Desulfurization of hydrocarbon streams

A process for desulfurizing a hydrocarbon stream which includes at least 50 ppmw sulfur in the form of organic sulfur compounds, and C.sub.5 + hydrocarbons including benzene. The hydrocarbon stream is contacted in the absence of added hydrogen with a fluidized bed of an acidic catalyst having a structure of ZSM-5, ZSM-11, ZSM-22, ZSM-23, ZSM-35, ZSM-48, MCM-22, MCM-36, MCM-49, zeolite Y, zeolite beta or mixtures thereof to convert the organic sulfur compounds to hydrogen sulfide. The catalyst contacts the hydrocarbon stream at a pressure of from 0.0 psig to about 400 psig, a temperature of from about 400.degree. F. to about 900.degree. F., and a weight hourly space velocity of from about 0.1 hr..sup.-1 to about 10.0 hr..sup.-1. Thereafter, the hydrogen sulfide is removed from the hydrocarbon stream.

BACKGROUND OF THE INVENTION 
1. Field of the Invention 
The present invention relates to the desulfurization of hydrocarbon 
streams. More specifically the present invention relates to 
desulfurization of hydrocarbon streams by converting organic sulfur 
compounds in the streams to hydrogen sulfide without added hydrogen. 
2. Description of Prior Art 
The production of high octane gasoline continues to be a major objective of 
refinery operations worldwide. The phase-out of lead and the movement to 
reformulate gasoline to improve air quality in the United States, Europe, 
and the Pacific Rim countries present a major challenge and opportunity in 
the refining industry. In the United States, the recent Clean Act 
Amendments define reformulated gasoline in terms of composition including 
oxygen, benzene, Rvp and total aromatics, and of performance standards 
containing reductions in VOC's and air toxics. More stringent requirements 
may be required in the future as indicated by California Air Resources 
Board proposals for tighter limitations on gasoline olefins, sulfur, Rvp, 
and distillation curve. In Europe, movements are underway to reduce 
allowable benzene from the current guideline of 5 vol % maximum. An 
interim reduction to 3% has been proposed. Also, sulfur may be restricted 
to 200 ppmw in Eurograde gasoline. In the Pacific Rim countries, octane 
shortfall may occur as lead additives are phased out, and several 
countries are considering reducing the amount of allowable benzene in 
gasoline. Japan now limits the amount of sulfur in gasoline to 150 ppmw or 
less. However, conventional desulfurization technologies consume hydrogen 
or require caustic wash placing additional burdens on these limited 
refinery resources. 
Typically hydrotreating is used to convert sulfur compounds in hydrocarbon 
streams or fractions to hydrogen sulfide for removal from the fraction. 
Hydrotreating is also used to improve stability by saturating olefinic 
compounds in the stock being treated. Hydrotreating also may be employed 
to improve the quality of feed streams to other units such as naphtha 
reformers and cat crackers or product streams such as jet fuels and 
distillates. Hydrotreating of heavier crude fractions is also used to 
improve the quality of FCC feedstocks and to remove sulfur from residual 
fuel oil fractions. 
Specifically, hydrotreating of FCC feedstocks may be considered as feed 
preparation and/or as a pollutant cleanup process, and is generally 
associated with improved product selectivity and product quality in 
cracking. Thus, higher conversion and gasoline yield, and lower 
selectivity to coke have commonly been reported in FCC cracking of 
hydrogenated stocks. Also, more favorable light gas distribution, 
including higher isobutane yields, has been observed. Improved quality of 
cracked products, ranging from gas through coke, notably in lower sulfur 
and nitrogen contents, allows meeting ultimate SO.sub.2 and NO.sub.x 
specifications. 
More specifically, hydrotreating converts asphaltenes and potential 
coke-forming material and saturates polynuclear aromatic ring systems so 
that less coke is formed upon cracking. Much of the hydrogen consumption 
in hydrotreating can be related to saturation of polynuclear aromatics, 
and sulfur and nitrogen heterocyclics. 
A hydrotreating process is generally carried out in a fixed bed single pass 
adiabatic reactor with feed preheat, hydrogen-recycle/compression and 
cooling quench capabilities, and feed effluent heat exchange capacity. 
Typically, the required auxiliary apparatus are high and low pressure 
separators, fractionators, and access to amine scrubbers to remove 
hydrogen sulfide and mercaptans. A supply of H.sub.2 may be cascaded from 
a catalytic reformer, but high hydrogen-consumption dictates construction 
of a hydrogen plant. 
Sulfur is removed catalytically by hydrogenation of heterocyclic aromatic 
rings in which it is located. In lighter fractions, mild conditions may 
suffice for desulfurization. However, with heavier oils, the sulfur is 
deeply buried in the hydrocarbon, and a mild catalytic cracking is 
required to extract it. 
Processing residua for fuels is especially difficult if large amounts of 
asphaltenes are present. These high molecular weight, often colloidal 
aggregates, are highly aromatic and tend to coke up catalysts. Their 
sulfur and metals are difficult to remove, and much hydrogen is consumed 
in their processing. 
The prior art provides no simple alternative to these basic hydrogenative 
cleanup processes which require a capital intensive hydrogen plant, a 
hydrotreating reactor and other associated equipment. 
SUMMARY OF THE INVENTION 
In accordance with a broad aspect of the present invention, there is 
provided a process for desulfurizing a hydrocarbon feed stream which 
comprises at least 50 ppmw sulfur in the form of organic sulfur compounds. 
The process comprises the steps of contacting the hydrocarbon stream in 
the absence of added hydrogen with an acidic catalyst to convert organic 
sulfur compounds to hydrogen sulfide, and then removing the hydrogen 
sulfide from the hydrocarbon stream. The catalyst is preferably in a 
fluidized bed. 
The hydrocarbon feed stream may contain an olefin component, along with 
aromatic components including benzene. The olefin component which may 
range from C.sub.1 to C.sub.10 typically derives light olefins (C.sub.1 
-C.sub.4), if present, from LPG and /or fuel gas. Heavier olefins, if 
present, are generally obtained from cracking processes, such as 
catalytically cracked naphthas or pyrolysis or coker gasolines. The 
sources of the aromatic components including benzene are C.sub.5 + 
naphtha, FCC gasoline, reformate and thermally cracked pyrolysis and/or 
coker fractions. 
The feed stream may contain both aromatic and olefin components in a 
fraction of a single origin. For example, an FCC process may provide the 
light olefin component of C.sub.4 - olefins, as well as a catalytically 
cracked C.sub.5 + fraction including both the heavier olefinic and the 
aromatic components. The catalytically cracked C.sub.5 + fraction contains 
at least 50 ppmw of the organic sulfur compounds, and may contain at least 
200 ppmw of such organic sulfur compounds. 
In accordance with a specific aspect of the invention, the acidic catalyst 
is a zeolite having a structure of ZSM-5, ZSM-11, ZSM-12, ZSM-22, ZSM-23, 
ZSM-35, ZSM-48, MCM-22, MCM-36, MCM-49, zeolite Y, zeolite beta or 
mixtures thereof. 
In accordance with another aspect of the invention, the hydrocarbon stream 
contacts the acidic catalyst at a pressure of from 0.0 psig to about 400 
psig, and preferably from about 50 psig to about 250 psig; at a 
temperature of from about 400.degree. F. to about 900.degree. F.; and at a 
weight hourly space velocity of from about 0.1 hr..sup.-1 to about 10.0 hr 
.sup.-1 and preferably from about 0.1 hr..sup.-1 to about 2.0 hr. .sup.-1. 
Thus, the present invention provides an alternative method for 
desulfurization which can complement existing desulfurization facilities, 
and reduce capital expenditure on new or modified processes. 
DESCRIPTION OF SPECIFIC EMBODIMENTS 
HYDROCARBON FEED STREAM 
The hydrocarbon feed stream processed by the present invention preferably 
contains an olefin component, along with aromatic components including 
benzene. The olefin component which may range from C.sub.1 to C10 
typically derives light olefins (C.sub.1 -C.sub.4), if present, from LPG 
and/or fuel gas. Heavier olefins, if present, are generally obtained from 
FCC gasoline or other naphthas derived from cracking processes. These 
olefin-containing fractions typically have the following properties. 
______________________________________ 
FRACTION IP EP SULFUR CONTENT 
______________________________________ 
LPG -100.degree. F. 
100.degree. F. 
1-1,000 ppmw 
fuel gas -- -- 0-100 ppmw 
FCC gasoline 
70.degree. F. 
450.degree. F. 
50-50,000 
ppmw 
______________________________________ 
The sources of the aromatic component including benzene are straight run 
naphtha, FCC gasoline, reformate and/or thermally cracked pyrolysis and 
coker fractions. These fractions generally have an IP and EP of 70.degree. 
F. and 450.degree. F., respectively, and the following noted sulfur 
content. 
______________________________________ 
FRACTION SULFUR CONTENT 
______________________________________ 
straight run naphtha 
5-5,000 ppmw 
FCC gasoline 50-5,000 ppmw 
reformate 0.0-10 ppmw 
thermally cracked- 
pyrolysis gasoline 50-5,000 ppmw 
coker 50-5,000 ppmw 
______________________________________ 
The feed stream may contain both aromatic and olefin components in a 
fraction of a single origin. For example, a fluid catalytic cracking (FCC) 
process may provide the light olefin component of C.sub.4 -olefins. The 
FCC gasoline stream includes a catalytically cracked C.sub.5 + fraction 
including both the olefinic and aromatic components. The catalytically 
cracked C.sub.5 + fraction contains at least 50 ppmw of the organic sulfur 
compounds, and may contain at least 200 ppmw of said organic sulfur 
compounds. 
The C.sub.5 + hydrocarbon stream may also comprise C.sub.5 + reformate 
(e.g. a 150.degree.-210.degree. F. fraction rich in benzene), pyrolysis 
gasoline, coker naphtha or combinations thereof. 
In addition to desulfurization, the process of the present invention may 
provide significant olefin and benzene conversion and octane uplift. This 
conversion occurs as a result of the alkylation of benzene with olefins. 
The FCC naphtha fractions may be upstream or downstream of a mercaptan 
extractor such as the extractive Merox process developed by Universal Oil 
Products and described in Modern Petroleum Technology, 4th Ed, G. D. 
Hobson et al, Applied Science Publishers LTD, Essex, England, 1973, pages 
392-396. A fluid-bed reactor/regenerator is preferred to maintain catalyst 
activity. 
Process Parameters 
In accordance with another aspect of the invention, the hydrocarbon feed 
stream contacts a fluid bed of the acidic catalyst at a pressure of from 
0.0 psig to about 400 psig, preferably from about 50 psig to about 250 
psig; and at a temperature of from about 400.degree. F. to about 
900.degree. F., preferably from about 700.degree. F. to about 850.degree. 
F. for ZSM-5, ZSM-11, ZSM-22, ZSM-23, ZSM-35 and ZSM-48. The preferred 
temperature range for MCM-22, MCM-36, MCM-49, zeolite Y and zeolite beta 
is from about 400.degree. F. to about 800.degree. F. The weight hourly 
space velocity of the stream is from about 0.1 hr.sup.-1 to about 10.0 
hr.sup.-1 and preferably from about 0.1 hr.sup.-1 to about 2.0 hr.sup.-1. 
It is preferred that the process of the present invention remove at least 
30%, and more preferably at least 50%, of the organic sulfur compounds 
from the fuel gas feed stream. 
Catalyst 
The acidic catalyst used in the desulfurization process of the present 
invention is preferably a zeolite-based catalyst, that is, it comprises an 
acidic zeolite in combination with a binder or matrix material such as 
alumina, silica, or silica-alumina. The preferred zeolites for use in the 
catalysts in the present process are the medium pore size zeolites, 
especially those having the structure of ZSM-5, ZSM-11, ZSM-12, ZSM-22, 
ZSM-23, ZSM-35, ZSM-48 MCM-22. The medium pore size zeolites are a 
well-recognized class of zeolites and can be characterized as having a 
Constraint Index of 1 to 12. Constraint Index is determined as described 
in U.S. Pat. No. 4,016,218 incorporated herein by reference. Catalysts of 
this type are described in U.S. Pat. Nos. 4,827,069 and 4,992,067 which 
are incorporated herein by reference and to which reference is made for 
further details of such catalysts, zeolites and binder or matrix 
materials. 
The present process may also use catalysts based on large pore size 
zeolites such as the synthetic faujasites, especially zeolite Y, 
preferably in the form of zeolite USY. Zeolite beta may also be used as 
the zeolite component. Other materials of acidic functionality which may 
be used in the catalyst include the materials identified as MCM-36 
(described in U.S. patent applications Ser. Nos. 07/811,360, filed 20 Dec. 
1991 and 07/878,277, filed 4 May 1992) and MCM-49 (described in U.S. 
patent applications Ser. Nos. 07/802,938 filed 6 Dec. 1991 and 07/987,850, 
filed 9 Dec. 1992). These applications describing MCM-36 and MCM-49 are 
incorporated herein by reference. 
The particle size of the catalyst should be selected in accordance with the 
fluidization regime which is used in the process. Particle size 
distribution will be important for maintaining turbulent fluid bed 
conditions as described in U.S. Pat. No. 4,827,069 and incorporated herein 
by reference. Suitable particle sizes and distributions for operation of 
dense fluid bed and transport bed reaction zones are described in U.S. 
Pat. Nos. 4,827,069 and 4,992,607 both incorporated herein by reference. 
Particle sizes in both cases will normally be in the range of 10 to 300 
microns, typically from 20 to 100 microns. 
Thus, the preferred acidic zeolite catalysts are those exhibiting high 
hydrogen transfer activity and having a zeolite structure of ZSM-5, 
ZSM-11, ZSM-12, ZSM-22, ZSM-23, ZSM-35, ZSM-48, MCM-22, MCM-36, MCM-49, 
zeolite Y, and zeolite beta. 
These catalysts are capable of converting organic sulfur compounds such as 
thiophenes and mercaptans to hydrogen sulfide without added hydrogen by 
utilizing hydrogen present in the hydrocarbon feed. Metals such as nickel 
may be used as desulfurization promoters. 
These catalysts are also capable of simultaneously converting light olefins 
present in the fuel gas to more valuable gasoline range material. A 
fluid-bed reactor/regenerator is preferred over a fixed-bed system to 
maintain catalyst activity. Further, the hydrogen sulfide produced in 
accordance with the present invention can be removed using conventional 
amine based absorption processes such as those discussed hereinabove. 
ZSM-5 crystalline structure is readily recognized by its X-ray diffraction 
pattern, which is described in U.S. Pat. No. 3,702,866. ZSM-11 is 
disclosed in U.S. Pat. No. 3,709,979, ZSM-12 is disclosed in U.S. Pat. No. 
3,832,449, ZSM-22 is disclosed in U.S. Pat. No. 4,810,357, ZSM-23 is 
disclosed in U.S. Pat. Nos. 4,076,842 and 4,104,151, ZSM-35 is disclosed 
in U.S. Pat. No.4,016,245, ZSM-48 is disclosed in U.S. Pat. No.4,375,573 
and MCM-22 is disclosed in U.S. Pat. No. 4,954,325. The U.S. Patents 
identified in this paragraph are incorporated herein by reference. 
While suitable zeolites having a coordinated metal oxide to silica molar 
ratio of 20:1 to 200:1 or higher may be used, it is advantageous to employ 
aluminosilicate ZSM-5 having a silica:alumina molar ratio of about 25:1 to 
70:1, suitably modified. A typical zeolite catalyst component having 
Bronsted acid sites may consist essentially of crystalline aluminosilicate 
having the structure of ZSM-5 zeolite with 5 to 95 wt.% silica, clay 
and/or alumina binder. 
These siliceous zeolites are employed in their acid forms, ion-exchanged or 
impregnated with one or more suitable metals, such as Ga, Pd, Zn, Ni, Co 
and/or other metals of Periodic Groups III to VIII. The zeolite may 
include other components, generally one or more metals of group IB, IIB, 
IIIB, VA, VIA or VIIIA of the Periodic Table (IU). 
Useful hydrogenation components include the noble metals of Group VIIIA, 
especially platinum, but other noble metals, such as palladium, gold, 
silver, rhenium or rhodium, may also be used. Base metal hydrogenation 
components may also be used, especially nickel, cobalt, molybdenum, 
tungsten, copper or zinc. 
The catalyst materials may include two or more catalytic components which 
components may be present in admixture or combined in a unitary 
multifunctional solid particle. 
In addition to the preferred aluminosilicates, the gallosilicate, 
ferrosilicate and "silicalite" materials may be employed. ZSM-5 zeolites 
are particularly useful in the process because of their regenerability, 
long life and stability under the extreme conditions of operation. Usually 
the zeolite crystals have a crystal size from about 0.01 to over 2 microns 
or more, with 0.02-1 micron being preferred. 
In the following Examples, the fluidized bed catalyst particles consist 
essentially of 25 wt % H-ZSM-5 zeolite, based on total catalyst weight, 
contained within a silica-alumina matrix and having a alpha value of 5. 
Sulfur conversion to hydrogen sulfide will increase as the alpha value 
increases. 
In a fixed bed embodiment the catalyst may consist of a standard 70:1 
aluminosilicate H-ZSM-5 extrudate having an acid value of at least 20, 
preferably 150 or higher. 
The Alpha Test is described in U.S. Pat. 3,354,078, and in the Journal of 
Catalysis, Vol. 4, p. 527 (1965); Vol. 6, p. 278 (1966); and Vol. 61, p. 
395 (1980), each incorporated herein by reference as to that description.