PROCESS FOR PURIFICATION OF HYDROCARBONS

Abstract

Processes and equipment for purification of a sour hydrocarbon mixture or a gas mixture including hydrocarbons and sour gas, at least including the steps of directing the gas mixture to contact an absorbent liquid having affinity for sour gas, providing a purified off-gas mixture, directing the purified off-gas mixture to contact a liquid hydrocarbon mixture, providing an enriched liquid hydrocarbon mixture, with the associated benefit of such a process having a high recovery of hydrocarbons from the gas mixture to the enriched liquid hydrocarbon mixture, while being efficient in removing hydrogen sulfide from the gas mixture. The gas mixture to be purified may either be a natural gas, a fuel gas or an intermediate gas stream, e.g. from naphtha, kerosene, diesel or condensate hydrotreatment or hydrocracking, and it may also include further constituents, typically hydrogen.

Claims

1. A process for purification of a sour hydrocarbon mixture, comprising the steps of a. directing said sour hydrocarbon mixture to a means of separation, optionally a stripper, providing a liquid hydrocarbon fraction and a gas mixture, b. directing the gas mixture to contact an absorbent liquid having affinity for sour gas, providing a purified off-gas mixture, c. directing the purified off-gas mixture to contact a liquid hydrocarbon mixture, providing an enriched liquid hydrocarbon mixture.

2. A process for purification of a sour hydrocarbon mixture according to claim 1, wherein said liquid hydrocarbon mixture has a temperature in the range from 30 C. to 70 C., when contacted with said gas mixture.

3. A process for purification of a sour hydrocarbon mixture according to claim 1, wherein said absorbent liquid having affinity for sour gas has a temperature in the range from 30 C. to 90 C. and a pressure in the range of atmospheric to 30 barg.

4. A process for purification of a sour hydrocarbon mixture according to claim 3, wherein said absorbent liquid comprises an amine, an inorganic base, an ionic liquid or a physical solvent, comprising one or more compounds taken from the group comprising methanol, dimethyl ethers of polyethylene glycol, propylene carbonate and n-methyl-2-pyrrolidone.

5. A process for purification of a sour hydrocarbon mixture according to claim 1, wherein said liquid hydrocarbon mixture comprises at least a part of said liquid hydrocarbon fraction.

6. A process for purification of a sour hydrocarbon mixture according to claim 1, wherein said sour hydrocarbon mixture comprises at least 30% by weight, boiling in the range from 30 C. to 200 C.

7. A process for purification of a sour hydrocarbon mixture according to claim 1, wherein said sour hydrocarbon mixture comprises at least 2% hydrocarbons by weight, boiling below 30 C.

8. A process for production of a purified hydrocarbon mixture from a heteroatomic hydrocarbon mixture, comprising the process steps for purification of a sour hydrocarbon mixture according to claim 1, wherein said heteroatomic hydrocarbon mixture is directed to contact a material catalytically active in hydrotreatment under hydrotreatment conditions, providing the sour hydrocarbon mixture.

9. A process for production of a purified hydrocarbon mixture according to claim 8, wherein said hydrotreatment conditions involve a temperature from 250 C. to 450 C., a pressure from 10 barg to 100 barg, and a liquid hourly space velocity from 0.5 m.sup.3/m.sup.3/h and wherein said material catalytically active in hydrotreatment comprises molybdenum or tungsten optionally in combination with cobalt or nickel and supported on a support comprising a support material.

10. A process for production of a purified hydrocarbon mixture according to claim 8 wherein said heteroatomic hydrocarbon mixture is a condensate oil, a feedstock comprising naphtha or a product from a hydrocracking process comprising naphtha.

11. A process unit for purification of a gas mixture comprising hydrocarbon and hydrogen sulfide comprising a sour gas absorber and an oil absorber, each having a gas inlet, a gas outlet, a liquid inlet and a liquid outlet, wherein the gas mixture is directed to the gas inlet of said sour gas absorber, and the gas outlet of said sour gas absorber is in fluid communication with said oil absorber gas inlet, and where said oil absorber liquid outlet provides an enriched liquid hydrocarbon mixture.

12. A process unit for purification of a sour hydrocarbon mixture, comprising a process unit according to claim 11, and a means of separation having an inlet, a vapor outlet, a liquid outlet and optionally a stripping medium inlet, wherein said sour hydrocarbon mixture is directed to said inlet of the means of separation, and the vapor outlet of the means of separation is in fluid communication with the gas inlet of the sour gas absorber, and wherein the liquid outlet of the means of separation optionally is in fluid communication with the liquid inlet of the oil absorber.

13. A process plant for production of a purified hydrocarbon mixture from a heteroatomic hydrocarbon mixture, comprising a hydrotreatment reactor having an inlet and an outlet, said hydrotreatment reactor containing a material catalytically active in hydrotreatment, wherein the heteroatomic hydrocarbon mixture is directed to the inlet of the hydrotreatment reactor and outlet of hydrotreatment reactor is in fluid communication with the inlet of the means of separation.

Description

FIGURES

[0043] FIG. 1 shows a process for purification of a gas mixture comprising hydrocarbons and sour gas, according to the present disclosure

[0044] FIG. 2 shows a process for purification of a heteroatomic hydrocarbon mixture, according to the present disclosure.

[0045] FIG. 3 shows a process for purification of a heteroatomic hydrocarbon mixture, according to the prior art.

[0046] Elements shown in the figures: [0047] 2 heteroatomic hydrocarbon mixture [0048] 4 hydrotreatment section [0049] 6 sour hydrocarbon mixture [0050] 8 stripper [0051] 10 gas mixture [0052] 12 liquid hydrocarbon fraction from stripper [0053] 14 sour gas absorber [0054] 16 absorbent liquid having affinity for sour gas [0055] 18 absorbent liquid rich in sour gas [0056] 20 purified off-gas [0057] 22 oil absorber [0058] 24 liquid hydrocarbon mixture [0059] 26 enriched liquid hydrocarbon mixture. [0060] 28 off-gas [0061] 30 Liquid hydrocarbon product

[0062] In FIG. 1 a process for purification of a gas mixture 10 comprising hydrocarbon and a sour gas impurity is shown. The gas mixture may also contain other constituents, including hydrogen. The gas mixture 10 is directed to a gas inlet of a sour gas absorber 14, containing an absorbent liquid having affinity for sour gas. The sour gas absorber 14 further has an inlet for lean sour gas absorbent liquid 16, an outlet for rich sour gas absorbent liquid 18 and an outlet for purified off-gas 20. The purified off-gas 20 is directed to the liquid inlet of an oil absorber 22, containing a liquid hydrocarbon mixture. The oil absorber 22 further has an inlet for a lean liquid hydrocarbon mixture 24, an outlet for final purified off-gas 28 and an outlet for enriched liquid hydrocarbon mixture 26. As a result the enriched liquid hydrocarbon mixture will absorb the light hydrocarbons and thus contribute to an increased hydrocarbon recovery.

[0063] In FIG. 2 a process for purification of a heteroatomic hydrocarbon mixture 2 is shown. The heteroatomic hydrocarbon mixture 2, may e.g. be a condensate oil, a feedstock comprising naphtha or a product from a hydrocracking process comprising naphtha. The heteroatomic hydrocarbon mixture 2 is directed to a hydrotreatment section 4, comprising a reactor as well as a gas loop and a separator, as known in the art. The reactor contains a material catalytically active in hydrotreatment operating under hydrotreatment conditions. The material will typically comprise a base metal from Group 6 and a base metal from Group 8/9/10, most often Mo or W in combination with Ni or Co, on an appropriate support, such as alumina, silica or alumina-silica. From the outlet of the hydrotreatment section 4 a sour hydrocarbon mixture 6 is withdrawn, in which heteroatoms, such as sulfur or nitrogen, are converted into inorganic gases such as hydrogen sulfide or ammonia. The sour hydrocarbon mixture 6 is directed to the feed inlet of a means of separation, here a stripper 8 having a feed inlet, a liquid outlet and a vapor outlet. In addition to the sour hydrocarbon mixture 6 the stripper may receive a stripping medium but commonly it will operate by reboiling, providing the stripping medium by evaporation, and thus avoiding the cost and dilution due to an externally supplied stripping medium. The product is separated in a gas mixture 10 comprising hydrocarbon and sour gas withdrawn from the vapor outlet, and a liquid stripper product 12. The gas mixture 10 is directed to a gas inlet of a sour gas absorber 14, containing an absorbent liquid having affinity for sour gas. The sour gas absorber 14 further has an inlet for lean sour gas absorbent liquid 16, an outlet for rich sour gas absorbent liquid 18 and an outlet for purified off-gas 20. The purified off-gas 20 is directed to the liquid inlet of an oil absorber 22, containing a liquid hydrocarbon mixture. The oil absorber 22 further has an inlet for lean liquid hydrocarbon mixture 24, an outlet final purified off-gas 28 and an outlet for enriched liquid hydrocarbon mixture 26. In FIG. 2 at least an amount the liquid stripper product 12 is directed as lean liquid hydrocarbon mixture 24 to the oil absorber, and the enriched liquid hydrocarbon mixture 26 is combined with the lean liquid hydrocarbon mixture 24, to form the hydrocarbon product.

[0064] In an alternative embodiment the lean liquid hydrocarbon mixture 24 may be provided from an external source, instead of being an amount of liquid stripper product 12.

[0065] In FIG. 3 a process for purification of a heteroatomic hydrocarbon mixture 2 according to the prior art is shown. The heteroatomic hydrocarbon mixture 2, may be a condensate oil or a naphtha. The heteroatomic hydrocarbon mixture 2 is directed to a hydrotreatment reactor 4. From the outlet of the hydrotreatment reactor a sour hydrocarbon mixture 6 is withdrawn, in which heteroatoms, such as sulfur or nitrogen, are converted into inorganic gases such as hydrogen sulfide or ammonia. The sour hydrocarbon mixture 6 is directed to the feed inlet of a means of separation, here a stripper 8 having a feed inlet, a liquid outlet and a vapor outlet. In addition to the sour hydrocarbon mixture 6 the stripper may receive a stripping medium or it may operate by reboiling. In the stripper the sour hydrocarbon mixture is separated in a gas mixture 10 comprising hydrocarbon and sour gas withdrawn from the vapor outlet, and a liquid stripper product 12. The gas mixture 10 is directed to a gas inlet of a sour gas absorber 14, containing an absorbent liquid having affinity for sour gas. The sour gas absorber 14 further has an inlet for lean sour gas absorbent liquid 16, an outlet for rich sour gas absorbent liquid 18 and an outlet for purified off-gas 20. The purified off-gas 20 is directed to flare, and the liquid stripper product 12 is directed to further refinery operations.

EXAMPLES

[0066] In a first set of examples, Examples 1 and 2, the operation of a process as disclosed, is compared to a process according to the prior art, without an oil absorber, for the desulfurization of a stream of condensate oil.

[0067] In a second set of examples, Examples 3 and 4, the operation of a process as disclosed is compared to a process according to the prior art, without an oil absorber, for the desulfurization of a stream of naphtha.

[0068] In Example 1 the condensate oil characterized in Table 1 was hydrotreated over a cobalt molybdenum catalyst on an alumina support, at 334 C., 46 barg, LHSV 3.5 I/NL, followed by stripping in a stripper operating 6.7 barg pressure and 58 C. to 218 C. from top to bottom of the stripper. The vapor phase from the stripper was directed as a gas mixture to a sour gas absorber where hydrogen sulfide was captured in an absorbent comprising methyl diethanolamine at a temperature of 63 C.

[0069] In Example 2 the product characterized in Table 1 was hydrotreated and stripped under the same conditions as in Example 1. The vapor phase from the stripper was directed as a gas mixture to a sour gas absorber (operating at 63 C.). The purified gas mixture from the sour gas absorber was directed to an oil absorber where an amount of the hydrocarbons was recovered in a liquid hydrocarbon mixture at 67 C. The flow rate of the liquid hydrocarbon mixture was adjusted to meet the desired RVP of the product, and thus the optimal yield providing a product meeting the required specifications. This process corresponds to the process shown in FIG. 2.

[0070] Table 2 shows a comparison of the Examples 1 and 2. It can be seen that the product of Example 2 has a higher RVP compared to the product of Example 1, and also the yield of Example 2 is 1% higher, while the H.sub.2S content according to both examples is the same.

[0071] In Example 3 the naphtha feedstock characterized in Table 3 was hydrotreated over a cobalt molybdenum catalyst on an alumina support, at 334 C., 46 barg, LHSV 3.5 I/NL, followed by stripping in a stripper operating 6.7 barg pressure and 58 C. to 218 C. from top to bottom of the stripper. The vapor phase from the stripper was directed as a gas mixture to a sour gas absorber where hydrogen sulfide was captured at 80 C. in an absorbent comprising methyl diethanolamine at a temperature of 60 C.

[0072] In Example 4 the product characterized in Table 3 was hydrotreated and stripped under the same conditions as in Example 3. The vapor phase from the stripper was directed as a gas mixture to a sour gas absorber (operating at 80 C.). The purified gas mixture from the sour gas absorber was directed to an oil absorber where an amount of the hydrocarbons was recovered in a liquid hydrocarbon mixture at 60 C. The flow rate of the liquid hydrocarbon mixture was adjusted to meet the desired RVP of the product, and thus the optimal yield providing a product meeting the required specifications. This process corresponds to the process shown in FIG. 2.

[0073] Table 4 shows a comparison of the Examples 3 and 4. It can be seen that the product of Example 2 has a higher RVP compared to the product of Example 1, and also the yield of Example 2 is 1% higher, while the H.sub.2S content according to both examples is the same.

[0074] From both sets of examples it is seen that the yield of the process can be increased by operation according to the present disclosure, relative to the prior art, while adhering to RVP specifications.

TABLE-US-00001 TABLE 1 Feed type Condensate oil Specific gravity SG 60/60 F. 0.798 Sulphur content ppm wt 290 Distillation curve ASTM D 86 IBP C. 45 5% C. 72 10% C. 96 30% C. 128 50% C. 221 70% C. 230 90% C. 340

TABLE-US-00002 TABLE 2 COMPARISON RVP H.sub.2S Yield PSIA ppm wt Relative Example1 No oil absorber 2.2 9.1 100 Example2 With oil absorber 8.1 9.1 101

TABLE-US-00003 TABLE 3 Feed type Naphtha Specific gravity SG 60/60 F. 0.711 Sulphur content ppm wt 300 Total nitrogen ppm wt 0.6 Distillation curve ASTM D 86 IBP C. 59 5% C. 59.4 10% C. 61 30% C. 78 50% C. 100 70% C. 109 90% C. 135

TABLE-US-00004 TABLE 4 COMPARISON RVP H.sub.2S Yield PSIA ppm wt Relative Example 3 No oil absorber 5.2 0.025 100.0 Example 4 With oil absorber 12.0 0.025 101.3