Process and system for upgrading hydrocarbons

Abstract

Methods of removing contaminants from refinery gas are provided. Such methods can include recovering a process gas comprising ethylene and propylene from a steam cracker effluent recovered from a steam cracker in a steam cracker facility. A refinery gas can be recovered from a refinery facility. The process gas can be compressed in a plurality of compressor stages. A pressure of the refinery gas can be determined. A compressor stage of the plurality of compressor stages can be selected for introduction of the refinery gas using the determined pressure of the refinery gas. The refinery gas can be introduced to the selected compressor stage to produce a combined gas that can include the process gas and the refinery gas. At least a portion of one or more impurities can be removed from the combined gas in the steam cracker facility to produce an upgraded combined gas.

Description

[0001] Cross Reference to Related Applications

[0002] This application claims priority to and the benefit of U.S. Provisional Application No. 63 / 135,300, filed January 8, 2021, and European Patent Application No. 21161156.1, filed March 8, 2021, the entire disclosures of which are incorporated herein by reference in their entireties. TECHNICAL FIELD

[0003] The embodiments disclosed herein generally relate to methods and systems for upgrading hydrocarbons. More specifically, such methods and systems relate to removing contaminants from refinery gas. BACKGROUND

[0004] A refinery gas can be produced in many refineries that upgrade hydrocarbons via one or more processes such as, for example, fluid catalytic cracking, coking, hydrocracking, hydrotreating, isomerization, reforming, hydrocarbon saturation, and hydrocarbon unsaturation. The refinery gas often contains valuable hydrocarbons such as ethane, propane, and / or other hydrocarbons.

[0005] In addition to valuable hydrocarbons, the refinery gas also typically contains a significant amount of one or more contaminants such as molecular nitrogen, nitrogen oxides, mercaptans, carbonyl sulfide, ammonia, and / or molecular oxygen. However, the amount of valuable hydrocarbons relative to the contaminants that need to be separated from them limits the recovery of hydrocarbons from an economic perspective. As such, refinery gas is conventionally sent to a flare, burner, or otherwise disposed of.

[0006] Accordingly, there is a need for improved methods and systems for recovering hydrocarbons from refinery gas. SUMMARY

[0007] Methods and systems for removing contaminants from refinery gas are provided. In some embodiments, a method can include recovering a process gas that can include ethylene and propylene from a steam cracker effluent recovered from a steam cracker in a steam cracker facility. The method can also include recovering a refinery gas from a refinery facility. The process gas can be compressed in a plurality of compressor stages. A pressure of the refinery gas can be determined. A compressor stage of the plurality of compressor stages can be selected for introducing the refinery gas using the determined pressure of the refinery gas. The refinery gas can be introduced into the selected compressor stage to produce a combined gas that can include the process gas and the refinery gas. At least a portion of one or more impurities can be removed from the combined gas in the steam cracker facility to produce an upgraded combined gas that is lean in the one or more impurities.

[0008] In other embodiments, a method of removing contaminants from refinery gas can include recovering refinery gas from a refinery facility and pre-treating the refinery gas to remove at least a portion of one or more first impurities that can include at least one of: molecular nitrogen, nitrogen oxides, and molecular oxygen to produce a pre-treated refinery gas. The method can also include recovering a process gas that can include ethylene and propylene from a steam cracker effluent in a steam cracker facility. The process gas can be compressed in a plurality of compressor stages to produce a compressed process gas. A pressure, a composition, or a pressure and a composition of the pre-treated refinery gas can be determined. A location in the steam cracker facility can be selected for combining at least a portion of the pre-treated refinery gas with the compressed process gas using the pressure, the composition, or the pressure and the composition of the pre-treated refinery gas. At least a portion of the pre-treated refinery gas can be added to the process gas at the selected location to produce a combined gas that can include the process gas and the refinery gas. At least a portion of one or more second impurities can be removed from the combined gas in the steam cracker facility to produce an upgraded combined gas that is lean in the one or more second impurities.

[0009] In other embodiments, a method of removing contaminants from refinery gas can include recovering a refinery gas that can include one or more Ci-C5hydrocarbons and carbonyl sulfide from a refinery facility. The refinery gas can be contacted with an adsorbent under conditions sufficient to cause at least a portion of the carbonyl sulfide to adsorb onto the adsorbent to produce a pre-treated refinery gas lean in carbonyl sulfide and an adsorbent rich in carbonyl sulfide. The adsorbent rich in carbonyl sulfide can be contacted with a regeneration gas to produce a regenerated adsorbent and a desorption effluent comprising sulfur-based contaminants. The desorption effluent can be introduced into a pyrolysis zone of a steam cracker in a steam cracker facility to produce a steam cracker effluent. A process gas that can include one or more Ci-C4hydrocarbons can be recovered from the steam cracker effluent. In some embodiments, the process gas can also include C 5+ hydrocarbons. The process gas can be compressed in a plurality of compressor stages to produce a compressed process gas. The pre-treated refinery gas and the compressed process gas can be combined to produce a combined gas that can include the pre-treated refinery gas and the process gas. One or more impurities can be removed from the combined gas in the steam cracker facility to produce an upgraded combined gas that is lean in the one or more impurities.

[0010] BRIEF DESCRIPTION OF DRAWINGS

[0011] In order that the manner in which the above-recited features of the present application can be understood in detail, a more particular description of the application, briefly summarized above, can be had by reference to embodiments, some of which are illustrated in the appended drawings. It is to be noted, however, that the appended drawings illustrate only typical embodiments of this application and are therefore not to be considered limiting of its scope, for the application can admit to other equally effective embodiments.

[0012] Figure 1A schematic of an illustrative system for removing one or more contaminants from refinery gas and / or pretreated refinery gas recovered from a refinery facility is described in accordance with one or more embodiments described.

[0013] Figure 2 A schematic of an illustrative pretreatment stage for pretreating refinery gas and recovering fuel gas and pretreated refinery gas therefrom is described in accordance with one or more embodiments described.

[0014] Figure 3 A schematic of another illustrative pretreatment stage for pretreating refinery gas to remove at least a portion of any nitrogen oxides and / or at least a portion of any molecular oxygen is described in accordance with one or more embodiments described.

[0015] Figure 4 Another illustrative pretreatment stage for pretreating refinery gas by removing at least a portion of any carbonyl sulfide therefrom is described in accordance with one or more embodiments described.

[0016] Detailed Description

[0017] It is to be understood that the following disclosure describes several exemplary embodiments for implementing various features, structures, and / or functions of the present application. Exemplary embodiments of components, arrangements, and configurations are described below in order to simplify the present disclosure and to provide a concrete basis for the claims. These exemplary embodiments are not intended to limit the scope of the present application in any way but are included to provide one or more examples of how the present application can be implemented. It will be apparent to one of ordinary skill in the art that other exemplary embodiments and / or configurations not specifically described herein can be used without departing from the scope of the present application. Therefore, the scope of the present application should be determined not with reference to this disclosure, but should be determined with reference to the appended claims along with the full range of equivalents to which they are entitled.

[0018] As used herein, the indefinite articles "a" or "an" means "at least one" unless otherwise specified or clearly indicated from the context to mean a single instance only. Thus, use of the embodiment of "a separator" includes embodiments where one or two or more separators are used, unless specified to the contrary or the context clearly indicates otherwise. Likewise, use of the embodiment of "a separation stage" includes embodiments where one or two or more separation stages are used, unless specified to the contrary.

[0019] Definitions

[0020] The term "refinery gas" is refinery off-gas and refers to a gaseous stream recovered from a petroleum and / or petrochemical facility that upgrades one or more hydrocarbons via any upgrading process other than steam cracking. Facilities that can produce refinery gas include, but are not limited to, hydrocarbon upgrading processes including fluid catalytic cracking, coking, hydrocracking, hydrotreating, isomerization, reforming, decoking, hydrocarbon combustion, hydrocarbon distillation, hydrocarbon unsaturation, and hydrocarbon saturation processes. The term "process gas" refers to a gaseous stream recovered from a steam cracker effluent in a steam cracker facility.

[0021] As used herein, the term "hydrocarbon" means a class of compounds containing carbon bonded to hydrogen. The term "C n "hydrocarbon" means a hydrocarbon having n carbon atoms per molecule, where n is a positive integer. The term "C n+ "hydrocarbon" means a hydrocarbon having at least n carbon atoms per molecule, where n is a positive integer. The term "C n- "hydrocarbon" means a hydrocarbon having no more than n carbon atoms per molecule, where n is a positive integer. "Hydrocarbon" encompasses (i) saturated hydrocarbons, (ii) unsaturated hydrocarbons, and (iii) mixtures of hydrocarbons, including mixtures of (saturated and / or unsaturated) hydrocarbon compounds, including mixtures of hydrocarbon compounds having different n values.

[0022] The term "unsaturated" or "unsaturated hydrocarbon" means a C 2+ hydrocarbon containing at least one carbon atom directly bonded to another carbon atom through a double or triple bond. In other words, an olefin is a compound containing at least one pair of carbon atoms, wherein the first and second carbon atoms of the pair are directly connected by a double bond. "Light olefin" means a C 5- olefin.

[0023] The term "predominantly liquid phase" means a composition in which > 50 wt%, for example > 75 wt%, for example > 90 wt%, is in the liquid phase. A hydrocarbon feedstock is a predominantly liquid phase hydrocarbon feedstock when > 50 wt%, for example > 75 wt%, for example > 90 wt%, of the hydrocarbon feedstock is in the liquid phase at a temperature of 25 °C and a pressure of 1 bar absolute.

[0024] The term "raw" feedstock, for example raw hydrocarbon feedstock, means a predominantly liquid phase feedstock comprising > 25 wt%, for example > 50 wt%, for example > 75 wt%, or > 90 wt%, of a crude oil that has not been previously desalted and / or previously reflux fractionated.

[0025] The term "crude oil" means a naturally occurring mixture of hydrocarbons of geological origin, wherein the mixture (i) comprises > 1 wt%, such as > 5 wt%, such as > 10 wt% of residuum and (ii) has an API gravity of < 52°, such as < 30°, such as < 20° or < 10° or < 8°. Crude oils can be classified by API gravity, for example, heavy crude oils have an API gravity in the range from 5° up to, but not limited to, 22°.

[0026] Standard boiling points and standard boiling point ranges can be measured by gas chromatography distillation according to the methods described in ASTM D-6352-98 or D2887, with materials greater than 700°C being extended by extrapolation. The term "T 50 " means the temperature determined from a boiling point distribution in which 50 weight percent of a particular sample has reached its boiling point. Likewise, "T 90 ", "T 95 ", and "T 98 " means the temperature at which 90, 95, or 98 weight percent of a particular sample has reached its boiling point. The standard final boiling point means the temperature at which 99.5 weight percent of a particular sample has reached its boiling point.

[0027] Certain medium and / or heavy hydrocarbons, such as certain virgin hydrocarbon feedstocks, such as certain crude oils and crude oil mixtures contain one or more of asphaltenes, asphaltene precursors, and particulates. Asphaltenes are described in U.S. Patent No. 5,871,634. Asphaltene content can be determined using ASTM D6560-17. Asphaltenes in a hydrocarbon can be in a liquid phase (e.g., miscible liquid phase), as well as in a solid and / or semi-solid phase (e.g., as a precipitate). Asphaltenes and asphaltene precursors are typically present in the residuum portion of a crude oil. "Residuum" means an oil-like mixture, typically contained in or derived from a crude oil, having a standard boiling point range of > 1050°F (566°C). Residuum can include "non-volatile components," meaning compositions (organic and / or inorganic) having a standard boiling point range of > 590°C. Non-volatile components can be further limited to components having a boiling point of about 760°C or greater. Non-volatile components can include coke precursors, which are moderately heavy and / or reactive molecules, such as polycyclic aromatics, that can be condensed from the gas phase and then form coke under prescribed steam cracking conditions. Medium and / or heavy hydrocarbons, particularly their residuum portions, can also contain particulates, meaning solids and / or semi-solids in particulate form. Particulates can be organic and / or inorganic and can include coke, ash, sand, precipitated salts, and the like. While precipitated asphaltenes can be solid or semi-solid, precipitated asphaltenes are considered in the classification of asphaltenes rather than in the classification of particulates.

[0028] Hydrocarbon upgrading

[0029] Figure 1This illustration depicts a system for removing one or more contaminants from refined gas recovered from line 102 (recycled from refining facility 101) and / or pretreated refined gas from line 105, according to one or more embodiments. The system may include refining facility 101 and steam pyrolysis facility 110. The steam pyrolysis facility may include one or more steam pyrolysis units 115 and one or more recovery units 114. It has been found that the refined gas from line 102 and / or the pretreated refined gas from line 105 can be introduced into steam pyrolysis facility 110 and mixed, or combined with process gas within recovery unit 114 to produce a combined gas.

[0030] The refined gas in pipeline 102 and / or the pretreated refined gas in pipeline 105 may be, or may include but is not limited to, molecular hydrogen, one or more C1-C5 alkanes, one or more C2-C5 olefins, and one or more contaminants. In some embodiments, the refined gas in pipeline 105 may include C 5+ Hydrocarbons, such as C6-C9 hydrocarbons. One or more contaminants or impurities that may be present in the refined gas may be, or may include, but are not limited to, ammonia, methanol, methyl mercaptan, ethyl mercaptan, hydrogen sulfide, carbon monoxide, carbon dioxide, acetaldehyde, carbonyl sulfide (COS), water vapor, molecular nitrogen, one or more nitrogen oxides, molecular oxygen, mercury, arsine, silicon, carbon disulfide, one or more oxygen-containing compounds, one or more thiophenes, acetylene, or any mixture thereof.

[0031] One or more contaminants in the refined gas 102 and / or the pretreated refined gas in line 105 can be removed from the combined gas in one or more contaminant removal stages within the recovery facility 114. In some embodiments, at least a portion of the refined gas may be introduced via line 103 into pretreatment stage 104 to remove at least a portion of one or more contaminants and produce pretreated refined gas in line 105. In some embodiments, pretreatment stage 104 may be, or may include, but is not limited to, compression, water scrubbing tower, amine scrubbing tower, alkali scrubbing tower, dehydrator, mercury removal, tail gas separation cold box, DeOx reactor, carbonyl sulfide removal stage, or any combination thereof, as described in more detail below.

[0032] Steam cracker facility 110 can generate process gas in line 129. The process gas in line 129 may be, or may include, molecular hydrogen, one or more C1-C5 alkanes, one or more C2-C5 olefins, and one or more contaminants, or mixtures thereof. In some embodiments, the process gas may include C 5+Hydrocarbons. The generation of process gas in line 129 is described in more detail below. One or more contaminants or impurities that may be present in the process gas may be, or may include, but are not limited to, ammonia, methanol, methyl mercaptan, ethyl mercaptan, hydrogen sulfide, carbon monoxide, carbon dioxide, acetaldehyde, carbonyl sulfide, water vapor, mercury, arsine, silicon, carbon disulfide, molecular nitrogen, one or more nitrogen oxides, one or more oxygen-containing compounds, one or more thiophenes, acetylene, one or more nitrogen oxides, or any mixture thereof.

[0033] Process gas can be introduced into the first stage 131 of the multistage compressor 130 via line 129. As shown, the multistage compressor includes a first stage 131 and a second stage 133. The multistage compressor may include any number of compression stages, such as 2, 3, 4, 5, 6 or more. It should be understood that the multistage compressor 130 may also include one or more cooling stages between any two compression stages to cool the compressed fluid leaving a stage before it enters the next stage.

[0034] In some embodiments, the pressure of the refined gas in line 102 and / or the pressure of the pretreated refined gas in line 105 can be determined. A compressor stage in the multistage compressor 130 can be selected to introduce the refined gas in line 102 and / or the pretreated refined gas in line 105, based at least in part on the determined pressure of the refined gas in line 102 and / or the determined pressure of the pretreated refined gas in line 105. The refined gas in line 102 and / or the pretreated refined gas in line 105 can be combined with process gas just before the first stage 131, between the first stage 131 and the second stage 133, between the second stage 133 and the third stage, between any two additional stages, or with compressed process gas exiting the multistage compressor 130 via line 134.

[0035] In another embodiment, the process gas in line 129 may be introduced into the multistage compressor 130 and the compressed process gas may be recovered therefrom via line 134. The pressure and composition, or pressure and composition, of the pretreated refining gas in line 105 may be determined. A location within the recovery facility 114 may be selected for combining at least a portion of the pretreated refining gas in line 105 with the compressed process gas in line 134. In some embodiments, the pretreated process gas may be combined with the compressed process gas in line 134. In other embodiments, the pretreated process gas in line 105 may be combined with compressed process gas that may be present between or within any one or more of the separation, compression, and / or contaminant removal stages in the recovery facility 114, as described in more detail below. In still other embodiments, the pretreated process gas in line 105 may be combined with the process gas in line 129, the compressed process gas in line 132, the process gas compressed between any additional compression stages, and / or the compressed process gas in line 134.

[0036] As shown, refined gas via line 102 and / or pretreated refined gas via line 105 can be combined with compressed process gas in line 132 between the first compression stage 131 and the second compression stage 133 to produce a mixture of process gas and refined gas and / or pretreated refined gas, or simply a combined gas in line 132. The combined gas via line 132 can be introduced into the second stage 133 of the multistage compressor to produce a compressed combined gas via line 134 that may include process gas and refined gas and / or pretreated refined gas, which can be diverted from the multistage compressor 130.

[0037] The compressed combined gas via line 134 can be introduced into amine tower 135 for purification, for example by removing hydrogen sulfide and / or other acidic gases. The amine tower may also receive a lean solution of one or more light amines via line 122. At least a portion of any acidic gases in the combined gas can be transferred to the lean amine solution, thereby producing a rich amine solution that can be discharged via line 106. The processed combined gas via line 137 can be introduced into alkali tower 138 for additional treatment, such as treatment with an aqueous hydroxide solution, such as sodium hydroxide, to further reduce the content of any acidic gases in the combined gas. The upgraded combined gas can be discharged from alkali tower 138 via line 139.

[0038] The upgraded combined gas can be introduced into the separation stage 140 via pipeline 139, which can separate the bottom stream via pipeline 141 and the top stream via pipeline 142. The bottom stream may include C 3+ Hydrocarbons and overhead feed streams may include molecular hydrogen, C1-C2 hydrocarbons, and some C4 hydrocarbons. 3+ Hydrocarbons. It should be understood that the invention is not limited to hydrocarbons. Figure 1 The described embodiments. Thus, this description should not be construed as excluding other embodiments within the broad scope of the invention, such as those wherein (i) the overhead feed stream in line 142 comprises methane and molecular hydrogen and the bottom feed stream in line 141 comprises C 2+ Hydrocarbons, or (ii) the overhead feed in line 142 comprising molecular hydrogen and C 3- The hydrocarbon and bottom feed stream in pipeline 141 includes C 4+ Implementation schemes for hydrocarbons. Therefore, those skilled in the art will appreciate that, in addition to the hydrocarbons... Figure 1 In addition to the illustrated implementation, various separation and upgrading process configurations can be arranged in many different configurations within the scope of this invention.

[0039] The bottom feed stream via line 141 can be introduced into separation stage 113, which can separate the bottom feed stream via line 143 and the top feed stream via line 144. The bottom feed stream in line 143 may include C 4+The hydrocarbon and overhead stream in line 144 may include C3 hydrocarbons. The bottom stream via line 143 may be introduced into separation stage 145, which separates the bottom stream via line 146 and the overhead stream via line 147. The bottom stream in line 146 may include C... 5+ The overhead feed stream in line 147 may include C4 hydrocarbons. The bottom feed stream via line 146 may be introduced into the gasoline hydrotreating unit 148 to produce various gasoline products that can be recovered via line 149.

[0040] The overhead material in pipeline 144, including C3 hydrocarbons, can be transferred to additional processing stages, which may include, but are not limited to, (i) a methanol / COS bed 150, then through pipeline 151 to (ii) an arsine bed 152, and then through pipeline 153 to (iii) a methylacetylene and propadiene (MAPD) ​​converter 154, and then through pipeline 155 to (iv) a C3 separation stage, such as fractionator 156, for separating propylene via pipeline 157 and propane via pipeline 158. In some embodiments, the propane in pipeline 158 can be recycled to steam cracker 116 for cracking, for use in refining processes, for example, to refinery 101 for processing and / or recovery as a product.

[0041] The overhead material via line 142 can be introduced into compressor 160 for further compression. Compressor 160 may include a single compression stage or may be a multi-stage compressor that is the same as or similar to multi-stage compressor 130. From compressor 160, compressed molecular hydrogen, methane, and C2 hydrocarbons (possibly with some C42) can be produced. 3+ The feed stream of hydrocarbons is introduced via line 161 into a series of purification stages, which may include, but are not limited to, (i) a thiol and carbonyl sulfide removal bed 162, then through line 163 to (ii) an arsine bed 164, and then through line 165 to (iii) a C2 acetylene converter 166. The carbonyl sulfide removal bed 162 may include any suitable adsorbent or a combination thereof. Suitable adsorbents may be, or may include, alkaline-promoted alumina, such as sodium on alumina. Suitable commercially available adsorbents may include those available from BASF. and available from Axens 980 / 984. May include molecular hydrogen, methane, ethane, ethylene, and some C... 3+ A purified feed stream of hydrocarbons or mixtures thereof is introduced into separation stage 168 via line 167. Separation stage 168 can separate from the purified feed stream in line 167 at least (i) a first feed stream via line 169, which may include molecular hydrogen and methane, and (ii) a second feed stream via line 170, which may include C2 hydrocarbons, transferable to separation stage 171. Separator 171 can separate from the second feed stream (i) any residual C2 hydrocarbons. 3+Hydrocarbons, for example for recycling, are fed via line 172 to line 144 into methanol / COS bed 150, and (ii) include a stream of purified C2 hydrocarbons via line 173.

[0042] The carbonyl sulfide removal bed 162 can be regenerated periodically by introducing regenerated gas via line 159 into the carbonyl sulfide removal bed 162 and contacting it with a carbonyl sulfide-rich adsorbent to produce regenerated adsorbent and desorbed effluent, which may include one or more sulfur-based contaminants, recoverable via line 180. The regenerated gas may be, or may include, one or more C1-C4 alkanes. In some embodiments, the regenerated gas in line 159 may be recovered from the combined gas in recovery facility 114. For example, the regenerated gas may include methane from line 178, ethane from line 176, propane from line 158, and / or butane from line 147 separated from the combined gas. In some embodiments, the regenerated gas may contain <5 mol% of any olefin. In some embodiments, at least a portion of the desorbed effluent may be combined with the hydrocarbon feed from line 111 or the heated hydrocarbon feed from line 117 and introduced into steam cracker 115.

[0043] In some embodiments, the compressed combined gas in line 134, the processed combined gas in line 137, and / or the upgraded combined gas in line 139 may include water vapor. At least a portion of the water can be removed by condensation, adsorption, or other means, and by separating a dry gas from it. In some embodiments, at least a portion of the purified feed stream in line 167 may be introduced via line 190 into dehydrator 192 to remove at least a portion of the water vapor, thereby providing a dried feed stream via line 194, which may be introduced via line 167 into separation stage 168. Dehydrator 192 may be located at any suitable location within recovery facility 114. For example, the overhead feed stream in line 142 may be introduced into dehydrator 190, with the dried feed stream via line 194 introduced into carbonyl sulfide removal bed 162. In another example, the upgraded combined gas in line 139 may be introduced into dehydrator 190, with the dried feed stream via line 194 introduced into separation stage 140. As a supplement to or alternative to the dehydrator 190, water may be removed by one or more other means, such as during the compression of the overhead material in the line 142 via the compressor 160.

[0044] The feed stream in line 173 can be introduced into separation stage 174, from which at least (i) ethylene via line 175 and (ii) ethane via line 176 can be separated. The ethane can be recycled to steam cracker 116 for cracking, for use in refining processes, such as being fed to refinery 101 for processing and / or recovery as a product. Additional separation may optionally be performed. For example, separator 177 can be used to separate (i) methane via line 178 and (ii) molecular hydrogen via line 179 from the feed stream in line 169. In some embodiments, at least a portion of the separated methane in line 178 can be used as fuel gas and / or recycled to steam cracker 116 for the production of syngas and molecular hydrogen. In some embodiments, at least a portion of the molecular hydrogen in line 179 can be recycled to a hydroprocessing stage, for example for use in a modified gasoline hydrotreating unit 148.

[0045] In some embodiments, refined gas from line 102 and / or pretreated refined gas from line 105 may be introduced into the recovery facility 114 at one or more locations downstream of the multistage compressor 130. For example, the refined gas from line 102 and / or pretreated refined gas from line 105 may be combined with any one or more of the feed streams in lines 134, 137, 139, 141, 142, 161, 163, 165, 167, 190, 144, 151, 153, 155, 143, 170, and / or 146. The specific location at which the refined gas from line 102 and / or pretreated refined gas from line 105 may be introduced into the recovery facility 114 may depend at least in part on the composition and / or pressure of the refined gas from line 102 and / or pretreated refined gas from line 105. In at least one embodiment, the refined gas in line 102 and / or the pretreated refined gas in line 105 may be introduced into one of the multiple compressor stages, separation stages 156 and / or separation stages 145 of the multistage compressor 130.

[0046] Figure 2 This illustration depicts, according to one or more embodiments, an illustrative pretreatment stage 104 for pretreating refined gas in pipeline 103 and recovering fuel gas from pipeline 233 and pretreated refined gas from pipeline 105. In some embodiments, the refined gas in pipeline 103 may include molecular hydrogen, methane, C... 2+Alkanes and one or more impurities such as ammonia, water, and / or mercury. In some embodiments, pretreatment stage 104 may include, but is not limited to, compressor 205, water scrubbing tower 210, alkali tower 215, dehydrator 220, mercury removal stage 225, and separation stage 230. In some embodiments, pretreatment stage 104 may also include an optional amine tower, for example, between water scrubbing tower 210 and alkali tower 215. It should be understood that any one or more of compressor 205, water scrubbing tower 210, alkali tower 215, dehydrator 220, mercury removal stage 225, and separation stage 230 are optional and may be used or absent, at least in part, depending on the composition of the refined gas in line 103.

[0047] Refined gas via line 103 can be introduced into a compressor to produce compressed refined gas via line 206. The compressed refined gas via line 206 and wash water via line 208 can be introduced into and contacted in a water scrubbing tower 210. Overhead material via line 211 and wastewater via line 213 can be discharged from the water scrubbing tower 210. If the refined gas contains undesirable amounts of ammonia, the water scrubbing tower can reduce the ammonia concentration in the refined gas. Overhead material via line 211, wash water via line 212, and caustic alkali solution via line 214 can be introduced into an alkali tower 215 and contacted therein. The caustic alkali solution can be an aqueous hydroxide solution, such as sodium hydroxide, which can reduce the content of any acidic gases in the overhead stream introduced via line 211. Waste alkali via line 216 and overhead material via line 218 can be discharged from the alkali tower 215.

[0048] Overhead material via line 218 can be introduced into dehydrator 220 to remove at least a portion of any water vapor. The dried overhead material via line 222 can be diverted from dehydrator 220 to mercury removal stage 225. Mercury removal stage 225 removes at least a portion of any mercury or its compounds that may be present in the refined gas in line 103. Lean mercury overhead material can be diverted from mercury removal stage 225 to separation stage 230 via line 227. It should be understood that although dehydrator 220 and mercury removal stage 225 are shown as separate containers, they can be housed in a single container.

[0049] In some implementations, separation stage 230 may include, but is not limited to, a cold box and a demethanizer. Thus, the fuel gas feed stream via pipeline 233 and the C-containing gas stream via pipeline 105... 2+The refined gas from the pretreated hydrocarbons can be diverted from separation stage 230. In some embodiments, at least a portion of the fuel gas in line 233 and an oxidant, such as air, via line 235 can be introduced into and combusted in steam cracker 115 to generate at least a portion of the heat required to drive the steam cracking reaction within the radiant section 118 of steam cracker 115. In other embodiments, at least a portion of the fuel gas in line 233 and the oxidant in line 235 can be introduced into steam cracker 115, one or more boilers, one or more furnaces, one or more other combustion devices, or any combination thereof, and combusted therein to generate heat for heating the boilers, furnaces, and / or (one or more) other combustion devices. The refined gas from the pretreated hydrocarbons via line 105 can be combined with the process gas generated in steam cracker 115, as described above.

[0050] In some embodiments, combustion or fuel gas via line 240 and lean amine solution via line 243 may be introduced into and contacted in amine tower 250. Rich amine solution via line 252 and overhead material of lean acidic gas via line 254 may be discharged from amine tower 250. In some embodiments, overhead material via line 254 may be vented to the atmosphere or otherwise disposed of.

[0051] In an alternative embodiment, separation stage 230 (instead of including a cold box and a demethanizer) may include an adsorption-based demethanizer. By including an adsorption-based demethanizer, the process can operate at higher temperatures. By operating at higher temperatures, alkali removal can be achieved from alkali tower 215, dehydrator 220, and mercury removal stage 225, thus eliminating the costs associated with those devices. Therefore, in this alternative embodiment employing an adsorption-based demethanizer 230, pretreatment stage 104 may include, but is not limited to, compressor 205, water scrubbing tower 210, and separation stage 230 including an adsorption-based demethanizer.

[0052] Figure 3This describes a schematic of another illustrative pretreatment stage 104 for pretreating refined gas in line 103 to remove at least a portion of any nitrogen oxides and / or at least a portion of any molecular oxygen, according to one or more embodiments. Refined gas via line 103 may be introduced into compressor 305 to produce compressed refined gas via line 307. The compressed refined gas via line 307 and a lean amine solution via line 310 may be introduced into and contacted in amine tower 315. A rich amine solution via line 317 and a lean acidic gas overhead via line 319 may be discharged from amine tower 315. The overhead via line 319 may be introduced into DeOx reactor 325 to remove at least a portion of any oxygen, at least a portion of any nitrogen oxides, at least a portion of any acetylene, at least a portion of any mercury, at least a portion of any carbonyl sulfide, and / or at least a portion of any arsenic that may be present in the refined gas in line 103. DeOx reactor 325 may include one or more catalysts that can contact the refinery gas in the presence of molecular hydrogen under conditions sufficient to convert at least a portion of any nitrogen oxides to ammonia and / or at least a portion of any molecular oxygen to water. In some embodiments, the catalyst may be, or may include, but is not limited to, nickel-based sulfidation catalysts, copper-based catalysts, etc. The pretreated refinery gas via line 105 may be recovered from DeOx reactor 325 and combined with the process gas generated in steam cracker 115, as described above.

[0053] In alternative embodiments, pretreatment stage 104 may include compressor 305 and DeOx reactor 325, or amine tower 315 and DeOx reactor 325, or only DeOx reactor 325. In some cases, the use of compressor 305 and amine tower 315 may be optional and may depend at least in part on the pressure of the refined gas in line 103 and the amount of ammonia present in the refined gas in line 103.

[0054] Figure 4 This description describes another illustrative pretreatment stage 104 for pretreating refined gas in line 103 by removing at least a portion of any carbonyl sulfur, according to one or more embodiments. The refined gas via line 103 may be introduced into the carbonyl sulfur removal stage 410 and contacted with an adsorbent 412 to cause at least a portion of any carbonyl sulfur to be adsorbed onto the adsorbent, thereby producing a carbonyl sulfur-lean pretreated refined gas and a carbonyl sulfur-rich adsorbent. Suitable adsorbents 412 may be, or may include, commercially available adsorbents such as those available from BASF. and available from Axens 980 / 984. The pretreated refined gas via line 105 can be recovered from the carbonyl sulfur removal stage 410 and combined with the process gas produced in the steam cracker 115, as described above.

[0055] In some embodiments, the carbonyl sulfide removal stage 410 may include an adsorbent or a first adsorbent 412 and optionally a second adsorbent 414. The second adsorbent 414 removes at least a portion of any thiols contained in the refined gas line 103. Carbonyl sulfide-lean refined gas may be contacted with the second adsorbent 414 to produce pretreated refined gas via line 105. Suitable adsorbents 414 may be, or may include, one or more zeolites, such as 13X zeolite-based materials. Suitable commercially available adsorbents may include those available from BASF. CD and available from Axens 902. In some embodiments, the refined gas in pipeline 103 may come into contact with the first adsorbent 412 after the second adsorbent 414, or substantially simultaneously with the first adsorbent 412 and the second adsorbent 414.

[0056] In other implementation schemes, Figure 4 The pretreatment stage 104 shown may include an amine scrubber, an alkaline scrubber, or both, as a supplement to or alternative to the optional second adsorbent 414. In this embodiment, refined gas via line 103 may be introduced into an amine scrubber, an alkaline scrubber, an amine scrubber and then an alkaline scrubber, or an alkaline scrubber and then an amine scrubber, to produce intermediate-treated refined gas, which may have a reduced concentration of hydrogen sulfide and / or other acidic gases compared to the refined gas in line 103. The intermediate-treated refined gas may then be introduced into the carbonyl sulfide removal stage 410 and contacted with the first adsorbent 412 to produce the pretreated refined gas in line 105.

[0057] Adsorbent 412 and (if present) second adsorbent 414 can be periodically regenerated by contacting the adsorbent with regeneration gas introduced into the carbonyl sulfide removal stage 410 via line 416, thereby producing regenerated adsorbent 412 and (if present) regenerated second adsorbent 414 and desorbed effluent via line 420. The regeneration gas in line 416 may be, or may include, but is not limited to, hydrogen, methane, ethane, propane, butane, or mixtures thereof. In some embodiments, the regeneration gas in line 416 may be separated from the combined gas recovered from the recovery facility 114 in the steam cracker facility 110 or the upgraded combined gas. In some embodiments, at least a portion of the desorbed effluent via line 420 may be introduced into the pyrolysis zone of the steam cracker 115, thereby producing steam cracker effluent. In some embodiments, during the introduction of the desorbed effluent via line 420 into the pyrolysis zone of the steam cracker 115, line 119 ( Figure 1 At least a portion of the steam cracker effluent in the ) may include at least a portion of sulfur obtained from the desorption effluent as hydrogen sulfide.

[0058] Generation of process gases

[0059] Back Figure 1 The hydrocarbon feed in line 111 can be mixed, blended, combined, or otherwise contacted with water and / or steam in line 112 and heated in the convection section 116 of steam pyrolyzer 115 to produce a heated mixture in line 117. The heated mixture can be subjected to steam cracking conditions in the radiant section 118 of steam pyrolyzer 115 to produce a steam pyrolyzer effluent via line 119. In some embodiments, when a sufficiently heavy hydrocarbon feed is present in line 111, the heated mixture can be separated from the heated mixture in line 117 by introducing the heated mixture into one or more separation stages before subjecting it to steam cracking. The gaseous product can be heated to a temperature ≥400°C, for example, from about 425°C to about 825°C, and subjected to steam cracking conditions to produce a steam pyrolyzer effluent in line 119. The liquid product can be subjected to one or more additional upgrading processes known in the art. In some instances, the optional hydrocarbon feed separation stage and the upgrading of the liquid phase product may be or include those disclosed in U.S. Patent Nos. 7,138,047, 7,090,765, 7,097,758, 7,820,035, 7,311,746, 7,220,887, 7,244,871, 7,247,765, 7,351,872, 7,297,833, 7,488,459, 7,312,371, 6,632,351, 7,578,929, 7,235,705, and 8,158,840.

[0060] The hydrocarbon feed introduced into the steam cracker via pipeline 111 may include, or may include, but is not limited to: crude oil, desalted crude oil, gas oil, heating oil, jet fuel, diesel, kerosene, gasoline, coking naphtha, steam-cracked naphtha, catalytic-cracked naphtha, hydrocracking oil, reformate, residual oil reformate, Fischer-Tropsch synthesis liquid, Fischer-Tropsch synthesis gas, natural gasoline, distillate, straight-run naphtha, atmospheric tubular furnace bottoms, and vacuum tubular furnace charge streams, such as vacuum tubular furnace bottoms and... The feedstock includes: wide-boiling-range vacuum tubular furnace naphtha-gas oil condensate, heavy non-straight-run hydrocarbons from refineries, vacuum gas oil, heavy gas oil, crude oil-contaminated naphtha, atmospheric residue, heavy residue, C4 / residue mixtures, naphtha / residue mixtures, hydrocarbon gas / residue mixtures, hydrogen / residue mixtures, waxy residue, gas oil / residue mixtures, relatively light alkanes such as ethane, propane, butane, pentane, or mixtures thereof, their fractions, or any mixtures thereof. In at least some embodiments, the hydrocarbon feedstock may be, or may include, naphtha, gas oil, vacuum gas oil, waxy residue, atmospheric residue, crude oil, their fractions, or mixtures thereof. In some embodiments, if the raw crude oil or other hydrocarbons containing salts are to be steam-cracked, the raw crude oil or other hydrocarbons may optionally be pretreated, such as desalted, to remove at least a portion of any salts contained in the raw crude oil or other hydrocarbons before heating the hydrocarbon feedstock to produce a heated mixture. In some embodiments, the hydrocarbon feed may primarily comprise relatively light hydrocarbons such as C2-C8 alkanes. Suitable hydrocarbon feeds may also be or include hydrocarbons or hydrocarbon feeds disclosed in U.S. Patent Nos. 7,993,435, 8,277,639, 8,696,888, 9,327,260, 9,637,694, 9,657,239, and 9,777,227, and International Patent Application Publication No. WO 2018 / 111574.

[0061] Steam cracking conditions may include, but are not limited to, one or more of the following: exposing the hydrocarbon feed to a temperature ≥400°C (e.g., measured at the radiant outlet of the steam cracking unit), such as about 700°C, about 800°C, or about 900°C to about 950°C, about 1,000°C, or about 1050°C; a pressure of about 0.1 bar to about 5 bar (absolute value); and / or a steam cracking residence time of about 0.01 seconds to about 5 seconds. In some instances, methods and systems for steam cracking hydrocarbon feeds may be disclosed in U.S. Patent Nos. 6,419,885, 7,993,435, 9,637,694, and 9,777,227, U.S. Patent Application Publication No. 2018 / 0170832, and International Patent Application Publication No. WO 2018 / 111574. The steam pyrolyzer effluent in line 119 can be at a temperature of ≥300°C, ≥400°C, ≥500°C, ≥600°C, ≥700°C, or ≥800°C. The steam pyrolyzer effluent in line 119 can be cooled to produce cooled steam pyrolyzer effluent.

[0062] As shown, cooled steam cracker effluent via line 121 can be introduced into primary fractionation column 123. The cooled steam cracker effluent can be separated within the primary fractionation column to provide bottoms or tar products via line 124, steam cracker quench oil via line 125, steam cracker gas oil via line 126, and overhead products including steam cracker naphtha and process gas via line 127. In some embodiments, the cooled steam cracker effluent via line 121 can be introduced into one or more separation stages, such as tar separation drums, to separate tar products and light products, wherein the light products are then introduced into the primary fractionation column. Suitable separation stages may include those disclosed in U.S. Patent Nos. 7,674,366, 7,718,049, 8,083,931, 8,092,671, and 8,105,479.

[0063] The overhead product via line 127 can be introduced into quench tower 128 along with quench water, such as recirculated quench water via line 107, to cool the overhead product. Process gas, including ethylene, propylene, or both, can be recovered via line 129, and a mixture including steam cracker naphtha and quench water via line 109 can be diverted from quench tower 128. It should be understood that although shown as separate containers, quench tower 128 can be integrated with primary fractionation tower 123.

[0064] A mixture of steam cracker naphtha and quench water in line 109 can be introduced into one or more separators 108. Steam cracker naphtha via line 181, quench water via line 183, and recirculated quench water via line 107 can be diverted from separator 108. Quenched water via line 183 can be removed from the system, for example, by introducing it into a wastewater treatment process, sending it to a wastewater stripper, a dilution steam generation system, etc. Recirculated quench water via line 107 can be recycled to quench tower 128. In some instances, recirculated quench water via line 107 can be cooled, for example, by air and / or water, and then recycled to quench tower 128. In some instances, recirculated quench water via line 107 can be recycled to quench tower 128 as a single return and / or divided into multiple returns to quench tower 128 and / or other process equipment.

[0065] A portion of the steam cracker naphtha via lines 181 and 185 can be removed and further processed. A portion of the steam cracker naphtha via lines 181 and 136 can be recycled to the top fractionation section as reflux. The steam cracker naphtha in line 185 may have a final boiling point of ≤260°C, as measured according to ASTM D2887-18. In some instances, the steam cracker naphtha may have a final boiling point of approximately 220°C, approximately 221°C, approximately 225°C, or approximately 230°C to approximately 235°C, approximately 240°C, approximately 245°C, approximately 250°C, or approximately 255°C. In some instances, the amount of steam pyrolysis gas oil diverted from primary fractionation column 123 via line 126 can be controlled or regulated to maintain the recovery rate of steam pyrolysis naphtha in line 185, which has a final boiling point of ≤260°C as measured according to ASTM D2887-18. The amount of steam pyrolysis naphtha recirculated via lines 181 and 136 relative to the cooled steam pyrolysis effluent introduced into primary fractionation column 123 via line 121 can be adjusted or controlled to provide the desired temperature and / or liquid loading within the top fractionation section of primary fractionation column 123.

[0066] Steam crackers, primary fractionation columns, other equipment, and process conditions are well known. Suitable steam crackers, primary fractionation columns, process gas recovery configurations, other equipment, and process conditions may include those disclosed in U.S. Patent Nos. 6,419,885, 7,560,019, 7,993,435, 8,105,479, 8,197,668, 8,882,991, 8,894,844, 9,637,694, and 9,777,227; U.S. Patent Application Publications Nos. 2014 / 0061096, 2014 / 0357923, 2016 / 0376511, 2018 / 0170832, 2019 / 0016975; and WO Publication No. WO 2018 / 111574.

[0067] List of Implementation Plans

[0068] This disclosure may further include the following non-restrictive implementations:

[0069] 1. A method for removing contaminants from refined gas, comprising: recovering process gas containing ethylene and propylene from steam pyrolysis effluent recovered from a steam pyrolysis facility; recovering refined gas from a refining facility; compressing the process gas in multiple compressor stages; determining the pressure of the refined gas; selecting a compressor stage from the multiple compressor stages for introducing the refined gas at the determined pressure; introducing the refined gas into the selected compressor stage to produce a combined gas containing the process gas and the refined gas; and removing at least a portion of one or more impurities from the combined gas from the steam pyrolysis facility to produce an upgraded combined gas leaning against one or more impurities.

[0070] 2. The method of paragraph 1, wherein one or more impurities comprise at least one of the following: ammonia, methanol, methyl mercaptan, ethyl mercaptan, hydrogen sulfide, carbon dioxide, and acetaldehyde, and wherein removing at least a portion of one or more impurities from the combined gas comprises contacting the combined gas with an amine solution, an inorganic alkaline solution, or a combination thereof to produce a waste amine solution, a waste alkali, or a combination thereof, and a combined gas depleted of one or more impurities.

[0071] 3. The method of paragraph 1 or 2, wherein one or more impurities comprise carbonyl sulfur, and wherein removing at least a portion of one or more impurities from the combined gas comprises contacting the combined gas with the adsorbent under conditions sufficient to cause at least a portion of the carbonyl sulfur to be adsorbed onto the adsorbent, thereby producing a carbonyl sulfur-poor treated combined gas and a carbonyl sulfur-rich adsorbent.

[0072] 4. The method of paragraph 3 further includes: contacting a carbonyl sulfur-rich adsorbent with a regeneration gas containing molecular hydrogen, one or more C1-C4 hydrocarbons, or a mixture thereof to produce a regenerated adsorbent and a desorbed effluent containing sulfur-based contaminants; and introducing at least a portion of the desorbed effluent into a pyrolysis zone in a steam cracker.

[0073] 5. The method of paragraph 3 or 4, wherein the regenerated gas contains one or more C1-C4 alkanes, wherein the regenerated gas contains <5 mol% of any olefin, and wherein the regenerated gas is recovered from the upgraded combined gas.

[0074] 6. The method of any one of paragraphs 1 to 5, wherein the combined gas contains water vapor, and wherein removing at least a portion of one or more impurities from the combined gas comprises removing at least a portion of the water vapor to produce a dry combined gas.

[0075] 7. The method of any one of paragraphs 1 to 6, wherein refined gas is recovered from a upgrading method comprising at least one of the following: fluidized catalytic cracking, coking, hydrocracking, hydrotreatment, isomerization, reforming, decoking, hydrocarbon combustion, and hydrocarbon distillation.

[0076] 8. The method of any one of paragraphs 1 to 7 further includes: recovering an alkane feed comprising at least one of ethane and propane from the upgraded combined gas; and introducing at least a portion of the alkane feed into the pyrolysis zone of a steam cracker.

[0077] 9. The method of any one of paragraphs 1 to 8 further includes pretreating the refined gas to remove at least a portion of one or more impurities to produce pretreated refined gas, said impurities comprising at least one of molecular nitrogen, nitrogen oxides, and molecular oxygen, wherein the pretreated refined gas is introduced into a selected compressor stage to produce a combined gas.

[0078] 10. A method for removing contaminants from refined gas, comprising: recovering refined gas from a refining facility; pretreating the refined gas to remove at least a portion of one or more first impurities comprising at least one of the following to produce pretreated refined gas: molecular nitrogen, nitrogen oxides, and molecular oxygen; recovering process gas comprising ethylene and propylene from steam pyrolysis effluent in a steam pyrolysis facility; compressing the process gas in multiple compressor stages to produce compressed process gas; determining the pressure, composition, or pressure and composition of the pretreated refined gas; selecting a location in the steam pyrolysis facility for combining at least a portion of the pretreated refined gas with the compressed process gas using the pressure, composition, or pressure and composition of the pretreated refined gas; adding at least a portion of the pretreated refined gas to the process gas at the selected location to produce a combined gas comprising the process gas and refined gas; and removing at least a portion of one or more second impurities from the combined gas in the steam pyrolysis facility to produce an upgraded combined gas leaning against one or more second impurities.

[0079] 11. The method in paragraph 10 also includes recovering tail gas and C from pretreated refined gas. 2+ A gas, wherein the exhaust gas contains at least one of molecular hydrogen and methane, and wherein C20 is released at a selected location. 2+ Gas is added to the process gas.

[0080] 12. The method of paragraph 11 further includes: introducing at least a portion of the exhaust gas and oxidant into a burner in a steam pyrolysis unit located in a steam pyrolysis facility; burning the exhaust gas to generate heat and combustion effluent; and transferring at least a portion of the heat to the radiant section of the steam pyrolysis unit.

[0081] 13. The method in paragraph 12 also includes contacting the combustion effluent with an aqueous inorganic alkaline solution to produce an exhaust effluent and a waste aqueous inorganic alkaline solution depleted of sulfur-based pollutants.

[0082] 14. The method of any one of paragraphs 10 to 13, wherein one or more first impurities further comprise at least one of ammonia, water and mercury, and wherein the pretreated refined gas further comprises removing at least a portion of any ammonia, at least a portion of any water and at least a portion of any mercury to produce the pretreated refined gas.

[0083] 15. The method of any one of paragraphs 10 to 14, wherein a selected location in the steam cracker facility includes one of a plurality of compressor stages, a deethanizer, a depropanizer, or a debutanizer.

[0084] 16. The method of any one of paragraphs 10 to 15, wherein the refined gas comprises at least one of nitrogen oxides and molecular oxygen, and wherein pretreatment of the refined gas comprises contacting the refined gas with a catalyst in the presence of molecular hydrogen under conditions sufficient to convert at least a portion of any nitrogen oxides into ammonia and at least a portion of any molecular oxygen into water.

[0085] 17. The method of any one of paragraphs 10 to 16, wherein one or more second impurities comprise at least one of the following: ammonia, arsine, carbon monoxide, methane, methanol, carbonyl sulfide, methyl mercaptan, ethyl mercaptan, hydrogen sulfide, carbon dioxide, acetaldehyde, water, mercury, silicon, carbon disulfide, one or more thiophenes and acetylene.

[0086] 18. The method of any one of paragraphs 10 to 17, wherein refined gas is recovered from a upgrading method comprising at least one of the following: fluidized catalytic cracking, coking, hydrocracking, hydrotreatment, isomerization, reforming, decoking, hydrocarbon combustion, and hydrocarbon distillation.

[0087] 19. A method for removing contaminants from refined gas, comprising: recovering refined gas containing one or more C1-C5 hydrocarbons and carbonyl sulfides from a refining facility; contacting the refined gas with the adsorbent under conditions sufficient to cause at least a portion of the carbonyl sulfides to be adsorbed onto an adsorbent, thereby producing a carbonyl sulfide-lean pretreated refined gas and a carbonyl sulfide-rich adsorbent; contacting the carbonyl sulfide-rich adsorbent with a regeneration gas to produce a regenerated adsorbent and a desorption effluent containing sulfur-based contaminants; introducing at least a portion of the desorption effluent into the pyrolysis zone of a steam pyrolyzer in a steam pyrolyzer facility to produce a steam pyrolyzer effluent; recovering process gas containing one or more C1-C4 hydrocarbons from the steam pyrolyzer effluent; compressing the process gas in multiple compressor stages to produce a compressed process gas; combining the pretreated refined gas and the compressed process gas to produce a combined gas containing the pretreated refined gas and the process gas; and removing one or more impurities from the combined gas in the steam pyrolyzer facility to produce an upgraded combined gas leaning against one or more impurities. In some implementations, the pressure of the refining gas can be determined, and one or more suitable locations within the recovery facility can be identified for introducing the refining gas. For example, the pressure of the process gas or the gaseous stream separated from it may be sufficient to allow the refining gas to be introduced and combined with it.

[0088] 20. The method of paragraph 19, wherein the regenerated gas comprises at least one of the following: hydrogen, methane, ethane, propane and butane separated from the combined gas.

[0089] 21. The method of paragraph 19 or 20, wherein during the introduction of the desorbed effluent into the pyrolysis zone, the steam cracker effluent contains at least a portion of sulfur obtained from the desorbed effluent as hydrogen sulfide.

[0090] 22. The method of any one of paragraphs 19 to 21, wherein removing one or more impurities from the combined gas comprises contacting the combined gas with an amine solution, an aqueous solution of an inorganic alkali or a combination thereof, thereby producing waste amine solution, waste alkali or a combination thereof, and an upgraded combined gas.

[0091] 23. The method of any one of paragraphs 19 to 22, wherein refined gas is recovered from a upgrading method comprising at least one of the following: fluidized catalytic cracking, coking, hydrocracking, hydrotreatment, isomerization, reforming, decoking, hydrocarbon combustion, and hydrocarbon distillation.

[0092] 24. The method of any one of paragraphs 19 to 23 further includes removing one or more acid gases from refined gas or pretreated refined gas to produce refined gas or pretreated refined gas leaning against one or more acid gases.

[0093] 25. The method of any one of paragraphs 19 to 23, wherein the adsorbent is a first adsorbent, wherein the refined gas further comprises thiols, the method further comprising contacting the refined gas with a second adsorbent under conditions sufficient to cause at least a portion of the thiols to be adsorbed onto a second adsorbent, thereby producing a pretreated refined gas lean in carbonyl sulfide and thiols and a first adsorbent rich in carbonyl sulfide and a second adsorbent rich in thiols.

[0094] 26. The method of paragraph 25, wherein the refined gas is first contacted with the following adsorbents: first with a first adsorbent and then with a second adsorbent, first with a second adsorbent and then with a first adsorbent, or substantially simultaneously with the first and second adsorbents.

[0095] Certain embodiments and features have been described using a set of upper and lower numerical limits. It should be understood that, unless otherwise indicated, a range from any lower limit to any upper limit is covered. Some of the lower, upper, and ranges appear in one or more of the following claims. All numerical values ​​are those indicated by “about” or “approximately” and take into account experimental errors and biases expected by one of ordinary skill in the art.

[0096] The foregoing defines various terms. Where a term used in the claims is not defined above, it shall be given the broadest definition already provided to a person skilled in the art, as reflected in at least one printed publication or authorized patent. Furthermore, for all jurisdictions where such inclusion is permissible, all patents, test procedures, and other documents referenced in this application are fully incorporated by reference, provided that such disclosure does not contradict this application.

[0097] While the foregoing relates to embodiments of the invention, other and further embodiments of the invention may be devised without departing from the basic scope of the invention, the scope of which is defined by the appended claims.

Claims

1. Methods for removing contaminants from refined gas, including: Process gas containing ethylene and propylene is recovered from the steam pyrolyzer effluent recovered from the steam pyrolyzer in the steam pyrolyzer facility. Refined gas is recovered from refining facilities; Compressing process gas in multiple compressor stages; Determine the pressure of the refining gas; Select one compressor stage from multiple compressor stages to introduce refined gas at a determined pressure; Refined gas is introduced into a selected compressor stage to produce a combined gas containing process gas and refined gas; and In a steam cracker facility, at least a portion of one or more impurities is removed from the combined gas containing process gas and refining gas to produce an upgraded combined gas leaning against one or more impurities. One or more of the impurities comprises carbonyl sulfide, and the removal of at least a portion of one or more impurities from the combined gas comprises: The combined gas is brought into contact with the adsorbent under conditions sufficient to cause at least a portion of the carbonyl sulfur to be adsorbed onto the adsorbent, thereby producing a carbonyl sulfur-poor treated combined gas and a carbonyl sulfur-poor adsorbent. By contacting a carbonyl sulfur-rich adsorbent with a regeneration gas containing molecular hydrogen, one or more C1-C4 hydrocarbons, or mixtures thereof, a regenerated adsorbent and a desorbed effluent containing sulfur-based contaminants are produced; and At least a portion of the desorbed effluent is introduced into the pyrolysis zone of the steam pyrolyzer.

2. The method according to claim 1, wherein one or more impurities further comprise at least one of the following: ammonia, methanol, methyl mercaptan, ethyl mercaptan, hydrogen sulfide, carbon dioxide, and acetaldehyde, and wherein removing at least a portion of one or more impurities from the combined gas further comprises contacting the combined gas with an amine solution, an inorganic alkaline solution, or a combination thereof to generate waste amine solution, waste alkali, or a combination thereof, and a combined gas depleted of one or more impurities.

3. The method of claim 1, wherein the regenerated gas comprises one or more C1-C4 alkanes, wherein the regenerated gas comprises <5 mol% olefins, and wherein the regenerated gas is recovered from the upgraded combined gas.

4. The method according to any one of claims 1-3, wherein the combined gas comprising process gas and refining gas further comprises water vapor, and wherein removing at least a portion of one or more impurities from the combined gas further comprises removing at least a portion of the water vapor to produce a dry combined gas.

5. The method according to any one of claims 1-3, wherein refined gas is recovered from a upgrading process comprising at least one of the following: fluidized catalytic cracking, coking, hydrotreating, isomerization, reforming, decoking, hydrocarbon combustion, and hydrocarbon distillation.

6. The method according to any one of claims 1-3, wherein refined gas is recovered from a upgrading process comprising hydrocracking.

7. The method according to any one of claims 1-3, further comprising: Recovery of alkane feed containing at least one of ethane and propane from upgraded combined gas; and At least a portion of the alkane feed is introduced into the pyrolysis zone of the steam cracker.

8. The method according to any one of claims 1-3, further comprising pretreating the refined gas to remove at least a portion of one or more impurities to produce pretreated refined gas, said impurities comprising at least one of molecular nitrogen, nitrogen oxides, and molecular oxygen, wherein the pretreated refined gas is introduced into a selected compressor stage to produce a combined gas.

9. Methods for removing contaminants from refined gas, including: Refined gas is recovered from refining facilities; Pre-treated refined gas is produced by removing at least a portion of one or more first impurities comprising at least one of the following: molecular nitrogen, nitrogen oxides, and molecular oxygen. Process gas containing ethylene and propylene is recovered from the effluent of a steam pyrolysis facility; Compressed process gas is produced by compressing process gas in multiple compressor stages; Determine the pressure and composition, or pressure and composition, of the pretreated refining gas; Select a location in the steam cracker facility for using the pressure, composition, or pressure and composition of pretreated refined gas to combine at least a portion of the pretreated refined gas with compressed process gas. At the selected location, at least a portion of the pretreated refined gas is added to the process gas to produce a combined gas containing both process gas and refined gas. and In a steam cracker facility, at least a portion of one or more second impurities is removed from the combined gas containing process gas and refining gas to produce an upgraded combined gas depleted of one or more second impurities. One or more of the second impurities comprises carbonyl sulfide, and the removal of at least a portion of one or more of the second impurities from the combined gas comprises: The combined gas is brought into contact with the adsorbent under conditions sufficient to cause at least a portion of the carbonyl sulfur to be adsorbed onto the adsorbent, thereby producing a carbonyl sulfur-poor treated combined gas and a carbonyl sulfur-poor adsorbent. By contacting a carbonyl sulfur-rich adsorbent with a regeneration gas containing molecular hydrogen, one or more C1-C4 hydrocarbons, or mixtures thereof, a regenerated adsorbent and a desorbed effluent containing sulfur-based contaminants are produced; and At least a portion of the desorbed effluent is introduced into the pyrolysis zone of the steam pyrolyzer.

10. The method of claim 9, further comprising recovering tail gas and C from the pretreated refined gas. 2+ A gas, wherein the exhaust gas contains at least one of molecular hydrogen and methane, and wherein C20 is released at a selected location. 2+ Gas is added to the process gas.

11. The method of claim 10, further comprising: At least a portion of the exhaust gas and oxidant is introduced into the burner in the steam pyrolysis unit located in the steam pyrolysis unit; Combustion exhaust gases generate heat and combustion effluent; and At least a portion of the heat is transferred to the radiant section of the steam pyrolyzer.

12. The method of claim 11, further comprising contacting the combustion effluent with an inorganic alkaline aqueous solution to generate an exhaust effluent and a waste inorganic alkaline aqueous solution depleted of sulfur-based pollutants.

13. The method according to any one of claims 9 to 12, wherein one or more first impurities further comprise at least one of ammonia, water and mercury, and wherein the pretreated refined gas further comprises removing at least a portion of any ammonia, at least a portion of any water and at least a portion of any mercury to produce the pretreated refined gas.

14. The method according to any one of claims 9 to 12, wherein a selected location in the steam cracker facility comprises one of a plurality of compressor stages, a deethaner, a depropaner, or a debutaner.

15. The method according to any one of claims 9 to 12, wherein the refined gas comprises at least one of nitrogen oxides and molecular oxygen, and wherein pretreatment of the refined gas comprises contacting the refined gas with a catalyst in the presence of molecular hydrogen under conditions sufficient to convert at least a portion of any nitrogen oxides into ammonia and at least a portion of any molecular oxygen into water.

16. The method according to any one of claims 9 to 12, wherein one or more second impurities further comprise at least one of the following: ammonia, arsine, carbon monoxide, methane, methanol, methyl mercaptan, ethyl mercaptan, hydrogen sulfide, carbon dioxide, acetaldehyde, water, mercury, silicon, carbon disulfide, one or more thiophene compounds, and acetylene.

17. The method according to any one of claims 9 to 12, wherein refined gas is recovered from a upgrading process comprising at least one of the following: fluidized catalytic cracking, coking, hydrotreating, isomerization, reforming, decoking, hydrocarbon combustion, and hydrocarbon distillation.

18. The method according to any one of claims 9 to 12, wherein refined gas is recovered from a upgrading process comprising hydrocracking.

19. Methods for removing contaminants from refined gas, including: Refined gas containing one or more C1-C5 hydrocarbons and carbonyl sulfides is recovered from refining facilities; The refined gas is brought into contact with the adsorbent under conditions sufficient to cause at least a portion of the carbonyl sulfur to be adsorbed onto the adsorbent, thereby producing a pretreated refined gas with carbonyl sulfur lean and an adsorbent rich in carbonyl sulfur. By contacting a carbonyl sulfur-rich adsorbent with a regeneration gas, a regeneration adsorbent and a desorbed effluent containing sulfur-based pollutants are produced. At least a portion of the desorbed effluent is introduced into the pyrolysis zone of the steam pyrolysis unit within the steam pyrolysis facility to generate steam pyrolysis effluent. Recover process gas containing one or more C1-C4 hydrocarbons from steam cracker effluent; Compressed process gas is produced by compressing process gas in multiple compressor stages; Combine pretreated refined gas and compressed process gas to produce a combined gas containing both pretreated refined gas and process gas; and In a steam pyrolysis facility, one or more impurities are removed from the combined gas containing pretreated refined gas and process gas to produce an upgraded combined gas that is depleted of one or more impurities.

20. The method of claim 19, wherein the regenerated gas comprises at least one of the following: hydrogen, methane, ethane, propane, and butane separated from the upgraded combined gas.

21. The method of claim 19 or claim 20, wherein during the introduction of the desorbed effluent into the pyrolysis zone, the steam cracker effluent contains at least a portion of sulfur obtained from the desorbed effluent as hydrogen sulfide.

22. The method according to claim 19 or claim 20, wherein removing one or more impurities from the combined gas comprises contacting the combined gas with an amine solution, an inorganic alkaline aqueous solution, or a combination thereof to produce waste amine solution, waste alkali, or a combination thereof, and an upgraded combined gas.

23. The method according to claim 19 or claim 20, wherein refined gas is recovered from an upgrading process comprising at least one of the following: fluidized catalytic cracking, coking, hydrotreating, isomerization, reforming, decoking, hydrocarbon combustion, and hydrocarbon distillation.

24. The method of claim 19 or claim 20, wherein refined gas is recovered from a upgrading process comprising hydrocracking.

25. The method of claim 19 or claim 20, further comprising removing one or more acid gases from the refined gas or pretreated refined gas to produce refined gas or pretreated refined gas leaning against one or more acid gases.

26. The method of claim 25, wherein the refined gas is first contacted with an adsorbent: first with a first adsorbent and then with a second adsorbent, first with a second adsorbent and then with a first adsorbent, or simultaneously with both adsorbents.

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