US3732085A - Thermally efficient nonpolluting system for production of substitute natural gas - Google Patents

Abstract

SULFUR-FREE, METHANE-RICH SUBSTITUTE NATURAL GAS IN PRODUCED FROM A HIGH SULFUR CRUDE OIL BY A NONPOLLUTING PROCESS CAPABLE OF ACHIEVING AN UNEXPECTEDLY HIGH TERMAL EFFCICENCY. THE PRROCESS COMPISES SEPARATING WHOLE CRUDE OIL INTO A PLURALITY OF FRACTIONS COMPRISING A BOTTOMS FRACTION AND A LIGHTER OIL FRACTION, DESULFURIZING AND HYDROCRACKING THE OIL FRACTION INTO A SUBSTANTIALLY SULFUR-FREE NAPHTHA IN THE PRESENCE OF HYDROGEN, WHICH IS PROVIDED BY CONVERTING A RESIDUE PORTION OBTAINED FROM THE BOTTOMS FRACTION. THE RESULTING SULFUR-FREE NAPHTHA IS COVERED INTO SUBSTITUTE NATURAL GAS IN THE PRESENCE OF STREAM. NOT ONLY IS A THERMAL EFFICIENCY OF APPROXIMATELY 100 PERCENT OBTAINED, NOTWITHSTANDING THE USE OF A PORTION OF THE CRUDE OIL FOR REFINERY FUEL, BUT NAPHTHA IS PRODUCED AT A VOLUMETRIC EFFICIENCY OF ABOUT 100 PERCENT BASED UPON THE CRUDE OIL FEEDSTOCK. THE SYSTEM IS AUTOGENIC WITH RESPECT TO HYDROGEN REQUIREMENTS FOR DESULFURIZATION, NITROGEN REMOVAL, AND HYDROCRACKING.

D R A W I N G

Description

May 8, 1973 N CARR ETAL.

THERMALLY EFFICIENT NONPOLLUTING SYSTEM FOR PRODUCTION OF SUBSTITUTE NATURAL GAS 2 Sheets-Sheet 1 Filed June 4, 1971 INVENTOR R M E R W mum CRT 8 LA N A Y M R R RRR O A A NWH \N.

May 8, 1973 CARR ETTAL 3,732,685

N. L. THERMALLY EFFICIENT NONPOLLUTING SYSTEM FOR PRODUCTION Filed June 4., 1971 OF SUBSTITUTE NATURAL GAS 2 Sheets-Sheet 2 FIG. .3

1 THERMAL BWC/ENCY,

40 I I I I I /00 90 a0 70 lb CH 60 50 METHANE YIELD, lb CRUDE INVENTORS G45 WELD, "f, NORMAN L. cARR WARREN A. ROE JR. HARRY c. sTAURFE United States Patent 3,732,085 THERMALLY EFFICIENT NONPOLLUTTNG SYS- TEM FOR PRQDUCTION OF SUBSTITUTE NATURAL GAS Norman L. Carr, Allison Park, Warren A. Roe, Jr., Upper St. Clair, and Harry C. Stautrer, Cheswick, Pa., assignors to Gulf Research & Development Company, Pittsburgh, Pa.

Filed June 4, 1971, Ser. No. 150,146 I Int. Cl. C07c 9/04 US. Cl. 48-214 12 Claims ABSTRACT OF THE DISCLOSURE Sulfur-free, methane-rich substitute natural gas is produced from a high sulfur crude oil by a nonpolluting process capable of achieving an unexpectedly high thermal efficiency. The process comprises separating whole crude oil into a plurality of fractions comprising a bottoms fraction and a lighter oil fraction, desulfurizing and hydrocracking the oil fraction into a substantially sulfur-free naphtha in the presence of hydrogen, which is provided by converting a residue portion obtained from the bottoms fraction. The resulting sulfur-free naphtha is converted into substitute natural gas in the presence of steam. Not only is a thermal efficiency of approximately 100 percent obtained, notwithstanding the use of a portion of the crude oil for refinery fuel, but naphtha is produced at a volumetric efficiency of about 100 percent based upon the crude oil feedstock. The system is autogenic with respect to hydrogen requirements for desulfurization, nitrogen removal, and hydrocracking.

This invention relates to a process for converting crude oil containing a high proportion of sulfur and other contaminants into a substantially sulfur-free and nitrogenfree gaseous fuel. More particularly, this invention relates to a substantially pollution-free, thermally efficient, integrated process for employing the various fractions obtained by the distillation of crude oil in a highly efficient and relatively simple manner to provide a methane-rich gaseous product which is interchangeable with a highquality natural gas.

Natural gas is a highly desirable fuel, since it is a sulfurfree, clean burning fuel. Sulfur in certain fuels is a prime source of air pollution, since it produces noxious sulfur dioxide upon combustion. -In view of the desirability of consuming natural gas for ecological and other reasons, it has been projected that there will be a shortage of this material in the future since its supply is, of course, limited. High quality natural gas has a heat content of about 1,000 B.t.u.s per standard cubic foot (B.t.u./s.c.f.). Various proposals have been made in recent years for providing a substitute natural gas, i.e. a manufactured gaseous fuel, which is completely interchangeable with natural gas.

However, many of these processes have suifered from certain drawbacks. For example, it has been proposed to employ cyclic pyrolysis processes for converting distillate and residual petroleum oils into a high-Btu gas. However, such gases may not be substituted for natural gas in concentrations above 50 volume percent. See Manufactured Gas, Kirk-Othmer, Encyclopedia of Chemical Technology, second edition, volume 10, Interscience Publishers (1966), pages 388 to 432. Other processes have been proposed which are capable of providing a substitute natural gas. However, such processes have been capable of yielding a thermal efficiency of only about 60 to 70 percent at most when employing a crude or heavy oil feedstock. More recently, various processes have been proposed for producing substitute natural gas from a sulfur-free naphtha fraction. However, the naphtha is "ice usually obtained by a series of operations including, for example, distillation, desulfurization, etc. in a complex manner in order to obtain the naphtha which is ultimatel converted into the substitute natural gas. Naphtha is not usually available in sufiicient quantities for gasification; it is better used for gasoline manufacture.

It has now been found that whole crude oil containing a relatively high proportion of sulfur compounds and other contaminants including organically-bound nitrogen, vanadium and nickel, etc., may be subjected to a relatively simple, integrated process in which virtually all portions of the crude are utilized to provide a methane-rich, substitute natural gas which is completely interchangeable with a high-quality natural gas. The process of the present invention comprises separating the sulfur-containing crude oil into a plurality of fractions comprising a bottoms fraction and a lighter liquid fraction, such bottoms fraction providing a residue fraction, converting the residue fraction to hydrogen, hydrocracking and desulfurizing the lighter liquid fraction in the presence of at least a portion of the hydrogen to provide a substantially sulfur-free naphtha fraction, and converting the naphtha fraction to a methane-rich, gaseous fuel product in the presence of steam.

Surprisingly, the process of the present invention is capable of converting crude oil to a substitute natural gas at about percent thermal efficiency. In addition, the present process is autogenous with regard to hydrogen requirements. The low value pitch or the coke portions obtained from the bottom fraction of the crude oil is converted to hydrogen in quantities sufficient to keep the present system in hydrogen balance. This hydrogen is employed to desulfurize, denitrify, and hydrocrack a lighter portion of the crude to substantially sulfur-free naphtha which, in turn, is converted to a methane-rich fuel product.

Still another advantage of the present invention is that it is capable of converting a high-sulfur content crude oil to a more valuable naphtha fraction, which is sulfur-free, at about a 100 percent volumetric efliciency. Thus, as will be hereinafter demonstrated, 100,000 barrels per day of a sulfur-containing crude oil may be converted to approximately 100,000 barrels per day of a substantially sulfur-free naphtha. A portion of the crude is used for fuel and for hydrogen production in this case.

In addition to the economic advantages related to the thermal and volumetric efficiencies of the present process, it is significant that no sulfur (in the form of either S0 or hydrogen sulfide) is released by the present process to the atmosphere or to a public waterway, and essentially no sulfur is present in the pipeline gas product. Accordingly, neither the process nor the product of the present process contribute to air or water pollution. The only byproducts of the process are relatively pure elemental sulfur, carbon dioxide and ammonium hydroxide each of which have commercial value. For example, the ammonium hydroxide may be converted to ammonium sulfate fertilizer. The only feedstock to the process are crude oil, water and air, and there is but a single hydrocarbon product of the process, namely, a non-polluting pipeline gas.

The process will now be described in more detail by reference to the drawings, of which:

FIG. 1 is a flow diagram of the process of the present invention in which a sulfur-containing, whole crude oil is converted into a methane-rich pipeline gas;

FIG. 2 is a flow diagram showing in more detail a portion of the process illustrated in FIG. 1, in which the naphtha is converted into pipeline gas; and

FIG. 3 of the accompanying drawing presents experimental data demonstrating the unexpectedly high thermal efficiency provided by the present system.

The application of the process of the invention to the conversion of sulfur-containing crude oil to a methanerich pipeline gas is shown diagrammatically in FIG. 1.

Referring now to FIG. 1, a sulfur-containing crude oil is introduced into the system by means of a line into an atmospheric and vacuum distillation unit 12 wherein the crude oil is separated into a light gas fraction containing hydrogen sulfide and C to C gases, which light stream is discharged from the distillation unit by means of a line 14 to a gas treatment plant hereinafter described. Likewise, a light stream boiling in the C 375 F. range (e.g., a naphtha fraction) is withdrawn by means of line 16, while a heavy stream boiling in the 375-1040 F. range (e.g., the gas oil-furnace oil range) is withdrawn by means of a line 18. The bottoms fraction (e.g., 1040 F.+) is discharged from the bottom of tower 12 by means of line and is treated as will be hereinafter described.

The 375 1040 F. boiling range fraction is introduced by means of line 18 along with hydrogen from line 22 into hydrocracker unit 24. Hydrocracker 24 converts the gas oil fraction to a lighter, naphtha fraction, for example, in the C 35O boiling range and also converts the sulfur present to hydrogen sulfide, while converting organically-bound nitrogen to ammonia. The hydrogen sulfide is withdrawn along with C to C hydrocarbons by means of line 26 and the ammonit is withdrawn in the form of ammonium hydroxide from line 27, while the product naphtha fraction is discharged from the hydrocracker unit 24 by means of the line 28.

Hydrocracker 24 is preferably a two-stage unit wherein the primary function of the first stage is to remove the organic sulfur and nitrogen contaminants, while the second stage is the primary hydrocracking stage. It is essentially important to convert the nitrogen compounds to ammonia in the first stage, since these nirogen com pounds poison the catalyst in the hydrocracking stage. In a two-stage hydrocracking operation, the catalyst in the first stage may comprise, for example, a Group VI and Group VIII metal on a cracking or non-cracking support. A preferred catalyst is nickel-tungsten-fiuorine on a silica-alumina support. However, suitable catalysts also include cobalt-molybdenum, nickel-cobalt-molybdenum, nickel tungsten or nickel-molybdenum on an alumina support. In the second stage, the preferred catalyst is nickeltungsten-fluorine on a silica-alumina support. However, other suitable catalysts include the noble metals, such as platinum, palladium, etc., on zeolites or other cracking supports.

The hydrogen introduced by means of the line 22 is circulated through each hydrocracking stage of the unit 24 stage and is suitably 50 to 95 percent pure. However, 75 to 95 percent pure hydrogen is preferably employed. Suitable conditions for the first stage of the hydrocracker unit 24 include temperatures in the range of between about 600 and about 850 F., preferably between about 700 and about 800 F., while pressures in the range of between about 1000 and about 2500 p.s.i.g., preferably between about 1500 and about 2000 p.s.i.g. may be employed. Suitable space velocities include, for example, a liquid hourly space velocity (LHSV) of between about 0.1 and about 10, preferably between 1 and about 3 LHSV. Suitable hydrogen gas rates include about 1000 and about 10,000 s.c.f./bbl. of naphtha, preferably between about 3,000 and about 7,000 s.c.f./bbl.

Operating conditions for the primary hydrocracking stage or second stage of the hydrocracker unit include, for example, pressures of between about 1000 and about 5000 p.s.i.g., preferably between about 1500 and about 2500 p.s.i.g., with temperatures, for example, in the range of between about 600 and about 850 F., preferably between about 700 and about 800 F. A space velocity within the range employed in the first stage of the hydrocracker is suitable for the second stage, while a hydrogen gas rate in the range of about 5000 and about 20,000

4 preferably between about 8000 and about 15,000 s.c.f./ bbl. may be employed.

The naphtha fraction from hydrocracker 24 is passed by means of line 28 along with hydrogen gas introduced by means of the line 30 to a naphtha desulfurizer unit 32 within the naphtha and hydrogen circulate over a desulfurizing catalyst in order to desulfurize the naphtha and, in addition, saturate any olefins present in the naphtha stream. The naphtha can be fed directly to the gasification plant if its sulfur (organic) content is only about 1 ppm. An advantage of the present process is that only a very small amount of olefins are produced. Significant amounts of olefins cannot be tolerated in the pipeline gas product.

Suitable naphtha desulfurizing catalysts include, for example, Group VI and Group VIII metals on a noncracking support. A preferred desulfurizing catalyst is nickelcobalt-molybdenum on an alumina support. Likewise, a cobalt-molybdenum-, nickel-tungsten-, or a nickel-molybdenum-on-alumina catalyst may be suitably employed.

Operating conditions for the naphtha desulfurizer 32 include, for example, temperatures in the range of between about 400 and about 750 F., preferably between about 525 and 650 F., while suitable pressures include between about and about 1000 p.s.i.g., preferably between about 250 and about 750 p.s.i.g. The hydrogen stream may be employed at a rate of between about 400 and about 1000 s.c.f./bbl., preferably between about 500 and about 750 s.c.f./bbl., while the naphtha may be passed through the desulfurizer at a liquid hourly space velocity between about 2 and about 10, preferably between about 3 and about 7. Hydrogen sulfide is removed from the desulfurizer 32 by means of the line 34, and passed to a gas treatment plant hereinafter described.

The purified naphtha stream is discharged from the desulfurizer 32 by means of line 36 and is introduced into a substitute natural gas plant 38 wherein the naphtha is admixed with steam introduced by means of line 40 and converted along with some C and C gases obtained from another part of the system to a sulfur-free, methanerich fuel gas and carbon dioxide. The pure by-product carbon dioxide is discharged from the substitute natural gas plant 38 by means of the line 42, while the product methane-rich gas is discharged by means of the line 44.

According to an important aspect of the invention, the bottoms fraction 20 is passed to a visbreaker unit 46. The 1940 F.+ bottoms fraction line 20 is subjected to thermal cracking in the visbreaker 46 wherein the oil passes through heated coils and a portion thereof is cracked therein to lower molecular weight hydrocarbons. In this manner, additional light gases and naphtha suitable for conversion to additional methane are produced. The use of a visbreaker in the manner described is significant, since the volume of tar passed to the partial oxidazation unit (hereinafter described) is reduced thereby reducing the oxygen requirements for the oxidizer.

Suitable operating conditions for the visbreaker 46 include temperatures in the range of between about 800 and about 1000 F., preferably between about 850 and about 950 F. Operating pressures may be in the range of between about 50 and about 500 p.s.i.g., preferably between about 100 and about 300 p.s.i.g., while a suitable space velocity range is between about 2.5 and about 15 volumes of oil per hour per volume of the testing coil, preferably between about 5 and about 12 volumes of oil per hour per volume of coil.

Alternatively, unit 46 may be a coker unit wherein a portion of the bottoms fraction is reduced to coke with the concurrent production of additional naphtha and light gases. Suitable coking conditions are well known in the art and may include, for example, a temperature in the range of between about 900 and 950 F. and while employing atmospheric pressure. A solvent decarbonizer can also be employed, e.g. a unit wherein propane or other light paraflin is used to deasphalt or decarbonize. However, a visbreaker is especially preferred for the purposes of the present invention.

Light gases including hydrogen sulfide and C -C hydrocarbons are withdrawn from the visbreaker 46 by means of line 48, while a naphtha fraction boiling in the C 400 F. range is withdrawn by means of a line 50 and is passed to naphtha desulfurizer 32 (by a means not shown).

A fraction boiling in the range of 400 -950 F. is withdrawn from the visbreaker unit 46 by means of a line 52 and is introduced along with hydrogen introduced by means of line 54 to a desulfurizer unit 56.

The desulfurizer 56 may employ a noncracking catalyst similar to that employed in the naphtha desulfurizer 32. Suitable conditions which may be employed in the desulfurizer 56 include temperatures in the range of between about 600 and about 850 F., preferably between about 675 and about 775 F while suitable pressures include, for example, between about 750 and about 2000 p.s.i.g., preferably between about 800 and about 1200 p.s.i.g. The feed to the unit 56 may be passed therethrough at a space velocity of between about 0.5 and about 5 LHSV, preferably between about 1 and about 3 LHSV. Hydrogen is employed at a rate of between about 1000 and about 10,000 s.c.f./bbl. Preferably between about 2000 and about 5000 s.c.f./bb1. is used.

A light gas stream 58 comprising hydrogen sulfide and C hydrocarbons is withdrawn from the unit 56, while a fraction boiling in the range of C 400 F. is withdrawn by means of line 60 and may be passed to the naphtha desulfurizer unit 32 by a means not shown. A stream boiling in the range of 400 F.+ is discharged from the desulfurizer 56 by line 62 and this stream may be suitably employed as refinery fuel. This stream may constitute, for example, up to about percent by volume of the crude oil feedstock.

Alternatively, at least a portion of the 4-00-950 F. stream that is passed by means of line 52 to the desulfurizer unit 56 may be passed instead directly to the hydrocracker unit 24 by means of the line 52' and may be cracked therein to form additional naphtha and to increase the thermal efliciency of the process.

The desulfurizer 56 may be omitted altogether and all of the material in the stream 52 may be diverted to the hydrocracker unit 24 by means of the line 52. In this instance, refinery fuel may be drawn from the substitute natural gas product stream in line 44 or may be obtained as a portion of the heavy effluent from the hydrocracker.

According to another important aspect of the present invention, a residue pitch or coke fraction 64 is discharged from the bottom of the visbreaker unit 46 and is passed to a partial oxidizer unit 66 along with air and water which are introduced by means of the lines 68 and 70. Thus, portion of the crude oil which are ultimately provided in the form of either pitch or coke, which materials have the lowest economic value of any process fraction, are converted to useful hydrogen and to carbon dioxide. The sulfur present in this high boiling fraction is converted to hydrogen sulfide, while any organic nitrogen present is converted to ammonia. 'In this manner, the hydrogen requirements for the desulfurization, denitrification, and hydrocracking of the lower boiling portions of the crude oil are provided from the portions of the crude having the lowest value, thus rendering the process autogenous in hydrogen requirements and economically desirable. No extraneous hydrogen source is required to supply the large amount of hydrogen needed to convert the various streams to the ultimate product, viz, a methane-rich pipeline gas.

The hydrogen in line 72, which is withdrawn from the oxidizer 66 is passed to process lines 22, 30 and 54 to supply the various hydrogen requirements in the units 24, 32 and 56.

The partial oxidizer unit 66 may be operated at temperatures, for example, in the range of between about 2000 and about 3000 F., while employing pressures in the range of between about 400 and about 1500 p.s.i.g. at suitable residence times.

Hydrogen sulfide is withdrawn by means of line 74 and is passed to a line 76 wherein it is joined by other light gas streams 14, 26, 34, and 58 from other units in the system. The combined light gas streams are introduced into the gas treatment plant 78 for removal of hydrogen sulfide by a conventional scrubbing unit therein. Sulfurfree hydrogen, and C and C gases are withdrawn by means of the line 80 and are passed to the line 44, while sulfur-free C and C gases are withdrawn by means of the line 82 and are introduced into the substitute natural gas plant 38 along with the feed in line 36 (by a means not shown).

Elemental sulfur is recovered from the plant 78 and is withdrawn by means of the line 84.

Substantially pure carbon dioxide is withdrawn from the oxidizer 66 by means of the line 75 and combined with carbon dioxide which is withdrawn from the SNG plant by means of the line 42 and recovered therefrom.

Referring now to FIG. 2, the SNG plant 38 of FIG. 1 will now be described in more detail. Thus, a desulfurized naphtha is passed by means of line 136 to a guard bed 137 which may suitably contain zinc oxide for the removal of trace quantities of hydrogen sulfide and morcaptan sulfur, which impurity is discharged by means of line 138. A purified naphtha stream is discharged from the guard bed 137 by means of the line 139 wherein the naphtha is admixed with steam, which is introduced by means of line 140 and the combined stream is introduced into the reactor 142. Reactor 142 is a steam reforming unit wherein the naphtha and steam are contacted, for example, with a nickel-on-alumina catalyst for conversion to methane and carbon dioxide. Suitable conditions for the unit 142 include, for example, temperatures in the range of between 750 and 1000 F. and pressure of about 450 and about 550 p.s.i.g., while between about 1 and about 3, preferably between about 1.6 and about 2.0 pounds of steam per pound of naphtha are employed. A methane-rich gas having a heating value of, for example, about 700 B.t.u./s.c.f. is withdrawn from the unit 142 by means of the line 144 and the gas stream is thereby introduced into a hydrogasifier unit 146 wherein additional methane is produced from the hydrogen present in the stream 144. Suitable conditions for the hydrogasifier unit 146 include temperatures in the range of between about 625 and about 750 F.

A gas stream is withdrawn from the hydrogasifier unit 146 by means of line 148 which stream is enriched in methane and has a heating value of about 750 B.t.u./s.c.f., for example. The gas stream in line 148 is passed through a methanator wherein additional hydrogen and carbon monoxide are converted to methane. The methanator unit is a reactor wherein carbon monoxide and hydrogen are selectively converted to methane in the presence of a methanation catalyst, such as the same nickel catalyst as used in the first two stages of the SNG plant.

The product from the methanator unit 150 is discharged by means of line 152 and has a heating value of, for example, about 790 B.t.u./s c.f. This stream may then be introduced into the final purification stage 154 wherein carbon dioxide and water are removed by means of line 156, while the methane-rich fuel gas is discharged by means of line 158. This gas may have a heating value, for example, of about 1000 B.t.u./s.c.f. and is completely interchangeable with and a substitute for a high-quality natural gas.

As previously mentioned, the system of the present invention is capable of producing a pipeline gas at approximately 100 percent thermal efficiency. For example, 100,- 000 barrels per day of a crude oil containing sulfur and metal contaminants, such as nickel and vanadium, may

7 be processed by the present invention to provide about 5500 s.c.f./bbl. of crude of high quality pipeline gas at a thermal efficiency of from about 94 to about 100 percent.

Referring now to FIG. 3 of the drawing, it is seen that a pipeline gas yield of 5519 s.c.f. per barrel at a thermal efficiency of 94 percent based upon raw crude (line 260) is obtained by the present process. If only the crude oil portion of the feed which is free of sulfur and metals is considered (line 262) a 97 percent thermal efficiency is obtained. A combustible portion of the processed crude feed may be consumed as fuel within the process and another portion of the processed crude feed is employed to provide hydrogen for the desulfurization, denitrification and hydrocracking unit. Notwithstanding the utilization of this amount of the crude feed, a thermal efficiency of approximately 100 percent is still achieved. Furthermore, if less than 10 percent of the crude is employed as refinery fuel, e.g., about 5 percent, the present process is capable of providing a thermal efficiency in excess of 100 percent.

Although it is not intended to limit the present invention by any particular theory or mechanism, it appears that the high thermal efficiency achieved by the present process is realized because the hydrogen portion of the water that is employed, for example, in the partial oxidizer unit 66 and in the SNG plant 38 forms a portion of the ultimate methane product. In this manner, a thermal energy boost is realized which increases the overall thermal efiiciency of the process. In addition, energy conservation is achieved since virtually all the original crude oil energy is converted to gas fuel energy.

The process of the present invention provides practical- 1y a 100 percent efiiciency on a volumetric basis for converting sulfur-containing crude oil to sulfur-free naphtha, notwithstanding the fact that a portion of crude is consumed as refinery fuel and another portion is converted to hydrogen. Thus, for example, 98,655 barrels per day of sulfur-free naphtha may be prepared from 100,000 barrels per day of crude containing 2.7 weight percent sulfur.

Thus, the process of the present invention provides a thermal efficiency of approximately 100 percent and a volumetric efiiciency of approximately 100 percent when comparing the starting crude with the sulfur-free naphtha. In addition, virtually every portion of the crude is utilized along with water and air to provide a methane-rich fuel which is devoid of the prime source of air pollution, viz, sulfur, by means of a process whose by-products contribute to neither air nor water pollution. In short, the economic advantages of unexpected high thermal and volumetric efiiciencies are realized without adding to the polution of the air and waterways.

The following examples illustrate the preparation of pipeline gas according to the process of the present invention.

EXAMPLE A Kuwait crude oil containing 2.7 weight percent sulfur, nickel and vanadium, in the amount of 100,000 b.p.d. (barrels per day) are distilled to provide 51,950 b.p.d. of a stream boiling in the 375-1040 F. range, which is passed to a hydrocracker along with 95.3MM s.c.f.d. (million standard cubic feet per day) of hydrogen. Meanwhile, 21,000 b.p.d. of a 1040 F.+fraction are separated from the crude and are passed to a visbreaker wherein the bottoms fraction is thermally cracked at a temperature in the range of 850950 F. and a pressure of 100-300 p.s.i.g.

A stream comprising pitch is withdrawn from the visbreaker and the pitch has the composition set forth in Table I, following:

8 TABLE I.Visbreaker Pitch Gravity, solid state, 77/ 77 F 1.212 Softening point, F., ring and ball 337 Penetration, 210 F., g., 5 sec. 3 Carbon residue, Conradson, weight percent 59.4

Ultimate analysis, wt. percent:

Sulfur 7.52

Nitrogen 0.84 Hydrogen 6.70 Carbon 83.84

Undetermined 1.10 Metals, Ni-l-V, p.p.m 370 The resultant pitch is passed to a partial oxidizing unit wherein the pitch is reacted with air and water at a temperature of 2000-3000 F. and a pressure of 4001500 p.s.i.g. to provide 113.1MM s.c.f.d. of hydrogen. A portion of the hydrogen, i.e. 95.3 MM s.c.fd, are admixed with 53,663 barrels per day of the 3751040 P. fraction (96.8 volume percent) along with 3.2 volume percent of a 400950 F. boiling range fraction obtained from the visbreaker. The feed to the hydrocracker has the following composition set forth in Table II below:

TABLE II Gravity, API 29.3 Sulfur, wt. percent 2.01 Nitrogen, p.p.m 500 Carbon residue, rams. bottom, percent 0.50 Ni-l-V, p.p.m. 0.8 Aromatic, vol. percent 40 The resulting naphtha stream is desulfurized in a naphtha desulfurizer and has the composition set forth below in Table III:

The naphtha is then passed to a substitute natural gas plant wherein it is admixed with steam in the presence of nickel-on-alumina catalyst at a temperature of 930- 1000 F. The resulting pipeline gas has the composition set forth in Table IV, below and has a higher heating value of about 1000 B.t.u./s.c.f.

TABLE IV Composition: Volume percent Methane 98.35

Ethane 0.30

Ethylene 0.02 Hydrogen 0.93 Carbon dioxide 0.30 Carbon monoxide 0.10

Thus, it is seen that the process of the present invention is capable of providing a high quality natural gas substitute from a sulfur-containing whole crude oil.

The term thermal efiiciency as used herein is employed in its usual sense. Thus, with respect to the methane-rich pipeline gas of the present invention, thermal efiiciency may be calculated as follows:

Thermal efficiency (B.t.u./lb. pineline Gus Obviously, many modifications and variations of the invention as hereinabove set forth may be made without departing from the spirit and scope hereof and therefore only such limitations should be imposed as are indicated in the appended claims.

We claim:

1. A process for the production of a substantially sulfur-free, gaseous fuel production containing a high proportion of methane, which comprises separating a sulfurcontaining crude oil feedstock into a plurality of fractions comprising a light gas fraction, a first naphtha fraction, a higher boiling oil fraction and a bottoms fractions, obtaining a residue fraction from said bottoms fraction, converting said residue fraction to hydrogen, hydrocracking and desulfurizing said higher boiling oil fraction in the presence of at least a portion of said hydrogen to provide substantially sulfur-free, second naphtha fraction, and converting said sulfur-free, second naphtha fraction in the presence of steam to a methane-rich, gaseous fuel product.

2. The process of claim 1 wherein said residue fraction is obtained by subjecting said bottoms fraction to a visbreaking operation, a coking operation or a solvent decarbonizer operation.

3. The process of claim 2 wherein said bottoms fraction is subjected to a visbreaking operation to provide a residue fraction comprising pitch and a second higher boiling oil fraction, and said second higher boiling oil fraction is desulfuried and subjected to a hydrocracking option is desulfurized and subjected to a hydrocracking op- 4. The process of claim 3 wherein said visbreaking operation is conducted at a temperature in the range of between about 800 and 1000 F. and a pressure in the range of between about 50 and about 500 p.s.i.g.

5. The process of claim 1 wherein said residue fraction is subjected to partial oxidation in the presence of oxygen and water in the range of between about 2000" and about 3000 F. and a pressure in the range of between about 400 and about 1500 p.s.i.g.

6. The process of claim 1 wherein said first naphtha fraction boils in the C 375 F. range.

7. The process of claim 2 wherein said residue fraction is obtained by subjecting said bottoms fractions to a coking operation.

8. A process for the production of a substantially sulfur-free gaseous fuel product containing a high proportion of methane, which comprises distilling a sulfur-containing crude oil into a gaseous fraction, a first naphtha fraction, a heavier oil fraction boiling in the range of between about 375 and about 1040 F. and a bottoms fraction boiling above about 1040 F., subjecting said bottoms fraction to a visbreaking operation to obtain a residue frac tion comprising pitch, subjecting said residue fraction to partial oxidation in the presence of air and water to obtain hydrogen, hydrocracking said heavier oil fraction in the presence of at least a portion of said hydrogen to provide a second naphtha fraction, subjecting said first and said second naphtha fractions to a desulfurizat-ion operation, and converting the desulrfurized naphtha to a methanerich gaseous fuel in the presence of steam.

9. The process of claim 8 wherein said desulfur-ized naphtha is converted to a methane-rich, gaseous fuel product in the presence of steam and a catalyst comprising nickel on alumina.

10. The process of claim 8 wherein said visbreaking operation additionally provides a second oil fraction boiling in the range of between about 400 and about 950 F., and said fraction is hydrocracked to provide a third naphtha fraction.

11. The process of claim 10 wherein said second oil fraction is desulfurized prior to being hydrocracked.

12. The process of claim 8 wherein said first naphtha fraction boils in the C -375 F. range.

References Cited UNITED STATES PATENTS 3,531,267 9/1970 Gould 48-213 3,537,977 11/1970 Smith, Jr. 208-58 X 3,409,540 11/ 1968 Gould et al 208- X 3,321,395 5/1967 Paterson 208-78 2,989,460 6/ 1961 Eastman et al 208-107 JOSEPH SCOVRONEK, Primary Examiner US. Cl. X.R.

jgggg i 'UNiTED sT'lES PA 'l'E a 'CER'HFECAE oF CORECTIN Patent No. 35'732I085 D d May 8, 1973 Inventor) N. L. Carr, w. A. Roe, Jr. and H. c. Stauffer It .is certified that: error appears in the aboveridentified patent and that said Letters Patent are hereby corrected as shown below;

Column 3,v line 26 "ammonit" should read -amn1on ia Coluinn 4, line "within" should read wherein' Column 4}, line '46,; "-1940" should read -'-1o4o- Column 4', line 4 6, after "fraction" insert; .from Column 4, line 5"+, azfiofi should read i za tion". ColuI'I in 4, .line "testing" should read -heating- Column 9, l'ine 8, "production" should read --product Column 9,}1ihfejl29, delete entire line and insert eration to provide additional naphtha" Signed and sealed this 19t day of. November .1974.

'(SEAL) Attest:

' McCOY M. VGIBSON JR. a c. MARSHALL DANN Attesting Officera Commissioner of Patents

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