Methods for separating hydrocarbons

Abstract

Methods for separating hydrocarbons may include dehydrogenating a feed stream to form a product stream including one or more olefins. The methods may include compressing the product stream and separating the compressed product stream into at least a second product stream and a first non-condensable gas stream. The first non-condensable gas stream includes one or more of hydrogen, nitrogen, methane, carbon monoxide, and carbon dioxide, and the second product stream includes hydrocarbons. The method may include reducing the pressure of the first non-condensable gas stream to form a second non-condensable gas stream and heating the second non-condensable gas stream to form a third non-condensable gas stream. The method may include passing at least a portion of the third non-condensable gas stream to one or more of: a combustor, a pressure swing adsorption system, a dehydrogenation reactor, a compressor, a reactor feed pretreatment bed, or a dryer.

Description

METHODS FOR SEPARATING HYDROCARBONSCROSS-REFERENCE TO RELATED APPLICATIONS

[0001] This application claims the benefit of U.S. Provisional Application Serial No. 63 / 604,564 filed November 30, 2023, the contents of which are incorporated in their entirety herein.TECHNICAL FIELD

[0002] Embodiments described herein generally relate to methods and systems for separating hydrocarbons.BACKGROUND

[0003] Various hydrocarbons, such as ethylene, ethane, propylene, propane, and heavier hydrocarbons, may be recovered from a variety of product streams obtained from chemical reactors. Cryogenic separation processes may be used to recover more condensable hydrocarbons from less condensable gasses or products.SUMMARY

[0004] In cryogenic separation processes, a product stream from a chemical reactor may be compressed and cooled by heat exchange with other process streams and / or external sources of refrigeration. As the product stream is cooled, more condensable fractions of the product stream may be separated from less condensable gasses of the product stream. Less condensable gases may include hydrogen, nitrogen, methane, and carbon dioxide. These less condensable gasses may have uses throughout the chemical reactor system and may be recycled to various system components of the reactor system. For example, the less condensable gasses may be burned in a combustor as supplemental fuel and the less condensable gasses may be used to regenerate adsorbent material in dryers or hydrocarbon feed pretreatment beds. Additionally, the less condensable gasses may be used to control the velocity of gasses moving through the reactor or to control the molecular weight of the product stream exiting the reactor. The less condensable gasses may also be used to produce hydrogen in a hydrogen generation system. Accordingly, there is a need for methods for recycling the less condensable gasses from the cryogenic separation process to other system components of the reactor system.

[0005] According to one or more embodiments of the present disclosure, a method for separating hydrocarbons may comprise dehydrogenating a feed stream comprising one or more alkanes to form a product stream comprising one or more olefins. The dehydrogenation takes place in a reactor system comprising one or more of: a combustor, a pressure swing adsorption system, a dehydrogenation reactor, a compressor, a reactor feed pretreatment bed, or a dryer. The method may comprise compressing the product stream to form a compressed product stream. The method may comprise separating the compressed product stream into at least a second product stream and a first non-condensable gas stream. The first non-condensable gas stream comprises one or more of hydrogen, nitrogen, methane, carbon monoxide, and carbon dioxide, and the second product stream comprises hydrocarbons. The method may comprise reducing the pressure of the first non- condensable gas stream to form a second non-condensable gas stream and heating the second non- condensable gas stream to form a third non-condensable gas stream. The first non-condensable gas stream, the second non-condensable gas stream, and the third non-condensable gas stream have the same composition. The method may comprise passing at least a portion of the third non- condensable gas stream to one or more of: the combustor, the pressure swing adsorption system, the dehydrogenation reactor, the compressor, the reactor feed pretreatment bed, or the dryer.

[0006] Additional features and advantages of the technology disclosed herein will be set forth in the detailed description which follows, and in part will be readily apparent to those skilled in the art from that description or recognized by practicing the technology as described herein, including the detailed description which follows, the claims, as well as the appended drawings.BRIEF DESCRIPTION OF THE DRAWINGS

[0007] The following detailed description of specific embodiments of the present disclosure can be best understood when read in conjunction with the following drawings, where like structure is indicated with like reference numerals and in which:

[0008] FIG. 1 schematically depicts a system for reacting and separating a feed stream according to one or more embodiments disclosed herein; and

[0009] FIG. 2 schematically depicts a system for separating hydrocarbons and less condensable gasses according to one or more embodiments disclosed herein.

[0010] It should be understood that the drawings are schematic in nature, and do not include some components of a separation system commonly employed in the art, such as, without limitation, temperature transmitters, pressure transmitters, flow meters, pumps, valves, and the like. It would be known that these components are within the spirit and scope of the present embodiments disclosed. However, operational components, such as those described in the present disclosure, may be added to the embodiments described in this disclosure.

[0011] Reference will now be made in greater detail to various embodiments, some embodiments of which are illustrated in the accompanying drawings.DETAILED DESCRIPTION

[0012] One or more non-limiting embodiments of methods for separating hydrocarbons are described herein. FIG. 1 depicts an embodiment of a system for reacting and separating hydrocarbons. Embodiments of the methods for separating hydrocarbons described herein may be performed using a system as depicted in FIG. 1. However, it should be understood that the methods for separating hydrocarbons described herein are not necessarily limited to the use of the system depicted herein in FIG. 1. Embodiments of methods for separating hydrocarbons described herein may include recycling at least a portion of a non-condensable gas stream to one or more components of the system depicted in FIG. 1. The one or more components to which at least a portion of the non-condensable gas stream may be recycled include a combustor, a pressure swing adsorption system, a dehydrogenation reactor, a compressor, a reactor feed pretreatment bed, and a dryer.

[0013] In one or more embodiments described herein, a feed stream comprising one or more alkanes may be dehydrogenated in a reactor system to form a product stream comprising one or more olefins. The product stream may be separated into at least a second product stream and a non-condensable gas stream. The non-condensable gas stream may be used as a coolant by reducing the pressure of the non-condensable gas stream and then passing the non-condensable gas stream through one or more heat exchangers. Then, in one or more embodiments, portions of the non-condensable gas stream may be passed to one or more system components of the reactor system including: a combustor, a pressure swing adsorption system, a dehydrogenation reactor, a compressor, a reactor feed pretreatment bed, and a dryer. Embodiments of these methods are now described in more detail.

[0014] Referring now to FIG. 1, in one or more embodiments, methods for separating hydrocarbons may comprise dehydrogenating a feed stream 104 comprising one or more alkanes to form a product stream 106 comprising one or more olefins. In one or more embodiments, the feed stream 104 may comprise greater than or equal to 70 wt.% of one or more of C2, C3 and C4 alkanes. For example, the feed stream 104 may comprise at least greater than or equal to 70 wt.%, greater than or equal to 80 wt.%, greater than or equal to 90 wt.%, greater than or equal to 95 wt.% of one or more of C2, C3 and C4 alkanes.

[0015] In one or more embodiments, an untreated feed stream 102 may be passed through a reactor feed pretreatment bed 202 to form the feed stream 104. The reactor feed pretreatment bed 202 may comprise a packed bed. The packed bed may comprise an adsorbent material as packing. The adsorbent material may be any adsorbent material suitable for removing at least a portion of sulfur and / or water from the untreated feed stream 102. In one or more embodiments, the adsorbent material may comprise a molecular sieve. In some embodiments, the reactor feed pretreatment bed 202 may comprise multiple packed beds in parallel. In such embodiments, one or more packed beds may be used to treat the untreated feed stream 102 while one or more remaining packed beds may be regenerated.

[0016] The feed stream 104 may be dehydrogenated in a dehydrogenation reactor 204. Generally, the dehydrogenation reactor 204 may be operated by feeding the feed stream 104 and fluidized particulate solids to a reaction vessel, and reacting the feed stream by contact with fluidized particulate solids to produce a product stream 106. In one or more embodiments, the particulate solids may comprise a catalyst. The particulate solids may be separated from the product stream 106 in a gas / solids separation device. The particulate solids 108 may be transported out of the dehydrogenation reactor 204 and passed to a combustor 206. In the combustor 206, the particulate solids may be regenerated by chemical processes. For example, the spent particulate solids may be regenerated by one or more of oxidizing the particulate solids by contact with an oxygen containing gas, combusting coke present on the particulate solids, and combusting a supplemental fuel to heat the particulate solids. The particulate solids may be separated from gasses generated or used during the regeneration process and the regenerated particulate solids 110 may be passed to the dehydrogenation reactor 204.

[0017] In one or more embodiments, the product stream 106 may comprise one or more olefins. The product stream 106 may further comprise one or more alkanes that were not reacted in the dehydrogenation reactor 204. In one or more embodiments, the product stream 106 may comprise greater than or equal to 70 wt.% of C2, C3, and C4 olefins and alkanes. For example, the product stream 106 may comprise greater than or equal to 70 wt.%, greater than or equal to 80 wt.%, greater than or equal to 90 wt.%, greater than or equal to 95 wt.% of one or more of C2, C3 and C4 olefins and alkanes. In one or more embodiments, the C2, C3, and C4 olefins and alkanes may comprise one or more of ethane, ethylene, propane, propylene, butane, and butene.

[0018] In one or more embodiments, the product stream 106 may be compressed to form a compressed product stream 112. The product stream 106 may be compressed in compressor system 208. The compressor system may comprise one or more compressors. The compressors may be any suitable compressors, including but not limited to, centrifugal compressors. In one or more embodiments, the compressed product stream 112 may comprise hydrogen and one or more hydrocarbons. For example, the compressed product stream 112 may comprise hydrogen and one or more of C2, C3, and C4 olefins and alkanes. In one or more embodiments, the compressed product stream may comprise one or more of hydrogen, nitrogen, methane, carbon monoxide, and carbon dioxide and one or more of C2, C3, and C4 olefins and alkanes.

[0019] In one or more embodiments, the compressed product stream 112 may be dried to form a dried product stream 114. In some embodiments, the compressed product stream 112 may further comprise H2O. At least a portion of the H2O may be removed from the compressed product stream 112 before the compressed product stream 112 is separated. The compressed product stream 112 may be dried by any suitable means. In one or more embodiments, the compressed product stream 112, or one or more fractions of the compressed product stream 112, may be dried in one or more dryers. For example, in one or more embodiments, not depicted, a vapor fraction of compressed product stream 112 may be dried in one dryer and a liquid fraction of compressed product stream 112 may be dried in a second dryer. Still referring to FIG. 1, in one or more embodiments, the compressed product stream 112 may be dried in dryer 210. The dryer 210 may be any suitable dryer. In one or more embodiments, the dryer 210 may comprise one or more columns packed with an adsorbent. The adsorbent may comprise any material suitable for removing water from the compressed product stream 112. In one or more embodiments, the adsorbent may comprise a molecular sieve. In some embodiments, the dryer 210 may comprisemultiple packed columns in parallel. In such embodiments, one or more packed columns may be used to dry the compressed product stream 112 while one or more remaining packed columns may be regenerated.

[0020] In one or more embodiments, the dried product stream 114 may be separated in separation unit 300. The separation unit 300 may comprise one or more separators. An embodiment of separation unit 300 is schematically depicted in FIG. 2. However, it should be noted that other separation units may be suitable for making the separations described hereinbelow.

[0021] As used in this disclosure, a “separator” refers to any separation device or system of separation devices that at least partially separates one or more chemicals that are mixed in a process stream from one another. For example, a separator may selectively separate differing chemical species or phases from one another, forming one or more chemical fractions. Examples of separators include, without limitation, distillation columns, flash drums, knock-out drums, knock-out pots, traps, scrubbers, expansion devices, membranes, solvent extraction devices, and the like. It should be understood that separation processes described in this disclosure may not completely separate all of one chemical constituent from all of another chemical constituent. It should be understood that the separation processes described in this disclosure “at least partially” separate different chemical components from one another, and that even if not explicitly stated, it should be understood that separation may include only partial separation. As used in this disclosure, one or more chemical constituents may be “separated” from a process stream to form a new process stream. Generally, a process stream may enter a separator and be divided, or separated, into two or more process streams of desired composition.

[0022] In one or more embodiments, separation unit 300 may be a cryogenic separation unit. In a cryogenic separation process, a process stream, such as compressed product stream 112 or dried product stream 114, may be cooled by heat exchange with other process streams and / or external sources of cooling or refrigeration in one or more heat exchangers. In one or more embodiments, the one or more heat exchangers may be positioned within a cold box. The one or more separators may be used to separate more condensable hydrocarbons from less condensable gasses. As used in this disclosure, “more condensable hydrocarbons” may include C2, C3, and C4+ alkanes and olefins, and “less condensable gasses” may include to hydrogen, nitrogen, methane,carbon monoxide, and carbon dioxide. The “less condensable gasses” described herein may also be referred to as “non-condensable gasses” for the purposes of the separations described herein.

[0023] As used in this disclosure, a “cold box” refers to an insulated enclosure that may house one or more system components. The cold box may be insulated to minimize heat transfer between the system components and the environment. In one or more embodiments, one or more heat exchangers may be positioned within a cold box. In some embodiments, multiple heat exchangers may be positioned in series within a cold box. The heat exchangers may include a brazed heat exchanger, a shell and tube heat exchanger, double pipe heat exchanger, plate heat exchanger, tubular heat exchanger, fin type heat exchanger, condensers, evaporators, boilers, or combinations thereof.

[0024] Referring now to FIG. 2, the dried product stream 114 maybe cooled to form a cooled dried stream 302. The dried product stream 114 may be cooled in any suitable heat exchanger. In one or more embodiments, the dried product stream 114 may be cooled in heat exchanger 602. Heat exchanger 602 may be positioned in cold box 620. In one or more embodiments, cooling the dried product stream may condense at least a portion of the dried product stream 114.

[0025] In one or more embodiments, the cooled dried stream 302 may be separated into a first vapor stream 304 and a first liquid stream 306 in separator 700. Separator 700 may be any suitable separator, including but not limited to a vapor / liquid separator.

[0026] The first vapor stream 304 may be cooled to form a cooled stream 308. In some embodiments, the cooled stream 308 may be at least partially condensed. In one or more embodiments, the first vapor stream 304 may be cooled in heat exchanger 600. In one or more embodiments, heat exchanger 600 may be positioned within cold box 620.

[0027] Still referring to FIG. 2, the cooled stream 308 may be separated into a first non- condensable gas stream 310, and a second liquid stream 312. The cooled stream 308 may be separated into the first non-condensable gas stream 310 and the second liquid stream in separator 702. Separator 702 may be any suitable separator.

[0028] In one or more embodiments, the first non-condensable gas stream 310 may comprise one or more of hydrogen, nitrogen, methane, carbon monoxide, and carbon dioxide. In one or more embodiments, the first non-condensable gas stream 310 may comprise greater than or equalto 50 wt.% of one or more of hydrogen, nitrogen, methane, carbon monoxide, and carbon dioxide. For example, the first non-condensable gas stream 310 may comprise greater than or equal to 50 wt.%, 60 wt.%, 70 wt.%, 80 wt.%, 90 wt.%, or even 95 wt.%, of one or more of hydrogen, nitrogen, methane, carbon monoxide, and carbon dioxide.

[0029] In one or more embodiments, the pressure of the first non-condensable gas stream 310 may be reduced to form a second non-condensable gas stream 322. The second non- condensable gas stream 322 may be heated to form a third non-condensable gas stream 126. In one or more embodiments, the second non-condensable gas stream 322 may be heated by being passed through one or more heat exchangers to provide cooling to the one or more heat exchangers. Embodiments of these process steps are described in more detail hereinbelow.

[0030] In one or more embodiments, the first non-condensable gas stream 310 may be passed through one or more heat exchangers to provide cooling in the one or more heat exchangers. Referring still to FIG. 2, the first non-condensable gas stream 310 may be passed from the separator 702 to the heat exchanger 600 to provide cooling in heat exchanger 600 and form a warmed first non-condensable gas stream 320.

[0031] Still referring to FIG. 2, the pressure of the warmed first non-condensable gas stream 320 may be reduced to form a second non-condensable gas stream 322. The pressure of the warmed first non-condensable gas stream 320 may be reduced in expander 402. Reducing the pressure of the warmed first non-condensable gas stream 320 may cool the stream to form second non-condensable gas stream 322. In one or more embodiments, second non-condensable gas stream 322 may have a temperature less than the temperature of the warmed first non-condensable gas stream 320 and a pressure less than the pressure of the warmed first non-condensable gas stream 310.

[0032] In one or more embodiments, the second non-condensable gas stream 322 may be heated to form a third non-condensable gas stream 126. Heating the second non-condensable gas stream 322 may comprise passing the second non-condensable gas stream 322 through one or more heat exchangers. Passing the second non-condensable gas stream 322 through the one or more heat exchangers may provide cooling in the one or more heat exchangers. For example, in the embodiment depicted in FIG. 2, the second non-condensable gas stream 322 may be passed through heat exchanger 600 to form intermediate stream 323 and then through heat exchanger 602to form the third non-condensable gas stream 126. In one or more embodiments, heat exchanger 600 and heat exchanger 602 may be positioned in cold box 620. In one or more embodiments, the third non-condensable gas stream 126 may have a temperature that is greater than the temperature of the second non-condensable gas stream 322.

[0033] In one or more embodiments, the first non-condensable gas stream 310, the second non-condensable gas stream 322, and the third non-condensable gas stream 126 may have the same chemical composition. It should be understood that the temperature and pressure of each of the first non-condensable gas stream 310, the second non-condensable gas stream 322, and the third non-condensable gas stream 126 may be different, as described hereinabove.

[0034] Still referring to FIG. 2, in one or more embodiments, at least a portion of the second liquid stream 312 may be passed to a fractionation system 704. The second liquid stream 312 may be passed through one or more heat exchangers before being passed to the fractionation system 704. Passing the second liquid stream 312 through one or more heat exchangers may warm the second liquid stream 312 and may provide cooling to the one or more heat exchangers. In some embodiments, the second liquid stream 312 may be passed through heat exchanger 600 to provide cooling to heat exchanger 600. In some embodiments, the second liquid stream 312 may be passed through heat exchanger 602 to provide cooling to heat exchanger 602. In some embodiments, as depicted in FIG. 2, the second liquid stream 312 may be passed through heat exchanger 600 and then passed through heat exchanger 602 to provide cooling to both heat exchanger 600 and heat exchanger 602 before being passed to the fractionation system 704.

[0035] As used in this disclosure, a “fractionation system” refers to any fractionation device or system of fractionation devices that at least partially divide a certain quantity of a mixture (gas, solid, liquid, or combinations thereof), during a phase transition, into a number of smaller fractions in which the composition varies according to a gradient. In one or more embodiments, the fractionation system 704 may be a multi-stage fractionation system. In such embodiments, the fractionation system 704 may comprise multiple fractionation devices in series. For example, the fractionation system 704 may comprise multiple separators and may include reflux or recycle streams between the separators.

[0036] In one or more embodiments, the second liquid stream 312 may be separated into a light fraction 326, a recycle stream 328, and a second product stream 331. The second productstream 331 may comprise more condensable hydrocarbons. For example, the second product stream 331 may comprise one or more of C2, C3, and C4 hydrocarbons. In one or more embodiments, the second product stream 331 may comprise one or more of C2, C3, and C4 olefins. In one or more embodiments, the light fraction 326 may comprise C2 hydrocarbons. In one or more embodiments, the recycle stream 328 may comprise one or more of C2 and C3 hydrocarbons.

[0037] In one or more embodiments, the pressure of the light fraction 326 may be reduced to cool the light fraction 326 and form a cooled light fraction 327. The pressure of the light fraction 326 may be reduced by passing the light fraction 326 through valve 503. In such embodiments, the cooled light fraction 327 may be passed to heat exchanger 602 to provide cooling to heat exchanger 602. The cooled light fraction 327 may be warmed in heat exchanger 602 and may exit the system as a third product stream 329.

[0038] In one or more embodiments, the first liquid stream 306 may also be passed to the fractionation system 704. In some embodiments, as depicted in FIG. 2, the first liquid stream 306 may be combined with the second liquid stream 312 upstream of the fractionation system 704 to form a fractionator feed stream 319. In embodiments where the first liquid stream 306 is passed to the fractionation system 704, the first liquid stream 306 and the second liquid stream 312 may be separated into the light fraction 326, the recycle stream 328, and the second product stream 331.

[0039] Still referring to FIG. 2, a pressure of the recycle stream 328 may be reduced to at least partially vaporize the recycle stream 328 to form a first coolant stream 330. In one or more embodiments, the pressure of the recycle stream 328 may be reduced by passing the recycle stream 328 through valve 502. The first coolant stream 330 may be passed through heat exchanger 600 to provide cooling in heat exchanger 600 and to form a second coolant stream 334. It should be noted that in some embodiments, the first coolant stream 330 may be passed through one or more heat exchangers to form the second coolant stream 334.

[0040] The second coolant stream 334 may be passed through heat exchanger 602 to provide cooling in heat exchanger 602. In some embodiments, the second coolant stream 334 may be warmed in heat exchanger 602 to produce a warmed stream 336. In one or more embodiments, the warmed stream 336 may exit the cold box 620. Referring now to FIG. 1, in one or moreembodiments, at least a portion of the warmed stream 336 may be recycled to the compressor system 208, as a recycle stream.

[0041] Referring now to FIG. 1, in one or more embodiments, the third non-condensable gas stream 126 may be split, and portions of the third non-condensable gas stream may be passed to various components of the reactor system 100. For example, at least a portion of the third non- condensable gas stream 126 may be passed to one or more of: the combustor 206, a pressure swing adsorption system 230, the dehydrogenation reactor 204, the compressor 208, the reactor feed pretreatment bed 202, or the dryer 210. In one or more embodiments, a portion of the third non- condensable gas stream 126 may exit the reactor system as a byproduct. It should be understood that, as used in the present disclosure, the “reactor system 100” includes system components for both the reaction and the separation of hydrocarbons, which in some contexts may be considered part of separate reactor and separator systems. For the purposes of the present disclose, reactor and separator system components described herein are referred to collectively as part of “reactor system 100.”

[0042] Referring to FIGS. 1 and 2, in one or more embodiments, the third non-condensable gas stream 126 is split downstream of the cold box 620. In such embodiments, no portion of the split third non-condensable gas stream 126 is recycled to the one or more heat exchangers positioned within cold box 620. Without intending to be bound by theory, splitting the third non- condensable gas stream 126 downstream of the cold box 620 may prevent temperature pinches in the one or more heat exchanges within the cold box. As used in the present application, a “temperature pinch” refers to a point in a heat exchanger where a difference in temperature between the hot fluid and the cold fluid is at or near zero. If a temperature pinch occurs in a heat exchanger, then cooling in the heat exchanger may be insufficient.

[0043] Referring again to FIG. 1, in one or more embodiments, at least a portion of the third non-condensable gas stream 126a may be passed to the dryer 210. The portion of the third non- condensable gas stream 126a may be used to at least partially regenerate the dryer 210. In one or more embodiments, at least partially regenerating the dryer 210 may comprise heating the portion of the third non-condensable gas stream 126a and passing the heated portion of the third non- condensable gas stream 126a through the dryer 210. This may remove water from the adsorbent of the dryer 210, regenerating the dryer 210. In one or more embodiments, the portion of the thirdnon-condensable gas stream 126a may be heated to a temperature from 200 °C to 300 °C before being passed through the dryer 210. In one or more embodiments, the portion of the third non- condensable gas stream 126a may be heated by high-pressure steam or electric heating. In one or more embodiments, not depicted, at least a portion of the third non-condensable gas stream 126a may be recombined with the third non-condensable gas stream 126 after it has been used to at least partially regenerate the dryer 210. The dryer 210 may be included at any suitable point in the reactor system 100. For example, in some embodiments, the dryer 210 may be positioned between one or more compressors in compressor system 208. In some embodiments, the dryer 210 may include one or more dryers positioned within separation unit 300. It should be noted that compressor system 208 and separation unit 300 may each comprise multiple pieces of equipment and dryer 210, while described separately in the present disclosure, may be positioned among the pieces of equipment included in the compressor system 208 or in the separation unit 300. In some embodiments, the dryer may be positioned between the compressor system 208 and the separation unit 300.

[0044] In one or more embodiments, at least a portion of the third non-condensable gas stream 126b may be passed to a compressor. The compressor may be a compressor within compressor system 208. In one or more embodiments, at least a portion of the third non- condensable gas stream 126b may be passed to the compressor to control the average molecular weight of the compressed product stream 112. For example, in one or more embodiments, if the molecular weight of the compressed product stream 112 is too great, then the portion of the third non-condensable gas stream 126b passed to the compressor may be increased.

[0045] Still referring to FIG. 1, in one or more embodiments, at least a portion of the third non-condensable gas stream 126d may be passed to the dehydrogenation reactor 204. In one or more embodiments, at least a portion of the third non-condensable gas stream 126d may be passed to the dehydrogenation reactor 204 when the reactor is operating at decreased velocity. The dehydrogenation reactor 204 may be operating at decreased velocity when the reactor is operating at a velocity that is less than or equal to 80% of a target velocity for the reactor. It should be noted that the velocity of the reactor refers to the velocity of reactant and product gasses and solid particulates, such as catalyst, moving through the reactor. Without intending to be bound by theory, a decreased reactor velocity may indicate a reactor upset. Decreased reactor velocity may be caused, at least in part, by decreased temperature in the reactor, decreased conversion offeedstock to products in the reactor, decreased flow rate of feedstock to the reactor, and increased pressure within the reactor. Without intending to be bound by theory, at least a portion of the noncondensable gas stream 126d may be passed to the reactor to increase the velocity of gasses and solid particulates moving through the reactor to manage or mitigate reactor upsets.

[0046] In one or more embodiments, at least a portion of the third non-condensable gas stream 126e may be passed to the combustor 206. In one or more embodiments, the at least a portion of the third non-condensable gas stream 126e may be burned in the combustor as supplemental fuel. In such embodiments, the portion of the third non-condensable gas stream 126e may comprise a sufficient concentration of combustible gasses, such as hydrogen and methane, that the portion of the third non-condensable gas stream 126e may be used as a supplemental fuel in the combustor 206. As previously described, particulate solids used in the dehydrogenation reactor 204 may be heated in the combustor 206. In some embodiments, the particulate solids may be heated by burning coke that may accumulate on the particulate solids in the dehydrogenation reactor 204. If an insufficient amount of coke is formed on the particulate solids in the dehydrogenation reactor 204, then burning the coke in the combustor 206 may not provide sufficient heat to the particulate solids to maintain the temperature of the dehydrogenation reactor 204 when the regenerated particulate solids 110 are passed from the combustor 206 to the dehydrogenation reactor 204. In such embodiments, a portion of the third non-condensable gas stream 126e may be burned in the combustor 206 as a supplemental fuel to provide additional heat to the particulate solids and maintain the heat balance of the dehydrogenation reactor 204 and the combustor 206.

[0047] In one or more embodiments, at least a portion of the third non-condensable gas stream 126f may be passed to the reactor feed pretreatment bed 202. The portion of the third non- condensable gas stream 126f may be used to at least partially regenerate the reactor feed pretreatment bed 202. In one or more embodiments, at least partially regenerating the reactor feed pretreatment bed 202 may comprise heating the portion of the third non-condensable gas stream 126f and passing the heated portion of the third non-condensable gas stream 126f through the reactor feed pretreatment bed 202. This may remove water and / or sulfur from the adsorbent material in the reactor feed pretreatment bed 202, regenerating the reactor feed pretreatment bed 202. In one or more embodiments, the portion of the third non-condensable gas stream 126f may be heated to a temperature from 200 °C to 300 °C before being passed through the reactor feedpretreatment bed 202. In one or more embodiments, the portion of the third non-condensable gas stream 126f may be heated by high-pressure steam or electric heating.

[0048] Still referring to FIG. 1, in one or more embodiments, at least a portion of the third non-condensable gas stream 126c may be passed to a pressure swing adsorption system 230. As described herein, “pressure swing adsorption” is a technique used to separate some gas species from a mixture of gasses according to the gas species’ molecular characteristics and affinity for an adsorbent material. The pressure swing adsorption system 230 may comprise a compressor followed by any suitable pressure swing adsorption equipment. The pressure swing adsorption system 230 may use selective adsorbent material. The selective adsorbent material may be any material suitable for use in a pressure swing adsorption system to increase the concentration of hydrogen in a gas stream. In one or more embodiments, a concentration of hydrogen in the portion of the third non-condensable gas stream 126c may be increased in the pressure swing adsorption system 230 to form at least a fourth non-condensable gas stream 128.

[0049] In one or more embodiments, an off-gas stream 132 comprising one or more of methane, nitrogen, carbon monoxide and carbon dioxide, as well as hydrogen, is formed as a byproduct from the pressure swing adsorption system 230. The selective adsorbent material used in the pressure swing adsorption system 230 may be any material suitable for use in a pressure swing adsorption system to increase the concentration of methane, nitrogen, carbon monoxide and / or carbon dioxide in the off-gas stream 132 relative to the feed stream 126c. In one or more embodiments, at least a portion of the off-gas stream 132a may be passed to a compressor. The compressor may be a compressor within compressor system 208. In one or more embodiments, at least a portion of the off-gas stream 132a may be passed to the compressor to control the average molecular weight of the compressed product stream 112. The control of the molecular weight of the compressed product can be further refined by adjusting the relative amounts of non- condensable gas stream 126b and 132a that are fed to the compressor system 208. In one or more embodiments, a purge of the off-gas stream 132c may be combined with stream 126g to control the accumulation of components such as nitrogen, carbon monoxide, methane and carbon dioxide in stream 126g.

[0050] In one or more embodiments, at least a portion of the fourth non-condensable gas stream 128a may be passed to the combustor 206. In one or more embodiments, the portion of thefourth non-condensable gas stream 128a may be burned in the combustor as a supplemental fuel. As described hereinabove, supplemental fuel may be burned in the combustor 206 to provide heat to particulate solids in the combustor 206. The fourth non-condensable gas stream 128 may have a greater concentration of hydrogen than the third non-condensable gas stream 126, and the fourth non-condensable gas stream 128 may be a suitable supplemental fuel for the combustor 206.

[0051] In one or more embodiments, at least a portion of the fourth non-condensable stream 128d may be combined with the third non-condensable gas stream 126 to increase the concentration of hydrogen relative to the other components (namely nitrogen, methane, carbon monoxide, and carbon dioxide) in streams 126e and 126f. Without intending to be bound by theory, a lower concentration of methane in stream 126e may lead to a decrease in CO2 generation in the combustor 206.

[0052] In one or more embodiments, oxygen 145 may be fed to a reforming unit 234, which is part of a hydrogen generation system 232. The oxygen 145 may be produced by an air separation unit (not shown). Any separating unit capable of separating oxygen out of air may be used. The oxygen 145 may be oxygen from any source and is not limited to oxygen from an air separation unit. In one or more embodiments, oxygen 145, and / or steam (not shown), or combinations thereof is fed to the reforming unit 234. In one or more embodiments, steam may be generated within the reforming unit 234 that can be used internally within reforming unit 234 or exported for external use (not shown).

[0053] In the hydrogen generation system 232, at least a portion of the off-gas stream 132b from the pressure swing adsorption system 230 may be combined with oxygen 145 and reacted at elevated temperatures (>800°C) to generate syngas 142 from the methane in off-gas stream 132b in the reforming unit 234. In embodiments, the reforming unit 234 may be an autothermal reforming (ATR) unit. In other embodiments, the reforming unit may be a partial oxidation (POx) unit. In embodiments, the reforming unit 234 may be a steam reforming unit (SMR). It should be noted that CO2 generated from furnace heaters (not shown) in the reforming unit 234 may exit the reforming unit 234 and be captured and / or re-used in other processes.

[0054] In one or more embodiments, the syngas 142 produced at the reforming unit 234 may be sent to a water-gas-shift unit 236, within the hydrogen generation system 232, after being combined with steam 146. In one or more embodiments, the water-gas-shift unit 236 may includetwo water-gas-shift reactors operating in series. For example, the water-gas-shift unit 236 may comprise a high temperature water-gas-shift reactor followed by a low temperature water-gasshift reactor. In one or more embodiments, any suitable water-gas-shift unit 236 may be used. In one or more embodiments, the water-gas-shift reactor product stream may comprise greater than or equal to 50 wt.% of one or more of hydrogen and carbon dioxide. For example, water-gas-shift product may comprise greater than or equal to 50 wt.%, 60 wt.%, 70 wt.%, 80 wt.%, 90 wt.%, or even 95 wt.%, of hydrogen and carbon dioxide.

[0055] In one or more embodiments, the water-gas-shift reactor product comprising hydrogen and CO2 and is sent to a separation system within the water-gas-shift unit 236, where the CO2 is separated from the hydrogen. Any suitable separation unit that separates CO2 from hydrogen may be used as the separation unit. The CO2 155 recovered may then be collected and re-used in other processes (not shown). In one or more embodiments, the hydrogen rich product 152 may be combined with the at least a portion of the third non-condensable gas stream 126c fed to the pressure swing adsorption system 230 to further increase the concentration of hydrogen.

[0056] In one or more embodiments, relative flows of off-gas 132a and 132b may be adjusted to vary the feed to the hydrogen generation system 232. Without intending to be bound by theory, increasing the flow rate of off-gas 132b relative to the flow rate of off-gas 132a, may be used to increase the concentration of hydrogen in the third non-condensable gas stream 126 relative to methane. Furthermore, increasing the concentration of hydrogen in the third non- condensable gas stream 126, relative to methane, may result in a commensurate increase in the concentration of hydrogen in portions of third non-condensable gas stream 126e and 126f relative to methane. In one or more embodiments, a lower concentration of methane in the portion of the third non-condensable gas stream 126e may lead to a decrease in CO2 generation in the combustor 206.

[0057] In one or more embodiments, at least a portion of the fourth non-condensable gas stream 128c may be passed to a MAPD reactor system 232. As described herein a “MAPD reactor system” may be used to hydrogenation methylacetylene and propadiene. The at least a portion of the fourth non-condensable gas stream 128c may be passed to the MAPD reactor system 232 as a hydrogen source.

[0058] In one or more embodiments, at least a portion of the fourth non-condensable gas stream 128c may be passed from the reactor system 100 as a hydrogen product stream. Without intending to be bound by theory, the fourth non-condensable gas stream 128 may have some commercial value due to the content of hydrogen in the fourth non-condensable gas stream 128.

[0059] In one or more embodiments, at least a portion of the third non-condensable gas stream 126 g may exit the reactor system 100. In one or more embodiments, if an excess of the third non-condensable gas stream 126 is not being passed to another system component of the reactor system 100, then at least a portion of the third non-condensable gas stream 126g may be passed from the reactor system 100 as a byproduct.EXAMPLES

[0060] Various embodiments of the processes and systems for separating a feed stream will be further clarified in the following Examples. The Examples are illustrative in nature, and should not be understood to limit the subject matter of the present disclosure.

[0061] Example 1

[0062] Example 1 was conducted using an integrated separation train process model in Aspen plus for the reactor system depicted in FIGS. 1 and 2. Table 1 shows temperatures, pressures, and mass fractions ratios of streams depicted in FIGS. 1 and 2. The numbering of the streams included in Table 1 is consistent with the numbering of the streams in FIGS. 1 and 2 and the numbering used throughout the detailed description.Table 1.

[0063] As shown in Example 1, a third non-condensable gas stream 126 may be formed by the system depicted in FIGS. 1 and 2. The third non-condensable gas stream 126 may be suitable for recycling to various system components of the reactor system 100 as described hereinabove. Furthermore, separating the third non-condensable gas stream 126 downstream of the cold box 620 may prevent temperature pinches within the heat exchangers positioned within the cold box 620, as described in more detail hereinabove.

[0064] It is noted that one or more of the following claims utilize the term “wherein” as a transitional phrase. For the purposes of defining the present technology, it is noted that this term is introduced in the claims as an open-ended transitional phrase that is used to introduce a recitation of a series of characteristics of the structure and should be interpreted in like manner as the more commonly used open-ended preamble term “comprising.”

[0065] It should be understood that where a first component is described as “comprising” a second component, it is contemplated that, in some embodiments, the first component “consists of’ or “consists essentially of’ that second component. Additionally, the term “consisting essentially of’ is used in this disclosure to refer to quantitative values that do not materially affect the basic and novel characteristic(s) of the disclosure. For example, a chemical composition “consisting essentially of’ a particular chemical constituent or group of chemical constituents should be understood to mean that the composition includes at least about 99.5% of a that particular chemical constituent or group of chemical constituents.

[0066] It should be understood that any two quantitative values assigned to a property may constitute a range of that property, and all combinations of ranges formed from all stated quantitative values of a given property are contemplated in this disclosure.

[0067] The subject matter of the present disclosure has been described in detail and by reference to specific embodiments. It should be understood that any detailed description of a component or feature of an embodiment does not necessarily imply that the component or featureis essential to the particular embodiment or to any other embodiment. Further, it should be apparent to those skilled in the art that various modifications and variations can be made to the described embodiments without departing from the spirit and scope of the claimed subject matter.

Claims

CLAIMS1. A method for separating hydrocarbons, the method comprising: dehydrogenating a feed stream comprising one or more alkanes to form a product stream comprising one or more olefins, wherein the dehydrogenation takes place in a reactor system comprising one or more of: a combustor; a pressure swing adsorption system; a dehydrogenation reactor; a compressor; a reactor feed pretreatment bed; or a dryer; compressing the product stream to form a compressed product stream; separating the compressed product stream into at least a second product stream and a first non-condensable gas stream, wherein the first non-condensable gas stream comprises one or more of hydrogen, nitrogen, methane, carbon monoxide, and carbon dioxide, and wherein the second product stream comprises hydrocarbons; reducing the pressure of the first non-condensable gas stream to form a second non- condensable gas stream; heating the second non-condensable gas stream to form a third non-condensable gas stream, wherein the first non-condensable gas stream, the second non-condensable gas stream, and the third non-condensable gas stream have the same composition; and passing at least a portion of the third non-condensable gas stream to one or more of: the combustor; the pressure swing adsorption system;the dehydrogenation reactor; the compressor; the reactor feed pretreatment bed; or the dryer.

2. The method of claim 1, wherein the method comprises passing at least a portion of the third non-condensable gas stream to the combustor.

3. The method of claim 1, wherein the method comprises passing at least a portion of the third non-condensable gas stream to the pressure swing adsorption system.

4. The method of claim 3, wherein the third non-condensable gas stream comprises hydrogen and a concentration of hydrogen in the third non-condensable gas stream is increased in the pressure swing adsorption system to form a fourth non-condensable gas stream.

5. The method of claim 3 or 4, wherein an off-gas stream comprising hydrogen and one or more of methane, nitrogen, carbon monoxide, and carbon dioxide is passed from the pressure swing adsorption system to a hydrogen generation system.

6. The method of claim 5, wherein the hydrogen generation system comprises a reforming unit and a water-gas-shift unit; and wherein the method further comprises: reacting at least a portion of the off-gas stream with oxygen in the reforming unit to form syngas; andreacting at least a portion of the syngas with steam in the water-gas-shift unit to form at least hydrogen and carbon dioxide.

7. The method of claim 1, wherein the method comprises passing at least a portion of the third non-condensable gas stream to the dehydrogenation reactor.

8. The method of claim 1, wherein the method comprises passing at least a portion of the third non-condensable gas stream to the compressor.

9. The method of claim 8, wherein the compressing the mixed feed stream occurs in the compressor.

10. The method of claim 1, wherein the method comprises passing at least a portion of the third non-condensable gas stream to the reactor feed pretreatment bed.

11. The method of claim 10, wherein passing at least a portion of the third non-condensable gas stream to the reactor feed pretreatment bed at least partially regenerates the reactor feed pretreatment bed.

12. The method of claim 1, wherein the method comprises passing at least a portion of the third non-condensable gas stream to the dryer.

13. The method of claim 12, wherein passing at least a portion of the third non-condensable gas stream to the dryer at least partially regenerates the dryer.

14. The method of any one of claims 1 to 13, wherein the first non-condensable gas stream comprises at least 50 wt.% of one or more of hydrogen, nitrogen, methane, carbon monoxide, and carbon dioxide.

15. The method of any one of claims 1 to 14, wherein heating the second non-condensable gas stream occurs in one or more heat exchangers positioned within a cold box.

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