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For an FCC unit, conversion refers to the volume percent of the feedconverted to gasoline,light hydrocarbons, and coke. The conversion iscalculatedas 100 minus the volume percent of light cycle oil plus slurryoilproducts.
Hydrotreating the FCC feed can result in substantial benefits includingimprovedconversionof the heavy gas oilfeed,less severe orno hydrotreatingrequirements forFCC gasoline,reducedseverity hydrotreatingforthe FCCdistillate product,andreduced emissions fromthe FCC regenerator.
FCC hydrotreating projects can be very costly because the capacity isrelatively large compared with other refinery hydrotreating units. Forexample, a 100,000-b/sd refinery may have 50,000-b/sd of FCC feedmaterialto hydrotreat but only 20,000-30,000 b/sdof naphtha ordistillate.Typically this unit willoperate at substantially higherpressure thanotherhydrotreaters,thus increasingthe cost forexpensive alloys that are usedforpipingandequipment.
Hydrotreating FCC feed also produces significant quantities of hydrogensulfide andammonia that must be recoveredand disposedof appropriately.This step often requires new auxiliary facilities such as aminetreating K ,sulfur recovery L ,and sour-waterstripping
M . Furthermore,because of the relatively large capacity,additionalhydrogenis
needed,which might require more refinery hydrogen-generationcapacityorpurchase froma thirdparty.
Typical hydrotreated FCC product sulfur specifications are about 0.2 wt% if the main processing objective is improved conversion and reducedemissions. Some of the more recent feed hydrotreating projects havereducedproduct sulfurto about 500 ppm (wt).This reduces FCC-gasolinesulfurcontent to the extent that hydrotreatingafterthe FCC is not requiredto meet the US low-sulfur-gasoline requirements and similar standardsthat have beenadopted orare pendingin othercountries.
Nitrogenremoval andreduction inaromatics via saturationwithhydrogeninthe FCC feed are also important processingobjectives that canimproveFCC conversion.
FCC gasoline hydrotreating
N is a relatively new technology developedto assist refiners incomplyingwith US low-sulfur-gasoline requirements.These rules require that a refiners total gasoline pool have an averagesulfurcontent no greaterthan 30 ppm(wt)in a givenyear.
Feed to an FCC gasoline hydrotreater can vary from full boiling-rangematerial (C5 to 430 F. boiling range) to heavy FCC gasoline with a 325-430 F.boiling range.
StepsHeating
Inthe first stepina hydrotreatingprocess,a hydrocarbonstream(naphtha,dieselfuel,gasoline,gas oil)mixes withhydrogenand is heatedvia exchangewithhot reactorproducts in heat exchangers
1 andthenin a charge heater2 at moderate temperatures (600-800 F.)and pressures (300-1,500 psig).
The charge heatercontrols the temperature of the feed to the reactor.
ReactorInthe next step,the heatedoil-hydrogen mixture fromthe charge heater
enters the reactor 3 ,which is filledwithcatalyst inone ormore fixedbeds.Uniform feed distribution over the catalyst bed is important for maximumcatalyst utilization. Proprietary reactor internals can provide almost 100 %catalyst utilizationwhile ensuringalmost uniformdistributionof feedacrossthe catalyst bed.
Hydrotreating catalysts typically consist of a base material containingsmall quantities of cobalt and molybdenum, nickel and molybdenum,ora combination of both. The exact catalyst formulation varies according toa variety of criteria including feed composition,contaminant levels, andoperating pressure. The top and intermediate catalyst beds are supportedby a metalscreen affixedto the reactorwalls.The bottombedrests oninertsupport materialin the bottomof the reactor. Each catalyst bed can be upto 35 ft long.
The temperature rise through any one bed is typically limited to about50 F. At temperature increases greater than 50 F., a quench stream isadded between the beds. This requires special reactor internals to ensurethat the quench medium,usually hydrogen, is completely mixed with thematerial from the catalyst bed.
ContaminantsHydrogenreacts withorganicsulfur inthe feedoilto formH
2S,and reacts
withthe nitrogenin the oilto formammonia. These contaminants are thenremovedfromthe finalproduct stream.Hydrogen also reacts withthe olefinsanddiolefins to formparaffins and isoparaffins.
Contaminants innaphthahydrotreating are: Silicon. Normally found in naphthas from delayed cokers, silicon
deactivates hydrotreatingcatalysts but canbe abated withextra catalystandspecialized catalysts withhigh silica retentioncapacity.
Olefins. The saturation of olefins in the feed will lead to the formationof mercaptans that will not be removed from the treated product. Theresult is a product with excessive sulfur. This reaction normally occurswith coker naphtha and FCC gasoline and can be mitigated by adding asecond-stage reactorwithcooling betweenthe stages.
Diolefins. Normally associated with cracked naphthas,diole fins formpolymerization products,which are heavy materials resulting from thecombinationof many single molecules.These polymers normally formattemperaturesfound in the feedexchangers and can cause pluggingthatwillrestrict the flow throughthe unit.
Although not contaminants,lig ht ends (methane,ethane, propane, andbutanes) are usually formed to some degree in hydrotreating and must
be removedfromthe finalproduct. Light-endformation is usually minimal(less than1%) at naphtha-hydrotreaterprocess conditions.Contaminants indistillate hydrotreating are:
Nitrogen. Feed nitrogen levels can vary depending on the feed source.Product nitrogen content depends on the severity of hydrotreating. ForULSD,the product nitrogencontent willbe about equal to product sulfur.
Olefins.The highheat of reactioncan require aninter-reactor-bedquenchstream.
Aromatics.Depending onthe type of catalyst used,aromatics inthe feedcan react (saturate) with the hydrogen,and these reactions increasehydrogen consumption and heat release. Some European countriesand California require product aromatics levels as low as 10 vol %.Heat release inthe reactoris not necessarily undesirable.In fact,it resultsina reductioninoverallfuel consumption.Hydrogen,however,is generallyused for quench, which adds to compression requirements. Also thisdecreases the amount of hydrogen available forthe desirable hydrotreatingreactions.
Light ends. In distillate hydrocracking,side reactions convert about 2 wt %of thefeedinto light ends,depending onprocessconditions.In FCC feed hydrotreating , metals in
the feed can poison the catalyst. FCC feedhydrotreaters use feed filters to removesolids. Also in these units, a guard bedreactor
4 is normally installed upstreamof the main reactor. It contains a specialcatalyst that willcapture metals andpreventthemfrom poisoningthe maincatalyst.
As no ted p reviously, the reactor h asspecially designed internals to ensureuniform distribution of the hydrogen andhydrocarbons overthe catalyst.
The accompanying table shows typicalreactorconditions forhydrotreaters.
SeparatorsIn the next step,several arrangements
are available for separating liquids andvapor that exist in the reactor effluent. Ingeneral, the decision is whether to use ahot, high-pressure separator (HHPS) inaddition to a cold,high-p ressure separator(CHPS),or to use a CHPS on ly.
The HHPS 5 separates vapor,liquidhydrocarbons, and water and usuallyoperates at about 500-550 F. The hotvapors from the separator can be usedto heat recycle gas and liquids from thecold separator. The HHPS improves theefficiency of heat use in the hydrotreatingunit,which results in a smaller productstripper and auxiliary equipment. Usingan HHPS will also improve the oil-waterseparation in the CHPS.
Forheavygasoil hydrotreating ,a hot separator is practically mandatoryto achieve adequate oil-water separation. This is less of a concern fordiesel hydrotreating unless there are significant quantities of crackedmaterial in the unit feed, which decreases the API gravity.
Disadvantages of this design are a 5-10% lower recycle gas purity,which requires more recycle hydrogen compressor
6 horsepower. Usingan HHPS can be a viable option for increasing the capacity of an existing
hydrotreater that is limited by the flow of oil in the reactor loop. This revampwould require,however,a modest increase in inlet flow capacity and powerfor the recycle compressor.
Other options include using hot and cold low-pressure separators. Thesedesigns marginally decrease the amount of materials in the upper part ofthe stripper
7 and result in improved LPG recovery.
CompressorsThe recycle compressor 6 ,in the next step, circulates hydrogen and
light ends inthe reactor loop.The objective of the compressoris to provideexcess hydrogeninthe reactor,whichpromotes reactions andminimizes theamount coke produced.
Typically at the reactor inlet,at least four to five volumes of circulatinghydrogen to one volume of hydrogen actually consumed in the variousreactions are desiredto obtaina reasonable cycle length before the catalysthas to be replaced.A hydrotreatershouldtypically runat least 2 years beforeneedingto h ave its catalyst replaced.
The hydrogen compressor that handles the initial (makeup) hydrogen
stream compresses the makeup hydrogen,
8 which is typically froma reformer or hydrogen plant, from the supply pressure to the reactor-looppressure.
The numberof compressionstages depends on the source pressure andthe reactor-looppressure.
Towers
If a unit produces a single product,suchas with naphtha hydrotreaters,kerosine hydrotreaters,and some ULSD units,a strippertower 7 inthe finalstepdistills light ends,including hydrogensulfide fromthe bottomproduct.This towercanuse heat froma firedreboileror steam.Strippers have onlytwo product streams,a topand bottom.
With a steam stripper,d ownstream processing is required to removewater from the hydrotreated product. This is typically a salt dryer which isprecededby a coalesceror vacuumdryer.
If multiple products are produced (diesel and kerosine, or FCC feedand diesel,for example),then a fractionator 9 with a fired reboiler 10 isalso used.The charge heaterand firedreboiler share a commonstack
11 .Fractionators have multiple product streams.
Product strippers forFCC feedhydrotreaters cannot be reboiledbecausetemperatures of more than 700 F. are required to remove the light endsandhydrogen sulfide.These hightemperatures canlead to thermalcrackingsome of the product oilto light ends andaccelerated coke formation,whichis undesirable. Typically these strippers use a combination of feed heatingvia a furnace andsteam.
Refiners worldwide face new regulations thatrequire them to reduce sulfur in transportationfuels and,indirectly, intermediate products. Suchregulationshave recently taken effect in some regions;others willtake effect incoming years.
In the US,sulfur content has been reduced to an average30 ppm (wt) in motor gasoline and to 15-ppm (wt) maximumfor on-road diesel (ultralow-sulfur diesel; ULSD). This requirementfor on-road diesel practically always requires hydrotreating. Similarregulations are pending or have been implemented in Europe,South America,and Asia.
Hydrotreatingis a process that employs hydrogento remove sulfurand othercontaminants from refinery intermediate products and finished transportationfuels (called hydrotreating feed). It is,therefore, the primary process refiners areusingto comply withthe new regulations.
ProcessesSeveralhydrotreatingprocesses are typicallyfound in a refineryand are similarin concept
but have different operatingconditions andcosts. Naphthahydrotreating A removes sulfurandnitrogenfrom naphtha that is typically fedto catalytic
reforming(reformer B )and isomerization
C units to increase the octane number so that this materialcanbe blendedinto gasoline
D .Sulfur andnitrogen inthe feedto the reformerare catalyst poisons,andthe hydrotreatermust convert themto very low levels (0.5 ppmwt).
Naphtha hydrotreating feed comes from crude-oildistillation
E or from thermalprocesses such as delayedcoking F andvisbreaking.Distillate andgas-oil hydroprocessingunits canalso yielda smallnaphtha streamthatis usually processedin the naphtha hydrotreater.
Distillate hydrotreating G processes any of several refinery fuel products including jet fuel,on-road diesel, marinediesel,railroaddiesel, andhome heatingoil. Dieselhydrotreating,a formof distillate hydrotreating,removes organicsulfurfromdiesel.The feedtodistillate hydrotreating also comes fromcrude oildistillation,thermalprocesses,and fluidcatalyticcracking
H units.To allow
forsome contaminationin the distillate-product distributionsystem,andtherefore not exceed15 ppm(wt) at thepoint of sale,US refiners typically manufacture a ULSD product witha maximumsulfur content of about 7 ppm (wt).Otherdistillate streams may ormay not require hydrotreating,dependingon theirsulfur contents andthat of otherintermediaterefinery dieselstreams.Inthe future,most off-roaddieselin the US willhave to meet the 15-ppm(wt)sulfur specification.
Fluidcatalytic cracker(FCC) feedhydrotreating I isanoptionalrefineryprocess.IntheFCCunit
H ,heavygas-oilfeediscatalyticallyconvertedtogas/LPG,FCC gasoline,lightcycleoil (adistillatefraction),slurryoil, andcoke.
ForFCCfeedhydrotreating ,typicalfeed sources are heavy atmosphericgas oil,vacuumgas oil,heavy gas oils fromthermalprocesses (coking and visbreaking,for example),and deasphalted oils from solvent deasphalting. Solvent deasphaltingextracts additionalgas oilfrom the heavy bottoms product fromvacuumdistillation
J .
Technical terms LHSV = Liquid hourly space velocity:
theratioofthevolumeofoilprocessedtothevolumeofcatalystonanhourlybasis.
WA B T = We i g h t e d a v e r a g e b e dtemperature: normally calculated as thereactor inlet temperature plus two thirdsof the reactortemperature rise.
Treat gas/chemical ratio,al so known ashydrogen availability:The volume of purehydrogen at the reactor inlet divided bythe totalpure hydrogenconsumption fromreactions (desulfurization, denitrification,aromatics saturation,hydrocracking).
Petroleum fractions derived from crudeoils are characterizedas virginstocks,i.e.virgin naphtha,virgin distillate, etc. Thisis incontrast to fractions that are derivedfromsuchconversionprocesses as coking,visbreaking and fluid catalytic cracking.Generally the non-virgin materials aremore difficult to hydrotreat.
Hydrotreater feed Naphtha Distillate FCC feed FCC gasoline LHSV,hr-1 3.0-10.0 0.5-2.5 0.5-1.0 2.0-5.0Total pressure,psig 4 00 f or v ir gi n fe ed s; 8 00 f or v ir gi n fe ed s, 1 ,5 00 -2 ,5 00 2 50 -3 00
800 withsignificant 1,500 with25%+ FCC Light Cycle( 15 %+ ) co ke r na ph th a O il /C ok er D is ti ll at e a ndin feed 1,000+ppm (wt) feed nitrogen
WABT,F. 550-700 600-700 700-800 500-650Treatgas,scf 500-800 1,000-3,000 2,500-5,000 1,000-3,000hydrogen/bbl offeed Fornew designs,hydrogen intreat Fornew designs
gas/chemicalconsumption ratio hydrogenin treat( al so k n ow a s t h e h yd ro ge n a va i la bi l it y) g as /c he mi ca lshouldbe about 5.0 consumptionratio
shouldbe about 5.0.Chemical hydrogen 20-200 200-600 200-1,000 20-200consumption,scf hydrogen/bbl offeed
Other comments Reboiledstrippinginsteadof steamto ensuredry feedto reformer.
Reactor conditions
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Modern Refinery
Content by the Mustangtechnicalteam:Ed Palmer,Process EngineeringManager,StanPolcar,Process Manager,andJohnMcWilliams,Sr.Piping Designer/3D Admin.
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Modern Refinery:Hydrotreating
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