US3929430A - Process for making synthetic fuel gas from crude oil - Google Patents

Process for making synthetic fuel gas from crude oil Download PDF

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US3929430A
US3929430A US359791A US35979173A US3929430A US 3929430 A US3929430 A US 3929430A US 359791 A US359791 A US 359791A US 35979173 A US35979173 A US 35979173A US 3929430 A US3929430 A US 3929430A
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fraction
crude oil
natural gas
synthetic natural
combined
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Rolland E Dixon
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Phillips Petroleum Co
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Phillips Petroleum Co
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    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G11/00—Catalytic cracking, in the absence of hydrogen, of hydrocarbon oils
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
    • C10G11/00—Catalytic cracking, in the absence of hydrogen, of hydrocarbon oils
    • C10G11/10—Catalytic cracking, in the absence of hydrogen, of hydrocarbon oils with stationary catalyst bed
    • 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

Definitions

  • This gas or fuel can be combined with the first :enke et T gas fraction either before or after hydrogen has been epp et a 3,531,267 9/1970 Gould 412/213 removed from 7 3,551,124 12/1970 Takayuki lwaki et al.
  • the invention provides a pro cess for converting a crude oil substantially entirely into a fuel gas or synthetic natural gas by steps involving distilling or otherwise separating a crude oil into at least the following streams: a gas stream containing some ethane and lighter gases including hydrogen, a stream containing essentially propane and butane, a stream containing gasoline and boiling up to about 400 F and a heavy residual stream, the first two streams being treated as in a caustic treater to remove sulfur and sulfur compounds therefrom, the third stream ob tained being hydrodesulfurized and the last stream being catalytically cracked to extinction to produce gaseous products and an additional gasoline stream which is hydrodesulfurized whereupon all except the first gaseous stream are combined and gasified under conditions known in the art to produce a synthetic natural gas which can be combined with the first obtained gas stream either before or after hydrogen has been removed therefrom thus having converted substantially all of the crude oil to a synthetic fuel gas or synthetic natural gas.
  • a gas stream containing some ethane and lighter gases including hydrogen
  • a crude oil is separated into several fractions containing components according to their distillation or fractionation boiling points, each fraction is treated under optimum conditions to produce a gas fraction, a gaseous hydrocarbon fraction, a liquid hydrocarbon fraction boiling up to about, say, 400 F and a top crude or heavy residual fraction, converting the heavy residual fraction by catalytic cracking substantially to an additional gaseous fraction and a gasoline fraction, treating each of the streams, however the crude oil is separated into its 2 constituents, or separated into fractions or streams, to remove sulfur and/or sulfur containing compounds therefrom, combining at least the substantially liquid streams obtained and feeding the combined streams as charge stock to a synthetic natural gas or fuel gas production operation and later, as desired, combining product thus obtained with one or more of the remaining streams obtained to produce a synthetic fuel gas or a synthetic natural gas.
  • the present invention converts a crude oil into a fuel gas or to a synthetic natural gas by an especially attractive route. It employs a minimum of well-developed steps.
  • a complete crude oil is charged to a crude distillation unit wherein it is separated into several, e.g., four product streams.
  • a single distillation zone 1 is shown for simplicity.
  • Crude oil entering at 2 is heated and flashed to separate light components from an unvaporized heavier portion.
  • the light gaseous components are then passed via pipe 3 directly to treater 14 while the liquid residue is fractionated in crude fractionator 2.
  • the crude fractionator may comprise two or even more fractionation towers, as one skilled in the art will know. Crude oil fractionation is well known in the art.
  • the distillation unit is designed to produce each of the four product streams with a specified composition especially suited for the conversion of each into a synthetic natural gas.
  • a preflash tower and a distillation column usually there will be used.
  • the overhead product stream 3 will be obtained from the flash tower and will contain ethane and lighter components. Therefore, according to the invention, it will need only to be desulfurized before use as a fuel gas.
  • the remaining heavier components in the flash tower bottoms in the original crude oil are reduced in molecular weight and are treated separately from overhead stream 3 as follows:
  • the propane and butane in the crude oil are separated as a second product from the distillation unit 2 as stream 4. This stream is easily desulfurized in the liquid state by caustic scrubbing in treater 13.
  • a C to about 400 F fraction is passed by 5 from the distillation unit to hydrodesulfurizing zone 12. This material can be converted to fuel gas without a preliminary cracking step. This fraction is desulfurized by catalytic hydrogenation in zone 12. The remaining heavy components of the crude oil, the about 400F- plus fraction, is cracked before conversion to fuel gas. This is done in heavy oil catalytic cracker 7 which, though it is like a conventional catalytic cracker, is operated under more severe cracking conditions to crack the heaviest components of the crude oil.
  • Products of the cracking step are: light gases which are combined by 8 with stream 3 from the distillation unit; a propane-butane stream which is combined by 9 with stream 4 from the distillation unit; and a catalytic gasoline stream 10.
  • the gasoline stream 10 is desulfurized by hydrogenation in unit 11 (similar to unit 12) and is then ready for conversion to fuel gas. All heavier components are recycled and cracked to extinction.
  • the crude oil in stream 2 after conventional desalting and heat exchange with bottoms stream 6 is passed at the rate of about 200,000 barrels per day into the lower portion of a preflash tower which distills as an overhead product all light components and the majority of the gasoline.
  • the heavier components are reheated in a furnace coil and are passed into the lower portion of crude oil fractionator.
  • the separation of crude oil into a plurality of cuts according to boiling point is practiced in oil refineries and specific details of such operations are known.
  • U.S. Pat. Nos. 3,567,628; 3,303,127; 3,301,778; and 3,297,566 give details of crude oil fractionation.
  • the preflash tower produces an overhead gaseous product stream containing ethane through light gasoline.
  • the overhead flash vapors are conventionally processed by oil absorption and fractionation to yield stream 3 consisting of ethane and lighter components at the rate of about 200 barrels per day (300,000 cu. ft. per day).
  • stream 4 consisting of propane and butane at the rate of about 5,600 barrels per day is also recovered from the flash tower overhead.
  • the remaining heavier components in the flash tower overhead are recovered as light gasoline and combined with similar material from the crude fractionator as stream 5 amounting to 49,200 barrels per day of material boiling from about 300 to about 400 F.
  • Temperature at the topof the preflash tower is about 320 F.
  • the reduced crude which is yielded as bottom product of the preflash tower is heated in a furnace coil to about 700 F and introduced to the crude oil fractionator.
  • the heavier gasoline fraction (300-400 F boiling range) is yielded as overhead product of the fractionator. Temperature at the top of this fractionator is 330 F. The remainder of the crude charged to the fractionator, that is, material boiling above 400 F, is withdrawn as bottoms stream 6 at a rate of 145,000 barrels per day.
  • the preflash tower herein contains a total of eight liquid-vapor contacting trays.
  • Distillation tower contains a total of 34 liquid-vapor contacting trays. Both are operated at essentially atmospheric pressure and at the temperatures given above.
  • the bottoms stream 6 is converted to gaseous product stream 8 consisting of ethane and lighter in the amount of about 87,400,000 cu. ft. per day; propanebutane product stream 9 amounting to about 48,980 barrels per day; and catalytically cracked gasoline stream 10 in the amount of about 1 15,000 barrels per day.
  • a conventional cracking catalyst silica-alumina, may be used in cracking unit 7.
  • Others such as synthetic or natural clays, bauxite, and the like can be used.
  • the new zeolite-type catalysts are especially attractive.
  • Hydrodesulfurization of gasoline stream 10 in unit 11 is effected under conditions known in the art for removal of sulfur compounds. Hydrodesulfurization of liquid hydrocarbon streams is illustrated in U.S. Pat. Nos. 3,487,011 and 2,951,807.
  • gasoline stream 10 is contacted with a cobalt molybdate catalyst (3 percent cobalt oxide and 15 percent molybdenum oxide) deposited upon activated alumina in the presence of hydrogen at a temperature of about 680 F, a pressure of about 600 psig, a space velocity of about 4 volumes of gasoline per volume of catalyst per hour and a hydrogen rate of about 4,000 standard cubic feet per barrel of gasoline feedstock.
  • the sulfur content is reduced from about 1 percent to less than 0.05 weight percent, and the bromine number is reduced from about to about 3.
  • Hydrodesulfurization unit 12 converts sulfur compounds in straight-run gasoline stream 5 by the same type of catalytic treatment as employed in unit 11. Streams 5 and 10 can be combined and passed through a single desulfurization unit such as 11, depending upon the degree of refinement of the operation desired.
  • Propane-butane streams 4 and 9 are desulfurized in treater 13 by a conventional caustic scrubbing procedure as disclosed in U.S. Pat. No. 3,474,027.
  • the propane-butane stream in the liquid state is countercurrently contacted with a suitable strength aqueous caustic (NaOH) solution at a temperature of about F and a pressure of about psig.
  • a packed or tray-type tower is used with a residence time for the hydrocarbon of about 10 minutes.
  • the caustic solution contains about 19 weight percent NaOH upon entering the contactor.
  • the spent caustic is stripped as described in U.S. Pat. No. 3,474,027 and the regenerated caustic recycled to the treater.
  • Treater 14 also operates like treater 13.
  • the feedstream is made up of streams 3 and 8 and is in the gaseous state.
  • a vapor-liquid contact is made in treater 14 between the gaseous hydrocarbon and the liquid caustic.
  • Effluent stream 15 from treater 14 amounts to about 87,000,000 cubic feet ps day and has a composition as follows:
  • Propane 1 Stream can be used directly as a fuel gas. It can be blended with other natural or synthetic gases, or it may. be passed through hydrogen recovery unit 16 for separation of the contained hydrogen.
  • Unit 16 is a conventional cryogenic unit wherein the gaseous feedstock is cooled to a sufficiently low temperature to liquefy all components except thehydrogen. Cooling Jis accomplished by heat exchange with an external refrigeration system such as the methane-ethane-propane cascade refrigeration system of U.S. Pat. No. 3,020,723. Refrigeration can also be accomplished by heat exchange of the ingoing feedstock with the cold products of the step as in U.S. Pat. No. 3,223,745.
  • the three liquid, desulfurized streams 18, and 19, and 20 are combined and converted to synthetic natural gas in gasification unit 21.
  • a unit is described in U.S. Pat. No. 3,506,417. It consists of a process for the production of methane-containing gases fungible with natural gas from a nonmethane feedstock which comprises contacting said feedstock and steam at a temperature below about 1000F with an alkali metal on a nickel and silica-containing support, alkaline earth metal promoted catalyst on a nickel and silica-containing or an alkali metal or a supported platinum group metal catalyst, e.g., platinum on silica-alumina can also be used.
  • the reforming temperature employed usually will not exceed about 1000F and preferably is in the range of from about 650 to about 1000F.
  • the reaction pressure will ordinarily be sufficient to maintain liquid-phase conditions, such as from about 100 psig to about 500 psig.
  • the steam to hydrocarbon molecular ratio ordinarily is at least about 2.5 to 1, and generally in the range of from about 2.5 to about 6 to l.
  • the total gaseous hourly space velocity (GHSV) ordinarily ranges from about 500 to about 40,000 volumes of gas per volume of catalyst per hour, calculated at 32F and one atmosphere.
  • the nickel catalyst used in the process is preferably a nickel-kieselguhr catalyst containing from about 5 to about 90 weight percent nickel on a reduced basis and about 0.5 to about 10 weight percent alkali or alkaline earth metal. In this application, the values for weight percent are based on the total weight of the catalyst.
  • kieselguhr other natural or synthetic silicacontaining material, such as silica, silica-alumina, silica-zirconia, the natural or synthetic crystalline aluminosilicates, and the like, can be used.
  • the alkali metal or alkaline earth metal can be applied to the catalyst as the hydroxide,-carbonate, or other soluble salt. Potas-.
  • the nickel catalyst exhibits a considerably'longer catalyst life than is obtained with known nickelalumina catalyst.
  • the longer life is now attributed to is a presently preferred alkaline matethe fact that a silica-containing support is considerably more-stable in thepresence of steam than an aluminacontaining support.
  • the platinum group metals can be ruthenium, rhodium, osmium, iridium, platinum, palladium, or mixture of such metals and/or their compounds can be used. Ruthenium is a presently preferred platinum group metal.
  • the platinum group metals can be incorporated into any of "the known natural or synthetic refractory inorganic oxide materials known assupports such as alumina, silica, magnesia, zirconia, silica-alumina, the natural or crystalline aluminosilicates, and the like.
  • the amount of platinum group metal present in the catalyst composition can vary from about 0.01 to about 20 weight percent, preferably in amounts less than about 10 percent by weight.
  • the amount of alkali metal or alkaline earth metal present in the catalyst can range from about 0.5 to about 10 weight percent.
  • the alkali metal or alkaline earth metal can be applied as hydroxide, carbonate, or other soluble salt.
  • the term soluble is intended to include either aqueous or nonaqueous solvents, although water is presently preferred. Potassium carbonate is the presently preferred'alkali or alkaline earth compound.
  • steam reforming of hydrocarbons results in a gaseous product fungible with natural gasfwhic h product contains as much as -92 'mole percent methane.
  • Combined streams 18, 19- and 20 amounting to 218,780 barrels per day of liquids ranging from propane to components with a boiling point of 500 F are passed to gasifier unit 21 containing a fixed-bed catalyst of an alkali metal-promoted-nickel kieselguhr in the form of one-eighth inch pellets.
  • the nickel content is 72 weight percent (after reduction) and the potassium carbonate content is 1.6 weight percent (equivalent to 0.9 weight percent potassium). It is prepared by impregnating kieselguhr with an aqueous solution of a soluble nickel salt, calcining, impregnating with aqueous potassium carbonate, calcining, and reducing in hydrogen for about 7 hours at 650 F and 1 hour at 840 F. Reaction conditions are as follows:
  • Effluent gas composition (stream 22) is as follows:
  • the above gas stream 22 can be used directly as fuel gas, may have the carbon dioxide removed as by rub- 7 bing with amine solutions and then used as a fuel gas, and can be blended with other fuel gases.
  • the residual cut or topped crude is catalytically cracked at rather high temperatures to produce the maximum possible amount of gaseous, olefinic components.
  • the catalytic unit in which the cracking operation is conducted is under conditions to produce mainly synthetic natural gas and therefore the usual good cracking catalyst in the normal context is not needed. There is no advantage to keeping low level of metals on the catalyst. In fact, conditions normally desirable for catalytic cracking to produce liquid products are not preferred in this invention.
  • the invention is particularly applicable to convert imported heavy oils to maximum gas. While no two crude oils have precisely the same composition, they may all be converted to synthetic natural gas by my invention.
  • the sequence of steps is the same regardless of whether the crude oil contains a high or low percentage of heavy components or a high or low percentage of paraffins, naphthenes, etc.
  • the relative amounts of the fractions obtained in fractionating the crude will, of course, vary but the treatment of the fractions is the same. Thus a very heavy crude oil will have a larger residual fraction passing through the heavy oil catalytic cracker while a light crude oil will have a smaller fraction requiring this treatment.
  • a process for the conversion of a crude oil to a synthetic natural gas which comprises separating the crude oil into a first fraction containing ethane and lighter gases, a second fraction containing propane and butane, a third fraction which is normally liquid and will contain hydrocarbons boiling up to about 400F and a fourth residual fraction comprising topped crude oil; treating said first and second fractions to remove sulfur therefrom as sulfur or sulfur compounds; hydrodesulfurizing said third fraction and catalytically cracking substantially to extinction said fourth fraction to obtain a lower boiling product which product is then hydrodesulfurized, thereafter combining at least two of the last three fractions to form a charge stock for a synthetic natural gas producing operation and catalytically converting said charge stock to form a synthetic natural gas.

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  • Chemical & Material Sciences (AREA)
  • Oil, Petroleum & Natural Gas (AREA)
  • Engineering & Computer Science (AREA)
  • Chemical Kinetics & Catalysis (AREA)
  • General Chemical & Material Sciences (AREA)
  • Organic Chemistry (AREA)
  • Production Of Liquid Hydrocarbon Mixture For Refining Petroleum (AREA)
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Cited By (3)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US20020168307A1 (en) * 2001-03-09 2002-11-14 James Seaba Micro component hydrocarbon steam reformer system and cycle for producing hydrogen gas
US20090130732A1 (en) * 2007-10-12 2009-05-21 Encana Corporation Conversion of heavy oil and bitumen to methane by chemical oxidation and bioconversion
US20110146979A1 (en) * 2009-12-17 2011-06-23 Greatpoint Energy, Inc. Integrated enhanced oil recovery process

Citations (11)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US3050457A (en) * 1958-11-24 1962-08-21 Phillips Petroleum Co Hydrocarbon conversion with the hydrogenation of the cracked products
US3223745A (en) * 1962-01-02 1965-12-14 Phillips Petroleum Co Process for dealkylation and recovery of hydrogen from refinery gases
US3474027A (en) * 1967-06-19 1969-10-21 Phillips Petroleum Co Plural stages of sulfur removal
US3487011A (en) * 1966-11-23 1969-12-30 Gulf Research Development Co Hydrodesulfurization of naphthas
US3506417A (en) * 1966-05-13 1970-04-14 Phillips Petroleum Co Hydrocarbon reforming
US3531267A (en) * 1965-06-17 1970-09-29 Chevron Res Process for manufacturing fuel gas and synthesis gas
US3551124A (en) * 1965-02-17 1970-12-29 Japan Gasoline Process of gasifying hydrocarbon fractions containing sulfur
US3595805A (en) * 1968-07-17 1971-07-27 Engelhard Min & Chem Steam reforming with preliminary hydrodesulfurization
US3732085A (en) * 1971-06-04 1973-05-08 Gulf Research Development Co Thermally efficient nonpolluting system for production of substitute natural gas
US3778239A (en) * 1971-03-10 1973-12-11 Ford Bacon & Davis Inc Production of gaseous and liquid fuels from crude oil
US3862899A (en) * 1972-11-07 1975-01-28 Pullman Inc Process for the production of synthesis gas and clean fuels

Patent Citations (11)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US3050457A (en) * 1958-11-24 1962-08-21 Phillips Petroleum Co Hydrocarbon conversion with the hydrogenation of the cracked products
US3223745A (en) * 1962-01-02 1965-12-14 Phillips Petroleum Co Process for dealkylation and recovery of hydrogen from refinery gases
US3551124A (en) * 1965-02-17 1970-12-29 Japan Gasoline Process of gasifying hydrocarbon fractions containing sulfur
US3531267A (en) * 1965-06-17 1970-09-29 Chevron Res Process for manufacturing fuel gas and synthesis gas
US3506417A (en) * 1966-05-13 1970-04-14 Phillips Petroleum Co Hydrocarbon reforming
US3487011A (en) * 1966-11-23 1969-12-30 Gulf Research Development Co Hydrodesulfurization of naphthas
US3474027A (en) * 1967-06-19 1969-10-21 Phillips Petroleum Co Plural stages of sulfur removal
US3595805A (en) * 1968-07-17 1971-07-27 Engelhard Min & Chem Steam reforming with preliminary hydrodesulfurization
US3778239A (en) * 1971-03-10 1973-12-11 Ford Bacon & Davis Inc Production of gaseous and liquid fuels from crude oil
US3732085A (en) * 1971-06-04 1973-05-08 Gulf Research Development Co Thermally efficient nonpolluting system for production of substitute natural gas
US3862899A (en) * 1972-11-07 1975-01-28 Pullman Inc Process for the production of synthesis gas and clean fuels

Cited By (5)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US20020168307A1 (en) * 2001-03-09 2002-11-14 James Seaba Micro component hydrocarbon steam reformer system and cycle for producing hydrogen gas
US20040079031A1 (en) * 2001-03-09 2004-04-29 James Seaba Micro component liquid hydrocarbon steam reformer system and cycle for producing hydrogen gas
US20090130732A1 (en) * 2007-10-12 2009-05-21 Encana Corporation Conversion of heavy oil and bitumen to methane by chemical oxidation and bioconversion
US20110146979A1 (en) * 2009-12-17 2011-06-23 Greatpoint Energy, Inc. Integrated enhanced oil recovery process
US8733459B2 (en) * 2009-12-17 2014-05-27 Greatpoint Energy, Inc. Integrated enhanced oil recovery process

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