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Fluid Catalytic Cracking Units (FCCU)
October 1995

TNRCC Rule 116.111(3) in Regulation VI requires that Best Available Control Technology
(BACT) be applied to all facilities that must obtain a permit.  BACT determinations are made on a
case-by-case basis.  Current BACT guidelines for FCCU is:  

                                   CEMS      Control Technology

PM        NSPS            no            electrostatic precipitator (EPS) 

Opacity   15-20%         yes            same as PM

CO        500 ppmv       yes            hot regenerator
                                                       CO boiler
                                                       CO combustion promoters

SO2       200-300 ppmv   yes            scrubber (or alternative method
                                                  of flue gas desulfurization)
                                                       feedstock hydrodesulfurization
                                                       and/or blending
                                                       SOx reduction catalysts

NOx       200 ppmv         yes          minimize use of CO combustion

VOC       <10 ppmv        no            complete combustion

Comments on BACT:

(a)  The PM emission rate is obtained from the maximum coke burn-off rate.  PM emission
     rates have also been calculated using the AP-42 emission factor of 19 lbs per 1,000 bbl
     of fresh feed.  This is acceptable but does not obviate the need to demonstrate
     compliance with the NSPS PM standard if NSPS is applicable.

     When the NSPS PM standard was promulgated by EPA, their test method measured the
     filterable portion only; that is, the impinger catch (or condensible PM) was not
     included.  TNRCC practice has always added both to determine PM; that is, PM
     always means total suspended particulate (TSP) in the state program.  Because of the
     nature of the NSPS PM standard, some state permits have included two limits, one for
     filterable PM based on NSPS, and one for TSP based on Reg I.  It should be noted that
     Reg I is reasonably available control technology (RACT) and not BACT.  Accordingly,
     Reg I does not constitute a BACT review for TSP so that the applicant still has the
     burden of demonstrating BACT for the project.  The TSP issue is more likely to be
     raised by the applicant if an ESP is the final PM control device.

(b)  PM control usually consists of two or three stage cyclones, followed by either an ESP
     or a scrubber designed for both PM and SO2 removal.  TNRCC staff believe that
     scrubbers may have a higher degree of reliability.

(c)  Occasionally an operator will propose ammonia injection as a means of improving ESP
     opacity control.  Ammonia injection for opacity control is not necessary in a properly
     designed and operated system and is not considered BACT.

(d)  When a grandfathered FCCU is brought into the permit process, that act does not
     necessarily trigger a BACT review with regard to all pollutants.  For example, if the
     operator proposes to use CO combustion promoters in a grandfathered FCCU, SO2
     would not normally be an affected pollutant.  In this example, the BACT review would
     not be extended to SO2, instead the grandfathered SO2 emission rate would be
     determined and incorporated in the permit. Grandfathered emission rates are based on
     actual operating data, not on nameplate or design capacity.

(e)  A CEMS is required with regard to opacity, CO, SO2, and NOx, but not with regard to
     VOC.  For CO, concentration is measured on a ppmvd basis averaged over a one-hour
     period.  For SO2, concentration is measured on a ppmvd, air-free basis, averaged over
     a one-hour period.  CO and SO2 follow NSPS Subpart J practice.  There is no set
     standard practice with regard to NOx.

     Each CEMS must comply with all applicable state and federal requirements.  An
     oxygen CEMS will also be needed.

(f)  The most direct means of complying with the CO limit is to operate the regenerator at a
     higher temperature.  (Hot regenerator means an operating temperature of about
     1,350F.)  Sometimes the metallurgy of an existing unit does not allow this.  However,
     many of the newer units can operate hot.  The operator usually selects one or more of
     these options: hot regenerator, CO combustion promoters, CO boiler(s).  The CO
     boiler has the advantage of contributing process steam.

(g)  Regenerator SO2 (and NOx) emissions will reflect to some degree the composition of
     the crude.  Approximately 10 to 20% of the total sulfur in the FCCU feedstocks
     remains in the coke on the catalyst.  (In order to be conservative, use 20%.)

(h)       The design and operation of an add-on scrubber must assure at least 90% SO2 removal,
          a NSPS requirement.  NSPS contains provisions governing continuous demonstration of
     compliance with Subpart J, SO2 limits.

          The add-on "scrubber" is actually an absorber.  A caustic solution is utilized. They are
     often referred to as "sodium scrubbers."  The amount of sodium hydroxide (SOx)
          consumed by these scrubbers is approximately 1.15 times the amount of SOx in the inlet
          gas.  The pH of the circulating scrubbing liquid should be maintained above 6.0 at all

     Venturi or tray tower scrubbers may be used.  A tray tower is less attractive if
     simultaneous PM removal is desired.  Jet-ejector and high energy venturi scrubbers have
     been used successfully in Texas.  Downstream of a CO boiler, a jet- ejector venturi
     scrubber would normally be used.  With a hot regenerator only, a high energy venturi
     scrubber would normally be used.

     All currently existing systems in Texas are venturi scrubbers.  The addition of water is
     usually controlled by a water level monitor on the separation tank.  The addition of caustic
     is usually controlled by a pH monitor.  Each permit will require continuous monitoring of
     liquid pH to provide a continuous demonstration of compliance.  A number of other
     approaches for monitoring scrubber operations have been suggested to enhance
     continuous demonstration of compliance.  These include pressure drop through the
     venturi, scrubber liquid/flue gas ratio, and throat velocity ratio.  One of these may also be
     incorporated in the permit.

     On-site wastewater facilities will be needed.  At inland locations where wastewater
     disposal may be a problem, alternative scrubbing systems such as dual alkali or citrate
     scrubbing systems may be considered, or a different control technology such as SOx
     reduction catalysts can be selected.  A citrate based system has been used in a cat cracker
     application in Texas (it was not considered a success).

     The agency is very supportive of the use of scrubbers in FCCU regenerator vent gas
     control because opacity and PM are also very effectively controlled.  Opacity is reduced to
     less than 15%.  As of October 1, 1994, eight scrubbers were in cat cracker catalyst
     regenerator flue gas vent service.

     The maximum BACT limit for SO2 emissions of 300 ppmv allows the operator to select
     control technologies other than scrubbers.  It should be noted that an add-on scrubber can
     be designed and operated to limit SO2 emissions to 200 ppmv or less.

(i)            SOx reduction catalysts reduce FCCU SOx emissions by about 70%, most of which is
               transferred to the refinery sulfur plant as an increased sulfur load.  Therefore, if SOx
               reduction catalysts are to be used, the sulfur plant must be carefully evaluated to assure
               that adequate capacity is available; and any related amendment to the sulfur plant
               permit must be secured.

(j)           Regenerator NOx forms by two mechanisms: thermal NOx as a result of the combustion
               process, and chemical NOx from nitrogen present in the coke.  Regenerator
               temperatures are not high enough to create large amounts of thermal NOx.  Even in hot
               regenerator operation, NOx emissions are generally less than 200 ppmv.  Chemical NOx
               is the dominant mechanism.

               NOx emissions increase when CO combustion promoters or CO boilers are used. 
               Burner design can help control thermal NOx emissions from CO boilers.  NOx
               emissions do not seem to be significantly affected by hot regenerators.  If add-on
               scrubbers reduce NOx emissions, the effects have not been quantified.  There is no
               clear consensus on the effects of SOx reduction catalysts on NOx emissions (the effects
               are probably negligible).

               NOx may be adjusted to a value significantly higher than 200 ppmv on a case-by-case
               basis if the operator meets all of the other state and federal requirements and presents
               appropriate arguments together with supporting information.  There is no FCCU flue
               gas NOx control technology per se.

(k)            Any process (CO boilers, CO incinerators, regenerator  combustion promoters, hot
               regenerators) that pushes combustion to completion will significantly reduce VOC
               emissions.  VOC emissions from a hot regenerator are less than 10 ppmv.  It is
               unlikely that an add-on scrubber will significantly reduce VOC emissions.

(l)            A question arises on how to calculate BACT emission rates if a CO boiler is in the flue
               gas train given the fact that large amounts of refinery fuel gas are usually combined
               with the regenerator flue gas in order to assure good combustion.  Comments follow:

               VOC resulting from refinery fuel gas combustion can be estimated by using the AP-42
               emission factor for nonmethane volatile organics.  Regenerator-related VOC in the CO
               boiler outlet can be estimated by applying the DRE of the combustion device (typically
               99 to 99.9 percent) to the VOC waste load of the inlet flue gas (about 220 lbs of VOC
               per 1,000 bbl fresh feed).

               CO resulting from refinery fuel gas combustion can also be estimated using AP-42. 
               With regard to the flue gas, CO cannot result from the combustion of CO, but can
               result from flue gas VOC combustion.  Regenerator-related CO in the CO boiler outlet
               can be estimated by applying a destruction efficiency of 99 percent to the CO waste
               load of the inlet flue gas.  The final (combined) vent should be converted to ppmv to
               assure that the value does not exceed 500 ppmv.

               Refinery fuel gas related SO2 emissions can be readily estimated.  Regenerator-related
               SO2 emissions can be calculated using a BACT concentration of 300 ppmv and the flue
               gas flow rate prior to fuel gas addition.  If an add-on scrubber is used, the vent of the
               SO2 control device is the final vent so the combined flow is the one which is used in the
               calculation; however, a value of 200 ppmv or less will be applied.  In this case,
               refinery fuel gas related SO2 is not separately calculated.

               The amount of thermal NOx (typically much less than the chemical NOx) can be
               estimated using normal emission factors.  The use of burners which reduce thermal
               NOx emissions have been required in some cases.

               CO boiler related products of combustion PM can be estimated using AP-42. 
               However, if the CO boiler is followed by an add-on scrubber, normal practice has been
               to apply the NSPS emission rate to the scrubber vent and take the rate as representing
               TSP.  This treatment is possible because of the ability of the scrubber to reduce PM
               emissions well below the NSPS rate.