US3870481A

US3870481A - Method for production of synthetic natural gas from crude oil

Info

Publication number: US3870481A
Application number: US297012A
Authority: US
Inventors: William P Hegarty
Original assignee: Individual
Current assignee: Individual
Priority date: 1972-10-12
Filing date: 1972-10-12
Publication date: 1975-03-11
Anticipated expiration: 1992-03-11
Also published as: FR2208967A1; AU6065773A; GB1453081A; ZA737505B; IT996290B; CA1001416A; IN140810B; FR2208967B1; AU463986B2; ES419508A1; GB1453082A; JPS4970901A; BE805927A; DE2350666A1

Abstract

A process for the production of a pipeline gas of high BTU content from crude oil by hydrogasification of the crude oil. The crude oil is first vaporized in the presence of hydrogen and then gasified to form an effluent gas containing essentially methane, ethane, aromatic hydrocarbons, hyrogen and hydrogen sulfide. After separation of the aromatics and hydrogen sulfide from the effluent, the effluent is subjected to cryogenic separation of the hydrogen and a final catalytic conversion of the ethane to methane.

Description

United States Patent Hegarty [111 I 3,870,481 Mar. 11,1975

METHOD FOR PRODUCTION OF SYNTHETIC NATURAL GAS FROM CRUDE OIL [76] Inventor: William P. Hegarty, 31 Fairway Ln.,

Wescoville, Pa. 18106 [22] Filed: Oct. 12, 1972 [21] Appl. No.: 297,012

[52] US. Cl 48/213, 48/197 R, 48/214 [51] Int. Cl C0lb 2/16 [58] Field of Search 48/211, 213, 214, 197 R; 260/449 M, 683.9; 208/362 [56] References Cited UNITED STATES PATENTS 3,183,181 5/1965 Rudbach 208/362 X 3,363,024 1/1968 Majumdar et a1. 260/683.9

3,531,267 9/1970 Gould 48/213 3,537,977 11/1970 Smith 203/89 3,591,356 7/1971 Thompson et a1. 48/213 OTHER PUBLICATIONS Kil1ingholme," C. J. P. De Winton, Gas Journal, Jan.

RESIDUAL OIL TO PARTIAL OXIDATION HYDROGEN FEED Primary Examiner-S.- Leon Bashore Assistant ExaminerPeter F. Kratz Attorney, Agent, or Firm-James C. Simmons; Barry Moyerman [57] ABSTRACT A process for the production of a pipeline gas of high BTU content from crude oil by hydrogasification of the crude oil. The crude oil is first vaporizedin the presence of hydrogen and then gasified to form an effluent gas containing essentially methane, ethane, aromatic hydrocarbons, hyrogen and hydrogen sulfide. After separation of the aromatics and hydrogen sulfide from the effluent, the effluent is subjected to cryogenic separation of the hydrogen and a final catalytic conversion of the ethane to methane.

19 Claims, 4 Drawing Figures PRODUCT GAS LIQUID v AROMATICS WJFNWI'EUMARI 119.13 A 3.870.481

.SHEET 1 f 3 /0 /s 34 48 T v 22 4 OIL CRUDE on. Z oNE STAGE PURIFICATION-i, CRYOGENIC 7 TOPPING GASIFICATION SEPARATION r FUEL FOR m PLANT 2- 6 usE /3- /2 co 40 18M 56 vENT 24 v 54 5a OXYGEN HYDROGEN SULFUR CATALYTIC Q PLANT PLANT 7 PLANT RICH PROD C 28 GAS SYN 5A;- REACTOR kaz PRODUCT GAS OIL F RESIDUAL OIL TO EESS PARTIAL OXIDATION 76 LIQUID AROMATICS PTTTEF ITEUE- AR 1 1 1975 SHEET 2 or 3 STEAM /a' NAPHTHA FIRST CATALYTIC RICH GAS REACTOR METHANE AND ETHANE 50 /60 FROM HYDROGEN SEPARATION SECOND CATALYTIC RICHGAS REACTOR METHANATION UNIT METHOD FOR PRODUCTION OF SYNTHETIC NATURAL GAS FROM CRUDE OIL BACKGROUND OF THE INVENTION 1. Field of the Invention.

This invention pertains to the production of synthetic natural gas (methane) by the gasification of crude oil. Crude oil is generally separated into high and low boiling point fractions and the low boiling point fractions are then treated at high temperature to produce an effluent gas containing methane, ethane, acid gases such as hydrogen sulfide, excess hydrogen, and residual aromatic constituents. The effluent from the gasification step is then subjected to further processing sequences where the acid gas and aromatic fractions are removed and the hydrogen is separated, and finally the ethane is reacted to form additional methane and the methane or synthetic natural gas is fed to a pipeline for use in, among other things, residential communities and industrial concerns.

2. Prior Art.

Treatment of crude oil or crude oil fractions to produce a synthetic pipeline gas either rich in hydrogen or rich in methane is shown in many processes in the prior art.

One commercial process technique for producing synthetic natural gas by hydrocarbon gasification of naphtha distillate feed stocks is the stream reforming process operated either under severe or mild reforming conditions. In general, the steam reforming process is carried out at elevated temperatures at atmospheric or higher pressures in the presence of a catalyst, generally a supported nickel catalyst. Hydrocarbons react with the steam to give a gas comprising hydrogen, carbon oxide, and methane with the composition of the gas depending upon the conditions of the reaction. Steam reforming under severe conditions is disclosed in U.S. Pat. Nos. 3,103,423 and 3,063,936. British Pat. No. 981,726 discloses a process for steam reforming under mild conditions wherein a methane rich gas is produced. This is illustrative of what is known in the trade as the British Gas Council Catalytic Rich Gas Process (CRG Process).

A second method of producing a synthetic pipeline gas, and one that is especially rich in methane, is by the various thermal hydrocracking techniques. Thermal hydrocracking can be broken down into various categories. The first of these is the operation of the thermal hydrocracking unit without a coke bed or a catalyst; the second is operation with a fluidized coke bed in order to control carbon deposition by periodic withdrawal of solids; and the last is the operation with a hydroforming catalyst to influence the reaction. However, in the latter process the reaction remains largely thermal hydrocracking rather than catalytic hydrocracking at low pressures and high temperatures involved with steam being used to control coke deposition (lay down) on the catalyst.

The thermal hydrocracking processes are exemplified in U.S. Pat. Nos. 2,759,806, 2,882,138, 2,926,077, 3,124,436, 3,202,603, 3,484,219, and 3,591,356. The foregoing Patents are illustrative of thermal hydrocracking processes that variously employ a fluidized bed, recirculation of the gas, or a multiple stage gasification system. In general, it is known that thermal hydrocracking processes or hydrocracking processes accomplished without the influence of a catalyst will produce large quantities of methane in the production of synthetic pipeline gases. Hydrocarbon feed stocks, boiling over a wide range, can be used as the starting product for conventional thermal hydrocracking processes. The conventional processes can operate at temperatures of between 750 and 1650F. and at pressures from 800 to 3500 psig with large hydrogen requirements per barrel of liquid hydrocarbon feed. Higher temperatures are needed with the lighter feed stocks. Very heavy feed stocks may be processed at lower temperatures. Reactions include thermal cracking and hydrogenation, and production of a large volume of light gases including methane is characteristic in large part because of the required high temperature to produce cracking in the absence of a catalyst. In such processes, steam may be added to the reaction zone in order to control the deposition of coke on the vessel interior.

Of particular interest is the process developed by the British Gas Council and embodied in U.S. Pat. No. 3,363,024, which is called the Gas Recycle Hydrogenator Process (GRH Process). This process has been used successfully in producing methane from light petroleum distillates, which can be subsequently processed to a synthetic natural gas for pipeline use. The process is basically a thermal hydrocracking one and is conducted at temperatures of between l290 and 1470F, and at pressures on the order of from to 1350 psig in the presence of a hydrogen gas. The hydrogen gas reacts with the hydrocarbon feed in an exothermic reaction to produce gaseous hydrocarbons; mainly, methane and ethane. Product gases are formed from paraffins in the petroleum distillate and side chains of aromatics in the distillate wherein the aromatic neuc'leus is unaffected. The aromatic constituents can then be separated from the product gases to produce a valuable benzol by-product. With this process, the hydrogen gas can be either pure hydrogen or a gas consisting predominately of hydrogen, such as the product gas from a partial oxidation unit or a steam reforming unit.

A third category of gasification processes which under certain conditions may be used in the process of the present invention include the partial oxidation process. In these processes, a gaseous or liquid hydrocarbon feed is partially oxidized using oxygen, or air with light feeds, or steam with heavy feeds. Reactors are operated at pressures of to 300 psig at temperatures of between 1800 and 3500F. Such reactors produce predominantly hydrogen and carbon monoxide and are well known in the art. Two commercial processes that are offered for sale have been developed by Shell and Texaco. The Shell process is shown in U.S. Pat. No. 2,971,829.

A fourth process for the manufacture of fuel gas is disclosed in U.S. Pat. No. 3,531,267 and combines a catalytic hydrocracking and gasification process.

Of the above processes, only those developed by the British Gas Council and embodied in U.S. Pat. No. 3,363,024 and British Pat. No. 981,726 has been found acceptable for producing a pipeline gas for use by the public consumer. The British Gas Council process has been found to be applicable to feed streams with end points up to 365F (naphthas). It is necessary to provide vaporization of the feed before introduction into the gas recycle hydrogenator if carbon deposition is to be avoided. One method is disclosed in U.S. Pat. No. 3,591,356 for utilizing the higher boiling feed stocks in order to convert the feed stock to methane, ethane, residual aromatics and hydrogen in the gas recycle hydrogenator, which product is used as a component of town gas. Another method is disclosed in US. Pat. No. 3,124,436 wherein there is disclosed a fluidized bed hydrogenation process. In each of these processes, carbon is formed in the gasifier.

The balance of the references cited above disclose processes that have not achieved commercial acceptance for the direct manufacture of synthetic natural gas as of this time usually due to problems with the formation of carbon, coke, or tar in the reactor due to the reactions, as will be hereinafter explained.

SUMMARY OF THE INVENTION In accord with the present invention, there is provided an improved process for producing a pipeline gas of high heating value from a crude oil. The process comprises basically the steps of vaporizing a substantial portion of the crude oil at a temperature of between 600 and 1000F, thereafter introducing the vaporized crude oil and a hydrogenation gas into a gasification vessel maintained at a temperature in excess of 1000F wherein the feed stream is gasified producing an effluent consisting essentially of hydrogen, hydrogen sulfide, methane, ethane, and residual aromatic hydrocarbons, thereafter cooling the effluent gas to room temperature and recovering the waste heat, drying the effluent and removing the hydrogen sulfide and residual aromatics from the effluent, cryogenically separating the methane and ethane from the hydrogen, and thereafter reacting the ethane with steam to produce additional methane and carbon dioxide, and removing the carbon dioxide. The two methane streams are combined and discharged into a process pipeline or storage vessel. The methane from the gasifier does not have to be separated from the ethane during ethane conversion. The process includes additional steps wherein the various side streams can be used to produce sources of reactant or heat for operating the plant utilities in order to achieve an efficient overall process. While it would be possible to use various hydrogasification methods, the gas recycle hydrogenator developed by the British Gas Council is the preferred hydrogenation vessel for the method of the instant application.

The hydrogen separated from the methane and ethane can be recycled to the feed stream vaporization unit or the gasifier.

A key to the present invention is the vaporization step, which is also disclosed, comprising heating the oil and the hydrogenation gas, preferably hydrogen, and admixing the heated oil and gaseous hydrogen in a vaporizer and taking the vaporizer effluent and passing it in to the hydrogenation vessel, thereafter recovering the heat from the gasifier effluent and using a portion of the gasifier effluent after cooling to control the temperature of reaction of the gasification vessel thereby preventing unwanted coke formation in the gasification vessel.

Therefore, it is the primary object of this invention to provide an improved process for the production of synthetic natural gas from crude oil.

It is another object of this invention to provide a method of hydrogasifying crude oil.

It is a further object of this invention to provide a method for feeding heavier crude oil into a hydrogasification zone.

It is still a further object of this invention to provide a method of producing synthetic natural gas from crude oil wherein the by-product streams from the main process stream are used in operating the overall process thereby providing process economies.

A BRIEF DESCRIPTION OF THE DRAWING FIG. 1 is a schematic drawing of the overall process for producing a synthetic natural gas from a crude oil.

FIG. 1a is a schematic drawing of an alternative method of converting naphtha and ethane to methane and carbon dioxide.

FIG. 2 is a schematic diagram of the improved method of feeding the hydrogasification vessel in order to achieve an effluent that is convertible to synthetic natural gas.

FIG. 3 is a schematic diagram of the test system used to verify the feeding and hydrogasification steps of the present invention.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT There is shown in FIG. 1 an overall process flow sheet for the method of the present invention.

In FIG. 1, numeral 10 indicates a feed stream preparation step in the overall process wherein a crude oil stream 12 is subjected to preliminary separation wherein a naphtha fraction having 360F end point is taken overhead through conduit 18 and used in a subsequent processing step as will hereinafter be more fully explained.

The process stream 15 after preparation may be subjected to a vaporization process as will be discussed in connection with FIG. 2, after which said stream comprises crude oil material having a +360F boiling point and hydrogenation gas 13 which is injected into a single-stage gasifier such as that disclosed in US. Pat. No. 3,363,024. The vaporizer and/or gasifier is represented in'FlG. 1 by block 16.

In the gasifier, about 83 percent of the oil is gasified at high temperature to a mixture of methane, ethane, excess hydrogen, hydrogen sulfide and residual aromatics. The 17 percent residue of the oil plus a portion of the aromatics separated from the gas after cooling are fed to a hydrogen plant 20. In the hydrogen plant 20, hydrogen (represented by arrow 13) is produced by the partial oxidation process for use in the gasifier or in vaporization of the feed stream in order to react with the vaporized crude oil to formthe gasifier effluent 22. Oxygen for the partial oxidation portion of the hydrogen plant 20 is supplied by a separate oxygen plant 24, which plants are commercially available. The balance of the hydrogen plant 20 includes waste heat recovery systems, water gas shift, acid gas removal and methanation systems to produce high-purity hydrogen by the reaction of CO and steam and subsequent removal of hydrogen sulfide and C0 The CO from the hydrogen plant 20 is vented through conduit 26 and the hydrogen sulfide is passed bia a conduit 28 to a sulfur plant 30 wherein it is combined with the hydrogen sulfide from the purification unit 34 and removed from the system by the claus process as elemental sulfur as at 32. The gasifier effluent stream 22 is cooled and passed through a purification section 34 wherein the gas is dried and the acid gases as well as benzene and other residual aromatics are removed.

Acid gases are taken to mean CO and hydrogen sulfide. The benzene and other residual aromatics are removed through conduit 36 and conducted through

conduits

38 and 40 to the conduit 42, which receives the residual oil fraction from the gasifier and the mixture introduced into the hydrogen plant for production of hydrogen by the partial oxidation process. A portion of the benzene and residual aromatics can be used as a source of fuel for operating the plant. Hydrogen sulfide is removed through conduit 44 and sent to the sulfur plant 30. The effluent-from purification step 34 in conduit 46 contains essentially hydrogen, methane and ethane and is sent to a cryogenic separation unit 48 wherein the process stream is cooled, the methane and ethane are liquefied, separated from the hydrogen, vaporized, rewarmed compressed and removed through conduit 50, and the hydrogen through conduit 52. The hydrogen in conduit 52 is warmed to ambient and recycled to the gasifier or the feed stream preparation section 16 and respectively.

The combined methane-ethane liquid stream in conduit 50 is charged to a catalytic rich gas process unit 54 along with the naphtha that is taken from the feed stream preparation stage 10 via conduit 18. In the catalytic rich gas section 54, the naphtha is desulfurized and the naphtha and ethane are reacted with steam in an autothermic catalytic reaction to produce methane plus carbon dioxide. The carbon dioxide is separated and vented through conduit 56 and the methane product in conduit 58 is dried and compressed to 1000 psig and discharged into a product pipeline or suitable storage receptacle.

In the catalytic rich gas unit 54, the methane produced in the gasifier is carried along with the process stream but does not enter into the overall reaction. Alternatively, the methane from the gasifier can be separated before the catalytic rich gas unit 54 thereby reducing the overall size of unit 54. Another method of converting the naphtha ethane is shown in FIG. 1a wherein the naphtha from conduit 18 is reacted with steam 19 in a first catalytic rich gas reactor 54a thereby discharging steam, methane and carbon dioxide in conduit 160. The methane and ethane from the cryogenic separation unit 48 are injected in conduit 160 through conduit 50 and the mixture is injected into a second catalytic rich gas reactor 5412 wherein the ethane and steam are reacted to form essentially methane and carbon dioxide. The effluent in conduit 162 consists essentially of methane, carbon dioxide, carbon monoxide,

and hydrogen. This effluent is sent to a methanation unit wherein additional methane is produced and the product gas is then sent to a carbon dioxide removal unit 166 through conduit 168. After carbon dioxide removal, the effluent gas consisting of about 94% methane with hydrogen and a trace of carbon monoxide is sent into a product pipeline through conduit 170.

With a process as outlined in FIG. 1, a plant embodying such stages is completely self-sustaining regarding utilities. For example, by-product steam is generated in the hydrogen plant, the sulfur plant, and the gasification plant. This steam is supplemented with an auxiliary steam generating plant to meet the requirements of the oxygen plant, the purification process, cryogenic separation process and the catalytic rich gas section. Overall electrical power usage is neglibible since compressors and pumps are driven by condensing steam turbines. Fuel for auxiliary steam generators is supplied by the residual aromatics from the process, which are burned as a fuel. It is calculated that overall thermal efficiency (product gas heating value as a percent of feed oil heating value) is about 84 percent.

The overall process as set forth in connection wit FIG. 1 comprises eight separate steps each of which is within the perview of current technology; however, such a combination has never before been shown or suggested. However, the hydrogasification step 16 has not been successful for heavier crude oil (higher boiling feed stocks). Hydrogasification is basically a highpressure, high-temperature, non-catalytic gas phase hydrocracking reaction. High molecular weight hydrocarbons are cracked and the fragments are saturated with hydrogen. Paraffins and naphthenes (cycloparaffins) are completely gasified to methane and ethane in the hydrogasification reaction alkyl side chains of the aromatics are gasified leaving residual benzene. Polycyclic aromatics are gasified leaving residual benzene. Polycyclic aromatics are in part gasified also leaving residual refractory benzene and the sulfur is reacted to hydrogen sulfide. Overall, the reaction is very highly exothermic. The gas recycle hydrogenerator (GRH) as disclosed in US. Pat. No. 3,363,024 is the only hydrogen gasification process proven in cornmercail operation. This process features an adiabatic back-mixed reactor that dealkylates feed aromatics and completely gasifies paraffins and naphthenes (cycloparaffins) with a residence time of between 10 and 50 seconds at temperatures in the order of 1290F to 1390F under operating pressures of from to 1350 psig. The product gas from such a gas recycle hydrogenator consists of methane, ethane, residual refractory aromatics and excess hydrogen. The British Gas council has published its findings claiming that the only limitation on liquid feed stock is the ability to evaporate it as a gasifier feed. Commercial applications have used naphthas with end points up to 365F. The Gas Council has conductd pilot-plant tests with 635F end point gas oil with no gasifier carbon problems. However, in the latter case, plugging problems did develop and the Gas Council has accepted 650F as the maximum feeding end point for the process.

The Gas Council has identified three types of carbon depositions that can be found in the gas recycle hydrogenator. These are catalytic carbon, which is deposited on catalytically active metal surfaces with attendant pitting corrosion of the metal surface; wall carbon, which deposits on a surface of low activity already coated with carbon; and space carbon, which is produced as soot in the gas phase and exhausted with the gas product (effluent). Carbon formation is promoted by excessively high operating temperatures, carbon monoxide and carbon dioxide content and low gasifier hydrogen partial pressure. On the'other hand, carbon formation is suppressed by sulfur and steam, with a high internal recirculation rate to give a closer approach to complete back-mixing in uniform temperatures also tending to decrease carbon formation. At normal operating conditions, with negligible carbon dioxide content, formation of space carbon and catalytic carbon with the accompanying corrosion is eliminated by ten parts per million of sulfur in the feed distillate plus a small amount of steam. Sulfur concentrations of to 300 parts per million in the feed may be required to eliminate wall carbon formation. Operating temperature and hydrogen pressure effects can be used in combination to avoid carbon formation, i.e. the normal 1380 operating temperature may be reduced to l320 when hydrogen partial pressure is low. As the operating temperature is lowered, however, the hydrogenation reaction rate decreases and paraffins and naphthenes may not be completely gasified. At temperatures below 1290F. reaction rates decrease sharply and operation of the gasifier becomes unstable and the reaction may extinguish. 7 A

It has also been found thatthe hydrocarbon liquid/- hydrogen feed ratio must be maintained within certain limits. At high ratios, hydrogen partial pressure is low and the hydrogenation rate decreases with resulting cyclization of the reaction thereby causing a net production of aromatics. In an extreme case, condensation to polycyclic aromatics could result in tar and coke problems. Operation of the reactor includes maintaining the temperature by regulating the feed preheat temperatures. At low ratios of hydrocarbon liquid to hydrogen feed less reactant is charged, therefore, the heater reaction is less and the feed preheat temperatures increase. If such increases are excessive, the reaction could initiate in the preheater with attendant difficulties therein.

The Gas Council has reported its efforts were directed to getting the highest possible heating value gas direct from the gas recycle hydrogenator. Therefore, they sought to minimize the excess hydrogen thereby having a high ethane concentration in the effluent gas (about 0.5 mole per mole of methane). They have not reported any investigations using excess hydrogen. One reported high-pressure run at I350 psia did hydrogenate ethane but the control was sluggish and operating temperature was unstable and carbon formation resulted in the vessels. If ethane hydrogenolysis is suddenly initiated with minimum excess hydrogemthere would be a sudden decrease in hydrogen partial pressure and the reacted temperature would rise. Such a combination would most surely produce carbon particularly when poor temperature control is present. Maintaining temperature control in the reactor with sufficient excess hydrogen to suppress carbon formation the additional heat release would decrease the required preheat temperature for the 'products being fed to the reactor.

Another major problem in oil hydrogasification is the formation of coke and tar. Coke deposition could result in plugging of the reactor, thereby making the overall process uneconomical and inefficient. Tar could cause fouling of heat exchange surfaces and prevent use of waste heat boilers requiring quenching the gasifier product with consequent loss of potential hightemperature level heat recovery and decrease thermal efficiency. It is known that aromatics are precursors to tar and coke formations. At elevated temperatures, aromatics condense to form heavy polycyclic molecules to give tars and ultimately coke. Maintaining high hydrogen partial pressure saturates olefinic cracking intermediates and prevents them from cyclizing to produce aromatics and also suppresses the condensation of aromatics already present in the feed. Saturation of olefins by hydrogen also slows reactions because the olefms crack more easily than saturated compounds. Therefore, it follows that in the presence of highpressure hydrogen, hydrocarbons can be heated to higher temperatures than normal without cracking or formation of tars or coke.

Recent advances in ethylene cracking technology have shown that aromatic coke precursors that condense to coke in the laminar films on the hot tube walls will form relatively fast in the bulk fluid at intermediate temperature levels. The rate of coke precursor formation, relative to the rate of the desired cracking reactions, was shown to decrease as the temperature was raised. Accordingly, cracking furnaces were designed to minimize residence time in an intermediate temperature range. Coke precursor formation was sharply reduced; and with reduced precursors, tube wall temperatures at the outlet end were increased without increased coking. The net result was development of the revolutionary short residence time ethylene cracking furnace. As an additional benefit, the tar formation was also reduced; and with lighter feed stocks, cracking oil transfer line waste heat boilers replaced quenching. This discovery leads to the conclusion that in the gas recycle hydrogenator coke formation may be avoided even with heavy oil feed stocks. The gas recycle hydrogenator is essentially a back-mixed reactor with the preheated feed (approximately -1000F) warmed to gasifier effluent temperature (about 1380F) almost instantaneously. In addition, feed oil vapor concentrations are diluted to outlet concentrations immediately thereby minimizing self-condensation reactions; thus, formation of precursors at the intermediate temperature and high feed concentration levels should be negligible and tar and coke production minimized.

With this preliminary work in hand, it was discovered that the gas recycle hydrogenator can accept feed stocks with higher boiling fractions when such feed stocks are gasified as shown in FIG. 2.

The basic gasification system is shown in FIG. 2 and consists of a vaporizer 60, gasifier 62, a liquid aromatics separator 64, a product gas compressor 66, together with hydrogen and

oil heaters

68 and 70 respectively, and a gasifier product cooler 72. Such a system would operate at 600 psig or higher with the crude oil feed 74 and the hydrogen feed 76, each being preheated and charged to the vaporizer 60. The oil 78 is further heatedby heater 80, which is submerged in the pool of liquid residual crude oil or heel as it is called in the trade. The hydrogen after being preheated is sparged beneath the surface of the liquid residual crude oil 78 in vaporizer 60 so that the oil is vaporized into a mixture with the hydrogen and taken from the vaporizer through conduit 82 and conducted into the gasifier 62.

With whole crude oil, or naphtha topped crude oil, about percent by volume of the oil would be evaporated with the residual oil being withdrawn through conduit 84 and used as feed for a partial oxidation plant to produce the required hydrogen. The level of the pool of liquid residual oil and rate of residual oil withdrawal are determined bylevel control 83. The vaporizer temperature would typically be in the range of from 800 to 1000F depending upon the particular crude oil feed. The hydrogen-oil vapors from the vaporizer in conduit 82 are injected into the adiabatic hydrogasifier 62 and the exothermic gasification reaction occurs. The oil is gasified to methane, ethane. and residual aromatics with excess hydrogen and hydrogen sulfide which is generated by the conversion of sulfur in the oil. The entering feed jet 86 induces a high internal recirculation rate in the gasifier along the path shown by the arrows. The contents of the entering jet 86 are essentially completely mixed and have substantially uniform composition and temperature. The temperature in the reactor is approximately 1400F and the average reactor residence time is between 10 and seconds.

The hot effluent gases are removed through conduit 88 and cooled in waste heat boiler 72 with heat recovery. After heat recovery, the effluent is conducted to aromatic separator 64 through a conduit wherein the condensed aromatic constituents are removed from the separator through conduit 92 and are used for supplementary feed to the partial oxidation unit and process fuel. The resulting gas product from the separator 64 is compressed in compressor 66 and pushed on to further processing. The gas at the exit end of the compressor consists essentially of hydrogen, methane, ethane, hydrogen sulfide, and uncondensed aromatics. This product can be further processed in accordance with the process described in FIG. 1. In FIG. 2, a portion of the cooled gas from the compressor 66 is taken through conduit 94 and recycled through valve 96 into the reactor or hydrogasifier 62 to provide cooling of the reactor to maintain the reacted temperature at the desired temperature level of about 1400F. I

The foregoing process was verified in a test setup shown in FIG. 3 that was constructed and operated. This system consisted of a hydrogen supply conduit 100, a hydrogen metering device (rotameter 102), electrically heated hydrogen humidifier 104, an oil feed system 106 comprising an oil tank 108, and oil metering pump 110, a vaporizer 112 that was electrically heated, a hydrogasification vessel 114, also electrically heated, a product cooler-condenser 116, a liquid separator 118, a back pressure controller 120, product gas analysis system shown generally as 122 consisting of a wet test meter 124 and a Ranerax meter 126, and a tempering gas recycle system consisting of recycle gas compressor I28 and recycle gas heater 130. In the above setup, electric heating was provided to the hydrogen humidifier, the vaporizer, the hydrogasifier, and the tempering recycle gas system and all high temperature transfer lines were electrically heated to maintain the process temperature.

In operation, the gasification system pressure was maintained by the product gas back pressure controller 120. Hydrogasifier temperature was automatically controlled by the hydrogasifier electric trim heaters and the hydrogen feed gas flow was manually set by hand control valve 132 to the desired level as indicated by the rotameter 102. Hydrogen was sparged in beneath the surface of the water 134 maintained in the humidifier and heated by heater 136 to becomesaturated with steam. Oil from tank 108 was pumped by the oil metering pump 110 into electrically heated discharge tubing 138 mixed with the hydrogen and pumped into the electrically heated vaporizer 112. The oil saturated hydrogen vapors exited from the vaporizer 112 through conduit 140 and were introduced into the hydrogasifier 114 through the nozzle 142. Residual unvaporized oil was withdrawn from the vaporizer, as indicated by the level control 144 in order to maintain a minimal level of liquid in the vaporizer, and discarded.

In view of the fact that overheating of the hydrogen oil hydrogasifier feed vapors can cause coke depositions in the inlet nozzle 142 with eventual plugging, the feed inlet tube was jacketed with tempering gas flow, which entered through a pearlite insulated top section 148. Heat leakage from the hydrogasifier 114 was reduced by the pearlite and the heat was largely absorbed by the tempering gas avoiding excessive heating of the feed vapor. The feed gas was injected into the hydrogasifier 114 at the top of the internal draft tube 150 at high velocity. The entering jet induced a large internal recirculation rate to give an approach to complete back-mixing. Incoming oil vapors were heated to the hydrogasifier temperature virtually instantaneously and reacted to give a product gas of methane, ethane, hydrogen sulfide, residual aromatics, and excess hydrogen in conduit 152. The test hydrogasifier was made of stainless steel reaction vessel approximately 1.16 inches in diameter and 18% inches long. The axial draft tube 150 was a 16-inch length of 20-gauge 96-inch stainless steel tubing. The overall volume of the test hydrogasifier was approximately 19.7 cubic inches.

The product gases exited the hydrogasifier 114 through an outlet tube extending through the annulus from the bottom to the top of the draft tube. The effluent gases were cooled in a product cooler-condenser 116 and passed through the liquid separator 118 where aromatic condensate liquid and water were collected and periodically drained through conduit 154. The gas from the separator 118 was let down through a back pressure controller and with the rate measured in a wet test meter 124 and specific gravity measured by a Ranerax instrument 126. Product gas was vented to the atmosphere with periodic gas chromatographic analysis being made. Prior to pressure letdown, a portion of the gas was compressed by the recycled gas compressor 128 heated to about 50 hotter than the hydrogasifier feed gas temperature and passed as a tempering gas through the inlet feed gas jacketing. The tempering gas was withdrawn through the hydrogasifier top and mixed with the hot gasifier product gas through conduit 156.

In an actual test run, Lagomedio crude oil was run in the abovetest setup with the following results:

Gas composition, mole g 45.5 CH, 36.7 C 11 17.8-.

100.0 Aromatics Liquid Composition, wt

Benzene 36.7 Toluene 6.5 Cg aromatics 2.1 C -C aromatics 0.5 Naphthalene 21.2 Anthrocene 5.4 Heavy ends 4.8 Residue & Loss 22.8

After 4 hours stable operation at these conditions, inspection of the reactor showed no significant coke deposition. The vaporizer showed no coke deposition or tarry deposits except for a small quantity of friable coke around the relatively cool (300F) inlet feed dip tube.

The test outlined above refers to a successful run feeding 76 weight percent of a medium gravity (32.6 APl) lagomedio crude oil to the gasifier. Approximately 82 weight percent of the oil feed to the gasifier was gasified with 18 weight percent being recovered as aromatic condensate; 76 weight percent vaporization is equivalent to about 1000F TPB cut point but even higher boiling consitutents were sure to be in the gasifier feed. There were no problems experienced in the reactive feed nozzle or vaporizer during this test.

In view of the foregoing, it was shown that the gas recycle hydrogenator reactor system can be used with higher boiling feed stocks including whole crude oil; and it is also believed that residual oil fractions can be used by direct partial vaporization at high pressure into hydrogen of the feed stock. Partial vaporization avoids the deposition and plugging problems that typically result when high boiling distillates or residual petroleum fractions are evaporated to dryness. The residual liquid from the evaporation step with high boiling oil feed stocks provides a suitable feed to a partial oxidation process to supply the hydrogen requirements for hydrogasification.

With high boiling distillates and residual oil feeds, high temperatures are required for evaporation of the oil. Evaporation into hydrogen at high pressure is beneficial in two respects. The high-pressure hydrogen suppresses cracking and coking reactions in the evaporator and also dilutes the oil vapors reducing their partial pressure and decreasing the temperature required to attain a given fraction vaporized.

It is within the scope of the present invention to use any of the conventional gasification schemes set forth in the art, however, the Gas Recycle Hydrogenation is preferred.

If process economies dictated it, a portion of the carbon dioxide produced in the process could be reacted with hydrogen in a methanation unit to produce athermal methane.

Having thus described my invention, what is desired to be secured by Letters Patent of the United States is set forth in the following Claims.

I claim:

1. A method of producing a pipeline gas of high heating value from crude oil comprising the steps of:

partially vaporizing a crude oil feed in the presence of hydrogen at a temperature of between 600 and 1000F, introducing the vaporized crude oil feed and hydrogen into a gasification vessel maintained at a temperature in excess of 1000F wherein the feed stream is gasified producing an effluent consisting essentially of hydrogen, hydrogen sulfide, methane, ethane, and residual aromatic hydrocarbons;

cooling the effluent gases to room temperature and recovering waste heat therefrom to form water and aromatic condensate; and

removing the hydrogen sulfide, water and residual aromatics from said effluent in a purification zone; cryogenically separating the methane and ethane from the hydrogen in a purified effluent stream;

reacting steam with the ethane contained in the methane and ethane stream to produce methane and carbon dioxide; and

removing the carbon dioxide and discharging methane in a product receiving device. 2. A method according to claim 1 wherein the crude oil feed stream is subjected to an initial step wherein a naphtha fraction is removed.

3. A method according to claim 2 wherein the naphtha fraction is reacted with steam in a catalytic process to produce methane and carbon dioxide, separating the carbon dioxide and combining the methane with methane from the ethane reaction.

4. A method according to claim 1 wherein there is included a hydrogen generating plant which plant takes residual non-gasified crude oil bottoms resulting from the partial vaporization of crude oil feed, together with a portion of the aromatics from the gasifier effluent for producing hydrogen for injection into the gasifier feed stream.

5. A method according to claim 1 wherein the hydrogen sulfide removed from the gasifier effluent is processed to elemental sulfur.

6. A method according to claim 1 wherein the gasification of the feed stream is carried out in an adiabatic hydrogasifier.

7. A method according to claim 1 wherein a portion of the product stream is cooled and after removal of residual aromatic and hydrogen sulfide is introduced into the gasification vessel to maintain temperature control in the gasifier vessel.

8. A method according to claim 1 wherein the cryogenically separated hydrogen is warmed to ambient temperature and mixed with fresh hydrogen for injection into the gasifier.

9. A method for producing a pipeline gas having a heating value of about 1000 BTU/SCF from crude oil comprising the steps of:

subjecting a crude oil stream to a topping operation wherein there is a 360F end point naphtha separation;

partially vaporizing the topped crude oil stream i the presence of hydrogen at a temperature of between 600F and 1000F thereby admixing the crude oil vapors and hydrogen to form a process stream;

gasifying the process stream to form an effluent consistin g essentially of methane, ethane, hydrogen sulfide, hydrogen and residual aromatic hydrocarbons;

removing the residual aromatic hydrocarbons and hydrogen sulfide from the effluent in a purification unit; separating the hydrogen from the methane and ethane in the effluent;

reacting the naphtha from the crude oil topping steps and the methane and ethane effluent with steam to produce a carbon dioxide and methane effluent; and

separating the carbon dioxide from the methane and introducing the methane into a product pipeline.

10. A method according to claim 9 wherein the hydrogen is separated from the methane and ethane efflu- 5 ent cryogenically and the hydrogen is warmed to ambi ent and recycled to gasification.

11. A method according to claim 9 wherein the reaction of the naphtha fraction and the methane and ethane effluent with steam is an autothermic catalytic reaction and the naphtha fraction is desulfurized prior to said autothermic catalytic reaction.

12. A method according to claim 9 wherein the hydrogen sulfide separated from the process stream effluent is treated to produce elemental sulfur by the Claus process.

13. A method according to claim 9 wherein the gasification of the process stream is effected in an adiabatic hydrogasifier wherein an exothermic reaction takes place to produce the gasifier effluent.

14. A method of gasifying a crude oil to produce a gaseous effluent consisting essentially of hydrogen, methane, ethane, hydrogen sulfide and uncondensed aromatics comprising the steps of:

introducing a liquid crude oil into a vaporization vessel heated to between 800 and lOF;

maintaining a pool of liquid residual crude oil in said vaporization vessel and introducing warmed gaseous hydrogen into the pool of liquid residual crude oil thereby forming a mixture of vaporized hydrogen and crude oil above the pool of liquid residual crude oil; and

withdrawing the vaporized crude oil hydrogen mixture and injecting said mixture into a hydrogasification vessel wherein the mixture is recirculated at a temperature of about 1400F to cause the mix ture to react to form a gasifier effluent consisting essentially of hydrogen, methane, ethane, aromatic hydrocarbons and hydrogen sulfide and lowering the temperature of said effluent and recovering heat thereby thus condensing and separating condensible aromatic hydrocarbons.

15. A method according to claim 14 wherein a portion of the effluent stream is injected into the hydrogasification vessel to maintain the reaction temperature of said vessel.

16. A method according to claim 14 wherein a portion of the heat in said gasifier effluent stream is recovered in a waste heat boiler before separation of the condensible aromatic hydrocarbons.

17. A method according to claim 14 wherein residual oil from said vaporization vessel is subjected to a partial oxidation process to produce hydrogen for the vaporization step.

18. A method according to claim 14 wherein the crude oil is given a 360F end point naphtha separation prior to being introduced into the vaporization vessel.

19. A method of gasifying a crude oil to produce a gaseous effluent consisting essentially of hydrogen, methane ethane, hydrogen sulfide and uncondensed aromatics comprising the steps of:

injecting a crude oil stream into a vaporization vessel heated to a temperature of between 800 and 1000F and maintaining a pool of liquid residual crude oil in said vaporization vessel;

sparging warmed gaseous hydrogen into said liquid residual crude oil below the surface of the pool thereby forming a mixture of hydrogen and vaporized crude oil above the pool;

withdrawing the vaporized hydrogen crude oil mixture and injecting said mixture into a hydrogasification vessel;

allowing said mixture to circulate in said hydrogasification vessel to react to produce a gasifier effluent consisting essentially of hydrogen, methane, ethane, aromatic hydrocarbons, and hydrogen sultide; and

lowering the temperature of said effluent and recovering heat thereby thus condensing and separating condensable aromatic hydrocarbons.

Claims

1. A method of producing a pipeline gas of high heating value from crude oil comprising the steps of: partially vaporizing a crude oil feed in the presence of hydrogen at a temperature of between 600* and 1000*F, introducing the vaporized crude oil feed and hydrogen into a gasification vessel maintained at a temperature in excess of 1000*F wherein the feed stream is gasified producing an effluent consisting essentially of hydrogen, hydrogen sulfide, methane, ethane, and residual aromatic hydrocarbons; cooling the effluent gases to room temperature and recovering waste heat therefrom to form water and aromatic condensate; and removing the hydrogen sulfide, water and residual aromatics from said effluent in a purification zone; cryogenically separating the methane and ethane from the hydrogen in a purified effluent stream; reacting steam with the ethane contained in the methane and ethane stream to produce methane and carbon dioxide; and removing the carbon dioxide and discharging methane in a product receiving device.

2. A method according to claim 1 wherein the crude oil feed stream is subjected to an initial step wherein a naphtha fraction is removed.

9. A method for producing a pipeline gas having a heating value of about 1000 BTU/SCF from crude oil comprising the steps of: subjecting a crude oil stream to a topping operation wherein there is a 360*F end point naphtha separation; partially vaporizing the topped crude oil stream in the presence of hydrogen at a temperature of between 600*F and 1000*F thereby admixing the crude oil vapors and hydrogen to form a process stream; gasifying the process stream to form an effluent consisting essentially of methane, ethane, hydrogen sulfide, hydrogen and residual aromatic hydrocarbons; removing the residual aromatic hydrocarbons and hydrogen sulfide from the effluent in a purification unit; separating the hydrogen from the methane and ethane in the effluent; reacting the naphtha from the crude oil topping steps and the methane and ethane effluent with steam to produce a carbon dioxide and methane effluent; and separating the carbon dioxide from the methane and introducing the methane into a product pipeline.

10. A method according to claim 9 wherein the hydrogen is separated from the methane and ethane effluent cryogenically and the hydrogen is warmed to ambient and recycled to gasification.

14. A method of gasifying a crude oil to produce a gaseous effluent consisting essentially of hydrogen, methane, ethane, hydrogen sulfide and uncondensed aromatics comprising the steps of: introducing a liquid crude oil into a vaporization vessel heated to between 800* and 1000*F; maintaining a pool of liquid residual crude oil in said vaporization vessel and introducing warmed gaseous hydrogen into the pool of liquid residual crude oil thereby forming a mixture of vaporized hydrogen and crude oil above the pool of liquid residual crude oil; and withdrawing the vaporized crude oil hydrogen mixture and injecting said mixture into a hydrogasification vessel wherein the mixture is recirculated at a temperature of about 1400*F to cause the mixture to react to form a gasifier effluent consisting essentially of hydrogen, methane, ethane, aromatic hydrocarbons and hydrogen sulfide and lowering the temperature of said effluent and recovering heat thereby thus condensing and separating condensible aromatic hydrocarbons.

14. A METHOD OF GASIFYING A CRUDE OIL TO PRODUCE A GASEOUS EFFLUENT CONSISTING ESSENTIALLY OF HYDROGEN, METHANE, ETHANE, HYDROGEN SULFIDE AND UNCONDENSED AROMATICS COMPRISING THE STEPS OF: INTRODUCING A LIQUID CRUDE OIL INTO A VAPORIZATION VESSEL HEATED TO BETWEEN 800* AND 1000*F; MAINTAINING A POOL LIQUID RESIDUAL CRUDE OIL IN SAID VAPORIZATION VESSEL AND INTRODUCING WARMED GASEOUS HYDROGEN INTO THE POOL OF LIQUID RESIDUAL CRUDE OIL THEREBY FORMING A MIXTURE OF VAPORIZED HYDROGEN AND CRUDE OIL ABOVE THE POOL OF LIQUID RESIDUAL CRUDE OIL; AND

18. A method according to claim 14 wherein the crude oil is given a 360*F end point naphtha separation prior to being introduced into the vaporization vessel.