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WO2010053865A1 - Intégration d’une gazéification et d’un hydrotraitement pour un raffinage à faibles émissions - Google Patents

Intégration d’une gazéification et d’un hydrotraitement pour un raffinage à faibles émissions Download PDF

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Publication number
WO2010053865A1
WO2010053865A1 PCT/US2009/062964 US2009062964W WO2010053865A1 WO 2010053865 A1 WO2010053865 A1 WO 2010053865A1 US 2009062964 W US2009062964 W US 2009062964W WO 2010053865 A1 WO2010053865 A1 WO 2010053865A1
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Prior art keywords
stream
gasification
upgrader
distillate
bottoms
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Inventor
Paul Steven Wallace
Alma Isabel Marin Rodarte
Govanon Nongbri
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Katana Energy LLC
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Katana Energy LLC
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    • C—CHEMISTRY; METALLURGY
    • C01—INORGANIC CHEMISTRY
    • C01B—NON-METALLIC ELEMENTS; COMPOUNDS THEREOF; METALLOIDS OR COMPOUNDS THEREOF NOT COVERED BY SUBCLASS C01C
    • C01B3/00—Hydrogen; Gaseous mixtures containing hydrogen; Separation of hydrogen from mixtures containing it; Purification of hydrogen
    • C01B3/50—Separation of hydrogen or hydrogen containing gases from gaseous mixtures, e.g. purification
    • C—CHEMISTRY; METALLURGY
    • C01—INORGANIC CHEMISTRY
    • C01B—NON-METALLIC ELEMENTS; COMPOUNDS THEREOF; METALLOIDS OR COMPOUNDS THEREOF NOT COVERED BY SUBCLASS C01C
    • C01B13/00—Oxygen; Ozone; Oxides or hydroxides in general
    • C01B13/02—Preparation of oxygen
    • C01B13/0229—Purification or separation processes
    • C—CHEMISTRY; METALLURGY
    • C01—INORGANIC CHEMISTRY
    • C01B—NON-METALLIC ELEMENTS; COMPOUNDS THEREOF; METALLOIDS OR COMPOUNDS THEREOF NOT COVERED BY SUBCLASS C01C
    • C01B3/00—Hydrogen; Gaseous mixtures containing hydrogen; Separation of hydrogen from mixtures containing it; Purification of hydrogen
    • C01B3/02—Production of hydrogen or of gaseous mixtures containing a substantial proportion of hydrogen
    • C01B3/22—Production of hydrogen or of gaseous mixtures containing a substantial proportion of hydrogen by decomposition of gaseous or liquid organic compounds
    • C—CHEMISTRY; METALLURGY
    • C01—INORGANIC CHEMISTRY
    • C01B—NON-METALLIC ELEMENTS; COMPOUNDS THEREOF; METALLOIDS OR COMPOUNDS THEREOF NOT COVERED BY SUBCLASS C01C
    • C01B3/00—Hydrogen; Gaseous mixtures containing hydrogen; Separation of hydrogen from mixtures containing it; Purification of hydrogen
    • C01B3/50—Separation of hydrogen or hydrogen containing gases from gaseous mixtures, e.g. purification
    • C01B3/52—Separation of hydrogen or hydrogen containing gases from gaseous mixtures, e.g. purification by contacting with liquids; Regeneration of used liquids
    • C—CHEMISTRY; METALLURGY
    • C01—INORGANIC CHEMISTRY
    • C01B—NON-METALLIC ELEMENTS; COMPOUNDS THEREOF; METALLOIDS OR COMPOUNDS THEREOF NOT COVERED BY SUBCLASS C01C
    • C01B3/00—Hydrogen; Gaseous mixtures containing hydrogen; Separation of hydrogen from mixtures containing it; Purification of hydrogen
    • C01B3/50—Separation of hydrogen or hydrogen containing gases from gaseous mixtures, e.g. purification
    • C01B3/56—Separation of hydrogen or hydrogen containing gases from gaseous mixtures, e.g. purification by contacting with solids; Regeneration of used solids
    • C—CHEMISTRY; METALLURGY
    • C01—INORGANIC CHEMISTRY
    • C01B—NON-METALLIC ELEMENTS; COMPOUNDS THEREOF; METALLOIDS OR COMPOUNDS THEREOF NOT COVERED BY SUBCLASS C01C
    • C01B3/00—Hydrogen; Gaseous mixtures containing hydrogen; Separation of hydrogen from mixtures containing it; Purification of hydrogen
    • C01B3/50—Separation of hydrogen or hydrogen containing gases from gaseous mixtures, e.g. purification
    • C01B3/56—Separation of hydrogen or hydrogen containing gases from gaseous mixtures, e.g. purification by contacting with solids; Regeneration of used solids
    • C01B3/58—Separation of hydrogen or hydrogen containing gases from gaseous mixtures, e.g. purification by contacting with solids; Regeneration of used solids including a catalytic reaction
    • 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
    • C10G49/00—Treatment of hydrocarbon oils, in the presence of hydrogen or hydrogen-generating compounds, not provided for in a single one of groups C10G45/02, C10G45/32, C10G45/44, C10G45/58 or C10G47/00
    • C10G49/007—Treatment of hydrocarbon oils, in the presence of hydrogen or hydrogen-generating compounds, not provided for in a single one of groups C10G45/02, C10G45/32, C10G45/44, C10G45/58 or C10G47/00 in the presence of hydrogen from a special source or of a special composition or having been purified by a special treatment
    • C—CHEMISTRY; METALLURGY
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    • C01B—NON-METALLIC ELEMENTS; COMPOUNDS THEREOF; METALLOIDS OR COMPOUNDS THEREOF NOT COVERED BY SUBCLASS C01C
    • C01B2203/00—Integrated processes for the production of hydrogen or synthesis gas
    • C01B2203/02—Processes for making hydrogen or synthesis gas
    • C01B2203/0266—Processes for making hydrogen or synthesis gas containing a decomposition step
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    • C01B2203/00—Integrated processes for the production of hydrogen or synthesis gas
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    • C01B—NON-METALLIC ELEMENTS; COMPOUNDS THEREOF; METALLOIDS OR COMPOUNDS THEREOF NOT COVERED BY SUBCLASS C01C
    • C01B2203/00—Integrated processes for the production of hydrogen or synthesis gas
    • C01B2203/04—Integrated processes for the production of hydrogen or synthesis gas containing a purification step for the hydrogen or the synthesis gas
    • C01B2203/0415—Purification by absorption in liquids
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    • C01B—NON-METALLIC ELEMENTS; COMPOUNDS THEREOF; METALLOIDS OR COMPOUNDS THEREOF NOT COVERED BY SUBCLASS C01C
    • C01B2203/00—Integrated processes for the production of hydrogen or synthesis gas
    • C01B2203/04—Integrated processes for the production of hydrogen or synthesis gas containing a purification step for the hydrogen or the synthesis gas
    • C01B2203/042—Purification by adsorption on solids
    • C01B2203/043—Regenerative adsorption process in two or more beds, one for adsorption, the other for regeneration
    • C—CHEMISTRY; METALLURGY
    • C01—INORGANIC CHEMISTRY
    • C01B—NON-METALLIC ELEMENTS; COMPOUNDS THEREOF; METALLOIDS OR COMPOUNDS THEREOF NOT COVERED BY SUBCLASS C01C
    • C01B2203/00—Integrated processes for the production of hydrogen or synthesis gas
    • C01B2203/04—Integrated processes for the production of hydrogen or synthesis gas containing a purification step for the hydrogen or the synthesis gas
    • C01B2203/0435—Catalytic purification
    • C01B2203/0445—Selective methanation
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    • C01B—NON-METALLIC ELEMENTS; COMPOUNDS THEREOF; METALLOIDS OR COMPOUNDS THEREOF NOT COVERED BY SUBCLASS C01C
    • C01B2203/00—Integrated processes for the production of hydrogen or synthesis gas
    • C01B2203/04—Integrated processes for the production of hydrogen or synthesis gas containing a purification step for the hydrogen or the synthesis gas
    • C01B2203/0465—Composition of the impurity
    • C01B2203/0475—Composition of the impurity the impurity being carbon dioxide
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    • C01B2203/00—Integrated processes for the production of hydrogen or synthesis gas
    • C01B2203/04—Integrated processes for the production of hydrogen or synthesis gas containing a purification step for the hydrogen or the synthesis gas
    • C01B2203/0465—Composition of the impurity
    • C01B2203/0485—Composition of the impurity the impurity being a sulfur compound
    • C—CHEMISTRY; METALLURGY
    • C01—INORGANIC CHEMISTRY
    • C01B—NON-METALLIC ELEMENTS; COMPOUNDS THEREOF; METALLOIDS OR COMPOUNDS THEREOF NOT COVERED BY SUBCLASS C01C
    • C01B2203/00—Integrated processes for the production of hydrogen or synthesis gas
    • C01B2203/06—Integration with other chemical processes
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    • C01B—NON-METALLIC ELEMENTS; COMPOUNDS THEREOF; METALLOIDS OR COMPOUNDS THEREOF NOT COVERED BY SUBCLASS C01C
    • C01B2203/00—Integrated processes for the production of hydrogen or synthesis gas
    • C01B2203/06—Integration with other chemical processes
    • C01B2203/061—Methanol production
    • C—CHEMISTRY; METALLURGY
    • C01—INORGANIC CHEMISTRY
    • C01B—NON-METALLIC ELEMENTS; COMPOUNDS THEREOF; METALLOIDS OR COMPOUNDS THEREOF NOT COVERED BY SUBCLASS C01C
    • C01B2203/00—Integrated processes for the production of hydrogen or synthesis gas
    • C01B2203/06—Integration with other chemical processes
    • C01B2203/062—Hydrocarbon production, e.g. Fischer-Tropsch process
    • C—CHEMISTRY; METALLURGY
    • C01—INORGANIC CHEMISTRY
    • C01B—NON-METALLIC ELEMENTS; COMPOUNDS THEREOF; METALLOIDS OR COMPOUNDS THEREOF NOT COVERED BY SUBCLASS C01C
    • C01B2203/00—Integrated processes for the production of hydrogen or synthesis gas
    • C01B2203/06—Integration with other chemical processes
    • C01B2203/068—Ammonia synthesis
    • C—CHEMISTRY; METALLURGY
    • C01—INORGANIC CHEMISTRY
    • C01B—NON-METALLIC ELEMENTS; COMPOUNDS THEREOF; METALLOIDS OR COMPOUNDS THEREOF NOT COVERED BY SUBCLASS C01C
    • C01B2203/00—Integrated processes for the production of hydrogen or synthesis gas
    • C01B2203/14—Details of the flowsheet
    • C01B2203/146—At least two purification steps in series
    • C01B2203/147—Three or more purification steps in series
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    • C01—INORGANIC CHEMISTRY
    • C01B—NON-METALLIC ELEMENTS; COMPOUNDS THEREOF; METALLOIDS OR COMPOUNDS THEREOF NOT COVERED BY SUBCLASS C01C
    • C01B2210/00—Purification or separation of specific gases
    • C01B2210/0043—Impurity removed
    • C01B2210/0046—Nitrogen

Definitions

  • This invention relates generally to methods and systems for integrating two or more industrial processes, and, more particularly, to methods and systems for integrating hydroprocessing and gasification processes to reduce emissions, reduce by-products, and increase refining efficiency.
  • FIG. 1 shows a schematic depicting a typical refinery process 100 according to a prior art.
  • the typical refinery process 100 consists of a crude unit 110, a hydrocracker unit 120, a coker unit 130, a hydrotreater unit 140, a hydrogen plant 150, and a sulfur plant 160.
  • the crude unit 110 is a crude unit 110, a hydrocracker unit 120, a coker unit 130, a hydrotreater unit 140, a hydrogen plant 150, and a sulfur plant 160.
  • a diluted crude stream 105 enters the crude unit 110.
  • the diluted erode stream 105 flows to a desalter (not shown) for removing contaminants such as water, salt, clay, and sand.
  • the diluted crude stream 105 is further heated in a, fired heater (not shown) and then flows into a crude column (not shown) for fractionation.
  • three streams, or fractions, are generated, a diluent stream 112, a light oil stream 114, and a heavy oil stream 116.
  • the diluent stream 112 consists of diluent, which is the lightest component.
  • the diluent is added to the oil to make it easier to pump through the pipeline. Once the diluent has been removed from the oil, the diluent is sent back to the field, via the diluent stream 112, so that it may be added to more oil.
  • the fight oil stream 114 which makes up about one-third barrel of oil, consists of jet kerosene and gas oil and is sent to the hydrotreater unit 140, while the heavy oil stream 116, which makes up about two-thirds barrel of oil, consists of residuum and is sent to the hydrocracker unit 120.
  • a natural gas stream 107 and a steam stream 109 enter the hydrogen plant 150, wherein hydrogen streams 152, 154 are generated.
  • the natural gas stream 107 and the steam stream 109 are mixed together and passed through a reformer furnace (not shown) so that the natural gas stream 107 reacts with the steam stream 109 to produce a reformer furnace outlet stream containing hydrogen, carbon monoxide, and carbon dioxide.
  • the reformer furnace outlet stream then enters a shift converter (not shown) to remove the carbon monoxide from the reacted stream, thereby producing a shift converter outlet stream.
  • the shift converter outlet stream then enters a steam methane reformer pressure swing absorption unit (not shown) to remove the remaining carbon monoxide, carbon dioxide, methane, and nitrogen, thereby producing a steam methane reformer pressure swing absorption unit outlet stream which is substantially pure hydrogen.
  • the steam methane reformer pressure swing absorption unit outlet stream may then enter a hydrogen compressor, which compresses the pure hydrogen and sends it to the hydrocracker unit 120 and the hydrotreater unit 140 via hydrogen streams 152, 154. Approximately 1000 cubic feet of natural gas is consumed to produce one barrel of synthetic crude.
  • the heavy oil stream 116 is sent to the hydrocracker unit 120 where the hydrogen stream 152 is added at high temperatures and at high pressure.
  • the heavy oil stream 116 is initially sent through a fired heater (not shown) where the heavy oil stream 116 is preheated.
  • the pre-heated heavy oil stream is then combined with the hydrogen stream 152 and both are sent to a catalytic reactor (not shown) where cracking of the preheated heavy oil stream occurs.
  • a catalytic reactor outlet stream is generated and flows into a series of separators (not shown) to separate the vapors from the liquids.
  • the separated liquids are routed to a fractionator (not shown) for splitting the separated liquids into naphtha, jet kerosene, gas oil, and heavy residuum.
  • the naphtha, jet kerosene, and gas oil are sent to the hydrotreater unit 140 for further cleaning via the hydrocracker unit light stream 122, while the heavy residuum is sent to the coker unit 130 for further cracking via the hydrocracker unit heavy stream 124.
  • the hydrocracker unit heavy stream 124 enters the coker unit 130 where it undergoes partial vaporization and mild cracking as it passes through a coking furnace (not shown).
  • a coking furnace outlet stream exits the coking furnace (not shown) and enters a coke drum (not shown),
  • the vapors in the coke drum (not shown) undergo cracking as they pass through the coke drum (not shown) and exit the coke drum (not shown) via a coke drum vapor stream.
  • the coke drum vapor stream is sent to a fractionation facility (not shown) where the coke drum vapor stream is separated into gas, naphtha, jet fuel, and gas oil and is sent to the hydrotreater unit 140 via a coker unit light stream 135.
  • the petroleum coke within the coking furnace outlet stream remains in the coke drum (not shown).
  • the heavy hydrocarbon liquid trapped in the coke drum (not shown) is subjected to successive cracking and polymerization until it is converted to vapors and coke.
  • this coke may be sold as an end product via a coke stream 132.
  • the light oil stream 114 from the crude unit 110, the hydrocracker unit iight stream 122 from the hydrocracker unit 120, and the coker unit light stream 135 from the coker unit 130 enter the hydrotreatcr unit 140 for further upgrading.
  • the hydrogen stream 154 is added at high temperatures and at high pressure to the light oil stream 114, the hydrocracker unit light stream 122, and the coker unit light stream 135.
  • the hydrotreater unit 140 may contain a naphtha/jet hydrotreater (not shown) and a gas oil hydrotreater (not shown) for producing a product stream 145.
  • the naphtha/jet hydrotreater (not shown) produces a jet fuel as its product stream 145
  • the gas oil hydrotreater (not shown) produces a gas oil as its product stream 145.
  • Each of the naphtha/jet hydrotreater (not shown) and the gas oil hydrotreater (not shown) have a fired heater (not shown) for receiving at least one of the light oil stream 114, the hydrocracker unit light stream 122, and the coker unit iight stream 135.
  • streams 114, 122, 135 enter a catalytic reactor (not shown) where hydrogen sulfide and ammonia are produced.
  • the catalytic reactor (not shown) produces a catalytic reactor outlet stream which enters a separator (not shown) where the hydrogen and other gases are separated from the liquid.
  • the separator (not shown) produces a separator liquid outlet stream which then enters a stripper (not shown) to produce the product stream 145.
  • the separator (not shown) also produces a separator vapor outlet stream 142, which contains hydrogen sulfide, that is sent to the sulfur plant 160.
  • hydrogen sulfide is converted to elemental sulfur using methods and processes known to those of ordinary skill in the art.
  • the elemental sulfur may be removed from the typical refinery process 100 via a sulfur stream 162.
  • One exemplary embodiment of the invention is an integrated hydroprocessing and gasification system that includes an oil processing system and a gasification facility.
  • the oil processing system receives an oil processing feed stream and produces a fuel/diesel outlet stream and a heavy product bottoms outlet stream.
  • the gasification facility receives a gasification feed stream and produces a hydrogen outlet stream and a high pressure steam outlet stream.
  • the gasification teed stream includes the heavy product bottoms outlet stream.
  • the hydrogen outlet stream and the high pressure steam outlet stream are utilized within the oil processing system.
  • Another exemplary embodiment of the invention is a method for operating an integrated hydroprocessing and gasification system. The method includes providing an oil processing system and coupling a gasification facility to the oil processing system.
  • the oil processing system receives an oil processing feed stream and produces a fuel/diesel outlet stream and a heavy product bottoms outlet stream.
  • the gasification facility receives a gasification feed stream and produces a hydrogen outlet stream and a high pressure steam outlet stream.
  • the gasification feed stream includes the heavy product bottoms outlet stream.
  • the hydrogen outlet stream and the high pressure steam outlet stream are utilized within the oil processing system.
  • Figure 1 shows a schematic depicting a typical refinery process according to a prior art
  • FIG. 2 shows a flowchart of an integrated hydroprocessing and gasification system that illustrates the equipment utilized in an oil processing facility in accordance with an exemplary embodiment
  • FIG. 3 shows a flowchart of an integrated hydroprocessing and gasification system that illustrates the equipment utilized in the gasification faculty in accordance with an exemplary embodiment
  • Figure 4A shows a bitumen yield graph comparing a prior art oil refining system bitumen crude yield versus an integrated hydroprocessing and gasification system bitumen crude yield in accordance with an exemplary embodiment
  • Figure 4B shows a bitumen margin graph comparing a prior art oil refining system cost versus an integrated hydroprocessing and gasification system cost and comparing a prior art oil refining system bitumen margin versus an integrated hydroprocessing and gasification system bitumen margin in accordance with an exemplary embodiment
  • Figure 5A shows a comparison between a prior art oil refining system
  • FIG. 5B shows an Arab heavy margin graph comparing a prior art oil refining system cost versus an integrated hydroproeessing and gasification system cost and comparing a prior art oil refining system Arab heavy gross margin versus an integrated hydroproeessing and gasification system Arab heavy gross margin in accordance with an exemplary embodiment;
  • Figure 6A shows a comparison between a prior art oil refining system UAE crude yield flowchart versus an integrated hydroproeessing and gasification system UAE crude yield flowchart in accordance with an exemplary embodiment
  • Figure 6B shows an UAE medium margin graph comparing a prior art oil refining system cost versus an integrated hydroprocessing and gasification system cost and comparing a prior art oil refining system UAE medium gross margin versus an integrated hydroproeessing and gasification system UAE medium gross margin in accordance with an exemplary embodiment.
  • the application is directed to methods and systems for integrating two or more industrial processes.
  • the application is directed to methods and systems for integrating hydroproeessing and gasification processes to reduce emissions, reduce by-products, and increase refining efficiency.
  • hydroproeessing and gasification processes to reduce emissions, reduce by-products, and increase refining efficiency.
  • FIG. 2 shows a flowchart of an integrated hydroprocessing and gasification system 200 that illustrates the equipment utilized in an oil processing facility 210 in accordance with an exemplary embodiment.
  • the integrated hydroprocessing and gasification system 200 comprises an oil processing facility 210 and a gasification facility 290. As shown, the oi!
  • processing faculty 210 comprises a first distillation unit steam heater 215, a first distillation unit 220, a second distillation unit steam heater 225, a second distillation unit 230, a distillate upgrader steam heater 235, a distillate upgrader 240, a distillate finisher steam heater 245, a distillate finisher 250, a bottoms upgrader steam heater 255, a bottoms upgrader 260, a deasphalter steam heater 265, and a deasphalter 270.
  • a steam heater is illustrated with respect to each of the equipment in the oil processing facility, other types of no emission heaters may be used without departing from the scope and spirit of the exemplary embodiment.
  • a heavy feed and diluent stream 212 comprising heavy crude and diluent flows into the first distillation unit steam heater 215 and is heated via high pressure steam to a desired temperature to facilitate separation of the diluent from the heavy crude.
  • the desired temperature may vary and is known to those of ordinary skill in the art.
  • the heavy feed and diluent stream 212 may be sent from a storage tank (not shown) or directly from a pipeline (not shown).
  • Some non- limiting examples of heavy crude include, but is not limited to, Bitumen crudes, Arab heavy crude, and United Arab Emirates crude.
  • the high pressure steam enters the first distillation unit steam heater 215 via a high pressure steam inlet stream 292 and exits the first distillation unit steam heater 215 via a high pressure steam outlet stream 293.
  • the high pressure steam inlet stream 292 is produced in the gasification facility 290, which will be described below.
  • a first distillation unit steam heater outlet stream 218 exits the first distillation unit steam heater 215 and enters the first distillation unit 220.
  • the first distillation unit 220 comprises a distillation column (not shown) and may include various other equipment (not shown) such as separators, drums, pumps, condensers, and reboilers.
  • various other equipment such as separators, drums, pumps, condensers, and reboilers.
  • the diluent is separated from the rest of the components within the first distillation unit steam heater outlet stream 218 and is recycled so that it may be added to additional incoming heavy crude.
  • the diluent exits the first distillation unit 220 via a diluent outlet stream 222.
  • the remaining components of the first distillation unit steam heater outlet stream 218 include light components and heavy components which exit the first distillation unit 220 and enter the second distillation unit steam heater 225 via a first distillation unit bottoms stream 224.
  • the first distillation unit bottoms stream 224 flows into the second distillation unit steam heater 225 and is heated via high pressure steam to a desired temperature to facilitate separation of the first distillation unit bottoms stream 224 into a light fraction, a heavy fraction, and a vac bottoms.
  • the desired temperature may vary and is known to those of ordinary skill in the art.
  • the high pressure steam enters the second distillation unit steam heater 225 via the high pressure steam inlet stream 292 and exits the second distillation unit steam heater 225 via the high pressure steam outlet stream 293.
  • the high pressure steam inlet stream 292 is produced in the gasification facility 290, which will be described below.
  • a second distillation unit steam heater outlet stream 228 exits the second distillation unit steam heater 225 and enters the second distillation unit 230.
  • the second distillation unit 230 comprises a distillation column (not shown) and may include various other equipment (not shown) such as .separators, drums, pumps, condensers, and reboilers.
  • the second distillation unit steam heater outlet stream 228 enters the second distillation unit 230
  • the second distillation unit steam beater outlet stream 228 is separated into various components, including a light fraction, a heavy fraction, and a vac bottoms.
  • the light fraction exits the second distillation unit 230 via a second distillation unit light fraction outlet stream 231.
  • the heavy fraction exits the second distillation unit 230 via a second distillation unit heavy fraction outlet stream 232.
  • the vac bottoms exits the second distillation unit 230 via a second distillation unit vac bottoms outlet stream 233.
  • the second distillation unit heavy fraction outlet stream 232 combines with a deasphalter light oil outlet stream 271 and a bottoms upgrader heavy oil outlet stream 261 and then enters the distillate upgrader steam heater 235.
  • the deasphaiter light oil outlet stream 273 and the bottoms upgrader heavy oil outlet stream 261 will be further described below.
  • the second distillation unit heavy fraction outlet stream 232, the deasphalter light oil outlet stream 271, and the bottoms upgrader heavy oil outlet stream 261 flow into the distillate upgrader steam heater 235 and is heated via high pressure steam to a desired temperature to facilitate separation of the streams 232, 271, 261 into light products and heavy products. Additionally, a distillate upgrader hydrogen inlet stream 298 also enters the distillate upgrader steam heater 235 for heating and mixes with streams 232, 271, 261 prior to entering the distillate upgrader 240.
  • the desired temperature may vary and is known to those of ordinary skill in the art.
  • the high pressure steam enters the distillate upgrader steam heater 23S via the high pressure steam inlet stream 292 and exits the distillate upgrader steam heater 235 via the high pressure steam outlet stream 293.
  • the high pressure steam inlet stream 292 is produced in the gasification facility 290, which will be described below.
  • a distillate upgrader steam heater outlet stream 238 exits the distillate upgrader steam heater 235 and enters the distillate upgrader 240.
  • the distillate upgrader 240 comprises a reactor/reactors (not shown) and may include various other equipment (not shown) such as distillation columns, separators, drums, pumps, condensers, and reboilers. According to some embodiments, the reactor may be combined with the distillation column. Once the distillate upgrader steam heater outlet stream 238 enters the distillate upgrader 240, the distillate upgrader steam heater outlet stream 238 reacts with the hydrogen and catalyst present within the reactor and is separated into a light product and a heavy product.
  • the light products exit the distillate upgrader 240 via a distillate upgrader light product outlet stream 242 and may be sent to an acid gas removal system (not shown) located within the gasification facility 290.
  • the heavy products exit the distillate upgrader 240 via a distillate upgrader heavy product outlet stream 244.
  • the distillate upgrader heavy product outlet stream 244 combines with the second distillation unit light fraction outlet stream 231 and a bottoms upgrader light oil outlet stream 262 and then enters the distillate finisher steam heater 245.
  • the distillate upgrader 240 may comprise at least two reactors coupled together in series and an inter-stage vapor separation. These two reactors may be ebullated bed reactors.
  • the use of ebulating bed hydroprocessing allows the heat of reaction to supply the required heat for the operation. This reduces the feed preheat requirements to a temperature level achievable by high pressure steam heaters.
  • the reactors are ebullated bed reactors, the reactors may be any type of reactor, including but not limited to ebullated bed reactors, fixed bed reactors, or a combination of these types of reactors.
  • the catalyst used in these reactors may comprise hydrotrating extrudates or trilobes type which includes, but is not limited to, Criterion HDS-424, Criterion DN-200, or Axcns HTS- 358. Although some non-limiting examples have been provided for the catalysts, any type of catalyst used for treating crude oil may be used without departing from the scope and spirit of the exemplary embodiment.
  • distillate upgrader heavy product outlet stream 244, the second distillation unit light fraction outlet stream 231, and the bottoms upgrader light oil outlet stream 262 flow into the distillate finisher steam heater 245 and is heated via high pressure steam to a desired temperature to facilitate separation of the streams 244, 231 , 262 into fight products and diesel/jet fuel. Additionally, a distillate finisher hydrogen inlet stream 296 also enters the distillate finisher steam heater 245 for heating and mixes with streams 244, 231, 262 prior to entering the distillate finisher 250.
  • the desired temperature may vary and is known to those of ordinary skill in the art.
  • the high pressure steam enters the distillate finisher steam heater 245 via the high pressure steam inlet stream 292 and exits the distillate finisher steam heater 245 via the high pressure steam outlet stream 293.
  • the high pressure steam iniet stream 292 is produced in the gasification facility 290, which will be described below.
  • a distillate finisher steam heater outlet stream 248 exits the distillate finisher steam heater 245 and enters the distillate finisher 250.
  • the distillate finisher 250 comprises a reactor/reactors (not shown) and may include various other equipment (not shown) such as distillation columns, separators, drums, pumps, condensers, and reboilers. According to some embodiments, the reactor may be combined with the distillation column. Once the distillate finisher steam heater outlet stream 248 enters the distillate finisher 250, the distillate finisher steam heater outlet stream 248 reacts with the hydrogen and catalyst present within the reactor and is separated into a light product and a diesel/jet fuel.
  • the tight products exit the distillate finisher 250 via a distillate finisher light product outlet stream 252 and may be combined with the distillate upgrader light product outlet stream 242 before being sent to the acid gas removal system (not shown) located within the gasification facility 290.
  • the diesel/jet fuel exits the distillate finisher 250 via a diesel/jet fuel stream 254 and may then be collected, stored, and sold.
  • the distillate finisher 250 may comprise at least two reactors coupled together in series and an inter-stage vapor separation.
  • reactors may be ebullated bed reactors.
  • the use of ebulating bed hydroprocessingg allows the heat of reaction to supply the required heat for the operation. This reduces the feed preheat requirements to a temperature level achievable by high pressure steam heaters.
  • the reactors may be any type of reactor, including but not limited to ebuilated bed reactors, fixed bed reactors, or a combination of these types of reactors.
  • the catalyst used in these reactors may comprise hydrotrating extrudates or trilobes type which includes, but is not limited to, Criterion HDS-424, Criterion DN-200, or Axens HTS-358. Although some non-limiting examples have been provided for the catalysts, any type of catalyst used for treating crude oil may be used without departing from the scope and spirit of the exemplary embodiment.
  • the second distillation unit vac bottoms outlet stream 233 and a deasphaiter heavy oil outlet stream 272 flow into the bottoms upgrader steam heater 255 and is heated via high pressure steam to a desired temperature to facilitate separation of the streams 233, 272 into a light oil, a heavy oil, and a vac bottoms, lite deasphaiter heavy oil outlet stream 272 will be further described below.
  • a bottoms upgrader hydrogen inlet stream 294 also enters the bottoms upgrader steam heater 255 for heating and mixes with streams 233, 272 prior to entering the bottoms upgrader 260.
  • the desired temperature may vary and is known to those of ordinary skill in the art.
  • the high pressure steam enters the bottoms upgrader steam heater 255 via the high pressure steam inlet stream 292 and exits the bottoms upgrader steam heater 255 via the high pressure steam outlet stream 293.
  • lite high pressure steam inlet stream 292 is produced in the gasification facility 290, which will be described below.
  • a bottoms upgrader steam heater outlet stream 2SS exits the bottoms upgrader steam heater 255 and enters the bottoms upgrader 260.
  • the bottoms upgrader 260 comprises a reactor/reactors (not shown) and may include various other equipment (not shown) such as distillation columns, separators, drums, pomps, condensers, and reboilers. According to some embodiments, the reactor may be combined with the distillation column.
  • the bottoms upgrader steam heater outlet stream 258 Once the bottoms upgrader steam heater outlet stream 258 enters the bottoms upgrader 260, the bottoms upgrader steam heater outlet stream 258 reacts with the hydrogen and catalyst present within the reactor and is separated into a light oil, a heavy oil, and a vac bottoms.
  • the light oil exits the bottoms upgrader 260 via the bottoms upgrader light oil outlet stream 262 and is combined with the distillate upgrader heavy product outlet stream 244 and the second distillation unit light fraction outlet stream 231 prior to entering the distillate finisher steam heater 245, as described above:.
  • the heavy oil exits the bottoms upgrader 260 via the bottoms upgrader heavy oil outlet stream 261 and is combined with the second distillation unit heavy fraction outlet stream 232 and the deasphalter light oil outlet stream 271 prior to entering the distillate upgrader steam heater 235, as also described above.
  • the vac bottoms exits the bottoms upgrader 260 via a bottoms upgrader vac bottoms outlet stream 263, which flows to the deasphalter 270 via the deasphalter steam heater 265.
  • the bottoms upgrader 260 may comprise at least two reactors coupled together in series and an inter-stage vapor separation. These two reactors may be ebultated bed reactors.
  • the reactors are ebullated bed reactors
  • the reactors may be any type of reactor, including but not limited to ebullated bed reactors, fixed bed reactors, or a combination of these types of reactors.
  • the catalyst used in these reactors may comprise sediment control extrudates type which includes, but is not limited to, Criterion TEX-2710, Criterion TEX-2910, Criterion TEX-2710N, or Criterion TEX-2731.
  • Criterion TEX-2710 Criterion TEX-2910
  • Criterion TEX-2710N Criterion TEX-2731
  • the bottoms upgrader vac bottoms outlet stream 263 flows into the deasphalter steam heater 265 and is heated via high pressure steam to a desired temperature. It is then mixed with an extracting solvent (not shown) in an extractor (not shown). The extractor temperature is controlled to facilitate separation of the bottoms upgrader vac bottoms outlet stream 263 into a light deasphalted oil, a heavy deasphalted oil, and an asphalt. The desired temperature may vary and is known to those of ordinary skill in the art.
  • the high pressure steam enters the deasphalter steam heater 265 via the high pressure steam inlet stream 292 and exits the deasphalter steam heater 265 via the high pressure steam outlet stream 293.
  • the high pressure steam inlet stream 292 is produced in the gasification facility 290, which will be described below.
  • a deasphalter steam heater outlet stream 268 exits the deasphalter steam heater 265 and enters the deasphalter 270.
  • the deasphalter 270 comprises an extractor (not shown) and may include various other equipment (not shown) such as distillation columns, separators, drums, pumps, condensers, and reboilers. According to some embodiments, the extractor may be combined with the distillation column. Once the deasphalter steam heater outlet stream 268 contacts with the solvent present within the extractor and is separated into a light deasphalted [DA] oil, a heavy deasphalted [DA] oil, and an asphalt.
  • DA light deasphalted
  • DA heavy deasphalted
  • the light DA oil exits the deasphalter 270 via the deasphalter light DA oil outlet stream 271 and is combined with the second distillation unit heavy fraction outlet stream 232 and the bottoms upgrader heavy oil outlet stream 261 prior to entering the distillate upgrader steam heater 235, as described above.
  • the heavy DA oil exits the deasphalter 270 via the deasphalter heavy DA oil outlet stream 272 and is combined with the second distillation unit vac bottoms outlet stream 233 prior to entering the bottoms upgrader steam heater 255, as also described above.
  • the asphalt exits the deasphalter 270 via an asphalt stream 273, which flows as one of the feed sources to the gasification facility 290.
  • the deasphalter 270 may comprise at least one or two extractors.
  • the extracting solvents may include, but are not limited to, C 3 , C 4 , C 5 , C 6 , or C 7
  • the gasification facility 290 may be of any type of gasification facility that is capable of producing hydrogen and high pressure steam. As shown in Figure 2, the asphalt stream 273 and a coke stream 285 is fed into one or more gasifiers (not shown) in the gasification facility 290. The gasification facility 290 processes the asphalt stream 273 and the coke stream 285 to produce at least the distillate upgrader hydrogen inlet stream 298, the distillate finisher hydrogen inlet stream 296, the bottoms upgrader hydrogen inlet stream 294, and the high pressure steam inlet stream 292. The gasification facility 290 also comprises an acid gas removal system (not shown) that processes the distillate upgrader light product outlet stream 242 and the distillate finisher light product outlet stream 252, which both contain hydrogen sulfide.
  • FIG. 3 shows a flowchart of an integrated hydroprocessing and gasification system 200 that illustrates the equipment utilized in the gasification facility 290 in accordance with an exemplary embodiment.
  • the integrated hydroprocessing and gasification system 200 comprises an oil processing facility 210 and a gasification facility 290.
  • the gasification facility 290 comprises an air separation unit 310, at least one gasifier 320, 330, 340, 3S0, 360, 370, a first stream treating unit 380, and a second stream treating unit 390.
  • the air separation unit 310 (3x40% or 2x60%) separates air into at least a nitrogen (“N 2 ”) component and an oxygen (“O 2 ") component At least some of the O 2 component exits the air separation unit 310 through an air separation unit outlet stream 31 1.
  • the air separation unit outlet stream Upon exiting the air separation unit 310, the air separation unit outlet stream enters an O 2 supply header 312, which serves to distribute the O 2 to each of the at least one gasifier 320, 330, 340, 350, 360, 370.
  • the use of the oversized air separation unit 310 may result in an increase in overall production of SNG, hydrogen, and/or steam.
  • the at least one gasifier 320, 330, 340, 350, 360, 370 comprises a first gasifier 320 (1x25%), a second gasifier 330 (1x25%), a third gasifier 340 (1x25%), a fourth gasifier 350 (1x25%), a fifth gasifier 360 (1x10%), and a sixth gasifier 370 (1x10%).
  • the coke stream 285 is fed into each of the first gasifier 320, the second gasifier 330, the third gasifier 340, and the fourth gasifier 350, while the asphalt stream 273, 304 from the oil processing facility 210 is fed into each of the fifth gasifier 360 and the sixth gasifier 370.
  • Each of the at least one gasifier 320, 330, 340, 350, 360, 370 produces a slag stream (not shown) and a gasifier outlet stream 322, 332, 342, 352, 362, 372.
  • the slag stream (not shown) may comprise metals naturally occurring in. the coke stream 285 and the asphalt stream 273, 304, and added minerals to control the melting point of the slag stream (not shown).
  • the slag stream (not shown) may be utilized as an aggregate in concrete manufacturing and/or the manufacturing of other materials.
  • the gasifier outlet stream 322, 332, 342, 352, 362, 372 comprises about 35% CO, about 15% hydrogen ("H 2 "), about 40% water (“H 2 O"), and about 10% carbon dioxide ("CO 2 ").
  • the conversion of the coke stream 285, the asphalt stream 273, 304, and the air separation unit outlet stream 311 into the slag stream (not shown) and the gasifier outbt stream 322, 332, 342, 352, 362, 372 is an exothermic process and as a result, a high pressure saturated steam stream (not shown) also is produced, which may be used in a methanation unit 383.
  • specific compositions have been provided for the gasifier outlet stream 322, 332, 342, 352, 362, 372, alternative compositions may be achieved without departing from the scope and spirit of the exemplary embodiment.
  • gasifier outlet stream 322, 332, 342, 352, 362, 372 exits the at least one gasifier 320, 330, 340, 350, 360, 370 and flows into a gasifier outlet distribution header 374.
  • a first distribution header outlet stream 376 exits the gasifier outlet distribution header 374 and flows into the first stream treating unit 380 (2x50%), which may be designed to process anyone of the gasifier outlet stream 322, 332, 342, 352, 362, 372 so mat SNG is produced .
  • a second distribution header outlet stream 378 exits the gasifier outlet distribution header 374 and flows into the second stream treating unit 390 (1x100%), which may be designed to process anyone of the gasifier outlet stream 322, 332, 342, 352, 362, 372 so that hydrogen for the oil processing facility 210 is produced.
  • the first stream treating unit 380 comprises an acid gas removal unit ("AGR") 381, a sulfur recovery unit (“SRU'') 382, and a methanatio ⁇ unit (“MU”) 383.
  • the first distribution header outlet stream 376 flows into the AGR 381.
  • the AGR 381 may utilize SelexolTM for hydrogen sulfide ("H 2 S") removal and CO 3 capture. As a result, a vapor CO 2 stream 389 is produced.
  • the vapor CO 2 stream 389 may be compressed into a liquid CO 2 , which may then be utilized for enhanced oil recovery by pumping the liquid CO 2 into the ground to increase the production of oil.
  • the CO 2 may be used in other areas of the facility, for example, during startup processes or even sold.
  • the AGR 381 also produces an acid gas stream (not shown), which enters the SRU 382 to produce a sulfur stream 388 and a recycle tail gas stream (not shown).
  • the sulfur stream 388 comprises sulfur and may be sold to fertilizer plants and the like.
  • the recycle tail gas stream (not shown) comprises some sulfur and may be recycled back into the AGR 381.
  • the AGR 381 also produces an acid gas removal system outlet stream
  • the acid gas removal system outlet stream (not shown) comprising mainly of CO and H 2 . Since the CO 2 has been removed within the AGR 381, the acid gas removal system outlet stream (not shown) comprises about 25% CO and about 75% H 2 .
  • the acid gas removal system outlet stream (not shown) may be sold as syngas to market or consumed by other systems requiring the syngas (not shown).
  • the syngas may be used as ammonia, methanol, or hydrogen, or be utilized in the production of power or chemicals.
  • the acid gas removal system outlet stream may then enter a MU 383, which includes one or more methanation reactors (not shown).
  • the MU 383 converts the acid gas removal system outlet stream (not shown) into a methanation unit outlet stream 387.
  • the methanation unit outlet stream 387 comprises SNG and may be sold to market or consumed by other systems requiring the syngas.
  • a portion of the methanation unit outlet stream 387 may enter combustion turbines (not shown) to produce power to be sold to market.
  • the high pressure saturated steam stream (not shown) from the at least one gasifier 320, 330, 340, 350, 360, 370 may enter the MU 383.
  • the conversion of the acid gas removal system outlet stream (not shown) into the methanation unit outlet stream 387 in the MU 383 is an exothermic reaction and as a result, the high pressure saturated steam stream (not shown) is converted to a high pressure superheated steam stream 292, which may be utilized in at least the steam heaters of the oil processing facility 210 and also in a steam turbine (not shown) to produce power to be sold to market or consumed by other systems requiring the power.
  • the second stream treating unit 390 comprises an acid gas removal unit (“AGR") 391 and a pressure swing absorber ("PSA”) 392.
  • the second distribution header outlet stream 378 flows into the AGR 391.
  • the distillate upgrader light product outlet stream 242, which includes the distillate finisher light product outlet stream 252 exits the oil processing facility 210 and enters the AGR 391 for treating.
  • the AGR 391 may utilise SelexoiTM for hydrogen sulfide ("H 2 S”) removal and COa capture.
  • H 2 S hydrogen sulfide
  • COa vapor CO 2 stream 394 is produced.
  • the vapor CO 2 stream 394 may be compressed into a liquid CO 2 , which may then be utilized tor enhanced oil recovery hy pumping the liquid CO 2 into the ground to increase the production of oil.
  • the CO 2 may be used in other areas of the facility, for example, during startup processes or even sold.
  • the AGR 391 also produces an acid gas stream 398, which enters the
  • the AGR 391. also produces an acid gas removal system outlet stream (not shown) comprising mainly of CO and H 2 .
  • the acid gas removal system outlet stream may then enter the PSA 392, which separates the gases and produces a high purity hydrogen stream that exits the PSA 392 via the bottoms upgrader hydrogen inlet stream 294, which includes the distillate upgrader hydrogen inlet stream 298 and the distillate finisher hydrogen inlet stream 296 and is utilized in at least the distillate upgrader 240 ( Figure 2). the distillate finisher 250 ( Figure 2), and the bottoms upgrader 260 ( Figure 2 ⁇ of the oil processing facility 210.
  • the PSA 392 also produces a tail gas stream 396, which may he recycled back into a shift reactor system (not shown) that may be located between the at least one gasifter 320, 330, 340, 350, 360, 370 and the first stream treating unit 380.
  • This tail gas stream 396 is eventually converted to SNG, which thereby eliminates the need to combust this tail gas stream 396.
  • the oil processing facility 210 may be of any type of oil processing facility that is capable of utilizing at least hydrogen and/or high pressure steam produced by the gasification facility 290. As shown in Figure 3, the heavy feed and diluent stream 212, the high pressure superheated steam stream 292. and the bottoms upgrader hydrogen inlet stream 294, which includes the distillate upgrader hydrogen inlet stream 298 and the distillate finisher hydrogen inlet stream 296. are led into the oil processing facility 210. The oil processing facility 210 processes the heavy feed and diluent stream 212 to produce at least the asphalt stream 273, the distillate upgrader light product outlet stream 242. which includes the distillate finisher light product outlet stream 252, the diluent outlet stream 222, and the diesel/jet fuel stream 254.
  • the gasification facility may have an alternate steam treating unit having at least an AGR, a SRU, and a PSA without departing from the scope and spirit of the exemplary embodiment.
  • an alternate steam treating unit having at least an AGR, a SRU, and a PSA
  • AGR AGR
  • SRU AGR
  • PSA PSA
  • the embodiment described above illustrates a gasification facility having at least one gasifier capable of being fed both the coke stream and the asphalt stream
  • the gasification facility may have gasifiers designed to be fed only the asphalt stream without departing from the scope and spirit of the exemplary embodiment.
  • the above embodiment illustrates that the high pressure superheated steam stream generated from the gasification facility is used in the steam heaters of the oil processing facility, any type of high pressure steam, including saturated steam, generated from the gasification facility may be used in the steam heaters of the oil processing facility without departing from the scope and spirit of the exemplary embodiment.
  • the distillate upgrader 240 may comprise at least two reactors coupled together in series and an inter-stage vapor separation. These two reactors may be ebullated bed reactors.
  • the use of ebulating bed hydroprocessing allows the heat of reaction to supply the required heat for the operation. This reduces the feed preheat requirements to a temperature level achievable by high pressure steam heaters.
  • the reactors are ebullated bed reactors, the reactors may be any type of reactor, including but not limited to ebuliated bed reactors, fixed bed reactors, or a combination of these types of reactors.
  • the catalyst used in the first stage reactor may comprise hydroconversion extrudates type which includes, but is not limited to, Criterion HDS-2443B or TEX-2910.
  • the catalyst used in the second stage reactor may comprise hydrotrating extrudates or trilobes type which includes, but is not limited to, Criterion HDS-424, Criterion DN- 200, or Axens HTS-358.
  • the bottoms upgrader 260 may comprise at least two reactors coupled together in series and an inter-stage vapor separation.
  • reactors may be ebullated bed reactors.
  • the use of ebulating bed hydroprocessing allows the heat of reaction to supply the required heat for the operation. This reduces the feed preheat requirements to a temperature level achievable by high pressure steam heaters.
  • the reactors may be any type of reactor, including but not limited to ebuilated bed reactors, fixed bed reactors, or a combination of these types of reactors.
  • the catalyst used in these reactors may comprise sediment control extrudates type which includes, but is not limited to, Criterion TEX- 2710, Criterion TEX-2910, Criterion TEX-2710N, or Criterion TEX-2731.
  • the reactors of the distillate finisher 250 may be configured similarly to the reactors of the distillate upgrader 240.
  • the extractors of the deasphalter 270 may be configured similarly to the reactors of the bottoms upgrader 260.
  • the deasphalter light DA oil outlet stream 271 and the deasphalter heavy DA oil outlet stream 272 are now fed into the first stage reactor of the distillate upgrader 240 and a bottoms stream (not shown) from the distillate upgrader 240 may now be fed into the reactor of the bottoms upgrader 260.
  • This configuration may increase the total crude rate to the refinery.
  • Figure 4A shows a bitumen yield graph 400 comparing a prior art oil refining system bitumen crude yield 402 versus an integrated hydroprocessing and gasification system bitumen crude yield 404 in accordance with an exemplary embodiment.
  • the bitumen yield graph 400 illustrates the prior art oil refining system bitumen crude yield 402 and the integrated hydroprocessing and gasification system bitumen crude yield 404 on the x-axis and a volumetric yield percentage 406 on the y- axis.
  • the volumetric yield percentage which comprises a distillate yield 410 and a naphtha and light products gas yield 420, is about 85%.
  • the distillate yield 410 comprises diesel fuel, jet fuel, and other valuable fuels and has about 40% volumetric yield.
  • the naphtha and light products gas yield 420 has about 45% volumetric yield.
  • the volumetric yield percentage which comprises a distillate yield 430 and a naphtha and light products gas yield 440, is about 120%.
  • the distillate yield 430 comprises diesei fuel, jet fuel, and other valuable fuels and has about 85% volumetric yield.
  • the naphtha and light products gas yield 440 has about 35% volumetric yield.
  • the distillate yield 410, 430 has a margin of about $l5-$25/barrel, while the naphtha and light products gas yield 420, 440 has a margin of about $0-$5/barrel.
  • the profitability margin substantially increases because greater volumetric yield percentages of higher value fuels are produced using the integrated hydroprocessing and gasification system in accordance with an exemplary embodiment versus the prior art oil refining system.
  • Figure 4B shows a bitumen margin graph 430 comparing a prior art oil refining system cost 451 versus an integrated hydroprocessing and gasification system cost 453 and comparing a prior art oil refining system bitumen margin 452 versus an integrated hydroprocessing and gasification system bitumen margin 454 in accordance with an exemplary embodiment
  • the information illustrated within the bitumen margin graph 450 is for refining only.
  • the bitumen margin graph 450 illustrates the prior art oil refining system cost 451, the prior art oil refining system bitumen gross margin 452, the integrated hydroprocessing and gasification system cost 453, and the integrated hydroprocessing and gasification system bitumen gross margin 454 on the x-axis and a dollar/barrel value 456 on the y-axis.
  • the total cost which comprises a capital recovery cost 460, an operating and maintenance cost 462, a fuel cost 464, and a transportation cost 466, is about $28 per barrel.
  • the capita! recovery cost 460 is about $7 per barrel.
  • the operating and maintenance cost 462 is about $2 per barrel.
  • the fuel cost 464 is about $1 per barrel.
  • the transportation cost 466 is about $18 per barrel.
  • the total cost which comprises a capita! recovery cost 480, an operating and maintenance cost 482, a fuel cost 484, and a transportation cost 486, is about $26 per barrel.
  • the capital recovery cost 480 is about $14 per barrel.
  • the operating and maintenance cost 482 is about $3 per barrel.
  • the fuel cost 484 is about $1 per barrel.
  • the transportation cost 486 is about $8 per barrel.
  • the total cost for refining oil is slightly less when utilizing the integrated hydroprocessing and gasification system in accordance with an exemplary embodiment versus the prior art oil refining system.
  • bitumen crude margin 470 is about $30 per barrel.
  • bitumen crude margin 490 is about $72 per barrel.
  • the gross margin for refining oil is substantially higher when utilizing the integrated hydroprocessing and gasification system in accordance with an exemplary embodiment versus the prior art oil refining system.
  • Figure 5A shows a comparison between a prior art oil refining system
  • Arab heavy crude yield flowchart 500 versus an integrated hydroprocessing and gasification system Arab heavy crude yield flowchart 520 in accordance with an exemplary embodiment.
  • the prior art oil refining system Arab heavy crude yield flowchart 500 illustrates an Arab heavy crude stream 504 and a naturai gas stream 506 entering a prior art oil refining system 510.
  • the prior art oil refining system 510 processes the Arab heavy crude stream 504 and the natural gas stream 506 and produces a coke stream 512, a distillates stream 514, and a light product gas and gasoline stream 516.
  • the flowrate of the Arab heavy crude stream 504 may be about 400 million barrels per day ("MBD'*) and the flowrate of the natural gas stream 506 may be about 130 million standard cubic feet per day (“MMSCFD").
  • MBD'* standard tons per day
  • MMSCFD standard cubic feet per day
  • These feed flowrates produce the coke stream 512 having a flowrate of about 5000 standard tons per day (sTPD), the distillates stream 514 having a flowrate of about 190 MBD, and the light product gas and gasoline stream 516 having a flowrate of about 190 MBD.
  • This prior art refining system 510 produces about a 95% yield when having the Arab heavy crude stream 504 enter the prior art refining system 510.
  • an exemplary flowrate has been provided for each of these streams, alternative stream flowrates may be produced without departing from the scope and spirit of the exemplary embodiment.
  • the integrated hydroprocessing and gasification system Arab heavy crude yield flowchart 520 illustrates an Arab heavy crude stream 524 and a coke stream 526 entering an integrated hydroprocessing and gasification system 530 in accordance with an exemplary embodiment.
  • the integrated hydroprocessing and gasification system 530 processes the Arab heavy crude stream 524 and the coke stream 526 and produces a distillates stream 534 and a light product gas and gasoline stream 536.
  • the flowrate of the Arab heavy crude stream 524 may be about 400 MBD and the flowrate of the coke stream 526 may be about 10,000 sTPD.
  • This integrated hydroprocessing and gasification system 530 produces about a 110% yield when having the Arab heavy crude stream 524 enter the integrated hydroprocessing and gasification system 530.
  • an exemplary flowrate has been provided for each of these streams, alternative stream flowrates may be produced without departing from the scope and spirit of the exemplary embodiment.
  • the percent yield substantially increases when utilizing the integrated hydroprocessing and gasification system 530 in accordance with an exemplary embodiment than when utilizing the prior art oil refining system 510. This yield increases because byproducts are not formed in the integrated hydroprocessing and gasification system 530 and hydrogen is not produced in the integrated hydroprocessing and gasification system 530 by using valuable natural gas feed streams.
  • FIG. 5B shows an Arab heavy margin graph 550 comparing a prior an oil refining system cost 551 versus an integrated hydroprocessing and gasification system cost 553 and comparing a prior art oil refining system Arab heavy gross margin 552 versus an integrated hydroprocessing and gasification system Arab heavy gross margin 554 in accordance with an exemplary embodiment.
  • the Arab heavy margin graph 450 illustrates the prior art oil refining system cost 551, the prior art oil refining system Arab heavy gross margin 552, the integrated hydroprocessing and gasification system cost 553, and the integrated hydroprocessing and gasification system Arab heavy gross margin 554 on the x-axis and a dollar/barrel value 556 on the y-axis.
  • the total cost which comprises a capital recovery cost 560, an operating and maintenance cost 562, and a fuel cost 564, is about $19 per barrel.
  • the capital recovery cost 560 is about $12 per barrel.
  • the operating and maintenance cost 562 is about $2 per barrel.
  • the fuel cost 564 is about $5 per barrel.
  • the total cost which comprises a capital recovery cost 580, an operating and maintenance cost 582. and a fuel cost 584, is about $16 per barrel.
  • the capital recovery cost 580 is about $12 per barrel.
  • the operating and maintenance cost 582 is about $3 per barrel.
  • the fuel cost 584 is about $1 per barrel.
  • the total margin, which comprises an Arab heavy margin 570 is about $22 per barrel.
  • the total margin which comprises an Arab heavy margin 590 and a CO 2 and N 2 margin 592, is about $46 per barrel.
  • the Arab heavy margin 590 is about $43 per barrel.
  • the CO 2 and N 2 margin 592 is about $3 per barrel.
  • the gross margin for refining oil is substantially higher when utilizing the Integrated hydroprocessing and gasification system in accordance with an exemplary embodiment versus the prior art oil refining system.
  • Figure 6A shows a comparison between a prior art oil refining system UAE crude yield flowchart 600 versus an integrated hydroprocessing and gasification system UAE crude yield flowchart 620 in accordance with an exemplary embodiment.
  • the prior art oil refining system Arab heavy crude yield flowchart 600 illustrates an UAE crude stream 604 and a natural gas stream 606 entering a prior art oil refining system 610.
  • the prior art oil refining system 610 processes the UAE crude stream 604 and the natural gas stream 606 and produces a coke stream 612, a distillates stream 614, and a light product gas and gasoline stream 616.
  • the f ⁇ owrate of the UAE crude stream 604 may be about 500 MBD and the flowrate of the natural gas stream 606 may be about 150 MMSCFD.
  • These feed flowrates produce the coke stream 612 having a flowrate of about 5000 sTPD, the distillates stream 614 having a flowrate of about 260 MBD, and the light product gas and gasoline stream 616 having a flowrate of about 240 MBD.
  • This prior art refining system 610 produces about a 98% yield when having the UAE crude stream 604 enter the prior art refining system 610.
  • an exemplary flowrate has been provided for each of these streams, alternative stream flowrates may be produced without departing from the scope and spirit of the exemplary embodiment.
  • the integrated hydroprocessing and gasification system UAE crude yield flowchart 620 illustrates an UAB crude stream 624 and a coke stream 626 entering an integrated hydroproeessing and gasification system 630 in accordance with an exemplary embodiment.
  • the integrated hydroprocessing and gasification system 630 processes the UAE crude stream 624 and the coke stream 626 and produces a distillates stream 634 and a light product gas and gasoline stream 636.
  • the flowrate of the UAE crude stream 624 may be about 500 MBD and the flowrate of the coke stream 626 may be about 10,000 sTPD.
  • this integrated hydroprocessing and gasification system 630 produces about a 109% yield when having the UAE crude stream 624 enter the integrated hydroprocessing and gasification system 630.
  • an exemplary flowrate has been provided for each of these streams, alternative stream flowrates may be produced without departing from the scope and spirit of the exemplary embodiment.
  • the percent yield substantially increases when utilizing the integrated hydroprocessing and gasification system 630 in accordance with an exemplary embodiment than when utilizing the prior art oil refining system 610. This yield increases because byproducts are not formed in the integrated hydroprocessing and gasification system 630 and hydrogen is not produced in the integrated hydroprocessing and gasification system 630 by using valuable natural gas feed streams.
  • FIG. 6B shows an UAB medium margin graph 650 comparing a prior art oil refining system cost 651 versus an integrated hydroprocessing and gasification system cost 653 and comparing a prior art oil refining system UAB medium gross margin 652 versus an integrated hydroprocessing and gasification system UAE medium gross margin 654 in accordance with an exemplary embodiment.
  • the UAE medium margin graph 650 illustrates the prior art oil refining system cost 651, the prior art oil refining system UAE medium gross margin 652, the integrated hydroprocessing and gasification system cost 653, and the integrated hydroprocessing and gasification system UAB medium gross margin 654 on the x-axis and a dollar/barrel value 656 on the y-axis.
  • the total cost which comprises a capital recovery cost 660, an operating and maintenance cost 662, and a fuel cost 664, is about $18 per barrel.
  • the capital recovery cost 660 is about $11 per barrel.
  • the operating and maintenance cost 662 is about $2 per barrel.
  • the fuel cost 664 is about $5 per barrel.
  • the total cost which comprises a capital recovery cost 680, an operating and maintenance cost 682, and a fuel cost 684, is about $15 per barrel.
  • the capital recovery cost 680 is about $12 per barrel.
  • the operating and maintenance cost 682 is about $2 per barrel.
  • the fuel cost 684 is about $1 per barrel.
  • the total cost for refining oil is slightly less when utilizing the integrated hydroprocessing and gasification system in accordance with an exemplary embodiment versus the prior art oil refining system.
  • the total margin which comprises an UAE medium margin 670
  • the total margin is about $20 per barrel.
  • the total margin which comprises an UAE, medium margin 690 and a CO 2 and N 2 margin 692
  • the UAE medium margin 690 is about $36 per barrel.
  • the CO 2 and N 2 margin 692 is about $2 per barrel.
  • the gross margin for refining oil is substantially higher when utilizing the integrated hydroprocessing and gasification system in accordance with an exemplary embodiment versus the prior art oil refining system.
  • the hydrogen gas is used in the hydroprocessing of the heavy crude oil to replace the carbon double and triple bonds, the carbon rings, and the single carbon bonds when the longer carbon chains are broken down into smaller carbon chains.
  • This process as described within one of the embodiments of the present invention, thereby increases the cetane number and makes the fuel cleaner burning and more environmentally friendly than the processes used in the prior art.
  • there are no fired heaters, fired boilers, methane reformers, or catalytic crackers used to refine the heavy crude oil instead, there are high pressure steam, heaters and an integrated gasification facility in accordance with some of ihe embodiments.

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  • Chemical & Material Sciences (AREA)
  • Organic Chemistry (AREA)
  • Engineering & Computer Science (AREA)
  • Inorganic Chemistry (AREA)
  • Combustion & Propulsion (AREA)
  • Chemical Kinetics & Catalysis (AREA)
  • Oil, Petroleum & Natural Gas (AREA)
  • Analytical Chemistry (AREA)
  • General Chemical & Material Sciences (AREA)
  • Health & Medical Sciences (AREA)
  • General Health & Medical Sciences (AREA)
  • Production Of Liquid Hydrocarbon Mixture For Refining Petroleum (AREA)

Abstract

L’invention concerne un système intégré d’hydrotraitement et de gazéification et un procédé d’exploitation du système intégré d’hydrotraitement et de gazéification. Le système intégré d’hydrotraitement et de gazéification comprend une installation de traitement du pétrole intégrée avec une installation de gazéification. L’installation de gazéification utilise une alimentation de charbon/coke moins coûteuse pour produire un courant d’hydrogène et un courant de vapeur à pression élevée. Le courant d’hydrogène fournit suffisamment d’hydrogène pour l’installation de traitement du pétrole, tandis que le courant de vapeur à pression élevée est utilisé pour préchauffer les courants qui entrent dans l’équipement de l’installation de traitement du pétrole dans un dispositif de chauffage à vapeur. Ces dispositifs de chauffage à vapeur éliminent essentiellement les émissions. Par ailleurs, aucun produit de fond brut lourd n’est formé dans l’installation de traitement du pétrole car le produit de fond est introduit dans l’installation de gazéification. Selon certains modes de réalisation, les réacteurs utilisés dans l’installation de traitement du pétrole peuvent être des réacteurs à combustible en suspension, qui utilisent la chaleur de réaction pour fournir la chaleur requise pour le fonctionnement.
PCT/US2009/062964 2008-11-04 2009-11-02 Intégration d’une gazéification et d’un hydrotraitement pour un raffinage à faibles émissions Ceased WO2010053865A1 (fr)

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US10494578B2 (en) 2017-08-29 2019-12-03 Saudi Arabian Oil Company Integrated residuum hydrocracking and hydrofinishing
US10836967B2 (en) 2017-06-15 2020-11-17 Saudi Arabian Oil Company Converting carbon-rich hydrocarbons to carbon-poor hydrocarbons

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US10836967B2 (en) 2017-06-15 2020-11-17 Saudi Arabian Oil Company Converting carbon-rich hydrocarbons to carbon-poor hydrocarbons
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US10723963B2 (en) 2017-08-29 2020-07-28 Saudi Arabian Oil Company Integrated residuum hydrocracking and hydrofinishing
US11118122B2 (en) 2017-08-29 2021-09-14 Saudi Arabian Oil Company Integrated residuum hydrocracking and hydrofinishing

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