WO2017127288A1 - Production de naphte à partir de gaz combustible de raffinerie - Google Patents
Production de naphte à partir de gaz combustible de raffinerie Download PDFInfo
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- WO2017127288A1 WO2017127288A1 PCT/US2017/013282 US2017013282W WO2017127288A1 WO 2017127288 A1 WO2017127288 A1 WO 2017127288A1 US 2017013282 W US2017013282 W US 2017013282W WO 2017127288 A1 WO2017127288 A1 WO 2017127288A1
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- WIPO (PCT)
- Prior art keywords
- effluent
- compounds
- less
- olefin
- fuel gas
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- 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
- C10G50/00—Production of liquid hydrocarbon mixtures from lower carbon number hydrocarbons, e.g. by oligomerisation
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- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
- B01D—SEPARATION
- B01D53/00—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols
- B01D53/14—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols by absorption
- B01D53/1431—Pretreatment by other processes
- B01D53/1437—Pretreatment by adsorption
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- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
- B01D—SEPARATION
- B01D53/00—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols
- B01D53/14—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols by absorption
- B01D53/1456—Removing acid components
- B01D53/1468—Removing hydrogen sulfide
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- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
- B01D—SEPARATION
- B01D53/00—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols
- B01D53/14—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols by absorption
- B01D53/1487—Removing organic compounds
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- C—CHEMISTRY; METALLURGY
- C07—ORGANIC CHEMISTRY
- C07C—ACYCLIC OR CARBOCYCLIC COMPOUNDS
- C07C11/00—Aliphatic unsaturated hydrocarbons
- C07C11/02—Alkenes
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- C—CHEMISTRY; METALLURGY
- C07—ORGANIC CHEMISTRY
- C07C—ACYCLIC OR CARBOCYCLIC COMPOUNDS
- C07C2/00—Preparation of hydrocarbons from hydrocarbons containing a smaller number of carbon atoms
- C07C2/02—Preparation of hydrocarbons from hydrocarbons containing a smaller number of carbon atoms by addition between unsaturated hydrocarbons
- C07C2/04—Preparation of hydrocarbons from hydrocarbons containing a smaller number of carbon atoms by addition between unsaturated hydrocarbons by oligomerisation of well-defined unsaturated hydrocarbons without ring formation
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- C—CHEMISTRY; METALLURGY
- C07—ORGANIC CHEMISTRY
- C07C—ACYCLIC OR CARBOCYCLIC COMPOUNDS
- C07C7/00—Purification; Separation; Use of additives
- C07C7/11—Purification; Separation; Use of additives by absorption, i.e. purification or separation of gaseous hydrocarbons with the aid of liquids
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- 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
- C10G11/00—Catalytic cracking, in the absence of hydrogen, of hydrocarbon oils
- C10G11/14—Catalytic cracking, in the absence of hydrogen, of hydrocarbon oils with preheated moving solid catalysts
- C10G11/18—Catalytic cracking, in the absence of hydrogen, of hydrocarbon oils with preheated moving solid catalysts according to the "fluidised-bed" technique
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- 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
- C10G21/00—Refining of hydrocarbon oils, in the absence of hydrogen, by extraction with selective solvents
- C10G21/06—Refining of hydrocarbon oils, in the absence of hydrogen, by extraction with selective solvents characterised by the solvent used
- C10G21/12—Organic compounds only
- C10G21/14—Hydrocarbons
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- 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
- C10G21/00—Refining of hydrocarbon oils, in the absence of hydrogen, by extraction with selective solvents
- C10G21/06—Refining of hydrocarbon oils, in the absence of hydrogen, by extraction with selective solvents characterised by the solvent used
- C10G21/12—Organic compounds only
- C10G21/20—Nitrogen-containing compounds
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- 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
- C10G45/00—Refining of hydrocarbon oils using hydrogen or hydrogen-generating compounds
- C10G45/02—Refining of hydrocarbon oils using hydrogen or hydrogen-generating compounds to eliminate hetero atoms without changing the skeleton of the hydrocarbon involved and without cracking into lower boiling hydrocarbons; Hydrofinishing
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- 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
- C10G45/00—Refining of hydrocarbon oils using hydrogen or hydrogen-generating compounds
- C10G45/32—Selective hydrogenation of the diolefin or acetylene compounds
- C10G45/34—Selective hydrogenation of the diolefin or acetylene compounds characterised by the catalyst used
- C10G45/36—Selective hydrogenation of the diolefin or acetylene compounds characterised by the catalyst used containing nickel or cobalt metal, or compounds thereof
- C10G45/38—Selective hydrogenation of the diolefin or acetylene compounds characterised by the catalyst used containing nickel or cobalt metal, or compounds thereof in combination with chromium, molybdenum or tungsten metals, or compounds thereof
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- 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
- C10G5/00—Recovery of liquid hydrocarbon mixtures from gases, e.g. natural gas
- C10G5/04—Recovery of liquid hydrocarbon mixtures from gases, e.g. natural gas with liquid absorbents
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- 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
- C10G57/00—Treatment of hydrocarbon oils, in the absence of hydrogen, by at least one cracking process or refining process and at least one other conversion process
- C10G57/02—Treatment of hydrocarbon oils, in the absence of hydrogen, by at least one cracking process or refining process and at least one other conversion process with polymerisation
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- 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
- C10G69/00—Treatment of hydrocarbon oils by at least one hydrotreatment process and at least one other conversion process
- C10G69/02—Treatment of hydrocarbon oils by at least one hydrotreatment process and at least one other conversion process plural serial stages only
- C10G69/12—Treatment of hydrocarbon oils by at least one hydrotreatment process and at least one other conversion process plural serial stages only including at least one polymerisation or alkylation step
- C10G69/126—Treatment of hydrocarbon oils by at least one hydrotreatment process and at least one other conversion process plural serial stages only including at least one polymerisation or alkylation step polymerisation, e.g. oligomerisation
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- 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
- C10G70/00—Working-up undefined normally gaseous mixtures obtained by processes covered by groups C10G9/00, C10G11/00, C10G15/00, C10G47/00, C10G51/00
- C10G70/04—Working-up undefined normally gaseous mixtures obtained by processes covered by groups C10G9/00, C10G11/00, C10G15/00, C10G47/00, C10G51/00 by physical processes
- C10G70/06—Working-up undefined normally gaseous mixtures obtained by processes covered by groups C10G9/00, C10G11/00, C10G15/00, C10G47/00, C10G51/00 by physical processes by gas-liquid contact
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- 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
- C10G9/00—Thermal non-catalytic cracking, in the absence of hydrogen, of hydrocarbon oils
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- C—CHEMISTRY; METALLURGY
- C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
- C10L—FUELS NOT OTHERWISE PROVIDED FOR; NATURAL GAS; SYNTHETIC NATURAL GAS OBTAINED BY PROCESSES NOT COVERED BY SUBCLASSES C10G, C10K; LIQUEFIED PETROLEUM GAS; ADDING MATERIALS TO FUELS OR FIRES TO REDUCE SMOKE OR UNDESIRABLE DEPOSITS OR TO FACILITATE SOOT REMOVAL; FIRELIGHTERS
- C10L3/00—Gaseous fuels; Natural gas; Synthetic natural gas obtained by processes not covered by subclass C10G, C10K; Liquefied petroleum gas
- C10L3/06—Natural gas; Synthetic natural gas obtained by processes not covered by C10G, C10K3/02 or C10K3/04
- C10L3/08—Production of synthetic natural gas
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- C—CHEMISTRY; METALLURGY
- C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
- C10L—FUELS NOT OTHERWISE PROVIDED FOR; NATURAL GAS; SYNTHETIC NATURAL GAS OBTAINED BY PROCESSES NOT COVERED BY SUBCLASSES C10G, C10K; LIQUEFIED PETROLEUM GAS; ADDING MATERIALS TO FUELS OR FIRES TO REDUCE SMOKE OR UNDESIRABLE DEPOSITS OR TO FACILITATE SOOT REMOVAL; FIRELIGHTERS
- C10L3/00—Gaseous fuels; Natural gas; Synthetic natural gas obtained by processes not covered by subclass C10G, C10K; Liquefied petroleum gas
- C10L3/06—Natural gas; Synthetic natural gas obtained by processes not covered by C10G, C10K3/02 or C10K3/04
- C10L3/10—Working-up natural gas or synthetic natural gas
- C10L3/101—Removal of contaminants
- C10L3/102—Removal of contaminants of acid contaminants
- C10L3/104—Carbon dioxide
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- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
- B01D—SEPARATION
- B01D2252/00—Absorbents, i.e. solvents and liquid materials for gas absorption
- B01D2252/20—Organic absorbents
- B01D2252/204—Amines
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- 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
- B01J2231/00—Catalytic reactions performed with catalysts classified in B01J31/00
- B01J2231/20—Olefin oligomerisation or telomerisation
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- C—CHEMISTRY; METALLURGY
- C07—ORGANIC CHEMISTRY
- C07C—ACYCLIC OR CARBOCYCLIC COMPOUNDS
- C07C2529/00—Catalysts comprising molecular sieves
- C07C2529/04—Catalysts comprising molecular sieves having base-exchange properties, e.g. crystalline zeolites, pillared clays
- C07C2529/06—Crystalline aluminosilicate zeolites; Isomorphous compounds thereof
- C07C2529/40—Crystalline aluminosilicate zeolites; Isomorphous compounds thereof of the pentasil type, e.g. types ZSM-5, ZSM-8 or ZSM-11
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- 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
- C10G2300/10—Feedstock materials
- C10G2300/1088—Olefins
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- 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
- C10G2400/00—Products obtained by processes covered by groups C10G9/00 - C10G69/14
- C10G2400/02—Gasoline
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- 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
- C10G2400/00—Products obtained by processes covered by groups C10G9/00 - C10G69/14
- C10G2400/26—Fuel gas
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- C—CHEMISTRY; METALLURGY
- C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
- C10L—FUELS NOT OTHERWISE PROVIDED FOR; NATURAL GAS; SYNTHETIC NATURAL GAS OBTAINED BY PROCESSES NOT COVERED BY SUBCLASSES C10G, C10K; LIQUEFIED PETROLEUM GAS; ADDING MATERIALS TO FUELS OR FIRES TO REDUCE SMOKE OR UNDESIRABLE DEPOSITS OR TO FACILITATE SOOT REMOVAL; FIRELIGHTERS
- C10L2290/00—Fuel preparation or upgrading, processes or apparatus therefore, comprising specific process steps or apparatus units
- C10L2290/54—Specific separation steps for separating fractions, components or impurities during preparation or upgrading of a fuel
- C10L2290/541—Absorption of impurities during preparation or upgrading of a fuel
Definitions
- refinery fuel gas can be a low value product stream from one or more refinery processes, and is often utilized for burning in refinery furnaces. While a refinery fuel gas for use in refinery furnaces would ideally mostly comprise methane, a refinery fuel gas stream may include a variety of compounds, including some C4+ or C5+ compounds, olefins, sulfur-containing compounds, and/or hydrogen. The presence of any of these additional components can cause a refinery furnace to run hotter than normal, thereby increasing NOx production.
- U.S. Patent No. 4,831,203 discloses a process for an improved separation and recovery of liquid hydrocarbons in a FCC gas plant.
- the process includes integrating a catalytic bed oligomerization reactor within the FCC gas plant to produce a gasoline product stream from a light olefinic FCC product stream.
- U.S. Patent No. 5,482,617 discloses a process for desulfurization of hydrocarbon streams having at least 50 ppmw organic sulfur compounds, and C5+ hydrocarbons including benzene.
- the hydrocarbon stream is exposed to a fluidized bed of an acidic catalyst in the absence of added hydrogen at a pressure of 0.0 psig to 400 psig and a temperature of 400°F to 900°F.
- U.S. Patent No. 6,372,949 discloses a one-step process for converting an oxygenate- containing feed to liquid boiling range C5+ hydrocarbons.
- the feed is contacted with a catalyst having a unidimensional 10-ring zeolite at a temperature less than 350°C and a pressure above 40 psia.
- a method for producing a refinery fuel gas product can include exposing an olefin-containing feed comprising at least about 50 wt. % C1-C4 compounds, at least about 10 wt. % C2+ olefins, or a combination thereof to a separation process.
- An example of a suitable separation process can be exposing the olefin-containing feed to a liquid sorbent stram.
- the olefin-containing feed can be derived from at least one of a thermal cracking effluent and a fluid catalytic cracking effluent.
- the liquid sorbent stream can comprise C5+ compounds.
- the liquid sorbent stream can absorb at least a portion of C3+ compounds present in the olefin-containing feed, thereby forming a first effluent.
- at least a portion of the first effluent can then be exposed to one or more amine-containing compounds to remove at least a portion of sulfur-containing compounds present in the first effluent to form at least a desulfurized effluent.
- At least a portion of the desulfurized effluent can then be exposed to effective conversion conditions to produce an oligomerized effluent comprising oligomerized C5+ compounds.
- the effective conversion conditions can incldue exposing at least a portion of the desulfurized effluent to an acidic zeolite catalyst at (for example) a pressure of less than about 400 psig, and a temperature of from about 700°F to about 800°F. At least a portion of the C3+ compounds (or at least C5+ compounds) can be separated from the oligomerized effluent to form a light hydrocarbon effluent.
- the light hydrocarbon effluent can have an increased weight percent of methane relative to the oligomerized effluent.
- At least a portion of the light hydrocarbon effluent can be exposed to one or more amine-containing compounds to form a product effluent, the product effluent comprising at least about 70 wt% less (organic) sulfur compounds than the olefin-containing feed, at least about 10 wt% less (organic) nitrogen compounds than the olefin-containing feed, or a combination thereof.
- a method for producing a refinery fuel gas product can include exposing an olefin-containing feed comprising at least about 50 wt. % C1-C4 compounds, at least about 10 wt. % C2-C4 olefins, or a combination thereof to a liquid sorbent stream to absorb at least a portion of C3+ compounds present in the olefin-containing feed, thereby forming a first effluent.
- the liquid sorbent stream can comprise C5+ compounds.
- At least a portion of the first effluent can be exposed to one or more amine-containing compounds to remove at least a portion of sulfur-containing compounds present in the first effluent, thereby forming a desulfurized effluent.
- At least a portion of the desulfurized effluent can be exposed to effective conversion conditions to produce an oligomerized effluent comprising C5+ olefins and H2.
- the effective conversion conditions can include exposing at least a portion of the desulfurized effluent to an acidic zeolite catalyst at (for example) a pressure of less than about 400 psig and a temperature of from about 700°F to about 800°F.
- At least a portion of the oligomerized effluent and a sulfur-containing naphtha boiling range feed can then be exposed to a hydrodesulfurization catalyst under effective hydrodesulfurization conditions to form a desulfurized effluent.
- At least a portion of the C5+ olefins can then be separated from the desulfurized effluent to form at least a light hydrocarbon effluent.
- the light hydrocarbon effluent can have an increased wt. % of methane and/or ethane relative to the oligomerized effluent.
- At least a portion of the light hydrocarbon effluent can be exposed to one or more amine-containing compounds to remove at least a portion of sulfur-containing compounds to form a product effluent.
- the product effluent can have a heating value of from about 850 BTU/SCF to about 1200 BTU/SCF.
- a refinery fuel gas product derived from at least one of a thermal cracking effluent and fluid catalytic cracking effluent is provided.
- the refinery fuel gas product can have a heating value of from about 850 BTU/SCF to about 1200 BTU/SCF.
- the refinery fuel gas product can include methane, ethane, and/or propane.
- the refinery fuel gas product can include at least about 5 wt. % of d compounds, about 5 wt% or less of C3+ compounds, about 5 wt% or less of olefins, an organic sulfur content of about 100 wppm or less, or a combination thereof.
- a method for producing a refinery fuel gas product can include exposing an olefin-containing feed comprising at least about 50 wt. % Ci- C4 compounds, at least about 10 wt. % C2-C4 olefins, or a combination thereof to a liquid sorbent stream to absorb at least a portion of C3+ compounds present in the olefin-containing feed, thereby forming a first effluent.
- at least a portion of the first effluent can be exposed to one or more amine-containing compounds to remove at least a portion of sulfur-containing compounds present in the first effluent, thereby forming a desulfurized effluent.
- At least a portion of the desulfurized effluent can be exposed to effective conversion conditions to produce an oligomerized effluent comprising C5+ olefins.
- the effective conversion conditions can include exposing at least a portion of the desulfurized effluent to an acidic zeolite catalyst at (for example) a pressure of less than about 300 psig and a temperature of from about 700°F to about 800°F.
- At least a portion of the oligomerized effluent (which can contain hydrogen) can be exposed to a catalyst to saturate at least a portion of the C5+ olefins, thereby forming a saturated oligomerized effluent.
- At least a portion of the C3+ olefins can be separated from the saturated oligomerized effluent to form a light hydrocarbon effluent.
- the light hydrocarbon effluent can have an increased wt. % of methane and/or ethane relative to the oligomerized effluent.
- At least a portion of the light hydrocarbon effluent can be exposed to one or more amine-containing compounds to remove at least a portion of sulfur-containing compounds present in the light hydrocarbon effluent, thereby forming a product effluent.
- the product effluent can correspond, for example, to a refinery fuel gas product having a heating value of from about 850 BTU/SCF to about 1200 BTU/SCF.
- FIG. 1 schematically shows an example of a reaction system for upgrading a refinery fuel gas product having a controlled energy content, according to an aspect of the invention.
- systems and methods are provided for upgrading a refinery fuel gas.
- this can include producing a refinery fuel gas product having a controlled energy content from an olefin-containing feed. Additionally or alternately, in some aspects this can include producing a naphtha boiling range product from a refinery fuel gas.
- the olefin-containing feed can comprise a refinery fuel gas stream.
- a refinery fuel gas stream can be a light ends stream produced by a Fluid Catalytic Cracking (FCC) and/or a coker unit.
- the olefin-containing feed can include hydrogen, methane, ethane, or other Cs- compounds, olefins, sulfur-containing compounds, nitrogen- containing compounds such as amines and ammonia, inert gases, or a combination thereof.
- At least a portion of the olefin-containing feed is exposed to a liquid stream comprising C5+ compounds (or heavier) to remove at least a portion of C3+ compounds present in the refinery fuel gas stream to form an effluent having a reduced content of C3+ hydrocarbons.
- One or more sulfur- containing compounds can be converted to H2S in the oligomerization zone
- the effluent having a reduced content of C3+ hydrocarbons can be exposed to one or more amine compounds (such as an amine wash) to produce a desulfurized effluent.
- the desulfurized effluent can be exposed to effective conversion conditions to produce an oligomerized effluent comprising oligomerized olefins, such as C5+ olefins.
- the oligomerized olefins can be removed thereby forming a light hydrocarbon effluent.
- the light hydrocarbon effluent corresponding to an upgraded refinery fuel gas, can optionally be exposed to an amine wash for further desulfurization.
- the resulting refinery fuel gas product can provide a variety of advantages when burned in refinery furnaces, such as buming at a more controlled temperature (i.e., not too hot), which can reduce NOx emissions.
- H2, C2+ compounds including C4+ or C5+ compounds
- olefins present in the refinery fuel gas stream can cause the furnace to bum faster and therefore at a higher local temperature than optimum.
- the exact composition of a fuel gas can strongly influence its buming and emission characteristics. If the actual mix of hydrocarbons in a fuel gas has an increased percentage of C2+ compounds relative to an expected composition, the resulting combustion reaction will generate an increased amount of heat, leading to an unexpectedly high local burner temperature. In certain scenarios, burning a furnace at an elevated temperature can increase NOx production. Further, by burning refinery fuel gas containing H2, C2+ compounds and/or olefins, a refinery may lose any potential value that can be obtained from the H2, C2+ compounds and/or olefins.
- the systems and methods described herein can address one or more of the above problems. For example, by oligomerizing at least a portion of the olefins present in the refinery fuel gas to C5+ olefins and then removing these C5+ olefins, the resulting fuel gas will contain less C2+ compounds, or have an increased amount (wt. %) of methane compared to the initial refinery fuel gas.
- this refinery fuel gas product can have a more controlled energy content and can be burned in a refinery furnace without burning too hot at an early phase of combustion, which can reduce NOx production.
- a valuable product stream e.g., naphtha boiling range compounds or products
- a valuable product stream can be recovered from a stream that may initially have little or no content of naphtha boiling range compounds.
- the systems and methods described herein can reduce NOx and SOx production at a refinery and produce valuable naphtha boiling range compounds or products, while reducing, minimizing, or possibly eliminating the need to implement other NOx-reducing processes, such as Selective Catalytic Reduction.
- the desulfurized effluent is mixed with a sulfur containing naphtha stream such as light FCC naphtha, FCC naphtha, coker naphtha or pyrolysis naphtha to also reduce the sulfur content of said naphtha stream by hydrogen formed in the oligomization step.
- the oligomerization effluent is preferably sent to a fractionation system to recover C3-C4, C5+ and C2- rich fuel gas.
- C2- rich fuel gas is then scrubbed with at least one amine to remove H2S and NH3/HCN produced in the oligomerization reactor.
- the oligomerization effluent is sent to a hydrotreating reactor to saturate olefins and further desulfurize naphtha while consuming H2 present in said oligomerization effluent.
- refrigeration can also be utilized to help separation of C3 or C2+ compounds from a fuel gas product.
- the above aspects can assist with providing a fuel gas with a reduced or minimized variation in fuel content by reducing or minimizing the presence of olefins, H2 and/or C3+ compounds in the fuel gas.
- Reducing the variation in the energy content and/or flame speed of a fuel gas can reduce or minmize NOx (i.e., nitrogen oxides) generation in furnaces as said fuel gas is burned.
- NOx i.e., nitrogen oxides
- said fuel gas NOx production is reduced by more than 10% and in many cases by more than 25%. This helps sites to meet environmental regulations related to NOx emissions.
- the dual stage sulfur scrubbing in addition to oligomerization conversion of sulfur compounds in fuel gas to H2S allows fuel gas burning SOx emission reduction as well.
- an oligomerization reaction can be operated in a sweet spot that increases or maximizes C3- olefins conversion to C4+ or ethylene conversion to C3+ to minimize light olefins burning in furnaces.
- the sweet operating spot does not necessarily maximize C5+ production but it ensures minimizing environmental emissions.
- a narrow temperature range of 700-800°F can be used for this purpose, such as 725-775°F.
- the methods described herein can reduce fuel gas burning emissions while upgrading more than 60% of the olefin content of the fuel gas to larger compounds; reducing more than 70% of the organic sulfur content of the fuel gas with minimal or no H2 addition to the reaction environment; utilizing at least a portion of the H2 content of the fuel gas for hydrotreating; reducing corrosiveness of fuel gas by reducing the content of mercaptans and/or oxygenates in the fuel gas by at least 70%; and/or recovering more valuable LPG (liquefied propane gas) and heavier compounds from the fuel gas.
- LPG liquefied propane gas
- the above benefits can be achieved by running an oligomerization reaction zone in a conversion mode that is selective for ethylene or ethylene-plus-propylene conversion, utilizing a hydroprocessing zone downstream of the oligomerization zone and using conventional fractionation, refrigeration and amine scrubbing for removing more H2S and recovering more C3+ compounds.
- sulfur-containing olefinic naphtha can also be upgraded and desulfurized in the oligomerization step.
- naphtha boiling range refers to an initial or T5 boiling point of at least about 50°F (10°C), and/or a final or T95 boiling point of less than about 450°F (232°C).
- T5 boiling point refers to a temperature at which 5 wt. % of the feed, effluent, product, stream, or composition of interest will boil.
- T95 boiling point refers to a temperature at which 95 wt. % of the feed, effluent, product, stream, or composition of interest will boil.
- the olefin-containing feed can be any hydrocarbon feed that contains olefins.
- at least a portion of the olefin-containing feed can be a portion of a product stream from an FCC unit or flue gas from a cracking or coking process, such as a refinery fuel gas stream.
- the olefin-containing feed can correspond to a feed that is substantially composed of Ci - C4 hydrocarbons. While C5+ compounds can be included, conventional separation processes can typically allow for recovery of such C5+ compounds as part of a naphtha boiling range stream.
- an olefin-containing feed can also include one or more sulfur-containing naphtha fractions such as light FCC naphtha, FCC naphtha and coker naphtha
- the olefin-containing feed can include at least about 1 wt. at least about 5 wt. %, at least about 10 wt. %, at least about 20 wt. %, at least about 30 wt. %, at least about 40 wt. %, at least about 50 wt. %, at least about 60 wt. %, or at least about 70 wt. %.
- the olefin-containing feed can include less than about 100 wt. % olefins, less than about 90 wt. %, less than about 80 wt. %, or less than about 70 wt. %.
- the olefin-containing feed can include at least about 1 wt. % Ci- C4 hydrocarbon compounds, with a portion being C2-C4 olefins, such as the olefin amounts listed above, at least about 5 wt. %, at least about 10 wt. %, at least about 20 wt. %, at least about 30 wt. %, at least about 40 wt. %, at least about 50 wt. %, at least about 60 wt. %, at least about 70 wt. %, at least about 80 wt. %, at least about 90 wt. %, or at least about 95 wt. %.
- the olefin-containing feed can include less than about 100 wt. % C1-C4 hydrocarbon compounds, with a portion being C2-C4 olefins, such as the olefin amounts listed above, less than about 90 wt. %, less than about 80 wt. %, or less than about 70 wt. %.
- the olefin- containing feed can include C1-C4 hydrocarbon compounds, with a portion being C2-C4 olefins, such that the C1-C4 hydrocarbon compounds are at least about 10 wt. % greater than the amount (wt. %) of C2-C4 olefins, at least about 20 wt.
- % greater at least about 30 wt. % greater, at least about 40 wt. % greater, at least about 50 wt. % greater, at least about 60 wt. % greater, at least about 70 wt. % greater, at least about 80 wt. % greater, or at least about 90 wt. % greater.
- C5+ compounds can be included in the olefin-containing feed, preferably they can be separated out in a prior separation for recovery of naphtha.
- C5+ compounds can be present in the olefin-containing feed in an amount of about 5 wt. % or less, about 2.5 wt. % or less, or about 1 wt. % or less.
- a sulfur-containing C5+ naphtha feed can be added to an olefin-containing feed to use hydrogen generated from olefin oligomerization for naphtha sulfur reduction.
- an olefinic C5+ naphtha feed can be added to the olefin-containing feed to upgrade the C5+ olefins to higher value products.
- the olefin-containing feed can include hydrogen gas in an amount of at least about 1 wt. %, at least about 5 wt. %, or at least about 10 wt. %. In the same or alternative aspects, the olefin-containing feed can include hydrogen gas in an amount of about 25 wt. % or less, or about 20 wt. % or less, or about 15 wt. % or less, or about 10 wt. % or less.
- the olefin-containing feed can have a sulfur content of at least about 100 wppm, or at least about 500 wppm, or at least about 1000 wppm, or at least about 1500 wppm.
- the sulfur content can be about 7000 wppm or less, or about 6000 wppm or less, or about 5000 wppm or less, or about 3000 wppm or less.
- the sulfur may be present as organically bound sulfur.
- the olefin-containing feed can include an inert gas, such as nitrogen (N 2 ).
- the inert gas may be present in the olefin-containing feed in an amount of at least about 0.5 wt. %, at least about 1 wt. %, at least about 5 wt. %, at least about 10 wt. %, at least about 20 wt. %, or at least about 30 wt. %.
- the inert gas may be present in the olefin-containing feed in an amount of about 50 wt. % or less, about 40 wt. % or less, or 30 wt. % or less.
- nitrogen compounds can also be present in the olefin- containing feed.
- the amount of nitrogen can be at least about 5 wppm, or at least about 10 wppm, or at least about 20 wppm, or at least about 40 wppm.
- the nitrogen content can be about 250 wppm or less, or about 150 wppm or less, or about 100 wppm or less, or about 50 wppm or less.
- the olefin-containing feed can include one or more low value refinery streams, such as refinery fuel gas or flue gas from a cracking or coking process.
- the one or more low value streams may be present in the olefin-containing feed in an amount of at least about 50 wt. %, at least about 60 wt. %, at least about 70 wt. %, at least about 80 wt. %, at least about 90 wt. %, at least about 95 wt. %, or at least about 99 wt. %.
- the one or more low value streams may be present in the olefin- containing feed in an amount of about 100 wt. % or less, about 99 wt. % or less, about 95 wt. % or less, about 90 wt. % or less, about 80 wt. % or less, about 70 wt. % or less, or about 60 wt. % or less.
- the olefin-containing feed can include a refinery fuel gas from an FCC unit, such as in the amounts discussed above.
- the refinery fuel gas can include a C 4 - cut of the product effluent of an FCC unit.
- the refinery fuel gas from an FCC unit can include any combination of the properties of the olefin-containing feed discussed above.
- any type of FCC process or system can be utilized to produce a refinery fuel gas that can be included in the olefin-containing feed.
- a feed such as a feed boiling in the range of about 430°F to about 1050°F (221°C to 566°C) or higher, can be contacted with a conventional catalytic cracking catalyst under cracking conditions to produce a product effluent.
- the product effluent can be fractionated into a refinery fuel gas stream, a catalytic naphtha stream, a light cycle oil stream, and an FCC bottoms stream.
- such a fractionated refinery fuel gas stream can be utilized in the olefin-containing feed described herein.
- at least majority of C3-C4 compounds can also be fractionated out of the fuel gas.
- the olefin-containing feed can pass through a heavy hydrocarbon liquid stream in a primary absorber to remove at least a portion of the heavy hydrocarbons, such as C3+, C4+, and/or C5+ hydrocarbons, from the olefin-containing feed.
- the heavy hydrocarbon liquid stream can be any type of conventional heavy hydrocarbon liquid stream utilized in conventional primary absorbers.
- the heavy hydrocarbon liquid stream can be a C5+ hydrocarbon liquid stream.
- the heavy hydrocarbon liquid stream can be a naphtha boiling range stream.
- the naphtha boiling range stream can be a catalytic naphtha stream of a product effluent of a FCC unit.
- At least a portion of the catalytic naphtha stream and at least a portion of the olefin-containing feed can be different fractions of a product effluent of an FCC unit or other cracking process.
- the heavy hydrocarbon liquid stream can be a virgin naphtha stream or wild naphtha from FCC or coker main fractionator overhead system.
- any conventional primary absorber can be used in the systems and processes described herein.
- a pressurized gaseous feed e.g., the olefin-containing feed described herein
- a first effluent is formed.
- This first effluent can include a reduced level of C3+, C4+, and/or C5+ hydrocarbons compared to the olefin-containing feed.
- the first effluent can be a wet gas compressor outlet stream with or without effluent cooler and separator.
- the effluent having a reduced content of C3+ hydrocarbons that exits the primary absorber or wet gas compressor system can be subjected to an optional amine wash (or another conventional sulfur removal method) to remove at least a portion of the sulfur-containing compounds, such as H2S, present in the effluent having a reduced content of C3+ hydrocarbons.
- an optional amine wash or another conventional sulfur removal method
- Any conventional amine wash process is suitable.
- a non-limiting list of amine-containing compounds that can be used in an amine wash include diethanolamine, monoethanolamine, methyldiethanolamine, diisopropanolamine, and aminoethoxyethanol (diglycolamine).
- the effluent having a reduced content of C3+ hydrocarbons in the optional amine wash, can be exposed to one or more amine-containing compounds to remove at least a portion of the H2S or other sulfur-containing compounds present in the effluent having a reduced content of C3+ hydrocarbons to form a second or desulfurized effluent, which includes at least a portion of the remainder of the original olefin-containing feed.
- the effluent having a reduced content of C3+ hydrocarbons or the desulfurized effluent from the amine wash can be exposed to an acidic catalyst (such as a zeolite) under effective conversion conditions for olefinic oligomerization.
- an acidic catalyst such as a zeolite
- the zeolite or other acidic catalyst can also include a metal function, such as a Group VIII metal or other suitable metal or combinations of metals.
- the desulfurized effluent can be exposed to the acidic catalyst without providing preferably any additional hydrogen to the reaction environment.
- Added hydrogen refers to hydrogen introduced as an input flow to the process, as opposed to any hydrogen that might be generated in-situ during processing or comes along with the process feedstream.
- Exposing the desulfurized effluent to an acidic catalyst without providing added hydrogen is defined herein as exposing the feed to the catalyst in the presence of a) less than about 100 SCF/bbl of added hydrogen, or less than about 50 SCF/bbl; b) a partial pressure of less than about 50 psig (350 kPag), or less than about 15 psig (100 kPag) of hydrogen; c) a combination thereof.
- exposing the desulfurized effluent to an acidic catalyst without providing added hydrogen is explicitly defined to include the situation where no added hydrogen is present and/or where the partial pressure of hydrogen is 0 to within one decimal place (i.e., less than about 0.1 psig, or less than about 1 kPag).
- the acidic catalyst used in the processes described herein can be a zeolite-based catalyst, that is, it can comprise an acidic zeolite in combination with a binder or matrix material such as alumina, silica, or silica-alumina, and optionally further in combination with a hydrogenation metal. More generally, the acidic catalyst can correspond to a molecular sieve (such as a zeolite) in combination with a binder, and optionally a hydrogenation metal. Molecular sieves for use in the catalysts can be medium pore size zeolites, such as those having the framework structure of ZSM-5, ZSM-11, ZSM-12, ZSM-22, ZSM-23, ZSM-35, ZSM-48, or MCM-22.
- Such molecular sieves can have a 10-member ring as the largest ring size in the framework structure.
- the medium pore size zeolites are a well-recognized class of zeolites and can be characterized as having a Constraint Index of 1 to 12. Constraint Index is determined as described in U.S. Pat. No. 4,016,218 incorporated herein by reference. Catalysts of this type are described in U.S. Pat. Nos. 4,827,069 and 4,992,067 which are incorporated herein by reference and to which reference is made for further details of such catalysts, zeolites and binder or matrix materials.
- catalysts based on large pore size framework structures such as the synthetic faujasites, especially zeolite Y, such as in the form of zeolite USY.
- Zeolite beta may also be used as the zeolite component.
- Other materials of acidic functionality which may be used in the catalyst include the materials identified as MCM-36 and MCM-49.
- Still other materials can include other types of molecular sieves having suitable framework structures, such as silicoaluminophosphates (SAPOs), aluminosilicates having other heteroatoms in the framework structure, such as Ga, Sn, or Zn, or silicoaluminophosphates having other heteroatoms in the framework structure.
- SAPOs silicoaluminophosphates
- Mordenite or other solid acid catalysts can also be used as the catalyst.
- the exposure of the desulfurized effluent to the acidic catalyst can be performed in any convenient manner, such as exposing the olefin-containing feed or the desulfurized effluent to the acidic catalyst under fluidized bed conditions.
- the particle size of the catalyst can be selected in accordance with the fluidization regime which is used in the process. Particle size distribution can be important for maintaining turbulent fluid bed conditions as described in U.S. Pat. No. 4,827,069 and incorporated herein by reference. Suitable particle sizes and distributions for operation of dense fluid bed and transport bed reaction zones are described in U.S. Pat. Nos. 4,827,069 and 4,992,607 both incorporated herein by reference. Particle sizes in both cases will normally be in the range of 10 to 300 microns, typically from 20 to 100 microns.
- Acidic zeolite catalysts suitable for use as described herein can be those exhibiting high hydrogen transfer activity and having a zeolite structure of ZSM-5, ZSM-11, ZSM-12, ZSM-22, ZSM-23, ZSM-35, ZSM-48, MCM-22, MCM-36, MCM-49, zeolite Y, and zeolite beta.
- Such catalysts can be capable of oligomerizing olefins from the desulfurized effluent.
- such catalysts can convert C2-C4 olefins, such as those present in a fuel gas from an FCC unit, to C5+ olefins.
- Such catalysts can also be capable of converting organic sulfur compounds such as mercaptans to hydrogen sulfide without added hydrogen by utilizing hydrogen present in the olefin-containing feed or the desulfurized effluent.
- Group VIII metals such as nickel may be used as desulfurization promoters.
- a fluid-bed reactor/regenerator can assist with maintaining catalyst activity in comparison with a fixed-bed system.
- suitable zeolites having a coordinated metal oxide to silica molar ratio of 20: 1 to 200: 1 or higher may be used, it can be advantageous to employ aluminosilicate ZSM-5 having a silica: alumina molar ratio of about 25 : 1 to 70: 1, suitably modified.
- a typical zeolite catalyst component having Bronsted acid sites can comprises, consist essentially of, or consist of crystalline aluminosilicate having the structure of ZSM-5 zeolite with 5 to 95 wt. % silica, clay and/or alumina binder.
- siliceous zeolites can be employed in their acid forms, ion-exchanged or impregnated with one or more suitable metals, such as Ga, Pd, Zn, Ni, Co, Mo, P, and/or other metals of Periodic Groups III to VIII.
- suitable metals such as Ga, Pd, Zn, Ni, Co, Mo, P, and/or other metals of Periodic Groups III to VIII.
- the zeolite may include other components, generally one or more metals of group IB, IIB, IIIB, VA, VIA or VIIIA of the Periodic Table (IUPAC).
- Useful metals can include the noble metals of Group VIIIA, such as platinum, but other noble metals, such as palladium, gold, silver, rhenium or rhodium, may also be used.
- Base metal hydrogenation components may also be used, such as nickel, cobalt, molybdenum, tungsten, copper or zinc.
- the catalyst materials may include two or more catalytic components which components may be present in admixture or combined in a unitary multifunctional solid particle.
- the gallosilicate, ferrosilicate and "silicalite” materials may be employed.
- ZSM-5 zeolites can be useful in the process because of their regenerability, long life and stability under the extreme conditions of operation.
- the zeolite crystals have a crystal size from about 0.01 to over 2 microns or more, such as 0.02-1 micron.
- the fluidized bed catalyst particles can contain about 25 wt. % to about 40 wt.% H-ZSM-5 zeolite, based on total catalyst weight, contained within a silica-alumina matrix.
- Typical Alpha values for the catalyst can be about 100 or less. Sulfur conversion to hydrogen sulfide can increase as the alpha value increases.
- the desulfurized effluent may be exposed to the acidic catalyst by using a moving or fluid catalyst bed reactor.
- the catalyst may be regenerated, such via continuous oxidative regeneration.
- the extent of coke loading on the catalyst can then be continuously controlled by varying the severity and/or the frequency of regeneration.
- a turbulent fluidized catalyst bed the conversion reactions are conducted in a vertical reactor column by passing hot reactant vapor upwardly through the reaction zone and/or reaction vessel at a velocity greater than dense bed transition velocity and less than transport velocity for the average catalyst particle.
- a continuous process is operated by withdrawing a portion of coked catalyst from the reaction zone and/or reaction vessel, oxidatively regenerating the withdrawn catalyst and returning regenerated catalyst to the reaction zone at a rate to control catalyst activity and reaction severity to effect feedstock conversion.
- Preferred fluid bed reactor systems are described in Avidan et al U.S. Pat. No. 4,547,616; Harandi & Owen U.S. Pat. No. 4,751,338; and in Tabak et al U.S. Pat. No. 4,579,999, incorporated herein by reference.
- other types of reactors can be used, such as fixed bed reactors, riser reactors, fluid bed reactors, and/or moving bed reactors.
- the effective conversion conditions are chosen to increase the oligomerization of the olefins present in the olefin-containing feed or desulfurized effluent.
- the effective conversion conditions may include a temperature of from about 700°F (371°C) to about 800°F (427°C), or of from about 750°F (399°C) to about 800°F (427°C); and a pressure of about 150 psig (1.03 MPag) to about 200 psig (1.4 MPag), or about 300 psig (4.1 MPag) or less.
- the goal would be to increase or maximize production of naphtha boiling range compounds, which occurs at 700°F (371°C) or less.
- the effective conversion conditions for exposing the olefin- containing feed or the desulfurized effluent to an acidic catalyst can generally include a temperature of about 650°F (343°C) to about 1000°F (537°C).
- naphtha products can be increased at a temperature of about 750°F (399°C) or less.
- olefin oligomerization can be increased at a temperature of from about 700°F (371°C) to about 800°F (427°C), or of from about 750°F (399°C) to about 800°F (427°C).
- a higher temperature range such as about 700°F (371°C) to about 800°F (427°C), or about 750°F (399°C) to about 800°F (427°C)
- naphtha yield is reduced, but the overall level of C2-C3 olefin conversion is increased.
- the refinery fuel gas product produced in the processes described herein will be improved, as more olefins and/or C2+ compounds will have been oligomerized and removed prior to burning the refinery fuel gas product, which can reduce NOx production.
- the effective conversion conditions for exposing the olefin- containing feed or the desulfurized effluent gas to an acidic catalyst can include a pressure of about 50 psia (0.34 MPa) to about 350 psig (2.4 MPag), or about 100 psig (0.69 MPag) to about 300 psig (4.1 MPag), or about 150 psig (1.03 MPag) to about 200 psig (1.4 MPag), or a pressure of about 350 psig (2.4 MPag) or less, or a pressure of about 300 psig (4.1 MPag) or less; and a weight hourly space velocity of about 0.05 hr 1 to about 20 hr 1 , or about 0.05 to about 10 hr 1 , or about 0.1 to about 10 hr 1 , or about 0.1 to about 2 hr 1 , or about 0.1 hr 1 to about 1.0 hr 1 , or about 0.1 hr 1 to about 0.75
- temperatures of about 550°F (260°C) to about 700°F (371°C) can provide a beneficial combination of reactivity and run length. Temperatures below 550°F can result in high rates of catalyst deactivation, which leads to reduced reactivity extent of oligomerization reaction.
- exposing the desulfurized effluent to the conversion conditions discussed above can produce an oligomerized effluent that includes oligomerized olefins.
- this oligomerized effluent can include an increased C5+ content and/or an increased amount of naphtha boiling range compounds compared to the olefin-containing feed or the desulfurized effluent.
- % of the olefins from the olefin- containing feed or the desulfurized effluent can be incorporated into the oligomerized olefins in the oligomerized effluent.
- An oligomerized effluent can contain olefins, saturates and aromatics.
- the oligomerized olefins in the oligomerized effluent can be subjected to saturation conditions to saturate at least a portion of the oligomerized olefins.
- hydrogen present in the oligomerized effluent can be utilized to saturate the oligomerized olefins. This can provide an economical way to utilize the hydrogen present in the oligomerized effluent to increase the volume of the oligomerized olefins, which may ultimately be processed into a gasoline or other valuable product.
- the optional saturation step can also increase the degree of desulfurization of naphtha in the overall process.
- Hydrofinishing catalysts can include catalysts containing Group VI metals, Group VIII metals, and mixtures thereof.
- preferred metals include at least one metal sulfide having a strong hydrogenation function, such as Ni, NiW, NiMo, NiMoW, Co, C0M0, or CoW.
- the hydrofinishing catalyst can include a Group VIII noble metal, such as Pt, Pd, or a combination thereof.
- the mixture of metals may also be present as bulk metal catalysts wherein the amount of metal is about 30 wt. % or greater based on catalyst.
- Suitable metal oxide supports include low acidic oxides such as silica, alumina, silica-aluminas or titania, preferably alumina.
- the preferred hydrofinishing catalysts will comprise at least one metal having relatively strong hydrogenation function on a porous support.
- Typical support materials include amorphous or crystalline oxide materials such as alumina, silica, and silica-alumina.
- the support materials may also be modified, such as by halogenation, or in particular fluorination.
- the metal content of the catalyst is often as high as about 20 weight percent for non-noble metals.
- a preferred hydrofinishing catalyst can include a crystalline material belonging to the M41S class or family of catalysts.
- the M41 S family of catalysts are mesoporous materials having high silica content. Examples include MCM-41, MCM-48 and MCM-50. A preferred member of this class is MCM-41.
- Hydrofinishing conditions can include temperatures from about 125°C (257°F) to about 425°C (797°F), or about 180°C (356°F) to about 280°C (536°F); a total pressure from about 200 psig (1.4 MPa) to about 800 psig (5.5 MPa), or about 400 psig (2.8 MPa) to about 700 psig (4.8 MPa); and a liquid hourly space velocity from about 0.1 hr 1 to about 5 hr 1 LHSV, preferably about 0.5 hr 1 to about 1.5 hr 1 .
- a conventional hydrotreating catalyst for reducing sulfur content could be used to saturate at least a portion of the oligomerized olefins present in the oligomerized effluent.
- the gas phase reaction pressure of the oligomerization reactor effluent after a cooler can be used as the hydrogen-containing treat gas to prevent additional processing before hydrofinishing.
- Conventional hydrotreating catalysts for reducing sulfur content include catalysts composed of a Group VIB metal (Group 6 of IUPAC periodic table) and/or a Group VIII metal (Groups 8 - 10 of IUPAC periodic table) on a support. Suitable metals include cobalt, nickel, molybdenum, tungsten, or combinations thereof. Suitable supports include silica, silica-alumina, alumina, and titania.
- the oligomerized effluent can be exposed to the hydrotreating catalyst under conventional hydrotreating conditions and/or the hydrofinishing conditions described above.
- the oligomerized olefins from the oligomerized effluent can be removed. Any conventional refinery processes, such as the use of a sponge absorber and/or a refrigeration system, can be utilized to remove at least a portion of the oligomerized olefins from the oligomerized effluent.
- a sponge absorber in a sponge absorber, the oligomerized effluent can be exposed to a hydrocarbon liquid sorbent stream or sponge oil.
- hydrocarbon liquid sorbent streams includes a naphtha stream (e.g., a stripped heavy naphtha), light fuel oil, light cycle oil, or a combination thereof.
- the hydrocarbon liquid sorbent stream or sponge oil can have an initial or T5 boiling point of at least about 70°C (158°F), at least about 80°C (176°F), or at least about 90°C (194°F), and/or a T80 boiling point of less than about 315°C (600°F), less than about 288°C (550°F), or less than about 260° (500°F).
- the oligomerized effluent can be exposed to a countercurrent flow of a hydrocarbon liquid sorbent stream to remove at least a portion of oligomerized olefins from the oligomerized effluent to form a fourth or light hydrocarbon effluent.
- the light hydrocarbon effluent can include at least about 20 wt. %, at least about 30 wt. %, at least about 40 wt. %, at least about 50 wt. %, at least about 75 wt. %, at least about 85 wt. %, or at least about 95 wt. % less C3+oligomerized olefins than the oligomerized effluent. Additional Amine Wash
- the light hydrocarbon effluent may be subjected to an amine wash to remove at least a portion of sulfur-containing compounds present therein, such as H2S that may have been formed during the olefin oligomerization process.
- Any conventional amine wash process is suitable, such as the amine wash processes discussed above.
- the product effluent resulting from the amine wash can include a refinery fuel gas product.
- the rich amine from the additional amine wash can be cascaded as lean amine to the first amine wash. This can reduce or minimize the amine regeneration cost.
- the refinery fuel gas product can include less olefins, less sulfur, and/or less nitrogen than the initial olefin-containing feed, which can provide a more controlled energy output when burned in refinery furnaces, and provide reduced NOx and/or SOx emissions.
- the refinery fuel gas product includes at least about 40 wt. % less C2-C4 olefins than the initial olefin-containing feed, at least about 50 wt. % less, at least about 60 wt. % less, at least about 70 wt. % less, at least about 80 wt. % less, at least about 90 wt. % less, or at least about 95 wt. % less.
- the refinery fuel gas product includes at least about 40 wt. % less C2-C5 olefins than the initial olefin-containing feed, at least about 50 wt. % less, at least about 60 wt. % less, at least about 70 wt. % less, at least about 80 wt. % less, at least about 90 wt. % less, or at least about 95 wt. % less.
- the refinery fuel gas product can include at least methane, ethane, and propane.
- the refinery fuel gas product can further comprise at least about 5 wt% C2 compounds, or at least about 10 wt%; about 5 wt% or less of C3+ compounds, or about 2 wt% or less; and/or about 5 wt% or less of olefins, or about 2 wt% or less.
- the organic sulfur content (i.e., excluding H2S) of the refinery fuel gas product can be about 500 wppm or less, or about 100 wppm or less, or about 50 wppm or less, or about 30 wppm or less, or about 20 wppm or less, or about 10 wppm or less.
- the organic sulfur content of the refinery fuel gas product can be reduced by at least about 50%, or at least about 60%, or at least about 70%, or at least about 80%, or at least about 90%, or at least about 95% relative to the sulfur content of the initial olefin-containing feed.
- the organic nitrogen content of the refinery fuel gas product can be reduced by at least about 10%, or at least about 30%, or at least about 50%, or at least about 70%, or at least about 90% relative to the nitrogen content of the initial olefin-containing feed.
- the refinery fuel gas product can have a heating value of at least about 850 BTU/SCF, at least about 900 BTU/SCF, at least about 950 BTU/SCF, or at least about 1000 BTU/SCF.
- the refinery fuel gas product can have a heating value of about 1500 BTU/SCF or less, about 1400 BTU/SCF or less, about 1300 BTU/SCF or less, about 1200 BTU/SCF or less, about 1100 BTU/SCF or less, or about 1050 BTU/SCF or less.
- FIG. 1 depicts one example of a system 100 for producing a refinery fuel gas product from an olefin-containing feed.
- the olefin-containing feed includes a refinery fuel gas stream 110 from an FCC unit 104, but any other convenient source of a refinery fuel gas containing olefins could also be used.
- a feed 102 is subjected to catalytic cracking conditions and the resulting effluent 106 can be subjected to a conventional fractionator 108.
- the fractionator 108 can separate the effluent 106 into a refinery fuel gas stream 110 and a catalytic naphtha stream 112.
- the fuel gas stream 110 and the catalytic naphtha stream 112 can have any or all of the respective properties discussed above.
- the fuel gas stream 110 is exposed to a countercurrent flow of a liquid sorbent stream that includes the catalytic naphtha stream 112, to thereby absorb at least a portion of the C3+ compounds present in the refinery fuel gas stream 110.
- the resulting effluent gas stream 116 is then subjected to a conventional amine wash 118, such as the amine wash discussed above, to remove at least a portion of the sulfur-containing compounds present in the effluent gas stream 116.
- the gas stream effluent 120 can be exposed to a conversion catalyst in the conversion reactor 122, such as one or more of the acidic catalysts discussed above.
- the conversion reactor 122 can be a fiuidized bed reactor.
- a portion 124 of the conversion catalyst in the conversion reactor 122 can be sent to a regenerator 126 for regeneration.
- the regenerated catalyst 128 can be returned to the conversion reactor 122.
- the conversion conditions in the conversion reactor 122 can be maximized to oligomerize at least a portion of the olefins present in the gas stream effluent 120.
- the effluent 130 exiting the conversion reactor 122 can include C5+ olefins, such as in the amounts discussed above.
- the effluent 130 can then be subjected to a sponge absorber 132, such as the sponge absorber discussed above, to remove at least a portion of the C5+ olefins present in the effluent 130.
- the effluent 134 exiting the sponge absorber 132 can then be subjected to another amine wash 136 to remove at least a portion of the sulfur-containing compounds present in the effluent 134.
- the resulting product effluent 138 includes a refinery fuel gas product, such as the refinery fuel gas product discussed above.
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- Organic Chemistry (AREA)
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- Chemical Kinetics & Catalysis (AREA)
- General Chemical & Material Sciences (AREA)
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- Production Of Liquid Hydrocarbon Mixture For Refining Petroleum (AREA)
Abstract
L'invention concerne des systèmes et procédés destinés à valoriser le gaz combustible de raffinerie et/ou la production de naphte à partir de gaz combustible de raffinerie. Tout d'abord, une charge contenant des oléfines peut être exposée à des conditions classiques pour l'élimination d'une partie de composés C3+ et d'une partie de composés contenant du soufre.<sb /> La charge contenant des oléfines peut être ensuite exposée à des conditions de conversion pour l'oligomérisation des oléfines présentes dans la charge contenant des oléfines, produisant un effluent qui comprend des oléfines C5+.<sb /> Les oléfines C5+ peuvent être éliminées de l'effluent, et l'effluent peut être soumis à un lavage à l'amine pour l'élimination des composés contenant du soufre.<sb /> L'effluent de produit résultant comprend un produit de gaz combustible de raffinerie possédant une valeur calorifique maîtrisée.
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US201662280336P | 2016-01-19 | 2016-01-19 | |
US62/280,336 | 2016-01-19 |
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WO2017127288A1 true WO2017127288A1 (fr) | 2017-07-27 |
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PCT/US2017/013282 WO2017127288A1 (fr) | 2016-01-19 | 2017-01-13 | Production de naphte à partir de gaz combustible de raffinerie |
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Cited By (2)
Publication number | Priority date | Publication date | Assignee | Title |
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WO2021127322A1 (fr) * | 2019-12-19 | 2021-06-24 | Kellogg Brown & Root Llc | Procédé de préparation d'alimentation à l'aide de colonne à cloison et/ou de colonne classique pour unité de craquage catalytique ciblant la production d'oléfines |
WO2022132369A1 (fr) * | 2020-12-16 | 2022-06-23 | Exxonmobil Chemical Patents Inc. | Procédés et systèmes de valorisation d'une charge contenant des hydrocarbures |
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Cited By (4)
Publication number | Priority date | Publication date | Assignee | Title |
---|---|---|---|---|
WO2021127322A1 (fr) * | 2019-12-19 | 2021-06-24 | Kellogg Brown & Root Llc | Procédé de préparation d'alimentation à l'aide de colonne à cloison et/ou de colonne classique pour unité de craquage catalytique ciblant la production d'oléfines |
CN114901374A (zh) * | 2019-12-19 | 2022-08-12 | 凯洛格·布朗及鲁特有限公司 | 使用分隔壁塔和/或传统塔制备用于针对烯烃生产的催化裂化单元的进料的方法 |
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WO2022132369A1 (fr) * | 2020-12-16 | 2022-06-23 | Exxonmobil Chemical Patents Inc. | Procédés et systèmes de valorisation d'une charge contenant des hydrocarbures |
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