|Publication number||US3666659 A|
|Publication date||May 30, 1972|
|Filing date||Mar 24, 1970|
|Priority date||Mar 24, 1970|
|Publication number||US 3666659 A, US 3666659A, US-A-3666659, US3666659 A, US3666659A|
|Inventors||Carlson Edgar, Lehrian William R|
|Original Assignee||Gulf Research Development Co|
|Export Citation||BiBTeX, EndNote, RefMan|
|Patent Citations (5), Referenced by (11), Classifications (15), Legal Events (1)|
|External Links: USPTO, USPTO Assignment, Espacenet|
United States Patent Carlson et al.
 METHOD FOR STABILIZING HYDRODESULFURIZED OIL  Inventors: Edgar Carlson, Allison Park, Pa.; William R. Lehrian, Tokyo, Japan  Assignee: Gulf Research & Development Company,
 Filed: Mar. 24, 1970  Appl.No.: 22,200
[ 51 May 30, 1972 3,383,300 5/1968 Kimberlin,.lr ..308/2ll FOREIGN PATENTS OR APPLICATIONS 895,058 4/1962 Great Britain ..208/21 1 Primary Examiner-Delbert E. Gantz Assistant ExaminerG. .l. Crasanakis Attorney-Meyer Neishloss, Deane E. Keith and Thomas G. Ryder  ABSTRACT A stabilized, desulfurized hydrocarbon oil is provided by separating the oil feed into light and heavy fractions, desulfurizing the heavy fraction and combining the desulfurized heavy fraction and the untreated light fraction after removing hydrogen sulfide from the heavy fraction. A hydrogen sulfidedepleted recycle stream provides for absorption of light hydrocarbons into the desulfurized heavy fraction. The stabilized, desulfurized hydrocarbon oil has a light ends content approximating that of the original oil feed.
9 Claims, 1 Drawing Figure Patented May 30, 1972 3,666,659
004 mama/v W/LL/AM 1a. LEM /AA/ invention relates to the production of a desulfurized synthetic crude oil having the approximate light ends content of the original whole crude.
Hydrocarbon fractions which contain sulfur have been conventionally subjected to a catalytic desulfurization treatment in the presence of hydrogen. Hydrogen sulfide and certain hydrocarbons are formed in the desulfurization process in excess of that contained in the original feed. It is highly desirable to separate the hydrogen sulfide from the hydrodesulfun'zed product in order to prevent equipment corrosion and contamination of the hydrocarbon product.
In order to recover a hydrocarbon product substantially free of hydrogen sulfide, it has been previously suggested to effect a separation of the total hydrodesulfurization reaction effluent into a liquid product fraction and vapor. Such separation can be effected through the techniques of condensation, flashing, stripping, etc. Generally, however, the vapor obtained from prior art processes not only contained hydrogen sulfide but also was comprised of methane, ethane, propane, butanes, naphtha and other lower boiling hydrocarbon compounds. This resulted in a hydrodesulfurized product deficient in light ends and particularly, when treating a full crude, a product deficient in the light ends originally contained in the charge stock.
It has now been found that a stabilized, hydrodesulfurization synthetic oil having the approximate light ends content of the original oil may be produced by the process of the present invention which comprises separating a hydrocarbon oil charge stock into a light fraction and a heavy fraction, subjecting the heavy fraction to a desulfurization treatment, separating a gaseous hydrogen sulfide-containing stream from the desulfurized heavy fraction, and combining the resultant heavy fraction and the light fraction to form a stabilized, desulfurized product.
Thus, the petroleum hydrocarbon charge stock, such as a crude oil may be separated into a light fraction and a heavy fraction and the heavy fraction is subjected to a desulfurization treatment such as hydrodesulfurization. The desulfurized heavy fraction is then passed to the upper portion of a contacting zone while the untreated light fraction is passed to a lower portion of the same contacting zone. A gaseous stream comprising hydrogen sulfide, hydrogen and light hydrocarbons is withdrawn from an upper portion of the contacting zone and this stream is recycled to an intermediate portion of the contacting zone after the hydrogen sulfide has been substantially removed. A stabilized hydrocarbon product fraction, such as a stabilized synthetic crude oil, is discharged from a lower portion of a contacting zone.
A portion of the stabilized product fraction may be recycled to an intermediate portion of the contacting zone after being cooled, so as to provide temperature control in the contacting zone and therefore vapor pressure control of the product. As previously mentioned, the recycled stream which is withdrawn from an upper portion of the contacting contains hydrogen and significant amounts of light hydrocarbon in addition to the hydrogen sulfide. By recycling this stream through the contacting zone after hydrogen sulfide has been substantially removed therefrom, the hydrogen in this stream not only aids in stripping the hydrogen sulfide from the desulfurized heavy fraction, but at the same time light hydrocarbons in the recycled gas are absorbed into the desulfurized heavy fraction. Thereafter, the desulfurized heavy fraction recombines with the light fraction in the lower portion of the contactor to provide a stabilized synthetic desulfurized crude oil having a light ends content approximating that of the original crude oil.
In the foregoing manner a stabilized, desulfurized synthetic oil can be provided, with the hydrodesulfurization being conducted in a more economical manner. A hydrodesulfurization reactor of a substantially small capacity can be employed, since only the heavy fraction is treated.
According to one aspect of the present invention, a crude oil is subjected to flash distillation so as to provide the light fraction and the heavy fraction with the light fraction being passed to the lower portion of the contacting zone. Thus, the light fraction provides a heat source and stripping vapor to the bottom of the contacting zone to aid in the removal of the hydrogen sulfide from the heavy fraction which is introduced in the upper end of the contacting zone.
According to another aspect of the present invention, the synthetic desulfurized product which is discharged from a lower portion of the contacting zone is cooled and a portion thereof is recycled to an intermediate portion of the contacting zone. This provides a quenching zone below the point of introduction within which the flash vapors of the lighter fraction may be condensed.
According to still another aspect of the present invention, high purity hydrogen is introduced into a lower portion of the contacting zone below the point of introduction of recycled product to provide stripping gas in the quenching portion of the contacting zone and to assure removal of any chloride constituents present in the oil.
In order to more fully understand the nature of the present invention, reference is made to the accompanying drawing which is substantially a schematic diagram of a process which embodies the present invention.
Referring to the drawing, I a high boiling petroleum hydrocarbon oil 10, such as a total crude containing sulfur, is passed to a separator, such as the flash drum 12. The term total crude or full crude as employed herein includes naturally occurring petroleum oil which has not been processed in any manner, but has been preferably separated from water or sediment and desalted.
In the flash drum 12 about 25 percent by volume of the crude is flashed, for example, at an operating temperature and pressure of about 600 F. and psia, respectively. The flashed vapor is withdrawn by'means of the line 14, while the flashed crude liquid is withdrawn from the flash drum 12 by means of the line 16. When treating crude oil, it is desired to remove as large a portion of the hydrocarbons boiling below 375 F. by means of the line 14 with a minimum removal of the heavier hydrocarbons boiling above 375 F., since the desulfurization process does not-appreciably. affect the hydrocarbons boiling at 375 F. and below. By removing such lighter hydrocarbons at this point from the heavier hydrocarbons which are discharged by means of the line 16, the desulfurization reactor diameter, recycle gas volume and size of the heat exchange train in the system may be substantially reduced.
The flashed crude is passed to a gas-fired heater after being admixed with make-up and recycled hydrogen which are added by means of the lines 20 and 33, respectively. The hydrogen-flashed crude admixture is heated to a temperature suitable for catalytic desulfurization and may be admixed with additional recycle hydrogen added by means of line 34. The
desulfurization charge stock may be passed to catalyst guard beds (not shown) for the removal of contaminates detrimental to the desulfurization catalyst. The preheated stream is passed by means of the line 22 to the desulfurization reactor 24 which is provided with one or more beds of a conventional desulfurization catalyst. The desulfurization catalyst may be any which has been conventionally employed for this purpose. Suitable desulfurization catalysts include Group lVa and Group VIII metals of the Periodic Table, their oxides or sulfides, alone, or in admixture, and preferably provided on a non-cracking support such as alumina, bauxite and the like. Examples of such catalysts include Ni-Co-Mo on alumina, Como on alumina, and Ni-W-S on alumina.
The hydrodesulfurization reaction is conducted at a temperature in the range of between about 500 and about 900 F., preferably between about 700 and about 850 F. Suitable pressures for the desulfurization include between about 250 and about 4,000 psig, preferably between about 500 and about 3,000 psig while employing a liquid hourly space velocity in the range of between about 0.25 and about 16,
removal unit such preferably between about 0.5 and about 3.0 Hydrogen is passed to the reactor 24 at a rate of between about 200 and 20,000 standard cubic feet per barrel of liquid charge, preferably between about 2,000 and 10,000 standard cubic feet per barrel.
The desulfurized reactor effluent is discharged from the reactor 24 by means of line 26. This stream may be heat exchanged with recycled gas from the reactor, the feed to the hydrodesulfurization reactor and the crude feed (by means not shown). Next, the temperature of the reactor effluent is further reduced in a suitable heat exchange means, such as aerial cooler 28. The cooled efiluent may be passed to a flash drum for the separation of liquid from vapor, if desired. The flash gas containing hydrogen and smaller amounts of low boiling light hydrocarbon may be recycled for admixture with the feed to the hydrodesulfurization reactor by means of the process lines 32, 33 and 34, after being treated for the removal of hydrogen sulfide therefrom by a suitable means (not shown). Suitable means for hydrogen sulfide removal includes amine treating agents, such as ethanolamine. About percent of the net hydrogensulfide may be removed from the hydrogen and light hydrocarbon-containing recycle stream 32.
The liquid product from the flash drum 30 is discharged by means of the line 36 and is passed to a contacting zone, for example to the top tray of a synthetic crude stripper 38. The stripper 38 may be operated at a temperature in the range of between about 70 and about 400 F., preferably between about 120 and about 300 F. Suitable pressures are in the range of between about and about 150 psig, preferably between about 75 and about 1 10 psig.
The stream 36-contains hydrogen sulfide and water in addition to the relatively high boiling hydrocarbons therein. Meanwhile, hot vapor flashed from the whole crude enters the bottom of the stripper 38 by means of line 14. This crude flash vapor is substantially free of hydrogen sulfide and comprises hydrocarbons boiling below 375 F. Vapors comprising hydrogen, methane, ethane, propane, isobutane, normal butane and hydrogen sulfide are withdrawn from the stripper 38 by means of the line 40 and are passed to a hydrogen sulfide as, for example, a low pressure amine contactor 42.
In the amine contactor 42, hydrogen sulfide is removed therefrom by the countercurrent passage of amine from the line 44 with the introduction of water from the line 46 as a final wash. The hydrogen sulfide-containing sour amine is withdrawn from the contactor 42 by means of the line 48 and can be passed to an amine recovery unit. The desulfurized vapor stream comprising hydrogen and low molecular hydrocarbons is withdrawn by means of the lines 50 and 52 and is conducted to a compressor 53 prior to being recycled by means of the conduit 54 to the stripper 38. The-portion of the hydrogen-containing stream withdrawn from the treater 42 by means of lines 50 and 55 is passed to the heater 18 for use as fuel thereto or further purification and use for stripping in the process (by means not shown). Additionally, high purity hydrogen can be introduced by means of the conduit 56 to the bottom of the stripper 38.
In the foregoing manner, the hydrogen sulfide-depleted gas which is introduced by means of line 54 acts as a primary stripping medium for removal of the hydrogen sulfide from the flashed crude introduced into the stripper 38 by means of line 36. Meanwhile, significant amounts of light hydrocarbons such as propane and the like are absorbed from the recycled stripping gas by the incoming flashed crude of line 36 flowing down the tower 38. Thus, for example, the top 24 trays in the tower 38 act as an absorber-stripper zone 57 wherein about as much of the light hydrocarbons, such as propane and heavier hydrocarbons, are absorbed from the recycled gas as are stripped therefrom. At the same time the hydrogen sulfide in the downflowing liquid is-stripped and removed overhead. If the desulfurized overhead stream 40 were not recycled as a stripping gas via line 54, significant amounts of light hydrocarbons 'would be lost in the overhead gas stream. Furthermore, additional processing would be required to recover these components from the overhead stream. Additionally, the process of the present invention produces its own stripping gas, since the hydrodesulfurized crude contains hydrocarbons and hydrogen that have a higher vapor pressure than the hydrogen sulfide contaminates.
A synthetic crude bottoms is discharged from the bottom of tower 38 by means of a line 58 and is passed to a pump 59 and a cooler 60, which may be an air cooled heat exchanger. A portion of the cooled bottoms is recycled to the stripper 38 by means of the line 62 so as to provide the desired quenching temperature in the zone 68 for the incoming flashed whole crude from line 14 and for proper vapor pressure control of the synthetic crude product.
The remaining portion of the bottoms is passed to synthetic crude storage tanks (not shown) as a product of the present process by means of the line 64. By recycling cooled synthetic crude bottoms in this manner, a bottoms temperature is coritrolled in the stripper 38, for example, between about 250 and about 280 F. so as to obtain the desired vapor pressure characteristics of the synthetic crude product. Thus, for example, the bottom six trays of the stripper 38 act as a quench zone 68 for the flashed crude vapors introduced by means of line 14.
In the mode of operation shown in the drawings, the flashed crude which is introduced by means of line 14 to the stripper 38 furnishes a required heat source for the process and additionally produces stripping vapor in the bottom of stripper 38. Stripping vapor is required at this point to strip the small quantity of very light hydrocarbons and hydrogen from the downflowing desulfurized flash crude which have been absorbed from the recycled stripping gas introduced at line 54. This heat source in effect heats the hydrodesulfurized crude to its required bubble point at the stripping pressure for synthetic crude vapor pressure control. Since this heat source is the original light ends from the crude, this provides the same in the bottom of the tower for combination or blending with the downflowing desulfurized crude.
As previously mentioned, if the flashed vapor such as that in the line 14 were to be processed in the hydrodesulfurization reactor, it would not be desulfurized and would substantially increase the investment and operating costs of the desulfuriza tion reactor.
Additional hydrogen can be introduced by means of the line 56 into the stripping tower 38 to assist in stripping essentially all ,of the hydrogen sulfide from the synthetic crude introduced by means of the line 36 and to provide stripping gas in the quench zone 68 depending upon the amount of hydrogen sulfide in the desulfurized crude. Additionally, it is desirable to add hydrogen at this point as a precautionary measure to assure removal of any chloride which may be in the crude oil, since upon flash distillation of the crude in the flash drum 12, any chloride present would be substantially taken overhead with the crude flash vapor in the process line 14.
In the foregoing manner, a desulfurized synthetic crude is produced having a light ends content which approximates the composition of the original crude. Furthermore, the present invention permits a reduction in desulfuriz'ation reactor diameter, recycle gas volume and amount of heat exchange necessary, since the volume of vapor flashed fiom the crude is not passed through the reactor. As a specific example of the advantages obtained by the employment of the present process, the main hydrodesulfurization reactor diameter may be reduced by 2 to 3 feet for the same pressure drop previously employed when the whole crude is treated.
EXAMPLE In a specific example, an arrangement similar to that illustrated in the drawing is employed. A Kuwait crude oil having a light ends composition comprising 0.01 percent by weight methane, 0.06 percent ethane, 0.46 percent propane, 0.26 percent isobutane and 1.08 percent normal butane is desalted and dewatered and is heated in a fired heater and is passed to a flash drum at the rate of 44,000 BPSD (barrels per stream day). The flash drum is operated at a temperature of 600 F. and under a pressure of 115 psia resulting in a separation of the crude into a light fraction comprising 24 percent by volume of the total crude fed.
The flashed crude heavy fraction is pumped to the pressure required for desulfurization and is then mixed with make-up hydrogen and a recycle hydrogen-containing gas stream that had been amine-treated for the removal of hydrogen sulfide. The mixture of liquid feed and vaporous hydrogen is then heated in a fired heater. At the heater outlet, the feed is joined with additional recycle gas that has been preheated by exchange with reactor effluent. The average temperature of this mixture at reactor inlet is about 750 F.
The feed then flows to catalyst guard beds and is passed to the desulfurization reactor which is provided with a solid catalytic material comprising Ni-Co-Mo supported on alumina. Other reaction conditions employed in the reactor are a liquid hourly space velocity of about 1 and a hydrogen partial pressure of about 2,000 psi.
Reactor effluent is withdrawn at a maximum temperature of about 815 F. and is heat exchanged with recycle gas, feed to the hydrodesulfurization reactor, and crude feed. At the outlet of the crude feed heat exchange system, the effluent has a temperature of about 350 F.
The effluent is then cooled to 150 F. in an aerial cooler and the resulting liquid and vapor separated in a flash drum. Flashed vapor is compressed and recycled to the reactor system as a quench medium, untreated recycle to the reactor and amine-treated recycle. The liquid phase desulfurized crude is sent to a low pressure flash drum for removal of water and is then fed to the top tray of a synthetic crude stripper at the rate of about 34,000 BPSD. A stripper off-gas is drawn off the top of the stripper and comprises about 53 mol percent hydrogen, about 11 mol percent hydrogen sulfide with the remainder substantially being C -C hydrocarbons.
The stripper overhead gas is sent to a low-pressure amine contactor for the substantial removal of hydrogen sulfide, and a stream comprising about 57 mol percent hydrogen, virtually no hydrogen sulfide and the'remainder being substantially C -C. hydrocarbons is recycled to the stripper and is introduced at an intermediate point thereof below the stripperabsorber section. The excess hydrogen sulfide-depleted gas stream is either employed as fuel for the heaters or is sent to a hydrogen unit.
Meanwhile, 1,000 mols per hour of untreated hot vapor flashed from the whole crude is introduced in the bottom of the stripper and is condensed in the bottom section. The condensation of the flashed hot vapor is achieved, in part, by recycling bottoms from the stripper which has been cooled to a temperature of 150 F. in an aerial cooler and reintroduced at an intermediate portion of the stripper just above the quench section. This recycling of a portion of the cooled bottoms product from the stripper controls the stripper bottoms temperature in the range of 250 to 280 F. The stripper bottoms not recycled is further cooled to '1 F. by heat exchange with, for example, sea water, and is then sent to storage as the synthetic crude product.
A high purity hydrogen gas stream comprising about 93.5 mol percent hydrogen and small quantities of hydrocarbons is introduced at the rate of about 1 l0 mols per hour into the bottom of the stripper to provide stripping gas in the quench zone, to assist as a secondary stripping gas in the stripping of the hydrogen sulfide from the desulfurized heavy fraction, and to assure the removal of any chloride in the crude flash vapor.
The synthetic crude product has a light ends composition comprising a trace of methane, 0.04 percent by weight ethane,
0.52 percent propane, 0.29 percent isobutane and 1.22 percent normal butane. As may be seen upon comparison with the light ends composition of the original Kuwait crude oil, the
synthetic crude oil has about the same light ends composition. The foregoing description of spec c method is not intended to be limiting in scope except where indicated. For example, in regard to the stripping tower 38 various types of packing material may be employed in the zone 57 and 68. Thus, raschig rings, beryl saddles, bubble plates with risers, and similar conventional packing materials may be suitably employed. Likewise, while the stripper-absorber section 57 and quench section 68 are illustrated in the same tower 38, they may be provided, respectively, in separate, sequential towers, if desired. In the same manner, the desulfurization reactor 24 may alternatively be a series of separate reaction zones each comprising a bed of catalytic material. Obviously, the drawing has been greatly simplified so that various pumps, compressors, heat exchange means and the like have not been shown for the sake of simplicity. Thus, where single coolers 28 and 60, flash tanks 12 and 30 are shown, a plurality of such devices may be employed.
Obviously, many modifications and variations of the inven tion as hereinabove set forth may be made without departing from the spirit and scope thereof and, therefore, only such limitations should be imposed as are indicated in the appended claims.
I. A process for the production of a stabilized, desulfurized hydrocarbon oil, which comprises separating a petroleum hydrocarbon charge stock into a light fraction boiling below about 375 F. and a heavy fraction boiling above about 375 F., subjecting said heavy fraction to a desulfurization treatment, passing the desulfurized heavy fraction to an upper portion of an absorber-stripper vessel, withdrawing a gaseous stream comprising hydrogen sulfide, light hydrocarbons and hydrogen from an upper portion of said vessel, separating at least a portion of said hydrogen sulfide from said gaseous stream, recycling said hydrogen sulfide-depleted gaseous stream to an intermediate portion of said vessel whereby said light hydrocarbons are absorbed by said desulfurized heavy fraction from the hydrogen sulfide-depleted gaseous stream, combining said light fraction with said desulfurized heavy fraction at a lower portion of said vessel, and withdrawing said stabilized, desulfurized hydrocarbon oil from the bottom portion of said vessel.
2., The process of claim 1 wherein the hydrocarbon oil charge stock is a crude oil.
3. The process of claim 1 which further includes introducing said light fraction into a lower portion of said vessel whereby stripping vapor is formed and said stripping vapor strips hydrogen and a small quantity of very light hydrocarbons from the desulfurized heavy fraction.
4. The process of claim 3 wherein said charge stock is subjected to a flash distillation to form said light and heavy fractions.
5. The process of claim 5 wherein at least a part of the combined light fraction and desulfurized heavy fraction withdrawn from a lower portion of said contacting zone is cooled and recycled to said vessel at an intermediate portion thereof.
6. The process of claim 5 wherein said charge stock is a crude oil and the flash distillation is conducted under conditions to form a light fraction boiling below about 375 F.
7. The process of claim 1 wherein said vessel is operated under a temperature of between about 70 and about 400 F. and a pressure of between about 50 and about psig.
8. The process of claim 3 wherein hydrogen is introduced into a lower portion of said vessel.
9. The process of claim 1 wherein said desulfurization treatment is conducted in the presence of hydrogen.
PC1-1050 UNITED STATES PATENT OFFICE CERTIFICATE OF CORRECTION Patent No. 3,666,659 Dated May 30, 1972 Inventor) Edgar Carlson and William R. Lehrian It is certified that error appears in the above-identified patent and that said Letters Patent are hereby corrected as shown below:
Column 5, line .32, delete "to the reactor" Claim 5, line 1, "The process of claim 5" should be -The process of Claim 4-- Signed and sealed this lhth day of November 1972.
EDWARD M.FLETCHER,JR. ROBERT GOT'I'SCHALK Attesting Officer Commissioner of Patents
|Cited Patent||Filing date||Publication date||Applicant||Title|
|US2048241 *||Mar 30, 1933||Jul 21, 1936||Phillips Petroleum Co||Process and apparatus for removing hydrogen sulphide from liquids|
|US2315843 *||Apr 20, 1939||Apr 6, 1943||Phillips Petroleum Co||Method of degassing liquids|
|US3383300 *||Sep 24, 1965||May 14, 1968||Exxon Research Engineering Co||Process for the preparation of low sulfur fuel oil|
|US3464915 *||Mar 10, 1967||Sep 2, 1969||Chevron Res||Desulfurization and blending of heavy fuel oil|
|GB895058A *||Title not available|
|Citing Patent||Filing date||Publication date||Applicant||Title|
|US5908548 *||Mar 21, 1997||Jun 1, 1999||Ergon, Incorporated||Aromatic solvents having aliphatic properties and methods of preparation thereof|
|US6610197||Oct 12, 2001||Aug 26, 2003||Exxonmobil Research And Engineering Company||Low-sulfur fuel and process of making|
|US6896795||Apr 1, 2002||May 24, 2005||Institut Francais Du Petrole||Process for the production of gasolines with low sulfur contents|
|US7678263||Jan 30, 2006||Mar 16, 2010||Conocophillips Company||Gas stripping process for removal of sulfur-containing components from crude oil|
|US20020153280 *||Apr 1, 2002||Oct 24, 2002||Institut Francais Du Petrole||Process for the production of gasolines with low sulfur contents|
|US20070175796 *||Jan 30, 2006||Aug 2, 2007||Conocophillips Company||Gas stripping process for removal of sulfur-containing components from crude oil|
|WO1998042804A1 *||Mar 20, 1998||Oct 1, 1998||Ergon Incorporated||Aromatic solvents having aliphatic properties and methods of preparation thereof|
|WO2004074405A2 *||Feb 18, 2004||Sep 2, 2004||Hydrogensource Llc||Hydrogen generator for hydrogen desulfurization of hydrocarbon feeds|
|WO2004074405A3 *||Feb 18, 2004||Nov 11, 2004||Hydrogensource Llc||Hydrogen generator for hydrogen desulfurization of hydrocarbon feeds|
|WO2007103596A2 *||Jan 30, 2007||Sep 13, 2007||Conocophillips Company||Gas stripping process for removal of sulfur-containing components from crude oil|
|WO2007103596A3 *||Jan 30, 2007||Dec 21, 2007||Conocophillips Co||Gas stripping process for removal of sulfur-containing components from crude oil|
|U.S. Classification||208/209, 208/218, 208/212, 208/211|
|International Classification||C10L1/04, C10G45/02, C10G49/22, C10G49/00, C10L1/00|
|Cooperative Classification||C10L1/04, C10G49/22, C10G45/02|
|European Classification||C10L1/04, C10G45/02, C10G49/22|
|May 5, 1986||AS||Assignment|
Owner name: CHEVRON RESEARCH COMPANY, SAN FRANCISCO, CA. A COR
Free format text: ASSIGNMENT OF ASSIGNORS INTEREST.;ASSIGNOR:GULF RESEARCH AND DEVELOPMENT COMPANY, A CORP. OF DE.;REEL/FRAME:004610/0801
Effective date: 19860423
Free format text: ASSIGNMENT OF ASSIGNORS INTEREST;ASSIGNOR:GULF RESEARCH AND DEVELOPMENT COMPANY, A CORP. OF DE.;REEL/FRAME:004610/0801