Controlled freeze zone tower

Process for removing a target gas from a mixture of gases by thermal swing adsorption

Temperature swing adsorption of CO2 from flue gas using a parallel channel contactor

TEMPERATURE SWING ADSORPTION OF CO2 FROM FLUE GAS USING A PARALLEL CHANNEL CONTACTOR

The adsorption of CO2 from flue gas streams using temperature swing adsorption. Adsorbent contactors are used in the temperature swing adsorption unit that contain a plurality of substantially parallel channels comprised of or coated with an adsorbent material that is selective for adsorbing CO2 from flue gas.

INNER SURFACE FEATURES FOR CO-CURRENT CONTACTORS

A co-current contactor (202a, 202b, 202c, 202d) for separating components in a fluid stream, the co-current contactor comprising a first inlet configured to receive the fluid stream proximate to a first end (208a, 208b, 208c, 208d) of the co-current contactor, a second inlet configured to receive a solvent proximate the first end of the co-current contactor, and a mass transfer section (222) configured to receive the fluid stream and the solvent and to provide a mixed, two-phase flow, wherein the mass transfer section comprises a surface feature along an inner surface of the mass transfer section configured to reduce film flow along an inner wall of the mass transfer section, and wherein the surface feature comprises at least one of a hydrophobic surface, a superhydrophobic surface, a porous wall surface, and a nonlinear surface irregularity extending radially inward or radially outward along the inner surface of the mass transfer section.

Integrated controlled freeze zone (CFZ) tower and dividing wall (DWC) for enhanced hydrocarbon recovery

The present invention relates to methods and apparatuses for the operation of a distillation tower containing a controlled freezing zone and at least one distillation section. The process and tower design are utilized for the additional recovery of hydrocarbons from an acid gas. In this process, a separation process is utilized in which a multi-component feedstream is introduced into an apparatus that operates under solids forming conditions for at least one of the feedstream components. The freezable component, although typically CO2, H2S, or another acid gas, can be any component that has the potential for forming solids in the separation system. A dividing wall is added to at least a portion of the lower distillation section of the apparatus to effect the separation of at least some fraction of the hydrocarbons in that portion of the tower.

Integration of cold solvent and acid gas removal

A method of separating impurities from a natural gas stream. CO ...

Removal of a target gas from a mixture of gases by swing adsorption with use of a turboexpander

Apparatus and system for enhanced selective contaminant removal processes related thereto

Systems and methods for separating CO

Method and system of controlling a temperature within a melt tray assembly of a distillation tower

A method and system of controlling a temperature within a melt tray assembly of a distillation tower. The method may include determining a melt tray fluid composition of a melt tray fluid, determining a melt tray fluid temperature of the melt tray fluid, determining if the melt tray fluid temperature is within an expected melt tray fluid temperature range for the melt tray fluid composition, decreasing the melt tray fluid temperature if the melt tray fluid temperature is greater than an expected melt tray fluid temperature range upper limit, increasing the melt tray fluid temperature if the melt tray fluid temperature is less than an expected melt tray fluid temperature range lower limit, and maintaining the melt tray fluid temperature if the melt tray fluid temperature is within the expected melt tray fluid temperature range.

Method and system for separating fluids in a distillation tower

A method and system for separating fluids in a distillation tower. The method may include feeding a stream to the distillation tower, wherein the stream includes carbon dioxide, reducing a carbon dioxide concentration of the stream received by the rectifier section by feeding a first cryogenic fluid to the controlled freeze zone section and accumulating rectifier section stream in at least one of a holding vessel and a sump of the rectifier section, and terminating reducing the carbon dioxide concentration when the carbon dioxide concentration of the stream travelling from the controlled freeze zone section to the rectifier section is less than or equal to a maximum carbon dioxide concentration. The first cryogenic fluid may comprise a substantially carbon-dioxide-free fluid.

COMPACT CONTACTING SYSTEMS AND METHODS FOR SCAVENGING SULFUR-CONTAINING COMPOUNDS

A hydrogen sulfide (H2S) scavenging system for removing H2S, mercaptans, and/or other sulfur-containing compounds from a natural gas stream. A co-current contacting system is located in-line within a pipe and receives the natural gas stream and a liquid scavenger stream. The co-current contacting system includes a co-current contactor including a droplet generator and a mass transfer section. The droplet generator generates droplets from the liquid scavenger stream and disperses the droplets into the natural gas stream. The mass transfer section provides a mixed, two-phase flow having a vapor phase and a liquid phase. The liquid phase includes the liquid scavenger stream with H2S, mercaptans, and/or other sulfur-containing compounds absorbed from the natural gas stream, and the vapor phase includes the natural gas stream. A separation system separates the vapor phase from the liquid phase.

METHOD AND SYSTEM OF CONTROLLING A TEMPERATURE WITHIN A MELT TRAY ASSEMBLY OF A DISTILLATION TOWER

A method and system of controlling a temperature within a melt tray assembly of a distillation tower. The method may include determining a melt tray fluid composition of a melt tray fluid, determining a melt tray fluid temperature of the melt tray fluid, determining if the melt tray fluid temperature is within an expected melt tray fluid temperature range for the melt tray fluid composition, decreasing the melt tray fluid temperature if the melt tray fluid temperature is greater than an expected melt tray fluid temperature range upper limit, increasing the melt tray fluid temperature if the melt tray fluid temperature is less than an expected melt tray fluid temperature range lower limit, and maintaining the melt tray fluid temperature if the melt tray fluid temperature is within the expected melt tray fluid temperature range.

INTEGRATED CONTROLLED FREEZE ZONE (CFZ) TOWER AND DIVIDING WALL (DWC) FOR ENHANCED HYDROCARBON RECOVERY

The present invention relates to methods and apparatuses for the operatio n of a distillation tower containing a controlled freezing zone and at least one distillation section. The process and tower design are utilized for the additional recovery of hydrocarbons from an acid gas. In this process, a se paration process is utilized in which a multi-component feedstream is introd uced into an apparatus that operates under solids forming conditions for at least one of the feedstream components. The freezable component, although ty pically CO2, H2S, or another acid gas, can be any component that has the pot ential for forming solids in the separation system. A dividing wall is added to at least a portion of the lower distillation section of the apparatus to effect the separation of at least some fraction of the hydrocarbons in that portion of the tower.

METHOD AND SYSTEM FOR SEPARATING FLUIDS IN A DISTILLATION TOWER

A method and system for separating fluids in a distillation tower. The method may include feeding a stream to the distillation tower, wherein the stream includes carbon dioxide, reducing a carbon dioxide concentration of the stream received by the rectifier section by feeding a first cryogenic fluid to the controlled freeze zone section and accumulating rectifier section stream in at least one of a holding vessel and a sump of the rectifier section, and terminating reducing the carbon dioxide concentration when the carbon dioxide concentration of the stream travelling from the controlled freeze zone section to the rectifier section is less than or equal to a maximum carbon dioxide concentration. The first cryogenic fluid may comprise a substantially carbon-dioxide-free fluid.

Integración de remoción de solvente frío y gas ácido.

UN MÉTODO PARA SEPARAR IMPUREZAS DE UNA CORRIENTE DE GAS NATURAL. LA CORRIENTE DE GAS NATURAL SE ENFRÍA A TRAVÉS DE INTERCAMBIO DE CALOR CON UNA O MÁS CORRIENTES DE PROCESO PARA PRODUCIR UNA CORRIENTE DE GAS REFRIGERADA QUE SE PONE EN CONTACTO CON UNA CORRIENTE DE SOLVENTE POBRE EN UN APARATO DE CONTACTO PARA SEPARAR SULFURO DE HIDRÓGENO (H2S) DE LA CORRIENTE DE GAS REFRIGERADA, PARA DE ESTA MANERA PRODUCIR UNA CORRIENTE DE SOLVENTE RICO Y UNA CORRIENTE DE GAS PARCIALMENTE TRATADA. EL DIÓXIDO DE CARBONO (CO2) Y H2S SE SEPARAN DE LA CORRIENTE DE GAS PARCIALMENTE TRATADA EN UN SISTEMA DE SEPARACIÓN DE MEMBRANA, PARA DE ESTA MANERA CREAR UNA CORRIENTE DE GAS COMPLETAMENTE TRATADA Y UNA CORRIENTE DE GAS DE PERMEADO, LA CORRIENTE DE GAS DE PERMEADO QUE ESTÁ COMPRENDIDA PRINCIPALMENTE DE H2S Y CO2, Y LA CORRIENTE DE GAS COMPLETAMENTE TRATADA QUE ESTÁ COMPRENDIDA PRINCIPALMENTE DE GAS NATURAL. LA CORRIENTE DE GAS COMPLETAMENTE TRATADA Y LA CORRIENTE DE GAS DE PERMEADO ESTÁN EN UNA TEMPERATURA ...

Removal of a target gas from a mixture of gases by swing adsorption with use of a turboexpander

The separation of a target gas selected from a high pressure gas mixture containing said target gas as well as a product gas using a swing adsorption process unit. A turboexpander is used upstream of the swing adsorber to reduce the pressure of the high pressure gas mixture. A compressor is optionally used downstream of the swing adsorber to increase the pressure of the target gas-containing stream for injecting into a subterranean formation.

Temperature swing adsorption of CO2 from flue gas using a parallel channel contactor

The adsorption of CO from flue gas streams using temperature swing adsorption. Adsorbent contactors are used in the temperature swing adsorption unit that contain a plurality of substantially parallel channels comprised of or coated with an adsorbent material that is selective for adsorbing CO from flue gas.

INTEGRATION OF COLD SOLVENT AND ACID GAS REMOVAL

A method of separating impurities from a natural gas stream. CO2 and H2S are separated from the natural gas stream in a membrane separation system, thereby creating a partially -treated gas stream and a permeate gas stream, both of which are at a lower temperature than the natural gas stream. The partially-treated gas stream is contacted with a first lean solvent stream in a first contactor to separate H2S from the partially -treated gas stream, thereby producing a first rich solvent stream and a fully -treated gas stream. The permeate gas stream is contacted with a second lean solvent stream in a second contactor to separate H2S therefrom to produce a second rich solvent stream and a CO2 gas stream. H2S and CO2 are removed from the first and second rich solvent streams, thereby producing the first and second lean solvent streams.

SYSTEMS AND METHODS FOR SEPARATING HYDROGEN SULFIDE FROM CARBON DIOXIDE IN A HIGH-PRESSURE MIXED STREAM

Systems and methods for separating hydrogen sulfide from carbon dioxide in a high-pressure mixed stream are disclosed herein. The methods include receiving the high-pressure mixed stream in an oxidation reactor and at an inlet pressure of at least 0.3 megapascals. The high-pressure mixed stream includes 0.01 to 5 mole percent hydrogen sulfide and at least 90 mole percent carbon dioxide. The methods further include oxidizing the high-pressure mixed stream with an oxidant to generate a high-pressure oxidized stream, includes oxidized hydrogen sulfide and carbon dioxide, at an oxidation pressure of at least 0.3 megapascals. The methods also include separating the high-pressure oxidized stream into an oxidized hydrogen sulfide product and a carbon dioxide product and generating the carbon dioxide product at a pressure of at least 0.3 megapascals. The systems include the high-pressure mixed stream, an oxidation reactor, and a separation assembly.

REMOVAL OF A TARGET GAS FROM A MIXTURE OF GASES BY SWING ADSORPTION WITH USE OF A TURBOEXPANDER

The separation of a target gas selected from a high pressure gas mixture containing said target gas as well as a product gas using a swing adsorption process unit. A turboexpander is used upstream of the swing adsorber to reduce the pressure of the high pressure gas mixture. A compressor is optionally used downstream of the swing adsorber to increase the pressure of the target gas-containing stream for injecting into a subterranean formation.

Inner surface features for co-current contactors

A co-current contactor (202a, 202b, 202c, 202d) for separating components in a fluid stream, the co-current contactor comprising a first inlet configured to receive the fluid stream proximate to a first end (208a, 208b, 208c, 208d) of the co-current contactor, a second inlet configured to receive a solvent proximate the first end of the co-current contactor, and a mass transfer section (222) configured to receive the fluid stream and the solvent and to provide a mixed, two-phase flow, wherein the mass transfer section comprises a surface feature along an inner surface of the mass transfer section configured to reduce film flow along an inner wall of the mass transfer section, and wherein the surface feature comprises at least one of a hydrophobic surface, a superhydrophobic surface, a porous wall surface, and a nonlinear surface irregularity extending radially inward or radially outward along the inner surface of the mass transfer section.

Kinetic fractionators, and cycling processes for fractionation of gas mixtures

A process for separating methane from a natural gas mixture employs pressure swing adsorption in one or more vessels. Each vessel has an adsorbent material having a kinetic selectivity for contaminants over methane greater than 5. Contaminants within the natural gas mixture become gases kinetically adsorbed within the adsorbent material. The vessel is placed under pressure to cause contaminants to be adsorbed in the surfaces and micro-pores of the adsorbent material. The process includes releasing a product stream comprised at least 95% by volume methane from a first gas outlet in the vessel, and desorbing the contaminant gases from the adsorbent material by reducing the pressure within the vessel. The desorbing step is done without applying heat to the vessel, thereby delivering a waste gas stream comprised at least 95 % by volume of the contaminant gases. An improved fractionation vessel having both major and minor flow channels is also provided.

COALESCER FOR CO-CURRENT CONTACTORS

The disclosure includes a method, comprising passing a fluid into a co-current contactor, passing a solvent into the co-current contactor, dividing the solvent into solvent droplets having a first average droplet size, placing the fluid in contact with the solvent droplets to create a combined stream, coalescing at least a portion of the solvent droplets to create solvent droplets having a second average droplet size, wherein the second average droplet size is greater than the first average droplet size, and separating the fluid and the solvent.

APPARATUS AND SYSTEM FOR ENHANCED SELECTIVE CONTAMINANT REMOVAL PROCESSES RELATED THERETO

Systems and methods for separating CO2 and H2S from a gaseous stream are provided herein. The system includes a selective solvent that is utilized with a compact contacting technology unit to remove H2S from a gaseous stream.

CONTROLLED FREEZE ZONE TOWER

A cryogenic distillation tower is provided for the separation of a fluid stream containing at least methane and carbon dioxide. The cryogenic distillation tower has a lower stripping section, an upper rectification section, and an intermediate spray section. The intermediate spray section includes a plurality of spray nozzles that inject a liquid freeze zone stream. The nozzles are configured such that substantial liquid coverage is provided across the inner diameter of the intermediate spray section. The liquid freeze zone stream generally includes methane at a temperature and pressure whereby both solid carbon dioxide particles and a methane-enriched vapor stream are formed. The tower may further include one or more baffles below the nozzles to create frictional resistance to the gravitational flow of the liquid freeze zone stream. This aids in the breakout and recovery of methane gas. Additional internal components are provided to improve heat transfer and to facilitate the breakout of methane gas.

Solvent mixtures for dissolving elemental sulfur, methods of utilizing the solvent mixtures, and methods of forming the solvent mixtures

Solvent mixtures for dissolving elemental sulfur, methods of utilizing the solvent mixtures, and methods of forming the solvent mixtures. The solvent mixtures include an elemental sulfur solvent fraction and an odorant fraction. The elemental sulfur solvent fraction includes an elemental sulfur solvent that has a solvent odor and a solvent sulfur solubility of at least 10 weight percent (wt %). The odorant fraction includes at least one odorant that has an odorant odor that differs from the solvent odor. The solvent mixture includes at least 20 wt % and at most 80 wt % of both the elemental sulfur solvent fraction and the odorant fraction. The presence of the odorant fraction, within the solvent mixture, decreases an intensity of the mixture odor relative to the solvent odor and/or decreases an offensiveness of the mixture odor relative to the solvent odor.

Integration of cold solvent and acid gas removal

A method of separating impurities from a natural gas stream. The natural gas stream is cooled through heat exchange with one or more process streams to produce a chilled gas stream, which is contacted with a lean solvent stream in a contactor to separate hydrogen sulfide (H ...

COALESCER FOR CO-CURRENT CONTACTORS

The disclosure includes a method, comprising passing a fluid into a co-current contactor, passing a solvent into the co-current contactor, dividing the solvent into solvent droplets having a first average droplet size, placing the fluid in contact with the solvent droplets to create a combined stream, coalescing at least a portion of the solvent droplets to create solvent droplets having a second average droplet size, wherein the second average droplet size is greater than the first average droplet size, and separating the fluid and the solvent.

METHOD AND SYSTEM FOR SEPARATING FLUIDS IN A DISTILLATION TOWER

A method and system for separating fluids in a distillation tower. The method may include feeding a stream to the distillation tower, wherein the stream includes carbon dioxide, reducing a carbon dioxide concentration of the stream received by the rectifier section by feeding a first cryogenic fluid to the controlled freeze zone section and accumulating rectifier section stream in at least one of a holding vessel and a sump of the rectifier section, and terminating reducing the carbon dioxide concentration when the carbon dioxide concentration of the stream travelling from the controlled freeze zone section to the rectifier section is less than or equal to a maximum carbon dioxide concentration. The first cryogenic fluid may comprise a substantially carbon-dioxide-free fluid.

KINETIC FRACTIONATORS, AND CYCLING PROCESSES FOR FRACTIONATION OF GAS MIXTURES

A process for separating methane from a natural gas mixture employs pressure swing adsorption in one or more vessels. Each vessel has an adsorbent material having a kinetic selectivity for contaminants over methane greater than 5. Contaminants within the natural gas mixture become gases kinetically adsorbed within the adsorbent material. The vessel is placed under pressure to cause contaminants to be adsorbed in the surfaces and micro-pores of the adsorbent material. The process includes releasing a product stream comprised at least 95% by volume methane from a first gas outlet in the vessel, and desorbing the contaminant gases from the adsorbent material by reducing the pressure within the vessel. The desorbing step is done without applying heat to the vessel, thereby delivering a waste gas stream comprised at least 95 % by volume of the contaminant gases. An improved fractionation vessel having both major and minor flow channels is also provided.

METHOD AND SYSTEM OF CONTROLLING A TEMPERATURE WITHIN A MELT TRAY ASSEMBLY OF A DISTILLATION TOWER

Inner surface features for co-current contractors

A co-current contactor for separating components in a fluid stream, the co-current contactor comprising a first inlet configured to receive the fluid stream proximate to a first end of the co-current contactor, a second inlet configured to receive a solvent proximate the first end of the co-current contactor, and a mass transfer section configured to receive the fluid stream and the solvent and to provide a mixed, two-phase flow, wherein the mass transfer section comprises a surface feature along an inner surface of the mass transfer section configured to reduce film flow along an inner wall of the mass transfer section, and wherein the surface feature comprises at least one of a hydrophobic surface, a superhydrophobic surface, a porous wall surface, and a nonlinear surface irregularity extending radially inward or radially outward along the inner surface of the mass transfer section.

Integrated controlled freeze zone (CFZ) tower and dividing wall (DWC) for enhanced hydrocarbon recovery

The present invention relates to methods and apparatuses for the operation of a distillation tower containing a controlled freezing zone and at least one distillation section. The process and tower design are utilized for the additional recovery of hydrocarbons from an acid gas. In this process, a separation process is utilized in which a multi-component feedstream is introduced into an apparatus that operates under solids forming conditions for at least one of the feedstream components. The freezable component, although typically CO ...

Temperature swing adsorption of CO2 from flue gas utilizing heat from compression

Adsorbing contaminants from a gas stream

A method and systems for adsorbing contaminants from a gas stream (206) are provided herein. The method includes flowing the gas stream (206) into a treating vessel (210) and through a moving bed of adsorbents (202). The method includes flowing the adsorbents (220) out of the treating vessel and into a fluidized bed (204) of a regenerator (222). The method includes desorbing the contaminants from the adsorbents in the fluidized bed of the regenerator to form regenerated adsorbents. The method further includes cooling (232) the adsorbents and returning (234) the cooled, regenerated adsorbents to the treating vessel (210).

Systems and methods for separating hydrogen sulfide from carbon dioxide in a high-pressure mixed stream

Systems and methods for separating hydrogen sulfide from carbon dioxide in a high-pressure mixed stream are disclosed herein. The methods include receiving the high-pressure mixed stream in an oxidation reactor and at an inlet pressure of at least 0.3 megapascals. The high-pressure mixed stream includes 0.01 to 5 mole percent hydrogen sulfide and at least 90 mole percent carbon dioxide. The methods further include oxidizing the high-pressure mixed stream with an oxidant to generate a high-pressure oxidized stream, includes oxidized hydrogen sulfide and carbon dioxide, at an oxidation pressure of at least 0.3 megapascals. The methods also include separating the high-pressure oxidized stream into an oxidized hydrogen sulfide product and a carbon dioxide product and generating the carbon dioxide product at a pressure of at least 0.3 megapascals. The systems include the high-pressure mixed stream, an oxidation reactor, and a separation assembly.

INTEGRATED CONTROLLED FREEZE ZONE (CFZ) TOWER AND DIVIDING WALL (DWC) FOR ENHANCED HYDROCARBON RECOVERY

The present invention relates to methods and apparatuses for the operation of a distillation tower containing a controlled freezing zone and at least one distillation section. The process and tower design are utilized for the additional recovery of hydrocarbons from an acid gas. In this process, a separation process is utilized in which a multi-component feedstream is introduced into an apparatus that operates under solids forming conditions for at least one of the feedstream components. The freezable component, although typically CO2, H2S, or another acid gas, can be any component that has the potential for forming solids in the separation system. A dividing wall is added to at least a portion of the lower distillation section of the apparatus to effect the separation of at least some fraction of the hydrocarbons in that portion of the tower.

Reducing refrigeration and dehydration load for a feed stream entering a cryogenic distillation process

A system for conditioning a sour gas feed stream for a cryogenic distillation tower, comprising a dehydration unit configured to separate the sour gas feed stream into a first stream comprising water and a feed stream, and a sequential cooling assembly coupled to both the dehydration unit and the cryogenic distillation tower, wherein the sequential cooling assembly comprises a first stage configured to separate the feed stream into a partially cooled feed stream and a second stream comprising acid gas, a second stage configured to cool the partially cooled feed stream into a cooled feed stream and a third stream comprising acid gas, and a cooled feed stream header coupled to a cryogenic distillation tower feed inlet, wherein the first stage, the second stage, or both are configured to send at least one of the second and third streams to a bottom section of the cryogenic distillation tower.

Compact contacting systems and methods for scavenging sulfur-containing compounds

A hydrogen sulfide (H ...

Controlled freeze zone tower

A cryogenic distillation tower is provided for the separation of a fluid stream containing at least methane and carbon dioxide. The cryogenic distillation tower has a lower stripping section, an upper rectification section, and an intermediate spray section. The intermediate spray section includes a plurality of spray nozzles that inject a liquid freeze zone stream. The nozzles are configured such that substantial liquid coverage is provided across the inner diameter of the intermediate spray section. The liquid freeze zone stream generally includes methane at a temperature and pressure whereby both solid carbon dioxide particles and a methane-enriched vapor stream are formed. The tower may further include one or more baffles below the nozzles to create frictional resistance to the gravitational flow of the liquid freeze zone stream. This aids in the breakout and recovery of methane gas. Additional internal components are provided to improve heat transfer and to facilitate the breakout ...

Integrated controlled freeze zone (CFZ) tower and dividing wall (DWC) for enhanced hydrocarbon recovery

METHOD AND SYSTEM OF CONTROLLING A TEMPERATURE WITHIN A MELT TRAY ASSEMBLY OF A DISTILLATION TOWER

A method and system of controlling a temperature within a melt tray assembly of a distillation tower. The method may include determining a melt tray fluid composition of a melt tray fluid, determining a melt tray fluid temperature of the melt tray fluid, determining if the melt tray fluid temperature is within an expected melt tray fluid temperature range for the melt tray fluid composition, decreasing the melt tray fluid temperature if the melt tray fluid temperature is greater than an expected melt tray fluid temperature range upper limit, increasing the melt tray fluid temperature if the melt tray fluid temperature is less than an expected melt tray fluid temperature range lower limit, and maintaining the melt tray fluid temperature if the melt tray fluid temperature is within the expected melt tray fluid temperature range.

TEMPERATURE SWING ADSORPTION OF CO2 FROM FLUE GAS USING A PARALLEL CHANNEL CONTACTOR

The adsorption of CO2 from flue gas streams using temperature swing adsorption. Adsorbent contactors are used in the temperature swing adsorption unit that contain a plurality of substantially parallel channels comprised of or coated with an adsorbent material that is selective for adsorbing CO2 from flue gas.

KINETIC FRACTIONATORS, AND CYCLING PROCESSES FOR FRACTIONATION OF GAS MIXTURES

A process for separating methane from a natural gas mixture employs pressure swing adsorption in one or more vessels. Each vessel has an adsorbent material having a kinetic selectivity for contaminants over methane greater than 5. Contaminants within the natural gas mixture become gases kinetically adsorbed within the adsorbent material. The vessel is placed under pressure to cause contaminants to be adsorbed in the surfaces and micro-pores of the adsorbent material. The process includes releasing a product stream comprised at least 95% by volume methane from a first gas outlet in the vessel, and desorbing the contaminant gases from the adsorbent material by reducing the pressure within the vessel. The desorbing step is done without applying heat to the vessel, thereby delivering a waste gas stream comprised at least 95 % by volume of the contaminant gases. An improved fractionation vessel having both major and minor flow channels is also provided.

Controlled freeze zone tower

Method and system for separating fluids in a distillation tower

A method and system for separating fluids in a distillation tower. The method may include feeding a stream to the distillation tower, wherein the stream includes carbon dioxide, reducing a carbon dioxide concentration of the stream received by the rectifier section by feeding a first cryogenic fluid to the controlled freeze zone section and accumulating rectifier section stream in at least one of a holding vessel and a sump of the rectifier section, and terminating reducing the carbon dioxide concentration when the carbon dioxide concentration of the stream travelling from the controlled freeze zone section to the rectifier section is less than or equal to a maximum carbon dioxide concentration. The first cryogenic fluid may comprise a substantially carbon-dioxide-free fluid.

INTEGRATION OF COLD SOLVENT AND ACID GAS REMOVAL

A method of separating impurities from a natural gas stream. The natural gas stream is cooled through heat exchange with one or more process streams to produce a chilled gas stream, which is contacted with a lean solvent stream in a contactor to separate hydrogen sulfide (H2S) from, the chilled gas stream, thereby producing a rich solvent stream and a partially -treated gas stream. Carbon dioxide (CO2) and H2S are separated from the partially-treated gas stream in a membrane separation system, thereby creating a fully -treated gas stream and a permeate gas stream, the permeate gas stream being comprised primarily of H2S and CO2, and the fully-treated gas stream being comprised primarily of natural gas. The fully-treated gas stream and the permeate gas stream are at a lower temperature than the partially-treated gas stream. The fully -treated gas stream and the permeate gas stream comprise the one or more process streams.

PROCESS FOR REMOVING A TARGET GAS FROM A MIXTURE OF GASES BY THERMAL SWING ADSORPTION

The separation of a target gas from a mixture of gases using a thermal swing adsorption process wherein a thermal wave is used, primarily in the desorption step. The process of this invention enables one to separately remove multiple contaminants from a treated gaseous stream.

ADSORBING CONTAMINANTS FROM A GAS STREAM

A method and systems for adsorbing contaminants from a gas stream (206) are provided herein. The method includes flowing the gas stream (206) into a treating vessel (210) and through a moving bed of adsorbents (202). The method includes flowing the adsorbents (220) out of the treating vessel and into a fluidized bed (204) of a regenerator (222). The method includes desorbing the contaminants from the adsorbents in the fluidized bed of the regenerator to form regenerated adsorbents. The method further includes cooling (232) the adsorbents and returning (234) the cooled, regenerated adsorbents to the treating vessel (210).

Coalescer for Co-Current Contactors

The disclosure includes a method, comprising passing a fluid into a co-current contactor, passing a solvent into the co-current contactor, dividing the solvent into solvent droplets having a first average droplet size, placing the fluid in contact with the solvent droplets to create a combined stream, coalescing at least a portion of the solvent droplets to create solvent droplets having a second average droplet size, wherein the second average droplet size is greater than the first average droplet size, and separating the fluid and the solvent.

Integrated controlled freeze zone (CFZ) tower and dividing wall (DWC) for enhanced hydrocarbon recovery

Coalescer for co-current contactors

The disclosure includes a method, comprising passing a fluid into a co-current contactor, passing a solvent into the co-current contactor, dividing the solvent into solvent droplets having a first average droplet size, placing the fluid in contact with the solvent droplets to create a combined stream, coalescing at least a portion of the solvent droplets to create solvent droplets having a second average droplet size, wherein the second average droplet size is greater than the first average droplet size, and separating the fluid and the solvent.

Integration of cold solvent and acid gas removal

A method of separating impurities from a natural gas stream. The natural gas stream is cooled through heat exchange with one or more process streams to produce a chilled gas stream, which is contacted with a lean solvent stream in a contactor to separate hydrogen sulfide (H ...

SYSTEMS AND METHODS FOR SEPARATING HYDROGEN SULFIDE FROM CARBON DIOXIDE IN A HIGH-PRESSURE MIXED STREAM

Systems and methods for separating hydrogen sulfide from carbon dioxide in a high-pressure mixed stream are disclosed herein. The methods include receiving the high-pressure mixed stream in an oxidation reactor and at an inlet pressure of at least 0.3 megapascals. The high-pressure mixed stream includes 0.01 to 5 mole percent hydrogen sulfide and at least 90 mole percent carbon dioxide. The methods further include oxidizing the high-pressure mixed stream with an oxidant to generate a high-pressure oxidized stream, includes oxidized hydrogen sulfide and carbon dioxide, at an oxidation pressure of at least 0.3 megapascals. The methods also include separating the high-pressure oxidized stream into an oxidized hydrogen sulfide product and a carbon dioxide product and generating the carbon dioxide product at a pressure of at least 0.3 megapascals. The systems include the high-pressure mixed stream, an oxidation reactor, and a separation assembly.

INNER SURFACE FEATURES FOR CO-CURRENT CONTACTORS

A co-current contactor (202a, 202b, 202c, 202d) for separating components in a fluid stream, the co-current contactor comprising a first inlet configured to receive the fluid stream proximate to a first end (208a, 208b, 208c, 208d) of the co-current contactor, a second inlet configured to receive a solvent proximate the first end of the co-current contactor, and a mass transfer section (222) configured to receive the fluid stream and the solvent and to provide a mixed, two-phase flow, wherein the mass transfer section comprises a surface feature along an inner surface of the mass transfer section configured to reduce film flow along an inner wall of the mass transfer section, and wherein the surface feature comprises at least one of a hydrophobic surface, a superhydrophobic surface, a porous wall surface, and a nonlinear surface irregularity extending radially inward or radially outward along the inner surface of the mass transfer section.

ADSORBING CONTAMINANTS FROM A GAS STREAM

A method and systems for adsorbing contaminants from a gas stream (206) are provided herein. The method includes flowing the gas stream (206) into a treating vessel (210) and through a moving bed of adsorbents (202). The method includes flowing the adsorbents (220) out of the treating vessel and into a fluidized bed (204) of a regenerator (222). The method includes desorbing the contaminants from the adsorbents in the fluidized bed of the regenerator to form regenerated adsorbents. The method further includes cooling (232) the adsorbents and returning (234) the cooled, regenerated adsorbents to the treating vessel (210).

PROCESS FOR REMOVING A TARGET GAS FROM A MIXTURE OF GASES BY THERMAL SWING ADSORPTION

The separation of a target gas from a mixture of gases using a thermal swing adsorption process wherein a thermal wave is used, primarily in the desorption step. The process of this invention enables one to separately remove multiple contaminants from a treated gaseous stream.

TEMPERATURE SWING ADSORPTION OF CO2 FROM FLUE GAS UTILIZING HEAT FROM COMPRESSION

Adsorption of M. from flue gas streams using temperature swing adsorption. The resulting CO2 rich stream is compressed for sequestration into a subterranean formation and at least a portion of the heat of compression is used in the desorption step of the temperature swing adsorption process.

REMOVAL OF A TARGET GAS FROM A MIXTURE OF GASES BY SWING ADSORPTION WITH USE OF A TURBOEXPANDER

The separation of a target gas selected from a high pressure gas mixture containing said target gas as well as a product gas using a swing adsorption process unit. A turboexpander is used upstream of the swing adsorber to reduce the pressure of the high pressure gas mixture. A compressor is optionally used downstream of the swing adsorber to increase the pressure of the target gas-containing stream for injecting into a subterranean formation.

INNER SURFACE FEATURES FOR CO-CURRENT CONTACTORS

Controlled freeze zone tower

A cryogenic distillation tower is provided for the separation of a fluid stream containing at least methane and carbon dioxide. The cryogenic distillation tower has a lower stripping section, an upper rectification section, and an intermediate spray section. The intermediate spray section includes a plurality of spray nozzles that inject a liquid freeze zone stream. The nozzles are configured such that substantial liquid coverage is provided across the inner diameter of the intermediate spray section. The liquid freeze zone stream generally includes methane at a temperature and pressure whereby both solid carbon dioxide particles and a methane-enriched vapor stream are formed. The tower may further include one or more baffles below the nozzles to create frictional resistance to the gravitational flow of the liquid freeze zone stream. This aids in the breakout and recovery of methane gas. Additional internal components are provided to improve heat transfer and to facilitate the breakout ...

Integration of cold solvent and acid gas removal

A method of separating impurities from a natural gas stream. CO ...

Inner surface features for co-current contactors

A co-current contactor (202a, 202b, 202c, 202d) for separating components in a fluid stream, the co-current contactor comprising a first inlet configured to receive the fluid stream proximate to a first end (208a, 208b, 208c, 208d) of the co-current contactor, a second inlet configured to receive a solvent proximate the first end of the co-current contactor, and a mass transfer section (222) configured to receive the fluid stream and the solvent and to provide a mixed, two-phase flow, wherein the mass transfer section comprises a surface feature along an inner surface of the mass transfer section configured to reduce film flow along an inner wall of the mass transfer section, and wherein the surface feature comprises at least one of a hydrophobic surface, a superhydrophobic surface, a porous wall surface, and a nonlinear surface irregularity extending radially inward or radially outward along the inner surface of the mass transfer section.

Process for removing a target gas from a mixture of gases by thermal swing adsorption

The separation of a target gas from a mixture of gases using a thermal swing adsorption process wherein a thermal wave is used, primarily in the desorption step. The process of this invention enables one to separately remove multiple contaminants from a treated gaseous stream.

Reducing refrigeration and dehydration load for a feed stream entering a cryogenic distillation process

A system for conditioning a sour gas feed stream for a cryogenic distillation tower, comprising a dehydration unit configured to separate the sour gas feed stream into a first stream comprising water and a feed stream, and a sequential cooling assembly coupled to both the dehydration unit and the cryogenic distillation tower, wherein the sequential cooling assembly comprises a first stage configured to separate the feed stream into a partially cooled feed stream and a second stream comprising acid gas, a second stage configured to cool the partially cooled feed stream into a cooled feed stream and a third stream comprising acid gas, and a cooled feed stream header coupled to a cryogenic distillation tower feed inlet, wherein the first stage, the second stage, or both are configured to send at least one of the second and third streams to a bottom section of the cryogenic distillation tower.

Adsorbing contaminants from a gas stream

A method and systems for adsorbing contaminants from a gas stream (206) are provided herein. The method includes flowing the gas stream (206) into a treating vessel (210) and through a moving bed of adsorbents (202). The method includes flowing the adsorbents (220) out of the treating vessel and into a fluidized bed (204) of a regenerator (222). The method includes desorbing the contaminants from the adsorbents in the fluidized bed of the regenerator to form regenerated adsorbents. The method further includes cooling (232) the adsorbents and returning (234) the cooled, regenerated adsorbents to the treating vessel (210).

Systems and methods for separating hydrogen sulfide from carbon dioxide in a high-pressure mixed stream

Systems and methods for separating hydrogen sulfide from carbon dioxide in a high-pressure mixed stream are disclosed herein. The methods include receiving the high-pressure mixed stream in an oxidation reactor and at an inlet pressure of at least 0.3 megapascals. The high-pressure mixed stream includes 0.01 to 5 mole percent hydrogen sulfide and at least 90 mole percent carbon dioxide. The methods further include oxidizing the high-pressure mixed stream with an oxidant to generate a high-pressure oxidized stream, includes oxidized hydrogen sulfide and carbon dioxide, at an oxidation pressure of at least 0.3 megapascals. The methods also include separating the high-pressure oxidized stream into an oxidized hydrogen sulfide product and a carbon dioxide product and generating the carbon dioxide product at a pressure of at least 0.3 megapascals. The systems include the high-pressure mixed stream, an oxidation reactor, and a separation assembly.

Apparatus and system for enhanced selective contaminant removal processes related thereto

Systems and methods for separating CO ...

Temperature swing adsorption of CO2 from flue gas utilizing heat from compression

Adsorption of CO from flue gas streams using temperature swing adsorption. The resulting CO rich stream is compressed for sequestration into a subterranean formation and at least a portion of the heat of compression is used in the desorption step of the temperature swing adsorption process.

Kinetic fractionators, and cycling processes for fractionation of gas mixtures

A process for separating methane from a natural gas mixture employs pressure swing adsorption in one or more vessels. Each vessel has an adsorbent material having a kinetic selectivity for contaminants over methane greater than 5. Contaminants within the natural gas mixture become gases kinetically adsorbed within the adsorbent material. The vessel is placed under pressure to cause contaminants to be adsorbed in the surfaces and micro-pores of the adsorbent material. The process includes releasing a product stream comprised at least 95% by volume methane from a first gas outlet in the vessel, and desorbing the contaminant gases from the adsorbent material by reducing the pressure within the vessel. The desorbing step is done without applying heat to the vessel, thereby delivering a waste gas stream comprised at least 95 % by volume of the contaminant gases. An improved fractionation vessel having both major and minor flow channels is also provided.

Method and system of controlling a temperature within a melt tray assembly of a distillation tower

A method and system of controlling a temperature within a melt tray assembly of a distillation tower. The method may include determining a melt tray fluid composition of a melt tray fluid, determining a melt tray fluid temperature of the melt tray fluid, determining if the melt tray fluid temperature is within an expected melt tray fluid temperature range for the melt tray fluid composition, decreasing the melt tray fluid temperature if the melt tray fluid temperature is greater than an expected melt tray fluid temperature range upper limit, increasing the melt tray fluid temperature if the melt tray fluid temperature is less than an expected melt tray fluid temperature range lower limit, and maintaining the melt tray fluid temperature if the melt tray fluid temperature is within the expected melt tray fluid temperature range.

Method of purifying hydrocarbons and regeneration of adsorbents used therein

An improved method is provided for removing contaminants from a hydrocarbon stream, such as a stream of raw natural gas. The contaminated hydrocarbon stream is passed through a first adsorbent bed containing molecular sieves to adsorb contaminants on the molecular sieves, thereby removing at least some of the contaminants from the hydrocarbon stream. The contaminated hydrocarbon stream may optionally be passed through a second adsorbent bed containing a desiccant material other than molecular sieves. The molecular sieves are regenerated using a wet regeneration process in which both the water content and temperature of the regeneration fluid stream are staged. The molecular sieves and the desiccant material can also be regenerated by contacting the desiccant material with a regeneration fluid stream comprising water to adsorb at least a portion of the water onto the desiccant material, thereby forming a regeneration fluid stream that is at least partially dried and in contact with a desiccant ...

Compact contacting systems and methods for scavenging sulfur-containing compounds

A hydrogen sulfide (H ...

Coalescer for co-current contactors

The disclosure includes a method, comprising passing a fluid into a co-current contactor, passing a solvent into the co-current contactor, dividing the solvent into solvent droplets having a first average droplet size, placing the fluid in contact with the solvent droplets to create a combined stream, coalescing at least a portion of the solvent droplets to create solvent droplets having a second average droplet size, wherein the second average droplet size is greater than the first average droplet size, and separating the fluid and the solvent.

Coalescer for co-current contactors

The disclosure includes a method, comprising passing a fluid into a co-current contactor, passing a solvent into the co-current contactor, dividing the solvent into solvent droplets having a first average droplet size, placing the fluid in contact with the solvent droplets to create a combined stream, coalescing at least a portion of the solvent droplets to create solvent droplets having a second average droplet size, wherein the second average droplet size is greater than the first average droplet size, and separating the fluid and the solvent.

Method and apparatus for removal of oil from utility gas stream

The present application is directed to a method and system for preparing gaseous utility streams from gaseous process streams, particularly, removing oil contamination from such streams prior to use in a dry gas seal. The methods and systems may include at least one kinetic swing adsorption process including pressure swing adsorption, temperature swing adsorption, calcination, and inert purge processes to treat gaseous streams for use in dry gas seals of rotating equipment such as compressors, turbines and pumps and other utilities. The adsorbent materials used include a high surface area solid structured microporous and mesoporous materials.

KINETIC FRACTIONATORS, AND CYCLING PROCESSES FOR FRACTIONATION OF GAS MIXTURES

A process for separating methane from a natural gas mixture employs pressure swing adsorption in one or more vessels. Each vessel has an adsorbent material having a kinetic selectivity for contaminants over methane greater than 5. Contaminants within the natural gas mixture become gases kinetically adsorbed within the adsorbent material. The vessel is placed under pressure to cause contaminants to be adsorbed in the surfaces and micro-pores of the adsorbent material. The process includes releasing a product stream comprised at least 95% by volume methane from a first gas outlet in the vessel, and desorbing the contaminant gases from the adsorbent material by reducing the pressure within the vessel. The desorbing step is done without applying heat to the vessel, thereby delivering a waste gas stream comprised at least 95 % by volume of the contaminant gases. An improved fractionation vessel having both major and minor flow channels is also provided.

Kinetic fractionators, and cycling processes for fractionation of gas mixtures

A process for separating methane from a natural gas mixture employs pressure swing adsorption in one or more vessels. Each vessel has an adsorbent material having a kinetic selectivity for contaminants over methane greater than 5. Contaminants within the natural gas mixture become gases kinetically adsorbed within the adsorbent material. The vessel is placed under pressure to cause contaminants to be adsorbed in the surfaces and micro-pores of the adsorbent material. The process includes releasing a product stream comprised at least 95% by volume methane from a first gas outlet in the vessel, and desorbing the contaminant gases from the adsorbent material by reducing the pressure within the vessel. The desorbing step is done without applying heat to the vessel, thereby delivering a waste gas stream comprised at least 95% by volume of the contaminant gases. An improved fractionation vessel having both major and minor flow channels is also provided.

Method and system of controlling a temperature within a melt tray assembly of a distillation tower

A method and system of controlling a temperature within a melt tray assembly of a distillation tower. The method may include determining a melt tray fluid composition of a melt tray fluid, determining a melt tray fluid temperature of the melt tray fluid, determining if the melt tray fluid temperature is within an expected melt tray fluid temperature range for the melt tray fluid composition, decreasing the melt tray fluid temperature if the melt tray fluid temperature is greater than an expected melt tray fluid temperature range upper limit, increasing the melt tray fluid temperature if the melt tray fluid temperature is less than an expected melt tray fluid temperature range lower limit, and maintaining the melt tray fluid temperature if the melt tray fluid temperature is within the expected melt tray fluid temperature range.

Inner Surface Features for Co-Current Contactors

A co-current contactor for separating components in a fluid stream, the co-current contactor comprising a first inlet configured to receive the fluid stream proximate to a first end of the co-current contactor, a second inlet configured to receive a solvent proximate the first end of the co-current contactor, and a mass transfer section configured to receive the fluid stream and the solvent and to provide a mixed, two-phase flow, wherein the mass transfer section comprises a surface feature along an inner surface of the mass transfer section configured to reduce film flow along an inner wall of the mass transfer section, and wherein the surface feature comprises at least one of a hydrophobic surface, a superhydrophobic surface, a porous wall surface, and a nonlinear surface irregularity extending radially inward or radially outward along the inner surface of the mass transfer section.

Acid gas disposal method

This invention is method of recovering gas from a gas-bearing subterranean formation in which gas is produced from an upper portion of the formation and a waste gas is injected into a lower portion of the formation to dispose of the waste gas. The waste gas is injected within a 3000 foot (914 m) radial distance from the production of the gas. The injection and production can be carried out using one well or a plurality of wells.

Kinetic Fractionators, and Cycling Processes for Fractionation of Gas Mixtures

A process for separating methane from a natural gas mixture employs pressure swing adsorption in one or more vessels. Each vessel has an adsorbent material having a kinetic selectivity for contaminants over methane greater than 5. Contaminants within the natural gas mixture become gases kinetically adsorbed within the adsorbent material. The vessel is placed under pressure to cause contaminants to be adsorbed in the surfaces and micro-pores of the adsorbent material. The process includes releasing a product stream comprised at least 95% by volume methane from a first gas outlet in the vessel, and desorbing the contaminant gases from the adsorbent material by reducing the pressure within the vessel. The desorbing step is done without applying heat to the vessel, thereby delivering a waste gas stream comprised at least 95% by volume of the contaminant gases. An improved fractionation vessel having both major and minor flow channels is also provided. 118.-. (canceled)19. A fractionation vessel for separating methane from a natural gas mixture , the vessel comprising:a housing;a gas inlet for receiving the natural gas mixture into the housing at a pressure of at least 100 psig;a first gas outlet for releasing at least a portion of the natural gas mixture from the housing;an adsorbent material within the housing, the adsorbent material having a kinetic selectivity for contaminants over methane greater than 5, such that the contaminants become kinetically adsorbed within the adsorbent material in gas phase;at least two major flow channels through the adsorbent material, the at least two major flow channels placing the gas inlet and the first gas outlet in fluid communication; andat least one minor flow channel through the adsorbent material, the at least one minor channel being in fluid communication with the major channels.20. The fractionation vessel of claim 19 , further comprising:a manifold for cycling the natural gas mixture through sequential releasing and ...

Compact contacting systems and methods for scavenging sulfur-containing compounds

A hydrogen sulfide (H2S) scavenging system for removing H2S, mercaptans, and/or other sulfur-containing compounds from a natural gas stream. A co-current contacting system is located in-line within a pipe and receives the natural gas stream and a liquid scavenger stream. The co-current contacting system includes a co-current contactor including a droplet generator and a mass transfer section. The droplet generator generates droplets from the liquid scavenger stream and disperses the droplets into the natural gas stream. The mass transfer section provides a mixed, two-phase flow having a vapor phase and a liquid phase. The liquid phase includes the liquid scavenger stream with H2S, mercaptans, and/or other sulfur-containing compounds absorbed from the natural gas stream, and the vapor phase includes the natural gas stream. A separation system separates the vapor phase from the liquid phase.

METHOD AND SYSTEM FOR SEPARATING FLUIDS IN A DISTILLATION TOWER

Hydrocarbon Gas Treatment Systems and Methods

Hydrocarbon gas treatment systems and methods. The hydrocarbon gas treatment systems include a feed gas supply system configured to provide a feed gas stream and a hydrogen sulfide removal system configured to separate the feed gas stream into a product gas stream and an acid gas stream. The hydrocarbon gas treatment systems also include a heat exchanger configured to cool the acid gas stream to generate a cooled acid gas stream and an acid gas enrichment system configured to separate the cooled acid gas stream into a treated gas stream and an enriched acid gas stream. The methods include providing a feed gas stream, separating the feed gas stream into a product gas stream and an acid gas stream, cooling the acid gas stream to generate a cooled acid gas stream, and separating the cooled acid gas stream into a treated gas stream and an enriched acid gas stream. 1. A hydrocarbon gas treatment system , comprising:a feed gas supply system configured to provide a feed gas stream, wherein the feed gas stream includes hydrocarbon gas, carbon dioxide, and hydrogen sulfide;a hydrogen sulfide removal system configured to receive the feed gas stream and to separate the feed gas stream into a product gas stream, which includes a substantial portion of the hydrocarbon gas from the feed gas stream, and an acid gas stream, which includes carbon dioxide and a substantial portion of the hydrogen sulfide from the feed gas stream;a heat exchanger configured to receive the acid gas stream and to cool the acid gas stream to generate a cooled acid gas stream; andan acid gas enrichment system configured to receive at least a portion of the cooled acid gas stream and to separate the portion of the cooled acid gas stream into a treated gas stream, which includes a substantial portion of the carbon dioxide from the portion of the cooled acid gas stream, and an enriched acid gas stream, which includes a substantial portion of the hydrogen sulfide from the portion of the cooled acid gas stream ...

Compact Contacting Systems and Methods for Scavenging Sulfur-Containing Compounds

A hydrogen sulfide (HS) scavenging system for removing HS, mercaptans, and/or other sulfur-containing compounds from a natural gas stream. A co-current contacting system is located in-line within a pipe and receives the natural gas stream and a liquid scavenger stream. The co-current contacting system includes a co-current contactor including a droplet generator and a mass transfer section. The droplet generator generates droplets from the liquid scavenger stream and disperses the droplets into the natural gas stream. The mass transfer section provides a mixed, two-phase flow having a vapor phase and a liquid phase. The liquid phase includes the liquid scavenger stream with HS, mercaptans, and/or other sulfur-containing compounds absorbed from the natural gas stream, and the vapor phase includes the natural gas stream. A separation system separates the vapor phase from the liquid phase. 1. A hydrogen sulfide (HS) scavenging system for removing HS , mercaptans , and/or other sulfur-containing compounds from a natural gas stream , comprising:a liquid scavenger stream; [{'sub': '2', 'a co-current contactor including a droplet generator and a mass transfer section, the droplet generator configured to generate droplets from the liquid scavenger stream and to disperse the droplets into the natural gas stream, and the mass transfer section configured to provide a mixed, two-phase flow having a vapor phase and a liquid phase, wherein the liquid phase includes the liquid scavenger stream with HS, mercaptans, and/or other sulfur-containing compounds absorbed from the natural gas stream, and wherein the vapor phase includes the natural gas stream; and'}, 'a separation system configured to separate the vapor phase from the liquid phase., 'a co-current contacting system located in-line within a pipe, the co-current contacting system receiving the natural gas stream and the liquid scavenger stream, the co-current contacting system including2. The HS scavenging system of claim 1 , ...

Methods for removing sulfur-containing compounds

A method for removing sulfur-containing compounds is provided. In one embodiment, the method includes selectively separating a feed stream (118) comprising carbon dioxide and one or more sulfur-containing compounds, including hydrogen sulfide, at conditions sufficient to produce a first stream (122) comprising carbon dioxide and hydrogen sulfide and a second stream (124) comprising carbon dioxide and hydrogen sulfide. A molar ratio of carbon dioxide to hydrogen sulfide in the first stream is greater than a molar ratio of carbon dioxide to hydrogen sulfide in the second stream, and a molar ratio of hydrogen sulfide in the first stream to hydrogen sulfide in the second stream is about 0.005 or more.

REDUCING REFRIGERATION AND DEHYDRATION LOAD FOR A FEED STREAM ENTERING A CRYOGENIC DISTILLATION PROCESS

KINETIC FRACTIONATORS, AND CYCLING PROCESSES FOR FRACTIONATION OF GAS MIXTURES

Removal of acid gases from a gas stream, with O2 enrichment for acid gas capture and sequestration

A method and apparatus for processing a hydrocarbon gas stream including sulfurous components and carbon dioxide. The hydrocarbon gas stream is separated into a sweetened gas stream and an acid gas stream. The acid gas stream and an air stream, enriched with oxygen such that the air stream comprises between 22% and 100% oxygen, are combusted in a sulfur recovery unit to separate the acid gas stream into a liquid stream of elemental sulfur and a tail gas stream comprising acid gas impurities. The tail gas stream and an air flow are sub-stoichiometrically combusted to produce an outlet stream comprising hydrogen sulfide and carbon monoxide. The outlet stream is hydrogenated to convert sulfur species to a gaseous catalytic output stream comprising hydrogen sulfide. Water is removed from the gaseous catalytic output stream to produce a partially-dehydrated acid gas stream, which is pressurized and injected into a subsurface reservoir.

Removal of Acid Gases From A Gas Stream, With O2 Enrichment For Acid Gas Capture and Sequestration

A method and apparatus for processing a hydrocarbon gas stream including sulfurous components and carbon dioxide. The hydrocarbon gas stream is separated into a sweetened gas stream and an acid gas stream. The acid gas stream and an air stream, enriched with oxygen such that the air stream comprises between 22% and 100% oxygen, are combusted in a sulfur recovery unit to separate the acid gas stream into a liquid stream of elemental sulfur and a tail gas stream comprising acid gas impurities. The tail gas stream and an air flow are sub-stoichiometrically combusted to produce an outlet stream comprising hydrogen sulfide and carbon monoxide. The outlet stream is hydrogenated to convert sulfur species to a gaseous catalytic output stream comprising hydrogen sulfide. Water is removed from the gaseous catalytic output stream to produce a partially-dehydrated acid gas stream, which is pressurized and injected into a subsurface reservoir. 1. A gas processing facility for processing a hydrocarbon gas stream including sulfurous components and carbon dioxide , the gas processing facility comprising: a sweetened gas stream and', 'an acid gas stream comprised primarily of hydrogen sulfide and carbon dioxide;, 'an acid gas removal facility for separating the hydrocarbon gas stream into'} a liquid stream of elemental sulfur, and', 'a tail gas stream comprising acid gas impurities; and, 'a Claus sulfur recovery unit (SRU) that receives the acid gas stream and an air stream, the air stream being enriched with oxygen such that the air stream comprises between 22% and 100% oxygen, the SRU combusting the acid gas stream and the atmospheric air to thereby separate the acid gas stream into'} [{'sub': '2', 'a reducing gas generator (RGG) that combusts fuel gas and the tail gas stream with an air flow, the RGG sub-stoichiometrically combusting the fuel gas and tail gas stream with the air flow to produce an RGG outlet stream comprising hydrogen sulfide (HS) and carbon monoxide;'}, {'sub': ...

Enhanced acid gas removal within a gas processing system

A gas processing system is described herein. The gas processing system includes a number of co-current contacting systems configured to contact a sour feed gas stream including an acid gas with a solvent stream to produce a partially-sweetened gas stream and a rich solvent stream including an absorbed acid gas. At least one of the co-current contacting systems is configured to send the rich solvent stream to a regenerator. The regenerator is configured to remove the absorbed acid gas from the rich solvent stream to produce a lean solvent stream. The gas processing system also includes a solvent treater configured to treat at least a portion of the lean solvent stream to produce an enhanced solvent stream, and a final co-current contacting system configured to contact the partially-sweetened gas stream with the enhanced solvent stream to produce a partially-loaded solvent stream and a final gas stream.

Sulfur Recovery Within A Gas Processing System

A method for recovering sulfur within a gas processing system is described herein. The method includes contacting a natural gas stream including an acid gas with a solvent stream within a co-current contacting system to produce a sweetened natural gas stream and a rich solvent stream including an absorbed acid gas. The method also includes removing the absorbed acid gas from the rich solvent stream within a regenerator to produce a concentrated acid gas stream and a lean solvent stream. The method further includes recovering elemental sulfur from hydrogen sulfide (HS) within the concentrated acid gas stream via a sulfur recovery unit. 1. A gas processing system , comprising: contact a natural gas stream comprising an acid gas with a solvent stream to produce a sweetened natural gas stream and a rich solvent stream comprising an absorbed acid gas; and', 'send the rich solvent stream to a regenerator;, 'a co-current contacting system configured to remove the absorbed acid gas from the rich solvent stream to produce a concentrated acid gas stream and a lean solvent stream; and', 'send the concentrated acid gas stream to a sulfur recovery unit; and, 'the regenerator configured to{'sub': '2', 'the sulfur recovery unit configured to recover elemental sulfur from hydrogen sulfide (HS) within the concentrated acid gas stream.'}2. The gas processing system of claim 1 , wherein the co-current contacting system comprises: an annular support ring configured to maintain the co-current contactor within the pipe;', 'a plurality of radial blades configured to allow the solvent stream to flow into the co-current contactor; and', 'a central gas entry cone configured to allow the natural gas stream to flow through a hollow section within the co-current contactor;', 'wherein the co-current contactor provides for efficient incorporation of liquid droplets formed from the solvent stream into the natural gas stream such that the acid gas from the natural gas stream is absorbed by the ...

Adsorbing contaminants from a gas stream

A method and systems for adsorbing contaminants from a gas stream are provided herein. The method includes flowing the gas stream into a treating vessel and through a moving bed of adsorbents. The method includes flowing the adsorbents out of the treating vessel and into a fluidized bed of a regenerator. The method includes desorbing the contaminants from the adsorbents in the fluidized bed of the regenerator to form regenerated adsorbents. The method further includes cooling the adsorbents and returning the cooled, regenerated adsorbents to the treating vessel.

COALESCER FOR CO-CURRENT CONTACTORS

Generating elemental sulfur

Techniques for generating elemental sulfur are provided herein. The disclosed methods may include a gas processing system including a processed feed gas. The methods may include a distillation column configured to receive the processed feed gas and to generate a high-pressure acid gas stream. The methods may include a reactor configured to partially combust the high-pressure acid gas stream to generate a limiting reactant. The methods may include a plurality of reactors configured with a shell side and a plurality of reaction tubes, where a reaction between the high-pressure acid gas stream and the limiting reactant produces a partially-reacted high-pressure acid gas containing elemental sulfur. The methods may include a plurality of condensers configured to condense the elemental sulfur. The methods may include a plurality of separators configured to separate out the partially-reacted high-pressure acid gas stream to recover elemental sulfur.

Systems and Methods for Selectively Removing Hydrogen Sulfide From a Feed Gas Stream

Systems and methods for selectively removing hydrogen sulfide from a feed gas stream. The systems include an absorber-heat exchanger (ABHEX) assembly configured to exchange thermal energy between a mixed stream and a thermal management fluid stream. The ABHEX assembly defines a mixed stream volume and a thermal management fluid stream volume. The ABHEX assembly includes an isolation structure that maintains fluid separation between the mixed stream and the thermal management fluid stream and facilitates thermal communication between the mixed stream and the thermal management fluid stream. The ABHEX assembly is configured to receive and to mix the feed gas stream and a lean solvent stream to generate the mixed stream, to separate the mixed stream into a product gas stream and a rich solvent stream, and to cool the mixed stream. The methods include methods of operating the systems. 1. A selective hydrogen sulfide removal system , comprising:an absorber-heat exchanger (ABHEX) assembly configured to exchange thermal energy between a mixed stream and a thermal management fluid stream, wherein the ABHEX assembly:(i) defines a mixed stream volume configured to contain the mixed stream;(ii) defines a thermal management fluid stream volume configured to contain the thermal management fluid stream; and(iii) includes an isolation structure configured to maintain fluid separation between the mixed stream and the thermal management fluid stream and to facilitate thermal communication between the mixed stream and the thermal management fluid stream;a feed gas supply conduit configured to provide a feed gas stream, which includes hydrogen sulfide, carbon dioxide, and hydrocarbon gas, to the mixed stream volume;a lean solvent supply conduit configured to provide a lean solvent stream, which includes a hydrogen sulfide-absorbing solvent, to the mixed stream volume;a product gas discharge conduit configured to discharge a product gas stream, which includes purified hydrocarbon gas ...

Integration of Cold Solvent and Acid Gas Removal

A method of separating impurities from a natural gas stream. CO 2 and H 2 S are separated from the natural gas stream in a membrane separation system, thereby creating a partially-treated gas stream and a permeate gas stream, both of which are at a lower temperature than the natural gas stream. The partially-treated gas stream is contacted with a first lean solvent stream in a first contactor to separate H 2 S from the partially-treated gas stream, thereby producing a first rich solvent stream and a fully-treated gas stream. The permeate gas stream is contacted with a second lean solvent stream in a second contactor to separate H 2 S therefrom to produce a second rich solvent stream and a CO 2 gas stream. H 2 S and CO 2 are removed from the first and second rich solvent streams, thereby producing the first and second lean solvent streams.

Enhanced Acid Gas Removal Within a Gas Processing System

A gas processing system is described herein. The gas processing system includes a number of co-current contacting systems configured to contact a sour feed gas stream including an acid gas with a solvent stream to produce a partially-sweetened gas stream and a rich solvent stream including an absorbed acid gas. At least one of the co-current contacting systems is configured to send the rich solvent stream to a regenerator. The regenerator is configured to remove the absorbed acid gas from the rich solvent stream to produce a lean solvent stream. The gas processing system also includes a solvent treater configured to treat at least a portion of the lean solvent stream to produce an enhanced solvent stream, and a final co-current contacting system configured to contact the partially-sweetened gas stream with the enhanced solvent stream to produce a partially-loaded solvent stream and a final gas stream.

Kinetic Fractionators, and Cycling Processes for Fractionation of Gas Mixtures

A process for separating methane from a natural gas mixture employs pressure swing adsorption in one or more vessels. Each vessel has an adsorbent material having a kinetic selectivity for contaminants over methane greater than 5. Contaminants within the natural gas mixture become gases kinetically adsorbed within the adsorbent material. The vessel is placed under pressure to cause contaminants to be adsorbed in the surfaces and micro-pores of the adsorbent material. The process includes releasing a product stream comprised at least 95% by volume methane from a first gas outlet in the vessel, and desorbing the contaminant gases from the adsorbent material by reducing the pressure within the vessel. The desorbing step is done without applying heat to the vessel, thereby delivering a waste gas stream comprised at least 95% by volume of the contaminant gases. An improved fractionation vessel having both major and minor flow channels is also provided. 1. A process for separating methane from a natural gas mixture , the process comprising: a gas inlet for receiving the natural gas mixture,', 'a first gas outlet,', 'an adsorbent material that has a kinetic selectivity for contaminants over methane greater than 5, such that the contaminants become gases kinetically adsorbed within the adsorbent material,', 'at least two major flow channels through the adsorbent material placing the gas inlet and the first gas outlet in fluid communication, and', 'at least one minor flow channel through the adsorbent material, the minor flow channels being in fluid communication with the major flow channels;, 'directing a natural gas mixture into a gas separation unit, the gas separation unit having at least one vessel comprised ofplacing the at least one vessel under pressure to cause contaminants to be adsorbed to the adsorbent material;releasing a product stream comprised at least 95% by volume of methane from the first gas outlet; anddesorbing the contaminant gases from the adsorbent ...

Solvent Mixtures for Dissolving Elemental Sulfur, Methods of Utilizing the Solvent Mixtures, and Methods of Forming the Solvent Mixtures

Solvent mixtures for dissolving elemental sulfur, methods of utilizing the solvent mixtures, and methods of forming the solvent mixtures. The solvent mixtures include an elemental sulfur solvent fraction and an odorant fraction. The elemental sulfur solvent fraction includes an elemental sulfur solvent that has a solvent odor and a solvent sulfur solubility of at least 10 weight percent (wt %). The odorant fraction includes at least one odorant that has an odorant odor that differs from the solvent odor. The solvent mixture includes at least 20 wt % and at most 80 wt % of both the elemental sulfur solvent fraction and the odorant fraction. The presence of the odorant fraction, within the solvent mixture, decreases an intensity of the mixture odor relative to the solvent odor and/or decreases an offensiveness of the mixture odor relative to the solvent odor. 1. A solvent mixture for dissolving elemental sulfur , the solvent mixture having a mixture odor and comprising:an elemental sulfur solvent fraction including an elemental sulfur solvent, wherein the elemental sulfur solvent has a solvent odor and has a solvent sulfur solubility of at least 10 weight percent (wt %) at standard temperature and pressure (STP); andan odorant fraction including at least one odorant, wherein the at least one odorant has an odorant odor that differs from the solvent odor;wherein the elemental sulfur solvent fraction forms at least 20 wt % and at most 80 wt % of the solvent mixture;wherein the odorant fraction forms at least 20 wt % and at most 80 wt % of the solvent mixture; andwherein the presence of the odorant fraction, within the solvent mixture, at least one of:(i) decreases an intensity of the mixture odor relative to the solvent odor; and(ii) decreases an offensiveness of the mixture odor relative to the solvent odor.2. The solvent mixture of claim 1 , wherein the elemental sulfur solvent fraction includes dimethyl disulfide (DMDS).3. The solvent mixture of claim 2 , wherein the ...

Method and System For Separating Fluids In A Distillation Tower

A method and system for separating fluids in a distillation tower. The method may include feeding a stream to the distillation tower, wherein the stream includes carbon dioxide, reducing a carbon dioxide concentration of the stream received by the rectifier section by feeding a first cryogenic fluid to the controlled freeze zone section and accumulating rectifier section stream in at least one of a holding vessel and a sump of the rectifier section, and terminating reducing the carbon dioxide concentration when the carbon dioxide concentration of the stream travelling from the controlled freeze zone section to the rectifier section is less than or equal to a maximum carbon dioxide concentration. The first cryogenic fluid may comprise a substantially carbon-dioxide-free fluid.

Integration of Cold Solvent and Acid Gas Removal

A method of separating impurities from a natural gas stream. The natural gas stream is cooled through heat exchange with one or more process streams to produce a chilled gas stream, which is contacted with a lean solvent stream in a contactor to separate hydrogen sulfide (H 2 S) from the chilled gas stream, thereby producing a rich solvent stream and a partially-treated gas stream. Carbon dioxide (CO 2 ) and H 2 S are separated from the partially-treated gas stream in a membrane separation system, thereby creating a fully-treated gas stream and a permeate gas stream, the permeate gas stream being comprised primarily of H 2 S and CO 2 , and the fully-treated gas stream being comprised primarily of natural gas. The fully-treated gas stream and the permeate gas stream are at a lower temperature than the partially-treated gas stream. The fully-treated gas stream and the permeate gas stream comprise the one or more process streams.

Apparatus and System for Enhanced Selective Contaminant Removal Processes Related Thereto

Systems and methods for separating COand HS from a gaseous stream are provided herein. The system includes a selective solvent that is utilized with a compact contacting technology unit to remove HS from a gaseous stream. 1. A method for separating HS and COfrom a gaseous stream , including:passing a gaseous stream to a compact contacting unit;mixing the gaseous stream with a selective solvent to form a mixed stream, wherein the selective solvent is configured to react with a first contaminant with a first reaction time and to react with a second contaminant with a second reaction time;performing an absorption step for a residence time period, wherein the first reaction time is less than the residence time period, and the second reaction time is greater than the residence time period;conducting away a contaminant stream having a portion of the first contaminant from the mixed stream, wherein the remaining mixed stream has a lower concentration of the first contaminant than the mixed stream; andremoving the first contaminant from the process.2. The method of claim 1 , further comprising:{'sub': '2', 'determining a concentration of COin the gaseous stream;'}{'sub': 2', '2, 'comparing the concentration of COto a COthreshold; and'}adjusting the flow rate of the selective solvent based on the comparison.3. The method of claim 1 , further comprising:{'sub': '2', 'determining a concentration of HS in the gaseous stream;'}{'sub': 2', '2, 'comparing the concentration of HS to a HS threshold; and'}adjusting the flow rate of the selective solvent based on the comparison.4. The method of claim 1 , further comprising:measuring a temperature of the gaseous stream; andadjusting the flow rate of the selective solvent based on the measured temperature.5. The method of claim 1 , further comprising:measuring a pressure of the gaseous stream; andadjusting the flow rate of the selective solvent based on the measured pressure.6. The method of claim 1 , wherein the selective solvent has ...

Systems And Methods For Separating Hydrogen Sulfide From Carbon Dioxide In A High-Pressure Mixed Stream

Systems and methods for separating hydrogen sulfide from carbon dioxide in a high-pressure mixed stream are disclosed herein. The methods include receiving the high-pressure mixed stream in an oxidation reactor and at an inlet pressure of at least 0.3 megapascals. The high-pressure mixed stream includes 0.01 to 5 mole percent hydrogen sulfide and at least 90 mole percent carbon dioxide. The methods further include oxidizing the high-pressure mixed stream with an oxidant to generate a high-pressure oxidized stream, includes oxidized hydrogen sulfide and carbon dioxide, at an oxidation pressure of at least 0.3 megapascals. The methods also include separating the high-pressure oxidized stream into an oxidized hydrogen sulfide product and a carbon dioxide product and generating the carbon dioxide product at a pressure of at least 0.3 megapascals. The systems include the high-pressure mixed stream, an oxidation reactor, and a separation assembly.

Method and System of Controlling A Temperature Within A Melt Tray Assembly Of A Distillation Tower

A method and system of controlling a temperature within a melt tray assembly of a distillation tower. The method may include determining a melt tray fluid composition of a melt tray fluid, determining a melt tray fluid temperature of the melt tray fluid, determining if the melt tray fluid temperature is within an expected melt tray fluid temperature range for the melt tray fluid composition, decreasing the melt tray fluid temperature if the melt tray fluid temperature is greater than an expected melt tray fluid temperature range upper limit, increasing the melt tray fluid temperature if the melt tray fluid temperature is less than an expected melt tray fluid temperature range lower limit, and maintaining the melt tray fluid temperature if the melt tray fluid temperature is within the expected melt tray fluid temperature range. 1. A method of controlling a temperature within a melt tray assembly of a distillation tower , comprising:maintaining a melt tray assembly, within a controlled freeze zone section of a distillation tower that forms a solid and a vapor from a stream that enters the distillation tower, that comprises a melt tray fluid and a melt tray heat exchanging device within the melt tray fluid;providing a phase changing fluid, to the melt tray heat exchanging device, that is configured to be a dual-phase heat transfer fluid;determining a melt tray fluid composition of the melt tray fluid;determining a melt tray fluid pressure of the melt tray fluid;determining a melt tray fluid temperature of the melt tray fluid;determining if the melt tray fluid temperature is within an expected melt tray fluid temperature range for the melt tray fluid composition and pressure, wherein the expected temperature has an expected melt tray fluid temperature range upper limit and an expected melt tray fluid temperature range lower limit;decreasing the melt tray fluid temperature if the melt tray fluid temperature is greater than the expected melt tray fluid temperature range ...

Adsorbing Contaminants From A Gas Stream

A method and systems for adsorbing contaminants from a gas stream are provided herein. The method includes flowing the gas stream into a treating vessel and through a moving bed of adsorbents. The method includes flowing the adsorbents out of the treating vessel and into a fluidized bed of a regenerator. The method includes desorbing the contaminants from the adsorbents in the fluidized bed of the regenerator to form regenerated adsorbents. The method further includes cooling the adsorbents and returning the cooled, regenerated adsorbents to the treating vessel. 1. A method for adsorbing contaminants from a gas stream , the method comprising:flowing the gas stream into a treating vessel and through a moving bed of adsorbents to adsorb contaminants in the gas stream;flowing the adsorbents out of the treating vessel and into a fluidized bed of a regenerator;desorbing the contaminants from the adsorbents in the fluidized bed of the regenerator to form regenerated adsorbents;cooling the regenerated adsorbents; andreturning the cooled, regenerated adsorbents to the treating vessel.2. The method of claim 1 , wherein the adsorbents comprise a blend of different adsorbent types.3. The method of claim 1 , wherein the adsorbent moves counter-current to the gas stream in the treating vessel at a flow rate of about 0.4 cm/s to about 4 cm/s.4. The method of claim 1 , wherein desorbing the contaminants in the gas stream comprises flowing a regeneration gas into the regenerator at a velocity of about 8 cm/s to about 50 cm/s.5. The method of claim 1 , comprising adjusting the particle size of the adsorbents to substantially match fluidization characteristics.6. The method of claim 1 , comprising adjusting the amount of regenerated adsorbents before reintroduction into the treating vessel.7. The method of claim 1 , wherein the regenerated adsorbents are cooled via a cooler before reintroduction into the treating vessel.8. The method of claim 1 , comprising flowing the gas stream ...

POROUS LIQUID AND METHODS OF MAKING AND USING THE SAME

The present disclosure relates to a porous liquid or a porous liquid enzyme that includes a high surface area solid and a liquid film substantially covering the high surface area solid. The porous liquid or porous liquid enzyme may be contacted with a fluid that is immiscible with the liquid film such that a liquid-fluid interface is formed. The liquid film may facilitate mass transfer of a substance or substrate across the liquid-fluid interface. The present disclosure also provides methods of performing liquid-based extractions and enzymatic reactions utilizing the porous liquid or porous liquid enzyme of the present disclosure. 1. A porous liquid or a porous liquid enzyme comprising:a high surface area solid; anda liquid film coating at least 30% of the surface area of the high surface area solid.2. The porous liquid of claim 1 , wherein the high surface area solid includes at least one of:a rough surface, a textured surface, or both;{'sup': '2', 'a sum of the apparent surface area of the solid of greater than 0.001 m/g; or combinations thereof.'}3. The porous liquid of claim 1 , wherein the high surface area solid comprises a matrix of solid features spaced sufficiently close to stably contain a liquid therebetween such that the solid features have an average dimension of about 0.1 μm to 1000 μm and/or an average distance between them of about 0.1 μm to 500 μm.4. The porous liquid of claim 1 , wherein the high surface area solid includes wool claim 1 , glass claim 1 , glass wool claim 1 , polyethylene claim 1 , insoluble fibers claim 1 , polyethylene wool claim 1 , quartz claim 1 , quartz wool claim 1 , fibers claim 1 , polymer fibers claim 1 , a 3D printed structure claim 1 , or a combination thereof.5. The porous liquid of claim 1 , wherein the high surface area solid is made of a material that is not reactive with the liquid film.6. The porous liquid of claim 1 , further comprising a fluid in contact with the liquid film claim 1 , wherein the fluid is ...

Increasing Combustibility of Low BTU Natural Gas

A system and methods for increasing a combustibility of a low BTU natural gas are provided herein. The method includes increasing the adiabatic flame temperature of the low BTU natural gas using heavy hydrocarbons, wherein the heavy hydrocarbons include compounds with a carbon number of at least two. The method also includes burning the low BTU natural gas in a gas turbine. 1. A method for increasing a combustibility of a low BTU natural gas , comprising:increasing an adiabatic flame temperature of the low BTU natural gas using heavy hydrocarbons, wherein the heavy hydrocarbons comprise compounds with a carbon number of at least two; andburning the low BTU natural gas in a gas turbine.2. The method of claim 1 , comprising increasing the adiabatic flame temperature of the low BTU natural gas by spiking the low BTU natural gas with the heavy hydrocarbons.4. The method of claim 3 , wherein recovering the portion of the heavy hydrocarbons from the carbon dioxide removal process comprises cryogenically separating carbon dioxide from the low BTU natural gas via a controlled freeze zone (CFZ) process.5. The method of claim 1 , comprising:generating hydrogen from the heavy hydrocarbons via a pressure swing reforming process; andfeeding the hydrogen into the gas turbine, wherein the hydrogen increases the adiabatic flame temperature of the low BTU natural gas within the gas turbine.6. The method of claim 1 , comprising increasing the adiabatic flame temperature of the low BTU natural gas by spiking the low BTU natural gas with hydrogen.7. The method of claim 1 , comprising:removing hydrogen sulfide from the low BTU natural gas;generating hydrogen from the hydrogen sulfide; andspiking the low BTU natural gas with the hydrogen by feeding the hydrogen into the gas turbine.8. The method of claim 7 , comprising generating the hydrogen from the hydrogen sulfide via thermolysis or electrolysis claim 7 , or any combination thereof.9. The method of claim 7 , comprising removing the ...

Cold Solvent Gas Treating System

A method of removing impurities from a natural gas stream. A selective solvent is provided that absorbs a first impurity at a first rate and a second impurity at a second rate that is slower than the first rate. The solvent is cooled to a temperature below 60° F. to provide a cooled solvent. The cooled solvent is contacted with the natural gas stream, thereby generating a rich solvent that includes the first impurity. The rich solvent is removed from the natural gas stream, wherein an amount of the first impurity remaining in the natural gas stream is below a sales gas requirement. 1. A method of removing impurities from a natural gas stream , comprising:providing a solvent that absorbs a first impurity at a first rate and a second impurity at a second rate that is slower than the first rate;cooling the solvent to a temperature below 60° F. to provide a cooled solvent;contacting the cooled solvent with the natural gas stream, thereby generating a rich solvent that includes the first impurity; andremoving the rich solvent from the natural gas stream, wherein an amount of the first impurity remaining in the natural gas stream is below a sales gas specification.2. The method of claim 1 , wherein the first impurity is hydrogen sulfide.3. The method of claim 1 , wherein the second impurity is carbon dioxide.4. The method of claim 1 , wherein the predetermined temperature is below 60° F.5. The method of claim 1 , wherein the solvent is cooled using seawater.6. The method of claim 1 , wherein the solvent is cooled by one or more of air claim 1 , refrigeration claim 1 , a cooling tower claim 1 , and by cross-exchange with the natural gas.7. The method of claim 1 , further comprising:maintaining the temperature of the cooled solvent at least 10° F. higher than a temperature of the natural gas, to avoid condensation of hydrocarbons into the solvent.8. The method of claim 1 , further comprising:maintaining a temperature of the natural gas at least 10° F. higher than a hydrate ...

Coalescer For Co-Current Contactors

The disclosure includes a method, comprising passing a fluid into a co-current contactor, passing a solvent into the co-current contactor, dividing the solvent into solvent droplets having a first average droplet size, placing the fluid in contact with the solvent droplets to create a combined stream, coalescing at least a portion of the solvent droplets to create solvent droplets having a second average droplet size, wherein the second average droplet size is greater than the first average droplet size, and separating the fluid and the solvent. 1. A method , comprising:passing a fluid into a co-current contactor;passing a solvent into the co-current contactor;dividing the solvent into solvent droplets having a first average droplet size;placing the fluid in contact with the solvent droplets to create a combined stream;coalescing at least a portion of the solvent droplets to create solvent droplets having a second average droplet size, wherein the second average droplet size is greater than the first average droplet size; andseparating the fluid and the solvent.2. The method of claim 1 , wherein the first average droplet size is between less than about 1 micrometer (μm) and about 1000 μm.3. The method of claim 1 , wherein the second average droplet size is between about 2 micrometers (μm) and about 10000 μm.4. The method of claim 1 , wherein coalescing comprises electrically inducing coalescence claim 1 , mechanically inducing coalescence claim 1 , or both.5. The method of claim 1 , wherein coalescing takes between less than about 0.01 seconds and about 15 seconds of residence time.6. The method of claim 1 , wherein coalescing comprises passing the combined stream through a pre-coalescer to create solvent droplets having a third average droplet size claim 1 , wherein the third average droplet size is greater than the first average droplet size and less than the second average droplet size.7. The method of claim 1 , wherein the fluid and the solvent are liquids.8. A ...

Generating Elemental Sulfur

Techniques for generating elemental sulfur are provided herein. The disclosed methods may include a gas processing system including a processed feed gas. The methods may include a distillation column configured to receive the processed feed gas and to generate a high-pressure acid gas stream. The methods may include a reactor configured to partially combust the high-pressure acid gas stream to generate a limiting reactant. The methods may include a plurality of reactors configured with a shell side and a plurality of reaction tubes, where a reaction between the high-pressure acid gas stream and the limiting reactant produces a partially-reacted high-pressure acid gas containing elemental sulfur. The methods may include a plurality of condensers configured to condense the elemental sulfur. The methods may include a plurality of separators configured to separate out the partially-reacted high-pressure acid gas stream to recover elemental sulfur. 1. A system for generating elemental sulfur , comprising:a gas treatment system to provide a processed feed gas;a distillation column configured to receive the processed feed gas and to generate a high-pressure acid gas stream;a reactor configured to partially combust the high-pressure acid gas stream to generate a limiting reactant;a plurality of reactors configured with a shell side and a tube side, wherein the tube side comprises a plurality of reaction tubes, and wherein a reaction between the high-pressure acid gas stream and the limiting reactant produces a partially-reacted high-pressure acid gas containing elemental sulfur;a plurality of condensers configured to condense the elemental sulfur; anda plurality of separators configured to separate out a partially-reacted high-pressure acid gas stream to recover elemental sulfur.2. The system of claim 1 , wherein the high-pressure acid gas stream is at a pressure of at least 500 psig.3. The system of claim 1 , wherein the processed feed gas comprises substantially carbon ...

Method And Apparatus For Removal of Oil From Utility Gas Stream

The present application is directed to a method and system for preparing gaseous utility streams from gaseous process streams, particularly, removing oil contamination from such streams prior to use in a dry gas seal. The methods and systems may include at least one kinetic swing adsorption process including pressure swing adsorption, temperature swing adsorption, calcination, and inert purge processes to treat gaseous streams for use in dry gas seals of rotating equipment such as compressors, turbines and pumps and other utilities. The adsorbent materials used include a high surface area solid structured microporous and mesoporous materials.

Coalescer for Co-Current Contactors

The disclosure includes a method, comprising passing a fluid into a co-current contactor, passing a solvent into the co-current contactor, dividing the solvent into solvent droplets having a first average droplet size, placing the fluid in contact with the solvent droplets to create a combined stream, coalescing at least a portion of the solvent droplets to create solvent droplets having a second average droplet size, wherein the second average droplet size is greater than the first average droplet size, and separating the fluid and the solvent. 1. A method , comprising:passing a fluid into a co-current contactor, the fluid including a hydrocarbon and a contaminant;passing a solvent into the co-current contactor;dividing the solvent into solvent droplets having a first average droplet size;placing the fluid in contact with the solvent droplets to create a combined stream;absorbing the contaminant into the solvent droplets;coalescing at least a portion of the solvent droplets to create solvent droplets having a second average droplet size, wherein the second average droplet size is greater than the first average droplet size;separating the fluid from the solvent droplets;collecting the solvent droplets in a boot; andrecycling gas, collecting in the boot, to the co-current contactor via a recycle gas inlet.2. The method of claim 1 , wherein the first average droplet size is between less than about 1 micrometer (μm) and about 1000 μm.3. The method of claim 1 , wherein the second average droplet size is between about 2 micrometers (μm) and about 10000 μm.4. The method of claim 1 , wherein coalescing comprises electrically inducing coalescence claim 1 , mechanically inducing coalescence claim 1 , or both.5. The method of claim 1 , wherein coalescing takes between less than about 0.01 seconds and about 15 seconds of residence time.6. The method of claim 1 , wherein coalescing comprises passing the combined stream through a pre-coalescer to create solvent droplets having a ...

Reducing Refrigeration and Dehydration Load for a Feed Stream Entering a Cryogenic Distillation Process

A system for conditioning a sour gas feed stream for a cryogenic distillation tower, comprising a dehydration unit configured to separate the sour gas feed stream into a first stream comprising water and a feed stream, and a sequential cooling assembly coupled to both the dehydration unit and the cryogenic distillation tower, wherein the sequential cooling assembly comprises a first stage configured to separate the feed stream into a partially cooled feed stream and a second stream comprising acid gas, a second stage configured to cool the partially cooled feed stream into a cooled feed stream and a third stream comprising acid gas, and a cooled feed stream header coupled to a cryogenic distillation tower feed inlet, wherein the first stage, the second stage, or both are configured to send at least one of the second and third streams to a bottom section of the cryogenic distillation tower. 1. A system for conditioning a sour gas feed stream for a cryogenic distillation tower , comprising:a dehydration unit configured to separate the sour gas feed stream into a first stream comprising water and a feed stream; and a first stage configured to separate the feed stream into a partially cooled feed stream and a second stream comprising acid gas;', 'a second stage configured to cool the partially cooled feed stream into a cooled feed stream and a third stream comprising acid gas; and', 'a cooled feed stream header coupled to a cryogenic distillation tower feed inlet,', 'wherein the first stage, the second stage, or both are configured to send at least one of the second and third streams to a bottom section of the cryogenic distillation tower., 'a sequential cooling assembly coupled to both the dehydration unit and the cryogenic distillation tower, wherein the sequential cooling assembly comprises2. The system of claim 1 , wherein the first stage comprises a first separator coupled to a first cryogenic distillation tower bottom section inlet.3. The system of claim 1 , ...

Reducing refrigeration and dehydration load for a feed stream entering a cryogenic distillation process

A system for conditioning a sour gas feed stream for a cryogenic distillation tower. A dehydration unit separates the sour gas feed stream into a first stream including water and a feed stream. A sequential cooling assembly is coupled to both the dehydration unit and the cryogenic distillation tower. The sequential cooling assembly includes: a first stage that separates the feed stream into a partially cooled feed stream and a second stream including acid gas; a second stage that cools the partially cooled feed stream into a cooled feed stream and a third stream including acid gas; and a cooled feed stream header coupled to a cryogenic distillation tower feed inlet. The first stage, the second stage, or both send at least one of the second and third streams to a bottom section of the cryogenic distillation tower.

Apparatus and system for enhanced selective contaminant removal processes related thereto

Systems and methods for separating CO 2 and H 2 S from a gaseous stream are provided herein. The system includes a selective solvent that is utilized with a compact contacting technology unit to remove H 2 S from a gaseous stream.

Process for removing sulfur-containing compounds

Verfahren zum Entfernen Schwefel-haltiger Verbindungen, umfassend: selektives Trennen eines Einsatzmaterialstroms, der Kohlendioxid und ein oder mehrere Schwefel-haltige Verbindungen, insbesondere Schwefelwasserstoff, umfasst, unter Bedingungen, die ausreichen, um einen ersten Strom, der Kohlendioxid und Schwefelwasserstoff umfasst, und einen zweiten Strom, der Kohlendioxid und Schwefelwasserstoff umfasst, herzustellen, wobei das Molverhältnis von Kohlendioxid zu Schwefelwasserstoff in dem ersten Strom größer als das Molverhältnis von Kohlendioxid zu Schwefelwasserstoff in dem zweiten Strom ist, das Molverhältnis von Schwefelwasserstoff in dem ersten Strom zu Schwefelwasserstoff in dem zweiten Strom etwa 0,005 oder mehr ist und das selektive Trennen des Einsatzmaterialstroms eine zumindest teilweise Flash-Verdampfung des Einsatzmaterialstroms in einer einzigen Stufe umfasst. A method for removing sulfur-containing compounds, comprising: selectively separating a feed stream comprising carbon dioxide and one or more sulfur-containing compounds, in particular hydrogen sulfide, under conditions sufficient to produce a first stream comprising carbon dioxide and hydrogen sulfide and a second stream comprising carbon dioxide and hydrogen sulfide , in which the molar ratio of carbon dioxide to hydrogen sulfide in the first stream is greater than the molar ratio of carbon dioxide to hydrogen sulfide in the second stream, the molar ratio of hydrogen sulfide in the first stream to hydrogen sulfide in the second stream is about 0.005 or more and selectively separating the feed stream comprises at least partial flash evaporation of the feed stream in a single step.

Acid gas disposal method

Kinetic fractionators, and cycling processes for fractionation of gas mixtures

A process for separating methane from a natural gas mixture employs pressure swing adsorption in one or more vessels. Each vessel has an adsorbent material having a kinetic selectivity for contaminants over methane greater than 5. Contaminants within the natural gas mixture become gases kinetically adsorbed within the adsorbent material. The vessel is placed under pressure to cause contaminants to be adsorbed in the surfaces and micro-pores of the adsorbent material. The process includes releasing a product stream comprised at least 95% by volume methane from a first gas outlet in the vessel, and desorbing the contaminant gases from the adsorbent material by reducing the pressure within the vessel. The desorbing step is done without applying heat to the vessel, thereby delivering a waste gas stream comprised at least 95 % by volume of the contaminant gases. An improved fractionation vessel having both major and minor flow channels is also provided.

Cold solvent and sour gas removal integration

UN MÉTODO PARA SEPARAR IMPUREZAS DE UNA CORRIENTE DE GAS NATURAL. EL CO2 Y EL H2S SE SEPARAN DE LA CORRIENTE DE GAS NATURAL EN UN SISTEMA DE SEPARACIÓN DE MEMBRANA, PARA DE ESTA MANERA CREAR UNA CORRIENTE DE GAS PARCIALMENTE TRATADA Y UNA CORRIENTE DE GAS DE PERMEADO, AMBAS DE LAS CUALES ESTÁN A UNA TEMPERATURA MENOR QUE LA CORRIENTE DE GAS NATURAL. LA CORRIENTE DE GAS PARCIALMENTE TRATADA SE PONE EN CONTACTO CON UNA PRIMERA CORRIENTE DE SOLVENTE POBRE EN UN PRIMER APARATO DE CONTACTO PARA SEPARAR EL H2S DE LA CORRIENTE PARCIALMENTE TRATADA, PARA DE ESTA MANERA PRODUCIR UNA PRIMERA CORRIENTE DE SOLVENTE RICO Y UNA CORRIENTE DE GAS COMPLETAMENTE TRATADA. LA CORRIENTE DE GAS DE PERMEADO SE PONE EN CONTACTO CON UNA SEGUNDA CORRIENTE DE SOLVENTE POBRE EN UN SEGUNDO APARATO DE CONTACTO PARA SEPARAR H2S DE LA MISMA PARA PRODUCIR UNA SEGUNDA CORRIENTE DE SOLVENTE RICO Y UNA CORRIENTE DE GAS CO2. EL H2S Y CO2 SE REMUEVEN DE LA PRIMERA Y SEGUNDA CORRIENTES DE SOLVENTE RICO, PARA DE ESTA MANERA PRODUCIR LA PRIMERA Y SEGUNDA CORRIENTES DE SOLVENTE POBRE. A METHOD TO SEPARATE IMPURITIES FROM A NATURAL GAS STREAM. CO2 AND H2S ARE SEPARATED FROM THE NATURAL GAS STREAM IN A MEMBRANE SEPARATION SYSTEM, IN ORDER TO CREATE A PARTIALLY TREATED GAS STREAM AND A PERMEATED GAS STREAM, BOTH OF WHICH ARE AT A TEMPERATURE LESS THAN THE CURRENT OF NATURAL GAS. THE PARTIALLY TREATED GAS CURRENT IS CONTACTED WITH A FIRST POOR SOLVENT CURRENT IN A FIRST CONTACT APPARATUS TO SEPARATE THE H2S FROM THE PARTIALLY TREATED CURRENT, IN ORDER TO PRODUCE A FIRST FIRST CURRENT OF COMPLETELY RICH SOLVENT AND A FIRST CURRENT OF COMPLETELY RICH SOLVENT TREATED. THE PERMEATED GAS STREAM IS CONTACTED WITH A SECOND POOR SOLVENT STREAM IN A SECOND CONTACT APPARATUS TO SEPARATE H2S FROM IT TO PRODUCE A SECOND RICH SOLVENT STREAM AND A CO2 GAS STREAM. H2S AND CO2 ARE REMOVED FROM THE FIRST AND SECOND RICH SOLVENT STREAMS, IN ORDER TO PRODUCE THE FIRST AND SECOND POOR SOLVENT STREAMS.

cold solvent integration and acid gas removal

Um método de separar impurezas de uma corrente de gás natural. CO2 e H2S são separados da corrente de gás natural em um sistema de separação em membrana, criando deste modo uma corrente de gás parcialmente tratado e uma corrente de gás permeado, ambas das quais estão em uma temperatura mais baixa do que a corrente de gás natural. A corrente de gás parcialmente tratado é contatada com uma primeira corrente de solvente magro em um primeiro contator para separar H2S da corrente de gás parcialmente tratado, produzindo deste modo uma primeira corrente de solvente rico e uma corrente de gás totalmente tratado. A corrente de gás permeado é contatada com uma segunda corrente de solvente magro em um segundo contator para separar H2S dela para produzir uma segunda corrente de solvente rico e uma corrente de gás CO2. H2S e CO2 são removidos da primeira e segunda correntes de solvente rico, produzindo deste modo a primeira e segunda correntes de solvente magro. A method of separating impurities from a stream of natural gas. CO2 and H2S are separated from the natural gas stream in a membrane separation system, thereby creating a partially treated gas stream and a permeate gas stream, both of which are at a lower temperature than the natural gas stream . The stream of partially treated gas is contacted with a first stream of lean solvent in a first contactor to separate H2S from the stream of partially treated gas, thereby producing a first stream of rich solvent and a stream of fully treated gas. The permeate gas stream is contacted with a second stream of lean solvent in a second contactor to separate H2S from it to produce a second stream of rich solvent and a stream of CO2 gas. H2S and CO2 are removed from the first and second streams of rich solvent, thereby producing the first and second streams of lean solvent.

Integration of cold solvent and acid gas removal

A method of separating impurities from a natural gas stream. CO2 and H2S are separated from the natural gas stream in a membrane separation system, thereby creating a partially -treated gas stream and a permeate gas stream, both of which are at a lower temperature than the natural gas stream. The partially-treated gas stream is contacted with a first lean solvent stream in a first contactor to separate H2S from the partially -treated gas stream, thereby producing a first rich solvent stream and a fully -treated gas stream. The permeate gas stream is contacted with a second lean solvent stream in a second contactor to separate H2S therefrom to produce a second rich solvent stream and a CO2 gas stream. H2S and CO2 are removed from the first and second rich solvent streams, thereby producing the first and second lean solvent streams.

Integration of cold solvent and acid gas removal

Acid gas disposal method

This invention is method of recovering gas from a gas-bearing subterranean formation in which gas is produced from an upper portion of the formation an d a waste gas is injected into a lower portion of the formation to dispose of the waste gas. The waste gas is injected within a 3000 foot (914 m) radial distance from the production of the gas. The injection and production can be carried out using one well or a plurality of wells.

Inner surface featurees for co-current contactors

A co-current contactor (202a, 202b, 202c, 202d) for separating components in a fluid stream, the co-current contactor comprising a first inlet configured to receive the fluid stream proximate to a first end (208a, 208b, 208c, 208d) of the co-current contactor, a second inlet configured to receive a solvent proximate the first end of the co-current contactor, and a mass transfer section (222) configured to receive the fluid stream and the solvent and to provide a mixed, two-phase flow, wherein the mass transfer section comprises a surface feature along an inner surface of the mass transfer section configured to reduce film flow along an inner wall of the mass transfer section, and wherein the surface feature comprises at least one of a hydrophobic surface, a superhydrophobic surface, a porous wall surface, and a nonlinear surface irregularity extending radially inward or radially outward along the inner surface of the mass transfer section.

ACID GAS DISPOSAL PROCEDURES

Temperature swing adsorption of co2 from flue gas utilizing heat from compression

Reducing refrigeration and dehydration load for a feed stream entering a cryogenic distillation process

A system for conditioning a sour gas feed stream for a cryogenic distillation tower, comprising a dehydration unit configured to separate the sour gas feed stream into a first stream comprising water and a feed stream, and a sequential cooling assembly coupled to both the dehydration unit and the cryogenic distillation tower, wherein the sequential cooling assembly comprises a first stage configured to separate the feed stream into a partially cooled feed stream and a second stream comprising acid gas, a second stage configured to cool the partially cooled feed stream into a cooled feed stream and a third stream comprising acid gas, and a cooled feed stream header coupled to a cryogenic distillation tower feed inlet, wherein the first stage, the second stage, or both are configured to send at least one of the second and third streams to a bottom section of the cryogenic distillation tower.

Acid gas scrubbing methods featuring amine phase separation for hydrogen sulfide capture

Capture of hydrogen sulfide from a gas mixture may be accomplished using an aqueous solution comprising an amine. Certain sterically hindered amines may selectively form a reaction product with hydrogen sulfide under kinetically controlled contacting conditions and afford a light phase and a heavy phase above a critical solution temperature, wherein the hydrogen sulfide may be present in either phase. Upon separation of the light phase from the heavy phase, processing of one of the phases may take place to remove hydrogen sulfide therefrom. Recycling of the amine to an absorber tower may then take place to promote capture of additional hydrogen sulfide.

Integration of cold solvent and acid gas removal

A method of separating impurities from a natural gas stream. CO2 and H2S are separated from the natural gas stream in a membrane separation system, thereby creating a partially -treated gas stream and a permeate gas stream, both of which are at a lower temperature than the natural gas stream. The partially-treated gas stream is contacted with a first lean solvent stream in a first contactor to separate H2S from the partially -treated gas stream, thereby producing a first rich solvent stream and a fully -treated gas stream. The permeate gas stream is contacted with a second lean solvent stream in a second contactor to separate H2S therefrom to produce a second rich solvent stream and a CO2 gas stream. H2S and CO2 are removed from the first and second rich solvent streams, thereby producing the first and second lean solvent streams.

Method of purifying hydrocarbons and regeneration of adsorbents used therein

An improved method is provided for removing contaminants from a hydrocarbon stream, such as a stream of raw natural gas. The contaminated hydrocarbon stream is passed through a first adsorbent bed containing molecular sieves to adsorb contaminants on the molecular sieves, thereby removing at least some of the contaminants from the hydrocarbon stream. The contaminated hydrocarbon stream may optionally be passed through a second adsorbent bed containing a desiccant material other than molecular sieves. The molecular sieves are regenerated using a wet regeneration process in which both the water content and temperature of the regeneration fluid stream are staged. The molecular sieves and the desiccant material can also be regenerated by contacting the desiccant material with a regeneration fluid stream comprising water to adsorb at least a portion of the water onto the desiccant material, thereby forming a regeneration fluid stream that is at least partially dried and in contact with a desiccant material that is at least partially hydrated. The hydrated desiccant material is heated to release adsorbed water into the partially dried regeneration fluid stream while such regeneration fluid stream is passed through the molecular sieves to desorb and remove at least a portion of the contaminants adsorbed on the molecular sieves. A method for producing liquefied natural gas employing such improved method is also disclosed.

Temperature swing adsorption of co2 from flue gas using a parallel channel contactor

Acid gas disposal method

This invention is method of recovering gas from a gas-bearing subterranean formation in which gas is produced from an upper portion of the formation and a waste gas is injected into a lower portion of the formation to dispose of the waste gas. The waste gas is injected within a 3000 foot (914 m) radial distance from the production of the gas. The injection and production can be carried out using one well or a plurality of wells.

Removal of a malt gas from a mixture of gases by turn adsorption using a turbocharger

Separasjonen av en målgass valgt fra en høytrykksgassblanding inneholdende målgassen så vel som en produktgass ved anvendelse av en svingadsorpsjonsprosessenhet. En turboekspander benyttes oppstrøms for svingadsorberen for å redusere trykket i høytrykksgassblandingen. En kompressor blir eventuelt benyttet nedstrøms for svingadsorberen for å øke trykket i den målgassinneholdende strømmen for injeksjon inn i en undergrunnsformasjon.

internal surface features for competing contactors

um contactor concorrente (202a, 202b, 202c, 202d) para separar componentes em uma corrente de fluido, o contactor concorrente compreendendo uma primeira entrada, configurada para receber a corrente de fluido próximo de uma primeira extremidade (208a, 208b, 208c, 208d) do contactor concorrente, uma segunda entrada, configurada para receber um solvente próximo da primeira extremidade do contactor concorrente, e uma seção de transferência de massa (222), configurada para receber a corrente de fluido e o solvente e prover um fluxo de duas-fases misturadas, em que a seção de transferência de massa compreende um recurso de superfície ao longo de uma superfície interna da seção de transferência de massa, configurado para reduzir o fluxo de película ao longo de uma parede interna da seção de transferência de massa, e em que o recurso de superfície compreende pelo menos uma de uma superfície hidrofóbica, uma superfície super-hidrofóbica, uma superfície de parede porosa, e uma irregularidade de superfície não-linear, estendendo-se radialmente para dentro ou radialmente para fora ao longo da superfície interna da seção de transferência de massa. a concurrent contactor (202a, 202b, 202c, 202d) for separating components in a fluid stream, the concurrent contactor comprising a first inlet configured to receive fluid stream near a first end (208a, 208b, 208c, 208d) of the concurrent contactor, a second inlet configured to receive a solvent near the first end of the concurrent contactor, and a mass transfer section (222) configured to receive the fluid stream and solvent and provide a two-phase flow. wherein the mass transfer section comprises a surface feature along an inner surface of the mass transfer section, configured to reduce film flow along an inner wall of the mass transfer section, and in that the surface feature comprises at least one of a hydrophobic surface, a superhydrophobic surface, a porous wall surface, and a nonlinear surface irregularity extending radially ...

Increasing Combustibility of Low BTU Natural Gas

Systems and methods for separating hydrogen sulfide from carbon dioxide in a high-pressure mixed stream

Systems and methods for separating hydrogen sulfide from carbon dioxide in a high-pressure mixed stream are disclosed herein. The methods include receiving the high-pressure mixed stream in an oxidation reactor and at an inlet pressure of at least 0.3 megapascals. The high-pressure mixed stream includes 0.01 to 5 mole percent hydrogen sulfide and at least 90 mole percent carbon dioxide. The methods further include oxidizing the high-pressure mixed stream with an oxidant to generate a high-pressure oxidized stream, includes oxidized hydrogen sulfide and carbon dioxide, at an oxidation pressure of at least 0.3 megapascals. The methods also include separating the high-pressure oxidized stream into an oxidized hydrogen sulfide product and a carbon dioxide product and generating the carbon dioxide product at a pressure of at least 0.3 megapascals. The systems include the high-pressure mixed stream, an oxidation reactor, and a separation assembly.

Absorbent regeneration processes and units that use diabatically heated stripping plates

An absorbent regeneration units that uses a diabatic stripping plate may comprise: a plurality of juxtaposing plates comprising a plurality of stripping plates and one or more heating plates; wherein each stripping plate is in thermal contact with at least one of the heating plates; and wherein at least one of the plurality of stripping plates comprises: (a) a stripping chamber defined by two opposing walls and sides between the two opposing walls; (b) a plurality of trays extending between the two opposing walls and defining a primary fluid flow path between a rich absorbent inlet at a top portion of the stripping chamber and a lean absorbent outlet at a bottom portion of the stripping chamber; and (c) a gas outlet at the top portion of the stripping chamber.

Reducing carbon emissions associated with waste gas

Methods of the present disclosure may comprise: introducing a first effluent and a second effluent in a gasifier of a partial oxidation unit to produce a waste gas, wherein the first effluent comprises one or more hydrocarbon containing feeds and the second effluent comprises air, enriched air with oxygen or oxygen; selectively removing hydrogen sulfide (H2S) from the waste gas; combining the waste gas and steam in a water-gas shift unit to produce a shift gas comprising hydrogen and carbon dioxide; separating the carbon dioxide from the shift gas in a carbon capture unit to produce a carbon dioxide-enriched effluent and an effluent comprising a hydrogen- and nitrogen-enriched mixture; and recovering the carbon dioxide from the carbon dioxide-enriched effluent.

Odor management for disulfide solvents and surfaces contacted therewith

Disulfide solvents may be particularly effective for dissolving deposits comprising elemental sulfur, but the extreme odor of these solvent may make their use rather problematic. Solvent blends comprising at least one disulfide solvent, amine solvent, ketone solvent, and ester solvent may afford a less obnoxious odor and not appreciably compromise the sulfur dissolution capabilities. Surfaces contacted with such solvent blends or at least partially spent variants thereof may exhibit excessive odor due to loss of one or more of the amine, ketone, or ester solvents. Excessive odor resulting from a solvent residue upon a surface may be alleviated by contacting the surface with at least one oxidant. Odor balance may also be restored to at least partially spent solvent blends by introducing additional ester solvent, which may convert a biphasic mixture into an emulsion comprising the disulfide solvent.

Natural gas sweetening methods and related systems

The present disclosure relates to methods and systems for sweetening natural gas may utilize a water wash to achieve a reduction in raw natural gas stream contaminants (e.g., particulate contaminants and/or chemical contaminants) and/or to recover solvent used for removing H 2 S and CO 2 from the natural gas. For example, a method may include contacting a first natural gas stream with a first water stream in a co-current contacting system to produce a second natural gas stream and a second water stream, wherein the first natural gas stream comprises natural gas, an acid gas, and a contaminate, and wherein a concentration of the contaminate in the second natural gas stream is less than a concentration of the contaminate in the first natural gas stream; and removing at least a portion of the acid gas from the second natural gas stream.

Integrated acid gas and sour gas reinjection process

A method for hydrocarbon processing is provided. In one or more embodiments, the method includes splitting a hydrocarbon stream comprising natural gas and acid gas into a first stream and a second stream. Alternatively, the first stream and second stream may be provided from other sources. The first stream is processed to remove a portion of the acid gas therefrom, thereby producing a third stream comprising the acid gas removed from the first stream and a fourth stream comprising less than 100 ppm of sulfur-containing compounds. The second stream is combined with the third stream to provide a combined stream, which is compressed and reinjected into a subterranean reservoir.

Integration of cold solvent and acid gas removal

A METHOD OF SEPARATING IMPURITIES FROM A NATURAL GAS STREAM. C02 AND H2S ARE SEPARATED FROM THE NATURAL GAS STREAM IN A MEMBRANE SEPARATION SYSTEM. THEREBY CREATING A PARTIALLY-TREATED GAS STREAM AND A PERMEATE GAS STREAM, BOTH OF WHICH ARE AT A LOWER TEMPERATURE THAN THE NATURAL GAS STREAM. THE PARTIALLY-TREATED GAS STREAM IS CONTACTED WITH A FIRST LEAN SOLVENT STREAM IN A FIRST CONTACTOR TO SEPARATE H2S FROM THE PARTIALLY-TREATED GAS STREAM. THEREBY PRODUCING A FIRST RICH SOLVENT STREAM AND A FULLY-TREATED GAS STREAM. THE PERMEATE GAS STREAM IS CONTACTED WITH A SECOND LEAN SOLVENT STREAM IN A SECOND CONTACTOR TO SEPARATE H2S THEREFROM TO PRODUCE A SECOND RICH SOLVENT STREAM AND A C02 GAS STREAM. H2S AND C02 ARE REMOVED FROM THE FIRST AND SECOND RICH SOLVENT STREAMS, THEREBY PRODUCING THE FIRST AND SECOND LEAN SOLVENT STREAMS.

Solids removal using solvent blends comprising a disulfide solvent

Solids dissolution may be promoted using a solvent blend comprising a disulfide solvent, particularly additional solids present in combination with elemental sulfur deposits. The solvent blends may comprise at least one disulfide solvent, at least one amine solvent, at least one ketone solvent, at least one ester solvent, and optionally water. Solids dissolution methods may comprise: identifying one or more solids in addition to elemental sulfur to be contacted by the solvent blend; adjusting a composition of the solvent blend to afford selectivity for dissolution of at least a portion of the one or more solids; and contacting the solvent blend with elemental sulfur and the one or more solids to promote at least partial dissolution thereof.

Regenerating solvent mixtures that are used for elemental sulfur removal within hydrocarbon wells

Methods for utilizing and regenerating solvent mixtures for dissolving elemental sulfur within hydrocarbon wells are described herein. One method includes providing a solvent mixture including an elemental sulfur solvent fraction including disulfide compound(s), as well as an odorant fraction including a lactate ester solvent. The method also includes injecting the solvent mixture into a hydrocarbon well such that the elemental sulfur solvent fraction dissolves elemental sulfur deposited on well components, as well as collecting the resulting spent solvent mixture, which includes thiols and residual lactate ester solvent, within a spent solvent separator. The method further includes sparging the spent solvent mixture with oxidizer within the spent solvent separator to allow for oxidation of the thiols to produce the disulfide compound(s) using the residual lactate ester solvent (and, optionally, additional lactate ester solvent), as well as regenerating the solvent mixture using at least a portion of the produced disulfide compound(s).

Integrated acid gas and sour gas reinjection process

A method for hydrocarbon processing is provided. In one or more embodiments, the method includes splitting a hydrocarbon stream comprising natural gas and acid gas into a first stream and a second stream. Alternatively, the first stream and second stream may be provided from other sources. The first stream is processed to remove a portion of the acid gas therefrom, thereby producing a third stream comprising the acid gas removed from the first stream and a fourth stream comprising less than 100 ppm of sulfur-containing compounds. The second stream is combined with the third stream to provide a combined stream, which is compressed and reinjected into a subterranean reservoir.

Método e sistema para separar impurezas de uma corrente de gás natural

Um método de separar impurezas de uma corrente de gás natural. CO2 e H2S são separados da corrente de gás natural em um sistema de separação em membrana, criando deste modo uma corrente de gás parcialmente tratado e uma corrente de gás permeado, ambas das quais estão em uma temperatura mais baixa do que a corrente de gás natural. A corrente de gás parcialmente tratado é contatada com uma primeira corrente de solvente magro em um primeiro contator para separar H2S da corrente de gás parcialmente tratado, produzindo deste modo uma primeira corrente de solvente rico e uma corrente de gás totalmente tratado. A corrente de gás permeado é contatada com uma segunda corrente de solvente magro em um segundo contator para separar H2S dela para produzir uma segunda corrente de solvente rico e uma corrente de gás CO2. H2S e CO2 são removidos da primeira e segunda correntes de solvente rico, produzindo deste modo a primeira e segunda correntes de solvente magro.

Method of purifying hydrocarbons and regeneration of adsorbents used therein

An improved method is provided for removing contaminants from a hydrocarbon stream, such as a stream of raw natural gas. The contaminated hydrocarbon stream is passed through a first adsorbent bed containing molecular sieves to adsorb contaminants on the molecular sieves, thereby removing at least some of the contaminants from the hydrocarbon stream. The contaminated hydrocarbon stream may optionally be passed through a second adsorbent bed containing a desiccant material other than molecular sieves. The molecular sieves are regenerated using a wet regeneration process in which both the water content and temperature of the regeneration fluid stream are staged. The molecular sieves and the desiccant material can also be regenerated by contacting the desiccant material with a regeneration fluid stream comprising water to adsorb at least a portion of the water onto the desiccant material, thereby forming a regeneration fluid stream that is at least partially dried and in contact with a desiccant material that is at least partially hydrated. The hydrated desiccant material is heated to release adsorbed water into the partially dried regeneration fluid stream while such regeneration fluid stream is passed through the molecular sieves to desorb and remove at least a portion of the contaminants adsorbed on the molecular sieves. A method for producing liquefied natural gas employing such improved method is also disclosed.

Method of purifying hydrocarbons and regeneration of adsorbents used therein

An improved method is provided for removing contaminants from a hydrocarbon stream, such as a stream of raw natural gas. The contaminated hydrocarbon stream is passed through a first adsorbent bed containing molecular sieves to adsorb contaminants on the molecular sieves, thereby removing at least some of the contaminants from the hydrocarbon stream. The contaminated hydrocarbon stream may optionally be passed through a second adsorbent bed containing a desiccant material other than molecular sieves. The molecular sieves are regenerated using a wet regeneration process in which both the water content and temperature of the regeneration fluid stream are staged. The molecular sieves and the desiccant material can also be regenerated by contacting the desiccant material with a regeneration fluid stream comprising water to adsorb at least a portion of the water onto the desiccant material, thereby forming a regeneration fluid stream that is at least partially dried and in contact with a desiccant material that is at least partially hydrated. The hydrated desiccant material is heated to release adsorbed water into the partially dried regeneration fluid stream while such regeneration fluid stream is passed through the molecular sieves to desorb and remove at least a portion of the contaminants adsorbed on the molecular sieves. A method for producing liquefied natural gas employing such improved method is also disclosed.

Sistemas e métodos de contato compactos para coletar compostos contendo enxofre

Trata-se de um sistema de coleta de sulfeto de hidrogênio (H2S) para remover H2S, mercaptanos e/ou outros compostos contendo enxofre de uma corrente de gás natural. Um sistema de contato de cocorrente está localizado em linha dentro de um tubo e recebe a corrente de gás natural e uma corrente de coleta de líquidos. O sistema de contato de cocorrente inclui um contator de cocorrente, que inclui um gerador de gotículas e uma seção de transferência de massa. O gerador de gotículas gera gotículas da corrente de coleta de líquidos e dispersa as gotículas na corrente de gás natural. A seção de transferência de massa fornece um fluxo bifásico misturado com uma fase de vapor e uma fase líquida. A fase líquida inclui a corrente de coleta de líquidos com H2S, mercaptanos e/ou outros compostos contendo enxofre absorvidos da corrente de gás natural, e a fase de vapor inclui a corrente de gás natural. Um sistema de separação separa a fase de vapor da fase líquida.

Method and system for separating fluids in a distillation tower

A method and system for separating fluids in a distillation tower. The method may include feeding a stream to the distillation tower, wherein the stream includes carbon dioxide, reducing a carbon dioxide concentration of the stream received by the rectifier section by feeding a first cryogenic fluid to the controlled freeze zone section and accumulating rectifier section stream in at least one of a holding vessel and a sump of the rectifier section, and terminating reducing the carbon dioxide concentration when the carbon dioxide concentration of the stream travelling from the controlled freeze zone section to the rectifier section is less than or equal to a maximum carbon dioxide concentration. The first cryogenic fluid may comprise a substantially carbon-dioxide-free fluid.