US3172843A

US3172843A - Dssulfubization process

Info

Publication number: US3172843A
Authority: US
Priority date: 1960-05-03
Publication date: 1965-03-09
Anticipated expiration: 1982-03-09
Also published as: DE1470583A1; GB897664A

Description

MalCh 9, 1965 c. E. sLYNGsTAD ETAL 3,172,843

DESULFURIZATION PROCESS Filed May 3, 1960 OmNEDmJDwmO (m0 IUE mmmmomm: or

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vm- W 0 IUE NI United States Patent O M 3,172,843 DESULFUREZA'HN EFRCESS Charles E. Siyngstad, Rutherford, NJ., and Waiter A. Kai-dash, Yonkers, and Marvin l'. Nathan, New York, NX., assigne-rs to iulinian incorporated, a corporation of Delaware Filed May 3, 1960, Ser. No. 26,553 '7 Claims. (Cl. 20S- 210) This invention relates to a method for treating hydrocarbon feed materials with hydrogen-rich gases to produce desired products. In one aspect, the invention relates to the removal of sulfur and nitrogen constituents from hydrocarbon feed materials in an improved manner.

The present invention has wide application for systems in which a chemical compound is contacted With a hydrogen containing gas. In hydrofining processes it is preferred to maintain a relatively high ratio of hydrogen to the hydrocarbon being treated since the use of high hydrogen partial pressure in the reaction zone has a desirable influence on the efciency of the process, the life of the catalyst and on the amount of carbonaceous material produced. The investment and operation costs of present day desulfurization processes vary considerably and are dependent in large part upon the cost of the hydrogen available, its efcient utilization and the process equipment essential for the separation of desired product constituents. Accordingly, the need for an eiicient process for the desulfurization of dissimilar hydrocarbon feed materials and particularly those contaminated With sulfur and nitrogen compounds has become increasingly important.

An object of this invention is to provide an improved process for hydrofining hydrocarbon oils containing sulfur and nitrogen.

Another object of this invention is to provide an improved arrangement and sequence of process Steps for efficiently desulfurizing dissimilar hydrocarbon feed materials and for the recovery of desired products.

Other objects and advantages of this invention Will become apparent from the following description.

In accordance with one aspect of this invention hydrocarbon feed materials are desulfurized with hydrogen-rich gas under conditions wherein low-boiling hydrocarbon constituents in the gas oil boiling range are separately treated under desired treating conditions, thereafter separated to recover the low-boiling naphtha constituents contained in the product efiiuent of the gas oil treating step and the thus separated naphtha cascaded for further treatnient with additional naphtha boiling range material in a separate treating Zone.

1n another aspect of this invention the separate treating zones and combination of process steps are arranged such that all of the fresh hydrogen-rich make-up gas introduced to the process may be introduced first to the naphtha treating zone and cascaded therefrom to the gas oil treating step with hydrogen-rich gas recovered from the product effluent of the gas oil treating step being recycled thereto.

ln a more particular aspect the method and treating steps of this invention are operated under conditions to maintain a hydrogen partial pressure of at least about 450 p.s.i.a. and preferably above about 500 p.s.i.a., at the outlet of each reaction zone in addition to employing operating conditions suficiently severe to effect significant desulturization and derritrogenation of the hydrocarbon feed materials. Therefore, it is desirable to operate the process at relatively high temperatures in the range of from about 650 F. to about 900 F., preferably from about 700 F. to about 825 F., with the higher temperatures being employed when more severe denitrogenation conditions are Patented Mar. 9, 1965 required. The removal of nitrogen and sulfur compounds from feed materials for catalytic operations is important in order to avoid the deactivating effects of these materials on the catalytic materials employed, for example, in reforming and catalytic cracking operations. Therefore, in the practice of this invention it is preferred to fix the conditions and operate Within a range of conditions for obtaining desired removal of nitrogen and sulfur, as Well as to obtain optimum yields of desired products. At the temperature specified above, the process is maintained at a suitably elevated pressure in the range of from about 500 to about 1200 p.s.i.g., preferably from about 700 to about 1000 p.s.i.g., with the higher pressures being more effective for removal of nitrogen constituents from the hydrocarbon material. As hereinbefore indicated, relatively severe operating conditions are employed in the process of this invention with the more severe conditions being employed when treating hydrocarbons containing relatively large amounts of combined nitrogen. Since severity of the desulfurization process is related to space velocity (pounds of oil charged to the reaction zone at an hourly basis per pound of catalyst) and may be in the range of from about 0.25 to about 10, preferably from about 0.5 to about 5, it is preferred to employ relatively low space velocities in the process when optimizing removal of nitrogen.

The catalysts which may be employed in the process of this invention include the oxides and/or sulfides of a metal of Group VI of the Periodic Table, either alone or supported on a suitable carrier material, such as for example, alumina, silica-alumina, magnesia, fullers earth, kieselguhr, pumice, bentonite clay, etc. The catalytic material can be used if desired in combination with an oxide and/or sulfide o-f a Group VIII metal having an atomic number not greater than 28. The catalytic agent can comprise from about 0.1 to about 25 percent by Weight of the total catalyst, preferably about 6 to 17 percent by Weight thereof. The catalytic agent can be, for example, molybdenum trioxide, molybdenum trisulide, chromia, tungsten sulfide, etc. The promoter includes, for example, cobalt oxide and/ or sulfide, iron oxide and/ or sulfide, and nickel oxide and/or sulfide. When employed, the promoter comprises about 1 to 10 percent, preferably about l to 5 percent, based on the total Weight of catalyst. In order to enhance the stability of the catalyst at elevated temperatures, silica can be used in an amount of about 0.5 to about 12 percent by Weight, based on the total catalyst.

Hydrocarbon feed materials which may be desulfurized in the process of this invention include those referred to as straight run hydrocarbons or hydrocarbon products of cracking operations including gasoline, naphtha, kerosene, gas oil, cycle stocks from catalytic cracking or thermal cracking operations, residual oils, thermal and coker distillates.

The sulfur concentration in these hydrocarbons may vary over a relatively wide range of from about 0.03 to about 10 percent by Weight, more usually the sulfur concentration will be in the range of from about 0.25 to about 6 percent by Weight. In addition, the hydrocarbon oils may be derived from petroleum crudes to obtain hydrocarbon fractions having initial boiling points in the range of from about F. to about 750 F., and an end point in the range of from about 350 F. to about l350 F. As hereinbefore indicated, these hydrocarbon oils may be straight run or virgin stocks, materials which have been previously cracked, thermally or catalytically, or mixtures of straight run and cracked stocks. The sulfur content of the hydrocarbon oils Will vary as hereinbefore indicated with or Without combined nitrogen, measured as nitrogen in the range of from about 0.001 to about 2.0 percent by weight.

In a more specific aspect the present invention is directed to an improved arrangement and combination or process steps for the treatment of dissimilar hydrocarbon fractions contaminated with sulfur and nitrogen cornpounds. The processing of hydrocarbon fractions boiling in the range of from about C to about 900 F. and obtained from a coker operation may be handled in a number of diferent ways. In the process of this invention it is preferred to separate the products of the coking operation to obtain a iirst coker naphtha fraction boiling in the range of from about C5 to about 375 F. and a second gas oil fraction boiling in the range of from about 300 F. to about 900 F., and containing the high-boiling range naphtha constituents. By so separating the hydrocarbon feed materials and employing the improved combination of process steps of this invention the naphtha boiling range material is substantially separated into two fractions such that the highest boiling range naphtha fraction having the highest concentration of sulfur and nitrogen constituents therein is retained in the gas oil feed and subjected to .a plurality of sequential treating steps by cascading naphtha boiling range constituents from the gas oil treating step to the lower boiling naphtha feed treating step. That is, the gas oil fraction referred to above is combined with hydrogen-richgas substantially free of hydrogen sulde, preheated in a plurality of indirect heat exchange steps more specifically discussed herein and further heated in a suitable furnace to a sufficiently elevated temperature for introduction into the gas oil treating reactor, which may comprise one or more desulfurization reactors. The gas oil feed stream heated in the furnace is then combined with additional hydrogenrich recycle gas obtained from the product effluent of the Coker naphtha distillation zone more fully discussed hereinafter and passed into the gas oil desulfurizataion Zone maintained under elevated temperature and pressure conditions to obtain the desired degree of severity of treatment as herein discussed. The product effluent of the gas oil desulfurization zone is thereafter separated to recover a desulfurized gas oil fraction, a lower boiling naphtha fraction including that contained in the gas oil feed and that produced during the relatively severe desulfurization of the gas oil, as Well as a hydrogen-rich gas stream. The hydrogen-rich gas stream is recovered and treated to remove hydrogen sulfide therefrom with, for example, diethanolamine. Thereafter, the thus treated hydrogen-rich gas is combined with additional gas oil feed being passed to the desulfurization zone. The lowboiling coker naphtha product containing sulfur and nitrogen contaminants is combined with an excess of makeup hydrogen-rich gas introduced to the process of at least about 75 percent purity and preferably above about S0 percent purity. This combined naphtha-hydrogen rich gas stream is further combined after suitable heating with the naphtha recovered from the product effluent of the gas oil treating steps and the combined streams are then passed to a naphtha desulfurization zone wherein sufficiently severe operating conditions are employed to desulfurize and denitrogenate the naphtha boiling range material. As hereinbefore discussed, by this improved arrangement and combination of process steps, the naphtha fraction having the highest concentration of sulfur and nitrogen constituents therein is retained in the gas oil feed material and is subjected to at least two stages of relatively severe denitrogenation treatment in series to assure removal of substantially all of the nitrogen constituents therefrom. Although the conditions of operation including temperature, pressure and severity of operation may be substantially the same in each of the plurality of desulfurization zones, it is desirable and preferred to employ more severe operating conditions including higher pressures in the coker naphtha desulfurization zone than in the gas oil desulfurization zones. The

n... il)

lhydrogen-rich gas recovered from the coker naphtha product efiiuent is passed to the gas oil desulfurization zones and may be cascaded thereto without further compression when employing higher pressures in the naphtha treating step than in the gas oil treating step.

Another important embodiment of the improved arrangement of process steps of this invention is directed to the method of separating the gas oil product eiiluent stream and recovery of desired products to maximize the eicient use of and recovery of heat in the process. That is, applicants employ in conjunction with a gas oil product fractionator, at least two sequentially connected relatively high temperature separation zones in conjunction with at least two sequentially connected relatively low temperature separation zones with the last separation zones in the series of high temperature zones and low temperature separation zones being at a substantially reduced pressure from that employed in the first zones of the series. The low pressure separation Zones are maintained, however, above the pressure employed in the gas oil fractionation zone such that naphtha boiling range materials separated from the gas oil product effluent in said high temperature separation zones is cascaded to said low temperature separation zones and concentrated as a product stream in the last of said series of low temperature separation zones for recovery and passage to the upper portion of said gas oil fractionating zone as a separate stream from the gas oil fraction passed thereto which is recovered from the last of said series of high temperature separation zones.

By this improved combination of recovery steps and heat exchange steps employed therewith, hydrogen-rich gas in the gas oil product effluent is recovered at an elevated pressure for recycling to the process after the removal of sulfur therefrom with the naphtha and gas oil fractions recovered at elevated temperatures for passage to the fractionator. As a means for supplying heat to the fractionator in addition to that supplied by the naphtha and gas oil product passed thereto, a portion of the gas oil product in the lower portion of the fractionator is passed in indirect heat exchange with product eflluent of the gas oil treating prior to passing the eiiiuent of the gas oil treating steps to the high pressure-high temperature separation zone. The fractionator is operated and maintained under conditions to recover a naphtha-rich fraction from the top thereof and a desulfurized and denitrogenated gas oil fraction from the lower portion thereof. The naphtha-rich fraction withdrawn from the fractionator is mixed with water, cooled and then separated to recover a naphtha fraction, a water fraction containing water soluble constituents and a low-boiling normally gaseous hydrocarbon containing hydrogen sulfide. The naphtha stream is then passed to the naphtha treating zone as herein discussed.

Having thus generally described the improved method and process of this invention, reference is now had by way of example to the drawing illustrating a preferred embodiment thereof.

A coker gas oil boiling in the range of from about 350 F. to about 900 F., having a gravity of about 22 API is introduced to the process by conduit 2 and combined with hydrogen-rich recycle gas in conduit 4. The combined stream is then passed by conduit 2 to indirect heat exchanger 6 wherein the temperature of the stream is heated to about 435 F. The thus heated gas oil stream is then passed by conduit S to heat exchanger 10 wherein the gas oil is further heated to an elevated temperature of about 620 F. and then is passed by conduit 12 to preheat furnace t8 after being separated into two streams i4 and 16. The preheated gas oil is recovered from furnace 18 by

conduits

20 and 22, combined with additional hydrogen-rich gas in conduits 24 and 26 and passed to desulfurization zones 28 and 3) maintained at desired operating conditions including elevated temperature and pressure conditions as herein described to effect desulfurization and denitrogenation of the gas oil feed passed thereto. The product efuents of

zones

28 and 30 are withdrawn by

conduits

32 and 34, combined as a single stream 36 and passed to reboiler 38 wherein the gas oil effluent stream gives up heat to the fractionator bottoms more fully discussed hereinafter. The effluent stream is recovered from reboiler 3S by conduit 40 and passed to heat exchanger wherein it is further cooled to a temperature of about 530 F. by giving up heat to the gas oil feed in conduit S. A bypass conduit having valve 42 is provided between

conduits

36 and 40 as a means for controlling the quantity of hot product efuent passed to reboiler 38. The product effluent is recovered from exchanger 10 by conduit 42 and passed to exchanger 44 wherein it is further cooled by giving up heat to hydrogen-rich gaseous material passed to desulfurization zones 2S and 30. The gas oil product eluent is recovered from heat exchanger 44 and passed by conduit 46 to separation zone d8 maintained at an elevated temperature of about 500 F. and a pressure of about 770 p.s.i.g. In separation drum 4.13 the major portion of the naphtha boiling range constituents in the gas oil product effluent are separated from the gas oil boiling range materials and removed therefrom with gaseous material containing hydrogen, ammonia, hydrogen sulfide, and low boiling normally gaseous hydrocarbons by conduit 50. Thereafter the separated naphtha material with the separated gaseous material is passed through heat exchanger 52, conduit 54, cooler 56, conduit SS, cooler 62 and conduit 64 to separation drum 66 maintained at a temperature of about 100 F., and an elevated pressure of about 750 p.s.i.g. Provisions are made for introducing water by conduit 60 to conduit 5S for the purpose of absorbing ammonia in the hydrocarbon stream. In separating drum 66 conditions are maintained to separate a naphtha-rich stream from a gaseous stream containing hydrogen and hydrogen sulfide, as well as a water stream containing absorbed ammonia and its salts. The hydrogen-containing gaseous stream is withdrawn from separator 66 by conduit 68 and passed to hydrogen sulfide absorber tower 70 for removal of hydrogen sulfide from the gaseous stream to produce a hydrogenrich gas stream substantially free of hydrogen sulfide. The hydrogen-rich gases substantially free of hydrogen sulfide are removed from tower 70 by conduit 72 at a pressure of about 750 p.s.i.g., and thereafter passed to knock-out drum 74 and then by conduit 76 at a pressure of about 740 p.s.i.g. to compressor 78 wherein the hydrogen-rich gases are further compressed to an elevated pressure of about 840 p.s.i.g. and suitable for passage by conduit 4 as hereinbefore described. Returning noW to separator drum 48 a gas oil rich fraction containing a minor amount of entrained naphtha is withdrawn by conduit 80 having a pressure relief Valve 82 and passed to low pressure separator drum 84 maintained at a temperature of about 495 F. and a pressure of about 55 p.s.i.g. In separator drum 84 additional naphtha boiling range material is separated from the gas oil boiling range material with the separated naphtha being withdrawn by conduit 86 and passed to separator drum 88. The major naphtha stream separated in drum 66 is withdrawn by conduit 90 containing pressure relief Valve 92 and combined with the minor naphtha stream in conduit S6 for passage to low pressure separator drum 38. Water Containing absorbed ammonia is withdrawn from separator 66 by conduit 94. In separator drum S8 maintained at a temperature of about 110 F. and a pressure of about 50 p.s.i.g., normally gaseous material comprising hydrogen, hydrogen sulfide and low-boiling C2-C4 hydrocarbons are separated from the major naphtha stream. The separated gaseous material is withdrawn from separator 88 by conduit 96 and sent to suitable recovery equipment such as a Coker recovery section or directed to a fuel gas system, not shown. The separated naphtha is withdrawn from separator drum 88 and passed by conduit 98 to heat exchanger 52 wherein the naphtha is heated to an elevated temperature of about 385 F. The thus heated naphtha is then passed by conduit 100 to the upper intermediate portion of fractionator tower 102. The gas oil product material separated from naphtha drum 84 is withdrawn and passed by conduit 104 to heat exchanger 106 wherein this gas oil stream is heated to an elevated temperature of about 560 F. and thereafter passed by conduit 108 to the lower intermediate portion of fractionator 102. Fractionator 102 is maintained at a temperature of about 620 F. in the lower portion thereof and a pressure of about 30 p.s.i.g. Heat is supplied to the bottom portion of fractionator 102 by passing a gas oil fraction from the lower portion of the tower to reboiler 38 by conduit 110 and returned in a heated condition by conduit 112 to the fractionator. A desulfurized gas oil product is recovered from the bottom of fractionator 102 at an elevated temperature and passed by conduit 114 to heat exchanger 106 wherein it gives up heat and is partially cooled to a temperature of about 575 F. by passing in indirect heat exchange with the gas oil stream passed to the fractionator by conduit 108. The partially cooled gas oil product stream is then passed by conduit 116 to heat exchanger 6 wherein it gives up additional heat to the gas oil feed stream in conduit 2. The gas oil product stream is then passed by conduit 113 to cooler 120 wherein it is cooled to a temperature of about 200 F. Thereafter the desulfurized gas oil product is passed by conduit 122 to suitable recovery equipment, not shown, for further use as desired. The naphtha product separated from the gas oil product in fractionator 102 is removed by conduit 12d, mixed with water introduced by conduit 126, passed through cooler 128 to reduce the temperature of the mixture and is then passed by conduit 130 to separator drum 132 maintained at a temperature of about 100 F. and a pressure of about 20 p.s.i.g. In separator drum 132 an additional gaseous material containing hydrogen, hydrogen sulfide and C3-C4 hydrocarbons is separated from a water fraction containing absorbed ammonia and a naphtha fraction. 'Ihe gaseous stream is removed from separator 132 by conduit 134 with the separated water fraction being removed by conduit 136 from separator drum 132. A portion of the separated naphtha in drum 132 is recycled to fractionator 102 as a reflux by conduit 138 provided with pump 140. The remaining portion of the naphtha fraction separated in drum 132 is withdrawn and passed by conduit 142 containing pump 144 to heat exchanger 146 wherein it is heated to a temperature of about 440 F. The naphtha stream is withdrawn from heat exchanger 146 and passed by conduit 148 to naphtha desulfurization zone 150 more fully discussed hereinafter. A coker naphtha fraction stream boiling in the range of from about C5 to about 400 F. and having a gravity of about 51.9 API is introduced to the process by conduit 152 and mixed with hydrogen-rich gas of about 95 percent purity and at a pressure of about 910 p.s.i.g. introduced by conduit 154. The combined stream is then passed by conduit 156 to heat exchanger 15S wherein it is indirectly heated to a temperature of about 555 F. The thus heated naphtha-hydrogenrich stream is withdrawn from exchanger 153 and passed by conduit 160 to furnace 162 wherein it is further heated to a desired elevated temperature. The naphtha-hydrogen-rich gas stream is withdrawn from furnace 162 by conduit 164, combined with the partially treated naphtha in conduit 148 and passed to naphtha desulfurization Zone 150. In naphtha desulfurization zone 150 the conditions of operation are maintained to effect the desired degree of desulfurization and denitrogenation as herein described. The naphtha product effluent of the desulfurization zone 150 is passed by conduit 166 to heat exchanger 158 wherein the naphtha effluent product stream gives up heat to the naphtha feed in conduit 156 and thereafter the naphtha product etiiuent is passed by conduit 168 to heat exchanger 146 wherein it gives up additional heat to the naphtha feed in conduit 142. The naphtha product eiiiuent stream at a temperature of about 450 F. and an elevated pressure is Withdrawn from exchanger 146 and passed by conduit 176, cooler 172, conduit 174, cooler 176, and conduit 178 to high pressure separator drum 18) maintained at a pressure of about 820 p.s.i.g. and a ternperature of about 100 F. Provision is also made for introducing Water to the naphtha product effluent stream by conduit 182 for the purpose of absorbing ammonia therein. In separator drum 180 a high pressure hydrogen-rich gas stream is separated from a water fraction and a desulfurized-denitrogenated naphtha liquid fraction. The naphtha liquid fraction is withdrawn from separator drum 180 and passed by conduit 184 to suitable recovery equipment, not shown, for example, a coker recovery unit for further treatment as desired. A water fraction containing absorbed ammonia is withdrawn from separator drum 180 by conduit 186. The high pressure hydrogen-rich gas stream is withdrawn from separator drum 180 and passed by conduit 188 to heat exchanger 44 wherein the hydrogen gas stream is heated to an elevated temperature of about 500 F. Thereafter the hydrogen gas stream is passed from heat exchanger 44 by conduit 26 provided with branched conduit 24 to the gas oil desulfurization zones, as hereinbefore described. It is also contemplated, depending upon the concentration of hydrogen sulfide in the hydrogen-rich gas stream in conduit 188, of combining this stream with the hydrogen-rich gas stream in conduit 68 being passed to hydroyen sulfide absorber tower '70 wherein hydrogen sulfide is removed from the hydrogen-rich gases with a suitable absorption medium such as diethanolamine. When this latter arrangement is employed, the compressed hydrogen-rich gases in conduit 4 may all be passedfirst through heat exchanger 44 and then combined with the gas oil feed in conduit 8 or only a portion of the hydrogen-rich gas in conduit 4 may be passed to heat exchanger 44 and then to the desulfurization zones by conduit 26 with the remaining portion of hydrogen-rich gases in conduit 4 being combined with the feed in conduit 2 as hereinbefore described.

Having thus generally described the improved method and process of this invention and described a specific embodiment thereof, as well as presented modifications thereto, it is to be understood that no undue limitations are to be placed thereon by reason thereof and that many modifications may be made thereto without departing from the spirit thereof.

We claim:

l. A process for removing sulfur and nitrogen constituents from hydrocarbon feed streams which comprises:

(a) heating to an elevated temperature a first relatively low-boiling hydrocarbon feed in the presence of a hydrogen-rich gaseous material to obtain a first heated feed stream;

(b) passing said heated feed stream to an upstream desulfurization zone containing a suitable catalytic material and maintained under elevated temperature and pressure conditions to hydrogenate sulfur and nitrogen constituents thereof, thereby obtaining a first treated eiuent;

(c) separating said first treated effluent under an elevated pressure to recover a low-boiling product stream and a gaseous stream comprising hydrogen under an elevated pressure; and passing said gaseous stream to a downstream desulfurization Zone;

(d) passing a second relatively high-boiling heated feed stream to said downstream desuiturization zone containing a suitable catalytic material and maintained under desulfurization conditions to hydrogenate the sulfur constituents thereof, thereby obtaining a second treated effluent;

(e) separating from said second treated efiiuent a gaseous stream comprising hydrogen and hydrogen sulfide; removing hydrogen sulfide from said gaseous stream and passing the thus purified gaseous stream to said downstream desulfurization Zone; and further separating the remaining second treated effluent to recover a relatively high-boiling stream and a relatively low-boiling stream;

(f) passing a portion of said relatively low-boiling stream as a liquid to said upstream desulfurization zone as a portion of the feed thereto.

2. A process for removing sulfur and nitrogen constitutents Ifrom hydrocarbon feed streams which comprises:

(a) heating to an elevated temperature a rst relatively low-boiling hydrocarbon feed in the presence of a hydrogen-rich gaseous material to obtain a first heated feed stream;

(b) passing said heated feed stream to an upstream desulfurization Zone containing a suitable catalytic material and maintained under elevated temperature and pressure conditions to hydrogenate sulfur and nitrogen constituents thereof, thereby obaining a first treated euent;

(c) separating said first treated effluent under an elevated pressure to recover a low-boiling product stream and a gaseous stream comprising hydrogen under an elevated pressure; and passing said gaseous stream to a downstream desulfurization zone maintained under a lower pressure than said upstream desulfurization Zone;

(d) separately heating to an elevated temperature a second relatively high-boiling hydrocarbon feed in the presence of a hydrogen-rich gaseous material to obtain a second heated feed stream;

(e) passing said second heated feed stream to a downstream desulfurization zone containing a suitable catalytic material and maintained under desulfurization conditions to hydrogenate the sulfur constituents thereof, thereby obtaining a second treated efiiuent;

() separating from said second treated effluent a gaseous stream comprising hydrogen and hydrogen sulfide; removing hydrogen sulfide from said gaseous stream and passing the thus purified gaseous stream to said downstream desulfurization zone; and further separating the remaining second treated eiuent at a reduced pressure to recover a relatively high-boiling stream and .a relatively low-boiling stream;

(g) `passing a portion of said relatively low-boiling stream as a liquid to said upstream desulfurization zone as a portion of the feed thereto.

3. The process of claim 2 in which said relatively highboiling stream and said relatively low-boiling stream obtained in step (f) are separately passed at an elevated temperature to a fractionation zone; a fractionation zone overhead stream is recovered and passed as a liquid stream to said upstream desulfurization zone; a fractionation Zone bottoms stream is recovered and passed in indirect heat exchange with said second treated eiuent and is then returned to said fractionation zone; and a portion of said fractionation bottoms stream is withdrawn as a product of the process.

4. A process for removing sulfur and nitrogen constituents from hydrocarbon feed streams which comprlses:

(ci) heating to an elevated temperature a naphtha boiling range feed in the presence of a hydrogen-rich gaseous material to obtain a first heated feed stream;

(b) passing said heated feed stream to an upstream desulfurization zone containing a suitable catalytic material and maintained under elevated temperature and pressure conditionsy to hydrogenate sulfur and nitrogen constituents thereof, thereby obaining a first treated effluent;

(c) separating said first treated effluent under an elevated pressure to recover a naphtha product stream which is withdrawn from the process and a hydrogenrich gaseous stream under an elevated pressure; and passing said hydrogen-rich stream to a downstream desulfurization zone maintained under a lower pressure than said upstream desulfurization zone;

(d) separately heating to an elevated temperature a relatively high-boiling hydrocarbon feed in the presence of a hydrogen-rich gaseous material to obtain a second heated feed stream;

(e) passing said second heated feed stream to a downstream desulfurization zone containing a suitable catalytic material and maintained under desulfurization conditions to hydrogenate the sulfur constituents thereof, thereby obtaining a second treated effluent;

(f) separating from said second treated etliuent a gaseous stream comprising hydrogen and hydrogen sulfide; removing hydrogen sulde from said gaseous stream and passing the thus purified gaseous stream to said downstream desulfurization zone; and further separating the remaining second treated effluent at a reduced pressure to recover a relatively high-boiling stream and a stream comprising a naphtha-boiling fraction;

(g) passing said naphtha-boiling fraction as a liquid to said upstream desulfurization zone as a portion of the feed thereto.

5. The process of claim 4 in which said downstream desulfurization zone comprises at least two separate zones containing a suitable catalytic material and maintained in parallel iiow relationship with respect to said second hydrocarbon feed material.

6. The process of claim 4 in which said first treated effluent obtained in step (b) is treated in a Water-wash step to remove water soluble impurities therefrom, said stream thereafter being passed to step (c).

7. A process for removing sulfur and nitrogen constituents from hydrocarbon feed streams which comprises:

(a) heating to an elevated temperature a naphtha boiling range fraction in the presence of a hydrogen-rich gaseous material to obtain a first heated feed stream;

(b) passing said heated feed stream to an upstream desulfurization zone containing a suitable catalytic material and maintained under elevated temperature and pressure conditions to hydrogenate sulfur and nitrogen constituents thereof, thereby obtaining a first treated efiiuent;

(c) separating said first treated effluent under an elevated pressure to recover a naphtha product stream which is withdrawn from the process and a gaseous stream comprising at least about percent hydrogen under an elevated pressure; and passing said gaseous stream to a downstream desulfurization zone maintained under a lower pressure than said upstream desulfurization zone;

(d) separately heating to an elevated temperature a gas-oil boiling range fraction, in which the higher boiling range constituents of said naphtha fraction are retained, in the presence of a hydrogen-rich gaseous material to obtain a second heated feed stream;

(f) separating from said second treated efl'luent a gaseous stream comprising hydrogen and hydrogen sulfide; removing hydrogen sulfide from said gaseous stream and passing the thus purified gaseous stream to said downstream desulfurization zone; further separating the remaining second treated effluent to recover a relatively high-boiling stream and a relatively low-boiling stream;

(g) separately passing said relatively high-boiling and said relatively low-boiling streams at an elevated temperature to a fractionation zone to recover a fractionation overhead stream and a fractionation bottoms stream;

(lz) passing said fractionation overhead stream as a liquid stream to said upstream desulfurization zone as a portion of the feed thereto and passing a portion of said fractionation bottoms in indirect heat exchange with said second treated effluent; and withdrawing a portion of said fractionation bottoms stream as a product of the process.

References Cited in the file of this patent UNITED STATES PATENTS 2,763,358 Linn etal Sept. 18, 1956 2,773,008 Hengstebeck Dec. 4, 1956 2,833,698 Patton et al May 6, 1958 2,951,032 Inwood Aug. 30, 1960 2,952,625 Kelley et al Sept. 13, 1960 3,011,971 Slyngstad et al. Dec. 5, 1961

Claims

1. A PROCESS FOR REMOVING SULFUR AND NITROGEN CONSTITUENTS FROM HYDROCARBON FEED STREAMS WHICH COMPRISES: (A) HEATING TO AN ELEVATED TEMPERATURE A FIRST RELATIVELY LOW-BOILING HYDROCARBON FEED IN THE PRESENCE OF A HYDROGEN-RICH GASEOUS MATERIAL TO OBTAIN A FIRST HEATED FEED STREAM; (B) PASSING SAID HEATED FEED STREAM TO AN UPSTREAM DESULFURIZATION ZONE CONTAINING A SUITABLE CATALYTIC MATERIAL AND MAINTAINED UNDER ELVELATED TEMPERATURE AND PRESSURE CONDITIONS TO HYDROGENATE SULFUR AND NITROGEN CONSTITUENTS THEREOF, THEREBY OBTAINING A FIRST TREATED EFFLUENT; (C) SEPARATING SAID FIRST TREATED EFFUENT UNDER AN ELEVATED PRESSURE TO RECOVER A LOW-BOILING PRODUCT STREAM AND A GASEOUS STREAM COMPRISING HYDROGEN UNDER AN ELEVATED PRESSRUE; AND PASSING SAID GASEOUS STREAM TO A DOWNSTREAM DESULFURIZATION ZONE; (D) PASSING A SECOND RELATIVELY HIGH-BOILING HEATED FEED STREAM TO SAID DOWNSTREAM DESULFURIZATION ZONE CONTAINING A SUITABLE CATALYTIC MATERIAL AND MAINTAINED UNDER DESULFURIZATION CONDITIONS TO HYDROGENATE THE SULFUR CONSTUTUTENTS THEREOF, THEREBY OBTAINING A SECOND TREATED EFFUENT; (E) SEPARATING FROM SAID SECOND TREATED EFFUENT A GASEOUS STREAM COMPRISING HYDROGEN AND HYDROGEN SULFIDE; REMOVING HYDROGEN SULFIDE FROM SAID GASEOUS STREAM AND PASSING THE THUS PURIFIED GASEOUS STREAM TO SAID DOWNSTREAM DESULFURIZATION ZONE; AND FURTHER SEPARATING THE REMAINING SECOND TREATED EFFUENT TO RECOVER A RELATIVELY HIGH-BOILING STREAM AND A RELATIVELY LOW-BOILING STEAM; (F) PASSING A PORTION OF SAID RELATIVELY LOW-BOILING STREAM AS A LIQUID TO SAID UPSTREAM DESULFURIZATION ZONE AS A PORTION OF THE FEED THERETO.