US3836344A - Process and system for the production of substitute pipeline gas - Google Patents

Process and system for the production of substitute pipeline gas Download PDF

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US3836344A
US3836344A US00281376A US28137672A US3836344A US 3836344 A US3836344 A US 3836344A US 00281376 A US00281376 A US 00281376A US 28137672 A US28137672 A US 28137672A US 3836344 A US3836344 A US 3836344A
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hydrogen
plant
pyrolysis
gas
delivering
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F Maslyk
L Patterson
L Krawitz
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    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10L—FUELS NOT OTHERWISE PROVIDED FOR; NATURAL GAS; SYNTHETIC NATURAL GAS OBTAINED BY PROCESSES NOT COVERED BY SUBCLASSES C10G, C10K; LIQUEFIED PETROLEUM GAS; ADDING MATERIALS TO FUELS OR FIRES TO REDUCE SMOKE OR UNDESIRABLE DEPOSITS OR TO FACILITATE SOOT REMOVAL; FIRELIGHTERS
    • C10L3/00—Gaseous fuels; Natural gas; Synthetic natural gas obtained by processes not covered by subclass C10G, C10K; Liquefied petroleum gas
    • 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
    • C01B3/32—Production of hydrogen or of gaseous mixtures containing a substantial proportion of hydrogen by reaction of gaseous or liquid organic compounds with gasifying agents, e.g. water, carbon dioxide, air
    • C01B3/34—Production of hydrogen or of gaseous mixtures containing a substantial proportion of hydrogen by reaction of gaseous or liquid organic compounds with gasifying agents, e.g. water, carbon dioxide, air by reaction of hydrocarbons with gasifying agents
    • C01B3/38—Production of hydrogen or of gaseous mixtures containing a substantial proportion of hydrogen by reaction of gaseous or liquid organic compounds with gasifying agents, e.g. water, carbon dioxide, air by reaction of hydrocarbons with gasifying agents using catalysts
    • 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

Definitions

  • the process includes separation of the crude oil into several fractions, catalytic [2]] Appl' 281376 gasification of the crude oil fraction boiling below about 375F., pyrolysis treatment of the middle distil- [52] 11.8. C1 48/211, 48/213, 48/214 late of the crude oil, blending of the catalytically gas- [51] Int. Cl Cl0g 9/46 ified product and the G s and lighter product pro- [58] Field of Search 48/211, 197 R, 197 FM, Jerusalem by the pyrolysis treatment, and the production 48/102 R, 214, 213; 208/213, 93 of fuel oil from the heavy high boiling fraction of the crude oil feed.
  • the process and system of the present invention are directed to the production of fuel gas product. More particularly, the process and system of the present invention are directed to the production of fuel gas product from crude oil, which fuel gas product can be burned in appropriately designed and/or adjusted burncrs or which can be blended with natural gas and burned in conventional burners.
  • Natural gas is an especially desirable fuel for use in home heating because it is a clean burning fuel. Natural gas after treatment, if necessary, at or near the producing wells, is essentially free of sulfur and other pollution forming compounds. Further, it is instantly available from a distribution network and is easily transported through conventional pipelines. For essentially the same reasons, natural gas is also in great demand as an industrial fuel and especially as a fuel for generating steam in power stations in many parts of the country.
  • the gas produced by the catalytic gasification process requires treatment after the catalytic gasification steps.
  • the treatment involves subsequent methanation reactions whereby hydrogen is reacted with oxides of carbon to produce methane, thus increasing the concentrations of methane in the gas and decreasing the concentration of hydrogen and carbon monoxide and to a slight extent decreasing the concentration of carbon dioxide. Carbon dioxide is then substantially removed in further apparatus.
  • the existing substitute pipeline gas (SPG) processes 5 consist of reacting a straight run naphtha fraction, boiling up to as high as 375F., with steam over a nickelbased catalyst.
  • the catalytic reaction is performed at a temperature of about 900F. and a pressure of about 500 psig.
  • This catalytic reaction produces a mixture of gases, of which methane on a water-free basis is the major constituent.
  • the gas also contains varying percentages of hydrogen, carbon monoxide, carbon dioxide and residual steam.
  • This gas generally has a higher heating value of approximately 700-800 B.T.U./S.C.F. on a water-free basis.
  • the gas must be further catalytically reacted to reduce the concentrations of hydrogen and the oxides of carbon and, thereby increase the methane concentration.
  • Carbon dioxide is then substantially removed in a regenerable type of scrubber using wellknown process schemes, and the water is removed by final cooling of the gas to ambient temperature. All this is necessary to provide the final 99 mol per cent methane product gas which has a higher heating value of approximately l,000 B.T.U./S.C.F. and combustion properties similar to natural gas.
  • This process provides a very suitable SPG which has the characteristics of natural gas.
  • This particular SP6 is more commonly termed in the industry as SNG, synthetic natural gas.
  • SNG synthetic natural gas
  • SPG synthetic pipeline gas
  • Additional objects of the present invention are to produce residual fuel oil low in sulfur content and to manufacture aromatic hydrocarbon by-products.
  • crude oil which, if need be, has been desalted is fed to an atmospheric distillation unit wherein three fractions of the crude oil are separated.
  • the light fraction, (boiling below approximately 375F.), the middle fraction, (boiling between about 375F. and about 650F.), and the heavy traction, (boiling above about 650F.) are separated and are directed to distinct processing units.
  • the light fraction is treated to remove sulfur and is delivered to the catalytic gasification plant wherein it is first reacted with steam and then treated for carbon dioxide and steam removal.
  • the gas resulting from this process has a higher heating value of 700800 B.T.U./S.C.F.
  • the middle distillate is delivered to a pyrolysis furnace and thermally cracked in the presence of dilution steam.
  • the effluent from the pyrolysis furnace is ultimately separated into four principal streams.
  • the streams are C s and lighter hydrocarbons including hydrogen, C s, pyrolysis gasoline and pyrolysis fuel oil.
  • the C and lighter stream has a higher heating value of from 1,300 to 1,400 B.T.U./S.C.F.
  • the C and lighter stream is blended with the gas from the catalytic gasification plant in the appropriate ratio to provide a fuel gas product approximately 950 to 1,000 B.T.U./S.C.F.
  • This fuel gas product because of its burning characteristics, should not be burned in the conventional burners used to burn natural gas. However, this fuel gas product can be burned safely and economically in burners appropriately designed and/or adapted for its burning characteristics.
  • the fuel gas product can be blended with High B.T.U. Natural Gas to provide a blend which contains 60 mol per cent High B.T.U. Natural Gas and 40 mol per cent fuel gas product or a blend which contains 50 mol per cent High Methane Natural Gas and 50 mol per cent fuel gas product to produce a synthetic pipeline gas (SPG) product which is interchangeable with natural gas to the extent that it can be burned safely and economically in conventional burners designed to burn natural gas.
  • SPG synthetic pipeline gas
  • the C s from the pyrolysis effluent are preferably returned to the pyrolysis furnace for use as fuel.
  • the pyrolysis gasoline is hydrotreated and preferably processed to benzene, toluene and xylenes with residual raffinate remaining.
  • the raffinate is preferably returned to the catalytic gasification plant for processing to fuel gas product.
  • the heavy (high boiling) bottoms from the atmospheric distillation unit are desulfurized to provide clean burning fuel oil.
  • This desulfurization is a hydrogen treating process.
  • the hydrogen used in the desulfurization and hydrotreating equipment is generated in a conventional hydrogen plant which uses the light distillate from the atmospheric distillation unit as feed.
  • the process and system of the present invention are intended to afford maximum yield of substitute pipeline gas (SPG) or alternatively fuel gas product from crude oil.
  • the process equipment includes an atmospheric distillation tower 2, a gasification plant 4, a pyrolysis plant 6 and hydrotreatment facilities 8.
  • the atmospheric distillation tower 2 is conventional and is used to separate the crude oil feed into three fractions.
  • the atmospheric distillation tower 2 is designed to be operated at a temperature range from 100F. to l,000F. and a pressure of slightly above atmospheric.
  • a feed line 10 is provided to deliver crude oil or similar heavy hydrocarbon oil to the atmospheric distillation tower 2.
  • a line 12 is provided for the light distillate overhead from the atmospheric distillation tower 2 and line 14 is provided to afford removal of the middle distillate.
  • a line 18 is provided to convey the heavy boiling bottoms to downstream process equipment.
  • the gasification plant 4 is preferably a catalytic gasification plant and is comprised of a desulfurization unit 22, a catalytic gasification vessel 20, a conventional carbon dioxide removal unit 32 using hot potassium carbonate or equivalent to absorb at least a portion of the carbon dioxide, a conventional regenerator 33 to regenerate the absorbing solution and an optional drying system 36.
  • the catalytic gasification plant converts the low boiling distillate from the atmospheric distillation tower 2, after desulfurization in the desulfurization unit 22, to fuel gas components.
  • the desulfurization occurring in the desulfurization unit 22 can be performed by any conventional means.
  • the desulfurization unit 22 includes, preferably, a catalytic hydrodesulfurization step to hydrodesulfurize organic sulfur compounds, particularly mercaptans and thiophenes.
  • the sulfur contained in these compounds reacts with the hydrogen to fonn hydrogen sulfide gas.
  • the hydrogen sulfide gas is removed from the process stream by passing the process stream through beds of known absorptive materials, such as ZnO or equivalent material selective to absorption of hydrogen sulfide.
  • absorptive materials such as ZnO or equivalent material selective to absorption of hydrogen sulfide.
  • Other methods of sulfur removal are known in the art and may be equally suitable depending upon the amount of organic sulfur present in the feed stream 12 and particular economic factors that may become apparent during the design analysis stage.
  • the hydrogen sulfide is schematically shown removed from the system by line 9, although in practice if an absorptive material such as ZnO is used, the hydrogen sulfide is absorbed by the ZnO and the spent absorbent is discarded after a period of time and replaced with fresh absorptive material.
  • an absorptive material such as ZnO
  • the process stream is conveyed by line 5 and admixed with steam from line 25.
  • the combined stream is fed through line 16 to the catalytic gasification vessel 20.
  • the catalytic gasification vessel 20 is arranged to accommodate a bed of nickel-based catalyst.
  • the vessel 20 operates at a temperature of about 900F. and a pressure of about 500 psig.
  • the process which occurs in the catalytic vessel 20 is steam-naphtha reforming.
  • the efiluent from the catalytic vessel 20 is cooled in heat exchanger 10 or an equivalent and passed through line 21 preferably directly to a carbon dioxide removal system wherein at least a portion of the CO contained in the effluent line 21 is removed.
  • the carbon dioxide removal system is comprised of a hot carbonate absorber 32 and a conventional regenerator 33 or an equivalent system. The CO removal system is used to obtain a sufficient degree of control on the specific gravity, heating value and burning characteristics of the fuel gas product.
  • the methanation vessel 27 operates preferably within a range of temperatures between 535F. to
  • the methanator may be more preferable in some cases to operate the methanator with the inlet feed at 535F. to 660F. and the outlet end of the methanator vessel internally cooled to a temperature as low as 390F. to 480F.
  • the effluent gas, line 14, from the methanation vessel 27 will have a higher methane content.
  • the higher methane content so resulting is dictated by chemical equilibrium. It is well known that higher methane concentration is obtainable at these lower outlet temperatures providing a sufficiently active catalyst is used.
  • the purpose of the methanation vessel 27 is to provide, if necessary, further control on the specific gravity, heating value and burning characteristics of the fuel gas product in line primarily by increasing the methane content and decreasing the hydrogen content of the catalytic gasification vessel effluent stream 13. If the methanation vessel 27 is used, the catalytic gasification effluent stream from line 13, after cooling in heat exchanger 10 or equivalent, is passed by line 21 to the methanation vessel 27. The effluent from the methanation vessel 27 is cooled in heat exchanger 11 or the equivalent and passed through line 19 to the CO absorber 29.
  • the effluent from the CO absorber 29 is cooled to approximately 100F. in a suitable heat exchanger 34.
  • the cooled gas leaving the heat exchanger 34 may be passed through line 35 to an optional drying step 36.
  • the drying step 36 comprised of packed beds of activated alumina dessicant, molecular sieves, or equiva lent, is used if a completely moisture-free SPG product or fuel gas product is required.
  • a line 28 is provided to deliver the dried gas to the fuel gas product line 30 wherein blending occurs with a pyrolysis plant C and lighter gas in line 31.
  • the pyrolysis plant 6 is comprised of pyrolysis furnaces 32, a quench system 41, a primary fractionator 42, a compression and drying system 45, an acid gas or H S removal unit 48, and acetylenes hydrogenation unit 51, a depropanizer tower 34, a distillate stripper 44, and a debutanizer tower 36.
  • the pyrolysis furnace 32 is preferably designed to 0perate at slightly higher than atmospheric pressure and crack the middle distillate feed in the presence of dilution steam to produce pyrolysis gas effluent at about l500F.
  • the pyrolysis furnace may also be designed to'operate at higher pressures ranging from slightly above atmospheric to 500 psig. In some cases, depending upon the specification requirements for the SPG product gas, it may be more economical to crack the middle distillate at these higher pressures.
  • the higher pressure cracking is similarly carried out in the presence of dilution steam and produces a pyrolysis gas effluent at about l500F.
  • a line 40 is provided to deliver the furnace effluent from the pyrolysis furnace 32 to the quench equipment 41 and thence to the primary fractionator tower 42.
  • the primary fractionator tower 42 separates gasoline and lighter hydrocarbons from pyrolysis fuel oil.
  • the pyrolysis fuel oil is transported from the pyrolysis plant through line 24.
  • a line 57 is provided to transfer the raw pyrolysis gasoline product from the primary fractionator 42 to the distillate stripper tower 44 which is provided with a steam reboiler (not shown).
  • the distillate stripper tower 44 operates in a temperature range between F. and 200F. at a pressure slightly higher than atmospheric.
  • the distillate stripper distills C15 and lighter hydrocarbons from the raw pyrolysis gasoline stream 57. These lighter hydrocarbons are passed from the-distillate stripper overhead through line 43.
  • the distillate stripper overhead line 43 is joined with the primary fractionator overhead line 38.
  • the combined stream is passed through line 39 to the compression and drying system 45 where it is compressed to a pressure of approximately 200 psig in conventional gas compressors with suitable interstage cooling.
  • the compressed gas is dried within the compression system 45 by conventional methods using methanol or employing vessels packed with an activated alumina dessicant, molecular sieves or the equivalent.
  • the gas leaves the compression and drying system 34 and is passed by line 46 to the depropanizer tower 34.
  • the depropanizer 34 is refluxed in the conventional manner and is provided with an overhead condenser (not shown) and a bottom reboiler (not shown) in the conventional manner.
  • the depropanizer 34 operates at a temperature range of 20F.
  • C s and ligher hydrocarbons including hydrogen are taken overhead from the depropanizer 34 through line 47 and passed to an acid gas (hydrogen sulfide and carbon dioxide) removal system 48.
  • the acid gas removal system is conventional and is designed to either scrub the cracked gas with an aqueous solution of caustic soda (NaOH) or contact the cracked gas with regenerable solvents such as aqueous solutions of monethanolamine and diethanolamine.
  • the hydrogen sulfide removal step is carried out by conventional means identical or equivalent to the means for H S removal in unit 22.
  • Effluent from the acid gas or hydrogen sulfide removal system 48 is passed through line 49 to hydrogenation system 51.
  • the system 51 is comprised of conventional means for the selective hydrogenation of acetylene, methyl acetylene, and propadiene present in the cracked gas efflu ent.
  • the catalysts used for this purpose are well known in the art. The catalysts may be regenerated, when necessary, by passing a heated mixture of steam and air through the catalyst by means of lines not shown.
  • the hydrogen required for the hydrogenation is supplied by the hydrogen already present in the gas stream 49.
  • the hydrogenated gas comprised of C s and lighter hydrocarbons including unreacted excess hydrogen, is the pyrolysis plant product gas.
  • This product gas is transferred from the system 51 through line 53.
  • a line 54 is provided to admix the C s gas in line 59 with a portion of the pyrolysis plant product C s and lighter gas contained in line 53.
  • the admixed gas is delivered through line 55 to the pyrolysis furnaces 32 wherein the gas is used as fuel for the furnace burners.
  • the remaining portion of the pyrolysis plant product gas contained in line 53 is passed through line 31 and blended in line 30 with the catalytic gasification plant product gas contained in line 28.
  • the blended gas in line 30 results in the fuel gas product.
  • Hydrogen may be mixed into the blend of lines 28 and 31 in order to obtain slightly further control of the specific gravity and heating value of the substitute pipeline gas product.
  • a line 76 is provided for this purpose.
  • gas passing through line 31 and/or the gas passing through line 28 may be compressed.
  • the fuel gas product in line 30 can be burned in burners appropriately designed and/or adjusted for this fuel gas product. For reasons of safety and economy, the fuel gas-in line 30 should not be burned in unmodified conventional burners designed to burn natural gas.
  • the system includes a line 100 to deliver natural gas for blending with the fuel gas product in line 30.
  • a blend which contains 60 mol per cent of any natural gas commonly distributed to industrial or residential burners, i.e., High B.T.U. Natural Gas or High Methane Natural Gas from line 100, and 40 mol per cent fuel gas product from line 30 will provide a SPG in line 101 which can be burned safely and economically in conventional burners designed to burn the respective natural gas with which the fuel gas product has been blended.
  • the mol percentage of natural gas in the blend can be greater than 60 per cent.
  • the fuel gas product in line 30 typically has the following composition and characteristics:
  • Typical High Methane Natural Gas One of the types of natural gas which can be delivered through line 100 for blending with the fuel gas product is Typical High Methane Natural Gas. At present, this gas is the most common high methane natural gas used in the United States. Typical High Methane Natural Gas has the following composition and characteristics:
  • High Methane Texarkana Natural Gas Another high methane natural gas which can be delivered through line 100 for blending with the fuel gas product is commonly known as High Methane Texarkana Natural Gas. This gas has the following composition and characteristics:
  • High Methane Natural Gas is any natural gas having methane content above about mol per cent.
  • a blend which contains 50 mol per cent Typical High Methane Natural Gas from line 30 will provide a SPG in line 101 which can be burned safely and economically in conventional burners.
  • the SPG in line 101, so blended, has the following characteristics:
  • a blend which contains 50 mol per cent High Methane Natural Gas from line and 50 mol per cent fuel gas product from line 30 provides a SPG in line 101 which contains a practical minimum High Methane Natural Gas to achieve commercial interchangeability with High Methane Natural Gas.
  • Another natural gas which can be blended with the fuel gas product in line 30 is High B.T.U. Natural Gas.
  • a common High B.T.U. Natural Gas has the following composition and characteristics:
  • High B.T.U. natural gas is defined as natural gas with a methane content below 90 mol per cent and a B.T.U. content of above 1100 B.T.U./S.C.F.
  • a blend which contains 60 mol per cent High B.T.U. Natural Gas from line 100 and 40 mol per cent fuel gas product from line 30 will provide a SPG in line 101 which can be burned safely and economically in conventional burners, designed to burn High B.T.U. Natural Gas.
  • the SPG, so blended has the following composition and characteristics:
  • the debutanizer tower 36 operates at a temperature range from 100F. to 200F. and at a pressure of 65 psia.
  • the debutanizer tower 36 is refluxed in the conventional manner and is provided with an overhead condenser (not shown) and a bottoms reboiler (not shown) in the conventional manner.
  • the depropanizer tower bottoms line 92 comprises the feed stream to the debutanizer 36.
  • C,,s are taken from the debutanizer 36.
  • Cjs are taken from the debutanizer tower overhead through line 91.
  • the overhead Cfs can be used for fuel in the pyrolysis furnace 32 or can be transported to processing equipment (not shown) for the purpose of separating therefrom, butadiene or other useful products.
  • Line 93 is provided to convey the C s to the butadiene processing equipment.
  • Pyrolysis gasoline is taken from the debutanizer bottoms through line 90.
  • the debutanizer bottoms in line 90 is combined with the distillate stripper bottoms in line 94 resulting in the total pyrolysis gasoline from the pyrolysis plant.
  • the total pyrolysis gasoline is transported through line 50 to the pyrolysis gasoline hydrotreater 52 wherein the olefins and other unsaturated hydrocarbons are hydrogenated.
  • the pyrolysis gasoline hydrotreater 52 is also provided with a delivery line 54 for conveying hydrogen thereto from the hydrogen plant 64.
  • a line 58 is arranged to deliver the hydrotreated product pyrolysis gasoline from the hydrotreater 52 to the aromatics extraction unit 56.
  • aromatics extraction unit 56 benzene, toluene and xylene are produced and are withdrawn from the unit through lines 82, 83 and 84.
  • the hydrotreated gasoline from the hydrotreater 52 may optionally be blended with other available gasoline stocks to produce motor gasoline.
  • Line 62 is provided as an alternate branch line to deliver the hydrotreated pyrolysis gasoline to the blending equipment.
  • the process equipment further includes hydrotreating facilities comprised of a hydrogen plant 64, a pyrolysis gasoline hydrotreater 52 and an atmospheric residuum desulfurization unit 66.
  • a feed line 68 is provided to convey a portion of the low boiling distillate from the atmospheric distillation tower overhead line 12 to the hydrogen plane 64.
  • the hydrogen plant 64 is conventional and is adapted to convert light overhead distillate from the atmospheric distillation tower 2 to hydrogen. Steam is introduced to the hydrogen plant 64 through line 85. By-product carbon dioxide is conveyed through line 70 to the atmosphere or to a dry ice plant (not shown).
  • the hydrogen generated in the hydrogen plant 64 is transported through line 86 to the atmospheric residuum desulfurization plant 66, through lines 87 and 54 to the pyrolysis gasoline hydrotreater 52, through lines 87 and 89 to the desulfurization unit 22 and optionally to line 76 for blending with the fuel gas product in line 30.
  • the atmospheric residuum desulfurization plant 66 contains equipment to remove sulfur from the atmospheric distillation residuum of the crude oil which is taken through line 18 as bottoms from the atmospheric distillation unit 2.
  • the desulfurized fuel oil is taken through line 74 as a low sulfur fuel oil product.
  • a particularly suitable use for the fuel oil is in power stations for generating steam. If the fuel oil is used in power stations which normally employ natural gas to tire the boilers, the natural gas previously used therein will be released for other uses uniquely suitable to its character.
  • the process and system of the substitute pipeline gas generating facility of the present invention converts crude oil to synthetic pipeline gas, fuel oil and petrochemicals.
  • the crude oil 10 which is to be desalted, if necessary, is delivered to the atmospheric distillation tower 2 where it is separated into three fractions.
  • the low boiling distillate i.e., the fraction boiling below about 375F., is taken overhead through line 12 and delivered to the catalytic gasification plant 4.
  • a portion of the overhead from the atmospheric distillation unit is also delivered through line 68 to the hydrogen plant 64.
  • the low boiling distillate which is delivered to the catalytic gasification plant 4 is reacted with steam in the catalytic gasification vessel 20.
  • the reaction is performed over a nickel-based catalytic bed at a tempera ture of approximately 900F. and a pressure of about 500 psig.
  • the gasified product thus produced in a vessel 20 is cooled in exchanger 10', or equivalent, and then directly purified in absorber 32 by removal of at least a portion of the CO present in the gas. Residual steam is removed from the gas in cooler 34.
  • the resulting gas product has a methane content of approximately 60 to v0. and a higher heating value of between 700-800 B.T.U./S.C.F.
  • the hydrogen is delivered to the pyrolysis gasoline hydrotreater 52, the atmospheric residuum desulfurization plant 66, the desulfurization unit 22 and a portion may be delivered optionally to the SP6 product line 30.
  • the middle distillate from the atmospheric distilla tion unit boils between 375F. and 650F. This range distillate is delivered to the pyrolysis furnace 32 wherein it is cracked at about 1,500F. at approximately atmospheric pressure but not limited to atmospheric pressure.
  • the furnace effluent is quenched. compressed, dryed and delivered to a depropanizer 34 wherein the C s and lighter hydrocarbons are taken overhead. After acid gas or H 8 removal and C acetylene, C acetylene and propadiene hydrogenation, the C and lighter hydrocarbons and hydrogen are delivered to pipeline gas product line 30. In line 30, the C s and lighter constituents are blended with the gas effluent in line 28 from the catalytic gasification plant 4.
  • the higher heating value of the C and lighter stream in line 31 is approximately 1300 to 1400 B.T.U./S.C.F.
  • the blending is regulated to provide a fuel gas product of approximately 1000 B.T.U./S.C.F. with a specific gravity of about 0.65, a Wobbe number of about 1240 and a Weaver flame speed of about 25.0.
  • a fuel gas product of these characteristics is so obtained without use of the methanator vessel 27.
  • the fuel gas product with the above-cited characteristics is so obtained by feeding the effluent in line 21 directly to the CO absorber 32, thus by-passing the methanator 27 and exchanger 11.
  • Carbon dioxide is removed in absorber 32 to any desired degree, thus providing a means for regulating the specific gravity, heating value and burning characteristics of the fuel gas product in line 30 and the substitute pipeline product gas in line 101.
  • the specific gravity, heating value, and burning characteristics of the fuel gas product and the substitute pipeline product gas may be further controlled by including the methanation vessel 27.
  • the methanation vessel 27, if included, provides a degree of additional control on the characteristics of the fuel gas product and the substitute pipeline gas, primarily by increasing the methane content and decreasing the hydrogen content of the catalytic vessel effluent stream 13.
  • the specific gravity, heating value and burning characteristics of the fuel gas product and the substitute pipeline gas product can be controlled to a slightly further degree by introducing hydrogen into the blended gas through line 76 and also by adjusting the severity of cracking in the pyrolysis furnaces 32.
  • CO is present in the product gas in quantities sufficiently high to cause corrosion in downstream pipelines, then this gas may be rendered non-corrosive, if moisture is entirely eliminated by drying the gas in the drying unit 36.
  • the Cjs and heavier hydrocarbons which form the bottoms of the depropanizer 34 are treated in the debutanizer tower 36 to provide C s overhead, and pyrolysis gasoline in the bottoms.
  • the C s are optionally mixed with some C s and returned to the pyrolysis furnace 32 to be used there as fuel.
  • the pyrolysis gasoline is hydrotreated in the hydrotreater 52 to hydrogenate olefins and diolefins and further refined to produce chemicals such as benzene, toluene and xylenes which are removed from the unit through lines 82, 83 and 84.
  • the raffinate from the chemical production process is returned to line 12 for use as feed in the manufacture of the fuel gas product in the catalytic gasification plant 4.
  • the heavy (high boiling) material from the atmospheric distillation unit 2 is taken from the bottom of the unit and treated in the atmospheric residuum desulfurization plant 66.
  • the major portion of the sulfur is removed and the end product is fuel oil which is now One hundred thousand barrels of a typical crude oil such as a light Kuwait crude after desalting are delivered to the atmospheric distillation tower 2.
  • 17,000 barrels of low boiling distillate with a 375F. End Point are taken overhead.
  • the methanator 27 is entirely by-passed in this example.
  • the effluent in line 13 from the catalytic gasification vessel 20 after cooling in exchanger 10 or equivalent is passed directly to the CO absorber 32. Carbon dioxide is partially removed in absorber 32 and the residual steam is removed from the gas in cooler 34.
  • the line 35 is provided to pass the gas from the cooler 34.
  • the drying unit 36 is optional and is by-passed in this example. Therefore, the gas resulting in line 35 is the product gas from the catalytic gasification plant. One hundred twenty-four million (124,000,000) standard cubic feet of this gas is produced. The higher heating value of this gas is 718 B.T.U./S.C.F.
  • the remaining 2,150 barrels of low boiling distillate are delivered to the hydrogen plant 64. Therein the distillate is treated by conventional means and 33.7 million standard cubic feet of hydrogen gas is produced. Eleven million two hundred thousand (1 1,200,000) standard cubic feet of the hydrogen is delivered to the pyrolysis gasoline hydrotreater 52 and the remainder is passed to the desulfurization units 66 and 22. Nineteen million eight hundred thousand (19,800,000) standard cu. feet of hydrogen is delivered to unit 66 and 2.7 million cubic feet is delivered to unit 22.
  • the middle distillate from the atmospheric distillation unit 2, boiling from 375F. to 650F., provides 35,000 barrels of feed for the pyrolysis plant. These 35,000 barrels are cracked in the pyrolysis furnace 32.
  • the effluent from the pyrolysis furnaces is quenched and then delivered to the depropanizer 34.
  • the depropanizer 34 provides 106 million standard cubic feet of C s and lighter hydrocarbons as an overhead product stream.
  • Ninety-five million (95,000,000) standard cubic feet of C s and lighter hydrocarbons are delivered through line 31 to be blended with the gas through line 28 from the catalytic gasification plant.
  • the higher heating value of the C s and lighter hydrocarbons is 1,368 B.T.U./S.C.F.
  • the 124 million standard cubic feet of gas from the catalytic gasification plant and the million standard cubic feet of C s and lighter hydrocarbons from the pyrolysis plant produce 219 million standard cubic feet of fuel gas product.
  • the higher heating value of the fuel gas product is 1000 B.T.U./S.C.F.
  • This gas has a specific gravity of 0.65 a Wobbe number of 1240 and a Weaver flame speed of 25.1.
  • the debutanizer tower in the pyrolysis plant provides 47,000 lbs. per hour of C.,s which are mixed with 11 million standard cubic feet of C s and lighter hydrocarbons from line 54 and the combined stream is returned through line 55 to the pyrolysis furnace wherein it is used as fuel.
  • the bottoms fractions from the distillate stripper 44 and the debutanizer 36 are combined and provide pyrolysis gasoline which, after treatment in the hydrotreater, yields 10,750 barrels of hydrotreated gasoline. ln addition. 4.000 barrels of pyrolysis fuel oil are also produced as bottoms from the primary fractionation tower 42.
  • the atmospheric distillation crude unit also produces 48,000 barrels of atmospheric residuum plus high boiling distillate.
  • This stream is passed by line 18 to the atmospheric residuum desulfurization plant 66.
  • the stream is desulfurized and purified in the atmospheric residuum desulfurization plant 66 and approximately 48,000 barrels of fuel oil product result.
  • Another example of the process of the subject inven tion repeats the first example to produce 219 million standard cubic feet of fuel gas product. Then 219 million standard cubic feet of High Methane Natural Gas are blended with the 219 million standard cubic feet of fuel gas product to produce 438 million standard cubic.
  • the blended mixture contains 50 mol per cent High Methane Natural Gas and 50 mol percent fuel gas product.
  • a third example of the process of the subject invention repeats the first example to produce 219 million standard cubic feet of fuel gas product. Then 329 million standard cubic feet High B.T.U. natural gas is blended with the 219 million standard cubic feet of fuel gas product to produce 548 standard cubic feet of SPG, thus the blended mixture contains 60 mol per cent High B.T.U. natural gas and 40 mol per cent fuel gas product.
  • a process for producing a fuel gas product from crude oil comprising:
  • a process for producing a fuel gas product from crude oil comprising:
  • a process as in claim 1 further comprising the steps of separating the other products from the furnace effluent into a first fraction of G s, a second fraction of pyrolysis gasoline and a third fraction of pyrolysis fuel oil.
  • a process as in claim 3 further comprising the steps of:
  • a process as in claim 4 further comprising the steps of:
  • a process as in claim 3 further comprising the steps of:
  • a process as in claim 5 further comprising the steps of:
  • a process as in claim 8 wherein the catalytic gasification is performed by delivering steam to a catalytic gasification vessel and passing the steam and first distillate fraction over a nickel-based catalyst at about 900F. and about 500 psig.
  • a process as in claim 9 further comprising the steps of removing carbon dioxide and residual steam from the gas produced in the catalytic gasification vessel.
  • a process as in claim 1 further comprising the steps of:
  • a process as in claim 7 further comprising the step of mixing hydrogen from the hydrogen plant with the stream containing C s and lower hydrocarbons and with the gas produced in the gasification plant.
  • a process as in claim 12 further comprising the steps of:
  • a process as in claim 1 further comprising the step of:

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Abstract

Process and system for producing substitute pipeline gas (SPG) from crude oil. The process includes separation of the crude oil into several fractions, catalytic gasification of the crude oil fraction boiling below about 375*F., pyrolysis treatment of the middle distillate of the crude oil, blending of the catalytically gasified product and the C3''s and lighter product produced by the pyrolysis treatment, and the production of fuel oil from the heavy high boiling fraction of the crude oil feed. A selfcontained hydrogen generation plant is included for hydrotreatment within the system.

Description

United States Patent Krawitz et al. 1 Sept. 17, 1974 PROCESS AND SYSTEM FOR THE 3,531,267 9/1970 Gould 421 213 PRQDUCTION OF SUBSTITUTE PIPELINE 3,732,085 5/1973 Carr et al 48/214 GAS Primary Examiner-S. Leon Bashore [76] Inventors: Leonard Krawitz, Richard, Assistant E p p Kratz Needham, Mass. 02192; Frank ,1. Maslyk, 12118 Boheme Dr.; Leland W. Patterson, 418 Wycliffe, both Of, 57 ABSTRACT Houston 77024 Process and system for producing sflifi'fiibipeiin [22] Filed: Aug. 17, 1972 gas (SPG) from crude oil. The process includes separation of the crude oil into several fractions, catalytic [2]] Appl' 281376 gasification of the crude oil fraction boiling below about 375F., pyrolysis treatment of the middle distil- [52] 11.8. C1 48/211, 48/213, 48/214 late of the crude oil, blending of the catalytically gas- [51] Int. Cl Cl0g 9/46 ified product and the G s and lighter product pro- [58] Field of Search 48/211, 197 R, 197 FM, duced by the pyrolysis treatment, and the production 48/102 R, 214, 213; 208/213, 93 of fuel oil from the heavy high boiling fraction of the crude oil feed. A self-contained hydrogen generation [56] References Cited plant is included for hydrotreatrnent within the sys- UNITED STATES PATENTS tem 3,060,116 10/1962 Hardin et al 208/79 17 Claims, 1 Drawing Figure Sniff/3223185521 5 2 New 6: 604 "I" QB h l FQACT ONATOQ u a 54 k |3l 1 C55 /vo L/swze 14 $6 1k g g g; Q3 cd's 5 j E I fyyoum f Q13 w 5 81 l C E 7 1 (iv 20v: Q l Finn's/s l q m Mat 5;) Gas u [UP/16701 62:2): 65O,;1 I q- ,t/ l 58 011W flflofl'sown l 54 I 84 83 [6M L w w w w l I /Pqriwmz l l J\ L l l J 1 [FAN ,4 7O
1 1 P 4 1 68 i iL l AmaWlse/c 0/4 1 J Mom/v HAW His/000M 8 I &O Q'SUU'UEIZHf/(JV 74 l l l PROCESS AND SYSTEM FOR THE PRODUCTION OF SUBSTITUTE PIPELINE GAS CROSS REFERENCE TO RELATED APPLICATION This patent application and Ser. No. 281,331, filed contemporaneously with this patent application filed Aug. 17, 1972, entitled PROCESS AND SYSTEM FOR THE PRODUCTION OF SUBSTITUTE PIPE- LINE GAS by Barry D. Josephs and John P. Eames contain common subject matter and are related.
FIELD OF THE INVENTION The process and system of the present invention are directed to the production of fuel gas product. More particularly, the process and system of the present invention are directed to the production of fuel gas product from crude oil, which fuel gas product can be burned in appropriately designed and/or adjusted burncrs or which can be blended with natural gas and burned in conventional burners.
BACKGROUND OF THE INVENTION Description of the Prior Art It has become widely accepted that natural gas is an especially desirable fuel for use in home heating because it is a clean burning fuel. Natural gas after treatment, if necessary, at or near the producing wells, is essentially free of sulfur and other pollution forming compounds. Further, it is instantly available from a distribution network and is easily transported through conventional pipelines. For essentially the same reasons, natural gas is also in great demand as an industrial fuel and especially as a fuel for generating steam in power stations in many parts of the country.
As a result of the virtues of natural gas and the fact that new gas producing fields have not been discovered at a rate that is satisfactory to supply anticipated needs, much work has been done to synthesize a substitute pipeline gas (SPG) having essentially the same characteristics as natural gas. As a result of the efforts, a satisfactory substitute pipeline gas (SPG) has been produced from various hydrocarbon feeds. Most of the existing processes are catalytic, and as a result, are unable to accept hydrocarbon feeds having a boiling point above that of heavy naphtha. At present, if gas oils or any feed heavier than heavy naphtha are used in the catalytic gasification process, the catalysts will rapidly deactivate as a result of coke formation on the catalyst.
In addition, the gas produced by the catalytic gasification process requires treatment after the catalytic gasification steps. The treatment involves subsequent methanation reactions whereby hydrogen is reacted with oxides of carbon to produce methane, thus increasing the concentrations of methane in the gas and decreasing the concentration of hydrogen and carbon monoxide and to a slight extent decreasing the concentration of carbon dioxide. Carbon dioxide is then substantially removed in further apparatus.
This treatment is necessary for the final product gas to have a methane concentration of approximately 99% by volume, which methane concentration must be achieved to produce from the current catalytically generated gases a gas having combustion properties similar to natural gas and the required higher heating value of The existing substitute pipeline gas (SPG) processes 5 consist of reacting a straight run naphtha fraction, boiling up to as high as 375F., with steam over a nickelbased catalyst.
The catalytic reaction is performed at a temperature of about 900F. and a pressure of about 500 psig. This catalytic reaction produces a mixture of gases, of which methane on a water-free basis is the major constituent. The gas also contains varying percentages of hydrogen, carbon monoxide, carbon dioxide and residual steam. This gas generally has a higher heating value of approximately 700-800 B.T.U./S.C.F. on a water-free basis. As a result, the gas must be further catalytically reacted to reduce the concentrations of hydrogen and the oxides of carbon and, thereby increase the methane concentration. Carbon dioxide is then substantially removed in a regenerable type of scrubber using wellknown process schemes, and the water is removed by final cooling of the gas to ambient temperature. All this is necessary to provide the final 99 mol per cent methane product gas which has a higher heating value of approximately l,000 B.T.U./S.C.F. and combustion properties similar to natural gas.
This process provides a very suitable SPG which has the characteristics of natural gas. This particular SP6 is more commonly termed in the industry as SNG, synthetic natural gas. However, as previously indicated, these catalytic processes will not realistically or economically produce SPG from crude oil since it has been found that any feed having a higher boiling point than about 375 1 will rapidly form cofke on the catalyst and thereby deactivate the catalyst.
SUMMARY OF THE INVENTION It is a principal object of the present invention to provide a process and a system for producing a fuel gas product from feeds heavier than naphtha, and, in particular, from crude oil.
It is a further object to provide an integrated system which will provide a maximum amount of fuel gas product from crude oil.
It is also an object of the present invention to provide a process and system for producing a fuel gas product which can be burned in appropriately designed and/or adjusted burners and a synthetic pipeline gas (SPG) product comprised of a blend of natural gas and the fuel gas product of this invention which can be burned in conventional burners.
Additional objects of the present invention are to produce residual fuel oil low in sulfur content and to manufacture aromatic hydrocarbon by-products.
In the process of the present invention, crude oil which, if need be, has been desalted is fed to an atmospheric distillation unit wherein three fractions of the crude oil are separated. The light fraction, (boiling below approximately 375F.), the middle fraction, (boiling between about 375F. and about 650F.), and the heavy traction, (boiling above about 650F.) are separated and are directed to distinct processing units. The light fraction is treated to remove sulfur and is delivered to the catalytic gasification plant wherein it is first reacted with steam and then treated for carbon dioxide and steam removal. The gas resulting from this process has a higher heating value of 700800 B.T.U./S.C.F.
The middle distillate is delivered to a pyrolysis furnace and thermally cracked in the presence of dilution steam. The effluent from the pyrolysis furnace is ultimately separated into four principal streams. The streams are C s and lighter hydrocarbons including hydrogen, C s, pyrolysis gasoline and pyrolysis fuel oil. The C and lighter stream has a higher heating value of from 1,300 to 1,400 B.T.U./S.C.F. The C and lighter stream is blended with the gas from the catalytic gasification plant in the appropriate ratio to provide a fuel gas product approximately 950 to 1,000 B.T.U./S.C.F. This fuel gas product, because of its burning characteristics, should not be burned in the conventional burners used to burn natural gas. However, this fuel gas product can be burned safely and economically in burners appropriately designed and/or adapted for its burning characteristics.
Alternatively, the fuel gas product can be blended with High B.T.U. Natural Gas to provide a blend which contains 60 mol per cent High B.T.U. Natural Gas and 40 mol per cent fuel gas product or a blend which contains 50 mol per cent High Methane Natural Gas and 50 mol per cent fuel gas product to produce a synthetic pipeline gas (SPG) product which is interchangeable with natural gas to the extent that it can be burned safely and economically in conventional burners designed to burn natural gas.
The C s from the pyrolysis effluent are preferably returned to the pyrolysis furnace for use as fuel. The pyrolysis gasoline is hydrotreated and preferably processed to benzene, toluene and xylenes with residual raffinate remaining. The raffinate is preferably returned to the catalytic gasification plant for processing to fuel gas product.
The heavy (high boiling) bottoms from the atmospheric distillation unit are desulfurized to provide clean burning fuel oil. This desulfurization is a hydrogen treating process. The hydrogen used in the desulfurization and hydrotreating equipment is generated in a conventional hydrogen plant which uses the light distillate from the atmospheric distillation unit as feed.
DESCRIPTION OF THE DRAWING The drawing is a schematic flow diagram of the process of the preferred embodiment of the invention.
The drawing and the following detailed description of the process and system will illustrate the invention.
DESCRIPTION OF THE PREFERRED EMBODIMENT The process and system of the present invention are intended to afford maximum yield of substitute pipeline gas (SPG) or alternatively fuel gas product from crude oil. The process equipment includes an atmospheric distillation tower 2, a gasification plant 4, a pyrolysis plant 6 and hydrotreatment facilities 8.
The atmospheric distillation tower 2 is conventional and is used to separate the crude oil feed into three fractions. The atmospheric distillation tower 2 is designed to be operated at a temperature range from 100F. to l,000F. and a pressure of slightly above atmospheric. A feed line 10 is provided to deliver crude oil or similar heavy hydrocarbon oil to the atmospheric distillation tower 2. A line 12 is provided for the light distillate overhead from the atmospheric distillation tower 2 and line 14 is provided to afford removal of the middle distillate. A line 18 is provided to convey the heavy boiling bottoms to downstream process equipment.
The gasification plant 4 is preferably a catalytic gasification plant and is comprised of a desulfurization unit 22, a catalytic gasification vessel 20, a conventional carbon dioxide removal unit 32 using hot potassium carbonate or equivalent to absorb at least a portion of the carbon dioxide, a conventional regenerator 33 to regenerate the absorbing solution and an optional drying system 36.
The catalytic gasification plant converts the low boiling distillate from the atmospheric distillation tower 2, after desulfurization in the desulfurization unit 22, to fuel gas components.
The desulfurization occurring in the desulfurization unit 22 can be performed by any conventional means. The desulfurization unit 22 includes, preferably, a catalytic hydrodesulfurization step to hydrodesulfurize organic sulfur compounds, particularly mercaptans and thiophenes. The sulfur contained in these compounds reacts with the hydrogen to fonn hydrogen sulfide gas. The hydrogen sulfide gas is removed from the process stream by passing the process stream through beds of known absorptive materials, such as ZnO or equivalent material selective to absorption of hydrogen sulfide. Other methods of sulfur removal are known in the art and may be equally suitable depending upon the amount of organic sulfur present in the feed stream 12 and particular economic factors that may become apparent during the design analysis stage. The hydrogen sulfide is schematically shown removed from the system by line 9, although in practice if an absorptive material such as ZnO is used, the hydrogen sulfide is absorbed by the ZnO and the spent absorbent is discarded after a period of time and replaced with fresh absorptive material.
After desulfurization in step 22, the process stream is conveyed by line 5 and admixed with steam from line 25. The combined stream is fed through line 16 to the catalytic gasification vessel 20. The catalytic gasification vessel 20 is arranged to accommodate a bed of nickel-based catalyst. The vessel 20 operates at a temperature of about 900F. and a pressure of about 500 psig. The process which occurs in the catalytic vessel 20 is steam-naphtha reforming.
The efiluent from the catalytic vessel 20 is cooled in heat exchanger 10 or an equivalent and passed through line 21 preferably directly to a carbon dioxide removal system wherein at least a portion of the CO contained in the effluent line 21 is removed. The carbon dioxide removal system is comprised of a hot carbonate absorber 32 and a conventional regenerator 33 or an equivalent system. The CO removal system is used to obtain a sufficient degree of control on the specific gravity, heating value and burning characteristics of the fuel gas product.
It may be desirable in some cases to obtain an added degree of control on the specific gravity, heating value and burning characteristics of the fuel gas product in line 30. This may be accomplished by adding a conventional catalytic methanation vessel 27 between the catalytic gasification vessel 20 and the CO absorber 29.
The methanation vessel 27 operates preferably within a range of temperatures between 535F. to
660F. at about 500 psig. It may be more preferable in some cases to operate the methanator with the inlet feed at 535F. to 660F. and the outlet end of the methanator vessel internally cooled to a temperature as low as 390F. to 480F. When the outlet end of the vessel is internally cooled to these lower temperatures, the effluent gas, line 14, from the methanation vessel 27 will have a higher methane content. The higher methane content so resulting is dictated by chemical equilibrium. It is well known that higher methane concentration is obtainable at these lower outlet temperatures providing a sufficiently active catalyst is used. The purpose of the methanation vessel 27 is to provide, if necessary, further control on the specific gravity, heating value and burning characteristics of the fuel gas product in line primarily by increasing the methane content and decreasing the hydrogen content of the catalytic gasification vessel effluent stream 13. If the methanation vessel 27 is used, the catalytic gasification effluent stream from line 13, after cooling in heat exchanger 10 or equivalent, is passed by line 21 to the methanation vessel 27. The effluent from the methanation vessel 27 is cooled in heat exchanger 11 or the equivalent and passed through line 19 to the CO absorber 29.
The effluent from the CO absorber 29 is cooled to approximately 100F. in a suitable heat exchanger 34. The cooled gas leaving the heat exchanger 34 may be passed through line 35 to an optional drying step 36.
The drying step 36, comprised of packed beds of activated alumina dessicant, molecular sieves, or equiva lent, is used if a completely moisture-free SPG product or fuel gas product is required. A line 28 is provided to deliver the dried gas to the fuel gas product line 30 wherein blending occurs with a pyrolysis plant C and lighter gas in line 31.
The pyrolysis plant 6 is comprised of pyrolysis furnaces 32, a quench system 41, a primary fractionator 42, a compression and drying system 45, an acid gas or H S removal unit 48, and acetylenes hydrogenation unit 51, a depropanizer tower 34, a distillate stripper 44, and a debutanizer tower 36.
The pyrolysis furnace 32 is preferably designed to 0perate at slightly higher than atmospheric pressure and crack the middle distillate feed in the presence of dilution steam to produce pyrolysis gas effluent at about l500F.
The pyrolysis furnace may also be designed to'operate at higher pressures ranging from slightly above atmospheric to 500 psig. In some cases, depending upon the specification requirements for the SPG product gas, it may be more economical to crack the middle distillate at these higher pressures. The higher pressure cracking is similarly carried out in the presence of dilution steam and produces a pyrolysis gas effluent at about l500F. A line 40 is provided to deliver the furnace effluent from the pyrolysis furnace 32 to the quench equipment 41 and thence to the primary fractionator tower 42. The primary fractionator tower 42 separates gasoline and lighter hydrocarbons from pyrolysis fuel oil. The pyrolysis fuel oil is transported from the pyrolysis plant through line 24.
A line 57 is provided to transfer the raw pyrolysis gasoline product from the primary fractionator 42 to the distillate stripper tower 44 which is provided with a steam reboiler (not shown). The distillate stripper tower 44 operates in a temperature range between F. and 200F. at a pressure slightly higher than atmospheric. The distillate stripper distills C15 and lighter hydrocarbons from the raw pyrolysis gasoline stream 57. These lighter hydrocarbons are passed from the-distillate stripper overhead through line 43.
The distillate stripper overhead line 43 is joined with the primary fractionator overhead line 38. The combined stream is passed through line 39 to the compression and drying system 45 where it is compressed to a pressure of approximately 200 psig in conventional gas compressors with suitable interstage cooling. The compressed gas is dried within the compression system 45 by conventional methods using methanol or employing vessels packed with an activated alumina dessicant, molecular sieves or the equivalent. The gas leaves the compression and drying system 34 and is passed by line 46 to the depropanizer tower 34. The depropanizer 34 is refluxed in the conventional manner and is provided with an overhead condenser (not shown) and a bottom reboiler (not shown) in the conventional manner. The depropanizer 34 operates at a temperature range of 20F. to F. and at a pressure of l65 psia. C s and ligher hydrocarbons including hydrogen are taken overhead from the depropanizer 34 through line 47 and passed to an acid gas (hydrogen sulfide and carbon dioxide) removal system 48. The acid gas removal system is conventional and is designed to either scrub the cracked gas with an aqueous solution of caustic soda (NaOH) or contact the cracked gas with regenerable solvents such as aqueous solutions of monethanolamine and diethanolamine.
In some cases it may be more practical to remove only the hydrogen sulfide and allow the carbon dioxide present in line 47 to remain in the gas unreacted and unabsorbed and ultimately be carried into the fuel gas product line 30.
The hydrogen sulfide removal step is carried out by conventional means identical or equivalent to the means for H S removal in unit 22. Effluent from the acid gas or hydrogen sulfide removal system 48 is passed through line 49 to hydrogenation system 51. The system 51 is comprised of conventional means for the selective hydrogenation of acetylene, methyl acetylene, and propadiene present in the cracked gas efflu ent. The catalysts used for this purpose are well known in the art. The catalysts may be regenerated, when necessary, by passing a heated mixture of steam and air through the catalyst by means of lines not shown. The hydrogen required for the hydrogenation is supplied by the hydrogen already present in the gas stream 49. The hydrogenated gas, comprised of C s and lighter hydrocarbons including unreacted excess hydrogen, is the pyrolysis plant product gas. This product gas is transferred from the system 51 through line 53. A line 54 is provided to admix the C s gas in line 59 with a portion of the pyrolysis plant product C s and lighter gas contained in line 53.
The admixed gas is delivered through line 55 to the pyrolysis furnaces 32 wherein the gas is used as fuel for the furnace burners. The remaining portion of the pyrolysis plant product gas contained in line 53 is passed through line 31 and blended in line 30 with the catalytic gasification plant product gas contained in line 28. The blended gas in line 30 results in the fuel gas product. Hydrogen may be mixed into the blend of lines 28 and 31 in order to obtain slightly further control of the specific gravity and heating value of the substitute pipeline gas product. A line 76 is provided for this purpose.
, 1f need be, to achieve a higher product gas pressure, the
gas passing through line 31 and/or the gas passing through line 28 may be compressed.
The fuel gas product in line 30 can be burned in burners appropriately designed and/or adjusted for this fuel gas product. For reasons of safety and economy, the fuel gas-in line 30 should not be burned in unmodified conventional burners designed to burn natural gas.
The system includes a line 100 to deliver natural gas for blending with the fuel gas product in line 30. A blend which contains 60 mol per cent of any natural gas commonly distributed to industrial or residential burners, i.e., High B.T.U. Natural Gas or High Methane Natural Gas from line 100, and 40 mol per cent fuel gas product from line 30 will provide a SPG in line 101 which can be burned safely and economically in conventional burners designed to burn the respective natural gas with which the fuel gas product has been blended. The mol percentage of natural gas in the blend can be greater than 60 per cent.
The fuel gas product in line 30 typically has the following composition and characteristics:
One of the types of natural gas which can be delivered through line 100 for blending with the fuel gas product is Typical High Methane Natural Gas. At present, this gas is the most common high methane natural gas used in the United States. Typical High Methane Natural Gas has the following composition and characteristics:
C 11 plus CaHg and higher paraffins 4.0
Sp. Gr. 0.62 Wobbe No. 1300 Weaver Flame Speed 13.9 HHV. B.T.U./S.C.F. 1000-1030 Required Theoretical Air for Combustion cu. ft./cu. ft. gas 9.5
Another high methane natural gas which can be delivered through line 100 for blending with the fuel gas product is commonly known as High Methane Texarkana Natural Gas. This gas has the following composition and characteristics:
-Continucd Sp. Gr. 0.57 Wobbe No. 1280 Weaver Flame Speed 13.7 HHV, B.T.U./SOP. 967 Required Theoretical Air for Combustion cu. ft./cu. ft. gas 9.2
High Methane Natural Gas is any natural gas having methane content above about mol per cent. A blend which contains 50 mol per cent Typical High Methane Natural Gas from line 30 will provide a SPG in line 101 which can be burned safely and economically in conventional burners. The SPG in line 101, so blended, has the following characteristics:
M01. 72 H; 10.4 CH. 70.0 C H, 7.4 C H 2.7 C l-l 3.4 H 0.7 CO; 3.4 CO 0.2 N
Sp. Gr. .63 Wobbe No. 1260-1280 Weaver Flame Speed 19.5 HHV, B.T.U./S.C.F. 1000-1015 Required Theoretical Air for Combustion cu. l'L/cu. ft. gas 9.3
A blend which contains 50 mol per cent High Methane Natural Gas from line and 50 mol per cent fuel gas product from line 30 provides a SPG in line 101 which contains a practical minimum High Methane Natural Gas to achieve commercial interchangeability with High Methane Natural Gas.
Another natural gas which can be blended with the fuel gas product in line 30 is High B.T.U. Natural Gas. A common High B.T.U. Natural Gas has the following composition and characteristics:
Mol. CH 83.0 C H 16.0 CO 0.5 N 0.5 100.0
Sp. Gr. 0.64 Wobbe No. 1395 Weaver Flame Speed 14.7 HHV, B.T.U.IS.C.F. 1115 Required Theoretical Air for Combustion, cu.ft./cu. ft. gas 10.6
Customarily, High B.T.U. natural gas is defined as natural gas with a methane content below 90 mol per cent and a B.T.U. content of above 1100 B.T.U./S.C.F.
A blend which contains 60 mol per cent High B.T.U. Natural Gas from line 100 and 40 mol per cent fuel gas product from line 30 will provide a SPG in line 101 which can be burned safely and economically in conventional burners, designed to burn High B.T.U. Natural Gas. The SPG, so blended, has the following composition and characteristics:
Mol. H, 8.3 CH, 69.0 C H, 5.9 C H 10.5 C H, 2.8 C H 0.1 CO 0.2 CO 2.9 N 0.3 100.0
s v Gr. 0.64 Wobbe No. 1340 Weaver Flame Speed 18.6 HHV, B.T.U./S.C.F. 1070 Required Theoretical Air for Combustion, cu. ft./cu. ft. gas l0.0
It has been found that to provide a SPG interchangeable with High B.T.U. Natural Gas in commercial practice the blend of High B.T.U. Natural Gas and fuel gas product from line 30 should include 60 mol per cent of the High B.T.U. Natural Gas. The larger the percentage of High B.T.U. Natural Gas in the blend, the more the interchangeability with High B.T.U. natural gas is enhanced.
The debutanizer tower 36 operates at a temperature range from 100F. to 200F. and at a pressure of 65 psia. The debutanizer tower 36 is refluxed in the conventional manner and is provided with an overhead condenser (not shown) and a bottoms reboiler (not shown) in the conventional manner. The depropanizer tower bottoms line 92 comprises the feed stream to the debutanizer 36. C,,s are taken from the debutanizer 36. Cjs are taken from the debutanizer tower overhead through line 91. The overhead Cfs can be used for fuel in the pyrolysis furnace 32 or can be transported to processing equipment (not shown) for the purpose of separating therefrom, butadiene or other useful products. Line 93 is provided to convey the C s to the butadiene processing equipment. Pyrolysis gasoline is taken from the debutanizer bottoms through line 90. The debutanizer bottoms in line 90 is combined with the distillate stripper bottoms in line 94 resulting in the total pyrolysis gasoline from the pyrolysis plant. The total pyrolysis gasoline is transported through line 50 to the pyrolysis gasoline hydrotreater 52 wherein the olefins and other unsaturated hydrocarbons are hydrogenated. The pyrolysis gasoline hydrotreater 52 is also provided with a delivery line 54 for conveying hydrogen thereto from the hydrogen plant 64.
A line 58 is arranged to deliver the hydrotreated product pyrolysis gasoline from the hydrotreater 52 to the aromatics extraction unit 56. In the aromatics extraction unit 56 benzene, toluene and xylene are produced and are withdrawn from the unit through lines 82, 83 and 84. The unextracted portion, or raffinate, which remains after the benzene, toluene and xylene production, is delivered through line 60 to the feed line 12 of the catalytic gasification plant 4.
The hydrotreated gasoline from the hydrotreater 52 may optionally be blended with other available gasoline stocks to produce motor gasoline. Line 62 is provided as an alternate branch line to deliver the hydrotreated pyrolysis gasoline to the blending equipment. The process equipment further includes hydrotreating facilities comprised of a hydrogen plant 64, a pyrolysis gasoline hydrotreater 52 and an atmospheric residuum desulfurization unit 66.
A feed line 68 is provided to convey a portion of the low boiling distillate from the atmospheric distillation tower overhead line 12 to the hydrogen plane 64. The hydrogen plant 64 is conventional and is adapted to convert light overhead distillate from the atmospheric distillation tower 2 to hydrogen. Steam is introduced to the hydrogen plant 64 through line 85. By-product carbon dioxide is conveyed through line 70 to the atmosphere or to a dry ice plant (not shown).
The hydrogen generated in the hydrogen plant 64 is transported through line 86 to the atmospheric residuum desulfurization plant 66, through lines 87 and 54 to the pyrolysis gasoline hydrotreater 52, through lines 87 and 89 to the desulfurization unit 22 and optionally to line 76 for blending with the fuel gas product in line 30.
The atmospheric residuum desulfurization plant 66 contains equipment to remove sulfur from the atmospheric distillation residuum of the crude oil which is taken through line 18 as bottoms from the atmospheric distillation unit 2.
The desulfurized fuel oil is taken through line 74 as a low sulfur fuel oil product. A particularly suitable use for the fuel oil is in power stations for generating steam. If the fuel oil is used in power stations which normally employ natural gas to tire the boilers, the natural gas previously used therein will be released for other uses uniquely suitable to its character.
In operation, the process and system of the substitute pipeline gas generating facility of the present invention converts crude oil to synthetic pipeline gas, fuel oil and petrochemicals. The crude oil 10 which is to be desalted, if necessary, is delivered to the atmospheric distillation tower 2 where it is separated into three fractions. The low boiling distillate, i.e., the fraction boiling below about 375F., is taken overhead through line 12 and delivered to the catalytic gasification plant 4. A portion of the overhead from the atmospheric distillation unit is also delivered through line 68 to the hydrogen plant 64.
The low boiling distillate which is delivered to the catalytic gasification plant 4 is reacted with steam in the catalytic gasification vessel 20. The reaction is performed over a nickel-based catalytic bed at a tempera ture of approximately 900F. and a pressure of about 500 psig. The gasified product thus produced in a vessel 20 is cooled in exchanger 10', or equivalent, and then directly purified in absorber 32 by removal of at least a portion of the CO present in the gas. Residual steam is removed from the gas in cooler 34. The resulting gas product has a methane content of approximately 60 to v0. and a higher heating value of between 700-800 B.T.U./S.C.F.
The low boiling distillate from the atmospheric distillation unit 2, which is delivered to the hydrogen plant 64, is converted to hydrogen. The hydrogen is delivered to the pyrolysis gasoline hydrotreater 52, the atmospheric residuum desulfurization plant 66, the desulfurization unit 22 and a portion may be delivered optionally to the SP6 product line 30.
The middle distillate from the atmospheric distilla tion unit boils between 375F. and 650F. This range distillate is delivered to the pyrolysis furnace 32 wherein it is cracked at about 1,500F. at approximately atmospheric pressure but not limited to atmospheric pressure.
I The furnace effluent is quenched. compressed, dryed and delivered to a depropanizer 34 wherein the C s and lighter hydrocarbons are taken overhead. After acid gas or H 8 removal and C acetylene, C acetylene and propadiene hydrogenation, the C and lighter hydrocarbons and hydrogen are delivered to pipeline gas product line 30. In line 30, the C s and lighter constituents are blended with the gas effluent in line 28 from the catalytic gasification plant 4.
The higher heating value of the C and lighter stream in line 31 is approximately 1300 to 1400 B.T.U./S.C.F. Thus, the blending is regulated to provide a fuel gas product of approximately 1000 B.T.U./S.C.F. with a specific gravity of about 0.65, a Wobbe number of about 1240 and a Weaver flame speed of about 25.0. A fuel gas product of these characteristics is so obtained without use of the methanator vessel 27. The fuel gas product with the above-cited characteristics is so obtained by feeding the effluent in line 21 directly to the CO absorber 32, thus by-passing the methanator 27 and exchanger 11.
Carbon dioxide is removed in absorber 32 to any desired degree, thus providing a means for regulating the specific gravity, heating value and burning characteristics of the fuel gas product in line 30 and the substitute pipeline product gas in line 101. The specific gravity, heating value, and burning characteristics of the fuel gas product and the substitute pipeline product gas may be further controlled by including the methanation vessel 27. The methanation vessel 27, if included, provides a degree of additional control on the characteristics of the fuel gas product and the substitute pipeline gas, primarily by increasing the methane content and decreasing the hydrogen content of the catalytic vessel effluent stream 13. The specific gravity, heating value and burning characteristics of the fuel gas product and the substitute pipeline gas product can be controlled to a slightly further degree by introducing hydrogen into the blended gas through line 76 and also by adjusting the severity of cracking in the pyrolysis furnaces 32.
If CO is present in the product gas in quantities sufficiently high to cause corrosion in downstream pipelines, then this gas may be rendered non-corrosive, if moisture is entirely eliminated by drying the gas in the drying unit 36.
The Cjs and heavier hydrocarbons which form the bottoms of the depropanizer 34 are treated in the debutanizer tower 36 to provide C s overhead, and pyrolysis gasoline in the bottoms. The C s are optionally mixed with some C s and returned to the pyrolysis furnace 32 to be used there as fuel. The pyrolysis gasoline is hydrotreated in the hydrotreater 52 to hydrogenate olefins and diolefins and further refined to produce chemicals such as benzene, toluene and xylenes which are removed from the unit through lines 82, 83 and 84. The raffinate from the chemical production process is returned to line 12 for use as feed in the manufacture of the fuel gas product in the catalytic gasification plant 4.
The heavy (high boiling) material from the atmospheric distillation unit 2 is taken from the bottom of the unit and treated in the atmospheric residuum desulfurization plant 66. The major portion of the sulfur is removed and the end product is fuel oil which is now One hundred thousand barrels of a typical crude oil such as a light Kuwait crude after desalting are delivered to the atmospheric distillation tower 2. As a result of the processing in the atmospheric distillation unit, 17,000 barrels of low boiling distillate with a 375F. End Point are taken overhead.
Fourteen-thousand-eight hundred fifty (14,850) barrels of the low boiling distillate are delivered to the catalytic gasification vessel 20. Therein the low boiling distillate is reacted with steam over the nickel-based catalyst at approximately 900F. and about 500 pounds per square inch gage pressure.
The methanator 27 is entirely by-passed in this example. The effluent in line 13 from the catalytic gasification vessel 20 after cooling in exchanger 10 or equivalent is passed directly to the CO absorber 32. Carbon dioxide is partially removed in absorber 32 and the residual steam is removed from the gas in cooler 34. The line 35 is provided to pass the gas from the cooler 34. The drying unit 36 is optional and is by-passed in this example. Therefore, the gas resulting in line 35 is the product gas from the catalytic gasification plant. One hundred twenty-four million (124,000,000) standard cubic feet of this gas is produced. The higher heating value of this gas is 718 B.T.U./S.C.F.
The remaining 2,150 barrels of low boiling distillate are delivered to the hydrogen plant 64. Therein the distillate is treated by conventional means and 33.7 million standard cubic feet of hydrogen gas is produced. Eleven million two hundred thousand (1 1,200,000) standard cubic feet of the hydrogen is delivered to the pyrolysis gasoline hydrotreater 52 and the remainder is passed to the desulfurization units 66 and 22. Nineteen million eight hundred thousand (19,800,000) standard cu. feet of hydrogen is delivered to unit 66 and 2.7 million cubic feet is delivered to unit 22.
The middle distillate from the atmospheric distillation unit 2, boiling from 375F. to 650F., provides 35,000 barrels of feed for the pyrolysis plant. These 35,000 barrels are cracked in the pyrolysis furnace 32. The effluent from the pyrolysis furnaces is quenched and then delivered to the depropanizer 34. The depropanizer 34 provides 106 million standard cubic feet of C s and lighter hydrocarbons as an overhead product stream. Ninety-five million (95,000,000) standard cubic feet of C s and lighter hydrocarbons are delivered through line 31 to be blended with the gas through line 28 from the catalytic gasification plant. The higher heating value of the C s and lighter hydrocarbons is 1,368 B.T.U./S.C.F. Thus, the 124 million standard cubic feet of gas from the catalytic gasification plant and the million standard cubic feet of C s and lighter hydrocarbons from the pyrolysis plant produce 219 million standard cubic feet of fuel gas product.
The higher heating value of the fuel gas product is 1000 B.T.U./S.C.F. This gas has a specific gravity of 0.65 a Wobbe number of 1240 and a Weaver flame speed of 25.1.
The debutanizer tower in the pyrolysis plant provides 47,000 lbs. per hour of C.,s which are mixed with 11 million standard cubic feet of C s and lighter hydrocarbons from line 54 and the combined stream is returned through line 55 to the pyrolysis furnace wherein it is used as fuel. The bottoms fractions from the distillate stripper 44 and the debutanizer 36 are combined and provide pyrolysis gasoline which, after treatment in the hydrotreater, yields 10,750 barrels of hydrotreated gasoline. ln addition. 4.000 barrels of pyrolysis fuel oil are also produced as bottoms from the primary fractionation tower 42.
The atmospheric distillation crude unit also produces 48,000 barrels of atmospheric residuum plus high boiling distillate. This stream is passed by line 18 to the atmospheric residuum desulfurization plant 66. The stream is desulfurized and purified in the atmospheric residuum desulfurization plant 66 and approximately 48,000 barrels of fuel oil product result.
Another example of the process of the subject inven tion repeats the first example to produce 219 million standard cubic feet of fuel gas product. Then 219 million standard cubic feet of High Methane Natural Gas are blended with the 219 million standard cubic feet of fuel gas product to produce 438 million standard cubic.
feet of SPG, thus the blended mixture contains 50 mol per cent High Methane Natural Gas and 50 mol percent fuel gas product.
A third example of the process of the subject invention repeats the first example to produce 219 million standard cubic feet of fuel gas product. Then 329 million standard cubic feet High B.T.U. natural gas is blended with the 219 million standard cubic feet of fuel gas product to produce 548 standard cubic feet of SPG, thus the blended mixture contains 60 mol per cent High B.T.U. natural gas and 40 mol per cent fuel gas product. I
What is claimed is:
l. A process for producing a fuel gas product from crude oil comprising:
separating from the crude oil feed a first distillate fraction boiling below about 375F.;
separating from the crude oil feed a second distillate fraction boiling between 375F. and 650F.; gasifying the first distillate fraction to obtain a product gas; cracking by steam hydrocarbon pyrolysis the second distillate fraction in a pyrolysis furnace to produce a pyrolysis cracked furnace effluent;
separating the pyrolysis cracked furnace effluent into a stream containing C s, lower hydrocarbons and hydrogen and streams containing other products; and
blending the stream containing the G s, lower hydrocarbons and hydrogen with the product gas produced in the gasification step to produce a fuel gas containing olefins.
2. A process for producing a fuel gas product from crude oil comprising:
separating from the crude oil feed a first distillate fraction boiling below about 375F.;
separating from the crude oil feed a second distillate fraction boiling between 375F. and 650F.; gasifying the first distillate fraction to obtain a product gas; cracking by steam hydrocarbon pyrolysis the second distillate fraction in a pyrolysis furnace to produce a pyrolysis cracked furnace effluent;
separating the pyrolysis cracked furnace effluent into a stream containing C s, lower hydrocarbons and hydrogen, and streams containing other products;
blending the stream containing the C s, lower hydrocarbons and hydrogen with the product gas pro- 6 duced in the gasification step to produce a fuel gas containing olefins;
delivering a portion of the first distillate fraction to a hydrogen plant; generating hydrogen in the hydrogen plant; delivering hydrogen from the hydrogen plant to an atmospheric residuum desulphurization plant; delivering the bottoms of the crude oil feed, which is atmospheric residuum remaining in the crude oil feed after removal of the first and second distillate fractions to the atmospheric residuum desulphurization plant; and
removing the sulfur from the bottoms.
3. A process as in claim 1 further comprising the steps of separating the other products from the furnace effluent into a first fraction of G s, a second fraction of pyrolysis gasoline and a third fraction of pyrolysis fuel oil.
4. A process as in claim 3 further comprising the steps of:
delivering a portion of the first distillate fraction to a hydrogen plant;
generating hydrogen in the hydrogen plant;
delivering a portion of the hydrogen from the hydrogen plant to a pyrolysis gasoline hydrotreater; delivering the pyrolysis gasoline to the pyrolysis gasoline hydrotreater; and
removing the olefins from the pyrolysis gasoline in the pyrolysis gasoline hydrotreater.
5. A process as in claim 4 further comprising the steps of:
producing an aromatics extract. containing benzene,
tolulene and xylenes from the hydrotreated pyrolysis gasoline; and
returning the unextracted constituents of the hydrogenated pyrolysis gasoline to the gasification plant.
6. A process as in claim 3 further comprising the steps of:
mixing the first fraction of C s and a portion of the stream containing G s and lower hydrocarbons to form a mixture; and
delivering the mixture of Cjs and G s and lower bydrocarbons to the pyrolysis furnace for fuel. 7. A process as in claim 5 further comprising the steps of:
mixing the first fraction of C s and a portion of the stream containing C s and lower hydrocarbons to form a mixture; and
delivering the mixture of C s and C s and lower bydrocarbons to the pyrolysis furnace for fuel.
8. A process as in claim 1 wherein the gasification of the first distillate fraction is catalytic gasification.
9. A process as in claim 8 wherein the catalytic gasification is performed by delivering steam to a catalytic gasification vessel and passing the steam and first distillate fraction over a nickel-based catalyst at about 900F. and about 500 psig.
10. A process as in claim 9 further comprising the steps of removing carbon dioxide and residual steam from the gas produced in the catalytic gasification vessel.
11. A process as in claim 1 further comprising the steps of:
delivering a portion of the first distillate fraction to a hydrogen plant;
generating hydrogen in the hydrogen plant; and
mixing hydrogen from the hydrogen plant with the stream containing C s and lower hydrocarbons and with the gas produced in the gasification plant.
12. A process as in claim 7 further comprising the step of mixing hydrogen from the hydrogen plant with the stream containing C s and lower hydrocarbons and with the gas produced in the gasification plant.
13. A process as in claim 12 further comprising the steps of:
delivering hydrogen from the hydrogen plant to an atmospheric residuum desulphurization plant;
delivering the bottoms of the crude oil feed which is atmospheric residuum remaining in the crude oil feed after removal of the first and second distillate fractions to the atmospheric residuum desulphurization plant; and
removing the sulfur from the bottoms.
14. A process as in claim 12 wherein the gasification of the first distillate fraction is catalytic gasification;
15. A process as in claim 14 wherein the product gas from the catalytic gasification step has a heating value between 700800 B.T.U./S.C.F. and the stream containing C s and lighter hydrocarbons from the pyrolysis effluent has a heating value of 13004400 B.T.U./S.C.F.
16. A process as in claim 1 further comprising the step of:
delivering a portion of the first distillate fraction to a hydrogen plant; generating hydrogen in the hydrogen plant; delivering hydrogen from the hydrogen plant to a desulfurization removal plant; and removing sulfur from the first distillate fraction in the desulfurization removal plant prior to gasifying the first distillate fraction. 17. The process of claim 1 wherein separation of the first and second fractions from the crude oil feed is performed by atmospheric distillation.
UNITED STATES PATENT AND TRADEMARK OFFICE CERTIFICATE OF CORRECTION b PATENTNO. 3,836,344
DATED I September 17, 1974 |NV ENTOR( I Krawitz et al It is certified that error appears in the above-identified patent and that said Letters Patent k are hereby corrected as shown below:
Page 1, Col. 1, between "Inventors" and "Filed" insert Assignee: Stone & Webster Engineering Corp. Boston, Mass. P Column 5, line 40 after "48" change "and" to an Column 6, line after "drying system" change "34" to 45 Column lO, line 47 after "in" delete a Column 14, line 34 change "hydrogenated" to --hydrotreated- Signed and Scaled this Fit rh a Of N [SE D ovember I977 Attest:
RUTH C. MASON Acting Commissioner of Patents and Trademarks

Claims (16)

  1. 2. A process for producing a fuel gas product from crude oil comprising: separating from the crude oil feed a first distillate fraction boiling below about 375*F.; separating from the crude oil feed a second distillate fraction boiling between 375*F. and 650*F.; gasifying the first distillate fraction to obtain a product gas; cracking by steam hydrocarbon pyrolysis the second distillate fraction in a pyrolysis furnace to produce a pyrolysis cracked furnace effluent; separating the pyrolysis cracked furnace effluent into a stream containing C3''s, lower hydrocarbons and hydrogen, and streams containing other products; blending the stream containing the C3''s, lower hydrocarbons and hydrogen with the product gas produced in the gasification step to produce a fuel gas containing olefins; delivering a portion of the first distillate fraction to a hydrogen plant; generating hydrogen in the hydrogen plant; delivering hydrogen from the hydrogen plant to an atmospheric residuum desulphurization plant; delivering the bottoms of the crude oil feed, which is atmospheric residuum remaining in the crude oil feed after removal of the first and second distillate fractions to the atmospheric residuum desulphurization plant; and removing the sulfur from the bottoms.
  2. 3. A process as in claim 1 further comprising the steps of separating the other products from the furnace effluent into a first fraction of C4''s, a second fraction of pyrolysis gasoline and a third fraction of pyrolysis fuel oil.
  3. 4. A process as in claim 3 further comprising the steps of: delivering a portion of the first distillate fraction to a hydrogen plant; generating hydrogen in the hydrogen plant; delivering a portion of the hydrogen from the hydrogen plant to a pyrolysis gasoline hydrotreater; delivering the pyrolysis gasoline to the pyrolysis gasoline hydrotreater; and removing the olefins from the pyrolysis gasoline in the pyrolysis gasoline hydrotreater.
  4. 5. A process as in claim 4 further comprising the steps of: producing an aromatics extract containing benzene, tolulene and xylenes from the hydrotreated pyrolysis gasoline; and returning the unextracted constituents of the hydrogenated pyrolysis gasoline to the gasification plant.
  5. 6. A process as in claim 3 further comprising the steps of: mixing the first fraction of C4''s and a portion of the stream containing C3''s and lower hydrocarbons to form a mixture; and delivering the mixture of C4''s and C3''s and lower hydrocarbons to the pyrolysis furnace for fuel.
  6. 7. A process as in claim 5 further comprising the steps of: mixing the first fraction of C4''s and a portion of the stream containing C3''s and lower hydrocarbons to form a mixture; and delivering the mixture of C4''s and C3''s and lower hydrocarbons to the pyrolysis furnace for fuel.
  7. 8. A process as in claim 1 wherein the gasification of the first distillate fraction is catalytic gasification.
  8. 9. A process as in claim 8 wherein the catalytic gasification is performed by delivering steam to a catalytic gasification vessel and passing the steam and first distillate fraction over a nickel-based catalyst at about 900*F. and about 500 psig.
  9. 10. A process as in claim 9 further comprising the steps of removing carbon dioxide and residual steam from the gas produced in the catalytic gasification vessel.
  10. 11. A process as in claim 1 further comprising the steps of: delivering a portion of the first distillate fraction to a hydrogen plant; generating hydrogen in the hydrogen plant; and mixing hydrogen from the hydrogen plant with the stream containing C3''s and lower hydrocarbons and with the gas produced in the gasification plant.
  11. 12. A process as in claim 7 further comprising the step of mixing hydrogen from the hydrogen plant with the stream containing C3''s and lower hydrocarbons and with the gas produced in the gasification plant.
  12. 13. A process as in claim 12 further comprising the steps of: delivering hydrogen from the hydrogen plant to an atmospheric residuum desulphurization plant; delivering the bottoms of the crude oil feed which is atmospheric residuum remaining in the crude oil feed after removal of the first and second distillate fractions to the atmospheric residuum desulphurizatioN plant; and removing the sulfur from the bottoms.
  13. 14. A process as in claim 12 wherein the gasification of the first distillate fraction is catalytic gasification.
  14. 15. A process as in claim 14 wherein the product gas from the catalytic gasification step has a heating value between 700-800 B.T.U./S.C.F. and the stream containing C3''s and lighter hydrocarbons from the pyrolysis effluent has a heating value of 1300-1400 B.T.U./S.C.F.
  15. 16. A process as in claim 1 further comprising the step of: delivering a portion of the first distillate fraction to a hydrogen plant; generating hydrogen in the hydrogen plant; delivering hydrogen from the hydrogen plant to a desulfurization removal plant; and removing sulfur from the first distillate fraction in the desulfurization removal plant prior to gasifying the first distillate fraction.
  16. 17. The process of claim 1 wherein separation of the first and second fractions from the crude oil feed is performed by atmospheric distillation.
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Cited By (14)

* Cited by examiner, † Cited by third party
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US4209305A (en) * 1975-12-08 1980-06-24 British Gas Corporation Process for making substitute natural gas
US4217112A (en) * 1978-12-29 1980-08-12 Hydrocarbon Research, Inc. Production of fuel gas by liquid phase hydrogenation of coal
US4289475A (en) * 1977-01-05 1981-09-15 Selas Corporation Of America Steam vaporization of oil
WO2001060950A1 (en) * 2000-02-17 2001-08-23 Imperial Chemical Industries Plc Desulphurisation
US20030129109A1 (en) * 1999-11-01 2003-07-10 Yoram Bronicki Method of and apparatus for processing heavy hydrocarbon feeds description
US20100108492A1 (en) * 2008-11-05 2010-05-06 Mr. Azamat Zaynullovich Ishmukhametov Method for cracking, unification and refining of hydrocarbons and device for its implementation
US20110229382A1 (en) * 2010-03-17 2011-09-22 General Electric Company System for heat integration with methanation system
WO2013041186A1 (en) * 2011-09-21 2013-03-28 Linde Aktiengesellschaft Adjustment of the wobbe index of fuels
WO2013045025A1 (en) * 2011-09-29 2013-04-04 Linde Aktiengesellschaft Adjusting the wobbe index of fuels
US11149220B2 (en) 2020-02-13 2021-10-19 Saudi Arabian Oil Company Process and system for hydrogenation, hydrocracking and catalytic conversion of aromatic complex bottoms
US11248173B2 (en) 2020-02-13 2022-02-15 Saudi Arabian Oil Company Process and system for catalytic conversion of aromatic complex bottoms
US11268037B2 (en) 2020-02-13 2022-03-08 Saudi Arabian Oil Company Process and system for hydrodearylation and hydrogenation of aromatic complex bottoms
US11279888B2 (en) 2020-02-13 2022-03-22 Saudi Arabian Oil Company Process and system for hydrogenation of aromatic complex bottoms
US11591526B1 (en) 2022-01-31 2023-02-28 Saudi Arabian Oil Company Methods of operating fluid catalytic cracking processes to increase coke production

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US3060116A (en) * 1959-11-06 1962-10-23 Socony Mobil Oil Co Inc Combination reforming and cracking process
US3531267A (en) * 1965-06-17 1970-09-29 Chevron Res Process for manufacturing fuel gas and synthesis gas
US3732085A (en) * 1971-06-04 1973-05-08 Gulf Research Development Co Thermally efficient nonpolluting system for production of substitute natural gas

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US3060116A (en) * 1959-11-06 1962-10-23 Socony Mobil Oil Co Inc Combination reforming and cracking process
US3531267A (en) * 1965-06-17 1970-09-29 Chevron Res Process for manufacturing fuel gas and synthesis gas
US3732085A (en) * 1971-06-04 1973-05-08 Gulf Research Development Co Thermally efficient nonpolluting system for production of substitute natural gas

Cited By (17)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US4209305A (en) * 1975-12-08 1980-06-24 British Gas Corporation Process for making substitute natural gas
US4289475A (en) * 1977-01-05 1981-09-15 Selas Corporation Of America Steam vaporization of oil
US4217112A (en) * 1978-12-29 1980-08-12 Hydrocarbon Research, Inc. Production of fuel gas by liquid phase hydrogenation of coal
US20030129109A1 (en) * 1999-11-01 2003-07-10 Yoram Bronicki Method of and apparatus for processing heavy hydrocarbon feeds description
WO2001060950A1 (en) * 2000-02-17 2001-08-23 Imperial Chemical Industries Plc Desulphurisation
JP2003523450A (en) * 2000-02-17 2003-08-05 インペリアル・ケミカル・インダストリーズ・ピーエルシー Desulfurization
US20100108492A1 (en) * 2008-11-05 2010-05-06 Mr. Azamat Zaynullovich Ishmukhametov Method for cracking, unification and refining of hydrocarbons and device for its implementation
US7931785B2 (en) * 2008-11-05 2011-04-26 Azamat Zaynullovich Ishmukhametov Method for cracking, unification and refining of hydrocarbons and device for its implementation
US20110229382A1 (en) * 2010-03-17 2011-09-22 General Electric Company System for heat integration with methanation system
US8354082B2 (en) * 2010-03-17 2013-01-15 General Electric Company System for heat integration with methanation system
WO2013041186A1 (en) * 2011-09-21 2013-03-28 Linde Aktiengesellschaft Adjustment of the wobbe index of fuels
WO2013045025A1 (en) * 2011-09-29 2013-04-04 Linde Aktiengesellschaft Adjusting the wobbe index of fuels
US11149220B2 (en) 2020-02-13 2021-10-19 Saudi Arabian Oil Company Process and system for hydrogenation, hydrocracking and catalytic conversion of aromatic complex bottoms
US11248173B2 (en) 2020-02-13 2022-02-15 Saudi Arabian Oil Company Process and system for catalytic conversion of aromatic complex bottoms
US11268037B2 (en) 2020-02-13 2022-03-08 Saudi Arabian Oil Company Process and system for hydrodearylation and hydrogenation of aromatic complex bottoms
US11279888B2 (en) 2020-02-13 2022-03-22 Saudi Arabian Oil Company Process and system for hydrogenation of aromatic complex bottoms
US11591526B1 (en) 2022-01-31 2023-02-28 Saudi Arabian Oil Company Methods of operating fluid catalytic cracking processes to increase coke production

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