US20170015915A1

US20170015915A1 - Production of low sulfur gasoline

Info

Publication number: US20170015915A1
Application number: US15/202,711
Authority: US
Inventors: Mohsen N. Harandi; John P. Greeley; Michael R. Chuba; Bryan C. LU
Original assignee: ExxonMobil Research and Engineering Co
Current assignee: ExxonMobil Technology and Engineering Co
Priority date: 2015-07-17
Filing date: 2016-07-06
Publication date: 2017-01-19
Also published as: EP3325575A1; WO2017014947A1; CA2990021A1; SG10201911858XA

Abstract

Systems and methods are provided for producing naphtha boiling range fractions having a reduced or minimized amount of sulfur and an increased and/or desirable octane rating and suitable for incorporation into a naphtha fuel product. A naphtha boiling range feed can be separated to form a lower boiling portion and a higher boiling portion. The lower boiling portion, containing a substantial amount of olefins, can be exposed to an acidic catalyst without the need for providing added hydrogen in the reaction environment. Additionally, during the exposure of the lower boiling portion to the acidic catalyst, a stream of light olefins (such as C₂-C₄olefins) can be introduced into the reaction environment. Adding such light olefins can enhance the C₅+ yield and/or improve the removal of sulfur from thiophene and methyl-thiophene compounds in the naphtha feed.

Description

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims the benefit of provisional U.S. Ser. No. 62/193,646, filed Jul. 17, 2015, the entire contents of which are expressly incorporated by reference herein.

FIELD OF THE INVENTION

This disclosure provides systems and methods for desulfurizing naphtha boiling range feeds, such as feeds suitable for production of gasoline.

BACKGROUND

Many countries now require automotive gasoline fuels to have a sulfur content that satisfies a strict standard, such as 15 wppm of sulfur or less. One of the difficulties in meeting such a standard can be related to incorporating cracked naphtha fractions into gasoline. Cracked naphtha fractions can potentially be beneficial for the octane rating of a gasoline due to the presence of olefins in such fractions. However, conventional desulfurization methods for removing sulfur from naphtha fractions by hydrodesulfurization can tend to also saturate olefins, thus mitigating the benefit of using a cracked naphtha fraction.
U.S. Pat. No. 5,482,617 describes a method for removing sulfur from a naphtha fraction by exposing the naphtha fraction to a suitable zeolite without providing added hydrogen to the reaction environment. Instead, an optional light olefin feed can be provided to the reaction environment. The method is described as being suitable for achieving up to about 60% desulfurization of a cracked feed and/or reformate feed.

SUMMARY

In an aspect, a method for treating a naphtha boiling range fraction is provided, comprising: separating a feedstock to form a lower boiling fraction and a higher boiling fraction, the separated lower boiling fraction comprising a naphtha boiling range fraction, the separation being performed at a separation cut point temperature of about 160° F. (˜71° C.) to about 290° F. (˜149° C.); exposing at least a portion of the separated lower boiling fraction to an acidic catalyst without providing substantial added hydrogen under effective desulfurization conditions to form at least a desulfurized naphtha boiling range effluent having a sulfur content of about 90 wppm or less, the effective desulfurization conditions including a pressure of at least about 150 psia (about 1.0 MPaa); and exposing at least a portion of the separated higher boiling fraction to a hydrotreating catalyst under effective hydrotreating conditions to form a hydrotreated effluent having a sulfur content of about 15 wppm or less.
In another aspect, a method for treating a naphtha boiling range fraction is provided, comprising: separating a feedstock to form a lower boiling fraction and a higher boiling fraction, the separated lower boiling fraction comprising a naphtha boiling range fraction, the separation being performed at a separation cut point temperature of about 170° F. (˜77° C.) to about 270° F. (˜132° C.); exposing at least a portion of the separated lower boiling fraction and a C₂-C₄olefin stream to an acidic catalyst without providing substantial added hydrogen under effective desulfurization conditions to form at least a desulfurized naphtha boiling range effluent having a sulfur content of about 90 wppm or less, the effective desulfurization conditions including a pressure of at least about 150 psia (about 1.0 MPaa); and exposing at least a portion of the separated higher boiling fraction to a hydrotreating catalyst under effective hydrotreating conditions to form a hydrotreated effluent having a sulfur content of about 15 wppm or less.
In still another aspect, a method for treating a naphtha boiling range fraction is provided, comprising: separating a feedstock to form a lower boiling fraction and a higher boiling fraction, the separated lower boiling fraction comprising a naphtha boiling range fraction, the separation being performed at a separation cut point temperature of about 160° F. (˜71° C.) to about 300° F. (˜149° C.), the separated lower boiling fraction comprising at least about 10 wppm of thiophene, methyl thiophene, or a combination thereof, the separated lower boiling fraction further comprising about 50 wppm or less of sulfur contained in C₂+ thiophenes; exposing at least a portion of the separated lower boiling fraction to an acidic catalyst without providing substantial added hydrogen under effective desulfurization conditions to form at least a desulfurized naphtha boiling range effluent having a sulfur content of about 90 wppm or less, the effective desulfurization conditions including a pressure of at least about 150 psia (about 1.0 MPaa); and exposing at least a portion of the separated higher boiling fraction to a hydrotreating catalyst under effective hydrotreating conditions to form a hydrotreated effluent having a sulfur content of about 15 wppm or less.

BRIEF DESCRIPTION OF THE FIGURES

FIG. 1 shows an example of a reaction system for processing a naphtha boiling range feed according to an aspect of the invention.

FIG. 2 shows results from processing an FCC naphtha fraction according to a method described herein.

DETAILED DESCRIPTION

In various aspects, systems and methods are provided for producing naphtha boiling range fractions suitable for incorporation into a naphtha fuel product. The naphtha boiling range fractions produced according to methods described herein can have a reduced or minimized amount of sulfur and an increased and/or desirable octane rating. For example, a naphtha boiling range feed can be separated to form a lower boiling portion and a higher boiling portion. The lower boiling portion, containing a substantial amount of olefins, can be exposed to an acidic catalyst, such as a zeolite, without the need for providing added hydrogen in the reaction environment. This can allow for sulfur removal while reducing or minimizing the amount of olefin saturation. Additionally, during the exposure of the lower boiling portion to the acidic catalyst, a stream of light olefins (such as C₂-C₄olefins) can be introduced into the reaction environment. Adding such light olefins can enhance the C₅+ yield and/or improve the removal of sulfur from sulfur species such as thiophene and methyl-thiophene compounds in the naphtha feed. The processing of the lower boiling portion can also result in a decrease in the Reid Vapor Pressure (RVP) of the final naphtha product. The higher boiling portion, which can contain a substantial portion of the sulfur from the original feed, can be hydrotreated under effective hydrotreating conditions for sulfur removal to a desired level, such as 10 wppm or less. After the separate processing of the lower boiling and higher boiling portions, the lower boiling and higher boiling portions can optionally be combined for use, such as use as part of a gasoline pool. The resulting naphtha product from combining the processed lower boiling and higher boiling portions can have a desired sulfur content, such as 10 wppm or less, while also having an improved octane rating relative to a conventionally processed naphtha fraction.
In this discussion, “thiophene”, unless otherwise specified, refers to the 5-member ring compound having the chemical formula C₄H₄S. In this discussion, unless otherwise specified, a reference to a “C_Xthiophene” refers to a substituted thiophene, where the substituent has the specified number (X) of carbons. In this discussion, unless otherwise specified, a reference to a “C_X+ thiophene” refers to a substituted thiophene, where the substituent has at least the specified number (X) of carbons. For C_X+ thiophenes, it is noted that benzothiophene represents a substituted thiophene having 4 carbons in the substituent. In this discussion, unless otherwise specified, a reference to a “C_Xalkyl-substituted thiophene” or a “C_X+ alkyl-substituted thiophene” refers to a thiophene with an alkyl substituent having X (or alternatively at least X) carbons.

Feedstock

In the discussion herein, reference is made to naphtha boiling range fractions (including feeds, products, or streams) and distillate boiling range fractions (including feeds, products, or streams). The naphtha boiling range can be defined based on an initial boiling point and/or the temperature at which 5 wt % of the feed can boil (T5 boiling point). In some aspects, an initial boiling point and/or a T5 boiling point can correspond to about the boiling point for a C₅alkane. In this type of alternative, it is noted that n-pentane boils at about 36° C., isopentane boils at about 28° C., and neopentane boils at about 10° C. Thus, an initial boiling point or a temperature at which 5 wt % of the feed can boil can correspond to any of the above boiling points for C₅alkanes. In other embodiments, the initial boiling point and/or the T5 boiling point can be higher, such as at least about 50° C. Additionally or alternately, the naphtha boiling range can be defined based on a final boiling point and/or the temperature at which 95 wt % of the feed can boil (T95 boiling point) and/or the temperature at which 90 wt % of the feed can boil (T90 boiling point). In some aspects, the final boiling point and/or the T95 boiling point and/or the T90 boiling point can be about 450° F. (˜232° C.) or less, such as about 400° F. (˜204° C.) or less. As an example, the maximum naphtha boiling range based on the above definitions is a range from about the boiling point of neopentane (about 50° F. or ˜10° C.) to about 450° F. (˜232° C.). For a distillate boiling range feed, a feed can have a boiling range (Initial or T5 to T95 or final) of from about 300° F. (˜149° C.) to about 800° F. (˜427° C.). For example, a distillate feed that includes a kerosene portion as part of feed can have an initial boiling point and/or temperature at which 5 wt % of the feed can boil of at least about 300° F. (˜149° C.), such as at least about 350° F. (˜177° C.). If a kerosene portion is not included in the distillate feed, the feed can have an initial boiling point and/or temperature at which 5 wt % of the feed can boil of at least about 400° F. (˜204° C.), such as at least about 450° F. (˜232° C.).
With regard to olefin content, suitable feedstocks can include feedstocks having a wide range olefin content. Some types of feeds, such as a feed based on a naphtha boiling range output from a hydrocracking process, can have an olefin content of less than about 250 wppm, such as less than about 200 wppm. Other types of feeds, such as a feed based on the naphtha boiling range output from a coker, can have olefin contents between about 1 wt % to about 25 wt %. Still other types of feeds, such as a feed based on the naphtha boiling range output from a fluid catalytic cracking unit, can have an olefin content from about 15 wt % to about 40 wt %, such as about 30 wt % or less. For some olefinic naphthas, still higher olefin contents may be possible, such as up to about 60 wt % or less or even about 70 wt % or less. Non-limiting examples of suitable feedstocks can include fluid catalytic cracking unit naphtha (FCC catalytic naphtha or cat naphtha), steam cracked naphtha, coker naphtha, or a combination thereof. This can include blends of olefinic naphthas (olefin content of at least about 5 wt %) with non-olefinic naphthas (olefin content of about 5 wt % or less). In some aspects, a naphtha feed for processing as described herein (including a feed corresponding to a blend of one or more olefinic naphthas with one or more non-olefinic naphthas) can have an olefin content of at least about 5 wt %, or at least about 10 wt %, or at least about 15 wt %, or at least about 20 wt %, and/or about 70 wt % or less, or about 60 wt % or less, or about 50 wt % or less. Olefinic naphtha refinery streams generally contain not only paraffins, naphthenes, and aromatics, but also unsaturates, such as open-chain and cyclic olefins, dienes, and cyclic hydrocarbons with olefinic side chains. An olefinic naphtha feedstock can also have a diene concentration up to about 15 wt %, but more typically less than about 5 wt % based on the total weight of the feedstock. High diene concentrations in gasoline blend stocks can be undesirable since they can result in a gasoline product having poor stability and color.
The sulfur content of a naphtha feedstock that has not been previously exposed to a hydrodesulfurization and/or hydrocracking process can be at least about 100 wppm, or at least about 500 wppm, or at least about 1000 wppm, or at least about 1500 wppm. In another embodiment, the sulfur content can be about 7000 wppm or less, or about 6000 wppm or less, or about 5000 wppm or less, or about 3000 wppm or less. The sulfur can typically be present as organically bound sulfur. That is, as sulfur compounds such as simple aliphatic, naphthenic, and aromatic mercaptans, sulfides, di- and polysulfides and the like. Other organically bound sulfur compounds include the class of heterocyclic sulfur compounds such as thiophene and its higher homologs and analogs.
Nitrogen can also be present in the feed. In an aspect, the amount of nitrogen can be at least about 5 wppm, or at least about 10 wppm, or at least about 20 wppm, or at least about 40 wppm. In another aspect, the nitrogen content can be about 250 wppm or less, or about 150 wppm or less, or about 100 wppm or less, or about 50 wppm or less.
Additionally or alternately, a feedstock can include a naphtha boiling range portion of an effluent from a non-selective hydrodesulfurization process. This includes non-selective hydrodesulfurizations of naphtha boiling range feeds as well as hydrodesulfurizations of wider boiling range feeds that include, for example, both a naphtha boiling range portion and a higher boiling range portion.

Fractionation of Naphtha Boiling Range Feed

In order to produce a naphtha boiling range product having a desirable combination of sulfur content, RVP, and octane rating, a naphtha boiling range feed can initially be fractionated to form a lower boiling fraction and a higher boiling fraction. It has also been unexpectedly discovered that small variations in the fractionation temperature and/or the quality of fractionation into a lower boiling and higher boiling portion can lead to substantial improvements in the properties of a resulting naphtha product after processing, such as the sulfur content in the naphtha product. For example, controlling the fractionation can allow C₂+ thiophenes (such as ethyl thiophenes) to be excluded from the lower boiling portion while retaining thiophene and methyl thiophenes. This can allow sulfur-containing compounds difficult to remove to be reduced or minimized in the lower boiling portion. Higher reactivity of methyl thiophenes and lower boiling sulfur compounds over zeolite catalysts can be complemented with higher olefin concentrations in this fraction, which can allow for improvements in desulfurization, octane improvement and RVP reduction, optionally all at the same time.
In this discussion, reference is made to a “lower boiling portion/fraction” and “a higher boiling portion/fraction”. It is understood that a lower boiling portion can include multiple portions or fractions based on additional fractionation at temperatures (i.e., cut points) below the temperature for forming the lower boiling portion, and that similarly a higher boiling portion can include multiple portions or fractions based on additional fractionation at temperatures above the temperature for forming the higher boiling portion.
One consideration for performing a suitable fractionation or separation can be to perform a fractionation at a suitable temperature. In various aspects, the fractionation or separation temperature (sometimes referred to as a fractionation or separation cut point temperature) for forming a lower boiling naphtha fraction and a higher boiling naphtha fraction can be about 300° F. (˜149° C.) or less, or about 270° F. (˜132° C.) or less, or about 250° F. (˜121° C.) or less, or about 240° F. (˜116° C.) or less, or about 225° F. (˜107° C.) or less, or about 210° F. (˜99° C.) or less. Optionally, the fractionation temperature can be at least about 160° F. (˜71° C.), or at least about 170° F. (˜77° C.), or at least about 180° F. (˜82° C.).
Selecting a suitable fractionation temperature can assist with making a desired naphtha boiling range product based in part on the nature of the distribution of olefins and/or sulfur within the various compounds in a naphtha boiling range feed. In a naphtha boiling range feed, a substantial portion of the olefins present in the feed can correspond to olefinic compounds having a boiling point of about 225° F. (˜107° C.) or less, or about 210° F. (˜99° C.) or less, or about 205° F. (˜96° C.) or less, or about 200° F. (˜93° C.) or less, or about 190° F. (˜88° C.) or less, or about 180° F. (˜82° C.) or less. The amount of olefinic compounds having such a boiling point can correspond to about 20% to 80% of the total weight of olefinic compounds in a naphtha feed. For example, a naphtha boiling range feed can be separated to form a lower boiling portion and higher boiling portion at a fractionation temperature of about 300° F. (˜149° C.) or less, 270° F. (˜132° C.) or less, or about 250° F. (˜121° C.) or less, or about 240° F. (˜116° C.) or less, or about 225° F. (˜107° C.) or less, or about 210° F. (˜99° C.) or less and/or at least about 160° F. (˜71° C.), or at least about 170° F. (˜77° C.), or at least about 180° F. (˜82° C.). After such a fractionation, the weight of olefins in the lower boiling portion can correspond to about 20% to about 80% of the weight of olefins present in the feed prior to fractionation, such as about 20% to about 40%, or about 20% to about 50%, or about 20% to about 60%, or about 20% to about 70%, or about 20% to about 80%, or about 30% to about 40%, or about 30% to about 50%, or about 30% to about 60%, or about 30% to about 70%, or about 30% to about 80%, or about 40% to about 50%, or about 40% to about 60%, or about 40% to about 70%, or about 40% to about 80%, or about 50% to about 60%, or about 50% to about 70%, or about 50% to about 80%, or about 60% to about 80%.
An alternative way of characterizing the amount of olefins in a lower boiling portion can be based on the weight percent of olefins in the lower boiling portion relative to the weight of the lower boiling portion. In such an alternative, the weight percentage of olefins in the lower boiling portion (based on the total weight of the lower boiling portion) can be about 20 wt % to about 40 wt %, or about 20 wt % to about 50 wt %, or about 20 wt % to about 60 wt %, or about 20 wt % to about 70 wt %, or about 20 wt % to about 80 wt %, or about 30 wt % to about 40 wt %, or about 30 wt % to about 50 wt %, or about 30 wt % to about 60 wt %, or about 30 wt % to about 70 wt %, or about 30 wt % to about 80 wt %, or about 40 wt % to about 50 wt %, or about 40 wt % to about 60 wt %, or about 40 wt % to about 70 wt %, or about 40 wt % to about 80 wt %, or about 50 wt % to about 60 wt %, or about 50 wt % to about 70 wt %, or about 50 wt % to about 80 wt %, or about 60 wt % to about 80 wt %.
Based on selecting a suitable fractionation temperature, a substantial portion of the olefins in a naphtha boiling range feed can be separated into a lower boiling fraction not exposed to hydrotreatment conditions. This can reduce or minimize the amount of olefin saturation performed on the lower boiling portion, which can provide a benefit in the octane rating of the resulting naphtha boiling range product.
Another factor in selecting a fractionation temperature can be the distribution of sulfur-containing compounds in the feed. A substantial portion of the sulfur present in a naphtha boiling range feed can be present in compounds with a boiling point of at least about 200° F. (˜93° C.), or at least about 205° F. (˜96° C.), or at least about 210° F. (˜99° C.), or at least about 225° F. (˜107° C.), or at least about 240° F. (˜116° C.). Additionally or alternately, the nature of the sulfur compounds in a higher boiling portion of a feed can tend to correspond to sulfur compounds more difficult to remove. A lower boiling portion of a naphtha boiling range feed can tend to contain sulfur containing compounds such as mercaptans or sulfides which are relatively easier to convert into H₂S for eventual separation and removal of the sulfur. Thiophenes, such as alkyl-substituted thiophenes, are examples of compounds with higher boiling points that contain sulfur that conventionally can be more difficult to convert. However, it has been discovered that thiophenes and C₁thiophenes (i.e., methyl-thiophenes) can be substantially removed from a naphtha feed under sufficiently high pressures and/or in the presence of an additional olefin stream. Selecting an appropriate fractionation temperature can reduce or minimize the amount of sulfur compounds difficult to convert in the lower boiling portion of a naphtha feed while providing sufficient olefinicity. For example, the amount of alkyl-substituted thiophenes present in a lower boiling portion of a naphtha feed, and/or the amount of alkyl-substituted thiophenes having alkyl substitution containing two or more carbons (C₂+ alkyl-substituted thiophenes), can be limited by performing an appropriate fractionation. Such compounds can instead be separated into the higher boiling portion, where the sulfur removal can be performed by exposing the compounds to a hydrotreating catalyst under effective hydrotreating conditions. The proposed operation can advantageously increase or maximize the amount of olefins entering into the zeolite desulfurization zone while reducing or minimizing the amount of olefins entering a hydroprocessing zone that can (disadvantageously) saturate olefins to lower octane paraffins.
In various aspects, the sulfur content of a lower boiling portion that corresponds to sulfur contained in C₂+ alkyl-substituted thiophenes can be about 300 wppm or less, or about 100 wppm or less, or about 90 wppm or less, or about 75 wppm or less, or about 50 wppm or less, or about 30 wppm or less, or about 20 wppm or less, and or at least about 1 wppm, or at least about 10 wppm. Additionally or alternately, the sulfur content of a lower boiling portion that corresponds to sulfur contained in C₃+ alkyl-substituted thiophenes in the lower boiling portion can be about 100 wppm or less, or about 50 wppm or less, or about 30 wppm or less, or about 20 wppm or less, or about 15 wppm or less, or about 10 wppm or less, and/or at least about 1 wppm, or at least about 10 wppm.
One option for controlling the amount of C₂+ thiophenes (such as C₂+ alkyl-substituted thiophenes) present in a lower boiling portion can be to control the sharpness of the separation or fractionation used for forming the lower boiling portion. In other words, in addition to selecting a suitable cut point temperature for performing a fractionation, another consideration in forming a lower boiling portion and a higher boiling portion can be performing the fractionation to reduce or minimize the amount of overlap in the boiling ranges for the lower boiling portion and the higher boiling portion. In a typical fractionation procedure, a “cut point” or target separation temperature can be selected to roughly determine the composition of a higher boiling and a lower boiling portion. However, fractionation of a feed is rarely ideal, so there can typically be some overlap between the resulting boiling ranges for a lower boiling and a higher boiling fraction. For example, at a cut point of 200° F. (93° C.), a typical fractionation could lead to a lower boiling fraction that has a T95 boiling point greater than 200° F. and/or a higher boiling fraction with a T5 boiling point of less than 200° F. As another example, a typical fractionation with a 200° F. cut point could result in a lower boiling fraction with a final boiling point of at least about 210° F. (˜99° C.) and/or a higher boiling portion an initial boiling point of less than about 190° F. (˜88° C.).
One of the difficulties in performing an ideal separation can be related to the vapor pressure of various compounds in a mixture being separated. For example, the boiling point of 2-ethyl thiophene is roughly 132° C. (˜270° F.). This means that 2-ethyl thiophene can have a substantial vapor pressure at temperatures above 250° F. (121° C.). As a result, it can be difficult to completely exclude ethyl thiophenes and/or other C₂+ thiophenes from a lower boiling fraction. However, the C₂+ thiophene content of a lower boiling fraction can be reduced or minimized by controlling the nature of the separation. Because C₂+ thiophenes (and other higher boiling sulfur compounds) can have a lower reactivity for a non-hydrogen-assisted sulfur removal process as described herein, removing sulfur from such compounds can be difficult. As a result, achieving a desired target sulfur content in the lower boiling fraction can be assisted by controlling the separation that forms the lower boiling fraction to reduce or minimize the amount of C₂+ alkylthiophenes, benzo-thiophenes, and/or other higher boiling sulfur compounds in the lower boiling fraction.
In various aspects, a fractionation of a naphtha boiling range feed can be performed using a separation device with sufficient separation power to provide a relatively narrow difference between a selected fractionation temperature and the actual final boiling point/initial boiling point of the respective fractions formed by the separation. An example of a fractionator for performing a separation with reduced or minimized overlap in the boiling ranges of the resulting fractions can be a distillation column having a separating efficiency equivalent to at least about 20 trays, or at least about 30 trays, or at least about 40 trays, or at least about 50 trays. In some aspects, a fractionation can be characterized based on the difference between the initial boiling point of the resulting higher boiling fraction and the final boiling point of the resulting lower boiling fraction. In such aspects, the difference between the initial boiling point of a higher boiling fraction and the final boiling point of a resulting lower boiling fraction can be about 40° F. (˜21° C.) or less, or about 30° F. (˜17° C.) or less, or about 25° F. (˜14° C.) or less, or about 20° F. (˜11° C.) or less, or about 15° F. (˜8° C.) or less, or about 10° F. (˜6° C.) or less. In other aspects, a fractionation can be characterized based on the difference between a T95 boiling point for the lower boiling fraction and the T5 boiling point for the higher boiling fraction. In such aspects, the difference between the T95 boiling point of the lower boiling fraction and the T5 boiling point of the higher boiling fraction can be about 40° F. (˜22° C.) or less, or about 30° F. (˜17° C.) or less, or about 25° F. (˜14° C.) or less, or about 20° F. (˜11° C.) or less, or about 15° F. (˜8° C.) or less, or about 10° F. (˜6° C.) or less. Additionally or alternately, in such aspects, the T5 boiling point for the higher boiling fraction can be greater than the T95 boiling point for the lower boiling fraction, or at least 5° F. (˜3° C.) greater, or at least 10° F. (˜6° C.) greater. Such fractionation can be optimized based on the sulfur target in a gasoline pool, sulfur reduction severity, feed sulfur content and distribution, and/or processing costs such as capital equipment costs and energy costs.

Acidic Catalyst Sulfur Removal (with No Requirement for Added Hydrogen)

In various aspects, sulfur can be removed from the lower boiling portion of a naphtha feed by exposing the lower boiling portion to an acidic catalyst (such as a zeolite) under effective conditions. Optionally, the zeolite or other acidic catalyst can also include a hydrogenation functionality, such as a Group VIII metal or other suitable metal that can activate hydrogenation/dehydrogenation reactions. The lower boiling portion can be exposed to the acidic catalyst without providing substantial additional hydrogen to the reaction environment. Added hydrogen refers to hydrogen introduced as an input flow to the process, as opposed to any hydrogen that might be generated in-situ during processing. Exposing the feed to an acidic catalyst without providing substantial added hydrogen is defined herein as exposing the feed to the catalyst in the presence of a) less than about 100 SCF/bbl of added hydrogen, or less than about 50 SCF/bbl; b) a partial pressure of less than about 50 psig (˜350 kPag), or less than about 15 psig (˜100 kPag) of hydrogen; or c) a combination thereof.
Although additional hydrogen is not required, in various aspects performing the desulfurization process at a sufficiently high pressure can be valuable for allowing effective desulfurization of thiophenes and C₁thiophenes. In various aspects, the pressure in the reaction environment can be at least about 150 psia (˜1.0 MPaa), or at least about 170 psia (˜1.2 MPaa), or at least about 180 psia (˜1.24 MPaa), or at least about 200 psia (˜1.4 MPaa).
Additionally or alternately, the lower boiling portion can be exposed to the acidic catalyst in the presence of an additional stream containing light olefins, such as C₂-C₄olefins. The weight hourly space velocity of the additional light olefin stream can be about 0.1 hr⁻¹to about 1.0 hr⁻¹, or about 0.1 hr⁻¹to about 0.75 hr⁻¹, or about 0.1 hr⁻¹to about 0.6 hr⁻¹.
In various aspects, the conditions for exposing the lower boiling feed to the acidic catalyst without a substantial portion of added hydrogen can be effective for reducing the sulfur content of the lower boiling portion to about 100 wppm or less, or about 90 wppm or less, or about 75 wppm or less, or about 50 wppm or less, or about 30 wppm or less, or about 20 wppm or less, or about 10 wppm or less. Additionally or alternately, the conditions can be effective for achieving at least about 70% desulfurization of the lower boiling portion, or at least about 75%, or at least about 80%, or at least about 85%. Without being bound by any particular theory, it is believed that reducing the sulfur content to a desired level and/or achieving at least a desired percentage of desulfurization can be achieved in part by performing the desulfurization at a sufficiently high pressure, by reducing or minimizing the content of C₂+ thiophenes in the feed, by introducing an additional olefin stream into the reaction environment, or a combination thereof.
When a light olefins (or light olefin-containing) stream is also introduced into the reaction environment, a further optional benefit can be provided by increasing the C₅+ content of the reactor effluent. In addition to performing desulfurization, the reaction conditions can also allow for olefin oligomerization. The oligomerization can result in conversion of high RVP components such as pentenes, which can lead to a reduction in the Reid Vapor Pressure (RVP) of the overall combined naphtha product. The reduction in RVP can be from about 0.1 psi to about 4.0 psi. Examples of refinery streams that can contain light olefins (C₂-C₄olefins) include fuel gas streams from a coker or a fluid catalytic cracking (FCC) process.
The acidic catalyst used in the desulfurization process described herein can be a zeolite-based catalyst, that is, it can comprise an acidic zeolite in combination with a binder or matrix material such as alumina, silica, or silica-alumina, and optionally further in combination with a hydrogenation metal. More generally, the acidic catalyst can correspond to a molecular sieve (such as a zeolite) in combination with a binder, and optionally a hydrogenation metal. Molecular sieves for use in the catalysts can be medium pore size zeolites, such as those having the framework structure of ZSM-5, ZSM-11, ZSM-12, ZSM-22, ZSM-23, ZSM-35, ZSM-48, or MCM-22. Such molecular sieves can have a 10-member ring as the largest ring size in the framework structure. The medium pore size zeolites are a well-recognized class of zeolites and can be characterized as having a Constraint Index of 1 to 12. Constraint Index is determined as described in U.S. Pat. No. 4,016,218 incorporated herein by reference. Catalysts of this type are described in U.S. Pat. Nos. 4,827,069 and 4,992,067 which are incorporated herein by reference and to which reference is made for further details of such catalysts, zeolites and binder or matrix materials.
Additionally or alternately, catalysts based on large pore size framework structures (12-member rings) such as the synthetic faujasites, especially zeolite Y, such as in the form of zeolite USY. Zeolite beta may also be used as the zeolite component. Other materials of acidic functionality which may be used in the catalyst include the materials identified as MCM-36 and MCM-49. Still other materials can include other types of molecular sieves having suitable framework structures, such as silicoaluminophosphates (SAPOs), aluminosilicates having other heteroatoms in the framework structure, such as Ga, Sn, or Zn, or silicoaluminophosphates having other heteroatoms in the framework structure. Mordenite or other solid acid catalysts can also be used as the catalyst.
The exposure of the lower boiling portion to the acidic catalyst can be performed in any convenient manner, such as exposing the lower boiling portion to the acidic catalyst under fluidized bed conditions. In some aspects, the particle size of the catalyst can be selected in accordance with the fluidization regime which is used in the process. Particle size distribution can be important for maintaining turbulent fluid bed conditions as described in U.S. Pat. No. 4,827,069 and incorporated herein by reference. Suitable particle sizes and distributions for operation of dense fluid bed and transport bed reaction zones are described in U.S. Pat. Nos. 4,827,069 and 4,992,607 both incorporated herein by reference. Particle sizes in both cases can normally be in the range of 10 to 300 microns, typically from 20 to 100 microns.
Thus, acidic zeolite catalysts suitable for use as described herein can be those exhibiting high hydrogen transfer activity and having a zeolite structure of ZSM-5, ZSM-11, ZSM-12, ZSM-22, ZSM-23, ZSM-35, ZSM-48, MCM-22, MCM-36, MCM-49, zeolite Y, and zeolite beta. Such catalysts can be capable of converting organic sulfur compounds such as thiophenes and mercaptans to hydrogen sulfide without added hydrogen by utilizing hydrogen present in the hydrocarbon feed. Group VIII metals such as nickel may be used as desulfurization promoters. Such catalysts can also be capable of simultaneously converting light olefins present in a fuel gas to more valuable gasoline range material. A fluid-bed reactor/regenerator can assist with maintaining catalyst activity in comparison with a fixed-bed system. Further, the hydrogen sulfide produced in accordance with the present invention can be removed using conventional amine based absorption processes.
ZSM-5 crystalline structure is readily recognized by its X-ray diffraction pattern, which is described in U.S. Pat. No. 3,702,866. ZSM-11 is disclosed in U.S. Pat. No. 3,709,979, ZSM-12 is disclosed in U.S. Pat. No. 3,832,449, ZSM-22 is disclosed in U.S. Pat. No. 4,810,357, ZSM-23 is disclosed in U.S. Pat. Nos. 4,076,842 and 4,104,151, ZSM-35 is disclosed in U.S. Pat. No. 4,016,245, ZSM-48 is disclosed in U.S. Pat. No. 4,375,573 and MCM-22 is disclosed in U.S. Pat. No. 4,954,325. The U.S. patents identified in this paragraph are incorporated herein by reference.
While suitable zeolites having a coordinated metal oxide to silica molar ratio of 20:1 to 200:1 or higher may be used, it can be advantageous to employ aluminosilicate ZSM-5 having a silica:alumina molar ratio of about 25:1 to 70:1, suitably modified. A typical zeolite catalyst component having Bronsted acid sites can comprises, consist essentially of, or consist of crystalline aluminosilicate having the structure of ZSM-5 zeolite with 5 to 95 wt % silica, clay and/or alumina binder.
These siliceous zeolites can be employed in their acid forms, ion-exchanged or impregnated with one or more suitable metals, such as Ga, Pd, Zn, Ni, Co, Mo, P, and/or other metals of Periodic Groups III to VIII. The zeolite may include other components, generally one or more metals of group IB, IIB, IIIB, VA, VIA or VIIIA of the Periodic Table (IUPAC).
Useful hydrogenation components can include the noble metals of Group VIIIA, such as platinum, but other noble metals, such as palladium, gold, silver, rhenium or rhodium, may also be used. Base metal hydrogenation components may also be used, such as nickel, cobalt, molybdenum, tungsten, copper or zinc.
The catalyst materials may include two or more catalytic components which components may be present in admixture or combined in a unitary multifunctional solid particle.
In addition to the preferred aluminosilicates, the gallosilicate, ferrosilicate and “silicalite” materials may be employed. ZSM-5 zeolites can be useful in the process because of their regenerability, long life and stability under the extreme conditions of operation. Usually the zeolite crystals have a crystal size from about 0.01 to over 2 microns or more, such as 0.02-1 micron.
In various aspects, the fluidized bed catalyst particles can contain about 25 wt % to about 40 wt % H-ZSM-5 zeolite, based on total catalyst weight, contained within a silica-alumina matrix. Typical Alpha values for the catalyst can be about 100 or less. Sulfur conversion to hydrogen sulfide can increase as the alpha value increases.
In a fixed bed embodiment the catalyst may consist of a standard 70:1 aluminosilicate H-ZSM-5 extrudate having an acid value (alpha value) of at least 20, preferably 150 or higher.
The Alpha Test is described in U.S. Pat. No. 3,354,078, and in the Journal of Catalysis, Vol. 4, p. 527 (1965); Vol. 6, p. 278 (1966); and Vol. 61, p. 395 (1980), each incorporated herein by reference as to that description.
The effective desulfurization conditions for exposing the lower boiling portion of a feed to an acidic catalyst can include a temperature of about 400° F. (˜204° C.) to about 1200° F. (˜649° C.), or about 500° F. (˜260° C.) to about 900° F. (˜482° C.), or about 700° F. (˜371° C.) to about 850° F. (˜454° C.); a pressure of about 150 psia (˜1.0 MPaa) to about 750 psia (˜5.2 MPaa), or about 170 psia (˜1.2 MPaa) to about 600 psia (˜4.1 MPaa); and a weight hourly space velocity of about 0.05 to about 10 hr⁻¹, or about 0.1 to about 2 hr⁻¹.

Example of Reaction Configuration

In FIG. 1, an example of a reaction system for conversion of a feed including a naphtha boiling range portion is shown. An initial feed 105 can be separated or fractionated 110 to generate at least one or more lower boiling portions 112 and one or more higher boiling portions 118. If the initial feed 105 contains portions above the naphtha boiling range, such as portions in a kerosene boiling range or a distillate boiling range, the one or more higher boiling portions can optionally also include such portions, or kerosene and/or distillate boiling range portions can be excluded so that the one or more higher boiling portions correspond to naphtha boiling range portion(s). The one or more lower boiling portions 112 can be passed into a reactor 120, such as a fluidized bed reactor, for exposure to an acidic catalyst without the presence of substantial added hydrogen, as described herein. An optional light olefins stream 123, such as a FCC and/or coker fuel gas, can also be introduced into reactor 120. The reactor 120 can represent multiple reactors and/or reaction stages. The reaction products in the effluent from the reactor 120 can include a stream 131 corresponding to C₂and lighter compounds, a stream 133 corresponding to a mixture of olefinic and non-olefinic compounds, and a light olefinic naphtha 137. In some aspects, based on the nature of the reaction conditions in reactor 120, the light olefinic naphtha 137 can retain a substantial portion of the olefins present in the one or more lower boiling portions 112. In other aspects, the olefins retained in the one or more lower boiling portions can correspond to a minor portion of the olefins. The effluent from reactor 120 can optionally be separated or fractionated to separate the light olefinic naphtha 137 from the other portions of the effluent.
The one or more higher boiling portions 118 can be introduced into reactor hydrotreatment 140, along with a hydrogen-containing stream 141. The reactor 140 can represent multiple reactors and/or reaction stages. Reactor 140 can include one or more beds of a hydrotreating catalyst, hydrocracking catalyst, or a combination thereof. The one or more higher boiling portions can be exposed to the catalyst in reactor 140 in the presence of the hydrogen under effective conditions for performing hydroprocessing. The effluent from reactor 140 can then be separated in one or more separation stages to produce at least a desulfurized (heavy) naphtha product 157 and one or more streams 151 containing light ends, contaminant gases generated during hydrotreatment such as H₂S, and/or excess hydrogen. Optionally, the (heavy) naphtha product 157 and the light olefinic product 137 can then be combined, such as combining the products 157 and 137 as part of a combined product or as a part of a gasoline pool.

Hydrodesulfurization of Naphtha Feed

In various aspects, the higher boiling portion of a naphtha boiling range feed can be hydrotreated (sometimes referred to as hydrodesulfurized) to reduce the sulfur content of the higher boiling portion. Such a hydrodesulfurization process can correspond to a selective or a non-selective hydrodesulfurization process. A selective hydrodesulfurization process can refer to a process where the hydrotreatment catalyst and/or the hydrotreatment conditions are selected based on a desire to preserve the olefin content of the hydrotreated product. A non-selective hydrodesulfurization process can refer to a process where a substantial portion of the olefins present in an naphtha feed are saturated during hydrodesulfurization. While a selective hydrodesulfurization process can be used to treat the higher boiling portion, it is not necessary.
A (optionally selective) hydrodesulfurization process can be performed in any suitable reaction system. The hydrodesulfurization can be performed in one or more fixed bed reactors, each of which can comprise one or more catalyst beds of the same, or different, hydrodesulfurization catalyst. Optionally, more than one type of catalyst can be used in a single bed. Although other types of catalyst beds can be used, fixed beds are preferred. Non-limiting examples of such other types of catalyst beds that may be used in the practice of the present invention include fluidized beds, ebullating beds, slurry beds, and moving beds. Interstage cooling between reactors, or between catalyst beds in the same reactor, can be employed since some olefin saturation can take place, and olefin saturation as well as the desulfurization reaction are generally exothermic. A portion of the heat generated during hydrodesulfurization can be recovered by conventional techniques. Where this heat recovery option is not available, conventional cooling may be performed through cooling utilities such as cooling water or air, or by use of a hydrogen quench stream. In this manner, optimum reaction temperatures can be more easily maintained.
In various embodiments, suitable (optionally selective) hydrodesulfurization catalysts include catalysts comprised of at least one Group VIII metal oxide, preferably an oxide of a metal selected from selected from Co and/or Ni, more preferably Co; and at least one Group VI metal oxide, preferably an oxide of a metal selected from Mo and W, more preferably Mo, on a support material, such as silica or alumina. Other suitable hydrotreating catalysts include zeolitic catalysts, as well as noble metal catalysts where the noble metal is selected from Pd and Pt. It is within the scope of the present invention that more than one type of hydrotreating catalyst be used in the same reaction vessel. The Group VIII metal oxide of a selective hydrodesulfurization catalyst can be present in an amount ranging from about 0.1 to about 20 wt %, preferably from about 1 to about 12%. The Group VI metal oxide can be present in an amount ranging from about 1 to about 50 wt %, preferably from about 2 to about 20 wt %. All metal oxide weight percents are on support. By “on support” we mean that the percents are based on the weight of the support. For example, if the support were to weigh 100 g. then 20 wt % Group VIII metal oxide would mean that 20 g. of Group VIII metal oxide is on the support.
The hydrodesulfurization catalysts can be supported catalysts. Any suitable refractory catalyst support material, such as inorganic oxide support materials, can be used as supports for the catalyst of the present invention. Non-limiting examples of suitable support materials include: zeolites, alumina, silica, titania, calcium oxide, strontium oxide, barium oxide, carbons, zirconia, magnesia, diatomaceous earth, lanthanide oxides including cerium oxide, lanthanum oxide, neodynium oxide, yttrium oxide, and praesodymium oxide; chromia, thorium oxide, urania, niobia, tantala, tin oxide, zinc oxide, and aluminum phosphate. Preferred are alumina, silica, and silica-alumina. It is to be understood that the support material can also contain small amounts of contaminants, such as Fe, sulfates, silica, and various metal oxides that can be introduced during the preparation of the support material. These contaminants are present in the raw materials used to prepare the support and can preferably be present in amounts less than about 1 wt %, based on the total weight of the support. It is more preferred that the support material be substantially free of such contaminants. In another embodiment, about 0 to about 5 wt %, preferably from about 0.5 to about 4 wt %, and more preferably from about 1 to about 3 wt % of an additive can be present in the support, which additive is selected from the group consisting of phosphorus and metals or metal oxides from Group IA (alkali metals) of the Periodic Table of the Elements.
Generally, (optionally selective) hydrodesulfurization conditions can include temperatures from about 425° F. (˜218° C.) to about 800° F. (˜427° C.), or about 500° F. (˜260° C.) to about 675° F. (˜357° C.). Other (optionally selective) hydrodesulfurization conditions can include a pressure of from about 60 psig (˜410 kPag) to about 800 psig (˜5.5 MPag), preferably from about 200 psig (˜1.4 MPag) to about 500 psig (˜3.4 MPag), more preferably from about 250 psig (˜1.7 MPag) to about 400 psig (˜2.8 MPag). The hydrogen feed rate can be from about 500 standard cubic feet per barrel (scf/b) (˜84 m³/m³) to about 6000 scf/b (˜1000 m³/m³), preferably from about 1000 scf/b (˜170 m³/m³) to about 3000 scf/b (˜510 m³/m³). The liquid hourly space velocity can be from about of about 0.5 hr⁻¹to about 15 hr⁻¹, preferably from about 0.5 hr⁻¹to about 10 hr⁻¹, more preferably from about 1 hr⁻¹to about 5 hr⁻¹.
In various embodiments, a goal of a (optionally selective) hydrodesulfurization process can be to produce a naphtha product having a desired level of sulfur. In an aspect, the desired level of sulfur can be at least about 2 wppm, or at least about 5 wppm, or at least about 10 wppm, or at least about 20 wppm and/or about 50 wppm or less, or about 30 wppm or less, or about 15 wppm or less, or about 10 wppm or less.

Modified Hydroprocessing Strategy—Consecutive Bed/Reactor Exposure

As a variation on the above, another option for reducing the sulfur content of an optionally olefinic naphtha feed can be to hydroprocess the feed using a modified hydroprocessing strategy. One option that can assist with preserving the octane of an olefinic naphtha feed can be to process the feed at a higher processing temperature over a selective catalyst, such as an alumina or silica supported CoMo hydroprocessing catalyst. Unfortunately, in order to achieve commercial scale run lengths, naphtha feeds are typically processed at lower temperatures to reduce or minimize the amount of catalyst deactivation. Thus, the conditions that can be beneficial for producing an improved product are in contrast to the conditions that can be beneficial for improved run length. Conventionally, this conflict is resolved by lowering the processing temperature so that commercial scale run lengths can be achieved. This can reduce or minimize the number of reactor shutdowns needed in order to remove or replace catalyst.
As an alternative to a conventional strategy, in various aspects a reactor or reactors can include multiple beds of hydrotreating catalyst. In such aspects, the feed is not initially exposed to all catalyst beds (and/or reactors) of the hydrotreating catalyst. Instead, the feed can be introduced upstream from a final one or more catalyst beds (and/or reactors), thus bypassing the remaining catalyst beds. An alternative way of describing this situation can be that the feed is introduced at a first position upstream from one or more catalyst beds but downstream from one or more additional catalyst beds. The feed can then be hydroprocessed under higher temperature conditions over the final one or more catalyst beds. This can lead to catalyst deactivation at an increased rate. However, because only the final one or more beds are exposed to the feed, the reaction system does not need to be shut down after the catalyst deactivates. Instead, after the final one or more beds deactivate, the entry point for the feed can be switched to an upstream location. The feed can then be exposed to the additional group of one or more beds. The feed can optionally also pass through the final one or more beds of deactivated catalyst. This strategy can be repeated until all available beds have been used as fresh catalyst for processing of the feed. This can allow for processing at conditions favorable for producing a desired product while maintaining a more desirable run length for the reaction system.
It is noted that the above strategy can more generally be applied in any situation where desirable processing conditions for a feed are in conflict with conditions that extend the run length of a catalyst. Thus, the above strategy can be used with naphtha feeds, distillate feed, lubricating base oil feed, or any other convenient type of feed. Similarly, the above strategy can be used with any type of hydroprocessing catalyst, such as a hydrotreating catalyst, a dewaxing catalyst, a hydrocracking catalyst, an aromatic saturation catalyst, or a combination thereof. This type of strategy for consecutively using the beds and/or reactors in a reaction system can be employed with any convenient number of reaction zones, such as 2 to 30 reaction zones.
Still another alternative strategy can correspond to exposing an entire naphtha feed, without fractionation, to the acidic catalyst optionally in the presence of an olefin-containing stream, along with hydroprocessing the entire naphtha feed either prior to or after exposing the feed to the acidic catalyst. This type of alternative can be suitable when a fractionator is not available for forming a lower boiling portion and a higher boiling portion from a naphtha feed. If the hydroprocessing is performed prior to exposure to the acidic catalyst, the amount of olefins present in the feed can be reduced, which can reduce the benefits of exposing the feed to the acidic catalyst. For example, this can reduce the amount of alkylation that occurs during exposure to the acidic catalyst, resulting in lower desulfurization. The reduced olefin content can also result in a lower octane rating for the product. If hydroprocessing is performed after exposure to the acidic catalyst, the octane rating of the resulting product can be reduced due to olefin saturation.

Additional Embodiments

Embodiment

1

A method for treating a naphtha boiling range fraction, comprising: separating a feedstock to form a lower boiling fraction and a higher boiling fraction, the separated lower boiling fraction comprising a naphtha boiling range fraction, the separation being performed at a separation cut point temperature of about 160° F. (˜71° C.) to about 290° F. (˜149° C.); exposing at least a portion of the separated lower boiling fraction to an acidic catalyst without providing substantial added hydrogen under effective desulfurization conditions to form at least a desulfurized naphtha boiling range effluent having a sulfur content of about 90 wppm or less, the effective desulfurization conditions including a pressure of at least about 150 psia (about 1.0 MPaa); and exposing at least a portion of the separated higher boiling fraction to a hydrotreating catalyst under effective hydrotreating conditions to form a hydrotreated effluent having a sulfur content of about 15 wppm or less, or about 10 wppm or less.

Embodiment 2

A method for treating a naphtha boiling range fraction, comprising: separating a feedstock to form a lower boiling fraction and a higher boiling fraction, the separated lower boiling fraction comprising a naphtha boiling range fraction, the separation being performed at a separation cut point temperature of about 170° F. (77° C.) to about 270° F. (132° C.); exposing at least a portion of the separated lower boiling fraction and a C₂-C₄olefin-containing stream to an acidic catalyst without providing substantial added hydrogen under effective desulfurization conditions to form at least a desulfurized naphtha boiling range effluent having a sulfur content of about 90 wppm or less, the effective desulfurization conditions including a pressure of at least about 150 psia (about 1.0 MPaa); and exposing at least a portion of the separated higher boiling fraction to a hydrotreating catalyst under effective hydrotreating conditions to form a hydrotreated effluent having a sulfur content of about 15 wppm or less, or about 10 wppm or less.

Embodiment 3

The method of Embodiments 1 or 2, wherein the separated lower boiling fraction comprises about 100 wppm or less of sulfur contained in C₂+ thiophenes, or about 75 wppm or less, or about 50 wppm or less, or about 25 wppm or less, or about 10 wppm or less.

Embodiment 4

A method for treating a naphtha boiling range fraction, comprising: separating a feedstock to form a lower boiling fraction and a higher boiling fraction, the separated lower boiling fraction comprising a naphtha boiling range fraction, the separation being performed at a separation cut point temperature of about 160° F. (˜71° C.) to about 300° F. (˜149° C.), the separated lower boiling fraction comprising at least about 10 wppm of thiophene, methyl thiophene, or a combination thereof, the separated lower boiling fraction further comprising about 50 wppm or less of sulfur contained in C₂+ thiophenes; exposing at least a portion of the separated lower boiling fraction to an acidic catalyst without providing substantial added hydrogen under effective desulfurization conditions to form at least a desulfurized naphtha boiling range effluent having a sulfur content of about 90 wppm or less, the effective desulfurization conditions including a pressure of at least about 150 psia (about 1.0 MPaa); and exposing at least a portion of the separated higher boiling fraction to a hydrotreating catalyst under effective hydrotreating conditions to form a hydrotreated effluent having a sulfur content of about 15 wppm or less.

Embodiment 5

The method of any of Embodiments 1 or 4, wherein exposing at least a portion of the separated lower boiling fraction to an acidic catalyst comprises exposing the at least a portion of the separated lower boiling fraction and a C₂-C₄olefin-containing stream to the acidic catalyst.

Embodiment 6

The method of any of the above embodiments, wherein a weight hourly space velocity of the C₂-C₄olefin-containing stream exposed to the acidic catalyst is about 0.1 hr⁻¹to about 1.0 hr⁻¹, or about 0.1 hr⁻¹to about 0.75 hr⁻¹, or about 0.1 hr⁻¹to about 0.6 hr⁻¹.

Embodiment 7

The method of any of the above embodiments, wherein the separated lower boiling fraction has a sulfur content of 50 wppm or less of sulfur contained in C₂+ alkyl-substituted thiophenes, or about 25 wppm or less, or about 10 wppm or less.

Embodiment 8

The method of any of the above embodiments, wherein the separation is performed at a separation cut point temperature of about 250° F. (˜121° C.) or less, or about 240° C. (˜116° C.) or less, or about 225° F. (˜107° C.) or less, or about 210° F. (˜99° C.) or less.

Embodiment 9

The method of any of the above embodiments, wherein a T95 boiling point of the separated lower boiling fraction differs from a T5 boiling point of the separated higher boiling fraction by about 40° F. (˜22° C.) or less, or about 30° F. (˜17° C.) or less, or about 20° F. (˜11° C.) or less, or about 10° F. (˜6° C.) or less.

Embodiment 10

The method of any of the above embodiments, wherein the hydrodesulfurization process comprises a selective hydrodesulfurization process and the separated higher boiling range fraction comprises at least about 5 wt % of olefins, or wherein the hydrodesulfurization process comprises a non-selective hydrodesulfurization process.

Embodiment 11

The method of any of the above embodiments, wherein the desulfurized naphtha boiling range effluent has a sulfur content of about 50 wppm or less, or about 30 wppm or less, or about 20 wppm or less, or about 10 wppm or less, or wherein the effective desulfurization conditions are effective for converting at least about 60% of the sulfur-containing compounds in the separated lower boiling fraction, or at least about 70% or at least about 80%, or a combination thereof.

Embodiment 12

The method of any of the above embodiments, further comprising combining at least a portion of the desulfurized naphtha boiling range effluent and at least a portion of the hydrotreated effluent to form a naphtha boiling range product, the naphtha boiling range product having a sulfur content of about 15 wppm or less, or about 10 wppm or less.

Embodiment 13

The method of any of the above embodiments, wherein the effective desulfurization conditions comprise a temperature of about 400° F. (˜204° C.) to about 1200° F. (˜649° C.), or about 500° F. (˜260° C.) to about 900° F. (˜482° C.), or about 700° F. (˜371° C.) to about 850° F. (˜454° C.); a pressure of about 150 psia (˜1.0 MPaa) to about 750 psia (˜5.2 MPaa), or about 170 psia (˜1.2 MPaa) to about 600 psia (˜4.1 MPaa); and a weight hourly space velocity of about 0.05 to about 10 hr⁻¹, or about 0.1 to about 2 hr⁻¹, the effective desulfurization conditions optionally comprising exposing the lower boiling portion to the acidic catalyst under fluidized bed conditions.

Embodiment 14

The method of any of the above embodiments, wherein the acidic catalyst comprises a hydrogenation metal supported on an aluminosilicate molecular sieve optionally substituted with one or more heteroatoms, an silicoaluminophosphate molecular sieve optionally substituted with one or more heteroatoms, or a combination thereof.

Embodiment 15

The method of any of the above embodiments, wherein the acidic catalyst comprises a molecular sieve having a 10-member ring structure, a 12-member ring structure, or a combination thereof, the acidic catalyst optionally comprising a molecular sieve having a framework structure of ZSM-5, ZSM-11, ZSM-12, ZSM-22, ZSM-23, ZSM-35, ZSM-48, MCM-22, MCM-36, MCM-49, zeolite Y, zeolite beta, mordenite, or a combination thereof.

Embodiment 16

The method of any of the above embodiments, wherein exposing the at least a portion of the separated lower boiling fraction to the acidic catalyst without providing substantial added hydrogen comprises exposing the at least a portion of the separated lower boiling fraction to the acidic catalyst in the presence of a) less than about 100 SCF/bbl of added hydrogen, or less than about 50 SCF/bbl; b) a partial pressure of less than 50 psig (350 kPag) of hydrogen, or less than about 15 psig (˜100 kPag); or c) a combination thereof.

Embodiment 17

The method of any of the above embodiments, wherein exposing the at least a portion of the separated higher boiling fraction to a hydrotreating catalyst under effective hydrotreating conditions comprises: exposing the at least a portion of the separated higher boiling fraction to one or more beds of the hydrotreating catalyst, the one or more beds of the hydrotreating catalyst being located downstream from a first location in a reaction system, an additional one or more beds of the hydrotreating catalyst being located upstream from the first location, the at least a portion of the separated higher boiling fraction being introduced into the reaction system at a position downstream from the first location; determining that the one or more beds of the hydrotreating catalyst are deactivated; modifying a position for introducing the at least a portion of the separated higher boiling fraction to a second location, the second location being upstream from the additional one or more beds of hydrotreating catalyst; and exposing the at least a portion of the separated higher boiling fraction to the additional one or more beds of hydrotreating catalyst.

Embodiment 18

The method of Embodiment 17, wherein exposing the at least a portion of the separated higher boiling fraction to the additional one or more beds of hydrotreating catalyst further comprises exposing the at least a portion of the separated higher boiling fraction to the deactivated one or more beds of hydrotreating catalyst after said exposing to the additional one or more beds of hydrotreating catalyst.

Embodiment 19

A naphtha composition corresponding to the desulfurized naphtha boiling range effluent having a sulfur content of about 90 wppm or less formed according to the method of any of the above embodiments.

EXAMPLE

Conversion Rates for Sulfur-Containing Compounds

It has been discovered that the efficiency of sulfur removal by exposure to zeolites without added hydrogen can be strongly impacted by the nature of the sulfur compounds in a feed. In particular, substituted thiophene type compounds can be more resistant to removal than lighter sulfur compounds. Thus, achieving a desired level of sulfur removal can be dependent on reducing or minimizing the amount of such compounds in a feed.
FIG. 2 shows examples of data from processing of an FCC naphtha feed in the presence of a ZSM-5 catalyst without added hydrogen at a pressure of about 180 psig (˜1.24 MPag). As shown in FIG. 2, the FCC naphtha feed was processed at various conditions that included temperatures between about 400° C. and about 450° C. and added light olefins at a weight hourly space velocity of about 0.5 or about 0.75 hr⁻¹. The FCC naphtha feed was cut so that both C₁and C₂alkyl substituted thiophenes were included in the FCC naphtha feed. The total content of C₃+ alkyl substituted thiophenes in the feed was less than 1 ppmw, and no benzothiophenes were included. The total amount of sulfur in the FCC naphtha feed was about 200 ppmw, which was split about 45/55 with regard to sulfur in mercaptan or alkyl sulfide compounds versus sulfur in thiophene compounds.
As shown in FIG. 2, the amount of conversion for each type of sulfur compound is shown. Although it would conventionally be expected that all thiophene compounds would be more difficult to convert for sulfur removal relative to mercaptans or alkyl sulfides, it was unexpectedly discovered that thiophene and methyl thiophene (i.e., C₁thiophene) could be converted in a percentage similar to the mercaptans and alkyl sulfides under at least some conditions. By contrast, it appears from the data in FIG. 2 that the more difficult to convert compounds are the C₂+ alkyl-substituted thiophenes. For example, as shown in FIG. 2, the percentage of conversion (i.e., removal) of C₂alkyl substituted thiophenes at each condition shown in FIG. 2 is at least about 5% lower than the conversion percentage for C₁alkyl substituted thiophenes. The conversion percentage for the C₂alkyl-substituted thiophenes was around 55% or lower, while conversion percentages for thiophene and C₁thiophenes were at least 70% under all conditions. Additionally, depending on the initial concentration in the feed, some larger compounds (such as C₃+ alkyl-substituted thiophenes) may have an apparent negative conversion amount due to formation of the larger compounds in the reaction environment.
FIG. 2 can also provide further insight into the potential reasons for why C₂+ alkyl substituted thiophenes are apparently converted at a lower rate than thiophene and/or C₁thiophenes. FIG. 2 shows the product distribution for various alkyl substituted thiophenes in the initial FCC-based feed and the resulting products at each of the processing conditions from FIG. 2. As previously noted, FIG. 2 shows that the initial feed has less than 1 ppmw of sulfur in compounds corresponding to C₃+ alkyl substituted thiophenes. However, the resulting products show C₃+ alkyl substituted thiophene amounts of roughly 8-12 ppmw. This appears to show that at least a portion of the reactions of alkyl substituted thiophenes corresponds to alkylation reactions to form heavier sulfur containing compounds, as opposed to reactions to convert sulfur to H₂S. This combination of incomplete conversion of alkyl-substituted thiophenes with reaction to form higher molecular weight sulfur containing compounds demonstrates the difficulty in removing such alkyl-substituted thiophenes from a feed.
When numerical lower limits and numerical upper limits are listed herein, ranges from any lower limit to any upper limit are contemplated. While the illustrative embodiments of the invention have been described with particularity, it should be understood that various other modifications should be apparent to and can be readily made by those skilled in the art without departing from the spirit and scope of the invention. Accordingly, it is not intended that the scope of the claims appended hereto be limited to the examples and descriptions set forth herein but rather that the claims be construed as encompassing all the features of patentable novelty which reside in the present invention, including all features which would be treated as equivalents thereof by those skilled in the art to which the invention pertains.
The present invention has been described above with reference to numerous embodiments and specific examples. Many variations can suggest themselves to those skilled in this art in light of the above detailed description. All such obvious variations are within the full intended scope of the appended claims.

Claims

What is claimed is:

1. A method for treating a naphtha boiling range fraction, comprising:

separating a feedstock to form a lower boiling fraction and a higher boiling fraction, the separated lower boiling fraction comprising a naphtha boiling range fraction, the separation being performed at a separation cut point temperature of about 170° F. (77° C.) to about 270° F. (132° C.);

exposing at least a portion of the separated lower boiling fraction and a C₂-C₄olefin-containing stream to an acidic catalyst without providing substantial added hydrogen under effective desulfurization conditions to form at least a desulfurized naphtha boiling range effluent having a sulfur content of about 90 wppm or less, the effective desulfurization conditions including a pressure of at least about 150 psia (about 1.0 MPa); and

exposing at least a portion of the separated higher boiling fraction to a hydrotreating catalyst under effective hydrotreating conditions to form a hydrotreated effluent having a sulfur content of about 15 wppm or less.

2. The method of claim 1, wherein a weight hourly space velocity of the C₂-C₄olefin-containing stream exposed to the acidic catalyst is about 0.1 hr⁻¹to about 1.0 hr⁻¹.

3. The method of claim 1, wherein the separated lower boiling fraction has a sulfur content of about 50 wppm or less of sulfur contained in C₂+ thiophenes.

4. The method of claim 1, wherein the separation is performed at a separation cut point temperature of about 250° F. (121° C.) or less.

5. The method of claim 1, wherein a T95 boiling point of the separated lower boiling fraction differs from a T5 boiling point of the separated higher boiling fraction by about 40° F. (22° C.) or less.

6. The method of claim 1, wherein the hydrodesulfurization process comprises a selective hydrodesulfurization process and wherein the separated higher boiling range fraction comprises at least about 5 wt % of olefins.

7. The method of claim 1, wherein the effective desulfurization conditions are effective for converting at least about 60% of the sulfur-containing compounds in the separated lower boiling fraction.

8. The method of claim 1, further comprising combining at least a portion of the desulfurized naphtha boiling range effluent and at least a portion of the hydrotreated effluent to form a naphtha boiling range product, the naphtha boiling range product having a sulfur content of about 15 wppm or less, or about 10 wppm or less.

9. The method of claim 1, wherein the effective desulfurization conditions comprise a temperature of about 400° F. (204° C.) to about 1200° F. (649° C.); a pressure of about 150 psia (1.0 MPa) to about 750 psia (5.2 MPa); and a weight hourly space velocity of about 0.05 to about 10 hr⁻¹.

10. The method of claim 1, wherein the effective desulfurization conditions comprise exposing the lower boiling portion to the acidic catalyst under fluidized bed conditions.

11. The method of claim 1, wherein the acidic catalyst comprises a hydrogenation metal supported on an aluminosilicate molecular sieve optionally substituted with one or more heteroatoms, an silicoaluminophosphate molecular sieve optionally substituted with one or more heteroatoms, or a combination thereof.

12. The method of claim 1, wherein the acidic catalyst comprises a molecular sieve having a 10-member ring structure, a 12-member ring structure, or a combination thereof.

13. The method of claim 1, wherein the acidic catalyst comprises a molecular sieve having a framework structure of ZSM-5, ZSM-11, ZSM-12, ZSM-22, ZSM-23, ZSM-35, ZSM-48, MCM-22, MCM-36, MCM-49, zeolite Y, zeolite beta, mordenite, or a combination thereof.

14. The method of claim 1, wherein exposing the at least a portion of the separated lower boiling fraction to the acidic catalyst without providing substantial added hydrogen comprises exposing the at least a portion of the separated lower boiling fraction to the acidic catalyst in the presence of a) less than about 100 SCF/bbl of added hydrogen, or less than about 50 SCF/bbl; b) a partial pressure of less than 50 psig (350 kPag) of hydrogen, or less than about 15 psig (100 kPag); or c) a combination thereof.

15. The method of claim 1, wherein exposing the at least a portion of the separated higher boiling fraction to a hydrotreating catalyst under effective hydrotreating conditions comprises:

exposing the at least a portion of the separated higher boiling fraction to one or more beds of the hydrotreating catalyst, the one or more beds of the hydrotreating catalyst being located downstream from a first location in a reaction system, an additional one or more beds of the hydrotreating catalyst being located upstream from the first location, the at least a portion of the separated higher boiling fraction being introduced into the reaction system at a position downstream from the first location;

determining that the one or more beds of the hydrotreating catalyst are deactivated;

modifying a position for introducing the at least a portion of the separated higher boiling fraction to a second location, the second location being upstream from the additional one or more beds of hydrotreating catalyst; and

exposing the at least a portion of the separated higher boiling fraction to the additional one or more beds of hydrotreating catalyst.

16. The method of claim 15, wherein exposing the at least a portion of the separated higher boiling fraction to the additional one or more beds of hydrotreating catalyst further comprises exposing the at least a portion of the separated higher boiling fraction to the deactivated one or more beds of hydrotreating catalyst after said exposing to the additional one or more beds of hydrotreating catalyst.

17. A naphtha boiling range composition formed according to a method comprising:

separating a feedstock to form a lower boiling fraction and a higher boiling fraction, the separated lower boiling fraction comprising a naphtha boiling range fraction, the separation being performed at a separation cut point temperature of about 170° F. (77° C.) to about 270° F. (132° C.); and

exposing at least a portion of the separated lower boiling fraction and a C₂-C₄olefin-containing stream to an acidic catalyst without providing substantial added hydrogen under effective desulfurization conditions to form at least a naphtha boiling range composition having a sulfur content of about 90 wppm or less, the effective desulfurization conditions including a pressure of at least about 150 psia (about 1.0 MPa).

18. A method for treating a naphtha boiling range fraction, comprising:

separating a feedstock to form a lower boiling fraction and a higher boiling fraction, the separated lower boiling fraction comprising a naphtha boiling range fraction, the separation being performed at a separation cut point temperature of about 160° F. (71° C.) to about 300° F. (149° C.), the separated lower boiling fraction comprising at least about 10 wppm of thiophene, methyl thiophene, or a combination thereof, the separated lower boiling fraction further comprising about 50 wppm or less of sulfur contained in C₂+ thiophenes;

exposing at least a portion of the separated lower boiling fraction to an acidic catalyst without providing substantial added hydrogen under effective desulfurization conditions to form at least a desulfurized naphtha boiling range effluent having a sulfur content of about 50 wppm or less, the effective desulfurization conditions including a pressure of at least about 150 psig (about 1.0 MPag); and

19. The method of claim 18, wherein exposing at least a portion of the separated lower boiling fraction to an acidic catalyst comprises exposing the at least a portion of the separated lower boiling fraction and a C₂-C₄olefin stream to the acidic catalyst.

20. The method of claim 18, wherein the separation is performed at a separation cut point temperature of about 250° F. (121° C.) or less.