am-02-27 fcc flue gas emission control options - KBR

AM-02-27 

FCC FLUE GAS EMISSION CONTROL OPTIONS 

Authors: 

Phillip K. Niccum 

Chief Technology Engineer, FCC 

Eusebius Gbordzoe 

Principal Engineer, FCC 

Stephan Lang 

Principal Engineer, Environmental 

Publication / Presented: 

NPRA 

2002 Annual Meeting 

Date: 

March 17-19, 2002 

Notes: 

Marriott Rivercenter Hotel 

San Antonio, TX

Introduction 

Fluid Catalytic Cracking (FCC) is widely used to produce 

products such as gasoline and C3/C4 olefi ns from lower 

value, higher molecular weight, petroleum fractions. As oil 

refi ning has evolved over the last 60 years, the FCC process 

has evolved with it, meeting the challenges of cracking 

heavier, more contaminated feedstocks, while still accommodating 

increasingly stringent environmental regulations. 

Combustion of coke in the FCC regenerator produces a 

variety of potential atmospheric pollutants, but these can 

be controlled at or below egulatory mandated levels using a 

variety of technologies as summarized in Figure 1. 

For many decades, carbon monoxide (CO) emissions from 

U.S. FCC operations have been eff ectively controlled to 

levels below 500 ppm by the use of CO boilers and complete 

CO combustion with CO combustion promoting catalyst 

Figure 1: FCCU Flue Gas Emissions 

And Control Technologies 

Carbon Monoxide 

�Complete Combustion/CO Promoter 

�CO Boiler (CO Incinerator) 

Particulates 

�Third Stage Separation 

�Electrostatic Precipitation 

�Flue Gas Scrubbing 

Sulfur Oxides 

� Feed Desulfurization 

�Flue Gas Scrubbing 

� SOx Catalyst Additives 

Nitrogen Oxides 

�Selecive Catalytic Reduction 

�Selective Non-Catalytic Reduction 

�NOx Catalyst Additives 

�Counter-Current Regeneration 

Orthofflow TM FCC 

additives. (Th e FCC units built in the 1940’s operated with 

fl ue gas CO emissions of approximately 10 vol% or 100,000 

ppm!). Particulate emissions have also been controlled 

through the application of more attrition resistant catalyst 

and improved regenerator cyclone designs, as well as third 

stage separators and electrostatic precipitators downstream 

of the FCC regenerator. Technologies to control SOx emissions 

have also been widely applied, utilizing a combination 

of technologies (alone or in combination) such as feed desulfurization, 

fl ue gas scrubbing, and SOx reducing catalyst 

additives. NOx emissions from FCC regenerators has long 

been a topic of academic study and discussion but only now 

are NOx emissions becoming a major issue for many FCC 

operators. No single fl ue gas emission control technology or 

combination of technologies is best for all applications. Th e 

optimum choice for a given refi ner depends on a number of 

factors, such as regenerator operating mode, feedstock quality, 

targeted emission level. 

Regulatory Review 

In the United States, there are currently three major regulatory 

drivers impacting FCCU fl ue gas controls and thus 

future emission limitations. Th ese are (1) the continuing application 

of New Source Performance Standards (NSPS), (2) 

the up-coming implementation of Hazardous Air Pollutant 

(HAP) controls via what is known as MACT II regulations, 

and (3) the U.S. Environmental Protection Agency (EPA) enforcement 

actions and their Consent Decrees. Each of these 

regulatory forces impacts the selection of future emission 

control technology when site-specifi cs are addressed and 

they need to be integrated into any 

master compliance planning eff ort. At the same time, FCC 

units operating outside of the U.S. are also under pressure 

to reduce emissions, sometimes to levels even lower than 

required in the U.S. 

NSPS 

New Source Performance Standards for FCCU’s are well 

established for the control of particulate matter, carbon 

monoxide, and sulfur dioxide emissions (1). Th ese standards 

apply to FCC units constructed aft er January 17, 1984 as well 

as existing units that trigger their applicability with either of 

the following occurrences: 

• 

• 

Major FCC modifi cations (reconstruction) wherein 

cumulative investments over a two year period exceed 

50 % of the fi xed capital cost of facility replacement. 

Th is involves maintaining proper documentation on 

fi le for inspection (2). 

Changes in equipment or operation, which increase 

the rate to the atmosphere of any pollutant to which a 

standard applies. 

NSPS does not set explicit limits on NOx emissions from 

FCC regenerators. However, site and situation specifi c NOx 

limits may be established at the time the FCC unit is permitted 

or modifi ed. 

For more information, visit www.kbr.com

MACT II 

When the Maximum Achievable Control Technology 

(MACT) standards were issued for petroleum refi neries in 

August 1995(3), the EPA did not address fl ue gas from existing 

FCCU’s, catalytic reformers, and sulfur recovery units. 

In September 1998, the EPA proposed National Emission 

Standards for Hazardous Air Pollutants (NESHAP) to cover 

these remaining three types of refi ning process units (4). 

Th is NESHAP, commonly referred to as MACT II regulations, 

will establish the allowable pollution levels for FCCU 

regenerator particulate matter and carbon monoxide emissions. 

As presently proposed, MACT II particulate matter 

and carbon monoxide limits will be the same as the current 

NSPS requirements but will apply to FCC units previously 

grandfathered with respect to NSPS. 

• 

• 

Th e MACT II regulatory proposal uses CO control 

to NSPS levels (500 ppmvd) as a surrogate to demonstrate 

complete combustion of all organic HAPs that 

might otherwise be defi ned. 

Th e MACT II regulatory proposal uses nickel as a 

surrogate for other metals HAPs found either in crude 

feedstocks or FCC catalyst formulations, and seeks 

to limit its emission through control of particulate 

matter emitted with fl ue gas to the atmosphere. Metal 

HAPs include compounds of antimony, arsenic, beryllium, 

cadmium, chromium, cobalt, lead, manganese, 

mercury, nickel and selenium. A direct alternative 

limit of 0.029 lb/hr of Ni from the FCC regenerator 

stack has also been proposed. Some operators with 

very low nickel feedstocks may choose to address 

this specifi c nickel limit rather than the PM limit 

for MACT II compliance. It has been estimated that 

about one half of the nearly 100 FCC units operating 

in the U.S. will require installation of pollution 

control technology to reduce particulate emissions to 

the levels required by MACT II. 

EPA Consent Decrees 

Most recently, the EPA has entered into binding Consent 

Decrees (5) with several major U.S. refi ners to signifi - 

cantly reduce the amount of SO2 as well as NOx emissions 

from their FCC regenerators. Since the SO2 emission limitations 

sought are signifi cantly lower than NSPS levels, their 

implementation on existing sources via these consent decree 

projects may ultimately portend revisions to NSPS limits. 

Th e breakdown of how these regulations apply to FCC fl ue 

gas emissions is summarized in Table 1. 

Table 1 

FCCU Emissions Control Regulatory Drivers 

Pollutant Emissions/ Applicability of Major Regulatory Drivers 

Regulatory Item 

EPA Consent Decrees MACT II NSPS 

Particulate Matter No Yes for Ni Yes 

Opacity No No Yes 

Carbon Monoxide (CO) No Yes Yes 

Sulfur Dioxide (SO2) Yes No Yes 

Nickel Compounds (Ni) No Yes via PM Yes via MACT II 

Nitrogen Oxides (NOx) Yes No No 

Continuous Emissions 

Monitoring 

Yes Yes Yes 

Record Keeping Yes Yes Yes 

Th e EPA Consent Decrees have involved schedules with 

interim compliance dates stretching to 2008 for each refi ner. 

Th e MACT II fi nal rule, originally scheduled to be issued 

on May 15, 1999, is now expected sometime in 2002(6) and 

will take eff ect 3 years aft er it is adopted. Th e NSPS covering 

FCCU regenerator fl ue gas is not currently under review and 

revisions are not expected until the current Consent Decrees 

with refi ners are completed. Current emission limits applicable 

to FCCU regenerators are presented in Table 2. 

Table 2 

FCCU Regenerator Flue Gas Emission Control 

Requirements 

In many parts of the world, particulate emission limits are 

expressed in units of milligrams per normal cubic meter 

of fl ue gas. Table 3 illustrates the approximate relationship 

between FCC fl ue gas particulate concentration in units of 

mg/Nm3 and the EPA limit of 1.0 lb particulate matter/1000 

lb coke burned. Th e table shows that the particulate concentration 

corresponding to the MACT II limit is a function of 

the FCC regenerator operating mode and that the value will 

typically be between about 95 and 125 mg/Nm3. 


Pollutant Limit Reference Comments 

Particulate Matter 

(PM) 

1lb PM/ 1000 lb coke 

Burned 

40 CFR 60.102(a)(1) Incremental 0.10 lb/million 

Btu (PM allowed from 

supplemental liquid or solid 

fuel fi red in incinerator or 

waste heat boiler per 40 CFR 

60.102(b) 

Opacity 30% 40 CFR 60.102(a)(2) CMES required under 

60.105(a)(1) 

Pollutant Limit Reference Comments 

50 ppmvd or 90% reduction, 

whichever 

40 CFR 60.104(b)(1) With add-on SO2 control 

device. CEMS required 

under 40 CFR 

Sulfur Dioxide is less stringent 60.105(a)(8-9) 

25 ppmvd considered 

achieve-able within Consent 

Decrees 

9.8 lb SO2/1000 lb 

coke burned or no 

greater than 0.3 

wt% feed sulfur 

Nickel L lb PM/1000 lb coke 

burn-off 

Nitrogen Oxides 

(NOx) 

40 CFR 60.104(b)(2) 

Or 

40 CFR 60.104(b)(3) 

Without add-on SO2 , Control 

device 

See proposed 40 CFR 63 

-Sub-part UU (MACT II), 

13,000 mg/hr (0.029 lb/hr) 

of Ni. 

NA Consent Decrees 20 ppmvd considered 

achieve-able within Consent 

Decrees 

Notes: 

1) ppmvd = parts per million, volume, dry basis corrected to 0% O2 

2) 40 CFR 60 = Title 40, Code of Federal Regulations, Part 60, also known as the New Source Performance 

Standards. Subpart J (60.100-60.109) covers Standards of Performance for Petroleum 

Refi neries 

3) CEMS = Continuous emissions monitoring system. When concentration limits imposed, O2 

per40 CFR 60.105(a)(10) 

Table 3 

Typical Flue Gas Particulate Concentrations for 

Compliance with NSPS / MACT II 

Several options for controlling FCC fl ue gas particulate, SOx 

and NOx emissions to meet environmental requirements are 

discussed in more detail below. 

Regenerator 

Operating Mode 

Complete CO 

Combustion 

Partial CO 

Combustion 

Partial CO 

Combustion 

Flue gas O2, vol% 1.5 0.2 0.2 0.2 

Flue gas CO2/CO, 

vol/vol 

5 2 1 

Flue gas 

particulate, 

lb/1000 lb coke 

Flue gas particulate, 

mg/Nm3 

8 

1.0 1.0 1.0 1.0 

97 109 116 124 

Partial CO 

Combustion 

Third Stage Separators 

Th ird stage separators (TSS) provide another stage of 

cyclonic separation in addition to the two stages of cyclones 

typically included within FCC regenerator vessels for 

environmental protection. Th ird stage separators have also 

been widely utilized in FCC applications to protect fl ue gas 

expanders from erosion by catalyst fi nes in the fl ue gas exiting 

the regenerator, as shown in Figure 2. 

Figure 2: Third Stage Separator 

Controlling Particulate Emissions and Expander 


Th e FCC technologies off ered by Halliburton KBR 

include the CycloFines TM TSS, which uses patented cyclone 

technology and a proprietary design to remove catalyst 

fi nes from FCC regenerator fl ue gas. Th e CycloFines TM TSS 

consists of a pressure vessel containing numerous cyclone 

elements as depicted in Figure 3. Flue gas from the FCC 

regenerator enters the top of the separator where it is then 

distributed to the cyclone elements. Th e clean fl ue gas exits 

from the upper plenum chamber, while a small underfl ow 

of fl ue gas carries the captured particulates out the bottom 

of the separator. Developed by ExxonMobil and KBR in an 

extensive joint program that began in 1993, CycloFines TM 

TSS off ers refi ners an improved abatement technology which 

in many cases, can easily comply with EPA particulate emission 

limits(7). 

Th e CycloFines TM TSS development program was initiated 

to determine if existing TSS designs that were underperforming 

in ExxonMobil refi neries could be improved. 

Th e initial investigation led to cold fl ow modeling of full 

scale cyclone elements. 


In these tests, cyclone diameter, orientation, gas inlet, gas 

outlet, and proprietary confi gurations were optimized. 

Figure 3: CycloFinesTM TSS 


To assure scale-up to commercial operating conditions, hot 

fl ow modeling was performed. Finally, a large scale cold 

fl ow model, which included six commercial scale cyclone 

elements, was also built and tested at the KBR Technology 

Development Center in Houston, con-cluding development 

of the ultra-effi cient CycloFines TM TSS. 

CycloFines TM technology was fi rst commercialized for environmental 

protection in September 1997 at the ExxonMobil 

refi nery in Altona, Australia with a conventional 4th stage 

cyclone on the underfl ow. Th e CycloFines TM TSS at Altona 

has operated very well, proving the eff ectiveness of the new 

technology in commercial operation(8). Dust surveys as 

summarized in Table 4 below have consistently shown that 

the TSS collected 90 to 91 percent of the dust and nearly all 

particles with diameters greater than 4 microns entering the 

separator. Dust concentrations at the outlet of the TSS have 

been measured in the range of 10 to 20 mg/Nm3. Th e overall 

system, including gas from the underfl ow separator, is providing 

an FCC stack fl ue gas dust content of below 30 mg/ 

Nm3. Th is loss rate equates to only 0.3 lb catalyst per 1000 

lbs of coke burned, which is far lower than the MACT II particulate 

emission limit of 1.0 lb catalyst per 1000 lb of coke. 

Table 4 

CycloFines TM TSS Commercial Data from 

ExxonMobil Altona 

Operating Data Test #1 2/8/98 Test #2 2/10/98 Test #3 2/11/98 

Temperature, °F 1315 1310 13601 

Pressure, psig 18 17 17 

Gas rate, Mlb/hr 299 288 295 

Pressure drop, psi 1.4 1.6 4.6 

Underfl ow, % 

COLLECTION DATA 

1.5 1.5 None 

Inlet loading, mg/Nm³ 81 118 109 

Outlet loading, mg/Nm³ 7.3 10.3 10.2 

TSS Effi ciency, % 91.0 91.3 90.6 

Not only has the CycloFines TM TSS at Altona demonstrated 

the expected ultra-high effi ciency during normal operation, 

it has also demonstrated robustness of operation during 

upsets in the FCC regenerator operation. Th e CycloFines TM 

TSS effi ciency exceeds the requirements of MACT II with 

essentially 100% capture of all particles larger than 5 microns 

in diameter. Th is extra protection may be important to future 

operations because the regenerator catalyst loss rate and 

particle size distribution may change signifi cantly over time 

due to deterioration of regenerator cyclones, changes in fresh 

catalyst make-up rate or catalyst properties, and changes to 

regenerator operating conditions and other FCC operating 

variables. 

Electrostatic Precipitators 

Electrostatic precipitators (ESP’s) have been used for the 

reduction of FCC particulate emissions since the 1940’s, and 

modern ESP’s can be designed to reduce particulate emissions 

to very low levels. Figure 4 depicts an ESP in a typical 

FCC application. ESP’s consist of one or more gas tight 

chambers containing rows of collection plates and voltage 

discharge electrodes, which apply electrical charges to the 

particles in a waste gas stream in order to collect them before 

they reach the stack. 

ESP operation consists of three basic steps; particle 

charging, particle collection, and particle removal. Each 

step must be executed properly in order to eff ectively remove 

particulate to acceptable levels. 


Figure 4: Electrostatic Precipitator 

Factors Effecting ESP Performance 

Flue Gas Properties 

�Temperature 

�Composition 

�Rate (Velocity) 

Catalyst Properties 

�Resistivity 

�Particle size 

Collection Plate Rapping 

�Frequency 

�Intensity 


Th e process of charging a particle is accomplished by establishing 

a non-uniform electric fi eld between the discharge 

electrodes and the collection plates. Th is non-uniform fi eld 

is established by applying high voltage to the discharge 

electrodes, which generates electrons that fl ow from the discharge 

electrodes to the collection plates. As a result, neutral 

gas molecules are charged when struck by the high velocity/ 

high energy electrons. Th e fl ow of negatively charged gas 

ions and electrons is generally referred to as corona current 

fl ow (see Figure 5). As the fl ue gas travels through the 

resulting corona, suspended particles in the fl ue gas become 

charged by the negative ions, which are attracted to the surface 

of the particles. 

A measure of how readily a particle takes a charge is referred 

to as the particle resistivity. A highly resistive particle is diffi - 

cult to charge. Th e resistivity of the catalyst plays a key factor 

in collection effi ciency. Some FCC catalysts display 

high resistivity making it diffi cult to place a charge on them. 

If a particle is resistive to receiving an adequate charge, a 

greater electric fi eld will need to be generated in order to 

capture this particle. If a suffi cient fi eld cannot be 

generated, the resistive particle will simply pass through the 

ESP. 

Th e particle collection process begins the moment the particle 

absorbs a charge suffi cient enough to be attracted by the 

collection plates. Th e electric fi eld generated by the discharge 

electrodes causes the charged particles to migrate towards 

the grounded collecting plates where they accumulate in a 

layer, gradually losing their charge. Th e factors, which aff ect 

the particle charging and collection process, include particle 

size, particle resistivity, electric fi eld, and the temperature 

and composition of the fl ue gas. 

Figure 5: ESP Particle Charging Process 


Temperature and humidity, as shown in Figure 6 (9), aff ect 

the resistivity of a particle. At temperatures less than 300oF, 

the predominant mechanism for applying a charge is surface 

conduction. For this type of conduction, the charged ion 

is deposited on a thin surface fi lm, which surrounds the 

particle. During surface conduction, the ability to charge 

a particle decreases as the temperature increases (10). For 

temperatures greater than 300oF, the eff ects of surface 

conduction decrease and volume conduction takes over. Th is 

type of conduction involves the charged ion actually being 

absorbed by the particle. 

During this process, the ability of a particle to accept a 

charge increases with increasing temperature. In addition, 

certain gas molecules, which are found in FCC fl ue gas, are 

easier to charge than others. Molecules such as nitrogen 

oxides, sulfur oxides, ammonia, and water readily absorb an 

electrical charge. Ammonia and/or water are oft en injected 

into FCC fl ue gas streams upstream of the ESP to increase 

removal effi ciency (11). 


Figure 6: Effect of Flue Gas Properties 

on Resistivity of dust 


Upon proper rapping, a solid sheet of catalyst falls by gravity 

into hoppers located beneath the ESP. Th e second phase in 

particle removal is to remove the catalyst from these hoppers. 

Several methods to remove catalyst from hoppers are 

off ered. Th ese methods include gravity drop out systems, 

screw conveyor systems, and pneumatic/vacuum transfer 

systems. Bridging problems can be avoided by installing 

vibrators in the hopper walls. Likewise, heaters are oft en 

installed in the hopper walls to drive moisture out of the collected 

catalyst. 

Most of the ESP systems can be maintained externally 

without having to shut down the entire unit. In addition, 

a number of recent improvements have been made to ESP 

mechanical hardware, including rappers, electrode design, 

and control systems. However, if this hardware is not operated 

properly, taking into account how each of these systems 

aff ect each other, the particle removal effi ciency of the ESP 

can be compromised. 

Flue Gas Scrubbing 

An appropriately designed fl ue gas scrubbing process can 

easily meet the Refi nery NSPS particulate and SOx emission 

limits. As specifi ed in the proposed MACT II rule, an FCC 

Unit which meets the requirements of the Refi nery NSPS is 

considered in compliance with MACT II(12). As a result, 

FCC Units equipped with fl ue gas scrubbers will be in compliance 

with both MACT II and NSPS. In order to maintain 

their NSPS “grandfathered” status, many FCC Units have 

not undergone process modifi cation. Th e installation of fl ue 

gas scubbers in these units will satisfy the MACT II require- 

ments, as well as allow for process changes. 

Figure 7 shows a schematic of an ExxonMobil Wet Gas 

Scrubber(13). Th e fl ue gas enters the scrubbers where intensive 

contact between the gas and liquid removes both the 

particulates and sulfur oxides. Particulate capture occurs by 

inertial impaction of the liquid droplets with particles in the 

gas stream. Sulfur oxide removal occurs by reaction with a 

well known sulfi te buff er. Th us, the system provides a single 

step removal of both pollutants. 

Figure 7: Wet Gas Scrubbing Process 

controls both SOx And Particulates 


Th e clean gas is separated from the “dirty” liquid in the separator 

drum. Th e cleaned gas then exits to the atmosphere 

through a stack mounted on top of the separator drum. 

Th e scrubbing liquid is regenerated by direct addition of a 

sodium based chemical to the scrubber liquor and recycled 

back to the scrubbers. Water lost through evaporation and 

purge is also made up. A liquid stream may be purged from 

the disengaging drum to maintain an equilibrium concentration 

of solids and dissolved salts (products of sulfur 

oxide removal) within the system. Th e purge stream can be 

further treated in the Purge Treatment Unit (PTU) to reduce 

its Chemical Oxygen Demand (COD) and Total Suspended 

Solids content to environmentally acceptable levels. Exxon- 

Mobil Wet Gas Scrubbing (WGS), also off ered by Halliburton 

KBR, is a widely commercialized FCC fl ue gas scrubbing 

technology with sixteen units in operation and additional 

units are planned or in construction. Flue gas scrubbing 

systems have demonstrated, on a long-term basis, the ability 

to remove particulates to very low levels. In addition, fl ue 

gas scrubbing systems have demonstrated SO2 removal in 

excess of 90 percent, with several demonstrating effi ciencies 


above 99 percent. Operating experience has shown that dayto-day 

changes in fl ue gas rate, composition, solids loading, 

temperature, etc. can readily be handled, with small changes 

in the fl ue gas scrubber operating conditions. 

Flue Gas NOx Origin 

In general, nitrogen oxides (NOx) are generated Either from 

thermal oxidation of nitrogen in the combustion air which 

is known as thermal NOx, or by oxidation of organically 

bound nitrogen found in a fuel known as fuel NOx. In the 

FCC process, fuel NOx is produced in the regenerator as 

result of burning nitrogen contained in coke that originates 

from the FCC feed (14). Very little thermal NOx is generated 

in FCC because of the low operating temperatures. Th e 

nitrogen oxide species presen in the regenerator are mostly 

in the form of NO and NO2 with higher proportion of NO. 

Th e factors that aff ect NOx generation in the FCCU regenerator 

include fl ue gas oxygen content, carbon on regenerated 

catalyst, regenerator design, combustion/particle temperature, 

concentration of nitrogen in coke and FCC additives 

such as CO promoters and SOx additives. 

Current methods for controlling the NOx from FCC 

regenerator fl ue gas can be grouped into the following two 

classifi cations: 

• 

• 

Post regeneration technologies such as Selective Cata- 

lytic Reduction (SCR) and Selective Non-Catalytic 

Reduction (SNCR). 

Source control technologies such as catalyst additives, 

feed hydrotreating, and counter-current regeneration 

which lower the amount of NOx produced in the FCC 

regenerator. 

FCC REGENERATOR NOX 

EMISSIONS 

•NOx originates from nitrogen 

in the FCC feedstock. 

•The coke contains less than 

60% of the nitrogen in the FCC 

feedstock. 

•Less than 30% of the nitrogen in 

the coke is converted to NOx in 

the regenerator. 

Selective Catalytic Reduction (SCR) 

SCR technology is commercially proven for reducing NOx 

in FCC regenerator fl ue gas and involves the reaction of ammonia 

with NOx in the presence of oxygen and catalyst. Th e 

catalyst, depicted in Figure 8, is most commonly vanadium 

pentoxide/titanium dioxide based(15). Other catalysts based 

on precious metals (platinum or palladium) or zeolites can 

also be used as SCR catalyst. SCRs can operate in the temperature 

range between 300 and 1100°F (16,17) depending 

on the catalyst (preferably 600 to 750°F for vanadium pentoxide/ 

titanium dioxide catalyst) and achieve greater than 

90% NOx removal effi ciency. A NH3/NOx molar ratio of 1.0 

or slightly higher is commonly used in modern SCR systems. 

Th e reactions between NOx and ammonia on the SCR catalyst 

are as follows: 

4 NH3 + 4 NO + O2 �4 N2 + 6 H2O 

4 NH3 + 2 NO2 + O2 �3 N2 + 6 H2O 

Th e fi rst reaction is the conversion of NO to nitrogen and 

the second reaction is the conversion of NO2 to nitrogen. 

One mole of ammonia is required to convert one mole of 

NO, whereas, 2 moles of ammonia are required to convert 

one mole of NO2. Th is means that as the NO2 concentration 

in the fl ue gas increases, the amount of ammonia required 

will increase. Th ere is usually Suffi cient oxygen in the fl ue 

gas without the need to supply additional oxygen. 

Figure 8: SCR Catalyst Beds 



Another important reaction is the oxidation of 

SO2 to SO3: 

2SO2 + O2�2SO3 

Th is reaction is reversible. Th e SO2 conversion to SO3 is a 

function of temperature and the SCR catalyst formulation 

(V2O5 content). Irrespective of the catalyst formulation, the 

SO2 conversion increases with temperature in the range of 

interest. 

Unreacted NH3 leaving the SCR reacts with sulfur trioxide 

to form ammonium sulfate and bisulfate that deposit on 

downstream equipment. Th e key reactions for the formation 

of ammonium bisulfate and ammonium sulfate are shown 

below and data describing their formation as a function of 

temperature are presented in Figure 9(18). 

NH3 + SO3 + H2O� NH4HSO4 

2NH3 + SO3 + H2O � (NH4)2SO4 

Ammonium sulfates deposit on surfaces below 450°F(19) 

and increase particulate emission. Ammonium sulfate is a 

dry particulate matter that contributes to plume formation. 

Ammonium bisulfate is highly acidic and sticky substance, 

which deposits on downstream equipment such as convection 

coils and air heaters or economizers resulting in 

pluggage and deterioration of equipment performance (19). 

Keeping ammonia slip low and monitoring downstream fl ue 

gas temperature can minimize deposit formation. 

Th e SCR catalyst normally consists of a ceramic substrate 

or a metal carrier and active ingredients dispersed in the 

carrier. A typical carrier is titanium dioxide (TiO2); tungsten 

trioxide (WO3) is also added to provide strength and 

thermal stability. Th e three popular shapes of SCR catalyst 

available are honeycomb, corrugated and plate. 

Th e types of ammonia available are anhydrous, aqueous and 

urea (CO(NH2)2). Anhydrous ammonia has a high vapor 

pressure at ambient temperature, and thus requires pressurized 

storage. It is very toxic and its release to the atmos- 

phere may present an inhalation hazard, which makes 

transportation of pure anhydrous ammonia less desirable 

from a safety standpoint than in its aqueous form. It is also 

subject to risk management regulations imposed by regulatory 

authorities such as EPA as well as OSHA. However, the 

energy required to vaporize a pound of anhydrous ammonia 

is less than required to vaporize a pound of aqueous amonia 

and transportation costs are also less because of the water 

content. 

Figure 9: Salt Formation Temperatures 

Ammonium - Sulfate and Bisulfate 


Aqueous ammonia, which is commonly used, is less hazardous. 

A typical industrial grade contains approximately 25 to 

29 wt% ammonia in water. Th is ammonia-water mixture has 

a nearly atmospheric vapor pressure at ambient temperature 

and it can be more safely transported by road. Depending on 

site-specifi cs, storage would still be in a pressurized container 

and other special precautions may be taken to prevent 

ammonia vapor from reaching its explosive limits. 

Urea is not commonly used directly for SCR applications. 

However, urea-to-ammonia conversion systems (20) are now 

available and could be used where anhydrous or aqueous 

ammonia transportation or storage is viewed as an unacceptable 

risk. Th e current process hydrolyzes urea solution to an 

ammonia/CO2 gas mixture that meets the dynamic requirements 

of the NOx control system. 

For an aqueous ammonia system, the ammonia skid comprises 

of ammonia storage tank, ammonia injection pump, 

dilution air fan and heater, ammonia vaporizer and ammonia 

injection grid, control valves and fl ow meters. Th e 

aqueous ammonia is pumped, metered and sprayed into the 

vaporizer. It is then combined with preheated dilution air 

before being injected through distribution grids located in 

the fl ue gas line near the inlet of the SCR. 

Soot blowers are used when the SCR inlet dust loading is 

high to remove accumulated dust from the SCR catalyst surface. 

If the dust settles on the catalyst surface or enters and 

plugs the micropores, the SCR catalyst activity is reduced 

because of the unavailability of active sites. Th e traditional 


method of catalyst cleaning is the use of rake type soot 

blowers. Th e nozzles can be fi xed or rotary. Soot blowers use 

either superheated steam or dry air. Th ey can be sequenced 

to cycle once per shift depending on the dust loading. Sonic 

or acoustic horns are also being considered as alternate to 

steam soot blowing in SCR applications. 

Th e SCR is usually installed downstream of the waste heat 

boiler either before or aft er the electrostatic precipitator. 

In either case, the waste heat boiler must be modifi ed by 

removing the economizer tubes or by providing hot gas 

bypass around it to maintain the fl ue gas temperature to the 

SCR. Ammonia slip is a term used to describe the amount of 

ammonia escaping unreacted from the reaction zone in the 

fl ue gas. Th e most important parameters considered for the 

design of the SCR are the interdependence between NOx reduction, 

ammonia slip and the catalyst volume. Th e required 

volume of catalyst increases with the design NOx removal effi 

ciency, and for a given volume of catalyst, the NOx removal 

effi ciency increases with ammonia slip, as shown in Figure 

10(18). Careful consideration must also be given to design 

catalyst life and overpressure protection for the SCR. 

Selective Non-Catalytic Reduction (SNCR) 

SNCR involves the reduction of NOx with ammonia or urea 

in the absence of catalyst at high temperatures. Th e principal 

reactions between NOx and ammonia are: 

4NH3 + 6NO � 5N2 + 6H2O 

8NH3 + 6NO2�7N2 +12H2O 

Figure 10: SNCR Ammonia Slip 

Typical Performance 


Depending on the temperature, NH3 can be oxidized to produce 

more NO. Urea decomposes to form NH2 radicals and 

CO that react with NOx with the following overall reaction: 

CO (NH2)2 + 2NO + 0.5O2 � 2N2 + CO2 + 2H2O 

In the typical application of SNCR depicted in Figure 

11(21), fl ue gas temperatures in the range of 1600 to 1900°F 

are required as well as suffi cient residence time at these 

temperatures to promote the best NOx reduction. Also, 

through the use of secondary reductant additions, this temperature 

range, which displays a characteristic peak, may be 

shift ed to lower operating temperature ranges (22). 

Figure 11: SNCR Temperature Window 

Typical Performance 


SNCR requires some amount of excess ammonia addition 

above stoichiometric requirements to achieve high NOx 

reduction. Th is requirement is due, in part, to the thermally 

driven ammonia consumption reactions occurring before 

the NOx reduction reactions. Ammonia slip in SNCR applications 

is typically 10 to 50 ppmv. 

Due to the low NOx reduction at low temperatures, SNCR 

is not currently used to treat fl ue gas from an FCC regenerator 

operating in complete combustion mode, with typical 

exhaust temperature of 1350 °F. For SNCR to be most 

eff ective, the fl ue gas must be reheated to between 1600 to 

1800 °F, which would normally be cost prohibitive. In an 

FCC operating in partial combustion mode, an SNCR can 

be used to reduce NOx by applying it to the CO boiler which 

is normally operated above 1600 °F and which has suffi cient 

residence time at temperature to achieve SNCR goals. For 

this case, ammonia vapor or urea solution is injected into the 

combustion zone at a location most favorable for NOx removal. 

SCNR NOx removal effi ciencies achievable can range 

from 30 to 70% depending upon site-specifi cs. 


Catalyst Additives 

Platinum based CO combustion promoters are known to 

increase FCC NOx emissions. Non-platinum based CO 

combustion promoters are now available and can be used to 

reduce NOx generation in FCC regenerators. In commercial 

tests of non-platinum based CO promoters, they have 

reduced NOx emission by 25 to 85%(23) compared to NOx 

emissions while using platinum based CO promoters. 

Specially formulated FCC catalyst additives can also be 

added to the regenerator to promote the reduction of NOx 

formed to nitrogen and water. Th ese catalysts promote the 

reduction reaction between carbon or carbon monoxide and 

nitrogen oxides inside the regenerator. 

Figure 12: Counter-Current Regenerator 

Controlled Combustion 


Catalyst manufacturers are currently conducting commercial 

tests at selected refi neries to evaluate the eff ectiveness of 

NOx reducing additives. Published results indicate a broad 

range of NOx reduction percentages with a 40 to 50% reduction 

being most common(24). NOx reducing additives may 

be most economical in cases where the amount of NOx reduction 

required does not justify the installation of an SCR. 

FCC Regenerator Design for Low NOx Emission 

Th e FCC regenerator design also plays an important role in 

NOx emission because the percentage of nitrogen in coke 

converted to NOx varies widely with regenerator design. In 

the KBR counter-current regenerator, the coke-rich incoming 

spent catalyst is evenly distributed and fi rst exposed to 

regeneration gas near the top of the fl uid bed, as shown in 

Figure 12. Th e carbon-rich environment at the top of the 

fl uid bed promotes the reduction of NOx to nitrogen according 

to the following reaction mechanism: 

2C + 2NO _ 2CO + N2 

For a given concentration of nitrogen in coke, the KBR Orthofl 

ow regenerator produces 60 to 80% less NOx than other 

types of regenerators as shown in Figure 13. 

Figure 13: NOx from FCC Coke Burning 

Impact of regenerator design 


Conclusion 

Th e proper choice of technology to comply with environmental 

requirements is greatly infl uenced by the specifi cs of 

the application and the overall goals of the facility. 

What might be a great option for one facility may not work 

for another. Table 5 summarizes the relative attributes of the 

FCC regenerator fl ue gas control technologies discussed in 

this paper and provides insight into which technology is best 

suited to a particular application. 

Based on 

NSPS or MACT 

II Limits 

Particulate 

Control 

Expander 

Protection 

Cyclofi nes TM 

TSS 

ESP Flue Gas 

Scrubbet 

SCR 

SNCR 

Catalyst 

Additives 

Yes Yes Yes No No No 

Yes No No No No No 

Counter- 

Current 

Regen 

CO Control No No No No Yes No 

SOx Control No No Yes No Yes No 

NOx Control No No No Yes Yes Yes 

Major Utilities None Electricity Caustic Ammonia 

Consumption 

Soda ash Urea 

Water 

Steam 

Electricity 

Catalyst 


References 

1.Title 40, Code of Federal Regulations, Part 60 – 

Standards of Performance for New Stationary 

Sources,Subpart J, (40 CFR 60.100-109, NSPS Refi ning). 

2.Title 40, Code of Federal Regulations, Part 60– Standards 

of Performance for New Stationary Sources, 

Subpart A, (40 CFR 60.14 Modifi cation, & 60.15 

Reconstruction) 

3.Federal Register, volume 60, Page 43244, August18, 

1995 (60 FR 43244) 

4.National Emission Standard for Hazardous Air Pollutants 

from Petroleum Refi neries - Catalytic Cracking 

(fl uidized and other) Units, Catalytic Reforming 

Units, and Sulfur Plant Units (63 FR 48890, 9/11/98). 

5.WWW.usdoj.gov Web Site. 

6.Federal Register, Volume 66, Page 26178, May 14, 

2001 ( 66 FR 26178) EPA’s Unifi ed Agenda, Item 

Number 3324. 

7.Bussey, B. K., Chitnis, G. K, and Schatz, K. W., New 

FCC Particulate Abatement Technology, 1997 NPRA 

Annual Meeting. Paper No. AM-97-1. 

8.Raterman, M., Chitnis, G. K., Holtan,T. and Bussey, B. 

K., A Post Audit of the New Mobil – Kellogg CycloFines 

TSS, 1998 NPRA Annual Meeting. Paper No. 

AM-98-19. 

9.White, H. J., Resistivity Problems in Electrostatic 

Precipitation. Air Pollution Control Assoc. 24 (April 

1974: 314). 

10.Cooper, C. and Alley, F., AIR POLLUTION CON- 

TROL - A Design Approach, 2nd ed. Waveland Press, 

Inc. 1994 

11.Wark, K. and Warner, C. F., AIR POLLUTION - Its 

Origin and Control, 2nd ed. Harper Collins Publishers, 

1981. 

12. Title 40, Code of Federal Regulations, Part 63-National 

Emission Standards for Hazardous Air Pollutants 

for Source Categories, (40 CFR 63.1560(d)) 

13. Cunic, J. D. and Feinberg, A. S., Innovations in 

FCCU Wet Gas Scrubbing, 1996 NPRA Annual Meeting. 

14. Mathias, S. A., Stevenson, R. F. and Apelia, M. R., 

Th e NOx Formation Mechanism in an FCC Regenerator.Environmental 

Reaction Engineering I, AIChE 

Meeting, November 1997, Los Angeles CA. 

15. Anderson, M.R. and Nolen, C.H, NOx Emission 

Control Strategies, Responding to the Houston/ 

Galveston Area NOx Rules, Dec 18, 2000. 

16. Sandell, M. Putting NOx in a Box, 3/98 Pollution 

Engineering. 

17. Frey, C. H., Engineering-Economic Evaluation of 

SCR NOx Control Systems for Coal-Fired Power 

Plants. Proceedings of the American Power Conf., 

Vol 57-II, April 1995, pp 1583-1588. 

18. API 536, Post – Combustion NOx Control for Fire 

Equipment in General Refi nery Services, First Edition, 

March 1998. 

19. Hernquist, R. W., SCR Tackles NOx and Ammonia 

despite High NOx, Dust and Sox Loadings. Chemical 

Engineering, Feb 2001, pp 95-99. 

20. Spencer III, H. W., Peters, J. and Fisher, J, U 2 A 

Urea-to-Ammonia “State of the Technology”, Th e 

Mega Symposium, August 20-23, Chicago, IL. 

21.Fuel Tech, NOx-Out Brochure 

22. Mansour, N. and Sudduth, B.C., Integrated Catalytic/Non-catalytic 

Process for Selective Reduction of 

Nitrogen Oxides, US Patent No. 5,510,092, April 1996. 

23. Davison Catalgram, Number 85, 1997. 

24. Davison Catalgram, Clean Air Catalysts: Hydroprocessing, 

FCC Catalysts and Additives for Clean Fuels 

and Emission Control. Number 89, 2001.

am-02-27 fcc flue gas emission control options - KBR

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