dissolved alkalinity to maintain SO 2 removal. This requires more un-dissolved limestone to be pres ent, increasing the limestone feed rate and potentially the scaling po tential of the slurry.

Mitsubishi/Advatech Double Co ntact Flow Scrubber (DCFS)

Mitsubishi Heavy Industries (M HI) has been providing emissi ons control systems for power plants for more than 40 years. The DCFS is the current state-of-the art for the MHI FGD technology and has been installed on power gene ration plants for the last 30 years. The Double Contact Flow Scrubber (DCFS) design is currently offered by MHI under the name

Advatech in the North American markets.

In low sulfur applications, flue gas enters the bottom of the absorber where the absorbent slurry is sprayed upward through large diameter (1.5”) nozzles creating a dense liquid-filled area. Slurry is supplied to a single spray head er by multiple large recy cle pumps. The flue gas contacts the slurry as it is sprayed out of the nozzle (co-cu rrent), and as the liquid falls back down towards the nozzles (counter-current). Therefore, the flue gas double contacts the limestone slurry. While the single tower design is mainly used for low sulfur applications up

to 700 MW and 97% SO 2 removal, efficiencies in excess of 99% have been maintained in high sulfur applications using a single DCFS module. A process flow diagram for this single tower arrangement is on the left in Figure 2.

For larger units and those requiring higher removal efficiencies, as well as some higher sulfur fuel applications, MHI can add a second tower section so that the doubl e-contact between the slurry and the flue gas occurs in two towers fed by a common reaction tank. The inlet tower

is referred to as the co-curre nt tower, and the outlet tower as the counter-current tower. A diagram of this dual tower application is s hown on the right in Figure 2. The dual tower configuration has demonstrated removal effi ciency capabilities of 99+%. One DCFS

installation on a 2% oil-fired boiler has c onsistently been able to reach 99.9% SO 2 reduction.

One recent design enhancement for the MHI DCFS Process is the inclusion of a chemical oxygen demand (COD)/sulfite monitoring system th at measures and controls the oxidation reduction potential (ORP) of the slurry. The ORP monitor mainta ins the slurry chemistry in the optimum range and indicates slurry conditions that coul d lead to aluminum fluoride blinding of the limestone particle s in the slurry, allowing the op erators to take action to stop the potential loss of reduction efficiency.

Medium sulfur fuel applications of the DC FS system have now demonstrated continuous operation at greater than 99% SO 2 removal efficiency. This commercial experience may translate to high efficiency commercial guarantee s in the future. This level of performance can be achieved using either the single or twin tower design depe nding upon other operating7 conditions at the plant. The DCFS design has achieved 99.9% efficiency with a single tower applied to a high inlet SO 2 flue gas stream (2,670 ppm on 150 MW unit). The outlet concentration was measured at 3 ppm. This perf ormance is stated to be possible due to the enhanced liquid-to-gas contact and high reagent activity in the 30 wt.% slurry. Similar performance was obtained at a second unit operating on a 2,600 ppm gas stream (99.6% SO 2 reduction with design guarantee at 98.3% on 100 MW unit).

Figure 2: MHI/Advatech Single and Dual Tower DCFS Diagram

Alstom Open Spray Tower and FLOWPAC Scrubber

The open spray tower was Alstom’s first FGD product offering with the first unit starting up in 1975. The absorbers generally have two or more spray levels, each with their own dedicated recycle pump. Design, selection and placement of spray nozzles at each spray level are critical to performa nce in high efficiency wet FGD systems. The spray nozzle configuration is determined by computer mode ling in order to achieve the desired gas to liquid contact and sc rubbing efficiency.

One of the innovations added to the original spray tower desi gn are wall rings. Wall rings are radial baffles that project inward from the spray tower wall and redirect any flue gas traveling up the tower wall back into the spra y zone. These baffles have been shown to improve SO 2 removal efficiency by 2-5% or alte rnatively to allow 10-20% reduction in liquid-to-gas ratio a nd achieve the same SO 2 removal as without baffles. Additional advances in spray tower design a nd operation include the following:

 Use of conservative design parameters in the areas of oxidation air stoichiometry and good air distribution has reduced the occurr ence of oxidation deficiencies in the latest designs.8  Maintaining 18-20% gypsum solids in the r ecycle slurry provides more surface for crystal growth in the slurry than is availa ble on the internal surfaces. This helps to reduce scaling on internal surf aces and increase system re liability. Nuclear density meters have demonstrated their ability to tightly control suspended solids density in the recycle slurry.

Alstom has guaranteed 98% removal for high effi ciency applications. Several of Alstom’s operating spray towers have achieved 99+% remova l for extended periods, while others have been able to achieve 2-3 pp m without the addition of any organic acid. The Navajo

installation has maintained an outlet emission rate of 0.04 lbs/MMBtu, which is approximately equivalent to 17 ppm SO 2

.

Alstom is using their commercial spray tower design at these high performance installations, incorporating wall rings and slurry spray patter ns to eliminate the potential for flue gas sneakage past the sprays. Trays or additives should not be required to achieve these high levels of continuous performance in the future. To maintain constant 99+% reduction, it will probably be necessary to add a nother spray level, and increase the L/G to the absorber by 20-

25%.

Alstom has recently developed a new scr ubber design -- the FLOWPAC turbulent bed absorber. The chemical reactions occurring in the FLOWPAC absorber are essentially identical to those in all other LSFO systems. The primary difference between this process and standard open spray tower design is the unique absorber vessel used in the FLOWPAC system. Alstom has a full-scale commercial system operating at a 340 MW high sulfur oilfired unit located at the Karlshamm power plan t in Sweden. This full scale unit achieves

98% SO 2 removal continuously when firing a 3.5 weight % sulfur oil. It is also reported to

have achieved 99.5% SO 2 removal when acetic acid is added to the slurry and the plant was burning 2.4% S fuel oil for a 3-month period.

The first FLOWPAC absorber consisted of an ab sorber tank with a circumferential sieve tray installed at the top of the tank. The flue gas enters the absorber be neath the sieve tray. Recycled slurry pours over the sieve tray, a nd the flue gas bubbles up through the slurry forming a highly turbulent froth layer. The froth layer provides a la rge surface area of reagent and flue gas. Slurry flows through re turn pipes downward from the outside of the sieve trays to the bottom of the absorber tank where oxidation air is introduced. The oxidation air acts as the lifting method recycling the slurry from the bottom to the top of the reaction tank, thereby eliminating the need fo r slurry recycle pumps. Figure 3 provides a flow diagram of the FLOWPAC process. Alst om is testing a recta ngular tank design on a pilot scale at the Karlshamn plant.

The FLOWPAC absorber can change the depth of the bubble layer above the sieve tray to follow the plant load or changes in inlet SO 2 concentration. This ability to change the depth above the sieve tray also provides an i nherent capability to achieve higher SO 2 reduction9 efficiencies, with the 99+% capability already possible and previously demonstrated. This increase in slurry depth comes w ith a higher absorber pressure drop.

Figure 3: Alstom FLOWPAC Turbulent Bed Absorber

Alstom has recently begun to actively mark et the FLOWPAC absorber design around the world, and has introduced the concept to the U. S. utility market. To-date, there are no

FLOWPAC installations or sales in the U.S. Ho wever, two have been sold overseas – one in Lithuania (3 x 150 MW) and one in Denmark (1 x 150 MW). These units are scheduled for startup in 2008 and 2009, respectively.

Babcock & Wilcox Wet Lime and Limest one Forced Oxidation Tray Tower

B&W has supplied FGD systems to the U.S. utility industry for decades. Their original focus was on the use of lime reagents in a tray tower design. Recent experience includes many installations of LSFO sy stems, again using a combination of trays and an open spray tower. B&W has also developed an oxidation systems for lime FGD systems, allowing the process to produce a gypsum product instead of a sulfite product that must be mixed with lime and flyash before disposal in a landfill. The t ypical B&W absorber uses a perforated tray and two absorber spray levels. The two spray levels include one under and one above the tray.

The hot flue gas enters the absorbers and is co oled to saturation by absorber slurry sprayed from the spray level under the tray, as well as th e slurry falling from the tray. The saturated flue gas flows through the absorber tray, which distributes the flue gas and slurry from the upper spray level across the abso rber cross-section. As th e gas passes through the tray perforations the increased gas velocity gene rates energetic bubbling thereby assuring liquidRaw Gas

Absorbent

slurry

Compressed
air Clean gas Demister10 gas contact. The flue gas then passes thr ough the upper absorber spra y zone, where absorber slurry spraying countercurrent to the flue gas flow completes sulfur dioxide removal.

 Tests conducted on a LSFO FGD system operating at a coal-fired power plant showed that addition of a second perforated tray and operation at a higher L/G ratio

increased the SO 2 removal from 90% to 98% at sligh tly lower lime stoichiometry.

 In a second test at the same installation, a ddition of the second perforated tray and increasing the pH by 0.5 increased the SO 2 removal from 90% to 98%.

As previously mentioned, B&W’s lime system s may warrant renewed interest, especially since magnesium enhanced lime (MEL) can achieve the same SO 2 removal efficiencies as LSFO systems, but at much lower L/G ratios. Based on medium sulfur Appalachian coal, the B&W LSFO system was able to achieve 98% removal at an L/G ratio of 130, whereas MEL

was able to achieve 98% removal at an L/G rati o of 40. When using the lime reagent, further increases in the recycle rate could lead to a system capable of 99+% SO 2 reduction. There are 30 MEL installations in the U.S. ranging in size from 80 MW to 1400 MW. The new MEL oxidized process is used at seven of the units. This process allows for the SO 2 reaction products to be oxidized from calcium sulfite to calcium sulfate.

Babcock Power

Babcock Power relies primarily on an open spra y tower design using bi-directional sprays (slurry sprays upward and downward with respect to the flue gas flow). The tower has wall baffles to mitigate the chance of internal flue gas bypass. The geometry of each spray level varies and the direction of the spray from the spray nozzles is also designed to mitigate the chance of internal flue gas bypass. This LSFO process has the same process chemistry as the other LSFO processes. The following are recen t design modifications and/or enhancements to the Babcock Power wet FGD process technology:

 The absorber inlet is optimized to provide the best possible gas flow distribution – they no longer use a tangentia l gas inlet and the gas velo city through the scrubber has been increased by more than 20% to redu ce the capital cost while improving the gasliquid contact efficiency. This is offset by an increase in the pressure drop across the

absorber.

 Babcock Power employs CFD modeling to optimize the design of their FGD absorbers. This modeling resulted in cha nges to the location of and the number of nozzles per spray levels in their current wet absorber designs. The nozzle design has also been optimized, using dual-direction noz zles that can spray both co-current and counter-current to the direction of the ga s flow through the absorber vessel. These nozzles produce small droplets that incr ease the number of droplet collisions, producing additional spray pattern coverage. A staggered spray patt ern is also used.

 Nozzles are installed along th e walls of the absorber vesse l to spray countercurrent to the gas flow and minimize the potential for gas sneakage (wall effects) past the spray pattern. High spray flows along the absorber walls help to increase overall collection11 efficiency. Wall rings are also used to re duce the potential for ga s slippage past the

spray zones.

 Babcock Power also offers a dual loop design for very high efficiency or high sulfur applications while reducing the overall power consumption.

Babcock Power stated that in order to achieve the 99+% reduction efficiency, it is likely that it could be met by the addition of another spray level with its associated recycle pump. The L/G increase would correspond to the increase in pumping capacity. No internal packing, trays or additives should be necessary. Babcock is currently testing these design modifications to confirm single digit performance capability, to enable them to offer this level of performance commercially in the future.

Siemens-Wheelabrator

The Siemens-Wheelabrator (Siemens) FGD absorb er design comes in various configurations, ranging from a typical open spray tower to the use of a sieve tr ay and spray headers. They have supplied systems based on lime and limestone reagents, and provided recent installations with perf ormance guarantees up to 98% achieving outlet SO 2 emission rates of 20-25 ppm. Siemens did not provide any additional input regardi ng their future plans to meet the high efficiency FGD market at this time.



### Alternate FGD Technologies

Other methods have been proposed to increase SO 2 reduction efficiency across the FGD system. Some of these options are discussed in the following material.

Dry Injection of Trona

O’Brien and Gere, using trona supplied by FM C and Solvay, offers the trona injection technology for both SO 2 and SO 3 removal from coal-fired fl ue gas. Although these dry injection systems are not nece ssarily capable of achieving the 99+% reduction efficiency targeted in this analysis, they could provide some trim to the SO 2 inlet concentrations entering the wet FGD systems, thereby reduci ng the load on the scrubber and possibly its

outlet emissions concentration. Reduction ra tes of 40-90% have been demonstrated in previous tests, with the most economical reduc tion efficiency falling in a range of 50-60%.

Recent advancements include the use of mille d trona down to 15 micr on particle size to improve reagent utilization rates, and injection at higher gas temperatures in front of the air preheater to provide th e better performance.

Dynawave/ReverseJet Scrubber

Monsanto EnviroChem (now MECS) offers th e Dynawave/Reverse Jet Scrubber technology for electric utility applications. This technol ogy has seen most development and application

for removal of SO 2 from sulfur recovery units (SRUs) operating in refineries, achieving 99.8% reductions. However, the inlet concentrations of SO 2 for these units are very high,12 and the technology has not been applied to a coal -fired boiler in the U. S. to-date. Pilot testing has demonstrated the system’s capability to achieve less than 6 ppm SO 2 . The process relies on a revers e jet scrubber design; SO 2 is captured by contacting the flue gas stream with an alkaline reagent in a froth zone region of intense turbulence with substantial back-mixing and a high rate of liquid surface renewal. This froth zone is generated in an

inlet duct to the absorber where slurry is injected into th e gas pass counter-current to the gas flow. These fountains provide intimate gas-liqui d contact. The momentum of the gas causes the liquid to spread out and form a standing wave at the point wh ere the liquid and gas

momentums are balanced. Turbul ent films of liquid occlude and envelop the particulate or gaseous contaminants, while also providing the gas-liquid contacting necessary for gas quenching and acid gas absorption.

Until 1987, this technology was confidential a nd applied only within DuPont. In 1987, MECS realized the applicability of the froth scrubbing techno logy for FGD applications, and entered into a licensing agreement with DuP ont. Since then, MECS has built more than 300 DynaWave® systems for variou s industries around the world.



### Multi-Pollutant Systems

The following material provides brief descri ptions of multi-pollutant processes that simultaneously remove SO 2 , NOx, and mercury (Hg). These pr ocesses have the potential to remove high levels of SO 2 and consequently are included in this report. Some of the processes have commercial-scale experience overs eas, but most are only at the demonstration stage. These processes are of in terest because of the benefit of being able to remove several pollutants, but it may be difficult for utilities to justify selection of one of these processes until they gain more extensive commercial experience.

Powerspan ECOTM and ECO 2 TM

Powerspan’s ECO TM process is designed for installation downstream of an existing particulate collection device. The process util izes a dielectric barrier discharge reactor to oxidize pollutants in the flue gas stream, followed by a wet ammonia scrubber and wet ESP for removal of oxidized pollutants and byproduc ts. The technology produces a saleable

ammonium sulfate fertilizer byproduct. A process flow di agram is shown in Figure 4.

The ECO TM technology was pilot tested on a 1-MW e quivalent slipstream of FirstEnergy’s R.E. Burger Plant in southern Ohio for four years and followed by the installation of a 50

MW commercial demonstration unit at the same site. Emission results from the pilot tests

and the commercial scale demonstration have shown similar performance, achieving 98%

SO 2 removal, 90% NOx removal, 85% Hg removal, and less than 0.01 lb/MMBtu emissions of fine particulate. Higher SO 2 reduction efficiencies appear to be possible given the results of short term testing. Powerspan has entered into agreements to construct additional full

scale installations in Ohio and as part of an ECO 2 installation in North Dakota.13 Since the possible need for power plants to capture CO 2 is one factor driving higher SO 2 removal efficiencies, it is wo rth mentioning Powerspan’s ECO 2 TM Process, which is under development to absorb CO 2 from power plant flue gas. The ECO 2 TM process utilizes an aqueous solution of ammonia to absorb CO 2 from the flue gas. The system is designed to be installed downstream, and work in conjunction with, the ECO TM technology. The CO 2 is later released for sequestrati on, while the ammonia is recycl ed back to the system to minimize operating costs.

Figure 4: ECOTM Process Flow Diagram

Powerspan and the DOE’s National Energy T echnology Laboratory (NETL) are working under a three-year cooperative research a nd development agreement (CRADA) to conduct

tests on ECO 2 TM . Initial results indicate up to 90% CO 2 removal associated with the injection of aqua ammonia. Current plans are to eventu ally run a pilot test on a power plant near the end of the CRADA, at which point the process design and cost estimates will be finalized. Preliminary cost estimates predict that ECO 2 TM will cost less than half of the current CO 2 removal technologies that are commercially in use.

J-Power ReACT

The ReACT process utilizes a moving bed of activ ated coke (AC) with ammonia injection to simultaneously remove SO 2 , NOx, and mercury from the flue gas. Spent activated coke from the adsorption process is regenerated a nd recycled back to the adsorber, while SO 2 rich gas is sent to a byproduct recovery unit and pro cessed into a saleable sulfuric acid or gypsum14 byproduct. The ReACT system is currently being marketed worldwide by J-POWER EnTech Inc. J-Power, formerly known as Mits ui Electric Power Development Company, is a Japanese utility with 67 plants and 16,000 MW of capacity, approximately half of which is

coal fired.

The activated coke process was initially developed in Germany and Japan by Bergbau Forschung (BF) and licensed to Mitsui Mining Company. J-POWER has recently acquired the patents for the Mitsui-BF process and established J-POWER EnTech Inc. to market

ReACT worldwide.

The ReACT technology has been installed on 14 commercial units to date, including four coal-fired utility boilers a nd other industrial flue gas a pplications. All commercial installations of the technology are located abroad, w ith the majority locat ed in Japan. The technology has been demonstrated successfully on large utility boilers, with a 350 MW installation in operation at J-Power’s Takehara Unit #2 since 1995, and a 600 MW installation in operation at Isogo #1 since 2002. J-POWER is currently constructing another 600 MW unit at the same site, Isogo #2, sche duled for startup in July 2009. Figure 5 contains a simplified process flow diagram for the ReACT process.

Figure 5: ReACT Simplifie d Process Flow Diagram

Flue Gas fro m Existing ESP/FF

Adsorptio n
Reactor

Regeneratio n
Tower Flue Gas

to Stack

Coke Fines (to sale/disposal)

Byproduct Processing

Plant Sulfuric

Acid Byproduct

Make-up

Activated

Coke Silo Regen.

Gas

Furnace N atural

Gas Ammonia

Commercial installations located in Ja pan and Germany operate at 90-99% SO 2 removal,

with SO 2 inlet concentrations as high as 1300 ppm SO 2 . NOx removal at existing installations ranges from 50-80% on coal-fired units, but is high ly dependant on coal sulfur content. Sulfur dioxide in the flue gas reac ts readily with injected ammonia, limiting the

amount of NOx removal that can occur at an in jection rate that lim its ammonia slip. J-15 POWER EnTech reports ammonia in jection into the regenerator is necessary if more than 50% NOx removal is required under higher SO 2 concentrations. However, recent findings

indicate that NOx removal re actions from reducing compounds on the surface of activated carbon allow removal of >50% NOx for gas streams with higher SO 2 concentrations. Greater than 90% mercury removal has been demons trated at the 600 MW Isogo #1 installation.

At this point, the ReACT technology has not been demonstrated on high-sulfur coal applications. To simulate U.S. flue gas conditions, J-POWER has performed slipstream testing at Isogo #1 with sulfur content up to 2,000 ppm. Performance tests were completed at

various conditions in order to optimize the design. J-POWER En Tech expects that there will be some modifications to the system design to adapt to flue gas from Eastern U.S. coals. They recently completed a slipstream test of th e ReACT system at a utility site in Nevada.

The ReACT technology is highly sensitive to coal sulfur content. The system was initially designed for low-sulfur (<1300 ppm) coals, and has not been optimized for operation with higher sulfur contents at this point. For high sulfur concentr ations, the amount of activated

coke fed to the adsorber increases substantia lly due to the need for more contact area to

remove SO 2 from the flue gas. This results in the need for additional adsorber and regenerator modules, and supplementary solid s conveying equipment. Additionally, the amount of sulfuric acid byproduct increases with the amount of SO 2 removed, resulting in increased sulfuric acid producti on plant costs. Demonstrated SO 2 removal efficiency has approached 99% in some low sulfur coal commercial installations.

Airborne

The Airborne ProcessTM uses a sodium bi carbonate scrubbing technology combined with post-scrubbing oxidants to remove sulfur dioxide (SO 2 ), sulfur trioxide (SO 3 ), nitrous oxide (NO

x ), and mercury (Hg) from co mbustion flue gases, while pr oducing a saleable fertilizer byproduct. Additionally, the process removes other heavy metals and toxics release inventory substances, su ch as sulfuric acid (H 2 SO 4 ), hydrochloric acid (HCl), and hydrofluoric (HF) acid. A flow diagram of the process is provided in Figure 6.

Flue gas desulfurization usi ng sodium carbonate or bicar bonate has been previously identified as a highly effective process; there are over 3,200 MW of sodium scrubbing experience that has been in operation for over 25 years. However, sodium reagent costs are often economically prohibitiv e, and the sodium sulfite byproduct can pose a disposal problem. Sodium scrubbing has been in operatio n at PacifiCorp’s Jim Bridger Power Plant, Naughton Station in Wyoming, and at Nevada Power’s Gardner Stati on. Sodium scrubbing at these units is made economical by use of a waste product sodium material from a manufacturing process in Wyoming.

Airborne Clean Energy (ACE) has developed a process where the sodium sulfite byproduct can be used to regenerate sodium bicarbonate reagent, while simultaneously producing an16 agricultural grade fertilizer. ACE is offering th is technology in combination with oxidants to achieve additional NOx and Hg removal.

Figure 6: Airborne Simplif ied Process Flow Diagram

The regeneration component of the Airborne ProcessTM was successfully demonstrated at

Airborne’s commercial sodium sulfate mine in Ormiston, Saskatchewan, Canada. The 18 ton/day demonstration plant was initially built w ith the intention of upgrading sodium sulfate to commercial-grade sodium bicarbonate for sale. The demonstration plant at Ormiston produced a 98%+ sodium bicarbonate product a nd 99%+ ammonium sulfate from a sodium

sulfate feed stream. Both sodium bicarbonate and ammonium sulfate were sold from the pilot plant.

The first demonstration of the integrated technology was installed at LG&E’s Ghent Generating Station located in Ca rroll County, Kentucky. As a part of the DOE’s Clean Coal Power Initiative, the technology was installed on a 5 MW equi valent slipstream of Unit 2, and tested between January and July 2003. The tests demonstrated effective operation of the system including the reagent regeneration ste p. According to data provided by the vendor,

the demonstration unit achieved 99.9% SO 2 removal on a consistent basis. NOx removal was approximately 40% during normal operation, an d increased up to 90% removal with the

addition of an oxidant. Additional NOx remo val could be obtained by the reduction of sodium bicarbonate particle size. Mercury re moval during operation of the demonstration facility peaked at 60-80% removal.17 A commercial scale demonstration at the 300 MW Mustang Generating Station near Milan, NM was halted when Peabody Energy, HPD LLC was unable to secure an air permit from the New Mexico Government. ACE is installing their system at Saskatchewan Minerals and they are in negotiations with other clients in North America and China.

CANSOLVTM Process

The CANSOLV system expands on the regenerable amine SO 2 removal process by including CO 2 removal in an integrated tower configuration. NOx and Hg removal capabilities, previously marketed, have been discontinued from CANSOLV’s product offerings. CANSOLV is focusing on marketing the SO 2 and CO 2 process configuration as shown in Figure 7. To better address the U. S. market, CANSOLV has teamed with Massey Energy and HG Engineering to form CANSOLV LLC to market their SO 2 and CO 2 process.

Figure 7: CANSOLV Simplifi ed Process Flow Diagram

Prescrubber SO2 Lean-Rich Exchanger SO2 Stripping
Column Electrolysis Salt

Removal SO2 Absorption

Water

Wash Flue Gas

To Stack

Existing ESP/FF Steam

Condensate SO2 to Sulfuric

Acid Production

The CANSOLV System was initially developed as a SO 2 scrubbing technology for industrial gas streams. CANSOLV’s SO 2 system is currently operational at seven different commercial installations, with two more scheduled for startup at th e end of 2007. Of the nine installations, four are in the U.S., two in Canada, and the others overseas. All of the installations operating or under c onstruction are either at smelte rs or petrochemical plants.

The inlet SO 2 concentrations at thes e installations range from 800 ppmv to 11 volume % sulfur. The largest of these installations removes ~97% SO 2 from a fluid catalytic cracking unit (FCCU) unit flue gas stream equivalent to 175 MW. At an acid gas installation, SO 2 is18 reduced from 3,000 ppmv to 15 ppmv in the outle t flue gas (99.5 % removal). Three of the installations have been oper ating since 2002 and four have been operating since 2005/2006.

CANSOLV’s SO 2 /NOx and CO 2 technologies were tested at p ilot-scale at the Saskatchewan Power Poplar River station in 2006. These tests showed positive results for the CO 2 system, and less interesting results for the NOx and Hg process. As a result, CANSOLV has currently discontinued NOx control from its co mmercial offerings, but is actively pursuing

CO 2 control. They were competing for a large-scale CO 2 capture system in Norway.

Other Developing Multi-Pollutant Processes

The following developing technol ogies are targeting 99% SO 2 removal efficiency or higher: ISCA, Lextran, Consummator, Green Coal, E nvirolution, Flue-Ace, PEA, EnviroScrub, and the IPR system. All of these systems are proceeding through initial stages of commercial development.



### COST IMPACTS

It should be noted that the cost estimates provided herein are termed rough-order-ofmagnitude (ROM = ± 30% accuracy) and are dependent upon the various underlying assumptions, inclusions and exclus ions utilized in developing th em. Actual project costs will differ, and can be significantly affected by mark et pressures, other changes in the external environment, and the manner in which the project is implemented. Estimate accuracy ranges are only projections based upon cost estimating methods and are not a guarantee of actual project costs. The base case costs are gene ric and it should be unders tood that site-specific issues might result in wide variatio ns in cost for these technologies.



### Increased SO 2 

### Removal

An EPRI study completed in 2006 iden tified the incremental cost of SO 2 removal for one

case based on the use of a wet limestone w ith forced oxidation FGD system (LSFO) in a spray tower absorber vessel. The syst em was installed on one 500 MW unit burning Appalachian coal (Pittsburgh # 8 coal with HHV of about 13,400 Btu/lb and 2.1 wt. % sulfur). Figure 8 provides the incremental cost of this LSFO case as the SO 2 removal

increases from 90% to 99%.

From this figure, it is appare nt that the incremental cost increases moderately from 92% to 97%, and dramatically rises from 97% to 99%. To achieve these removal rates, the L/G ratio was increased for each percentage point increase in SO 2 removal in this scenario. The impacts of increasing the L/G ratio include the following: need to purchase larger absorber circulation piping, more spray nozzles, larger an d/or additional absorber circulation pumps,

and an increase in the flue gas-side pressure drop resul ting in increased ID fan power consumption, and repositioning of the spray header to accommodate the new spry pattern at

the increased flow rates.19 Figure 8: Incremental Cost of Increasing SO2 Control

Incremental Cost of SO2 Control for LSFO, Pitts #8 Coal - SI Units

$0 $500 $1,000 $1,500 $2,000 $2,500 $3,000

0.91 0.92 0.93 0.94 0.95 0.96 0.97 0.98 0.99 1

SO2 Removal, %Levelized Control Cost of LSFO System,$/Incremental tonne SO2 Removed (Dec-2007$) BASIS/DEFINITIONS:

1. Incremental Cost in $/tonne SO 2 is Difference in Annual Cost divided by Annual

Difference in SO 2 Removed.

2. Levelized Costs Include TCR and All O&M Costs.

3. NOTE: SO 2 Removal is Based on Design/ Performance Conditions.

4. 90% SO 2 Removal is Base Case.

Low End of

Range



### Incremental Cost Impact of SO 2 

### and CO 2 

### Removal for Increasing FGD Removal Efficiency

Although the bulk of this paper covers high efficiency SO 2 removal, the looming possibility of regulations requiring fossil fuel -fired power plants to reduce CO 2 emissions is relevant to

the discussion. Some CO 2 removal processes will dire ctly impact the design and performance required from any FGD system operating upstream due to the low inlet SO 2 concentration sometimes required by the CO 2 reduction system. In many cases, sulfur dioxide needs to be in the low ppm range so that the CO 2 removal processes can be a costeffective candidate for installati on at a PC-fired power plant. An amine based system, which is widely used in the gas pr ocessing industry to remove CO 2 from gas streams, is one available technology option for PC fired utilities to capture CO 2 from their flue gas streams. Amine based systems require very low inlet SO 2 concentrations, mainly to minimize the buildup of heat stable salts in the amine sc rubbing loop. A thermal reclaimer is commonly included with an amine scrubbing system to remove these heat stable salts. This regeneration step requires energy, produces a waste product, and results in an increase in the amine degradation/makeup rate.

An analysis was performed to examine the le velized cost for a PC power plant firing an Appalachian coal (2.6 wt% sulfur) with a LSFO FGD step and CO 2 removal using an MEA (monoethanolamine) system. The plant size was assumed to be 500 MW, gross, excluding the power requirement for CO 2 and SO 2 removal systems. The levelized costs are presented in dollars per tonne of CO 2 removed.20 The analysis examined the incremental cost for removing additional SO 2 in increments from 90% to 99% for the LSFO process. This incl uded the incremental capit al and operating costs associated with the FGD system at various co ntrol efficiencies, as well as the incremental operating costs for the amine scrubbing system as they related to variat ions in the inlet SO 2 concentrations. These costs are primarily rela ted to the operation of the thermal reclaimer including variations in steam us age, amine losses, and waste generation rates. All of these operating costs typically increase as the inlet SO 2 concentration increases.

The correlations for the increase in MEA cons umption and increased reclaimer duty were taken from Simisky (1986). The cost for make up of the MEA was assumed to be $2.11/lb. The steam cost was assumed to be $3.86/1000 lb and the amine waste disposal cost was based on $0.19/gallon. The results shown in Figure 9 demonstrate the impact that SO 2 inlet

concentration has on the incremental leveli zed cost for the sum of the FGD and CO 2 removal systems. It should be noted that the analysis in Figure 9 does not include capital costs for the

CO 2 capture process nor does it includ e capital and operating costs for CO 2 sequestration.

Figure 9: Incremental Cost of SO 2 Control for LSFO Plus Incremental Amine System

Cost for CO 2 Removal Based on Amine Inlet SO 2 , Appalachian Coal (2.6 wt% S)

$0 $10 $20 $30 $40 $50 $60 $70

0 20 40 60 80 100 120 140 160
Inlet SO2 Concentration to Amine System, ppmvIncremental Levelized Cost, $/tonne CO2 Removed(Jan-2008 $) 92%

95%

97%

98%

99% % = SO2 removal percentage

Notes: 1. Incremental levelized cost is the difference starting at 90% SO2 removal then moving in increments up to 99% along with 90% removal of CO2 from the amine system. 2. The incremental levelized cost for the amine system is that associated with the reclaimer (steam, amine loss, & waste generation) for higher inlet SO2 concentrations.

3. The incremental levelized cost of the additional sulfur

removal inclues incremental TCR and O&M Costs for LSFO. 3. Cost in $/tonne CO2 is Levelized Annual Cost divided by

A nnual tonnes CO2 Removed.21 It is clear that the lowest inlet SO 2 concentration to the amine unit will result in the lowest

additional cost for CO 2 removal. The cost for amine losse s is the largest contributor to the increase in levelized cost, followed by the a dditional energy cost associated with the steam requirement for thermal regeneration. Although the inlet SO 2 concentration for the bituminous case is above single digit ppm leve ls, the evaluation emphasizes the need for FGD technologies to be able to maintain 99+% SO 2 removal for the sake of operating a

downstream CO 2 removal system.



### SUMMARY

In the foreseeable future it is possible that el ectric utilities may be required to reduce their

SO 2 emissions by 99+% due to the current regu latory environment and public pressure on regulatory agencies to control CO 2 emissions in the future. Many of the major FGD suppliers in the U.S. have demonstrated SO 2 removal efficiencies in the 98% - 99% range with only limited modifications to their absorb er design and operating conditions. Several of the design modifications that the FGD vendors are employing to achieve these results include: installation of wall baffles or rings; addition of trays and spray levels; use of CFD modeling to improve the inlet gas distribution, spray nozzle co nfiguration and slurry spray patterns to improve gas to liquid contact and lim it the amount of gas sneakage. In a number of cases it may be necessary to use spare reci rculation pumps and spray headers to increase liquid to gas (L/G) slurry recycle ra tios by 20-30% to achieve increased SO 2 removal. Other FGD absorber designs rely on adjusting some other operating characteristics such as increases in pH, increasing the froth layer contact depth, use of chemical additives, improved monitoring of process operating conditions, etc. To consistently maintain 99+% SO 2 removal on a multi-day rolling average basis, greater emphasis will need to be placed on monitoring and maintaining FGD performance. This may require the utility industry to consider adopting a different operating philosophy; one that includes more hands-on involvement of engineering staff day-to-day and greater attention to instrument and equipment maintenance.

Increased SO 2 removal does not come without a cost. The incremental cost per ton of SO 2 removed above 98% is exponential for a trad itional LSFO system. If regulation of CO 2 emissions is enacted, then not removing enough SO 2 will only add to a utility’s operating

costs. An amine based CO 2 removal process, one of the few commercially proven and

available CO 2 removal processes at present, is mo re cost effective at lower inlet SO 2 concentrations due to th e negative impact that SO 2 has on the operational chemistry of the

process.

Some of the latest process developments in the area of multi-pollutant control technologies may result in cost-effective alternatives that achieve high SO 2 removal in conjunction with removal of NOx and mercury. Multi-pollutant technologies such as ECOTM, ReACT, Airborne, and CANSOLVTM show promise of achieving 99+% SO 2 removal and continue to gain commercial experience, improve perfor mance, and achieve higher reliability. As22 federal, state and local agencies demand additional reduction in SO 2 , NOx and mercury emissions, these integrated emission control systems may see more consideration due to operating advantages and cost competitive perf ormance when compared to installation of separate control systems for each of the respective pollutants.



### REFERENCES

1. Incremental Cost of Selected Emission C ontrol Systems for PC Plants, EPRI EPP6623/C3368, September 2006

2. State of the Art Emissions Control Systems, EPRI Report, 2006

3. Alain, B., et. al. “New Scrubber Design for Wet FGD Applications”, Power-Gen Europe 2004.

4. Simisky, P.L. “The Recovery of CO 2 From Flue Gases”. American Institute of Chemical Engineers National Spring Meeting. New Orleans, Louisiana. April, 1986.

5. Judd, Bill. Dow. Personnel corresponde nce. Calgary, Canada. November 2007.

6. Testimony by Professor Gregory J. McRae of Massachusetts Institute of Technology on Clean Coal Technology – Science, T echnology, and Innovation, United States Senate Committee on Commerce, Scien ce, and Transportation, April 27, 2007

7. Tracking New Coal-Fired Power Plants, Coal’s Resurgence in Electric Power Generation, DOE, National Energy Technology Laboratory, May 1, 2007