FCC Flue Gas Emission Control Options

AM-02-27

FCC FLUE GAS EMISSION CONTROL OPTIONS

Authors: Phillip K. NiccumChief Technology Engineer, FCCEusebius GbordzoePrincipal Engineer, FCCStephan LangPrincipal Engineer, Environmental

Publication / Presented: NPRA2002 Annual Meeting

Date: March 17-19, 2002

Notes: Marriott Rivercenter HotelSan Antonio, TX

For more information, visit www.kbr.com

IntroductionFluid 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 pro-cess has evolved with it, meeting the challenges of cracking heavier, more contaminated feedstocks, while still accom-modating 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

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 emis-sions have also been widely applied, utilizing a combination of technologies (alone or in combination) such as feed des-ulfurization, 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 qual-ity, targeted emission level.

Regulatory ReviewIn the United States, there are currently three major regula-tory drivers impacting FCCU fl ue gas controls and thus future emission limitations. Th ese are (1) the continuing ap-plication 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) en-forcement 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 anymaster 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.

NSPSNew 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 permit-ted or modifi ed.

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

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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 exist-ing 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 regula-tions, will establish the allowable pollution levels for FCCU regenerator particulate matter and carbon monoxide emis-sions. 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 demon-strate 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, beryl-lium, 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 operat-ing 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 Con-sent 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 limita-tions 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 1FCCU Emissions Control Regulatory Drivers

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 appli-cable to FCCU regenerators are presented in Table 2.Table 2FCCU Regenerator Flue Gas Emission Control RequirementsIn 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 concen-tration 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 Emissions/ Regulatory Item

Applicability of Major Regulatory Drivers

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


Table 3Typical Flue Gas Particulate Concentrations forCompliance with NSPS / MACT IISeveral options for controlling FCC fl ue gas particulate, SOx and NOx emissions to meet environmental requirements are discussed in more detail below.

Third Stage SeparatorsTh ird stage separators (TSS) provide another stage of cyclonic separation in addition to the two stages of cy-clones 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 exit-ing the regenerator, as shown in Figure 2.

Th e FCC technologies off ered by Halliburton KBR include the CycloFinesTM TSS, which uses patented cyclone technology and a proprietary design to remove catalyst fi nes from FCC regenerator fl ue gas. Th e CycloFinesTM 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 emis-sion limits(7).

Th e CycloFinesTM TSS development program was initi-ated to determine if existing TSS designs that were under-performing in ExxonMobil refi neries could be improved. Th e initial investigation led to cold fl ow modeling of full scale cyclone elements.

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% re-duction, 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

40 CFR 60.104(b)(2)Or40 CFR 60.104(b)(3)

Without add-on SO2 , Control device

Nickel L lb PM/1000 lb coke burn-off

See proposed 40 CFR 63 -Sub-part UU (MACT II), 13,000 mg/hr (0.029 lb/hr) of Ni.

Nitrogen Oxides (NOx)

NA Consent Decrees 20 ppmvd considered achieve-able within Consent Decrees

Notes:1) ppmvd = parts per million, volume, dry basis corrected to 0% O22) 40 CFR 60 = Title 40, Code of Federal Regulations, Part 60, also known as the New Source Per-formance Standards. Subpart J (60.100-60.109) covers Standards of Performance for Petroleum Refi neries3) CEMS = Continuous emissions monitoring system. When concentration limits imposed, O2 per40 CFR 60.105(a)(10)

Regenerator Operating Mode

Complete COCombustion

Partial COCombustion



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

1.0 1.0 1.0 1.0

Flue gas particu-late, mg/Nm3

97 109 116 124

8

Figure 2: Third Stage Separator Controlling Particulate Emissions and Expander

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In these tests, cyclone diameter, orientation, gas inlet, gas outlet, and proprietary confi gurations were optimized.

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 CycloFinesTM TSS.CycloFinesTM technology was fi rst commercialized for envi-ronmental protection in September 1997 at the ExxonMobil refi nery in Altona, Australia with a conventional 4th stage cyclone on the underfl ow. Th e CycloFinesTM 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 pro-viding 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 par-ticulate emission limit of 1.0 lb catalyst per 1000 lb of coke.

Table 4CycloFinesTM TSS Commercial Data from ExxonMobil Altona

Not only has the CycloFinesTM 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 CycloFinesTM

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 fu-ture 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 PrecipitatorsElectrostatic 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 emis-sions 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; particlecharging, particle collection, and particle removal. Eachstep must be executed properly in order to eff ectively remove particulate to acceptable levels.

Figure 3: CycloFinesTM TSS

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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, % 1.5 1.5 None

COLLECTION DATA

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


Th e process of charging a particle is accomplished by estab-lishing 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 dis-charge 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 cur-rent 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 sur-face 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 displayhigh 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 begenerated, the resistive particle will simply pass through the ESP.Th e particle collection process begins the moment the par-ticle 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.

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 surfaceconduction 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).

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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

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Figure 5: ESP Particle Charging Process


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 hop-pers. 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 col-lected 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 oper-ated 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 ScrubbingAn 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 com-pliance 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 in-tensive 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.

Th e clean gas is separated from the “dirty” liquid in the sepa-rator 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 con-centration 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 Hallibur-ton 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

Figure 6: Effect of Flue Gas Properties on Resistivity of dust

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Figure 7: Wet Gas Scrubbing Process controls both SOx And Particulates

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above 99 percent. Operating experience has shown that day-to-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 OriginIn 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 gener-ated 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 regener-ator include fl ue gas oxygen content, carbon on regenerated catalyst, regenerator design, combustion/particle tempera-ture, 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.

Selective Catalytic Reduction (SCR)SCR technology is commercially proven for reducing NOx in FCC regenerator fl ue gas and involves the reaction of am-monia 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 tem-perature range between 300 and 1100°F (16,17) depending on the catalyst (preferably 600 to 750°F for vanadium pen-toxide/ 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 cata-lyst are as follows:4 NH3 + 4 NO + O2 4 N2 + 6 H2O4 NH3 + 2 NO2 + O2 3 N2 + 6 H2OTh 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.

FCC REGENERATOR NOX EMISSIONS

•NOx originates from nitrogenin 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.

Figure 8: SCR Catalyst Beds

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Another important reaction is the oxidation of SO2 to SO3:2SO2 + O2 2SO3Th 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 NH4HSO42NH3 + SO3 + H2O (NH4)2SO4Ammonium 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 con-vection 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); tung-sten 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 pres-surized storage. It is very toxic and its release to the atmosphere 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 regula-tory 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.

Aqueous ammonia, which is commonly used, is less hazard-ous. 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 con-tainer 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 unaccept-able risk. Th e current process hydrolyzes urea solution to an ammonia/CO2 gas mixture that meets the dynamic require-ments of the NOx control system.For an aqueous ammonia system, the ammonia skid com-prises of ammonia storage tank, ammonia injection pump, dilution air fan and heater, ammonia vaporizer and am-monia 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 sur-face. 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

Figure 9: Salt Formation Temperatures Ammonium - Sulfate and Bisulfate

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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 re-duction, ammonia slip and the catalyst volume. Th e required volume of catalyst increases with the design NOx removal ef-fi 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 + 6H2O8NH3 + 6NO2 7N2 +12H2O

Depending on the temperature, NH3 can be oxidized to pro-duce 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 + 2H2OIn 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 tem-perature range, which displays a characteristic peak, may be shift ed to lower operating temperature ranges (22).

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 ap-plications 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 regenera-tor operating in complete combustion mode, with typi-cal 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 re-moval. SCNR NOx removal effi ciencies achievable can range from 30 to 70% depending upon site-specifi cs.

Figure 10: SNCR Ammonia Slip Typical Performance

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Figure 11: SNCR Temperature Window Typical Performance

OrthofflowTM FCC


Catalyst AdditivesPlatinum 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 commer-cial 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.

Catalyst manufacturers are currently conducting commer-cial 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% reduc-tion being most common(24). NOx reducing additives may be most economical in cases where the amount of NOx re-duction required does not justify the installation of an SCR.

FCC Regenerator Design for Low NOx EmissionTh 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 incom-ing 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 accord-ing to the following reaction mechanism:

2C + 2NO _ 2CO + N2 For a given concentration of nitrogen in coke, the KBR Or-thofl ow regenerator produces 60 to 80% less NOx than other types of regenerators as shown in Figure 13.

ConclusionTh e proper choice of technology to comply with environ-mental 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.

Figure 12: Counter-Current Regenerator Controlled Combustion

OrthofflowTM FCC

Figure 13: NOx from FCC Coke Burning Impact of regenerator design

OrthofflowTM FCC

Based on NSPS or MACT II Limits

Cyclofi nesTM TSS

ESP Flue GasScrubbet

SCRSNCR

CatalystAdditives

Counter-Current Regen

Particulate Control

Yes Yes Yes No No No

Expander Protection

Yes No No No No No

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 Consumption

None Electricity Caustic Soda ash WaterSteam Electricity

AmmoniaUreaCatalyst


References1.Title 40, Code of Federal Regulations, Part 60 –

Standards of Performance for New Stationary Sources,Subpart J, (40 CFR 60.100-109, NSPS Refi n-ing).

2.Title 40, Code of Federal Regulations, Part 60– Stan-dards 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 Pol-lutants from Petroleum Refi neries - Catalytic Crack-ing (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 Cy-cloFines 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 Publish-ers, 1981.

12. Title 40, Code of Federal Regulations, Part 63-Na-tional Emission Standards for Hazardous Air Pollut-ants 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 Meet-ing.

14. Mathias, S. A., Stevenson, R. F. and Apelia, M. R., Th e NOx Formation Mechanism in an FCC Regen-erator.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 Edi-tion, 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 Brochure22. Mansour, N. and Sudduth, B.C., Integrated Cata-

lytic/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: Hydropro-

cessing, FCC Catalysts and Additives for Clean Fuels and Emission Control. Number 89, 2001.

FCC Flue Gas Emission Control Options

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