Patent Application
20200199464
Naphthenic compositions derived from fluid catalytic cracking product fractions are provided, along with systems and methods for forming such naphthenic compositions. Examples of naphthenic compositions include naphthenic base oils, specialty industrial oils, and naphthenic and/or aromatic hydrocarbon fluids.
Fluid catalytic cracking (FCC) processes are commonly used in refineries as a method for converting feedstocks, without requiring additional hydrogen, to produce lower boiling fractions suitable for use as fuels. While FCC processes can be effective for converting a majority of a typical input feed, under conventional operating conditions at least a portion of the resulting products can correspond to a fraction that exits the process as a “bottoms” fraction. This bottoms fraction can typically be a high boiling range fraction, such as a ˜650° F.+(˜343° C.+) fraction. Because this bottoms fraction may also contain FCC catalyst fines, this fraction can sometimes be referred to as a catalytic slurry oil.
U.S. Pat. No. 8,691,076 describes methods for manufacturing naphthenic base oils from effluences of a fluidized catalytic cracking unit. The methods describe using an FCC unit to process an atmospheric resid to form a fuels fraction, a light cycle oil fraction, and a slurry oil fraction. Portions of the light cycle oil and/or the slurry oil are then hydrotreated and dewaxed to form naphthenic base oils. U.S. Pat. No. 8,585,889 describes a variation where the slurry oil fraction is deasphalted prior to hydrotreatment and dewaxing. U.S. Pat. No. 8,911,613 describes still other variations where the light cycle oil and/or slurry oil fractions are co-processed in the hydrotreating and dewaxing stages with a deasphalted oil from another source.
U.S. Patent Application Publication 2017/0002279 describes methods for processing catalytic slurry oils under fixed bed hydrotreating conditions. U.S. Patent Application Publication 2017/0002273 describes various types of fuels that can be formed based on fixed bed hydrotreatment of catalytic slurry oils.
In an aspect, a method is provided for processing a product fraction from a fluid catalytic cracking (FCC) process. The method can include exposing a feed comprising a catalytic slurry oil, the feed comprising a 343° C.+ portion, to a hydrotreating catalyst under effective hydrotreating conditions to form a hydrotreated effluent, the 343° C.+ portion of the feed comprising a density of 1.06 g/cm3 or more. The method can further include exposing at least a portion of the 343° C.+ portion to a hydroprocessing catalyst under effective hydroprocessing conditions to form a hydroprocessed effluent, wherein a C5+ portion of the hydroprocessed effluent comprises 50 mol % or more naphthenic carbons and 500 wppm or less of sulfur.
In another aspect, a naphthenic base oil composition is provided that includes 500 wppm or less sulfur, 18 mol % to 30 mol % paraffinic carbons, 50 mol % or more of naphthenic carbons, a kinematic viscosity at 100° C. of 2.0 cSt to 30 cSt, a viscosity index of 25 or less, and a T5 distillation point of 260° C. or more.
In various aspects, systems and methods are provided for producing naphthenic compositions corresponding to various types of products, such as naphthenic base oil, specialty industrial oils, and/or hydrocarbon fluids. The methods of producing the naphthenic compositions can include exposing a heavy fraction from a fluid catalytic cracking (FCC) process, such as a FCC bottoms fraction (i.e., a catalytic slurry oil), to hydroprocessing conditions corresponding to hydrotreating and/or aromatic saturation conditions. The hydroprocessing can be performed without exposing the FCC heavy fraction to catalytic dewaxing conditions. By using a FCC heavy fraction as a feedstock rather than a conventional feed, naphthenic product compositions can be formed that have unexpected properties, such as compositions with unexpectedly low viscosity index values relative to the naphthenic carbon content of the compositions. Additionally, by minimizing or avoiding exposure of the FCC heavy fraction feedstock to catalytic dewaxing conditions, naphthenic product compositions can be formed that have unexpected combinations of pour point, kinematic viscosity, and viscosity index relative to the amount of naphthenic carbon in the composition.
Catalytic slurry oils (or other names used to refer to FCC bottoms fractions) are high sulfur and high aromatic content fractions generated during FCC processing. Catalytic slurry oils typically have an initial boiling point and/or T5 distillation point of 343° C. or more. The final boiling point and/or T95 distillation point can vary, but is commonly 565° C. or more. Traditionally, the product disposition for catalytic slurry oil is to use the catalytic slurry oil as a blend component for forming regular sulfur fuel oils, or as feedstock for formation of carbon black. Due in part to upcoming and/or planned changes in regulations for sulfur content in fuel oils, however, alternative dispositions for catalytic slurry oils are desirable.
Based on the highly aromatic nature of catalytic slurry oils, some possible alternative dispositions correspond to using catalytic slurry oils as a feedstock for production of aromatic products or naphthenic products. However, catalytic slurry oils can also contain up to 6.0 wt % or more of sulfur as well as substantial amounts of nitrogen. Methods for removing such heteroatoms while preserving the desired aromatic/naphthenic character of the catalytic slurry oil are needed in order to produce commercially viable products.
It has been unexpectedly discovered that catalytic slurry oil can be used to make a variety of naphthenic product compositions that are traditionally made from higher value feeds, such as naphthenic crude oils. In various aspects, single stage or (preferably) multi-stage hydroprocessing of catalytic slurry oil can be used to form naphthenic product compositions. By adjusting the processing conditions, including optionally performing aromatic saturation and/or solvent processing, naphthenic hydrocarbon mixtures can be produced with desirable combinations of compositional and physical properties, such as hydrocarbon mixtures with high naphthenic carbon content, low sulfur content, and targeted values for viscosity and/or viscosity index.
In various aspects, any convenient number of hydroprocessing stages can be used for the hydrotreatment and/or aromatic saturation of the FCC heavy fraction. For example, single stage hydrotreatment may be suitable for forming an effluent containing less than 250 wppm sulfur and 50 wt % to 75 wt % aromatics. Various naphthenic compositions can then be formed from such an effluent, including naphthenic compositions having a kinematic viscosity at 100° C. of 2.5 cSt to 35 cSt. Such naphthenic compositions can include 50 wt % to 90 wt % aromatics. Of course, any convenient number of hydrotreatment stages could be used to make such an effluent. As another example, multi-stage hydroprocessing may be suitable for forming an effluent containing less than 250 wppm sulfur and 60 wt % or more naphthenes (or 70 wt % or more). Optionally, the first stage for forming such a hydroprocessing effluent can correspond to a hydrotreatment stage, while the second stage can correspond to an aromatic saturation stage. Various naphthenic compositions can then be formed from such a hydroprocessing effluent, including naphthenic compositions having a kinematic viscosity at 100° C. of 2.0 cSt to 100 cSt, or 2.5 cSt or 50 cSt. Of course, any convenient number of hydroprocessing stages could be used to make such a hydroprocessed effluent.
In various aspects, the naphthenic compositions can have unexpected combinations of naphthenic carbon content and viscosity index. Naphthenic carbon content refers to the number of carbon atoms participating in naphthenic bonding (i.e., saturated ring bonding). This is in contrast to paraffinic carbons (alkane type bonding) and aromatic carbons (carbon atoms that are part of a pi-bond system). The amount of naphthenic carbon, paraffinic carbon, and/or aromatic carbon can be determined by ASTM D2140. In some aspects, a naphthenic composition can include 60 mol % or more naphthenic carbons, relative to the total amount of carbon, or 65 mol % or more, or 70 mol % or more, such as up to 80 mol % or possibly still higher. In such aspects, the viscosity index of the naphthenic composition can be −200 to 50, or −150 to 35. This combination of naphthenic carbon content and viscosity index is in contrast to naphthenic compositions formed from a conventional source, such as a naphthenic crude. Naphthenic compositions formed from naphthenic crudes typically have less than 60 mol % naphthenic carbons. Additionally or alternately, the amount of paraffinic carbon can be 30 mol % or less, or 25 mol % or less, such as down to 18 mol % or possibly still lower. Optionally, in such aspects, the amount of saturates in the naphthenic composition can be 50 wt % or more, or 60 wt % or more, or 70 wt % or more, such as up to 99.8 wt % saturates or possibly still higher. Conventionally, naphthenic oils made from conventional feeds include 34 mol % or more of paraffinic carbons. Optionally, the effluent can also contain 15 mol % or less aromatic carbon, or 10 mol % or less, or 5.0 mol % or less, such as down to 1.0 mol % or possibly still lower.
In this discussion, an FCC bottoms fraction can be referred to as a catalytic slurry oil. Catalytic slurry oil is defined herein to also refer to FCC fractions that substantially correspond to an FCC bottoms fraction. An FCC fraction that substantially corresponds to an FCC bottoms fraction is defined to include FCC fractions that have a T5 to T95 boiling range that is within the typical boiling range for an FCC bottoms fraction, even if the fraction was formed via a distillation process that generated another higher boiling fraction. It is noted that when initially formed, a catalytic slurry oil can include several weight percent of catalyst fines. Such catalyst fines can optionally but preferably be removed (such as partially removed to a desired level) by any convenient method, such as filtration. In this discussion, unless otherwise explicitly noted, references to a catalytic slurry oil are defined to include catalytic slurry oil either prior to or after such a process for reducing the content of catalyst fines within the catalytic slurry oil.
As defined herein, the term “hydrocarbonaceous” includes compositions or fractions that contain hydrocarbons and hydrocarbon-like compounds that may contain heteroatoms typically found in petroleum or renewable oil fraction and/or that may be typically introduced during conventional processing of a petroleum fraction. Heteroatoms typically found in petroleum or renewable oil fractions include, but are not limited to, sulfur, nitrogen, phosphorous, and oxygen. Other types of atoms different from carbon and hydrogen that may be present in a hydrocarbonaceous fraction or composition can include alkali metals as well as trace transition metals (such as Ni, V, or Fe).
In some aspects, reference may be made to conversion of a feedstock relative to a conversion temperature. Conversion relative to a temperature can be defined based on the portion of the feedstock that boils at greater than the conversion temperature. The amount of conversion during a process (or optionally across multiple processes) can correspond to the weight percentage of the feedstock converted from boiling above the conversion temperature to boiling below the conversion temperature. As an illustrative hypothetical example, consider a feedstock that includes 40 wt % of components that boil at 700° F. (˜371° C.) or greater. By definition, the remaining 60 wt % of the feedstock boils at less than 700° F. (˜371° C.). For such a feedstock, the amount of conversion relative to a conversion temperature of ˜371° C. would be based only on the 40 wt % that initially boils at ˜371° C. or greater. If such a feedstock could be exposed to a process with 30% conversion relative to a ˜371° C. conversion temperature, the resulting product would include 72 wt % of ˜371° C.− components and 28 wt % of ˜371° C.+ components.
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.
A catalytic slurry oil can correspond to a high boiling fraction, such as a bottoms fraction, from an FCC process. A feed including a catalytic slurry oil can correspond to a feed that includes 50 wt % or more of a catalytic slurry oil, or 75 wt % or more, or 90 wt % or more, such as up to 100 wt %. A variety of properties of a catalytic slurry oil can be characterized to specify the nature of a catalytic slurry oil feed.
One aspect that can be characterized corresponds to a boiling range of the catalytic slurry oil. Typically the cut point for forming a catalytic slurry oil can be 650° F. (˜343° C.) or more. As a result, a catalytic slurry oil can have a T5 distillation (boiling) point or a T10 distillation point of 650° F. (˜343° C.) or more, as measured according to ASTM D2887. In some aspects the D2887 10% distillation point can be greater, such as 675° F. (˜357° C.) or more, or 700° F. (˜371° C.) or more. In some aspects, a broader boiling range portion of FCC products can be used as a feed (e.g., a 350° F.+/˜177° C.+ boiling range fraction of FCC liquid product), where the broader boiling range portion includes a 650° F.+(˜343° C.+) fraction that corresponds to a catalytic slurry oil. The catalytic slurry oil (650° F.+/˜343° C.+) fraction of the feed does not necessarily have to represent a “bottoms” fraction from an FCC process, so long as the catalytic slurry oil portion comprises one or more of the other feed characteristics described herein.
In addition to and/or as an alternative to initial boiling points, T5 distillation point, and/or T10 distillation points, other distillation points may be useful in characterizing a feedstock. For example, a feedstock can be characterized based on the portion of the feedstock that boils above 1050° F. (˜566° C.). In some aspects, a feedstock (or alternatively a 650° F.+/˜343° C.+ portion of a feedstock) can have an ASTM D2887 T95 distillation point of 1050° F. (˜566° C.) or more, or a T90 distillation point of 1050° F. (˜566° C.) or more. Additionally or alternately, the T95 distillation point and/or the final boiling point can be 1200° F. (˜650° C.) or less, or 1150° F. (˜620° C.) or less. If a feedstock or other sample contains components that are not suitable for characterization using D2887, ASTM D1160 may be used instead for such components.
In various aspects, density, or weight per volume, of the catalytic slurry oil can be characterized. The density of the catalytic slurry oil (or alternatively a 650° F.+/˜343° C.+ portion of a feedstock) can be 1.06 g/cm3 or more, or 1.08 g/cm3 or more, or 1.10 g/cm3 or more, such as up to about 1.20 g/cm3 or possibly still higher (ASTM D4052). The density of the catalytic slurry oil can provide an indication of the amount of heavy aromatic cores that are present within the catalytic slurry oil. A lower density catalytic slurry oil feed can in some instances correspond to a feed that may have a greater expectation of being suitable for hydrotreatment without substantial and/or rapid coke formation.
Contaminants such as nitrogen and sulfur are typically found in catalytic slurry oils, often in organically-bound form. Nitrogen content can range from 50 wppm to 5000 wppm elemental nitrogen, or 100 wppm to 2000 wppm elemental nitrogen, or 250 wppm to 1000 wppm, based on total weight of the catalytic slurry oil. The nitrogen containing compounds can be present as basic or non-basic nitrogen species. Examples of nitrogen species can include quinolines, substituted quinolines, carbazoles, and substituted carbazoles.
The sulfur content of a catalytic slurry oil feed can be 500 wppm or more elemental sulfur, based on total weight of the catalytic slurry oil. Generally, the sulfur content of a catalytic slurry oil can range from 500 wppm to 100,000 wppm elemental sulfur, or from 1000 wppm to 50,000 wppm, or from 1000 wppm to 30,000 wppm, based on total weight of the heavy component. Sulfur can usually be present as organically bound sulfur. Examples of such sulfur compounds include the class of heterocyclic sulfur compounds such as thiophenes, tetrahydrothiophenes, benzothiophenes and their higher homologs and analogs. Other organically bound sulfur compounds include aliphatic, naphthenic, and aromatic mercaptans, sulfides, di- and polysulfides.
Catalytic slurry oils can include n-heptane insolubles (NHI) or asphaltenes. In some aspects, the catalytic slurry oil feed (or alternatively a ˜650° F.+/˜343° C.+ portion of a feed) can contain 1.0 wt % or more of n-heptane insolubles or asphaltenes, or 3.0 wt % or more, or 5.0 wt % or more, such as up to 10 wt % or possibly still higher. Another option for characterizing the heavy components of a catalytic slurry oil can be based on the amount of micro carbon residue (MCR) in the feed. In various aspects, the amount of MCR in the catalytic slurry oil feed (or alternatively a ˜343° C.+ portion of a feed) can be 5 wt % or more, or 8 wt % or more, or 10 wt % or more, such as up to 15 wt % or possibly still higher.
Catalytic slurry oil fractions are typically formed by atmospheric fractionation of the effluent from an FCC reactor. For example, after performing an FCC process on a feed, the resulting FCC effluent is typically fractionated in one or more separation stages. The one or more separation stages can correspond to an atmospheric distillation unit, or the one or more separation stages can correspond to a plurality of individual separations that have roughly a similar effect as using an atmospheric distillation unit. The lower boiling fractions generated by fractionation of an FCC effluent correspond to the typical desired products from FCC processing, such as a light ends/olefin-containing fraction, a naphtha fraction, and one or more cycle oils that can optionally be further upgraded for use as distillate fuel. The “bottoms” cut from the fractionation of the FCC effluent corresponds to the catalytic slurry oil.
Due to the nature of fluid catalytic cracking processes, catalyst fines are typically generated during such processes. These catalyst fines tend to be segregated into the bottoms fraction during the atmospheric fractionation, resulting in formation of a catalytic slurry oil. Prior to hydroprocessing of a catalytic slurry oil in a reaction that includes fixed catalyst beds (such as trickle beds), it can be beneficial to remove the catalyst fines so that the catalyst fines do not contribute to plugging or channeling in the catalyst bed. The feedstock, after any optional treatment in a particle removal stage, can have a particle content of about 500 wppm or less of particles having a size of 25 μm or more, or about 100 wppm or less, or about 50 wppm or less, or about 20 wppm or less, such as down to substantially no content of suspended solids (˜0 wppm). Filtration is an example of a suitable method for removing the catalyst fines, although other methods can also be used in addition to or in place of filtration. Examples of other methods include, but are not limited to, gravity settling, electrostatic filtration, and centrifugation. For example, particles can be removed by first performing gravity settling, and then passing the effluent from the gravity settler through a filter available from Mott Corporation or through an electrostatic filter available from Gulftronic. After removing particles in the catalytic slurry oil to a desired level, the feed can be hydroprocessed.
In some aspects, an alternative to performing filtration can be to use fractionation and/or solvent processing to remove catalyst fines from the feed. In other aspects, filtration can be performed in combination with fractionation and/or solvent processing. Thus, solvent processing and/or fractionation can potentially be performed prior to, during, and/or after the hydroprocessing of the feed including catalytic slurry oil. In addition to removing particles, performing fractionation and/or solvent processing can also remove a portion of the higher boiling components in the feed. If vacuum fractionation is used without filtration, the catalyst fines can be segregated into the vacuum bottoms fraction. If solvent deasphalting is used without filtration, the catalyst fines can be segregated into the residual or rock fraction.
Solvent deasphalting is an example of a solvent extraction process. In some aspects, suitable solvents for solvent deasphalting include alkanes or other hydrocarbons (such as alkenes) containing 4 to 7 carbons per molecule. Examples of suitable solvents include n-butane, isobutane, n-pentane, C4+ alkanes, C5+ alkanes, C4+ hydrocarbons, and C5+ hydrocarbons. In other aspects, suitable solvents can include C3 hydrocarbons, such as propane. In such other aspects, examples of suitable solvents include propane, n-butane, isobutane, n-pentane, C3+ alkanes, C4+ alkanes, C5+ alkanes, C3+ hydrocarbons, C4+ hydrocarbons, and C5+ hydrocarbons.
A deasphalting process typically corresponds to contacting a heavy hydrocarbon feed (such as a feed including catalytic slurry oil) with an alkane solvent (propane, butane, pentane, hexane, heptane etc and their isomers), either in pure form or as mixtures, to produce two types of product streams. One type of product stream corresponds to a deasphalted oil extracted by the alkane, which is further separated to produce deasphalted oil stream. A second type of product stream is the residual portion of the feed not soluble in the solvent (i.e., a raffinate). Conventionally, the residual product from solvent deasphalting can be referred to as a rock or asphaltene fraction. The deasphalted oil fraction can be hydroprocessed. The rock fraction can potentially be used as a blend component to produce asphalt, fuel oil, and/or other products. The rock fraction can also be used as feed to gasification processes such as partial oxidation, fluid bed combustion or coking processes. The rock can be delivered to these processes as a liquid (with or without additional components) or solid (either as pellets or lumps).
During solvent deasphalting, the feed can be mixed with a 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. The portion of the deasphalted feedstock that is extracted with the solvent is often referred to as deasphalted oil. Typical solvent deasphalting conditions include mixing a feedstock fraction with a solvent in a weight ratio of from about 1:2 to about 1:10, such as about 1:8 or less. Typical solvent deasphalting temperatures range from 40° C. to 200° C., or 40° C. to 150° C., depending on the nature of the feed and the solvent. The pressure during solvent deasphalting can be from about 50 psig (345 kPag) to about 500 psig (3447 kPag).
It is noted that the above solvent deasphalting conditions represent a general range, and the conditions will vary depending on the feed. For example, under typical deasphalting conditions, increasing the temperature can tend to reduce the yield of DAO while increasing the quality of the resulting deasphalted oil. Under typical deasphalting conditions, increasing the molecular weight of the solvent can tend to increase the yield while reducing the quality of the resulting deasphalted oil, as additional compounds within a resid fraction may be soluble in a solvent composed of higher molecular weight hydrocarbons. Under typical deasphalting conditions, increasing the amount of solvent can tend to increase the yield of the resulting deasphalted oil. As understood by those of skill in the art, the conditions for a particular feed can be selected based on the resulting yield of deasphalted oil from solvent deasphalting. Because catalytic slurry oils often are composed of primarily 1050° F.− components, the yield of deasphalted oil can be quite high, such as 70 wt % to 95 wt %, or 70 wt % to 98 wt %.
Hydroprocessing of Catalytic Slurry Oil to form Naphthenic Product Compositions
In various aspects, a feed including catalytic slurry oil can be hydroprocessed to form one or more naphthenic product compositions. An example of a suitable type of hydroprocessing can be hydrotreatment, such as hydrotreatment under trickle bed conditions. Hydrotreatment can optionally be used in conjunction with other hydroprocessing, such as an aromatic saturation process. However, in various aspects, the hydroprocessing can be performed without exposing the feed containing catalytic slurry oil to dewaxing conditions. Optionally, the feed including catalytic slurry oil can also be solvent processed, fractionated, or a combination thereof. The optional solvent processing/fractionation can be performed prior to hydroprocessing, between hydroprocessing stages, and/or after hydroprocessing.
In various aspects, a feed including catalytic slurry oil can be hydrotreated under effective hydrotreating conditions to form a hydrotreated effluent. In some aspects, the hydrotreating conditions can be selected to achieve a desired level of sulfur removal, such as reducing the sulfur content in the liquid portion of the hydrotreated effluent to 250 wppm or less, or 150 wppm or less, or 100 wppm or less, or 50 wppm or less. In some aspects, the hydrotreating conditions can be selected to achieve a desired level of nitrogen removal, such as reducing the nitrogen content in the liquid portion of the hydrotreated effluent to 250 wppm or less, or 150 wppm or less, or 100 wppm or less, or 50 wppm or less. The amount of aromatics remaining in the hydrotreated effluent after reducing the sulfur to 250 wppm or less can be 50 wt % to 80 wt %, or 60 wt % to 80 wt %.
Optionally, the effective hydrotreating conditions can be selected to allow for reduction of the n-heptane asphaltene content of the hydrotreated effluent to less than about 1.0 wt %, or less than about 0.5 wt %, or less than about 0.1 wt %, and optionally down to substantially no remaining n-heptane asphaltenes. Additionally or alternately, the effective hydrotreating conditions can be selected to allow for reduction of the micro carbon residue content of the hydrotreated effluent to less than about 2.5 wt %, or less than about 1.0 wt %, or less than about 0.5 wt %, or less than about 0.1 wt %, and optionally down to substantially no remaining micro carbon residue.
Additionally or alternately, in various aspects, the processing conditions can be selected to achieve a desired level of conversion of a feedstock, such as conversion relative to a conversion temperature of ˜700° F. (˜371° C.). For example, the process conditions can be selected to achieve 40% or more conversion of the 1050° F.+(˜566° C.+) portion of the feedstock to 1050° F.− (˜566° C.)− components, or 50 wt % or more, or 60 wt % or more, such as up to 80 wt % or possibly still higher.
Hydroprocessing (such as hydrotreating) can be carried out in the presence of hydrogen. A hydrogen stream can be fed or injected into a vessel or reaction zone or hydroprocessing zone corresponding to the location of a hydroprocessing catalyst. Hydrogen, contained in a hydrogen “treat gas,” can be provided to the reaction zone. Treat gas, as referred to herein, can be either pure hydrogen or a hydrogen-containing gas stream containing hydrogen in an amount that for the intended reaction(s). Treat gas can optionally include one or more other gasses (e.g., nitrogen and light hydrocarbons such as methane) that do not adversely interfere with or affect either the reactions or the products. Impurities, such as H2S and NH3 are undesirable and can typically be removed from the treat gas before conducting the treat gas to the reactor. In aspects where the treat gas stream can differ from a stream that substantially consists of hydrogen (i.e, at least about 99 vol % hydrogen), the treat gas stream introduced into a reaction stage can contain at least about 50 vol %, or at least about 75 vol % hydrogen, or at least about 90 vol % hydrogen.
During hydrotreatment, a feedstream can be contacted with a hydrotreating catalyst under effective hydrotreating conditions which include temperatures in the range of 450° F. to 800° F. (˜232° C. to ˜427° C.), or 500° F. to 750° F. (˜260° C. to ˜399° C.); pressures in the range of 1.5 MPa-g to 20.8 MPa-g (˜200 to ˜3000 psig), or 3.4 MPa-g to 17.2 MPa-g (˜500 to ˜2500 psig), or 6.9 MPa-g to 17.25 MPa-g (˜1000 psig to ˜2500 psig); a liquid hourly space velocity (LHSV) of from 0.1 to 10 hr-1, or 0.1 to 5 hr-1; and a hydrogen treat gas rate of from 430 to 2600 Nm3/m3 (˜2500 to ˜15000 SCF/bbl), or 850 to 1700 Nm3/m3 (˜5000 to ˜10000 SCF/bbl).
In an aspect, the hydrotreating step may comprise at least one hydrotreating reactor, and optionally may comprise two or more hydrotreating reactors arranged in series flow. A vapor separation drum can optionally be included after each hydrotreating reactor to remove vapor phase products from the reactor effluent(s). The vapor phase products can include hydrogen, H2S, NH3, and hydrocarbons containing four (4) or less carbon atoms (i.e., “C4− hydrocarbons”). The C5+ hydrocarbons can be subsequently cooled to form liquid products, and therefore the C5+ portion of the effluent can be referred to as the liquid portion of the effluent. The effective hydrotreating conditions can be suitable for removal of 70 wt % or more, or 80 wt % or more, or 90 wt % or more of the sulfur content in the feedstream from the resulting liquid products. Additionally or alternately, 50 wt % or more, or 75 wt % or more of the nitrogen content in the feedstream can be removed from the resulting liquid products.
Hydrotreating catalysts suitable for use herein can include those containing at least one Group VIA metal and at least one Group VIII metal, including mixtures thereof. Examples of suitable metals include Ni, W, Mo, Co and mixtures thereof, for example CoMo, NiMoW, NiMo, or NiW. These metals or mixtures of metals are typically present as oxides or sulfides on refractory metal oxide supports. The amount of metals for supported hydrotreating catalysts, either individually or in mixtures, can range from ˜0.5 to ˜35 wt %, based on the weight of the catalyst. Additionally or alternately, for mixtures of Group VIA and Group VIII metals, the Group VIII metals can be present in amounts of from ˜0.5 to ˜5 wt % based on catalyst, and the Group VIA metals can be present in amounts of from 5 to 30 wt % based on the catalyst. A mixture of metals may also be present as a bulk metal catalyst wherein the amount of metal can comprise ˜30 wt % or greater, based on catalyst weight.
Suitable metal oxide supports for the hydrotreating catalysts include oxides such as silica, alumina, silica-alumina, titanic, or zirconia. Examples of aluminas suitable for use as a support can include porous aluminas such as gamma or eta. In some aspects where the support can correspond to a porous metal oxide support, the catalyst can have an average pore size (as measured by nitrogen adsorption) of 30 Å to 1000 Å, or 50 Å to 500 Å, or 60 Å to 300 Å. Pore diameter can be determined, for example, according to ASTM Method D4284-07 Mercury Porosimetry. Additionally or alternately, the catalyst can have a surface area (as measured by the BET method) of 100 to 350 m2/g, or 150 to 250 m2/g. In some aspects, a supported hydrotreating catalyst can have the form of shaped extrudates. The extrudate diameters can range from 1/32nd to ⅛th inch (˜0.7 to ˜3.0 mm), from 1/20th to 1/10th inch (˜1.3 to ˜2.5 mm), or from 1/20th to 1/16th inch (˜1.3 to ˜1.5 mm). The extrudates can be cylindrical or shaped. Non-limiting examples of extrudate shapes include trilobes and quadralobes.
Optionally, more than one hydrotreating stage can be used, such as having multiple reactors containing hydrotreating catalyst with a separation stage in between. In such aspects, a portion of the hydrodesulfurization and/or hydrodenitrogenation can be performed in a second hydrotreating stage. Optionally, such a second hydrotreating stage can be operated under aromatic saturation conditions.
Aromatic saturation conditions can be similar to hydrotreating conditions, but the aromatic saturation conditions can be selected separately (if desired) from the hydrotreating conditions. Preferably, a separation stage can be located between the aromatic saturation stage and any hydrotreating stages that perform substantial removal of sulfur from the feed. The separation stage can be used to remove H2S, NH3, and C4− hydrocarbons from the feed after hydrotreating. In other aspects, a separation may not be performed, so that the effluent may be contacted with an aromatics saturation catalyst with or without the removal of H2S, NH3 and C4− components. During aromatic saturation, a feedstream (such as a portion of a hydrotreated effluent) can be contacted with an aromatic saturation catalyst under effective aromatic saturation conditions which include temperatures in the range of 390° F. to 800° F. (˜232° C. to ˜427° C.), or 390° F. to 750° F. (˜260° C. to ˜399° C.); pressures in the range of 1.5 MPa-g to 20.8 MPa-g (˜200 to ˜3000 psig), or 3.4 MPa-g to 17.2 MPa-g (˜500 to ˜2500 psig), or 6.9 MPa-g to 17.25 MPa-g (˜1000 psig to ˜2500 psig); a liquid hourly space velocity (LHSV) of from 0.1 to 10 hr-1, or 0.1 to 5 hr-1; and a hydrogen treat gas rate of from 430 to 2600 Nm3/m3 (˜2500 to ˜15000 SCF/bbl), or 850 to 1700 Nm3/m3 (˜5000 to ˜10000 SCF/bbl).
Hydrofinishing and/or aromatic saturation catalysts can include catalysts containing Group VI metals, Group VIII metals, and mixtures thereof. In some aspects, hydrotreating catalysts can be used as aromatic saturation catalysts. In some aspects, an aromatic saturation catalyst can include a Group VIII noble metal, such as Pt, Pd, or a combination thereof. For supported aromatic saturation catalysts, suitable 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 can be as high as about 20 weight percent for non-noble metals. In some aspects, an aromatic saturation 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.
The effective hydrotreating conditions and/or aromatic saturation conditions can optionally be suitable for incorporation of a substantial amount of additional hydrogen into the hydrotreated effluent. During hydrotreatment and/or aromatic saturation, the consumption of hydrogen by the feed in order to form the hydrotreated effluent can correspond to 1000 SCF/bbl (˜260 Nm3/m3) or more of hydrogen, or 1500 SCF/bbl (˜290 Nm3/m3) or more, or 2000 SCF/bbl (˜330 Nm3/m3) or more, or 2200 SCF/bbl (˜370 Nm3/m3) or more, such as up to 5000 SCF/bbl (˜850 Nm3/m3) or possibly still higher.
In various aspects, the feed including catalytic slurry oil can be hydroprocessed without exposing the feed to catalytic dewaxing conditions. For example, the hydroprocessing conditions can be selected to avoid exposing the feed to dewaxing catalyst and/or dewaxing conditions where dewaxing is performed primarily by isomerization. In some aspects, such dewaxing catalysts that cause dewaxing primarily by isomerization can correspond to, for example, catalysts that include zeotype frameworks with a unidimensional pore structure. Additionally or alternately, such catalysts can include 10-member ring pore zeolites, such as EU-1, ZSM-35 (or ferrierite), ZSM-11, ZSM-57, NU-87, SAPO-11, and ZSM-22. Such dewaxing catalysts can include a metal hydrogenation component. The metal hydrogenation component can typically be a Group 6 and/or a Group 8-10 metal, such as a Group 8-10 noble metal. For example, the metal hydrogenation component can be Pt, Pd, or a mixture thereof. Alternatively, the metal hydrogenation component can be a combination of a non-noble Group 8-10 metal with a Group 6 metal. Suitable combinations can include Ni, Co, or Fe with Mo or W, preferably Ni with Mo or W.
The intermediate and/or final products from processing of catalytic slurry oil can be characterized in various manners. One type of product that can be characterized can be the hydrotreated effluent derived from hydrotreatment of a catalytic slurry oil feed (or a feed substantially composed of catalytic slurry oil). Additionally or alternately, the hydrotreated effluent derived from hydrotreatment of a catalytic slurry oil feed (or a feed substantially composed of a catalytic slurry oil) may be fractionated into light ends, naphtha, distillate and, residual range portions prior to characterization.
After hydrotreatment, the liquid (C5+) portion of the hydrotreated effluent can have a volume of 95% or more of the volume of the catalytic slurry oil feed, or 100% or more of the volume of the feed, or 105% or more, or 110% or more, such as up to 150% of the volume or possibly still higher.
After hydrotreatment, the boiling range of the liquid (C5+) portion of the hydrotreated effluent can be characterized in various manners. In some aspects, the total liquid product can have a T50 distillation point of 320° C. to 400° C., or 350° C. to 380° C. In some aspects, the total liquid product can have a T90 distillation point of 450° C. to 525° C. In some aspects, the total liquid product can have a T10 distillation point of 250° C. or more, which can reflect the low amount of conversion that occurs during hydroprocessing of higher boiling compounds to C5+ compounds with a boiling point below 200° C. In some aspects, the (weight) percentage of the liquid (C5+) portion that comprises a distillation point greater than about ˜566° C. can be 10 wt % or less, or 5.0 wt % or less, or 2.0 wt % or less, or 1.0 wt % or less, such as down to 0.05 wt % or less (i.e., substantially no compounds with a distillation point greater than about 1050° F./˜566° C.). Additionally or alternately, the (weight) percentage of the liquid portion that comprises a distillation point less than about −370° C. can be 40 wt % or more, or 50 wt % or more, or 60 wt % or more, such as up to 90 wt % or possibly still higher.
In some aspects, the density (at 15° C.) of the liquid (C5+) portion of the hydrotreated effluent can be 1.05 g/cm3 or less, or 1.00 g/cm3 or less, or 0.95 g/cm3 or less, such as down to 0.88 g/cc or lower. The sulfur content of the liquid (C5+) portion of the hydrotreated effluent can be 1000 wppm or less, or 500 wppm or less, or 100 wppm or less, such as down to substantially no remaining sulfur (−1 wppm or possibly lower). The micro carbon residue of the liquid (C5+) portion of the hydrotreated effluent can be 4.0 wt % or less, or 2.0 wt % or less, or 1.0 wt % or less, such as substantially complete removal of micro carbon residue.
The aromatics content of the liquid (C5+) portion of the hydrotreated effluent can vary depending on the severity of the hydroprocessing. Generally, the aromatics content can range from substantially no aromatics (˜0 wt %, or alternatively 1.0 wt % or less) to 30 wt %. In some aspects, the liquid portion of the hydrotreated effluent can have an aromatics content of 0 wt % to 30 wt %, or 0 wt % to 20 wt %, or 0 wt % to 10 wt %. In such aspects with lower aromatics content, the naphthene content of the liquid portion of the hydrotreated effluent can be 70 wt % to 98 wt %, or 70 wt % to 90 wt %, or 80 wt % to 98 wt %.
For compositions with a T5 distillation point of 343° C. or more and an aromatics content of 30 wt % or less, or 30 wt % or less, or 20 wt % or less, the amount of naphthenic carbon in the composition can also be characterized. For example, a naphthenic composition can include 60 mol % or more naphthenic carbons, relative to the total amount of carbon, or 65 mol % or more, or 70 mol % or more. In such aspects, the viscosity index of the naphthenic composition can be −200 to 50, or −150 to 35.
One or more products can also be further fractionated to form narrow boiling range hydrocarbon fluids. For example, at least a portion of the diesel product (177° C. to 343° C.) can be fractionated to form hydrocarbon fluids. The hydrocarbon fluids can be formed to have a desired boiling range, a desired average carbon number, and/or another target property.
As examples of fractions that can be formed, in some aspects a naphthenic base oil composition can be formed that includes a kinematic viscosity at 100° C. of 1.5 cSt to 4.0 cSt, a viscosity index of −20 to 25, and a T5 distillation point of 270° C. or more. As another example, a naphthenic base oil composition can be formed that includes a kinematic viscosity at 100° C. of 4.5 cSt to 8.0 cSt, a viscosity index of −50 to 0, and a T5 distillation point of 300° C. or more. As another example, a naphthenic base oil composition can be formed that includes a kinematic viscosity at 100° C. of 8.0 cSt to 20 cSt, a viscosity index of −80 to −20, and a T5 distillation point of 330° C. or more. As still another example, a naphthenic base oil composition can be formed that includes a kinematic viscosity at 100° C. of 25 cSt to 75 cSt, a viscosity index of −120 to −50, and a T5 distillation point of 360° C. or more.
In various aspects, reference may be made to one or more types of fractions generated during distillation of a petroleum feedstock. Such fractions may include naphtha fractions, kerosene fractions, diesel fractions, and vacuum gas oil fractions. Each of these types of fractions can be defined based on a boiling range, such as a boiling range that includes at least −90 wt % of the fraction, or at least −95 wt % of the fraction. For example, for many types of naphtha fractions, at least ˜90 wt % of the fraction, or at least ˜95 wt %, can have a boiling point in the range of ˜85° F. (˜29° C.) to ˜350° F. (˜177° C.). For some heavier naphtha fractions, at least ˜90 wt % of the fraction, and preferably at least ˜95 wt %, can have a boiling point in the range of ˜85° F. (˜29° C.) to ˜400° F. (˜204° C.). For a diesel fraction, at least ˜90 wt % of the fraction, and preferably at least ˜95 wt %, can have a boiling point in the range of ˜400° F. (˜204° C.) to ˜750° F. (˜399° C.).
In the configuration shown in
In other aspects, the additional vacuum fractionator 460 can be omitted, and the bottoms fraction 485 plus one or more of diesel fraction 483, heavy diesel fraction 482, and light gasoil fraction 484 can be passed into aromatic saturation stage 490 for further hydroprocessing.
Aromatic saturation stage 490 can generate an effluent 495 that is then fractionated 430 to form a variety of products. The variety of products can include, for example, a naphtha fraction 441, a diesel fraction 443, one or more light naphthenic base oils 432, and one or more heavy naphthenic base oils 436.
Various examples are provided below to demonstrate hydroprocessing of catalytic slurry oils (without dewaxing) to form naphthenic product compositions. In the various examples below, representative catalytic slurry oil feeds were used. Table 1 shows the range of properties for the representative catalytic slurry oil feeds.
A catalytic slurry oil feed within the typical ranges described in Table 1 was exposed to a stacked bed of commercially available hydrotreating catalysts under conditions corresponding to 2400 psig (˜16.5 MPa-g) of H2, a LHSV of 0.24 hr-1, and a hydrogen treat gas rate of 10,500 scf/bbl (˜1800 m3/m3). The temperature during hydrotreatment was selected to generate a total liquid product (C5+) with a sulfur content of roughly 150 wppm. The resulting hydrotreated effluent was then fractionated to form a fuels cut (including naphtha and diesel boiling range components), a 566° C.+ bottoms fraction, and four naphthenic base oil compositions. The naphthenic base oil compositions corresponded to a light naphthenic base oil with a kinematic viscosity at 100° C. of 2.9 cSt; a medium naphthenic base oil with a kinematic viscosity at 100° C. of 6.0 cSt; a first heavy naphthenic base oil with a kinematic viscosity at 100° C. of 18.7 cSt; and a second heavy naphthenic base oil with a kinematic viscosity at 100° C. of 58.4 cSt. Table 2 shows the properties of the naphthenic base oils.
Naphthenic base oils 1 and 2 from Table 2 were further processed using solvent extraction in N-Methyl Pyrrolidone. The solvent extraction conditions are shown in Table 5, along with a comparison of the properties of the naphthenic base oil prior to extraction and the resulting raffinate naphthenic base oil. As shown in Table 3, solvent extraction can reduce the aromatic content of the raffinate naphthenic base oil while also improving the viscosity index of the raffinate naphthenic base oil.
A feed within the ranges of Table 1 was hydrotreated under conditions similar to those used in Example 1. The resulting hydrotreated effluent was fractionated, which included formation of a 3.6 cSt naphthenic base oil composition. The 3.6 cSt naphthenic base oil had an aromatics content of roughly 60 wt %, a paraffin content of 2.3 wt %, and a viscosity index of roughly −100. The 3.6 cSt naphthenic base oil composition was then exposed to several types of aromatic saturation catalysts under aromatic saturation conditions that included 2000 psig (˜13.8 MPa-g) of H2 and a hydrogen treat gas rate of 4600-5000 scf/bbl (˜820-890 m3/m3). The temperature and LHSV were varied between roughly 500° F. (260° C.) and 575° F. (302° C.) as shown in
Three different aromatic saturation catalysts were used for aromatic saturation. One aromatic saturation catalyst corresponded to a commercially available aromatic saturation catalyst that included noble metals on a refractory support. The second aromatic saturation catalyst corresponded to 0.6 wt % Pt on an alumina bound USY support. The third aromatic saturation catalyst corresponded to 0.9 wt % Pd and 0.3 wt % Pt on an alumina bound MCM-41 support.
During aromatic saturation, the commercially available aromatic saturation catalyst was effective for substantially complete saturation of the aromatics in the feed, resulting in naphthenic base oils with roughly 73 mol % to 76 mol % naphthenic carbons, 20 mol % to 23 mol % paraffinic carbons, and 3 mol % to 4 mol % aromatics carbons (ASTM D2140). The naphthenic base oils had a viscosity index of between −4 and 7 and a kinematic viscosity at 100° C. of roughly 3.0.
The catalyst with 0.6 wt % Pt supported on alumina bound USY resulted in slightly less saturation of aromatic rings relative to the commercially available catalyst. At temperatures of roughly 280° C. and roughly 300° C., the 0.6 wt % Pt/USY catalyst generated an aromatic saturation effluent similar to the commercial catalyst, including 73 mol % to 75 mol % naphthenic carbons, 20 mol % to 23 mol % paraffinic carbons, and 4 mol % to 5 mol % aromatic carbons. The viscosity index of the effluent from the 0.6 wt % Pt/USY catalyst was between 8 and 26 at the temperatures of 280° C. and 300° C., which is higher than the range for the commercially available catalyst. The resulting kinematic viscosity at 100° C. was also lower, corresponding to roughly 2.7 to 2.9 cSt. It is noted that the processing at 260° C. resulted in substantially less aromatic saturation, so that the aromatic carbon content was roughly 10 mol %, with a corresponding viscosity index of roughly −18. Although the 0.6 wt % Pt/USY catalyst appeared to have modestly lower activity for aromatic saturation, the viscosity index of the resulting effluent appeared to be higher.
The catalyst with 0.9 wt % Pd and 0.3 wt % Pd on alumina bound MCM-41 appeared to have still lower activity for aromatic saturation at the temperatures and space velocities shown in
A feed within the ranges of Table 1 was hydrotreated under conditions similar to those used in Example 1. The resulting hydrotreated effluent was fractionated, which included form various naphthenic base oil compositions. A 14.28 cSt naphthenic base oil cut was further hydrotreated over a bulk metal hydrotreating catalyst and then over a commercial aromatic saturation catalyst after the separation of the H2S, NH3, and C1-C4 light ends. Hydrotreating was conducted under the conditions that included 2000 psig (˜13.8 MPa-g) of H2, a hydrogen treat gas rate of 10,000 scf/bbl (˜1781 m3/m3), an LHSV of roughly 1.0 hr-1, and a temperature of 375° C. Aromatic saturation was conducted under the conditions that included 2000 psig (˜13.8 MPa-g) of H2, a hydrogen treat gas rate of 10,000 scf/bbl (˜1781 m3/m3), an LHSV of roughly 0.25 hr-1, and a temperature of either roughly 225° C. or 250° C. Liquid products collected from AROSAT were distilled to obtain naphthenic oils with a nominal IBP of 700° F.+ fraction.
Properties of the resulting naphthenic base oils, listed in Table 4, show that the 2-stage process has produced naphthenic base oils with a kinematic viscosity of roughly 9 cSt at 100° C. and a VI of −54. Aromatic reduction was greater than 99.5%. The products contain 27-28 mol % paraffinic carbon, 69 mol % naphthenic carbon and 3-4 mol % aromatic carbon.
For comparison, the amount of naphthenic carbon versus viscosity index is shown for a large number of naphthenic base oils made from conventional naphthenic crude feeds (circle data points). The comparative data points correspond to data points that were available in various types of literature. The dividing line between the two sets of data points demonstrates the unexpected disparity between the viscosity index and naphthenic carbon content for the naphthenic oils formed using conventional naphthenic feed versus naphthenic oils formed from catalytic slurry oil.
As still another type of comparisons,
As shown in
A method for processing a product fraction from a fluid catalytic cracking (FCC) process, comprising: exposing a feed comprising a catalytic slurry oil, the feed comprising a 343° C.+ portion, to a hydrotreating catalyst under effective hydrotreating conditions to form a hydrotreated effluent, the 343° C.+ portion of the feed comprising a density of 1.06 g/cm3 or more, and exposing at least a portion of the 343° C.+ portion to a hydroprocessing catalyst under effective hydroprocessing conditions to form a hydroprocessed effluent, wherein a C5+ portion of the hydroprocessed effluent comprises 50 mol % or more naphthenic carbons and 500 wppm or less of sulfur, the C5+ portion of the hydroprocessed effluent optionally comprising a density of 1.00 g/cm3 or less.
The method of Embodiment 1, wherein the C5+ portion of the hydroprocessed effluent comprises 60 mol % or more of naphthenic carbons (or 65 mol % or more, or 70 mol % or more), or wherein the C5+ portion of the hydroprocessed effluent comprises 30 mol % or less of paraffinic carbons (or 25 mol % or less), or a combination thereof.
The method of any of the above embodiments, wherein the C5+ portion of the hydroprocessed effluent comprises 50 wt % or more saturates (or 60 wt % or more, or 70 wt % or more).
The method of any of the above embodiments, wherein the C5+ portion of the hydroprocessed effluent comprises 15 wt % or less aromatics (or 10 wt % or less), or wherein the C5+ portion of the hydroprocessed effluent comprises 15 mol % or less of aromatic carbons (or 10 mol % or less, of 5.0 mol % or less), or a combination thereof.
The method of any of the above embodiments, wherein the C5+ portion of the hydroprocessed effluent comprises a kinematic viscosity at 100° C. of 2.0 cSt to 30 cSt, a viscosity index of 25 or less, or a combination thereof.
The method of any of the above embodiments, further comprising fractionating the C5+ portion of the hydroprocessed effluent to form one or more naphthenic base oil compositions, the one or more naphthenic base oil compositions comprising: a) at least one naphthenic base oil composition comprising a kinematic viscosity at 100° C. of 1.5 cSt to 4.0 cSt, a viscosity index of −20 to 25, and a T5 distillation point of 270° C. or more; b) at least one naphthenic base oil composition comprising a kinematic viscosity at 100° C. of 4.5 cSt to 8.0 cSt, a viscosity index of −50 to 0, and a T5 distillation point of 300° C. or more; c) at least one naphthenic base oil composition comprising a kinematic viscosity at 100° C. of 8.0 cSt to 20 cSt, a viscosity index of −80 to −20, and a T5 distillation point of 330° C. or more; d) at least one naphthenic base oil composition comprising a kinematic viscosity at 100° C. of 25 cSt to 75 cSt, a viscosity index of −120 to −50, and a T5 distillation point of 360° C. or more; e) a combination of two or more of a), b), c), and d); or f) a combination of three or more of a), b), c), and d).
The method of Embodiment 6, wherein the one or more naphthenic base oil compositions comprise 60 mol % or more of naphthenic carbons (or 65 mol % or more, or 70 mol % or more); or 30 mol % or less paraffinic carbons (or 25 mol % or less); or 50 wt % or more saturates (or 60 wt % or more, or 70 wt % or more), or 15 mol % or less of aromatic carbons (or 10 mol % or less, of 5.0 mol % or less); or a combination of two or more thereof, or three or more thereof.
The method of any of the above embodiments, wherein the hydroprocessed effluent is formed without exposing the catalytic slurry oil to a dewaxing catalyst under catalytic dewaxing conditions, or wherein the hydroprocessed effluent is formed without exposing the catalytic slurry oil to a catalyst comprising a zeotype framework in the presence of hydrogen under hydroprocessing conditions, or wherein the effective hydroprocessing conditions comprise fixed bed hydroprocessing conditions, or a combination thereof.
The method of any of the above embodiments, wherein the feed comprises a fraction from a fluid catalytic cracking process having a T5 distillation point of 343° C. or more, a T95 distillation point of 566° C. or less, or a combination thereof, the method optionally further comprising treating the fraction from the fluid catalytic cracking process to form a treated fraction comprising a particle content of 500 wppm or less of particles having a size of 25 μm or more (or 100 wppm or less), the catalytic slurry oil comprising at least a portion of the treated fraction.
A naphthenic base oil composition, comprising 500 wppm or less sulfur, 18 mol % to 30 mol % paraffinic carbons, 50 mol % or more of naphthenic carbons, a kinematic viscosity at 100° C. of 2.0 cSt to 30 cSt, a viscosity index of 25 or less, and a T5 distillation point of 260° C. or more.
The composition of Embodiment 10, wherein i) the composition comprises 70 mol % or more naphthenic carbons and a viscosity index of −50 to 25; ii) the composition comprises 60 mol % to 70 mol % naphthenic carbons and a viscosity index of −100 to 10; or iii) the composition comprises 50 mol % to 60 mol % naphthenic carbons and a viscosity index of −150 to −20.
The composition of Embodiment 10, wherein the composition comprises 25 mol % to 30 mol % paraffinic carbons, 65 mol % to 75 mol % of naphthenic carbons, a kinematic viscosity at 100° C. of 8.0 cSt to 15 cSt, and a viscosity index of −40 or less (or −50 or less).
The composition of any of Embodiments 10-12, wherein the composition comprises 50 wt % or more saturates (or 60 wt % or more, or 70 wt % or more); or wherein the composition comprises 15 wt % or less aromatics (or 10 wt % or less, or 5 wt % or less); or wherein the composition comprises 15 mol % or less of aromatic carbons (or 10 mol % or less, of 5.0 mol % or less), or a combination thereof.
A composition formed according to the method of any of Embodiments 1-9.
A naphthenic base oil composition, comprising 500 wppm or less sulfur, 18 mol % to 30 mol % paraffinic carbons and 60 mol % or more of naphthenic carbons, the naphthenic base oil composition further comprising: a) a kinematic viscosity at 100° C. of 1.5 cSt to 4.5 cSt, a viscosity index of −20 to 25, and a T5 distillation point of 270° C. or more; b) a kinematic viscosity at 100° C. of 4.5 cSt to 8.0 cSt, a viscosity index of −50 to 0, and a T5 distillation point of 300° C. or more; c) a kinematic viscosity at 100° C. of 8.0 cSt to 20 cSt, a viscosity index of −80 to −20, and a T5 distillation point of 330° C. or more; or d) a kinematic viscosity at 100° C. of 20 cSt to 75 cSt, a viscosity index of −120 to −50, and a T5 distillation point of 360° C. or more.
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 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 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 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.
This application claims priority to U.S. Provisional Application Ser. No. 62/781,892 filed Dec. 19, 2018, which is herein incorporated by reference in its entirety.
| Number | Date | Country | |
|---|---|---|---|
| 62781892 | Dec 2018 | US |
