Patent Application
20140042056
Systems and methods are provided for production of lubricant oil basestocks.
Dewaxing is a commonly used technique for improving the properties of a petroleum fraction for use in various products, such as fuels or lubricant base stocks. Historically, solvent dewaxing was the first type of dewaxing used for modifying the properties of a feedstock. Solvent extraction and dewaxing allowed for separation of a feedstock into a raffinate fraction for use as a distillate fuel or lubricant, an aromatics fraction, and a waxy fraction. More recently, catalytic dewaxing has been commonly used for improving the properties of feeds for use in fuels or lubricant base stocks.
U.S. Pat. No. 4,259,170 describes a process for manufacturing lube basestocks. In the process, one or more lower boiling fractions from a vacuum distillation tower are solvent dewaxed to form lubricant base stocks. One or more higher boiling fractions are catalytically dewaxed in order to provide a pour point improvement for the higher boiling fractions that is greater than the amount that can be achieved by solvent dewaxing.
U.S. Pat. No. 6,773,578 describes a process for preparing lubes with high viscosity index values. The process includes obtaining a first feedstock that includes at least 95% of material that boils below 1150° F. (621° C.), and a second feedstock that includes at least 95% of material that boils above 1150° F. (621° C.). The feedstock containing the portion that boils below 1150° F. is catalytically dewaxed. The feedstock containing the portion that boils above 1150° F. is solvent dewaxed and optionally also catalytically dewaxed. Performing solvent dewaxing on the above 1150° F. portion is described as reducing the difference between the cloud point and the pour point for the resulting products.
U.S. Pat. No. 7,354,508 describes a process for preparing a heavy and a light lubricating base oil. A feedstock for forming lubricant basestocks is separated into a lower boiling fraction and a higher boiling fraction. The lower boiling fraction and higher boiling fraction are dewaxed under different conditions. Solvent dewaxing is generally mentioned as a type of dewaxing. However, catalytic dewaxing is identified as the preferred type of dewaxing for dewaxing of both fractions.
In an aspect, a method for forming fuel and lubricant products is provided. The method includes separating a feedstock into at least a first fraction having a T5 boiling point greater than 600° F. (316° C.) and a T95 boiling point of 1150° F. (621° C.) or less and a bottoms fraction; deasphalting the bottoms fraction to form a deasphalted bottoms fraction and an asphalt product; extracting the deasphalted bottoms in the presence of an extraction solvent to form a raffinate stream and an extract stream, an aromatics content of the raffinate stream being lower than an aromatics content of the deasphalted bottoms; dewaxing the raffinate stream in the presence of a dewaxing solvent to form a lubricant base oil product and a wax product; hydroprocessing a combined feedstock corresponding to the first fraction and a fuels feedstock, at least a portion of the combined feedstock having a boiling point greater than 700° F. (371° C.), the fuels feedstock having a T5 boiling point greater than 350° F. (177° C.) and a T95 boiling point of 1150° F. (621° C.) or less, under first effective hydroprocessing conditions to form a hydroprocessed effluent; separating the hydroprocessed effluent to form at least a gas phase effluent and a liquid phase effluent; hydroprocessing at least a portion of the liquid phase effluent in the presence of at least a dewaxing catalyst under second effective hydroprocessing conditions to form a dewaxed effluent, the first effective hydroprocessing conditions and the second effective hydroprocessing conditions being effective for conversion of at least 60% of the portion of the combined feedstock boiling above 700° F. (371° C.) to a portion boiling below 700° F. (371° C.); and fractionating the dewaxed effluent to form at least a distillate fuel product having a T95 boiling point of 750° F. (399° C.) or less and a lubricant base oil product having a viscosity index of at least 80, a sulfur content of 300 wppm or less, and an aromatics content of 10 wt % or less.
In another aspect, separation of the feedstock includes separating the feedstock into at least a first fraction having a T5 boiling point greater than 600° F. (316° C.) and a T95 boiling point of 950° F. (510° C.) or less, a second fraction having a T5 boiling point of at least the T95 boiling point of the first fraction, and a bottoms fraction. In such an aspect, extracting the deasphalted bottoms includes extracting the deasphalted bottoms and the second fraction in the presence of an extraction solvent to form a raffinate stream and an extract stream, an aromatics content of the raffinate stream being lower than an aromatics content of the combined deasphalted bottoms and second fraction.
In still another aspect, separation of the feedstock includes separating the feedstock into at least a first fraction having a T5 boiling point greater than 600° F. (316° C.) and a T95 boiling point of 950° F. (510° C.) or less, a second fraction having a T5 boiling point of at least the T95 boiling point of the first fraction, and a bottoms fraction. In such an aspect, the method further includes extracting the second fraction in the presence of an extraction solvent to form a second raffinate stream and a second extract stream, an aromatics content of the second raffinate stream being lower than an aromatics content of the second fraction; and dewaxing the second raffinate stream in the presence of a dewaxing solvent to form a second lubricant base oil product and a second wax product.
All numerical values within the detailed description and the claims herein are modified by “about” or “approximately” the indicated value, and take into account experimental error and variations that would be expected by a person having ordinary skill in the art.
In various embodiments, methods are provided for producing a plurality of lubricant base oil products. A suitable feedstock for forming lubricant base oils is separated into at least a lower boiling portion and a higher boiling portion. The lower boiling portion is combined with a feed suitable for use as a fuels hydrocracking feed. The combined feed is hydrocracked and catalytically dewaxed in order to form fuels and Group II, Group II+, or Group III light neutral basestocks. The higher boiling portion of the feedstock is solvent processed in order to form Group I heavy neutral base oils and/or Group I brightstock base oils. This provides a desirable combination that cannot be readily achieved by solvent dewaxing or catalytic dewaxing of the full lubricant feedstock.
Group I basestocks or base oils are defined as base oils with less than 90 wt % saturated molecules and/or at least 0.03 wt % sulfur content. Group I basestocks also have a viscosity index (VI) of at least 80 but less than 120. Group II basestocks or base oils contain at least 90 wt % saturated molecules and less than 0.03 wt % sulfur. Group II basestocks also have a viscosity index of at least 80 but less than 120. Group III basestocks or base oils contain at least 90 wt % saturated molecules and less than 0.03 wt % sulfur, with a viscosity index of at least 120. In addition to the above formal definitions, some Group I basestocks may be referred to as a Group I+ basestock, which corresponds to a Group I basestock with a VI value of 103 to 108. Some Group II basestocks may be referred to as a Group II+ basestock, which corresponds to a. Group II basestock with a VI of at least 113. Some Group III basestocks may be referred to as a Group III+ basestock, which corresponds to a Group III basestock with a VI value of at least 140.
Conventionally, a feedstock for lubricant base oil production is processed either using solvent dewaxing or using catalytic dewaxing. For example, in a lube solvent plant, a vacuum gas oil (VGO) or another suitable feed is fractionated into light neutral (LN) and heavy neutral (HN) distillates and a bottom fraction by some type of vacuum distillation. The bottoms fraction is subsequently deasphalted to recover an asphalt fraction and a brightstock. The LN distillate, HN distillate, and brightstock are then solvent extracted to remove the most polar molecules as an extract and corresponding LN distillate, HN distillate, and brightstock raffinates. The raffinates are then solvent dewaxed to obtain a LN distillate, HN distillate, and brightstock basestocks with acceptable low temperature properties. It is beneficial to hydrofinish the lubricant basestocks either before or after the solvent dewaxing step. The resulting lubricant basestocks ma contain a significant amount of aromatics (up to 25%) and high sulfur (>300 ppm). Thus, the typical base oils formed from solvent dewaxing alone are Group I basestocks. As an alternative, a raffinate hydroconversion step can be performed prior to the solvent dewaxing. The hydroconversion is essentially a treatment under high H2 pressure in presence of a metal sulfide based hydroprocessing catalyst which remove most of the sulfur and nitrogen. The amount of conversion in the hydroconversion reaction is typically tuned to obtain a predetermined increase in viscosity index and 95%+ saturates. This allows the solvent dewaxed lubricant basestock products to be used as Group II or Group II+ basestocks. Optionally, the wax recovered from a solvent dewaxing unit may also be processed by catalytic dewaxing to produce Group III or Group III+ lubricant basestocks.
For production of lubricant base oils in an all catalytic process, a VGO (or another suitable feed) is hydrocracked under medium pressure conditions to obtain a hydrocracker bottoms with reduced sulfur and nitrogen contents. One or more LN and/or FIN distillate fractions may then be recovered from the desulfurized hydrocracker bottoms. The recovered fractions are then catalytically dewaxed, such as by using a shape selective dewaxing catalyst, followed by hydrofinishing. This process typically results in production of Group II, Group II+, and Group III base oils. However, due to the conversion in the hydrocracker, the amount of heavy neutral base oils that are produced is limited.
A wide range of petroleum and chemical feedstocks can be hydroprocessed in accordance with the disclosure. Suitable feedstocks include whole and reduced petroleum crudes, atmospheric and vacuum residua, propane deasphalted residua, e.g., brightstock, cycle oils, FCC tower bottoms, gas oils, including vacuum gas oils and coker gas oils, light to heavy distillates including raw virgin distillates, hydrocrackates, hydrotreated oils, slack waxes, Fischer-Tropsch waxes, raffinates, and mixtures of these materials.
One way of defining a feedstock is based on the boiling range of the feed. One option for defining a boiling range is to use an initial boiling point for a feed and/or a final boiling point for a feed. Another option, which in some instances may provide a more representative description of a feed, is to characterize a feed based on the amount of the feed that boils at one or more temperatures. For example, a “T5” boiling point for a feed is defined as the temperature at which 5 wt % of the feed will boil off. Similarly, a “T95” boiling point is a temperature at 95 wt % of the feed will boil.
Typical feeds include, for example, feeds with an initial boiling point of at least 650° F. (343° C.), or at least 700° F. (371° C.), or at least 750° F. (399° C.). Alternatively, a feed may be characterized using a T5 boiling point, such as a feed with a T5 boiling point of at least 650° F. (343° C.), or at least 700° F. (371° C.), or at least 750° F. (399° C.). In some aspects, the final boiling point of the feed can be at least 1100° F. (593° C.), such as at least 1150° F. (621° C.) or at least 1200° F. (649° C.). In other aspects, a feed may be used that does not include a large portion of molecules that would traditional be considered as vacuum distillation bottoms. For example, the feed may correspond to a vacuum gas oil feed that has already been separated from a traditional vacuum bottoms portion. Such feeds include, for example, feeds with a final boiling point of 1150° F. (621° C.), or 1100° F. (593° C.) or less, or 1050° F. (566° C.) or less. Alternatively, a feed may be characterized using a T95 boiling point, such as a feed with a T95 boiling point of 1150° F. (621° C.) or less, or 1100° F. (593° C.) or less, or 1050° F. (566° C.) or less. An example of a suitable type of feedstock is a wide cut vacuum gas oil (VGO) feed, with a T5 boiling point of at least 700° F. (371° C.) and a T95 boiling point of 1100° F. or less. Optionally, the initial boiling point of such a wide cut VGO feed can be at least 700° F. and/or the final boiling point can be at least 1100° F. It is noted that feeds with still lower initial boiling points and/or T5 boiling points may also be suitable, so long as sufficient higher boiling material is available so that the overall nature of the process is a lubricant base oil production process and/or a fuels hydrocracking process.
The above feed description corresponds to a potential feed for producing lubricant base oils. In some aspects, methods are provided for producing both fuels and lubricants. Because fuels are a desired product, feedstocks with lower boiling components may also be suitable. For example, a feedstock suitable for fuels production, such as a light cycle oil, can have a T5 boiling point of at least 350° F. (177° C.), such as at least 100° F. (201° C.). Examples of a suitable boiling range include a boiling range of from 350° F. (177° C.) to 700° F. (371° C.), such as from 330° F. (200° C.) to 650° F. (343° C. Thus, a portion of the feed used for fuels and lubricant base oil production can include components having a boiling range from 170° C. to 350° C. Such components can be part of an initial feed, or a first feed with a T5 boiling point of 650° F. (343° C.) can be combined with a second feed, such as a light cycle oil, that includes components that boil between 200° C. and 350° C.
In embodiments involving an initial sulfur removal stage prior to hydrocracking, the sulfur content of the feed can be at least 300 ppm by weight of sulfur, or at least 1000 wppm, or at least 2000 wppm, or at least 1000 wppm, or at least 10,000 wppm, or at least 20,000 wppm. In other embodiments, including some embodiments where a previously hydrotreated and/or hydrocracked feed is used, the sulfur content can be 2000 wppm or less, or 1000 wppm or less, or 500 wppm or less, or 100 wppm or less.
In some embodiments, at least a portion of the feed can correspond to a feed derived from a biocomponent source. In this discussion, a biocomponent feedstock refers to a hydrocarbon feedstock derived from a biological raw material component, from biocomponent sources such as vegetable, animal, fish, and/or algae. Note that, for the purposes of this document, vegetable fats/oils refer generally to any plant based material, and can include fat/oils derived from a source such as plants of the genus Jatropha. Generally, the biocomponent sources can include vegetable fats/oils, animal fats/oils, fish oils, pyrolysis oils, and algae lipids/oils, as well as components of such materials, and in some embodiments can specifically include one or more type of lipid compounds. Lipid compounds are typically biological compounds that are insoluble in water, but soluble in nonpolar (or fat) solvents. Non-limiting examples of such solvents include alcohols, ethers, chloroform, alkyl acetates, benzene, and combinations thereof.
The biocomponent feeds usable in the present disclosure can include any of those which comprise primarily triglycerides and free fatty acids (FFAs). The triglycerides and FFAs typically contain aliphatic hydrocarbon chains in their structure having from 8 to 36 carbons, preferably from 10 to 26 carbons, for example from 14 to 22 carbons. Types of triglycerides can be determined according to their fatty acid constituents. The fatty acid constituents can be readily determined using Gas Chromatography (GC) analysis. This analysis involves extracting the fat or oil, saponifying (hydrolyzing) the fat or oil, preparing an alkyl (e.g., methyl) ester of the saponified fat or oil, and determining the type of (methyl) ester using GC analysis. In one embodiment, a majority (i.e., greater than 50%) of the triglyceride present in the lipid material can be comprised of C10 to C26, for example C12 to C18, fatty acid constituents, based on total triglyceride present in the lipid material. Further, a triglyceride is a molecule having a structure substantially identical to the reaction product of glycerol and three fatty acids. Thus, although a triglyceride is described herein as being comprised of fatty acids, it should be understood that the fatty acid component does not necessarily contain a carboxylic acid hydrogen. Other types of feed that are derived from biological raw material components can include fatty acid esters, such as fatty acid alkyl esters (e.g., FAME and/or FAEE).
Biocomponent based feedstreams typically have relatively low nitrogen and sulfur contents. For example, a biocomponent based feedstream can contain up to 500 wppm nitrogen, for example up to 300 wppm nitrogen or up to 100 wppm nitrogen, instead of nitrogen and/or sulfur, the primary heteroatom component in biocomponent feeds is oxygen. Biocomponent diesel boiling range feedstreams, e.g., can include up to 10 wt % oxygen, up to 12 wt % oxygen, or up to 14 wt % oxygen. Suitable biocomponent diesel boiling range feedstreams, prior to hydrotreatment, can include at least 5 wt % oxygen, for example at least 8 wt % oxygen.
Alternatively, a feed of biocomponent origin can be used that has been previously hydrotreated. This can be a hydrotreated vegetable oil feed, a hydrotreated fatty acid alkyl ester feed, or another type of hydrotreated biocomponent feed. A hydrotreated biocomponent feed can be a biocomponent feed that has been previously hydroprocessed to reduce the oxygen content of the feed to 500 wppm or less, for example to 200 wppm or less or to 100 wppm or less. Correspondingly, a biocomponent feed can be hydrotreated to reduce the oxygen content of the feed, prior to other optional hydroprocessing, to 500 wppm or less, for example to 200 wppm or less or to 100 wppm or less. Additionally or alternately, a biocomponent feed can be blended with a mineral feed, so that the blended feed can be tailored to have an oxygen content of 500 wppm or less, for example 200 wppm or less or 100 wppm or less, in embodiments where at least a portion of the feed is of a biocomponent origin, that portion can be at least 2 wt %, for example at least 5 wt %, at least 10 wt %, at least 20 wt %, at least 25 wt %, at least 35 wt %, at least 50 wt %, at least 60 wt %, or at least 75 wt %. Additionally or alternately, the biocomponent portion can be 75 wt % or less, for example 60 wt % or less, 50 wt % or less, 35 wt % or less, 25 wt % or less, 20 wt % or less, 10 wt % or less, or 5 wt % or less.
The content of sulfur, nitrogen, and oxygen in a feedstock created by blending two or more feedstocks can typically be determined using a weighted average based on the blended feeds. For example, a mineral feed and a biocomponent feed can be blended in a ratio of 80 wt % mineral feed and 20 wt % biocomponent feed. In such a scenario, if the mineral feed has a sulfur content of 1000 wppm, and the biocomponent feed has a sulfur content of 10 wppm, the resulting blended feed could be expected to have a sulfur content of 802 wppm.
In various embodiments, at least two lubricant base oil products can be made from a feedstock. As an initial process, a suitable feedstock can be separated to form at least a lower boiling feedstock portion, a higher boiling feedstock portion, and a bottoms portion. Such a separation can be performed, for example, using a vacuum distillation unit. One method for determining the amounts in the various portions is by selecting cut point temperatures. The cut point temperatures may vary depending on the nature of the feedstock. Generally, the cut point between the lower boiling portion and the higher boiling portion can be between 850° F. (454° C.) and 950° F. (510° C.), such as at least 875° F. (468° C.) or less than 925° F. (496° C.) or less than 900° F. (482° C.). The cut point between the higher boiling portion and the bottoms portion can be between 1050° F. (566° C.) and 1150° F. (621° C.), such as less than 1100° F. (593° C.). In some alternative aspects, it may be desirable to increase the relative amount of light neutral base oils that are produced. In such aspects, the cut point between the lower boiling portion and the higher boiling portion may be higher, such as at least 950° F. (510° C.), or at least 1000° F. (538° C.), and less than 1150° F. (621° C.), such as less than 1100° F. (593° C.) or less than 1050° F. (566° C.).
It is noted that the above fractionation temperatures represent the split between lighter feedstock portions, heavier feedstock portions, and a bottoms portion. If desired, additional fractions could also be formed based on additional cut points. For the purposes of the discussion herein, any such additional fractions can be processed according to boiling range. Thus, if additional fractions are formed with a T95 boiling point of less than 850° F. (454° C.) to 950° F. (510° C.), all such additional fractions would be processed as part of the lower boiling feedstock portion.
Another factor in selecting a cut point temperature for fractionating a feedstock is selecting a cut point to achieve a desired viscosity for the Group I lubricant base oils and/or brightstock. During hydroprocessing to form light neutral base oils, some changes in the viscosity of a base oil can be made by selecting appropriate hydroprocessing conditions. However, for heavy neutral base oils and brightstock produced from solvent extraction and solvent dewaxing, the ability to modify the viscosity of a feed to produce a desired viscosity product is limited. As a result, the fractionation cut point should be selected to produce heavy neutral base oils and/or brightstock from solvent processing that has a desired viscosity. For example, the fractionation cut points can be selected so that the heavy neutral base oil produced from solvent processing has a viscosity of at least 6.0 cSt at 100° C., such as at least 7.0 cSt or at least 8.0 cSt.
After fractionation to form a lower boiling feedstock portion, a higher boiling feedstock portion, and a bottoms portion, each of the portions can be further processed. The lower boiling feedstock portion can be hydroprocessed to form Group II, Group II+, or Group III base oils. The higher boiling feedstock portion can be solvent dewaxed to form Group I base oils. The bottoms portion can be deasphalted, followed by solvent dewaxing along with the higher boiling feedstock portion.
In some alternative aspects, a feedstock may correspond to a feed where molecules traditionally considered as corresponding to a vacuum bottoms portion are not present, such as in a feed that corresponds to a vacuum gas oil from a previous vacuum distillation process. In such aspects, it may be desirable to form only the lighter feedstock portion and the heavier feedstock portion. Of course, some portion during the separation will correspond to a “bottoms”, but the boiling range of such a “bottoms” will fall within the boiling range definition for the heavy portion of the feedstock. In these types of aspects, solvent deasphalting of a bottoms fraction is optional. Instead, all of the heavier portion of the feedstock after separation can be processed by solvent extraction followed by solvent dewaxing.
In still other alternative aspects, it may be desirable to increase the relative proportion of light neutral base oils relative to heavy neutral base oil. In such aspects, it may sometimes be desirable to separate the feedstock into only a lighter portion and a bottoms portion, without forming a fraction corresponding to the “heavy portion.” In these types of aspects, all of the feedstock separated into the bottoms portion is processed by solvent deasphalting, solvent extraction, and solvent dewaxing.
One of the fractions formed during vacuum distillation of the feedstock is a bottoms portion. This bottoms portion can include a variety of types of molecules, including asphaltenes. Solvent deasphalting can be used to separate asphaltenes from the remainder of the bottoms portion. This results in a deasphalted bottoms fraction and an asphalt or asphaltene fraction.
Solvent deasphalting is a solvent extraction process. Typical solvents include alkanes or other hydrocarbons containing 3 to 6 carbons per molecule. Examples of suitable solvents include propane, n-butane, isobutene, and n-pentane. Alternatively, other types of solvents may also be suitable, such as supercritical fluids. During solvent deasphalting, a feed portion is mixed with the solvent. Portions of the feed that are soluble in the solvent are then extracted, leaving behind a residue with little or no solubility in the solvent. Typical solvent deasphalting conditions include mixing a feedstock fraction with a solvent in a weight ratio of from 1:2 to 1:10, such as 1:8 or less. Typical solvent deasphalting temperatures range from 40° C. to 150° C. The pressure during solvent deasphalting can be from 50 psig (345 kPag) to 500 psig (3447 kPag).
The portion of the deasphalted feedstock that is extracted with solvent often referred to as deasphalted oil. In various aspects, the bottoms from vacuum distillation can be used as the feed to the solvent deasphalter, so the portion extracted with the solvent can also be referred to as deasphalted bottoms. The yield of deasphalted oil from a solvent deasphalting process varies depending on a variety of factors, including the nature of the feedstock, the type of solvent, and the solvent extraction conditions. A lighter molecular weight solvent such as propane will result in a lower yield of deasphalted oil as compared to n-pentane, as fewer components of a bottoms fraction will be soluble in the shorter chain alkane. However, the deasphalted oil resulting from propane deasphalting is typically of higher quality, resulting in expanded options for use of the deasphalted oil. Under typical deasphalting conditions, increasing the temperature will also usually reduce the yield while increasing the quality of the resulting deasphalted oil. In various embodiments, the yield of deasphalted oil from solvent deasphalting can be 85 wt % or less of the feed to the deasphalting process, or 75 wt % or less. Preferably, the solvent deasphalting conditions are selected so that the yield of deasphalted oil is at least 65 wt %, such as at least 70 wt % or at least 75 wt %. The deasphalted bottoms resulting from the solvent deasphalting procedure are then combined with the higher boiling portion from the vacuum distillation unit for solvent processing.
After a deasphalting process, the yield of deasphalting residue is typically at least 15 wt % of the feed to the deasphalting process, but is preferably 35 wt % or less, such as 30 wt % or less or 25 wt % or less. The deasphalting residue can be used, for example, for making various grades of asphalt.
Two types of solvent processing can be performed on the combined higher boiling portion from vacuum distillation and the deasphalted bottoms. The first type of solvent processing is a solvent extraction to reduce the aromatics content and/or the amount of polar molecules. The solvent extraction process selectively dissolves aromatic components to form an aromatics-rich extract phase while leaving the more paraffinic components in an aromatics-poor raffinate phase. Naphthenes are distributed between the extract and raffinate phases. Typical solvents for solvent extraction include phenol, furfural and N-methylpyrrolidone. By controlling the solvent to oil ratio, extraction temperature and method of contacting distillate to be extracted with solvent, one can control the degree of separation between the extract and raffinate phases. Any convenient type of liquid-liquid extractor can be used, such as a counter-current liquid-liquid extractor. Depending on the initial concentration of aromatics in the deasphalted bottoms, the raffinate phase can have an aromatics content of 5 wt % to 25 wt %. For typical feeds, the aromatics contents will be at least 10 wt %.
In some aspects, the deasphalted bottoms and the higher boiling fraction from vacuum distillation can be solvent processed together. Alternatively, the deasphalted bottoms and the higher boiling fraction can be solvent processed separately, to facilitate formation of different types of lubricant base oils. For example, the higher boiling fraction from vacuum distillation can be solvent extracted and then solvent dewaxed to form a Group I base oil while the deasphalted bottoms are solvent processed to form a brightstock. Of course, multiple higher boiling fractions could also be solvent processed separately if more than one distinct Group I base oil and/or brightstock is desired.
The raffinate from the solvent extraction is preferably under-extracted. In such preferred aspects, the extraction is carried out under conditions such that the raffinate yield is maximized while still removing most of the lowest quality molecules from the feed. Raffinate yield may be maximized by controlling extraction conditions, for example, by lowering the solvent to oil treat ratio and/or decreasing the extraction temperature. The raffinate from the solvent extraction unit can then be solvent dewaxed under solvent dewaxing conditions to remove hard waxes from the raffinate.
Solvent dewaxing typically involves mixing the raffinate feed from the solvent extraction unit with chilled dewaxing solvent to form an oil-solvent solution. Precipitated wax is thereafter separated by, for example, filtration. The temperature and solvent are selected so that the oil is dissolved by the chilled solvent while the wax is precipitated.
An example of a suitable solvent dewaxing process involves the use of a cooling tower where solvent is prechilled and added incrementally at several points along the height of the cooling tower. The oil-solvent mixture is agitated during the chilling step to permit substantially instantaneous mixing of the prechilled solvent with the oil. The prechilled solvent is added incrementally along the length of the cooling tower so as to maintain an average chilling rate at or below 10° F. per minute, usually between 1 to 5° F. per minute. The final temperature of the oil-solvent/precipitated wax mixture in the cooling tower will usually be between 0 and 50° F. (−17.8 to 10° C.). The mixture may then be sent to a scraped surface chiller to separate precipitated wax from the mixture.
Representative dewaxing solvents are aliphatic ketones having 3-6 carbon atoms such as methyl ethyl ketone and methyl isobutyl ketone, low molecular weight hydrocarbons such as propane and butane, and mixtures thereof. The solvents may be mixed with other solvents such as benzene, toluene or xylene.
In general, the amount of solvent added will be sufficient to provide a liquid/solid weight ratio between the range of 5/1 and 20/1 at the dewaxing temperature and a solvent/oil volume ratio between 1.5/1 to 5/1. The solvent dewaxed oil is typically dewaxed to an intermediate pour point, preferably less than +10° C., such as less than 5° C. or less than 0° C. The resulting solvent dewaxed oil is suitable for use in forming one or more types of Group I base oils. The aromatics content will typically be greater than 10 wt % in the solvent dewaxed oil. Additionally, the sulfur content of the solvent dewaxed oil will typically be greater than 300 wppm.
The lower boiling portions from the vacuum distillation can be hydroprocessed to form Group II, Group II+, or even Group III base oils. A suitable type of processing is to process the lower boiling portions from the vacuum distillation in a fuels hydrocracking process train. In this type of aspect, the lower boiling portion from vacuum distillation is mixed with a feed suitable for use in fuels hydrocracking, such as a vacuum gas oil or a light cycle oil. Suitable fuels hydrocracking feeds can be similar to the feeds used for the initial separation to form a lower boiling portion, a higher boiling portion, and the bottoms portion. Optionally, the fuels hydrocracking feed and the feed for forming the various portions by vacuum distillation can be the same feed. Additionally or alternately, other components can also be introduced into the feed for the hydroprocessing reaction system, such as slack wax or other waxy components. In still another alternative aspect, the lower boiling portion from vacuum distillation can be hydroprocessed without blending with another feed.
In the discussion below, a stage can correspond to a single reactor or a plurality of reactors. Optionally, multiple parallel reactors can be used to perform one or more of the processes, or multiple parallel reactors can be used for all processes in a stage. Each stage and/or reactor can include one or more catalyst beds containing hydroprocessing catalyst. Note that a “bed” of catalyst in the discussion below can refer to a partial physical catalyst bed. For example, a catalyst bed within a reactor could be filled partially with a hydrocracking catalyst and partially with a dewaxing catalyst. For convenience in description, even though the two catalysts may be stacked together in a single catalyst bed, the hydrocracking catalyst and dewaxing catalyst can each be referred to conceptually as separate catalyst beds.
In the discussion herein, reference will be made to a hydroprocessing reaction system. The hydroprocessing reaction system corresponds to the one or more stages, such as two stages and/or reactors and an optional intermediate separator, that are used to expose a feed to a plurality of catalysts under hydroprocessing conditions. The plurality of catalysts can be distributed between the stages and/or reactors in any convenient manner, with some preferred methods of arranging the catalyst described herein.
Various types of hydroprocessing can be used in the production of lubricant base oils, including production of lubricant base oils as one of several products generated during a fuels hydrocracking process. Typical processes include a hydrocracking process to provide uplift in the viscosity index (VI) of the feed. The hydrocracked feed can then be dewaxed to improve cold flow properties, such as pour point or cloud point. The hydrocracked, dewaxed feed can then be hydrofinished, for example, to remove aromatics from the lubricant base stock product. This can be valuable for removing compounds that are considered hazardous under various regulations. In addition to the above, a preliminary hydrotreatment and/or hydrocracking stage can also be used for contaminant removal.
After separation in the vacuum distillation apparatus, the lower boiling portion of the feedstock is passed into a hydroprocessing reaction system. The hydroprocessing reaction system can be, for example, a reaction system suitable for performing fuels hydrocracking. Typically this will correspond to a two stage hydrocracker, but alternatively the reaction system may include a first hydrotreater stage and a second hydrocracker stage. In still other aspects, the hydrocracking may be performed in a single stage and/or reactor, or more than two stages may be used. A separator can be used between the first stage and the second stage, such as a high temperature separator, to allow for removal of H2, NH3, and/or other contaminant gases and light ends in between the stages of the reaction system. In order to maximize diesel production, and to improve the cold flow properties of the hydrocracker bottoms, at least a portion of the catalyst in the second hydrocracker stage can be a dewaxing catalyst. Optionally, the hydrocracker bottoms or the entire liquid effluent from the hydrocracker can also be exposed to a hydrofinishing catalyst. The hydrofinishing catalyst can be included as part of a final bed in the second hydrocracker stage or in a separate reactor.
In some aspects, at least a portion of the catalyst in the hydrocracking reaction system can correspond to hydrotreatment catalyst. For example, one or more beds of catalyst in the first stage of a two stage reaction system can be hydrotreating catalyst. Optionally, the first stage can correspond to a hydrotreatment stage, with hydrocracking being performed in the second stage.
Hydrotreatment is typically used to reduce the sulfur, nitrogen, and aromatic content of a feed. The catalysts used for hydrotreatment of the heavy portion of the crude oil from the flash separator can include conventional hydroprocessing catalysts, such as those that comprise at least one Group VIII non-noble metal (Columns 8-10 of IUPAC periodic table), preferably Fe, Co, and/or Ni, such as Co and/or Ni; and at least one Group VI metal (Column 6 of IUPAC periodic table), preferably Mo and/or W. Such hydroprocessing catalysts optionally include transition metal sulfides that are impregnated or dispersed on a refractory support or carrier such as alumina and/or silica. The support or carrier itself typically has no significant/measurable catalytic activity. Substantially carrier- or support-free catalysts, commonly referred to as bulk catalysts, generally have higher volumetric activities than their supported counterparts.
The catalysts can either be in bulk form or in supported form. In addition to alumina and/or silica, other suitable support/carrier materials can include, but are not limited to, zeolites, titania, silica-titania, and titania-alumina. Suitable aluminas are porous aluminas such as gamma or eta having average pore sizes from 50 to 200 Å, or 75 to 150 Å; a surface area from 100 to 300 m2/g, or 150 to 250 m2/g; and a pore volume of from 0.25 to 1.0 cm3/g, or 0.35 to 0.8 cm3/g. More generally, any convenient size, shape, and/or pore size distribution for a catalyst suitable for hydrotreatment of a distillate (including lubricant base oil) boiling range feed in a conventional manner may be used. It is within the scope of the present disclosure that more than one type of hydroprocessing catalyst can be used in one or multiple reaction vessels.
The at least one Group VIII non-noble metal, in oxide form, can typically be present in an amount ranging from 2 wt % to 40 wt %, preferably from 4 wt % to 15 wt %. The at least one Group VI metal, in oxide form, can typically be present in an amount ranging from 2 wt % to 70 wt %, preferably for supported catalysts from 6 wt % to 40 wt % or from 10 wt % to 30 wt %. These weight percents are based on the total weight of the catalyst. Suitable metal catalysts include cobalt/molybdenum (1-10% Co as oxide, 10-40% Mo as oxide), nickel/molybdenum (1-10% Ni as oxide, 10-40% Co as oxide), or nickel/tungsten (1-10% Ni as oxide, 10-40% W as oxide) on alumina, silica, silica-alumina, or titania.
The hydrotreatment is carried out in the presence of hydrogen. A hydrogen stream is, therefore, fed or injected into a vessel or reaction zone or hydroprocessing zone in which the hydroprocessing catalyst is located. Hydrogen, which is contained in a hydrogen “treat gas,” is provided to the reaction zone. Treat gas, as referred to in this disclosure, can be either pure hydrogen or a hydrogen-containing gas, which is a gas stream containing hydrogen in an amount that is sufficient for the intended reaction(s), optionally including one or more other gasses (e.g., nitrogen and light hydrocarbons such as methane), and which will not adversely interfere with or affect either the reactions or the products. Impurities, such as H2S and NH3 are undesirable and would typically be removed from the treat gas before it is conducted to the reactor. The treat gas stream introduced into a reaction stage will preferably contain at least 50 vol. % and more preferably at least 75 vol. % hydrogen.
Hydrogen can be supplied at a rate of from 100 SCF/B (standard cubic feet of hydrogen per barrel of feed) (17 Nm3/m3) to 1500 SCF/B (253 Nm3/m3). Preferably, the hydrogen is provided in a range of from 200 SCF/B (34 Nm3/m3) to 1200 SCF/B (202 Nm3/m3). Hydrogen can be supplied co-currently with the input feed to the hydrotreatment reactor and/or reaction zone or separately via a separate gas conduit to the hydrotreatment zone.
Hydrotreating conditions can include temperatures of 200° C. to 450° C., or 315° C. to 425° C.; pressures of 250 psig (1.8 MPag) to 5000 psig (34.6 MPag) or 300 psig (2.1 MPag) to 3000 psig (20.8 MPag); liquid hourly space velocities (LHSV) of 0.1 hr−1 to 10 hr−1; and hydrogen treat rates of 200 scf/B (35.6 m3/m3) to 10,000 scf/B (1781 m3/m3), or 500 (89 m3/m3) to 10,000 scf/B (1781 m3/m3).
In various aspects, the reaction conditions in the reaction system can be selected to generate a desired level of conversion of a feed. Conversion of the feed can be defined in terms of conversion of molecules that boil above a temperature threshold to molecules below that threshold. The conversion temperature can be any convenient temperature, such as 700° F. (371° C.). In an aspect, the amount of conversion in the stage(s) of the reaction system can be selected to enhance diesel production while achieving a substantial overall yield of fuels. The amount of conversion can correspond to the total conversion of molecules within any stage of the fuels hydrocracker or other reaction system that is used to hydroprocess the lower boiling portion of the feed from the vacuum distillation unit. Suitable amounts of conversion of molecules boiling above 700° F. to molecules boiling below 700° F. include converting at least 55% of the 700° F.+ portion of the feedstock to the stage(s) of the reaction system, such as at least 60% of the 700° F.+ portion, or at least 70%, or at least 75%. Additionally or alternately, the amount of conversion for the reaction system can be 85% or less, or 80% or less, or 75% or less, or 70% or less. Still larger amounts of conversion may also produce a suitable hydrocracker bottoms for forming lubricant base oils, but such higher conversion amounts will also result in a reduced yield of lubricant base oils. Reducing the amount of conversion can increase the yield of lubricant base oils, but reducing the amount of conversion to below the ranges noted above may result in hydrocracker bottoms that are not suitable for formation of Group II, Group II+, or Group III lubricant base oils.
in order to achieve a desired level of conversion, the fuel hydrocracking reaction system or other reaction system can include at least one hydrocracking catalyst. Hydrocracking catalysts typically contain sulfided base metals on acidic supports, such as amorphous silica alumina, cracking zeolites such as USY, or acidified alumina. Often these acidic supports are mixed or bound with other metal oxides such as alumina, titania or silica. Examples of suitable acidic supports include acidic molecular sieves, such as zeolites or silicoaluminophosphates. One example of suitable zeolite is USY, such as a USY zeolite with cell size of 24.25 Angstroms or less. Additionally or alternately, the catalyst can be a low acidity molecular sieve, such as a USY zeolite with a Si to Al ratio of at least 20, and preferably at least 40 or 50. Zeolite Beta is another example of a potentially suitable hydrocracking catalyst. Non-limiting examples of metals for hydrocracking catalysts include metals or combinations of metals that include at least one Group VIII metal, such as nickel, nickel-cobalt-molybdenum, cobalt-molybdenum, nickel-tungsten, nickel-molybdenum, and/or nickel-molybdenum-tungsten. Additionally or alternately, hydrocracking catalysts with noble metals can also be used. Non-limiting examples of noble metal catalysts include those based on platinum and/or palladium. Support materials which may be used for both the noble and non-noble metal catalysts can comprise a refractory oxide material such as alumina, silica, alumina-silica, kieselguhr, diatomaceous earth, magnesia, zircons, or combinations thereof, with alumina, silica, alumina-silica being the most common (and preferred, in one embodiment).
In various aspects, the conditions selected for hydrocracking for fuels hydrocracking and/or lubricant base stock production can depend on the desired level of conversion, the level of contaminants in the input feed to the hydrocracking stage, and potentially other factors. For example, hydrocracking conditions in the first stage and/or the second stage can be selected to achieve a desired level of conversion in the reaction system. A hydrocracking process in the first stage (or otherwise under sour conditions) can be carried out at temperatures of 550° F. (288° C.) to 840° F. (449° C.), hydrogen partial pressures of from 250 psig to 5000 psig (1.8 MPag to 34.6 MPag), liquid hourly space velocities of from 0.05 h−1 to 10 h−1, and hydrogen treat gas rates of from 35.6 m3/m3 to 181 m3/m3 (200 SCF/B to 10,000 SCF/B). In other embodiments, the conditions can include temperatures in the range of 600° F. (343° C.) to 815° F. (435° C.), hydrogen partial pressures of from 500 psig to 3000 psig (3.5 MPag-20.9 MPag), and hydrogen treat gas rates of from 213 m3/m3 to 1068 m3/m3 (1200 SCF/B to 6000 SCF/B). The LHSV relative to only the hydrocracking catalyst can be from 0.25 h−1 to 50 h−1 if such as from 0.5 h−1 to 20 h−1, and preferably from 1.0 h−1 to 4.0 h−1.
In some aspects, a portion of the hydrocracking catalyst and/or the dewaxing catalyst can be contained in a second reactor stage. In such aspects, a first reaction stage of the hydroprocessing reaction system can include one or more hydrotreating and/or hydrocracking catalysts. The conditions in the first reaction stage can be suitable for reducing the sulfur and/or nitrogen content of the feedstock. A separator can then be used in between the first and second stages of the reaction system to remove gas phase sulfur and nitrogen contaminants. One option for the separator is to simply perform a gas-liquid separation to remove contaminant. Another option is to use a separator such as a flash separator that can perform a separation at a higher temperature. Such a high temperature separator can be used, for example, to separate the feed into a portion boiling below a temperature cut point, such as 350° F. (177° C.) or 400° F. (204° C.), and a portion boiling above the temperature cut point. In this type of separation, the naphtha boiling range portion of the effluent from the first reaction stage can also be removed, thus reducing the volume of effluent that is processed in the second or other subsequent stages. Of course, any low boiling contaminants in the effluent from the first stage would also be separated into the portion boiling below the temperature cut point. If sufficient contaminant removal is performer in the first stage, the second stage can be operated as a “sweet” or low contaminant stage.
Still another option can be to use a separator between the first and second stages of the hydroprocessing reaction system that can also perform at least a partial fractionation of the effluent from the first stage. In this type of aspect, the effluent from the first hydroprocessing stage can be separated into at least a portion boiling below the distillate (such as diesel) fuel range, a portion boiling in the distillate fuel range, and a portion boiling above the distillate fuel range. The distillate fuel range can be defined based on a conventional diesel boiling range, such as having a lower end cut point temperature of at least 350° F. (177° C.) or at least 400° F. (204° C.) to having an upper end cut point temperature of 700° F. (371° C.) or less or 650° F. (343° C.) or less. Optionally, the distillate fuel range can be extended to include additional kerosene, such as by selecting a lower end cut point temperature of at least 300° F. (149° C.).
In aspects where the inter-stage separator is also used to produce a distillate fuel fraction, the portion boiling below the distillate fuel fraction includes, naphtha boiling range molecules, light ends, and contaminants such as H2S. These different products can be separated from each other in any convenient manner. Similarly, one or more distillate fuel fractions can be formed, if desired, from the distillate boiling range fraction. The portion boiling above the distillate fuel range represents the potential lubricant base oils. In such aspects, the portion boiling above the distillate fuel range is subjected to further hydroprocessing in a second hydroprocessing stage.
A hydrocracking process in a second stage (r otherwise under non-sour conditions) can be performed under conditions similar to those used for a first stage hydrocracking process, or the conditions can be different. In an embodiment, the conditions in a second stage can have less severe conditions than a hydrocracking process in a first (sour) stage. The temperature in the hydrocracking process can be 40° F. (22° C.) less than the temperature for a hydrocracking process in the first stage, or 80° F. (44° C.) less, or 120° F. (66° C.) less. The pressure for a hydrocracking process in a second stage can be 100 psig (690 kPa) less than a hydrocracking process in the first stage, or 200 psig (1380 kPa) less, or 300 psig (2070 kPa) less. Additionally or alternately, suitable hydrocracking conditions for a second (non-sour) stage can include, but are not limited to, conditions similar to a first or sour stage. Suitable hydrocracking conditions can include temperatures of 550° F. (288° C.) to 840° F. (449° C.), hydrogen partial pressures of from 250 psig to 5000 psig (1.8 MPag to 34.6 MPag), liquid hourly space velocities of from 0.05 h−1 to 10 h−1, and hydrogen treat gas rates of from 35.6 m3/m3 to 1781 m3/m3 (200 SCF/B to 10,000 SCF/B). In other embodiments, the conditions can include temperatures in the range of 600° F. (343° C.) to 815° F. (435° C.), hydrogen partial pressures of from 500 psig to 3000 psig (3.5 MPag-20.9 MPag), and hydrogen treat gas rates of from 213 m3/m3 to 1068 m3/m3 (1200 SCF/B to 6000 SCF/B). The liquid hourly space velocity can vary depending on the relative amount of hydrocracking catalyst used versus dewaxing catalyst. Relative to the combined amount of hydrocracking and dewaxing catalyst, the LHSV can be from 0.2 h−1 to 10 h−1, such as from 0.5 h to 5 h and/or from 1 h−1 to 4 h−1. Depending on the relative amount of hydrocracking catalyst and dewaxing catalyst used, the LHSV relative to only the hydrocracking catalyst can be from 0.25 h−1 to 50 h−1 such as from 0.5 h−1 to 20 h−1, and preferably from 1.0 h−1 to 4.0 h−1.
In still another embodiment, the same conditions can be used for hydrotreating and hydrocracking beds or stages, such as using hydrotreating conditions for both or using hydrocracking conditions for both. In yet another embodiment, the pressure for the hydrotreating and hydrocracking beds or stages can be the same.
In order to enhance diesel production and to improve the quality of lubricant base oils produced from the bottoms of the reaction system, at least a portion of the catalyst in the final reaction stage can be a dewaxing catalyst. Typically, the dewaxing catalyst is located in a bed downstream from any hydrocracking catalyst stages and/or any hydrocracking catalyst present in a stage. This can allow the dewaxing to occur on molecules that have already been hydrotreated or hydrocracked to remove a significant fraction of organic sulfur- and nitrogen-containing species. The dewaxing catalyst can be located in the same reactor as at least a portion of the hydrocracking catalyst in a stage. Alternatively, the effluent from a reactor containing hydrocracking catalyst, possibly after a gas-liquid separation, can be fed into a separate stage or reactor containing the dewaxing catalyst. Depending on the aspects, the amount of hydrocracking catalyst relative to the amount of dewaxing catalyst can vary from 10:90 to 90:10, such as from 20:80 to 70:30, and preferably from 60:40 to 40:60. Optionally, in some aspects it may be possible to omit the hydrocracking catalyst, so that only a dewaxing catalyst is used. Optionally, in some aspects it may be possible to omit the dewaxing catalyst, so that only a hydrocracking catalyst is used.
Suitable dewaxing catalysts can include molecular sieves such as crystalline aluminosilicates (zeolites). In an embodiment, the molecular sieve can comprise, consist essentially of, or be ZSM-5, ZSM-22, ZSM-23, ZSM-35, ZSM-48, zeolite Beta, or a combination thereof, for example ZSM-23 and/or ZSM-48, or ZSM-48 and/or zeolite Beta. Optionally but preferably, molecular sieves that are selective for dewaxing by isomerization as opposed to cracking can be used, such as ZSM-48, zeolite Beta, ZSM-23, or a combination thereof. Additionally or alternately, the molecular sieve can comprise, consist essentially of, or be a 10-member ring 1-D molecular sieve. Examples include EU-1, ZSM-35 (or ferrierite), ZSM-11, ZSM-57, NU-87, SAPO-11, ZSM-48. ZSM-23, and ZSM-22. Preferred materials are EU-2, EU-11, ZBM-30, ZSM-48, or ZSM-23. ZSM-48 is most preferred. Note that a zeolite having the ZSM-23 structure with a silica to alumina ratio of from 20:1 to 40:1 can sometimes be referred to as SSZ-32. Other molecular sieves that are isostructural with the above materials include Theta-1, NU-10, EU-13, KZ-1, and NU-23. Optionally but preferably, the dewaxing catalyst can include a binder for the molecular sieve, such as alumina, titania, silica, silica-alumina, zirconia, or a combination thereof, for example alumina and/or titania ter silica and/or zirconia and/or titania.
Preferably, the dewaxing catalysts used in processes according to the disclosure are catalysts with a low ratio of silica to alumina. For example, for ZSM-48, the ratio of silica to alumina, in the zeolite can be less than 200:1, such as less than 110:1, or less than 100:1, or less than 90:1, or less than 75:1. In various embodiments, the ratio of silica to alumina can be from 50:1 to 200:1, such as 60:1 to 160:1, or 70:1 to 100:1.
In various embodiments, the catalysts according to the disclosure further include a metal hydrogenation component. The metal hydrogenation component is typically a. Group VI and/or a Group VIII metal. Preferably, the metal hydrogenation component is a Group VIII noble metal. Preferably, the metal hydrogenation component is Pt, Pd, or a mixture thereof. In an alternative preferred embodiment, the metal hydrogenation component can be a combination of a non-noble Group VIII metal with a Group VI metal. Suitable combinations can include Ni, Co, or Fe with Mo or W, preferably Ni with Mo or W.
The metal hydrogenation component may be added to the catalyst in any convenient manner. One technique for adding the metal hydrogenation component is by incipient wetness. For example, after combining a zeolite and a binder, the combined zeolite and binder can be extruded into catalyst particles. These catalyst particles can then be exposed to a solution containing a suitable metal precursor. Alternatively, metal can be added to the catalyst by ion exchange, where a metal precursor is added to a mixture of zeolite (or zeolite and binder) prior to extrusion.
The amount of metal in the catalyst can be at least 0.1 wt % based on catalyst, or at least 0.15 wt %, or at least 0.2 wt %, or at least 0.25 wt %, or at least 0.3 wt %, or at least 0.5 wt % based on catalyst. The amount of metal in the catalyst can be 20 wt % or less based on catalyst, or 10 wt % or less, or 5 wt % or less, or 2.5 wt % or less, or 1 wt % or less. For embodiments where the metal is Pt, Pd, another Group VIII noble metal, or a combination thereof, the amount of metal can be from 0.1 to 5 wt %, preferably from 0.1 to 2 wt %, or 0.25 to 1.8 wt %, or 0.4 to 1.5 wt %. For embodiments where the metal is a combination of a non-noble Group VIII metal with a Group VI metal, the combined amount of metal can be from 0.5 wt % to 20 wt %, or 1 wt % to 15 wt %, or 2.5 wt % to 10 wt %.
The dewaxing catalysts useful in processes according to the disclosure can also include a binder. In some embodiments, the dewaxing catalysts used in process according to the disclosure are formulated using a low surface area binder, a low surface area binder represents a binder with a surface area of 100 m2/g or less, or 80 m2/g or less, or 70 m2/g or less. The amount of zeolite in a catalyst formulated using a binder can be from 30 wt % zeolite to 90 wt % zeolite relative to the combined weight of binder and zeolite. Preferably, the amount of zeolite is at least 50 wt % of the combined weight of zeolite and binder, such as at least 60 wt % or from 65 wt % to 80 wt %.
A zeolite can be combined with binder in any convenient manner. For example, a bound catalyst can be produced by starting with powders of both the zeolite and binder, combining and mulling the powders with added water to form a mixture, and then extruding the mixture to produce a bound catalyst of a desired size. Extrusion aids can also be used to modify the extrusion flow properties of the zeolite and binder mixture. The amount of framework alumina in the catalyst may range from 0.1 to 3.33 wt %, or 0.1 to 2.7 wt %, or 0.2 to 2 wt %, or 0.3 to 1 wt %.
Process conditions in a catalytic dewaxing zone in a sour environment can include a temperature of from 200 to 450° C., preferably 270 to 400° C., a hydrogen partial pressure of from 1.8 MPag to 34.6 MPag (250 psig to 5000 psig), preferably 4.8 MPag to 20.8 MPag, and a hydrogen circulation rate of from 35.6 m3/m3 (200 SCF/B) to 1781 m3/m3 (10,000 scf/B), preferably 178 m3/m3 (1000 SCF/B) to 890.6 m3/m3 (5000 SCF/B). In still other embodiments, the conditions can include temperatures in the range of 600° F. (343° C.) to 815° F. (435° C.), hydrogen partial pressures of from 500 psig to 3000 psig (3.5 MPag-20.9 MPag), and hydrogen treat gas rates of from 213 m3/m3 to 1068 m3/m3 (1200 SCF/B to 6000 SCF/B). These latter conditions may be suitable, for example, if the dewaxing stage is operating under sour conditions. The liquid hourly space velocity can vary depending on the relative amount of hydrocracking catalyst used versus dewaxing catalyst. Relative to the combined amount of hydrocracking and dewaxing catalyst, the LHSV can be from 0.2 h−1 to 10 h−1, such as from 0.5 h−1 to 5 h−1 and/or from 1 h−1 to 4 h−1. Depending on the relative amount of hydrocracking catalyst and dewaxing catalyst used, the LHSV relative to only the dewaxing catalyst can be from 0.25 h−1 to 50 h−1 such as from 0.5 h−1 to 20 h−1 and preferably from 1.0 h−1 to 4.0 h−1.
Additionally or alternately, the conditions for dewaxing can be selected based on the conditions for a preceding reaction in the stage, such as hydrocracking conditions or hydrotreating conditions. Such conditions can be further modified using a quench between previous catalyst bed(s) and the bed for the dewaxing catalyst. Instead of operating the dewaxing process at a temperature corresponding to the exit temperature of the prior catalyst bed, a quench can be used to reduce the temperature for the hydrocarbon stream at the beginning of the dewaxing catalyst bed. One option can be to use a quench to have a temperature at the beginning of the dewaxing catalyst bed that is the same as the outlet temperature of the prior catalyst bed. Another option can be to use a quench to have a temperature at the beginning of the dewaxing catalyst bed that is at least 10° F. (6° C.) lower than the prior catalyst bed, or at least 20° F. (11° C.) lower, or at least 30° F. (16° C.) lower, or at least 40° F. (21° C.) lower.
As still another option, the dewaxing catalyst in the final reaction stage can be mixed with another type of catalyst, such as hydrocracking catalyst, in at least one bed in a reactor. As yet another option, a hydrocracking catalyst and a dewaxing catalyst can be co-extruded with a single binder to form a mixed functionality catalyst.
Hydrofinishing and/or Aromatic Saturation Process
In some aspects, a hydrofinishing and/or aromatic saturation stage can also be provided. The hydrofinishing and/or aromatic saturation can occur after the last hydrocracking or dewaxing stage. The hydrofinishing and/or aromatic saturation can occur either before or after fractionation. If hydrofinishing and/or aromatic saturation occurs after fractionation, the hydrofinishing can be performed on one or more portions of the fractionated product, such as being performed on the bottoms from the reaction stage (i.e., the hydrocracker bottoms). Alternatively, the entire effluent from the last hydrocracking or dewaxing process can be hydrofinished and/or undergo aromatic saturation.
In some situations, a hydrofinishing process and an aromatic saturation process can refer to a single process performed using the same catalyst. Alternatively, one type of catalyst or catalyst system can be provided to perform aromatic saturation, while a second catalyst or catalyst system can be used for hydrofinishing. Typically a hydrofinishing and/or aromatic saturation process will be performed in a separate reactor from dewaxing or hydrocracking processes for practical reasons, such as facilitating use of a lower temperature for the hydrofinishing or aromatic saturation process. However, an additional hydrofinishing reactor following a hydrocracking or dewaxing process but prior to fractionation could still be considered part of a second stage of a reaction system conceptually.
Hydrofinishing and/or aromatic saturation catalysts can include catalysts containing Group VI metals, Group VIII metals, and mixtures thereof. In an embodiment, preferred metals include at least one metal sulfide having a strong hydrogenation function. In another embodiment, the hydrofinishing catalyst can include a Group VIII noble metal, such as Pt, Pd, or a combination thereof. The mixture of metals may also be present as bulk metal catalysts wherein the amount of metal is 30 wt % or greater based on catalyst. Suitable metal oxide supports include low acidic oxides such as silica, alumina, silica-aluminas or titanic, preferably alumina. The preferred hydrofinishing catalysts for aromatic saturation will comprise at least one metal having relatively strong hydrogenation function on a porous support. Typical support materials include amorphous or crystalline oxide materials such as alumina, silica, and silica-alumina. The support materials may also be modified, such as by halogenation, or in particular fluorination. The metal content of the catalyst is often as high as 20 wt % for non-noble metals. In an embodiment, a preferred hydrofinishing catalyst can include a crystalline material belonging to the M41S class or family of catalysts. The M41S family of catalysts are mesoporous materials having high silica content. Examples include MCM-41, MCM-48 and MCM-50. A preferred member of this class is MCM-41. If separate catalysts are used for aromatic saturation and hydrofinishing, an aromatic saturation catalyst can be selected based on activity and/or selectivity for aromatic saturation, while a hydrofinishing catalyst can be selected based on activity for improving product specifications, such as product color and polynuclear aromatic reduction.
Hydrofinishing conditions can include temperatures from 125° C. to 425° C., preferably 180° C. to 280° C., a hydrogen partial pressure from 500 psig (3.4 MPa) to 3000 psig (20.7 MPa), preferably 1500 psig (10.3 MPa) to 2500 psig (17.2 MPa), and liquid hourly space velocity from 0.1 hr−1 to 5 hr−1 LHSV, preferably 0.5 hr−1 to 1.5 hr−1. Additionally, a hydrogen treat gas rate of from 35.6 m3/m3 to 1781 m3/m3 (200 SCF/B to 10,000 SCF/B) can be used.
After hydroprocessing, the bottoms from the hydroprocessing reaction system can have a viscosity index (VI) of at least 95, such as at least 105 or at least 110. The amount of saturated molecules in the bottoms from the hydroprocessing reaction system can be at least 90%, while the sulfur content of the bottoms is less than 300 wppm. Thus, the bottoms from the hydroprocessing reaction system can be suitable for use as a Group II, Group II+, or Group III lubricant base oil.
In the configuration shown in
The highest boiling portion 173 from separator 160 is then passed into second hydroprocessing stage 170. In the configuration shown in
In the following examples, a lower boiling portion of a lubricant base oil feedstock was mixed with a fuels hydrocracking feed for hydroprocessing. The hydroprocessing configuration included hydrotreatment of the combined feed; gas-liquid separation to remove contaminant gases from the hydrotreated liquid effluent; hydrocracking of the hydrotreated liquid effluent; and dewaxing of the effluent from hydrocracking. The hydroprocessing conditions, in combination, correspond to conditions suitable for sufficient conversion of the feedstock to produce a lubricant base oil yield of 20 wt %.
The hydrotreatment was performed by exposing the combined feed to a conventional NiMo catalyst in the presence of hydrogen at a temperature of 675° F. (357° C.). The hydrocracking was performed by exposing the hydrotreated liquid effluent to a USY catalyst in the presence of hydrogen at, the temperature shown below in Table 1. The USY catalyst was a commercially available low acidity catalyst with an Si to Al content of at least 20 that include a noble metal as a hydrogenation metal. The hydrocracked effluent was then dewaxed in the presence of an alumina-bound ZSM-48 dewaxing catalyst having an Si to Al ratio of 90:1 or less with 0.6 wt % of Pt supported on the catalyst. The dewaxing temperature is shown in Table 1. The ratio by volume of hydrocracking catalyst to dewaxing catalyst was 1:1. The LHSV over the hydrocracking catalyst was 4 hr−1 and the LHSV over the dewaxing catalyst was 4 hr−1.
The combined feedstock corresponded to a combination of a light cycle oil feed having a boiling range of from 350° F. (177° C.) to 700° F. (371° C.) and a lower boiling portion of one of two vacuum gas oil lubricant feeds having a boiling range of from 700° F. (371° C.) to 900° F. (482° C.). The feed included 65 wt % of the light cycle oil and 35 wt % of the lower boiling portion of the lubricant feed.
After processing, the feed was fractionated to recover the lubricant boiling range portion. As shown in Table 1, the lubricant base oil yield was 20 wt % for both types of lubricant feeds. Similar viscosity index values were also obtained for both types of lubricant feeds, resulting in a lubricant base oil suitable for use in forming Group II+ light neutral base oils.
Embodiment 1. A method for forming fuel and lubricant products, comprising: separating a feedstock into at least a first fraction having a T5 boiling point greater than 600° F. (316° C.) and a T95 boiling point of 1150° F. (621° C.) or less and a bottoms fraction; deasphalting the bottoms fraction to form a deasphalted bottoms fraction and an asphalt product; extracting the deasphalted bottoms in the presence of an extraction solvent to form a raffinate stream and an extract stream, an aromatics content of the raffinate stream being lower than an aromatics content of the deasphalted bottoms; dewaxing the raffinate stream in the presence of a dewaxing solvent to form a lubricant base oil product and a wax product; hydroprocessing a combined feedstock corresponding to the first fraction and a fuels feedstock, at least a portion of the combined feedstock having a boiling point greater than 700° F. (371° C.), the fuels feedstock having a T5 boiling point greater than 350° F. (177° C.) and a T95 boiling point of 1150° F. (621° C.) or less, under first effective hydroprocessing conditions to form a hydroprocessed effluent; separating the hydroprocessed effluent to form at least a gas phase effluent and a liquid phase effluent; hydroprocessing at least a portion of the liquid phase effluent in the presence of at least a dewaxing catalyst under second effective hydroprocessing conditions to form a dewaxed effluent, the first effective hydroprocessing conditions and the second effective hydroprocessing conditions being effective for conversion of at least 60% of the portion of the combined feedstock boiling above 700° F. (371° C.) to a portion boiling below 700° F. (371° C.); and fractionating the dewaxed effluent to form at least a distillate fuel product having a T95 boiling point of 750° F. (399° C.) or less and a lubricant base oil product having a viscosity index of at least 80, a sulfur content of 300 wpm or less, and an aromatics content of 10 wt % or less.
Embodiment 2. The method of Embodiment 1, wherein separating the feedstock comprises: separating the feedstock into at least a first fraction having a T5 boiling point greater than 600° F. (316° C.) and a T95 boiling point of 950° F. (510° C.) or less, a second fraction having a T5 boiling point of at least the T95 boiling point of the first fraction, and a bottoms fraction; and wherein extracting the deasphalted bottoms comprises: extracting the deasphalted bottoms and the second fraction in the presence of an extraction solvent to form a raffinate stream and an extract stream, an aromatics content of the raffinate stream being lower than an aromatics content of the combined deasphalted bottoms and second fraction.
Embodiment 3. The method of Embodiment 1, wherein separating the feedstock comprises separating the feedstock into at least a first fraction having a T5 boiling point greater than 600° F. (316° C.) and a T95 boiling point of 950° F. (510° C.) or less, a second fraction having a T5 boiling point of at least the T95 boiling point of the first fraction, and a bottoms fraction; the method further comprising extracting the second fraction in the presence of an extraction solvent to form a second raffinate stream and a second extract stream, an aromatics content of the second raffinate stream being lower than an aromatics content of the second fraction; and dewaxing the second raffinate stream in the presence of a dewaxing solvent to form a second lubricant base oil product and a second wax product.
Embodiment 4. The method of Embodiments 2 or 3, wherein the first fraction has a T95 boiling point of 900° F. or less, such as 850° F. or less, and the second fraction has a T5 boiling point of at least 850° F., such as at least 900° F.
Embodiment 5. The method of any of Embodiments 2 to 4, wherein the second fraction has a T95 boiling point of 1100° F. or less.
Embodiment 6. The method of any of the above embodiments, wherein the first fraction has a T5 boiling point of at least 650° F., such as at least 700° F.
Embodiment 7. The method of any of the above embodiments, wherein the first effective hydroprocessing conditions comprise exposing the combined feedstock to a hydrotreating catalyst, a hydrocracking catalyst, or a combination thereof under effective hydrotreating conditions, effective hydrocracking conditions, or a combination thereof.
Embodiment 8. The method of Embodiment 7, wherein the hydrocracking catalyst is USY, zeolite Beta, or a combination thereof.
Embodiment 9. The method of any of the above embodiments, wherein the second effective hydroprocessing conditions comprise effective dewaxing conditions.
Embodiment 10. The method of any of the above embodiments, wherein the second effective hydroprocessing conditions further comprise exposing the at least a portion of the liquid effluent to a hydrocracking catalyst under second effective hydrocracking conditions.
Embodiment 11. The method of any of the above embodiments, wherein the first effective hydroprocessing conditions and the second effective hydroprocessing conditions are effective for conversion of at least 70% of the portion of the combined feedstock boiling above 700° F. (371° C.) to a portion boiling below 700° F. (371° C.), such as at least 75%.
Embodiment 12. The method of any of the above embodiments, wherein separating the hydroprocessed effluent to form at least a gas phase effluent comprises separating the hydroprocessed effluent to form a lower boiling fraction having a T95 boiling point of 400° F. (204° C.) or less, such as 350° F. (177° C.) or less.
Embodiment 13. The method of any of the above embodiments, wherein separating the hydroprocessed effluent to form at least a liquid phase effluent comprises forming a first liquid phase effluent with a T95 boiling point of 700° F. (371° C.) or less, such as 650° F. (343° C.) or less, and a second liquid phase effluent having a T5 boiling point of at least 650° F. (343° C.), such as at least 700° F. (371° C.).
Embodiment 14. The method of any of the above embodiments, wherein the liquid phase effluent has a sulfur content of 300 wppm or less, such as 100 wppm or less.
Embodiment 15. The method of any of the above embodiments, further comprising dividing an initial feed into the feedstock and the fuels feedstock.
Embodiment 16. The method of any of the above embodiments, further comprising hydrofinishing at least a portion of the dewaxed effluent under effective dewaxing conditions.
Embodiment 17. The method of any of the above embodiments, wherein the first effective hydroprocessing conditions comprise a temperature of 550° F. (2° C.) to 840° F. (449° C.), hydrogen partial pressures of from 250 psig to 5000 psig (1.8 MPag to 34.6 MPag), and a hydrogen treat gas rate of from 35.6 m3/m3 to 1781 m3/m3 (200 SCF/B to 10,000 SCF/B), and wherein the second effective hydroprocessing conditions comprise a temperature of from 200 to 450° C., preferably 270 to 400° C., a hydrogen partial pressure of from 1.8 MPag to 34.6 MPag (250 psig to 5000 psig), preferably 4.8 MPag to 20.8 MPag and a hydrogen treat gas rate of from 35.6 m3/m3 (200 SCF/B) to 1781 m3/m3 (10,000 scf/B), preferably 178 m3/m3 (1000 SCF/B) to 890.6 m3/m3 (5000 SCF/B).
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 disclosure have been described with particularity, it will be understood that various other modifications will be apparent to and can be readily made by those skilled in the art without departing from the spirit and scope of the disclosure. 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 disclosure, including all features which would be treated as equivalents thereof by those skilled in the art to which the disclosure pertains. All documents described herein are incorporated by reference herein, including any priority documents and/or testing procedures to the extent they are not inconsistent with this text.
The present disclosure has been described above with reference to numerous embodiments and specific examples. Many variations will 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.
