US3733260A - Hydrodesulfurization process - Google Patents

Abstract

A HYDRODESULFURIZATION PROCESS FOR TREATING A SULFUR CONTAINING GAS-OIL HYDROCARBON CHARGE TO YIELD A LOWSULFUR GAS-OIL PRODUCT AND A NAPHTHA PRODUCT WHEREIN EFFLUENT FROM A HYDRODESULFURIZATION PROCESS COMPRISING GAS-OIL, NAPHTHA, HYDROGEN AND HYDROGEN SULFIDE IS SEPARATED INTO A LIQUID FRACTION AND A VAPOR FRACTION, WHEREIN THE VAPOR FRACTION IS TREATED TO YIELD A TREATED HYDROGEN STREAM SUBSTANTIALLY FREE OF HYDROGEN SULFIDE, WHEREIN RECYCLE, NAPHTHA IS COMBINED WITH THE LIQUID FRACTION TO FORM A MIXTURE HAVING A BUBBLE POINT TEMPERATURE BELOW ABOUT 650*F. AT A PRESSURE OF ABOUT 130 P.S.I.G., WHEREIN THE LIQUID MIXTURE IS STRIPPED IN A STRIPPING ZONE TO REMOVE HYDROGEN SULFIDE EMPLOYING TREATED HYDROGEN AS STRIPPING VAPOR AT A PRESSURE OF ABOUT 100-130 P.S.I.G. AT THE BUBBLE POINT TEMPERATURE OF THE LIQUID MIXTURE, WHEREIN STRIPPED LIQUID SUBSTANTIALLY FREE O HYDROGEN SULFIDE IS FRACTIONATED INTO A NAPHTHA FRACTION AND A GAS-OIL FRACTION, AND WHEREIN A PORTION OF THE NAPHTHA FRACTION IS RECYCLED FOR MIXTURE WITH ADDITIONAL LIQUID FRACTION FROM THE HYDRODESULFURIZATION REACTION.

Description

May 15, 1973 J. A. DAvn-:s ET AL 3,733,260

HYDRODESULFURIZATION PROCESS United States Patent O U.S. Cl. 208-212 3 Claims ABSTRACT OF THE DISCLOSURE A hydrodesulfurization process for treating a sulfur containing gas-oil hydrocarbon charge to yield a lowsulfur gas-oil product and a naphtha product wherein eluent from a hydrodesulfurization process comprising -gas-oil, naphtha, hydrogen and hydrogen sulfide is separated into a liquid fraction and a vapor fraction, wherein the vapor fraction is treated to yield a treated hydrogen stream substantially free of hydrogen sulfide, wherein recycle, naphtha is combined with the liquid fraction to form a mixture having a bubble point temperature below about 650 F. at a pressure of about 130 p.s.i.g., wherein the liquid mixture is stripped in a stripping zone to remove hydrogen sulfide employing treated hydrogen as stripping vapor at a pressure of about 100-130 p.s.i.g. at the bubble point temperature of the liquid mixture, wherein stripped liquid substantially free of hydrogen sulfide is fractionated into a naphtha fraction and a gas-oil fraction, and wherein a portion of the naphtha fraction is recycled for mixture with additional liquid fraction from the hydrodesulfurization reaction.

BACKGROUND OF THE INVENTION The present invention relates to a hydrodesulfurization process wherein gas-oil range hydrocarbons are treated with molecular hydrogen at an elevated temperature and pressure in the presence of a hydrodesulfurization catalyst to convert sulfur compounds contained in such gas-oil hydrocarbons into hydrogen sulfide, and wherein treated gas-oil hydrocarbons are recovered substantially free of hydrogen sulfide and low boiling hydrocarbons. More particularly, the present invention relates to an improved method for recovering treated gas-oil hydrocarbons substantially free of hydrogen sulfide and low boiling hydrocarbons.

Hydrotreating processes for converting sulfur compounds contained in gas-oil range hydrocarbons into hydrogen sulfide are well known. Gas-oil hydrocarbons may be treated at temperatures from about 600 to about 800 F., pressures of from about 500 to about 1200 p.s.i.g. with molecular hydrogen in a hydrogen to gas-oil ratio of from about 300 to 2500 standard cubic feet per barrel, in therpresence of a hydrodesulfurization catalyst. Catalyst which have been found to be useful in the hydrodesulfurization of gas-oil hydrocarbons include nickel, cobalt, molybdenum, tungsten, their oxides, their sulfides, and mixtures thereof. Such catalysts may be unsupported in a reaction zone or may be supported'upon a relatively inert inorganic oxide base such as, for example, alumina, or silica-alumina. In such hydrodesulfurization reactions, a portion of the gas-oil hydrocarbon is converted into low boiling hydrocarbons from methane through the kerosine boiling range.

Petroleum fractions boiling in the gas-oil hydrocarbon range of from about 600 F. to about ll00 F. may be converted into more valuable products such as gasoline and kerosine by such methods as fluidized catalytic cracking. Many gas-oil range hydrocarbons contain substantial amounts of sulfur compounds which interfere With processes for converting such gas-oil range hydrocarbons into gasoline and other desirable products. The presence of 3,733,260 Patented May l5., 1973 ICC sulfur compounds in a gas-oil hydrocarbon may contrlbute to decreased yield and product quality for the desirable products recovered from such conversion processes.

'I The reaction mixture from a hydrodesulfurization reaction zone may be separated into a gas-oil fraction substantially free of hydrogen sulfide, a hydrogen stream suitable for recycle to the hydrodesulfurization reaction zone and a sour gas stream comprising hydrogen sulfide and low boiling hydrocarbons. To allow effective separation into desired components, the reaction zone effluent is preferably separated into a first liquid fraction and a first vapor fraction in a hot separation zone at a temperature of from about 400 to about 500 F. and a pressure of about 400 to about 1100 p.s.i.g. Under such conditions the liquid portion may be separated from the vapor portion of said reaction effluent. Water may be injected into the hydrodesulfurization effluent stream to prevent deposition of solid salts in process equipment. Under conditions of lower temperature and pressure, such water in combination with heavy gas-oils tends to foam. Such foaming prevents an effective separation of the first liquid fraction from the first vapor fraction.

The first vapor fraction is partially condensed by cooling to a temperature of from about to about 120 F. at a pressure of about 380 to about 1080 p.s.i.g. Condensate formed and noncondensed vapors comprising hydrogen are separated in a cold separation zone into a second liquid fraction and a hydrogen stream. The hydrogen stream from the cold separation zone may be treated in a hydrogen treating zone to remove hydrogen sulfide therefrom. The treated hydrogen stream, substantially free of hydrogen sulfide, recovered from the hydrogen treating zone may be recycled to the hydrodesulfurization reaction zone for reaction with additional amounts of sulfur containing gas-oil hydrocarbons. Preferably a portion of the recycle hydrogen stream is vented to remove low boiling hydrocarbons from the system and thereby maintain the recycle hydrogen at a desirable purity. Fresh hydrogen may be added to the recycle hydrogen stream to make-up for hydrogen consumed in the hydrodesulfurization reaction and for hydrogen vented from the process.

-Hot separation zone liquid fraction and cold separation zone liquid fraction comprise gas-oil hydrocarbons, naphtha boiling below about 600 F., pentane and lighter hydrocarbons, hydrogen, and hydrogen sulfide. Such liquid fractions may be treated in a stripping zone to separate a gas-oil hydrocarbon substantially free of hydrogen sulfide and low boiling hydrocarbons. Conventionally such separation is affected in a stripping zone wherein the liquid fractions are contacted with a stripping vapor, such as steam, to vaporize the hydrogen sulfide and low boiling hydrocarbons. The hydrogen sulfide, low boiling hydrocarbons, and stripping vapor are recovered as an overhead product vapor and gas-oil, substantially free of hydrogen sulfide, is recovered from the stripping zone as a bottoms liquid product. Bottoms liquid product from the stripping zone may be fractionated in a fractionation zone into desirable fractions such as for example a gas-oil fraction suitable for low sulfur fuels blending or for charge to a fluidized catalytic cracking retction and a naphtha-kerosine fraction comprising hydrocarbons boiling in the range of from about to about 500 F.

In the stripping zone, operating conditions are maintained such that substantially all hydrogen sulfide and the major portion of pentane and lighter hydrocarbons are vaporized for recovery as components of the overhead vapor stream. Commonly the temperature in the bottom of the stripping zone is maintained at about the bubble point temperature of the gas-oil hydrocarbon in order to obtain disengagement of hydrogen sulfide and low boiling hydrocarbons from the liquid hydrocarbon fractions charged to the stripping zone. Preferably, the temperature in the stripping zone is maintained below about 650 F., above which temperature substantial thermal cracking of gas-oil hydrocarbons may occur. Consequently, to maintain gas-oil bubble point temperatures below about l650" F., stripping zone pressures in the range of from about 20 p.s.i.g. to about 5() p.s.i.g. are normally utilized. Control of operating temperatures in the stripping zone below about `650 F. prevents substantial thermal cracking of the hydrocarbon.

Stripping vapors are provided to the stripping zone to lower the partial pressure of hydrogen sulfide and low boiling hydrocarbons sufficiently to allow such material to vaporize and be separated from the gas-oil hydrocarbons. Commonly, steam is employed as a stripping vapor, although other stripping vapors such as hydrogen or methane may also be used. Relatively large volumes of stripping vapors are required in the stripping zone, therefore steam is preferred as a stripping vapor since it may be condensed from the stripping zone vapor efiiuent and removed from the system. When noncondensable stripping vapors such as hydrogen or methane are employed, these noncondensable vapors must be processed along with the separated hydrogen sulfide and low boiling hydrocarbons. In order to dispose of the vapors from a stripping zone, such as to a sulfur recovery unit or to a fuel system, it is often necessary to compress such vapors to a pressure suiciently high to allow entry into the selected disposal system. Large amounts of noncondensable stripping vapors add substantially to expense of compression as well as adding to the total vapor which must be treated.

When steam is employed as stripping vapor and is condensed for separation from the overhead gas stream, the condensed steam and hydrogen sulfide combine to form an acid. The presence of such acid, particularly in the top of the stripping zone and in related overhead vapor recovery piping, requires that materials of construction such as nickel alloys be employed which are resistant to corrosion by such acid. Such corrosion resistant materials add to the expense of constructing a stripping zone and related overhead vapor recovery piping.

SUMMARY OF THlE INVENTION Now according to the present invention, an improved method is disclosed for separating a hydrodesulfurization reaction efiuent into a gas-oil fraction, a recycle hydrogen fraction and a vapor fraction comprising hydrogen sulfide and low boiling hydrocarbons. The improvement of the present invention comprises recycling a liquid naphtha fraction boiling in the range of about 100 F.- 600 F., from a fractionation zone to a hot separator vapor stream in a weight ratio of recycled oil to vapor of from about 1.1 to 1 to about 0.5 to l; and stripping hydrogen sulfide and low boiling hydrocarbons from a hot separator liquid fraction `in a stripping zone at a pressure of from about 100 p.s.i.g. to about 130 p.s.i.g. employing a slip stream of hydrogen sulfide free recycle hydrogen.

One advantage of the present invention is the recycled naphtha absorbs low-boiling hydrocarbons, resulting in an increased purity of recycle hydrogen. Another advantage is the stripper may be operated at a pressure suiciently high to allow entry of overhead vapors without compression into subsequent treating facilities such as sulfur recovery units. The stripping zone may be operated substantially free of water such that the hydrogen sulfide containing overhead vapor is substantially less corrosive than a similar wet vapor. Such dry overhead vapors allows use of less expensive materials, such as carbon steel, in the construction of the stripping zone and related overhead piping. These and other advantages will be more fully described in the detailed description of the invention which follows.

'4 BRIEF DESCRIPTION OF THE DRAWING The attached drawing is a schematic flow diagram of a process for hydrodesulfurizing a gas-oil range hydrocarbon, which process embodies the improvement of the present invention.

DETAILED DESCRIPTION OF THE INVENTION Within the contemplation of the present invention a gas-oil hydrocarbon boiling in the range of from about 600 F. to about l100 F. is subjected to a hydrodesulfurization reaction with molecular hydrogen in a ratio of hydrogen to gas-oil from about 2000 to about 2400 standard cubic feet per barrel, at a temperature of from about `600 to about 800 F. and a pressure of from about 500 to about 1200 p.s.i.g. in the presence of a hydrodesulfurization catalyst. Such hydrodesulfurization reactions are well known and need not be discussed further herein.

Efliuent from the hydrodesulfurization reaction comprises gas-oil hydrocarbons, naphtha range hydrocarbons, pentane and lighter hydrocarbons, hydrogen and hydrogen sulfide. Preferably the reaction mixture is passed into a hot separation zone wherein the reaction mixture is separated into a vapor fraction and a liquid fraction. According to the method of the present invention, hot separator vapor is combined with a recycle stream recovered from a fractionation zone as will hereinafter be described. The mixture of hot separator vapor and recycle naphtha is passed into a condensing zone wherein the mixture is partially condensed. From the condensing zone, condensate and noncondensed vapor pass into a cold separation zone. The recycled naphtha serves in the condensing zone and the cold separation zone as sponge oil to absorb a portion of the hydrocarbons, such as butanes and pentanes, from the noncondensed vapor. In the separation methods of the prior art, these hydrocarbons remain in the vapor phase thereby reducing the purity of hydrogen in the hydrogen recycle stream.

In the coldy separation zone, condensate is separated from the noncondensed vapors. Noncondensed vapors are recovered and treated for the removal of hydrogen sulfide. A treated hydrogen stream comprising hydrogen and low boiling hydrocarbons is recovered from the hydrogen sulfide removal step. The major portion of this treated hydrogen stream is recycled to the hydrodesulfurization zone for reaction with additional gas-oil hydrocarbons. Fresh hydrogen may be added to the recycle hydrogen stream to make up for hydrogen consumed in the hydrodesulfurization reaction and for hydrogen removed from the process as will hereinafter be described.

A minor portion of the treated hydrogen stream is vented, removing low boiling hydrocarbons from the hydrodesulfurization process and maintaining hydrogen purity in the recycle hydrogen stream at a desired value. Another minor portion of the recycle stream is employed as stripping vapor in a stripping zone as will hereinafter be further described.

Cold separation zone liquid phase and hot separation zone liquid phase are charged into a stripping zone. Recycle naphtha entering the stripping zone with cold separation zone liquid, serves to lower the boiling point temperature of the liquid mixture in the stripping zone. The stripping zone is operated at from about p.s.i.g. to about p.s.i.g. pressure and at about the bubble point temperature of the liquid in the stripping zone. Preferably, sufficient recycle naphtha is charged to the stripping zone to reduce the bubble point temperature of the stripper bottoms liquid to about 600 F. or below, thereby substantially preventing thermal cracking of the gas-Oil hydrocarbons present in the stripping zone.

A A slip stream of treated hydrogen stream, comprising hydrogen and low boiling hydrocarbons, is employed as stripping vapor in the stripping zone. Such stripping vapor reduces the partial pressure of hydrogen sulfide and low boiling hydrocarbons such as pentane and lighter hydrocarbons thereby allowing such compounds to vaporize and separate from the gas-oil hydrocarbons. The stripping vapor, hydrogen sulfide, and low boiling hydrocarbons are recovered from the stripping zone as a stripper overhead vapor stream and are removed from the hydrodesulfurization process for further treating. By employing treated hydrogen as stripping vapor, the stripping zone may be operated in the substantial absence of water thereby substantially decreasing the corrosive eiect of hydrogen sulfide. Consequently, the stripping zone and related overhead piping may be constructed of relatively inexpensive carbon steel. lFrom the bottom of the stripping zone a liquid fraction comprising gas-oil and naphtha boiling range hydrocarbons, substantially free of hydrogen sulfide, is passed into a fractionation zone. In the fractionation zone the stripping zone bottoms liquid fraction is separated into a gas-oil fraction and a naphtha fraction. A portion of the naphtha fraction is recycled for combination with the hot separation zone vapor fraction as hereinbefore described. The gas-oil fraction is recovered for further processing such as conversion into gasoline in a uidized catalytic cracking process.

The method of the present invention may be better understood by reference to the attached drawing which illustrates one embodiment of the present invention. It is not intended to restrict the invention by the drawing since modifications -may be made by one skilled in the art which are within the spirit and scope of the appended claims.

In the drawing, 1,171,000 lbs. per hour of a gas-oil charge stock containing about 1.9% sulfur and boiling in the range of from about 500 to about 1100 F. in line 1 is mixed with 119,200 lbs. per hour of a hydrogen stream comprising about 81 mole percent hydrogen from line 2. The gas-oil hydrogen mixture passes via line 3 into a heater 4 wherein the mixture is heated to a temperature of about '690 F. From the heater 4 the heated gas-oil hydrogen mixture passes via line 5 into hydrodesulfurization reactor 6, which contains a hydrodesulfurization catalyst comprising cobalt and molybdenum supported upon a silica-alumina base. The operating conditions Within the hydrodesulfurization reactor 6 include a pressure of about 1,115 p.s.i.g., a temperature of about 705 F., a liquid hourly space velocity (LHSV) of about 1.0 volume of oil per hour per volume of catalyst, and a hydrogen to oil ratio of about 2,000 standard cubic feet per barrel (s.c.f./b). A hydrodesulfurization reaction effluent comprising gas-oil, naphtha, low boiling hydrocarbons, hydrogen, and hydrogen sulde at a rate of about 1,348,300 lbs. per hour passes from the hydrodesulfurization reactor 6 via line 7 into hot separator 8 at a temperature of 450 F. and a pressure of 1,033 p.s.i.g. In hot separator 8 the reaction efluent is separated into a liquid fraction and a vapor fraction. Vapor is recovered from the hot separator 8 via line 9 at a rate of 216,400 lbs. per hour and is combined with about 211,000 lbs. per hour of recycled naphtha via line 10. The recycle naphtha-vapor mixture passes via line 11 into partial condenser 12. From partial condenser 12 condensate and noncondensed vapor pass via line 13 into cold separator 14 wherein the condensate is separated from the noncondensed vapor. From cold separator 14 a vapor stream at a rate of 188,700 lbs. per hour passes via line 15 into amine absorber 16 whereinsubstantially all hydrogen sulde is separated from the vapor stream. Overhead from amine absorber 16, a treated hydrogen stream comprising about 78.85 mole percent hydrogen and substantially free of hydrogen sulde, is recovered via line 17 at a rate of about 169,300 lbs. per hour. From line 17 treated hydrogen is vented via line 18 at a rate of about 10,300 lbs. per hour to remove a portion of the low boiling hydrocarbons from the hydrodesulfurization process. Makeup hydrogen at a rate of about 18,750 lbs. per hour from line 19 is combined with the treated hydrogen stream in line 17. This mixed hydrogen stream passes into line Z from which it is combined with additional gas-oil charge stocks in line 3 as hereinbefore described.

Liquid from hot separator 8, at a rate of about 1,131,900 lbs. per hour, passes via line 20 into a hot surge drum 21 maintained at a temperature of 541 F. and a pressure of 210 p.s.i.g. Liquid from the hot surge drum 21 passes via line 22 into a heater 23 at a rate of 1,124,500 lbs. per hour, wherein the hot surge drum liquid is heated to a temperature of '642 F. From the heater 23, heated hot surge drum liquid passes via line 24 into line 26. Vapor from hot surge drum 21 at a rate of 7,200 lbs. per hour, passes via line 27 into line 26 wherein it is mixed with the heated hot surge drum liquid from line 24. The vapor stream rate in line 27 is adjusted to maintain the hot surge drum at 210 p.s.i.g. operating pressure. From line 26 the vapor-liquid mixture passes into the lower portion of a stripper 28.

Liquid from cold separator 14 at a rate of 238,700 lbs. per hour passes via line 29 into cold surge drum 30 maintained at a temperature of 111 F. and a pressure of 200 p.s.i.g. From cold surge drum 30 a liquid stream at a rate of 236,800 lbs. per hour passes via line 31 into the upper portion of the stripper 28. A vapor stream at a rate of 1,900 lbs. per hour passes from cold separator drum 30 via line 32 into stripper overhead vapor line 33. The vapor rate in line 32 is adjusted to maintain the desired operating pressure of 200 p.s.i.g. within cold surge drum 30.

From line 17 a slip stream of treated hydrogen at a rate of 4,020 lbs. per hour passes Via line 34 into heater 35 wherein the slip stream is heated to a temperature of 620 F. From heater 35, the slip stream passes via line 36 into the lower portion of stripper 28. In stripper 28, substantially all hydrogen sulde and low boiling hydrocarbons such as pentanes and lighter are vaporized. Naphtha and gas-oil hydrocarbons collect as a liquid in th'e bottom of stripper 28. Vapors comprising hydrogen, hydrogen sulde and low boiling hydrocarbons are recovered overhead from stripper 28 via line 33. Viapors from cold surge drum 30 are combined, via line 32, with stripper overhead vapors in line 33 as hereinbefore described. From line 33 the vapor mixture passes into condenser 37 wherein the vapor mixture is partially condensed. From condenser 37 condensate and noncondensed vapors pass via line 38 into stripper overhead receiver 39 wherein condensate is separated from the noncondensed vapors. From receiver 39 condensate is returned via line 40 as reflux to the top of stripper 28. Noncondensed vapors comprising hydrogen sulde, hydrogen, and low boiling hydrocarbons are recovered at a rate of 14,850 lbs. per hour from receiver 39 via line 41 from which such noncondensed vapors pass at a pressure of about 112 p.s.i.g. to further treatment, such as sulfur recovery not shown.

From the bottom of stripper 28, a liquid stream comprising -gas-oil hydrocarbon and naphtha hydrocarbon substantially free of hydrogen sulfide is recovered at a rate of 1,360,200 lbs. per hour via line 42. From line 42 the stripper bottoms liquid passes into heater 43 wherein the bottoms liquid are heated to a temperature of about 717 F. From heater 43 the heated bottoms liquid pass via line 44 into fractionator 4S wherein the bottoms liquid is separated into a gas-oil fraction and a naphtha fraction fboiling in the range of from about to about 500 F. An overhead vapor stream comprising naphtha is recovered from fractionator 45 via line 46 and is passed into condenser 47. From condenser 47, condensate and a small amount of noncondensed vapor pass via line 48 into fractionator overhead receiver 49. From overhead receiver 49 a noncondensed vapor stream comprising pentane and lighter hydrocarbons is vented via line 50 at a rate of about 500 lbs. per hour. A portion of the liquid from receiver 49 passes via line 51 as reflux to the top of fractionator 45. Naphtha product at a rate of 45,200 lbs. per hour is recovered from receiver 49 via line 52. A recycle 7 naphtha stream, recovered from receiver 49 via line 10 at a rate of 211,100 lbs. per hour, is combined with hot separator vapor in line 11 as hereinbefore described.

From the bottom of fractionator 45 a gas-oil stream substantially free of hydrogen suliide, containing less than 0.2% sulfur is recovered as a product at a rate of 1,103,500 lbs. per hour via line 53. From line 53 the gasoil product may be passed to other processing, such as catalytic cracking, not shown.

As will be apparent to those skilled in the art upon reading the foregoing disclosure, many modifications, substitutions, and changes are possible in the practice of this invention Without departing from the spirit and scope theory. Therefore, no limitations to the present invention are intended except those contained Within the spirit and scope of the appended claims.

We claim:

1. In a hydrodesulfurization process for removing sulfur from a gas-oil hydrocarbon which comprises treating a sulfur containing gas-oil with hydrogen at an elevated temperature and pressure in the presence of a hydrodesulfurization catalyst in a reaction zone, separating the reaction zone eiliuent into a first vapor fraction and a iirst liquid fraction under conditions of elevated temperature and pressure to prevent foaming of the first liquid fraction, partially condensing the rst vapor fraction into a hydrogen fraction and a second liquid fraction, treating the hydrogen fraction to remove HZS therefrom, recycling treated hydrogen to the reaction zone, and stripping HES and low boiling hydrocarbons from the rst liquid fraction and the second liquid fraction in a stripping zone; the improvement which comprises:

(A) Employing a slip stream of treated hydrogen as stripping gas in the stripping zone;

(B) Separating the stripped hydrocarbon liquid into a naphtha fraction and a gas-oil fraction; and

(C) Recycling at least a portion of the naphtha fraction to the rst vapor fraction condensing step.

2. The method of claim 1 wherein the stripping zone is operated at a pressure of from about p.s.i.g. to about p.s.i.g., and wherein sucient naphtha is recycled to lower the bubble point temperature of the liquid in the stripping zone to about 650 F. or less.

3. The method of claim 2 wherein the weight ratio of naphtha recycle to first vapor fraction is from about 1.1 to about 0.5.

References Cited UNITED STATES PATENTS 2,794,766 6/1957 Offutt 208-212 3,081,259 3/1963 Donovan et al. 208-216 3,362,903 1/1968 Eastman et al 208-143 3,637,485 1/1972 Salka 208-211 3,666,659 5/1972 Carlson et al. 208-208 R DELBERT E. GANTZ, Primary Examiner J. W. HELLWEGE, Assistant Examiner U.S. Cl. X.R.

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