Direct oxidation of hydrogen sulfide in a hydroprocessing recycle gas stream with hydrogen purification

Abstract

A process and system for treating a hydroprocessing unit effluent gas stream for recycling includes introducing the effluent gas stream into a hydrogen purification zone and recovering a hydrogen-rich gas stream and a liquid stream containing a mixture that includes C1 to C4 hydrocarbons and H.sub.2S which is then mixed with an oxidant and fed to an oxidation unit containing catalyst for conversion of the H.sub.2S to elemental sulfur vapors that is separated for recovery of the elemental sulfur, and recovering a sweetened mixture that includes C1 to C4 hydrocarbons. Alternatively, the hydroprocessing unit effluent gas stream containing H.sub.2S is cooled, contacted with a solvent to absorb the C1 to C4 hydrocarbons and H.sub.2S, with the hydrogen-rich stream being recovered for recycling to the hydroprocessing unit, and the rich liquid solvent being flashed to produce a lean solvent stream for recycling to the adsorption zone and a mixed gas stream that includes the C1 to C4 hydrocarbons and H.sub.2S that is passed to an oxidation zone and is reacted with an oxidant in the presence of a catalyst to complete the process as described above for the recovery of elemental sulfur and a mixture that includes the sweetened C1 to C4 hydrocarbons.

Claims

1. An integrated process for the treatment of a hydrocarbon hydrocracking unit recycle gas stream, the process comprising: a. mixing a sulfur-containing heavy hydrocarbon liquid feedstock with hydrogen gas to produce a combined feedstream and introducing the combined feedstream into a hydrocracking unit; b. hydrocracking the combined feedstream to produce a hydrocracking unit effluent stream; c. passing the effluent stream to a gas/liquid separator and removing a liquid effluent stream and a gaseous effluent stream from the separator; d. introducing the gaseous effluent stream into a hydrogen purification unit to produce a hydrogen-rich gas stream and a hydrogen-lean stream consisting essentially of a mixture of C1 to C4 hydrocarbons and H.sub.2S; e. mixing the hydrogen-lean stream consisting essentially of the mixture of C1 to C4 hydrocarbons and H.sub.2S with an oxidant to produce an oxidation unit feedstream; f. contacting the oxidation unit feedstream in a catalytic oxidation unit with a catalyst, wherein the catalyst is MgCr.sub.2O.sub.4 or Cu—Zn on an alumina support, to convert substantially all of the H.sub.2S to elemental sulfur and to produce an oxidation unit effluent stream comprising a sweetened mixture of C1 to C4 hydrocarbons and elemental sulfur vapors; g. condensing the sulfur vapors and recovering the elemental sulfur from the oxidation unit effluent stream; and h. recovering the sweetened mixture of C1 to C4 hydrocarbons from the oxidation unit.

2. The process of claim 1, wherein the hydrogen-rich gas stream of step (d) contains from 90 mol % to 99 mol % of hydrogen.

3. The process of claim 1, wherein the hydrogen purification unit is selected from the group consisting of an absorption unit, a pressure swing absorption unit, a membrane separation unit, a cryogenic unit, and combinations thereof.

4. The process of claim 3, wherein the hydrogen purification unit is an absorption unit.

5. The process of claim 1, wherein the oxidation unit is maintained at a temperature in the range of from 100° C. to 400° C.

6. The process of claims 1 and 5, wherein the oxidation unit is maintained at a pressure in the range of from 1 bar to 20 bar.

7. The process of claim 1, wherein the oxidant is air or oxygen or oxygen-enriched air.

8. An integrated process for the treatment of a hydrocracking unit hydrocarbon recycle gas stream, the process comprising: a. mixing a sulfur-containing heavy hydrocarbon liquid feedstock with hydrogen gas to produce a combined feedstream and introducing the combined feedstream into a hydrocracking unit; b. hydrocracking the combined feedstream to produce a hydrocracking unit effluent stream; c. separating the hydrocracking unit effluent stream in a gas/liquid separator into a hydrocracking unit effluent liquid stream and a hydrocracking unit effluent gas stream; cooling the hydrocracking unit effluent gas stream and recovering a cooled hydrocracking unit effluent gas stream; e. introducing the cooled hydrocracking unit effluent gas stream and a liquid solvent stream into an absorption zone to absorb a mixture comprising C1 to C4 hydrocarbons and H.sub.2S and produce a hydrogen-rich gas stream and a rich liquid solvent stream comprising a mixture of C1 to C4 hydrocarbons and H.sub.2S; f. recovering the hydrogen-rich gas stream for use as a recycle hydrogen gas stream; g. recovering and flashing the rich liquid solvent stream comprising the mixture of C1 to C4 hydrocarbons and H.sub.2S in at least one flashing zone to produce a lean liquid solvent stream and a second stream consisting essentially of a mixture of C1 to C4 hydrocarbons and H.sub.2S; h. mixing the second stream consisting essentially of the mixture of C1 to C4 hydrocarbons and H.sub.2S with an oxidant to produce an oxidation unit feedstream; i. oxidizing the oxidation unit feedstream in an oxidation unit in the presence of a catalyst, wherein the catalyst is MgCr.sub.2O.sub.4 on an alumina support or Cu—Zn on an alumina support, to convert substantially all of the H.sub.2S to elemental sulfur vapors and separating the elemental sulfur vapors from the hydrocarbon mixture consisting essentially of sweetened C1 to C4 hydrocarbons; j. recovering elemental sulfur vapors from the oxidation unit; and k. recovering the mixture consisting essentially of sweetened C1 to C4 hydrocarbons from the oxidation unit.

9. The process of claim 8, wherein the hydrogen-rich gas stream of step (e) contains from 90 mol % to 99 mol % of hydrogen.

10. The process of claim 8, wherein the oxidation unit is maintained at a temperature in the range of from 100° C. to 400° C.

11. The process of claims 8 and 10, wherein the oxidation unit is maintained at a pressure in the range of from 1 bar to 20 bar.

12. The process of claim 8, wherein the hydrocracking unit effluent gas stream is cooled to a temperature in the range of from −20° C. to 40° C.

13. The process of claim 8, wherein the solvent in step (e) comprises C4 and C5 hydrocarbons.

14. The process of claim 8, further comprising recycling the lean liquid solvent stream from step (g) for use in step (e).

Description

BRIEF DESCRIPTION OF THE DRAWINGS

(1) The invention will be described in further detail below and with reference to the attached drawings in which like numerals are used to refer to the same or similar elements, and where:

(2) FIG. 1, as noted above, is a simplified schematic illustration of a hydrocracking unit operation of the prior art that includes an amine stripping unit to remove H.sub.2S from the recycle stream;

(3) FIG. 2 is a plot depicting the effect of hydrogen sulfide present in the recycle gas expressed as a vol % on the activity of a hydrotreating catalyst as measured by the increase required in the reactor operating temperature;

(4) FIG. 3 is a simplified schematic illustration of an improved process in accordance with the present disclosure for a hydrocracking unit with hydrogen purification and sour gas oxidation; and

(5) FIG. 4 is a simplified schematic illustration of an embodiment in accordance with the present disclosure for a hydrocracking unit employing hydrogen purification by absorption and sour gas oxidation.

DETAILED DESCRIPTION OF PREFERRED EMBODIMENTS

(6) The process and system of the present disclosure will be described in additional detail with reference to an embodiments illustrated schematically in FIGS. 3 and 4. It will be noted that in FIGS. 3 and 4, the numbering system applied to the principal elements and streams is common, with the first digit corresponding to the respective figure number. In each figure, the exemplary embodiment is directed to a hydrocracking unit operation. However, it will be understood that the process and system has utility in other hydroprocessing unit operations where a recycle gas stream containing principally hydrogen is mixed with lower hydrocarbons and hydrogen sulfide that must be treated to purify the hydrogen for use in the recycle stream prior to its introduction with the make-up hydrogen stream into the recycle hydrogen compressor.

(7) Referring now to FIG. 3, the heavy hydrocarbon liquid feed containing sulfur compounds (306) is mixed with the compressed mixed hydrogen feed (362) and the mixed feed (308) enters the hydrocracking reactor (310) where the feed is catalytically hydrocracked to produce the hydrocracking unit effluent stream (312) which includes liquid hydrocarbons of reduced molecular weight and hydrocarbon gases including hydrogen, C1 to C4, and hydrogen sulfide. Depending upon the geographical source of the unprocessed heavy hydrocarbon feed, the sulfur can range from a low of about 0.1 W % for sweet crude oil and up to 6 W % for extremely sour crude oils.

(8) A hydrocracked product stream (322) is recovered from the HP gas/liquid separator and sent to a fractionating zone (not shown) for recovery of end products. The gaseous effluent stream (324) from the HP separator (320) is passed to the absorption zone (330) for removal of the C1 to C4 compounds and the H.sub.2S which are discharged as an effluent stream (332). The purified hydrogen recycle gas stream (338) is recovered from absorption zone (330) and is mixed with the hydrogen make-up stream (364). The mixed hydrogen stream (366) is passed to the recycle gas compressor (360) from which the compressed mixed hydrogen stream (362) is introduced as mixed feed (308) into the reactor (310) with the heavy liquid hydrocarbon feed (306).

(9) With continued reference to FIG. 3, the hydrocarbon effluent stream (332) from the absorption zone (330) is mixed with an oxidant (334) and passed as a mixed reactant stream (336) into the catalyzed oxidation unit (350) where the hydrogen sulfide is converted to elemental sulfur stream (352) in vapor form that is separated from the remaining hydrocarbons that then pass as the sweetened hydrocarbon fuel stream (354).

(10) The oxidation zone (350) can be operated as a fixed bed or a fluidized bed reactor with a GHSV of about 3600/hr. The sulfur-to-oxygen ratio can be in the range of from 10:1, and preferably in the range of 4:1, with the preferred range of 2:1. The reactor can be operated at a temperature of up to 380° C., and preferably from 140° C. to 350° C., or 140° C. to 160° C., or 250° C. to 350° C., and at pressures ranging from 1-10 bars, or 1-5 bars, and preferably from 1-3 bars. The hot sulfur vapors are cooled for separation and removed from the oxidation zone (350) as elemental sulfur (352) in accordance with the prior art Claus process.

(11) As noted above, the oxidation of the H.sub.2S takes place well above the dew point of the elemental sulfur produced and the downstream treatment includes the steps of the separation of the sulfur from the sweetened fuel gas and the condensation of the gaseous elemental sulfur into a molten or solid form in accordance with methods and employing apparatus that is known in the art.

Example 1

(12) An effluent gas stream from a hydrocracking unit HP hot liquid/gas separator containing 67 V % of hydrogen is passed to an absorption column to remove methane, heavier hydrocarbons, and hydrogen sulfide. The sour bottoms containing methane and heavier hydrocarbons, and hydrogen sulfide are sent to an oxidation zone to remove the hydrogen sulfide and produce elemental sulfur. The process increases hydrogen purity from 67 V % to 89 V %. The operating conditions for Example 1 are provided in Table 1 below.

(13) TABLE-US-00001 TABLE 1 Variable\Vessel Units 430 440 450 Temperature ° C. min/max −1/−18 0/14 100/350 Pressure Bar min/max 50/200 50/200  1/10 LHSV h.sup.−1 1  0.5 Residence Seconds 0.8 Time Solvent/Oil Lt/Kg- 41.6 Ratio mol O.sub.2/S ratio Mol/Mol 1.5 GHSV h.sup.−1 min/max 1000/5000  1000/5000  1000/5000

(14) Reference is now made to the embodiment of FIG. 4 in which the initial process steps correspond to those described in connection with FIG. 3. The liquid heavy hydrocarbon feed containing sulfur compounds (406) is mixed with the compressed mixed hydrogen feed (462) and the mixed feed (408) enters the hydrocracking reactor (410) where the feed is catalytically hydrocracked to produce the hydrocracking unit effluent stream (412) which is comprised of liquid hydrocarbons of reduced molecular weight and hydrocarbon gases, including C1 to C4, hydrogen and hydrogen sulfide. The effluent (412) is passed to HP hot gas/liquid separator (420).

(15) A hydrocracked liquid hydrocarbon product stream (422) is recovered from the HP separator (420) and sent to a fractionating column (not shown) for recovery of end products. The gaseous effluent stream (424) from the HP separator (420) is passed to the liquid hydrocarbon absorption zone (430) the operation of which will be described in more detail below for removal of the C1 to C4 compounds and the H.sub.2S which are discharged as absorbent-rich solvent effluent stream (432). Heat exchange and cooling is required of the hot effluent stream (424) which can be at a temperature of from 200° C. to 260° C. Cooling can be by a combination of ambient air and water cooled heat exchangers, in combination with cryogenic coolers. The purified hydrogen recycle gas stream (438) is recovered from absorption zone (430) and is mixed with the hydrogen make-up stream (464). The mixed hydrogen stream (466) is passed to the recycle gas compressor (460) from which the compressed mixed hydrogen stream (462) is introduced as mixed feed (408) into the reactor (410) with the heavy liquid hydrocarbon feed (406).

(16) The rich hydrocarbon solvent (432) is passed to flashing zone (440) to separate the solvent compounds for recovery as recycle stream (446) for return to the solvent absorption zone (430). The C1 to C4 compounds and hydrogen sulfide (442) are recovered and are passed from the flashing zone (440) to the catalyzed gaseous oxidation zone (450). An oxidant, e.g., air (444) is mixed with the compounds (442) recovered from the flashing zone (440) and introduced into the catalyst bed contained in the gaseous oxidation zone (450), where the H.sub.2S is directly oxidized to elemental sulfur in a gaseous form which is then cooled and condensed into at least a liquid form (452) for recovery. With the H.sub.2S converted into elemental sulfur the remaining sweetened hydrocarbons (454) are recovered for use as a refinery fuel and/or for further downstream processing, e.g., steam cracking to obtain additional value added products such as ethylene, propylene and butenes.

(17) The material balance for the absorption and direct oxidation steps is set forth below in Table 2. Continuing reference is made to the flow diagram of FIG. 4 in connection with the following description of Table 2, which represents the material balance data for each of the streams beginning with the sour gas stream (424) that is introduced into the absorption zone (430). Note that the element numbers for each of the seven (7) streams identified in FIG. 4 appears in sequence in the first row of Table 2 and that a short description for each stream appears in the second row of Table 2 below its corresponding element number. The conditions of Temperature, Pressure and Density, where relevant, are provided for the respective streams in the third, fourth and fifth rows. The constituents comprising the streams are entered in the first column on the left side of Table 2 under the heading “Composition”. The bottom row entries represent the totals as measured in Kg/H for each of the constituents listed above.

(18) It is noted that each of the values for the C1 to C5 alkanes, and the value for the combined C6 and C7 compounds in the sour gas stream (442) is the same following their recovery in the sweetened fuel stream (454). The value for the elemental sulfur (452) recovered from the oxidation zone (450) is consistent with the original value for hydrogen sulfide in the sour gas stream (442), reduced by the hydrogen sulfide that passed with the sweetened hydrogen recycle stream (438) that is required to maintain the hydroprocessing reactor catalyst in a sulfided state.

(19) TABLE-US-00002 TABLE 2 Material balance around absorption and oxidation steps Stream number 424 446 438 442 444 454 452 Stream Name MW Sour Solvent Sweet Sour Oxidant Sweet Sulfur Gas Gas Reject Fuel Temperature ° C. −17.7 −31.4 15.8 16.2 250 250 250 Pressure psig 700 1 670 5 1 5 1 Density Kg/L 626 Composition Oxygen Kg/h 32 0.0 0.0 0.0 0.0 585.8 0.0 0.0 H2 Kg/h 2 1942.3 0.0 1799.3 141.9 0.0 141.9 0.0 HYDROGEN Kg/h 34 1224.0 0.0 92.3 1131.7 0.0 0.0 1065.1 SULFIDE METHANE Kg/h 16 5739.6 0.0 1554.9 4009.9 0.0 4009.9 0.0 ETHANE Kg/h 28 444.5 0.0 42.8 384.0 0.0 384.0 0.0 PROPANE Kg/h 44 1040.0 0.0 94.1 839.4 0.0 839.4 0.0 I-BUTANE Kg/h 58 859.5 0.0 69.4 587.8 0.0 587.8 0.0 N-BUTANE Kg/h 58 426.8 0.0 32.2 259.3 0.0 259.3 0.0 PENTANE Kg/h 72 348.0 827.6 232.6 1565.2 0.0 1565.2 0.0 C6-C7 Kg/h 93 8.2 0.0 7.7 16.0 0.0 16.0 0.0 Total Kg/h 12032.9 827.6 3925.3 8935.2 585.8 7803.5 1065.1

(20) As previously noted, the active phase metals in oxide form are not catalytically active and must be sulfided to convert them into the active sulfide form. The following are simplified reaction schemes for some active phase metals in their oxide forms that are converted to sulfides.
1MoO.sub.3+H.sub.2+2H.sub.2S−>MoS.sub.2+3H.sub.2O  (1)
3NiO+H.sub.2+2H.sub.2S−>Ni.sub.3S.sub.2+3H.sub.2O  (2)
9CoO+H.sub.2+8H.sub.2S−>Co.sub.9S.sub.8+9H.sub.2O  (3)
1WO.sub.3+H.sub.2+2H.sub.2S−>WS.sub.2+3H.sub.2O  (4)

(21) For example, if it is predetermined that at least 1000 ppm of H.sub.2S is required to maintain the catalyst in the sulfide form, the concentration of H.sub.2S in the sweetened hydrogen recycle stream (438) will be controlled accordingly to meet this requirement.

(22) In an embodiment that will be described with reference to FIG. 4, one or more H.sub.2S sensors “S” (439) linked to a microprocessor (not shown) continuously or intermittently monitor the concentration of H.sub.2S in the recycle stream (438) leaving the hydrocarbon absorption zone (430). If the sensor “S” indicates an H.sub.2S concentration below the predetermined desired value, an automated three-way valve (441) controlled by signals from the microprocessor is opened to admit a predetermined flow of the gaseous effluent (442) containing H.sub.2S from the flashing zone (440) and pass the supplemental H.sub.2S feed (443) for mixing with the sweetened hydrogen recycle stream (438) upstream of the sensor “S” (439) monitoring the H.sub.2S concentration and, via a signal to the microprocessor, adjusts the automated three-way flow control valve (441) to maintain the predetermined desired H.sub.2S concentration introduced into the mixed hydrogen stream (466).

(23) The practice of the integrated refinery process of the present disclosure for the direct oxidation of hydrogen sulfide in a hydroprocessing recycle gas stream with hydrogen purification provides the following benefits:

(24) 1. hydrogen purity is increased by 22 V % which results in an increase in hydrogen partial pressure and improved conversion rates in hydrotreating and hydrocracking processes;

(25) 2. the recycle gas compressor efficiency is improved since the methane and other hydrocarbons separated as sour bottoms in the absorption step are not passed to the recycle gas compressor;

(26) 3. the hydrogen sulfide is converted to elemental sulfur and the installation and use of an amine column traditionally required for H.sub.2S absorption is eliminated; and

(27) 4. a sweetened fuel stream that is substantially free of H.sub.2S is recovered for use as a fuel in the refinery or for further processing.

(28) The improved process and system have been described above and in the attached drawings from which modifications and variations will be apparent to one of ordinary skill in the art and the scope of the invention is to be determined by the claims.