Cost Effective Deoxygenation Process With Gas Recycle

Abstract

The present disclosure relate to a process plant and a method for production of a hydrocarbon mixture from a feedstock stream comprising oxygenates and a make-up hydrogen gas stream, involving directing a feed stream, comprising the feedstock stream comprising oxygenates, the make-up hydrogen gas stream and a hydrogen rich gas stream, to contact a material catalytically active in deoxygenation under active deoxygenation conditions and withdrawing a deoxygenated product stream, characterized in the hydrogen rich gas stream comprising at least 70 vol % hydrogen, at least 0.1 vol % carbon oxides and at least 50 ppm.sub.vol H.sub.2S, with the associated benefit that such a method, where carbon oxides are allowed to be present may be realized without requiring a step of purifying said recycled hydrogen rich gas stream, e.g. by use of an amine wash.

Claims

1. A method for production of a hydrocarbon mixture from a feedstock stream comprising oxygenates and a make-up hydrogen gas stream, comprising the steps of directing a feed stream, comprising the feedstock stream comprising oxygenates, the make-up hydrogen gas stream and a hydrogen rich gas stream, to contact a material catalytically active in deoxygenation under active deoxygenation conditions and withdrawing a deoxygenated product stream, wherein the hydrogen rich gas stream comprising at least 70% hydrogen, at least 0.1% carbon oxides and at least 50 ppm H.sub.2S.

2. A method according to claim 1, wherein the hydrogen rich gas stream comprising at least 0.1% carbon dioxide.

3. A method according to claim 1, wherein the hydrogen rich gas stream comprising at least 0.1% carbon monoxide.

4. A method according to claim 1, wherein said feedstock stream comprising oxygenates, comprises a fresh feedstock rich in oxygenates and a diluent, said diluent being a further feedstock or a recycled liquid stream.

5. A method according to claim 4, wherein said liquid diluent comprising less than 0.1 wt % atomic oxygen.

6. A method according to claim 4, wherein said liquid diluent comprises an amount of said deoxygenated product stream or comprises an amount of a product from a process step receiving an amount of said deoxygenated product stream.

7. A method according to claim 4, wherein said liquid diluent being a stream comprising fossil feedstock.

8. A method according to claim 1, wherein the amount of sulfur contained in said hydrogen rich gas stream relative to the amount of sulfur in the gas phase of the combined feed stream is at least 40%.

9. A method according to claim 1, wherein said material catalytically active in deoxygenation comprising molybdenum and/or nickel, on a support of refractory material and comprising less than 0.1 wt % cobalt.

10. A method according to claim 1, wherein at least an amount of said deoxygenated product stream being directed to contact a material catalytically active in hydrocracking and/or hydroisomerization under active hydrocracking and/or hydroisomerization conditions and withdrawing a further treated product stream.

11. A method according to claim 1, wherein said deoxygenated product stream or said further treated product stream is separated in a gas stream and a liquid stream, and wherein said hydrogen rich gas stream comprises a recycled amount of said gas stream.

12. A method according to claim 1, wherein less than 50 vol % of the carbon oxides in the recycled amount of said gas stream are removed prior to the recycled amount of said gas stream being directed to contact said material catalytically active in deoxygenation.

13. A method according to claim 12, wherein said carbon oxides are removed from the gas stream by a process involving membrane separation or by withdrawal of a purge gas stream.

14. A method according to claim 12, wherein said removal of carbon oxides does not involve scrubbing of the gas stream.

15. A process plant section for conversion of a feedstock stream comprising oxygenates to a hydrocarbon mixture, comprising a deoxygenation reactor having an inlet and an outlet, a separation section having an inlet and a gas outlet, an aqueous phase outlet and a hydrocarbon phase outlet, wherein said deoxygenation reactor inlet is configured for receiving said feedstock and a recycled hydrogen rich gas stream, said separator is configured for receiving a deoxygenated product stream from said deoxygenation reactor outlet, and the separation section gas outlet is configured for providing said recycled hydrogen rich gas stream, wherein said process plant section not comprising an amine scrubber configured for treating the stream of the separation section gas outlet.

Description

[0038] FIG. 1 shows a process layout according to the present disclosure.

[0039] FIG. 2 shows a process layout according to the prior art.

ELEMENTS SHOWN IN THE FIGURES

[0040] 2 Feedstock stream comprising oxygenates [0041] 4 Hydrogen rich gas [0042] 6 Combined feed stream [0043] 8 Deoxygenated product stream [0044] 10 Aqueous liquid stream [0045] 11 Hydrocarbon liquid stream [0046] 12 Gas stream [0047] 14 Lean amine solution [0048] 16 Rich amine solution [0049] 18 Purified gas stream [0050] 20 Purge gas stream [0051] 22 Hydrogen rich recycle gas stream [0052] 24 Make-up hydrogen stream [0053] 26 Sulfide source [0054] HDO Deoxygenation reactor [0055] SEP Separation section [0056] COMP Recycle compressor [0057] ABS Amine absorber

[0058] In FIG. 1, a process with recycle of gas, with a purge, and no other intermediate removal of carbon oxides is shown. Here a feedstock stream comprising oxygenates (2) is combined with a hydrogen rich gas stream (4), and directed as a combined feed stream (6) to a deoxygenation reactor (HDO). Often the combined feed stream (6) may be combined with an amount of a hydrocarbon mixture, which may be recycled product, or added hydrocarbon, such as a fossil feedstock. The deoxygenation reactor operates under deoxygenation conditions, such as 30-150 barg pressure, 250-400 C and gas/oil ratio of 500-2000 Nm3/m3, with a typical conversion of 90-100% of oxygenates to hydrocarbons, water and CO.sub.2. From the deoxygenation reactor (HDO) a deoxygenated product stream (8) is withdrawn and directed to a separation section (SEP), which may be a single flash separator, a stripping column, or a train of separators. From the separation section (SEP) at least a liquid stream (11) and a gas stream (12) are withdrawn. Optionally an aqueous (10) and a non-aqueous liquid stream (11) are withdrawn, since water is a significant product of the deoxygenation process. The gas stream (12) is optionally split in a purge gas stream (20) and hydrogen rich gas stream, which is pressurized in a recycle compressor (COMP). An amount of make-up hydrogen (24) is typically added to the hydrogen rich gas stream (22), and a sulfide source (26) is typically added to the feedstock stream comprising oxygenates (2), but the latter may be avoided if the gas recycle is sufficient to concentrate a moderate amount of sulfur in the feed (2).

[0059] During a catalyst cycle, an amount of carbon oxides and light hydrocarbons such as methane may build up in the hydrogen rich gas stream (22), and therefore, especially towards end of run purge may be withdrawn, or the amount of purge may be increased.

[0060] In a further embodiment, the process layout may include further process elements. This may include a pre-treatment section separating oxygenates from raw biological material, by chemical and or mechanical treatment. It may also include a pre-hydrogenation section, in which selected chemical conversions are carried out under specific conditions, e.g. hydrogenation of olefins at low temperatures. The process layout may also include a hydrocracking and/or an isomerization section, which may involve a sulfided or a reduced catalytically active material. If the catalytically active material is sulfided, the section may typically be placed between the deoxygenation reactor (HDO) and the separation section (SEP), whereas, if it is reduced, it will placed downstream the separation section (SEP), and receive purified hydrogen.

[0061] In FIG. 2, a process with recycle of hydrogen and amine absorber in the gas loop is shown. Again, a feedstock stream comprising oxygenates (2) is combined with a hydrogen rich gas stream (4), and directed as a combined feed stream (6) to a deoxygenation reactor (HDO). From the deoxygenation reactor (HDO) a deoxygenated product stream (8) is withdrawn and directed to a separation section (SEP), which may be a single flash separator, a stripping column, or a train of separators. From the separation section (SEP) at least a liquid stream (11) and a gas stream (12) are withdrawn. Optionally an aqueous (10) and a non-aqueous (11) liquid stream are withdrawn. The gas stream (12) is directed to an amine absorber (ABS) or another means of selective separation, withdrawing one or more of CO, CO.sub.2 and H.sub.2S. If the means of selective separation is an amine absorber, a stream of lean amine solution (14) is directed to the absorber, and a rich amine solution (16), comprising amines and CO.sub.2 and H.sub.2S is withdrawn. A purified gas stream (18) is withdrawn from the amine absorber (ABS) and optionally split in a purge gas stream (20) and hydrogen rich gas stream, which is pressurized in a recycle compressor (COMP). An amount of make-up hydrogen (24) is typically added to the hydrogen rich gas stream (22), and a sulfide source (26) is added to the feedstock stream comprising oxygenates (2).

[0062] In this layout, carbon dioxide will not build up in the hydrogen rich gas stream (22), but a purge may be required to remove other impurities, including CO, especially towards end of run purge may be withdrawn, or the amount of purge may be increased.

Examples

[0063] Experiments were carried out to evaluate the performance of a hydrogenation process in which CO was present.

[0064] Experiment 1 evaluates hydrogenation activity by comparing desulfurization of a pure fossil gasoil with desulfurization of a combined feedstock, comprising 85% gasoil and 15% rapeseed oil, over a catalytically active material, comprising 3.4% cobalt and 15% molybdenum, supported on alumina. The composition of the feedstocks can be seen in Table 1, and the conditions of the experiment in Table 2.

[0065] Pure Hydrogen was used as treat-gas in the test. The experiment showed active hydrogenation (desulfurization was 99.0%) for fossil gasoil, but for the combined feedstock under the same conditions, hydrogenation activity was low (desulfurization activity was only 93.6%).

[0066] Experiment 2 investigates the reason for the low hydrogenation activity, for the combined feedstock, by varying the concentration of CO, with the experimental conditions of Table 3. The experimental results in Table 4 shows that the hydrogenation activity decreases significantly with the presence of CO, with a sulfur level in the product of 645 ppm.sub.wt, when 1% CO was present, vs a sulfur level in the product of 167 ppm.sub.wt, in the absence of CO.

[0067] Experiments 1 and 2 confirm the assumption in the field, that recycle of treat gas requires efficient removal of CO, to avoid poisoning of the catalyst.

[0068] However, further experiments were carried out, based on the same feedstocks, but a different catalytically active material, comprising 2.9% nickel and 15.5% molybdenum, supported on alumina. Experiment 3 evaluates hydrogenation activity by comparing desulfurization of a pure fossil gasoil with desulfurization of a combined feedstock, comprising gasoil and rapeseed oil, over a nickel/molybdenum catalyst, at the conditions shown in Table 5. Pure Hydrogen was used as treat-gas in the test. The experiment showed active hydrogenation (desulfurization was 99.1%) for fossil gasoil, and surprisingly similar hydrogenation activity (desulfurization was 99.4%) was found for combined feedstock.

[0069] Experiment 4 investigates the influence of CO on hydrogenation activity, by varying the concentration of CO. The results of the experiment in Table 6 shows that the hydrogenation activity is only slightly decreased with the presence of CO, with a sulfur level in the product of 434 ppm.sub.wt, when 1% CO was present, vs. a sulfur level in the product of 300 ppm.sub.wt, in the absence of CO.

[0070] Based on Experiments 1-4 it may be concluded that presence of CO is acceptable for nickel/molybdenum catalyst, and thus that this material is preferred for feedstocks rich in oxygenates and treat gases comprising CO. Considering this robustness, a process with recycle of treat gas may be carried out without requiring highly efficient removal of CO.

[0071] An analysis of the investment and operation cost for the process layouts according to FIG. 1 and FIG. 2 shows an approximate 10% investment saving and an approximate 5% operational saving, which naturally is highly relevant.

TABLE-US-00001 TABLE 1 Gasoil Gasoil/Rapeseed oil Sulphur, wt % 1.28 1.04 Hydrogen, wt % 13.1 12.9 SG 60/60° F. 0.8554 0.8647 Nitrogen, wtppm 180 169 Aromatics, wt % 26.96 25.89 Mono-aromatics, wt % 15.36 13.25 Di-aromatics, wt % 9.56 8.55 Tri aromatics+, wt % 2.04 4.09 Sim. Dist. D-2887XC IBP 132 137 10 wt %, ° C. 253 254 30 wt %, ° C. 286 287 50 wt %, ° C. 313 318 70 wt %, ° C. 345 356 90 wt %, ° C. 388 426 FBP wt %, ° C. 429 612

TABLE-US-00002 TABLE 2 Experiments 1A Experiments 1B Temperature, ° C. 350 350 Pressure, barg 45 45 LHSV, 1/h 1.5 1.5 H.sub.2/Oil, Nl/l 250 250 Feedstock Gasoil Gasoil/Rapeseed oil Product sulfur (wtppm) 127 696 Desulfurization 99.0% 93.6%

TABLE-US-00003 TABLE 3 Experiment 2 and 4 Feedstock Gasoil Pressure, barg 30 LHSV, 1/h 1.0 Treat gas composition 0-1 vol % CO, Balance with H2 Treat gas/Oil, Nl/l 250

TABLE-US-00004 TABLE 4 CO vol % Product sulfur (wtppm) Desulfurization 0 167 98.7% 0.1 223 98.3% 1 645 95.0%

TABLE-US-00005 TABLE 5 Experiments 3A Experiments 3B Temperature, ° C. 350 350 Pressure, barg 45 45 LHSV, 1/h 1.5 1.5 Treat gas composition 100 vol % H2 100 vol % H2 Treat gas/Oil, Nl/l 250 250 Feedstock Gasoil Gasoil/Rapeseed oil Product sulfur (ppm) 75 96 Desulfurization 99.4% 99.1%

TABLE-US-00006 TABLE 6 CO vol % Product sulfur (wtppm) Desulfurization 0 300 97.7% 0.01 326 97.5% 0.1 346 97.3% 1 434 96.6%