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 installations 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 better poison resistance than earlier generation 

products. Additionally, catalyst management strategies 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, static mixers to promote contacting of reagent 

and flue gas. These features improve performance 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-fired capacity in the US may be equipped with 

SCR NOx 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 design: the first commercial applications in Japan in the late 1970s, 

and subsequent installations in Europe (predominantly Germany) in the mid-1980s. SCR 

process design basis and operating requirements have significantly evolved from these prior 

generations, both simplifying and, in some ways, complicating the pending operations in the U.S. 

This paper reviews the key design and operational evolutions, and projects how future US 

operation may be affected. 

BACKGROUND AND HISTORY 

Strict NOx 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 Electric Power Development Company (EPDC) was 

required to “cap’ the NOx emissions from the two-unit Takehara Station to allow construction of 
a third, coal-fired unit. These requirements prompted early R&D and pilot investigations to 

evaluate SCR NOx control to achieve at least 50-60% NOx removal. Figure 1 presents a timeline 

of significant events regarding the development and commercialization of SCR technology. 

Figure 1. Timeline Of Key SCR Events 

Subsequent to the approximately 20-30 pilot plants operated in Japan in the late 1970s (mostly 

on fuel oil and natural gas), several demonstrations of coal-fired 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 Hokkaido Electric Tomato-Atsuma Station, and EPDC’s 

Takehara Station, where for the latter 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. NOx removal from these units ranged from 50-80%, with a 5-10 

ppm residual NH3 limit. Thus, early coal-fired experience was divided between high dust and 

low dust applications. 

Significant experience with high dust 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/Deiszeiu 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. NOx removal performance in the German and European 

applications increased to generally 80%, with selected high NOx-emitting units such as 

Knepper C achieving 90%. Experience in Germany also identified arsenic poisoning of catalysts 

through both pilot plant tests and full-scale experience, and further demonstrated that control of 

residual NH3 to 2-3 ppm (and not 5 ppm) was in most cases required to maintain 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 

Chugoku Electric: Unit: Merrimack

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 

Chugoku Electric: Unit: Merrimack

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 witnessed 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. NOx reduction varied significantly, with removal efficiencies from 50% to 

approaching 90%, the latter applied to high NOx emitting units. The low sulfur level of coals 

fired in Japan minimized concern for SO2 conversion, at least for some units. Also, limited 

experience with high dust applications had not identified the true impact of residual NH3; thus, 

control to 5 ppm (and at times 10 ppm) was allowed for coal-fired applications. 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 SO2 approached 2% for 

some of these designs, which was not problematic for the early low sulfur 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 NOx (ppm) 300 500 300 750 325 

NOx Reduction (%) 80 50 66 88 80 

Residual NH3 (ppm) 5 5 5 3 5 

SO2 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 features of SCR process equipment which distinguish the imminent 

US applications from predecessors. These include (a) catalyst technology, (b) process conditions 

applied, (c) reactor layout, (d) reagent injection equipment, (e) coal-fired experience base, (f) 

reagent type and handling systems, and (g) balance-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 operation and evaluation of a catalyst management strategy employing 

regeneration is presented. 

Catalyst 

Possibly the most significant advances have been 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 catalyst geometry for early designs. Accordingly, relatively thick 

extruded walls or coatings were necessary to provide 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 geometrical 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 characteristics of platetype catalysts, which offer among the highest open area (e.g., lowest flue gas pressure drop) and 

have remained relatively constant to exploit that important feature. Also of note is the 

introduction of ceramic fibers as substrate, offering significant surface area of reaction per unit 

weight. 

Table 2. Evolution of Catalyst Physical 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 

US, 2000 New Madrid grid 9.2 0.83 383 83 

various grid 7.4 0.83 480 79 

US, 2001 various corrugated 

plate 

10.6 

(hyd dia) 

1 390 78 
For 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” catalyst 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 initial catalyst inventory, some adjustment of pitch 

to operating characteristics is anticipated with experience. 

Composition 

Catalyst composition changes have increased activity while maintaining or reducing conversion 

of SO2 to SO3, and provided resistance to arsenic poisoning. Specifically, catalyst suppliers have 

employed additives as well as improved manufacturing and processing techniques that influence 

the available surface area for reaction. The common TiO2-based catalysts also can employ 

molybdenum trioxide (MoO3) and tungsten trioxide (WO3), in addition to the key active 

ingredient, vanadium pentoxide (V2O5). Perhaps the most significant consequence of the 

improved manufacturing process has been the increased “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 volume of catalyst and catalytic activity, coupled 

with catalyst management techniques, has probably reduced the initial volume of catalyst 

employed for a given application. Comparisons to early designs can be misleading as both NOx

removal targets and the initial catalyst guarantee period have evolved. However, Table 2 data 

when compared to present space velocities for 90% NOx removal and 2 ppm residual NH3

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 detailed process monitoring to diagnose and detect 

performance trends as early as possible. 

Process Conditions

The selection of SCR “process conditions” – the distribution of flue gas velocity, NH3/NO ratio, 

and the range of acceptable temperature that establish the operating environment for the 

catalyst - have evolved to support present performance targets. There are several methods of 

specifying the distribution of velocity and NH3/NO ratio; this paper will utilize the standard 

deviation (SD) of the measurements. 

Figure 3 illustrates the role of flue gas velocity and NH3/NO ratio SD on NOx removal 

performance and residual NH3. These data represent a performance calculation for an inlet NOx

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. The process calculations employ a random distribution of initial 

velocity and NH3/NOx ratio across the surface of a catalyst, characterized by varying levels of 

non-uniformity. At each location on the catalyst, the local NOx reduction and NH3 slip were 

calculated and the results integrated over the surface. Uniform velocity enhances performance 

by providing uniform residence time across the catalyst, insuring no “cells” have inadequate 
Figure 3: Role of Maldistributions in Velocity and NH3/NO on SCR Performance 

(a) Velocity Non-Uniformity Effects (NH3/NOx Non-Uniformity = 7%) 

(b) NH3/NOx 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 high velocity and deposit-inducing 

low velocity are minimized. Figure 3 shows that improved velocity distribution increases 

performance, but the payback for achieving extremely “flat” velocity profiles diminishes. 

Figure 3 also shows the NH3/NOx uniformity is significantly more important than the velocity 

uniformity in providing for high NOx removal. If any one “cell” of flue gas is deficient in either 

reactant (NH3 or NO), then the reaction will not proceed to completion – regardless of the 

volume of catalyst that is utilized. Figure 3 also illustrates the criticality of NH3/NOx uniformity 

increases as NOx reductions exceed 90%. 

Most early generation designs in Japan and Europe are believed to feature distributions of 

velocity of a 15-20% SD, and of NH3/NO ratio of 6% or greater SD. The evolution to high 

performance systems requiring 90% NOx removal at 2 ppm slip has reduced the velocity 

distribution modestly to perhaps 10-15% SD, but significantly for NH3/NO ratio. The specified 

SD for the latter is frequently less than 5%, and for some applications as low as 3%. As a 

consequence of these strict specifications, SCR process equipment and catalyst suppliers and 

owners have conducted aggressive modeling studies. Regarding physical “cold-flow” modeling, 

the scale of model, details of construction included in the simulation, and extent of 

measurements have significantly increased to support the high performance systems. The use of 

CFD has been integrated with physical flow models to augment the evaluation, particularly with 

the distribution of flue gas temperature. 

One item that may become of concern is the ability 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 tolerances of less than one inch may be problematic in actually 

achieving the flow distribution specified by the model. The challenge to operators of these 

systems may also be to insure the process conditions, once delivered by the process supplier, are 

maintained. Finally, as will be discussed subsequently, simply demonstrating that these strict 

process conditions are actually delivered by the process supplier may be a critical issue to SCR 

operators. 

Reactor Layout 

Reactor layout can vary widely, depending upon whether SCR is installed in a new plant, or 

retrofit to an existing unit. 

Comparison of contemporary reactor 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 catalyst and reactor volume, without the complexity of handling high 

dust loading. Many boilers in Germany employ tower 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 path 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 European installations are represented by this concept, and numerous 

challenging retrofits were undertaken and successfully implemented. 
Of note with US SCR applications is the potential for a larger fraction of flue gas to be bypassed 

around the economizer, to provide the operating temperature “floor”, due to higher flue gas SO3

content (from higher sulfur coals). The relatively large volume of flue gas to be bypassed around 

the economizer over a wide load range can complicate mixing patterns. Figure 4 depicts a 

specific reactor and ductwork layout in which a relatively large volume of flue gas exiting the 

economizer bypass was problematic in preventing the distribution of flue gas temperature and 

velocity to be simultaneously achieved. The diversion of flue gas around the economizer 

necessary to meet the temperature specification biased the flow field and significantly distorted 

the velocity profile. For example, at mid-load 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 dampers are fully open, and the system must mix 

a large volume of large, high velocity flow diverted 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 devices. The specification was ultimately attained. 

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

Historically, the approach to achieving uniform mixing of reagent with NOx is a high-density 

arrangement of individual injectors 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 number of large injectors (4-12) combined with static mixers has 

emerged as an alternative to a conventional ammonia 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 individually from suppliers of static mixers. 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, etc.) will provide static 

mixer technology as stand-alone offerings to be incorporated into the process design. 

Recent US designs have employed up to five individual rows of static mixers to achieve a 

required distribution of velocity, temperature, and NH3/NO ratio. For example, static mixers are 

deployed (1) at the flue gas economizer exit, to rectify imbalances in velocity, temperature, and 

composition, (2) downstream of the take–off duct for 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 induce 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 performance may favor utilizing static mixers and 

fewer injectors over a conventional AIG. Experience with static mixers suggests that if installed 

correctly the units will be maintenance-free, and operators are predicating plans on this 

observation. 

Coal Experience 

Early SCR experience in Japan was dominated by low 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 coals was greeted with the observation of arsenic 

poisoning at pilot scale. Although no episode similar 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 that affect catalyst deactivation, 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 cited can penetrate catalyst pores when 

exposed to moisture (from tube leaks or condensation due startup). As described previously, 

arsenic is a well-documented poison that, although most acute for wet-bottom boilers that 
employ ash recycle, is still problematic for dry 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 SO3 formed at 

site to produce CaSO4; 

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 SO3. which can 

react with Ca to form 

CaSO4

<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 sulfur – although not exerting a direct role – indirectly can 

contribute the alkali sulfate formation by production of SO3. 

Figure 5 compares coals utilized in the Japanese and European experience 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 compounds. 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 that (due to compatibility 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 greater challenges than the first coals did, due to higher sulfur and in 

some case Fe content, which will increase SO3 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. Finally, 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. However, not all catalyst 
suppliers share this view, and the first commercial installation with PRB coal has not incurred 

any noticeable deactivation. 

Figure 5: Comparison Of Coal Characteristics For Japanese, European, And Anticipated US 

Applications 

In summary, some US coals are not described by the existing experience database, and despite 

the best efforts of catalyst suppliers, some risk to deactivation or balance-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 applications can employ either anhydrous, or aqueous forms of ammonia 

(of 19.5 or 29% solution strength). In addition, depending on the progress of several early 

demonstration projects, urea may be applied. From strictly a cost standpoint, anhydrous reagent 

is usually preferred, as it requires the least delivered cost and capital equipment. However, 

concerns voiced by local communities have prompted adoption of aqueous reagent for many 

systems, and for urea on a limited basis. 

In Europe, the first installations employed reagent receiving, storage, 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, interest 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 Source

Percent Coal Or Ash Content

Sulfur

Ash

Calcium

Total Alkaline
installations, although numerous aqueous systems will 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. Specifically, both approaches require a separate 

vaporization step, which entails additional process reactors, and managing and monitoring the 

reagent devolatilization or hydrolysis process. The manpower burden for such monitoring is not 

significant (with much of the duty remotely monitored), but the additional steps for evaporation 

of ammonia from the aqueous form, or devolatilization of HN fragments from urea introduces 

time delays that must be accounted for in process 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) factors is outside the scope of this paper; but 

several key items are identified. 

Air Heater 

Most European units were initially equipped with enameled-coated heat exchange baskets in the 

cold end of the air heater, and thus enjoyed superior protection from the additional, SCRpromoted SO3. 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 retrofitting SCR in the US are believed to be 

upgrading air heaters to mitigate the impact of residual NH3 and higher SO3. These 

modifications include installing enameled surfaces, utilizing a more “open” geometry to retain 

the momentum of sootblowing media 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 NH3 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 capability to handle the higher resistance imposed by 

the reactor and process equipment varies significantly with specific units. Typically, the 

additional resistance ranges from 3 in. to7 in. 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 accommodate 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 NH3/NO distribution – the price for which is paid in pressure drop. Thus, the evolution 
of SCR application has probably not materially 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 SO3 outlet concentration (8). Generally, anywhere from 0.5-2% of the coal mass 

consumption rate is augmented with lime, dolomotic limestone, or conventional limestone to 

provide alkalinity. Capital costs for such equipment 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. One major SCR process equipment supplier strongly 

advises deployment of such equipment, and most (but not all) catalyst suppliers agree that for 

certain applications the additional alkali is beneficial. 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 SO3 emissions may slightly increase O&M, but 

adoption of alkali injection/addition is not anticipated to be widespread. 

LONG-TERM OPERATING CHARACTERISTICS 

Operating data obtained for coal-fired SCR-equipped units shows that performance can vary over 

relatively short periods of time. Given that the NOx 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 Houston area must observe 24 hour daily averages of 

a magnitude that are not significantly above the 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 data, obtained from a dry bottom boiler in the US 

with SCR operational for several years. The data presents NOx emissions within 5% of full load. 

The details of operation and the intent of the operators are unknown; thus it is not possible to 

determine the source of variability. However, it is clear the optimal amount of reagent required 

by a particular set of process conditions is not consistently delivered to the reactor. 

The variation can be quantified by applying statistical procedures 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 boilers retrofit with SCR for high NOx removal from 

approximately 0.45 lbs/MBtu (Units A and D); one cyclone boiler designed for 80-85% NOx

removal from 1.2-1.5 lbs/MBtu; (Unit C), and a new plant capable of 50-60% SCR NOx removal 

from 0.5 lbs/MBtu (Unit E). The data in Figure 7 show that NOx typified by short-term 
averaging periods can be significantly greater than the calculated 30 day rolling average. These 

data can be used to establish an “operating margin” NOx outlet rate that should 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 NOx 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 OPERATION

NOx 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 12

ACHIEVABLE 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 Da
Figure 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% NOx capability. This figure again depicts the wide 

variability in SCR outlet NOx from Unit A; however, as the subject unit has operated with SCR 

for less than one year, the results should be considered preliminary. Data from most of the other 

units suggest operators may be required to consider 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) requires the least NOx reduction. It is not clear which, if any, of these factors is 

responsible for this observation. 

One must be cautious with Figures 6-8, as operating 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 for successful process operation. The results also 

suggest that any short-term monitoring requirements by local agencies 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, Hours

Margin Above 30-Day Average, Percent

Unit A B C D E F
IMPLICATIONS FOR US O&M ACTIVITIES 

Essentially all major utility systems are deploying SCR as the central element in their NOx

control strategy, and plan to “overcontrol” NOx on the largest plants, allowing smaller, lower 

capacity factor units to adopt less stringent controls. The success of each NOx compliance 

program is heavily dependent on successful operation of SCR at target levels. 

Maximize NOx Removal 

NOx Distribution Testing 

The previous discussion shows regardless of whether a conventional AIG or static mixer system 

is utilized, achieving and maintaining extremely uniform contacting of reagent and NO is 

necessary. Testing on an annual basis will be necessary to determine the inlet and outlet NOx

distribution to infer the NH3/NO ratio at the catalyst inlet. Many European utilities conduct these 

exercises on approximately an annual basis, which is recommended for US applications. With 

conventional high density AIG, considerable flexibility is available to bias reagent injection to 

different regions of the ductwork. Using static mixers and a limited 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 any 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., across 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 NOx may be attained with a boiler NOx output 

optimization for distribution, not necessarily the least magnitude. Consistent testing of 

inlet/outlet NOx profiles will identify optimal operating modes. 

Catalyst Maintenance 

The need to achieve high performance requires catalyst to retain activity as projected by the 

supplier. As both physical blocking by fly ash and a reduction in site activity (due to arsenic, 

alkali sulfate and other compounds) contribute to deactivation, inspection and cleaning are 

critical. The use of coupon tests conducted by the catalyst 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 catalyst during outages will be necessary to assure that the 

maximum surface area is clean and available to participate in NOx reduction. 

Data Historian 

Operators will need to document the process operations and coal composition rigorously to 

validate that the conditions of guarantees have been observed. All units to some degree require 

this, but particularly those operators 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 separate 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 targets are not satisfied, it is anticipated the catalyst supplier will 

first require demonstration that process conditions called for in the specification have been 

delivered– particularly if the catalyst supplier was not the responsible party for flow modeling. 

However, measuring velocity distribution in high temperature, particulate-laden flue gas to 

within the accuracy required may not be viable; thus, it may not be possible to validate process 

conditions. 

Regarding coal composition, catalyst suppliers will require assurance 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 systematic and controlled methodology to sample and 

analyze coal, using agreed upon protocols, is necessary to construct an adequate arrangement. 

System Wide Catalyst Management 

The use of several SCR facilities 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 replacement, that specific layer can still provide adequate NOx

removal – as long as the reactor has been designed to accommodate the lower initial activity. 

Also, catalyst regeneration techniques can increase activity for a cost below new catalyst. 

Systemwide catalyst management has been deployed at several stations in Germany, and 

regeneration techniques have evolved in recent years. Several providers of catalyst recycling 

services have refined their offerings and are planning to offer such services for the U.S. market. 

Each regeneration technology is different, but appears to utilize a combination of (a) physical 

cleaning to remove ash adhered to catalyst, decreasing resistance to mass transfer, (b) washing 

with an aqueous or nonaqueous solvent to enhance 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 systemwide 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 equipped with a 3+1 reactor design, and each offer 

50% of the generating capacity (and catalyst inventory and replacement requirements). All units 

fire a moderate-high arsenic content coal, install the fourth layer at 16,000 operating hours, and 

(when using new catalyst) replace existing layers at intervals of approximately 18,000 operating 

hours. “Spent” catalyst from all units is “pooled” 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 management over a 15-year period, assuming seasonal 

operation for the initial four years and annual operation thereafter. The Baseline Case requires a 

total of 18 layers of new catalyst to be purchased for all units, at a NPV of $11.4 M. The 

Regeneration Case reduces total new catalyst purchased to 5 layers, with a total of 14 layers 

regenerated. The use of catalyst of lower activity requires one additional layer to be exchanged 

for Unit A, over the 15-year period. Total incurred cost is reduced by almost 20% to $9.5 M. 

The scenario described in Table 4 is necessarily simplified; and selected to emphasize the 

benefits of catalyst regeneration. Specifically, the assumption of moderate-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 balancing 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 Including 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 significant potential, is that of process controls. 

Current SCR processes employ a feedforward signal for reagent demand (based on boiler NOx, 

or a surrogate such as load or steam flow) with a feedback signal, the latter based on measured 

outlet NOx at the reactor exit or stack. Numerous operators have attempted to couple a 

continuous on-line ammonia monitor as an additional feedback signal, but until recently such 

instruments have not provided commercially acceptable service. 

In practice, a residual NH3 monitor may not provide significant value over inferring ammonia 

absorbed by fly ash. If the deposition of ammonium sulfates and bisulfates (ABS) is a 

phenomenon dependent on cumulative, long-term and “low level” exposure to residual NH3 and 

SO3, then monitoring ammonia absorbed on fly ash may be adequate. However, if process 

upsets and the “flooding” of residual NH3 is a contributor, then a real-time monitor will be 
useful. As ABS deposition depends on flue gas SO3 concentration, it is likely that long-term 

exposure is dominant. 

Perhaps more importantly, the need to maintain the uniformity of NH3/NO ratio to standard 

deviations of below 5% may require control of the boiler NOx 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, NOx rate. For example, a boiler 

NOx outlet of 0.35 lbs/MBtu characterized by a 3% SD may be preferable to 0.32 lbs/MBtu 

characterized by a 6% SD, if 90% removal is to be consistently achieved. 

Finally, consistently delivering 90% NOx removal may benefit from upgrade of the injection 

system (either conventional AIG or static mixer enhanced) from passive to active control. NOx

distribution profiles generated during operation with a fixed, permanent grid may be coupled to a 

series of control valves or other means to bias reagent across the grid. Although implementing 

this concept is not simple, the additional cost and O&M could significantly 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 applications and design 

requirements of the SCR installations for the SIP-Call has increased, with 90% removal and the 

need for NH3/NO ratio as low as 3% SD. As a consequence, entire generating system NOx

compliance strategies depend on successful deployment of the SCR. And lacking a robust NOx

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 probably leave less design margin in catalyst sizing 

(compared to the Japanese and European experience), 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 NH3/NO ratio 

and other key process operating characteristics are essential to maintaining high performance. 

Although time-consuming and cumbersome, establishing the grid of inlet and/or outlet NOx

from which one can infer the NH3/NO distribution will be useful. Also important will be 

inspection and evaluation of catalyst deactivation (possibly including a third party) during the 

annual outage. 

3. Short-Term SCR Outlet NOx Variability. Actual NOx outlet data can vary widely over 

short periods of time, so that an 8-hour rolling 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 NOx “cap”, a “target” should be determined to assure compliance. 
4. Data Historian. A “data historian” activity will be beneficial 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 catalyst can be interchanged between units. The 

ability to regenerate catalyst should be evaluated by the degree of activity restoration versus 

cost, and the net savings available within an entire system. Operators should consider an 

independent assessment of system wide catalyst management, including competing 

regeneration options, in addition to new catalyst purchase. 

6. I&C Improvements. Various improvements to I&C systems should be considered, that are 

logical extensions to leverage the investment in SCR to extract additional NOx 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 Control Strategies In The SIP-Call, 

final report prepared for the Midwest Ozone Group, October 16, 2000. 

2. Nakabayashi, Y. Research and Development on NOx Removal in Japan and Results of 

EPDC’s Research and Development of the DeNOx Process; Proceedings of the Second NOx

Control Technology Seminar, EPRI Special Report, EPRI FP-1109-SR, July 1979. 

3. Rentz, O., Application Of DeNOx Technologies In The Federal Republic of Germany And 

Europe, Proceedings Of The 1985 Symposium On Stationary Combustion NOx 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 Symposium, 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 Symposium – The Mega Symposium, Volume 2, 

August, 1999, Atlanta, GA. 

8. Gutberlet, H., SO2 Conversion Rate of DeNOx Catalysts – Effects On Downstream Plant 

Components And Remedial Measures, Proceedings of the EPRI-DOE-EPA Air Pollution 

Control Symposium – The Mega Symposium, Volume 2, August, 1999, Atlanta, GA.