GB897664A - Purifying hydrocarbons - Google Patents

Abstract

<PICT:0897664/III/1> A two-stage catalytic hydrofining process for hydrocarbon feed materials, especially straight run hydrocarbon products of cracking operations such as gasoline, naphtha, kerosene, gas oil, cycle stocks, residual oils, and thermal and coker distillates, comprises passing the hydrocarbon feed together with hydrogen-rich gas in contact with a hydrogenation catalyst in the first stage, separating and recovering a higher boiling hydrocarbon product from a lower boiling product and the hydrogen rich gas stream, treating this gas stream to remove hydrogen sulphide, passing the treated gas stream with the lower boiling hydrocarbon product in contact with a hydrogenation catalyst in the second stage, thereafter separating the lower boiling product from the hydrogen-rich gas stream which is then treated to remove hydrogen sulphide once more and then used as the hydrogen-rich gas for the first hydrogenation stage. In the preferred embodiment shown, coker gas oil (boiling range 350 to 900 DEG F.) enters by line 2 and is mixed with hydrogen-rich recycle gas from line 4; the mixture passes to heat exchangers 6 and 10 before passing in two streams 14 and 16 to preheat furnace 18. Before passing to parallel desulphurization zones 28 and 30, the streams are mixed with additional hydrogen-rich gas fed in by lines 26 and 24. In catalytic treating zones 28 and 30, the pressure and temperature conditions are sufficient to effect both desulphurization and denitrogenation. The effluents pass by line 36, reboiler 38, line 40, heat exchangers 10 and 44, and line 46 to separator 48. In separator 48 the major portion of the naphtha boiling range constituents are separated, and pass together with gaseous hydrocarbons, hydrogen, ammonia and hydrogen sulphide by line 50, heat exchanger 52, cooler 56, and cooler 62 to separator 66, water being fed into the stream at 60. The gaseous stream is passed by line 68 to absorber tower 70 to remove hydrogen sulphide, e.g. with diethanolamine, the purified hydrogen-rich gas then passing to knock-out drum 74 before introduction to the feed material by line 4. The water phase is removed from separator 66 by line 94 while the main naphtha stream passes to separator 88, together with the minor naphtha stream from line 86. A gaseous fraction is removed at 96 for recovery (not shown) while the main stream passes by line 98, heat exchanger 52 and line 100 to fractionator 102. The gas oil-rich fraction from separator 48 meanwhile passes by line 80 to separator 84, where naphtha is separated for return to the main naphtha stream by line 86 as already described, the main gas oil stream passing by line 104, heat exchanger 106 and line 108 to fractionator 102 which is heated by circulating a fraction from the lower part of the tower by line 110 to reboiler 38 and back by line 112. Desulphurized gas oil leaves the base of fractionator 102 by line 114 and passes to recovery through heat exchangers 106 and 6, and cooler 120. The naphtha product leaves fractionator 102 by line 124 and together with water introduced at 126 passes through cooler 128 to separator 132. From separator 132 a gas stream is removed by line 134 and a water fraction by line 136; a portion of the naphtha fraction is recycled to fractionator 102 by line 138, while the rest passes by line 142, heat exchanger 146, and line 148 to the second desulphurization zone 150. Prior to entry thereto, the naphtha is mixed with a mixture of coker naphtha introduced at 152 and hydrogen-rich gas introduced at 154 which are passed by line 156, heat exchanger 158, line 160, and furnace 162. The effluent from zone 150 passes through heat exchangers 158 and 146, and coolers 172 and 176 to separator 180, water being fed into the stream at 182. A water-fraction is withdrawn from 186, and the naphtha fraction from 184, while the hydrogen rich gas stream passes by line 188, heat exchanger 44, and lines 26 and 24 to be mixed with the feed to desulphurization zones 28 and 30. If preferred however, because of a high hydrogen sulphide content therein, the gas stream in line 188 may be combined with that in line 68 and passed to absorber tower 70, in which case the gases in line 4 are passed through heat exchanger 44 and then combined with oil feed in line 8; alternatively, only a portion of the gas in line 4 is passed to exchanger 44 and thence by line 26 to the desulphurization zone, while the rest is combined with feed in line 2 as before. Usually the second desulphurizing zone is maintained at a higher pressure than the first. Suitable catalysts include the oxides and/or sulphides of Group VI metals, especially molybdenum trioxide or trisulphide, chromia, or tungsten sulphide either alone or supported on a suitable carrier, e.g. alumina, silica-alumina, magnesia, fuller's earth, kieselguhr, pumice or bentonite, and many include as promoter an oxide and/or sulphide of iron, cobalt or nickel. In general the catalytic agent comprises 0,1 to 25% by weight of the catalyst, and the promoter 1 to 10% by weight. To enhance heat stability, silica may be present in the catalyst in amounts of 0,5 to 12% by weight.