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Publication numberUS3228467 A
Publication typeGrant
Publication dateJan 11, 1966
Filing dateApr 30, 1963
Priority dateApr 30, 1963
Publication numberUS 3228467 A, US 3228467A, US-A-3228467, US3228467 A, US3228467A
InventorsNational Bank The Security Fir, Schlinger Warren G
Original AssigneeTexaco Inc
Export CitationBiBTeX, EndNote, RefMan
External Links: USPTO, USPTO Assignment, Espacenet
Process for recovering hydrocarbons from an underground formation
US 3228467 A
Abstract  available in
Images(2)
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Claims  available in
Description  (OCR text may contain errors)

Jan. 11, 1966 w. G. scHLlNGER ETAL 3,228,467

PROCESS FOR RECOVERING HYDROCARBONS FROM AN UNDERGROUND FORMATION 2 Sheets-Sheet 1 Filed April 50, 1963 -lip 2 Sheets-Sheet 2 Jan. 1l, 1966 w. G. scHLrNGER ETAL FROCESS FOR RECOVERING HYDROCARBONS FR AN UNDERGROUND FORMATION Filed April 50, 1963 United States Patent O 3,228,467 PRGCESS FR RECOVERlNG HYDROCARBNS FROM AN UNDERGROUND FORMATION Warren G. Schlinger, Pasadena, Calif., and du Bois Eastman, deceased, late of Whittier, Calif., by The Security first National Bank, executor, Los Angeles, Calif., assignors to Texaco Inc., New York, NE., a corporation of Delaware Filed Apr. 30, 1963, Ser. No. 277,669 Claims. (Cl. l66-7) This application is a continuation-in-part application of our copending, commonly assigned application Serial No. 747,918, filed July 1l, 1958, now abandoned.

This invention relates to the production of hydrocarbons from subsurface formations. More particularly, this invention relates to a method for improving and/or increasing the recovery of hydrocarbons from subsurface hydrocarbon-containing formations. In accordance with one embodiment this invention is directed to the recovery of viscous hydrocarbons from subsurface formations. ln accordance with yet another embodiment this invention is directed to the recovery of petroleum from gas-depleted, petroleum-containing formations.

In the production of petroleum from subsurface formations it sometimes happens that the natural gas within the petroleum-containing formation becomes depleted and/ or is insuicent in amount to produce a satisfactory amount of petroleum. In certain other petroleum-containing formations the petroleum therein is sometimes so viscous that the production of petroleum therefrom by the available primary methods, natural gas drive, Water drive, etc. is not satisfactory with the result that a substantial amount of petroleum is left behind in the formation. Various techniques have been proposed to increase the recovery of petroleum from petroleum-containing formations. The proposed techniques for primary recovery and secondary recovery include solvent flooding such as injection of LPG followed by the injection of natural gas, water flooding, gas repressuring and the like. Gas repressuring as a secondary recovery operation is relatively widely practiced. However, in certain locations there is an insufficient amount of gas available to carry out a satisfactory gas repressuring or injection operation for the production of petroleum.

Accordingly, it is an object of this invention to provide a method to enhance or improve the primary and/or secondary recovery of petroleum from subsurface formations.

Another object of this invention is to provide a method wherein crude petroleum or a portion thereof is converted l to produce a gas and/or fluid fraction suitable for injection into a petroleum-producing formation to enhance the recovery of petroleum therefrom.

A further object of this invention is to provide an improved recovery operation for the production of petroleum from subsurface formations.

A still further object is to provide a method of treating crude petroleum or a petroleum fraction thereof to produce product streams useful in the recovery of petroleum from petroleum subsurface formations.

ln accordance with one embodiment of the present invention, a method of converting petroleum or a fraction thereof into product streams useful in the recovery of crude petroleum from an underground petroleum containing formation comprises subjecting an admixture of petroleum and hydrogen to hydroconversion at an elevated temperature and pressure to form a hydroconversion eiiluent, comprising normally gaseous and normally liquid hydrocarbons, separating from said eflluent a first product stream for injection comprising the normally gaseous hydrocarbons, subjecting a portion of the normally liquid hydrocarbons to partial combustion under conditions to form a 3,228,467 Patented Jan. 1l., i966 hydrogen-carbon monoxide combustion effluent, shift converting the resulting combustion eluent to form a shift conversion eflluent comprising hydrogen and carbon dioxide, and separating carbon dioxide therefrom as a second product stream for injection.

ln the practice of this invention, hydroconversion of the crude petroleum or portion thereof is preferably carried out by the process of our commonly assigned U.S. Patent No. 2,989,461 issued June 20, 1961, the disclosure of said patent being incorporated in and made part of this disclosure.

In accordance with this process, the hydroconversion operation is carried out by contacting a liquid petroleum hydrocarbon in the liquid, gaseous or combined liquid-gas phase with a hydrogen-containing gas under conditions of turbulent flow and at an elevated temperature and pressure to convert the petroleum charge into lighter hydrocarbon products. In such an operation, the turbulence level should be at least 25, preferably between about L50 and 150. Use of these turbulence levels suppresses formation of undesirable polymers and coke and permits smooth, effective hydrogenation of the active centers formed in the cracking operation. In addition, relatively high rates of conversion of the charge oil to lower boiling products are obtained in the relatively short processing times of about 5 to 200 seconds residence time in the hydroconversion unit. The hydroconversion step is carried out at temperatures between about 800 to 1500o F. preferably 900 and l100 F., and at pressures of 500 p.s.i.g. or more, preferably in the range of 1000 to 10,000 p.s.i.g. The hydrogen-containing gas should contain about 25% by volume of hydrogen, desirably to 90% for most satisfactory results. The hydrogen gas feed rate is in the order of 1000 cubic feet of gas, desirably 2000 to 100,000 cubic feet, per barrel of petroleum feed for the most consistent results.

During the hydroconversion operation the hydrocarbons undergoing treatment are split and carbon-carbon bonds ruptured. The hydrogen reacts with the ruptured carboncarbon bonds as well as adding to any unsaturated hydrocarbon molecules present. The gaseous hydrogen serves also to refine the petroleum fraction undergoing treatment by the removal of sulfur, nitrogen and oxygen.

However, any hydrocracking or destructive hydrogenation operation can be used in the practice of this invention for the hydroconversion step provided the hydrocarbons being treated are broken down into lower molecular Weight materials more susceptible to hydrogenation.

In the practice of this invention, the hydrogen containing gas used in the hydroconversion step is produced by the partial combustion of hydrocarbons to yield a gaseous combustion elliuent containing a substantial amount of hydrogen. Particulars of a suitable combustion process are described in greater detail in commonly assigned U.S. Patent 2,582,934.

For purposes of more fully describing the method of the present invention and to provide for a better understanding thereof, reference is made to the accompanying drawings in which:

FIG. l is a diagrammatic illustration of one embodiment of the method of this invention; FIG. 2 is a diagrammatic View of a further and preferred embodiment of this invention. Various ancillary pieces of equipment, such as pumps, valves, and the like, which are readily apparent to those skilled in the art, have been omitted from the drawings for the sake of clarity.

Referring now to the drawings in detail and to FIG. 1 in particular, a preheated mixture of hydrogen and crude oil, obtained from a petroleum containing formation as hereinafter more fully described, is supplied through line 10 to hydroconversion unit 11 wherein the mixture is subjected to hydroconversion type reactions and hydrogenation of the ruptured hydrocarbon fragments with resulting formation of normally gaseous and normally liquid hydrocarbons having an average molecular weight less than that of the petroleum component of the charge mixture.

The eiuent from hydroconversion unit 11 is passed through line 12 to high pressure separator 13 wherein unreacted hydrogen together with minor amounts of C1 and C2 hydrocarbons is recovered and returned by way of line 14 to line 10 to serve as one source of hydrogen for hydroconversion unit 11.

The remaining hydroconversion effluent is withdrawn from high pressure separator 13 and passed through line 15 to low pressure separator-fractionator 16. From low pressure separator 16 there is recovered a normally gaseous hydrocarbon fraction comprising mainly gaseous C1-C4 hydrocarbons which is withdrawn by line 17, and a C5-jhydrocarbon fraction which is withdrawn by way of line 18.

A portion of the C5-jfraction in line 18 is passed through line 20 to partial oxidation unit 23 and therein reacted at an elevated temperature and pressure with water or water vapor and air or an oxygen containing gas which are fed by way of line 22 to the partial oxidation unit 23. The effluent from the partial oxidation unit comprising hydrogen, carbon monoxide and some water vapor, is withdrawn by way of line 24 and passed therethrough to carbon monoxide shift converter 25, together with additional water in the form of steam which is obtained by way of line 27.

In shift converter 25 the admixture of hydrogen, carbon monoxide and Water vapor is converted by the watergas shift reaction to a mixture of a hydrogen rich gas and carbon dioxide. The mixture is withdrawn from converter 25 by way of line 26 and passed therethrough to carbon dioxide removal unit 28,

In carbon dioxide removal unit 28, the hydrogen-carbon dioxide mixture is separated in a known manner into its components, a hydrogen rich gas stream and a carbon dioxide stream. Carbon dioxide is separated from the mixture using a stripping agent such as monoethanolamine fed to removal unit 28 by lines 33 and 34. Separated carbon dioxide is withdrawn therefrom by way of line 30. The withdrawn carbon dioxide is passed by way of line 32 to a mixing zone, not shown, wherein the carbon dioxide becomes a component of an injection mixture being prepared in said zone to recover petroleum hydrocarbons from an underground formation.

The hydrogen component of the feed to carbon dioxide removal unit 28, after separation and withdrawal of the carbon dioxide component, is withdrawn by way of line 29 and passed therethrough the feed line 1t] of the hydroconversion unit 11. The hydrogen in line 29, together with the recycle hydrogen in line 14 supplys substantially all of the hydrogen required by hydroconversion unit 11, once the process is in operation.

Reverting back to carbon dioxide removal unit 28, a particularly desirable method of accomplishing separation of the carbon dioxide component from the hydrogen rich component of the mixture in removal unit28 is to employ a portion of the C5-lhydrocarbon fraction obtained as a product of hydroconversion. The C-lhydrocarbon fraction in line 18 is passed by way of line 21 and line 34; to the carbon dioxide removal unit 28 and contacts the adm ixture of hydrogen and carbon dioxide therein with the resultant dissolving of carbon dioxide in the C5-lhydrocarbon fraction. The carbon dioxide rich C5-jhydrocarbon fraction can then be withdrawn by way of line 30 and separately recovered by way of line 32. This particular method is advantageous when it is desired to form an injection admix-ture having as a component thereof a C5| hydrocarbon fraction component containing dissolved therein carbon dioxide gas.

If it is desired to add air or an oxygen containing gas stream to the injection mixture this can be readily accomplished in a known manner. For example, one method comprises introducing the air or oxygen into the carbon dioxide stream in line 32 by way of line 41.

An alternate method of carrying out the process of the invention is to obtain part of the charge oil for hydroconversion unit 11 from an underground petroleum formation which is fed thereto by way of line 10.

In this embodiment, the produced petroleum in line 45 is passed by line 47 to crude fractionator 50 for separation and recovery of a crude naphtha fraction. The separated naphtha is passed by way of line 51 to feed line 10 and can advantageously be used as the sole feed to hydroconversion unit 11. Moreover, one can pass a part of the crude petroleum in line 45 through line 46 to partial oxidation unit 23 as supplemental feed thereto.

The remaining portion of the crude from fractionator 50 can be withdrawn by way of line 52 for further processing by means not shown, or can be used as an alternate source of feed to partial oxidation unit 23, through lines 53 and 46.

In accordance with a further embodiment of the present invention, illustrated in FIG. 2 of the drawings, the primary and/ or secondary recovery of hydrocarbons from a producing formation is achieved by converting the petroleum hydrocarbons recovered from an underground petroleum bearing formation into an injection composition for introduction into the formation to stimulate production of further quantities of petroleum therefrom.

In this embodiment, the charge oil in admixture with a relatively large quantity of hydrogen is subjected to a rst hydroconversion step under conditions of relatively high turbulent flow to effect cracking and hydrogenation of the resulting formed lower molecular weight hydrocarbons and vaporization of part of the petroleum feedstock in the manner more particularly described in cornmonly assigned U.S. 2,989,461. The vaporized and unvaporized portions of the feed with hydrogen are introduced into a contacting tower to effect separation of the vaporized components and unconsumed hydrogen from the liquid portion of the feed in the manner more particularly described in commonly assigned, copending applications Serial No. 33,582, filed June 2, 1960 and Serial No. 130,217, filed July 25, 1961, now U.S. 3,089,843 and U.S. 3,148,135, respectively, the disclosures of said applications being incorporated herein and made part of this disclosure.

The liquid portion of the feed is countercurrently contacted in the contacting tower with additional quantities of hydrogen to effect further vaporization of the hydrocarbons which is combined with the previously separated vapors and hydrogen. y

If the feed to contacting tower contains sulfur, nitrogen and unsaturated or gum forming constituents the vaporized petroleum components and hydrogen from the lcontact zone are then introduced into a catalytic hydrogenation zone to effect hydrogenation and saturation of unsaturated components of the feed and resultant formation of hydrogen sulfide and ammonia with the sulfur and nitrogen components.

If the feed is substantially free from sulfur, nitrogen and unsaturated or gum forming constituents or if the presence of these materials is unobjectionable in the final product, then the hydrocatalytic reactor can be eliminated and 4the eiuent from the contacting tower can -be passed directly into a second hydroconversion zone. When the catalyst chamber is used `the catalyst chamber euent is then subjected to a second hydroconversion operation to produce additional quantities of lighter hydrocarbons, particularly the normal gaseous and light normally liquid hydrocarbons which are subsequently recovered from the resultant product.

Hydrogen for the operation is obtained by partial -oxidation of a portion of the crude petroleum or fraction thereof, and/0r with a portion of nal product from the second hydroconversion operation and optionally with a portion of the unconverted liquid portion of the feed to the contacting tower. The partial oxidation operation product is converted to a hydrogen containing gas for use in the process and carbon monoxide. The other component of the partial oxidation process, carbon monoxide, is converted into carbon dioxide which is advantageously used as component of the injection fluid adrnixture being introduced into `the underground formation to recover petroleum therefrom.

FIG. 2 of the drawings schematically illustrates this embodiment of the practice of this invention wherein a charge oil in line 95, such as crude oil or a fraction thereof which may be obtained from a producing formation, as hereinafter more particularly described, is intimately mixed with an excess of hydrogen obtained from line 144 or from an external source not shown to start up the process and fed into a rst non-catalytic hydroconversion unit 100, maintained at a temperature within the range of about 800 to 1100 F. and at a pressure of between about 1,000 and 10,000 p.s.i.g. The rate of hydrogen fed into hydroconversion unit 100 is between about 1,000 and 100,000 cubic feet per barrel of charge oil, preferably 5,000 cubic feet or more, and the hydrogen has a purity of at least about 70 volume percent.

In hydroconversion unit 100 the oil-gas admixture is reacted under conditions of turbulent flow, employing a turbulence level in the range of about 100 to 150 to effect rupture or cracking of the charge oil hydrocarbon molecules and substantially simultaneous hydrogenation of the formed molecular fragments without substantial formation of heavy tars and cokes. The resulting formed lower molecular weight hydrocarbons are at least partially Vaporized in the hydroconversion operation and there issues via line 101 a hydroconversion eflluent comprising vaporous, liquid, and partially vaporized and partially liquid hydrocarbons.

The hydroconversion eluent is passed through line 101 into contacting tower 110 maintained at a temperature between 1,000 to 1,600 F. and at a pressure between about 1400 to 2000 p.s.i.g. wherein the vaporous hydroconversion product is separated from the liquid phase and withdrawn from the tower 110 by way of line 111. The liquid lphase is countercurrently contacted with a hot hydrogen gas stream (about 850 to 1,000 F.) at a rate of between 5,000 and 50,000, preferably between 5,000 and 20,000 s.c.f./bbl. of feed, `to effec-t additional hydroconversion of liquid hydrocarbons and removal of occluded vaporous hydrocarbons. In addition, in tower 110 any heavy materials such as tars and asphalt-like materials present in the feed are separated along with residual liquid hydrocarbons from the descending liquid and are removed by way of line 112. Unreacted hydrogen and converted gaseous hydrocarbons are Withdrawn by out of line 111 and introduced with the previously withdrawn vaporous hydrocarbons product into hydrogenation catalyst reactor 120.

In catalyst reactor 120 the vaporous hydrocarbon product-hydrogen admixture is catalytically hydrogenated at a temperature between 60G-950 F., a pressure of between 500 and 2,000 p.s.i.g., and a space velocity of 0.5 to 5 volumes of normally liquid feed per volume of catalyst per hour to convert any sulfur and nitrogen present to hydrogen suliide and ammonia respectively, and to hydrogenate any unsaturated and gum forming constituents to stable compounds.

Hydrogenation catalysts that can be used include the oxides and/or suliides of Group VI or Group VIII metals and mixtures thereof such as, for example, molybdenum oxide, molybednum sulde, nickel suh'ide, nickel oxide, nickel molybdenum sulfide, nickel molybdenum oxide, cobalt molybdenum oxide, cobalt nickel molybdenum sulde, cobalt nickel molybdenum oxide, and mixtures thereof alone or on a suitable catalyst support.

The eiiluent from reactor is withdrawn by way of line 121 and passed to a second non-catalytic hydroconversion unit wherein the feed is again subjected to turbulent ow conditions substantially the same as those ernploye-d in the first non-catalytic hydroconversion unit 100. As a resul-t of the second hydroconversion operation, the feed is further converted to additional light hydrocarbons which are substantially immediately hydrogenated.

The effluent from the second hydroconversion unit is withdrawn through line 131 and passed to high pressure separator maintained at substantially the same pressure as hydroconversion unit 130 to etfect separation of a hydrogen rich gas therefrom. The separated hydrogen rich gas is recycled through lines 141, 144, 143 and 121, to the second hydroconversion unit 130, and a portion thereof can also be recycled through lines 141, 144 and 95 to the first hydroconversion uni-t.

The remaining lportion of the hydroconversion product is withdrawn from separator 140 by way of line 1-42 and fed to a combined low pressure separator-fractionator 150, maintained at a pressure of about 200-500 p.s.i.g., preferably 450 p.s.i.g.

There is recovered from separator a gaseous hydrocarbon fraction comprising (I1-C4 hydrocarbons by way of line 151, a C5 to 400 F. naphtha fraction by way of line 152, and a middle distillate fraction by way of line 153.

The gaseous C1-C4 hydrocarbon fraction in line 151 can be used as one component of an injection mixture, being fed by line 1510 to line 156 and passed therethrough into the injection well. All of or part of the naphtha fraction in line 152 can be fed by line 152a to line 156 and through line 156 into the injection well. The middle dstillate fraction in line 153 can be withdrawn from the system for storage by means not shown. A portion of said fraction can be fed through lines 153, 154, 113, 114 and 157 to partial oxidation unit 160. However, it is particularly desirable to return at least a portion of the middle distillate fraction by way of lin'e 155 to the second hydroconversion unit 130 to permit formation of additional light gaseous hydrocarbon components in the unit 130. A portion of the middle distillate can be used as a component of the injection composition in line 156 by way of line 153e.

Referring back to contacting tower 110 the unconverted liquid hydrocarbons in contacting tower 110, together with any metallic constituents, tars and asphalt like materials present in the feed to tower 111) are withdrawn by Way of line 112 admixed with the middle distillate in line 154 and passed by way of lines 113, 114, and line 157 to the partial oxidation unit 160.

The charge oil to oxidation unit 169 introduced therein by line 157 can be augmented by all or a porti-on of the crude oil obtained in a manner hereinafter described. Thr-e is also fed to partial oxidation unit 160 air, or an oxygen rich gas stream by way of line 153 and water or steam by way of line 159. In the partial oxidation unit the charge oil, air and steam are subjected to the water gas shift reaction .to form a gaseous eiiiuent comprising hydrogen, carbon monoxide and water vapor. The gaseous effluent is withdrawn by way of line 161 and introduced into carbon monoxide shift converter 170, together with an additional quantity of steam lobtained by Way of line 162. In converter the respective components are converted to form a gaseous mixture of hydrogen and carbon dioxide which is Withdrawn as the effluent from converter 170 by way of line 171 and introduced into carbon dioxide absorber 180. In carbon dioxide absorber a conventional stripping material such as methylethanolamine fed thereto by way of line 192, etects separation of the carbon-dioxide component from the mixture. The resulting separated carbon-dioxide component together with the stripping material is withdrawn by way of line 182.

The remaining portion of the mixture, the hydrogen component, is withdrawn by way of line 131, is used as a source of make-up hydrogen for the system. The hydrogen in line 181 can be passed by Way of lines 184 and 186 to the charge oil feed line 95 for the rst hydroc-cnversion unit 100. In addition, the hydrogen in line 181 can be introduced into contacting tower feed line 101 by Way of lines 184 and 185. Make-up hydrogen can also be supplied to the second hydroconvension unit by way of lines 181, 18-3, and 121.

The eluent from the carbon dioxide absorber 180 comprising carbon dioxide and stripping agent is passed to carbon dioxide stripper 190 by Way of 182. Carbon dioxide is separated from the stripping agent therein in a known manner and the recovered carbon dioxide is withdrawn by way of line 191 for admixture with the gaseous hydrocarbon components in line 156 being fed to the injection well.

Crude oil obtained from a production well relatively adjacent to the injection well by way of line 194 can be passed to separator-fractionator 193 to permit recovery therein of the lighter normally gaseous C1-C4 hydrocarbons and any carbon dioxide dissolved inthe produced oil. The recovered C1-C4 hydrocarbons and carbon dioxide can be returned by way of line 195 and line 156 as makeup for the injection uid composition being introduced into the injection well. Optionally, a portion of the C5 and heavier hydrocarbons contained in the petroleum toil can be recovered in separator-fractionator 193 and withdrawn therefrom by means not shown.

A further modification shown in FIG. 2 is wherein the crude oil in line 194 is passed by way of lines 196, 197, and 199 to line 95 to b'e mixed therein with charge oil introduced into line 95 from a source not shown. The crude oil can be the primary source of charge oil in line 95. A further modification is wherein a portion of the crude oil in line 199 is passed by way of lines 199a, 114, and 157, as a component of the feed oil to partial oxidation unit 160.

As pointed out hereinabove, any one, two or three of the product fractions obtained from low pressure :separator-fractionator 150 or combinations thereof, can be used to furnish part of the injection fluid mixture in line 156 which is then mixed therein with the carbon dioxide from line 191 to form the injection fluid composition being introduced into the underground formation to recover petroleum therefrom.

When crude oil separator-fractionator 193 is used in the practice of this invention, the recycled C1-C4 hydrocarbons, the carbon dioxide dissolved in the crude oil recovered from the separator-fractionator 193 by way of line 195, can be also introduced into the injection fluid composition.

In this modification of the invention, as shown in FIG. 2 of the drawings, the injection fluid composition comprises the carbon dioxide obtained from carbon dioxide stripper 190, together with at least one of the product fractions recovered in low pressure separator-fractionator 150. As shown hereinabove, the injection fluid composition may additionally comprise one or more of the gaseous C1C4 fraction, naphtha fraction, and the middle distillate fraction from the low pressure separator. An additional component can be the C1-C4 hydrocarbons andthe carbon dioxide recovered from the produced crude oil in the separator-fractionator 193.

The following example is described with reference to FIGURE 1 of the drawings.

A Persian Gulf Crude is fractionated in crude fractionator 50 at a pressure of about 10 to 20 p.s.i.g to recover overhead a naphtha fraction at the rate of 8 barrels per hour (B.P.H.). This overhead naphtha fraction is passed in lines 51 and 10 to hydroconversion unit 11 operated at a pressure of about 2000 p.s.i.g., a temperature of about lO00 F. and a turbulence level of about 90. In hydroconversion unit 11 the naphtha is subjected to hydroconversion type reactions and the resulting formed hydroconversion etiiuent is passed by way of line 12 to high pressure separator 13 maintained at a pressure of about 2000 p.s.i.g. Approximately 1200 standard cubic feet of hydrogen is consumed per barrel of feed in hydroconversion unit 11.

There is recovered from separator 13 a recycle gas stream compri-sing predominantly hydrogen in an'amount of about 25,000 standard cubic feet per hour (s.c.f.h.) of gas predominantly hydrogen which is recycled to hydroconversion unit 11 through line 14.

The remaining portion of the hydroconversion etiiuen is passed to low pressure separator 16. From separator 16 there is recovered a normally gaseous C1-C4 hydrocarbon fraction by way of line 17 in an amount of 20,300 s.c.f.h., which is suitable for injection into the underground formation. There is also recovered from separator 16 a liquid C5}- hydrocarbon fraction by way of line 18. Part of the recovered C54- fraction in line 18 is fed through line 20 to partial oxidation unit 23 for con- Version intro hydrogen required by the process. The remaining portion of the recovered C54- hydrocarbon fraction in line 18 is Withdrawn and can b-e used as a component of the injection mixture or returned to hydroconversion unit 11 to produce additional light gaseous hydrocarbons for injection.

The C1-C4 hydrocarbon fraction in line 17 has the following composition expressed as percent by volume, 96.9% (l-C4 hydrocarbons, 0.5% H2, 2.2% CO, 0.1% CO2 and 0.3% N2. The C5-ihydrocarbon fraction in 4line 18 is recovered in an amount of about 1.6 barrels per hour.

The liquid C5-ifraction withdrawn from line 18 through line 20 is introduced into partial oxidation unit 23 at the rate of 0.8 bbls./hr. together with 3120 s.c.f.h. oxygen and pounds per hour of water. The partial oxidation unit is maintained at an elevated temperature of about 2550 F. and at a pressure of 400 p.s.i.g. The resulting gaseous combustion effluent is then passed to shift converte-r 25 along with additional steam introduced through line 27. In the converter 25 the steam reacts with CO to yield a mixture of H2-l-CO2. There is recovered a gaseous etiiucnt in an amount of 12,800 s.c.f.h. comprising 62.1% H2, 2.5% CO, 34.2% CO2, 0.8% CH4 and 0.4% N2, on a dry volume basis. This gaseous admixture from the shift converter is passed to CO2 removal unit 28 wherein 6228 s.c.f.h. of carb-on dioxide are removed and withdrawn by way of line 30 and line 32 for introduction into the injection mixture. There is also withdrawn through line 29 12,000 s.c.f.h. of make-up hydrogen having a purity of about 94.2% which is used as a source of hydrogen for hydroconversion unit 11.

By employing the practice of this invention an injection gas or Huid of substantially any suitable composition can be obtained from norm-ally liquid hydrocarbons recovered from the petroleum-producing formation undergoing treatment.

In the foregoing disclosure considerable emphasis with respect to the practice of this invention has been pla-ced on the recovery of hydrocarbons, such as petroleum from underground petroleum-containing formation. However, as already indicated, the practice of this invention is readily applicable to the recovery of normally liquid hydrocarbons from hydrocarbon-containing formations such as tar sands and shales and oil shales as well as from particularly difficult underground formations containing heavy vis-cous crude oils such as the San Ardo and Santa Maria crudes of California and Arabian crudes.

The recovery of such heavy crude oils from underground formations can be readily accomplished by carrying out the practice of the present invention particularly the embodiment shown in FIG. 2 of the drawings.

Various other modifications will be obvious to those skilled in the art without departing from the spirit and scope of the invention and therefore only such limitations should be imposed as are indicated in the appended claims.

lVe claim:

It. Method of converting petroleum into product streams which comprises subjecting an admixture of petroleum and hydrogen to hydroconversion at an elevated temperature and pressure to form a hydroconversion eluent comprising normally gaseous and no-rmally liquid hydrocarbons, separating the normally gaseous hydrocarbons from said efuent as a rst product stream, subjecting a portion of the normally liquid hydrocarbons in the hydroconversion eiuent to partial combustion under conditions to form a hydrogen-carbon monoxide combustion eluent, shift converting the resulting partial combustion etliuent to form a shift conversion eluent comprising hydrogen and carbon dioxide, and separating a gas stream consisting essentially of carbon dioxide therefrom as a second product stream and combining said separated streams to form a combined stream.

2. Method as claimed in claim 1 wherein hydroconversion is carried out at a temperature between 900 and l200 F., a pressure between 1000 and 5000 psig., a hydrogen feed rate of at least 4000 standard cubic feet er barrel of feed, and at a turbulence level of at least 50.

3. Method as claimed in claim 1 wherein a portion of the normally liquid hydrocarbons of said hydroconversion effluent is lrecovered as a third product stream and combined with said rst product stream and said second product stream.

Li. In the recovery of petroleum from an underground formation wherein an injection stream obtained from said recovered petroleum is introduced into said formation and petroleum is recovered from said formation, the improvement which comprises hydroconverting at least a portion of the recovered petroleum with hydrogen at an elevated temperature and pressure to form a hydroconversion eliiuent comprising normally gaseous and normally liquid hydrocarbons, separating normally gaseous hydrocarbons from said efuent as a first product stream, subjecting a portion of the normally liquid hydrocarbons in the hydroconversion effluent to partial combustion in admixture with an oxygen-containing gas to form a partial combustion eiiuent comprising hydrogen and carbon monoxide, shift converting the partial combustion eiiluent to form a shift conversion etliuent comprising hydrogen and carbon dioxide, separating a gas stream consisting essentially of carbon dioxide therefrom as a second product stream, employing the hydrogen from said shift conversion elluent in the hydroconversion reaction, combining said separated normally gaseous hydrocarbon product stream and said separated carbon dioxide product stream and introducing the resulting mixture into said formation.

5. Method as claimed in claim 4 wherein a portion of the normally liquid hydrocarbons of said hydroconversion etliuent is recovered and combined with said first product stream and said second product stream and the resultant combined stream is introduced int-o said formation.

References Cited by the Examiner UNITED STATES PATENTS 2,361,012 10/1944 Cole et al` 166-7 2,623,596 12/1952 Whorton et al 166-7 2,703,308 3/1955 Oblad et al 208-60 X 2,880,801 4/1959 Crump 166-9 2,989,460 6/1961 Eastman et al 208-107 2,989,461 6/1961 Eastman et al 208-107 3,008,895 1l/l961 Hansford et al 208-69 X 3,103,972 9/1963 Parker 166-9 CHARLES E. OCONNELL, Primary Examiner.

BENJAMIN HERSH, Examiner.

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Classifications
U.S. Classification166/266, 208/58
International ClassificationE21B43/34, E21B43/40, E21B43/16
Cooperative ClassificationE21B43/164, E21B43/40
European ClassificationE21B43/16E, E21B43/40