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Publication numberUS2614066 A
Publication typeGrant
Publication dateOct 14, 1952
Filing dateMay 10, 1949
Priority dateMay 10, 1949
Publication numberUS 2614066 A, US 2614066A, US-A-2614066, US2614066 A, US2614066A
InventorsCornell Paul W
Original AssigneeGulf Oil Corp
Export CitationBiBTeX, EndNote, RefMan
External Links: USPTO, USPTO Assignment, Espacenet
Hydrodesulfurization of petroleum hydrocarbons
US 2614066 A
Abstract  available in
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Claims  available in
Description  (OCR text may contain errors)

Oct. 14, 1952 2,614,066

HYDRODESULFURIZATION oF PETROLEUM HYDROCARBONS P. W. CORNELL 2 SHEETS-SHEET 1 Filed May 10. 1949 P. W. CORNELL Get. 14, 1952 HYDRODESULFURIZATION OF PETROLEUM HYDROCARBONS 2 SHEETS--SHEET 2 Filed May l0, 1949 erhmmm@ NOU @7mm @Nm Patented Get. 14, 1952 HYDRDESULFURIZATION OF PETROLEUM HYDROCARBONS Paul W. Cornell, Mount Lebanon, Pa., assignor to Gulf Oil Corporation, Pittsburgh, Pa., a corporation of Pennsylvania Application May l0, 1949, Serial No. 92,436

4 Claims.

This invention relates to the hydrodesulfurization of petroleum hydrocarbons, and more particularly to a continuous method of hydrodesulfurization in which the hydrogen utilized in the process is largely obtained from contaminant produced concomitant with the hydrodesulfurization process.

The hydrodesulfurization process has proved to be of marked value in the treatment of petroleum hydrocarbons containing sulfur, especially high boiling petroleum hydrocarbons such as high sulfur crudes. The hydrodesulfurization methods may be classiiied into two major type processes, namely the catalytic hydrodesulfurization method, and the contact hydrodesulfurization method. The former comprises contacting the sulfur-bearing petroleum hydrocarbon with a contact material having hydrogenating characteristics at a temperature of the order of '700 to 900 F. The sulfur present in the crude is converted into a gaseous form such as hydrogen sulde, and in this manner removed from the hydrocarbon.

The contact method of hydrodesulfurization comprises contacting a sulfur-bearing petroleum hydrocarbon with a contact material having hydrogenating characteristics such as an iron group metal, metal oxide or combinations thereof on a carrier, and which causes the sulfur in the crude to become combined with the contact as metallic sulde, and continuing said process until regeneration of the contact proves necessary. The contact agent is then regenerated and the process is continued as before.

One of the problems encountered with the aforementioned processes is the maintenance of adequate amounts of hydrogen in the system. This problem arises due to the fact that in these processes signiiicant amounts of gaseous hydrocarbons such as methane are formed, thereby causing a reduction of the hydrogen purity in the recycle stream, as well as the consumption of hydrogen involved in the manufacture of these gaseous hydrocarbons. Furthermore, appreciable amounts of hydrogen are lost to the system by Virtue of being dissolved in the liquid hydrocarbon product, either in the form of hydrogen per se or as gaseous hydrocarbon contaminants.

Various methods have been proposed for combating this problem, such as processing the recycle stream through an absorption system to remove the gaseops hydrocarbon, and thereby producing a stream having a higher hydrogen concentration. However, such methods have not proved satisfactory in that the substantial amounts of elemental hydrogen, and hydrogen compounds such as gaseous hydrocarbons dissolved in the product are lost to the system.

An object of the present invention is to provide a method whereby the hydrogen concentration of the recycle stream in a hydrodesulfurization process is maintained at suiiicient purity to meet the requirements of the process.

A further object of this invention is to provide a method whereby hydrogen is manufactured from the contaminants of the hydrodesulfurization process.

These and other objects are achieved by the process of the present invention which comprises removing sulfur from petroleum hydrocarbons by contacting petroleum hydrocarbons containing sulfurous material at an elevated temperature witha hydrogen-containing gas in the presence of a contact material having hydrogenating characteristics, cooling the eluent to obtain a first gas portion, and a hydrocarbon liquid portion containing dissolved gases, separating said hydrocarbon liquid portion and removing the dissolved gases from said hydrocarbon liquid to form a second gas portion. Substantial amounts of the hydrocarbon portion of this second gas portion are then converted into hydrogen and this hydrogen is utilized for the hydrodesulfurization of petroleum hydrocarbons.

The present process is applicable to hydrodesulfurization processes in general. Such processes may be conducted over awide range of temperatures and pressures although the temperature range that has been found most applicable for these processes is usually of the order of 600 to 950 F. Petroleum hydrocarbons having a wide range of specication characteristics may be utilized, although these methods are most widely used with high boiling crudes having a high sulfur content.

In accordance with my invention I utilize the fact that vthe hydrocarbon liquids emanating from the hydrodesulfurization reaction chamber preferentially absorb the hydrocarbon gases produced in the process, and that upon releasing these dissolved gases from the hydrocarbon liquids a gas having a high concentration of hydrocarbon gas is obtained. By converting the hydrocarbon portion of this gas into hydrogen and returning this manufactured hydrogen to the recycle stream, there is a marked benefit in the ease and facilities in which the process may be conducted.

The procedure for carrying out the contact hydrodesulfurization type of process has been described in U. S. application Ser. Nos. 699,671 and 699,672, filed September 27, 1946, by W. A. Horne and J. F. Junge, now Patents 2,516,876 and 2,516,877 respectively. As disclosed in these copending Horne and Junge applications optimum results are obtained in contact hydrodesulfurization processes when the contact contains a substantial amount of the oxide of an iron group metal and especially nickel oxide, and these materials can be used in accordance with my invention. While contacts containing free metals of the iron group such as elemental nickel cause cracking of hydrocarbons to gas and excessive amounts of carbon to be deposited upon the contact, my invention permits an improvement with this type of contact as well as with the oxide type, and hence is to be regarded as equally applicable to both types of contacts. Whichever type contact is utilized it should be deposited upon a carrier such as kieselguhr, silica gel, alumina, aluminum silicates, silica-aluminas, Alfrax, Magnesol, Porocel, bauxite, diatomaceous earth, etc. Other contact materials having hydrogenating characteristics may be utilized but the aforementioned and particularly nickel oxide constitute the preferred contact material.

The total amount of metal in the contact may be varied considerably. Minor amounts of other chemical substances may be added for special purposes or present as impurities. In those cases in which a metal oxide is employed, the contact agent may be prepared by coprecipitation of metal oxide and carrier, or the precipitation of the metal oxide in the presence of a support. Also, impregnation may be employed as a method of preparing contacts such as by absorbing soluble salts of the metal on the support followed by decomposition of the salt at elevated temperatures. The final contact agent may be prepared by either single or multiple impregnation to attain any suitable concentration of metal oxide. Other methods of preparation will be obvious to those versed in the art.

Where a metal or mixture of metal and metal oxide is to be used as contact agent, any of the above mentioned methods may be utilized and then followed by treatment with a reducing medium such as a hydrogen-containing gas. In the case of a metal-metal oxide contact this will consist of only a partial reduction.

The reaction takes place at varying temperatures, pressures and space velocities with the optimum conditions depending on the type charge stock that is used. For example, with low boiling hydrocarbons such as those normally liquid petroleum fractions having an ASTM end point below 600 F., such as straight run or cracked gasolines and naphtha, the temperature will usually lie between 600 and 800 F. I have found that at temperatures below 600 F., the desulfurization activity of the contact diminshes Whereas with temperatures higher than 800 F. excessive cracking reactions result in decreased product recovery and rapid coke formation which deactivates the contact. I have further found that the optimum pressures lie between 100 and 500 p. s. i. g. At pressures below 100 p. s. i. g. the partial pressure of hydrogen is not suflicient to maintain desulfurization activity nor to suppress cracking reactions which result in coke formation. Increasing the pressure above 500 p. s. i. g. results in only a slight incremental gain in desulfurization, and a decrease in the bromine number of the end product gasoline and is thus not commercially desirable. The preferred space velocities lie, between 1.0 and 6.0 liquid volumes of charge per hour per volume of contact agent. Space velocities below 1.0 result in excessive cracking and olefin saturation reactions caused by the long contact time whereas at space velocities above 6.0 the contact time is too short to provide sufficient desulfurization.

This invention can be applied with exceptional success to high boiling petroleum hydrocarbon oils such as total crude as well as topped or reduced crude. These terms may be defined as follows: total crude is defined as naturally occurring petroleum oil which has not been processed in any manner but has been or preferably should be separated from water or sediment and desalted. Topped or reduced crude is defined as the residual pertoleum oil resulting from removal of all or some of the straight run fractions such as gas, gasoline, kerosene, naphtha, furnace oil, gas oil, etc., which are normally removed from the above defined total crude by the process of atmospheric and/or vacuum topping or distillation. Charge stocks such as total crude which has been diluted or admixed with lower boiling straight run or cracked petroleum fractions including gases are also included. Diluents of this kind may be required in processing low gravity crudes such as some of those from'Mississippi as well as those from Kuwait. Diluents may also be necessary and preferred in desulfurizing topped or reduced crudes. The purpose of this diluent is to assist vaporization of the heavier constituents of the charge stock. I nsome cases it may be desirable to admix steam with the charge stock to asist vaporizatioin Preferred operating conditions for the aforementioned high boiling petroleum hydrocarbons may vary within certain ranges depending upon the charge stock.

I have found the optimum temperature range to be from 750 to 950 F. for high boiling petroleum hydrocarbons. At temperatures below 750 F. the desulfurizing activity of the contact diminishes whereas at temperatures greater than 950 F. excessive cracking actions result in decreased product recovery and rapid coke formation which deactivates the contact. I have further ascertained the preferred pressure range to be between and 1000 p. s. i. g. With pressures below 100 p. s. i. g. it appears that the partial pressure of hydrogen is not suflicient to maintain desulfurizing activity nor to suppress cracking reactions which result in coke formation. Increasing the pressure above 1000 p. s. i. g, results in only a slight incremental gain in desulfurization and is thus not commercially desirable. The space velocity range which I prefer to employ is 0.2 to 6.0 volumes of charge per hour per volume of contact agent. A space velocity below the former causes excessive cracking reactions due to the long contact time, while space velocities above 6.0 are too short in duration to allow suficient desulfurization. The hydrogen-containing gas to oil ratio should be greater than 300 S. C. F./bbl. of petroleum hydrocarbons. The throughput should be in the range of l to 50.

The contact absorption hydrodesulfurization process can best be explained by examination of Figure l. Crude charge enters the system through line I0 and is pumped by charge pump I2 through line I3 and line I4 into heat exchangers I6, I8 and 20. The charge then passes by means of line 22 into oil and hydrogen heater 24.

The initial hydrogen is prepared from fuel gas 'which enters the system in line 215 through line 28, into hydrogen producing plant 3|). The hydrogen may be most advantageously produced by means of the conventional reforming and shift reactions,in which the fuel gas is burned in the presence` of. steam, and the carbon monoxide formed in the reaction is converted to carbon dioxide. The hydrogen plus carbon dioxide produced in plant 3d is passed by means of line 52 into gas holder 3ft where it may be stored before returning to plantee by passing it through line S5, raw hydrogen compressor 35 and line 3l'. In hydrogen producing plant 35 the carbon dioxide is removed by conventional means and purified and compressed hydrogen is then removed from hydrogen producing plant 3e by .means of line 38 and passed through compressorpump it to line I4 where it joins the crude petroleum charge coming from line i3. The hydrogen plus charge likewise passes from line |t through heat exchangers l5, |8 and 2.0 into line 22 and then into oil and hydrogen heater 21|.- Inoil and hydrogen heater 2t the charge and hydrogen are heated to reaction temperature. At this temperature the charge stock is substantially in the vapor phase, although small droplets of liquid may be present. The charge stock mixture is then passed by means of line 42 to valve its and line iinto reactor 48. Alternatively, valve Liri may be closed and the oil and hydrogen mixture passed from heater 2t to line t2, into line 5t, valve 52, line 54 and thence into reactor 55. By alternating, one reactor may always be kept on-stream while the other is being purged or regenerated. While only 'two reactors are shown, a greater number may be provided so that one or more may be in the processing stage, while the remaining reactors are at other stages in their reaction cycle. In

the reactors the petroleum hydrocarbons are hydrodesulfurized by passing over the contact agent which may contain any of the iron group metal oxides, metals or combinations thereof on a carrier although as has heretofore been mentioned the preferred contact agent is nickel oxide.

The sulfur is removed from the charge stock by combining as sulfide with the contact agent. The desulfurized product is passed fromI reactor i8 into line 58, valve SQ and into line 52. If reactor 56 is on-stream desulfurized product from reactor 56 is passed by means of line el, valve 69 and line into line |52. The desulfurized product in line |52 ispassed in heat exchanger relationship through heat exchanger 2|! and into line 64 where a portion is diverted through heat exchanger 66 while the remainder is passed through heat exchanger is into line 53. rThe portion that was diverted through heat exchanger |55 is passed through line t5, heat exchanger IS and into line l0. The remainder in line i3 likewise passes vthrough heat exchanger |55 and enters line 1U. The product from the heat exchangers passes through line lt, condenser l2, line lll, into high pressure fiash drum le.

In high pressure flash drum '|13 the non-dissolved gaseous portion of the hydrodesulfurization products is separated from the liquid portion. Any water in high pressure flash drum 'It is removed by water separator 96 and line 9S. This liquid-portion passes from high pressure ash drum l5 to line 92, and then into low pressure flash drum 56|. The gaseous portion is removed from high pressure flash drum 1E by line 18 where it may be recycled into the system by passing through line si), recycle compressor 82, line 8d into line |11.. If desired, a portion of the gases from high pressure hash drum 'i5 may be passed from line 18 through line 85 valve H3 into line Q0. From line 99 these gases are passed through valve l I and line 28 into hydrogen-producing plant 3|] where they are converted, as has heretofore been explained, into hydrogen. It will be suitable in most cases to recirculate all of the gases from high pressure flash drum` 'i5 and in these cases valve ||3 may be closed and all the gases recirculated through line 85.

The liquid product in low pressure flash drum 94 is removed by means of line |00, transfer pump |52 to line |55. From line |06 the product is removed from the system. Any water present in low pressure flash drum 9i! is removed by means of water separator 95 and line 91.

The vapors from low pressure flash drum 9d are passed through line |61, absorber gas compressor |58, line H5 into reboiled absorber co1- umn H2. Reboiled absorber column ||2 is kept under proper distillation conditions by means of line H4, vaporizer I6 and line IIB.

In reboiled absorber column H2 the low boiling contaminants, such as the low boiling hydrocarbon gases from low pressure flash drum gli and the unreacted hydrogen-containing gas, are removed as overhead, passed into line |26 and thence into line 9G, Valve and line 28 into hydrogen-producing plant 3d. In hydrogen-producing plant 3U it is converted, as heretofore indicated, into hydrogen and reutilized in the process. Depending upon the mechanical leakage, and the degree of purity of hydrogen required in the system, more or less quantities of fuel gas may be added from time to time by means of line 2S to supplement the source materials for the production of hydrogen.

The desirable hydrocarbon products present in the vapors from low pressure flash drum 9d, such as the normally liqueflable hydrocarbons, are removed as bottoms by means of line |22 and passed through heat exchanger |Zli, line |25l into stripper |23. The distilling conditions in stripper |28 are maintained by means of line |35, heat exchanger 66 and line |32. The lean oil bottoms from stripper |28 are removed by means of line |34, pass in heat exchanger relationship through heat exchanger |24, line |36, pump |38, line Hifi, cooler |132, line IM into reboiled absorber ||2 for use as absorption oil. The overhead vapors, from lstripper |28 which comprise the valuable hydrocarbon products, are discharged through line |455, condenser |58 and then passed through line IEE, reiiux drum |52, line ld into stripper renux pump |55l where a portion is returned as reflux to stripper |28 by means of line |58. rIhe remainder of the overhead from stripper |23 is removed from the system by means of line 56|), and may be combined with the products that were removed from the system through line |56.

The on-stream cycle is terminated at the completion of the hydrodesulfurization process and the contact is regenerated. |The time of termination of the on-stream cycle may be varied depending upon the nature of the charge stock as well as the results to be achieved. In instances where hydrogen sulnde cannot be tolerated in the product from the hydrodesulfurization reactors, the on-stream cycle must be concluded when substantial amounts of hydrogen sulfide appear in the product.

Another method for determining the point at which the on-stream cycle should be consummated is by the empirical method of concluding the on-stream cycle when the contact has been 30 to 60% sulded, e. g., when between about 30 to 60% of the iron group metal content of the contact has been converted into metallic sulde.

In those cases in which small amounts of hydrogen sulfide may be tolerated in the product, or means for removing hydrogen sulfide from the product are available, the hydrosulfurization process may :be continued until the iron group metal content of the contact has been substantially converted into metal sulfide, e. g., the contact has become saturated with sulfur.

At the completion of the on-stream cycle the on-stream cycle is stopped by closing valves 44 or 52. The contact beds are then regenerated by depressuring and purging the reactors With an inert substance such as steam. The purpose of the purge is to recover valuable hydrocarbons which remain in the contact bed. An inert substance is introduced into reactor 48 by means of valve 41, lines 45 and 46 and may leave the reactor through line 58, valve 60 and line 62, or through line 58 and a valve, condenser and lines (not shown) to low pressure flash drum 94. The inert substance for reactor 56 is introduced b'y means of valve 55, lines 53 and 54 and leaves the reactor by means of line 61, valve 69, line 1I and line 62 or through line 61 and a valve, condenser and lines (not shown) to drum 94.

Following the purge, valves 60 or 69 are closed and regenerating gas such as oxygen, or an oxygen-containing gas such as air is introduced into reactors 48 or 56 from lines 45 and 46, or 53 and 54 by opening valves 41 or 55. In reactor 48 or 56 the contact .bed is oxidized and the sulfur on the contact surface is removed as sulfur dioxide. This regeneration product gas is removed from reactors 48 or 56 by their corresponding lines 51 and 63, and valves 59 and 65. The sulfur dioxide in this gas may be recovered in a conventional manner such as by solvent absorption and stripping. The regeneration off-gas, which has been freed from sulfur dioxide, may then serve to dilute the first regeneration gas admitted to the reactors. Alternatively, the sulfur dioxide gas containing regeneration off-gas may serve to dilute the fresh regeneration gas. After regeneration is complete, which may readily be determined by the fact thatthe contact agent is substantially free of sulfur and is once again in the oxide form, the oxidizing gas is shut oi and the reactor steamed to remove any oxygen present.

Depending upon the nature of the contact, it may be tested with a reducing gas following regeneration treatment. In the case of oxide contact agents this step is usually omitted. However, in those cases where free metal such as nickel, or a mixture of metal-metal oxide such as nickelnickel oxide is employed as the contact, it is desirable to reduce or partially reduce the contact agent with a reducing gas such as a hydrogencontaining gas. This is accomplished by passing hydrogen-containing gas through valve 41, line 45, and line 46 into reactor 48 or through valve 55, line 53 and line 54 into reactor 56. The reducing gas is vented through line 51 and valve 59 or line 63 and valve 65. This hydrogen-containing gas is recovered and may be used again, or may be puried in hydrogen-producing plant 30.

The reactor is then blocked oiT by closing valves 41 or 55. Also, valves 59 or 65 are likewise closed. At this point reactor 48 or 56 is brought on-stream by opening valves 44 or 52 and valves 60 and 69 and permitting the charge to enter the reactor. Then the process is continued as before.

I have found that when using a ratio of 5000 cubic feet of hydrogen rich gas per barrel of West Texas crude, a hydrogen purity of about 85% is desirable. As a practical matter, I have found that an average of 3D0-350 cubic feet of hydrogen are lost to the operation for each barrel of crude oil fed to it, and further, that a quantity of light gases such as methane, ethane and propane are produced in a quantity in excess of 250 cubic feet per barrel. In addition to a major portion of these contaminants, about 120 cubic feet per barrel of hydrogen are dissolved in the desulfurized product that is removed from the high pressure ash drum 16. Thus, the hydrogen lost by solution in the product constitutes about one-third of the requirements of the process. If all of the light gases produced by the process together with the impurities introduced with the makeup or fresh hydrogen could be dissolved in the desulfurized product removed from flash drum 16, then a recycle gas of B3-84% purity in the amount of 4625 or 4650 cubic feet per barrel would be removed overhead in line 18 from flash drum 15. The hydrogen convertor may then be regulated to produce suflicient amounts of hydrogen of a purity of 93-96% to raise the average purity of the recycle stream to 85% and restore its rate to 5000 cubic feet per barrel.

If operating conditions are such that the liquid product does not dissolve quite all of the light gases produced, the purity of the recycle stream in equilibrium with the liquid and leaving the top of flash drum 16 will fall below 8384%, and when the fresh hydrogen is added in the amount required the purity of 85% will not be obtained.

Since this net gas make escaping into the recycle gas must be withdrawn from the system, line 86 and valve I I 3 have been provided. In this manner, I have found it possible to keep the system operating in an economical manner without permitting the purity of the hydrogen in line to fall below 80% and still achieve the desired overall purity of As has heretofore been indicated my invention is equally applicable to catalytic hydrodesulfurization methods. In these methods the sulfur present in the hydrocarbons is converted into a gaseous form, usually hydrogen sulfide, and the hydrogen sulfide gas is removed from the product. The conditions for this type of process are somewhat similar to those for the contact method. The prime difference between these processes being the fact that in the contact method, the process is not permitted to continue beyond the point at which the contact has become completely sulded, that is when the entire metal content of the contact has been converted into metal sulfide. The catalytic method contemplates longer on-stream cycle periods since it is not necessary to regenerate the catalyst after it has been completely sulded. In addition to the oxide and free-metal type materials contemplated as useful contacts for the contact method, other compounds such as sulfide compounds may be used in the catalytic method. In fact, it appears that any material having hydrogenating characteristics may be utilized as a catalyst in the catalytic type method.

I have found that the optimum temperature conditions for this type process will be of the order of r700" to 900 F., with the higher temperature ranges being utilized for heavier charge stock materials. The optimum pressures will usually lie between and 1,000 pounds per square inch and the space velocities should be of the order of 0.5 to 2.0. The hydrogen to oil ratio may be 9. varied over a wide range such as from 500 to 10,000 S. C. F./bb1. I have found that the throughput may also be varied between the range of about 2 to about 12.

The process of the present invention as applied to the catalytic hydrodesulfurization method is best understood by an examination of accompanying Figure 2. Crude charge enters the system through line 210 and passes, by means of charge pump 212, through line 212, heat exchanger 215, into line 218 where it is joined by fresh hydrogen in line 222.

vThe mixture of fresh hydrogen and oil feed passes from line 222 and heat exchanger 224 into line 228. From line 228 the hydrogen-oil feed mixture is passed to heater 228 where it is heated to reaction temperature. From heater 228 the mixture is passed by Way of line 238 into line 232, valve 2311, line 238 into reactor 238. Alternatively, valve 235 may be closed land the oil and hydrogen mixture passed from heater 228 through line238, into line 283, valve 242, line 2M and thence into reactor 2115. By alternating, one reactor may always be kept on-stream while the other is being purged or regenerated. While only two reactors are shown, a greater number may be provided so that one or more may be in the processing stage, while the remaining reactors are at other stages in the reaction cycle. In the reactors the petroleum hydrocarbons are hydrodesulfurized yby passing over the hydrodesulfurization catalyst comprising a hydrogenating agent such as a molybdenum compound, or nickel or nickel compound on a carrier, thereby causing sulfur in the feed to be converted into gaseous hydrogen sulfide. Among the compounds which I have found most useful for this purpose are the oxides and suldes.

The products from the hydrodesulfurization reaction are passed from reactor 233 through line 233, valve 250, line 252, into heat exchanger 2211. If reactor 2116 is on-stream, the hydrodesulfurization products from reactor 2116 are passed by means of line 2511, valve 258, line 252 into heat exchanger 2211. After passing through heat exchanger 224 these products are conveyed by means of line 258 through reboiler 260, line 262, heat exchanger 258, line 258, cooler 288, line 218, into fiash drum 212.

In the ash drum 212 the non-dissolved gases in the hydrodesulfurization products are removed by Ameans of line 2111. The liquid hydrodesulfurization products containing dissolved hydrogen and preferentially absorbed hydrocarbon gases, are removed from flash drum 212 by means of line 232, automatic valve 285, line 286, heat exchanger 2511, line 286 and passed into fractionator 298. Any Water contaminants present in the desulfurized products are removed from flash drum 212 by means of Water separator 213, line 215, automatic valve 211 and line 210 from which the water is disposed. In fractionator 290 the liquid hydrodesulfurization products are distilled and the treated oil product bottoms are removed by means of line 232 and heat exchanger 216 from which they are passed out of the system to a suitable storage or utility vessel. The overhead distillate from fractionator 238 containing substantial amounts of absorbed hydrogen and lowboiling hydrocarbons is passed by means of line 292 to condenser 280 where it is partially condensed, and then carried by means of line 298 to reflux drum 382. In reflux drum 3138 the liquid condensate is separated from the absorbed gases and returned as reflux by means of line 302, reflux 10 pump 384, line 30B to fractionator 290. The absorbed gases 'are removed from reiiux drum380 by means of line 308 and valve 318 and are passed to line 218 where they join the Agases from ash drum 212. p

The gases from flash drum 212 after passing through line 214 enter line 211. From line 211 a portion of these gases may pass through valve 218 and line 218r into hydrogen sulde scrubber 280. The remainder of thesegases are recirculated by means of line 21S, recycle gas compressor 221, line 223 and heat exchanger 218 into line 218 where they jointhe fresh hydrogen in line 222. On occasion, it may be desirable to recirculate all of the gases in line 211, in whichv case valve 216 is closed.

If desired, a portion of the gases removed from flash drum 212 by means of line 214 may bebled from the system by means of line 281, automatic Valve 283 and line 285 to form lbleed gas. The percentage of the gases from ash drum 212 which may be utilized for this purpose is controlled by automatic valve 283 and may be regulated to meet any existing conditions. In some cases it may be necessary to addfuel gas through line 211 and valve 213 into line'218 in vorder to bolster the source materials for the production of hydrogen.

The combined mixture of the gases 'from line 218 is desulfurized in hydrogen sulde scrubber 283.k This rmay be accomplished' by vany of the conventional methods. I havefound that the commercial ethanolamine` solution scrubbing methodis suitable for'this purpose. In this method the amine solution enters hydrogen sulde scrubber 280 by means of line 312 where it passes countercurrently to the gases from line 218. The desulfurized gases are removed from hydrogen sulde scrubber 280 byline 312 and mixed-with steam which has entered the system by means of lines 313 and 315. The amine solution vcontaining absorbed hydrogen sulide is removed from hydrogen sulfide scrubber 238 by line 318. l

The mixture of steam and desulfurized gases in line 315 is passed to reformer furnace 318.

In reformer furnace318 'the desulfurized gases from H2S scrubber 288 are converted by theV methane reforming reaction into ycarbon monoxide and hydrogen. These gases are passed from reformer furnace 318 by line 338 to line 328 where` they are joined by steam which has enteredthe system from line 313 and'line 352. ture of steam, carbon monoxide and hydrogen is passed through cooler 334,' line 3415 into shift converter 348. In shift converter 3118 the oarbon monoxide is converted by reaction with the steam to form carbon dioxide and hydrogen. This mixture of carbon dioxide andy hydrogen is removed from shift converter 343 by line358 and passes through raw hydrogen compressor v352* into line 3511 and thence into carbon dioxide scrubber 358,. In carbon dioxide scrubber 355 the removed from carbon dioxide scrubber 358 Vby` line 358 Where it joins the sulfur containing amine solution in line 318. Y

The amine solution containing hydrogen suliide and carbon dioxide passes from line 318 r)The mixthrough heat exchanger 3 20 line 322 linto amine solution regenerator 32,4. Amine solution regenerator 324 is'kept under suitable distillation conditions by passing a portion of its contents through line 32|, reboiler 323 and. :line 325. Steam from line 321 is circulated through reboiler 323 and supplies the heat to maintain the regenerator at distillation conditions.

Hydrogen sulfide and carbon dioxide are removed as overhead from amine solution regenerator 324 by line 326. Puried amine solution passes from amine solution regenerator 324 by means of line 328 Yheat exchanger 320 line 330 cooler 332 line 33 4 into regenerated solution pump 336. After the solution has passed through regenerator pump 336 a portion of it passes by means of line 3|2 to hydrogen sulfide scrubber 289. The remainder of the solution is passed by line 358 to carbon dioxide scrubber '356.

Carbon dioxidefree hydrogen is removed from carbon dioxide scrubber Y356 by line 362 and fresh hydrogen compressor '364. From `fresh hydrogen compressor 364 the puried hydrogen is returned to the hydrodesulfurization system rby means of line 222.

During the on-stream period valves 23|, 233, 235 and 231 of reaction 238 remain closed. At the completion of this on-stream period when it becomes necessary to regenerate the catalyst due to catalyst deactivation or plugging caused by carbon deposition, lvalves 234 and250 are closed and the pressure in reactor 238 is released by opening valves 23| and 235. Reactor 238 may then be vacuum purged in a conventional manner. Alternatively, valves 23| and 235 may be closed and valves 233 and 25,0 opened and the catalyst purged with an inert gas or steam so as to recover the valuable hydrocarbons in the reactor bed which are passed to line 252. Following the purge valves 233 and 250 are closed and valves 23| and235 opened and the catalyst bed-in reactor 238 is regenerated by the admission of regenerating gas through valves 235 and line 248. The regenerating gas which may comprise oxygen-containing gases such as oxygen or air, regenerates the vcatalyst and simultaneously forms sulfur-containing gases which are vented from reactor 238 by means of vline 236 and valve 23|, togetherwith combustion gases from any carbQnaceous deposit on the catalyst bed. rThis regeneration-oitI gas contains a recoverable quantity of sulfur-containing gases and this sulfurcontaining gas may be recovered in any normal manner, such as by solvent absorption and stripping. 'Ivhe sulfur regeneration-off gas may serve to -dilute freshregeneration gases admitted to the reaction chamber. Alternatively, the sulfur-containing regeneration-oil gas may serve to dilute fresh regeneration gas.

Depending upon the nature of the catalyst it may be treated with various gases following regeneration treatment In the case o f oxide catalysts this step is usually omitted. However, in the case of free metaly catalysts such as nickel, or mixtures of free metal-metal oxide catalysts such as nickel-nickel oxide catalystsv it is desirable to reduce or partially reduce the contact agent with a reducing gas such as a hydrogencontaining gas. In the case of sulfide catalysts such as molybdenum .sulde it is desirable to sulfurize the catalyst prior to the commencement of the on-stream period bythe use of a sulfur-containing gas such as hydrogen sulde.

In any event, if additional treatment with one or more of these gases is desirable after the 12 oxidation step, a suitable gas may be introducedinto reactor 238 by rst closing .the valves 235 and 23| and then opening valves 231 and 233 and introducing the gas through valve 231 and line 248 into reactor 23B. The gas is then vented through line 236 and valve 233.

In those cases in which treatment with an additional gas is omitted it is usually desirable to flush the system after the oxidation has been concluded with an inert gas and/or purge. This may be accomplished by passing the inert gas or steam through valve 231 and line 248 into the reactor bed and then out of the reactor by passage through line 236 and valve 233. When the regeneration treatment is concluded thereactor is put oli-steam by closing off valves 23 l, 233, 235, and 231 and opening valves 234 and 250.

As yhas been heretofore described one reactor may be on-steam while the other may be in the regeneration portion of the cycle. Thus, for example, reactor 238 may be on-steam while reactor 246 is being regenerated. In this case reactor 246 will be treated in an exactly analogous .manner to that described for reactor 238 by the utilization of valves 24|, 243, 245 and 241.

The description of the apparatus described in Figures l and 2 is to be considered merely illustrative of the methods which may be utilized. Thus, for example, multiple or single beds of catalyst may be used, as well as systems in which the catalyst is continuously charged and removed from the reaction zone and `followed by external regeneration. In addition this invention is applicable to methods in which the catalyst is finely divided and employed in the iiuidized state.

As has been shown the utilization of this hydrodesulfurization process permits the mellifluous production of hydrogen from the hydrocarbon gases formed in the process, due to the fact that these gases are preferentially absorbed in the hydrodesulfurized liquid hydrocarbon products. This permits maximum possible elliciency in the hydrocarbon conversion into hydrogen inasmuch as the recycle gases from the high pressure separator, e. g., the first gas portion, have a much lower hydrocarbon content than the gases recovered from the desulfurized product and therefore the recovered gases are capable of producing a higher yield of hydrogen. Furthermore, the utilization of this invention permits substantial savings in the cost of equipment and apparatus in thatthe customary absorption system normally used to remove the gaseous hydrocarbons such as methane is completely dispensed with.

What I claim is:

1. In the process for hydrodesulfurizing a petroleum hydrocarbon by contacting the petroleum hydrocarbon containing sulfurous material at an elevated temperature and pressure with a hydrogen-containing gas in the presence of a contact material` having hydrogenating characteristics, cooling the effluent from the aforesaid hydrodesulfurizing treatment to obtain a rst gas portion and a hydrocarbon liquid portion which liquid portion contains dissolved gases, separating said hydrocarbon liquid portion and removing the dissolved gases from said hydrocarbon liquid portion to obtain a second gas portion, the improvement in the above which comprises subjecting this second gas portion, without previous separation of the hydrogen and hydrocarbon components thereof, to a reforming and shift reaction whereby the hydrocarbon gas components of the second gas portion are converted into hydrogen without requiring physical separation of the hydrogen gas from the hydrocarbon gases and whereby the hydrogen contained in the second gas portion is caused to improve the operation of the reforming reaction, adding the gas stream from the reforming and shift reaction to the rst gas portion and recycling said combined gas mixture into contact with the petroleum hydrocarbon to be desulfurized.

2. In the process of hydrodesulfurizing a high boiling petroleum hydrocarbon by contacting the petroleum hydrocarbon containing sulfurous material at a temperature between about 750 and 950 F., at a pressure between about 100 and 1000 p. s. i. with a hydrogen-containing gas in the presence of a Contact material selected from the group consisting of iron group metals, iron group metal oxides and combinations thereof on a carrier, absorbing sulfur from the high boiling hydrocarbon to form iron group metal sulde, cooling the eiiluent from the aforesaid hydrodesulfurizing treatment to obtain a first gas portion and a hydrocarbon liquid portion which liquid portion contains dissolved gases, separating said hydrocarbon liquid portion and removing the dissolved gases from said hydrocarbon liquid portion to obtain a second gas portion, the improvement in the above which comprises subjecting this second gas portion, without previous separation of the hydrogen and hydrocarbon components thereof, to a reforming and shift reaction whereby the hydrocarbon gas components of the second gas portion are converted into hydrogen without requiring physical separation of the hydrogen gas from the hydrocarbon gases and whereby the hydrogen contained in the second gas portion is caused to improve the operation of the reforming reaction, adding the gas stream from the reforming and shift reaction to the first gas portion and recycling said combined gas mixture into contact with the high boiling petroleum hydrocarbon to be desulfurized.

3. 1n the process for hydrodesulfurizing a petroleum hydrocarbon by contacting the petroleum hydrocarbon containing sulfurous material at a temperature between about 700 and 900 F. at a pressure between about 100 and 1000 p. s. i., with a hydrogen-containing gas in the presence of a contact material having hydrogenating characteristics, cooling the eiiiuent from the aforesaid hydrodesulfurizing treatment to obtain a first gas portion and a hydrocarbon liquid portion which liquid portion contains dissolved gases, separating said hydrocarbon liquid portion and removing the dissolved gases from said hydrocarbon liquid portion to obtain a second gas portion, the improvement in the above which comprises removing hydrogen sulfide from the second gas portion, subjecting this second gas portion, without previous separation of the hydrogen and hydrocarbon components thereof, to a reforming and shift reaction whereby the hydrocarbon gas components of the second gas portion are converted into hydrogen without requiring physical separation of the hydrogen gas from the hydrocarbon gases and whereby the hydrogen contained in the second gas portion is caused to improve the operation of the reforming reaction, adding the gas stream from the reforming and shift reaction to the first gas portion and recycling said combined gas mixture into contact with the petroleum hydrocarbon to be desulfurized.

4. 1n the process for hydrodesulfurizing a petroleum hydrocarbon by contacting the petroleum hydrocarbon containing sulfurous material at a temperature between about 700 and 900 F. at a pressure between about and 1000 p. s. i., with a hydrogen-containing gas in the `presence of a contact material having hydrogenating characteristics, cooling the eiiiuent from the aforesaid hydrodesulfurizing treatment to obtain a rst gas portion and a hydrocarbon liquid portion which liquid portion contains dissolved gases, separating said hydrocarbon liquid portion and removing the dissolved gases from said hydrocarbon liquid portion to obtain a second gas portion, the improvement in the above which comprises combining part of the rst gas portion with the second gas portion, removing hydrogen sulfide from the combined mixture, subjecting the combined mixture, without previous separation of the hydrogen and hydrocarbon components thereof, to a reforming and shift reaction whereby the hydrocarbon gas components of the combined mixture are converted into hydrogen without requiring physical separation of the hydrogen gas from the hydrocarbon gases and whereby the hydrogen contained in the combined mixture is caused to improve the operation of the reforming reaction, adding the gas stream from the reforming and shift reaction to an additional part of the first gas portion and recycling the resultant mixture into Contact with the petroleum hydrocarbon to be desulfurized.

PAUL EV. CORNELL.

REFERENCES CITED The following references are of record in the iile of this patent:

UNITED STATES PATENTS Number Name Date 1,592,474 Szarvasy July 13, 1926 2,073,578 Gwynn Mar. 9, 1937 2,174,510 Gwynn Oct. 3, 1939' 2,417,308 Lee Mar. 11, 1947 2,419,029 Oberfell Apr. 15, 1947 2,516,876 Horne et al Aug. 1, 1950 2,516,877 Horne et al Aug. 1, 1950 FOREIGN PATENTS Number Country Date 489,544 Great Britain July 25, 1938

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Classifications
U.S. Classification208/212, 423/564, 423/651, 423/655, 423/437.1
International ClassificationC10G49/00
Cooperative ClassificationC10G49/007
European ClassificationC10G49/00H