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
  • C10G9/00—Thermal non-catalytic cracking, in the absence of hydrogen, of hydrocarbon oils
  • C10G9/005—Coking (in order to produce liquid products mainly)
• • B—PERFORMING OPERATIONS; TRANSPORTING
  • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
  • B01D—SEPARATION
  • B01D3/00—Distillation or related exchange processes in which liquids are contacted with gaseous media, e.g. stripping
  • B01D3/14—Fractional distillation or use of a fractionation or rectification column
  • B01D3/143—Fractional distillation or use of a fractionation or rectification column by two or more of a fractionation, separation or rectification step
• • C—CHEMISTRY; METALLURGY
  • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
  • C10B—DESTRUCTIVE DISTILLATION OF CARBONACEOUS MATERIALS FOR PRODUCTION OF GAS, COKE, TAR, OR SIMILAR MATERIALS
  • C10B55/00—Coking mineral oils, bitumen, tar, and the like or mixtures thereof with solid carbonaceous material
  • C10B55/02—Coking mineral oils, bitumen, tar, and the like or mixtures thereof with solid carbonaceous material with solid materials
  • C10B55/04—Coking mineral oils, bitumen, tar, and the like or mixtures thereof with solid carbonaceous material with solid materials with moving solid materials
  • C10B55/06—Coking mineral oils, bitumen, tar, and the like or mixtures thereof with solid carbonaceous material with solid materials with moving solid materials according to the "moving bed" type
• • C—CHEMISTRY; METALLURGY
  • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
  • C10B—DESTRUCTIVE DISTILLATION OF CARBONACEOUS MATERIALS FOR PRODUCTION OF GAS, COKE, TAR, OR SIMILAR MATERIALS
  • C10B55/00—Coking mineral oils, bitumen, tar, and the like or mixtures thereof with solid carbonaceous material
  • C10B55/02—Coking mineral oils, bitumen, tar, and the like or mixtures thereof with solid carbonaceous material with solid materials
  • C10B55/04—Coking mineral oils, bitumen, tar, and the like or mixtures thereof with solid carbonaceous material with solid materials with moving solid materials
  • C10B55/08—Coking mineral oils, bitumen, tar, and the like or mixtures thereof with solid carbonaceous material with solid materials with moving solid materials in dispersed form
  • C10B55/10—Coking mineral oils, bitumen, tar, and the like or mixtures thereof with solid carbonaceous material with solid materials with moving solid materials in dispersed form according to the "fluidised bed" technique
• • 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
• • 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
• • 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
• • 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
  • C10G65/00—Treatment of hydrocarbon oils by two or more hydrotreatment processes only
• • 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
  • C10G67/00—Treatment of hydrocarbon oils by at least one hydrotreatment process and at least one process for refining in the absence of hydrogen only
  • C10G67/02—Treatment of hydrocarbon oils by at least one hydrotreatment process and at least one process for refining in the absence of hydrogen only plural serial stages only
  • C10G67/04—Treatment of hydrocarbon oils by at least one hydrotreatment process and at least one process for refining in the absence of hydrogen only plural serial stages only including solvent extraction as the refining step in the absence of hydrogen
  • C10G67/0409—Extraction of unsaturated hydrocarbons
• • 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
  • C10G67/00—Treatment of hydrocarbon oils by at least one hydrotreatment process and at least one process for refining in the absence of hydrogen only
  • C10G67/02—Treatment of hydrocarbon oils by at least one hydrotreatment process and at least one process for refining in the absence of hydrogen only plural serial stages only
  • C10G67/06—Treatment of hydrocarbon oils by at least one hydrotreatment process and at least one process for refining in the absence of hydrogen only plural serial stages only including a sorption process as the refining step in the absence of hydrogen
• • 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
  • C10G69/06—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 step of thermal cracking in the absence of hydrogen
• • 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
  • C10G69/14—Treatment of hydrocarbon oils by at least one hydrotreatment process and at least one other conversion process plural parallel stages only
• • 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
  • C10G7/00—Distillation of hydrocarbon oils
  • C10G7/06—Vacuum distillation
• • 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
  • C10G9/34—Thermal non-catalytic cracking, in the absence of hydrogen, of hydrocarbon oils by direct contact with inert preheated fluids, e.g. with molten metals or salts
  • C10G9/36—Thermal non-catalytic cracking, in the absence of hydrogen, of hydrocarbon oils by direct contact with inert preheated fluids, e.g. with molten metals or salts with heated gases or vapours
• • 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
  • C10G2300/1037—Hydrocarbon fractions
  • C10G2300/1048—Middle distillates
• • 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
  • C10G2300/1077—Vacuum residues
• • 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
• • 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
  • C10G2400/04—Diesel oil
• • 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
  • C10G2400/06—Gasoil
• • 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
  • C10G2400/10—Lubricating oil

Definitions

• the invention relates to an integrated process for producing petrochemicals and fuel product from a crude oil feed.
• the integrated process includes an initial separation step to separate from a crude oil feed in an atmospheric distillation zone at least a fraction comprising straight run naphtha and lighter components, one or more middle distillate fractions, and an atmospheric residue fraction.
• a vacuum gas oil fraction is separated from the atmospheric residue fraction in a vacuum distillation zone.
• a distillate hydroprocessing ("DHP") zone such as a diesel hydrotreater, at least a portion of the middle distillates are processed to produce a naphtha fraction and a diesel fuel fraction.
• DHP distillate hydroprocessing
• FIG. 4 schematically depicts operations downstream of and including a steam cracker complex in embodiments of processes for producing petrochemicals integrating metathesis
• FIG. 5 schematically depicts operations downstream of and including a steam cracker complex in embodiments of processes for producing petrochemicals and fuel products integrating mixed butanol production;
• FIGs. 7 and 8 schematically depict operations upstream of a steam cracker complex in further embodiments of processes for producing petrochemicals and fuel product;
• LPG refers to the well-known acronym for the term “liquefied petroleum gas,” and generally is a mixture of C3-C4 hydrocarbons. In certain embodiments, these are also referred to as “light ends.”
• diesel is used with reference to a straight run fraction from the atmospheric distillation unit.
• the diesel fraction refers to medium AGO range hydrocarbons and in certain embodiments also in combination with heavy kerosene range hydrocarbons.
• Kerosene fuel or “kerosene fuel products” refer to fuel products used as energy carriers, such as jet fuel or other kerosene range fuel products (and precursors for producing such jet fuel or other kerosene range fuel products).
• Kerosene fuel includes but is not limited to kerosene fuel products meeting Jet A or Jet A- 1 jet fuel specifications.
• wild naphtha is used herein to refer to naphtha products derived from hydroprocessing units such as distillate hydroprocessing units, diesel hydroprocessing units and/or gas oil hydroprocessing units.
• C4 Raffinate 3 or “C4 Raff-3” refers to the mixed C4s stream leaving the C4 distillation unit, that is, mixed C4s from the crude C4 except butadiene, isobutene, and butane- 1.
• pyrolysis gasoline and its abbreviated form “py-gas” are used herein having their well-known meaning, that is, thermal cracking products in the range of C5 to C9, for instance having an end boiling point of about 204.4°C (400°F), in certain embodiments up to about 148.9°C (300°F).
• a distillate hydroprocessing (“DHP") zone such as a diesel hydrotreater
• DHP distillate hydroprocessing
• first DHP fraction comprises naphtha
• second DHP fraction is used for diesel fuel production.
• the first vacuum distillation zone fraction (and optionally all or a portion of an atmospheric gas oil fraction, or all or a portion of a heavy atmospheric gas oil fraction) is processed in a gas oil hydroprocessing zone to produce naphtha, middle distillates, and hydrotreated gas oil and/or unconverted oil. Hydrotreated gas oil and/or unconverted oil are processed in the gas oil steam cracking zone.
• the mixed feed steam cracking zone and the gas oil steam cracking zone are shown for simplicity in a single schematic block 230/250 in FIGs. 3, 4, 5 and 6.
• both the mixed feed steam cracking zone 230 and the gas oil steam cracking zone 250 are collectively referred to as the "steam cracker complex" 230/250 in certain instances, although a person having ordinary skill in the art will appreciate that the different steam cracking zones contain different furnaces and associated exchangers, with certain products from each combined for further downstream operations.
• quench systems and fractionation units can be combined.
• separate quench systems and fractionation units can be used for each of the mixed feed steam cracking zone 230 and the gas oil steam cracking zone 250.
• Straight run naphtha 136 from the atmospheric distillation zone 110 is passed to the mixed feed steam cracking zone 230.
• all, a substantial portion or a significant portion of the straight run naphtha 136 is routed to the mixed feed steam cracking zone 230.
• Remaining naphtha (if any) can be added to a gasoline pool.
• the straight run naphtha stream 136 contains naphtha from other sources as described herein and sometimes referred to as wild naphtha, for instance, naphtha range hydrocarbons from one or more of the integrated distillate, gas oil and/or residue hydroprocessing units.
• all or a portion of the liquefied petroleum gas produced in the vacuum gas oil hydroprocessing zone can be passed with the wild naphtha.
• Heavy product from the vacuum gas oil hydroprocessing zone is routed to the gas oil steam cracking zone 250.
• heavy product is the hydrotreated gas oil fraction 304 that contains the portion of the vacuum gas oil hydrotreater 300 effluent that is at or above the AGO, H-AGO or VGO boiling range.
• heavy product is the unconverted oil fraction 324.
• all, a substantial portion, a significant portion or a major portion of heavy product from the vacuum gas oil hydroprocessing zone is routed to the gas oil steam cracking zone 250.
• the mixed feed steam cracking zone 230 and the gas oil steam cracking zone 250 operate to convert their respective feeds into ethylene 202, propylene 204, mixed C4s 206, pyrolysis gasoline 212, pyrolysis oil 218, and off-gases 208 that can be passed to an integrated fuel gas system. Further, hydrogen 210 is recovered from the cracked products and can be recycled to hydrogen users within the complex limits. Not shown are the ethane and propane recycle, which are typical in steam cracking operations, although it is appreciated that in certain embodiments all or a portion of the ethane and propane can be diverted.
• all, a substantial portion, a significant portion or a major portion of ethane is recycled to the mixed feed steam cracking zone 230, and all, a substantial portion, a significant portion or a major portion of propane is mixed feed steam cracking zone 230.
• hydrogen for all hydrogen users in the integrated process and system is derived from hydrogen 210 recovered from the cracked products, and no outside hydrogen is required once the process has completed start-up and reached equilibrium. In further embodiments excess hydrogen can be recovered.
• Separation of the ethylene 202, propylene 204 and the mixed C4s stream 206 occurs in a suitable arrangement of known separation steps for separating steam cracking zone effluents, including compression stage(s), depropanizer, debutanizer, demethanizer and deethanizer.
• pyrolysis oil 218 can be blended into the fuel oil pool.
• pyrolysis oil 218 can be fractioned (not shown) into light pyrolysis oil and heavy pyrolysis oil.
• light pyrolysis oil can be blended with the first middle distillate stream 116 and/or the second middle distillate stream 122 to produce diesel fuel product and/or additional feed to the mixed feed steam cracking zone 230.
• light pyrolysis oil derived from pyrolysis oil 218 can be processed in the vacuum gas oil hydroprocessing zone.
• light pyrolysis oil derived from pyrolysis oil 218 can be blended into the fuel oil pool.
• light pyrolysis oil derived from pyrolysis oil 218 can be processed in the delayed coking zone 900. In certain embodiments, all, a substantial portion, a significant portion or a major portion of light pyrolysis oil can be processed in the delayed coking zone 900. Heavy pyrolysis oil can be processed in the delayed coking zone 900, blended into the fuel oil pool, and/or used as a carbon black feedstock. In certain embodiments, all, a substantial portion, a significant portion or a major portion of the pyrolysis oil 218 (light and heavy) can be processed in the delayed coking zone 900.
• C5 raffinate is recycled to the mixed feed steam cracking zone 230 (as in the embodiments of FIG. 3) via stream 606, shown in dashed lines in FIG. 4.
• all or a portion of the cracked C5s from the py-gas hydrotreater can be routed to the metathesis unit 530 prior to aromatics extraction.
• 0-100% of the third C4 raffinate stream 524 can be routed to the metathesis conversion unit 530, and the remainder (if any) is directed to the mixed feed steam cracking zone 230.
• the quantity can be determined, for instance, based upon demand for ethylene, demand for propylene, and/or minimum ranges for which the unit is operated depending on design capacity.
• Suitable processes to convert a mixture of butenes into mixed butanols are described in one or more of commonly owned patent publications US20160115107A1, US20150225320A1, US20150148572A1, US20130104449A1, US20120245397A1 and commonly owned patents US9447346B2, US9393540B2, US9187388B2, US8558036B2, all of which are incorporated by reference herein in their entireties.
• a particularly effective conversion process known as "SuperButolTM” technology is integrated, which is a one-step process that converts a mixture of butenes into mixed butanol liquids.
• all, a substantial portion, a significant portion or a major portion of the third C4 raffinate stream is routed to the metathesis conversion unit 530, and the remainder (if any) is directed to the mixed feed steam cracking zone 230.
• all, a substantial portion, a significant portion or a major portion of the third C4 raffinate stream is routed to the metathesis conversion unit 530, and the remainder (if any) is directed to the mixed butanols production zone 550 for production of mixed butanols.
• all, a substantial portion, a significant portion or a major portion of the third C4 raffinate stream is routed to the mixed butanols production zone 550 for production of mixed butanols, and the remainder (if any) is directed to the metathesis conversion unit 530.
• the quantity can be determined, for instance, based upon demand for ethylene, demand for propylene, demand for mixed butanols, and/or minimum ranges for which the unit is operated depending on design capacity.
• a hydrogen treat gas feed rate (standard liters per liter of hydrocarbon feed, SLt/Lt) up to about 400, 385, 353 or 337, in certain embodiments from about 256-385, 256-353, 256-337, 289-385, 289-353, 289-337, 305-385, 305-353 or 305-337;
• Recycle hydrogen is recovered, and passed (along with make-up hydrogen) to the reaction zone as treat gas and quench gas.
• the light vacuum gas oil stream 164 and heavy vacuum gas oil stream 166 (or full range VGO, not shown) are processed in a gas oil hydroprocessing zone, in the presence of an effective amount of hydrogen obtained from recycle within the gas oil hydroprocessing zone and make-up hydrogen 302. In certain embodiments, all, a substantial portion, a significant portion or a major portion of the coker gas oil stream 904 is also processed in the gas oil hydroprocessing zone.
• the severity of the gas oil hydroprocessing operation can be used to moderate the relative yield of olefin and aromatic chemicals from the overall complex and improve the economic threshold of cracking heavy feeds.
• This application of a gas oil hydroprocessing zone, as a chemical yield control mechanism, is uncommon in the industry, where fuels products are typically the product objectives.
• the naphtha fraction 326 is routed to the mixed feed steam cracking zone 230.
• the naphtha fraction 326 is routed through the crude complex 100, alone, or in combination with other wild naphtha fractions from within the integrated process.
• all or a portion of the liquefied petroleum gas produced in the gas oil hydrocracking zone 320 can be passed with the naphtha fraction 326.
• the unconverted oil fraction 324 is routed to the gas oil steam cracking zone 250.
• the diesel fuel fraction 322 is recovered as fuel, for instance, compliant with Euro V diesel standards, and can be combined with the diesel fuel fraction 182 from the diesel hydrotreating zone 180.
• Vacuum gas oil hydrocracking zone 320 can operate under mild, moderate or severe conditions, depending on factors including the feedstock and the desired degree of conversion. Such conditions are effective for removal of a significant amount of the sulfur and other known contaminants, and for conversion of the feed(s) into a major proportion of hydrocracked products and minor proportions of off-gases, light ends and unconverted product that is passed to the gas oil steam cracking zone 250.
• the gas oil hydrocracking zone 320 can contain one or more fixed-bed, ebullated- bed, slurry-bed, moving bed, continuous stirred tank (CSTR) or tubular reactors, in series and/or parallel arrangement. Additional equipment, including exchangers, furnaces, feed pumps, quench pumps, and compressors to feed the reactor(s) and maintain proper operating conditions, are well known and are considered part of the gas oil hydrocracking zone 320. In addition, equipment, including pumps, compressors, high temperature separation vessels, low temperature separation vessels and the like to separate reaction products and provide hydrogen recycle within the gas oil hydrocracking zone 320, are well known and are considered part of the gas oil hydrocracking zone 320.
• Effective hydrocracking catalyst generally contain about 5-40 wt% based on the weight of the catalyst, of one or more active metal component of metals or metal compounds (oxides or sulfides) selected from the Periodic Table of the Elements IUPAC Groups 6-10.
• the active metal component is one or more of Mo, W, Co or Ni.
• the active metal component is typically deposited or otherwise incorporated on a support, such as amorphous alumina, amorphous silica alumina, zeolites, or combinations thereof.
• Pt group metals such as Pt and/or Pd, may be present as a hydrogenation component, generally in an amount of about 0.1 -2 wt% based on the weight of the catalyst.
• Suitable hydrocracking catalyst have an expected lifetime in the range of about 18-30, 22-30, 18-26 or 22-26 months.
• Reaction zone 332 generally includes one or more inlets in fluid communication with a source of initial feedstock 334 and a source of hydrogen gas 338. One or more outlets of reaction zone 332 that discharge effluent stream 340 is in fluid communication with one or more inlets of the fractionating zone 342 (typically including one or more high pressure and/or low pressure separation stages therebetween for recovery of recycle hydrogen, not shown).
• reaction outlet pressure in the range of from about 100-150, 100-137, 100-130, 112-150, 112-137, 112-130, 118-150, 118-137 or 118-130;
• a hydrogen partial pressure (barg) in the range of from about 77-116, 77- 106, 77-101, 87-116, 87-106, 87-101, 92-116, 92-106, 92-101 or 94-98;
• a start of run (SOR) reaction temperature as a weighted average bed temperature (WABT), in the range of from about 310-475, 310-435, 310-415, 350-475, 350-435, 350- 415, 370-475, 370-435, 370-415 or 390-397;
• an end of run (EOR) reaction temperature as a WABT, in the range of from about 338-516, 338-471, 338-450, 382-516, 382-471, 382-450, 400-516, 400-471, 400-450 or 422-430;
• liquid hourly space velocity values (h "1 ), on a fresh feed basis relative to the hydrocracking catalysts, are in the range of from about 0.1 -10.0, 0.1-5.0, 0.1-2.0, 0.3- 10.0, 0.3-5.0, 0.3-2.0, 0.4-10.0, 0.4-5.0, 0.4-2.0 or 0.5-3.0.
• series flow hydrocracking zone 350 which operates as series-flow hydrocracking system with recycle to the first reactor zone, the second reactor zone, or both the first and second reactor zones.
• series flow hydrocracking zone 350 includes a first reaction zone 352, a second reaction zone 358 and a fractionating zone 342.
• First reaction zone 352 generally includes one or more inlets in fluid communication with a source of initial feedstock 334, a source of hydrogen gas 338, and in certain embodiments recycle stream 364a comprising all or a portion of the fractionating zone 342 bottoms stream 348 and optionally a portion of fractionating zone 342 product stream 362.
• One or more outlets of the first reaction zone 352 that discharge effluent stream 354 is in fluid communication with one or more inlets of the second reaction zone 358.
• the effluents 354 are passed to the second reaction zone 358 without separation of any excess hydrogen and light gases.
• one or more high pressure and low pressure separation stages are provided between the first and second reaction zones 352, 358 for recovery of recycle hydrogen (not shown).
• a feedstock stream 334 and a hydrogen stream 338 are charged to the first reaction zone 352.
• Hydrogen stream 338 is an effective quantity of hydrogen to support the requisite degree of hydrocracking, feed type, and other factors, and can be any combination including, recycle hydrogen 336 from optional gas separation subsystems (not shown) associated with reaction zones 352 and 358, and/or derived from fractionator gas stream 344 and make-up hydrogen 302.
• a reaction zone can contain multiple catalyst beds and can receive one or more quench hydrogen streams between the beds (not shown).
• First reaction zone 352 operates under effective conditions for production of reaction effluent stream 354 which is passed to the second reaction zone 358 (optionally after one or more high pressure and low pressure separation stages to recover recycle hydrogen), optionally along with an additional hydrogen stream 356.
• Second reaction zone 358 operates under conditions effective for production of the reaction effluent stream 360, which contains converted, partially converted and unconverted hydrocarbons.
• a suitable cut point is in the range of 350 to 450°C, 360 to 450°C, 370 to 450°C, 350 to 400°C, 360 to 400°C, 370 to 400°C, 350 to 380°C, or 360 to 380°C.
• the stream above that cut point is routed to the gas oil steam cracking zone 250 as described herein.
• stream 364a recycled to zone 352 comprises 0 to 100 vol%, in certain embodiments 0 to about 80 vol%, and in further embodiments 0 to about 50 vol% of stream 348
• stream 364b recycled to zone 358 comprises 0 to 100 vol%, in certain embodiments 0 to about 80 vol%, and in further embodiments 0 to about 50 vol% of stream 348.
• a suitable series flow hydrocracking zone 350 can include, but is not limited to, systems based on technology commercially available from Honeywell UOP, US; Chevron Lummus Global LLC (CLG), US; Axens, IFP Group Technologies, FR; or Shell Global Solutions, US.
• the reactor arrangement in the series flow hydrocracking zone 350 can contain one or more fixed-bed, ebullated-bed, slurry-bed, moving bed, continuous stirred tank (CSTR), or tubular reactors, which can be in parallel arrangement. Additional equipment, including exchangers, furnaces, feed pumps, quench pumps, and compressors to feed the reactor(s) and maintain proper operating conditions, are well known and are considered part of the series flow hydrocracking zone 350. In addition, equipment, including pumps, compressors, high temperature separation vessels, low temperature separation vessels and the like to separate reaction products and provide hydrogen recycle within the series flow hydrocracking zone 350, are well known and are considered part of the series flow hydrocracking zone 350.
• an end of run (EOR) reaction temperature as a WABT, in the range of from about 338-516, 338-471, 338-450, 382-516, 382-471, 382-450, 400-516, 400-471, 400-450 or 422-430;
• a reactor outlet temperature in the range of from about 350-516, 350-471, 350-450, 382-516, 382-471, 382-450, 400-516, 400-471, 400-450 or 422-430;
• make-up hydrogen rate up to about 372, 338, 323 or 309, in certain embodiments from about 250-338, 250-323, 250-309, 264-338, 264-323, 264-309, 279- 338, 279-323, or 279-309;
• First reaction zone 372 generally includes one or more inlets in fluid communication with a source of initial feedstock 334 and a source of hydrogen gas 338. One or more outlets of the first reaction zone 372 that discharge effluent stream 374 are in fluid communication with one or more inlets of the fractionating zone 342 (optionally having one or more high pressure and low pressure separation stages therebetween for recovery of recycle hydrogen, not shown).
• Fractionating zone 342 includes one or more outlets for discharging gases 344, typically H 2 S, H 3 , and light hydrocarbons (C 1-C4); one or more outlets for recovering product 346, such as naphtha and diesel products boiling in the temperature range including and below atmospheric gas oil range fractions (for instance in the temperature range of 36-370°C); and one or more outlets for discharging bottoms 348 including hydrocarbons boiling above the atmospheric gas oil range (for instance about 370°C), from which a bleed stream 368 is obtained in processes that do not operate with 100% recycle.
• the temperature cut point for bottoms 348 (and correspondingly the end point for the products 346) is a range corresponding to the upper temperature limit of the desired gasoline, kerosene and/or diesel product boiling point ranges for downstream operations.
• operating conditions for the second stage reactor(s) in hydrocracking zone 370 using a two-stage with recycle configuration operating in a full conversion mode of operation include:
• An effective quantity of catalyst is provided in gas oil hydrotreating zone 300, including those possessing hydrotreating functionality, for hydrodesulfurization and hydrodenitrifi cation.
• Such catalyst generally contain one or more active metal component of metals or metal compounds (oxides or sulfides) selected from the Periodic Table of the Elements IUPAC Groups 6-10.
• the active metal component is one or more of Co, Ni, W and Mo.
• the active metal component is typically deposited or otherwise incorporated on a support, such as amorphous alumina, amorphous silica alumina, zeolites, or combinations thereof.
• a reactor inlet temperature in the range of from about 324-496, 324-453, 324- 431, 367-496, 367-453, 367-431, 389-496, 389-453, 389-431 or 406-414;
• reaction outlet pressure in the range of from about 104-118, 104-108, 112-118 or 108-112;
• a hydrogen partial pressure (barg) (outlet) in the range of from about 76-95, 76- 83, 83-89, or 89-95;
• a hydrogen treat gas feed rate up to about 525, 485, 490 or 520, in certain embodiments from about 474-520, 474-488, 488-500, or 500-520
• a hydrogen quench gas feed rate up to about 450, 441, 416 or 429, in certain embodiments from about 400-441, 400-415, 415-430, or 430-441;
• exemplary products from the gas oil hydrotreating zone 300 operating under conditions effective for feed conditioning and to maximize targeted conversion to petrochemicals in the steam cracker complex include 20-30, 22-28, 23-27 or 24-26 wt% of effluent (relative to the feed to the gas oil hydrotreating zone 300) boiling at or below the atmospheric residue end boiling point, such as 370°C, including LPG, kerosene, naphtha, and atmospheric gas oil range components.
• the remaining bottoms fraction is the hydrotreated gas oil fraction, all or a portion of which can be effectively integrated as feed to the gas oil steam cracking zone 250 as described herein.
• the vacuum residue from the vacuum distillation zone is processed in a delayed coking zone.
• the delayed coking zone produces a coker naphtha stream, a coker gas oil stream and petroleum coke.
• Some or all of the coker naphtha can be routed to the aromatics extraction zone and/or the mixed feed steam cracking zone.
• some or all of the coker gas oil is sent to a vacuum gas oil hydroprocessing zone. Liquefied petroleum gas can be recovered from delayed coking unit and routed to the mixed feed steam cracking zone, the olefins recovery train and/or the saturated gas plant.
• feedstock is typically introduced into a lower portion of a coking feed fractionator where one or more lighter materials are recovered as one or more top fractions, and bottoms are passed to a coking furnace.
• a coking temperature e.g., in the range of 480°C to 530°C
• the hot mixed fresh and recycle feedstream is maintained in the coke drum at coking conditions of temperature and pressure where the feed decomposes or cracks to form coke and volatile components.
• some or all of the coker naphtha stream 922 is sent to a coker naphtha hydrotreater 924, and the effluent can be routed to the aromatics extraction zone 620, the mixed feed steam cracker 230, the crude complex 100, or any combination of the aromatics extraction zone 620 and the mixed feed steam cracker 230.
• the vacuum residue stream 168 is charged to a coking furnace 912 where the contents are rapidly heated to a coking temperature, for example, in the range of about 480-530°C, and then fed to a coking drum 914 or 916.
• Coking unit 900 can be configured with two or more parallel drums 914 and 916 and can be operated in a swing mode, such that when one of the drums is filled with coke, vacuum residue stream 168 is transferred to the empty parallel drum so that accumulated coke 910 can be recovered from the filled drum.
• Liquid and gas stream 918 from the coker drum 914 or 916 are fed to a coking product fractionator 920. Any hydrocarbon vapors remaining in the coke drum are removed by steam injection.
• the coke is cooled with water and then removed from the coke drum using hydraulic and/or mechanical means.
• Liquid and gas coking unit product stream 918 is introduced into a coking product stream fractionator 920.
• the coking product stream 918 is fractionated to yield separate product streams that can include a coker naphtha stream 922, and a coker gas oil stream 904 which is recovered from the fractionator.
• some or all of the coker gas oil stream 904 is sent to the vacuum gas oil hydroprocessing zone.
• Effluent off-gases are recovered from the delayed coking unit 900 and are passed to the olefins recovery train, an unsaturated gas plant, and/or directly to a fuel gas system.
• Liquefied petroleum gas can be recovered from delayed coking unit 900 and routed to the mixed feed steam cracking zone, the olefins recovery train and/or the unsaturated gas plant.
• some or all of the coker naphtha stream 922 is sent to a coker naphtha hydrotreater 924 for further treatment because it generally contains heavy metals and about 10-20 times the amount of sulfur that a straight run naphtha and is not suitable for processing in other refinery units such as the mixed feed steam cracking zone 230 or other hydrotreaters.
• a start of run (SOR) reaction temperature (°C), as a weighted average bed temperature (WABT), in the range of from about 284-436, 284-398, 284-379, 322-436, 322-398, 322-379, 341-436, 341-398, 341-379 or 357-363; an end of run (EOR) reaction temperature (°C), as a WABT, in the range of from about 316-482, 316-441, 316-420, 357-482, 357-441, 357-420, 378-482, 378-441, 378- 420 or 396-404;
• reaction inlet pressure in the range of from about 44-66, 44-60, 44-58, 49-66, 49-60, 49-58, 52-66, 52-60, 52-58 or 53-56;
• a hydrogen partial pressure (barg) (outlet) in the range of from about 22-33, 22- 30, 22-29, 25-33, 25-30, 25-29, 26-33, 26-30 or 26-29;
• a hydrogen treat gas feed rate up to about 640, 620, 570 or 542, in certain embodiments from about 413-620, 413-570, 413-542, 465-620, 465-570, 465-542, 491-620, 491-570 or 491-542;
• a make-up hydrogen feed rate up to about 120, 110 or 102, in certain embodiments from about 78-120, 78-110, 78-102, 87-120, 87-110, 87-102, 92-120, 92-110, 92-102 or 95-100.
• the mixed feed steam cracking zone 230 which operates as high severity or low severity thermal cracking process, generally converts LPG, naphtha and heavier hydrocarbons primarily into a mixed product stream 232 containing mixed C1-C4 paraffins and olefins.
• the mixed feed steam cracking zone 230 processes straight-run liquids from the crude unit, ethane and/or propane (from outside battery limits and/or recycled) and various recycle streams from chemical production and recovery areas within the integrated process and system.
• a suitable mixed feed steam cracking zone 230 can include, but is not limited to, systems based on technology commercially available from Linde AG, DE; TechnipFMC pic, UK; Chicago Bridge & Iron Company N.V.
• the products from the mixed feed steam cracking zone 230 include: a quenched cracked gas stream 232 containing mixed C1-C4 paraffins and olefins that is routed to the olefins recovery zone 270; a raw pyrolysis gasoline stream 234 that is routed to a py-gas hydrotreating zone 600 to produce hydrotreated pyrolysis gasoline 604 as feed to the aromatics extraction zone 620, and C5s 606; and a pyrolysis fuel oil stream 236.
• the feed mixture is heated to a high temperature in a convection section and material with a boiling point below a predetermined temperature is vaporized.
• the heated mixture (in certain embodiments along with additional steam) is passed to the pyrolysis section operating at a further elevated temperature for short residence times, such as 1-2 seconds or less, effectuating pyrolysis to produce a mixed product stream.
• separate convection and radiant sections are used for different incoming feeds to the mixed feed steam cracking zone 230 with conditions in each optimized for the particular feed.
• steam cracking in the mixed feed steam cracking zone 230 is carried out using the following conditions: a temperature (°C) in the convection section in the range of about 400-600, 400-550, 450-600 or 500-600; a pressure (barg) in the convection section in the range of about 4.3 -4.8, 4.3-4.45, 4.3-4.6, 4.45-4.8, 4.45-4.6 or 4.6-4.8; a temperature (°C) in the pyrolysis section in the range of about 700-950, 700- 900, 700-850, 750-950, 750-900 or 750-850; a pressure (barg) in the pyrolysis section in the range of about 1.0-1.4, 1.0-1.25, 1.25-1.4, 1.0-1.15, 1.15-1.4 or 1.15-1.25; a steam-to- hydrocarbon ratio in the in the convection section in the range of about 0.3 : 1 -2: 1, 0.3 : 1- 1.5: 1, 0.5:
• a closed-loop dilution steam/process water system is enabled, in which dilution steam is generated using heat recovery from the primary fractionator quench pumparound loops.
• the primary fractionator enables efficient recovery of pyrolysis fuel oil due to energy integration and pyrolysis fuel oil content in the light fraction stream.
• Products from the gas oil steam cracking zone 250 include a quenched cracked gas stream 252 containing mixed C1-C4 paraffins and olefins that is routed to the olefins recovery zone 270, a raw pyrolysis gasoline stream 254 that is routed to a py-gas hydrotreating zone 600 to provide additional feed 604 to the aromatics extraction zone 620, and a pyrolysis fuel oil stream 256.
• steam cracking in the gas oil steam cracking zone 250 is carried out using the following conditions: a temperature (°C) in the convection section in the range of about 300-450 or 300-400; a pressure (barg) in the convection section in the range of about 7.2-9.7, 7.2-8.5, 7.2-7.7, 7.7-8.5, 7.7-9.7 or 8.5-9.7; a temperature (°C) in the pyrolysis section in the range of about 700-850, 700-800, 700-820, 750-850, 750-800 or 750-820; a pressure (barg) in the pyrolysis section in the range of about 0.9-1.2, 0.9- 1.4, 0.9-1.6, 1.2-1.4, 1.2-1.6 or 1.4-1.6; a steam-to-hydrocarbon ratio in the in the convection section in the range of about 0.75: 1 -2: 1, 0.75: 1-1.5: 1, 0.85: 1-2: 1, 0.9: 1-1.5: 1, 0.9:
• cracked gas from the gas oil steam cracking zone 250 furnaces is quenched in transfer line exchangers by producing, for instance, 1800 psig steam. Quenched gases are stripped with steam in a primary fractionator. Lighter gases are recovered as the overhead product; a side-draw stream contains pyrolysis fuel oil. The primary fractionator bottoms product is pyrolysis tar, which is cooled and sent to product storage. Pyrolysis fuel oil from the primary fractionator is stripped with steam in the pyrolysis fuel oil stripper, which separates pyrolysis gasoline as the overhead and pyrolysis fuel oil as the bottoms product.
• Gasoline in the primary fractionator overhead is condensed and combined with gasoline from the pyrolysis fuel oil stripper before being sent to a gasoline stabilizer.
• the gasoline stabilizer removes light products in the overhead, while the stabilizer bottoms are sent to the py-gas hydrotreater.
• C4 and lighter gases in the primary fractionator overhead are compressed, for instance, in two stages of compression, before entering an absorber, depropanizer and debutanizer.
• a closed-loop dilution steam/process water system is enabled, in which dilution steam is generated using heat recovery from the primary fractionator quench pumparound loops.
• the primary fractionator enables efficient recovery of pyrolysis fuel oil due to energy integration and pyrolysis fuel oil content in the light fraction stream.
• Products include: hydrogen 210 that is used for recycle and/or passed to users; fuel gas 208 that is passed to a fuel gas system; ethane 272 that is recycled to the mixed feed steam cracking zone 230; ethylene 202 that is recovered as product; a mixed C3 stream 286 that is passed to a methyl acetylene/propadiene saturation and propylene recovery zone 280; and a mixed C4 stream 206 that is passed to a butadiene extraction zone 500.
• a methyl tertiary butyl ether zone 510 is integrated to produce methyl tertiary butyl ether 514 and a second C4 raffinate 516 from the first C4 raffinate stream 504.
• C4 Raffinate 1 504 is subjected to selective hydrogenation to selectively hydrogenate any remaining dienes and prior to reacting isobutenes with methanol to produce methyl tertiary butyl ether.
• the raffinate stream 504 contains 35-45 %, 37-42.5 %, 38-41 % or 39-40 % isobutylene by weight. This component is removed from the C4 raffinate 516 to attain requisite purity specifications, for instance, greater than or equal to 98 wt% for the 1 -butene product stream 522 from the butene- 1 recovery zone 520.
• Isobutane product 526 can optionally be recovered in the overhead (shown in dashed lines), 1-butene product 522 is recovered as a sidecut, and n-butane is recovered as the bottoms stream. Bottoms from both splitters is recovered as all or a portion of recycle stream 524.
• all or a portion of the make-up hydrogen 602 is derived from the steam cracker hydrogen stream 210 from the olefins recovery train 270.
• a suitable py-gas hydrotreating zone 600 can include, but is not limited to, systems based on technology commercially available from Honeywell UOP, US; Chevron Lummus Global LLC (CLG), US; Axens, IFP Group Technologies, FR; Haldor Topsoe A/S, DK; or Chicago Bridge & Iron Company N. V. (CB&I), NL.
• Pd-based catalyst materials are effective.
• Two parallel first-stage reactors can be used in certain embodiments to allow for regeneration in a continuous process without shutdown.
• the first-stage reactor contains three catalyst beds with cooled first stage separator liquid recycled as quench material between each bed.
• First-stage effluent is stabilized and separated in a column operating under slight vacuum to reduce temperature.
• C5 from the C6+ is drawn, followed by a deoctanizer to remove C9+ and produce a C6-C8 heart naphtha cut.
• the column operates under slight vacuum to limit temperature.
• the first stage product is stripped to remove hydrogen, H 2 S, and other light ends.
• the stripped first stage product is depentanized to remove cracked C5, for instance, as feed to a metathesis unit.
• a second stage reactor operates in vapor phase and removes sulfur and saturates olefins.
• the second stage product is stripped to remove hydrogen, H 2 S, and other light ends.
• both reactors are multi-bed and use product recycle to control reactor temperature rise.
• the first reaction stage of the py-gas hydrotreating zone 600 operating conditions include:
• a reactor inlet temperature in the range of from about 80-135, 80-125, 80- 115, 95-135, 95-125, 95-115, 100-135, 100-125, 100-115 or 107-111
• a reactor outlet temperature in the range of from about 145-230, 145-206, 145-200, 165-230, 165-206, 165-200, 175-230, 175-206, 175-200 or 184-188;
• reaction inlet pressure in the range of from about 25-40, 25-35, 25-33, 28-40, 28-35, 28-33, 30-40, 30-35 or 30-33;
• liquid quench feed ratio up to about 0.8, 0.7, 0.6 or 0.5, and in certain embodiments in the range of from about 0.35-0.6, 0.35-0.55, 0.35-0.5, 0.4-0.6, 0.4-0.55, 0.4-0.5, 0.45-0.6, 0.45-0.55 or 0.45-0.5;
• the second reaction stage of the py-gas hydrotreating zone 600 operating conditions include:
• a reactor inlet temperature in the range of from about 225-350, 225-318, 225-303, 255-350, 255-318, 255-303, 270-350, 270-318, 270-303 or 285-291;
• a reactor outlet temperature in the range of from about 289-445, 289-405, 289-386, 328-445, 328-405, 328-386, 345-445, 345-405, 345-386 or 364-370;
• a start of run (SOR) reaction temperature °C
• WABT weighted average bed temperature
• reaction outlet pressure in the range of from about 23-35, 23-32, 23-30, 26-35, 26-32, 26-30, 28-35, 28-32 or 28-30;
• An effective quantity of second stage pyrolysis gasoline reactor catalyst is provided, including those having hydrogenation functionality and which generally contain one or more active metal component of metals or metal compounds (oxides or sulfides) selected from the Periodic Table of the Elements IUPAC Groups 6-10.
• the active metal component is one or more of Co, Ni, W and Mo.
• the active metal component is typically deposited or otherwise incorporated on a support, such as amorphous alumina, amorphous silica alumina, zeolites, or combinations thereof.
• the catalyst used in the first stage pyrolysis gasoline reactor includes one or more catalyst selected from Co/Mo, Ni/Mo, Ni/W, and Co/Ni/Mo.
• Effective liquid hourly space velocity values (h "1 ), on a fresh feed basis relative to the first stage pyrolysis gasoline reactor catalyst, are in the range of from about 0.1 -10.0, 0.1-5.0, 0.1-2.0, 0.3- 10.0, 0.3-5.0, 0.3-2.0, 0.5-10.0, 0.5-5.0, 0.5-2.0 or 0.8-1.2.
• Suitable catalysts used in the second stage pyrolysis gasoline reactor have an expected lifetime in the range of about 18-30, 22-30, 18-26 or 22-26 months.
• Hydrotreated pyrolysis gasoline 604 is routed to the aromatics extraction zone620. In certain embodiments to maximize production of petrochemicals, all, a substantial portion or a significant portion of the hydrotreated pyrolysis gasoline 604 is passed to the aromatics extraction zone 620. In modes of operation in which production of gasoline is the objective some of the hydrotreated pyrolysis gasoline 604 is passed to a gasoline pool (not shown).
• the aromatics extraction zone 620 includes, for instance, one or more extractive distillation units, and operates to separate the hydrotreated pyrolysis gasoline into high- purity benzene, toluene, xylenes and C9 aromatics. As depicted in FIG. 13, a benzene stream 624, a mixed xylenes stream 626 and a raffinate stream 646 are recovered from the aromatics extraction zone 620, with the raffinate stream 646 routed to the mixed feed steam cracking zone 230 as additional feed.
• a toluene stream 636 and C9+ aromatics stream 638 are passed from the aromatics extraction zone 620 to a toluene and C9+ transalkylation zone 630 for production of additional benzene and xylenes, recycled as stream 640 to the aromatics extraction zone 620.
• ethylbenzene can be recovered (not shown).
• Heavy aromatics 642 are also recovered from the aromatics extraction zone 620.
• aromatics are separated from the feed by extractive distillation using, for instance, n- formylmorpholine (NFM), as an extractive solvent.
• NFM n- formylmorpholine
• Benzene, toluene, mixed xylenes and C9+ aromatics are separated via distillation.
• Benzene and mixed xylenes are recovered as product streams 624 and 626, and toluene 636 and C9+ aromatics 638 are sent to the toluene and C9+ transalkylation zone 630.
• the transalkylation zone product stream 640 containing benzene and mixed xylenes is returned to the recovery section of the aromatics extraction zone 620.
• the extraction solvent can be a pure glycol or a glycol diluted with from about 2-10 wt% water.
• Suitable sulfolanes include hydrocarbon-substituted sulfolanes (e.g., 3-methyl sulfolane), hydroxy sulfolanes (e.g., 3- sulfolanol and 3 -methyl -4-sulfolanol), sulfolanyl ethers (e.g., methyl -3 -sulfolanyl ether), and sulfolanyl esters (e.g., 3 -sulfolanyl acetate).
• hydrocarbon-substituted sulfolanes e.g., 3-methyl sulfolane
• hydroxy sulfolanes e.g., 3- sulfolanol and 3 -methyl -4-sulfolanol
• the aromatic separation apparatus can operate at a temperature in the range of from about 40-200, 40-150, 60-200, 60-150, 86-200 or 80-150°C.
• the operating pressure of the aromatic separation apparatus can be in the range of from about 1 -20, 1-16, 3-20, 3-16, 5-20 or 5-16 barg.
• Types of apparatus useful as the aromatic separation apparatus in certain embodiments of the system and process described herein include extractive distillation columns.
• the toluene and C9+ transalkylation zone 630 operates under conditions effective to disproportionate toluene and C9+ aromatics into a mixed stream 640 containing benzene, mixed xylenes and heavy aromatics. Product ratio of benzene and xylene can be adjusted by selection of catalyst, feedstock and operating conditions.
• the transalkylation zone 630 receives as feed the toluene stream 636 and the C9+ aromatics stream 638 from the aromatics extraction zone 620.
• a small quantity of hydrogen 632 in certain embodiments which is obtained all or in part from the hydrogen stream 210 derived from the olefins recovery zone 270, is supplied for transalkylation reactions.
• pyrolysis oil streams 236 and 256 can be blended into the fuel oil pool as a low sulfur component, and/or used as carbon black feedstock.
• either or both of the pyrolysis oil streams 236 and 256 can be fractioned (not shown) into light pyrolysis oil and heavy pyrolysis oil.
• light pyrolysis oil can be blended with one or more of the middle distillate streams, so that 0- 100% of light pyrolysis oil derived from either or both of the pyrolysis oil streams 236 and 256 is processed to produce diesel fuel product and/or additional feed to the mixed feed steam cracking zone 230.
• 0-100% of light pyrolysis oil derived from either or both of the pyrolysis oil streams 236, 256 can be processed in the vacuum gas oil hydroprocessing zone. In certain embodiments, all, a substantial portion, a significant portion or a major portion of light pyrolysis oil can be processed in the delayed coking zone 900. Heavy pyrolysis oil can be blended into the fuel oil pool as a low sulfur component, and/or used as a carbon black feedstock. In further embodiments, 0-100% of light pyrolysis oil and/or 0-100%) of heavy pyrolysis oil derived from either or both of the pyrolysis oil streams 236, 256 can be processed in the delayed coking unit 900. In certain embodiments, all, a substantial portion, a significant portion or a major portion of the pyrolysis oil streams 236, 256 (light and heavy) can be processed in the delayed coking zone 900.
• Feedstocks to the metathesis zone 530 include: a portion 536 of the ethylene product 202; a C4 Raffinate-3 stream 532 from the 1-butene recovery zone 520, and the olefinic C5 cut 606 from the py-gas hydrotreating zone 600.
• the C4 Raffinate-3 stream 532 is 0-100% of the total C4 Raffinate-3 from the 1-butene recovery zone 520; any remaining portion 524 can be recycled to the mixed feed steam cracking zone 230.
• Products from the metathesis zone 530 include a propylene product stream 534 and a stream 542, having a mixture of mostly saturated C4/C5 from a metathesis unit that is recycled to the mixed feed steam cracking zone.
• the metathesis reactor effluent contains a mixture of propylene, ethylene, and butenes/butanes, and some C5 and heavier components from by-product reactions.
• C4 olefins isomerize in the disproportionation reactor and react with ethylene to form additional propylene.
• disproportionation of C5 olefins yields isobutylene by-product for production of additional MTBE.
• Cooled reactor effluent enters a deethylenizer, which recycles overhead ethylene to the disproportionation reactor. Deethylenizer bottoms are passed to a depropylenizer, which recovers grade propylene product as overhead. Propylene product purity is >99.5 mol% (polymer grade).
• FIG. 15 depicts embodiments in which kerosene sweetening is in an optional unit, that is, the first middle distillate fraction 116 can be routed either through the kerosene sweetening zone 170 or routed to the distillate hydrotreating zone 180.
• the process of FIG. 15 operates according to the description with respect to FIGs. 7 and 13, or any of the other embodiments herein, in all other aspects.
• the first middle distillate fraction 124 contains kerosene range hydrocarbons and a portion of medium AGO range hydrocarbons and the second middle distillate fraction 134 contains a portion of medium AGO range hydrocarbons and heavy AGO range hydrocarbons.
• the process of FIG. 16 operates according to the description with respect to FIGs. 7 and 13, or any of the other embodiments herein, in all other aspects.
• process dynamics of the configurations and the integration of units and streams attain a very high level of integration of utility streams between the mixed feed steam cracking and other process units, result in increased efficiencies and reduced overall operating costs.
• the hydrogen can be tightly integrated so that the net hydrogen demand from outside of the battery limits is minimized or even eliminated.
• the overall hydrogen utilization from outside of the battery limits is less than about 40, 30, 15, 10 or 5 wt% hydrogen based on the total hydrogen required by the hydrogen users in the integrated process.
• Hydrogen is recovered from the olefins recovery train, and is supplied to the hydrogen users in the system, including the diesel hydrotreater, the gas oil hydroprocessing zone, the vacuum residue hydroprocessing zone, the py-gas hydrotreater, and transalkylation, so as to derive most or all of the utility hydrogen from within the battery limits.
• there is zero external hydrogen use in which make-up hydrogen is only required to initiate the operations; when the reactions reach equilibrium, the hydrogen derived from the mixed feed steam cracking and gas oil steam cracking products provides sufficient hydrogen to maintain the hydrogen requirements of the hydrogen users in the integrated process.
• there is a net hydrogen gain so that hydrogen can be added, for instance, to the fuel gas that is used to operate the various heating units within the integrated process.
• individual unit operations can include a controller to monitor and adjust the product slate as desired.
• a controller can direct parameters within any of the individual unit operations the apparatus depending upon the desired operating conditions, which may, for example, be based on customer demand and/or market value.
• a controller can adjust or regulate valves, feeders or pumps associated with one or more unit operations based upon one or more signals generated by operator data input and/or automatically retrieved data.
• controllers provide a versatile unit having multiple modes of operation, which can respond to multiple inputs to increase the flexibility of the recovered product.
• the controller can be implemented using one or more computer systems which can be, for example, a general -purpose computer.
• the computer system can include specially-programmed, special-purpose hardware, for example, an application- specific integrated circuit (ASIC) or controllers intended for a particular unit operation within a refinery.
• ASIC application- specific integrated circuit
• the computer system is described above by way of example as one type of computer system upon which various aspects of the processes herein can be practiced, it should be appreciated that the invention is not limited to being implemented in software, or on the computer system as exemplarily described. Indeed, rather than implemented on, for example, a general purpose computer system, the controller, or components or subsections thereof, can alternatively be implemented as a dedicated system or as a dedicated programmable logic controller (PLC) or in a distributed control system. Further, it should be appreciated that one or more features or aspects of the processes can be implemented in software, hardware or firmware, or any combination thereof. For example, one or more segments of an algorithm executable by a controller can be performed in separate computers, which in turn, can be in communication through one or more networks.
• PLC programmable logic controller
• Factors that can result in various adjustments or controls include customer demand of the various hydrocarbon products, market value of the various hydrocarbon products, feedstock properties such as API gravity or heteroatom content, and product quality (for instance, gasoline and middle distillate indicative properties such as octane number for gasoline and cetane number for middle distillates).
• the disclosed processes and systems provide alternatives for chemicals production that have lower capital investment relative to conventional routes that utilize refining units and an integrated chemicals complex. Moreover, the disclosed processes and systems offer the flexibility of simultaneously producing fuel products and chemical products. The ratio of chemicals to residual fuels can be modulated by process operations to address changing fuels and chemical market opportunities.
• the process configurations are flexible to enable processing of crude oil, such as Arab Light or Arab Extra Light, to provide superior production of chemical products, while minimizing the production of refined fuel products.
• the configurations offer the flexibility to structure operations to adjust the ratio of petrochemicals to refined products in order to achieve optimum operations and allows shifting the production ratio of chemicals to fuels, thereby adjusting to market conditions.

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• 2017
  • 2017-11-17 US US15/817,143 patent/US10472574B2/en active Active
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• 2019
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