US20100294698A1

US20100294698A1 - Deep desulfurization process

Info

Publication number: US20100294698A1
Application number: US12/469,609
Authority: US
Inventors: Marcus Dutra e Mello; Bi-Zeng Zhan; Zunquin He; Akshay Verma; Sheila Yeh
Original assignee: Chevron USA Inc
Current assignee: Chevron USA Inc
Priority date: 2009-05-20
Filing date: 2009-05-20
Publication date: 2010-11-25
Also published as: WO2010135434A2; WO2010135434A3

Abstract

Methods for producing a substantially desulfurized hydrocarbon fuel stream, using no substantial amount of hydrogen, at pressures less than 125 psig are described. The process uses two fixed beds in series to remove sulfur and/or other heteroatoms to produce a substantially desulfurized (less than 1 ppm sulfur) hydrocarbon fuel stream. The first fixed bed uses a transition metal catalyst dispersed on an inorganic oxide matrix and the second bed uses a high surface area, porous, amorphous inorganic oxide catalyst or a high surface area porous carbonaceous catalyst. The second fixed bed can additionally comprise one or more metals.

Description

BACKGROUND

Environmental regulations continue to mandate lower sulfur emissions and as a result, new processes and equipment are necessary to achieve low sulfur levels in fuels. In addition, there is growing interest in using low sulfur hydrocarbon streams as a source of hydrogen for hydrogen based fuel cell systems. One approach to address the issues of hydrogen generation and storage is to develop technology that can convert liquid hydrocarbon-based fuels into hydrogen and utilize the existing refining and fuels distribution infrastructure. The presence of sulfur-containing compounds in a hydrocarbon fuel stream can be very damaging to the hydrogen fuel cell processing components and such compounds must therefore be substantially removed. In many cases, current hydrotreating technology is not economically suitable for the goal of producing hydrocarbons with less than 1 ppm sulfur.
Sulfur containing compounds with hindered sulfur atoms are often referred to as “hard or refractory sulfur” due to the difficulty in removing them from a hydrocarbon stream by hydrotreating processes, whereas nonaromatic sulfur compounds, sulfides, and thiophenes are often referred to as “easy sulfur” due to their relative ease of removal from hydrocarbon streams. Many conventional methods are directed to “easy sulfur” removal. In order to remove the “hard sulfur”, such as 4,6dimethyl-dibenzothiophene, a substantially larger amount of catalyst and higher temperature and pressure, plus higher hydrogen partial pressure can be required, which negatively impacts the economic feasibility of the process.
In addition to hydrodesulfirization catalysts, adsorbents can be used to remove sulfur and sulfur containing compounds from hydrocarbon streams. Adsorbents physically sequester the sulfur and/or sulfur containing compounds. Adsorbents such as activated charcoal, alumina, and other high porosity materials are known in the art. While adsorbents are useful, they have certain limitations. Adsorbents may be regenerable. i.e., they can desorb the sulfur compounds they have adsorbed under certain operating conditions and therefore may be utilized again for sulfur binding in another adsorption-desorption cycle. This process is known as thermal swing adsorption (TSA). Economics of using adsorption as a means of sulfur removal is usually favored by the use of regenerable adsorbents as opposed to single use adsorbents in a throwaway process. One limitation of the use of adsorbents is the limits on the quantity of sulfur compounds which can be adsorbed by the adsorbents.
There exists a need for processes that produce hydrocarbon streams with less than 1 ppm sulfur under economically feasible conditions. It has been surprisingly discovered that the performance of a desulfurization system can be substantially enhanced by utilizing two adsorbent zones in series, one which is suitable to target less refractory (“easy sulfur”) sulfur species and the other which targets more refractory (“hard sulfur”) sulfur species such as alkyl-substituted dibenzothiophenes. The adsorbents include microporous and mesoporous inorganic oxides such as silica, alumina, silica-alumina, titania, zirconia, zeolites, high surface area mesoporous inorganic oxide materials, and high surface area activated carbon. Metal nano-particles can be deposited on the supports to increase activity. No substantial amount of hydrogen is utilized during the desulfurization process, providing a further economic benefit.

SUMMARY

Processes for removing sulfur and sulfur containing compounds from hydrocarbons streams are provided. In addition, it was found that other heteroatoms such as nitrogen were reduced in the described processes. In an embodiment, the process of the invention comprises the steps of a) contacting a hydrocarbon feed stream, which comprises heteroatom containing compounds, in a first adsorption zone with a first adsorbent comprising at least one transition metal and at least one inorganic oxide at a first pressure and a first temperature, in the absence of any substantial amounts of added hydrogen, to form a first effluent wherein the first effluent has a heteroatom content lower than the heteroatom content of the hydrocarbon feedstream and b) contacting at least a portion of the first effluent, in a second adsorption zone, with a second adsorbent comprising an amorphous inorganic oxide, a porous carbonaceous material, or combinations thereof at a second reaction pressure and a second reaction temperature, in the absence of any substantial amounts of added hydrogen, to form a second effluent, wherein the second effluent has a heteroatom content lower than the heteroatom content of the first effluent. In another embodiment, the process of the invention utilizes at least two adsorption beds connected in parallel in each adsorption zone. The use of parallel beds allows the regeneration and/or replacement of a bed while allowing the process to be run continuously. The invention thus provides for a process comprising the steps of a) contacting a hydrocarbon feed stream, which comprises heteroatom containing compounds, in a first adsorption zone wherein the first adsorption zone comprises at least two adsorption beds in parallel, in the absence of any substantial amounts of added hydrogen, to form a first effluent wherein the first effluent has a heteroatom content lower than the heteroatom content of the hydrocarbon feedstream and b) contacting at least a portion of the first effluent, in a second adsorption zone, wherein the second adsorption zone comprises at least 2 adsorption beds in parallel, at a second reaction pressure and a second reaction temperature, in the absence of any substantial amounts of added hydrogen, to form a second effluent, wherein the second effluent has a heteroatom content lower than the heteroatom content of the first effluent. In an embodiment, the first adsorbent comprises at least one transition metal and at least one inorganic oxide. In an embodiment the second adsorbent comprises an amorphous inorganic oxide, a porous carbonaceous material, or combinations thereof.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic of one embodiment of the invention.

DETAILED DESCRIPTION

The invention is directed to processes for removing sulfur and/or other heteroatom-containing compounds from hydrocarbon feed streams through the use of adsorbents. The process of the invention uses two different adsorbent beds run sequentially to remove sulfur and/or other heteroatom-containing compounds. Depending of the types and amounts of sulfur and/or other heteroatom-containing compounds present in the feedstock, the nature of the adsorbents chosen can change. Generally, the adsorbents have a high surface area and/or porosity to allow for the effective sequestering of sulfur containing compounds and/or other heteroatom-containing compounds.

Definitions

While the invention is susceptible to various modifications and alternative forms, specific embodiments thereof are herein described in detail. It should be understood, however, that the description herein of specific embodiments is not intended to limit the invention to the particular forms disclosed, but on the contrary, the intention is to cover all modifications, equivalents, and alternatives falling within the spirit and scope of the invention as defined by the appended claims.
The following terms will be used throughout the specification and will have the following meanings unless otherwise indicated.
As used herein “hydrocarbon” refers to any compound which comprises hydrogen and carbon, and “hydrocarbon feedstock” and “hydrocarbon feed stream” refers to any charge stock which contains greater than about 90 weight percent carbon and hydrogen.
As used herein, “heteroatom containing compounds” are compounds containing atoms other than carbon and hydrogen. “Heteroatoms” are atoms other than carbon and hydrogen. Nitrogen and sulfur are examples of heteroatoms. Sulfur and/or nitrogen containing compounds are heteroatom containing compounds.
As used herein “Group VIB” or “Group VIB metal” refers to one or more metals, or compounds thereof, selected from Group VIB of the CAS Periodic Table.
As used herein “Group IB” or “Group IB metal” refers to one or more metals, or compounds thereof, selected from Group IB of the CAS Periodic Table.
As used herein “Group IIB” or “Group IIB metal” refers to one or more metals, or compounds thereof, selected from Group IIB of the CAS Periodic Table.
As used herein “Group VIII” or “Group VIII metal” refers to one or more metals, or compounds thereof, selected from Group VIII of the CAS Periodic Table.
The term “mesoporous” refers to an average pore size of about 2 to about 50 nm. The term “macroporous” refers to an average pore size greater than about 50 nm.
As used herein the term “adsorbent” refers to any solid material capable of sequestering and/or binding sulfur containing compounds, nitrogen containing compounds, or. The adsorption can take place on the external surface of the solid material, in the interior pores of the material, or both.
The BET surface area is determined by adsorption of nitrogen at 77K and mesopore surface area by the BJH method (described in E. P. Barrett, L. C. Joyner and P. H. Halenda, J. Amer. Chem. Soc., 73, 1951, 373.). The micropore volume is determined by the DR equation (as described in Dubinin, M. M. Zaverina, E. D. and Raduskevich, L. V. Zh. Fiz. Khimii, 1351-1362, 1947). The total pore volume is determined from the nitrogen adsorption data, the mesopore volume is determined by the difference between total pore volume and the micropore volume.
Feedstocks
A wide variety of hydrocarbon feedstocks can be used in the process of the invention. The feedstocks can be petroleum derived or biologically derived feedstocks. In an embodiment, the feedstocks can be derived from plant, animal, and/or algal oils and/or waxes. Naphtha boiling range streams can be used in the process of the invention. Naphtha feedstocks comprise any one or more refinery streams boiling in the range from about 10° C. to about 230° C., at atmospheric pressure. The naphtha boiling range stream usually contains cracked naphtha, such as fluid catalytic cracking unit naphtha (FCC catalytic naphtha, or cat cracked naphtha), coker naphtha, hydrocracker naphtha, resid hydrotreater naphtha, debutanized natural gasoline (DNG), and gasoline blending components from other sources from which a naphtha boiling range stream can be produced. FCC cat naphtha and coker naphtha are generally more olefinic naphthas since they are products of catalytic and/or thermal cracking reactions. In another embodiment, the feedstock contains major components of hydrocarbons having boiling points between about 30 to about 600° C., preferably from about 100 to about 400° C. The feedstock used in the process of the invention can be petroleum distillates as exemplified, for example, by gas oil distillates, kerosene distillates, diesel distillates and gasoline distillates. The feedstocks used in the process of the invention are preferably distillate feedstocks and more preferably diesel distillate feedstocks.
The sulfur content of the feedstocks used in the process of the invention can vary. In an embodiment, the sulfur content can be less than about 1000 ppm. In another embodiment the sulfur content of the feedstock can be less than 100 ppm. In a further embodiment, the sulfur content of the feedstock can be less than 10 ppm. In one embodiment, the object of the invention is to produce an effluent with a total sulfur content of less than about 1 ppm. In this embodiment, it is preferred that the feedstock first be hydrotreated to reduce its sulfur content, preferably to less than about 1000 ppm, more preferably to less than about 500 ppm, most preferably to less than about 200 ppm, particularly to less than about 100 ppm sulfur, and ideally to less than about 50 ppm.
The types of sulfur containing compounds present in the feedstock can vary. Nonlimiting examples of sulfur compounds which can be present in the feedstock include carbonyl sulfide, hydrogen sulfide, thiophenes, such as tetrahydrothiophene, benzothiophenes, alkylbenzo and dibenzothiophenes, alkyldibenzo and dialkyldibenzo thiophenes, dimethyl sulfide, various mercaptans, disulfides, sulfoxides, other organic sulfides, higher molecular weight organic sulfur compounds, and combinations thereof.
The nitrogen content of the feedstock is preferably less than about 50 ppm, more preferably less than about 20 ppm, and most preferably less than about 10 ppm. The presence of high amounts of nitrogen containing compounds can inhibit the adsorption of sulfur containing compounds and/or deactivate any active metals present in the adsorbent. Nonlimiting examples of nitrogen containing compounds which can be present in the feedstock include amines, amides, aromatic nitrogen containing molecules, indoles, and carbazoles.
Bed 1
The first adsorbent zone comprises one or more adsorbent beds. In an embodiment the first adsorbent zone contains two or more adsorbent beds in parallel. The adsorbent bed(s) comprise an inorganic oxide and one or more transition metals. The inorganic oxide can act as a support for the transition metals and can be referred to herein as an “inorganic oxide support”. “Inorganic oxide” and “inorganic oxide support” are thus used interchangeably within the description of the invention. Examples of inorganic oxides include, but are not limited to, silica, alumina, titania, zirconia, zeolites, and combinations thereof. In an embodiment, the inorganic oxide is silica. In another embodiment, the inorganic oxide is alumina. In still another embodiment, the inorganic oxide is silica-alumina. The inorganic oxide can be crystalline or non-crystalline. Examples of crystalline inorganic oxides include, but are not limited to, zeolites, silicoaluminophosphates, borosilicates, gallosilicates, and other molecular sieves. In an embodiment, crystalline inorganic oxides can be used as supports in the first absorbent bed(s). In another embodiment, the first absorbent bed(s) comprises amorphous inorganic oxides. The amorphous inorganic oxide can have a surface area of greater than 100 m2/g, preferably greater than 150 m2/g, more preferably greater than 200 m2/g, and most preferably greater than 250 m2/g. The amorphous inorganic oxide can have mesopores, micropores, and macropores. Preferably, the inorganic oxide is mesoporous.
The first adsorbent bed or beds contain one or more metals selected from Group VIB, Group VIII, Group IB, and Group IIB of the periodic table. Preferred, the adsorbent comprises at least one Group VIII metal, preferably selected from Fe, Co, and Ni, alone or in combination with a component of at least one metal selected from the Group VIB metals, Group IB metals, and Group IIB metals and mixtures thereof. More preferably the Group VIII metal is Co and/or Ni, most preferably Ni. It is also preferred that at least one Group VI metal, preferably Mo and W, more preferably Mo, be present. The Group VIII metal is typically present in an amount ranging from about 2 to 60 wt. %, preferably from about 10 to 50 wt. %, more preferably from 30 to 50 wt. %. The Group VIB metal will typically be present in an amount ranging from about 0 to 60 wt. %, preferably from about 10 to 50 wt. %, and more preferably from about 20 to 40 wt. %. All metal weight percents are based on the total weight of the adsorbent. For example, if the adsorbent weighs 100 g, then 20 wt. % Group VIII metal would mean that 20 g of Group VIII metal was in the adsorbent.
Various methods of adding metals to inorganic oxide supports are known in the art. Briefly, methods of incorporating metals include ion exchange, homogeneous deposition precipitation, redox chemistry, chemical vapor deposition, and impregnation. Preferably, impregnation is used to incorporate active metals into the inorganic oxide support. Impregnation involves exposing supports to a solution comprising the metal or metals to be incorporated followed by evaporation of the solvents. The solvents are water and/or alcohols and/or their combination, and more preferably water. In an embodiment, chelating agents are used during metal impregnation. “Chelating agents” or “chelates” can be described as a molecule containing one or more atoms capable of bonding to, or complexing with, a metal ion. The chelating agent acts as a ligand to the Group VIII and/or Group VIB metal ions, often through electron pair donor atoms in the chelating agent. Chelated metal ions tend to be more soluble and chelating agents can improve the dispersion of metal ions throughout the inorganic oxide supports. Chelates can be polydentate, in that they can bond or complex to a metal ion through one or more positions. For example a bidentate ligand forms two bonds with a metal ion, whereas a hexadentate ligand forms six bonds with a metal ion. Examples of chelating agents include, but are not limited to, citrate, ethylene diamine tetraacetic acid (EDTA), polyethylene glycols with varying molecular weights, ethylene glycol tetraacetic acid (EGTA), nitrilotriacetic acid (NTA), halides, nitrate, sulfate, acetate, salicylate, oxalate, and formate. For a review see A. Jos van Dillen, R. J. A. M. Terörde, D. J. Lensveld, J. W. Geus, and K. P. de Jong, “Synthesis of supported catalysts by impregnation and drying using aqueous chelated metal complexes”, Journal of Catalysis, 2003, p. 257-264, herein incorporated by reference in its entirety.
Desulfurization Conditions
The invention is practiced by introducing, at suitable conditions including in the substantial absence of added hydrogen, the feedstream containing the heteroatom containing compounds into a first adsorption zone containing the first adsorption bed or beds described above. The temperature in the first adsorption zone can range from about 100° C. to about 500° C., preferably from about 200° C. to about 400° C. The pressure of the first adsorption zone can range from about 20 psig to about 125 psig, preferably from about 25 psig to about 75 psig. The LHSV can vary. Generally, the first adsorption zone is run at an LHSV of between about 0.1 to about 10, although higher or lower LHSV are not excluded.
In an embodiment, the process of the invention can use a first adsorption zone with two or more adsorption beds connected in parallel. This allows the process to be run in continuous adsorption mode. By this it is meant that the same type of adsorbent can be present in two or more adsorption beds wherein the feedstream is selectively directed to one of the two or more adsorption beds connected in parallel. The bed or beds which are not in use can be regenerated or fresh adsorbent switched in for spent adsorbent. Generally, when an adsorption bed exhibits a certain percentage breakthrough of sulfur containing species, the adsorption bed will be regenerated and/or replaced. By having at least two adsorption beds connected in parallel there is little or no downtime and the process of the invention can be run in continuous adsorption mode. This provides an economic benefit by maximizing desulfurized product production with little or no downtime.
In one embodiment, the first adsorbent bed or beds are not regenerated, but replaced by fresh adsorbent. In another embodiment, the first adsorbent bed is regenerated. For example, after the bed of adsorbent material has become saturated with sulfur moieties, it can optionally be regenerated using a hydrogen-containing gas (regenerant gas) at an effective flow rate and at an effective pressure and temperature. In one embodiment, the hydrogen-containing gas is substantially pure hydrogen. Small amounts of hydrogen sulfide, methane, and/or other hydrocarbons can be present in the regenerant gas stream. In general the regenerant gas stream contains at least 1% hydrogen with the remainder of the regenerant gas an inert gas such as nitrogen or helium. During the regeneration cycle, the hydrogen-containing gas can first be heated before passing through the sulfur-saturated bed. Regenerant gas can flow either co-current or counter-current with respect to the flow of feedstream to be treated, but under typical operating conditions, the regenerant gas will flow co-current with the feedstream. The pressures and temperatures of the regeneration cycle are maintained at effective pressures from about 0 to about 2000 psig, preferably from about 60 to about 1000 psig, and more preferably form about 60 to about 500 psig. Effective temperatures are from about 100° C. to about 600° C., preferably from about 200° C. to about 500° C., and more preferably from about 260° C. to about 400° C.
Effective regenerant gas flows are preferably greater than about 0.01 ft/min and more preferably greater than about 0.1 ft/min and most preferably greater than about 1 ft/min.
Bed 2
At least a portion of the effluent from the first adsorption zone is passed to a second adsorption zone. The second adsorption zone comprises one or more second adsorbent beds. Generally, the first adsorption zone removes less refractory sulfur species. In order to achieve sulfur levels of less than about 1 ppm, a second adsorption zone can be needed to remove more refractory sulfur species such as alkyldibenzothiophenes, and dialkyldibenzothiophene.
The second adsorption bed or beds comprise a second adsorbent which is a porous material such as alumina, silica, silica-alumina, or carbonaceous materials such as activated charcoal. For example, hydrated alumina can be used as an adsorbent in the second adsorption bed or beds. The hydrated alumina can be impregnated with alkali metal ions, such as sodium or potassium ions. Activated hydrated alumina of this type is prepared by methods recognized in the art, such as those disclosed, for example, in U.S. Pat. Nos. 3,058,800 and 4,835,338, both of which patents are incorporated herein by reference. Preferably, the second adsorption bed or beds comprise a carbonaceous material. In order to effectively adsorb the unwanted heteroatom containing compounds, the second adsorbent must have high surface area and large pore volume. In an embodiment, the second adsorbent is a carbonaceous material with a surface area of at least 1000 m2/g, preferably 1500 m2/g, and most preferably at least 2000 m2/g. In an embodiment the carbonaceous adsorbent has a pore volume of greater than 0.5 cc/g, preferably greater than 1 cc/g, more preferably greater than 2 cc/g, and most preferably greater than 3 cc/g. The second adsorbent can optionally comprise one or more metals selected from Group VIB, Group VIII, Group IB, Group IA, Group IIA, and Group IIB of the periodic table.
In an embodiment, the second adsorbent comprises activated carbon. Activated carbon, or activated charcoal, is a carbon material in which the pore structure is developed. Activated carbon is widely used industrially as an adsorptive agent and in catalysts. Activated carbon can occur naturally, such as anthracite, or be produced from the carbonization of organic matter. The production method of the carbonaceous material is not critical. Activation of the carbonaceous material can occur through any method known in the art including, but not limited to, gas activation, alkali activation, sulfuric acid activation, and chemical activation.
The activated carbon can be further subjected to a number of post-synthesis treatments including acid treatment, metal impregnation, and/or immobilization of organic compounds. During post synthetic acid treatment, the activated carbon is treated with one or more acids such as nitric acid, phosphoric acid, sulfuric acid, or combinations thereof. In an embodiment, the acid used can be an organic acid. While not being bound by any theory, we believe that acid treatment can lead to hydroxyl functionalization of the surface of the activated carbon and increase the binding capacity and/or increase the binding strength of sulfur containing compounds to the activated carbon adsorbent.
Metals from Group VIII, Group VIB, Group IB, Group IIB, Group IA, and/or Group IIA can be added to the second adsorbent. All methods known in the art can be used to add metals to the second adsorbent, including, but not limited to homogeneous deposition precipitation, redox chemistry, chemical vapor deposition, and impregnation.
In an embodiment, the second adsorption bed is regenerated. By regenerated it is meant that some or all of the sulfur and/or nitrogen containing compounds adsorbed onto the bed are removed so as to allow the adsorption bed to be reused for adsorption of sulfur and/or nitrogen containing compounds. Generally, regeneration can be affected by desorbing non-covalently bound compounds from the adsorbent by passing a desorbing liquid through the adsorbent bed. Examples of desorbing liquids include, but are not limited to aromatic solvents such as benzene and toluene, polar solvents such as methanol and ethanol, and paraffinic solvents such as hexane. The temperatures at which regeneration takes place can be elevated to facilitate desorption. Generally, the desorbing temperature is between about 50° C. and about 200° C.
Desulfurization Conditions
At least a portion of the effluent from the first adsorption zone is introduced to the second adsorption zone at suitable conditions including the substantial absence of added hydrogen. The temperature in the second adsorption zone can range from about ambient temperature (about 20° C.) to about 200° C. The pressure of the second adsorption zone can range from about ambient pressure (about 0 psig) to about 75 psig, preferably from ambient pressure to about 50 psig. The LHSV can vary. Generally, the second adsorption one is run at an LHSV of between about 0.1 to about 10, although higher or lower LHSV are not excluded.
In an embodiment, the process of the invention can use a second adsorption zone with two or more adsorption beds connected in parallel. This allows the process to be run in continuous adsorption mode. By this it is meant that the same type of adsorbent can be present in two or more adsorption beds within the second adsorption zone, and wherein the effluent from the first adsorption zone is selectively directed to one of the two or more adsorption beds connected in parallel in the second adsorption zone. The bed or beds which are not in use can be regenerated or fresh adsorbent switched in for spent adsorbent. Generally, when an adsorption bed exhibits a certain percentage breakthrough of sulfur containing species, the adsorption bed will be regenerated and/or replaced. By having at least two adsorption beds connected in parallel there is little or no downtime and the process of the invention can be run in continuous adsorption mode. This provides an economic benefit by maximizing desulfurized product production with little or no downtime.
Bed 2 Regeneration
In an embodiment, the process of the invention further comprises a step of desorbing the hetero atom containing compounds from the second adsorption bed or beds by heating the second adsorption bed or beds in a non-oxidizing atmosphere to regenerate the adsorbent. The adsorbent, after desorption of heteroatom containing compounds, can be repeatedly used. The adsorbent in the second bed is regenerated by passing a desorbing liquid through it continuously at preferred temperatures of 50° C. to200° C. Suitable desorbents include aromatic, paraffinic and polar solvents such as toluene and methanol. Regeneration can be confirmed by measuring and following the sulfur composition at the desorbing effluent and by submitting the said adsorbent bed to a new adsorption cycle. In doing so, capacity for sulfur should remain the same at the end of a second-time adsorption.
The process of the invention can be performed with two or more adsorbent beds in each of the two adsorption zones for a total of at least four adsorption beds. This process arrangement enables continuous adsorption mode leading to a continuous production of substantially sulfur-free streams. This is accomplished by suitably valving the feed to the spare bed(s) that has been freshly activated awaiting to go on adsorption mode. The bed that underwent adsorption can then be regenerated (second adsorbent) or replaced by fresh material (first adsorbent). In this embodiment, an economic benefit can be realized by allowing the process to be run continually with little or no downtime even during adsorbent regeneration and/or adsorbent replacement.
Reference is now made to an embodiment of the invention illustrated in FIG. 1. A hydrocarbon feedstock comprising heteroatom containing compounds such as sulfur compounds, 1, is passed through one or more valves, 5, to the first adsorption zone. Depending on the direction of the valve or valves, 5, the feedstream exits the valve or valves as feedstream 2 or 3. The feedstream then enters the first adsorption zone. The first adsorption zone consists of reactors 10 and 20. If the feedstream is directed to 2, it enters reactor 10. If the feedstream is directed to 3 it enters reactor 20. While the feedstream enters one reactor of adsorption zone 1, the second reactor of adsorption zone 1 may undergo catalyst regeneration and/or catalyst replacement if desired. The effluent from reactor 10, is labeled 4. The effluent from reactor 20 is labeled 6. The total effluent stream from the first adsorption zone, 7, is passed through one or more valves, 25, to the second adsorption zone. Depending on the direction of the valve or valves, 25, the effluent stream exits the second valve or valves, 25, as effluent 8 or 9. If the effluent is directed to 8 it enters reactor 30. If the effluent is directed to 9 it enters reactor 40. While the effluent enters one reactor of adsorption zone 2, the second reactor of adsorption zone 2 may undergo catalyst regeneration and/or catalyst replacement if desired. The effluent from reactor 30, is labeled 11. The effluent from reactor 40 is labeled 12. Effluent streams 11 and 12 combine to form effluent stream 13. According to the process of the invention, effluent stream 13 has a lower heteroatom content than effluent stream 7.

EXAMPLES

Example 1

Single Bed

A model feed with 50 ppm DBT (dibenzothiophene), 50 ppm DMDBT (dimethyldibenzothiophene), and 10 ppm methyl indoline was run over adsorption beds A-D. Adsorption bed A was activated charcoal, adsorption bed B was 1% Ag on activated charcoal, adsorption bed C was 1% Au on activated charcoal, and adsorption bed D was the activated charcoal of A after nitric acid treatment. Results are given in Table 1. The activated charcoal support had a surface area of 1800-2000 m²/g and a pore volume of 1.5-1.7 cc/g. The incipient wetness impregnation method was used to prepare Ag and Au supported on activated charcoal (adsorption bed B and C, respectively). Generally, the activated charcoal support was contacted with a solution of the nitrate salt or other soluble salt of the metal to be impregnated. The volume of solution was about 105% of the measured water pore volume of the support. The impregnation was conducted in a rotavaporizer at room temperature to ensure a homogenous impregnation. The adsorbent was then dried at 200° C. overnight in flowing air. X-ray photoelectron spectroscopy (XPS) and high resolution transmission electron microscopy were used to characterize metals dispersed on the supports. Adsorption bed B (Ag on activated charcoal) and adsorption bed C (Au on activated charcoal) were activated at 100° C. with a small amount of hydrogen prior to contact with the feedstock to be desulfurized. Adsorption beds B and C were contacted for at least two hours in flowing H₂(100 cc/min) or a flowing gas containing about 5% H₂at a flow rate of 100 cc/min.

	TABLE 1

		% capacity for total sulfur
	Adsorbent	removal (wt. %)

	A	0.11
	B	0.14
	C	0.13
	D	0.18

Example 2

Dual Bed

A model feed with 50 ppm DBT (dibenzothiophene), 50 ppm DMDBT (dimethyldibenzothiophene), and 10 ppm methyl indoline was run over adsorption bed E followed by adsorption bed F. Adsorption bed E was nickel supported on alumina. Adsorption bed F was activated charcoal after nitric acid treatment. The adsorption bed E was activated at 500° C. for 4 hrs in flowing H₂(100 cc/min) or a flowing gas containing about 5% H₂at a flow rate of 100 cc/min whereas adsorption bed F was activated at 200° C. for 4 hrs in flowing helium or nitrogen prior to contact with the model feed. Results are given in Table 2.

	TABLE 2

		% capacity for total sulfur
	Adsorbent	removal (wt. %)

	E	0.35
	F	0.12

Example 2 shows that the combination of beds yields more sulfur removal overall.

Example 3

The simulated diesel feed described in Table 3 (below) was passed over an adsorbent bed comprising activated charcoal and 10% Ag at ambient temperature, ambient pressure, and an LHSV of 2.2. Results are given in Table 4 (below). Breakthrough of sulfur containing compounds was noted at approximately 2.5 hr. The adsorbent bed was regenerated by passing toluene over the adsorbent bed for 2 hrs at a temperature of 100° C., an LHSV of 2.2, and ambient pressure. The simulated diesel feed of Table 3 was then passed over the regenerated bed. Results for sulfur removal for the regenerated bed run are given in Table 5.

	TABLE 3

	Alkyl Components	Wt. %

	Hexyl benzene	18.7
	Phenanthrene	1
	Hexyl-cyclohexane	5.2
	Decalin	5.2
	Hexadecane	20.6
	2,2,4,4,6,8,8-heptamethyl nonane	49.3
	Sulfur and Nitrogen Components	ppm
	Dibenzothiophene (sulfur)	50
	Dimethyldibenzothiophene (sulfur)	50
	Methyl-indoline (nitrogen)	10

	TABLE 4

	Time (hrs)	Total Sulfur concentration in effluent (ppm)

	0	0.0
	0.1	0.0
	0.3	0.0
	0.6	0.0
	1.1	0.0
	1.6	0.0
	2.2	1.0
	2.5	3.4
	2.9	68.6
	3.5	65.1
	4.1	69.1
	4.6	69.3
	5.5	73.0

	TABLE 5

	Time (hrs)	Total Sulfur concentration in effluent (ppm)

	0	0.0
	0.1	0.0
	0.3	0.0
	0.6	0.0
	1.2	0.0
	1.7	0.0
	2.3	2.6
	2.8	41.2
	3.4	63.8
	4.0	70.9
	4.7	70.5
	5.3	69.4

Claims

1. A process comprising the steps of:

a) contacting a hydrocarbon feed stream, which comprises heteroatom containing compounds, in a first adsorption zone with a first adsorbent comprising at least one transition metal and at least one inorganic oxide at a first pressure and a first temperature, in the absence of any substantial amounts of added hydrogen, to form a first effluent wherein the first effluent has a heteroatom content lower than the heteroatom content of the hydrocarbon feedstream and;

b) contacting at least a portion of the first effluent, in a second adsorption zone, with a second adsorbent comprising an amorphous inorganic oxide, a porous carbonaceous material, or combinations thereof, at a second reaction pressure and a second reaction temperature, in the absence of any substantial amounts of added hydrogen, to form a second effluent, wherein the second effluent has a heteroatom content lower than the heteroatom content of the first effluent.

2. The process of claim 1, wherein the first pressure is between about 25 psig to about 125 psig.

3. The process of claim 1, wherein the second pressure is between about 0 psig to about 50 psig.

4. The process of claim 1, wherein the first temperature is between about 100° C. to about 500° C.

5. The process of claim 1, wherein the second temperature is between about 0° C. to about 150° C.

6. The process of claim 1, wherein the first effluent has a sulfur content of less than about 50 ppm.

7. The process of claim 1, wherein the second effluent has a sulfur content of less than about 1 ppm.

8. The process of claim 1, further comprising the step of regenerating the second adsorbent by passing a desorbing liquid through said second adsorbent.

9. The process of claim 8, wherein the desorbing liquid is selected from the group consisting of aromatic solvents, paraffinic solvents, polar solvents, and combinations thereof.

10. The process of claim 9, wherein the desorbing liquid is toluene.

11. A process for desulfurizing a hydrocarbon feedstream in continuous adsorption mode in the absence of any substantial amount of added hydrogen comprising the steps of:

(a) contacting a hydrocarbon feed stream, which comprises heteroatom containing compounds, in a first adsorption zone wherein the first adsorption zone comprises at least two adsorption beds in parallel, in the absence of any substantial amounts of added hydrogen, to form a first effluent wherein the first effluent has a heteroatom content lower than the heteroatom content of the hydrocarbon feedstream and;

(b) contacting at least a portion of the first effluent, in a second adsorption zone, wherein the second adsorption zone comprises at least 2 adsorption beds in parallel, at a second reaction pressure and a second reaction temperature, in the absence of any substantial amounts of added hydrogen, to form a second effluent, wherein the second effluent has a heteroatom content lower than the heteroatom content of the first effluent.

12. The process of claim 11, wherein the first adsorbent comprising at least one transition metal and at least one inorganic oxide.

13. The process of claim 12, wherein the inorganic oxide is silica, alumina, or combinations thereof.

14. The process of claim 12, wherein the transition metal is nickel, molybdenum, or combinations thereof.

15. The process of claim 11, wherein the second adsorbent comprises an amorphous inorganic oxide, a porous carbonaceous material, or combinations thereof.

16. The process of claim 15, wherein the porous carbonaceous material is activated charcoal.

17. The process of claim 16, wherein the activated charcoal has a surface area of at least 1000 m²g.

18. The process of claim 11, wherein the hydrocarbon feedstream is selectively directed by at least one valve to one of the two or more adsorption beds of the first adsorption zone.

19. The process of claim 11, wherein at least a portion of the first effluent is selectively directed by at least one valve to one of the two or more adsorption beds of the second adsorption zone.