CN113906118A

CN113906118A - Pyrolysis tar upgrading

Info

Publication number: CN113906118A
Application number: CN202080040800.XA
Authority: CN
Inventors: J·J·蒙森; K·S·加尔万; K·坎德尔
Original assignee: ExxonMobil Chemical Patents Inc
Current assignee: ExxonMobil Chemical Patents Inc
Priority date: 2019-06-05
Filing date: 2020-05-15
Publication date: 2022-01-07
Also published as: WO2020247166A1; US20220204866A1; SG11202112679PA

Abstract

The present application provides methods and apparatus for producing liquid hydrocarbon products. In one embodiment, a method of making a liquid hydrocarbon product includes thermally treating a tar to produce a first tar composition and blending the tar composition with a utility fluid to form a tar-fluid mixture. The method includes separating a tar-fluid mixture to form a first lower density portion and a solids-containing first higher density portion. The method further includes heat treating the first higher density portion to form a heat treated first higher density portion to convert at least a portion of the solids to a liquid.

Description

Pyrolysis tar upgrading

Technical Field

This application claims priority and benefit from U.S. provisional application No.62/857,442 filed on day 06, 05, 2019 and european patent application No.19206400.4 filed on day 31, 10, 2019, which are incorporated herein by reference.

Embodiments generally relate to upgrading tar, for example, by one or more thermal treatments. More particularly, embodiments relate to a method and apparatus for hot-soaking steam cracking tar solids.

Background

Hydrocarbon pyrolysis processes, such as steam cracking, crack hydrocarbon feedstocks into a wide range of relatively high value molecules including ethylene, propylene, butenes, steam cracked gas oil ("SCGO"), steam cracked naphtha ("SCN"), or any combination thereof. In addition to these useful products, hydrocarbon pyrolysis can also produce large quantities of relatively low value heavy products, such as pyrolysis tars. When pyrolysis is performed by steam cracking, the pyrolysis tar is identified as steam cracked tar ("SCT"). The economic viability of refinery and petrochemical processes depends in part on the ability to incorporate as many product and residual fractions as possible, such as SCT, into the value chain. One use of residual fractions and/or relatively low value products is to blend these fractions with other hydrocarbons, such as other feed streams or products.

However, SCT typically contains relatively high molecular weight molecules, conventionally referred to as tar heavies ("TH") and significant amounts of sulfur. The presence of sulfur and TH makes SCT a less desirable blend stock, for example for blending with fuel oil blend-stocks or different SCTs. Compatibility is typically determined by visual inspection of the formation of solids, as described, for example, in U.S. patent No.5,871,634. Generally, SCT has a high viscosity and poor compatibility, or only a small amount of compatibility, with other heavy hydrocarbons such as fuel oil. Also, SCTs produced under specific conditions often have poor compatibility with SCTs produced under different conditions.

By catalytically hydrotreating SCT, viscosity and compatibility can be improved, and sulfur content reduced. However, the catalytic hydrotreating of undiluted SCT results in significant catalyst deactivation and the formation of undesirable deposits (e.g., coke deposits or particulates) on reactor internals. As the amount of these deposits increases, the yield of desirable upgraded pyrolysis tar (upgraded SCT) decreases and the yield of undesirable byproducts increases. The pressure drop across the hydroprocessing reactor also increases to a point where the reactor may be inoperable.

It is conventional to hydrotreat SCTs in the presence of a fluid, such as a solvent with a significant aromatic content, to reduce the formation of deposits. The hydrotreated product contains upgraded SCT products that typically have reduced viscosity, reduced atmospheric boiling range, and increased hydrogen content compared to the SCT of the feed, resulting in improved compatibility with the fuel oil blend stock. In addition, hydrotreating SCT in the presence of a fluid produces fewer undesirable byproducts and the rate of increase in pressure drop across the reactor becomes slower. Some forms of SCT processing are disclosed in U.S. patent nos.2,382,260 and 5,158,668 and in U.S. patent application publication No. us 2008/0053869. PCT patent application publication nos. WO 2013/033590, WO2018/111577, and WO 2019.203981 disclose recycling a portion of the hydrotreated tar for use as a fluid.

The presence of solids within SCT represents a serious challenge for effective SCT hydroprocessing. A significant amount of the solids in the SCT are in the form of particulates, such as coke (e.g., pyrolysis coke), oligomeric and/or polymeric species, inorganic solids (e.g., fines, metals, metal-containing compounds, ash, etc.), aggregates of one or more of these, and the like. Although removal of SCT particulates, for example by filtration, settling, centrifugation, etc., results in SCT that can be more easily hydrotreated, doing so will undesirably reduce the yield of hydrotreated SCT. Moreover, managing a large inventory of removed particulates may negatively impact process economics.

As an example, coke fines, inorganic fines, and other solids may be present within the SCT. The coke fines or particles may be or include pyrolytic coke and/or polymeric coke. These fines or particles may be formed during the polymerization conditions present in the primary fractionator (e.g., ≧ 150 ℃) after pyrolysis tar formation (upstream of the hydrotreater).

Accordingly, there is a need for an improved tar conversion process that has less solids present in the conversion of hydrocarbon feedstocks to tar.

Summary of The Invention

In certain embodiments, a method of upgrading tar, such as pyrolysis tar, is provided. Tars, e.g., tars containing pyrolysis tars such as steam cracker tars, are subjected to a first heat treatment to produce a tar composition. A first higher density portion and a first lower density portion are separated from the tar composition. The first higher density portion is subjected to a second heat treatment to produce a heat-treated first higher density portion. Separating the second higher density portion and the second lower density portion from the heat treated first higher density portion. At least a portion of the second lower density fraction may be recycled to one or more of: (i) tar, (ii) a tar composition, and (iii) a first, higher density fraction. The second, higher density portion may be directed away, for example, for storage and/or further processing. It was observed that the amount of solids present in the heat treated first higher density fraction was less than the amount of solids present in the first higher density fraction. It has been surprisingly found that the second heat treatment is effective to convert the solids in the first higher density portion primarily to liquid in the heat treated first higher density portion and little, if any, conversion to gas phase species. This in turn results in improved process economics, greater efficiency, increased amounts of desired liquid phase materials, and reduced amounts of less desired solids compared to conventional tar processing. Returning at least a portion of the second lower density fraction (which contains liquid from the conversion of solids in the second heat treatment) to the process increases the amount of tar available for hydroprocessing, resulting in increased yields in hydroprocessed tar.

In other embodiments, a process for upgrading steam cracker tar is provided. Steam cracking the steam cracker feed to form a steam cracker effluent comprising steam cracker tar. A steam cracker tar composition is produced by at least (i) separating at least a portion of the steam cracker tar from the steam cracker effluent, and (ii) thermally treating at least a portion of the separated steam cracker tar in a first thermal treatment. The tar-fluid mixture is produced by adding a first utility fluid and/or a first separation fluid to the pyrolysis tar composition. A first separation is performed wherein (i) a first lower density fraction comprising upgraded steam cracker tar and (ii) a first higher density fraction are separated from the thermally treated steam cracker tar composition. At least a portion of the first, lower density fraction is directed away, for example for hydrotreating. A diluent, typically comprising a second utility fluid and/or a second separation fluid, is introduced into the first higher density portion to form a diluted first higher density portion. Subjecting the diluted first higher density portion to a second heat treatment to produce a heat treated first higher density portion. The amount of solids in the heat treated first higher density fraction is less than the amount of solids present in the diluted first higher density fraction. In a second separation, the second lower density portion and the second higher density portion are separated from the heat treated first higher density portion. Adding at least a portion of the second lower density fraction to one or more of: (i) steam cracker effluent, (ii) steam cracker tar, (iii) steam cracker tar composition; (iv) (iv) a tar-fluid mixture, (v) a first higher density fraction and (vi) a first lower density fraction.

In other embodiments, a process for steam cracking of a steam cracker feed comprising a heavy oil, such as a residue-containing heavy oil, is provided. The steam cracker effluent comprises steam cracker tar. The steam cracker comprises a convection section and a radiant section. The radiant section includes at least one radiant coil having an inlet and an outlet. The steam cracker feed is preheated in the convection section. A predominantly gas-phase stream and a predominantly non-gas-phase stream are separated from at least a portion of the preheated steam cracker feed, wherein ≥ 50 wt% of the residue in the feed is transferred into the non-gas-phase stream. At least a portion of the predominantly vapor stream is directed into the inlet of the radiant coil. Steam cracking is carried out in the presence of steam under steam cracking conditions in radiant coils. Steam cracking conditions include a temperature ranging from about 760 ℃ to about 1200 ℃ at the outlet of the radiant coil, a steam cracking pressure ranging from about 1 bar (absolute) to about 10 bar (absolute) at the outlet of the radiant coil, and a steam cracking residence time ranging from about 0.1 seconds to about 2 seconds within the radiant coil. The steam cracker effluent containing steam cracker tar is led away from the radiant section via the radiant coil outlet. At least a portion of the steam cracker tar is separated from the steam cracker effluent. In a first heat treatment, at least a separated portion of the steam cracker tar is heat treated to produce a steam cracker tar composition. Adding a first utility fluid and/or a first separation fluid to a steam cracker tar composition, and/or producing a tar-fluid mixture. At least two additional separations were performed. In a first of these separations, at least one centrifuge may be used to separate (i) a first lower density fraction containing upgraded steam cracker tar and (ii) a first higher density fraction from the tar-fluid mixture. At least a portion of the first, lower density fraction is directed away, for example for hydrotreating. A diluent comprising a second utility fluid and/or a second separation fluid is introduced into the first higher density portion to form a diluted first higher density portion. Subjecting the diluted first higher density portion to a second heat treatment to produce a heat treated first higher density portion. The amount of solids in the heat treated first higher density fraction is less than the amount of solids present in the diluted first higher density fraction. These separate second separations, which may also utilize at least one centrifuge, separate (i) a second lower density fraction and (ii) a second higher density fraction from the heat treated first higher density fraction. At least a portion of the second lower density fraction is added to one or more of: (i) a steam cracker effluent, (ii) a steam cracker tar, (iii) a steam cracker tar composition, (iv) a tar-fluid mixture, (v) a first higher density fraction and (vi) a first lower density fraction.

Other aspects of the invention include comminuting the first higher density portion (e.g., by grinding) prior to the second heat treatment. Still other aspects of the invention include separating a predominately gas-phase stream and a predominately non-gas-phase stream from a preheated steam cracker feed in a separation section integrated with a convection section. The separated predominantly vapor stream may be exposed to additional heating in the convection section prior to cracking in the radiant section.

Other aspects of the invention relate to systems and apparatus for performing any of the foregoing processes, to upgraded pyrolysis tar, upgraded steam cracker tar, and to compositions containing one or more of these, to separated lower density and higher density fractions, and to the use of any of these or any of their fractions as a feed for further processing, for example as a feed for the hydroprocessing of tar.

These and other features, aspects, and advantages of the method will become better understood with regard to the following description, appended claims, and accompanying drawings.

Brief Description of Drawings

FIG. 1 is a schematic diagram illustrating an apparatus embodying certain aspects of the present disclosure.

Fig. 2 is a graph illustrating the amount of solids lost (wt%) as a function of temperature employed in a heat treatment corresponding to the second heat treatment, according to an embodiment.

Detailed Description

The present invention generally relates to separating pyrolysis tar from a pyrolysis effluent, and upgrading at least the separated pyrolysis tar. More particularly, the present invention relates to separating at least a portion of the pyrolysis tar from the pyrolysis effluent and exposing at least a portion of the separated pyrolysis tar to a first thermal treatment to produce a pyrolysis tar composition. A first lower density fraction (upgraded pyrolysis tar) and a first higher density fraction are separated from the pyrolysis tar composition. Exposing at least a portion of the first higher density portion to a second heat treatment produces a heat treated first higher density portion having less solids (on a weight basis) than the first higher density portion. Separating the second lower density portion and the second higher density portion from the heat treated first higher density portion. At least a portion of the second, lower density portion may be recycled, for example, to the separated pyrolysis tar and/or pyrolysis effluent. At least a portion of the second higher density portion may be directed away, for example for storage and/or further processing. Upgrading pyrolysis tar in this manner has been found to increase the amount of pyrolysis tar available for further upgrading, for example in one or more hydroprocessing sections, and improve the compatibility of the upgraded pyrolysis tar for blending with other hydrocarbon streams and to produce less particulates than conventional processes. The invention will now be described more particularly with respect to pyrolysis tar (steam cracker tar, or "SCT") produced by steam cracking. The present invention is not limited to processing SCT and this description is not meant to exclude the upgrading of pyrolysis tar produced by other forms of pyrolysis within the broader scope of the invention.

In certain aspects, the steam cracker effluent from the steam cracker furnace is cooled, for example, by indirect heat transfer in one or more transfer line exchangers. Alternatively or additionally, the steam cracker effluent and/or the cooled steam cracker effluent may be quenched (e.g. by direct heat transfer). This may be done by combining the steam cracker effluent and/or the cooled steam cracker effluent with a quench oil. In at least one separation section SCT is separated from the cooled and/or quenched steam cracker effluent. Some methods of separating SCT from the steam cracker effluent and heat treating the separated SCT will now be described in more detail. The invention is not limited in these respects and this description should not be construed as excluding other methods of separating and heat treating the SCT within the broad scope of the invention.

In certain aspects, the SCT is separated from the cooled and/or quenched steam cracker effluent in a separation vessel, such as a tar knock-out drum. The separated SCT accumulates at the bottom of the drum and is typically combined with: (i) the materials already present in the drum bottom product, and (ii) optionally an added flux (flux) (e.g., utility fluid), form an SCT composition. The overhead stream removed from the tar knock-out drum is typically directed to at least one fractionator, such as a primary fractionator. The overhead stream typically comprises (i) a residue of ≥ 75 wt% of the steam cracker effluent which has been cooled and/or quenched after SCT separation, e.g. ≥ 90 wt%, e.g. ≥ 99 wt%; (ii) greater than or equal to 50 wt% of any fluxing agent that may be present in the tar knock-out drum, such as greater than or equal to 75 wt%, or greater than or equal to 90 wt%; and (iii) any quench oil (if used) directed into the tar knock-out drum with the quenched steam cracker effluent, e.g. > 75 wt%, e.g. > 90 wt%. Due to the tar knock-out drum in the imperfect separator, (i) the tar knock-out drum overhead stream may contain unseparated SCT, typically ≦ 10 wt% of the total amount of SCT in the steam cracker effluent, and (ii) the drum bottoms product of the tar knock-out drum comprises an SCT composition comprising heat treated SCT that has been separated, any flux remaining after the tar knock-out drum overhead has been directed away, and ≧ 90 wt% any quench oil remaining after the tar knock-out drum overhead has been directed away. In these and some other aspects, the tar knock-out drum overhead is directed to a primary fractionator, typically for separating a process gas stream from the tar knock-out drum overhead, the process gas stream comprising light olefins, and optionally one or more of: (i) a pyrolysis gasoline stream, (ii) a steam cracker gas oil stream, and (iii) a fractionator bottoms stream. The fractionator bottoms stream or a portion thereof may be used as quench oil or quench oil component. In these and some other aspects, the specified SCT composition is produced by maintaining the drum bottom product of the tar knock-out drum at a temperature within a specified temperature range for a residence time within a specified residence time range.

In other aspects, a tar knock-out drum is not used. In these and some other aspects, the cooled and/or quenched steam cracker effluent is directed from the cooling and/or quenching section of the effluent directly to one or more fractionators, such as a primary fractionator. Typically in these aspects, the primary fractionator functions to separate a process gas stream from the cooled and/or quenched steam cracker effluent, the process gas stream comprising light olefins, and optionally one or more of the following: (i) a pyrolysis gasoline stream, (ii) a steam cracker gas oil stream, (iii) a quench oil stream, and (iv) a bottom product stream comprising an SCT composition, which comprises separated SCT. In these and some other aspects, the prescribed heat treated SCT can be produced from the primary fractionator bottoms stream. For example, a bottoms pumparound may be utilized, wherein the bottoms pumparound has one or more sections for heating and/or cooling by indirect heat transfer to achieve a specified temperature range and a specified residence time range for the thermal treatment of the SCT composition.

In aspects comprising a primary fractionator, fractionation conditions can be adjusted to reduce or substantially eliminate the formation of solids (e.g., polymers) in the primary fractionator bottoms and/or quench oil stream. For example, the primary fractionator inlet temperature may be preselected to be in the range of 150 ℃ to 300 ℃, e.g., 160 ℃ to 210 ℃. In conventional processes for SCT upgrading, the solids produced in the first heat treatment and/or primary fractionator are directed as a low value stream, for example from filters and/or centrifuges. Surprisingly, it has been found that at least a part of these solids can be converted in a defined second heat treatment and the conversion product is separated from the unconverted solids in a second SCT-separation, recycled to the tar-fluid mixture, and then transferred into the first lower density fraction in a first SCT-separation. Doing so increases the amount of material in the higher value first lower density fraction, which in turn may be the feed amount for a beneficial process such as SATC.

Certain aspects of the invention comprise separating at least a first higher density fraction and a first lower density fraction from the SCT composition. The separation may be performed in one or more centrifuge sections (collectively "first centrifuges"). Since SCT compositions typically exhibit a relatively large viscosity over a specified processing temperature range, a stream containing the first utility fluid and/or the first separation fluid (these being less viscous than SCT) is typically added upstream of at least this separation. In these cases, the first higher density fraction and the first lower density fraction are separated from the tar-fluid mixture comprising the SCT composition and the added utility fluid/separation fluid stream.

The first, lower density fraction is typically subjected to additional processing, such as in a Solvent Assisted Tar Conversion (SATC) process. Conventional SATC processes are described, for example, in PCT patent application publication No. wo2018/111577 and U.S. patent application serial nos.62/659183 and 62/750636, each of which is incorporated herein by reference.

In conventional SATC, the first higher density portion of the SCT may be conducted away from the process. Alternatively to doing so, certain aspects of the invention also include further processing of this stream, such as one or more of the following: (1) comminuting (e.g., grinding) the first higher density fraction, which effects a reduction in solid size (e.g., particle size) to produce a comminuted first higher density fraction, (2) diluting the first higher density fraction, for example, before and/or after comminution by adding one or more of the following: (a) a second utility fluid, (b) a second separation fluid, and (c) a recycle stream to produce a diluted first higher density fraction, and (3) heat treating the comminuted and/or diluted first higher density fraction in a second heat treatment to produce a heat treated first higher density fraction. It has been found that diluting the first higher density fraction prior to the second heat treatment can reduce or significantly prevent asphaltene formation (oligomerization) reactions that might otherwise occur in the second heat treatment. It has also been found that the amount of solids (on a weight basis, based on the weight of the first higher density portion) in the heat treated first higher density portion is less than the amount of solids in the first higher density portion. This reduction in the amount of solids occurs regardless of whether the pulverization is performed before the second heat treatment.

For example, the second lower density fraction and the second higher density fraction are separated from the heat treated first higher density fraction in one or more centrifuges (collectively "second centrifuges"). The second higher density portion may be conveyed away. At least a portion of the second lower density portion may be returned to (e.g., recycled to) the process. For example, certain aspects of the invention include adding at least a portion of the second lower density portion to one or more of: (i) steam cracker effluent, e.g. as quench oil, (ii) SCT before and/or during the first thermal treatment, (iii) SCT composition, (iv) tar-fluid mixture before and/or during the separation of the first higher density portion and the first lower density portion, (v) the first higher density portion, and (vi) the first lower density portion. Recycling at least a portion of the second lower density fraction to one or more of streams (i) to (vi) results in a highly desirable increase in the amount (by weight) of the first lower density fraction separated from the heat treated SCT.

In certain aspects, at least a portion of the second lower density fraction is recycled and combined with the SCT composition. Typically, a first utility fluid is also added to the SCT composition. The combination of SCT composition, recycled portion of the second lower density portion, and first utility fluid added if any (collectively in the form of a tar-fluid mixture) is directed to a separation section for separating the first lower density portion from the first higher density portion. This increases the weight ratio of the first lower density portion to the first higher density portion and thus increases the amount of the first lower density portion available for further processing, such as in an SATC process. This in turn increases the amount of hydrotreated tar required for production by the SATC compared to conventional SCT conversion processes which do not use a second heat treatment or second centrifugation.

The method and apparatus of the present disclosure provide the ability to upgrade increased amounts of SCT using downstream hydroprocessing, as compared to conventional methods and apparatus for tar upgrading. Also, in aspects utilizing a tar knock-out drum upstream of the primary fractionator, the primary fractionator bottoms portion can be maintained at a temperature sufficiently low to reduce the amount of undesired polymerization that might otherwise occur within the bottoms portion of the primary fractionator operating at greater temperatures, e.g., >160 ℃.

Definition of

"Hydrocarbon-containing feed" means a flowable composition, e.g., a liquid phase, high viscosity, and/or slurry composition, which (i) includes carbon bonded to hydrogen, and (ii) is of a massThe density is greater than that of gasoline, typically 0.72Kg/L or greater, for example 0.8Kg/L or greater, for example 0.9Kg/L or greater, or 1.0Kg/L or greater, 1.1Kg/L or greater. Such compositions can include one or more of a crude oil, a crude oil fraction, and a composition derived therefrom having (i) a kinematic viscosity at 50 ℃ of ≦ 1.5 × 10³cSt, (ii) contains carbon bonded to hydrogen, and (iii) has a mass density of 740kg/m or more³. The hydrocarbon-containing feed typically has a final boiling point at atmospheric pressure ("atmospheric boiling point", or "normal boiling point") > or more than 430 ° F (220 ℃). Some hydrocarbon feeds include components having atmospheric boiling points of 290 ℃ or higher, for example hydrocarbon feeds containing 20% by weight or higher, for example 50% by weight or higher, for example 75% by weight or higher, or 90% by weight or higher components having atmospheric boiling points of 290 ℃ or higher. When being irradiated by sunlight, the brightness is less than or equal to 7cd/m²Certain hydrocarbon feeds appear to have a black or dark brown color upon irradiation, with brightness measured according to CIECAM02 established by Commission international de l' clairage. Non-limiting examples of such feeds include pyrolysis tar, SCT, vacuum residuum fracturing, atmospheric residuum fracturing, vacuum gas oil ("VGO"), atmospheric gas oil ("AGO"), heavy atmospheric gas oil ("HAGO"), steam cracked gas oil ("SCGO"), deasphalted oil ("DAO"), catalytic cycle oil ("CCO", including light catalytic cycle oil, "LCCO", and heavy catalytic cycle oil, "HCCO"), natural and synthetic feeds derived from tar sands or shale oils, coal.

The term "pyrolysis tar" refers to (a) a mixture of hydrocarbons having one or more aromatic components and optionally (b) non-aromatic and/or non-hydrocarbon molecules, the mixture derived from pyrolysis of the hydrocarbons, and at least 70% of the mixture having a boiling point at atmospheric pressure of greater than or equal to about 550 ° F (290 ℃). Some pyrolysis tars have initial boiling points of 200 ℃. For some pyrolysis tars, 90.0 wt% or more of the pyrolysis tar has a boiling point of 550 ℃ F. (290 ℃) or higher at atmospheric pressure. The pyrolysis tar may include, for example, greater than or equal to 50.0 wt%, such as greater than or equal to 75.0 wt%, such as greater than or equal to 90.0 wt%, of hydrocarbon molecules having (i) one or more aromatic components and (ii) a number of carbon atoms greater than or equal to about 15, including mixtures and aggregates thereof, based on the weight of the pyrolysis tar. Pyrolysis tars generally have a value of ≦ 1.0X 10³ppmw metal content, based on the weight of the pyrolysis tar, which is much lower than that of the same average viscosityMetal content found in oil (or crude oil components).

"SCT" refers to pyrolysis tar obtained from steam cracking. Typically, SCT comprises (a) a mixture of hydrocarbons having one or more aromatic components and optionally (b) non-aromatic and/or non-hydrocarbon molecules, 90% of the total boiling point of the mixture being ≥ 550 ° F (290 ℃) (e.g. ≥ 90.0 wt.% of the SCT molecules having an atmospheric boiling point ≥ 550 ° F (290 ℃). The SCT can contain a weight based upon the SCT,>50.0 wt% (e.g.,>75.0% by weight, e.g.>90.0 wt%) of a hydrocarbon molecule having (i) one or more aromatic components and (ii) a carbon number ≧ 15 (including mixtures and aggregates thereof). SCT typically has ≦ 1.0 × 10³ppmw metal content, based on the weight of SCT (e.g., metal content much lower than that found in crude oil (or crude oil components) of the same average viscosity). Typically the mass density of SCT is ≥ 1.0Kg/L, e.g. ≥ 1.05Kg/L, e.g. ≥ 1.1Kg/L, or ≥ 1.15 Kg/L.

The present invention is not limited to pyrolysis tars such as SCT, and this description should not be construed to exclude other tars or similar compositions within the broader scope of the invention. For example, in certain aspects, the tar may be or include one or more of tar, pitch, residue (residues), gums, resins, and the like, such as those resulting from petroleum processes such as crude oil processing, residue processing, deasphalting, processing atmospheric and/or vacuum tower bottoms, processing compositions derived from catalytic cracking (e.g., processing major tower bottoms), compositions resulting from hydrotreating (e.g., processing of pitch obtained and/or derived from crude oil processing, residue processing, including hydrotreating of residues, and the like), and the like. Thus, the term "tar" encompasses these compositions and pyrolysis tars such as SCT.

"solvent assisted tar conversion" or ("SATC") is a process for producing upgraded tars, such as SCT. The process comprises hydrotreating a tar stream in the presence of a utility fluid and is generally described in PCT patent application publication No. wo 2018-. For example, SATC may include hydrotreating one or more SCT streams, including those that have been previously pretreated in the presence of a utility fluid, to produce hydrotreated tars having lower viscosity, improved blending characteristics, less heteroatom impurities, and less solids content (e.g., less particulates) than SCT.

"tar heavies" ("TH") refers to hydrocarbon pyrolysis products typically included in pyrolysis tars, such as SCT. Typically TH has an atmospheric boiling point >565 ℃ and contains >5 wt% of molecules with multiple aromatic nuclei based on the weight of the tar. Typically TH is a solid at 25 ℃ and usually comprises a SCT fraction which is insoluble in n-pentane to SCT at 25 ℃ in a ratio of 5:1(vol: vol). TH typically includes asphaltenes and other high molecular weight molecules.

Tars can contain various solid forms, where the term "solid" encompasses solid phase materials and materials such as semi-solids, quasi-solids, and the like having certain liquid-like characteristics and certain solid-like characteristics. The term "solid" also encompasses materials in particulate form, which means solids in particulate form. The term particle includes polymeric asphaltene particles, polymeric coke particles, pyrolytic coke particles, inorganic fines, other organic or inorganic particles, or any combination thereof. The particulates present in the tar typically have a specific gravity of from about 1.04 to about 1.5. When comparing the particulate content (whether calculated by weight, volume or quantity) in a flowable material, such as tar or upgraded tar, to another flowable material, the comparison is performed under substantially the same conditions, such as substantially the same temperature, pressure, etc. When a sample of flowable material is obtained from a process for comparison elsewhere, for example in a laboratory, the particulate content comparison may be performed at (i) conditions that mimic the process conditions and/or (ii) ambient conditions, for example a temperature of 25 ℃ and a pressure of 1 bar (absolute).

Coke is a solid composition that can be found in certain tars, e.g., pyrolysis tars such as SCT, "pyrolysis coke" or "pyrolysis coke particles" refers to materials generated by the pyrolysis of organic molecules present in SCT and/or quench oil. The pyrolytic coke is in solid form, such as in particulate form. By "polymeric coke" or "polymeric coke particles" is meant a material produced by oligomerization of olefin molecules that can seed small fouling agent particles. Olefin molecules may be present in the SCT and/or quench oil. The polymerized coke material or particles typically have a specific gravity of from about 1.04 to about 1.1, which is much less than the specific gravity of from about 1.2 to about 1.3 of the coke solids (non-polymerized material) typically found in tar.

The "solubility blending value (S)" and "insolubility value (I)" are described in U.S. patent No.5,871,634 and determined using n-heptane as the so-called "non-polar non-solvent" and chlorobenzene as the solvent, which is incorporated herein by reference in its entirety. The S and I values were determined at oil to test liquid mixture weight ratios ranging from 1 to 5. Reference herein to various such values, e.g., "I_TC"refers to the insolubility value of a pyrolysis tar composition, such as an SCT composition; "I_TF"refers to the insolubility value of the tar-fluid mixture; "I_LD"refers to the insolubility value of the first, lower density fraction separated from the tar-fluid mixture; "I_FHD"refers to the insolubility value of the first higher density fraction, particularly the liquid phase fraction thereof; "S_{Fluid, especially for a motor vehicle}"refers to the solubility blending value of a fluid or, if appropriate, a fluid-rich stream. In conventional notation, these I and S values are often defined as I_NAnd S_BN。

The terms "higher density portion" and "lower density portion" are relative terms, which mean the mass density (ρ) of the higher density portion₂) Higher than the density (p) of the lower density portion₁) E.g. p₂≥1.01*ρ₁E.g. p₂≥1.05*ρ₁Or ρ₂≥1.10*ρ₁. In some aspects, the higher density portion contains primarily a solid component and the lower density portion contains primarily a liquid phase component. The higher density component may also include a liquid phase component separated from the lower density portion. Likewise, the lower density portion may contain solids (even in particulate form), such as those having a density similar to the liquid hydrocarbon component of the pyrolysis tar.

The term "portion" generally refers to one or more components derived from a mixture, such as from a tar-fluid mixture.

Except for its application in terms of parts per million, the term "part" is used with respect to a specified process stream, and generally means less than all of the specified stream may be selected.

In this specification, particle size within a hydrocarbon can be characterized by laser diffraction. Note that the particle size distribution can vary between different device types when laser diffraction is performed to characterize the particle size. The particle size distribution can be characterized using a Mastersizer from Malvern Instruments. If desired, the particle size distribution of the sample may be determined according to a suitable ASTM method, such as ASTM D4464.

Pyrolysis and pyrolysis tar

Pyrolysis tar is a product or byproduct of hydrocarbon pyrolysis, e.g., steam cracking. Steam cracking is now described in more detail. The present disclosure is not limited to the use of pyrolysis tar produced by steam cracking, and the present description is not meant to preclude the utilization of pyrolysis tar formed by other pyrolysis processes within the broader scope of the present disclosure.

Steam cracking

A steam cracker typically comprises a furnace facility for producing steam cracked effluent and a recovery facility for removing various products and by-products, such as light olefins and SCT, from the steam cracked effluent. A furnace plant typically includes a plurality of steam cracking furnaces. Steam crackers typically include two main sections: a convection section and a radiant section, the radiant section typically containing fired heaters. Flue gas from the fired heater is transported from the radiant section into the convection section. The flue gas flows through the convection section and is then directed away, e.g., to one or more treatments for removal of combustion byproducts such as NO_x. The hydrocarbon-containing feed is introduced into a tubular coil (convection coil) located in the convection section for preheating. Steam is added to the preheated hydrocarbon-containing feed to produce a steam cracking feed (also referred to as steam cracker feed). Typically, the steam cracked feed is reintroduced into the convection section, for example, via an additional convection coil, to produce a heated steam cracked feed. The combination of indirect heating by flue gas and direct heating by added steam in the convection section can result in vaporization, or additional vaporization, when the hydrocarbon feed is already at least partially in the gas phase, if the hydrocarbon is first introduced into the convection section. Optionally, separating at least a portion of any that is not in the gas phaseThe heated steam cracks the feed and is conducted away. The heated steam cracking feed or the vapor phase components separated therefrom may be transferred from the convection coil to one or more tubular radiant coils located within the radiant section. The indirect heating of the steam cracked feed in the radiant tubes results in cracking of at least a portion of the hydrocarbon components of the steam cracked feed. Steam cracking conditions within the radiant section can include, for example, one or more of the following: (i) a temperature range of 760 ℃ to about 1200 ℃, e.g., about 760 ℃ to about 880 ℃, (ii) a pressure range of 1 to 5 bar (absolute), or (iii) a cracking residence time range of 0.10 to 2 seconds.

In certain aspects, the hydrocarbon-containing feed includes crude oil or crude oil fractions, such as those containing 1 wt.% or more hydrocarbons having normal boiling points 566 ℃ (about 1050 ° F), based on the weight of the hydrocarbon-containing feed, e.g., >5 wt.%, or > 10 wt.%. In these aspects, it is typically beneficial to utilize a steam cracking furnace that further includes a vapor-liquid separation section, such as a vapor-liquid knock-out drum, that is thermally integrated with (but typically located outside of) the convection section of the steam cracking furnace.

When such a vapor-liquid separation section is used, a predominantly vapor phase stream and a predominantly non-vapor phase stream are separated from the steam cracking feed in the vapor-liquid separation section. For example, a portion of the crude oil (or crude oil fraction) having a normal boiling point of equal to or greater than 566 ℃ of equal to or greater than 50 wt% can be transferred to a non-gaseous stream. The separated predominantly vapor stream is typically exposed to additional heating in the convection section prior to cracking. For a predominantly gaseous stream, up to 70 wt.%, for example up to 90 wt.%, of the stream is in the gaseous phase. For streams that are predominantly non-gaseous, up to 70 wt.%, e.g., > 90 wt.%, of the stream is not in the gaseous phase.

At least a portion of the stream of the predominately gas phase is directed into an inlet of at least one radiant coil located in the radiant section for cracking under steam cracking conditions. The radiant coil includes an inlet and an outlet, and the steam cracking conditions include one or more of: the temperature at the outlet of the radiant coil ranges from about 760 ℃ to about 1200 ℃ (e.g., about 880 ℃ to about 1,200 ℃, such as about 1,000 ℃ to about 1,200 ℃); the steam cracking pressure at the outlet of the radiant coil ranges from about 1 bar (absolute) to about 10 bar (absolute) (e.g., from about 1 bar (absolute) to about 5 bar (absolute), alternatively from about 6 bar (absolute) to about 10 bar (absolute)); and/or a steam cracking residence time in the radiant coil ranging from about 0.1 seconds to about 2 seconds. The steam cracker effluent is directed away from the radiant section for cooling and/or quenching. At least a portion of the SCT is separated from the cooled and/or quenched steam cracker effluent to produce an SCT composition.

Some hydrocarbon-containing feeds will now be described in more detail. The present invention is not limited to these hydrocarbon-containing feeds and the present description should not be construed to exclude steam cracking of other hydrocarbon-containing feeds within the broader scope of the invention.

Although the hydrocarbon-containing feed may include one or more light hydrocarbons such as methane, ethane, propane, butane, etc., the SCT yield is greater when the hydrocarbon-containing feed includes a significant amount of higher molecular weight hydrocarbons. For example, the hydrocarbonaceous feed can comprise ≥ 1.0 wt.%, e.g. ≥ 10 wt.%, e.g. ≥ 25.0 wt.%, or ≥ 50.0 wt.% (based on the weight of the hydrocarbonaceous feed) of hydrocarbon compounds in the liquid and/or solid phase at 25 ℃ and an absolute pressure of 1 bar.

The hydrocarbon portion of the hydrocarbonaceous feed typically comprises one or more of naphtha, gas oil, vacuum gas oil, waxy residue, atmospheric residue, residue mixture, crude oil and SCT at > 10.0 wt%, for example > 50.0 wt%, for example > 90.0 wt% (based on the weight of the hydrocarbon portion). Some hydrocarbonaceous feeds include greater than or equal to about 0.1 wt% asphaltenes. When the hydrocarbon-containing feed comprises crude oil and/or one or more fractions thereof, the crude oil is optionally desalted crude oil. Suitable crude oils include, for example, high sulfur crude oils such as those rich in polycyclic aromatic hydrocarbons. Crude oil fractions may be produced by separating an atmospheric pressure tube furnace ("APS") bottoms from crude oil followed by vacuum tube furnace ("VPS") processing of the APS bottoms. Suitable crude oils include, for example, a hydrocarbon-containing feed can include ≧ 90.0 wt% of one or more crude oil fractions such as those obtained from atmospheric APS and/or VPS; waxy residue; residue under normal pressure; naphtha contaminated with crude oil; a mixture of various residues.

Steam cracking feed is typically produced by heating a hydrocarbon-containing feed in one or more convection coils and combining the heated hydrocarbon-containing feed with steam. The steam cracking feed typically comprises ≥ 10.0 wt% hydrocarbons, e.g. ≥ 25.0 wt%,. gtoreq.50.0 wt%, e.g. ≥ 65 wt%, based on the weight of the steam cracking feed. Typically, the remainder of the steam cracker feed is steam at or above 90 wt%.

In certain aspects, the SCT is separated from the cooled and/or quenched steam cracker effluent in one or more separation stages. Conventional separation equipment may be used to separate SCT and other products and byproducts from the cooled and/or quenched steam cracking effluent, such as one or more flash drums, knock-out drums, fractionators, water quench towers, indirect condensers, and the like. Suitable separation stages are described in U.S. patent No.8,083,931 and in PCT patent application publication No. wo2018-111574, which is incorporated herein by reference in its entirety. The SCT can be separated from the quenched effluent itself and/or from one or more streams that have been separated from the cooled and/or quenched effluent. For example, SCT can be separated from the bottoms of a flash drum (e.g., the bottoms of one or more tar knock-out drums downstream of a steam cracking furnace and upstream of a primary fractionator). Some SCT is a mixture of the primary fractionator bottoms and the tar knock-out drum bottoms.

Representative SCTs are now described in more detail. The embodiments are not limited to the use of these SCTs and this description is not meant to exclude the treatment of other SCTs, or other pyrolysis tars, within the broader scope of the present disclosure.

Steam cracker tar ("SCT")

Typically, the cooled and/or quenched steam cracker effluent comprises steam, molecular hydrogen, hydrocarbons (saturated and unsaturated), non-hydrocarbon compositions, and solids (typically hydrocarbon-containing solids, such as TH, and non-hydrocarbon solids), including particulates. For example, the cooled and/or quenched steam cracker effluent may comprise ≧ 1.0 wt.% C₂Unsaturates and 0.1 wt% or more TH, based on the weight of the cooled and/or quenched steam cracker effluent. It is also typical for the cooled and/or quenched steam cracker effluent to include ≧ h0.5 wt% TH, for example ≧ 1.0 wt% TH. The SCT in the cooled and/or quenched steam cracker effluent typically comprises more than or equal to 50.0 wt%, such as more than or equal to 75.0 wt%, such as more than or equal to 90.0 wt% of the total TH in the cooled and/or quenched steam cracker effluent. TH is typically in the form of aggregates which comprise hydrogen and carbon and which have an average size in the range of from 10.0nm to 300.0nm in at least one dimension and an average number of carbon atoms ≧ 50. Generally, TH comprises ≥ 50.0 wt%, e.g. ≥ 80.0 wt%, e.g. ≥ 90.0 wt% of aggregates having a C: H atomic ratio in the range 1.0 to 1.8, a molecular weight in the range 250 to 5000, and a melting point in the range 100 ℃ to 700 ℃. SCT typically comprises ≥ 50.0 wt%, e.g. ≥ 75.0 wt%, e.g. ≥ 90.0 wt% TH in the quench effluent, based on the total weight of TH in the quench effluent.

Representative SCTs typically have (i) a TH content in the range of 5.0 to 40.0 wt%, based on the weight of the SCT, (ii) an API gravity (measured at a temperature of 15.8 ℃) of ≦ 8.5 API, such as ≦ 8.0 API, or ≦ 7.5 API; and (iii) in the range of 200cSt to 1.0X 10⁷cSt, e.g. 1X 10³cSt to 1.0X 10⁷cSt viscosity at 50 ℃ as determined according to A.S.T.M.D445. SCT can have, for example>0.5 wt%, or>A sulfur content of 1 wt%, or more, for example in the range of 0.5 wt% to 7.0 wt%, based on the weight of the SCT. In aspects in which the steam cracking feed does not contain a significant amount of sulfur, the SCT can comprise 0.5 wt% sulfur or less, e.g., 0.1 wt% or less, e.g., 0.05 wt% or less sulfur, based on the weight of the SCT.

The SCT can have, for example, (i) a TH content ranging from 5.0 wt% to 40.0 wt%, based on the weight of the SCT; (ii) 1.01g/cm at 15 DEG C³To 1.19g/cm³In a density range of, for example, 1.07g/cm³To 1.18g/cm³(ii) a And (iii) a viscosity at 50 ℃ in the range of ≥ 200cSt, e.g. ≥ 600cSt, or in the range of 200cSt to 1.0X 10⁷cSt. The density range is more than or equal to 1.10g/cm at the temperature of 15 DEG C³E.g.. gtoreq.1.12 g/cm³，≥1.14g/cm³，≥1.16g/cm³Or not less than 1.17g/cm³The defined hydrotreatment is particularly advantageous with respect to SCT. Optionally, the SCT has ≧ 1.0X 10⁴cSt, examplesE.g.. gtoreq.1.0X 10⁵cSt, or not less than 1.0X 10⁶cSt, or even ≧ 1.0X 10⁷cSt kinematic viscosity at 50 ℃. Optionally, the SCT has>80 of I_NAnd>70 wt% of pyrolysis tar molecules have a normal pressure boiling point of more than or equal to 290 ℃. Typically, insoluble content of SCT ("IC)_T") is equal to or greater than 0.5 wt%, for example, equal to or greater than 1 wt%, for example, equal to or greater than 2 wt%, or equal to or greater than 4 wt%, or equal to or greater than 5 wt%, or equal to or greater than 10 wt%.

In at least one embodiment, the SCT comprises a mixture of hydrocarbons having one or more aromatic components and optionally non-aromatics and/or non-hydrocarbons, and at least 70% of the mixture has a boiling point greater than or equal to about 550 ° F (290 ℃) at atmospheric pressure. SCT typically comprises hydrocarbons (including mixtures and aggregates thereof) having (i) one or more aromatic components and (ii) a number of carbon atoms greater than about 15. SCT typically has a metal content of less than or equal to 1000ppmw, based on the weight of the pyrolysis tar, which is much less than the metal content found in crude oil (or crude oil components) of the same average viscosity. Optionally, the normal boiling point of SCT is more than or equal to 290 ℃, and the viscosity at 15 ℃ is more than or equal to 1 x 10⁴cSt, and the density is more than or equal to 1.1g/cm³. The SCT can be a mixture comprising a first SCT and one or more additional pyrolysis tars, such as a combination of the first SCT and the one or more additional SCTs. When SCT is a mixture, typically at least 70 wt% of the mixture has a normal boiling point of at least 290 ℃ and includes olefinic hydrocarbons that contribute to tar reactivity under hydroprocessing conditions. When the mixture includes first and second pyrolysis tars (one or more of which is optionally SCT), the normal boiling point of the second pyrolysis tar, at or above 90 wt%, is optionally at or above 290 ℃.

It has been found that an increase in reactor fouling occurs during hydroprocessing of tar-fluid mixtures comprising SCT with excess olefinic hydrocarbons. To reduce the amount of fouling of the reactor, it is beneficial that the SCT has an olefin content of 10.0 wt% or less (based on the weight of the SCT), for example 5.0 wt% or less, for example 2.0 wt% or less. More particularly, it has been observed that less reactor fouling occurs during hydroprocessing when the SCT has an amount of vinyl aromatic hydrocarbon (based on the weight of the SCT) of ≦ 5.0 wt%, for example ≦ 3 wt%, for example ≦ 2.0 wt% and/or (ii) an amount of aggregate incorporated into the vinyl aromatic hydrocarbon of ≦ 5.0 wt% (based on the weight of the SCT), for example ≦ 3 wt%, for example ≦ 2.0 wt%.

SCT composition

The SCT composition typically comprises ≥ 40 wt% SCT which has been separated from the steam cracker effluent, e.g. ≥ 60 wt%, such as ≥ 70 wt%, or more, based on the weight of the SCT composition. The SCT composition can further include a composition formed during heat treatment of the SCT. In certain aspects, for example, in aspects in which (i) quench oil is not used to quench the steam cracker effluent and (ii) no utility fluid is added to the tar knock-out drum, the SCT composition may comprise ≥ 90 wt.% heat-treated SCT, e.g. ≥ 95 wt.%, or ≥ 99 wt.%, or more. The SCT composition typically comprises ≥ 90.0 wt% SCT which has been (i) separated from the cooled and/or quenched steam cracker effluent, and (ii) thermally treated. The SCT can further comprise SCT-derived material recycled to the first thermal treatment or a location upstream thereof (e.g., the recycled portion of the second lower density portion). The SCT composition obtained from one or more defined SCT sources may contain SCT at > 50.0 wt%, based on the weight of the stream, e.g. > 75.0 wt%, such as > 90.0 wt%, or more. In aspects in which > 50 wt%, or > 75 wt%, or > 90 wt%, or more of the SCT in the SCT composition is SCT separated in the tar knock-out drum, the remainder of the weight of the SCT stream greater than 90 wt% (e.g., the portion of the stream other than SCT, if any) typically comprises one or more of the following: (i) in aspects in which flux is added to the tar knock-out drum, any flux (e.g., utility fluid) remaining with the SCT after the tar knock-out drum overhead stream is directed away; (ii) in aspects in which quench oil is introduced into the steam cracker effluent and/or the cooled steam cracker effluent, any quench oil that may remain with the SCT after the tar knock-out drum overhead stream is directed away; (iii) a substance formed during or as a result of the first heat treatment; and (iv) particulates.

The aspect in which the first heat treatment comprises a heat soak in the tar knock-out drum will now be described in more detail. The present invention is not limited in these respects and the description should not be construed as excluding (i) other forms of thermal treatment, such as thermal treatment of the SCT composition in the primary fractionator, or (ii) other forms of thermal treatment thereof to pyrolyze the tar.

SCT heat treatment by hot dipping

During the heat soaking process, at least the separated SCT is maintained at the heat soaking location, for example within the bottom product region of the tar knock-out drum, or within one or more infuser vessels adapted for this purpose and located outside the tar knock-out drum. Conventional equipment for heat soaking SCT may be used, but the present invention is not limited thereto. Conventional plant configurations for heat soaking SCT are disclosed in PCT patent application publication No. wo2018-111574, which discloses heat soaking SCT in the bottom product region of a tar knock-out drum, and optionally in the presence of a utility fluid added as a flux. The flux may be used as an aid in the separation and thermal soaking, for example a flux having substantially the same composition as the first utility fluid. The separation of SCT and heat soaking can be performed before, during, and/or after the addition of flux. Since aspects of the present invention include at least one additional heat treatment (second heat treatment) of the stream derived from the SCT composition, the heat treatment of the separated SCT is referred to as a "first heat treatment" or a "first heat soak".

Using, for example, the hot-soaking structure disclosed in PCT patent application publication No. wo2018-111574, at least the separated SCT can be independently heated and/or cooled to reach the desired hot-soaking temperature (T;)_HS1) And for a desired period of time (t)_HS1). Temperature T_HS1Typically in the range of about 200 ℃, about 220 ℃, about 230 ℃, about 240 ℃, about 250 ℃, about 260 ℃, about 270 ℃, about 275 ℃, about 280 ℃, or about 290 ℃ to about 295 ℃, about 300 ℃, about 310 ℃, about 320 ℃, about 325 ℃, about 330 ℃, about 340 ℃, about 350 ℃, about 360 ℃, about 375 ℃, about 400 ℃, about 450 ℃, about 500 ℃, or more. E.g. T_HS1May range from about 200 ℃ to about 500 ℃, from about 230 ℃ to about 500 ℃, from about 250 ℃ to about 500 ℃, from about 280 ℃ to about 500 ℃, from about 290 ℃ to about 500 ℃, from about 300 ℃ to about 500 ℃, from about 320 ℃ to about 500 ℃, from about 350 ℃ to about 500 ℃, from about 250 ℃ to about 450 ℃, from about 280 ℃To about 450 ℃, about 290 ℃ to about 450 ℃, about 300 ℃ to about 450 ℃, about 320 ℃ to about 450 ℃, about 350 ℃ to about 450 ℃, about 250 ℃ to about 400 ℃, about 280 ℃ to about 400 ℃, about 290 ℃ to about 400 ℃, about 300 ℃ to about 400 ℃, about 320 ℃ to about 400 ℃, about 350 ℃ to about 400 ℃, about 250 ℃ to about 350 ℃, about 280 ℃ to about 350 ℃, about 290 ℃ to about 350 ℃, about 300 ℃ to about 350 ℃, about 320 ℃ to about 350 ℃, or about 330 ℃ to about 350 ℃. Although it is not required to maintain the separated SCT at a substantially constant temperature (i.e. at T) during the thermal soaking process_HS1Substantially constant temperature within the specified range), but typically does so.

The first heat soaking is typically performed for a predetermined time t within a range of about 2min, about 5min, about 10min, about 12min, or about 15min to about 20min, about 25min, about 30min, about 45min, about 60min, about 90min, about 2hr, about 3hr, about 5hr, or longer_HS1. E.g. t_HS1Can range from about 5min to about 5hr, from about 5min to about 3hr, from about 5min to about 2hr, from about 5min to about 1hr, from about 5min to about 45min, from about 5min to about 30min, or from about 5min to about 20 min. In one or more instances, t_HS1About 2min, about 5min, about 10min, about 15min, or about 20min to about 30min, about 45min, about 60min, about 90min, about 2hr, about 3hr, or about 5hr of (a) to dissolve and/or decompose at least a portion of the particles present within the separated SCT.

While not wishing to be bound by any theory or model, it is believed that the first heat soak dissolves and/or decomposes the particles within the separated SCT, or otherwise reduces the particle content. It was also observed that the separated SCT was maintained at a temperature T_HS1Next predetermined time t_HS1Afterwards, the SCT composition typically contains less particles than the SCT that has been isolated. In one or more embodiments, during and/or as a result of the first heat soaking, about 25 wt%, about 30 wt%, about 35 wt%, or about 40 wt% to about 45 wt%, about 50 wt%, about 60 wt%, about 70 wt%, about 75 wt%, about 80 wt%, about 85 wt%, about 90 wt%, about 92 wt%, about 95 wt%, about 97 wt%, about 98 wt%, about 99 wt%, or more of the particles within the separated SCT are dissolved and/or decomposed. In some examples, at the first heatAt least 25 wt%, at least 30 wt%, at least 35 wt%, at least 40 wt%, at least 45 wt%, at least 50 wt%, at least 60 wt%, at least 70 wt%, at least 75 wt%, at least 80 wt% to about 85 wt%, about 90 wt%, about 92 wt%, about 95 wt%, about 97 wt%, about 98 wt%, about 99 wt%, or more of the particles within the separated SCT are dissolved and/or decomposed during the soaking and/or as a result of the first heat soaking. For example, during and/or as a result of the first heat soaking, about 25 wt% to about 99 wt%, about 30 wt% to about 99 wt%, about 35 wt% to about 99 wt%, about 40 wt% to about 99 wt%, about 45 wt% to about 99 wt%, about 50 wt% to about 99 wt%, about 60 wt% to about 99 wt%, about 70 wt% to about 99 wt%, about 75 wt% to about 99 wt%, about 25 wt% to about 95 wt%, about 30 wt% to about 95 wt%, about 35 wt% to about 95 wt%, about 40 wt% to about 95 wt%, about 45 wt% to about 95 wt%, about 50 wt% to about 95 wt%, about 60 wt% to about 95 wt%, about 70 wt% to about 95 wt%, about 75 wt% to about 95 wt%, about 25 wt% to about 90 wt%, about 30 wt% to about 90 wt%, about 35 wt% to about 90 wt%, about 40 wt% to about 90 wt%, about 45 wt% to about 90 wt%, from about 50 wt% to about 90 wt%, from about 60 wt% to about 90 wt%, from about 70 wt% to about 90 wt%, from about 75 wt% to about 90 wt%, from about 25 wt% to about 80 wt%, from about 30 wt% to about 80 wt%, from about 35 wt% to about 80 wt%, from about 40 wt% to about 80 wt%, from about 45 wt% to about 80 wt%, from about 50 wt% to about 80 wt%, from about 60 wt% to about 80 wt%, from about 70 wt% to about 80 wt%, or from about 75 wt% to about 80 wt% of the particles in the separated SCT are dissolved and/or decomposed.

The SCT composition typically comprises the separated SCT, which is now heat treated, plus any added flux, minus the portion of the separated SCT that may have been converted during or as a result of the first heat treatment, plus at least a portion of certain conversion products (e.g., solids, such as polymer particulates) that may have been formed during or as a result of the first heat treatment. Other examples of the latter category include certain compositions that may result from decomposition during the first heat treatment of any solids present within the separated SCT (e.g., normal boiling point ranges similar to those of SCT). It has been found that certain solids, e.g. particulate solids, are formed during or as a result of the first heat treatment, e.g. by polymerisation of the separated SCT in a tar knock-out drum and/or a primary fractionator.

The SCT composition is subjected to further processing which includes separating a first higher density fraction and a first lower density fraction in a first stage of SCT separation ("first SCT separation stage"). At least a portion of any solids formed during or as a result of the first thermal treatment typically reside within the first higher density portion.

Although the SCT composition can be the feed to the first SCT separation section, it is typical to combine the SCT composition with a recycle portion of the second lower density portion upstream of the first SCT separation section to form a tar-fluid mixture. Some representative tar-fluid mixtures are now described in more detail. The present invention is not limited to these tar-fluid mixtures and, within the broader scope of the invention, this description should not be construed to exclude other tar-fluid mixtures within the broader scope of the invention.

Tar-fluid mixture

The tar-fluid mixture typically includes an SCT composition and a fluid. The fluid comprises a circulating portion of the second, lower density portion and typically further comprises a first utility fluid and/or a first separation fluid. The amount of fluid (e.g., by weight) in the tar-fluid mixture typically ranges from 20 wt% to 60 wt%, e.g., 30 wt% to 50 wt%. The amount of the circulating portion of the second lower density portion within the fluid is typically substantially equal to the weight of the material (typically particles) that is converted to a lower density during or as a result of the second heat treatment (e.g., using fig. 2), plus the weight of the diluent (e.g., the second utility fluid and/or the second separation fluid) added to the first higher density portion, the comminuted first higher density portion, the diluted first higher density portion, and/or the heat treated first higher density portion. Typically, the remaining portion of the stream (e.g., the portion of the stream that is not the second, lower density portion of the cycle) is the first utility stream and/or the first separation stream, e.g., ≧ 75 wt%, such as ≧ 90 wt%, or ≧ 99 wt%. The first utility fluid (and/or the first separation fluid), when used, can be added to (i) the SCT composition (which may already contain at least some of the utility fluid as a flux) and/or (ii) the mixture of the SCT composition and the recycled portion of the second, lower density portion. In other words, the first utility fluid and/or the first separation fluid may be added to the SCT composition before, during, and/or after the SCT composition is combined with the circulating portion of the second lower density portion. The viscosity of the tar-fluid mixture is lower than the SCT composition.

The tar-fluid mixture typically contains ≥ 5 wt% of the SCT composition, e.g. ≥ 10 wt%, > 20 wt%, > 30 wt%, > 40 wt%, > 50 wt%, > 60 wt%, > 70 wt%, > 80 wt%, or ≥ 90 wt% of the SCT composition, based on the total weight of the tar-fluid mixture (e.g. the combined weight of all components in the tar-fluid mixture). Additionally or alternatively, the tar-fluid mixture may include less than or equal to 10 wt% of the SCT composition, e.g., less than or equal to 20 wt%, less than or equal to 30 wt%, less than or equal to 40 wt%, less than or equal to 50 wt%, less than or equal to 60 wt%, less than or equal to 70 wt%, less than or equal to 80 wt%, less than or equal to 90 wt%, or less than or equal to 95 wt% of the SCT composition, based on the total weight of the tar-fluid mixture. Ranges specifically disclosed include combinations of any of the above enumerated values, for example, from about 5 wt% to about 95 wt%, from about 5 wt% to about 90 wt%, from about 5 wt% to about 80 wt%, from about 5 wt% to about 70 wt%, from about 5 wt% to about 60 wt%, from about 5 wt% to about 50 wt%, from about 5 wt% to about 40 wt%, from about 5 wt% to about 30 wt%, from about 5 wt% to about 20 wt%, or from about 5 wt% to about 10 wt% of the SCT composition.

In addition to the SCT composition, the tar-fluid mixture typically further comprises ≥ 5 wt.% utility fluid, e.g. ≥ 10 wt.%, ≥ 20 wt.%, ≥ 30 wt.%, ≥ 40 wt.%, ≥ 50 wt.%, ≥ 60 wt.%, ≥ 70 wt.%, ≥ 80 wt.%, or ≥ 90 wt.%, based on the total weight of the tar-fluid mixture (e.g., the combined weight of all components in the tar-fluid mixture). Additionally or alternatively, the tar-fluid mixture may include less than or equal to 10 wt.% of the utility fluid, e.g., less than or equal to 20 wt.%, less than or equal to 30 wt.%, less than or equal to 40 wt.%, less than or equal to 50 wt.%, less than or equal to 60 wt.%, less than or equal to 70 wt.%, less than or equal to 80 wt.%, less than or equal to 90 wt.%, or less than or equal to 95 wt.% of the utility fluid, based on the total weight of the tar-fluid mixture. Ranges expressly disclosed include combinations of any of the above enumerated values, for example, from about 5 wt% to about 95 wt%, from about 5 wt% to about 90 wt%, from about 5 wt% to about 80 wt%, from about 5 wt% to about 70 wt%, from about 5 wt% to about 60 wt%, from about 5 wt% to about 50 wt%, from about 5 wt% to about 40 wt%, from about 5 wt% to about 30 wt%, from about 5 wt% to about 20 wt%, or from about 5 wt% to about 10 wt% of the utility fluid.

In certain aspects, the tar-fluid mixture comprises (i) the SCT composition, (ii) a recycle portion of the second, lower density portion, and (iii) any first utility fluid added to the SCT composition prior to the first SCT separation segment. For example, the tar-fluid mixture may contain about 15 wt%, about 20 wt%, about 25 wt%, 30 wt%, about 35 wt%, about 40 wt%, about 45 wt%, or about 50 wt% to about 55 wt%, about 60 wt%, about 65 wt%, about 70 wt%, about 75 wt%, about 80 wt%, about 85 wt%, or about 90 wt%, or more of the utility fluid, based on the combined weight of the tar-fluid mixture (e.g., the combined weight of all components in the tar-fluid mixture). Typically, the tar-fluid mixture contains about 15 wt% to about 90 wt%, about 20 wt% to about 80 wt%, about 20 wt% to about 70 wt%, about 20 wt% to about 60 wt%, about 20 wt% to about 50 wt%, about 20 wt% to about 40 wt%, about 20 wt% to about 30 wt%, about 25 wt% to about 90 wt%, about 30 wt% to about 85 wt%, about 30 wt% to about 80 wt%, about 35 wt% to about 80 wt%, about 40 wt% to about 75 wt%, about 40 wt% to about 70 wt%, about 40 wt% to about 65 wt%, about 40 wt% to about 60 wt%, about 40 wt% to about 55 wt%, about 40 wt% to about 50 wt%, about 40 wt% to about 45 wt%, about 45 wt% to about 80 wt%, about 45 wt% to about 45 wt%, about 45 wt% to about 70 wt%, about 45 wt% to about 45 wt%, about 45 wt% to about 70 wt%, about 45 wt% to about 45 wt%, about 45 wt% to about 70 wt%, about 45 wt% to about 60 wt%, about 45 wt% to about 55 wt%, about 45 wt% to about 50 wt%, about 50 wt% to about 80 wt%, about 50 wt% to about 75 wt%, about 50 wt% to about 70 wt%, about 50 wt% to about 65 wt%, about 50 wt% to about 60 wt%, about 50 wt% to about 55 wt%, about 55 wt% to about 80 wt%, about 55 wt% to about 75 wt%, about 55 wt% to about 70 wt%, about 55 wt% to about 65 wt%, or about 55 wt% to about 60 wt% of a utility fluid, based on the total weight of the tar-fluid mixture.

The combination of the SCT composition, the utility fluid, and the recycle portion of the second, lower density portion is conducted under conditions that reduce or substantially prevent asphaltene precipitation. Those skilled in the art will appreciate that by doing so one can take advantage of blending information for these compositions, such as the insolubility value I_TFAnd a solubility blending value S_TF. Thus, in some aspects, the S of the tar-fluid mixture _TF150 or less, for example 140 or less, or 130 or less, or 120 or less, or 115 or more, or 110 or more, 105 or more, 100 or more, 95 or more, or 90 or more. In some examples, S of the tar-fluid mixture_TFIs about 70, about 80, about 85, about 90, about 95, about 100, about 105, about 110, about 115, about 120, about 130, about 140, or about 150. For example, S of tar-fluid mixtures_TFIn the range of about 70 to about 150, about 70 to about 130, about 70 to about 125, about 70 to about 120, about 70 to about 115, about 70 to about 110, about 70 to about 105, about 70 to about 100, about 70 to about 95, about 70 to about 90, about 70 to about 85, about 80 to about 130, about 80 to about 125, about 80 to about 120, about 80 to about 115, about 80 to about 110, about 80 to about 105, about 80 to about 100, about 80 to about 95, about 80 to about 90, about 85 to about 130, about 85 to about 125, about 85 to about 120, about 85 to about 115, about 85 to about 110, about 85 to about 105, about 85 to about 100, about 85 to about 95, about 85 to about 90, about 90 to about 130, about 90 to about 125, about 90 to about 120, about 90 to about 115, about 90 to about 110, about 90 to about 105, about 90 to about 100, about 90 to about 95, or about 90 to about 100.

In particular in aspects in which the tar-fluid mixture components are not subsequently hydrotreated, the fluids of the tar-fluid mixture may further include a first separated fluid, in which context "fluid" refers to the total amount of the first utility fluid in the tar-fluid mixture plus the total amount of the first separated fluid in the tar-fluid mixture. The separation fluid may be used as an aid in separating the first higher density and lower density portion and in separating the second higher density and lower density portion. Although the separation fluid may have substantially the same composition as the utility fluid, it typically has a different composition. The tar-fluid mixture can optionally include a first separation fluid typically used in an amount of 35 wt% or less, e.g., 30 wt% or less, 25 wt% or less, 20 wt% or less, 15 wt% or less, 10 wt% or less, 5 wt% or less, 2.5 wt% or less, based on the total weight of the fluids (e.g., utility fluid plus separation fluid) in the tar-fluid mixture. Additionally or alternatively, the separation fluid may be present in an amount of ≥ 0 wt%, for example ≥ 1.5 wt%, ≥ 2.5 wt%, ≥ 5 wt%, ≥ 10 wt%, > 15 wt%, > 20 wt%, > 25 wt%, or ≥ 30 wt%, based on the total weight of fluid in the tar-fluid mixture. Ranges specifically disclosed include combinations of any of the above enumerated values, for example, 0 to about 35 wt%, 0 to about 30 wt%, 0 to about 25 wt%, 0 to about 20 wt%, 0 to about 15 wt%, 0 to about 10 wt%, 0 to about 5 wt%, 0 to about 2.5 wt%, 0 to about 1.5 wt% of the separating fluid, based on the total weight of the fluid within the tar-fluid mixture.

Thus, in some aspects, the fluid comprises greater than or equal to 50 wt% of the separated fluid, e.g., greater than or equal to 60 wt%, greater than or equal to 70 wt%, greater than or equal to 80 wt%, greater than or equal to 90 wt%, greater than or equal to 95 wt%, greater than or equal to 97.5 wt%, greater than or equal to 99 wt%, or about 100 wt% of the separated fluid, based on the total weight of the tar-fluid mixture. Additionally or alternatively, the tar-fluid mixture may include 99 wt% or less of a separation fluid, for example,

97.5% by weight or less, 95% by weight or less, 90% by weight or less, 80% by weight or less, 70% by weight or less, or 60% by weight or less of the separating fluid, based on the total weight of the tar-fluid mixture. Ranges expressly disclosed include combinations of any of the above enumerated values, for example, from about 50 wt% to about 100 wt%, from about 60 wt% to about 100 wt%, from about 70 wt% to about 100 wt%, from about 80 wt% to about 100 wt%, from about 90 wt% to about 100 wt%, from about 95 wt% to about 100 wt%, from about 97.5 wt% to about 100 wt%, or from about 99 wt% to about 100 wt% of the separation fluid.

The kinematic viscosity of the tar-fluid mixture is typically less than that of the SCT composition. In some aspects, the dynamic viscosity of the tar-fluid mixture may be ≧ 0.5cP, e.g., ≧ 1cP, ≧ 2.5cP, ≧ 5cP,

is more than or equal to 7.5 cP. Additionally or alternatively, the kinematic viscosity of the tar-fluid mixture may be 10cP or less, e.g., 7.5cP or less, 5cP or less, 2.5cP or less, 1cP or less, 0.75cP or less at a temperature of from about 50 ℃ to about 250 ℃, e.g., about 100 ℃. Ranges include combinations of any of the above enumerated values, for example, from about 0.5cP to about 10cP, from about 1cP to about 10cP, from about 2.5cP to about 10cP, from about 5cP to about 10cP, or from about 7.5cP to about 10cP at a temperature of from about 50 ℃ to about 250 ℃, e.g., about 100 ℃.

Utility fluids

The first and second utility fluids may be independently selected. Each may be selected from conventional utility fluids such as those used as process aids for hydroprocessing tars such as SCT, but the invention is not so limited. Suitable utility fluids include those described in U.S. provisional application No. 62/716754; U.S. patent nos.9,090,836; 9,637,694, respectively; and 9,777,227; and 9,809,756 and those disclosed in PCT patent application publication No. wo2018-111574, which are incorporated herein by reference in their entirety. Although not required, the first and second utility fluids may have substantially the same composition and may be referred to as "utility fluids".

The utility fluid typically comprises ≥ 40 wt% of at least one aromatic or non-aromatic ring-containing compound, e.g. ≥ 45 wt%, ≥ 50 wt%, > 55 wt%, or ≥ 60 wt%, based on the weight of the utility fluid. Particular utility fluids contain ≥ 40%, ≥ 45%, ≥ 50%, ≥ 55%, or ≥ 60% by weight, based on the weight of the utility fluid, of at least one polycyclic compound. The compounds contain a majority of carbon and hydrogen atoms, but may also contain various substituents and/or heteroatoms.

In certain aspects, the utility fluid contains aromatics, e.g., > 70 wt% aromatics, based on the weight of the utility fluid, e.g., > 80 wt%, or > 90 wt%. Typically, the utility fluid contains ≦ 10 wt% paraffins based on the weight of the utility fluid. For example, the utility fluid may contain ≧ 95 wt% aromatics, ≦ 5 wt% paraffins. Optionally, the final boiling point of the utility fluid is 750 ℃ (1,400 ° F), e.g., ≦ 570 ℃ (1,050 ° F), e.g., ≦ 430 ℃ (806 ° F). Such utility fluids may contain ≧ 25 wt% of 1-ring and 2-ring aromatic hydrocarbons (e.g., those having one or two rings and at least one aromatic nucleus), based on the weight of the utility fluid. Utility fluids having relatively low final boiling points, such as final boiling point ≦ 400 ℃ (750 ° F), may be used. The utility fluid may have a total boiling point of 10% (weight basis) of 120 ℃ or more, e.g., 140 ℃ or more, e.g., 150 ℃ or more, and/or a total boiling point of 90% of 430 ℃ or less, e.g., 400 ℃ or less. Suitable utility fluids include those having a true boiling point distribution range of typically 175 ℃ (350 ° F) to about 400 ℃ (750 ° F). The true boiling point distribution, which can be extended by extrapolation when it has a final boiling point outside the range covered by the a.s.t.m. method, can be determined, for example, by conventional methods, such as the a.s.t.m.d7500 method. In certain aspects, the utility fluid has a mass density of ≦ 0.91g/mL, e.g., ≦ 0.90g/mL, e.g., ≦ 0.89g/mL, or ≦ 0.88g/mL, e.g., ranging from 0.87g/mL to 0.90 g/mL.

The utility fluid typically contains aromatics, e.g., > 95.0 wt% aromatics, e.g., > 99.0 wt%. For example, the utility fluid can contain ≧ 75 wt% based on the weight of the utility fluid of one or more of: benzene, ethylbenzene, trimethylbenzene, xylenes, toluene, naphthalenes, alkylnaphthalenes (e.g., methylnaphthalenes), decalin or alkyldecalin (e.g., methyldecalin), e.g., > 90 wt%, or > 95 wt%, or > 99.0 wt%, e.g., > 99.9 wt%. It is generally desirable for the utility fluid to be substantially free of molecules having alkenyl functionality, particularly in aspects employing hydrotreating catalysts that have a propensity for coke (e.g., pyrolyzed and/or polymerized particles) formation in the presence of such molecules. In certain aspects, the utility fluid contains ≦ 10.0 wt% having C₁-C₆Cyclic compounds of side chains with alkenyl functional groups, based on the weight of the utility fluid.

In some examples, the utility fluid may include ≧ 90 wt% monocyclic aromatic hydrocarbon including those having one or more hydrocarbon substituents, such as 1 to 3 or 1 to 2 hydrocarbon substituents. Illustrative hydrocarbon substituents or hydrocarbon groups can be or include, but are not limited to, C₁-C₆Alkyl, wherein the hydrocarbon groups may be branched or straight chain, and the hydrocarbon groups may be the same or different.

In some examples, the utility fluid can be substantially free of molecules having terminal unsaturation, such as vinyl aromatics. As used herein, the term "substantially free" means that the utility fluid includes less than or equal to 10 wt%, such as less than or equal to 5 wt%, or less than or equal to 1 wt% of terminal unsaturation based on the weight of the utility fluid. The utility fluid may include ≥ 50 wt% molecules having at least one aromatic nucleus, e.g. ≥ 60 wt% or ≥ 70 wt% based on the weight of the utility fluid. In some examples, the utility fluid can include ≧ 60 wt% molecules having at least one aromatic nucleus and less than or equal to 1 wt% terminal unsaturation, such as vinyl aromatic hydrocarbons, based on the weight of the utility fluid.

In aspects in which hydrotreating is envisioned, such as hydrotreating of the first lower density portion, the utility fluid typically contains a sufficient amount of molecules having one or more aromatic nuclei as processing aids, for example, to effectively increase the run length of the tar hydrotreating process. For example, the utility fluid can contain ≧ 50.0 wt% molecules having at least one aromatic nucleus (e.g., ≧ 60.0 wt%, such as ≧ 70 wt%), based on the total weight of the utility fluid. In one aspect, the utility fluid contains (i) ≧ 60.0 wt.% molecules having at least one aromatic nucleus and (ii) ≦ 1.0 wt.% vinyl aromatic hydrocarbons, weight percentages based on the weight of the utility fluid.

The utility fluid can be a utility fluid having a high dissolution through a solubility blending value ("S_{Fluid, especially for a motor vehicle}") to measure. For example, the utility fluid can have S_{Fluid, especially for a motor vehicle}≧ 90, such as ≧ 100, ≧ 110, ≧ 120, ≧ 150, ≧ 175, or ≧ 200. Additionally or alternatively, S_{Fluid, especially for a motor vehicle}Can be 200 or less, e.g., 175 or less, 150 or less, 125 or less, 110 or less, or 100 or less. Ranges expressly disclosed include any combination of the above enumerated values.

Additionally or alternatively, the utility fluid may be characterized by a kinematic viscosity typically less than the tar-fluid mixture. In particular aspects, the dynamic viscosity of the tar-fluid mixture may be ≧ 0.1cP, e.g., ≧ 0.5cP, ≧ 1cP, ≧ 2.5cP, or ≧ 4cP at a temperature of about 50 ℃ to about 250 ℃, e.g., about 100 ℃. Additionally or alternatively, the kinematic viscosity of the tar-fluid mixture may be 5cP or less, e.g., 4cP or less, 2.5cP or less, 1cP or less, 0.5cP or less, or 0.25cP or less, at a temperature of from about 50 ℃ to about 250 ℃, e.g., about 100 ℃. Ranges expressly disclosed include any combination of the above enumerated values. In some aspects, the dynamic viscosity of the utility fluid is adjusted so that when combined with the SCT composition to produce a tar-fluid mixture, solids greater than 25 μm in size settle out of the tar-fluid mixture to provide a solids-rich fraction (extract) and a solids-lean fraction (raffinate) as described herein, more particularly the viscosity is adjusted to also enable proper solids removal and production of the solids-lean fraction from the process.

Optional separation fluid

Each of the first and second separation fluids may be independently selected. Each may be selected from hydrocarbon liquids having a mass density less than the mass density of the SCT composition, e.g., ≦ 1% of the feed, e.g., ≦ 5%, or ≦ 10%. Although not required, the first and second separated fluids may have substantially the same composition, and may be referred to as "separated fluids". The separation fluid may be any hydrocarbon liquid, typically a non-polar hydrocarbon, or a mixture thereof. In some aspects, the separation fluid may be a paraffin or a mixture of paraffins. The particular paraffinic fluid comprises C₅-C₂₀Hydrocarbons and mixtures thereof, especially C₅-C₁₀Hydrocarbons such as hexane, heptane and octane. Such fluids may be particularly useful when subsequent hydroprocessing is not desired. In certain aspects, the mass density of the separation fluid is ≦ 0.91g/mL, e.g., ≦ 0.90g/mL, e.g., ≦ 0.89g/mL, or ≦ 0.88g/mL, e.g., in the range of 0.87 to 0.90 g/mL.

When a different separation fluid (i.e., a separation fluid having a composition substantially different from the utility fluid) is used in the production of the tar-fluid mixture, the separation fluid may be present in the tar-fluid mixture in an amount of 35 wt% or less, for example, 30 wt% or less, 25 wt% or less, 20 wt% or less, 15 wt% or less, 10 wt% or less, 5 wt% or less, 2.5 wt% or less, based on the total weight of the fluids in the tar-fluid mixture. Additionally or alternatively, the separation fluid may be present in an amount of ≥ 0 wt%, for example ≥ 1.5 wt%, ≥ 2.5 wt%, ≥ 5 wt%, ≥ 10 wt%, > 15 wt%, > 20 wt%, > 25 wt%, or ≥ 30 wt%, based on the total weight of fluid in the tar-fluid mixture. Ranges expressly disclosed include any combination of the above enumerated values. In these and other aspects, it is typical that the separation fluid (if used) and SCT composition together comprise a tar-fluid mixture of > 50 wt% balance (the balance being that part of the tar-fluid mixture of the non-utility fluid + the recycled part of the second, lower density fraction), for example > 75 wt%, such as > 90 wt%, or > 95 wt%, or > 99 wt%.

The tar-fluid mixture may contain both the utility fluid and the separation fluid. Particularly in aspects in which the tar-fluid mixture components are not subsequently hydrotreated, the tar-fluid mixture may include ≧ 30 wt% of the separated fluid. Thus, in some aspects, the fluid of the tar-fluid mixture (i.e., any utility fluid present within the tar-fluid mixture plus any separation fluid present within the tar-fluid mixture) may contain greater than or equal to 50 wt% of the separation fluid, e.g., greater than or equal to 60 wt%, greater than or equal to 70 wt%, greater than or equal to 80 wt%, greater than or equal to 90 wt%, greater than or equal to 95 wt%, greater than or equal to 97.5 wt%, greater than or equal to 99 wt%, or 100 wt% of the separation fluid based on the total weight of the tar-fluid mixture. Additionally or alternatively, the tar-fluid mixture may include 99 wt% or less of the separating fluid, e.g., 97.5 wt% or less, 95 wt% or less, 90 wt% or less, 80 wt% or less, 70 wt% or less, or 60 wt% or less of the separating fluid, based on the total weight of the tar-fluid mixture. Ranges expressly disclosed include any combination of the above enumerated values.

The aspects of the invention comprising separating a first higher density fraction and a first lower density fraction from a tar-fluid mixture in a first SCT separation section will now be described in more detail. The invention is not limited in these respects and the description should not be construed as excluding other forms of separation.

First SCT separation- -separation of the first higher density and first lower density fractions from the Tar-fluid mixture

The first higher density and lower density fractions may be separated from the tar-fluid mixture by any means suitable for achieving the specified separation, including one or more of precipitation, filtration, and extraction. Conventional separation techniques may be utilized, but the embodiments are not limited thereto. For example, the first lower density portion can be separated from the tar-fluid mixture by decantation, filtration, and/or boiling point separation (e.g., one or more distillation columns, splitters, flash drums, or any combination thereof). The first higher density portion can be separated from the tar-fluid mixture in a similar manner, for example, by removing the first higher density portion from the separation section as a bottoms portion. The first higher density portion and the first lower density portion may be separated from the tar-fluid mixture in any order, such as substantially simultaneously, by first separating the first higher density portion and then separating the first higher density portion from the first lower density portion, or vice versa. In some aspects, the first lower density portion and the first higher density portion are separated by exposing the tar-fluid mixture to centrifugal force, such as by using one or more centrifuges in a separation section.

Induced centrifugal force

In some aspects, a tar-fluid mixture containing SCT, solids (e.g., pyrolytic coke, polymeric coke, and/or inorganics), and a first utility fluid and/or a first separation fluid is provided to a centrifuge for exposure of the tar-fluid mixture to centrifugal force sufficient to form at least a higher density portion and a lower density portion. Optionally, the tar-fluid mixture is subjected to one or more filtration stages, e.g., to remove solids having a size of 5000 μm or more, e.g., 3000 μm or more, e.g., 2000 μm or more, or 1000 μm or more. In certain aspects, the solids present within the tar-fluid mixture range in size from less than 1 μm to 3000 μm, for example in the range of about 0.5 μm to 2000 μm. Typically, the size of the solids is ≥ 75% by weight ≥ 2000 μm, for example ≥ 90% by weight, such as ≥ 95% by weight, or ≥ 99% by weight. Typically, the size of the ≥ 75 wt.% solids ranges from 50 μm to 88 μm, e.g. ≥ 90 wt.%, e.g. ≥ 95 wt.%, or ≥ 99 wt.%.

Typically, the tar-fluid mixture exhibits a substantially uniform annular motion within the centrifuge as a result of the applied centrifugal force. Depending on the choice of reference frame, the central force may be referred to as a centrifugal force (within the reference frame of the tar-fluid mixture) or a centripetal force (within the reference frame of the centrifuge). The process may be carried out in a batch, semi-batch or continuous mode.

The centrifuge may be configured to apply heat to the tar-fluid mixture, such as by heating the tar-fluid mixture to an elevated temperature. In some aspects, inducing centrifugal force further comprises heating the tar-fluid mixture to a temperature of about 20 ℃, about 25 ℃, about 30 ℃, about 40 ℃, about 50 ℃, about 55 ℃, or about 60 ℃ to about 65 ℃, about 70 ℃, about 80 ℃, about 85 ℃, about 90 ℃, about 95 ℃, about 100 ℃, about 110 ℃, about 120 ℃, or greater. For example, the tar-fluid mixture may be heated while centrifuging to a temperature of from about 20 ℃ to about 120 ℃, from about 20 ℃ to about 100 ℃, from about 30 ℃ to about 100 ℃, from about 40 ℃ to about 100 ℃, from about 50 ℃ to about 100 ℃, from about 60 ℃ to about 100 ℃, from about 70 ℃ to about 100 ℃, from about 80 ℃ to about 100 ℃, from about 90 ℃ to about 100 ℃, from about 20 ℃ to about 80 ℃, from about 30 ℃ to about 80 ℃, from about 40 ℃ to about 80 ℃, from about 50 ℃ to about 80 ℃, from about 60 ℃ to about 80 ℃, or from about 70 ℃ to about 80 ℃.

The centrifugal force may be applied for any number of times. Typically, the centrifugal force is applied for more than or equal to 1 minute, e.g., more than or equal to 5 minutes, more than or equal to 10 minutes, more than or equal to 30 minutes, more than or equal to 60 minutes, or more than or equal to 120 minutes. Additionally or alternatively, centrifugal force can be applied for less than or equal to 120 minutes, less than or equal to 60 minutes, less than or equal to 30 minutes, less than or equal to 10 minutes, or less than or equal to 5 minutes. Ranges expressly disclosed include any combination of the above enumerated values, for example, from about 1 minute to about 120 minutes, from about 5 minutes to about 120 minutes, from about 10 minutes to about 120 minutes, from about 30 minutes to about 120 minutes, or from about 60 minutes to about 120 minutes. The centrifugal force may be applied at any amount of force or speed. For example, sufficient force is provided by a centrifuge operating at about 1,000rpm to about 10,000rpm, about 2,000rpm to about 7,500rpm, or about 3,000rpm to about 5,000 rpm.

Centrifuging the tar-fluid mixture typically results in separating from the tar-fluid mixture at least (i) an extract comprising, consisting essentially of, or consisting of a first, higher density fraction of the tar-fluid mixture, and (ii) a raffinate comprising, consisting essentially of, or consisting of a first, lower density fraction. In other words, exposing the tar-fluid mixture to centrifugal forces results in the removal of at least the higher density portion (extract) from the tar-fluid mixture. When the process is operated continuously or semi-continuously, at least two streams are directed from the centrifuge: one stream containing the extract and another stream containing the raffinate. Centrifuges having this capability are commercially available, but the present invention is not so limited.

Typically centrifugation is sufficient to separate ≥ 80 wt%,. gtoreq.90 wt%,. gtoreq.95 wt%,. gtoreq.99 wt% solids (including particles within the tar-fluid mixture) within the tar-fluid mixture having a size ≥ 2 μm, e.g.. gtoreq.10 μm, e.g.. gtoreq.20 μm, or ≥ 25 μm into a first, higher density fraction (e.g. extract), where wt% is based on the total weight of solids within the higher density and lower density fractions. When a subsequent hydrotreatment of the raffinate is envisaged, the higher-density fraction contains ≥ 95 wt.%, in particular ≥ 99 wt.% solids of a size ≥ 2 μm, for example ≥ 10 μm, for example ≥ 20 μm, or ≥ 25 μm. In other aspects, such as where the first lower density portion (e.g., raffinate) is not hydrotreated, the filtration should be sufficient to separate at least 80 wt% of the solids into the first higher density portion.

While the description focuses on separating the first higher density portion and the first lower density portion, other embodiments envision that components in the first tar-fluid mixture may be separated and extracted more independently, e.g., very light components separated to the top of the mixture, a portion containing primarily fluids, upgraded tar fractions, tar heavies, or solids at the bottom of the centrifuge chamber. Each of these fractions, or combinations thereof, can be selectively removed from the mixture as one or more raffinates.

A first lower density portion

The first lower density portion may be directed away for one or more of: storage, blending with other hydrocarbons, or further processing, for example for SATC. The first lower density portion is generally of a desired natureE.g., an insolubility value less than the SCT composition and/or less than the higher density fraction. Typically, the insolubility value (I) of the first, lower density fraction_FLD) Is equal to or greater than 20, for example, equal to or greater than 30, ≧ 40, ≧ 50, ≧ 60, ≧ 70, ≧ 80, ≧ 90, ≧ 100, ≧ 110, ≧ 120, ≧ 130, ≧ 140, or ≧ 150. Additionally or alternatively, I_FLDCan be 150 or less, e.g., 140 or less, 130 or less, 120 or less, 110 or less, 100 or less, 90 or less, 80 or less, 70 or less, 60 or less, 50 or less, 40 or less, or 30 or less. Ranges expressly disclosed include any combination of the above enumerated values, such as, for example, from about 20 to about 150, from about 20 to about 140, from about 20 to about 130, from about 20 to about 120, from about 20 to about 110, from about 20 to about 100, from about 20 to about 90, from about 20 to about 80, from about 20 to about 70, from about 20 to about 60, from about 20 to about 50, from about 20 to about 40, or from about 20 to about 30. Those skilled in the art will appreciate that hydrocarbon separation techniques are imperfect and that, therefore, small amounts of solids may be present in the first, lower density portion, e.g., an amount of solids that is 0.1 times or less the amount of solids in the tar-fluid mixture, e.g., 0.01 times or less. In aspects in which at least a portion of the first lower density fraction is hydrotreated, such as by a SATC process, a solids removal device (e.g., one or more filters) is typically employed between the separation stage and the hydrotreating stage.

Insolubility value I of the first, lower density fraction_FLDInsolubility value to SCT composition I_TCThe ratio of (B) is less than or equal to 0.95, for example less than or equal to 0.90, less than or equal to 0.85, less than or equal to 0.80, less than or equal to 0.75, less than or equal to 0.70, less than or equal to 0.65, less than or equal to 0.60, less than or equal to 0.55, less than or equal to 0.50, less than or equal to 0.40, less than or equal to 0.30, less than or equal to 0.20, or less than or equal to 0.10. Additionally or alternatively, I_FLDTo I_TCThe ratio may be equal to or greater than 0.10, for example, equal to or greater than 0.20, equal to or greater than 0.30, equal to or greater than 0.40, equal to or greater than 0.50, equal to or greater than 0.55, equal to or greater than 0.60, equal to or greater than 0.65, equal to or greater than 0.70, equal to or greater than 0.75, equal to or greater than 0.80, equal to or greater than 0.85, or equal to or greater than 0.90. Ranges expressly disclosed include any combination of the above enumerated values, such as, for example, about 0.10 to 0.95, about 0.20 to 0.95, about 0.30 to 0.95, about 0.40 to 0.95, about 0.50 to 0.95, about 0.55 to 0.95, about 0.60 to 0.95, about 0.65 to 0.95, about 0.70 to 0.95, about 0.75 to 0.95, about 0.80 to 0.95, about 0.85 to 0.95, or about 0.90 to 0.95.

A first higher density portion

The first, higher density fraction typically comprises solids having a size of less than or equal to 5000 μm, e.g., less than or equal to 2000 μm, e.g., less than or equal to 1000 μm, and optionally containing liquids brought from separation (e.g., from centrifugation), e.g., utility fluid and/or separation fluid. For example, the first higher density fraction may contain solids in the range of 1 wt% to 25 wt% with a size ≦ 5000 μm (or ≦ 3000 μm, or ≦ 2000 μm), such as 5 wt% to 15 wt%, based on the weight of the first higher density fraction. In certain aspects, the first higher density portion contains solids ranging in size from ≦ 1 μm to 5000 μm, for example, 0.1 μm to 3000 μm, for example, ranging from about 0.5 μm to 2000 μm. Typically, the size of the solids is ≥ 75% by weight ≥ 2000 μm, for example ≥ 90% by weight, such as ≥ 95% by weight, or ≥ 99% by weight. Typically, the size of the ≥ 75 wt.% solids ranges from 50 μm to 88 μm, e.g. ≥ 90 wt.%, e.g. ≥ 95 wt.%, or ≥ 99 wt.%.

The first, higher density fraction, in particular the liquid phase fraction thereof, may have an insolubility value I_FHDNot less than 20, not less than 40, not less than 70, not less than 90, not less than 100, not less than 110, not less than 120, not less than 130, not less than 140, or not less than 150. Additionally or alternatively, I_FHDCan be less than or equal to 40, less than or equal to 70, less than or equal to 90, less than or equal to 100, less than or equal to 110, less than or equal to 120, less than or equal to 130, less than or equal to 140, or less than or equal to 150. Ranges expressly disclosed include any combination of the above enumerated values, for example, from about 20 to about 150, from about 40 to about 150, from about 70 to about 150, from about 90 to about 150, from about 100 to about 150, from about 110 to about 150, from about 120 to about 150, from about 130 to about 150, or from about 140 to about 150.

Additionally or alternatively, the first higher density fraction may contain asphaltenes and/or tar heavies. In some aspects, the first higher density portion, particularly the liquid portion thereof, contains ≧ 50 wt% asphaltenes, e.g., ≧ 60 wt%, ≧ 75 wt%, based on the total weight of the first higher density portion. The first higher density fraction can comprise 10 wt% or less, for example 7.5 wt% or less, 5 wt% or less, 2.5 wt% or less, 2 wt% or less, 1.5 wt% or less, or 1 wt% or less of the total asphaltene content in the SCT composition. The first higher density fraction may comprise more than or equal to 1 wt%, e.g. > 1.5 wt%, more than or equal to 2 wt%, more than or equal to 2.5 wt%, more than or equal to 5 wt%, or more than or equal to 7.5 wt% of the total asphaltene content in the SCT composition. Ranges expressly disclosed include combinations of any of the above enumerated values, for example, 1 wt% to 10 wt%, 1 wt% to 7.5 wt%, 1 wt% to 5 wt%, 1 wt% to 2.5 wt%, 1 wt% to 2 wt%, or 1 wt% to 1.5 wt% of the total asphaltene content in the SCT composition. It may be preferable to remove a smaller amount of asphaltene content. For example, it has been surprisingly found that separating even small amounts of asphaltenes into a higher density fraction has a surprising effect on the insolubility value of the first lower density fraction. While not wishing to be bound by any theory or model, it is believed that the presence of relatively high density asphaltenes within the SCT composition has a much greater effect on the insolubility value than lower density asphaltenes. Thus, a relatively large number of problematic molecules may be separated, leaving a first, lower density fraction of molecules that contributes to the overall yield of the process.

The advantages of this process are obtained even when the first higher density fraction contains a relatively small fraction of the SCT composition. The first higher density fraction can contain less than or equal to 10 wt%, for example less than or equal to 7.5 wt%, less than or equal to 5 wt%, less than or equal to 2.5 wt%, less than or equal to 2 wt%, less than or equal to 1.5 wt%, or less than or equal to 1 wt% of the total weight of the SCT composition. Ranges expressly disclosed include combinations of any of the above enumerated values, for example, 1 wt% to 10 wt%, 1 wt% to 7.5 wt%, 1 wt% to 5 wt%, 1 wt% to 2.5 wt%, 1 wt% to 2 wt%, or 1 wt% to 1.5 wt% of the total weight of the SCT composition. Removal of the relatively low weight portion may surprisingly be accompanied by a relatively large improvement in the insolubility value of the first lower density portion. The solids present in the extract optionally have a mass density of ≧ 1.05g/mL, e.g., ≧ 1.10g/mL, e.g., > 1.2g/mL, or ≧ 1.3g/mL, or a range of about 1.05g/mL to 1.5 g/mL.

The first higher density fraction typically comprises > 50 wt% of any SCT solids remaining after the first heat treatment, e.g. > 75 wt%, such as > 90 wt%, or > 99 wt%. The first higher density fraction typically further comprises ≥ 50 wt.% any solids formed in the SCT composition during or as a result of the first heat treatment, e.g. ≥ 75 wt.%, e.g. ≥ 90 wt.%, or ≥ 99 wt.%. The first higher density fraction is treated in a second heat treatment and the size of the solids present in the first higher density fraction is optionally physically reduced (e.g. by comminution, e.g. grinding) in order to reduce the amount of solids. This treatment may be carried out in the presence of a diluent.

Optional size reduction-physical Process

Optionally, a physical process of solids, such as particle size reduction (milling, etc. -collectively referred to as comminution), is performed on the first higher density fraction to form a comminuted higher density fraction. Examples of physical methods of size reduction may include grinding, ball milling, ablation in an ablation drum, and/or other mechanical size reduction methods. The physical method of size reduction may be contrasted with the chemical method of size reduction. For example, as described herein, at least a portion of the solids (e.g., particulates) within the SCT fraction (or other pyrolysis tar fraction) that are small enough can be hydrotreated (e.g., under SATC conditions) to convert the small solids to a liquid product. During certain SATC processes, a combination of elevated temperature, elevated pressure, the presence of a chemical agent, and/or the presence of a catalyst is used to induce a chemical reaction. The chemical reaction results in a change in chemical composition, which may then lead to a reduction in size. Conversely, in some aspects, the physical size reduction may result in solids having substantially similar compositions both before and after the size reduction (with the possible exception of the surface layer).

After subjecting the first higher density portion to the first physical size reduction process, the weight of solids having a size greater than or equal to 25 μm in the comminuted higher density portion may be further reduced in one or more additional stages. The weight of solids having a size greater than or equal to 25 μm in the effluent from these stages is less than or equal to 85%, or less than or equal to 75%, or less than or equal to 65%, or less than or equal to 50%, for example up to 10% or possibly still lower, relative to the weight of such solids in the first higher density portion or diluted first higher density portion (as the case may be).

Suitable equipment for reducing the size of the solids is commercially available, but the invention is not limited thereto. Grinders, ball mills, and ablators are suitable. More generally, any convenient method of reducing the size of solids, such as coke fines, may be used.

Since the first higher density fraction is typically leaner in overall fluid (any first utility fluid + any first separation fluid) than the tar-fluid mixture, a diluted first higher density fraction may be formed by introducing a second utility fluid and/or a second separation fluid within the first higher density fraction. These diluents are optional and may be added to the first higher density fraction in (i) the second heat treatment and/or (ii) the separation of the second higher density and second lower density fractions, for example as a flux and/or as an aid. These diluents may be added before and/or after optional size reduction (e.g., optional grinding). For example, a secondary utility fluid may be added before and/or after optional grinding. The second utility fluid may be selected from the same compositions specified for the first utility fluid, and typically the first and second utility fluids have substantially the same composition.

Diluted first higher density fraction

If desired, for example, as a processing aid for the first higher density portion, a diluent (typically comprising a second utility fluid and/or a second separation fluid) may be added to the first higher density portion to form a diluted first higher density portion. The diluent, if used, may correspond to 20 wt% to 60 wt% of the diluted first higher density fraction, or 20 wt% to 50 wt%, or 30 wt% to 60 wt%. Even if diluent is added to the first higher density portion prior to the size reduction process, additional diluent may be added after the size reduction to further facilitate heat soaking of the first higher density portion (or the comminuted higher density portion) present within the diluted first higher density portion. Typically, the diluent comprises > 50 wt% of the utility fluid, based on the weight of the diluent, e.g. > 75 wt%, e.g. > 90 wt%. Typically, the balance of diluent of > 90 wt% comprises the separation fluid.

In certain aspects, the diluent is free of the second separation fluid. It has been found that treating the diluted first higher density fraction in a second heat treatment prior to separating the second higher density fraction from the second lower density fraction can eliminate the need for a second separation fluid.

It has been found advantageous that the diluent comprises a second utility fluid and that the second heat treatment is carried out under different conditions than the first heat treatment. It has been found that doing so provides for the dissolution of at least a portion of the polymer solids within the first higher density portion, such as those formed during and/or as a result of the first heat treatment, and the intentional depolymerization of these polymer solids. In addition, the second effect dilutes the second heat treated depolymerization products with a fluid, which is observed to reduce or eliminate re-polymerization of these products. The second utility fluid may be selected from utility fluids containing a reactive composition such as SCGO. When this second utility fluid is present within the diluted first higher density portion during the second thermal treatment, a decrease in reactivity (e.g., a decrease in SCGO reactivity) is observed. This feature mimics (and eliminates the need for) the use of higher value diluents, such as utility fluids (e.g., middle distillates) recovered from the SATC process. In other words, the diluent may include SCGO, middle distillates, or combinations thereof.

In some aspects, the diluent can contain greater than or equal to 65 wt% of the utility fluid, e.g., greater than or equal to 75 wt%, greater than or equal to 80 wt%, greater than or equal to 85 wt%, greater than or equal to 90 wt%, or greater than or equal to 95 wt% of the utility fluid, based on the total weight of the diluent. Additionally or alternatively, the diluent can contain less than or equal to 100 wt.% of the utility fluid, e.g., less than or equal to 95 wt.%, less than or equal to 90 wt.%, less than or equal to 85 wt.%, less than or equal to 80 wt.%, less than or equal to 75 wt.%, or less than or equal to 70 wt.% of the utility fluid, based on the total weight of the diluent. Ranges expressly disclosed include combinations of any of the above enumerated values, for example, from about 65 wt% to about 100 wt%, from about 75 wt% to about 100 wt%, from about 80 wt% to about 100 wt%, from about 85 wt% to about 100 wt%, from about 90 wt% to about 100 wt%, or from about 95 wt% to about 100 wt% of the utility fluid. In certain aspects, the diluent is a utility fluid.

In the following description of the diluted first higher density portion and the second heat treatment, it is to be understood that in aspects in which the optional pulverization step is performed, the first higher density portion may be a pulverized first higher density portion. Typically, the diluted first higher density fraction contains ≥ 5 wt% of the first higher density fraction, e.g. ≥ 10 wt%, ≥ 20 wt%, > 30 wt%, > 40 wt%,

greater than or equal to 50 wt%, greater than or equal to 60 wt%, greater than or equal to 70 wt%, greater than or equal to 80 wt%, or greater than or equal to 90 wt%, based on the total weight of the diluted first higher density portion. Those skilled in the art will recognize that the amount of utility fluid in the diluted first higher density portion includes (i) any residual first utility fluid transferred from the tar-fluid mixture to the first higher density portion and (ii) the second utility fluid.

In addition to the first higher density fraction, the diluted higher density fraction usually contains ≥ 5 wt.% diluent, e.g. ≥ 10 wt.%, ≥ 20 wt.%, ≥ 30 wt.%, ≥ 40 wt.%, ≥ 50 wt.%,

greater than or equal to 60 wt%, greaterthan or equal to 70 wt%, greaterthan or equal to 80 wt%, or greater than or equal to 90 wt%, based on the total weight of the diluted higher density portion (e.g., the combined weight of the first higher density portion, any residual first utility fluid brought from the tar-fluid mixture, any first separation fluid brought from the tar-fluid mixture, any second utility fluid, and any second separation fluid). Additionally or alternatively, the diluted first higher density fraction can include less than or equal to 10 wt% fluid, e.g., less than or equal to 20 wt%, less than or equal to 30 wt%, less than or equal to 40 wt%, less than or equal to 50 wt%, less than or equal to 60 wt%, less than or equal to 70 wt%, less than or equal to 80 wt%, less than or equal to 90 wt%, or less than or equal to 95 wt% diluent, based on the total weight of the diluted first higher density fraction. Ranges expressly disclosed include combinations of any of the above enumerated values, for example, from about 5 wt% to about 95 wt%, from about 5 wt% to about 90 wt%, from about 5 wt% to about 80 wt%, from about 5 wt% to about 70 wt%, from about 5 wt% to about 60 wt%, from about 5 wt% to about 50 wt%, from about 5 wt% to about 40 wt%, from about 5 wt% to about 30 wt%, from about 5 wt% to about 20 wt%, or from about 5 wt% to about 10 wt% of the fluid.

In some aspects, the diluted first higher density portion has a solubility blend value of less than 150, such as less than or equal to about 140, less than or equal to about 130, less than or equal to about 120, less than or equal to about 115, less than or equal to about 110, less than or equal to about 105, less than or equal to about 100, less than or equal to about 95, or less than or equal to about 90. In some examples, the diluted first higher density portion has a solubility blend value of about 70, about 80, about 85, about 90, about 95, about 100, about 105, about 110, about 115, about 120, about 130, about 140, or about 150. For example, the diluted first higher density portion has a solubility blend value of about 70 to about 150, about 70 to about 130, about 70 to about 125, about 70 to about 120, about 70 to about 115, about 70 to about 110, about 70 to about 105, about 70 to about 100, about 70 to about 95, about 70 to about 90, about 70 to about 85, about 80 to about 130, about 80 to about 125, about 80 to about 120, about 80 to about 115, about 80 to about 110, about 80 to about 105, about 80 to about 100, about 80 to about 95, about 80 to about 90, about 85 to about 130, about 85 to about 125, about 85 to about 120, about 85 to about 115, about 85 to about 110, about 85 to about 105, about 85 to about 100, about 85 to about 95, about 85 to about 90, about 90 to about 130, about 90 to about 125, about 90 to about 120, about 90 to about 115, about 90 to about 110, about 90 to about 105, about 90 to about 100, about 85 to about 95, or about 90 to about 100.

The diluted first higher density portion may have a lower kinetic viscosity than the first higher density portion. In some aspects, the dynamic viscosity of the diluted first higher density portion can be ≧ 0.5cP, e.g., ≧ 1cP, ≧ 2.5cP, ≧ 5cP, ≧ 7.5cP, at a temperature of about 50 ℃ to about 250 ℃, e.g., about 100 ℃. Additionally or alternatively, the dynamic viscosity of the tar-fluid mixture can be 10cP or less, e.g., 7.5cP or less, 5cP or less, 2.5cP or less, 1cP or less, 0.75cP or less at a temperature of from about 50 ℃ to about 250 ℃, e.g., about 100 ℃. Ranges may include any combination of the above enumerated values, for example, from about 0.5cP to about 10cP, from about 1cP to about 10cP, from about 2.5cP to about 10cP, from about 5cP to about 10cP, or from about 7.5cP to about 10cP at a temperature of from about 50 ℃ to about 250 ℃, e.g., about 100 ℃.

The diluted first higher density portion is subjected to an additional heat treatment. The aspect in which the second heat treatment includes the second heat soaking will now be described in more detail. The present invention is not limited in these respects and the description should not be construed as excluding forms of heat treatment that do not include heat soaking.

Second heat treatment

In other embodiments, the first higher density portion or the diluted first higher density portion (as the case may be) is subjected to a second heat treatment, e.g., a second heat soak. The second heat treatment may be carried out by heat soaking in at least one container or drum. Thermal soaking may include pyrolysis, such as thermal pyrolysis.

Some form of solids is present within the SCT when it is separated from the steam cracker effluent. Other forms of solids, such as certain particulates, are formed during and/or as a result of the first heat treatment, for example by polymerization of SCT that has been separated in the tar knock-out drum and/or in the primary fractionator. It has been found that (i) the SCT composition can contain both solid forms, and (ii) > 50 wt% of the solids within the SCT composition are transferred to the first higher density fraction, e.g. > 75 wt%, such as > 90 wt%, or > 95 wt%, or > 99 wt% when operating the first SCT separation under specified conditions. Surprisingly, it has been found that such solids can be converted during and/or as a result of the second heat treatment to form a conversion product (typically in the liquid phase) having a mass density in substantially the same range as the first, lower density fraction. The amount of material residing in the first lower density fraction can thus be increased by (i) transferring at least a portion of the second heat treated conversion products into the second lower density fraction, and then recycling the second lower density fraction to (i) the first lower density fraction and/or (ii) at a location in the process upstream of the separation of the first lower density fraction from the SCT composition. Typically,. gtoreq.50 wt% of the solids in the first higher density fraction are those produced during the first heat treatment, such as. gtoreq.75 wt%, such as. gtoreq.90 wt%, or more. FIG. 2 can be used to determine the amount of these solids converted in a defined second heat treatment. While not wishing to be bound by any theory or model, it is believed that the second heat treatment at least partially converts (e.g., dissolves or decomposes) solids present within the diluted first higher density fraction, particularly those solids produced during and/or as a result of the first heat treatment (e.g., by polymerization). For a typical SCT, fig. 2 shows that the temperature during or as a result of the second heat treatment is greater as a function of the temperature of the second heat treatment for a time range of 30 minutes to 60 minutesMass density translates to an amount of solids of lower mass density (e.g., from a more dense solid and/or semi-solid phase to a less dense liquid phase). One skilled in the art will appreciate that similar curves can be generated for other tars without undue experimentation. The second heat soaking may be performed using conventional heat soaking equipment, such as one or more infuser drums, although the invention is not limited thereto. Can be at a desired temperature (' T)_HS2") and for a desired period of time (" t "or" t "or" t "or" a "or" a "or" a "or" a "or" a "or" a "or" a "or" a "or" a "or" a "or" a "or_HS2") which is typically predetermined. T is_HS2Typically about 200 ℃, about 220 ℃, about 230 ℃, about 240 ℃, about 250 ℃, about 260 ℃, about 270 ℃, about 275 ℃, about 280 ℃, or about 290 ℃ to about 295 ℃, about 300 ℃, about 310 ℃, about 320 ℃, about 325 ℃, about 330 ℃, about 340 ℃, about 350 ℃, about 360 ℃, about 375 ℃, about 400 ℃, about 450 ℃, about 500 ℃, or more. E.g. T_HS2May range from about 200 ℃ to about 500 ℃, from about 230 ℃ to about 500 ℃, from about 250 ℃ to about 500 ℃, from about 280 ℃ to about 500 ℃, from about 290 ℃ to about 500 ℃, from about 300 ℃ to about 500 ℃, from about 320 ℃ to about 500 ℃, from about 350 ℃ to about 500 ℃, from about 250 ℃ to about 450 ℃, from about 280 ℃ to about 450 ℃, from about 290 ℃ to about 450 ℃, from about 300 ℃ to about 450 ℃, from about 320 ℃ to about 450 ℃, from about 350 ℃ to about 450 ℃, from about 250 ℃ to about 400 ℃, from about 280 ℃ to about 400 ℃, from about 290 ℃ to about 400 ℃, from about 300 ℃ to about 400 ℃, from about 320 ℃ to about 400 ℃, from about 350 ℃ to about 400 ℃, from about 250 ℃ to about 350 ℃, from about 280 ℃ to about 350 ℃, from about 300 ℃ to about 350 ℃, from about 320 ℃ to about 350 ℃, or from about 330 ℃ to about 350 ℃. Although it is not required to maintain the diluted first higher density portion at a substantially constant temperature (i.e., at T) during the second heat soaking process_HS2A substantially constant temperature within the specified range), but typically this is done. Time t_HS2Can be about 2min, about 5min, about 10min, about 12min, or about 15min to about 20min, about 25min, about 30min, about 45min, about 60min, about 90min, about 2hr, about 3hr, about 5hr, or longer. E.g. t_HS2Can range from about 5min to about 5hr, from about 5min to about 3hr, from about 5min to about 2hr, from about 5min to about 1hr, from about 5min to about 45min, from about 5min to about 30min, orAbout 5min to about 20 min. In one or more examples, t is during or as a result of the second heat treatment_HS2Is in a range of about 2min, about 5min, about 10min, about 15min, or about 20min to about 30min, about 45min, about 60min, about 90min, about 2hr, about 3hr, or about 5hr to convert (e.g., dissolve or decompose) solids (e.g., polymer solids) within the first higher density portion or diluted first higher density portion (as the case may be) into a less dense substance.

It was observed that the second heat soak produced a heat treated first higher density portion having less solids than the first higher density portion prior to the second heat treatment. In aspects in which a diluent is used, the second heat soak produces a heat treated diluted first higher density portion having less solids than the diluted first higher density portion. In one or more embodiments, during or as a result of the second heat treatment, about 25 wt%, about 30 wt%, about 35 wt%, or about 40 wt% to about 45 wt%, about 50 wt%, about 60 wt%, about 70 wt%, about 75 wt%, about 80 wt%, about 85 wt%, about 90 wt%, about 92 wt%, about 95 wt%, about 97 wt%, about 98 wt%, about 99 wt%, or more solids (e.g., polymer solids formed by the first heat treatment) are converted (e.g., dissolved or broken down) into (typically less dense) liquid species within the first higher-density portion or diluted first higher-density portion (as the case may be). In some examples, at least 25 wt%, at least 30 wt%, at least 35 wt%, at least 40 wt%, at least 45 wt%, at least 50 wt%, at least 60 wt%, at least 70 wt%, at least 75 wt%, at least 80 wt% to about 85 wt%, about 90 wt%, about 92 wt%, about 95 wt%, about 97 wt%, about 98 wt%, about 99 wt%, or more solids (e.g., particles) are converted during or as a result of the second heat treatment within the first higher density portion or the diluted first higher density portion (as the case may be). For example, about 25 wt% to about 99 wt%, about 30 wt% to about 99 wt%, about 35 wt% to about 99 wt%, about 40 wt% to about 99 wt%, about 45 wt% to about 99 wt%, about 50 wt% to about 99 wt%, about 60 wt% to about 99 wt%, about 70 wt% to about 99 wt%, about 75 wt% to about 99 wt%, about 25 wt% to about 95 wt%, about 30 wt% to about 95 wt%, about 35 wt% to about 95 wt%, about 40 wt% to about 95 wt%, about 45 wt% to about 95 wt%, about 50 wt% to about 95 wt%, about 60 wt% to about 95 wt%, about 70 wt% to about 95 wt%, about 75 wt% to about 95 wt%, about 25 wt% to about 90 wt%, about 30 wt% to about 90 wt%, about 35 wt% to about 90 wt%, about 40 wt% to about 90 wt%, about 45 wt% to about 90 wt%, about 50 wt% to about 90 wt%, about 60 wt% to about 90 wt%, about 70 wt% to about 90 wt%, about 75 wt% to about 90 wt%, about 25 wt% to about 80 wt%, about 30 wt% to about 80 wt%, about 35 wt% to about 80 wt%, about 40 wt% to about 80 wt%, about 45 wt% to about 80 wt%, about 50 wt% to about 80 wt%, about 60 wt% to about 80 wt%, about 70 wt% to about 80 wt%, or about 75 wt% to about 80 wt% of solids (e.g., polymer solids, such as polymer particulates, formed by the first heat treatment) are converted (e.g., dissolved or decomposed).

In certain aspects, the amount of solids (wt%) in the heat treated first higher density portion ("a")₂", based on the weight of the heat-treated first higher density portion) is less than the amount of solids (wt%) in the first higher density portion (" A ")₁", based on the weight of the first higher density portion), e.g., A₂≤R*A₁Wherein R is<A real number of 1, for example, one of 0.9, 0.8, 0.7, 0.6, 0.5, 0.4, 0.3, 0.2, and 0.1. In other aspects, the amount of solids (wt%) in the heat treated first higher density portion ("a")₂", based on the weight of the heat treated first higher density fraction) is less than the amount of solids (wt%) in the diluted first higher density fraction (" A ")_1d", based on the weight of the diluted first higher density portion), e.g., A₂≤R*A_1d. It has been found that relation a is achieved before the second heat treatment₂≤R*A₁And A₂≤R*A_1dRegardless of whether comminution is performed on the first, higher density portion, although smaller R values ("R") may be achieved when comminution is performed_c")。R_cCan be used forIs for example R0.9, such as R0.8, or R0.7. With or without comminution, e.g. A₂In the range of 10% of A₁To 40% of A₁E.g. 15% of A₁To 30% of A₁Or 20% of A₁To 25% of A₁。

The solids converted in the second heat treatment are typically converted to a composition that is predominantly in the liquid phase, e.g., > 75 wt% solids converted product in the liquid phase, e.g., > 90 wt%, or > 95 wt%, or > 99 wt%.

It was observed that the second heat treatment, e.g. the second heat soaking, improved the performance of the first higher density part contained within the diluted first higher density part. While at least a portion of the heat treated first higher density fraction is typically further processed (e.g., separation and recycle of the second lower density fraction), the heat treated first higher density fraction is itself a useful product, for example, for use as a fuel oil. This is because the heat treated first higher density portion has a lower reactivity and a lower solids content than the first higher density portion.

Representative heat treated first higher density portions will now be described in more detail. The present disclosure is not limited to these and the present description is not meant to exclude other heat treated first higher density portions within the broader scope of the present disclosure, such as those produced by the second heat treatment form without the second heat soak.

Heat treated first higher density portion

The final boiling point of the heat treated first higher density portion is typically at least about 550F + (-288 c +). Boiling point and/or fractional weight distillation point can be determined, for example, by ASTM D2892. The final boiling point of the heat treated first higher density fraction may depend on the nature of the higher density fraction, which in turn may depend on the composition of the steam cracking feed and the steam cracking conditions.

The portion of the thermally treated first higher density fraction having a boiling point of 550 ° F (≧ 288 ℃ +) at atmospheric pressure typically has a relatively low hydrogen content compared to other heavy oil fractions, such as those typically processed in refineries or petrochemical facilities. For example, the portion of the heat-treated first higher density portion can have a hydrogen content of less than or equal to about 8.0 wt%, less than or equal to about 7.5 wt%, or less than or equal to about 7.0 wt%, or less than or equal to about 6.5 wt%, such as in a range of about 5.5 wt% to about 8.0 wt%, or about 6.0 wt% to about 7.5 wt%.

The portion of the heat-treated first higher density fraction having a boiling point at or above 550 deg.F (. gtoreq.288 deg.C +) at atmospheric pressure is typically highly aromatic in nature. The paraffin content in the portion of the heat treated first higher density portion can be less than or equal to about 2.0 wt%, or less than or equal to about 1.0 wt%, e.g., substantially free of paraffin content. The naphthenes content of this heat treated first higher density fraction may also be less than or equal to about 2.0 wt%, or less than or equal to about 1.0 wt%, e.g., substantially free of naphthenes content. In some aspects, the combined paraffin and naphthenes content in the portion of the heat treated first higher density portion may be less than or equal to about 1.0 wt%.

The following aspect of the invention, which includes separating the second higher density portion and the second lower density portion from the heat treated first higher density portion, will now be described in more detail. The invention is not limited in these respects and the description should not be construed as excluding other forms of separation within the broader scope of the disclosure. For simplicity, this separation is referred to as the "second SCT separation". Those skilled in the art will appreciate that this identifier is used because the heat treated first higher density portion is derived from SCT. The use of this identifier should not be interpreted as limiting the second separation to streams separated from the SCT itself, e.g. SCT that have not been subjected to the first thermal treatment or the first SCT separation.

Second SCT separation- -separating the second higher density and second lower density fractions from the heat treated first higher density fraction

The second higher density and lower density fractions may be separated from the heat treated first higher density fraction by any means that achieves the specified separation, including one or more of settling, filtration, and extraction. Conventional separation techniques may be utilized, but the embodiments are not limited thereto. For example, the second lower density fraction can be separated from the heat treated first higher density fraction by decantation, filtration, and/or boiling point separation (e.g., one or more distillation columns, splitters, flash drums, or any combination thereof). The second higher density fraction may be separated from the heat treated first higher density fraction in a similar manner, for example by removing the second higher density fraction from the separation section as a bottom product fraction. The second higher density portion and the second lower density portion may be separated from the heat treated first higher density portion in any order, e.g., substantially simultaneously, by first separating the second higher density portion and then separating the second higher density portion from the second lower density portion, or vice versa. In some aspects, the second higher density fraction and the second lower density fraction are separated by exposing the heat treated first higher density fraction to centrifugal force, for example by using one or more centrifuges within a separation section.

The second higher density portion and the second lower density portion can be separated from the heat treated first higher density portion by any means that forms the second higher density and second lower density portions. The aspect of separation in the second SCT separation section using one or more centrifuges is now described in more detail. Embodiments are not limited in these respects, and the description is not to be construed as excluding the use of additional and/or alternative separation techniques, such as those that do not involve exposing the heat-treated first higher density portion to centrifugal forces.

Induced centrifugal force

In some aspects, the heat treated first higher density fraction containing the heat treated SCT, any diluent, and any solids remaining after the second heat treatment is provided to a second centrifuge to expose the heat treated first higher density fraction to centrifugal force sufficient to form at least a second higher density fraction and a second lower density fraction. Typically, the heat treated first higher density fraction exhibits a substantially uniform circular motion within the centrifuge as a result of the applied centrifugal force, which may be referred to as the centrifugal force (within the reference frame of the heat treated first higher density fraction) or the centripetal force (within the reference frame of the centrifuge) depending on the selection of the reference frame. The process may be carried out in a batch, semi-batch or continuous mode.

The centrifuge may be configured to apply heat to the heat treated first higher density portion, for example by heating the heat treated first higher density portion to an elevated temperature. In some aspects, inducing centrifugal force further comprises heating the heat-treated first higher density portion to a temperature of about 20 ℃, about 25 ℃, about 30 ℃, about 40 ℃, about 50 ℃, about 55 ℃, or about 60 ℃ to about 65 ℃, about 70 ℃, about 80 ℃, about 85 ℃, about 90 ℃, about 95 ℃, about 100 ℃, about 110 ℃, about 120 ℃, or more. For example, the heat-treated first higher density portion can be heated to a temperature of about 20 ℃ to about 120 ℃, about 20 ℃ to about 100 ℃, about 30 ℃ to about 100 ℃, about 40 ℃ to about 100 ℃, about 50 ℃ to about 100 ℃, about 60 ℃ to about 100 ℃, about 70 ℃ to about 100 ℃, about 80 ℃ to about 100 ℃, about 90 ℃ to about 100 ℃, about 20 ℃ to about 80 ℃, about 30 ℃ to about 80 ℃, about 40 ℃ to about 80 ℃, about 50 ℃ to about 80 ℃, about 60 ℃ to about 80 ℃, or about 70 ℃ to about 80 ℃ while centrifuging.

Centrifugal force may be applied for any amount of time. Typically, the centrifugal force is applied for more than or equal to 1 minute, e.g., more than or equal to 5 minutes, more than or equal to 10 minutes, more than or equal to 30 minutes, more than or equal to 60 minutes, or more than or equal to 120 minutes. Additionally or alternatively, centrifugal force can be applied for less than or equal to 120 minutes, less than or equal to 60 minutes, less than or equal to 30 minutes, less than or equal to 10 minutes, or less than or equal to 5 minutes. Ranges expressly disclosed include any combination of the above enumerated values, such as, for example, from about 1 minute to about 120 minutes, from about 5 minutes to about 120 minutes, from about 10 minutes to about 120 minutes, from about 30 minutes to about 120 minutes, or from about 60 minutes to about 120 minutes. The centrifugal force may be applied at any force or velocity magnitude. For example, sufficient force is provided by a centrifuge operating at about 1,000rpm to about 10,000rpm, about 2,000rpm to about 7,500rpm, or about 3,000rpm to about 5,000 rpm.

Centrifuging the heat-treated first higher density fraction typically results in separating from the heat-treated first higher density fraction at least (i) an extract containing the second higher density fraction of the heat-treated first higher density fraction and (ii) a second raffinate or second lower density fraction. In other words, exposing the heat treated first higher density fraction to centrifugal force results in removing at least a second higher density fraction (second extract) from the heat treated first higher density fraction. When the process is operated continuously or semi-continuously, at least two streams may be directed away from the centrifuge: one stream containing the second extract and another stream containing the second raffinate. Centrifuges having this capability are commercially available.

Typically, centrifugation is sufficient to separate ≥ 80 wt%,. gtoreq.90 wt%,. gtoreq.95 wt%,. gtoreq.99 wt% solids having a size ≥ 2 μm, e.g. > 10 μm, e.g. > 20 μm, or ≥ 25 μm, wherein wt% is based on the total weight of solids in the second higher density and second lower density fractions. In the case of subsequent hydrotreatment of the second raffinate envisaged, the second, higher-density fraction contains ≥ 95 wt.%, in particular ≥ 99 wt.% solids of a size ≥ 2 μm, for example ≥ 10 μm, for example ≥ 20 μm, or ≥ 25 μm. In other aspects, filtration should be sufficient to separate at least 80 wt% solids into the higher density fraction.

While the description focuses on the second higher density portion and the second lower density portion, other embodiments envision that the components in the heat treated first higher density portion can be separated and extracted more independently, e.g., very light components separated to the top of the mixture, containing primarily diluent, upgraded tar fractions, tar heavies, or a fraction of solids at the bottom of the centrifuge chamber. One or more of these fractions may be selectively removed from the mixture as one or more raffinates. Typically, at least a portion of the second lower density fraction is recycled (directly or indirectly) to the first centrifuge. The second, higher density fraction may be transported away from the process, for example for storage and/or further processing, including additional centrifugation.

The second lower density portion

The second, lower-density fraction is typically removed from the separation section as a second raffinate, a portion of which (e.g.. gtoreq.50 wt%,. gtoreq.75 wt%,. gtoreq.90 wt%) can be directed away for recycle, e.g. as a component of a tar-fluid mixture. In certain aspects, the second lower density fraction is recycled and combined with one or more of the following: (i) steam cracker effluent, (ii) SCT, (iii) an SCT composition, (iv) a tar-fluid mixture prior to and/or during separation of a first higher density portion and a first lower density portion, (v) a first higher density portion, and (vi) a first lower density portion. In certain aspects, the second, lower density portion can be added to the SCT composition in an amount sufficient to form a portion or all of the fluid used to form the tar-fluid mixture. In aspects in which the first lower density portion is hydrotreated (e.g., SATC hydrotreating), recycling at least a portion of the second lower density portion provides greater yield of upgraded (e.g., hydrotreated) tar as compared to conventional tar upgrading processes, provides material and cost savings for the tar upgrading process, and produces less solids that are channeled apart.

The second, lower density portion typically has a desired insolubility value, for example an insolubility value less than one or more of the following: (i) SCT, (ii) SCT composition, (iii) tar-fluid mixture, (iii) first higher density portion, and second higher density portion. Typically, the insolubility value (I) of the second, lower density fraction_LD) Is equal to or greater than 20, for example, equal to or greater than 30, ≧ 40, ≧ 50, ≧ 60, ≧ 70, ≧ 80, ≧ 90, ≧ 100, ≧ 110, ≧ 120, ≧ 130, ≧ 140, or ≧ 150. Additionally or alternatively, I_LDCan be 150 or less, e.g., 140 or less, 130 or less, 120 or less, 110 or less, 100 or less, 90 or less, 80 or less, 70 or less, 60 or less, 50 or less, 40 or less, or 30 or less. Ranges expressly disclosed include any combination of the above enumerated values, such as, for example, from about 20 to about 150, from about 20 to about 140, from about 20 to about 130, from about 20 to about 120, from about 20 to about 110, from about 20 to about 100, from about 20 to about 90, from about 20 to about 80, from about 20 to about 70, from about 20 to about 60, from about 20 to about 50, from about 20 to about 40, or from about 20 to about 30. Those skilled in the art will appreciate that the separation technique of hydrocarbons is not perfect and thus a small amount of solids may be present in the second phaseThe amount of solids in the low density portion, for example, is ≦ 0.1 times the amount of solids in the heat treated first higher density portion, for example ≦ 0.01 times. Insolubility value I of the second, lower density fraction_LDInsolubility value I for tar-fluid mixtures_TFThe ratio of (B) is less than or equal to 0.95, for example less than or equal to 0.90, less than or equal to 0.85, less than or equal to 0.80, less than or equal to 0.75, less than or equal to 0.70, less than or equal to 0.65, less than or equal to 0.60, less than or equal to 0.55, less than or equal to 0.50,

less than or equal to 0.40, less than or equal to 0.30, less than or equal to 0.20, or less than or equal to 0.10. Additionally or alternatively, I_LDTo I_TFThe ratio may be equal to or greater than 0.10, for example, equal to or greater than 0.20, equal to or greater than 0.30, equal to or greater than 0.40, equal to or greater than 0.50, equal to or greater than 0.55, equal to or greater than 0.60, equal to or greater than 0.65, equal to or greater than 0.70, equal to or greater than 0.75, equal to or greater than 0.80, equal to or greater than 0.85, or equal to or greater than 0.90. Ranges expressly disclosed include any combination of the above enumerated values, such as, for example, about 0.10 to 0.95, about 0.20 to 0.95, about 0.30 to 0.95, about 0.40 to 0.95, about 0.50 to 0.95, about 0.55 to 0.95, about 0.60 to 0.95, about 0.65 to 0.95, about 0.70 to 0.95, about 0.75 to 0.95, about 0.80 to 0.95, about 0.85 to 0.95, or about 0.90 to 0.95.

Typically, at least a portion of the second, lower density fraction is within the liquid phase, e.g., > 25 wt%, such as > 50 wt%, or > 75 wt%, or > 90 wt%. Typically, 50 wt% or more of the solids converted (e.g., from the form of particulates) during and/or as a result of the second heat treatment reside in the second lower density portion, e.g., 75 wt% or more, such as 90 wt% or more, or 99 wt% or more. Typically, not less than 50 wt% of the diluent in the diluted first higher density fraction resides in the second lower density fraction, e.g., not less than 50 wt%, such as not less than 75 wt%, or not less than 90 wt%, or not less than 99 wt%.

Constructional example of hot-soaking of cracked tar solids

FIG. 1 is a schematic diagram illustrating an apparatus for practicing certain aspects of the present invention. More generally, a configuration similar to that of FIG. 1 may be used to heat soak the higher density portions of the pyrolysis tar composition.

In fig. 1, the SCT-containing steam cracker effluent 102 is introduced into a first thermal treatment section 124, for example, the bottoms section of a tar knock-out drum. A stream of a predominantly vapor phase is directed via line 128 from section 124 to primary fractionator 126 for separation of at least quench oil stream 160 and process gas 170. The SCT composition comprising heat treated (e.g., heat soaked) SCT is directed from section 124 via line 105.

Recycle stream 104 and optional stream 103, which contains an optional first utility fluid and/or an optional first separation fluid provided by a source (not shown), are added to the SCT composition to produce a tar-fluid mixture. The tar-fluid mixture is introduced into a first SCT separation section 120, which typically comprises at least one centrifuge, such as a decanter centrifuge. The first higher density portion (directed away via line 125) and the first lower density portion (directed away via line 122) are separated from the tar-fluid mixture in section 120. In continuous operation, the first higher density portion conducted via line 125 typically comprises > 50 wt% of the first higher density portion available for further processing in hot dip vessel 116, e.g. > 75 wt%, e.g. > 90 wt%.

In the configuration shown in FIG. 1, at least a portion of the first lower density fraction is directed via line 122 to an optional stage 140 for hydroprocessing, such as SATC hydroprocessing. The first higher density portion can be transferred to one or more optional stages, such as at least one optional size reduction stage 130, to produce a comminuted first higher density portion. The first higher density fraction is combined with a diluent via lines 127 and/or 135, which includes a second utility fluid and/or a second separation fluid provided by one or more sources (not shown), e.g., before and/or after comminution. The diluted first higher density portion is introduced via line 114 to a second thermal treatment stage 116 (e.g., a second thermal soaking vessel). The second heat treatment stage 116 provides a thermally treated first higher density fraction which is introduced via line 118 into a second SCT separation stage 150 typically comprising at least one centrifuge, such as a decanter centrifuge. Section 150 provides a second higher density portion that can be transported away via line 122, for example for storage, additional thermal treatment and/or additional separation. The second, lower density portion is recycled via line 104.

Examples

High temperature dissolution/decomposition of the second heat treatment

0.5g of the solid obtained from a representative tar (representative SCT in this case) was mixed with about 50mL of toluene in a bomb reactor (bomb reactor). Toluene corresponds to the second utility stream in line 127. At a temperature in the range of 250 ℃ to 350 ℃ (sand bath temperature) N at 500psig₂The mixture was heat treated (heat dipped) for 30 min. The reactor was rapidly quenched with cold water and filtered through a 1.5um filter. The reactor was washed with excess toluene to ensure complete solids recovery. The weight of the residual solids was measured after heat treatment and the solids loss wt% was reported.

Figure 2 is a graph illustrating the amount of solids lost (wt%) as a function of temperature employed in the process using toluene as the solvent. The experimental results show that at least 80% or more of the solids (relatively low value materials) can be upgraded to higher value liquid phase materials suitable for use as SATC feed. Thus, key operating parameters include temperature, residence time and appropriate solvent. It was observed that heat soaking at a temperature of 275 ℃ -300 ℃ for 30 minutes to 60 minutes was sufficient.

All documents described herein are incorporated by reference in all jurisdictions in which such practice is permitted, including any priority documents and/or testing procedures to the extent that they do not conflict herewith, provided however that any priority document not recited in the initially filed application or filing document is not incorporated by reference herein. While forms of embodiments have been illustrated and described, various modifications can be made without departing from the spirit and scope of the disclosure. Accordingly, there is no intent to limit the disclosure to the particular forms disclosed. Likewise, the term "comprising" is considered synonymous with the terms "including" and "containing". Likewise, whenever the transitional phrase "comprising" precedes a composition, element, or group of elements, it is understood that we also contemplate the transitional phrase "consisting essentially of", "consisting of", or "being" preceding the composition, one or more elements, and vice versa, for the same composition or group of elements, and vice versa.

Certain embodiments and features are described using a set of numerical upper limits and a set of numerical lower limits. It is to be understood that any combination of any lower limit value with any upper limit value, any combination of two lower limit values, and/or any combination of two upper limit values is contemplated unless otherwise indicated. Certain lower limits, upper limits and ranges appear in one or more of the following claims.

Claims

1. A method of upgrading tar, the method comprising:

heat treating the tar in a first heat treatment to produce a tar composition;

separating a first lower density fraction and a first higher density fraction from at least a portion of the tar composition, wherein the first higher density fraction comprises an amount A₁wt% solids, based on the weight of the first higher density fraction;

directing at least a portion of the upgraded pyrolysis tar composition comprising at least a portion of the first lower density fraction away;

heat treating at least a portion of the first higher density portion in a second heat treatment to form a heat treated first higher density portion, wherein (i) the heat treated first higher density portion comprises an amount A₂wt% solids, based on the weight of the heat treated first higher density fraction, and (ii) A₂<A₁；

Separating a second lower density portion and a second higher density portion from at least a portion of the heat treated first higher density portion; and

adding at least a portion of the second lower density fraction to one or more of: (i) pyrolysis tar prior to and/or during the first heat treatment, (ii) a pyrolysis tar composition, (iii) a first higher density fraction, and (iv) a first lower density fraction.

2. The method of claim 1, further comprising adding a fluid to the tar composition, wherein ≧ 90 wt% of the added fluid is transferred into the first lower-density portion.

3. The process of claim 1 or 2, further comprising adding a diluent to the first higher density portion, and wherein ≧ 90 wt% of the added diluent resides within the second lower density portion.

4. The method of any of claims 1-3, wherein the first heat treatment comprises maintaining the tar at a temperature of 350 ℃ or less for a time in the range of 10 minutes to 60 minutes.

5. The method of any of claims 1-4, wherein the first heat treatment comprises maintaining the tar at a temperature in the range of 150 ℃ to 300 ℃ for a time in the range of 15 minutes to 30 minutes.

6. The method of any of claims 1-5, wherein (i) the second heat treatment comprises maintaining the first higher density portion at a temperature in the range of 220 ℃ to 500 ℃ for a time in the range of 10 minutes to 100 minutes, and (ii) A₂≤0.8*A₁。

7. The method of any of claims 1-6, wherein the second heat treatment comprises maintaining the first higher density portion at a temperature in the range of 250 ℃ to 400 ℃ for a time in the range of 20 minutes to 90 minutes.

8. The process of any one of claims 1 to 7, wherein A is₂Is in the range of 10% of A₁To 40% of A₁。

9. The method of any of claims 1-8, wherein the tar is a pyrolysis tar comprising steam cracker tar.

10. The process according to any of claims 1-9, wherein the tar is a steam cracker tar produced by steam cracking a steam cracker feed comprising ≥ 10 wt% based on the weight of the steam cracker feed, of a substance which is solid or liquid at 25 ℃ and an absolute pressure of 1 bar.

11. The method of any one of claims 1-10, wherein:

(i) the tar is steam cracked tar produced by steam cracking a hydrocarbon feed comprising ≥ 1 wt%, based on the weight of the steam cracker feed, of hydrocarbons having normal boiling points ≥ 566 ℃;

(ii) the steam cracker comprises a convection section and a radiation section;

(iii) preheating a hydrocarbon feed in a convection section and combining with steam to produce a steam cracker feed;

(iv) separating a predominantly vapor phase stream and a predominantly non-vapor phase stream from at least a portion of the steam cracker feed, wherein greater than or equal to 50 wt% of any hydrocarbons having a normal boiling point greater than or equal to 566 ℃ in the hydrocarbonaceous feed are transferred to the non-vapor phase stream;

(v) directing at least a portion of the stream of the predominately gas phase into an inlet of at least one radiant coil located in the radiant section for cracking under steam cracking conditions, wherein the radiant coil comprises the inlet and an outlet, and the steam cracking conditions comprise:

temperatures ranging from about 760 c to about 1200 c at the outlet of the radiant coil,

a steam cracking pressure in the range of about 1 bar (absolute) to about 10 bar (absolute) at the outlet of the radiant coil, and

a steam cracking residence time in the radiant coil in the range of about 0.1 seconds to about 2 seconds;

(vi) directing the steam cracker effluent away from the radiant section; and

(vii) separating at least steam cracker tar from the steam cracker effluent.

12. The process of claim 11, wherein the predominately gas-phase stream and the predominately non-gas-phase stream are separated from the steam cracker feed in a separation section integrated with the convection section, and wherein the separated predominately gas-phase stream is exposed to additional heating within the convection section prior to cracking.

13. The method of claim 11, wherein the temperature at the outlet of the radiant coil ranges from about 880 ℃ to about 1,200 ℃.

14. The process of claim 11, wherein the temperature at the outlet of the radiant coil ranges from about 1,000 ℃ to about 1,200 ℃, and the steam cracking pressure ranges from about 6 bar (absolute) to about 10 bar (absolute).

15. The process of claim 11 wherein the steam cracking temperature ranges from about 760 ℃ to about 880 ℃ and the steam cracking pressure ranges from about 1 bar (abs) to about 5 bar (abs).

16. The method of any of claims 1-11, wherein the tar composition further comprises material resulting from the first heat treatment.

17. The method of claim 3, further comprising milling the first higher density portion before and/or after adding the diluent.

18. A steam cracker tar upgrading process, the process comprising:

steam cracking a hydrocarbon feed comprising heavy oil to form a steam cracker effluent comprising steam cracker tar;

separating at least a portion of the steam cracker tar from the steam cracker effluent;

heat treating at least the separated steam cracker tar in a first heat treatment to produce a steam cracker tar composition;

adding a first utility fluid and/or a first separation fluid to a steam cracker tar composition to produce a tar-fluid mixture;

separating from the tar-fluid mixture (i) a first lower density fraction comprising upgraded steam cracker tar and (ii) a first higher density fraction;

directing at least a portion of the first lower density portion away;

introducing a second utility fluid into the first higher density portion to form a diluted first higher density portion, wherein the diluted first higher density portion comprises an amount A₁wt% solids, based on the weight of the first higher density fraction;

in the second heat treatmentHeat treating the diluted first higher density portion to form a heat treated first higher density portion, wherein (i) the heat treated first higher density portion comprises an amount A₂wt% solids, based on the weight of the heat treated first higher density fraction, and (ii) A₂≤0.8*A₁；

Separating at least a second lower density portion and a second higher density portion from the heat treated first higher density portion in a second separation; and

adding at least a portion of the second lower density fraction to one or more of: (i) steam cracker effluent, (ii) steam cracker tar before and/or during the first thermal treatment, (iii) steam cracker tar composition, (iv) separation of a tar-fluid mixture before and/or during the first higher density fraction and the first lower density fraction, (v) the first higher density fraction and (vi) the first lower density fraction.

19. The method of claim 18, wherein:

(i) steam cracking of heavy oil at a temperature of from about 760 ℃ to about 880 ℃, a pressure of from about 1 bar (absolute) to about 5 bar (absolute) and a residence time of from about 0.1 seconds to about 2 seconds;

(ii) the first heat treatment comprises maintaining the steam cracker tar at a temperature in the range of 150 ℃ to 300 ℃ for a time in the range of 15 minutes to 30 minutes; and

(iii) the second heat treatment comprises maintaining the diluted first higher density portion at a temperature in the range of 300 ℃ to 400 ℃ for a time in the range of 30 minutes to 60 minutes.

20. The method of claim 18 or 19 wherein the tar-fluid mixture includes the steam cracker tar composition in an amount ranging from about 40 wt% to about 80 wt%, based on the weight of the tar-fluid mixture.

21. The method of any of claims 18-20, further comprising milling the first higher density portion before and/or after introducing the second utility fluid.

22. The process of any of claims 18-21, further comprising (i) hydrotreating at least a portion of the first lower density fraction and (ii) directing at least a portion of the second higher density fraction away.

23. The process of any of claims 18-22, wherein (i) the first and/or second heat treatment comprises heat soaking in at least one infuser drum, and/or (ii) the first and/or second separation comprises centrifugation and/or filtration.

24. A steam cracker tar upgrading process, the process comprising:

steam cracking a heavy oil-containing hydrocarbon feed at a temperature of from about 760 ℃ to about 880 ℃, a pressure of from about 1 bar (absolute) to about 5 bar (absolute) and a residence time of from about 0.1 seconds to about 2 seconds to form a steam cracker effluent comprising steam cracker tar;

heat treating at least the separated steam cracker tar in a first heat treatment by maintaining the steam cracker tar at a temperature of 150 ℃ to 300 ℃ for a time of 15 minutes to 30 minutes to produce a steam cracker tar composition comprising polymer particulates formed during or as a result of the first heat treatment;

separating from the tar-fluid mixture (i) a first lower density fraction comprising upgraded steam cracker tar and (ii) a first higher density fraction comprising polymer particulates, wherein the first higher density fraction comprises a content A₁wt% polymer particulates, based on the weight of the first higher density fraction;

directing at least a portion of the first lower density portion away;

introducing a second utility fluid into the first higher density portion to form a diluted first higher density portion;

heat treating the diluted first higher density fraction in a second heat treatment by maintaining the diluted first higher density fraction at a temperature in the range of 300 ℃ to 400 ℃ for a time in the range of 30 minutes to 60 minutes to form a heat treated first higher density fraction, wherein (i) the heat treated first higher density fraction comprises a lower density conversion product than the polymer particulates, (ii) the heat treated first higher density fraction comprises an amount A₂(ii) wt% of polymer particulates, based on the weight of the heat-treated first higher density fraction, and (iii) A₂≤0.8*A₁；

Separating in a second separation at least a second lower density fraction and a second higher density fraction from the heat treated first higher density fraction, the second lower density fraction comprising a lower density of conversion products; and

25. An apparatus for upgrading steam cracker tar, the apparatus comprising:

a heat treatment section connected at a first end to the first end of the primary fractionator and at a second end to the first end of the first separation section via an SCT composition line;

a hydrotreating section connected at a first end to a second end of the first separation section;

a particle size reduction section connected at a first end via a second line to a third end of the separation section and at a second end via a third line to a first end of the second heat treatment section; and

a second separation section connected at a first end to a second end of the second thermal treatment section and at a second end to a SCT composition line.

26. The apparatus of claim 25, further comprising:

a source of utility fluid connected to the SCT composition line; and

a diluent source connected to the second line or the third line.

27. An apparatus for upgrading steam cracker tar, the apparatus comprising:

a hydrotreating section connected at a first end to a second end of the first separation section; and

a second heat treatment section connected at a first end to the third end of the first separation section via a second line and at a second end to the second separation section,

wherein the second separation section is connected to the SCT composition pipeline at the second end.

28. The apparatus of claim 27, further comprising:

a source of utility fluid connected to the SCT composition line; and

a diluent source connected to the second line.

29. A steam cracker tar upgrading process, the process comprising:

separating solids from the steam cracker tar;

converting at least a portion of the solids to a liquid;

directing an effluent comprising the liquid away from the conversion;

separating at least a portion of the liquid from the effluent; and

hydrotreating at least a portion of the separated liquid.

30. The method of claim 29 wherein the steam cracker tar comprises heat treated steam cracker tar, the converting comprises heat soaking, and the at least one separating comprises centrifuging.