Classifications

• • C—CHEMISTRY; METALLURGY
  • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
  • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
  • C10G47/00—Cracking of hydrocarbon oils, in the presence of hydrogen or hydrogen- generating compounds, to obtain lower boiling fractions
  • C10G47/24—Cracking of hydrocarbon oils, in the presence of hydrogen or hydrogen- generating compounds, to obtain lower boiling fractions with moving solid particles
  • C10G47/26—Cracking of hydrocarbon oils, in the presence of hydrogen or hydrogen- generating compounds, to obtain lower boiling fractions with moving solid particles suspended in the oil, e.g. slurries
• • B—PERFORMING OPERATIONS; TRANSPORTING
  • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
  • B01J—CHEMICAL OR PHYSICAL PROCESSES, e.g. CATALYSIS OR COLLOID CHEMISTRY; THEIR RELEVANT APPARATUS
  • B01J27/00—Catalysts comprising the elements or compounds of halogens, sulfur, selenium, tellurium, phosphorus or nitrogen; Catalysts comprising carbon compounds
  • B01J27/02—Sulfur, selenium or tellurium; Compounds thereof
  • B01J27/04—Sulfides
• • B—PERFORMING OPERATIONS; TRANSPORTING
  • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
  • B01J—CHEMICAL OR PHYSICAL PROCESSES, e.g. CATALYSIS OR COLLOID CHEMISTRY; THEIR RELEVANT APPARATUS
  • B01J27/00—Catalysts comprising the elements or compounds of halogens, sulfur, selenium, tellurium, phosphorus or nitrogen; Catalysts comprising carbon compounds
  • B01J27/02—Sulfur, selenium or tellurium; Compounds thereof
  • B01J27/04—Sulfides
  • B01J27/047—Sulfides with chromium, molybdenum, tungsten or polonium
• • B—PERFORMING OPERATIONS; TRANSPORTING
  • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
  • B01J—CHEMICAL OR PHYSICAL PROCESSES, e.g. CATALYSIS OR COLLOID CHEMISTRY; THEIR RELEVANT APPARATUS
  • B01J27/00—Catalysts comprising the elements or compounds of halogens, sulfur, selenium, tellurium, phosphorus or nitrogen; Catalysts comprising carbon compounds
  • B01J27/02—Sulfur, selenium or tellurium; Compounds thereof
  • B01J27/04—Sulfides
  • B01J27/047—Sulfides with chromium, molybdenum, tungsten or polonium
  • B01J27/051—Molybdenum
• • B—PERFORMING OPERATIONS; TRANSPORTING
  • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
  • B01J—CHEMICAL OR PHYSICAL PROCESSES, e.g. CATALYSIS OR COLLOID CHEMISTRY; THEIR RELEVANT APPARATUS
  • B01J27/00—Catalysts comprising the elements or compounds of halogens, sulfur, selenium, tellurium, phosphorus or nitrogen; Catalysts comprising carbon compounds
  • B01J27/02—Sulfur, selenium or tellurium; Compounds thereof
  • B01J27/04—Sulfides
  • B01J27/047—Sulfides with chromium, molybdenum, tungsten or polonium
  • B01J27/051—Molybdenum
  • B01J27/0515—Molybdenum with iron group metals or platinum group metals
• • B—PERFORMING OPERATIONS; TRANSPORTING
  • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
  • B01J—CHEMICAL OR PHYSICAL PROCESSES, e.g. CATALYSIS OR COLLOID CHEMISTRY; THEIR RELEVANT APPARATUS
  • B01J35/00—Catalysts, in general, characterised by their form or physical properties
  • B01J35/40—Catalysts, in general, characterised by their form or physical properties characterised by dimensions, e.g. grain size
• • B—PERFORMING OPERATIONS; TRANSPORTING
  • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
  • B01J—CHEMICAL OR PHYSICAL PROCESSES, e.g. CATALYSIS OR COLLOID CHEMISTRY; THEIR RELEVANT APPARATUS
  • B01J35/00—Catalysts, in general, characterised by their form or physical properties
  • B01J35/60—Catalysts, in general, characterised by their form or physical properties characterised by their surface properties or porosity
  • B01J35/61—Surface area
  • B01J35/613—10-100 m2/g
• • B—PERFORMING OPERATIONS; TRANSPORTING
  • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
  • B01J—CHEMICAL OR PHYSICAL PROCESSES, e.g. CATALYSIS OR COLLOID CHEMISTRY; THEIR RELEVANT APPARATUS
  • B01J35/00—Catalysts, in general, characterised by their form or physical properties
  • B01J35/60—Catalysts, in general, characterised by their form or physical properties characterised by their surface properties or porosity
  • B01J35/61—Surface area
  • B01J35/615—100-500 m2/g
• • B—PERFORMING OPERATIONS; TRANSPORTING
  • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
  • B01J—CHEMICAL OR PHYSICAL PROCESSES, e.g. CATALYSIS OR COLLOID CHEMISTRY; THEIR RELEVANT APPARATUS
  • B01J35/00—Catalysts, in general, characterised by their form or physical properties
  • B01J35/60—Catalysts, in general, characterised by their form or physical properties characterised by their surface properties or porosity
  • B01J35/63—Pore volume
  • B01J35/633—Pore volume less than 0.5 ml/g
• • B—PERFORMING OPERATIONS; TRANSPORTING
  • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
  • B01J—CHEMICAL OR PHYSICAL PROCESSES, e.g. CATALYSIS OR COLLOID CHEMISTRY; THEIR RELEVANT APPARATUS
  • B01J35/00—Catalysts, in general, characterised by their form or physical properties
  • B01J35/60—Catalysts, in general, characterised by their form or physical properties characterised by their surface properties or porosity
  • B01J35/64—Pore diameter
  • B01J35/647—2-50 nm
• • B—PERFORMING OPERATIONS; TRANSPORTING
  • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
  • B01J—CHEMICAL OR PHYSICAL PROCESSES, e.g. CATALYSIS OR COLLOID CHEMISTRY; THEIR RELEVANT APPARATUS
  • B01J37/00—Processes, in general, for preparing catalysts; Processes, in general, for activation of catalysts
  • B01J37/02—Impregnation, coating or precipitation
  • B01J37/03—Precipitation; Co-precipitation
  • B01J37/031—Precipitation
• • C—CHEMISTRY; METALLURGY
  • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
  • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
  • C10G47/00—Cracking of hydrocarbon oils, in the presence of hydrogen or hydrogen- generating compounds, to obtain lower boiling fractions
  • C10G47/02—Cracking of hydrocarbon oils, in the presence of hydrogen or hydrogen- generating compounds, to obtain lower boiling fractions characterised by the catalyst used
  • C10G47/06—Sulfides
• • C—CHEMISTRY; METALLURGY
  • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
  • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
  • C10G2300/00—Aspects relating to hydrocarbon processing covered by groups C10G1/00 - C10G99/00
  • C10G2300/20—Characteristics of the feedstock or the products
  • C10G2300/201—Impurities
  • C10G2300/207—Acid gases, e.g. H2S, COS, SO2, HCN
• • C—CHEMISTRY; METALLURGY
  • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
  • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
  • C10G2300/00—Aspects relating to hydrocarbon processing covered by groups C10G1/00 - C10G99/00
  • C10G2300/20—Characteristics of the feedstock or the products
  • C10G2300/30—Physical properties of feedstocks or products
  • C10G2300/301—Boiling range
• • C—CHEMISTRY; METALLURGY
  • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
  • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
  • C10G2300/00—Aspects relating to hydrocarbon processing covered by groups C10G1/00 - C10G99/00
  • C10G2300/40—Characteristics of the process deviating from typical ways of processing
  • C10G2300/4006—Temperature
• • C—CHEMISTRY; METALLURGY
  • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
  • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
  • C10G2300/00—Aspects relating to hydrocarbon processing covered by groups C10G1/00 - C10G99/00
  • C10G2300/40—Characteristics of the process deviating from typical ways of processing
  • C10G2300/4012—Pressure

Definitions

• the present invention is directed to a process for treating a hydrocarbon- containing feedstock.
• Upgrading by cracking is also effective to partially convert heavy hydrocarbon fractions such as atmospheric or vacuum residues derived from refining a crude oil or hydrocarbons derived from liquefying coal into lighter, more valuable hydrocarbons.
• Cracking heavy hydrocarbons involves breaking bonds of the hydrocarbons, particularly carbon-carbon bonds, thereby forming two hydrocarbon radicals for each carbon-carbon bond that is cracked in a hydrocarbon molecule.
• Numerous reaction paths are available to the cracked hydrocarbon radicals, the most important being: 1) reaction with a hydrogen donor to form a stable hydrocarbon molecule that is smaller in terms of molecular weight than the original hydrocarbon from which it was derived; and 2) reaction with another hydrocarbon or another hydrocarbon radical to form a hydrocarbon molecule larger in terms of molecular weight than the cracked hydrocarbon radical— a process called annealation.
• Slurry catalyst processes have been utilized to address the problem of catalyst aging by coke deposition in the course of cracking a hydrocarbon-containing feedstock.
• Slurry catalyst particles are selected to be dispersible in the hydrocarbon- containing feedstock or in vaporized hydrocarbon-containing feedstock so the slurry catalysts circulate with the hydrocarbon-containing feedstock in the course of cracking the feedstock.
• the feedstock and the catalyst move together through the cracking reactor and are separated upon exiting the cracking reactor.
• Coke formed during the cracking reaction is separated from the feedstock, and any coke deposited on the catalyst may be removed from the catalyst by regenerating the catalyst.
• the regenerated catalyst may then be recirculated with fresh hydrocarbon-containing feedstock through the cracking reactor. The process, therefore, is not affected by catalyst aging since fresh catalyst may be continually added into the cracking reactor, and catalyst upon which coke has been deposited may be continually regenerated.
• the catalyst is a highly effective catalyst for use in cracking a heavy hydrocarbon-containing material due, at least in part, to: 1) the ability of the catalyst to donate or share electrons with hydrocarbons based on the molecular structure of the catalyst (i.e. to reduce the hydrocarbon so the hydrocarbon forms a radical anion); and 2) the surface area of the catalyst available to interact with hydrocarbons and/or hydrocarbon radicals in the absence of any porous alumina, alumina- silica, or silica based carrier or support.
• Conventional hydrocracking catalysts utilize an active hydrogenation metal, for example a Group VIII metal such as nickel, on a support having Lewis acid properties, for example, silica, alumina- silica, or alumina supports. It is believed that cracking heavy hydrocarbons in the presence of a Lewis acid catalyst results in the formation of cracked hydrocarbon radical cations rather than hydrocarbon radical anions. Radical cations are most stable when present on a tertiary carbon atom, therefore, cracking may be energetically directed to the formation of tertiary hydrocarbon radical cations, or, most likely, the cracked hydrocarbon may rearrange to form the more energetically favored tertiary radical cation.
• an active hydrogenation metal for example a Group VIII metal such as nickel
• the catalyst utilized in the process of the present invention is particularly effective for use in cracking a heavy hydrocarbon-containing material due, in part, to the molecular structure of the catalyst, which facilitates donation or sharing of electrons from the catalyst to a hydrocarbon or a hydrocarbon anion radical.
• the sulfur atoms linking the first and second metals in the catalyst may facilitate the electron donating/sharing activity of the catalyst, acting to enable charge transfer from the first metal to the second metal or from the second metal to the first metal across the molecular orbitals of the sulfur atoms, as well as potentially acting to directly share electrons from the sulfur atoms in the catalyst with the hydrocarbon or hydrocarbon anion radical.
• the sulfur atoms may further facilitate donation/sharing of electrons from the catalyst to a hydrocarbon or hydrocarbon radical by charge stabilization of the catalyst as the catalyst donates/shares electrons with a hydrocarbon or
• the catalyst utilized in the process of the present invention may be particularly effective for use in cracking a heavy hydrocarbon-containing material since the molecular structure of the catalyst may have sulfided electron-rich metals incorporated therein while inhibiting reduction of such electron-rich metals to a zero- oxidation state.
• use of a catalyst having the ability to donate or share electrons with hydrocarbons and/or hydrocarbon anion radicals may facilitate cracking the hydrocarbons without attendant production of coke or proto-coke.
• the catalytic material containing sulfided electron-rich metals utilized in the process of the present invention therefore, facilitates hydrocarbon cracking without formation of coke or proto-coke.
• use of sulfided electron- rich metals is typically avoided in hydrocarbon cracking processes since the metal of typical electron-rich metal compounds may be easily desulfided and reduced to its zero-oxidation state in the presence of hydrogen, and zero-oxidation state electron- rich metals catalyze the production of coke in a cracking process.
• copper sulfide is an electron-rich metal that is not typically utilized in cracking processes due to its propensity to catalyze coke formation.
• the molecular structure of the catalyst utilized in the process of the present invention enables the use of an electron-rich metal such as copper or bismuth in a process for cracking a heavy hydrocarbon-containing material, where electron-rich metals such as copper or bismuth are preferred for use as the first metal in the catalyst.
• the electron-rich metal may be bound in the catalyst by two sulfur atoms, inhibiting or preventing the reduction of the electron-rich metal to its zero- oxidation state, and thereby inhibiting or preventing the formation of coke by the zero-oxidation state electron-rich metal.
• Inclusion of an electron-rich metal, particularly copper, in the catalyst utilized in the process of the present invention promotes the electron donation/sharing characteristics of the catalyst by increasing the electron density of the catalyst available to be donated or shared with a hydrocarbon or hydrocarbon anion radical.
• the catalyst may have a tetrahedral molecular structure and that the tetrahedral molecular structure causes the physical structure of the catalyst to have significant porosity and pore volume relative to typical non-supported catalysts (which may have an octahedral molecular structure with a plate-like physical structure).
• the surface area of the present catalyst that is available for contact with a hydrocarbon-containing feedstock may be relatively large due to the porosity of the catalyst.
• the catalyst may have a surface area, a pore size distribution, a pore volume, and porosity comparable to a catalyst having active metals deposited on an alumina, alumina- silica, or silica based carrier.
• the hydrogen sulfide acts as a further catalyst in the cracking of hydrocarbons in the hydrocarbon-containing feedstock in the presence of hydrogen and the catalyst comprised of the first metal, second metal, and sulfur, and inhibits coke formation under cracking conditions.
• Use of sufficient hydrogen sulfide in the process permits the process to be effected at a mixing zone temperature of at least at least 430°C or at least 450°C with little or no increase in coke formation relative to cracking conducted at lower temperatures since hydrogen sulfide, in sufficient quantity, inhibits coke formation.
• the rate of the process therefore, may be greatly increased with the use of significant quantities of hydrogen sulfide in the
• hydrocracking step of the process since the rate of reaction in the hydrocracking step of the process increases significantly relative to temperature.
• an acridinic compound includes any hydrocarbon compound containing the above structure, including, naphthenic acridines, napththenic benzoacridines, and benzoacridines, in addition to acridine.
• Anaerobic conditions means “conditions in which less than 0.5 vol.% oxygen as a gas is present".
• a process that occurs under anaerobic conditions is a process that occurs in the presence of less than 0.5 vol.% oxygen in a gaseous form. Anaerobic conditions may be such that no detectable oxygen gas is present.
• BET surface area refers to a surface area of a material as determined by ASTM Method D3663. "Blending” as used herein is defined to mean contact of two or more substances by intimately admixing the two or more substances.
• Boiling range distributions for a hydrocarbon-containing material are as determined by ASTM Method D5307.
• Bind as used herein with reference to atoms in a molecule may refer to a covalent bond, a dative bond, or an ionic bond, dependent on the context.
• Diesel content may be determined by the quantity of hydrocarbons having a boiling range of from 260°C to 343°C at a pressure of 0.101 MPa relative to a total quantity of hydrocarbons as measured by boiling range distribution in accordance with ASTM Method D5307.
• "Dispersible" as used herein with respect to mixing a solid, such as a salt, in a liquid is defined to mean that the components that form the solid, upon being mixed with the liquid, are retained in the liquid at STP for a period of at least 24 hours upon cessation of mixing the solid with the liquid.
• a solid material is dispersible in a liquid if the solid or its components are soluble in the liquid.
• a solid material is also dispersible in a liquid if the solid or its components form a colloidal dispersion or a suspension in the liquid.
• distillate or “middle distillate” refers to hydrocarbons with a boiling range distribution from 204°C up to 343°C (400°F up to 650°F) at a pressure of 0.101 MPa. Distillate content is as determined by ASTM Method D5307. Distillate may include diesel and kerosene.
• IP refers to the Institute of Petroleum, now the Energy Institute of London, United Kingdom.
• Iso-paraffins refer to branched chain saturated hydrocarbons.
• Naphtha refers to hydrocarbon components with a boiling range distribution from 38°C up to 204°C (100°F up to 400°F) at a pressure of 0.101 MPa. Naphtha content may be determined by the quantity of hydrocarbons having a boiling range of from 38°C to 204°C at a pressure of 0.101 MPa relative to a total quantity of hydrocarbons as measured by boiling range distribution in accordance with ASTM Method D5307. Content of hydrocarbon components, for example, paraffins, iso-paraffins, olefins, naphthenes and aromatics in naphtha are as determined by ASTM Method D6730. "n-Paraffins" refer to normal (straight chain) saturated hydrocarbons.
• Polyaromatic compounds refer to compounds that include three or more aromatic rings. Examples of polyaromatic compounds include, but are not limited to anthracene and phenanthrene.
• TAN refers to a total acid number expressed as millgrams ("mg") of KOH per gram ("g") of sample. TAN is as determined by ASTM Method D664.
• the amount of hydrocarbons having a boiling point of 538°C or less in a hydrocarbon-containing material may be determined in accordance with ASTM Method D5307.
• the hydrocarbon-containing feedstock may contain at least 20 wt.%, or at least 25 wt.%, or at least 30 wt.%, or at least 35 wt.%, or at least 40 wt.%, or at least 45 wt.% of naphtha and distillate.
• the hydrocarbon-containing feedstock may be a crude oil, or may be a topped crude oil.
• the hydrocarbon-containing feedstock may also contain appreciable quantities of naphthenic acids.
• the hydrocarbon-containing feedstock may have a TAN of at least 0.5, or at least 1.0, or at least 2.0.
• the catalyst may have a pore size distribution, where the pore size distribution has a mean and/or median pore diameter of from 50 angstroms to 1000 angstroms, or from 60 angstroms to 350 angstroms.
• the catalyst may have a pore volume of at least 0.2 cmVg, or at least 0.25 cmVg, or at least 0.3 cm 3 /g, or at least 0.35 cmVg, or at least 0.4 cmVg.
• the catalyst may have a BET surface area of at least 50 m 2 /g, or at least 100 m 2 , and up to 400 m 2 /g or up to 500 m 2 /g.
• the catalyst may be a solid particulate substance having a particle size distribution with a relatively small mean particle size and/or median particle size, where the solid catalyst particles preferably are nanometer size particles.
• the catalyst may have a particle size distribution with a median particle size and/or mean particle size of at least 50 nm, or at least 75 nm, or up to 5 ⁇ , or up to 1 ⁇ ; or up to 750 nm, or from 50 nm up to 5 ⁇ .
• the solid particulate catalyst having a particle size distribution with a large quantity of small particles, for example having a mean or median particle size of up to 1 ⁇ has a large aggregate surface area since little of the catalyst material is located within the interior of a particle.
• the solid particulate catalyst may be insoluble in the hydrocarbon-containing feed and in a hydrocarbon-depleted feed residuum formed by the process of the present invention.
• the solid particulate catalyst having a particle size distribution of at least 50 nm may be insoluble in the hydrocarbon-containing feed and the hydrocarbon-depleted residuum due, in part, to the size of the particles, which may be too large to be solvated by the hydrocarbon-containing feed or the residuum.
• the first salt utilized to form the material of the catalyst, and/or the catalyst includes a cationic component comprising a metal in any non-zero oxidation state selected from the group consisting of Cu, Fe, Ni, Co, Bi, Ag, Mn, Zn, Sn, Ru, La, Ce, Pr, Sm, Eu, Yb, Lu, Dy, Pb, and Sb, where the metal of the cationic component is the first metal of the material of the catalyst.
• the cationic component of the first salt may consist essentially of a metal selected from the group consisting of Cu, Fe, Ni, Co, Bi, Ag, Mn, Zn, Sn, Ru, La, Ce, Pr, Sm, Eu, Yb, Lu, Dy, Pb, and Sb.
• the cationic component of the first salt must be capable of bonding with the anionic component of the second salt to form the material of the catalyst in the aqueous mixture at a temperature of from 15°C to 150°C and under anaerobic conditions.
• the anionic component of the first salt may be selected from the group consisting of sulfate, chloride, bromide, iodide, acetate, acetylacetonate, phosphate, nitrate, perchlorate, oxalate, citrate, and tartrate.
• the first salt is preferably selected from the group consisting of Q1SO 4 , copper acetate, copper acetylacetonate, Ni FeS0 4 , Fe 2 (S0 4 )3, iron acetate, iron acetylacetonate, NiS0 4 , nickel acetate, nickel acetylacetonate, CoS0 4 , cobalt acetate, cobalt acetylacetonate, ZnCl 2 , ZnS0 4 , zinc acetate, zinc acetylacetonate, silver acetate, silver acetylacetonate, SnS0 4 , SnC , tin acetate, tin acetylacetonate, MnS0 4 , manganese acetate, manganese acetylacetonate, bismuth acetate, bismuth acetylacetonate, and hydrates thereof
• the organic solvent present in the first aqueous solution should be selected so that the organic compounds in the organic solvent do not inhibit reaction of the cationic component of the first salt with the anionic component of the second salt upon forming an aqueous mixture containing the first and second salts, e.g., by forming ligands or by reacting with the first or second salts or their respective cationic or anionic components.
• the first aqueous solution may contain no organic solvent, and may consist essentially of water, preferably deionized water, and the first salt.
• the concentration of the first salt in the first aqueous solution may be selected to promote formation of the material of the catalyst, and/or the catalyst, having a particle size distribution with a small mean and/or median particle size, where the particles have a relatively large surface area, upon mixing the first salt and the second salt in the aqueous mixture.
• the first aqueous solution may contain at most 3 moles per liter, or at most 2 moles per liter, or at most 1 mole per liter, or at most 0.6 moles per liter, or at most 0.2 moles per liter of the first salt.
• the second salt also contains a cationic component associated with the anionic component of the second salt to form the second salt.
• the cationic component of the second salt may be selected from an ammonium counterion, and alkali metal and alkaline earth metal counterions to the tetrathiometallate anionic component of the second salt so long as the combined cationic component and the anionic component of the second salt form a salt that is dispersable, and preferably soluble, in the aqueous mixture in which the first salt and the second salt are mixed, and so long as the cationic component of the second salt does not prevent the combination of the cationic component of the first salt with the anionic component of the second salt in the aqueous mixture to form the catalyst material.
• the cationic component of the second salt may comprise one or more sodium ions, or one or more potassium ions, or one or more ammonium ions.
• the second salt is preferably selected from the group consisting of Na 2 MoS 4 , Na 2 WS 4 , Na 3 VS 4> K 2 MoS 4 , K 2 WS 4> K 3 VS 4 , (NH 4 ) 2 MoS 4 , (NH 4 ) 2 WS 4 , (NH 4 ) 3 VS 4 , Na ⁇ nS ⁇ (NH 4 ) 4 SnS 4 , (NH 4 ) 3 SbS 4 , Na SbS 4> and hydrates thereof.
• the second salt may be a commercially available tetrathiomolybdate or tetrathiotungstate salt.
• the second salt may be ammonium
• the second salt may be produced from a commercially available tetrathiomolybdate or tetrathiotungstate salt.
• the second salt may be produced from ammonium tetrathiomolybdate, ammonium tetrathiotungstate, or from ammonium tetrathiovanadate.
• the second salt may be formed from the commercially available ammonium tetrathiometallate salts by exchanging the cationic ammonium component of the commercially available salt with a desired alkali or alkaline earth cationic component from a separate salt.
• the exchange of the cationic components to form the desired second salt may be effected by mixing the commercially available salt and the salt containing the desired cationic component in an aqueous solution to form the desired second salt.
• a method of forming the second salt is to disperse an ammonium
• tetrathiomolybdate, ammonium tetrathiotungstate, or ammonium tetrathiovanadate salt in an aqueous solution, preferably water, and to disperse an alkali metal or alkaline earth metal cationic component donor salt, preferably a carbonate, in the aqueous solution, where the cationic component donor salt is provided in an amount relative to the ammonium tetrathiomolybdate, ammonium tetrathiotungstate, or ammonium tetrathiovanadate salt to provide a stoichiometrially equivalent or greater amount of its cation to ammonium of the ammonium tetrathiomolybdate, ammonium tetrathiotungstate, or ammonium tetrathiovanadate salt.
• the aqueous solution may be heated to a temperature of at least 50°C, or at least 65°C up to 100°C to evolve ammonia from the ammonium containing salt and carbon dioxide from the carbonate containing salt as gases, and to form the second salt.
• a Na 2 MoS 4 salt may be prepared for use as the second salt by mixing commercially available (NH 4 ) 2 MoS 4 and Na 2 C0 3 in water at a temperature of 70°C-80°C for a time period sufficient to permit evolution of a significant amount, preferably substantially all, of ammonia and carbon dioxide gases from the solution, typically from 30 minutes to 4 hours, and usually about 2 hours.
• the second salt is a sodium tetrathiostannate salt
• it may be produced by dissolving Na 2 Sn(OH)6 and Na 2 S in a 1:4 molar ratio in boiling deionized water (100 g of Na 2 Sn(OH) 6 per 700 ml of water and 250 g of Na 2 S per 700 ml of water), stirring the mixture at 90-100°C for 2-3 hours, adding finely pulverized MgO to the mixture at a 2:5 wt.
• the second salt may be contained in an aqueous solution (the second aqueous solution, as noted above), where the second aqueous solution containing the second salt may be mixed with the first aqueous solution containing the first salt in the aqueous mixture to form the material of the catalyst.
• the second salt is preferably dispersible, and most preferably soluble, in the second aqueous solution and is dispersible, and preferably soluble, in the aqueous mixture containing the first and second salts.
• the concentration of the second salt in the second aqueous solution may be selected to promote formation of the material of the catalyst having a particle size distribution with a small mean and/or median particle size and having a relatively large surface area per particle upon mixing the first salt and the second salt in the aqueous mixture.
• the second aqueous solution may contain at most 0.8 moles per liter, or at most 0.6 moles per liter, or at most 0.4 moles per liter, or at most 0.2 moles per liter, or at most 0.1 moles per liter of the second salt.
• the first and second solutions containing the first and second salts, respectively, may be mixed in an aqueous mixture to form the material of the catalyst and/or the catalyst.
• the amount of the first salt relative to the amount of the second salt provided to the aqueous mixture may be selected so that the atomic ratio of the cationic component metal of the first salt to the metal of the anionic component of the second salt, either molybdenum or tungsten, is at least 1:2, or at least 2:3, or at least 1: 1, and at most 20: 1, or at most 15: 1, or at most 10: 1.
• the third aqueous solution may contain more than 50 vol.% water, or at least 75 vol.% water, or at least 90 vol.% water, or at least 95 vol.% water, and may contain more than 0 vol.% but less than 50 vol.%, or at most 25 vol.%, or at most 10 vol.%, or at most 5 vol.% of an organic solvent containing from 1 to 5 carbons and selected from the group consisting of an alcohol, a diol, an aldehyde, a ketone, an amine, an amide, a furan, an ether, acetonitrile, and mixtures thereof.
• the aqueous mixture of the first and second salts may be formed by combining the first aqueous solution containing the first salt and the second aqueous solution containing the second salt in the third aqueous solution.
• the volume ratio of the third aqueous solution to the first aqueous solution containing the first salt may be from 0.5: 1 to 50: 1 where the first aqueous solution may contain at most 3, or at most 2, or at most 1, or at most 0.8, or at most 0.5, or at most 0.3 moles of the first salt per liter of the first aqueous solution.
• the first aqueous solution containing the first salt and the second aqueous solution containing the second salt may be added to the third aqueous solution, preferably simultaneously, at a controlled rate selected to provide a desired
• the first aqueous solution containing the first salt and the second aqueous solution containing the second salt may be added to the third aqueous solution at a controlled rate by adding the first aqueous solution and the second aqueous solution to the third aqueous solution in a dropwise manner.
• the rate that drops of the first aqueous solution and the second aqueous solution are added to the third aqueous solution may be controlled to limit the instantaneous concentration of the first salt and the second salt in the aqueous mixture as desired.
• the first aqueous solution containing the first salt and the second aqueous solution containing the second salt may be dispersed directly into the third aqueous solution at a flow rate selected to provide a desired instantaneous concentration of the first salt and the second salt.
• the first aqueous solution and the second aqueous solution may be dispersed directly into the third aqueous solution using conventional means for dispersing one solution into another solution at a controlled flow rate.
• the first aqueous solution and the second aqueous solution may be dispersed into the third aqueous solution through separate nozzles located within the third aqueous solution, where the flow of the first and second solutions through the nozzles is metered by separate flow metering devices.
• the first and second salts in the aqueous mixture may be mixed under a pressure of from 0.101 MPa to 10 MPa (1.01 bar to 100 bar).
• the first and second salts in the aqueous mixture are mixed at atmospheric pressure, however, if the mixing is effected at a temperature greater than 100°C the mixing may be conducted under positive pressure to inhibit the formation of steam.
• the aqueous mixture of the first and second salts is maintained under anaerobic conditions. Maintaining the aqueous mixture under anaerobic conditions during mixing inhibits the oxidation of the catalyst material or the anionic component of the second salt so that the catalyst material produced by the process contains little, if any oxygen.
• the aqueous mixture of the first and second salts may be maintained under anaerobic conditions during mixing by conducting the mixing in an atmosphere containing little or no oxygen, preferably an inert atmosphere.
• the mixing of the first and second salts in the aqueous mixture may be conducted under nitrogen gas, argon gas, and/or steam to maintain anaerobic conditions during the mixing.
• Hydrogen may be provided continuously or intermittently to the mixing zone 1 of the reactor 3 through hydrogen inlet line 7, or, alternatively, may be mixed together with the hydrocarbon-containing feedstock, and optionally the catalyst, and provided to the mixing zone 1 through the feed inlet 5.
• Hydrogen sulfide may be provided continuously or intermittently as a liquid or a gas to the mixing zone 1 of the reactor 1 through a hydrogen sulfide inlet line 27, or, alternatively, may be mixed with the hydrocarbon-containing feedstock and provided to the mixing zone 1 with the hydrocarbon-containing feedstock through the feed inlet 5, or, alternatively, may be mixed with the hydrogen and provided to the mixing zone 1 through hydrogen inlet line 7.
• the hydrocarbon-containing feedstock may be provided to the mixing zone 1 of the reactor 3 at a rate of at least 350 kg/hr per m 3 of the mixture volume within mixing zone 1 of the reactor 3.
• the mixture volume is defined herein as the combined volume of the catalyst(s), the hydrocarbon-depleted feed residuum (as defined herein), and the hydrocarbon-containing feedstock in the mixing zone 1, where the hydrocarbon-depleted feed residuum may contribute no volume to the mixture volume (i.e. at the start of the process before a hydrocarbon-depleted feed residuum has been produced in the mixing zone 1), and where the hydrocarbon- containing feedstock may contribute no volume to the mixture volume (i.e. after initiation of the process during a period between intermittent addition of fresh hydrocarbon-containing feedstock into the mixing zone 1).
• the mixture volume within the mixing zone 1 may be affected by 1) the rate of addition of the
• the mixture volume of the hydrocarbon-containing feedstock, the hydrocarbon-depleted feed residuum, and the catalyst(s) is maintained within the mixing zone within a selected range of the reactor volume by selecting 1) the rate at which the hydrocarbon-containing feedstock is provided to the mixing zone 1; and/or 2) the rate at which a bleed stream is removed from and recycled to the mixing zone 1; and/or 3) the temperature and pressure within the mixing zone 1 and the reactor 3 to provide a selected rate of vapor removal from the mixing zone 1 and the reactor 3.
• the rate at which the hydrocarbon-containing feedstock is provided to the mixing zone 1 and/or the rate at which a bleed stream is removed from and recycled to the mixing zone 1 and/or the rate at which vapor is removed from the reactor 3 may be selected to maintain the mixture volume of the hydrocarbon-containing feedstock, the hydrocarbon-depleted feed residuum, and the catalyst(s) at a level of at least 10%, or at least 25%, or within 90%, or within 70%, or within 50% of the initial mixture volume during the process.
• the hydrocarbon-containing feedstock may be provided to the mixing zone 1 at such relatively high rates for reacting a feedstock containing relatively large quantities of heavy, high molecular weight hydrocarbons due to the inhibition of coke formation in the process of the present invention.
• Conventional processes for cracking heavy hydrocarbonaceous feedstocks are typically operated at rates on the order of 10 to 300 kg/hr per m 3 of reaction volume so that the conventional cracking process may be conducted either 1) at sufficiently low temperature to avoid excessive coke-make to maximize yield of desirable cracked hydrocarbons; or 2) at higher temperatures with significant quantities of coke production, where the high levels of solids produced impedes operation of the process at a high rate.
• the hydrogen sulfide may be provided in an amount on a mole ratio basis relative to the hydrogen provided of at least 1:9, or at least 1.5:8.5, or at least 1:4, or at least 2.5:7.5, or at least 3:7, or at least 3.5:6.5, or at least 4:6, up to 1: 1, where the combined hydrogen sulfide and hydrogen partial pressures are at least 60%, or at least 70%, or at least 80%, or at least 90%, or at least 95% of the total pressure in the reactor.
• the hydrogen sulfide partial pressure in the reactor may be maintained in a pressure range of from 0.4 MPa to 13.8 MPa, or from 2 MPa to 10 MPa, or from 3 MPa to 7 MPa.
• a non-condensable gas produced in the vapor along with the hydrocarbon-containing product may be separated from the hydrocarbon-containing product and recycled back into the mixing zone, where the non-condensable gas may comprise hydrocarbon gases such as methane, ethane, and propane as well as hydrogen sulfide and hydrogen.
• hydrocarbon gases such as methane, ethane, and propane as well as hydrogen sulfide and hydrogen.
• the catalyst, the hydrocarbon-containing feedstock, the hydrogen sulfide, and the hydrogen may be mixed by being blended into an intimate admixture in the mixing zone 1.
• the catalyst, hydrocarbon-containing feedstock and the hydrogen may be blended in the mixing zone 1, for example, by stirring a mixture of the components, for example by a mechanical stirring device located in the mixing zone 1.
• the catalyst, hydrocarbon-containing feedstock, and hydrogen may also be mixed in the mixing zone 1 by blending the components prior to providing the components to the mixing zone 1 and injecting the blended components into the mixing zone 1 through one or more nozzles which may act as the feed inlet 5.
• the catalyst, hydrocarbon-containing feedstock, hydrogen sulfide, and hydrogen may also be blended in the mixing zone 1 by blending the hydrocarbon-containing feedstock and catalyst and injecting the mixture into the mixing zone 1 through one or more feed inlet nozzles positioned with respect to the hydrogen inlet line 7 and hydrogen sulfide inlet line 27 such that the mixture is blended with hydrogen and hydrogen sulfide entering the mixing zone 1 through the hydrogen inlet line 7 and the hydrogen sulfide inlet line 27, respectively.
• Baffles may be included in the reactor 3 in the mixing zone 1 to facilitate blending the hydrocarbon-containing feedstock, catalyst, hydrogen sulfide, and hydrogen.
• the catalyst is present in the mixing zone 1 in a catalyst bed, and the hydrocarbon-containing feedstock, hydrogen sulfide, hydrogen, and catalyst are mixed by bringing the hydrocarbon-containing feedstock, hydrogen sulfide, and hydrogen simultaneously into contact with the catalyst in the catalyst bed.
• the temperature and pressure conditions in the mixing zone 1 are maintained so that heavy hydrocarbons in the hydrocarbon-containing feedstock may be cracked.
• the temperature in the mixing zone 1 is maintained from 375°C to 500°C.
• the mixing zone 1 is maintained at a temperature of from 425°C to 500°C, or from 430°C to 500°C, or from 440°C to 500°C, or from 450°C to 500°C.
• Higher temperatures may be preferred in the process of the present invention since 1) the rate of conversion of the hydrocarbon-containing feedstock to a hydrocarbon-containing product increases with temperature; and 2) the present process inhibits or prevents the formation of coke, even at temperatures of 430°C or greater, which typically occurs rapidly in conventional cracking processes at temperatures of 430°C or greater.
• the vapor may be comprised of hydrocarbons present initially in the hydrocarbon-containing feedstock that vaporize at the temperature and pressure within the mixing zone 1 and hydrocarbons that are not present initially in the hydrocarbon-containing feedstock but are produced by cracking and hydrogenating hydrocarbons initially in the hydrocarbon-containing feedstock that were not vaporizable at the temperature and pressure within the mixing zone 1.
• At least a portion of the vapor comprised of hydrocarbons that are vaporizable at the temperature and pressure within the mixing zone 1 may be continuously or intermittently separated from the mixture of hydrocarbon-containing feedstock, hydrogen, and catalyst since the more volatile vapor physically separates from the hydrocarbon-containing feedstock, catalyst, hydrogen, and hydrogen sulfide mixture.
• the vapor may also contain hydrogen gas and hydrogen sulfide gas which also separate from the mixture.
• the hydrocarbon-depleted feed residuum is comprised of hydrocarbons that are liquid at the temperature and pressure within the mixing zone 1.
• the hydrocarbon-depleted feed residuum may also be comprised of solids such as metals freed from cracked hydrocarbons and minor amounts of coke.
• the hydrocarbon-depleted feed residuum may contain little coke or proto-coke since the process of the present invention inhibits the generation of coke.
• the hydrocarbon-depleted feed residuum may contain, per metric ton of hydrocarbon-containing feedstock provided to the mixing zone 1, at most 10 kg, or less than 5 kg, or at most 1 kg of hydrocarbons insoluble in toluene as measured by ASTM Method D4072.
• At least a portion of the vapor separated from the mixture of the hydrocarbon- containing feedstock, hydrogen sulfide, hydrogen, and catalyst may be continuously or intermittently separated from the mixing zone 1 while retaining the hydrocarbon- depleted feed residuum, catalyst, and any fresh hydrocarbon-containing feedstock in the mixing zone 1. At least a portion of the vapor separated from the mixing zone 1 may be continuously or intermittently separated from the reactor 3 through a reactor product outlet 11.
• the reactor 3 may be comprised of a mixing zone 1, a disengagement zone 21, and a vapor/gas zone 23.
• the vapor comprised of hydrocarbons that are vaporizable at the temperature and pressure within the mixing zone 1 may separate from the mixture of hydrocarbon-depleted residuum, catalyst, and fresh hydrocarbon-containing feed, if any, in mixing zone 1 into the
• a stripping gas such as hydrogen may be injected into the disengagement zone 21 to facilitate separation of the vapor from the mixing zone 1.
• Some liquids and solids may be entrained by the vapor as it is separated from the mixing zone 1 into the disengagement zone 21, so that the disengagement zone 21 contains a mixture of vapor and liquids, and potentially solids.
• At least a portion of the vapor separates from the disengagement zone 21 into the vapor/gas zone 23, where the vapor separating from the disengagement zone 21 into the vapor/gas zone 23 contains little or no liquids or solids at the temperature and pressure within the vapor/gas zone.
• At least a portion of the vapor in the vapor/gas zone 23 exits the reactor 3 through the reactor product outlet 11.
• the hydrocarbons in the hydrocarbon-containing feed are contacted and mixed with the catalyst, hydrogen sulfide, and hydrogen in the mixing zone 1 of the reactor only as long as necessary to be vaporized and separated from the mixture, and are retained in the reactor 3 only as long as necessary to be vaporized and exit the reactor product outlet 11.
• Low molecular weight hydrocarbons having a low boiling point may be vaporized almost immediately upon being introduced into the mixing zone 1 when the mixing zone 1 is maintained at a temperature of 375°C to 500°C and a total pressure of from 6.9 MPa to 27.5 MPa. These hydrocarbons may be separated rapidly from the reactor 3.
• At least a portion of the vapor separated from the mixing zone 1 and separated from the reactor 3 may be condensed apart from the mixing zone 1 to produce the liquid hydrocarbon-containing product.
• the portion of the vapor separated from the reactor 3 may be provided to a condenser 13 wherein at least a portion of the vapor separated from the reactor 3 may be condensed to produce the hydrocarbon-containing product that is comprised of hydrocarbons that are a liquid at STP.
• a portion of the vapor separated from the reactor 3 may be passed through a heat exchanger 15 to cool the vapor prior to providing the vapor to the condenser 13.
• Condensation of the liquid hydrocarbon-containing product from the vapor separated from the reactor 3 may also produce a non-condensable gas that may be comprised of hydrocarbons having a carbon number from 1 to 6, hydrogen, and hydrogen sulfide.
• the condensed hydrocarbon-containing liquid product may be separated from the non-condensable gas through a condenser liquid product outlet 17 and stored in a product receiver 18, and the non-condensable gas may be separated from the condenser 13 through a non-condensable gas outlet 19.
• the non- condensable gas may be passed through an amine or caustic scrubber 20 and recovered through a gas product outlet 22. Alternatively, the non-condensable gas may be recycled into the mixing zone 1 without scrubbing to provide hydrogen and hydrogen sulfide to the mixture in the mixing zone 1.
• the condensed hydrocarbon-containing liquid product may be separated from the non-condensable gas in the low pressure separator through a low pressure separator liquid product outlet 10 and stored in a product receiver 18.
• the non-condensable gas may be separated from the high pressure separator 12 through a high pressure non-condensable gas outlet 24 and from the low pressure separator 14 through a low pressure non-condensable gas outlet 26.
• the non-condensable gas streams may be combined in line 28 and passed through an amine or caustic scrubber 20 and recovered through a gas product outlet 22. Alternatively, the combined non-condensable gas streams may be recycled into the mixing zone 1 without scrubbing to provide hydrogen and hydrogen sulfide to the mixture in the mixing zone 1.
• the vapor separated from the mixing zone 1 and from the reactor 3 through the reactor product outlet 11 may contain hydrogen sulfide.
• the hydrogen sulfide in the vapor product may be separated from the hydrocarbon-containing liquid product in the condenser 13 (Fig. 1) or in the high and low pressure separators 12 and 14 (Fig. 2), where the hydrogen sulfide may form a portion of the non-condensable gas.
• the vapor separated from the mixing zone 1 and from the reactor 3 may be further hydroprocessed without condensing the hydrocarbon-containing product.
• the vapor separated from the reactor may be hydrotreated to reduce sulfur, nitrogen, and olefins in the hydrocarbon- containing product by passing the vapor from the reactor 3 to a hydroprocessing reactor, where the vapor may be contacted with a conventional hydroprocessing catalyst and hydrogen at a temperature of from 260°C to 425°C and a total pressure of from 3.4 MPa to 27.5 MPa.
• a portion of the hydrocarbon-depleted feed residuum and catalyst(s) may be separated from the mixing zone to remove solids including metals and
• the reactor 3 may include a bleed stream outlet 25 for removal of a stream of hydrocarbon-depleted feed resdiuum and catalyst(s) from the mixing zone 1 and the reactor 3.
• the bleed stream outlet 25 may be operatively connected to the mixing zone 1 of the reactor 3.
• a portion of the hydrocarbon-depleted feed residuum and the catalyst(s) may be removed together from the mixing zone 1 and the reactor 3 through the bleed stream outlet 25 while the process is proceeding.
• Solids and the catalyst(s) may be separated from a liquid portion of the hydrocarbon-depleted feed residuum in a solid- liquid separator 30.
• the solid-liquid separator 30 may be a filter or a centrifuge.
• the liquid portion of the hydrocarbon-depleted feed residuum may be recycled back into the mixing zone 1 via a recycle inlet 32 for further processing or may be combined with the hydrocarbon-containing feed and recycled into the mixing zone 1 through the feed inlet 5.
• the vapor may be continuously or intermittently separated from the mixing zone 1 and the reactor 3 over substantially all of the time period that the hydrocarbon-containing feedstock, catalyst, hydrogen, and hydrogen sulfide are mixed in the mixing zone 1.
• Fresh hydrocarbon-containing feedstock, hydrogen, and hydrogen sulfide may be blended with the hydrocarbon-depleted residuum in the mixing zone 1 over the course of the time period of the reaction as needed.
• fresh hydrocarbon-containing feedstock, hydrogen, and hydrogen sulfide are provided continuously to the mixing zone 1 over substantially all of the time period the reaction is effected.
• Solids may be removed from the mixing zone 1 continuously or intermittently over the time period the process is run by separating a bleed stream of the hydrocarbon-containing feed residuum from the mixing zone 1 and the reactor 3, removing the solids from the bleed stream, and recycling the bleed stream from which the solids have been removed back into the mixing zone 1 as described above.
• the process of the present invention produces, in part, a hydrocarbon- containing product that is a liquid at STP.
• the hydrocarbon-containing product contains less than 4 wt.%, or at most 3 wt.%, or at most 2 wt.%, or at most 1 wt.%, or at most 0.5 wt.% of hydrocarbons having a boiling point of greater than 538°C in accordance with ASTM Method D5307 and at most 0.5 wt.%, or at most 0.25 wt.%, or at most 0.1 wt.% coke as determined in accordance with ASTM Method D4072. Furthermore, the hydrocarbon-containing product contains at least 80%, or at least 85%, or at least 90%, or at least 95%, or at least 97% of the atomic carbon present in the hydrocarbon-containing feedstock.
• the liquid hydrocarbon-containing product may contain VGO hydrocarbons, distillate hydrocarbons, and naphtha hydrocarbons.
• the liquid hydrocarbon- containing product may contain, per gram of liquid hydrocarbon-containing product, at least 0.05 grams, or at least 0.1 grams of hydrocarbons having a boiling point from the initial boiling point of the hydrocarbon-containing product up to 204°C (400°F).
• the liquid hydrocarbon-containing product may also contain, per gram of liquid hydrocarbon-containing product, at least 0.1 grams, or at least 0.15 grams of hydrocarbons having a boiling point of from 204°C (400°F) up to 260°C (500°F).
• the hydrocarbon-containing product produced by the process of the present invention may contain significant amounts of sulfur.
• the hydrocarbon-containing product may contain, per gram, at least 0.0005 gram of sulfur or at least 0.001 gram of sulfur.
• the sulfur content of the hydrocarbon-containing product may be determined in accordance with ASTM Method D4294.
• At least 40 wt.% of the sulfur may be contained in hydrocarbon compounds having a carbon number of 17 or less as determined by two-dimensional GC-GC sulfur chemiluminscence, where at least 60 wt. % of the sulfur in the sulfur-containing hydrocarbon compounds having a carbon number of 17 or less may be contained in benzothiophenic compounds as determined by GC-GC sulfur chemiluminscence.
• the amount of nitrogen-containing hydrocarbon compounds having a carbon number of 17 or less relative to the amount of nitrogen in all nitrogen-containing hydrocarbon compounds in the hydrocarbon-containing product and the relative amount of acridinic and carbazolic compounds may be determined by nitrogen chemiluminscence two dimensional gas chromatography (GCxGC-NCD).
• the hydrocarbon-containing product of the process of the present invention may contain relatively few polyaromatic hydrocarbon compounds containing three or more aromatic ring structures relative to combined mono-aromatic and di-aromatic hydrocarbon compounds.
• the combined mono-aromatic and di-aromatic hydrocarbon compounds may contain relatively few polyaromatic hydrocarbon compounds containing three or more aromatic ring structures relative to combined mono-aromatic and di-aromatic hydrocarbon compounds.
• hydrocarbon compounds in the hydrocarbon-containing product may be present in the hydrocarbon-containing product in a weight ratio relative to the polyaromatic hydrocarbon compounds of at least 1.5 : 1.0, or at least 2.0 : 1.0, or at least 2.5 : 1.0.
• the relative amounts of mono-, di- and polyaromatic compounds in the hydrocarbon- containing product may be determined by flame ionization detection-two dimensional gas chromatography (GCxGC-FID).
• the alpha olefins in the hydrocarbon-containing product may be present in the hydrocarbon-containing product relative to olefins having an internal double bond in a weight ratio of alpha olefins to internal double bond olefins is at least 0.7 : 1.0, or at least 0.9: 1.0, or at least 1.0: 1.0.
• the hydrocarbon-containing product of the process of the present invention may contain paraffins, where a significant amount of the paraffins may be w-paraffins. Paraffin content in the hydrocarbon-containing product may be determined in accordance with ASTM Method D6730. The w-paraffins in the hydrocarbon- containing product may be present relative to isoparaffins in a weight ratio of isoparaffins to w-paraffins of at most 1.4: 1.0, or at most 1.0: 1.0.
• a catalyst for use in a process of the present invention containing copper, molybdenum, and sulfur was produced, where at least a portion of the catalyst had a structure according to Formula (VII).
• a 22-liter round-bottom flask was charged with a solution of 1199 grams of copper sulfate (CuS0 4 ) in 2 liters of water.
• the copper sulfate solution was heated to 85°C.
• 520.6 grams of ammonium tetrathiomolybdate (ATTM) ⁇ (NH 4 ) 2 (MoS 4 ) ⁇ in 13 liters of water was injected into the heated copper sulfate solution through an injection nozzle over a period of 4 hours while stirring the solution. After the addition was complete, the solution was stirred for 8 hours at 93°C and then was allowed to cool and settle overnight.
• Solids were then separated from the slurry. Separation of the solids from the slurry was accomplished using a centrifuge separator at 12,000 Gauss to give a red paste. The separated solids were washed with water until conductivity measurements of the effluent were under 100 ⁇ 8 ⁇ 6 ⁇ 8 at 33°C. Residual water was then removed from the solids by vacuum distillation at 55 °C and 29 inches of Hg pressure. 409 grams of catalyst solids were recovered. Semi-quantitative XRF (element, mass ) measured: Cu, 16.4; Mo, 35.6; S, 47.7; and less than 0.1 wt.% Fe and Co.
• the catalyst solids were particulate having a particle size distribution with a mean particle size of 47.4 ⁇ as determined by laser diffractometry using a
• the BET surface area of the catalyst was measured to be 113 m 2 /g and the catalyst pore volume was measured to be 0.157 cmVg.
• the catalyst had a pore size distribution, where the median pore size diameter was determined to be 56 angstroms.
• X-ray diffraction and Raman IR spectroscopy confirmed that at least a portion of the catalyst had a structure in which copper, sulfur, and molybdenum were arranged as shown in Formula (VII) above.
• the total gas flow rate of each hydrocracking treatment was maintained at 950 standard liters per hour, where the hydrogen flow rate of the treatements ranged from 640-720 standard liters per hour and the hydrogen sulfide flow rate of the treatments ranged from 210-310 standard liters per hour.
• the liquid hourly space velocity of the bitumen feed for hydrocracking depended on the reaction rate, and ranged from 0.6 to 0.8 hr "1 .
• a target temperature was selected for each hydrocracking treatment within the range of 420°C to 450°C. The conditions for each hydrocracking treatment of the six samples are shown below in Table 2.
• the Peace River bitumen was preheated to approximately 105°C-115°C in a 10 gallon feed drum and circulated through a closed feed loop system from which the bitumen was fed into a semi- continuous stirred tank reactor with vapor effluent capability, where the reactor had an internal volume capacity of 1000 cm 3 .
• the reactor was operated in a continuous mode with respect to the bitumen feedstream and the vapor effluent product, however, the reactor did not include a bleed stream to remove accumulating metals and/or carbonaceous solids.
• bitumen feed of each sample was fed to the reactor as needed to maintain a working volume of feed in the reactor of approximately 475 ml, where a Berthold single-point source nuclear level detector located outside the reactor was used to control the working volume in the reactor.
• 50 grams of the catalyst was mixed with the hydrogen, hydrogen sulfide, and bitumen feed sample in the reactor during the course of the hydrocracking treatment.
• the bitumen feed sample, hydrogen, hydrogen sulfide, and the catalyst were mixed together in the reactor by stirring with an Autoclave Engineers MagneDrive ® impeller at 1200 rpm.
• non-benzothiophenes include sulfides, thiols, disulfides, thiophenes, arylsulfides, benzonaphthothiophenes, and naphthenic benzonaphthothiophenes
• benzothiophenes include benzothiophene, naphthenic benzothiophenes, di- benzothiophenes, and naphthenic di-benzothiophenes.
• the hydrocracking treatment provided a hydrocarbon composition in which a significant portion of the sulfur in the composition was contained in relatively low carbon number hydrocarbons.
• These low carbon number heteroatomic hydrocarbons generally have a low molecular weight relative to the sulfur containing hydrocarbons having a carbon number of 18 or greater, and generally are contained in the naphtha and distillate boiling fractions, not the high molecular weight, high boiling residue and asphaltene fractions in which sulfur- containing hydrocarbons are more refractory.
• the hydrocracking treatment provided a hydrocarbon composition that had a significant quantity of mono-aromatic and di-aromatic hydrocarbon compounds relative to the polyaromatic hydrocarbon compounds, where the weight ratio of the combined mono-aromatic and di-aromatic hydrocarbon compounds relative to the polyaromatic hydrocarbon compounds was 1.9: 1.
• tetrathiomolybdate was mixed with 636 grams of Na 2 C0 3 in 6 liters of water while stirring. The resulting solution was heated to 70°C and then stirred for three hours to produce a solution of Na 2 MoS 4 . The Na 2 MoS 4 solution was then permitted to cool overnight.
• a second solution was prepared by mixing 1498 grams of CuS0 4 5H 2 0 in 6 liters of water. The CuS0 4 solution was then added to the Na 2 MoS 4 solution via pneumatic pump through a 0.02" x 0.5" nozzle while stirring the mixture at ambient temperature. The mixture was stirred for two hours, and then the resulting solids were separated by centrifuge. 880 grams of solid particulate catalyst was recovered. The solids were then washed with water until the effluent from the wash had a
• the catalyst solids were particulate and had a particle size distribution with a mean particle size of 8.5 ⁇ as determined by laser diffractometry using a Mastersizer S (Malvern Instruments). The BET surface area of the catalyst solids was measured to be 29.3 m 2 /g. Semi-quantitative XRF of the catalyst solids indicated that the catalyst solids contained 45.867 mass Cu, 18.587 mass Mo, and 27.527 mass S. X-ray diffraction and Raman IR spectroscopy confirmed that at least a portion of the catalyst had a structure in which copper, molybdenum, and sulfur were arranged as shown in formula (VII) above.
• Peace River bitumen having the composition shown in Table 1 above was hydrocracked in a process in accordance with the present invention using different hydrogen sulfide levels to determine the effect of hydrogen sulfide on the rate of the hydrocracking reaction.
• Hydrogen sulfide was provided at 5 mol , 11.4 mol , and 20.1 mol % of the gas fed to the reactor.
• Nitrogen was provided as an inert gas in the gas fed to the reactor to maintain the total pressure of the reaction at 8.3 MPa, where nitrogen was provided as 25 mol % of the gas fed to the reactor when hydrogen sulfide was provided at 5 mol % of the gas fed to the reactor; as 20 mol % of the gas fed to the reactor when hydrogen sulfide was provided at 11.4 mol % of the gas fed to the reactor; as 10 mol % of the gas fed to the reactor when hydrogen sulfide was provided at 20.1 mol % of the gas fed to the reactor; and as 29.8 mol % of the gas fed to the reactor in the control.
• Hydrogen and hydrogen sulfide provided 75% of the total pressure in the reaction when hydrogen sulfide was provided at 5 mol % of the gas fed to the reactor, and provided 80% of the total pressure when hydrogen sulfide was provided at 11.4 mol % and 20.1 mol % of the gas fed to the reactor.
• Example 2 Four samples of the Peace River bitumen were hydrocracked, one each at the above specified hydrogen sulfide: hydrogen: nitrogen levels.
• the hydrocracking conditions were the same as specified above for Example 2 except that the catalyst that was used was the catalyst prepared in Example 3, the total pressure was maintained at 8.3 MPa, hydrogen sulfide and hydrogen partial pressures depended on the amount of each provided to each of the hydrocracking reactions as set forth above, the temperature was 430°C for each of the hydrocracking reactions, the gas flow rate was maintained at 900 standard liters per hour, and the working volume of feed in the reactor was maintained at 500 ml.
• Another catalyst was prepared for use in a hydrocracking process of the present invention to determine the relative amount of liquid hydrocarbon product, coke, non-condensable gas, and hold-up produced by the process.
• a solution was prepared by mixing 780 grams of ammonium tetrathiomolybdate and 636 grams of Na 2 C0 3 in 13.5 liters of deionized water. The solution was heated to 85°C to generate Na 2 MoS 4 .
• a separate solution of CuS0 4 was prepared by mixing 2994 grams of CuS0 4 in 5 liters of water. The CuS0 4 solution was heated to 85°C and added to the Na 2 MoS 4 solution through a 0.0625" spray nozzle. The mixed solution was stirred at 85°C for 2 hours and then at room temperature overnight.
• Solid catalyst material was then separated from the solution by centrifuge. The solid catalyst material was washed until the wash effluent had a pH of 7 and conductivity of 488 ⁇ 8 at 33°C. The solid catalyst material was then dried. 548 grams of glossy black catalyst solids were recovered.
• the catalyst solids were particulate and had a particle size distribution with a mean particle size of between 400 and 500 nm as determined by laser diffractometry using a Mastersizer S.
• the BET surface area of the catalyst was measured to be 58 m 2 /g.
• Semi-quantitative XRF indicated that the solid catalyst material contained 37.633 mass % Cu, 22.231 mass % Mo, 27.734 mass % S, and 0.503 mass % Na.
• X-ray diffraction and and Raman IR spectroscopy confirmed that at least a portion of the catalyst solids had a structure in which copper, molybdenum, and sulfur were arranged as shown in formula (VII) above.
• Peace River bitumen having the composition shown in Table 1 above was hydrocracked in a process in accordance with the present invention using gas containing 36.5 mol % hydrogen sulfide and 63.7 mol % hydrogen (mole ratio 1: 1.75, hydrogen sulfide:hydrogen) to determine the relative amounts of liquid hydrocarbon product, non-compressible gas, and coke produced by the hydrocracking reaction.
• Hydrocracking conditions were the same as set forth in Example 2 except that the catalyst that was used in the process was the catalyst prepared in Example 5, the hydrogen sulfide partial pressure was 4.78 MPa, the temperature was 420°C, the gas flow rate was maintained at 948 standard liters per hour, the working volume of feed in the reactor was maintained at 500 ml, and the pressure in the low temperature separator was maintained at 1.38 MPa to improve the capture yield of condensable vapors.

Landscapes

• Chemical & Material Sciences (AREA)
• Engineering & Computer Science (AREA)
• Chemical Kinetics & Catalysis (AREA)
• Organic Chemistry (AREA)
• Materials Engineering (AREA)
• Oil, Petroleum & Natural Gas (AREA)
• General Chemical & Material Sciences (AREA)
• Catalysts (AREA)
• Production Of Liquid Hydrocarbon Mixture For Refining Petroleum (AREA)

Applications Claiming Priority (2)

Publications (1)

Family

ID=44168134

Family Applications (1)

Country Status (3)

Family Cites Families (9)

• 2011
  • 2011-01-21 WO PCT/US2011/021967 patent/WO2011091202A2/en active Application Filing
  • 2011-01-21 EP EP11701439A patent/EP2526174A2/de not_active Withdrawn
  • 2011-01-21 CA CA2785512A patent/CA2785512A1/en not_active Abandoned

Non-Patent Citations (1)

Also Published As

Similar Documents

Legal Events