US 2640009 A
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Patented May 26, 1953 TEEATIVIENT OF HYDROCARBONS WITH HYDROGEN Charles W. Montgomery, Oakmont, and Charles S. Brown, Pittsburgh, Pa., assignors to Gulf Research & Development Company, Pittsburgh, Pa., a corporation of Delaware No Drawing. Application December 20, 1949,
Serial No. 134,116
11 Claims. 1
This invention relates to the treatment of hydrocarbon oils to reduce the amount of sulfur or sulfur compounds contained therein and/or to convert them into lower boiling hydrocarbons.
It has been known for a considerable period of time that hydrocarbons such as gasoline, gas oil, crude petroleum, etc., contain sulfur or sulfur compounds and that such sulfur compounds have a deleterious effect on the equipment in which such hydrocarbon oils are refined and used as well as on the properties of the refined hydrocarbon oils. It has also been known to remove such sulfur or sulfur compounds from sulfur containing hydrocarbon oils by various methods such as treatment with caustic solution, extraction with various solvents and solutizers, absorption with reactive metallic compounds, and by conversion to hydrogen sulfide by means of catalysts.
This invention has for its object to provide improved procedure for desulfurizing hydrocarbon oils. Another object is to provide a process whereby the sulfur content of low boiling hydrocarbon oils such as gasoline can be materially reduced without undesirably affecting the character and properties of the hydrocarbon oil being treated. A further object is to provide procedure whereby high boiling hydrocarbons can be effectively desulfurized and/or destructively hydrogenated without excessive cracking leading to large loss of the hydrocarbon in the form of gas and coke. Other objects will appear hereinafter.
These and other objects are accomplished by our invention which includes contacting vapors of the hydrocarbon and hydrogen with a composition which has been treated with wet steam and which initially comprises a hydrogenating catalyst composited with a solid refractory cracking catalyst. It has been found that the de-- sulfurization activity of such a contact agent is not materially reduced by the steam treatment whereas the steam treatment materially reduces the deleterious cracking activity of the composition so that less desirable products such as gas and carbon are not formed in large amounts during the process.
Our invention is applicable to hydrode'sulfurization and destructive hydrogenation processes in general. Hydrodesulfurization processes can be divided into two types, namely the absorption and catalytic type. In the absorption type the sulfur is absorbed and fixed on the catalytic composition which comprises an iron group metal, iron group metal oxide or a mixture of the two composited with the cracking catalyst base.
Nickel and especially nickel oxide give best results as the hydrogenating component in this type of process. During the absorption desulfurization the iron group metal or metal oxide reacts with the sulfur contained in the hydrocarbon oil and fixes it as metal sulfide. This metal sulfide is periodically regenerated by suitable treatment to reconvert the metal sulfide into the iron group metal or metal oxide. This regenerated catalyst is then reused in the process.
In the catalytic hydrodesulfurization process the sulfur present in the hydrocarbon oil is converted into hydrogen sulfide and the hydrogen sulfide gas is removed from the product. The principal difference between absorption hydrodesulfurization and catalytic hydrodesulfurization is that in the absorption method the process is not permitted to continue beyond the point at which the absorbing medium or catalyst has become completely sulfided, i. e., when the entire metal content has been converted into metal sulfide. Conventional catalytic hydrodesulfurization permits longer on-stream periods since it is not necessary to regenerate the catalyst after it has been completely sulfided. However, the catalyst does become inactivated during use. Also the catalyst bed eventually offers high resistance to passage of vapors due to the carbon deposited thereon. Periodic regeneration is therefore also desirable in this type of process. Any hydrogenating catalyst can be used in the catalytic hydrodesulfurization process, such as any catalyst mentioned above or molybdenum or tungsten oxides or sulfides, iron group metal molybdates, etc. Hydrogenating catalysts of the sulfur resistant type, such as the oxides or sulfides or mixtures thereof, of metals of the left hand column of group VI of the periodic table, etc., are preferred.
Both the catalytic and the absorption type of hydrodesulfurization have the characteristic of partially converting high boiling stocks into lower boiling products such as gas oil and gasoline. They are therefore in this respect somewhat similar to destructive hydrogenation. As indicated, our invention is also useful in connection with the destructive hydrogenation of high boiling hydrocarbons where no desulfurization is involved. This procedure, as is well known, is a conversion of high boiling hydrocarbons into lower boiling hydrocarbons by treatment with hydrogen while in the presence of a hydrogenating catalyst. Excessive or deleterious cracking to gas and coke is prevented or reduced in this procedure by utilizing a steam treated catalyst as described herein. Y
The hydrogenating component of the catalyst can be disposed on or carried by any known cracking catalyst of the solid refractory type. Preferred catalysts of this type are silicates or mixtures of silicates or mixtures oi oxides which are known to be cracking catalysts. cracking catalysts of this type are mixtures of hydrous oxides of silicon with one or more of the oxides of magnesium, boron, aluminum, titanium and zirconium. Natural cracking catalysts; of; this type are usually silicates of magnesium and/or aluminum combined with minor amounts of oxides of these metals which may or may not be activated as by acid treatment. SPQQfiiC, examples of suitable solid refractory cracking catalysts are natural or synthetic silica-alumina, silica-magnesia, zirconia-silica, titania-silioa, alumina-zirconia-silica, alumina-boria-silica or alumina-magnesia-silica cracking catalysts, It is to be noted that in the case of natural cracki s, c ta ysts the cem en ts mentio ed. wi l ordinarily be present in the form of silicates, These acki cata ysts may o t in ot er meta oxides having an activating action such as thorium, zirconium and titanium oxides other metallic compounds normally used in promoting cracking catalysts. Also, these cracking catalyst carriers or bases may be eithe fresh or they may have been previously used in a, cracking operation. The hydrogenating catalyst is dispersed on or composited with. the cracking catalyst carrier or base in any conventional manner, for exple by impr a ing i with. a ui able s ution of a salt such as the formats or nitrate followed by drying and calcining to convert the salt into the oxide.
The treatment of the catalyst with wet steam can be accomplished conveni ntly by admitting steam into the reaction chamber used for the desulfurization or destructive hydrogenation process. separate chamber if desired. Steam, is admitted; until the chamber and catalyst composition, have been heated to approximately the temperature to;
be used for the wet steam treatment, and the wet steam then led into the chamber at a more or less constant pressure. until the desired d,e-. crease in cracking activity has taken place. a temperature of about 350 to 550 F. can be used. However, we prefer to use a temperatt rev of about o he satu a ed steam sure, may vary from about 135 t 1000 POn QS. per square inch, We prefer to use a, pressure between about 25.0 and about 450. p s. i. Wetsteam under these conditions will, give a catalyst having a suitable activity in a period of about /2 to 2 hours. If desired the catalyst may, be preheated to the elevated temperature of 350 110.400 F.
by means of an inert gas and the saturated Steam then introduced under the conditions. outlined above.
If the steaming step is carried out immediately after the calcining step mentioned above, it may be necessary only to allow the. contact agent to v cool to the desired steaming temperature and then admit wet steam as. indicated. 1.11 is, necessary that the steam be wet, steam, i. e., that. it, be below the critical temperature of water and. be saturated.
In carrying out. the process the hydrocarbon vapor and hydrogen mixture is contacted. with the catalyst composition while at reaction temperature and pressure.. Hydro en is, used in. amounts of about 100. to. 20,000 cubic feet per barrel of oil charged. The reaction temperature dep nds. upon the character at he. cheese teak Synthetic However, the steaming may be done a,
but in general the temperature is in the range of about 600 to 950 F. The pressure should be between about to 2000 p. s. i., although 300 to 1000 .p. s. i. is advantageous. The space velocity also depends upon the charge stock, but is generally between about 0.2 to 6.0 volumes of liquid charge per hour per volume of the contact agent. It sulfur is to be removed and hydrogen sulfide in the product is not desired, the iron group metal or metal oxide should be used and the reaction terminated before the metal or metal oxide is completely sulfided or before the hydrogen sulfide appears in, the product in amounts large enough to require removal. This usually occurs when about 30 to 60 per cent of the original iron group oxide or metal has been converted into sulfide. The catalyst is then regenerated and again used in the process. The regeneration is accomplished in a conventional manner by heating the catalyst with oxygen containing gas such as air to reconvert to metal oxide and to burn off any carbonaceous. deposit. In the catalytic desulfurization process the on-stream period is terminated and regeneration takes place when coke deposition has reduced the activity ofthe catalyst. In both types of processes if a, metal hydrogenating catalyst is used, the regeneration, or the steam treatment, is usually followed by a reduction treatment to convert metal oxides to metals. This reduction may alternatively take place during the hydrodesulfurization process.
The invention is applicable to the, hydrodesulfurization treatment of hydrocarbon oils in general such as gasoline, kerosene, naphtha, furnace oil, gas oil, topped or reduced crude, as well, as crude petroleum and to the destructive hydrogenation of higher boiling hydrocarbons. The lower boiling petroleum oils such as gasoline, kerosene, etc., will in general be desulfurized more easily so that the less stringent conditions mentioned above may be used with these materials. During the treatment of light fractions such as gas oil, naphtha or gasoline, the amount of liquid, if any, present in the reactor or on the catalyst will be negligible. However, with heavy crude, reduced crude or topped crude, the oil may not be entirely in the vapor phase. However, in practically. every case such materials will be predominantly in the vapor phase. It is therefore to be understood that the terms vapor or vapor phase or the like as used herein and in the claims include a hydrocarbon charge stock n. this ondition.
The optimum, regeneration conditions, are approximat ly:
Temperature, F 1000-1300 Pressure, p. s. i. g 0-500 Diluent gas to air ratio, vol./vol 0-20 The regeneration temperature is limited to that which does not produce a loss ofmechanical strength or activity of the catalyst but at the same time it must be sufiiciently high to remove coke and in the case of the absorption type desulfurization process to convert the iron group sulfide nto t e Oxide a bu n o y cum lated. coke deposit. The regeneration pressure is adiust d t in t e indi at d. nge o. obtain. t e optimum regeneration time, which will depend on. charge stock and operating conditions. The diluent gas-.to-air ratio is, adjusted to maintain the desired regeneration temperature and obain: the ptim m re ene atio im Suitable lu nts ses e st am. flue as and regene ation off-gas. The initial wet steam treatment in acpared with the same catalyst after steaming. In
Example II nickel oxide on a spent silica-alumina cracking catalyst without any steaming step was compared with the same catalyst pretreated with I steam. The charge stock in both Examples I and II was a West Texas crude oil having the following properties:
Inspection data for West Texas crude oil Space velocity, vol. charge/hr./vol. contact 1.0
Through put, vol. charge/vol. contact agent Hydrogen-to-oil ratio, ftfi/bbl 200 The catalysts in both examples were prepared by impregnating the carrier with a nickel nitrate solution followed by draining, drying, and cal cining in contact with air at a temperature of about 800 F. Part of each catalyst so prepared was used without any further treatment, and another part of each was steam treated in accordance with the preferred conditions mentioned above. Each portion of the catalyst to be treated with wet steam was placed in a chamber and heated until the temperature of the contact agent reached about 400 F., and the temperature, of the catalyst was then maintained at about 400 to 450 F., for about one hour in the presence of saturated steam.
EXAMPLE I Run No i 2 Catalyst 16.74% Ni Same as as NiO on Run 1.
Fresh Silica- Alumina Cracking Catalyst.
Steam- Unsteamed Treated -Liquid Product:
Wt. Percent of Charge 90.7 91. 4 Gravity, API 41. 7 40.3 Suliur, Wt. Percent 0.27 0.30 400 F., E. P. Dist., V01. Percent 47.4 45.1 Non-Condensable Gases, Ft. per bbl. charge 152 119 Carbon Deposit, Wt. Percent of Charge 3. 3 2. 7 Hydrogen Consumption, Ft. per bbl. charge. 535 450 EXAMPLE Ii Run No 3 4 Catalyst 22.6% Ni Same as as NiO on Run 3. I
Spent Silica- Alumina Cracking Catalyst.
Steam- Unsteamed Treated I Liquid Product;
Wt. Percent of Charge 90. 0 92. Gravity, API 40. 8 39. Sulfur, Wt. Percent 0.28 0.34 Non-Condensable Gases, Ft. per bbl. charge. 87 76 Carbon Deposit Wt. Percent of Charge 3. 5 l. 5
The results show the advantage of steaming the contact inasmuch as there was a higher weight yield of liquid, lower hydrogen consumption, less non-condensable gas formed, less carbon deposit, only slightly less desulfurization, and appreciably less harmful cracking, as indicated by the API gravity of the product, the reduction in gas and coke, etc. In view of the decrease in carbon deposition longer on-stream periods would be possible as well as a material reduction in the time required for regeneration of the catalyst.
This application is a continuation-in-part of our application Serial No. 778,280, filed October 6, 1947, now abandoned.
What we claim is:
1. The process which comprises contacting vapors of a hydrocarbon oil and hydrogen with a catalyst composition which has been treated with wet steam at a temperature of about 350 to 550 F. and a pressure suflicient to maintain wet steam and between about and 1000 p. s. i. for a period of about /2 to 2 hours, saidv catalyst composition initially comprising a hydrogenating catalyst composited with a solid refractory cracking catalyst.
2. The process which comprises contacting vapors of a hydrocarbon oil and hydrogen with a catalyst composition which has been treated with wet steam at a temperature of about 350 to 550 F. and a pressure sufiicient to maintain wet steam and between about 135 and 1000 p. s. i. for a period of about to 2 hours, said catalyst composition initially comprising a hydrogenating catalyst composited with a silica-alumina cracking catalyst.
3. The process for desulfurizing a hydrocarbon oil which comprises contacting vapors of the hydrocarbon oil and hydrogen with a catalyst composition which has been treated with wet steam at a temperature of about 350 to 550 F. and a pressure sufficient to maintain wet steam and between about 135 and 1000 p. s. i. for a period of about to 2 hours, said catalyst composition initially comprising a member of the group consisting of iron group metals and iron group metal oxides composited with a solid refractory cracking catalyst base.
4. The process for desulfurizing a hydrocarbon oil which comprises contacting vapors of the hydrocarbon oil and hydrogen with a catalyst composition which has been treated with wet steam at a temperature of about 350 to 550 F. and a pressure suificient to maintain wet steam and between 135 and 1000 p. s. i. for a period of about /2 to 2 hours, said catalyst composition initially comprising nickel oxide composited with a solid refractory cracking catalyst base.
aaaoooe 5. The process fordesulfuriaing a hydrocarbon oil which comprises contacting vapors of the hy-. drocarbon oil and hydrogen with a catalyst composition which has been treated with wet steam at a temperature. of about 400 to 450 F. and a pressure. suificient to maintain Wet steam and between 25.0 and 450 p. s. i. for a period of about /2 to 2- hours, said catalyst composition iniijally comprising nickel oxide composited with a silica-alumina catalyst base.
6. The process for desulfurizing a hydrocarbon oil which comprises passing vapors of the. hydrocarbon oil at a temperature of between 600 and 950 F., together with hydrogen at a pressure of between 300 and 1000 p. s. i. over a catalyst composition which has been subjected to a treatment with wet steam at a temperature of about 350 to 550 F., and at a steam pressure suflicient to maintain wet steam andabout 135 to 1000 p. s. i. for a period ofabout -to 2 hours, said catalyst composition initially comprising nickel oxide composited with; a silica-alumina cracking catalyst base. I
7. The process for desulfurizing a hydrocarbon oil' which comprises passing vapors of the hydrocarbon oil at a temperature of between 600 and 950 FE, together with hydrogen at a pressure of between 300 and 1000 p. s. i. over a catalyst composition which has been treated with wet steam at a temperature of; about 400 to 450 F., at a steam pressure suflicient to maintain Wet steam and about 250 to 450 p; s. i. for a period of about to 2 hours, said catalyst composition initially comprising nickel oxide on a silicaalumina cracking catalyst base.
8. The process for desul'furizing a hydrocarbon oil which comprises passing vapors of the hydrocarbon oil at a temperature ofbetween 600- and 950 F., together with hydrogen at a pressure of between 300 and 1000 p. s. Lover a catalyst composition which has been treated with Wetsteam at a temperature of about 350 to 550 F;, at a steam pressure sufiicient to maintain wet steam and about 135 to 1000 p. s. i. for a period of about 1; to 2 hours, said catalyst compositioninitially comprising nickel oxide on a usedsilicaalumina cracking catalyst base.
9. The process which comprises contactingva- E pors 01 a hydrocarbon. oil: and hydro en with a catalyst coimmsitionv which has been treated with wet steam at. a. temperature of about. 350? to. 5.50 E: and a pressure sufficient, to. maintain I wet. steam and between about 135; and 1000. p. s. i.
for a, period of'at. least about /2. hour, said catalyst. composition initially comprising a hydro.-v genating catalyst composited with a. solid refractory cracking catalyst.
10. The process for desulfuriaing a hydrocarbon oil which comprises. contacting vapors of the hy-. drocarbon- 011 and; hydrogen with a catalyst com! position which has been, treated with wet. steam at. a temperature of: between about 400 and 450 R, and. a, pressure sufiicient to. maint in wet steam. and between about 2.50.. and p. s. i. o a nenodl about /21 to 2 an alys om osition nit ally e mpns ng a rqa a s; catalyst composited with a solid refractory crack? ing catalyst. V
The pr ess. tor de ulf rizins a h dro bon oil which comprises contacting vapors of the hydrocarbon oil and hydrogen with a catalyst composition which has been treated with wet steam at a temperature of between about 400- and. 450 Fa, and a pressure sufficient to. maintain wet steam and between about 250 and 450 p. s. i. fora period of about A to 2 hours, said catalyst composition initially comprising a hydrogenatin cats-131st Mass mo. with. a. spent. licaalumina cracking catalyst.
CHARLES W. MONTGOMERY. BRQWN.
References Cited in the file of this patent UN T STATE PATENT OTHER REFERENCES Sachanen, Conversion of Petroleum. (1940)., page. 1411;.