CA2017116C - Catalytic cracking with quenching - Google Patents

Abstract

Effective quenching is provided in a catalytic crack-ing process to decrease thermal cracking. For increased product yield, the quench is injected at special locations and a special quench is used. In the illustrated embod-iment, the quench is injected into the oil product imme-diately downstream of a gross cut separator and the quench comprises cycle oil.

Description

CATALYTIC CRACKING WITH QUENCHING

BACKGROUND OF THE INVENTION
This invention relates to catalytic cracking and, more particularly, to a process and system for increasing the yield of valuable liquids in a catalytic cracking unit.
Catalytic cracking of oil is an important refinery process which is used to produce gasoline and other hydro-carbons. During catalytic cracking, the feedstock, which is generally a cut or fraction of crude oil, is cracked in a reactor under catalytic cracking temperatures and pres-sures in the presence of a catalyst to produce more valu-able, lower molecular weight hydrocarbons. Gas oil is usually used as a feedstock in catalytic cracking. Gas oil feedstocks typically contain from 55% to 80% gas oil by volume having a boiling range from about 650F (343C) to about 1000F (538C) and less than 1% RAMS carbon by weight. Gas oil feedstocks also typically contain less than 5~ by volume naphtha and lighter hydrocarbons having a boiling temperature below 430F, from 10% to 30% by volume diesel and kerosene having a boiling range from about 430F (221C) to about 650F (343C), and less than 10% by volume resid oil having a boiling temperature above 1000F. Resid oil is sometimes present in greater concen-trations or added to the gas oil feedstock.
In conventional fluid catalytic cracking units (FCCU), the hot products from the riser reactor continue to undergo thermal cracking reactions above 900F (482C) downstream of the riser reactor. These thermal cracking reactions degrade the products, reduce yields, and make excess light gases which often unduly limit the production capability of the catalytic cracking unit.
Furthermore, while it is often desirable to operate a riser reactor at higher temperatures, such as at 1025F
(552C) or higher, to increase gasoline octane and oil and resid conversion, such high temperature cracking have sub-stantially increased the production of ethane and lighter fuel gas. This dramatic increase of fuel gas production ~ 2- 2017116 can create an imbalance in the refinery fuel gas system.
It may also limit the capacity of those FCCUs which have insufficient gas compression capability to handle the increased load. Therefore, despite incentives for increased ~asoline and octane production, riser temper-atures have sometimes been reduced.
Operation at higher cracking temperatures produce naphthas which are less stable and are more prone to undergo undesired oxidation reactions which form gums.
Prior methods for maintaining the stability of cracked naphthas and for maintaining the stability of gasolines containing cracked naphthas have included: 1) addition of antioxidant chemicals such as phenylene diamines or hin-dered phenols; 2) manipulation of the operating variables -of the cracking process, such as lowering the crackingtemperature and/or limiting the amount of resid; or 3) limiting the amount of cracked naphtha blended into the finished gasoline.
Typifying some of the many prior art catalytic crack-ers, regenerators, catalysts, equipment and refinery proc-esses are those shown in U.S. Patents: 2,240,160;

2,382,270; 2,382,382; 2,398,739; 2,398,759; 2,414,002;
2,422,501; 2,425,849; 2,436,927; 2,458,862; 2,669,591;
2,827,422; 2,884,303; 2,901,418; 2,981,676; 2,985,584;

3,004,926; 3,039,953; 3,290,405; 3,338,821; 3,351,548;
3,364,136; 3,513,087; 3,563,911; 3,593,968; 3,661,800;
3,676,519; 3,692,667; 3,838,036; 3,844,973; 3,850,742;
3,886,060; 3,907,661; 3,909,392; 4,043,899; 4,218,300;

4,325,817; 4,331,533; 4,332,674; 4,341,623; 4,341,660;
4,375,021; 4,446,009; 4,478,708; 4,552,645; 4,695,370;
4,764,268; 4,814,067; 4,824,557; 4,859,310; and European Patent Application Nos. 83307095.6 (publication no. EPO 113 180 A2), 85307242.9 (publication no. EPO 180 355 A2), and 88309278.5 (publication no. EPO 311 375 Al). These prior art catalytic crackers, regenerators, catalysts, equipment, and refinery processes have met with varying degrees of success.

~3~ 2017116 It is, therefore, desirable to provide an improved process and system to increase the yield of gasoline (naphtha) in catalytic cracking units and which improves the stability of gasoline (petrol) which contain these naphthas.

SU~I~ARY OF THE INVENTION
An improved catalytic cracking process and unit are provided which are effective, efficient, and economically attractive.
The novel catalytic cracking process and unit com-prises catalytically cracking feed oil, such as gas oil, hydrotreated oil, and/or resid oil, in a reactor of a cat-alytic cracking unit (FCCU) in the presence of a cracking catalyst to produce a catalytically cracked, effluent pro-duct stream of upgraded oil and, after catalytic cracking is substantially completed, quenching the product stream externally and downstream of the reactor with a quench line or injector after the catalytically cracked oil has exited and been discharged from the reactor, to increase the yield of naphtha and gasoline (petrol) produce more stable gasoline. Rapid quenching also attains a desirable shift in coke make and selectivity.
Preferably, the quench has a volumetric expansion on vaporization substantially less than water and steam. In the preferred form, the quench comprises a hydrocarbon stream which has been previously cracked or otherwise pro-cessed to remove the most reactive species. Desirably, the quench should have low thermal reactivity. Previously cracked hydrocarbons are very desirable because they are less reactive to thermal quenching than fresh unprocessed virgin feedstocks and hydrotreated stocks.
To this end, the quench can comprise kerosene, light coker gas oil, coke still (coker) distillates (CSD), hydrotreated distillate, or fresh unprocessed virgin feed-stocks, such as virgin gas oil, heavy virgin naphtha, light virgin naphtha, but preferably comprises light cata-~4~ 2017116 -lytic cycle oil (LCCO or LCO), heavy catalytic cycle oil (HCCO or HCO), or heavy catalytic naphtha (HCN), or any combination thereof. LCCO boils at a lower temperature than ~CCO but they have about the same heat of vaporiza-tion. For best results, the quench comprises LCCO whichhas a greater molecular weight than water. HCCO, however, is also very useful as a quench and less expensive than LCCO.
Steam and water are generally not desirable as a quench, because they: expand a lot on vaporization, take up a lot of reactor volume, expand in overhead lines, cause pressure disruption, disturb catalyst circulation, adversely affect cyclone operation, and produce substan-tial quantities of polluted water which have to be puri-fied. Excessive quantities of steam are also required insteam quenching.
Light naphtha (light virgin naphtha, light catalytic naphtha, light coker naphtha, etc.) is also not generally desirable as a quench because it occupies too much volume in the reactor. Furthermore, light naphtha is a gasoline blending product and it is not desirable to crack the light naphtha into less valuable hydrocarbons.
Decanted oil (DCO) is not generally desirable as a quench because it has a tendency to coke. Catalyst in the DCO can also erode the interior reactor walls and lines.
Resid i8 further not desirable as a quench because it has a tendency to coke and plug up lines.
Liquid hydrocarbon quenches are preferred over gas quenches to attain the benefit of the heat of vaporization of the liquid quench. Desirably, the liquid quench is injected into the product stream in an amount ranging from 2% to 20%, and preferably from 5% to 15~ of the volume flow rate of feed oil for best results. Advantageously, quenching decreases the temperature of the product stream and minimizes thermal cracking. Quenching can also increase the conversion of feed oil to upgraded oil and can increase the octane of the gasoline.

. ` ~5~ 2017116 -Kerosene, coker gas oil, and hydrotreated distillates are less advantageous as a-quench than are LCCO and HCCO.
Liquid nitrogen can be useful as a quench but is very expensive and has an undesirable volumetric expansion.
LCCO and HCCO have a high capacity to absorb heat, enhance operations, and do not materially increase operat-ing utility, maintenance, and waste treatment costs. LCCO
and HCCO provide excellent quenches because they are read-ily available in refineries, economical, stable, have low volume expansion, provide recoverable heat removal and have a low tendency to form coke. Quenching with cycle oil can decrease the amount of coke produced. Cycle oil quenching also permits high temperature cracking without loss of more valuable hydrocarbons, and without damaging internal cyclones, plenum, or refractory walls. Desira-bly, cycle oil quenching, substantially decreases fuel gas production.
In the preferred process, the coked catalyst is sepa-rated from the upgraded oil by gross separation in a vapor catalyst separator, such as in a rough cut cyclone, and the upgraded oil is immediately quenched to decrease ther-mal cracking of the upgraded oil to less valuable hydro-carbon products and light hydrocarbon gases. Desirably, the quenching occurs downstream of a riser reactor and the vapor product outlet (exit) of the rough cut cyclone of the catalytic cracking unit. It is more efficient and economical to add the quench to the catalytic cracked oil after gross separation of the catalyst from the oil.
Required quench volumes and pumping costs are also decreased.
In one of the illustrated embodiments, quenching occurs upstream of the disengaging and stripping vessel.
In one preferred form of this application, the catalytic cracking unit has an external rough cut cyclone positioned between the riser reactor and the disengaging and stripper vessel and the quench is injected immediately downstream ~ 6- 2017116 -~ of the vapor (product) exit of the external rough cut cyclone.
In other illustrated embodiments, the catalytic cracking unit has a disengaging vessel (disengager) with an internal rough cut separator and the quench is injected into the disengager immediately downstream and in proxim-ity to the vapor (product) exit(s) of the internal rough cut separator. The internal rough cut separator can com-prise an internal cyclone or an inverted can separator.
Ballistic separator and other inertia separators can also be used.
Advantageously, with quenching, the selectivity of coke can be decreased and less coke can be produced in the dilute phase portion of the disengaging and stripping vessel. Spent coked catalyst is regenerated in a regener-ator and is recycled to the riser reactor. Desirably, during the novel quer.ching process the regeneration tem-perature of the regenerator is decreased. In the pre-ferred mode, the regenerator is operated in full CO
(carbon monoxide) combustion whereby the coked catalyst is regenerated in the presence of a combustion-supporting gas, such as air, comprising excess molecular oxygen in an amount greater than the stoichiometric amount required to completely combust the coke on the coked catalyst to carbon dioxide. The regenerator can also be operated in partial CO burn.
As used in this patent application, the term "conver-sion" means the relative disappearance of the amount of feed which boils above 430F (221C).
As used in this application, the term "coke selectiv-ity" means the ratio of coke yield to conversion.
A more detailed explanation is provided in the fol-lowing description and appended claims taken in conjunc-tion with the accompanying drawings.

~ ~ ~7~ 2017116 BRIEF DESCRIPTION OF THE DRAWINGS
Figure 1 is a schematic flow diagram of a catalytic cracking unit with an external cyclone;
Figure 2 is a schematic flow diagram of another cata-lytic cracking unit with an external cyclone;
Figure 3 is a schematic flow diagram of part of an oil refinery;
Figure 4 is a schematic flow diagram of another part of the oil refinery;
Figure 5 is a schematic flow diagram of a coker unit;
Figure 6 is a schematic flow diagram of a catalytic cracking unit; and Figures 7 and 8 are charts of product temperature for various amounts of quenches;
Figure 9 is a chart of quench volume to product volume;
Figures 10 and 11 are charts of the effects of ini-tial quench at different catalytic cracking units;
Figure 12 is a schematic flow diagram of a catalytic cracking unit with an internal rough cut separator;
Figure 13 is a cross-sectional view of the disengager of Figure 12 taken substantially along lines 13-13 of Fig-ure 12:
Figure 14 is an enlarged fragmentary cross-sectional view of a disengager with an inverted can and quench lines, taken substantially along lines 14-14 of Figure 15;
Figure 15 is a schematic flow diagram of a catalytic cracking unit with a center riser reactor and an internal rough cut separator comprising an inverted can; and Figure 16 is a schematic flow diagram of another cat-alytic cracking.unit with an internal rough cut separator.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS
In refining, unrefined, raw, whole crude oil (petro-leum) is withdrawn from an aboveground storage tank 10 (Figure 3) by a pump 12 and pumped through feed line 14 into one or more desalters 16 to remove particulates, such ~ 8- 2017116 as sand, salt, and metals, from the oil. The desalted oil is fed through furnace inlet line 18 into a pipestill fur-nace 20 where it is heated to a temperature, such as to 750F (399C) at a pressure ranging from 125 to 200 psi.
The heated oil is removed from the furnace through exit line 22 by a pump 24 and pumped through a feed line 25 to a primary distillation tower 26.
The heated oil enters the flash zone of the primary atmospheric distillation tower, pipestill, or crude oil unit 26 before proceeding to its upper rectifier section or the lower stripper section. The primary tower is pref-erably operated at a pressure less than 60 psi. In the primary tower, the heated oil is separated into fractions of wet gas, light naphtha, intermediate naphtha, heavy naphtha, kerosene, virgin gas oil, and primary reduced crude. ~ portion of the wet gas, naphtha, and kerosene is preferably refluxed (recycled) back to the primary tower to enhance fractionation and efficiency.
Wet gas is withdrawn from the primary tower 26 through overhead wet gas line 28. Light naphtha is removed from the primary tower through light naphtha line 29. Intermediate naphtha is removed from the primary tower through intermediate naphtha line 30. Heavy naphtha is withdrawn from the primary tower 26 through heavy naphtha line 31. Kerosene and oil for producing jet fuel and furnace oil are removed from the primary tower through kerosene line 32. Part of the kerosene and/or heavy naph-tha can be fed to the quench line 186 (Figure 1) for use as part of the quench, if desired. Primary virgin, atmo-spheric gas oil is removed from the primary tower throughprimary gas oil line 33 and pumped to the fluid catalytic cracking unit (FCCU) 34 (Figure 4), sometimes via a cata-lytic feed hydrotreating unit.
Primary reduced crude is discharged from the bottom of the primary tower 26 (Figure 3) through the primary reduced crude line 35. The primary reduced crude in line 35 is pumped by pump 36 into a furnace 38 where it is heated, such as to a temperature from about 520F (271C) to about 750F (399C). The heated primary reduced crude is conveyed through a furnace discharge line 40 into the flash zone of a pipestill vacuum tower 42 or directly to the FCU reactor.
The pipestill vacuum tower 42 (Figure 3) is preEera-bly operated at a pressure ranging from 35 to 50 mm of mercury. Steam can be injected into the bottom portion of the vacuum tower through steam line 44. In the vacuum tower, wet gas or vacuum condensate is withdrawn from the top of the tower through overhead wet gas line 46. Heavy and/or light vacuum gas oil are removed from the middle portion of the vacuum tower through gas oil line 48 and can be fed to a catalytic feed hydrotreating unit (CFHU) 49 (Figure 4~ or to the riser reactor. Vacuum-reduced crude is removed from the bottom of the vacuum tower 42 (Figure 3) through a vacuum-reduced crude line 50. The vacuum-reduced crude, also referred to as resid or resid oil, typically has an initial boiling point near about 1000F (538C).
Some of the resid can be pumped and fed to the FCCU 34 (Figure 4) via FCCU resid line 52 or upgraded in a resid hydrotreating unit (RHU) comprising a series of ebullated, expanded bed reactors. Light gas oil (LGO) from the RHU can also be fed to the FCCU 34 via an RHU LGO
line 54. Some of the resid can be pumped to a coker unit 56 via a coker resid line 58.
The coker unit 56 (Figure 5) comprises a coker or coke drum 62 and a combined tower 64. In the coker 62, the vacuum tower bottoms are coked at a coking temperature of about 895F (479C) to about 915F (491C) at a pres-sure of about 10 psig to about 50 psig. Coke is withdrawn from the coker 62 a through chute, conduit, or line 66 and transported to a coke storage area for use as solid fuel.
Coker product vapors can be withdrawn from the coker 62 through coker vapor line 68 and passed (fed) to a combined coker tower 64. In the combined coker tower 64, the coker -lO- 2017116 product vapor can be separated into fractions of coker gas, coker naphtha, light coker gas oil, coke still dis-tillate (coker distillate) and heavy coker gas oil. Coker gas can be withdrawn from the combined tower 64 through coker gas line 70. Coker naphtha can be withdrawn from the combined tower 64 through coker naphtha line 72. Coke still distillate (coker distillate) can be withdrawn from the combined tower 64 through coke still distillate CSD
line 73. Light coker gas oil can be withdrawn from the combined tower 64 through light coker gas line 74 and fed to the FCCU 34 (Figure 4) or the catalytic feed hydro-treater (CFHU) 49. Part of the coke still distillate (coker distillate), light coker gas oil, and/or coker gas can be fed to the quench line 186 for use as part of the quench, if desired. Heavy coker gas oil can be withdrawn from the combined tower 64 (Figure 5) through heavy coker gas oil line 76 and hydrotreated in the catalytic feed hydrotreater (CFHU) 49 (Figure 4) before being catalyt-ically cracked in the catalytic cracker 34 (FCCU).
Heavy coker gas oil from heavy coker gas oil line 76 (Figure 5) and light vacuum gas oil and/or heavy vacuum gas oil from vacuum gas oil line 48 (Figure 3) are con-veyed to the riser reactor 100, or alternatively, to the catalytic feed hydrotreater or catalytic feed hydrotreat-ing unit (CFHU) 49 (Figure 4) where they are hydrotreated with hydrogen from hydrogen feed line 78 at a pressure ranging from atmospheric pressure to 2000 psia, preferably from 1000 psia to 1800 psia at a temperature ranging from 650F (343C) to 750F (399C) in the presence of a hydro-treating catalyst. The hydrotreated gas oil is dischargedthrough a catalytic feed hydrotreater discharge line 80 and fed to the catalytic cracker 34 (FCCU).
The catalytic cracking reactor 34 of Figure 1 has an upright elongated vertical riser reactor 100 with an upper portion 102 and a lower portion 104. Cracking catalyst and feed oil are mixed in the bottom of the riser reactor 100. The catalytic cracker (riser reactor) 100 catalyt-ically cracks feed oil in the presence of a cracking cata-lyst under catalytic cracking conditions to produce an upgraded effluent product. Stream of catalytically cracked oil containing particulates of spent coked crack-ing catalyst.
A gross cut inertia separator comprising an external rough cut cyclone 106 (~igure 1) is connected to and com-municates with the upper portion of the riser reactor 100 via a cyclone inlet line 105. The external rough cut cyclone 106 is positioned about and at a similar elevation as the upper portion 102 of the riser reactor 100. The rough cut cyclone makes a gross separation of the coked catalyst from the catalytically cracked oil. Preferably, at least 92~ to 98% of the coked catalyst in the oil is removed by the rough cut cyclone 106. Positioned down-stream of the external cyclone 106 is an upright disengag-ing vessel or disengager 108.
The disengaging vessel 108 (Figure 1) disengages and separates a substantial amount of the remaining coked cat-alyst from the catalytically cracked oil. The disengaging vessel 108 operates at a temperature of 900F (482C) to 975F (524~). The disengaging vessel 108 has an upper dilute phase portion 110 with at least one internal cyclone 112, an effluent product outlet line 113, a lower dense phase portion 114, and a stripping section 116 pro-viding a stripper in which volatile hydrocarbons are stripped from the coked catalyst. The stripping section can have baffles or internals 115. Stripping steam lines and injectors 117 can be connected to the stripper 116.
Extending from the upper portion of the external cyclone 106 (~igure 1) is a cyclone outlet line 118 pro-viding part of the product stream line 119. The product stream line 118 has an upper horizontal section 118, a vertical intermediate section 120, an intermediate hori-zontal section 122, and an elongated vertical section 124 providing a product stream dipleg which extends downwardly through the upper dilute phase portion 110 of the disen-gaging vessel 108 to the upper section of the dense phase portion 114. The product stream dipleg 124 with an inter-nal inertia separator providing an outlet 126 located in and communicating with the intermediate section of the upper dilute phase portion of the disengaging vessel 108.
The product stream line 118 provides a disengaging vessel input line which extends between, connects and com~uni-cates with the external cyclone 106 and the upper dilute phase portion 110 of the disengaging vessel 108.
A cyclone outlet spent catalyst line, conduit, and chute provides a catalyst dipleg 128 which extends into the lower dense phase portion 114 adjacent the stripping section 116 of the disengaging vessel 108. The catalyst dipleg 128 has an upper vertical section 130, an interme-diate angle section 132, a lower angle section 134, and a vertical dipleg end section 136 with an outlet opening 137. An aeration steam line 138 can be connected to the upper vertical section 130. A fluidizing steam line 139 can be connected to the lower angle section 134.
A regenerator 140 (Figure l) comprising a regenerator vessel 142 is positioned above the disengaging vessel 108.
The regenerator 140 substantially combusts and regenerates the spent coke catalyst in the presence of a combustion sustaining oxygen-containing gas, such as air. An upright vertical elongated lift pipe 144 provides a spent catalyst riser and line, which extends downwardly from the lower portion of the regeneration vessel 142 through the middle section of the dense phase portion 114 of the disengaging vessel 108 for transporting coked catalyst from the disen-gaging vessel 108 to the overhead regenerator vessel 142.A lift air injector 146 is positioned near the bottom of the lift pipe 144 for injecting air, lifting and trans-porting the spent catalyst to the regenerator vessel 142 and facilitating combustion of the coked catalyst. The regenerator vessel 142 can have internal cyclones 148 and 150, an upper dilute phase steam ring 152, an overhead .

flue gas line 154 and a lower dense phase fuel gas ring 156 and line 158.
Regenerated catalyst is discharged through a catalyst discharge line, conduit, and chute 160 (Figure 1) to an overhead withdrawal well and vessel 162 with an optional air ring 164 in its lower portion to offset pressure buildup. A vertical regenerated catalyst standpipe 166 extends downwardly from the withdrawal well 162 to a slide valve 168. A horizontal regenerated catalyst line 170 is connected to the lower portion 104 of the riser reactor 100 to convey regenerated catalyst to the riser reactor.
A fluidization steam line 171 can be connected to the regenerated catalyst line 170 below the slide valve 168.
An aeration air line 172 can be connected to the middle portion of the regenerated catalyst standpipe 166.
An aeration steam line 176 (Figure 1) can also be connected to the lower portion 104 of the riser reactor 100. Injector nozzles 178 (Figure 1) can be positioned in the lower portion 104 of the riser reactor 100 to inject the feed oil into the riser reactor. In the illustrated embodiment, a combined feed oil line 180 is connected to the nozzles 178 and to a fresh feed oil line 33. A recy-cle oil line 182 can be connected to and communicate with the combined feed oil line 180 to feed heavy catalytic cycle oil (HCCO), decanted oil (DCO) and/or slurry oil to the riser reactor 100, of up to 40%, preferably at a rate of 5% to 10%, by volume of the fresh feed rate in fresh feed oil line 33. The temperature of the regenerator is decreased from about 1F to about 20F, by cycle oil quenching.
A catalytic cycle oil quench injection line 184, com-prising a LCCO injection line and/or an HCCO injection line, with a vertical catalytic cycle oil injector section 186 extends downwardly, connects and communicates with the vertical section 120 of the disengaging vessel input line 118 to inject a light cycle oil (LCCO) quench and/or a heavy catalytic cycle oil (HCCO) quench into the hydrocar-' -14- 2017116 bon products after the products have exited the external cyclone 106 downstream of the riser reactor 100 and before the products have entered the disengaging vessel 108. The quench minimizes and inhibits substantial thermal cracking of the product stream of catalytically cracked grossly separated oil to less valuable hydrocarbons, such as fuel gas. Cycle oil quenching stops about 75~ to 90% of ther-mal cracking of the product oil and concurrently enhances the yield of naphtha to increase the production of gaso-line. During quenching, the temperature of the productstream of oil being discharged from the rough cut cyclone 106 is decreased from about 30F (17C) to about 200F
(111C), preferably about 50F (28C) to about 80F
(44C), such as to a range of 900F (482C) to about 930F
(499C).
Cycle oil quenching enhances the conversion of feed oil to upgraded oil and increases gasoline octane. The injection rate of the quench by volume ranges from 2% to 20%, preferably from 5% to 15%, of the input rate of feed oil in the riser reactor 100. Advantageously, less coke is produced in the dilute phase portion 110 of the disen-gaging vessel 108. Less C2- fuel gas is also produced during cycle oil quenching.
Mixing and vaporization of the quench can be advanta-geously increased to less than S seconds and preferablyless than 3 seconds by spraying the quench with one or more atomized quench injectors to provide a quick contact quench and assure rapid mixing. The quench is injected at a downward velocity of 50 to 100 ft/sec (lS to 30 m/sec.) at a residence time of 0.1 to 5 seconds, preferably less than 0.2 seconds. Losses of quench should be avoided.
High boiling quench media improves energy recovery.
The quench can be preheated, preferably above 212F
(100C) to enhance heat recovery and minimize heat loss.
Quench is sprayed into the external cyclone vapor exit line 118 to rapidly cool the products before entering the reactor vessel dilute phase.

For best results, the quench is injected as soon as the reaction is completed and preferably immediately after the coked catalyst particulates have been grossly sepa-rated from the product stream of catalytically cracked oil. Lesser amounts of quench are required after catalyst separation than before catalyst separation.
It was unexpectedly and surprisingly found that the use of cycle oil quench increases the yield of high value naphtha and can improve coke make and selectivity.
It appears that gas oil conversion beyond the riser reactor is substantially completed in the rough cut cyclone where catalyst is present. Excess fuel gas pro-duction has previously been associated with long residence time in the dilute phase portion of the disengaging vessel as a result of thermal cracking before the addition of cycle oil quench.
Regenerated catalytic cracking catalyst can be fed to the riser reactor 100 (Figure 1) through a regenerated catalyst line 170, respectively. Fresh makeup catalyst can be added to the regenerator 140. In the FCC riser reactor, the hydrocarbon feedstock is vaporized upon being mixed with the hot cracking catalyst and the feedstock is catalytically cracked to more valuable, lower molecular weight hydrocarbons. The temperatures in the riser reac-tor 100 can range from about 900F (482C) to about 1200F(649C), preferably from about 950F (510C) to about 1040F (560C), at a pressure from atmospheric pressure to about 50 psig. Weight hourly space velocity in the riser reactor can range from about 5 to about 200 WHSV. The velocity of the oil vapors in the riser reactor can range from about 5 ft/sec (1.5 m/sec) to about 100 ft/sec (30 m/sec).
Suitable cracking catalysts include, but are not lim-ited to, those containing silica and/or alumina, including the acidic type. The cracking catalyst may contain other refractory metal oxides such as magnesia or zirconia.
Preferred cracking catalysts are those containing crystal-` -16- 2017116 -line aluminosilicates, zeolites, or molecular sieves in an amount sufficient to materially increase the cracking activity of the catalyst, e.g., between about 1 and about 50% by weight. The crystalline aluminosilicates can have silica-to-alumina mole ratios of at least about 2:1, such as from about 2 to 12:1, preferably about 4 to 6:1, for best results. The crystalline aluminosilicates are usu-ally available or made in sodium form, and this component is preferably reduced, for instance, to less than about 4 or even less than about 1% by weight through exchange with hydrogen ions, hydrogen-precursors such as ammonium ions, or polyvalent metal ions. Suitable polyvalent metals include calcium, strontium, barium, and the rare earth metals such as cerium, lanthanum, neodymium, and/or natur-ally-occurring mixtures of the rare earth metals. Such crystalline materials are able to maintain their pore structure under the high-temperature conditions of cata-lyst manufacture, hydrocarbon processing, and catalyst regeneration. The crystalline aluminosilicates often have a uniform pore structure of exceedingly small size with the cross-sectional diameter of the pores being in a size range of about 6 to 20 angstroms, preferably about 10 to 15 angstroms. Silica-alumina based cracking catalysts having a major proportion of silica, e.g., about 60% to 90% by weight silica and about 10% to 40% by weight alu-mina, are suitable for admixture with the crystalline aluminosilicate or for use as the cracking catalyst.
Other cracking catalysts and pore sizes can be used. The cracking catalyst can also contain or comprise a carbon monoxide (CO) burning promoter or catalyst, such as a pla-tinum catalyst, to enhance the combustion of carbon monox-ide in the dense phase in the regenerator 140.
Spent catalyst containing deactivating deposits of coke is discharged from the disengaging vessel 108 and lifted upward through the spent catalyst riser 144 and fed to the bottom portion of the overhead fluidized catalyst regenerator or combustor 140. The riser reactor and regenerator together provide the primary components of the catalytic cracking unit. Air is injected upwardly into the bottom portion of the regenerator via the air injector line 146 and spent catalyst riser 144. The air is injected at a pressure and flow rate to fLuidize the spent catalyst particles generally upwardly within the regenera-tor. Residual carbon (coke) contained on the catalyst particles is substantially completely combusted in the regenerator 140 leaving regenerated catalyst for use in the reactor. The regenerated catalyst is discharged from the regenerator 140 through regenerated catalyst line 160 and fed to the riser reactor 100 via the regenerated cata-lyst line 170 and the regenerated catalyst standpipe 172.
The combustion off-gases (flue gases) are withdrawn from lS the top of the combustor 140 through an overhead com-bustion off-gas line or flue gas line 154.
As shown in Figure 6, the effluent product stream of catalytically cracked hydrocarbons (volatized oil) is withdrawn from the top of disengaging vessel 108 through an effluent product line 113 and conveyed to the FCC main fractionator 190. In the FCC fractionator 190, the cata-lytically cracked hydrocarbons comprising oil vapors and flashed vapors can be fractionated (separated) into light hydrocarbon gases, naphtha, light catalytic cycle oil (LCCO), heavy catalytic cycle oil (HCCO), and decanted oil (DCO). Light hydrocarbon gases are withdrawn from the FCC
fractionator through a light gas line 192. Naphtha is withdrawn from the FCC fractionator through a naphtha line ~ 194, LCCO is withdrawn from the FCC fractionator through a light catalytic cycle oil line 196. HCCO is withdrawn from the FCC fractionator through a heavy catalytic cycle oil line 198. Decanted oil is withdrawn from the bottom of the FCC fractionator through a decanted oil line 199.
Part of the LCCO and/or HCCO can be recycled to the cycle oil quench line 184 (Figure 1) for use as the quench.
Alternatively, in the main fractionator 402, the oil vapors and flashed vapors can be fractionated (separated) ` -18- 2017116 into: ~a) light hydrocarbons having a boiling temperature less than about 430F (221C), (b) light catalytic cycle oil (LCCO), and (c) decanted oil (DCO). The light hydro-carbons can be withdrawn from the main fractionator through an overhead line and fed to a separator drum. In the separator drum, the light hydrocarbons can be sepa-rated into (l) wet gas and (2) C3 to 430-F (221-C) light hydrocarbon material comprising propane, propylene, butane, butylene, and naphtha. The wet gas can be with-drawn from the separator drum through a wet gas line andfurther processed in a vapor recovery unit (VRU). The C3 to 430-F (221-C) material can be withdrawn from the sep-arator drum through a discharge line and passed to the vapor recovery unit (VRU) for further processing. LCCO
can be withdrawn from the main fractionator through an LCCO line for use as part of the quench or further refin-ing, processing, or marketing. Decanted oil (DCO) can be withdrawn from the main fractionator through one or more DCO lines for further use. Slurry recycle comprising decanted oil (DCO) can be pumped from the DCO line l99 (Figure 6) at the bottom portion of the main fractiona-tor l90 by a pump through a slurry line 182 (Figure 1) for recycle to the riser reactor lO0. The remainder of the DCO can be conveyed through for further use in the refinery.
Spent deactivated (used) coked catalyst discharged from the riser reactor 100 (Figure 1) can be stripped of volatilizable hydrocarbons in the stripper section 116 with a stripping gas, such as with light hydrocarbon gases or steam. The stripped, coked catalyst is passed from the stripper 116 through spent catalyst line 144 into the regenerator 140. Air is injected through air injector line 146 to fluidize and carry the spent coked catalyst into the regenerator 140 via the spent catalyst riser 144 at a rate of about 0.2 ft/sec (0.06 m/sec) to about 4 ft/sec (1.22 m/sec). Preferably, excess air is injected in the regenerator 140 to completely convert the coke on -l9 2017116 the catalyst to carbon dioxide and steam. The excess air can be from about 2.5% to about 25% greater than the stoi-chiometric amount of air necessary for the complete con-version of coke to carbon dioxide and steam.
In the regenerator 140 (Figure 1), the coke on the catalyst is combusted in the presence of air so that the catalyst contains less than about 0.1% coke by weight.
The coked catalyst is contained in the lower dense phase section of the regenerator, below an upper dilute phase section of the regenerator. Carbon monoxide (CO) can be combusted in both the dense phase and the dilute phase, although combustion of carbon monoxide predominantly occurs in the dense phase with promoted burning, i.e., the use of a CO burning promoter. The temperature in the dense phase can range from about 1050F (566C) to about 1400F (760C). The temperature in dilute phase can range from about 1200F (649C) to about 1510F (821C). The stack gas (combustion gases) exiting the regenerator 140 through overhead flue line 154 preferably contains less than about 0.2% CO by volume (2000 ppm). The major por-tion of the heat of combustion of carbon monoxide is pref-erably absorbed by the catalyst and is transferred with the regenerated catalyst through the regenerated catalyst line 170 and sta~ndpipe 166 riser reactor 100.
In a catalytic cracker (riser reactor) 100, some non-volatile carbonaceous material, or coke, is deposited on the catalyst particles. Coke comprises highly condensed aromatic hydrocarbons which generally contain 4-10 wt.%
hydroqen. As coke builds up on the catalyst, the activity of the catalyst for cracking and the selectivity of the catalyst for producing gasoline blending stock diminish.
The catalyst particles can recover a major proportion of their original capabilities by removal of most of the coke from the catalyst by a suitable regeneration process.
Catalyst regeneration is accomplished by burning the coke deposits from the catalyst surface with an oxygen-containing gas such as air. The burning of coke deposits -from the catalyst requires a large volume of oxygen or air. Oxidation of coke may be characterized in a simpli-fied manner as the oxidation of carbon and may be repres-ented by the following chemical equations:
a. C + 2 ~ C2 b. 2C + 2 ~ 2CO
c. 2CO + 2 ~ 2CO2 Reactions (a) and (b) both occur at typical catalyst regeneration conditions wherein the catalyst temperature may range from about 1050F (566C) to about 1300F
(704C) and are exemplary of gas-solid chemical inter-actions when regenerating catalyst at temperatures within this range. The effect of any increase in temperature is reflected in an increased rate of combustion of carbon and a more complete removal of carbon, or coke, from the cata-lyst particles. As the increased rate of combustion is ~ccompanied by an increased evolution of heat whenever sufficient oxygen is present, the gas phase reaction (c) may occur. This latter reaction is initiated and propa-gated by free radicals. Further combustion of CO to CO2is an attractive source of heat energy because reaction (c) is highly exothermic.
The catalytic cracker (catalytic cracking unit) of Figure 2 is generally structurally and functionally simi-lar to the catalytic cracker of Figure 1, except that thelight catalytic cycle oil (LCCO) quench line 284 is at an angle of inclination ranging from about 15 degrees to about 45 degrees, preferably about 30 degrees, relative to the vertical to increase the trajectory of the quench and enhance more uniform blending. The regenerator vessel 242 is also positioned laterally away from the disengaging vessel 208. For ease of understanding, the parts, ele-ments, and components of the catalytic cracker of Figure 2 have been given part numbers similar to the corresponding parts, elements, and components of the catalytic cracker of Figure 1, except increased by 100, i.e., in the 200 series, e.g., riser reactor 200, external cyclone 206, -disengaging vessel 208, stripper 216, regenerator 240, etc. The catalytic cracking reactor preferably comprises a riser reactor. Some catalytic cracking units can have two riser reactors, two rough cut cyclones, two slide valves, and two standpipes operatively connected to a single regenerator and to a single disengaging vessel.
The catalytic cracker (catalytic cracking unit) of Figures 12 and 13 is generally structurally and func-tionally similar to the catalytic cracker of Figure 2, except that four internal rough cut inertia separators 306 comprising gross (rough) cut internal cyclones are used in lieu of external cyclones to grossly separate a substan-tial amount of catalyst from the catalytically cracked oil after the product stream of catalytically cracked oil has been discharged from the riser reactor 300 via horizontal product line 305. Four CCO quench injector lines 384 extend into the interior dilute phase portion (zone) 310 is the disengaging vessel (disengager) 308 to locations just above the vapor product exit 318 of the internal gross cut separators 306 to inject and spray a CCO quench comprising LCCO and/or HCCO into the catalytically cracked oil after most of the coked catalyst has been removed from the oil by the internal gross cut separators 306. The quench injector lines can be positioned at an angle of inclination ranging from about 15 degrees downwardly to about 90 degrees (horizontal) relative to the vertical to minimize backflow of quench.
In Figure 12, a vertical outlet spent catalyst line, conduit, and chute 328 depends downwardly from the inter-nal gross cut separators 306 to discharge separated spentcoked catalyst into the lower dense phase portion (zone) 314 and stripping section (stripper) 316 of the disengag-ing vessel 308. The top portion of the upper dilute phase zone 310 of the disengaging vessel 308 can have five sec-ondary internal cyclones 312. The disengaging vessel 308and secondary internal cyclones 312 above the rough cut separators 306, cooperate to remove the remaining coked ~ -22-catalyst particles (fines) from the effluent gases and oil vapors. For ease of understanding, the parts, elements, and components of the catalytic c,racker of Figures 12 and 13 have been given part numbers similar to the correspond-ing parts, elements, and components of the, catalyticcracker of Figure 2, riser reactor 300, internal rough cut cyclone 306, stripper 316, regenerator 340, etc.
One of the major design changes implemented on FCCU
600 unit which is similar to the catalytic cracker of Fig-ures 12 and 13, was the use of HCCO instead of LCCO toquench the disengager. HCCO was selected instead of LCCO
to avoid flooding, i.e. exceeding the capacity of the LCCO
section of the fractionator, and to improve overall unit heat recovery, as well as to take advantage of the greater pumping capacity of the HCCO circuit.
The HCCO quench nozzles are positioned to maximize quench efficiency by cooling the reaction gases as soon as they exit the cyclone. HCCO quench can cool the disen-gager by 30F (17C) to 200F (93C), preferably at least about 100F (38C).
The catalytic cracker (catalytic cracking unit) of Figures 14 and 15 is generally structurally and func-tionally similar to the catalytic cracker of Figure 12, except the upright center, central riser reactor 400 extends vertically upwardly into the dilute phase portion (zone) 410 of and along the vertical axis of the disengag-ing vessel (disengager) 408. Coaxially positioned about the upper end 409 of the riser reactor 400 is an internal rough (gross) cut inertia separator 406 comprising an inverted can. The inverted can 406 has: an open bottom end 406a for discharge (egress) of separated coked cata-lyst into the dense phase portion (zone) 414 and stripper section (stripper) 416 of the disengaging vessel 408; an imperforate solid planar or flat top or ceiling 406b spaced above the upper end 409 of the riser reactor 400 and providing a striker plate upon which the catalyst laden stream of catalytically cracked oil strikes upon -exiting the upper end 409 of the riser reactor; an upper cylindrical tubular wall 406c which extends downwardly from the top 406b; an intermediate portion providing a hood 406d extending below the upper wall 406c; and a lower cylindrical tubular wall 406e about the open bottom 406a which extends downwardly below the hood 406d.
The hood 406d (Figures 14 and 15) comprises an out-wardly flared skirt. The hood 406d has an elongated down-wardly diverging upper frustroconical wall 406f, which extends downwardly from the upper wall 406c, and has an downwardly converging frustroconical lower wall 406g, which extends downwardly from wall 406f. The upper frus-troconical wall 406f has a pair of diametrically opposite rectangular discharge openings or windows 406h which pro-vide outlet ports for egress (exiting) of the effluentproduct stream of catalytically cracked oil after the oil has been grossly separated from the catalyst.
When the catalyst laden stream of catalytically cracked oil exits the upper end 409 (Figures 14 and 15) of the riser reactor 400, it strikes the top 406b of the internal gross cut separator (inverted can) 406 with suf-ficient momentum and force to grossly separate a substan-tial amount of spent coked catalyst from the catalytically cracked oil. The separated catalyst is discharged in part by gravity flow through the open bottom 406a of the inverted can 406. The catalytically cracked oil after being grossly separated from the catalyst, is discharged through the windows 406h of the inverted can 406.
A pair of diametrically opposite horizontal quench lines or injectors 484 (Figure 14) extend horizontally into the interior dilute phase portion (zone) 410 of the disengaging vessel 408 at locations in proximity to and in alignment with the windows 406h to inject and spray a quench comprising LCCO and/or HCCO into the catalytically cracked oil. The quench lines 484 can be positioned at an angle of inclination ranging from about 15 degrees down-~ -24--wardly to about 90 degrees (horizontal) relative to the vertical to minimize backflow of quench.
The disengaging vessel 408 (Figure 15) and the sec-ondary internal cyclones 412 at the top of the disengaging S vessel, above the rough cut separator 406, cooperate to remove the remaining coke catalyst particulates (fines) from the effluent gases and oil vapors. For ease of understanding, the parts, elements, and components of the catalytic cracker of Figures 14 and 15 have been given part numbers similar to the corresponding parts, elements, and components of the catalytic cracker of Figure 12, except in the 400 series, e.g., riser reactor 400, inter-nal rough cut separator 406, stripper 416, regenerator 440, etc.
The catalytic cracker (catalytic cracking unit) of Figure 16 is generally structurally and functionally simi-lar to the catalytic cracker of Figure 12, except that the regenerator 540 is positioned below the disengaging vessel (disengager) 50~. For ease of understanding, the parts, elements, and components of the catalytic cracker of Fig-ure 16 have been given part numbers similar to the corre-sponding parts, elements, and components of the catalytic cracker of Figure 12, except in the 500 series, e.g., riser reactor 506, stripper-516, regenerator 540, etc.
In some circumstances, it may be desirable to use a fluid bed reactor or a fluidized catalytic cracking reac-tor instead of or with a riser reactor.

EXAMPLES
The following examples serve to give specific illus-tration of the practice of this invention but are not intended in any way to limit the scope of this invention.

Examples 1 and 2 Experimental tests were conducted in a catalytic cracking unit (Unit Y) similar to that shown in Figure 1.

-The test of Example 1 provided the base case. Catalytic cracking in Example 1 proceeded without a LCCO quench.
Catalytic cracking in the test of Example 2 was conducted with an LCCO quench with a temporary gerry-rig quench line. The operating conditions and test results are shown below. The LCCO quenching test produced unexpected, sur-prisingly good results since naphtha octanes increased by 0.2 RM/2, conversion increased by 0.64 volume %, naphtha yield increased by 0.5 volume %, heavy catalytic naphtha stability improved, C2-gas yield decreased by 23% by weight, and coke selectivity (e.g. coke yield/conversion) improved. The extent, amount, and quality of the products produced during catalytic cracking with LCCO quench were unexpected. Such increase due to LCCO quenching has pro-duced a substantial increase in product value.

Difference Exampie 1 Example 2 Delta LCCO Quench, MB/D 0.0 1.5 +1.5 Fresh Feed, MB/D 24.6 24.7 +0.1 Riser, F 955. 956. +1.
Rough-Cut Cyclone 951. 903. -48.
Overhead Line, F
Vapor Line from 940. 903. -34.
Disengaging Vessel to Main Fractionator, F
Temperature Difference 15. 53. +38.
Between Riser Reactor and & Disengaging Vessel, F
Preheater Temperature, F 431. 435. -2.
HCCO Recycle, B/D 710. 790. +80.
Slurry Recycle, B/D 700. 700. 0.
Regen. Bed. Temp., F.1312. 1305. -7.
Conversion, Vol% 69.15 69.79 +0.64 Fresh Feed Properties API Gravity 23.9 24.0 +0.1 Nitrogen, Wt% 0.112 0.111 -0.001 Sulfur, Wt% 1.23 1.22 -0.01 Gas Oil, Vol% 97.8 97.6 +0.2 Difference Example 1 Example 2 Delta Conversion, Vol% 69.15 69.79 +0.64 TC2-, Wt% 3.34 3.11 -0.23 TC3, Vol% 10.80 10.90 +0.10 C3=/TC3 0.689 0.693 +0.004 TC4, Vol% 13.19 13.52 +0.33 C4=/TC4 0.524 0.513 -0.009 iC4/C4 saturates 0.789 0.785 -0.004 C5/430, Vol% gasoline51.83 52.33 +0.50 blending material, e.g. pentane, pentene LCCO, Vol% 25.54 24.91 -0.63 DCO, Vol% 4.62 4.57 -0.05 Coke, Wt% 5.90 6.16 +0.26 Volume Recovery, Vol%105.99 106.24 +0.24 MCL Octane 93.7 93.9 +0.2 RCL Octane 81.4 81.6 +0.2 Difference Example 1 Example 2 Delta LCN
induction period, min 25 25 0 RON 94.5 94.5 0 MON 80.2 80.2 0 HCN
induction period 395 615 +220 RON 92.9 93.4 +1.6 MON 80.9 81.4 +0.5 Examples 3 and 4 8ench study tests were performed on kerosene to simu-late catalytically cracked oil after the coke catalyst particles have been removed. In the tests of Examples 3 and 4, the quench rate was 60 grams/hr and the oil product rate was 125 grams/hour. The quench of Example 3 was HCCO. The quench of Example 4 was LCCO. Quench results of HCCO and LCCO were very similar and are reported below Example 3 Example 4 Reactor, F 1095 1100 C2- fuel gas (wt%) Isothermal at quenching14 16+
20 minutes of cooling 10 9 60 minutes of cooling 8 6 Examples 5 and 6 Experimental tests were conducted in another cata-lytic cracking unit (FCCU 500) similar to that shown in Figure 2. The test of Example 3 provided a base case without the use of a LCCO. Catalytic cracking in the test of Example 6 was performed with a LCCO quench. The oil feed rate was 79 MBD. Riser reactor temperature was 1020F (549C). Without LCCO quench, the reactor temper-ature at the top of the disengaging vessel was 12F belowthe riser reactor. At 5.6 MBD of LCCO quench, the riser reactor temperature decreased 53F (30C). LCCO quench yielded a desirable decrease in drying gas production by about 16.7% from 1140 MSCFH to 980 MSCFH, significantly increased gasoline production 4.4~ from 39.5 MBD to 41.2 MBD, and increased volume recovery by about l~. LCCO
quenching also decreased the production of propane, propy-lene, and isobutane. The operating conditions and test results are:

_ -29- 20I711~

Example 5 Example 6 with No quench LCCO quench LCCO quench rate O MBD 5.6 MBD
Riser temperature 1020F (549C) 1020F (549C) Disengaging Vessel top temp. 1008F (542~) 967F (519C) Temperature diff. between+12F (7C) +53F (30C) riser and disengager C2- dry gas 1140 MSCFH 980 MSCFH
C5+ gasoline 39.5 MBD 41.2 MBD
Volume % recovery 108.9% 109.8~

Example 5Example 6 Difference No quenchWith quench Delta (wt.%)(wt.%) (wt.%) C2- dry gas 4.8 4.0 - .8 Propane 2.1 1.8 - .3 Propylene 5.7 5.3 ~ 4 Isobutane 3.7 3.5 - .2 N-butane 1.2 1.2 20 Butenes 6.8 6.7 C5 gasoline 41.2 43.0 + 1.8 LCO/DCO 29.4 29.3 Coke 5.1 5.2 Examples 7-9 Further experimental tests were conducted at cata-lytic cracking units with cycle oil quenches. In Exam-ple 7, LCCO quench was injected immediately after the product exit of the external rough cut cyclone in a cata-lytic cracking unit (Unit Y) similar to that shown in Fig-ure 1 with a temporary gerry-rig quench line. Example 8, LCCO quench was injected immediately after the product exit of two external rough cut cyclones in another cata-lytic cracking unit (FCCU 500) similar to that shown in Figure 2. In Example 9, HCCO quench was injected imme-diately after the product exited four internal rough cut cyclones in a disengager in a catalytic cracking unit sim-`` 2017116 ~ -30-ilar to that shown in Figures 12 and 13. Experimental test conditions and results are shown below and in the charts of Figures 10 and 11.

Example 7 Feed Rate 24,700 B/D
Riser Outlet Temp. 951 F
Quench Media LCCO
Quench Rate 1500 B/D ~6.1%) Vapor Res Time in Disengager 16 sec Fuel Gas Reduction 635 M SCFD

K = 635 M SCFD = 1.61 SCF/BBL-Sec 24.7 M B/D (16 sec) Example 8 Feed Rate 77,000 B/D
20 Riser Outlet Temp. 1017 F
Quench Media LCCO
Quench Rate 5500 B/D (7.1%) Vapor Res Time in Disengager 9 sec Fuel Gas Reduction 5 MM SCFD
K = 5,000 M SCFD = 7.21 SCF/BBL-Sec 77 M 8/D (9 seconds) Example 9 Feed Rate 37,000 B/D
Riser Outlet Temp. 980F

5 Quench Media HCO
Quench Rate 3000 B/D (8.1%) Vapor Res Time in Disengager 13 sec Fuel Gas Reduction 1.5 MM SCFD

K = 1,500 M SCFD = 3.12 SCF/BBL-Sec 37 M B/D (13 sec) Examples 10-18 Increased reactor temperature at or above 940F
(504C), but especially above 1000F (538C) diminishes the oxidation stability of the naphtha product and gaso-line. Also, active matrix octane catalysts (cracking cat-alysts containing ultrastable-Y zeolite with or without rare earth exchanged into the zeolite, supported on a car-rier matrix which exhibits cracking activity independent of the zeolite) will produce a less stable naphtha product and gasoline than will rare earth exchanged Y catalysts, which produce larger volumes of lower octane naphtha.
Furthermore, inclusion of residual oil in the FCU feeds-tock mixture will diminish the stability of the naphtha product and gasoline.
Quenching in accordance with this invention can sub-stantially increase the oxidation and storage stability of the naphtha product and gasoline by reducing the temper-ature in the dilute phase of the disengaging vessel as quickly as possible following the initial gross cut sepa-ration of the mixture of oil vapor product and catalyst.
Oxidation stability tests were conducted at catalytic cracking units with and without cycle oil quenches. In Examples 10-13, gas oil feed was catalytically cracked in _ a catalytic cracking unit (Unit Y) similar to that shown ~ -32- 2017116 in Figure 1 with a temporary gerry-rig quench line, and LCCO quench, if indicated, was injected immediately after the product exit of the external rough cut cyclone. In Examples 14-16, gas oil feed was catalytically cracked in S a catalytic cracking unit (FCCU 500) similar to that shown in Figure 2, and LCCO quench, if indicated, was injected immediately after the product exit of two rough cut cyclones. In Examples 17 and 18, gas oil feed was cata-lytically cracked in a catalytic cracking unit (FCCU 600) similar to that shown in Figures 12 and 13, and HCCO
quench, if indicated, was injected immediately after the product exited two internal rough cut cyclones in the disengager ~disengaging vessel). Experimental test condi-tions and results are shown below:

~017116 -EFFECT OF DILUTE PHASE FCU QUENCH ON
FCCU NAPHTHA OXIDATION STABILITY

Ex. Unit Product Stream 10 Y Heavy Catalytic Naphtha 11 Y Heavy Catalytic Naphtha 10 12 Y Light Catalytic Naphtha 13 Y Light Catalytic Naphtha Total Catalytic Naphtha Total Catalytic Naphtha Total Catalytic Naphtha 17 FCCU-600 FCU Wild Gasoline -2045 hrs 18 FCCU-600 FCU Wild Gasoline -2000 hrs EFFECT OF DILUTE PHASE FCU QUENCH ON
FCCU NAPHTHA OXIDATION STABILITY

Cont'd Riser Outlet Dilute Phase Quench Ex.Temperature, FTemperature, F Fluid 940 940 None 12 940 940 None 14 1019 999 None 17 1020 990 None -EFFECT OF DILUTE PHASE FCU QUENCH ON
FCCU NAPHTHA OXIDATION STABILITY

Cont'd s Feedstock Composition ASTM D-525 % Hydrotreated %Stability, Ex.% HVGO Gas Oil ResidMinutes The preceding Examples 10-18 show the beneficial effects on quench of product stability.

Examples 19-48 Further oxidation stability tests were conducted with cycle oil quenches. LCCO quench was injected immediately after the product exit of two rough cut cyclones in a cat-alytic cracking unit (FCCU 500) similar to Figure 2. HCCO
quench was injected immediately after the product exited ~` 2017116 _ -36-two internal rough cut cyclones in the disengager (disen-gaging vessel) in a catalytic cracking unit (FCCU 600) similar to that shown in Figures 12 and 13. The Catalyst Complex was comprised of FCCU 500 and FCCU 600. Weighted average riser outlet temperature reflects the relative flow rates of feed to each unit (FCCU 500 and FCCU 600) and the cracking temperature of each unit (FCCU 500 and FCCU 600). Stabilities of LCN and HCN were measured as received from a sample point in the rundown line. ULR is blended from LCN and HCN which have been treated with an antioxidant additive. Test conditions and results are shown below.

~37~ 2 01 7116 EFFECT OF QUENCHING ON THE OXIDATION
STABILITY OF UNLEADED REGULAR (ULR) GASOLINES
OF CONTAINING FCCU PRODUCT NAPHTHA

Percent Riser Outlet Temperatures Resid in Feed to Weighted Catalytic Ex. FCCU 500 FCCU 600 Average Complex 19 970 980 974 4.4 973 980 976 4.0 21 980 980 980 4.2 22 980 980 980 4.3 23 980 980 980 4.7 Average 977 980 978 4.3 Std. Deviation5 - 3 0.2 24 980 981 980 4.3 983 983 983 4.4 26 975 985 979 4.4 27 985 985 985 4.4 28 985 985 985 4.4 29 985 985 985 4.3 985 985 985 4.5 Average 983 984 983 4.4 Std. Deviation4 2 3 0.1 _ -38- 2 0 1 7 1 1 6 EFFECT OF QUENCHING ON THE OXIDATION
STABILITY OF UNLEADED REGULAR (ULR) GASOLINES
OF CONTAINING FCCU PRODUCT NAPHTHA

Cont'd % Total Catalytic % HCN% LCN Naphtha 10 Ex. in ULRin ULR in ULR

19 50.3 14.5 64.8 49.8 19.2 69.0 21 56.5 14.0 70.5 22 58.0 14.7 72.7 23 56.0 9.2 65.2 Average 54.1 14.3 68.4 Std. Deviation 3.8 3.5 3.4 24 55.3 13.6 68.9 55.6 11.3 66.9 26 54.4 9.5 63.9 27 59.3 14.4 73.7 28 54.3 14.7 69.0 29 48.5 17.8 66.3 59.0 11.7 70.7 Average 55.2 13.3 68.5 Std. Deviation 3.6 2.7 3.2 _ _39_ 2017116 EFFECT OF QUENCHING ON THE OXIDATION
STABILITY OF UNLEADED REGULAR (ULR) GASOLINES
OF CONTAINING FCCU PRODUCT NAPHTHA

Cont'd LCCO HCCO
ASTM D-525 Quench Quench Oxidation Stability at at 10 Ex. ULR LCN HCN FCCU 500 FCCU 600 19 530 120 225 yes no 535 120 195 yes no 21 465 90 200 yes no 15 22 415 - - yes no 23 400 - - yes no Average 469 110 207 yes no Std. Deviation63 17 16 - -24 710 110 >240 yes yes 20 25 740 135 105 yes yes 26 730 135 >240 yes yes 27 770 105 >300 yes yes 28 710 105 - yes yes 29 825 120 ~300 yes yes 25 30 725 - - yes yes Average 744 118 - yes yes Std. Deviation41 14 ~ ~40- 2017116 EFFECT OF QUENCHING ON THE OXIDATION
STABILITY OF UNLEADED REGULAR (ULR) GASOLINES
OF CONTAINING FCCU PRODUCT NAPHTHA
Percent 5Riser Outlet Temperatures Resid in Feed to Weighted Catalytic Ex. FCCU 500 FCCU 600 Average Complex 31 1010 1015 1012 6.4 32 1010 1015 1012 6.5 33 1010 1015 1012 6.4 34 . 1010 1015 1012 6.4 1010 1015 1012 5.8 36 1010 1015 1012 5.5 37 1010 1015 1012 5.4 38 1010 1015 1012 5.4 39 1012 1015 1013 5.5 1012 1015 1013 5.7 41 1013 1016 1014 5.4 Average 1011 1015 1012 5.8 Std. Deviation 1 0.2 1 0.5 42 1010 1020 1014 5.3 43 1010 1020 1014 5.3 44 1010 1020 1014 5.8 1010 1020 1014 6.0 46 1010 1020 1014 6.0 EFFECT OF QUENCHING ON THE OXIDATION
STABILITY OF UNLEADED REGULAR (ULR) GASOLINES
OF CONTAINING FCCU PRODUCT NAPHTHA

Cont'd % Total Catalytic % HCN% LCN Naphtha 10 Ex. in ULRin ULR in ULR

31 56.0 12.3 68.3 32 56.0 12.6 68.6 33 50.0 15.2 65.2 15 34 52.0 15.7 67.7 49.0 14.8 63.8 36 56.0 9.0 65.0 37 55.1 12.5 67.6 38 55.1 12.5 67.6 20 39 54.7 12.7 67.4 56.5 10.5 67.0 41 59.3 13.6 72.9 Average 54.5 12.9 67.3 Std. Deviation3.0 2.0 2.4 25 42 52.8 12.3 65.1 43 52.8 12.3 65.1 44 55.8 8.3 64.1 50.0 10.3 60.3 46 50.0 10.3 60.3 EFFECT OF QUENCHING ON THE OXIDATION
STABILITY OF UNLEADED REGULAR (ULR) GASOLINES
OF CONTAINING FCCU PRODUCT NAPHTHA

Cont'd LCCO HCCO
ASTM D-525 QuenchQuench Oxidation Stability at at Ex. ULR LCN HCN FCCU 500FCCU 600 31 415 -- -- yes no 32 420 ~240 >240 yes no 33 395 -- -- yes - no 34 330 -- -- yes - no 340 -- -- yes no 36 355 -- -- yes no 37 335 -- -- yes no 38 320 -- -- yes no 39 340 90 -- yes no 330 105 75 yes no 41 335 90 135 yes no Average 355 -- -- yes no Std. Deviation36 -- -- -- --42 720 120 -- yes yes 43 720 105 >300 yes yes 44 825 105 >240 yes yes 710 105 >240 yes yes 46 710 105 >240 yes yes - Examples 49-54 Quenching downstream of the rough cut cyclone also reduces the yield of diolefins. Diolefins (molecules con-taining two unsaturated carbon-carbon bonds) are believed to be the product of thermal rather than catalytic crack-ing reactions, and are formed in regions of the FCCU where the temperature is high, or where the residence time is long. By reducing the temperature in the disengaging zone, the application of quench will reduce the yield of diolefinic molecules.
C4 diolefins (butadienes, and in particular 1,3,butadiene) are considered detrimental in subsequent processing of FCCU butylenes in an isobutane alkylation unit; they cause a higher than desired dilution of the acid alkylation catalyst.
C5 diolefins, including, but not limited to isoprene, 1,3-pentadiene, and cyclopentadiene are considered simi-larly undesirable in an FCCU product stream. If the C5 FCCU product is charged to an isobutane alkylation unit, the C5 diolef ins contained in this C5 hydrocarbon stream can cause a high dilution of the acid alkylation catalyst.-Alternatively, FCCU product streams containing C5 and high molecular weight diolefins may be blended into prod-uct gasolines. In gasoline, diolefins are suspected to conttibute to product instability. The high reactivity of chemical compounds containing two unsaturated bonds will cause the diolefins to rapidly react with oxygen or other substances, forming undesired gums.
Accordingly, a process which produces a lower diole-fin yield is to be desired. Quenching of the reactor dilute phase will lower the diolefin yield. The chemical reactions which contribute to instability in gasoline are complex. Diolefins are believed to participate in these reactions, but it is possible that the stability improve-ments with quenching in Examples 19-48 involve additional molecular compounds other than diolefins as well.
An example of the beneficial effect of quenching in reducing diolefin yields is given below. C5 diolefin yields from the tests are presented. Quenching is expected to change the yield of other diolefins in a simi-lar fashion.
Yield tests were performed in a catalytic cracking unit (FCCU 500) similar to Figure 2. Samples of the total -~4-overhead C5-430 naphtha product were obtained from the vapor product line leaving the disengaging vessel.
The samples in Examples 50 and 51 were taken with one riser reactor out of service. Only one riser reactor, discharging through a single external rough cut cyclone into the common disengaging vessel, was operating.
The samples taken in Examples 49 and 52-54 were taken with both riser reactors operating. Gas products from both external rough cut cyclones were quenched immediately downstream of the external rough cut cyclones with LCCO, then both quenched streams entered the common disengaging vessel.
The rates to each riser reactor in in Examples 49, 52, and 54 were identical but were reasonably split, roughly 50/50. For Example 53, the flow rate of quench was 2500 b/d to the A outlet, 4100 b/d to the B outlet, giving a total of 6600 ~b/d.
The following results were obtained:

Tests Performed Without Quench Fresh LCCO C5 Diolefin Cracking Feed Quench Volume Ex Temp B/D B/D f Fresh Feed 491016F (547C) 73,500 0 0.21 501027F (553C) 48,900 0 0.22 Sl1027F (553C) 48,900 0 0.17 Tests Performèd With LCCO Quench LCCO C5 Diolefin Cracking Fresh Quench Volume Ex. Temp B/D B/D of Fresh Feed 521009F (543C) 80,600 7,000 0.08 531019F (548C) 76,500 6,600 0.11 541020F (549C) 74,600 6,300 0.11 ~ _45_ 2017116 -At substantially the same cracking temperature, C5 diolefin yields were reduced approximately 35-50% by the application of LCCO quenching.

Quench Selection In general, the quench should have a boiling point of 125F (52C), preferably at least 430F (221C) in order to have a sufficient heat capacity to effectively cool the catalytically cracked oil product to minimize thermal cracking of the oil product as well as to allow heat recovery at the bottom rather than the top of the frac-tionator. Desirably, the quench should have a molecular weight over 90 to limit the total volumetric expansion of the quench and oil product upon vaporization to 100% to 120%, preferably 103% to 105% or less, of the volume of the oil products without the quench, i.e., the volumetric expansion of the quench should be from 0 to 20%, prefera-bly 3% to 5% or less of the volume of the catalytically cracked oil. Furthermore, the quench should be inactive and inert to thermal cracking at 900F (482C) to 1100F
(593C) for a residence time of 1-30 seconds in the dilute phase zone of the disengaging vessel. Previously cracked hydrocarbons, such as LCCO, HCCO, HCN, coker gas oil and coker distillates, are very desirable as quenches since they are less reactive to thermal cracking than fresh unprocessed virgin stocks, such as virgin gas oil and virgin naphtha, and hydrotreated stocks, such as hydro-treated gas oil and hydrotreated distillates. Moreover, the quench preferably has a boiling point under 900F
(482C) to completely vaporize in the dilute phase of the disengager in order provide effective cooling of the cata-lytically cracked oil product and avoid coking of the walls and lines of the refinery equipment.
It is also desirable that the guench decrease C2 fuel gas production in order to allow higher operating temper-atures at the catalytic cracking unit.

The properties of various quenches are shown in Table A. LCCO in this patent application also includes intermediate reflux on tower pump arounds with a boiling range, API gravity, and molecular weight similar to that shown for LCCO in Table A.

Table A

Properties of Quenches Nominal Average Nominal API Molecular Boiling Point Gravity Wt.
Light Catalytic 430-650F 11-30 200-300 Cycle Oil (221-343C) 20 avg 215 avg (LCCO) Heavy Catalytic 650-850F 2-25 250-350 Cycle Oil (343-454C) 10 avg (HCCO) lS
Heavy Catalytic 300-430F 20-50 100-250 Naphtha (149-221C) 35-40 avg (HCN) Light Coker 500-650F 30-35 210-300 Gas Oil 526F avg 34 avg (LCGO) (260-343C
274C avg) Coker Still 430-650F 30-40 200-250 Distillates 504F avg 35 215 avg (221-343C
262C avg) Kerosene 320-530F 35-45 150-200 - 400-450F avg 41 avg 175 (160-277C
204-232C avg) -Table A (Cont'd.) Nominal Average Nominal AP~ Molecular Boiling Point Gravity Wt.
Hydrotreated 430-650F 35-45 225-265 Distillate 560F avg 39.5 avg 230 (221-343C
293C avg) Virgin Gas Oil 650-1000F 21-32 300-400 (VGO) (343-538)C 25 avg 350 avg Heavy Virgin 300-350F 40-60 100-250 Naphtha 325F avg 50 150 lS (HVN) (149-177 C
163C avg) Light Virgin 125-175F 60-80 70-150 Naphtha 150F avg 70 125 (LVN) (52-79C
66C avg) Hydrotreated 650-1000F 24-35 300-400 Gas Oil (343-538C) 29 avg 350 avg (HGO) Decanted Oil 700-1200F -4 to +10 400-600 (DCO) 900F avg +2 avg 500 avg (371-649C
482C avs) Resid 1000-1600F 0-20 300-1000 (538-871C) 12 avg 700 avg Water 212F 10 avg 18 (H2O) (100C) _ -49-Quenching involves injecting a fluid, preferably a liquid, into the catalytic cracking unit, preferably imme-diate downstream of the gross cut separator (cyclone), to stop the reactions. Generally, a superior quench process:
1) Will provide maximum economic benefits by effec-tively reducing the loss of valuable products to the ther-mal reactions that occur after catalytic cracking is substantially completed.
2) Will have minimum adverse effects on operations.
3) Will minimally affect utility costs.
Although it is quite clear that a number of fluids could be used as quench, because the requirements of a quenching process are complex, the selection of a quench material and implementation of quenching are neither simple nor obvious. A fluid that is outstanding in one aspect may be unacceptable in another.
The quench fluid cools and dilutes the FCC riser pro-ducts and so reduces the yield of thermal products. Fig-ures 7 and 8 show, i.e., the ability of various quenches to cool the product stream, i.e, show the relative cooling capacities of different fluids. Quenched product temper-ature is plotted as a function of the amount of quench addition. The LCCO/CAT in Figure 7 means that LCCO quench was injected into the oil product before the catalyst was grossly separated from the oil product. The quench addi-tion, expressed as a percentage, is the ratio of the weight of quench fluid to the weight of the product stream. The heat capacity of the quench fluid and its heat of vaporization (if a liquid) influence the cooling capacity. Water is very effective and cools at 20F per 1 wt% addition. Hydrocarbons are also effective and pro-vide cooling at approximately 7F per 1 wt% addition.
Less effective is steam (4F per 1 wt%) because it is already vaporized. Cooling the products before removing catalyst requires tremendous amounts of quench fluid because the catalyst holds large quantities of heat and there is so much catalyst present (typically 6 times the ~50- 2017116 weight of oil). Although water provides good cooling, it has drawbacks that offset this advantage.

Table B

Relative C2-Quench Thermal Product Quench Fuel Gas Molecular Crack- Con- Con- Reduction Wt. ability centration centration Wt.%
Water 18 0.00 0.737 0.263 78.0 Hydro-carbons " 106 0.36 0.846 0.154 69.~
" 114 0.59 0.856 0.144 68.0 " 130 1.37 0.871 0.129 64.4 " 201 0.65 0.913 0.087 65.7 " 216 1.06 0.918 0.082 64.0 " 245 2.46 0.927 0.073 60.8 " 339 1.05 0.946 0.054 63.1 " 365 1.71 0.950 0.050 62.1 " 414 3.96 0.956 0.044 59.1 Adding a quench fluid reduces the fuel gas by decreasing the temperature of the product diluting the concentration of riser products. The rate of thermal degradation of the riser products (and also the hydrocar-bon quench) depends upon the temperature, the residence time in the system, the concentration of vapor, and the inherent reactivity (thermal crackability) of the mate-rial. Reducing the concentration of riser products slows the rate of degradation provided that the quench fluid itself has a lower thermal crackability than the riser product. Table B gives the relative molar concentrations of riser product initially at 1000F (538C) and quench fluid for various quench fluids of different molecular weights injected at a ratio of about 15~ by weight of the -51- 20l7lr~--product. In Table B and the following tables the C2-fuel gas reduction is relative to the instantaneous cooling of the hydrocarbon products from 1000F (538C) to 900F
(482C) with a residence time of about 13 seconds. The quench fluids (injected as liquids) expand to different volumes depending on the molecular weights. The lowest molecular weights provide the maximum expansion and, therefore, the maximum dilution of the riser product.
Table B also provides an estimate of the reduction in C2-fuel gas production based on laboratory tests and includesthe relative thermal reactivity of the quench fluids.
Quench fluids that have low molecular weights give the maximum reduction in C2-fuel gas production since C2-fuel provided measures the extent of thermal degradation, pro-vided that the quench fluid itself has a low susceptibil-ity to thermal cracking.
Stability of the quench is important. A quench mate-rial that is unstable will require excessive replacement and will itself contribute to the C2-yield. Table B
includes the thermal stability of the various fluids. The thermal stability (crackability) was determined from labo-ratory tests of various quench fluids. The values in the table are relative to the thermal stability of heavy cata-lytic naphtha, which will have properties similar to riser products. Of course, the non-hydrocarbon, water, does not crack, so its performance establishes a target for the hydrocarbons. Hydrocarbons with low crackability give satisfactory performance.
Mixing time is also an important factor in quenching.
When the quench fluid is injected into the hot product stream, the quench and product streams must mix as quickly as possible in order to get the maximum rate of cooling.
Inefficient mixing of the two streams allows extra time for the thermal reactions to proceed. By using atomizing nozzles to inject the quench fluid, very small droplets are formed that disperse and vaporize quickly.

The effect of mixing time on the reduction in thermal products is indicated in Table C, based on laboratory results for LCCO quench:

Table C

Effects of Cooling Time on C2 Fuel Gas Reduction for LCCO Quench Cooling Product Time Wt% of Quench C2-Fuel Gas Temperature sec to Product Reduction %

1000F (538C) 1 15 92.4 lS1000F (538C) 5 15 64.0 1200F (649C) 1 60 92.4 1200F (649C) 5 60 68.5 Vapor expansion is an important factor in selecting the proper quench. Vaporized quench enters the product recovery system and must be compatible with the process equipment and control. Improper selection of the quench fluid can lead to upsets in the riser discharge flow, in the separation of catalyst from the product vapors, and can cause interference with the efficient operation of the product fractionator. In order to minimize these dis-ruptions, the quench fluid should give the minimum expan-sion to the vapor so that erratic and extreme pressure levels are avoided. Figure 9 shows the ratio of the volume of the quenched product stream to the product stream alone as a function of temperature drop upon quenching for various quench fluids. The legend LCCO/CAT
in Figure 9 means that LCCO quench was injected into the oil product before the catalyst was grossly separated from the oil product. The gases, steam and propane, have the largest increases because substantial quantities must be added to cool the stream, and the low molecular weight gives large volumes of gas. Water also has a substantial vapor expansion. A water-quenched stream will have almost 20% more volume than the product stream alone. This mag-nitude of expansion can affect operations adversely and should be avoided. On the other hand, the liquid hydro-carbons exhibit a nearly neutral volume change. For the liquid hydrocarbons, the molecular weight is typically high enough so that the volume of gas is much less than for water. Also, the expansion of the hydrocarbon is offset by the contraction of the cooled product so that a nearly constant volumetric flow rate is achieved. This criterion is in contrast to the benefit of low molecular weight diluting the product vapor.
There are practical limits on the amount of quench that is used. The benefits diminish as the amount of quench increases. Also, the benefits are greatest the higher the riser product temperature. Table D illustrates this. Each pair of conditions in the table correspond to two levels of quench addition. At 1000F (538C) doubling the amount of quench reduces the C2-yield by only 45~. At 1200F (649C) increasing quench by a factor of 4 brings only a 30% improvement.

Table D

Pre- Post- C2-Quench Pre- Quench Post Ratio of Fuel Gas Time, Quench Time, Quench Quench to Reduc-seconds Temp. seconds Temp. Feed % tion, %

Quench:

Water 1 1000F 12 950F 2.33 71.2 (538C) (510C) Water 1 1000F 12 900F 5 99.3+
(538C) (482C) LCCO 1 1000F 12 950F 7 64.0 (538C) (510C) LCCO 1 1000F 12 900F 15 92.4 (538C) (482C) LCCO 5 1000F 8 950 F 7 43.9 (538C) (510C) LCCO 5 1000F 8 900F 15 64.0 (538C) (482C) ~55~ 201 7116 Table D (Cont'd.) Pre- Post- C2-Quench Pre- Quench Post Ratio of Fuel Gas Time, Quench Time, Quench Quench to Reduc-seconds Temp. seconds Temp. Feed % tion, %

Quench:
Water 1 1200F 12 1100~ 5 74.3 (649C) (593C) Water 1 1200F 12 900F 20 97.5 (649C) (482C) LCCO 1 1200F 12 1100F 15 67.2 (649C) (593C) LCCO 1 1200F 12 900F 60 92.4 (649C) (482C) LCCO 5 1200F 8 1100F 15 45.8 (649C) (593C) LCCO 5 1200F 8 900F 60 68.5 (649C) (g82C) Coking is another important criteria in determining the proper quench. A high tendency to form coke is detri-mental to a quench fluid. Coke deposits can restrict pro-cess flows that could force a shutdown. Excessive coke in the regenerator could adversely affect the unit's heat balance and economics. On the other hand, a quench fluid that reduces coke by interaction with catalyst in the dilute zone of the disengager vessel improves the unit's coke selectivity and economics.
The use of quench increase utilities costs. A supe-rior quench fluid minimizes those costs. Costs that are associated with the following: replacement of lost quench ~ 56- 2017116 fluid; pumping the quench fluid; incomplete heat recovery and losses; water requirements for cooling and as boiler feed; and treatment of dirty process water.
Some hydrocarbon quench materials can thermally degrade. C2-fuel gas is produced by the degradation.
Table E presents computer model predictions on the effects of various quench medium properties on the gross reduction in C2-. A quench fluid that degrades the products shows a lower C2-fuel gas reduction.
Table E

Effects of Quench Material Properties on Predicted Performance Avg Boiling Relative Concen- C2-Pt Thermal tration Fuel Gas Spec ABP Molecular Crack- of Reduc-20 Gravity F wt ability Quench tion, %

0.825 300 130 1.38 0.129 91.3 0.825 575 245 2.46 0.073 89.5 0.825 800 414 4.00 0.044 88.6 0.93 300 114 0.59 0.144 94.5 0.93 575 216 1.06 0.082 92.4 0.93 800 365 1.72 0.050 91.4 0.99 300 106 0.37 0.154 95.6 0.99 575 201 0.66 0.087 93.4 0.~99 800 339 1.06 0.054 92.4 There are not any or very little additional process water cost associated with the use of hydrocarbon fluids as quench material. Process water must be obtained when water is the quench material. The use of process water ~57~ 2017116 has additional cost. Water becomes contaminated when it goes through the process and must be treated to meet pol-lution control regulations.
Heat recovery is another important factor in select-ing the proper quench. Substantial quantities of heat areabsorbed by the quench material. This heat must be recov-erable in a usable form if the quench process is to be practical. Generally, the higher the temperature at which heat is available, the more easily it can be recovered.
Therefore, quench fluids that boil at higher temperatures will enable better heat recovery. In the FCC catalytic cracking unit, the heat recovery is integrated into the product fractionator system. Low temperature energy in the fractionator system is typically lost to cooling water. Energy in streams below approximately 212F
(100C) to 350F (177C) is not recovered. Therefore, water is a poor quench medium from an energy recovery standpoint since it condenses at 212F (100C) at atmo-spheric pressure and since most of its energy is released when it condenses. A fluid that boils just below the target quench temperature will provide the maximum heat recovery.
In Table F, the enthalpies of some candidate quench fluids (LCCO, HCCO, HVGO, Gas, Oil, Water) are given that correspond to the temperatures in the table. The heats, Ql, Q2, Q3, Q4, are shown which are the heats absorbable above (a) 625F (329C), (b) between 625F (329C) and 475F (246C), (c) between 475F (246C) and 325F
(163C), (d) and between 325F (163C) and 60F (16C), respectively. Materials that absorb large amounts of heat at high temperatures (e.g., high Ql) are preferred, and those that absorb heat at low temperature (e.g., high Q4) are not preferred. For the materials in Table F, the order of preference as a quench medium is (1) HCCO, (2) LCCO, (3) Gas Oil, and lastly Water. The quenched product temperature and Ql upper limit for each quench was _ -58- 2017116 at 900F (482C). The enthalpies were determined at a pressure of 20 psig (238 kPa).

~59~ 2017116 Table F

Enthalpies of FCCU Product Quench Fluids and Available Heats LCCO HCCO
Available Available Temp. Heat Temp. Heat F BTU/LB BTU/LB F BTU/LB BTU/LB
1200 866.2 Maximum 1200 811.5 Maximum 1174 846.9 <==Product 1174 793.3 <==Product 1125 810.5 Temp. 1125 758.9 Temp.
1050 756.1 1050 707.7 15 975 703.3 975 657.8 900 652.1 900 609.5 825 602.7 825 562.9 750 555.1 750 433.0 <==Liquid 675 508.4 675 384.0 20 625 417.9 Ql = 234.2 625 353.7 Ql = 255.8 600 372.6 <==Liquid 600 338.6 525 325.9 525 295.5 475 296.4 Q2 = 121.4 475 268.3 Q2 = 85.4 450 2881.7 450 254.7 25 375 239.9 375 216.4 325 313.8 Q3 = 82.7 325 192.7 Q3 = 75.6 300 200.7 300 180.9 225 164.5 225 148.4 150 131.3 150 119.3 30 75 101.8 75 94.0 95.9 Q4 =117.9 60 88.9 Q4 = 103.8 32 84.9 32 79.5 ~ -60- 2017116 Table F (cont'd.) Enthalpies of FCCU Product Quench Fluids and Available Heats Feed Oil (HVGO) Gas Oil Water Available Available 10 Temp. LCCO Heat Temp. Heat F BTU/LB BTU/L~B F BTU/LBBTU/LB

1200 925.6 Maximum 1200 1639Maximum 1174 904.5 <==Product 1174 1626 <==Product 151125 864.8 Temp. 1125 1600 Temp.
1050 805.3 1050 1500 975 747.2 975 1522 900 678.6 900 1483 825 566.8 <==Liquid 825 1445 20 750 509.6 750 1408 675 454.5 675 1371 625 419.2 Ql =259.4 625 1347 Ql =136.15 600 401.5 600 1335 525 350.7 525 1299 25 475 318.4 Q2 =100.8 475 1275 Q2 =72 450 302.2 450 1263 375 256.3 375 1227 325 227.5 Q3 =90.9 325 1203 Q3 =72 300 213.1 300 1191 30 225 173.0 225 193 150 136.3 150 118 103.5 75 45 <==Liquid 96.9 Q4 =130.6 60 20 Q4 =1175 32 84.7 32 0 Quench Material Selection:
Some quench fluids are evaluated in Table G. Differ-ent refineries may use different quench materials to meet specific requirements or to take advantage of special opportunities. Among the fluids examined below, LCCO is best and HCCO is second best. Water has some serious shortcomings. The remaining materials have certain char-acteristics that can reduce their attractiveness as a quench fluid.
Table G

Evaluation of Candidate Quench Materials 15 Quench Water Steam Propane HCN LCCO HCCO

Cooling Capacity E P P A A A
Product Dilution E E E A G G
Stability E E E G G G
20 Volume Expansion P P P A E E
Coking Tendency E E E E G F
Pumping/
Transporting G F F A A A
Heat Recovery P P P F G E
25 Water Use P P E E E E
Waste Disposal P P E E E E

Key:

P: Poor F: Fair A: Average G: Good E: Excellent Table G (cont'd.) Evaluation of Candidate Quench Materials Hydro- Hydro-(HVGO) treated treated Quench DCO GasOil Kerosene GasOil LCCO

Cooling Capacity A A A A A
10 Product Dilution F F A F A
Stability G A A A A
Volume Expansion E E E E E
Coking Tendency P G E E E
Pumping/
Transporting A A A A A
Heat Recovery E G G G G
Water Use E E E E E
Waste Disposal E E E E E

Key:

P: Poor F: Fair A: Average G: Good E: Excellent Among the many advantages of the novel catalytic cracking and quenching process and system are:
1. Enhanced product values and quality.
2. Greater yield of more valuable hydrocarbons.
3. Production of more naphtha and finished gaso-line.
4. Higher throughput.
5. Better throughput and oxidation stability of product naphtha.

6. Decreased thermal cracking and product degrada-tion thereby minimizing overcracking of gasoline into ethane and light fuel gas.

7. Lower pentadiene content in the naphtha product.

8. Less low value fuel gas production.

9. Increased octane number of naphtha and finished gasoline.

10. Economical ll. Efficient 12. Effective.
Although embodiments of the invention have been shown and described, it is to be understood that various modifi-cations and substitutions, as well as rearrangements of process steps, can be made by those skilled in the art lS without departing from the novel spirit and scope of the invention.

Claims (13)

1. A catalytic cracking process, comprising the steps of:
catalytically cracking feed oil in a catalytic crack-ing unit comprising a regenerator and at least one cata-lytic cracking riser reactor in the presence of a cracking catalyst to produce upgraded oil leaving coked catalyst;

making a gross-cut separation of said coked catalyst from said upgraded oil and substantially immediately thereafter;
quenching said upgraded oil to substantially decrease thermal cracking of said upgraded oil to less valuable hydrocarbon products and light hydrocarbon gases;
regenerating said coked catalyst in a regenerator;
and recycling said regenerated catalyst to said catalytic cracking reactor.

2. A catalytic cracking process in accordance with Claim 1 wherein;
said upgraded oil is quenched with about 2% to about 15% of said quench per volume of said feed oil;
said quench is selected from the group consisting of light cycle oil, heavy cycle oil, heavy catalytic naphtha, and combinations thereof; and said quenching occurs downstream of said riser reac-tor.

3. A catalytic cracking process, comprising the steps of:
catalytically cracking feed oil in a riser reactor of a catalytic cracking unit in the presence of a cracking cat-alyst to produce a catalytically cracked effluent stream of upgraded oil containing catalyst;

substantially separating said catalyst from said upgraded oil in an external gross cut separator and in a disengaging vessel;
quenching said upgraded oil downstream of said external gross cut cut separator and upstream of said dis-engaging vessel with a quench comprising at least one member selected from the group consisting of light cata-lytic cycle oil, heavy catalytic cycle oil, heavy cata-lytic naphtha, kerosene, coker distillates, light coker gas oil, hydrotreated distillate, fresh unprocessed virgin gas oil, and fresh unprocessed virgin naphtha; and said quench is injected into said stream in an amount ranging from about 2% to about 20% by volume per barrel of feed oil.

4. A catalytic cracking process, comprising the steps of:
substantially desalting petroleum comprising crude oil;
heating said desalted crude oil in a furnace;
pumping said heated crude oil to a primary distilla-tion tower;
separating said heated crude oil in said primary dis-tillation tower into streams of naphtha, primary gas oil, and primary reduced crude;
pumping said primary reduced crude oil to a pipestill vacuum tower;
separating said primary reduced crude oil in said pipestill vacuum tower into streams of wet gas, heavy gas oil, and vacuum reduced crude oil providing resid oil;
conveying a feed oil comprising said primary gas oil from said primary distillation tower to an upright elon-gated riser reactor of a catalytic cracking unit;
feeding fresh and regenerated crystalline cracking catalyst to said riser reactor;
catalytically cracking said feed oil in said riser reactor in the presence of said cracking catalyst under catalytic cracking conditions to produce an upgraded effluent product stream of catalytically cracked oil con-taining spent coked catalyst;
separating a substantial amount of said spent coked catalyst from said product stream in an external rough cut separator downstream of said riser reactor to make a gross separation of said coked catalyst from said product stream;
injecting and quenching said product stream soon after said product stream exits said external separator with a cycle oil quench for substantially minimizing ther-mal cracking of said product stream to less valuable hydrocarbons and concurrently enhancing the yield of naph-tha to substantially increase the production of gasoline, said quench comprising a cycle oil selected from the group consisting of light catalytic cycle oil and heavy cata-lytic cycle oil, said quench being injected into said pro-duct stream in an amount ranging from about 5% to about 15% by volume per barrel of feed oil;
conveying said quenched product stream into an upper diluste phase portion of a disengaging vessel;
disengaging and separating a substantial amount of the remaining spent coked catalyst fines from said quenched product stream in at least one internal cyclone in said dilute phase portion of said disengaging vessel;
stripping volatile hydrocarbons from said coked cata-lyst in a stripping section of said disengaging vessel;
passing said stripped coked catalyst to a regenerator of said catalytic cracking unit;
injecting air into said regenerator;
regenerating said spent catalyst by substantially combusting coke on said spent catalyst in the presence of air in said regenerator;
recycling said regenerated catalyst to said riser reactor;
separating said cracking oil in a fractionator into streams of light hydrocarbon gases, catalytic naphtha, catalytic cycle oil including light catalytic cycle oil, and decanted oil; and recycling said light catalytic cycle oil from said fractionator to a quench injection line located between said external cyclone and said fluidized bed reactor for use as said quench.

5. A catalytic cracking unit, comprising:
an upright elongated riser reactor for catalytically cracking feed oil in the presence of a cracking catalyst to produce an upgraded effluent product stream of catalyt-ically cracked oil leaving coked catalyst, said riser reactor having an upper portion and a lower portion;
an external rough cut separator connected to and com-municating with said upper portion of said riser reactor and being spaced from, positioned about and at a substan-tially similar elevation as said upper portion of said riser reactor for making a gross separation of said coked catalyst from said catalytically cracked oil;
an upright disengaging vessel for sustantially disen-gaging and separating a substantial amount of remaining coked catalyst from said catalytically cracked oil, said disengaging vessel having an upper dilute phase zone with at least one internal separator, a lower dense phase zone, and a stripping section providing a stripper;
product line extending between and connecting said external separator and said upper diluate phase portion of said vessel;
a spent catalyst line extending between and connect-ing said external separator and said dense phase portion of said disengaging vessel;
a regenerator comprising a vessel, an upright elon-gated lift pipe for transporting coked catalyst to regen-erator, an air injector communicating with said lift pipe for injecting air and facilitating combustion of said coked catalyst, and a regenerated catalyst line connected to said riser reactor for conveying regenerated catalyst to said riser reactor; and a cycle oil quench injection line connected to and communicating with said input line for injecting a quench comprising cycle oil selected from the group consisting of light catalytic cycle oil and heavy catalytic cycle oil, into said catalytically cracked oil after said catalyt-ically cracked oil has exited said external separator downstream of said riser reactor and has been grossly sep-arated from said catalyst and before said catalytically cracked oil enters said disengaging vessel for enhancing the yield of naphtha and substantially decreasing thermal cracking of said product stream of oil, said cycle oil quench line including a substantial vertical light cycle oil injector for injecting said quench substantially ver-tically downwardly into said input line or being at an angle of inclination ranging from about 15 degrees to about 45 degrees relative to a vertical reference line for increasing mixing of said quench with said products.

6. A catalytic cracking process, comprising the steps of:
catalytically cracking feed oil in a riser reactor of a catalytic cracking unit in the presence of a cracking cat-alyst to produce a catalytically cracked effluent stream of upgraded oil containing catalyst;
substantially separating said catalyst from said upgraded oil in an internal gross cut separator in a dis-engaging vessel, said internal gross cut separator com-prising an inertia separator selected from the group consisting of an internal cyclone and an inverted can sep-arator; and quenching said upgraded oil downstream of said inter-nal gross cut separator in said disengaging vessel with a quench comprising at least one member selected from the group consisting of light catalytic cycle oil, heavy cata-lytic cycle oil, heavy catalytic naphtha, kerosene, coker distillates, light coker gas oil, hydrotreated distillate, fresh unprocessed virgin gas oil, and fresh unprocessed virgin naphtha, said quench being injected into said stream in an amount ranging from about 2% to about 20% by volume per barrel of feed oil.

7. A catalytic cracking process, comprising the steps of:
substantially desalting petroleum comprising crude oil;
heating said desalted crude oil in a furnace;
pumping said heated crude oil to a primary distilla-tion tower;
separating said heated crude oil in said primary dis-tillation tower into streams of naphtha, primary gas oil, and primary reduced crude;
pumping said primary reduced crude oil to a pipestill vacuum tower;
separating said primary reduced crude oil in said pipestill vacuum tower into streams of wet gas, heavy gas oil, and vacuum reduced crude oil providing resid oil;
conveying a feed oil comprising said primary gas oil from said primary distillation tower to an upright elon-gated riser reactor of a catalytic cracking unit;
feeding fresh and regenerated crystalline cracking catalyst to said riser reactor;
catalytically cracking said feed oil in said riser reactor in the presence of said cracking catalyst under catalytic cracking conditions to produce an upgraded effluent product stream of catalytically cracked oil con-taining spent coked catalyst;
separating a substantial amount of said spent coked catalyst from said product stream in an internal rough cut separator in the dilute phase portion of a disengaging vessel located downstream of said riser reactor to make a gross separation of said coked catalyst from said product stream;
injecting and quenching said product stream soon after said product stream exits said internal separator with a cycle oil quench for substantially minimizing ther-mal cracking of said product stream to less valuable hydrocarbons and concurrently enhancing the yield of naph-tha to substantially increase the production of gasoline, said quench comprising a cycle oil selected from the group consisting of light catalytic cycle oil and heavy cata-lytic cycle oil, said quench being injected into said pro-duct stream in an amount ranging from about 5% to about 15% by volume per barrel of feed oil;
disengaging and separating a substantial amount of the remaining spent coked catalyst fines from said quenched product stream in at least one internal cyclone in said dilute phase portion of said disengaging vessel;
stripping volatile hydrocarbons from said coked cata-lyst in a stripping section of said disengaging vessel;
passing said stripped coked catalyst to a regenerator of said catalytic cracking unit;
injecting air into said regenerator;
regenerating said spent catalyst by substantially combusting coke on said spent catalyst in the presence of air in said regenerator;
recycling said regenerated catalyst to said riser reactor;
separating said quenched catalytically cracked oil in a fractionator into streams of light hydrocarbon gases, catalytic naphtha, catalytic cycle oil including light catalytic cycle oil, and decanted oil; and recycling said light catalytic cycle oil from said fractionator to said disengaging vessel for use as said quench.

8. A catalytic cracking process in accordance with Claims 4 or 7 including feeding some of said resid oil to said riser reactor for use as part of said feed oil and said quench comprises heavy catalytic cycle oil.

9. A catalytic cracking process in accordance with Claims 4 or 7 wherein light catalytic cycle oil is injected into said feed oil as at least part of said quench.

10. A catalytic cracking process in accordance with Claim 7 wherein:
said separating includes impinging said effluent pro-duct stream upon exiting said riser reactor against a striker plate of an inverted can separator, discharging said separated catalyst through the open bottom of said inverted can separator, and passing said separated cata-lytically cracked oil through at least one window compris-ing a product outlet of said inverted can separator; and said quenching comprises spraying said cycle oil in proximity to said window of said inverted can separator.

11. A catalytic cracking unit, comprising:
an upright elongated riser reactor for catalytically cracking feed oil in the presence of a cracking catalyst to produce an upgraded effluent product stream of catalyt-ically cracked oil leaving coked catalyst, said riser reactor having an upper portion and a lower portion;
an upright disengaging vessel communicating with said riser reactor for substantially disengaging and separating a substantial amount of coked catalyst from said catalyt-ically cracked oil, said disengaging vessel having an upper dilute phase zone with at least one internal cyclone, a lower dense phase zone, and a stripping section providing a stripper;
an internal gross cut separator positioned in said dilute phase zone of said disengaging vessel for making a gross separation of said coked catalyst from said catalyt-ically cracked oil, said internal gross cut separator defining a vapor port providing an oil outlet and having a lower portion providing a catalyst outlet;
a regenerator comprising a vessel, an upright elon-gated lift pipe for transporting coked catalyst from said disengaging vessel to said regenerator, an air injector communicating with said lift pipe for injecting air and facilitating combustion of said coked catalyst, and a regenerated catalyst line connected to said riser reactor for conveying regenerated catalyst to said riser reactor;
and at least one cycle oil quench injection line extend-ing into the interior of said disengaging vessel and sub-stantially aligned in registration with said oil outlet of said internal gross cut separator for injecting a quench comprising cycle oil selected from the group consisting of light catalytic cycle oil and heavy catalytic cycle oil, into said catalytically cracked oil after said catalyt-ically cracked oil has exited said oil outlet of said internal gross cut separator and has been grossly sepa-rated from said catalyst for substantially enhancing the yield of naphtha and substantially decreasing thermal cracking of said product stream of oil.

12. A catalytic cracking unit in accordance with Claim 11 wherein said cycle oil quench line is at an angle of inclination ranging from about 15 degrees to about 90 degrees relative to a vertical reference line extending through said disengager for substantially minimizing back-flow of said quench.

13. A catalytic cracking unit in accordance with Claim 11 wherein said regenerator is located below said disengaging vessel and said catalytic cracking unit includes a substantially horizontal conduit extending between and connecting the top portion of said riser reac-tor to said internal gross cut cyclone.