## Twenty-Five Years of SCR Evolution: Implications For US Application And Operation

J. E. Cichanowicz Consultant 236 N. Santa Cruz Avenue, Suite #202 Los Gatos, CA 95030

L. J. Muzio Fossil Energy Research Corporation 23342-C South Pointe Drive Laguna Hills, CA 92653



### ABSTRACT

In the 25 years since the first commercial inst allations in Japan, SCR technology has evolved in response to changing application conditions. For example, present-day catalysts feature thinner walls, improved mass transfer and activity, and be tter poison resistance th an earlier generation products. Additionally, catalyst management stra tegies frequently utilize catalysts from suppliers and with geometry different from the original specification, to improve operation and minimize cost. Catalyst regeneration rather than replacement is playing a role. Reactor design and layout has evolved to adopt, where necessary, st atic mixers to promote contacting of reagent and flue gas. These features improve perfor mance and offer lower cost, but may increase the need for monitoring and diagnostic measurements.



### INTRODUCTION

By the year 2004, in excess of 100 GW of coal-fir ed capacity in the US may be equipped with SCR NO x control technology, to mitigate “seasonal” ozone production as mandated by Title I of the 1990 Clean Air Act Amendments (1) . The application of SCR in the US will have evolved from two prior generations of desi gn: the first commercial applications in Japa n in the late 1970s, and subsequent installations in Europe (predominantly Germany) in the mid-1980s. SCR process design basis and operating requirements ha ve significantly evolved from these prior generations, both simplifying and, in some ways, co mplicating the pending operations in the U.S. This paper reviews the key design and operationa l evolutions, and projects how future US operation may be affected.



### BACKGROUND AND HISTORY

Strict NO
x emission limits were implemented by the Japanese federal government as early as 1973. Local authorities mandated additional reductions, lead by Yokohoma City in 1980 (2)

. Regarding new generating units, Japan’s Electr ic Power Development Company (EPDC) was required to “cap’ the NO
x emissions from the two-unit Takehara Station to allow construction ofa third, coal-fired unit. These requirements prom pted early R&D and pilot investigations to evaluate SCR NO
x control to achieve at least 50-60% NO
x removal. Figure 1 presents a timeline of significant events regardi ng the development and commercialization of SCR technology.

Figure 1 . Timeline Of Key SCR Events

Subsequent to the approximately 20-30 pilot plan ts operated in Japan in the late 1970s (mostly on fuel oil and natural gas), se veral demonstrations of coal-f ired units were conducted. Among the first SCR demonstrations was the 175 MW Shimonoseki station of Chugoku Electric, treatment on 25% of flue gas from the Hokkai do Electric Tomato-Atsum a Station, and EPDC’s Takehara Station, where for the la tter parallel reactors compared catalyst from two suppliers. Both the Tomato-Atsuma and Takehara units employed hot-side ESPs , providing a low ash environment to the catalyst. NO
x removal from these units ra nged from 50-80%, with a 5-10 ppm residual NH 3 limit. Thus, early coal-fired expe rience was divided between high dust and low dust applications.

Significant experience with high du st SCR continued with several early applications in Germany in the mid-1980s, in response to the Government Ordinance For Large Boilers, adopted by thethen Federal Republic of Germany (3) . Neckarwerke’s Altbach/De iszeiu Unit 5 was reportedly the first coal-fired commercial unit in Germany on a dry-bottom boiler, and Knepper C the first “slag-tap” boiler application. NO
x removal performance in the German and European applications increased to genera lly 80%, with selected high NO
x -emitting units such as Knepper C achieving 90%. Experience in Germany also identified arsenic poisoning of catalysts through both pilot plant tests and fu ll-scale experience, and further demonstrated that control of residual NH 3 to 2-3 ppm (and not 5 ppm) was in most cas es required to mainta in ash utilization. In the US, the Haynes Station of the Los Angeles Department of Water And Power was the first utility SCR application, employing an in-duct design for natural gas firing. The first coal-fired applications for new plants (Carney’s Point) and retrofit (Merrimack Unit 2) followed in the 

## 1975 1980 1985 1990 1995 2000

20-30 pilot plants on oil, gas, and refinery gas

EPDC Takara Unit 1: 250 MW demo (80%, low dust ) Hokkaido Electric:
Tomato-Atsuma (1/4 x250 MW) FRG passes
Government
Ordinance for Large Boiler
Installations~ 100 ppm First German unit:
Neckarwerke
Altbach/Deizisau Unit 5 (420 MW)

Arsenic “Episode”
Witnessed in
Pilot Plants 1st U.S. Gas
Unit: LADWP Haynes 1st New U.S. Coal Unit: Carneys Point

1st Retrofit U.S. Coal
Unit: Merrimack Chugoku Electric: Shimoneski (175 MW, 50% New Madrid,
Paradise

1st Evidence of As Poisoning in the US (OUC/Stanton Unit 2) 

## 1975 1980 1985 1990 1995 2000

20-30 pilot plants on oil, gas, and refinery gas

EPDC Takara Unit 1: 250 MW demo (80%, low dust ) Hokkaido Electric:
Tomato-Atsuma (1/4 x250 MW) FRG passes
Government
Ordinance for Large Boiler
Installations~ 100 ppm First German unit:
Neckarwerke
Altbach/Deizisau Unit 5 (420 MW)

Arsenic “Episode”
Witnessed in
Pilot Plants 1st U.S. Gas
Unit: LADWP Haynes 1st New U.S. Coal Unit: Carneys Point

1st Retrofit U.S. Coal
Unit: Merrimack Chugoku Electric: Shimoneski (175 MW, 50% New Madrid,
Paradise

1st Evidence of As Poisoning in the US (OUC/Stanton Unit 2)early 1990s. Finally, arsenic poisoning was witn essed in the US at the Orlando Utilities Commission Stanton Unit 2 (4)

.



### EARLY UNIT DESIGN CHARACTERISTICS

Table 1 summarizes the key design variables for several early SCR applications in Japan and Germany. NO x reduction varied significantly, with removal efficiencies from 50% to approaching 90%, the latt er applied to high NO
x emitting units. The low sulfur level of coals fired in Japan minimized concern for SO 2 conversion, at least for some units. Also, limited experience with high dust appl ications had not identified th e true impact of residual NH 3 ; thus, control to 5 ppm (and at times 10 ppm) was allo wed for coal-fired app lications. Figure 2 illustrates the catalyst geometry employed at Tomato-Isaku and one Takehara reactor, which consisted of “pipes” with walls of 5 mm to avoid erosion. Conversion of SO 2 approached 2% for some of these designs, which was not problema tic for the early low su lfur content coals.

Table 1 . Early Commercial SCR Installations: Design Features

DESIGN VARIABLE EPDC/ Takehara (1980) Shimonoseki (1981) Neckarwerke/ Altbach (1985) Neckarwerke/ Walheim (1986) EVS/ Heilbronn (1985) High Dust/low Dust LD HD HD HD HD
Inlet NO
x (ppm) 300 500 300 750 325
NO
x Reduction (%) 80 50 66 88 80
Residual NH3 (ppm) 5 5 5 3 5
SO 2 Conv. (%) 1 1 <2 <2 <2 Space Velocity (1/h) 2300 3000 3340 1900 2850

Figure 2: Early Pipe-Shaped Catalyst Geometry

### COMPARISON TO DESIGNS FOR US APPLICATION

There are numerous design featur es of SCR process equipment wh ich distinguish the imminent US applications from predecessors. These incl ude (a) catalyst technolog y, (b) process conditions applied, (c) reactor layout, (d) r eagent injection equipment, (e) coal-fired experience base, (f) reagent type and handling systems, and (g) balan ce-of-plant activities. Items (a) through (e) will be addressed in some detail, with highlights noted for (f) and (g). Subsequent to this discussion, data describing long-term operati on and evaluation of a catalyst management strategy employing regeneration is presented.



### Catalyst

Possibly the most significant advances have b een achieved in catalyst technology, resulting in increased performance and lower production cost. Improvements to both catalyst geometry and composition were realized.

Geometry

The limited strength of extruded material, or the ability to bond catalytically active ingredients onto a substrate, dictated catal yst geometry for early designs. Accordingly, relatively thick extruded walls or coatings were necessary to pr ovide erosion resistance. Figure 2 depicted the pipe-shape geometry employed in several early applications, requiring a 5 mm thick wall to prevent erosion. Table 2 compares the geometri cal characteristics of several early catalyst products, showing how the decrease in wall thickness improved available surface area for extruded material. Most notable in Table 2 is the increase in surface area-to-volume ratio, which for some specific products is significant. Of exception are the physical ch aracteristics of platetype catalysts, which offer among the highest open area (e.g., lowest flue gas pressure drop) and have remained relatively constant to exploit th at important feature. Also of note is the introduction of ceramic fibers as substrate, o ffering significant surface ar ea of reaction per unit weight.

Table 2 . Evolution of Catalyst P hysical Properties: 1979 – 2001

Physical Characteristic Unit Geometry Pitch or Characteristic Dimension (mm) Wall Thickness (mm) Surface Area/Volume m2/m3 Open Area (%) Japan 1979 various pipe 30 5 ~200 ~60 Japan 1980 Shimonoseki grid 9.8 1.8 333 67 Japan 1984, 1895 Sakata, Yokosuka grid 7.4 1.4 438 66 Europe, 1985 Altbach-Deizshu grid 7.2 1.4 448 64 Europe, 1986 Knepper grid 7.4 1.1 460 73 Europe, 1989 Mehrum plate 6 <1 330 82 US, 1995 OUC plate 5.4 <1 368 84 New Madrid grid 9.2 0.83 383 83 US, 2000 various grid 7.4 0.83 480 79 US, 2001 various corrugated plate 10.6 (hyd dia) 1 390 78For some SCR applications, the higher specific surface area, smaller pitch catalysts are purposely not utilized, and instead the larger pitch, lower specific surface area designs are used to avoid ash plugging and deposition. In fact, a “cascading” ca talyst pitch (pitch size decreases with each catalyst layer in the direction of gas flow) is frequently used in many stations operating in Europe to manage ash deposition and plugging (5) . Although no SCR retrofit units in the US at present are using the cascading approach with initia l catalyst inventory, some adjustment of pitch to operating characteristics is anticipated with experience.

Composition

Catalyst composition changes have increased ac tivity while maintaining or reducing conversion of SO 2 to SO 3 , and provided resistance to arsenic pois oning. Specifically, catalyst suppliers have employed additives as well as improved manufact uring and processing techniques that influence the available surface area for reaction. The common TiO 2 -based catalysts also can employ molybdenum trioxide (MoO 3 ) and tungsten trioxide (WO 3 ), in addition to the key active ingredient, vanadium pentoxide (V 2 O 5 ). Perhaps the most significant consequence of the improved manufacturing process has been the in creased “porosity” of the catalyst – and the ability to offer high mass transfer and surface area for reaction – without compromise to erosion resistance.

The combination of higher surface area per volu me of catalyst and catalytic activity, coupled with catalyst management techniques, has pr obably reduced the ini tial volume of catalyst employed for a given application. Comparisons to early designs can be misleading as both NO
x removal targets and the initial catalyst guarant ee period have evolved. However, Table 2 data when compared to present space velocities for 90% NO
x removal and 2 ppm residual NH 3 suggest lower volume is currently applied. This improvement leaves less margin for design or operating errors or anomalies compared to the more conservative European applications. Consequently, operators will benefit from deta iled process monitoring to diagnose and detect performance trends as early as possible.



### Process Conditions

The selection of SCR “process conditions” – the distributi on of flue gas velocity, NH 3 /NO ratio, and the range of acceptable temperature that establish the operating environment for the catalyst - have evolved to suppor t present performance targets. There are several methods of specifying the distribution of velocity and NH 3 /NO ratio; this paper will utilize the standard deviation (SD) of the measurements.

Figure 3 illustrates the role of flue gas velocity and NH 3 /NO ratio SD on NO
x removal performance and residual NH 3 . These data represent a perfor mance calculation for an inlet NO
x content of 0.30 lbs/MBtu, employing a catalyst with space velocity of 3200 1/h, and grid-type catalyst of 7.4 mm pitch. Th e process calculations employ a random distribution of initial velocity and NH 3 /NO x ratio across the surface of a catalyst, characterized by varying levels of non-uniformity. At each locati on on the catalyst, the local NO
x reduction and NH 3 slip were calculated and the results integr ated over the surface. Uniform velocity enhances performance by providing uniform residence time across the ca talyst, insuring no “cells ” have inadequateFigure 3: Role of Maldistributions in Velocity and NH 3 /NO on SCR Performance

(a) Velocity Non-Uniformity Effects (NH 3 /NO x Non-Uniformity = 7%)

(b) NH 3 /NO x Non-Uniformity Effects (Velocity Non-Uniformity = 10%) 

### 0 2 4 6 8 10

80 85 90 95 100

dNOx, %NH3-slip, ppm Vel-Std. Dev. 6%

Vel-Std. Dev. 10%

Vel-Std. Dev. 15%

Vel-Std. Dev. 22%

Vel-Std. Dev. 34%



### 0 2 4 6 8 10

80 85 90 95 100

dNOx, %NH3-slip, ppm NH3/NOx-Std. Dev 2%

NH3/NOx-Std. Dev 4%

NH3/NOx-Std. Dev 5%

NH3/NOx-Std. Dev 6%

NH3/NOx-Std. Dev 9%reaction time. Equally important , zones of erosion-inducing hi gh velocity and deposit-inducing low velocity are minimized. Figure 3 shows th at improved velocity distribution increases performance, but the payback for achieving extr emely “flat” velocity profiles diminishes.

Figure 3 also shows the NH 3 /NO x uniformity is significantly more important than the velocity uniformity in providing for high NO
x removal. If any one “cell” of flue gas is deficient in either reactant (NH 3 or NO), then the reaction will not pro ceed to completion – regardless of the volume of catalyst that is utilized. Fi gure 3 also illustrates the criticality of NH 3 /NO x uniformity increases as NO
x reductions exceed 90%.

Most early generation designs in Japan and Eur ope are believed to feat ure distributions of velocity of a 15-20% SD, and of NH 3 /NO ratio of 6% or greater SD. The evolution to high performance systems requiring 90% NO
x removal at 2 ppm slip has reduced the velocity distribution modestly to perhaps 10-15% SD, but significantly for NH 3 /NO ratio. The specified SD for the latter is frequently less than 5%, a nd for some applications as low as 3%. As a consequence of these strict specifications, S CR process equipment and catalyst suppliers and owners have conducted aggressive modeling stud ies. Regarding physical “cold-flow” modeling, the scale of model, details of construction included in the simulation, and extent of measurements have significantly increased to sup port the high performance systems. The use of CFD has been integrated with physical flow mode ls to augment the evalua tion, particularly with the distribution of flue gas temperature.

One item that may become of concern is the abil ity to construct and install the arrangement of turning vanes, baffles, and flow rectifiers to the necessary accuracy as specified by the physical or CFD model. Construction tole rances of less than one inch ma y be problematic in actually achieving the flow distribution specified by the m odel. The challenge to operators of these systems may also be to insure the process cond itions, once delivered by the process supplier, are maintained. Finally, as will be discussed subseq uently, simply demonstrating that these strict process conditions are actually de livered by the process supplier ma y be a critical issue to SCR operators.



### Reactor Layout

Reactor layout can vary widel y, depending upon whether SCR is installed in a new plant, or retrofit to an existing unit.

Comparison of contemporary reacto r designs to early applications in Japan and Europe is limited for several reasons. Many early SCR retrofits in Japan were “low dust” applications that inherently required smaller cataly st and reactor volume, without the complexity of handling high dust loading. Many boilers in Germany employ to wer designs, allowing a more straightforward reactor (at least in terms of process conditions, if not structural steel) that was amenable to improved performance. The flue gas flow pa th for some tower boiler SCR retrofits could employ perhaps two “elbow” turns prior to the catalyst, which affords good flue gas handling practices. Certainly, not all Euro pean installations are represente d by this concept, and numerous challenging retrofits were undertak en and successfully implemented.Of note with US SCR applications is the potential for a larger fr action of flue gas to be bypassed around the economizer, to provide the operating temperature “floor ”, due to higher flue gas SO 3 content (from higher sulfur coals) . The relatively large volume of flue gas to be bypassed around the economizer over a wide load range can co mplicate mixing patterns. Figure 4 depicts a specific reactor and ductwork layout in which a re latively large volume of flue gas exiting the economizer bypass was problematic in preventing th e distribution of flue gas temperature and velocity to be simultaneously achieved. Th e diversion of flue gas around the economizer necessary to meet the temperatur e specification biased the flow field and significantly distorted the velocity profile. For example, at mid-lo ad the bypass dampers are only 10-20% open and the system must mix the small, low velocity flow diverted around the economizer with the larger bulk flow. Conversely, at low load the bypass da mpers are fully open, and the system must mix a large volume of large, high velocity flow di verted around the economizer with a small bulk flow. A combination of physical cold flow and CFD modeling was used to specify the details of ductwork layout and flue gas rectification device s. The specification was ultimately attained.

Figure 4: Reactor And Ductwork Arrangement for One US SCR Retrofits

### Reagent Injection Equipment

Historically, the approach to achievi ng uniform mixing of reagent with NO
x is a high-density arrangement of individual injector s across a flue duct, with as many as 40-50 injectors per m2. The injectors can be individually adjusted to tune the delivery of reagent. In recent European applications, the use of a small nu mber of large injectors (4-12) co mbined with static mixers has emerged as an alternative to a conventional amm onia injection grid (AIG). This concept is receiving increased attention due to the potential for reduced maintenance for individual injectors. The necessary hardware and design expertise both are offered “packaged” with SCR equipment or catalyst, and individu ally from suppliers of static mi xers. Specifically, one catalyst supplier offers two versions of a static mixer for use in applications that employ their catalyst. Similarly, one SCR process supplier provides delta- wings as standard equipment in their system design. Several individual suppliers of static mixers (Sulzer, Koch, et c.) will provide static mixer technology as stand-alone offerings to be incorporated into the process design.

Recent US designs have employed up to five in dividual rows of static mixers to achieve a required distribution of velo city, temperature, and NH 3 /NO ratio. For example, static mixers are deployed (1) at the flue gas econom izer exit, to rectify imbalances in velocity, temperature, and composition, (2) downstream of the take–off duct fo r the process bypass, (3) prior to the reagent injectors, to rectify velocity maldistributions induced by a tight “elbow” turn required due to space constraints, (4) following the reagent injectors, to indu ce mixing, and (5) prior to the reactor entry plenum. The nominal gas pressure loss incurred by each row - less than 0.3-0.5 in w.g.– is the tradeoff for a correct distribution.

In summary, both the high density AIG and static-mixer concepts are employed in US applications. The need for extremely high perf ormance may favor utilizing static mixers and fewer injectors over a conventional AIG. Experience with static mi xers suggests that if installed correctly the units will be maintenance-free, and operators are pred icating plans on this observation.



### Coal Experience

Early SCR experience in Japan was dominated by lo w sulfur coals from Australia and S. Africa, the primary coal sources in the late 1970s. Despite the considerable understanding gained with these coals, generalization to European coal s was greeted with the observation of arsenic poisoning at pilot scale. Although no episode sim ilar to arsenic poisoning is anticipated for US applications, the uncertainty of broad deployment to a new set of coals merits that operators observe and document composition of coal fired to relate operations to catalyst activity.

Table 3 summarizes the key coal constituents th at affect catalyst deac tivation, identifying the most significant catalyst impact. Most notable is the role of alkali and alkaline earth elements that can induce alkali sulfate poisoning. Calcium sulfate was early recognized as a significant deactivating agent (6) the other more soluble alkali cite d can penetrate catalyst pores when exposed to moisture (from tube leaks or condensation due start up). As described previously, arsenic is a well-documented poison that, alt hough most acute for wet-bottom boilers thatemploy ash recycle, is still problematic for dr y bottom boilers with lower furnace gas exit temperatures.

Table 3: Key Coal Characteristics That Affect Catalyst Deactivation

Coal Constituent Process Or Catalyst Impact Japanese Experience European Experience Anticipated US Conditions Arsenic Reacts with V, negating site activity and/or blocking micropores Negligible coal As content did not identify phenomena Identified through pilot and early commercial applications Varies widely with As content in coal (2-40 ppm)

Alkaline material (K, Na, Mg) Reduces “acidity” and effectiveness of catalyst acid sites Total alkali <5% of ash (observed with oil firing) Total alkali 8- 15% of ash 5-12% of ash, up to 23% for PRB

Alkaline earth (primarily Ca) Reacts with SO 3 formed at site to produce CaSO 4 ; plugging pores, ability of NH3 to bond at the site. Minimum Ca needed to mitigate arsenic poisoning Generally 3-5% of coals fired (Australia, S. Africa) 3-5% of Ruhr, Saar Valley, and Polish coals 2-10% ash, up to 16% for PRB

Phosphorous As phosphoric acid, can condense, react, and block

pores. Not recognized Recognized in selected coals Will depend on coal P content, and oxidizing/reducing conditions in furnace Sulfur Indirectly, sulfur provides a source of SO 3 . which can react with Ca to form CaSO 4 <0.6% <1.7% 0.4-3.5%

Regarding arsenic, it is known a minimum level of calcium in the coal is desired to mitigate arsenic poisoning. Thus, a minimum level of calcium in ash (~2%) is desired. Phosphorous can also deactivate catalyst, and su lfur – although not exerting a di rect role – indirectly can contribute the alka li sulfate formation by production of SO 3

.

Figure 5 compares coals utilized in the Japanese and European e xperience with those anticipated US applications. Figure 5 compares the content of (a) sulfur, (b) ash, (c) calcium in the fly ash, and (d) total alkalinity of fly ash constituents (calcium, potassium, magnesium, and sodium). Figure 5 shows experience in Japan was derived with relatively low sulfur (~0.4%), 2-3% calcium in ash, and negligible soluble alkali co mpounds. The coals used in Europe typically feature double the sulfur content, and increased calcium and total alkali in fly ash. The first US SCR installations were on low sulfur coals th at (due to compatibil ity with dry scrubbing technology) resembled the coal used in Europe. The complete set of US coals that will see SCR duty in the US may present greate r challenges than the first coals did, due to higher sulfur and in some case Fe content, which will increase SO 3 production by the catalyst. For some coals, low calcium content in fly ash may be inadequate to negate arsenic poisoning , and adding limestone or other alkali to the coal will be required. Fi nally, the case of Powder River Basin (PRB) coals may be of concern, depending on the application. Short-term exploratory tests suggested the extreme calcium content of PRB promotes alkali sulfate poisoning. Howeve r, not all catalystsuppliers share this view, and the first commerci al installation with P RB coal has not incurred any noticeable deactivation.

Figure 5: Comparison Of Coal Characteristics Fo r Japanese, European, And Anticipated US Applications

In summary, some US coals ar e not described by the existing e xperience database, and despite the best efforts of catalyst suppliers, some risk to deactivation or bala nce-of-plant problems exists.



### Reagent Type and Systems

In comparison to early SCR applications, which were limited to solely anhydrous ammonia as a reagent source, present applica tions can employ either anhydrous, or aqueous forms of ammonia (of 19.5 or 29% solution strength). In additi on, depending on the progress of several early demonstration projects, urea may be applied. From strictly a cost standp oint, anhydrous reagent is usually preferred, as it requi res the least delivered cost and capital equipment. However, concerns voiced by local comm unities have prompted adoption of aqueous reagent for many systems, and for urea on a limited basis.

In Europe, the first installations employed reagent receiving, stor age, and handling standards that employed conservative measures such as underground tanks, double-wall tanks, and numerous fail-safe monitoring concepts. As SCR applications migrated from large, remotely located central stations to units in urban areas, intere st in aqueous-ammonia reagent increased with local concerns for handling and storage. Anhydrous systems appear to dominate planned US 0.00 2.00 4.00 6.00 8.00 10.00 12.00 14.00 16.00 18.00 20.00

Australia S. American Ruhr(1) Ruhr(2) Poland Low Sulfur Med Sulfur High Sulfur PRB

Coal SourcePercent Coal Or Ash Content Sulfur

Ash

Calcium

Total Alkalineinstallations, although numerous aqueous systems w ill be utilized. Urea–based applications have received recent interest. In terms of impacting SCR operation, the use of aqueous and urea systems introduces additional complexity. Specif ically, both approaches require a separate vaporization step, which entail s additional process reactors, and managing and monitoring the reagent devolatilization or hydrol ysis process. The manpower burden for such monitoring is not significant (with much of the duty remotely moni tored), but the additional steps for evaporation of ammonia from the aqueous form, or devolat ilization of HN fragments from urea introduces time delays that must be accounted for in proc ess control system design or operation. With target performance of 90% standard and necessary for system compliance, these factors must be considered in control system design.



### Balance-Of-Plant

A detailed treatment of balance-of-plant (BOP) f actors is outside the scop e of this paper; but several key items are identified.

Air Heater

Most European units were initia lly equipped with enameled-coated heat exchange baskets in thecold end of the air heater, and thus enjoyed superior protection from the additional, SCRpromoted SO 3 . The use of enameled-coated heat exchange baskets is not commonplace in US applications; however Corten is frequently used for higher sulfur coals. An informal survey suggests that approximately 75% of the units re trofitting SCR in the US are believed to be upgrading air heaters to mitigat e the impact of residual NH 3 and higher SO 3 . These modifications include installing enameled surfaces , utilizing a more “open” geometry to retain the momentum of sootblowing medi a in the axial direction, or both (7) . The evolution of SCR process equipment has probably eased air heater concerns, as experience in Germany in the mid1980s suggested residual NH 3 should be lowered from 5 to 2 ppm, for the purpose of ash utilization. The potential for air heater deposition has been reduced accordingly.

Flue Gas Handling

The need to retrofit additional flue gas flow capab ility to handle the higher resistance imposed by the reactor and process equipment varies signi ficantly with specific units. Typically, the additional resistance ranges from 3 in. to7 i n. w.g., depending on the application, with most installations probably incurring 4- 5 in. w.g. It has been widely reported that most European installations did not require upgrade to flue gas handling equipment; however, the nationwide program to retrofit flue gas desulfurization processes completed in 1984 (3) required flue gas handling upgrade that in many cases was able to also accomm odate SCR. An informal survey suggests that 50% of the units retrofit with SCR in the US require some improvement to flue gas handling, with upgraded motors or fans common.

Compared to previous experience, any reductions in flue gas resistance by improved catalyst design have probably been absorbed by static mixers and AIG components to provide a more effective NH 3 /NO distribution – the price for which is pa id in pressure drop. Thus, the evolutionof SCR application has probably not materia lly changed the additional flue gas handling requirements, or associated O&M.

Alkali Injection

Since arsenic poisoning was demonstrated a major contributor to catalyst deactivation, the need for a minimum quantity of available calcium in the fly ash has been recognized. Several European operators consistently inject or add limestone or lime to coals fired to augment the naturally available calcium in the ash, and claim a benefit in mitigating both arsenic poisoning and SO 3 outlet concentration (8) . Generally, anywhere from 0.5-2% of the coal mass consumption rate is augmented with lime, dolom otic limestone, or conventional limestone to provide alkalinity. Capital costs for such e quipment are not excessive, but O&M procedures must accommodate servicing the alkali supply and equipment. The extent to which such systems will be applied in the US is uncertain. On e major SCR process equipment supplier strongly advises deployment of such equipment, and most (but not all) catalyst su ppliers agree that for certain applications the additional alkali is be neficial. However, Southern Company recently announced they would forgo alkali addition, and accept possibly higher catalyst deactivation in exchange for simplicity and reduced plant operating duties. In summary, the need to inject alkali to mitigate either arsenic poisoning or control SO 3 emissions may slightly increase O&M, but adoption of alkali inject ion/addition is not anticipated to be widespread.



### LONG-TERM OPERATING CHARACTERISTICS

Operating data obtained for coal-fired SCR-equi pped units shows that performance can vary over relatively short periods of time. Given that the NO
x tons cap for the SIP-Call is effectively a 5-month average, hourly or daily variances will not be of significance for many operators. However, in addition to the seasonal (or annual) tons cap, some states require some combination of a 30 day, 24 hour, or 8 hour rolling average to be observed. Specifically, several SCRequipped units planned for operation in the Houst on area must observe 24 hour daily averages of a magnitude that are not significantly above th e annual cap. Also, new SCR-equipped units will in all likelihood be required to abide by a short-term average. Data from the Environmental Protection Agency’s Electronic Data Reporting (EDR) site is used to explore the variability observed in the US to date.

Figure 6 presents typical scatter in SCR outlet da ta, obtained from a dry bottom boiler in the US with SCR operational for several years. The data presents NO
x emissions within 5% of full load. The details of operation and the in tent of the operators are unknow n; thus it is not possible to determine the source of variabilit y. However, it is clear the optim al amount of reagent required by a particular set of process conditions is not consistently delivered to the reactor.

The variation can be quantifie d by applying statistical proced ures to calculate the 30 day average, a 24 hour average, and an 8 hour rolling average. Figure 7 compares this data for four units. Two units are dry bottom boile rs retrofit with SCR for high NO
x removal from approximately 0.45 lbs/MBtu (Units A and D) ; one cyclone boiler designed for 80-85% NO
x removal from 1.2-1.5 lbs/MBtu; (Unit C), a nd a new plant capable of 50-60% SCR NO
x removal from 0.5 lbs/MBtu (Unit E). The data in Figure 7 show that NO
x typified by short-termaveraging periods can be significa ntly greater than the calculated 30 day rolling average. These data can be used to establish an “operating margin” NO
x outlet rate that s hould be targeted if short-term compliance is required.

Figure 6: SCR Outlet Emissions Data Scatter For 90% Removal System

Figure 7: Comparison of 30 Day, 24 hour, and 8 Hour NO
x Outlet Data for Selected SCREquipped Units 0.0 0.1 0.2 0.3 0.4 0.5 0.6

0 500 1000 1500 2000 2500 3000 3500 4000

PROGRESSIVE HOURS OF OPERATIONNOx EMISSIONS, lb/mmBtu

0.00 0.05 0.10 0.15 0.20 0.25 0.30 0.35 0.40

1 2 3 4 5 6 7 8 9 10 11 12ACHIEVABLE NOx EMISSIONS, lb/mmBtu

UNIT A UNIT C UNIT D UNIT E 8 Hr

24 Hr

30 Da 8 Hr

24 Hr

30 Da 8 Hr

24 Hr

30 Da 8 Hr 24 Hr 30 DaFigure 8 compares this “margin” for the four units cited, in addition to a second cyclone unit (Unit E) and a second new unit with 50% NO
x capability. This figure again depicts the wide variability in SCR outlet NO
x from Unit A; however, as the s ubject unit has operated with SCR for less than one year, the results should be consid ered preliminary. Data from most of the other units suggest operators may be required to cons ider additional monitoring activities to align shorter and longer term rolling averages.

Of note is that the least variability is exhibited by the unit that (a) features the longest operating history, and (b) requ ires the least NO
x reduction. It is not clear whic h, if any, of these factors is responsible for this observation.

One must be cautious with Figures 6-8, as ope rating time is limited for some units, and the intention of the operators is not clear (e.g., minimizing short-term variability may not be important). Regardless, the data illustrate that precise attention to operating duties and development of a learning curve are necessary fo r successful process opera tion. The results also suggest that any short-term mon itoring requirements by local agenci es consider practical limits to process operations.

Figure 8: Estimate of Operating Margin Required For Six SCR-Equipped Units

Margins Required for Averaging Times Less than 30-Days

0 50 100 150 200 250

0 100 200 300 400 500 600 700 800
Averagine Time, HoursMargin Above 30-Day Average, Percent Unit A B C D E F

### IMPLICATIONS FOR US O&M ACTIVITIES

Essentially all major utility systems are depl oying SCR as the central element in their NO
x control strategy, and plan to “overcontrol” NO
x on the largest plants, allowing smaller, lower capacity factor units to a dopt less stringent controls . The success of each NO
x compliance program is heavily dependent on successf ul operation of SCR at target levels.



### Maximize NO
x 

### Removal

NO x Distribution Testing

The previous discussion shows regardless of whet her a conventional AIG or static mixer system is utilized, achieving and main taining extremely uniform cont acting of reagent and NO is necessary. Testing on an annual basis will be necessary to determine the inlet and outlet NO
x distribution to infer the NH 3 /NO ratio at the catalyst inlet. Many European utilities conduct these exercises on approximately an annual basis, wh ich is recommended for US applications. With conventional high density AIG, cons iderable flexibility is availabl e to bias reagent injection to different regions of the ductwor k. Using static mixers and a li mited number of injectors limits the flexibility, but does not eliminate the ability to bias the reagent. Process suppliers claim the mixing capabilities of static mixers eliminate an y need for flexibility, but only experience will prove so. Regardless, the scale of influence of static mixers is limited, and compensating for large-scale variations (e.g., acro ss the entire ductwork) may not be possible. Thus, even limited injectors with static mixers may require attention.

As discussed under I&C, the lowest SCR outlet NO
x may be attained with a boiler NO
x output optimization for distribution, not necessarily th e least magnitude. Consistent testing of inlet/outlet NO
x profiles will identify optimal operating modes.

Catalyst Maintenance

The need to achieve high performance requires cat alyst to retain activity as projected by the supplier. As both physical blocking by fly ash and a reduction in site activ ity (due to arsenic, alkali sulfate and other compounds) contribute to deactivation, inspection and cleaning are critical. The use of coupon tests conducted by the catalys t supplier (and possibly a third party) is essential to provide a snapshot of change in catalyst physical features and surface composition. The inspection and cleaning of cat alyst during outages will be n ecessary to assure that the maximum surface area is clean and available to participate in NO
x reduction.



### Data Historian

Operators will need to document the process operations and coal composition rigorously to validate that the conditions of guarantees have be en observed. All units to some degree require this, but particularly those operato rs that have secured a catalyst supply contract separate from the process supply contract.Many utilities have established a strategic alliance with a catalyst manufacturer for catalyst supply for an entire system. The selection of the particular supplier is based upon a firm cost estimate to provide adequate catalyst volume to achieve a projected performance target, presuming a fixed set of process conditions. A se parate contract is arranged with a process supplier to provide the equipment to deliver those process conditions.

Under this scenario, it may not be straightforward to attribute responsibility for malperformance. For example, if performance targ ets are not satisfied, it is antici pated the catalyst supplier will first require demonstration that process conditions called for in the specification have been delivered– particularly if the ca talyst supplier was not the respons ible party for flow modeling. However, measuring velocity dist ribution in high temperature, particulate-laden flue gas to within the accuracy required ma y not be viable; thus, it may not be possible to validate process conditions.

Regarding coal composition, catalyst suppliers will require assuran ce that coals as specified are utilized; for example, it will be important to document that a minimum level of calcium is available to mitigate arsenic poisoning. A system atic and controlled methodology to sample and analyze coal, using agreed upon protocols, is nece ssary to construct an ad equate arrangement.



### System Wide Catalyst Management

The use of several SCR facilitie s across a generating system affords the opportunity to employ a systemwide approach to catalyst management. Even though a catalyst layer may have suffered deactivation necessitating repla cement, that specific layer can still provide adequate NO
x removal – as long as the reactor has been desi gned to accommodate the lower initial activity. Also, catalyst regeneration techniques can incr ease activity for a cost below new catalyst.

Systemwide catalyst management has been depl oyed at several stations in Germany, and regeneration techniques have e volved in recent years. Severa l providers of catalyst recycling services have refined their offeri ngs and are planning to offer such services for the U.S. market. Each regeneration technology is different, but ap pears to utilize a combination of (a) physical cleaning to remove ash adhered to catalyst, de creasing resistance to ma ss transfer, (b) washing with an aqueous or nonaqueous solvent to enhan ce removal of ash, or removal of soluble alkali sulfate compounds, and/or (c) introduction of additional vanadium on the catalyst service.

The potential benefits of a sy stemwide catalyst management strategy can be quantified by a simple example. Consider a three-unit system employing a large station (Unit A) equipped with a 3+1 reactor design. Units B and C are also eq uipped with a 3+1 reactor design, and each offer 50% of the generating capacity (and catalyst in ventory and replacement requirements). All units fire a moderate-high arsenic content coal, inst all the fourth layer at 16,000 operating hours, and (when using new catalyst) replac e existing layers at intervals of approximately 18,000 operating hours. “Spent” catalyst from all units is “pool ed” for regeneration, eliminating the need for new catalyst after the 16,000 hour supplement and 34,000 hour replacement. Catalyst regeneration technology is assumed to restore activity (k /ko) to 0.85 for 65% of new catalyst cost.Table 4 summarizes system catalyst manage ment over a 15-year period, assuming seasonal operation for the initial four years and annual ope ration thereafter. The Baseline Case requires a total of 18 layers of new catalyst to be purch ased for all units, at a NPV of $11.4 M. The Regeneration Case reduces total new catalyst purc hased to 5 layers, with a total of 14 layers regenerated. The use of catalyst of lower activ ity requires one additional layer to be exchanged for Unit A, over the 15-year peri od. Total incurred cost is re duced by almost 20% to $9.5 M.

The scenario described in Table 4 is necessari ly simplified; and selected to emphasize the benefits of catalyst regeneration. Specificall y, the assumption of modera te-high arsenic content coal requires relatively frequent replacement. Also, the scenario assumes success in restoring activity for arsenic-poisoned catalyst; that catalyst layers can be regenerated more than once; and that catalyst deactivation rate after regeneration is the same as for new catalyst. An actual catalyst management strategy will require balanc ing of reactor potential required versus the generation of “spent” catalyst, and the cost and performance of regeneration technologies. Regardless, the potential benefits are notable, and merit an independent analysis of this alternative to purchase of new catalyst.

Table 4: Catalyst Management Strategy Includin g Regeneration for Hypothetical System

Catalyst Management Factor Unit A Unit B Unit C Total System Reactor Design 3+1 3+1 3+1 Initial Catalyst Inventory (c.m.) 500 250 250 Catalyst Per Layer 250 125 125 Baseline Strategy Catalyst Purchased (15 years) 6 layers 6 layers 6 layers 18 layers NPV Of Catalyst Management ($M) 5.70 2.85 2.85 11.14 Regeneration Case (85/65) New Catalyst Purchased 1 layer 2 layers 2 layers 5 layers Catalyst Regenerated (15 years) 6 layers 4 layers 4 layers 14 layers NPV Of Catalyst Management ($M) 4.78 2.35 2.35 9.5



### Improved I&C/Controls

One area that has not notably evolved, but with signi ficant potential, is that of process controls. Current SCR processes employ a feedforward signal for reagent demand (based on boiler NO
x , or a surrogate such as load or steam flow) with a feedback signal, the latter based on measured outlet NO
x at the reactor exit or stack. Numer ous operators have attempted to couple a continuous on-line ammonia monitor as an additi onal feedback signal, bu t until recently such instruments have not provided co mmercially acceptable service.

In practice, a residual NH 3 monitor may not provide signific ant value over inferring ammonia absorbed by fly ash. If the deposition of am monium sulfates and bi sulfates (ABS) is a phenomenon dependent on cumulative, long-term and “low level” exposure to residual NH 3 and SO 3 , then monitoring ammonia absorbed on fly as h may be adequate. However, if process upsets and the “flooding” of residual NH 3 is a contributor, then a real-time monitor will beuseful. As ABS deposition depends on flue gas SO 3 concentration, it is likely that long-term exposure is dominant.

Perhaps more importantly, the need to maintain the uniformity of NH 3 /NO ratio to standard deviations of below 5% may require control of the boiler NO
x emission distribution. Specifically, operators may find to achieve strict SCR outlet targets the boiler should be operated to produce the most uniform, and not necessarily the lowest, NO
x rate. For example, a boiler NO x outlet of 0.35 lbs/MBtu characterized by a 3% SD may be preferab le to 0.32 lbs/MBtu characterized by a 6% SD, if 90% remova l is to be consistently achieved.

Finally, consistently delivering 90% NO
x removal may benefit from upgrade of the injection system (either conventional AIG or static mixer enhanced) from passive to active control. NO
x distribution profiles generated durin g operation with a fixed, perman ent grid may be coupled to a series of control valves or other means to bi as reagent across the grid. Although implementing this concept is not simple, the additional cost and O&M could significan tly leverage the fixed investment in SCR.



### OBSERVATIONS AND CONCLUSIONS

SCR technology has evolved considerably in the almost 25 years since the first commercial demonstrations in Japan. Equally significant, the scope of the appl ications and design requirements of the SCR installa tions for the SIP-Call has increas ed, with 90% removal and the need for NH 3 /NO ratio as low as 3% SD. As a c onsequence, entire generating system NO
x compliance strategies depend on successful depl oyment of the SCR. And lacking a robust NO
x allowance market (at least in the early years), SCR system performance will directly impact the generation available from any one unit in a season. The following observations are offered regarding O&M activities to preserve the operation of these systems:

1. Design Margin. Both competitive market forces and the use of catalyst management strategies that minimize least first cost proba bly leave less design marg in in catalyst sizing (compared to the Japanese and European experi ence), to “insure” against unforeseen events. Monitoring process parameters is essential to understand SCR operation, and detect any problems early.

2. Proactive Diagnostic Measurements . Efforts to determine the distribution of NH 3 /NO ratio and other key process operating characteristics are essential to maintaining high performance. Although time-consuming and cumbersome, estab lishing the grid of inlet and/or outlet NO
x from which one can infer the NH 3 /NO distribution will be useful. Also important will be inspection and evaluation of catal yst deactivation (possibly including a third party) during the annual outage.

3. Short-Term SCR Outlet NO x Variability. Actual NO
x outlet data can vary widely over short periods of time, so that an 8-hour rol ling average may be as much as 200% above the 30-day average. For units that must observe a strict short-term average in addition to a 5- month or annual NO
x “cap”, a “target” should be dete rmined to assure compliance.4. Data Historian. A “data historian” activity will be be neficial to the owner/operator to track and document key operating parameters, including coal supply, and evaluation of trends between process operation and coal characteristics.

5. Catalyst Management Options . Catalyst management options are numerous, particularly across a utility operating system when catalys t can be interchanged between units. The ability to regenerate catalyst should be evalua ted by the degree of activ ity restoration versus cost, and the net savings available within an en tire system. Operators should consider an independent assessment of system wide catalyst management, including competing regeneration options, in additi on to new catalyst purchase.

6. I&C Improvements . Various improvements to I&C syst ems should be considered, that are logical extensions to leverage the investment in SCR to extract additional NO
x tons. Such systems may not be optional but necessities, if additional complexity introduced by aqueous/urea reagent systems induce time lags into the I&C strategy.

These actions may not necessarily be expensive, but comprise additional duties in a competitive marketplace that are essential to preserve plant reliability.



### REFERENCES

1. H. Zinder & Associates, Evaluation Of The Cost Of Sate Cont rol Strategies In The SIP-Call, final report prepared for the Midwest Ozone Group, October 16, 2000. 2. Nakabayashi, Y. Research and Development on NO
x Removal in Japan and Results of EPDC’s Research and Development of the DeNO
x Process; Proceedings of the Second NO
x Control Technology Seminar, EPRI Speci al Report, EPRI FP-1109-SR, July 1979. 3. Rentz, O., Application Of DeNO
x Technologies In The Federal Republic of Germany And Europe, Proceedings Of The 1985 Symposiu m On Stationary Combustion NO
x Control, Volume 1, Utility Boiler Applications, EPRI CS-4360, Volume 1, January 1986. 4. Engelmeyer, T. , Orlando Utilities’ Experience with SCR At Stanton Unit 2, EPRI SCR Workshop, March 22-24, 1999, Orlando, FL. 5. Cichanowicz, J.E., An Assessment of European Experience With Selective Catalytic Reduction In Germany and Denmark, Proceedings of the EPRI-DOE-EPA Air Pollution Control Symposium – The Mega Symposiu m, Volume 2, August, 1999, Atlanta, GA.
6. Catalyst Technology in MHI; Proceedings of the Mitsubishi SCR Symposim ’87, October 22, 1987, Weisbaden, FRG.
7. Bondurant, Louis P. III, SCR Compatibility for the Ljungstrom Air Preheater; Proceedings of the EPRI-DOE-EPA Air Pollution Control Sym posium – The Mega Symposium, Volume 2, August, 1999, Atlanta, GA. 8. Gutberlet, H., SO 2 Conversion Rate of DeNO
x Catalysts – Effects On Downstream Plant Components And Remedial Measures , Proceedings of the EPRI-DOE-EPA Air Pollution Control Symposium – The Mega Symposiu m, Volume 2, August, 1999, Atlanta, GA.