PROCESS AND APPARATUS FOR REMOVING HYDROGEN SULFIDE

Abstract

One exemplary embodiment can be a process for removing hydrogen sulfide from a fractionated hydroprocessed effluent. The process can include stripping a hydroprocessed effluent from a hydroprocessing zone, fractionating the stripped hydroprocessed effluent to obtain a naphtha cut, and sending the naphtha cut to a hydrogen sulfide removal zone. The hydrogen sulfide removal zone can include an amine wash settler, an amine contacting column, or a steam stripper.

Description

FIELD OF THE INVENTION

This invention generally relates to a process and an apparatus for removing hydrogen sulfide.

DESCRIPTION OF THE RELATED ART

The fractionation section of a hydroprocessing unit often includes a stripper column followed by a fractionator. The stripper column can remove hydrogen sulfide from the fractionator feed stream. However, some hydrogen sulfide may remain in the stripper effluent and can carry over to downstream units. Often, the hydrogen sulfide in the stripper effluent can concentrate in the fractionator overhead. A product, such as a light naphtha, exiting the top of the column and passing from a fractionator receiver can contain the hydrogen sulfide. As a result, the product can fail specifications, such as failing to pass a copper strip corrosion test. Hence, there is a need to provide a process and/or apparatus that can remove hydrogen sulfide and meet product specifications.

SUMMARY OF THE INVENTION

One exemplary embodiment can be a process for removing hydrogen sulfide from a fractionated hydroprocessed effluent. The process can include stripping a hydroprocessed effluent from a hydroprocessing zone, fractionating the stripped hydroprocessed effluent to obtain a naphtha cut, and sending the naphtha cut to a hydrogen sulfide removal zone. The hydrogen sulfide removal zone can include an amine wash settler, an amine contacting column, or a steam stripper.

Another exemplary embodiment may be an apparatus for removing hydrogen sulfide. The apparatus may include a hydroprocessing zone for producing a hydroprocessed effluent, a stripper for receiving at least a portion of the hydroprocessed effluent, a fractionation column for receiving a hydrocarbon stream from the stripper, and a hydrogen sulfide removal zone for receiving a naphtha cut. The hydrogen sulfide removal zone can include an amine wash settler, an amine contacting column, or a steam stripper.

A further exemplary embodiment can be a process for removing hydrogen sulfide from a fractionated hydroprocessed effluent. The process can include steam stripping an effluent from a hydroprocessing zone in a first section of a stripper, fractionating the stripped hydroprocessed effluent to obtain a naphtha cut, and sending the naphtha cut to a second section of the stripper for steam stripping.

Generally, the embodiments herein can strip a fractionator overhead product to remove excess hydrogen sulfide to produce products meeting the requisite specifications. Usually, a fractionator overhead product, such as a light naphtha stream, is stripped to remove the hydrogen sulfide. Desirably, sufficient amounts of hydrogen sulfide are stripped to meet product specifications, such as a copper strip corrosion test.

One exemplary embodiment may be a two-stage amine wash. Another exemplary embodiment can provide a single stage amine wash followed by a wash water. A further exemplary embodiment may be an amine wash followed by caustic wash. Yet another embodiment can be a hydrophobic or hydrophilic mesh positioned in a contactor to eliminate downstream wash water facilities. A further exemplary embodiment can be a packed column amine contactor followed with a wash water settler. A still further embodiment can be a light naphtha from the fractionator overhead receiver pumped to a stand-alone stripper column, which may operate at the same pressure as a primary stripper, or the primary stripper may form first and second sections. The stand-alone stripper column or second section may be provided with steam to strip hydrogen sulfide from the naphtha. The stripper vapor from this column or second section can be combined with the stripper overhead at the inlet of the condenser. Steam may be shared between the stand-alone stripper column and the primary stripper, or the first and second sections of the primary stripper.

DEFINITIONS

As used herein, the term “stream” can include various hydrocarbon molecules, such as straight-chain, branched, or cyclic alkanes, alkenes, alkadienes, and alkynes, and optionally other substances, such as gases, e.g., hydrogen, or impurities, such as heavy metals, and sulfur and nitrogen compounds. The stream can also include aromatic and non-aromatic hydrocarbons. Moreover, the hydrocarbon molecules may be abbreviated C1, C2, C3 . . . Cn where “n” represents the number of carbon atoms in the one or more hydrocarbon molecules. Furthermore, a superscript “+” or “−” may be used with an abbreviated one or more hydrocarbons notation, e.g., C3⁺ or C3⁻, which is inclusive of the abbreviated one or more hydrocarbons. As an example, the abbreviation “C3⁺” means one or more hydrocarbon molecules of three carbon atoms and/or more. In addition, the term “stream” may be applicable to other fluids, such as aqueous and non-aqueous solutions of an alkali, such as sodium hydroxide, or an amine aqueous solution.

As used herein, the term “zone” can refer to an area including one or more equipment items and/or one or more sub-zones. Equipment items can include one or more reactors or reactor vessels, heaters, exchangers, pipes, pumps, compressors, and controllers. Additionally, an equipment item, such as a reactor, dryer, or vessel, can further include one or more zones or sub-zones.

As used herein, the term “rich” can mean an amount of generally at least about 50%, and preferably about 70%, by mole, of a compound or class of compounds in a stream. If referring to a solute in solution, e.g., hydrogen sulfide in an amine solution, the term “rich” may be referenced to the equilibrium concentration of the solute. As an example, about 5%, by mole, of a solute in a solvent may be considered rich if the concentration of solute at equilibrium is 10%, by mole.

As used herein, the term “substantially” can mean an amount of at least generally about 80%, preferably about 90%, and optimally about 99%, by weight, of a compound or class of compounds in a stream.

As used herein, the term “naphtha” can include one or more C5-C10 hydrocarbons and have a boiling point of about 25-about 190° C. at atmospheric pressure. A naphtha may include a light naphtha that can include one or more C5-C6 hydrocarbons and have a boiling point of about 25-about 90° C.

As used herein, the term “alkali” can mean any substance that in solution, typically a water solution, has a pH value greater than about 7.0, and exemplary alkali can include sodium hydroxide, potassium hydroxide, or ammonia. Such an alkali in solution may be referred to as an alkaline solution or an alkaline. An alkali solution of sodium hydroxide may be referred to as a caustic.

As used herein, the term “kilopascal” may be abbreviated “KPa” and the term “megapascal” may be abbreviated “MPa”, and all pressures disclosed herein are absolute.

As depicted, process flow lines in the figures can be referred to interchangeably as, e.g., lines, parts, portions, effluents, cuts, pipes, feeds, products, or streams.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic depiction of an exemplary apparatus.

FIG. 2 is a schematic depiction of an exemplary hydrogen sulfide removal zone.

FIG. 3 is a schematic depiction of another hydrogen sulfide removal zone.

FIG. 4 is a schematic depiction of yet another exemplary hydrogen sulfide removal zone.

FIG. 5 is still another schematic depiction of an exemplary hydrogen sulfide removal zone.

FIG. 6 is a schematic depiction of a further hydrogen sulfide removal zone.

FIG. 7 is a schematic depiction of another version of the exemplary apparatus.

FIG. 8 is partial schematic version of yet another exemplary apparatus.

DETAILED DESCRIPTION

Referring to FIG. 1, an exemplary apparatus 100 can include a hydroprocessing zone 120, a primary stripper 160, a fractionation column 200, and a hydrogen sulfide removal zone 300. Generally, the hydroprocessing zone 120 can receive a feed 110 that often contains one or more hydrocarbons.

Often, the feed 110 can be any suitable heavy oil feedstock. Such a heavy oil feedstock can include one or more hydrocarbonaceous streams having components boiling above about 280° C., such as atmospheric gas oils, vacuum gas oils, deasphalted, vacuum, and atmospheric residua, coker distillates, straight run distillates, solvent-deasphalted oils, pyrolysis-derived oils, high boiling synthetic oils, cycle oils, hydrocracked feeds, and cat cracker distillates, although hydrocarbons boiling below about 280° C. may be present as well. These hydrocarbonaceous feed stocks may contain from about 0.1-about 4%, by weight, sulfur. Other suitable heavy oil feedstocks are disclosed in, e.g., U.S. Pat. No. 3,719,740.

The feed 110 can be converted in the hydroprocessing zone 120. The hydroprocessing zone 120 can include any suitable hydroprocessing reactor for conducting activity such as demetallizing, desulfurizing, denitrogenating, hydroisomerization, hydrotreating, and hydrocracking. More than one hydroprocessing reactor may be utilized. The hydroprocessing reactor can include a catalyst having a metal of groups 8-10 of the periodic table, preferably iron, cobalt and nickel, and optionally a metal of group 6 of the periodic table, preferably molybdenum, on a high surface area support material, preferably alumina. Other suitable hydrotreating catalysts include zeolitic catalysts, as well as noble metal catalysts where the noble metal can be at least one of palladium and platinum. The metal of groups 8-10 is typically present in an amount of about 2-about 20%, by weight, preferably about 4-about 12%, by weight, based on the weight of the catalyst. The metal of group 6 can be present in an amount of about 1-about 25%, by weight, preferably about 2-about 25%, by weight, based on the weight of the catalyst. Other catalysts and/or methods of manufacture are disclosed in, e.g., U.S. application Ser. No. 13/076,670 filed 31 Mar. 2011 and U.S. Pat. No. 3,719,740.

The hydroprocessing conditions can include a temperature of about 290-about 460° C., a pressure of about 3-about 20 MPa, and a liquid hourly space velocity of the fresh hydrocarbonaceous feed of about 0.5-about 4 hf⁻¹. The hydroprocessing zone 120 can provide at least a portion of the hydroprocessed effluent 124.

The hydroprocessed effluent 124 can be provided to the primary stripper 160. The primary stripper 160 can receive a steam stream 168 for removing undesirable compounds, such as hydrogen sulfide. A top stream 164 may be provided having gases, such as hydrogen, therein and a bottom stream or a stripped effluent 170. The stripped hydroprocessed effluent 170 containing one or more heavier hydrocarbons can be provided to the fractionation column 200. Generally, the fractionation column 200 can provide a variety of hydrocarbon streams such as naphtha, diesel, gas oil, and heavier hydrocarbon fractions.

Often, a naphtha cut 210 can be obtained from the top of the fractionation column 200 and provided to a receiver 220. The receiver 220 can form a boot for removal of water while a bottom stream 224 can contain the naphtha cut. Generally, the naphtha cut includes one or more C5-C10 hydrocarbons, such as one or more C5-C6 hydrocarbons.

The bottom stream 224 can be provided to the hydrogen sulfide removal zone 300. The hydrogen sulfide removal zone 300 can include an amine wash settler or first amine wash settler 320 and a second amine wash settler 356 to provide two amine wash stages. Generally, the naphtha cut can be provided to the hydrogen sulfide removal zone 300 and be combined with a recycled stream 366, as hereinafter described. These combined streams 234 and 366 can be provided to a first static mixer 324. Generally, the first static mixer 324 can be any suitable device having blades or coils to further the mixing of the streams as the fluid passes therethrough. Afterwards, a mixed stream 326 can be provided to the first amine wash settler 320. The amine can absorb any hydrogen sulfide that is present and gravity can separate the amine solution from the hydrocarbons. Often, the hydrocarbon stream 234 can be cooled to, e.g., about 38-about 40° C. before contacting the lean amine stream 312. A spent or rich amine stream 348 can be withdrawn from the boot of the first amine wash settler 320. The amount of the spent amine stream 348 can be determined by a level controller 342 that can communicate with a valve 346. Afterwards, the spent amine stream 348 can be sent to an amine regeneration unit.

A top stream 328 containing mostly hydrocarbon can be combined with a lean amine stream 312. The lean amine is typically an aqueous solution of amine and water and can include up to about 25%, by weight, amine. Any common amine, such as methyl-diethanol amine (MDEA) or diethanolamine (DEA) may be utilized.

The amount of the lean amine stream can be determined by passing the lean amine stream 312 through an orifice plate 318 communicating with a valve 322. The combined streams 328 and 312 can be passed through a second static mixer 352, which can be substantially similar to the first static mixer 324 described above. The mixed stream 354 can be provided to a second amine wash settler 356. The recycle stream 366 containing the amine solution can pass through a circulation pump 360 and be combined with the hydrocarbon stream 234, as described above. The amount of the recycle stream 366 can be determined by passing the recycle stream 366 through an orifice plate 370 communicating with a valve 374.

A top stream 378 from the second amine wash settler 356 can be withdrawn. The pressure of the top stream 378 can be regulated by a pressure controller 384 communicating with a valve 388. Thus, the top stream 378 can include the naphtha cut and be substantially free of hydrogen sulfide. Generally, the top stream 378 may have a reduced hydrogen sulfide content, preferably an amount of hydrogen sulfide not exceeding about 0.5 ppm, by weight, and passing a copper corrosion test. Optionally, the top stream 378 may be water washed downstream to remove any remnants of amine.

Referring to FIG. 2, another version of a hydrogen sulfide removal zone 300 is depicted. The hydrogen sulfide removal zone 300 in this version can include an amine wash settler 320, which may be substantially similar as described above, and a wash water settler 390. In this exemplary embodiment, the hydrocarbon stream 234 is added to the lean amine stream 312 to form a combined stream 240. The combined stream 240 may pass through the first static mixer 324 before being provided to the amine wash settler 320. A bottom stream 334 can be withdrawn that is spent or rich, and the level controller 342 can communicate with the valve 346 to regulate the amount of the bottom stream 334, as described above. The top stream 328, primarily including the naphtha cut, can be combined with a wash water stream 436. The wash water stream 436 can be regulated by being passed through an orifice plate 438 communicating with a valve 440. The streams 328 and 436 can be combined with a recycle stream 398, as hereinafter described. The combined streams 328, 436, and 398 may be passed through the second static mixer 352 to form a mixed stream 358, which can be provided to the wash water settler 390.

Generally, the wash water settler 390 can include a coalescer 392. Usually, the coalescer 392 can include at least one of a metal mesh, one or more glass fibers, sand, or an anthracite coal. Typically, the streams provided to the wash water settler 390 have water, amine, and hydrocarbon. The amine being soluble in water can be removed with the water. Usually, passing the streams through the coalescer 392 results in water collecting in the boot and being withdrawn as a bottom stream 396. The bottom stream 396 can be split into the recycle stream 398, containing the wash water, and a purged stream 400. The recycle stream 398 can be discharged by a circulation pump 410 and regulated by passing through an orifice plate 406 communicating with a valve 402. The purged stream 400 can be regulated by a level controller 420 communicating with a valve 424. Additionally, water can be purged intermittently to maintain an amine concentration of about 3%, by weight, in water. The purged stream 400 can be combined with the bottom stream 334 to form a combined stream 470 that can be sent to any suitable destination, such as an amine regeneration unit. A top stream 394 can include the naphtha cut and have a reduced hydrogen sulfide content, preferably an amount of hydrogen sulfide not exceeding about 0.5 ppm, by weight, and passing a copper corrosion test. Generally, the top stream 394 can be regulated by the pressure controller 428 communicating with a valve 432.

Still another version of a hydrogen sulfide removal zone 300 is depicted in FIG. 3. This version of a hydrogen sulfide removal zone 300 can include the amine wash settler 320 and an alkali settler 450. In this exemplary embodiment, not only can hydrogen sulfide be removed, but one or more sulfide compounds as well.

The bottom stream 224 containing the naphtha cut can be added to the lean amine stream 312 for forming the combined stream 240, which may be passed through the first static mixer 324, as described above, to provide the mixed stream 326. The mixed stream 326 may be passed to the first amine wash settler 320. A bottom stream 334, typically rich in hydrogen sulfide, can be provided to an amine regeneration unit. The amount of this bottom stream 334 can be regulated by the level controller 342 and the valve 346, as described above.

The top stream 328, containing the naphtha cut, can be added to an alkali stream 474 to form a combined stream 444. Often, the alkali stream 474 includes caustic. The alkali stream 474 can be regulated by passing the alkali stream 474 through an orifice plate 472 communicating with a valve 476. The combined stream 444 can be added to an alkali recycle stream 466 and passed through the second static mixer 352 to form a feed 448 before entering the alkali settler 450. The alkali solution can remove one or more sulfur compounds from the naphtha cut. Typically, the amine solution only removes hydrogen sulfide.

Generally, a bottom stream 458 can be withdrawn from a boot of the alkali settler 450 and be circulated by a circulation pump 462. A portion of the bottom stream 458 can be an alkali recycle stream 466 regulated by an orifice plate 402 communicating with a valve 406. An alkali purge stream 468 can be regulated with a level controller 420 communicating with a valve 424. A top stream 454 can be withdrawn from the alkali settler 450 and include the naphtha cut having reduced levels of hydrogen sulfide, preferably an amount of hydrogen sulfide not exceeding about 0.5 ppm, by weight, and passing a copper corrosion test. The top stream 454 can be regulated with a pressure controller 428 communicating with the valve 432.

Referring to FIG. 4, a further exemplary embodiment of a hydrogen sulfide removal zone 300 is depicted. The hydrogen sulfide removal zone 300 can include an amine contacting column 480. The amine contacting column 480 can include a mesh 484, optionally coated to provide hydrophobic or hydrophilic properties. The amine contacting column 480 may also contain packing or a packed bed. Generally, the mesh 484 prevents water, including amine aqueous solutions, from exiting the column 480. The amine can be in an aqueous solution with at least about 75%, by weight, water. Thus, the mesh 484 prevents the amine solution from exiting the amine contacting column 480 to provide a naphtha cut without the amine remnants.

In operation, the hydrocarbon stream 234 may be added to the lean amine stream 312 to form the combined stream 240 and passed through the first static mixer 324, as described above. The mixed stream 326 can enter the amine contacting column 480. Generally, the water and amine can exit as a bottom stream 504 being regulated with a level controller 420 communicating with the valve 424. The hydrocarbons can rise in the amine contacting column 480 and pass through the mesh 484 before exiting the column 480 as a top stream 500. The amount of the top stream 500 may be regulated with the pressure controller 428 communicating with the valve 432. The top stream 500 can include the naphtha cut having reduced levels of hydrogen sulfide, preferably an amount of hydrogen sulfide not exceeding about 0.5 ppm, by weight, and passing a copper corrosion test.

Referring to FIG. 5, a still further exemplary embodiment of the hydrogen sulfide removal zone 300 is depicted. As depicted, the hydrogen sulfide removal zone 300 can include the amine contacting column 480. In this exemplary embodiment, the amine contacting column 480 can include the mesh 484, optionally coated, a first distributor 492, a packing 488, and a second distributor 496. The first distributor 492 and the second distributor 496 can be any suitable distributor forming, independently, one or more holes and/or nozzles. Generally, the hydrocarbon stream 234 is added to a recycle stream 512, as hereinafter described, to form the combined stream 240. The combined stream 240 is provided to the second distributor 496. Meanwhile, the lean amine stream 312 can be provided to the first distributor 492. As a result, the hydrocarbon can rise through the packing 488, which can include one or more ring elements, although other materials may be used such as trays, fiber and/or film contactors, while the amine solution can fall due to gravity. The packing 488 can provide additional stages for removing hydrogen sulfide. The amine solution can exit as the bottom stream 504 being regulated by the level controller 420 communicating with the valve 424, as described above. The hydrocarbons can rise through the packing 488 and past the mesh 484, which may be in this exemplary embodiment a stainless steel mesh, although other materials may be utilized having hydrophobic or hydrophilic properties.

The top stream 500 can be obtained and split into the recycle stream 512 and a product stream 508. The recycle stream 512 can pass through the orifice plate 568 communicating with a valve 572 to regulate the flow. The product stream 508 may exit the hydrogen sulfide removal zone 300 and be regulated by the pressure controller 428 communicating with the valve 432. The product stream 508 can include the naphtha cut having reduced levels of hydrogen sulfide, preferably an amount of hydrogen sulfide not exceeding about 0.5 ppm, by weight, and passing a copper corrosion test. A wash water facility can be provided downstream to remove any entrained amine solution.

Referring to FIG. 6, yet another version of the hydrogen sulfide removal zone 300 can include the wash water settler 390 and the amine contacting column 480 as described in, respectively, FIGS. 2 and 5. In this exemplary embodiment, the wash water settler 390 can omit the coalescer 392. In operation, the hydrocarbon stream 234 is added to a recycle stream 580, as hereinafter described, to form the combined stream 240. The combined stream 240 can be provided to the second distributor 496 in the column 480. Additionally, the lean amine stream 312 can be provided to the first distributor 492. The hydrocarbons can rise and the amine can fall as the liquids contact in the packing 488. The bottom stream 504 can include the amine and be regulated by the level controller 420 communicating with the valve 424, as described above. The hydrocarbons can rise in the column 480 and pass through the stainless steel mesh 484. The top stream 500 can exit the column 480. A wash water stream 436 can be regulated by being passed through an orifice plate 438 communicating with a valve 440. The wash water stream 436 can be combined with the top stream 500 as well as the recycle stream 398, as hereinafter described. The streams 500, 436, and 398 can form a combined stream 588 passed through the first static mixer 324 to form a mixed stream 330.

The mixed stream 330 can be subsequently provided to the wash water settler 390. The hydrocarbon can rise within the wash water settler 390 and exit as a top stream 394 including the naphtha cut. The top stream 394 can be split into the recycle stream 580 that can be regulated by passing through an orifice plate 568 communicating with a valve 572 and a product stream 592 that can be regulated by the pressure controller 428 communicating with the valve 432. The product stream 592 can include the naphtha cut having reduced levels of hydrogen sulfide, preferably an amount of hydrogen sulfide not exceeding about 0.5 ppm, by weight, and passing a copper corrosion test.

The water can collect in the boot of the wash water settler 390 and exit as a bottom stream 396. The bottom stream 396 can be split into the recycle stream 398 and a purge stream 400. The recycle stream 398 may pass through a circulation pump 510 and be subsequently passed through an orifice plate 472 communicating with the valve 476 for controlling the rate of the recycle stream 398.

In addition, the purge stream 400 can be regulated by the level controller 528 on the wash water settler 390 and in communication with the valve 532. The purge stream 400 can be combined with the bottom stream 504 to form the combined stream 470 that may be sent to any suitable destination, such as an amine regeneration unit.

Referring to FIG. 7, another version of the exemplary apparatus 100 is depicted along with yet another hydrogen sulfide removal zone 300. This version of the exemplary apparatus 100 can include the hydroprocessing zone 120, the primary stripper 160, the fractionation column 200, and the hydrogen sulfide removal zone 300. Generally, the hydroprocessing zone 120, the steam stripper 160, and the fractionation column 200 are substantially the same as described above. The hydrogen sulfide removal zone 300 in this exemplary embodiment can include a stand-alone steam stripper 600, an air cooler 618, and a condenser 622.

In operation, the feed 110 can be provided to the hydroprocessing zone 120 to provide a hydroprocessed effluent 124, as discussed above. The hydroprocessed effluent 124 can be sent to the steam stripper 160 that may provide the top stream 164 added to a top stream 630, as hereinafter described, to provide a combined stream 198. The primary stripper or steam stripper 160 can be provided with a steam stream 168 that can be split into a first part 184 of steam stream 168 and a second part 186 of the steam stream 168. Generally, the first part 184 passes through an orifice plate 172 communicating with a valve 174 for regulating the first part 184 of the steam stream 168. The second part 186 of the steam stream 168 can be provided to the hydrogen sulfide removal zone 300, as described hereinafter.

The steam stripper 160 can also provide a stripped effluent 170 that can be regulated by a level controller 180 communicating with a valve 182. The stripped hydroprocessed effluent 170, including the naphtha cut, can be passed through a heat exchanger 188 to a flash drum 190. The flash drum 190 can provide a top stream 192 provided to the fractionation column 200. In addition, the flash drum 190 can provide a bottom stream 194 that may pass through a circulation pump 196 and be regulated by a level controller 202 on the flash drum 190 and in communication with a valve 204. The bottom stream 194 can be passed through a furnace 206 and subsequently to the fractionation column 200. The fractionation column 200, in addition to receiving the streams 192 and 194, may also receive a steam stream 260. The fractionation column 200 can produce a variety of products in addition to the naphtha cut 210, such as diesel and gas oil cuts as described above, for the apparatus 100 as depicted in FIG. 1. However, only the naphtha cut 210 will be described in detail hereinafter.

The naphtha cut 210 from the top of the fractionation column 200 can be passed through an air condenser and provided to a receiver 220 that can provide a bottom stream 224. Generally, the bottom stream 224 is split into a reflux stream 230 returned to the fractionation column 200 and a hydrocarbon stream 234.

The hydrocarbon stream 234 can pass through an exchanger 208 for heating to, e.g., about 180-about 190° C., before being sent to the hydrogen sulfide removal zone 300. The hydrogen sulfide removal zone 300 can receive the hydrocarbon stream 234 in the steam stripper 600. The steam stripper 600 receives the second part 186 of the steam stream 168 for stripping the naphtha cut. The second part 186 can be regulated by passing through an orifice plate 176 communicating with a valve 178. A top stream 630 can be obtained from the steam stripper 600 and combined with the top stream 164 of the primary stripper 160 to form a combined stream 198. The combined stream 198 may be a stripper overhead liquid having one or more hydrocarbons and/or other material that can be lighter than the naphtha cut.

The bottom stream 634 from the steam stripper 600 can be passed through the air cooler 618 and then to the condenser 622. Afterwards, the bottom stream 634 can be passed through an orifice plate 626 communicating with a valve 632. A level controller 614 may also communicate with the valve 632 for regulating the flow of the bottom stream 634, which contains the naphtha cut that can exit the hydrogen sulfide removal zone 300. The bottom stream 634 can have reduced levels of hydrogen sulfide, preferably an amount of hydrogen sulfide not exceeding about 0.5 ppm, by weight, and passing a copper corrosion test.

Referring to FIG. 8, yet another exemplary embodiment of the apparatus 100 is depicted. In this exemplary embodiment, a steam stripper can be incorporated into a primary stripper. As such, both strippers can be combined into a unitary device, and thus reduce the number of separate equipment pieces. In this exemplary embodiment, a primary stripper 700, which is only partially depicted, can include a first section 710 and a second section 720. The first section 710 can include one or more trays 712 and the second section 720 can include one or more trays 722. Generally, the first section 710 and the second section 720 are divided by a wall 716. Each section 710 and 720 can receive, respectively, the first part 184, as depicted in FIG. 7, and a second part 186 of a common steam stream. Moreover, the other features of the apparatus 100, such as the hydroprocessing zone 120 and the fractionation column 200, although not shown, can be the same as depicted in FIG. 7.

In operation, the hydrocarbon stream 234 can be provided to the second section 720 while the hydroprocessed effluent 124 can be provided to the first section 710. The hydrocarbon stream 234 can be obtained from the stripped hydroprocessed effluent 170 from the fractionation column 200, as described above in FIG. 7. Typically, the hydrocarbon stream 234, optionally heated, is provided to the second section 720 and stripped with the second part 186 of steam. A top stream 630 can be obtained that is combined with the top stream 164 from the first section 710.

Both streams 164 and 630 can form a combined stream 198 provided to an air cooler 730 that may be in turn provided to a receiver 740. A top stream 744 may be obtained that can primarily contain stripper off gases. A stream 756 containing sour water can be withdrawn from a boot of the receiver 740. A bottom stream 748 can be withdrawn from the receiver 740 that may be primarily a naphtha cut. A pump 752 can provide a discharge that is split into a reflux stream 764 that can pass through an orifice plate 768 communicating with a valve 772 to regulate the reflux return to the first section 710. Another portion of the discharge can be obtained as a hydrocarbon stream 760. The second section 720 can provide a bottom stream 776, which can be a naphtha cut product having reduced levels of hydrogen sulfide, preferably an amount of hydrogen sulfide not exceeding about 0.5 ppm, by weight, and passing a copper corrosion test. Thus, the naphtha cut product can be obtained and utilized.

Thus, the various versions disclosed herein can remove hydrogen sulfide with optional downstream water washing. Additionally, a sand filter may be downstream of any wash water facility. Moreover, any suitable pressure may be utilized, including a pressure where the treated naphtha does not exceed the battery limit pressure of the refinery or chemical manufacturing facility.

Without further elaboration, it is believed that one skilled in the art can, using the preceding description, utilize the present invention to its fullest extent. The preceding preferred specific embodiments are, therefore, to be construed as merely illustrative, and not limitative of the remainder of the disclosure in any way whatsoever.

In the foregoing, all temperatures are set forth in degrees Celsius and, all parts and percentages are by weight, unless otherwise indicated.

From the foregoing description, one skilled in the art can easily ascertain the essential characteristics of this invention and, without departing from the spirit and scope thereof, can make various changes and modifications of the invention to adapt it to various usages and conditions.

Claims

1. A process for removing hydrogen sulfide from a fractionated hydroprocessed effluent, comprising:

A) stripping a hydroprocessed effluent from a hydroprocessing zone;

B) fractionating the stripped hydroprocessed effluent to obtain a naphtha cut; and

C) sending the naphtha cut to a hydrogen sulfide removal zone, comprising: 1) an amine wash settler; 2) an amine contacting column; or 3) a steam stripper.

2. The process according to claim 1, wherein the naphtha cut comprises one or more C5-C10 hydrocarbons.

3. The process according to claim 1, wherein the naphtha cut comprises one or more C5-C6 hydrocarbons.

4. The process according to claim 1, wherein the hydrogen sulfide removal zone comprises the amine contacting column.

5. The process according to claim 4, wherein the amine contacting column comprises a mesh, optionally coated.

6. The process according to claim 5, wherein the amine contacting column further comprises a packing.

7. The process according to claim 1, wherein the hydrogen sulfide removal zone comprises the steam stripper.

8. The process according to claim 1, wherein the hydrogen sulfide removal zone comprises the amine wash settler.

9. The process according to claim 8, wherein the amine wash settler is a first amine wash settler, and the hydrogen sulfide removal zone further comprises a second amine wash settler.

10. The process according to claim 8, wherein the hydrogen sulfide removal zone further comprises a wash water settler.

11. The process according to claim 10, wherein the wash water settler further comprises a coalescer.

12. The process according to claim 8, wherein the hydrogen sulfide removal zone further comprises an alkali settler.

13. An apparatus for removing hydrogen sulfide, comprising:

A) a hydroprocessing zone for producing a hydroprocessed effluent;

B) a stripper for receiving at least a portion of the hydroprocessed effluent;

C) a fractionation column for receiving a hydrocarbon stream from the stripper; and

D) a hydrogen sulfide removal zone for receiving a naphtha cut wherein the hydrogen sulfide removal zone comprises: 1) an amine wash settler; 2) an amine contacting column; or 3) a steam stripper.

14. The apparatus according to claim 13, wherein the hydrogen sulfide removal zone comprises the amine wash settler.

15. The apparatus according to claim 14, wherein the amine wash settler is a first amine wash settler, and the hydrogen sulfide removal zone further comprises a second amine wash settler.

16. The apparatus according to claim 14, wherein the hydrogen sulfide removal zone further comprises a wash water settler.

17. The apparatus according to claim 14, wherein the hydrogen sulfide removal zone further comprises an alkali settler.

18. The apparatus according to claim 13, wherein the apparatus comprises the amine contacting column.

19. The apparatus according to claim 18, wherein the amine contacting column comprises a mesh, optionally coated.

20. A process for removing hydrogen sulfide from a fractionated hydroprocessed effluent, comprising:

A) steam stripping an effluent from a hydroprocessing zone in a first section of a stripper;

B) fractionating the stripped hydroprocessed effluent to obtain a naphtha cut; and

C) sending the naphtha cut to a second section of the stripper for steam stripping.